HomeMy WebLinkAboutAPA567dComment Draft Working Paper No. 3.1
Candidate Electric Energy
Technologies for Future
Application in the Railbelt
Region of Alaska
March 1981
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
COMMENT DRAFT WORKING PAPER 3.1
CANDIDATE ELECTRIC ENERGY TECHNOLOGIES
FOR FUTURE APPLICATION IN THE ALASKA
RAILBELT REGION
J. C. King
W. H. Swift
R. L. Aaberg
R. S. Schnorr(a)
S. 0. S1mmons(n)
J. E. Butts(a)
E. S. Cunningham(a}
R. A. Koelsch(a)
R. A. Zylman(a)
J. H. Barkshire(b}
C. R. Roy{b)
C. H. Kern(c)
J. R. Richardson(b}
R. D. Eggemeyer(b}
M • A. Newe 11 (d)
March 1981
Batte 11 e
Pacific Northwest Laboratories
Richland, Washington 99352
(a) Ebasco Services, Incorporated, Bellevue, WA.
{cb} Alaska Renewable Energy Associates, Anchorage,
( ) Reid, Collins, Inc., Vancouver, B.C.
(d) Wind Systems Engineering, Inc., Anchorage, AK.
AK.
CONTENTS
1.0 INTRODUCTION 1.1
1.1 CANDIDATE ELECTRIC ENERGY TECHNOLOGIES . 1.5
1.2 OVERVIEW OF RAILBELT GEOGRAPHIC AND SOCIOECONOMIC
CHARACTERISTICS 1.8
1.3 ELECTRIC GENERATING CAPACITY . 1.8
1.4 LOAD CHARACTERISTICS OF THE RAILBELT REGION . 1.16
2.0 BASE LOAD TECHNOLOGIES 2.1
2.1 COAL-FIRED STEAM-ELECTRIC GENERATION 2.5
2.2 NATURAL GAS AND DISTILLATE-FIRED STEAM
ELECTRIC GENERATION . 2.20
2.3 BIOMASS-FIRED STEAM-ELECTRIC GENERATION • 2.25
2.4 NUCLEAR STEAM ELECTRIC 2.35
2.5 GEOTHERMAL 2.47
3.0 CYCLING TECHNOLOGIES . 3.1
3.1 COMBUSTION TURBINES . 3.1
3.2 COMBINED CYCLE • 3.11
3.3 DIESEL GENERATION 3.18
3.4 HYDROELECTRIC ENERGY 3.23
3.5 FUEL CELLS 3.38
4.0 STORAGE TECHNOLOGIES 4.1
4.1 HYDROELECTRIC PUMPED-STORAGE . 4.1
4.2 STORAGE BATTERIES 4.13
5.0 FUEL SAVER TECHNOLOGIES . 5.1
5.1 COGENERATION 5.1
5.2 TIDAL POWER 5.17
iii
5.3 LARGE WIND ENERGY CONVERSION SYSTEMS
5.4 SMALL WINO ENERGY CONVERSION SYSTEMS
5.5 SOLAR ELECTRIC •
6.0 LOAD SHAPING
6.1 LOAD MANAGEMENT TECHNIQUES
6.2 LOAD MANAGEMENT APPLICATIONS •
6.3 COST-EFFECTIVENESS OF LAND MANAGEMENT
ALTERNATIVES
6.4 ENVIRONMENTAL, INSTITUTIONAL, AND REGULATORY
CONSIDERATIONS •
7.0 ELECTRIC ENERGY CONSERVATION IN BUILDINGS
7.1 METHODS OF CONSERVATION •
7.2 TECHNICAL CHARACTERISTICS
7.3 COSTS
7.4 ENVIRONMENTAL IMPACTS
7.5 SOCIOECONOMIC IMPACTS
7.6 POTENTIAL APPLICATION IN THE RAILBELT REGION •
7.7 COMMERCIAL MATURITY •
8.0 ELECTRIC ENERGY SUBSTITUTES
8.1 PASSIVE SOLAR FOR SPACE HEATING
8.2 DISPERSED ACTIVE SOLAR TECHNOLOGIES
8.3 WOOD FUEL FOR SPACE HEATING
REFERENCES
APPENDIX A -WATER RESOURCE IMPACTS ASSOCIATED WITH
STEAM CYCLE POWER PLANTS
APPENDIX B -AIR EMISSIONS FROM FUEL COMBUSTION
TECHNOLOGIES
iv
5.27
5.39
5.47
6.1
6.1
6.12
6.15
6.18
7.1
7.1
7.11
7.13
7.14
7.16
7.17
7.17
8.1
8.1
8.21
8.33
R.1
A.1
B.1
APPENDIX C -AQUATIC ECOLOGY IMPACTS ASSOCIATED WITH
STEAM CYCLE POWER PLANTS
APPENDIX D -IMPACTS OF STEAM CYCLE POWER PLANTS ON
TERRESTRIAL ECOLOGY
APPENDIX E -SOCIOECONOMIC IMPACTS ASSOCIATED WITH ENERGY
DEVELOPMENT IN THE RAILBELT REGION
APPENDIX F -COOLING WATER SYSTEMS IN STEAM CYCLE PLANTS
APPENDIX G ~ FUEL AVAILABILITY AND PRICES
APPENDIX H -AESTHETIC IMPACTS
APPENDIX I -COST ESTIMATING METHODOLOGY
APPENDIX J -SYNFUELS
APPENDIX K -SELECTION OF CANDIDATE ELECTRIC GENERATING
TECHNOLOGIES
v
C.l
0.1
E.l
F.l
G.l
H.l
I.l
J.l
K.l
FIGURES
1.1 Alaska Railbelt Region
1.2 Alaska National Interest Lands Conservation Act
1.3 Existing and Proposed Transmission Systems
1.4 Anchorage Municipal Light and Power 1975
Daily Peak Loads
1.5 Anchorage Municipal Light and Power Load
Duration Curve -1975
2.1 Typical Combustion-Fired Steam Electric
System (Without Reheat) •
2.2 Coal Resources, Alaska Railbelt Region •
2.3 Power Plant Components
2.4 Peat Resources
2.5 Major Concentrations and Capacities of Sawmills
2.6 Steam Electric System Using Pressurized Water Reactor .
2.7 Faults and Seismic Areas
2.8 Binary Cycle Geothermal Power Plant
2.9 Geothermal Resources in the Railbelt Region •
3.1 Simple Cycle Combustion Turbine
3.2 Combined Cycle Combustion Turbine •
3.3 Schematic Diagram of Typical Components
of a Hydropower System •
3.4 Potential Hydroelectric Resources •
3.5 Fuel Cell Plant
4.1 Schematic of a Pumped Storage Hydro Plant
5.1 Simplified Schematic of Steam Tubrine Topping Cycle
5.2 Simplified Schematic of Combustion Turbine
Topping Cycle •
vi
1.3
1.9
1.13
1 "" l.t:::u
1.21
2.2
2.7
2.11
2.31
2.33
2.37
2.41
2.50
2.58
3.5
3.13
3.26
3.33
3.40
4.6
5.5
5.6
5.3
5.4
5.5
5.6
5.7
5.8
5.9
Simplified Schematic of a Bottoming Cycle
Petroleum Refining in the Railbelt Area
Plan of a Typical Tidal Power Plant
Types of Turbine/Generator Sets for a Tidal
Power Plant
Schematic of a MOD-2 Wind Turbine Generator •
Power Profile of the MOD-2 Wind Machine
5.10 Average Wind Speeds
5.11 A Typical Horizontal Axis Small Wind Machine
5.12 Block Diagram of SWECS Configurations Presently
Being Used and Under Study
5.13 Local Terrain Can Significantly Affect the
Performance of a Wind Machine
5.14 Example of Increase in Energy Available in the Wind
with An Increased Tower Height
7.1 Energy Conserving Wall Systems
7.2 Energy Conserving Roof
8.1 Passive Solar Systems Appropriate for Alaska
8.2 Solar Gain Versus Heat Loss with Various Windows •
8.3 Solar Shading Considerations •
8.4 Schematic of a Typical Liquid Flat-Plate Collector
8.5 Typical Active Space Heating System
8.6 An Active Domestic Hot Water System
8.7 Schematic View of a Typical Air Collector
vii
5.9
5.15
5.19
5.21
5.29
1: "lf'\
...J•...JV
5.32
5.37
5.40
5.41
5.43
5.44
7.5
7.7
8.2
8.5
8.14
8.22
8.23
8.25
8.25
TABLES
1.1 Candidate Electric Energy Technologies •
1.2 Generating Capacity: Railbelt Utilities (1980) (MW)
1.3 Generating Capacity (MW): Non-Utilty Railbelt
Installations (1980)
1.4 Monthly Residential Electricity Consumption
For 1979 •
1.5 Monthly Heating Degree Days for 1975
1.6 Yearly Estimated Load Growth (Total Railbelt Region)
ISER Medium Load Growth Scenario •
2.1 Comparison of Caseload Technolog1es on Selected
Characteristics
2.2 Typical Land Requirements for Coal-Fired
Steam-Electric Power Plants
2.3 Fuel Cons11mption for C:nal-Firerl Steam Plants
2.4 Cost Summary of Coal-Fired Plants •
2.5 Cost Summary for Gas and Distillate-Fired Plants •
2.6 Conversion Efficiencies •
2.7 Fuel Requirements by Plant Size
2.8 Cost Summary for Biomass-Fired Plants
2.9 Fuel Availability for Wood and Municipal Wastes
2.10 Cost Summary for Nuclear Power Plants
2.11 Approximate Required Temperature of Geothermal
Plants for Various Applications
2.12 Cost Summary for Geothermal Developments
3.1 Comparison of Cycling Technologies on Selected
Characteristics
3.2 Estimated Costs for Combustion Turbine Power Plants
3.3 Estimated Costs for Combined Cycle Facility •
viii
1.6
1.15
1.16
1.18
1.19
1.22
2.3
2.15
2.15
2.16
2.22
2.26
2.27
2.28
2.35
2.44
2.48
2.54
3.2
3.9
3.15
3.4 Fuel Consumption Rates and Equivalent Heat Rates
for a Diesel Generator Operating at Various Loads
3.5 Estimated Costs for Diesel Electric Generation
3.6 Estimated Costs of Hydroelectric Facilities •
3.7 Estimated Manning Requirements for Hydro-
electric Projects
3.8 Potential Hydroelectric Resources in the (2.5 MW
or greater) Railbelt Region
3.9 Estimated Costs of Fuel Cell Generation Facilities
4.1 Comparison of Storage Technologies on Selected
Characteristics
4.2 Estimated Costs of Hydroelectric Pumped
Storage Facilities .
4.3 Battery Performance Parameters
5.1 Comparison of Fuel Saver Technologies on
Selected Characteristics
5.2 Cost Summary for Steam and Combustion Turbine Cycles
5.3 Estimated Costs of Small Wind Energy
Conversion Systems .
5.4 Estimated Costs for Solar Thermal Systems
6.1 Regional Market Penetration for Major Electric
Appliances (Western U.S.)
6.2 Average Daily Electric Consumption by Appliance
Per Month {kW-hr/day)
6.3 Direct Control and Communication Systems
6.4 Thermal Energy Storage Equipment
6.5 Load Control Cost Summary
6.6 Thermal Energy Storage Systems Summary of Payback
Period Calculations
7.1 Effects of Conservation on Heat Loss for Retrofit of House
and for Alaska-Specific Design
ix
3.20
3.22
3.29
3.37
3.39
3.46
4.2
4.9
4.13
5.2
5.10
5.44
5.52
6.3
6.4
6.5
6.11
6.16
6.17
7.14
7.2 Comparative Annual Heating Loads and Costs: Retrofit
Representative House and Alaska-Specific Design
8.1 Usable Solar Heat for the Main Structure from an
Attached Greenhouse At Anchorage, Alaska
8.2 Comparative Heating Needs of Home Built to ASHRAE
90-75 vs. Passive Solar Design
8.3 Percentage of Radiation Striking a Surface
at Given Incident Angles
8.4 Railbelt Wood Characteristics
8.5 Conversion Eff1ciencies for Wood-Fired Units
8.6 Survey of Wood Suppliers
8.7 Relative Wood and Oil Costs for Railbelt Area
8.8 Wood Heat Fire Hazards
8.9 Summary of State Firewood Permits •
8.10 Wood Energy Summary/Railbelt Area •
X
of
7.15
8.7
8.8
8.12
8.34
8.36
8.38
8.40
8.42
8.45
8.49
1.0 INTRODUCTION
The Railbelt region of Alaska includes Anchorage, Fairbanks, the Kenai
Peninsula and the Valdez-Glenallen areas, which together account for about
two-thirds of the population of the State (Figure 1.1). 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 a number of 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 have all
engaged in various aspects of electric power planning. None to date, however,
has prepared a comprehensive electric power plan for the Railbelt region
considering the overall electric energy needs for the region and considering
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-Northwest to perform a Railbelt Electric Power Alternatives Study.
The primary objective of this study is to develop and analyze alternative
long-range plans for electrical energy development for the Railbelt region.
These plans will be used as the basis for recommendations to the Governor and
Legislature for Railbelt electric power development, including whether or not
the State should concentrate its efforts on development of the hydroelectric
potential of the Susitna River or pursue other alternatives.
A major task of the Railbelt Electric Power Alternatives Study is to
examine electric energy technologies for their potential viability in the
Railbelt region. Technologies found to be potentially technically,
economically and socially viable, will be considered in the development of
electric energy plans for the Railbelt Region.
1.1
"~6(JJ
1-"mollil/t
~~.W..,.."r"~
I('J'~o . .,,,,
G'-1'~~1?-(" R NG(
"""'" 77.>,t
-9416
I06111!1T Slnltlt llf.IHif MI. fR TA8lf8~~~
A-D··
SCALE 1: 2 500 000
. ODETIC VERTICAL DATUM NATIONAL GE OF 1929
ALASKA RAILBELT
REGION
FIGURE 1.1.
USGS ALASKA MAP E
The purpose of this report is to provide an overview of a number of
candidate electric energy technologies for Rai1belt electric power planning.
This information will be used to support the selection of "viable" energy
technologies for subsequent in-depth consideration in later stages of this
study. In general, information is presented on the following aspects of each
technology.
• technical characteristices
• siting and fuel requirements
• costs
• environmental considerations
• socioeconomic considerations
• Railbelt applications.
The remainder of this introduction discusses the selection of candidate
electric energy technologies and provides an overview of the socioeconomic and
environmental characteristices of the Railbelt and a description of the
existing Railbelt electric energy systems. Profiles of the candidate
technologies are presented in subsequent chapters. Summary comparisons among
functionally similar technologies are provided at the beginning of each
chapter. Descriptive material common to several technologies is presented in
Appendices A through K.
1.1 CANDIDATE ELECTRIC ENERGY TECHNOLOGIES
A number of currently commercial, emerging, and advanced energy
technologies was compiled for consideration as potential candidate electric
energy technologies (Table 1.1). These technologies were classified into
seven catagories generally based on the role they typically play in an
electric energy system. The seven catagories include base load generation,
cycling generation, fuel saver generation, energy storage options, electric
energy substitutes, electric energy conservation and load shaping
technologies.
Base loaded power plants operate 65 to 85% of the time and are designed
to supply the continuous (base) portion of electric load at low cost. Cycling
1.5
TABLE 1.1. Candidate Electric Energy Technologies
Base Load Generation
Coal-Fired Steam Electric
Natural Gas/Distillate-Fired Steam Electric
Biomass-Fired Steam Electric
Combined Cycle
Magnetihydrodynamic Generators
Fission Reactors
Fast Breeder Fission Reactors
Geothermal Electric
Fusion Reactors
Ocean Current Energy Systems
Ocean Salinity Gradient Energy Systems
Ocean Thermal Energy Conversion Systems
Space Power Satellites
Cycling Generation
Combustion Turbines
Diesel Generation
Hydroelectric •
Fuel Cells
~!2ger ( IntermjJ!i-nt l ... ~~~~n~ra.ti on
ucean wave rmergy ~ys~ems
Tidal Electric
Central Wind Turbines
Dispersed Wind Turbines
Solar Photovoltaic Systems
Solar Central Receiver Systems
Cogeneration ·
Energa Storage Options
Pumpe Hydro
Compressed Air Storage
Storage Batteries
Electric Energ~ Substitutes
Passive Solar pace Heating
Dispersed Active Solar Systems
Wood-Fired Space Heating
Electric Energy Conservation
Bu1ld1ng Conservation
Load Shaping
Direct load Control
Passive Load Control
Incentive Pricing
Education and Public Involvement
Dispersed Thermal Energy Storage
1.6
Candidate
Electric
Energy
Technology
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
?
X
X
X
X
X
X
X
X
X
X
Rejected Technolofiies
Commercial Tee nical
Availability Feasibility
X
X
X
X
X
X
X
X
X
X
technologies have more flexible operational characteristics and serve
intermediate and peak loads, normally operating approximately 25 to 50% of the
time. Storage technologies convert the electric energy production of base
loaded power plants to a storable form of energy. The stored energy is
reconverted to electricity during periods of peak demand. Fuel saver
technologies include those generating devices which are available only on an
intermittent basis. Fuel saver technologies displace base-load generation by
contributing energy to a system, thus reducing overall fuel requirements.
Unless provided with storage devices, these technologies normally are not
credited as capacity credit since their availability is not assured on a
continuous basis. Electric energy substitutes permit the direct substitution
of other energy forms for electric power. Conservation technologies reduce
the absolute demand for energy, including electric energy. Load shaping is
used to reduce the need for peaking capacity. Load shaping is usually
accomplished by shifting the use of electrical energy not dependent on a
specific time of day to off-peak times.
In some cases a technology may havA thA potential for playing more than
one role in an electric energy supply system. For example, combustion
turbines, while commonly used in the "lower 48" as devices to meet cycling
load requirements, are currently used to provide base load generating capacity
in the Railbelt region partly because of the availability of inexpensive
natural gas fuel.
Candidate electric energy technologies selected for the Railbelt Electric
Power Alternatives Study are indicated in the second column of Table 1.1.
Selection of candidate technologies was based on two criteria: commercial
availability and technical feasibility.
Commercial Availability: A candidate technology should either be
currently commercial or commercially available by year 2000. A technology
which would be commercially available by year 2000 would have potential to
significantly contribute to the electric energy needs of the Railblet during
the planning period of this study (1980=2010). Energy technologies which were
rejected for consideration because of commercial availability are indicated in
the third column of Table 1.1.
1.7
Technical Feasibility: A candidate technology must demonstrate
reasonable potential for technical feasibility in the Railbelt region.
Technologies rejected for not meeting this criterion are indicated in the
fourth column of Table 1.1. Technologies rejected as technically infeasible
were typically technologies dependent upon nontransportable energy resources
not found in the Railbelt region. Further discussion of technologies rejected
from consideration as candidate electric energy technologies is provided in
Appendix K.
1.2 OVERVIEW OF RAILBELT GEOGRAPHIC AND SOCIOECONOMIC CHARACTERISTICS
The Railbelt region, as shown in Figure 1.1, 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, the Chugach and the Talkeetna Mountains form boundaries to
the three major lowland areas. Much of this land area in Alaska has recently
been designated national interest land by the Alaska National Interest Lands
Conservation Act of 1980 as shown on Figure 1.2.
Major industries in the Railbelt include fisheries, petroleum, timber,
agriculture, construction, tourism, and transporation. The federal government
provides employment in both the military and civilian sectors, although these
sectors are presently declining. Current and potential economic activity is
generally directly related to development of Alaska's natural resources
(Alaska Department of Commerce and Economic Develppment 1978).
1.3 ELECTRIC GENERATING CAPACITY
Eight utilities presently serve the region:
• Chugach Electric Association
• Anchorage Municipal Light and Power
• Homer Electric Association
1.8
't6/IJ q.,,,.,,,
;'}~t~WA~tnt
ALASKA NATIONAL INTEREST LANDS
CONSERVATION ACT
SOURCE: U.S. Geological Survey.
1. Alaska Maritime National Wildlife Refuge
2. Kenai National Wildlife Refuge
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.[ ·<:······j National Wild and Scenic
····· .... · Rivers System
9. Chugach National Forest
1 0. Yukon-Charley Rivers National Preserve
11. Nowltna National Wildlife Refuge
12. Steese National Conservation Areas
SCALE 1 : 2 500 000
MILES
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 1.2.
USGS ALASKA MAP E
• Matanuska Electric Association
• Seward Electric System
• Golden Valley Electric Association
• Fairbanks Municipal Utilities System
• Copper Valley Electric Association
The City of Anchorage is served by Chugach Electric Association and Anchorage
Municipal Light and Power. Most of the Kenai Peninsula is served by the Homer
Electric Association while the area in the vicinity of Palmer and Talkeetna is
served by Matanuska. Each of the aforementioned systems is interconnected.
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
installations, 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 1.3.
Existing electric generating capacity by major utility and type is shown
in Table 1.2. Non-utility generating capacity is summarized in Table 1.3. In
addition to the central generating systems, a number of smaller installations
operated by individuals or small communities are found in the Region.
Planned expansions of utility system generating capacity are limited.
Anchorage Municipal Light and Power is the only system currently considering
expansion, by adding a 74-MW combustion turbine in 1982.
Current estimates indicate that over 20% of U.S. energy resources are
located in Alaska. Coal deposits represent between 39 to 63% of the United
States• totals; oil, natural gas, and hydroelectric potentials are greater
than in any other single state {Alaska Dept. of Commerce and Economic
Development 1978). Proper development of these resources is important to
Alaska's future economic condition.
1.11
<\lm.,'-'1•
~f~tN,4MT1f
;,,,0
""" lAllf ~TN .,,
EXISTING AND PROPOSED
TRANSMISSION SYSTEMS
SOURCE: Alaska Power Administration.
Existing
Proposed
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 1. 3.
USGS ALASKA MAP E
TABLE 1. 2. Generating Capacity: Railbelt Utilities (1980) (MW)
Combined Diesel Hydro Combustion Combustion
Cycle Electric Electric Turbine(a) Turbine(b) Steam Total
Alaska Power Administration 0 0 30 0 0 0 30
Anchorage Municipal Light
and Power 139 2 0 0 90 0 231
Chugach Electric Association 0 0 17 120 287 19 443
Fairbanks Municipal
Uti 1 i ty System 0 8 0 0 28 29 65
I-' Golden Valley Electric . Associ! at ion 0 18 0 0 163 25 206 I-'
(.}1
Homer Electric Association 0 3 0 0 0 0 3
Seward Electric System 0 6 0 0 0 0 6
TOTAL 139 37 47 120 568 73 984
Source: Battelle (1980).
(a) Regenerative Cycle Combustion Turbine
(b) Simple Cycle Combustion Turbine
TABLE 1.3. Generating Capacity (MW): Non-Utilty Railbelt
Installations (1980)
Diesel Steam
Fort Richardson Electric Electric Total
Eielson AFB 0 9 9
Elmendorf AFB 2 32 34
Fort Greeley 2 0 2
Fort Richardson 7 10 '>C
I .1.U l...;)
Fort Wainwright 0 5 5
University of Alaska 6 13 19
17 77 94
Source: Battelle (1980)
Energy resource consumption within the State of Alaska is currently as
follows:
Energy Resource
Petroleum Liquids
Natural Gas
Coal
Hydropower
Percent
69
23
6
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.
1.4 LOAD CHARACTERISTICS OF THE RAILBELT REGION
The demand for electrical energy in the Railbelt as well as 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,
1.16
utilities have to provide sufficient generation, transmission, and
distribution facilities to meet the largest or peak hourly load. Therefore,
the time-of-use characteristics of system and class loads have important
implications for an electric utility system.
1.4.1 Seasonal Peak Load
The consumption of electricity is much greater during the winter season
in the Railbelt region than in other seasons. The major reason for this is
the need for energy for space heating. Monthly residential electric utility
consumption data for 1979 is provided in Table 1.4. It is denoted in this
table that the 1979 winter-summer ratio varied from 1.48 to 2.30 for the
various utilities. The seasonal electricity consumption fluctuations are
determined to a large extent by the change in heating degree days. The most
recent heating degree day data available for a "normal" year for which
electrical load data are also available are presented in Table 1.5. Note that
heating degree day data corresponds with seasonal load fluctuations.
As noted in Table 1.4, electricity consumption during the months of
November through January is very high, exceeding by far the consumption of
other months. It would seem reasonable that modifying the seasonal load
profile might be desirable to reduce the need for additional capacity
expansion and obtain a better allocation of system resources.
1.4.2 Daily Peak Loads
Peak loads vary each day as well as from season to season. The daily
variation reflects the living and working characteristics of the communities
as well as ambient temperatures and other factors that influence time-of-use
demands. To demonstrate this variation, the daily peaks for each month of
1975 are illustrated in Figure 1.4 for Anchorage Municipal Light and Power.
The lowest daily peak was 38 MW which occurred in July and the highest daily
load was 92 MW in December.
1.4.3 Load Duration Curve
Figure 1.5 illustrates the load duration curve for Anchorage Municipal
Light and Power for 1975. The curve portrays the number of hours of annual
generation that were a given percent of peak load. The curve indicates that
1.17
TABLE 1.4. Monthly Residential Electricity Consumption For 1979
{kWh/customer)
January
February
March
April
May
June
July
August
September
October
November
December
Monthly Average
Winter-Summer Ratio(a)
0
TOTAL
Nonspace Heat Load(b)
Total Minus Nonspace Heat
Percent Space Heat
Customers(c)
CVEA
620
646
562
525
466
432
371
426
432
434
571
549
491
1.48
5,892
5,892
0
0
CEA
1,179
1,324
1,127
856
779
741
726
583
779
783
953
1,279
AMLP
1,131
762
1,062
783
678
568
563
482
611
410
666
917
871
1.84
716
1.74
10,452
9,828
624
14
8,592
7, 726
866
15
HEA
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
MEA
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
GVEA
1,308
1,495
969
803
637
613
562
592
671
743
887
1,258
877
2.3
10,524
8,464
2,060
6
Space Heat Average 4,457 5,907
30
4,063 9,545 34,333
(a) (December+ January+ February)/{June +July+ August).
(b) Based upon the CVEA ratio of total annual sales to sales in the summer
months of June, July, and August (4.79).
(c) Estimate.
{d) Fairbanks Municipal Utility System data were not available. Institute of
Social and Economic Research.
Source: ISER 1980.
1.18
TABLE 1.5. Monthly Heating Degree Days for 1975
Month Anchorage Fairbanks
January 1,643 2,497
February 1,454 1,918
March 1,313 1,620
April 954 1,028
May 575 347
June 354 69
July 192 33
August ?t:;? ?7f'l ............. t.../V
September 463 570
October 937 1,270
November 1,517 2,195
December 1,654 2,513
Source: Bair, F. E. and Ruffner, J.A. (eds.) 1977. The
Weather Almanac, pp. 336, 340.
for almost all hours, actual loads were about 30 percent of the peak. Also,
about 250 hours of the year had loads exceeding 80 percent of the peak. The
"load factor" of a utility system is the ratio of actual energy supplied
during a period to the energy that would be supplied were the peak load to be
experienced throughout the period. Low load factors indicate a "peaky" load
while high load factors are characteristic of a flatter load profile. The
1975 load factor was about 0.55. Nationwide, load factors range from about
0.55 to 0.70 indicating that the AML&P load is rather peaky.
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.
1.4.4 Projected Load Growth
Table 1.6 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
approximately 3.7% annually with the load factor remaining essentially
constant at about 62 percent. Overall peak load is forecasted to grow from
1.19
1~~---------------------------------------------------,
130
120
110
100
90
80
70
60
50
MINIMUM MAXIMUM
DAILY DAILY
PEAK PEAK
LOAD LOAD
~
30~~~~~
20~~~~~~~~~~~~
J F M A M J J A S 0 N D ANNUAL
MAXIMUM DAILY
PEAK FOR 1975
MINIMUM DAILY
PEAK FOR 1975
FIGURE 1.4. Anchorage Municipal Light and Power 1975 Daily
Peak Loads
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.
1.20
LOAD
(Percent of Peak)
100
90
80
70
60
50
40
30
20
10
HOURS X100
FIGURE 1.5. Anchorage Municipal Light and Power Load
Duration Curve -1975
1.21
8760
TABLE 1.6. Yearly Estimated Load Growth (Total Railbelt Region)
ISER Medium Load Growth Scenario
Total Generation Peak Load Load Factor
Year (MWh X 12 000} (MW} {Percent)
1978(a) 3,323 606 62.6 1980(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).
1.22
2.0 BASE LOAD TECHNOLOGIES
Three fundamental base load generating technologies are considered in
this analysis: combustion-fired steam-electric generation, nuclear steam
electric generation, and steam-electric generation supplied by geothermal
energy. Because the fuel characteristics differ significantly among
combustion-fired steam electric generating technologies, that discussion is
presented in three sections: coal-fired steam-electric, distillate and
natural gas-fired steam-electric, and biomass-fired steam-electric. All of
these technologies, with the exception of geothermal, depend on the burning
(fission in the nuclear cycle) of a fuel to produce steam, which is expanded
through a steam turbine to produce electrical power in a generator. A
schematic representative of the steam cycle of the three combustion-fired base
load technologies is presented in Figure 2.1.
All of the base load technologies require: a fuel or energy source; site
access facilities; power egress corridors (electrical transmission lines);
environmental capabilities to support plant operation (e.g., cooling water and
stable foundation); environmental capacity to absorb plant effluents such as
liquid, gases, solids; institutional and social infrastructures to support
construction and operation of the facility; and a source of capital and
operating funds to construct and maintain the facility. Each of these
requirements is considered in the discussion of each base generating
technology. Salient characteristics of the base load technologies are
compared in Table 2.1.
In the lower 48 states, base load installations have typically been large
(200 MWe or more) oil, gas, coal, or nuclear fueled steam-electric plants.
The Railbelt region of Alaska, because of its unique development and
environmental characteristics, has not followed the traditional
power-producing patterns. In the Railbelt, large base-loaded units have
generally not been economically feasible because of sparse population and lack
of transmission interconnections. The relative ease of construction, greater
operating flexibility, short constructon lead times, and lower capital costs
of diesels and gas turbines have led to their use in the Railbelt region for
base load capacity. Capacity has been added in small increments, with the
2.1
N .
N
BOILER
FUEL
FIGURE 2.1.
ETACK
H.P. STEAM
Typi ca·l Combustion-Fired Steam Electric
System (Without Reheat)
ELECTRIC
GENERATOR
COOLING
~-------WTR OUT
COOLING .,...u...--WTR IN
\CONDENSER
N
w
TABLE 2.1. Comparison of Caseload Technologies on Selected Characteristics
First Stage
Attributes
1. Aesthetic Intru-
siveness
A. Visual Impacts
B. Operating Noise
C. Odor
2. Impacts on Biota
A. Aquat/'c/Marine
(gpm) a)
B. Terrestripl
(acres)(bJ
3. Cost of Energy
A. Capital Cost
($/kW)
B. O&M Cost
{$/kW)
C. Fuel Cost
D. Cost of Power
( $/kW)
4. Health & Safety
A. Pub lie
5. Consumer Effort
6. Adaptability to
Growth
A. Adjustments in
plant scale
7. Reliability
A. Availability (%)
Biomass
25 MW
Moderate
Minor
Significant
(Municipal Waste)
325
25
2160
68
Safe
Utility operated.
No individual or
community effort
required.
Dup 1 icate effort
required.
85
Coal
200 MW
Significant
Moderate
Minor
1800
225
2100
38
No direct safety
problems. Possible
long-term air quality
degradation.
Utility operated. No
individual or commu-
nity effort required.
Duplicate effort
required.
85
Oil & Natural Gas
10 MW
Minor
Minor
Minor
90
4
Oi 1 Gas
1920 1360
Oi 1 Gas
60 56
No direct safety
problems.
Utility or community
operated. No individ-
ual effort required.
Packaged units can be
added relatively
easily to existing
site.
85-90
Geothermal
50 MW
Significant
Moderate
Significant
750
5_(Excluding Wells)
1500
1500
N/A
0.035-0.151
No direct safety
problems. Possible
air quality degrada-
tion in vicinity of
plant.
Utility operated. No
individual or commu-
nity effort required.
Increases possible
but resource limited.
65
Significant
Minor
Minor
11000
125
1850
1850
Nuclear
1000 MW
No direct safety problems.
Possible short-and long-term
quality degradation or acci-
dental radionuclide discharge.
Utility operated. No indi-
vidual or community effort
required.
Duplicate effort including
some licensing.
70
N
+::>
F·irst Stage
Attnbutes
8. Expenditure Flow
From Alaska
A. Capita 1 Cost (%)
B. Operation and
Maintenance
Cost (%) c. Fuel Cost
g. Boom/Bust
10.
1.
2.
3.
4.
A. Ratio of Con-
struction to
Operating
Personnel
B. 11agn itude of
Impacts
Control of Technology
A. Utility
B. Individual
Second Stage
Attribute
COITIIM!rC i a 1 Avail-
ability
Railbelt Siting
Oppo1·tunit ies
Product Type
Generating Capacity
A. Range in Unit
Scale (MW)
TABLE 2.1. (contd)
Biomass
25 MW
Coal
200 MW
60 60
65:25 600:85
Significant in Severe
very small commu-
nities. Minor to
moderate in all
other locations.
Primary Control Primary Control
Limited through Limited through
regulatory agencies and
agencies and government.
government.
Mature Mature
Limited to loca-Limited to coal
tion fuel source. regions and railroad
or water transport.
Base load Base load
5-60 10-1300
75
Oil & Natural Gas
10 MW
60:20
Significant in very
small communities
Minor to moderate in
all other locations.
Primary Control
Limited through
regulatory agencies
and government.
Little current utility
experience, large
industrial usage.
Limited to fuel
delivery considera-
tions.
Base load
10-800
(a) Recirculating cooling water systems.
(b) All facilities.
Geothermal
50 MW
55
go:30
Severe
Primary Control
Limited through
regulatory agencies
and government.
Experimental techno-
logy for Railbelt
resources.
Limited to source.
Base load
3 MW per well up to
50 MW
60
1300:180
Nuclear
1000 MW
Severe with the exceptions
of Fairbanks and Anchorage.
Primary Control
Limited through regulatory
agencies and government.
Moderately mature, some
difficulties, no experi-
ence in Railbelt.
Limited to port facilities
or rail corridor, seismic
influenced.
Base load
1000 nominal
largest operating unit at approximately 68 MW. Of the approximately 1000 MW
of nonmilitary power installed, only 86 MW is steam-electric. 20 MW of this
is used as peaking capacity. The largest steam-electric unit currently found
in the region is the 25-MW coal-fired Healy Plant.
The Railbelt region's projected load growth o~ approximatly 3 1/2% per
year indicates that it may be possible to continue using individual generating
units of approximately 10 to 25 MW 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.
2.1 COAL-FIRED STEAM-ELECTRIC GENERATION
Coal-fired steam-electric generation is a mature, reliable, universally
accepted technology which supplies more electric power in the United States
than any other single fuel. Uncertainties in petroleum supply and rising
petroleum prices are leading industry to return to a coal-based energy
industry from one which had seen the rise of oil and natural gas use in the
1945-1975 period. Small users converted much of their steam generating
capacity to oil or natural 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, leading to installation of flue gas
clean-up equipment for 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 2.2.
Recent coal-fired power generation installations in the United States
have been large units (greater than 200 MW). It is expected, however, that
smaller users and producers of steam will look to coal as a fuel in the
forseeable future because of its relatively abundant supply and lower cost
when compared to competing fuels (Battelle 1980). In addition to economic
factors promoting use of coal, the Powerplant and Industrial Fuel Use Act of
2.5
Y61J.]
C\>m•u••
i~~r~tt.,r,.
,, .:JIJO
COAL RESOURCES
Joint Federal-State Land Use Planning Commission
~:~~~~~~~~:~~~~~~::;~~lC:~~~~J,:~~~for Alaska, 1975.
•·. , . ....... -....
SCALE 1 : 2 500 000
100
MILES
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 2.2.
USGS ALASKA MAP E
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).
Contemporary coal-fired installations differ from older units in the
important area of flue gas clean-up. The Clean Air Act and subsequent
amendments require control of particulates, oxides of sulfur and oxides of
nitrogen. Equipment is installed in the flue gas discharge path to remove
sulfur, oxides {SOx) and particulates before the gaseous emissions enter the
atmosphere. Nitrogen oxide (NOx) emissions are being controlled by use of
modified combustion technologies rather than through flue gas clean-up
equipment.
2.1.1 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
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
interconnected. Units of 100 to 200 MW may be practical in an interconnected
Railbelt system.
The firing of coal imposes unique requirements on the design of
steam-electric plants. First of all, it is necessary to provide for
significant amounts of on-site fuel storage, resulting in large coal storage
piles. The long-term storage area is usually sized for 60-90 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 limiting
conditions. In addition to the long-term storage is a "live storage•• area;
this area is usually designed for a 7-day supply, from which the coal is fed
to the plant.
Since coal combustion creates large quantities of ash, a location for
final disposal of the ash must be provided. If a dry ash removal system is
used, then only a small on-site storage area is required as dewatering is not
necessary. Wet ash removal systems require impoundments for dewatering. Ash
2.9
may be marketed as a by-product; otherwise, a permanent disposal site is
required. Permanent disposal may be in landfills; occasionally ash is
returned to the mine for disposal.
Coal installations sited in cold-weather regions require special
equipment, specifically thaw sheds at the unloading facility and frozen coal
crushers at the reclaim area.
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 2.3).
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 and
will be described in additional detail. The boiler plant includes coal
handling and preparation facilities and the boiler itself.
Coal Handling and Preparation.
Coal handling and preparation facilities include facilities for
receiving, handling and storing raw coal and equipment for preparing the coal
for firing. Principal coal handling and preparation facilities include the
following:
Unloading Station. The design of the unloading station depends on the
mode of coal transportation. For transportation by rail, 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, and 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.
Stacking and Reclaiming. 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 retrieving for use in the plant.
2.10
FLUE BOILER GASES r--------
PRECIPITATOR
HIGH PRESSURE
HIGH TEMPERATURE
STEAM
BOILER
FEED WATER
BOILER FEED WATER
PUMP
LOW PRESSURE
LOW TEMPERATURE STEAM
CONDENSER
FIGURE 2.3. Power Plant Components
STACK
Conveying. Most coal-fired plants use some form of conveyor system to
move the_ coal from the reclaiming area to the plant bunkers. Extreme
environments will require climate protection equipment as well as dust
supression systems to be used in the conveying.
Bunkers. In-plant storage bunkers are usually sized for 8 hours
capacity. The bunkers are situated above the mills for gravity feed and
require some form of a fire protection system.
Mills. The mills are generally located below the bunkers and serve to
pulverize and dry the coal in preparation for burning. The mills are
extremely large, heavy duty, slow speed, high energy-consuming pieces of
equipment.
Air Pollution Control System
Combustion of coal produces a flue gas containing a number of
environmentally harmful pollutants, notably particulate matter, oxides of
sulfur (SOx) and oxides of nitrogen {NOx). Each of these requires control
under the provision of the Clean Air Act of 1971 and subsequent amendments.
Particulates. Particulates are removed from the flue gas by use of
electrostatic precipitation or fabric filters (baghouses). The most widely
used system has been precipitators, which are capable of removal efficiencies
of 99.9%. The performance of precipitators is affected by the sulfur content
of the fly ash; higher levels of sulfur leading to enhanced removal
efficiencies. This has led to increased use of baghouses for plants burning
low sulfur coal.
Oxides of Sulfur. The most common methods of removing sulfur from the
flue gas is by use of 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 which are disposed of as solid waste. Removal
efficiencies are on the order of 90% for single units. Wet or dry systems are
available. The wet system results in a sludge requiring dewatering; dry
systems are designed such that drying of the sludge occurs in the flue gas
2.12
stream, resulting in a product requ1r1ng no additional dewatering. The dry
system has the advantage in a harsh winter climate--it reduces the freezing
problem.
Several other SOx removal processes are currently under development,
many of which are regenerative processes, producing marketable sulfur
byproducts and reducing the need for scrubber feedstock.
Oxides of Nitroaen. Oxides of nitrogen (NOx) are formed during the
combustion process by the combination of atmospheric oxygen with atmospheric
nitrogen at elevated firing temperatures. Oxides of nitrogen are currently
controlled by special firing techniques.
Unit availability refers to the total amount of time that a particular
piece of equipment was or could have been used divided by the total hours in
the period in question. 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.
Unit Size
100-199 MW
200-299 MW
300-399 MW
400-599 MW
Availability
(10 Year Average)
86.1 percent
84.8 percent
77.6 percent
74.1 percent
Additional information from the NERC survey indicates that in recent
years the availability has decreased in every size range. The added
complexity of flue gas clean-up 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 when one considers
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).
"Load factor" refers to the actual percent of time a unit is operated.
Load factors for units in the above sizes range from 45 to 86%; however, for
2.13
any particular unit the load 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.
2.1.2 Siting and Fuel Requirements
A complex decision process, which considers environmental aspects,
economics 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, available transportation facilities, and the size of the plant weigh
more heavily in the siting of a coal-fired unit than with oil or gas-fired
units because characteristics of the fuel vary so widely compared to oil or
gas.
Coal-fired steam-electric plants require water for condenser cooling,
emissions control, ash handling, boiler makeup, general cleaning, and for
domestic purposes. Typically, boiler makeup, emissions control, domestic and
other noncooling uses amount to approximately 5% of the boiler through-put.
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 this 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 F).
The acreage of sites required for coal-fired power plants of varying
capacities are given in Table 2.2:
2.14
TABLE 2.2. Typical Land Requirements for Coal-Fired
Steam-Electric Power Plants
Ash and Total Land
Scrubber Sludge Area Required
Plant Size (MW) Plant Site Disposal (Acres) (Acres)
20 5 3 8
200 25 200 225
400 75 400 475
600 120 550 670
These estimates account for the siting of not only plant facilities (including
coal storage and handling facilities, power plant systems, and cooling
systems) but also on-site housing facilities that would be necessitated by
remote siting requirements.
Plant heat rate is a measure (in Btus) of the amount of fuel energy
required to produce one kilowatt of electrical power, and is thus a measure of
plant efficiency. Heat rates are a function of unit size, basic design,
auxiliary equipment, heat sink temperatures, and operator attention. Fuel
consumption (quantity) for coal-fired steam electric plants varies with heat
rate and with the quality of the fuel. 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
{for power plant firing) and limestone for flue gas desulfurization if
necessary. Siting coal-fired steam electric plants at the coal source
(mine-mouth) eliminates the need for fuel delivery systems. Coal and
limestone consumption are shown in Table 2.3 for four plant sizes.
TABLE 2.3. Fuel Consumption for Coal-Fired Steam Plants
Heat Rate Range Coal Consumption Limestone
Plant Size (MW) {Btu/kWh) {Tons/hr} {lb/hr}
20 10,600 to 13,000 16 150
200 10,200 to 13,000 145 1,400
400 9,800 to 12,200 275 2,750
600 9,500 to 10,600 400 4,000
2.15
2.1.3 Costs
Engineering costs vary from project to project and depend on the
construction schedule, unit size, scope of work, and degree of
standardization.
Operating and maintenance costs are difficult to estimate because of the
wide variations in utility practice. The cost per kilowatt decreases
substantially as unit size increases; this is because larger units require
relatively fewer personnel than smaller units.
Estimated capital costs and operation and maintenance costs vary with
plant size as shown in Table 2.4. The basis for these cost estimates are
further discussed in Appendix I.
TABLE 2.4. Cost Summary of Coal-Fired Plants
Capital Costs 0 and M Costs Cost of Power
Plant Size {$/kW} {$/kW} {$/kWh)
20 MW 1600 45
200 MW 1115 25
400 MW 915 18
600 MW 790 12.5
2.1.4 Environmental Considerations
Coal-fired power plants generate large and problematic quantities of
solid waste derived from both the combustion process (fly ash and bottom ash)
and from atmospheric emissions (flue gas desulfurizaion wastes). These wastes
require more extensive environmental monitoring and waste characterizaion
studies, and generally more sophisticated treatment technologies than other
steam cycle technologies. Water resource impacts associated with these solid
wastes are generally mitigated through appropriate plant siting and a water,
wastewater, and solid waste management program (refer to Appendix A).
The combustion of large amounts of coal leads to a potentially
significant deterioration of the surrounding air quality. The atmospheric
emissions from a coal facility will be the subject of an in-depth review by
2.16
Alaska and EPA authorities. The expected emissions from a coal-fired power
plant and the regulatory framework are presented in detail in Appendix B,
where emissions are compared to those of alternative technologies. Note that
although impacts from coal combusion are generally greater than those of other
fuels, a judicious siting analysis and the employment of strict environmental
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 comnon to most of Alaska 1 s reserves.
Other significant, and difficult to mitigate, effects from coal-fired
steam plants are associated with water supply and wastewater discharge
requirments. 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 effects in the Railbelt region
when the discharge is stopped. These effects are discussed in greater detail
in Appendix C.
Coal-fired plants will use the same or less water per megawatt than other
steam cycle plans except a combined cycle facility. A suitable plant size for
the Railbelt region (200 MW) would, however, be second only to nuclear plants
in total water use and would require approximately 90,000 gpm and 1,800 gmp
for a once-through and recirculating cooling water system, respectively. In
addition, water from coal-fired steam plants, particularly from ash or
scrubber pile wastes, generally requires more sophisticated treatment to
reduce its hazardous composition before discharge than most other steam
plants.
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); plants
located in these areas would have to be designed to mitigate effects on these
resources.
The greatest impact on the terrestrial biota is the loss or alteration of
habitat due to the large amounts of land required for both construciton and
operation. These land requirements (Table 2.2) are generally greater than
those for other forms of fossil-fueled power plants.
2.17
Other impacts to the terrestrial ecology could result from gaseous and
particulate air emissions, fuel or waste storage discharges, human
disturbance, and the power plant facilities themselves, i.e., cooling towers.
The effects of these plant characteristics on the biota are discussed in
Appendix D. Impacts resulting from coal-fired plants on the terrestrial biota
are best mitigated by siting plants away from important wildlife areas and by
implementing appropriate modern pollution control procedures. Although
certain impacts can be controlled, land losses are irreplaceable.
2.1.5 Socioeconomic Considerations
The construction and operation of a coal-fired plant has the potential to
seriously affect localities and cause a boom/bust cycle. These effects are
due to the remoteness of prospective sites. The magnitude of these impacts is
a function of plant scale. A major contributing factor to this relationship
is the variation in size of the construction workforce with plant size.
Construction times, exclusive of licensing and permitting, will vary according
to the size, type of equipment, and external factors such as weather and labor
force. Construction schedules for coal-fired plants in the Railbelt will vary
depending upon whether or not the boiler is field-erected. A small 20-MW unit
could be constructed in approximately 20 months if the boiler is a package
design and auxiliary equipment is skid mounted. Larger units (above 50 MW)
which are field constructed will take from 3 to 5 years. Because of site work
involved with the fuel storage and ash disposal areas, it can be expected that
a coal-fired unit will require an additional 3 months over a similarly
situated oil or gas-fired plant.
Impacts would be most severe at the Beluga coal fields since the
surrounding communities are small and the infrastructure is not devloped.
Power plant components would most likely be shipped by barge and then
transported overland to the site. Secondary impacts would be caused by the
construction of haul roads. The largest community in the area is Tyonek, an
Alaskan native village with a population of 239. The influx of a construction
workforce, regardless of size, would disrupt the social structure of the
community.
2.18
Impacts from development of the Nenana and Matanuska coal fields and
construcion of a plant along the railroad corridor would depend on a scale of
plant. Existing communities may be able to accomodate the requirements for
constructing a 10 to 30-MW plant, but would be severely affected by a
large-scale plant.
The area of Kenai-Soldatna on the Kenai Peninsula has a more developed
infrastructure and a larger population to withstand the demands which
accompany power plant construction. The impacts of a small-scale plant would
be minor to moderate but the impacts of a large-scale plant could be
significant, depending on the extent of local labor utilization.
The flow of expenditures both outside and within the Railbelt are
expected to balance for a 200-MW field-erected project and be proportionately
higher outside the region for a 20-MW packaged unit. For a large unit, 50% of
the expenditures would flow outside the Railbelt and, for a smaller unit,
approximately 60% of the project investment would be made outside the
Railbelt. The percentage of capital investment for a field-erected plant is
larger compared to other base load technologies because of the large
construction workforce and extensive field preparation requirements.
2.1.6 Potential Application in the Railbelt Region
There are two major coal fields in the Railbelt reqion, the Nenana field
and the Beluga field (Figure 2.2). Some development of coal-fired steam
electric generation has occurred using coal from the Nenana coal field. A
25-MW coal-fired plant, located at Healy, is operated by the Golden Valley
Electric Association. In addition, the Fairbanks Municipal Utilities system
operates four units at Chena while the University of Alaska has three small
units at their power plant. The Beluga fields have not been developed,
although studies are underway to define the coal resource characteristics and
markets (Battelle 1980).
The Beluga and Nenana fields would be potential sites. Mine-mouth siting
has the advantage of being able to substantially reduce the coal storage area
and transportation costs. Secondary sites may include deposits on the Kenai
Peninsula as well as the Matanuska fields. The Matanuska fields have been
2.19
worked in the past; the Kenai fields have not been developed. The next most
logical siting choice is along the Alaska Railroad corridor. The area
adjacent to the railroad from Seward, through Anchorage to Fairbanks, has
existing transportation facilities which are adequate for coal transport from
the Nenana coal fields.
If neither mine-mouth operation nor rail service is available at an
otherwise attractive Railbelt site, then good roads would be essential for
truck hauling. This type of operation would probably be limited to smaller
plants (10 to 15 MW) requiring approximately 5 to 10 tons of fuel per hour.
This s}ting option has at least two disadvantages: coal storage would have to
be sized to handle plant operations during periods when deliveries are not
made, and increased truck traffic would become a nuisance as well as a
potential threat to highway user health and safety.
2.2 NATURAL GAS AND DISTILLATE-FIRED STEAM ELECTRIC GENERATION
The natural gas and distillate-fired (more generally oil-fired)
steam-electric technologies are well known and widely used in the utility
industry. However, the future application of these technologies is not
promising because of the worldwide oil supply and pricing disruptions caused
by the action of 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 exemptions are available to utilities that can
prove that no reasonable alternative exists, these exemptions are difficult to
obtain. Since this regulatory constraint severely limits new construction of
oil-and gas-fired facilities, our evaluation of these types of units
considers only units of 10 MW or less. Units of this overall size can be
accommodated in either an interconnected or isolated Railbelt power system.
U.S. utilities have very little experience with gas and distillate-fired
boilers in the 10 MW size range. Units of this size are used primarily in
heavy industrial applications; however, the purpose, operating procedures, and
operating conditions of such applications are usually different from those of
a utility and therefore can only give an indication of what can be expected
for electrical generation.
2.20
2.2.1 Technical Characteristics
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
requirements. A 1-week supply is a common criterion for plants with a
reliable source. Some means of heating the oil may be required, depending on
oil type and ambient temperatures in the Railbelt region. Depending on the
environmental regulations and the sulfur content of the fuel, flue gas
desulfurization equipment may be required.
No special fuel storage or handling provisions are required for gas
firing because the fuel is delivered by pipeline at high pressure. During
periods of extreme cold, when transmission line pressure drops, natural
gas-fired units may have to be shut down or shifted to distillate firing.
A 10-MW distillate-fired unit operating at rated capacity will consume
approximately 20,000 gal/day of distillate, assuming a heat rate of 11,000
Btu/kWh (typical for this size unit). The consumption for a similarly sized
natural gas fired plant will be approximately 2.9 million cu ft/day based on a
typical heat rate of 12,000 Btu/kWh.
Industrial users frequently obtain availability of approximately 90%.
This is possible because industrial boilers can be operated 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 units of this size based on industrial data and data
from NERC on the smallest reported units (100 MW).
2.2.2 Siting and Fuel Requirements
The siting decision process for small gas-or distillate-fired
steam-electric plants is similar to that for coal units with respect to water
resources and air quality limitations (flue gas constituents will differ but
the regulations, studies, and permits are similar). Both oil and natural gas
fuels are environmentally preferable to coal, and thus environmental
constraints on siting these facilities should be less rigid than those
2.21
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,
while 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. These estimates do not
inlcude an allowance for employee housing, if such is required.
2.2.3 Costs
The estimated costs in 1980 dollars to construct, operate, and maintain a
10-MW distillate-fired or natural gas-fired unit in the Railbelt Region with
construction starting in 1982 are shown in Table 2.5.
TABLE 2.5. Cost Summary for Gas and Distillate-Fired Plants
Capital Costs 0 and M Cost of Power
Fuel ($/kW) {$/kW) ($/kWh)
Distillate 1,920 60
Natural Gas 850 56
2.2.4 Environmental Considerations
Water resource impacts associated with the construction and operation of
a natural gas or oil-fired power plant are generally mitigated through
appropriate plant siting and a water, wastewater, and solid waste management
program (refer to Appendix A). These steam cycle facilities present the least
adverse impacts of the combustion technologies; significant, or difficult to
mitigate, water resource impacts are not anticipated, especially in light of
the small power plant capacities that are considered likely.
The burning of oil or natural gas in steam electric generators generally
presents the least adverse atmospheric impacts of the combustion
technologies. The expected emissions form a natural gas or oil-fired power
plant and the associated regulatory framework are presented in detail in
2.22
Appendix B. Emissions of sulfur dioxide from the burning of residual fuels
will be signficiant and will require conventional scrubbers for large
systems. In addition, emissions of nitrogen oxides resulting from
high-temperature combustion may also be significant and may require the
application of control techniques such as two-stage combustion.
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 C). 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. Because these
plants use the same or less water per megawatt than any steam cycle plant
except the combined cycle, and because of federal restrictions on maximum
plant size (10 MW), these plants would use less water than any other steam
plant (approximately 4,500 gpm for once-through cooling and 90 gpm for
recycling cooling systems). As a result, if properly sited and constructed,
impacts from these plants would be less than other steam cycle plants.
The greatest impact on the terrestrial biota resulting from natural gas
or distillate-fired steam electric would be loss or alternation of habitat.
However, since these plants are limited to 10 MW, land requirements for plant
development should be approximately 6 acres. Thus, these plant types
encompass l;UII~ i dentb ly 1 ess 1 and area than other steam cycle pI ants and
impacts are not expected to be significant. Also, natural gas and
distillate-fired power plants would probably be placed near existing
developments, thus avoiding environmental problems associated with plants
sited in remote areas.
2.2.5 Socioeconomic Considerations
Because plant size is limited to 10 MW, socioeconomic impacts will vary
with location rather than with scale of plant. Primary sites for oil-fired
plants occur near existing refineries or along distribution pipelines.
Secondary sites are located along the railroad, and major highway corridors.
Sites for gas-fired plants would be located near the gas transmission line
that links Soldatna to Anchorage.
2.23
The flexibility of siting a power plant, particularly an oil-fired plant,
results in numerous potential sites. Assuming good access, a 10-MW unit could
be constructed in 18 working months. This estimate is based on a packaged
boiler and skid mounted auxiliary equipment. Tank construction for oil firing
may add to the construction work force but the overall construction period
should be the same as for a gas-fired plant because tank work can proceed
simultaneously with the boiler and turbine installation. The construction
work forces are estimated to peak at 60 for an oil-fired unit and 50 for a
packaged gas unit. The difference is due to the tank and unloading facilities
needed for oil-fired units. Operational manpower. on the two types of firing
are basically the same and are estimated at 20 workers. In order to mitigate
a boom/bust cycle caused by the influx of workers, sites should be constrained
by the population size of the nearby communities. While very small
communities would be significantly affected by the influx of construction
workers, small communities should not be, assuming that temporary housing is
provided for the workers (see Appendix ). Primary locations meeting this
criterion which are near a distribution pipeline include Anchorage, Soldatna,
and Fairbanks. Secondary locations include Kenai, Seward, Wasilla, and
Palmer.
Expenditures that would flow out of the region due to the development of
these facility types would include investment in equipment and employment of
specialized supervisory personnel. Due to the moderate-sized construction
workforce and relatively short installation period, it can be expected that
25% of the project expenditures would be made within the region while 75%
would be sent outside Alaska.
2.2.6 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. There are plans for adding
refinery capacity in the Valdez area, the point of termination of the Alaska
pipeline. Petroleum pipelines carry refined products from the
Whittier to Anchorage. These areas are prime sites since fuel
pipeline transmission systems are already in place.
2.24
refining or
Areas served by good transportation facilities connecting to the
refineries 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. To supply a 10-MW plant operating at
capacity, approximately two to three tank truck deliveries per day would be
required.
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 system.
2.3 BIOMASS-FIRED STEAM-ELECTRIC CONSRATION
Biomass fuls potentially available in the Railbelt region for power
generation include sawmill residue and municipal waste. Biomass fuels have
I
been used in industrial power plants for many years. Biomass plants are
distinct from fossil~fired units in that maximum plant capacities are
relatively small; in addition, they have specialized fuel handling
requirements. The generally accepted capacity range for biomass-fired power
plants are approximately 5 to 60 MW (Bethel et al. 1979; Jamison 1979). The
moisture content of the fuel, as well as the scale of operation, introduces
thermal inefficiencies into the power plant system.
2.3.1 Technical Characteristics
The core of the biomass-fired power plant is the boiler and the
turbine-generator. Like the coal-fired power plant, ancillary systems exist
for fuel receiving, storage and processing, stack gas cleanup, bottom and
fly-ash handling, and condenser cooling. Fuel processing equipment is
particularly critical if spreader-stoker firing is used. Tramp iron(a) must
be removed from the biomass fuel usually by magnetic means. Preferably,
municipal waste will be shredded and classified, and sorted to minimize
contamination by metals and glass objects. Mass burning (firing of unsorted
(a) Foreign objects of iron and steel
2.25
refuse), while practical in some cases, requires less efficient operation of
the equipment. Research in such areas as fuel preparation and fuel
gasification is underway to improve upon and overcome limitations in the
efficiency of biomass power plant systems caused by moisture content, low bulk
densities, and modest heating values.
Biomass plant efficiencies improve rapidly as the scale of a plant
increases. Conversion efficiencies as a function of plant size are shown in
Table 2.6 (Tillman 1980). The equivalent heat rates are also shown.
TABLE 2.6. Conversion Efficiencies
Thermal Heat
Plant Size Efficiency Rate
(Megawatts) (Percent) (Btu/kWh)
5 17 20,000
15 23 15,100
25 24 14,200
35 24 14,100
50 24 14,000
Biomass facilities, which would be operated as base-load units, have
demonstrated high reliability. Industrial experience shows that load factors
of 80 to 90% can be achieved. High load factors are attained by constant
attention to maintenance and by proper design. Plant reliability is a
function of the individual reliability of the numerous parts of the system,
including fuel receiving, preparation, and handling systems; the boiler
itself; the turbine-generator and associated steam equipment; and pollution
control system (Jamison 1979). Increasing the complexity of any system has a
tendency to diminish reliability.
Fuel handling systems in the Railbelt area will have to be designed to
accommodate cold conditions and frozen fuel.
2.3.2 Siting and Fuel Requirements
Biomass fuels are generally inexpensive but are characaterized by high
moisture content, low bulk densities, and modest heating values. Typical net
heating values of biomass fuels are compared to coal below:
2.26
Fuel Btu/lb
Municipal Waste 4000
Peat 5000
Wood 4500
Coal 9000
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 (e.g., wood
and municipal waste). For example, the estimated supply of both wood and
municipal waste biomass fuel in Greater Anchorage will support a 19-MW power
plant operating 24 hr/day at a heat rate of 15,000 Btu/kWh (see
Section 2.4.6).
The rate of fuel consumption is a functon of efficiency and plant scale.
Fuel consumption as a function of plant capacity is presented in Table 2.7
(Tillman 1980).
TABLE 2.7. Fuel Requirements by Plant Size
Plant Size
(Megawatts}
5
15
25
35
50
Hourly Fuel
Requirements
{tons}
11
25
40
55
80
Truck
Loads
Per Hour
1
2
3
4
Siting requirements for biomass-fired power plants are dictated by the
condition of the fuel, location of the fuel source, and cooling water
requirements. Because biomass fuels are high in moisture content and low in
bulk density, economical transport distances do not exceed 50 miles (Tillman
1978). Biomass power plants are thus typically sited at, or close to, the
fuel source and may function as part of a cogeneration system. Sites must be
2.27
accessible to all-weather highways since biomass fuels are usually transported
by truck. (Approximately four trucks per hour would be required, for example,
for a 50-MW plant.)
While proximity to the fuel source may be the most limiting factor, sites
also must be accessible to water for process and cooling purposes. 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.
Plants that use peat will require additional land for air drying the
fuel. A 1 to 3-month fuel supply should be provided to assure fuel
availability during prolonged periods of inclement weather.
2.3.3 Costs
Biomass-fired power plants, particularly of a small scale, are expensive
to construct. Construction periods range from 18 months to 3 years (not
including permitting). Capital and operation and maintenance costs for
relevant scale biomass facilities in Alaska are presented in Table 2.8.
TABLE 2.8. Cost Summary for Biomass-Fired Plants
Plant Size
15 MW
25 MW
35 MW
Capital
Costs ($/kW)
2,400
2,160
1,280
0 and M
Costs ($/kW)
68
68
68
Cost of Power
($/kWh)
Biomass-fired facilities require relatively small labor forces to
construct and operate. For a 15 to 30-MW plant, the construction workforce
would comprise 65 people; operating and maintenance will require approximately
25 people.
2.3.4 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 in light of the small plant capacities that are considered likely.
2.28
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 B. Impacts arise largely from
particulate matter and nitrogen oxides emitted by the system. The emissions
of particulates can be well-controlled by using techniques such as
electrostatic precipitators or baghouses. The tradeoff between emission
controls and project costs must be assessed at each facility, but wood burning
facilities larger than about 5 MWe will require the application of these air
pollution control systems.
Potentially significant impacts to aquatic systems from biomass plants
are similar to other steam cycle plants and result from the water withdrawal
and effluent discharge (refer to Appendix C). Although these plants are
second only to geothermal facilities in rate of water use (730 gpm/MW), their
total use for a typical plant would only exceed that of oil and natural
gas-fired plants because of the small size of prospective plants.
Approximately 18,250 gpm and 362 gpm would be required for once-through and
recirculating cooling water systems, respectively. Proper siting and design
of intake and discharge structures could reduce these 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 coal-fired plants, and are generally
intermediate between those for nuclear and the other steam cycle power plants
(see Table 0.1).
Potential primary locations of biomass-fired power plants in the Railbelt
region are near Fairbanks, Soldatna, Anchorage, and Nenana. Lands surrounding
these five areas contain seasonal ranges of moose. Waterfowl also inhabit
these areas with high use occurring along the Matunuska and Susitna River
deltas near Anchorage, and areas around Nenana. The Soldatna region also
contains populations of black bear and calving, migration corridors, and
seasonal ranges of caribou. Populations of mountain goats, caribou, and Dall
sheep occupy habitats in the Susitna and Matunuska River drainages near
Anchorage. Impacts on these animal populations will depend on the
characteristics of the specific site and the densitites of the wildlife
2.29
populations in the site area. Due to the relatively small plant capacities
involved, however, impacts should be minimized through the plant siting
process.
2.3.5 Socioeconomic Effects
Impacts of biomass-fired plants will vary among the primary locations
identified as well as with plant size. Anchorage, Fairbanks, and Soldatna
should be able to accommodate the construction of a 5 to 50 MW-plant with
minimal impacts to the social and economic structure of these communities.
The impacts of plant construction on Nenana may be significant and will
increase with plant size. The cause of these impacts would be the small
population size and undeveloped infrastructure. Neana, which is an Alaskan
native village, has a population of 471 and the surrounding area has an
aggregate population of approximately 1,000. The transfer of workers and
their families for a period of 3 to 5 years may cause a strain on the social
fabric of Nenana and 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 project 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.
2.3.6 Potential Applications in the Railbelt Region
Potential sources of biomass fuels in the Railbelt region include peat
(Figure 2.4), mill residue from small sawmills (Figure 2.5), and municipal
waste from the cities of Fairbanks and Anchorage.
Fuel availability for wood residue and municipal waste in the Railbelt
region is shown in Table 2.9 (Alaska Sawmill Directory).
Only broad ranges of wood residue availability have been developed since
little information is available on lumber production as a function of markets,
lumber recovery, and internal fuel markets. Volumes of municipal waste have
been identified from studies of refuse recycling in the Anchorage area
(Nebesky 1980). Fuel supplies for a wood or municipal waste-fired biomass
2.30
PEAT RESOURCES
SCALE 1: 2 500 000
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 2.4.
USGS ALASKA MAP E
100
... ,
<.\'m•'•l•
1,~~1~"'"
\•·
MAJOR CONCENTRATIONS AND
CAPACITIES OF SAWMILLS
in Thousand Board Feet per Day
(MBF/D)
SOURCE: Alaska Sawmill Directory .
""'*-·-......
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 2.5.
USGS ALASKA MAP E
TABLE 2.9. Fuel Availability for Wood and Municipal Wastes
Railbelt
Region
Greater Anchorage
Kenai Peninsula
Fairbanks
Nenana
Daily Tons Wood Fuel
(Tons/Day)
200-600
60-180
10-30
40-140
Municipal Refuse
(Tons/Day)
400
150
plant may be sufficient in greater Anchorage, but marginal in Fairbanks or the
Kenai Peninsula. Peat deposits are substantial as shown on Figure 2.5 but
many other fuels are available which compete economically with peat.
Biomass power plants in the Railbelt region may potentially contribute
0.5% to 5% of future power needs. As such, 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
particularly adaptable to the modest incremental capacity needs forecast for
the Railbelt region.
2.4 NUCLEAR STEAM ELECTRIC
Nuclear steam electric generation is a mature, commercially available
technology. At present, some 73 units with a total installed capacity of
54,000 MWe are operable in the United States. An additional 104 units
representing approximately 116,000 MWe 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 technologies
developed within those respective countries.
In spite of this impressive backlog of experience, nuclear power is
experiencing social and political problems that might seriously affect its
2.35
viability. These problems manifest themselves in licensing and permit delays,
and are thus of significance to the Alaskan electrical supply situation given
their cost and schedule impacts.
Diminished load growth rates, concerns over nuclear weapons
proliferation, adverse public opinion fueled by the Three-Mile Island (TMI)
accident, expanding regulatory activity (also fueled by TMI), and lack of
overt support at the highest political levels have all resulted in no new
domestic orders for nuclear units since 1977. The industry is currently
maintaining its viability through completion of backlog work on domestic units
and by pursuing new foreign orders.
2.4.1 Technical Characteristics
Nuclear power plants produce electricity using a steam cycle similar to
fossil fuel-fired power plants. However, in a nuclear power plant the heat
used to raise steam is obtained by fissioning of uranium fuel in a nuclear
reactor. A schematic of a typical reactor is shown on Figure 2.6. Heat to
produce the steam is generated from nuclear fission of uranium fuel in the
reactor core. In Boiling Water Reactor (BWR) designs, coolant water
circulates through the core and is heated to form steam, at about 1,100 psi,
above the core for use in the turbine. Pressurized Water Reactor (PWR)
designs include two coolant loops (Figure 2.6). The primary (reactor) loop is
operated at approximately 1,700 psi, so that the cooling water remains in
liquid form at all times. The hot 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, and thus are not discussed
here.
The economics and design trends since the introduction of commercial
nuclear power have evolved to the point that almost all plants being
constructed are in the 800 to 1,200 MWe range. This magnitude of electric
power and costs means that nuclear power is a viable option for only those
utilities with a high system demand. (There are nuclear units operating in
the lower 48 states with generating capacities ranging from 50 MWe to 700
2.36
N
w
""-'
REACTOR
WATER
FUEL
RODS
REACTOR
COOLANT
PUMP
STEAM
STEAM
GENERATOR
WATER
FEEDWATER
PUMP
STEAM
TURB. ELECTRIC
GENERATOR
COOLING
1--_. WTR OUT
COOLING
....__....._,~_ .-.J..J4--WTR IN
\CONDENSER
FIGURE 2.6. Steam Electric System using Pressurized Water Reactor
MWe. However, these are demonstration and first and second generation nuclear
facilities and represent unit sizes not currently available from vendors.)
Nuclear power generating plants are typically designed for operation as
base load units (for a 40-year commercial life) because of their
characteristically high capital costs and low operating costs. The more power
produced from the plant, the lower cost per unit of electricity delivered.
Since nuclear plants are designed as base-load units, they are not able to
follow load changes readily.
The day-to-day operations of a nuclear plant are less affected by
environmental conditions than many other technologies. The plants are
constructed to withstand high wind loads, tornadoes, storms, earthquakes,
etc. In addition, the containment building (housing the reactor) is designed
to withstand large, internally generated loads resulting from system failure.
These requirements result in heavy, strong structures relatively unaffected by
ambient conditions.
Nuclear plants require periodic replacement of the uranium fuel
assembly. Typically, plants can operate for over a year on a single
refueling. Because the plants must be shutdown for refueling, refueling is
normally accomplished during periods of low electrical demand.
To a large degree, plant availability is dependent upon the performance
of cooling equipment and electrical transmission lines, facilities which are
not significantly different from those employed in other large scale
generation technologies. The availability of nuclear plants is reported to be
approximately 70%, with the upper end about 85%, and is expected to rise as
more operating experience is gained.
2.4.2 Siting and Fuel Requirements
Nuclear plant siting has more constraints than other technologies because
of stringent regulatory requirements resulting from the potential consequences
of accidents involving the release of radioactive materials. These
requirements alone, however, would not be expected to bar the development of
nuclear power in Alaska.
2.38
Under the siting criteria of the Nuclear Regulatory Commission (10 CFR
100), nuclear facilities must be isolated to the degree that proper exclusion
areas and low population zones may be maintained around the facility. Nominal
distances ranging from 2,000 to 5,000 feet to the nearest site boundary
(encompassing areas of 250 to 2,000 acres) are typically sufficient to meet
the first criterion for almost any sized nuclear facility. Additionally, a
physical separation of 3 to 5 miles from areas of moderate population density
allows compliance with the second criterion. These requirements are of iittie
real consequence in the present case considering the low population densities
existing in the Railbelt region. In the Railbelt region land required for
location of the construction force campsite could serve as an exclusion area
around the plant perimeter upon completion.
Seismic characteristics of a potential site are a major factor in plant
siting since 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 2.7. Construction of a nuclear plant in
~ the Railbelt in Zone 3 would very likely require expensive plant designs and a
lengthy permitting process. Siting a plant in Zone 2 is less difficult. In
either case, extensive preapproval geotechnical investigations will be
required. Total exclusion of nuclear plants on this basis is not indicated
since nuclear plants have been designed and constructed on a worldwide basis
in each of the seismic zones found in the Railbelt region.
In addition to meeting the specific nuclear safety requirements of the
U.S. Nuclear Regulatory Commission (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 represents a major long-term
construction effort, involving the transportation of bulky and heavy equipment
and large quantities of construction materials. Means of transportation
capable of handling these items limit the potential Railbelt sites to the
corridor along the Alaska Railroad and port areas of Cook Inlet and Prince
William Sound. As noted previously, it is necessary to site a nuclear plant
in an area of low population density. This requirement for remote siting must
be balanced against the cost of transmission facilities required to deliver
power to high-density population areas and load centers.
2.39
.~ ,;JfJO
..
MtddJetOfll 1o1
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 (3.0.4.5)
2·Moderate Structural (4.5·6.0)
Damage
3·Major Structural Damage (6.0.8.8)
---Major Faults
SCALE 1: 2 500 000
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 2. 7.
USGS ALASKA MAP E
The heat rejected by a 1,000-MW plant is substantial; a potential site
must thus have a sufficient supply of cooling water to remove the heat in a
manner complying with environmental criteria for thermal discharges.
Once-through cooling of a 1000-MWe facility requires a water flow of
approximately 3,000 cfs and would almost certainly require coastal siting.
Closed cycle systems require less water than once-through systems (probably
less than 100 cfs), thus expanding the range of siting options to some of the
rivers of the region (Appendix G).
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 United
States. The proximity of the nuclear plant to the fuel source is relatively
unimportant compared to fossil-fired and geothermal plants. Uranium is a
high-energy density fuel, and refueling 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 occur during periods of low electrical demand.
Current estimates indicate known uranium supplies are sufficient to fuel
only those reactors now in service or under construction for their estimated
lifetime. However, the latest nuclear designs are capable of being fueled by
plutonium as well as uranium, and assuming that breeder reactors, producing
surplus fuel-grade plutonium, become commercial, then 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.
2.4.3 Cost
The capital cost of a nuclear plant is high relative to other base load
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
2.43
because of the added complexity of the secondary fluid loop; however, this is
offset by the higher costs of the BWR's containment building and shielding.
Estimated nuclear power plant costs, adjusted for Alaska, are shown in
Table 2.10.
TABLE 2.10. Cost Summary for Nuclear Power Plants
Capital Costs $1850/kW installed capacity
Operation and Maintenance $13/kW/yr
2.4.4 Environmental Considerations
Water resource impacts associated with the construction and operation of
a nuclear power plant are generally mitigated through appropriate plant siting
and a water and wastewater management program (Appendix A). It should be
noted, however, that due to the large capacities required for nuclear power
stations {1000 MW}, the magnitude of water withdrawal impacts associated with
a given site may be greater than for other baseload technologies. Magnitude,
however, does not necessarily imply significance. A favorable attribute of
nuclear power is the lack of wastewater and solid waste associated with fuel
handling, combustion, and flue gas treatment experienced in other combustion
steam cycle technologies.
Nuclear power plants cause no deterioration in the air quality of the
locale, other than the routine or accidental releases of radionuclides. To
assess the potential dosages of these radioactive materials, a complex
meteorological monitoring program is required. The wind speeds and dispersive
power of the atmosphere play a crucial role in diluting the effluent.
Generally, sites in sheltered valleys and near population or agricultural
centers are not optimal from a meteorological point of view. Large amounts of
heat are also emitted by nuclear power plants. Some modification of
microclimatic conditions onsite will be noted, but these modifications will be
imperceptible offsite. The U.S. Nuclear Regulatory Commission 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 at many locations in the Railbelt
region.
2.44
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. The minimum size for a nuclear facility (1,000 MW) indicates
that these plants would be the largest water user of any steam cycle plants,
using approximately 310,000 gpm for a once-through cooling system and
6,200 gpm for a recirculating cooling water system. Their rate of use
(gpm/MW) is also higher than many other technologies (Table A.1) because of
somewhat lower plant efficiencies. Potential impingement and entrainment
impacts would therefore be somewhat higher than for other base load
technologies of comparable size. Detrimental effects of discharge may also be
high because of the large quantity of water used. But the discharge water may
have fewer hazardous compounds than may be found in other steam cycle
wastewaters.
The predominant biotic impact on terrestrial biota is habitat loss.
Nuclear power plants require land areas {100-150 acres) second in size to
those of coal-and biomass-fired plants. Furthermore, lands surrounding the
plant island are at least temporarily modified by ancillary construction
activities (i.e., laydown areas, roads, etc.). Partial recovery of these
lands could possibly be accomplished through revegetation. Other impacts
difficult to mitigate could be accidental releases of radionuclides. The
effects of such accidents on soils, vegetation, and animals could be
substantial. However, proper plant design and construction should prevent
these emissions. One positive feature of nuclear power is the absence of air
pollution emissions and resulting effects on biota.
2.4.5 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 base load
technologies, a nuclear power plant has the greatest potential to adversely
affect localities. The construction of a nuclear facility could severely
strain nearby communities' abilities to provide housing, public services and
facilities, and commercial goods and services. Highly skilled workers would
2.45
be required during both the construction and operating phases, adversely
affecting regional participation in the labor force. The in-migration of
construction workers would be augmented by spouses and dependents. The long
duration of the construction 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. However, the siting of a nuclear plant 25
to 50 miles from Anchorage could induce further urban sprawl. Communities
with populations of 5,000 or less would experience severe impacts.
Depending on location of the site, a new town could be built for
accommodating the workers and their families. At the termination of the
construction, most of the construction work force and their families would
leave the area, leaving an 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.
The proportion of project expenditures sent outside the Railbelt would be
approximately 60% since all equipment and most of the labor would be imported
from the lower 48 states. Expenditures on site improvements, with the
exception of purchasing cement and reinforcing steel outside the region, would
be made within the Railbelt.
2.4.6 Potential Application in the Railbelt Region
As discussed in Section 2.4.2 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 of
the need to deliver large amounts of construction material and very large and
heavy components to the site. Interior siting would have more favorable
seismic conditions.
More constraining than site availability is the rated capacity of
available nuclear units in comparison with forecasted electrical demand in the
2.46
Railbelt region. The Railbelt System, with a forecasted interconnected load
of 1,800 MW in 2010 (see Chapter 1), will probably be too small to accommodate
even the smaller nuclear power plants, primarily from the point of view of
system reliability. If nuclear power were available to the Railbelt System,
significant reserve capacity would still have to be available to provide
generating capacity during scheduled and unscheduled outages.
In addition, the large capacity of most current nuclear units limits the
adaptability to growth to very large increments, which are not characteristic
of projected Railbelt demands. Nuclear capacity is not added easily, as a
strict licensing, construction, and operation process must be followed.
2.5 GEOTHERMAL
Geothermal energy is defined as the heat generated within the earth's
interior. If this heat is close to the surface, it may be tapped as an energy
source. Geothermal energy may be utilized for electricity generation, which
usually requires temperatures of at least 280°F, or for direct applications
at 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.
Approximate required temperatures of geothermal fluids for various
applications is presented in Table 2.11.
Three types of geothermal resources hold potential for development:
hydrothermal, geopressured brine, and hot dry rock. Only hydrothermal systems
are in commercial operation today. 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
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
approximatly 450oF.
Liquid-dominated systems may be subdivided into two types, those
producing high enthalpy fluids greater than 200 calories/gram (360 Btu/lb),
2.47
TABLE 2.11. Approximate Required Temperature of Geothermal Fluids
for Various Applications
Saturated
Steam
Hot
Water
180 Evaporation of highly concentrated solutions
Refrigeration by ammonia absorption
Digestion in paper pulp (Kraft)
170
160
Heavy water via Hydrogen sulphide process
Drying of diatomacious earth
Drying of fish meal
Drying of timber
150 Alumina via Bayer's process
140 Drying farm products at high rates
Canning of food
130 Evaporation in sugar refining
Conventional
Power
Production
Extraction of salts by evaporation and crystallistation
Fresh water by distallation
120 Most multi-effect evaporation; Concentration of saline
solution
110 Drying and curing of aggregate slabs
100 Drying of organic materials, seaweeds, grass, vegetables,
etc.
Washing and drying of wool
90 Drying of stock fish
Intense de-icing operations
80 Space-heating (buildings and greenhouse)
70 Refrigeration (lower temperature limit)
60 Animal husbandry
Greenhouses by combined space and hotbed heating
50 Mushroom growing
Balneology
40 Soil warming
30 Swimming pools, biodegradation, fermentations
Warm water for year-round mining in cold climates
De-icing
20 Hatching of fish. Fish farming.
Source: Armstead, H. 1978.
2.48
and those producing low enthalpy fluids less than 200 calories/gram. The high
enthalpy fluids may be used to generate electrical power; the lower enthalpy
fluids may be useful for direct heating applications (Considine 1976).
Wells drilled into high enthalpy, liquid-dominated systems produce a
mixture of steam and water. The steam may be separated for turbine operation
to produce electricity.
2.5.1 Technical Characteristics
The specific type of plant which could be selected to develop the Alaskan
geothermal resources will depend on the temperature, pressure, and quality of
the geothermal fluid. Four geothermal generating technologies are currently
used: 1) dry steam; 2) flashed steam in either single or multiple flash
units; 3) binary plants which use secondary working fluids because the direct
use of the geothermal resource is either impossible or undesirable; and 4) a
combination of flashed steam and binary fluids. A fifth plant type, not yet
in use, is a hybrid in which geothermal resources are used in conjunction with
fossil fuels, solar energy, or biomass for electrical generation.
In a dry steam plant the 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 injected back into
the reservoir.
Flashed steam plants operate on steam flashed from de-pressurized hot
water brought to the surface. Utilization efficiency can often be increased
by flashing at decreasingly lower pressures (multiple flashing) to obtain as
much steam as possible from a given volume of water. Once the steam is
separated 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 systems is more technically demanding
for the liquid-dominated than for vapor-dominated systems. Certain
difficulties would be encountered in developing liquid-dominated systems:
larger masses of fluids must be produced to generate a given amount of
electrical energy; corrosion of well casing and piping may be excessive;
2.49
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 2.8, use secondary working fluids
such as freon, isobutane, or isopentane to drive turbines. The use of a
binary cycle plant allows for the generation of electricity with geothermal
fluids that are below the flashing temperature of water. Binary plants may
also use geothermal fluids whose direct use would be impossible because of
corrosion or scaling 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 drive turbo-generators, and condensed for reuse.
Generator
FIGURE 2.8. Binary Cycle Geothermal Power Plant
2.50
Air & water
vapor
Because the geothermal fluid is reinjected the reservoir pressure of the
geothermal fluid is maintained 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, thus extracting additional energy and making for
more efficient use of the resource.
Hybrid plants make use of geothermal resources together with ancillary
energy sources such as coal, biomass, or solar energy. The geothermal
resource is used as preheated feed water for a boiler fired by the ancillary
fuel. In some cases, such as with the use of biomass, the geothermal resource
can also be used to dry the organic fuel, thus increasing the burning
efficiency. The hybrid plant can utilize geothermal resources that are below
the temperature required to produce usable amounts of steam.
In a conventional geothermal electric generating plant, the working fluid
is withdrawn from the geothermal source, enters the turbine, is condensed, and
is either evaporated from the cooling tower, or reinjected into the
reservoir.
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 of between 50 and 60%. Plants receiving lower quality geothermal
energy will exhibit lower efficiencies because a portion 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 rates of the turbine are on the order of 22,000 Btu/kWh. This
2.51
is equivalent to a thermodynamic efficiency of 16%, which means that it would
require twice as much cooling water 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, maintenance
and source reliability. It is estimated that a geothermal plant in the
Railbelt region would be available approximately 65% of the time. Hot dry
rock resources would be used by injecting a working fluid, probably water,
into the hot rock using injection wells. The heated water would then be
brought to the surface using production wells where it would be flashed to
steam and used to drive turbo generators.
The low thermal conductivity of rock controls the rate of heat transfer
to the circulating fluid. Large surface areas are thus required for
geothermal utilization. Los Alamos Scientific Laboratory (LASL) is field
testing a rock-fracturing method based on conventional hydraulic fracturing.
By pumping high pressure water 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 from which the heated
working fluid is drawn.
2.5.2 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:
1. Fluid temperatures in excess of approximately 14ooc (2800F)
2. Heat sources at depths less than 10,000 ft with a temperature
gradient at 250F per 1,000 ft
3. Good rock permeability to allow heat exchange fluid to flow readily
4. Water recharge capability to maintain production.
2.52
Individual geothermal wells should have a capacity to supply 2 MW of
electricity. The power station's long term viability is dependent on the
prediction of reservoir energy capacity and management of reservoir
development.
The site must have access available for construction, operation, and
maintenance personnel, and a source of water available for condenser cooling
(and injection in the hot rock technology).
The land area required for the electrical generating and auxiliary
equipment portion of a geothermal 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.
2.5.3 Costs
Estimated capital costs and operation and maintenance costs of several
types of geothermal developments, including well field development, are shown
in Table 2.12. These are all 50-MW plants.
2.5.4 Environmental Impacts
A problem unique to geothermal steam cycles involves the water quality
characteristics of the geothermal fluid and the subsequent disposal method.
This fluid is generally saline and, because of this characteristic, most
geothermal plants in the United States mitigate this potential problem through
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 Cool Inlet shoud not prove
to be too difficult. The interior fields, however, could require extensive
wastewater treatment facilities to properly mitigate water quality impacts to
2.53
TABLE 2.12. Cost Summary for Geothermal Developments
Capital Costs 0 and M Costs Cost of Power(a)
System Type ($/kW) ($/kW/yr) ($/kW)
Vapor-dominated
cycle 900 0.035
Binary cycle 1550 0.052
Hot dry rock 2550 90 0.150
High-temperature
water 3400 0.101
Low-temperature
water 5300 0.151
General Average -
All Types 1100 65 0.040
(a) Cost of power calculated using general average O&M cost except for hot
dry rock case.
freshwater resources and comply with all relevant Alaska regulations.
Depending upon a specific field's water quality characteristics, the costs
associated with these treatment facilities could also preclude development.
Geothermal plants have the highest per megawatt use of any steam cycle
plant (845 gpm/MW). A maximum size plant for the Railbelt region (50 MW)
would use less water than only nuclear or coal fired-plants, with a total
water use rate of 42,200 gpm or 750 gpm for once-through and recirculating
cooling water systems, respectively.
Emissions of gases and particulates into the atmosphere from the
development of geothermal resources will consist primarily of carbon dioxide
and hydrogen sulfide (H 2s). Other emissions may consist of ammonia,
methane, boron, mercury, arsenic compounds, fine rock particles, and
radioactive elements. There is considerable variability in the nature and
amount of these emissions, and this uncertainty can be removed only by testing
2.54
wells in the proposed project area. Emissions are also a function of
operational techniques. If the reinjection of geo-thermal fluids is used,
emissions into the atmosphere may be reduced to nearly zero. Even when
reinjection is not used, H2s emissions can be controlled by oxidizing this
compound to sulfur dioxide (S0 2) and subsequently using conventional
scrubber technology on the product gases. Emissions may also be controlled in
the water stream by an 11 iron catalyst 11 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.
In addition to major potential impacts associated with water withdrawal
and effluent discharge that are similar for all steam cycle plants, geothermal
plants have some unique problems that may have hazardous effects on the
aquatic environment. 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 toxic nature of the brine. Current
regulations require reinjection of spent geothermal fluid; however, entry of
these brine solutions into the aquatic environment either by discharge,
accidental spills, or ground water seepage, could cause acute and chronic
water quality effects.
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 geothermal fluids into this system may have significant impacts on these
fish, and other aquatic organisms, depending on the size and locaton of the
release.
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
2.55
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.
The primary impact resulting from geothermal plants on the terrestrial
biota is habitat loss. Land requirements for geothermal plant facilities, on
a per-kW basis, are comparable to those for oil and natural gas plants.
Biomass, coal, and nuclear plants require larger tracts of land than
geothermal, either from the standpoint of capacity or kW production. However,
geothermal lands are more likely to be located in remote areas than other
steam cycle power plants. Disturbances to these areas could be extensive
depending on the land requirements of the geothermal well field.
Primary geothermal development locations are within the Wrangell and
Chigmit Mountains. The latter area is remote and is inhabitated 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. Impacts could 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 impose additional
disturbances to wildlife and vegetation from increased accessibility to
people.
2.5.5 Socioeconomic Effects
The construction of a 50-MW geothermal plant would require approximately
90 workers over a 7-year period. Although the construction workforce is
moderate in size, the remoteness of the geothermal resources will 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. Semi-permanent construction camps would be required to house
the workers. Impacts to the coastal communities may therefore be confined to
the disturbance caused from transporting equipment rather than from an influx
of workers.
Impacts to communities from development of the Wrangell Mountain resource
could be expected to be more severe since Glennallen (pop. 360) is a community
2.56
of sufficient size to attract workers and their families. The in-migration of
the workforce to Glennallen would place a strain on community infrastructure.
Similar to the Chigmit Mountain geothermal resources, haul roads would have to
be built from the Glennallen-Gakona-Gulkana area. Secondary impacts to the
communities would be associated with the transportation of equipment to the
site.
Project expenditures is estimated to be 55% outside the region and 45%
within the Railbelt. The large investment in production and reinjection wells
and equipment will be offset to some extent by the moderate-sized construction
workforce and long construction period.
2.5.6 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 2.9). 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 space heating. 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,
located approximately 200 miles from Anchorage, has subsurface temperatures
exceeding 12QQOF. The Chigmit System, 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.
A geothermal 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.
The geothermal areas (with the exception of Mt. Spurn) of both Wrangell
and Chigmit Mountains are located in lands designated as National Parks
(Figure 2.2). The federal Geothermal Steam Act prohibits leasing and
developing National Park lands. If, however, townships within these areas are
2.57
... ,
q.m,,,~
~~~totr"
"IJO
GEOTHERMAL RESOURCES
Source: U.S. Geological Survey Circular 726, Assessment
Geothermal Resources of the United States, 1975 .
\• ·....._·-......
SCALE 1 : 2 500 000
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 2.9.
USGS ALASKA MAP E
selected by a Native corporation under the Alaskan Native Claims Settlement
Act, and if the surface and subsurface estates are conveyed to private
ownership, then the federal government jurisdiction would not apply, and
development could be possible. The Alaska National Interest Lands
Conservation Act of 1980 allows the granting of rights-of-way for pipelines,
transmission lines and other facilities across National Interest Lands for
access to resources surrounded by National Interest Lands.
2.59
3.0 CYCLING TECHNOLOGIES
The primary characteristic of cycling technologies is the capability to
start and stop generating units on a daily or even more frequent basis
according to system demand. The cycling technologies would satisfy
intermediate load and peaking service electrical requirements in the Railbelt
region.
The lack of a regionai grid system and the unique growth pattern of the
Alaska Railbelt have resulted in technologies traditionally considered cycling
(certain combustion turbine and combined cycle units) being used for base load
service. This can be expected to change as the area grows and especially if
an interconnected system is developed.
Four currently available technologies and one emerging technology have
been identified as cycling technologies for purposes of this study:
• Combustion Turbines
• Combined Cycle
• Diesel Electric
• Hydroelectric
• Fuel Cells
The first four of these technologies already exist within 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 technologies considered in this study is provided in Table 3.1.
3.1 COMBUSTION TURBINES
Combustion turbines have been used for nearly two decades in the utility
industry primarily to provide peaking and emergency power generation.
Combustion 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 plants, and the
3.1
TABLE 3.1. Comparison of Cycling Technologies on Selected Characteristics
First Stage Combustion Turbines Combined Cycle Diesel Hydroe 1 ectr·i c Fuel Cells
Attributes 70 MW 200 MW 12 MW 50 MW 10 MW
1. Aesthetic Intru-
siveness
A. Vi sua 1 Impacts Minor Moderate Minor Moderate to Minor
Significant
B. Operating Noise Moderate Minor Minor Minor Minor c. Odor Minor Minor Minor Minor Minor
(Municipal Waste)
2. Impacts on Biota
A. Aquatic)Marine
(gpm)(a 0 600 0 Site-Specific 20(C)
B. Terrestrial
(acres) (b) 6 12 4 Site-Specific 2
3. Cost of Energy
A. Capital Cost 560 960 700 4000 650
($/kW)
B. O&M Cost 40 42 35 13 3.30
($/kW) c. Fuel Cost
D. Cost of Power
w ($/kW)
N 4. Health & Safety No direct safety No direct safety No direct safety Safe Safe
A. Public problems. Possible problems. Possible problems. Possible
long-term air long-term air air quality degrada~
quality quality tion
degradation. degradation.
5. Consumer Effort Utility operated. Utility operated. No Utility, community Utility operated. No Utility operated. No indi-
No individual or individual or commu-or individual individual or commu-vidual or community effort
community effort nity effort required. operated. nity effort required. required.
required.
6. Adaptability to Packaged units can Additional units Additional units can Additional units can Additional units can be
Growth be added relatively can be added. be added. be added. added
A. Adjustments in eaily to existing
plant scale site.
7. Reliability
A. Availability (%) 88 85 90 90 95
8. Expenditure Flow
From Alaska
A. Capital Cost (%) 80 70 80 65 80
TABLE 3.1. (contd)
First Stage Combustion Turbines Combined Cycle Diesel Hydroelectric Fuel Cells
Attributes 70 MW 200 MW 12 MW 50 MW 10 MW
B. Operation and
Maintenance
Cost (%} c. Fuel Cost
g. Boom/Bust
A. Ratio of Con-30:12 45:15 25:2 200:6 90:10
struction to
Operating
Personnel
B. Magnitude of Minor to moderate Minor to moderate Minor in all Severe in small com-Significant to very small
Impacts in all locations. in all locations. other locations. munities. Moderate conrnunit ies. Minor to
to significant in moderate in all other
Fairbanks & inter-locations.
mediate sized com-
munities. Minor in
vicinity of Anchorage.
10. Control of Technology
A. Utility Primary Control Primary Control Primary Control Primary Control Primary Control
B. Individual Limited through Limited through Potential for Limited through Limited through regulatory w regulatory regulatory individual control. regulatory agencies agencies and government.
w agencies and agencies and and government.
government. government.
Second Stage
Attribute
1. Commercial Avail-Mature Mature Mature Mature Emerging
ability
2. Railbelt Siting Limited to fuel Limited to fue 1 Limited to fue 1 Numerous sites Numerous sites available.
Opportunities delivery consid-delivery consider-delivery considera-available.
erations. erations. tions.
3. Pr·oduct Type Base load Base load Base load Base load Base load
Intermediate Intermediate Intermediate Intermediate Intermediate
Peaking Peaking Peaking Peaking Peaking
4. Generating Capacity
A. Range in Unit
Scale (MW}
3-80 15-150 30 KW -15 MW 50 MW -700 MW >40 KW
(a) Recirculating cooling water systems.
~b) All facilities.
c) Water produced and discharged.
petroleum-based fuels, which they most readily use, are in short supply. The
relative inefficiency of these units can be overcome by incorporation of gas
turbines into more efficient cycles (such as combined cycle, cogeneration, or
regenerative cycle) in which increased thermodynamic efficiencies stem from
the use of rejected heat. The fuel availability problem may be overcome by
development of synthetic fuel production (Appendix J).
3.1.1 Technical Characteristics
The combustion turbine power plant uses a gas turbine engine as the prime
mover. This engine, which is similar to a typical aircraft jet engine, can
burn either liquid or gaseous fuel. The fuel is burned continuously in the
presence of compressed air, and the hot exhaust is allowed to expand through a
power turbine. The power turbine drives the inlet air compressor and the
electric power generator, as shown in Figure 3.1. The fact that hot gas is
the working fluid in a combustion turbine gives rise to the gas turbine.
Combustion turbine powerplants have traditionally been less efficient
than conventional fossil-fired generating stations. However, recent advances
in combustion turbine technology, particularly improvements in blade
metallurgy and cooling and improvements in combustor efficiency, have
significantly increased combustion turbine output and efficiency.
Heat rate and conversion efficiency of combustion turbines are presented
below for different plant sizes.
Plant Size
(MW)
20 -100
0.5 -20
Heat Rate
(Btu/kWh)
10,000 -11,000 (LHV)(a)
12,000 -14,000 (LHV)(a)
Conversion
Er fit; i em.:y
(Percent)
34
28
(a) Lower heating value. For natural gas the LHV is
910 Btu/ft3 and the higher heating value is 1024
Btu/ft3.
3.4
GENERATOR
EXHAUST
GAS
fl
POWER TURBINE
~
COMBUSTORS t FUEL
FIGURE 3.1. Simple Cycle Combustion Turbine
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 have been
developed which utilize a portion of this exhaust gas heat to improve
efficiency. Combined cycle and cogeneration, which are discussed in separate
technology profiles, are two examples. A regenerative cycle is another
example. In the regenerative cycle, air leaving the compressor section is
channeled through an air-to-air heat exchanger located in the turbine
exhaust. The energy thus absorbed by the combustion air decreases the
requirement for fuel and can increase 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 powerplants.
A minimum economical plant size for combustion turbines is 500 kW, which
could serve a community of 80 to 100 households. Combustion turbine power
3.5
plants are not complex to build since most of the equipment arrives at the
site assembled. The machines are reliable; they are available to meet demand
approximately 88% of the time.
3.1.2 Fuel Requirements
Combustion turbines can use a wide variety of natural and synthetic
fuels, from heavy residual oils to medium Btu synthesis gases. Combustion
turbines operating in the Railbelt use natural gas produced in Alaska, or
distillate oil similar to grade DF-2. The performance of the turbine varies
slightly with each fuel. While 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 from the stand-
point of performance and operating simplicity. Heat rates are generally
better and exhaust emissions, especially for sulfurous oxides and particu-
lates, are almost non-existent. 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 utilized, 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 with
appropriate treatment. Distillate oil can contain sulfur, fuel ash, and trace
metals not generally present 1n 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
minimal 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. Thus is may be more economic to use even with treatment costs.
Combustion turbines are capable of burning a variety of synthetic fuels,
although little operating experience with synthetics has been gained to date.
3.6
This is due mainly to the high cost and limited availability of synthetic
fuels. However, certain synthetic fuels, notably gas synthesized from coal,
is approaching economic viability. Potential application of synthetic fuels
to Railbelt power facilities are described in Appendix J.
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, with only a minimum of modifications to existing
hardware required.
Methanol produces fewer emissions than petroleum-based fuels. Methanol
contains virtually no nitrogen and no sulfur. Further, since methanol has a
theoretical flame temperature approximately 3000F below that of distillate
oil, thermally produced NOx emissions are substantially reduced. Carbon
monoxide (CO) emissions are increased slightly, but are still comparable to
distillate CO emissions, especially when water injection is required to reduce
NOx emissions in distillate oil.
A fuel transportation system must be provided to use any of these fuels.
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
reliability of the source of supply. Both storage and transportation of
low-Btu gas is impractical, which thus requires the combustion turbine power
plant to be located adjacent to the gasification plant. Medium-Btu gas can be
transported economically via pipeline to distances up to approximatly 100
miles. This removes the limitation of locating the combustion turbines at the
gasification plant, and in fact, 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.
3.1.3 Siting Requirements
The simple cycle combustion turbine power plant has fewer siting
constraints than conventional fossil-fired or nuclear plants. Only limited
3.7
space is required, no cooling water is required, and operating personnel are
not necessary. The primary siting constraints relate to atmospheric emissions
and fuel supply.
One of the primary siting constraints of the combustion trubine
technology is environmental. The exhaust from combustion turbines typically
contains oxides of sulfur (SOx) when residual fuels are used, as well as
oxides of nitrogen (NOx) with residual fuels or natural gas. These
constituents comprise the main 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 utilized. 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.
Future power plants using synthetic fuels derived from coal will have to
be located adjacent or close to the coal conversion 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
transportation constraints that exist for liquid petroleum fuels would apply.
3.1.4 Costs
Combustion turbine powerplants are generally regarded as having the
lowest capital cost per kilowatt of any current technology. The brief
construction times, often 1 year or less, contribute to low construction costs.
As with any other facility, there is some economy of scale 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 capital costs are presented in Table 3.2.
3.8
TABLE 3.2. Estimated Costs for Combustion Turbine Power Plants
Capital 0 and M Cost of
Plant Size Cost Cost Power
(MW) {$/kW) ($/kW/yr) ($/kW}
50 -100 60 40
50 and under 20 40
Operation and Maintenance costs vary drastically and published costs can often
be misleading. Even with identical combustion turbines, many operators report
significantly different 0 and M costs. One reason for this is because
maintenance costs are more directly associated with operating 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.
Improper fuel selection and inlet air contamination can also have detrimental
effects. Also, maintenance practices differ significantly among utilities.
Some utilities rely heavily on preventative maintenance, while others only
perform maintenance as necessary. In addition, the methods of recording 0 and
M costs are not uniform, and differences in reported costs may result purely
from accounting practices.
3.1.5 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
insignificant.
Combustion turbine generators are comparatively inoffensive sources of
air pollution when compared to alternative fuel combustion technologies. This
comparison is provided in Appendix B along with a detailed discussion of the
regulatory framework and various siting considerations. Sulfur emissons can
be controlled through use of low-sulfur oils or natural gas. Emissions of the
oxides of nitrogen can be controlled by use of water or steam injection
3.9
techniques. These emissions will not preclude the siting of combustion
turbines anywhere in the Railbelt region, except that it may be difficult to
justify their operation within the Fairbanks or Anchorage non-attainment
areas. Optimum siting would involve a consideration of these areas as well as
nearness to fuel lines, fuel ports, and load centers.
Because cooling water is not required for combustion turbines, there
would be no impacts on aquatic biota associated with operation of combustion
turbines. The only potential impacts would be from construcitn runoff (refer
to Appendix C). The use of proper construction techniques would eliminate any
potential for impacts on the aquatic environment.
Land losses and human disturbance represent the most significant impacts
on the terrestrial biota resulting from combustion turbine power plants. Land
losses, however, will generally be small (3 acres for 170 MW plant). These
losses will be increased if fuels requiring storage and waste disposal
facilities are used. The overall land requirements for combustion turbine
plants are usually smaller than those for combined cycle, fossil fuel, or
other conventional power plants.
In addition to land losses, combustion turbine power plants fueled by
fossil-or syn-fuels release gaseous and particulate matter that could afffect
the terrestrial biota. Depending on the fuel type, S0 2 and certain trace
elements could be the most ecologically offensive pollutants. The impact of
toxic air emissions as well as habitat loss and human disturbance on soils,
vegetation, and wildlife are described in Appendix D. In the Railbelt region,
these impacts could be minimized by siting plants away from sensitive
ecological communities and installing effective pollutant control devices.
3.1.6 Socioeconomic Effects
Due to the relatively small workforce and acreage requirements for
combustion turbine development, impacts can be expected to vary more with
location than with plant scale. The absence of major siting constraints
allows flexibility in locating a combuston turbine facility. Thirty
construction workers will be required for a 170-MW plant for a period of
9 months. To minimize impacts, combuston turbines should not be sited in very
small towns, although the installation of a construciton workcamp would lessen
3.10
the demand for housing and public services. Primary sites would be Anchorage,
Soldatna, and Fairbanks. Secondary sites would include Kenai, Seward,
Wasilla, Palmer, and North Pole.
Since a combustion turbine is a cpaital-intensive facility, 20% of the
project expenditures would be invested within the Railbelt while 80% would be
spent outside the region.
3.1.7 Potential Application to Railbelt Region
Combustion turbine power plants found in the Railbelt vary from 3 MW 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 Railbelt.
The main reasons for their wide use in the Railbelt have been their low
I capital costs, relatively small unit size, and the availability of gas and
distillate fuels.
The potential for future application of this technology is somewhat
clouded by the provisions of the Fuel Use Act, which restricts the use of
petroleum fuels and natural gas. Simply stated, new units that use petroleum
fuels or natural gas may operate 1500 hr/yr as peak load units. After 1990
the use of natural gas is prohibited. It is possible however, to use
combustion turbine power plants that are integrated with a coal conversion
plant or fueled by a product from such a plant such as low or medium Btu gas,
methanol, or distillate oil.
3.2 COMBINED CYCLE
The combustion turbine combined cycle power plant relies on two proven
technologies, the combustion turbine and conventional steam cycle power
generation. This is an efficient and reliable generating resource which has
been in commercial operation well over a decade. These plants are capable of
closely following growth in demand since generating capacity can be added in
relatively small increments, especially compared to technologies such as
coal-fired or nuclear steam electric.
3.11
3.2.1 Technical Characteristics
The combined cycle power plant uses two different thermodynamic cycles
simultaneously to produce electricity. (This differs from cogeneration, which
produces two forms of energy, electricity and process heat.) A combustion
turbine combined cycle consists of a conventional combustion turbo-generator
(as described in the combustion turbine profile) with a heat recovery boiler
supplying a steam turbo-generator. The heat recovery boiler utilizes 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 which would otherwise go to waste, 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 3.2.
The early combined cycle plants resulted from ••repowering" existing
steam-electric generating facilities. Combustion turbines with heat recovery
boilers were retrofitted to provide steam for ex'isting steam turbine
generators. When fuel prices increased drastically during the mid-seventies,
several utilities converted simple cycle combustion turbine plants to combined
cycle operation, 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 3.2). The steam cycle can be started up when
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
combustion turbines are out of service. This allows a combined cycle plant
considerable flexibility in terms of electrical output.
Combined cycle power plants can be erected more rapidly than conventional
large power plants of equivalent capacity, with 2 to 4 years a typical
construction time for a new plant. They are usually constructed in phases,
3.12
HEAT
RECOVERY
BOILER
GENERATOR
(
EXHAUST
GAS
(I
----r--~---.--:----r---"-COOL/ NG
WATER
d 4 d d
COMBUSTORS
FIGURE 3.2. Combined Cycle Combustion Turbine
with the combustion turbine portion erected first. This allows the combustion
turbines to generate power while the balance of the plant is still under
construction. Combined cycle plants have therefore traditionally been used
where generation is needed to fill critical shortages.
The minimum size of a large-frame combustion turbine combined cycle plant
is 90 MW. This is slightly larger than a large combustion turbine plant
(60 MW). A 90-MW combined cycle plant can economically serve a community of
3.13
26,000 households. Anything smaller would not be economically viable. The
reliability of combined cycle compares favorably with other technologies based
on combustible fuels. Combined cycle power plants are available, on average,
88% of the time, compared to nuclear steam electric 78% and natural gas-fired
steam electric 92%. The response time to changes in load is very good, making
a combined cycle useful for load following applications.
Combined· cycle plants are considerably more efficient than simple cycle
combustion turbine plants, since turbine exhaust heat is converted into useful
electrical energy. Whereas a simple cycle plant may have a heat rate in the
11,000 to 12,000 Btu/kWh range, a combined cycle heat rate may be as low as
8,500 Btu/kWh (a thermal efficiency of approximately 40%). Compared to other
conventional fossil generation technologies of comparable capacity, a combined
cycle plant would use less fuel and reject less heat to the environment.
Combined cycle plants are generally used for intermediate duty
applications (2,000 to 4,000 hr/yr), but they are efficient enough for base
load operation. For example the Anchorage Municipal Light and Power Anchorage
2 Plant is operated as a base load plant. Since the combustion turbines can
be operated independently of the steam cycle, combined cycle plants can also
meet peaking duty requirements.
3.2.2 Siting and Fuel Requirements
Like the simple cycle combustion turbine plant, a combined cycle plant
has siting constraints related to air emissions (see Section 3.1). In
addition, the combined cycle plant has further constraints imposed by the
steam cycle, which requires water for condenser cooling and boiler make-up.
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 are the same as those described in
Section 3.1 for combustion turbines. Natural gas, distillates, and synthetic
fuels may be used. A typical 200-MW combined cycle plant composed of two
3.14
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.
3.2.3 Costs
Capital costs 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 3.3.
TABLE 3.3. Estimated Costs for Combined Cycle Facility
Capital Cost 0 and M Cost Cost of Power
Capac it~ {MW} {$/kW) {$/kW/~r} ($/kW/~r}
90 $1000 $1.60
200 920 1.60
Estimated capital costs of retrofitting a steam turbine/generator,and
heat recovery boilers to convert a simple cycle combustion turbine into a
combined cycle are presented below:
Capacity (MW)
90
200
Capital Cost
($/kW)
$240
320
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.
Operation and maintenance costs for combined cycle plants are fairly
constant over a large range of plant sizes. Operation and maintenance costs
for combined cycle plants seem to suffer the same recording and reporting
disparities as simple cycle combustion turbines. Reported operation and
maintenance costs vary considerably as a result of different operating and
maintenance practices as well as accounting practices.
3.15
It is interesting to note that reported operation and maintenance costs
for combined cycle plants are generally about 1 mill/kWh less than those for
simple cycle combustion turbine plants. This may be due to the fact that base
load operation typical of combined cycle plants is less demanding of machine
life than is the cyclic duty typical of combustion turbines.
3.2.4 Environmental Considerations
Water resource impacts associated with the construction and operation of
combined cycle power plant are generally mitigated through appropriate plant
siting criteria and a water and wastewater management program (refer to
Appendix A). A favorable attribute of combustion turbine combined cycle power
plants is that on a per-megawatt basis, these facilities require much less
water for cooling purposes than any other conventional steam cycle systems.
They also produce little solid waste, and therefore minimize disposal and
wastewater treatment requirements generally associated with these combustion
technology byproducts. Significant, or difficult to mitigate, water resource
impacts should therefore not pose restrictive constraints on the development
of this electric generating facility.
Air quality impacts are similar to those associated with combustion
turbines (see Appendix B). Emissions of nitrogen oxides can be controlled
through water or steam injection techniques while so 2 emissions can be
reduced by using low sulfur fuels. Additional water vapor is added to the air
from the waste heat rejection system of the boiler unit. The formation of
plumes can be eliminated by the use of a wet or wet/dry cooling tower system
(Appendix F). No offsite meteorological effects of system operation will be
detectable.
Potentially significant impacts from water withdrawal and effluent
discharge which are common to all steam cycle plants would be the lowest on a
per megawatt basis for combined cycle plants. The water use rate of these
facilities is only one-third that of the next lowest plant type, requiring
150 gpm/MW or 3 gpm/MW for once-through or recirculating cooling water
systems, respectively. Other potential impacts can be avoided by proper
siting, design, and construction techniques.
3.16
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 200-MW plant), but can be larger if plants are
fueled by distillate oil or certain types of synfuels which require on-site
fuel storage (12 acres). Distillate oil-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
terrestrial biota through gaseous and particulate emissions. so2 and
certain trace element emissions probably have the highest potential for
terrestrial impacts; this potential, however, is highly dependent on the fuel
type. Distillate oil-fired plants produce the highest levels of so 2
emissions while natural gas-fired plants produce almost none. The specific
impacts of these emissions and those associated with land loss and human
disturbance on the terrestrial biota are described in Appendix D. In the
Railbelt region, these impacts on soils, vegetation, and wildlife could be
minimized by siting plants away from sensitive ecological areas and installing
effective pollution control devices.
3.2.5 Socioeconomic Considerations
Construction of a 200-MW combined cycle plant requires 45 persons for a
period of 2 years. The operating and maintenance requirements would be
approximately 15 persons. Since the construction work force is relatively
small, impacts should vary more with site location than with plant capacity.
Severe construction related impacts could occur in very small communities
along the distribution pipeline or railroad 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.
Primary sites would include Anchorage, Fairbanks, and Soldatna. Secondary
locations adjacent to the railroad or major highway corridor include Kenai,
Seward, Wasilla, Palmer, and North Pole.
3.17
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 expenditures would be spent in the lower
48 states while 30% would be spent within the Railbelt.
3.2.6 Potential Application to The Railbelt Region
Use of the combined cycle technology is rather recent, with plants
currently operating in Anchorage and Fairbanks. However, prospects for
further use of this technology in Alaska would not appear good because of
provisions of the Fuel Use Act, which restricts new plants that use natural
gas or petroleum-based fuels. However, exemptions can be obtained for such a
plant if it is designed to use synthetic fuels derived from coal
{Appendix J). If coal gasification plants are built in the Alaska Railblet,
then large, base-loaded combined cycle plants could be integrated with the
gasification plant.
Sixty four percent of the installed capacity in the Railbelt region is
currently met by combustion turbine electric generation. Combustion turbine
plants serve most of the load in the Anchorage area and are used primarily to
meet peak loads in the Fairbanks area. The widespread use of combustion
turbines in the Railbelt area may provide an opportunity to increase
generating capacity through conversion to combined cycle plants. Heat
recovery boilers and steam turbines would be added to simple cycle plants to
provide more generation with no additional fuel use.
3.3 DIESEL GENERATION
Diesel generation accounts for approximately 5% of the Railbelt electric
generating capacity. Approximately 36 MW of utility capacity exists, while
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 when there is a power outage), peaking units, and standby units.
They also are used as load following units in remote locations and small
communities in the Railbelt. Diesel installations in the Railbelt region
range in size from 2 to 18 MW, although a much larger range is available.
3.18
Stationary diesel-generator sets have been built in capacities ranging from
30 kW to 15 MW. Units ranging in size up to 20 MW utilizing slow-speed,
two-stroke diesels are under construction.
3.3.1 Technical Characteristics
A diesel generating plant consists of a diesel cycle internal combustion
engine driving a standard electricity generator. The diesel engine was
invented to simulate the idealized Carnot thermodynamic 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 during combustion. Expansion of the products of combustion 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
rat1os are typically 12:1 to 15.1 contrasted with spark ignition ratios
ranging from 6:1 to 10:1 and can reach 20:1. It is these higher compression
ratios which contribute to the relatively high thermal efficiencies of diesel
units.
The fuel consumption of diesels is largely a function of thermal
efficiency. 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 units have achieved heat rates of 8,500-9,700 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 3.4).
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 Alaskan
locations may have a much shorter life because of poor maintenance.
3.19
TABLE 3.4. Fuel Consumption Rates and Equivalent Heat Rates
for a Diesel Generator Operating at Various Loads
Kilowatts
900
800
700
600
500
400
Fuel Consumption
(gas/hr)
70
60
52
45
39
32
Heat Rat~
(Btu/kWh) a)
11,100
10,700
10,600
1n 7nn ~V,/VV
11,200
11,400
{a) Assuming a heating value of 19,000 Btu/lb;
specific gravity of 0.9.
Diesel units are able to quickly respond to start-up and shut down.
These units are used in the Railbelt as black start units when other
generating units fail. They also serve in conjuncton with larger generating
base load systems as an emergency power source. Further, diesels can be used
to augment fuel saver technologies such as wind or tidal power when natural
conditions preclude power generation from the fuel saver technologies.
3.3.2 Siting and Fuel Requirements
Diesels are well-suited for generation throughout the Railbelt region.
The small high-speed units are compact, usually 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. Medium and low-speed units are larger,
usually site-erected, and require more foundation work. Diesel units require
a noise-suppressing weatherproof structure plus fuel storage facilities.
Sites for even the largest units seldom exceed 2-5 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
3.20
be remote controlled, allowing unattended operation. The principal site
constraints for diesel units include access to fuel supply, and site
accessibility via barge, rail, or truck. Air shipment of units has been used
in remote locations such as communities in the interior of Alaska.
Ancillary systems associated with diesel units are minimal. Fuel storage
is required, particularly in remote locations where fuel deliveries may be as
infrequent as once a year. Waste heat boilers may be attached for
cogeneration (see Section 5.1). The small size of diesel units, and the
relatively clean fuels consumed, generally eliminate the need for extensive
pallution control systems, although sound suppression is required.
Diesel units can be fueled by a variety of liquid and gaseous
hydrocarbons. Available data show that Alaska diesel units are fueled by
distillate 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, have also been proposed for diesel units, and their
adaptation to diesel generation cycles is under study.
3.3.3 Costs
Diesel power is expensive, but not in comparison to other options in
Alaska. Most of the capital cost expenditure is for the equipment, purchased
outside Alaska, and the transportation of that equipment to Alaska. Only a
small amount of on-site erection expenditures are necessary. For smaller,
high-speed units traditionally used in Alaska, operating costs are largely
incurred for purchase of fuels and lubricants. Remote control of several
systems by a single operator· ·is po~siule in multiple un1t systems.
Replacement of parts in remote villages is costly because of transportation
expenses for parts and possibly labor derived from Anchorage or the lower 48
states. In remote areas, consumers may play a role in diesel maintenance and
have a direct role in the decision to supply electricity.
Estimated capital, operation and maintenance, and estimated levelized
costs of power (in 1980 dollars) for various diesel plant capacities are
provided in Table 3.5.
3.21
TABLE 3.5. Estimated Costs for Diesel Electric Generation
Capital 0 and M Levelized Cost (a)
CaQacity (MW) Cost ($/kW} Cost {$/kW/~r) of Power ($/kWh)
3 850 55
6-9 800 45
12 700 35
I ' Based a fuel cost of $8.00/MMBtu (Appendix G). taJ on
3.3.4 Environmental Considerations
Diesel electric generating systems do not require cooling water or
continuous process feedwater for their efficient operation. They also 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 associated with diesel engines will be confined
mainly to carbon monoxide and particulates. Residual, high sulfur fuels are
generally not used in these engines. Carbon monoxide (CO) emissions can be
controlled through the use of catalytic converters, and particulate emissions
can be controlled through optimizing engine operation. In the Railbelt, these
facilities may be sited almost anywhere, but if they are prposed for the
carbon monoxide non-attainment areas (Anchorage and Fairbanks), regulatory
agencies may require the consideration of alternate viable sites.
Impacts on the terrestrial biota should be minimal. Land requirements
are small (less than 5 acres) and air pollution potential is low. Access road
requirements would also be minimal since plants would be sited in or adjacent
to developed areas. Other possible impacts due to noise and fuel storage can
generally be resolved through noise-suppression devices and the avoidance of
prime wildlife habitat during the siting process.
3.22
3.3.5 _ Socioeconomic Considerations
The impacts of siting diesel generators in the Railbelt are expected to
be minimal due to the inherent limitation of scale of plant (0.05-15 MW) and
absence of major siting constraints. Installation of a large diesel generator
would require a small construction crew of 5 to 25 workers for periods of
1 month to 1 year, depending upon unit size. One or two people on a part-time
basis could fulfill the operating and maintenance requirements. The work
force could be composed primarily of residents, making diesel power compatible
with very small, small, and intermediate-sized communities.
Since diesel electric generation is capital-intensive, a large portion of
the capital funds would be sent to the lower 48 states. Approximately 80% of
the capital investment of the project would be made outside of the Railbelt
while 20% would be spent inside the region.
3.3.6 Potential Application for Railbelt Region
Because small increments of capacity are available and because diesel
generators can be installed quickly, they can be used to provide base load
capacity or reserve capacity for small communities in the Railbelt region.
Their efficiency, particularly at partial loads, plus their reliability, make
them particularly suited to the remote villages. Cost of operation is the
limiting factor because of their dependence on high-priced refined petroleum
products.
3.4 HYDROELECTRIC ENERGY
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 economic viability of
hydroelectric developments depends on the arrangement of project features,
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
3.23
slow because transmission of electricity over great distances was
inefficient. As transmission efficiencies were improved, hydroelectric
developments progressed rapidly. In fact, for decades thermal plants served
primarily as standby in case of equipment failure or to supplement
hydroelectic power during peak demand hours. The more recent trend has been
toward the use of thermal power to carry base load with hydropower
supplementing thermal generation for peak loads.
Of the 610 million kilowatts of installed capacity for the United States
(U.S. DOE 1979), about 11.5% or 70.4 million kilowatts is hydroelectric
capacity. Most of this installed capacity and associated energy generation
are produced by conventional hydroelectric developments. 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.
3.4.1 Technical Characteristics
There are two basic types of hydroelectric plants: conventional and low
head.(a) By definition, conventional plants have heads greater than
20 meters (66ft), 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. There are, however, many
conventional and small high-head sites.
Small hydroelectric developments can be characterized as either complete
"scaled down" conventional developments or as additions of hydropower
generating facilities to existing dams. In remote areas, small hydropower
developments can provide a steady and reliable source of electricity, given
hydrologic conditions that would provide an adequate supply of water on a
year-round basis. Commonly, this development is a run-of-river type project
with little or no reservoir storage capacity. Small hydro projects are likely
to be less complex; thus, federal licensing and permit granting programs are
simpler, as are the physical facilities.
(a) 11 Head 11 is the difference between reservoir elevation and tailwater
elevation.
3.24
The major components of a conventional hydroelectric development include
a dam or diverison structure, a spillway for excess flows, turbines, a conduit
called a penstock to convey water from the reservoir to the turbines,
generators, control and switching apparatus, a powerhouse for housing
equipment, transformers, and transmission lines (see Figure 3.3). Additional
requirements may include fish passage equipment, trash racks at the entrance
to the penstock, 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 (channel into which water
is discharged after passing through the turbines). No two hydro power
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 topography of the area.
There are four types of dams, 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
containing spillway and low level outlets may be constructed across the main
river section with earth or rock-fill wing dams extending to either abutment.
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 of
transportation facilities.
A spillway is provided to discharge major floods without damaging the dam
and other components of the project. 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 spillway design flood (the largest
flood that statistically might be expected), normal discharge capacity of
outlet works, and the available reservoir flood storage.
3.25
RESERVOIR
A-ELEVATION
CANAL
FOREBAY
B·PLAN
SURGE
TANK I
HEAD
POWERHOUSE --...___.rr
PENSTOCK
TAILRACE
; ..........
POWERHOUSE
TAILRACE
FIGURE 3.3. Schematic Diagram of Typical Components
of a Hydropower System
3.26
If the turbines and generators are not located at the dam, various
combinations 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 terrain. However, penstocks are used for the
major portion of the elevation drop between the reservoir and the powerhouse.
A hydraulic turbine transforms the kinetic energy of flowing water into
mechanical energy that, when harnessed to a generator, performs usefui work.
There are three basic types of hydraulic turbines: 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
propeller), 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
reaction turbine is widely used for high-unit capacity and with hydraulic
heads in the range of 100 to 2,400 ft (medium range). Propeller-type reaction
turbines are used for hydraulic heads up to 100 ft.
The powerhouse that houses and protects hydraulic and electrical
equipment 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 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. The underground powerhouse is constructed in a natural or man-made
cavern. This arrangement is used in certain topographic conditions,
particularly narrow canyons, which preclude the convenient siting of a surface
powerhouse.
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 base load, cycling, or standby unit. It is capable of assuming
3.27
full load in a matter of minutes, and to follow 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 includes generator, turbine, and transformer
efficiencies and hydraulic friction losses. Transmission losses are not
included in this estimate. The response time for hydroelectric generators is
very good. When start-up 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. This characteristic improves
overall integrated generation and transmission system reliability of
hydroelectric generating facilities.
3.4.2 Siting Requirements
The power potential of a hydroelectric development is a function of the
head and streamflow available at a given site. If the head differential 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 in order to
provide storage and seasonal regulation without discharging water over a
spillway. Smaller, or low head, hydroelectric projects must be operated as
run-of-river, and therefore, are dependent 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. Flow duration data
(and head) are used to calculate average annual energy and dependable capacity
for the site.
3.28
The geophysical conditions at a site determine the availability and cost
of construction materials, type and height of dam, and required seepage
treatment. These conditions also strongly influence the general location of
major civil works for the project. Fault lines, sedimentary deposits,
potential seismic activity, and extensive depth to hard rock can cause
construction costs to soar, thus eliminating otherwise suitable sites.
3.4.3 Costs
Hydroelectric development capital investment costs 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 and
waterways vary considerably and may have little relationship to the installed
generating capacity. There is less variation in the costs of powerhouses, but
it is not unusual for two plants of the same capacity to have a cost
differential of 50%.
Civil components (dams, spillways and other nonmechanical or
nonelectrical) of low head and small hydro developments usually carry a
smaller percentage of the total development costs than features for
conventional hydro developments.
Capital cost information for hydroelectric development constructed in the
Railbelt area is scarce. Based on information from the 1976 Alaska Power
Survey Vol. I by the Federal Power Commission, we estimated hydro project
development costs were estimated for more favorable sites. Operation and
maintenance costs are determined primarily by plant size. Other factors
include the type of operation (base load or peaking), annual generation,
number and size of units, operating head, and other conditions peculiar to
individual plants. Estimated capital costs and operation and maintenance
costs for a 50-MW and a 200-MW hydro development are shown in Table 3.6.
TABLE 3.6. Estimated Costs of Hydroelectric Facilities
Capital 0 and M Cost of
Capacity (MW) Costs ($/kW) Costs ($/kW/yr) Power ($/kW)
50 4000 13
200 1750 5
3.29
3.4.4 Environmental Considerations
The physical configuration and operation of a hydroelectric facility can
cause a number of hydrologic impacts, the most obvious of which is the
creation of an impoundment. The change from a flowing-water to a still-water
environment is a fundamental modification of the hydrologic system.
Development of the reservoir also increases evaporation and groundwater
seepage. Both phenomena increase water losses to the watershed. In the low
runoff regions of the northern Railbelt area, these losses, if substantial,
could incur significant impacts by reducing downstream flow, especially during
the summer months.
Important hydrologic impacts are also associated with the operation of a
hydroelectric plant. Large diurnal fluctuations in river flow can result when
hydropower is used for peaking power or load following. Fluctuations that are
too large and rapid can adversely affect aquatic biota, and for the more
accessible small river projects, could be hazardous to downstream
recreationists. On a seasonal time scale, the reservoir level can vary
greatly, again potentially affecting aquatic biota and making the reservoir
unattractive for recreation (especially when the ~eservoir is low). If the
reservoir is so operated, it can have positive impacts by attenuating flood
flows, thereby helping prevent flood damage to property downstream. By
augmenting low river flows, the reservoir can improve water quality and
aquatic habitat. Flow attenuation can be a significant positive impact in
light of the fact that many rivers in the Railbelt region exhibit wide natural
flow variations.
Reservoir operation affects four parameters of water quality:
temperature, dissolved oxygen (DO), total dissolved gases, and suspended
sediment. Adverse impacts on temperature and DO can occur 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, elevated
river water temperatures downstream can result, causing adverse impacts on
aquatic biota (especially cold water fish). If all water released from the
3.30
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 can result in fish mortality. Supersaturation can
be minimized by various spillway designs 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 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. The latter scour problem can be mitigated by proper
engineering design.
The construction of dams and the development of fairly large bodies of
water (at least several square kilometers) will cause some variation in
meteorological conditions. Conditions will generally be less extreme near an
unfrozen reservoir, resulting in warmer nights and cooler days. There will be
no perceptible change in precipitation patterns. When reservoirs are frozen
and snow covered, nighttime temperatures will be less than those observed
before the reservoir was constructed. These modifications will be small and
will generally not be perceptible 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.
Potential major effects in the Railbelt that will be most difficult to
mitigate are: 1) loss of spawning areas above and below the dam; 2) loss of
3.31
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 shown on Figure 3.4
indicates that these major impacts could occur at many locations, especially
for anadromous fish (U.S. Department of Energy 1980). Many of these potential
sites are located on major anadromous salmon streams such as the Tenana,
Beluga, Skwentna, Susitna, and Copper Rivers.
Construction can result in elevated stream turbidity levels and gravel
loss, and expanded public fishing in the area due to increased access. Other
potentially significant impacts could include altered nutrient movement which
could affect primary production; flow pattern changes, which can modify
species composition; and temperature regime alteration, which could affect the
timing of fish migration and spawning, and insect and fish emergence.
Competition and predation between and within species may also be changed.
Mitigative procedures are possible for many impacts and are frequently
incorporated into the design of the facility. Fish hatcheries are commonly
used to replace losses in spawning habitat. Screening or diversion structures
are used to direct fish away from critical areas. Depending of the height of
dam and the availability of spawning areas upstream of the created reservoir,
fish ladders are frequently 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 during 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 types. Because of this feature, 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 in particular are critical
3.32
V5f1,J
"''n.t'''•
;~~'~"'"
. ..,.
i)910
... ,.
UaUWlll .,
POTENTIAL HYDROELECTRIC RESOURCES
Source: Alaska Power Survey, 1976.
(Refer to Table·3·2 for Site Identification)
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 3.4.
USGS ALASKA MAP E
habitats for migratory big game animals. Large reservoirs could also cause
genetic isolation of migratory big game animals and other wildlife. Aquatic
furbearers could be adversely affected by the loss of riparian or other
riverine habitats. Correspondingly, waterfowl and shorebird nesting, loafing,
and feeding areas could be eliminated by the flooding of these habitats. The
re-establishment of riparian and riverine habitats is generally prevented by
the constantly fluctuating water levels associated with plant operation.
Fluctuating water levels could also destroy trees and other natural structures
used by raptors for perching, nesting, and roosting sites. Fish-eattng
raptors and bear could be further affected by the loss of anadromous fish if
fish passage is prevented or reduced by the dam.
In the Railbelt region, 36 potential hydroelectric dam sites have been
identified (Figure 3.4). These sites occur in seven major drainages or
general geographic areas including: 1) West side of Cook Inlet; 2) East side
of Cook Inlet; 3) Susitna River Drainage; 4) Copper River; 5) Yukon River;
6) Nenana River; and 7) Lowe River. All of these areas contain important
wlldlife areas that could be affected by hydroelectric developments. Those
sites on the West side of Cook Inlet support moose and waterfowl populations.
The Crescent River site is an area for black bears. Key waterfowl areas are
located at the Beluga River sites. The Chakachatna and Beluga River sites
also conta1n seasonal moose range. Caribou are present at the Kijik River
location.
Potential dam sites in the areas on the east side of Cook Inlet have
mountain goat, Dall sheep, and moose ranges. The Bradley River site is also
used by black bears. Seasonal ranges for moose occur in both the Snow and
Bradley River sites. Waterfowl use on these areas is generally low.
The greatest number of potential dam sites occur in the Susitna River
Drainage. Moose range occurs at all 13 sites and caribou at all sites except
those on the Yenta and Skwenta Rivers. The Denali Project on the Susitan
River may cross a major caribou migration route. Waterfowl use of the. sites
over the entire drainage is low to moderate.
The Copper R1ver dam sites could affect a variety of wildlife primarily
because of their close coastal locations. These sites contain key waterfowl
3.35
use areas including trumpeter swan nesting areas. Dall sheep, mountain goat,
and, to a lesser degree, moose ranges are also present. Other important
w1ldlife are black bears, brown bears, and raptors, which utilize, at least in
part, the anadromous fish runs of the river.
The Yukon River Drainage dam sites possibly represent some of the most
remote locations. All eight sites contain moose seasonal ranges. Caribou
utilize ranges at each of these areas except at the Ruby Project on the Yukon
River and the Junction Island, Big Delta, and Gerstle Projects on the Tanana
River. The Woodchopper Project on the Yukon River is a key area for waterfowl
and for peregrine falcon breeding. Other project-specific locations of
important wildlife include bison at the Gerstle Project site and possibly Dall
sheep at the CAthedral Bluffs project site. Waterfowl occur throughout the
two tributaries of the drainage in low to moderate abundance.
The three project sites of the Nenana River drainage include seasonal
ranges of moose and caribou. The Bruskasna and Carlo Projects occur in areas
utilized by brown bears for denning. Waterfowl occur in moderate numbers
throughout the drainage. Wildlife use of the Lowe River area is low. It does
not appear to be a key area for game animals.
In addition to the losses of wildlife habitats resulting from inundation,
those projects located in remote areas will cause other impacts. Access roads
to remote locations will cause extensive disturbance to wildl1fe. Not only
will habitat be replaced by roads, but isolated wildlife populations will be
adversely affected by increased human activity and numbers. This could result
in disturbance of wilderness species like grizzly bears. Also, other wildlife
could be affected from increased 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 1rreplaceable. However, other habitats like islands used by waterfowl
for nesting could be created through placement of spoils or channels. Trees
and other natural features used by raptors could be retained instead of
removed as is usually done prior to inundation. While these relief measures
3.36
are somewhat specific, impacts on all wildlife could be minimized by selecting
only those sites where wildlife disturbances would be least. It should be
noted that one benefit to wildlife from creation of a reservoir would be that
waterfowl tend to use them as resting areas during migration.
3.4.5 Socioeconomic Considerations
The construction and operation of a large hydroelectric plant has a high
potential to cause a boom/bust cycle, but a small-scale project will have a
minor to moderate impact on community infrastructure. The primary reason
large projects create adverse effects is the remoteness of the larger sites.
All of these sites are located at or near communities with a population of
less than 500. An in-migration of 250 to 1,000 workers, depending on scale of
plant in the range of communities, could more than quadruple the population.
The installation of a construction camp would not mitigate the impacts on the
social and economic structure of a community. Estimated manning requirements
for hydroelectric projects are summarized in Table 3.7.
TABLE 3.7. Estimated Manning Requirements for Hydroelectric Projects
Small Hydro {5 MW)
Conventional Hydro
(100 MW)
{a) To first power.
Construction
Period
(years)(a)
2
3-5
Construction
Personnel
(number
of persons)
25-35
200-400
3-30
Operation
Personnel
(number of persons)
2-3
10-12
The expenditures that flow out of the region account for investment in
equipment and supervisory personnel. For a large-scale project, a larger
proportion of the expenditures is attributed to civil costs. Approximately
35% of an investment in a large project would be made outside the region while
3.37
65% would be made within the Ra1lbelt. Sixty-five percent of the investment
1n a small-scale hydro project would be made in the lower 48 while 35% would
be contained within the Railbelt.
3.4.6 Potential Application for 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 WW II,
development of resources, and thus demand for electrical energy; increased
significantly. In 1956, the total electric generating capacity was
approximately 100 MW. 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. Two significant hydro projects
are operational in the Ra1lbelt, Cooper Lake (15 MW) on the Kenai Peninsula
and Eklutna (30 MW) near Anchorage. The Solomon Gulch (19 MW) project near
Valdez is under construction and will serve Valdez and Glennallen when
finished.
Due to its flexibllity, hydropower is generally used for peaking power in
a large power grid. It can also provide intermediate and base load power. In
the Railbelt region, hydroelectric power can be used to provide base load for
remote communities, intermediate load for any community, and peaking for
larger communities with existing base and intermed1ate generation.
A number of siting opportunities for hydro development in the Railbelt
region have been identified (Table 3.8 and Figure 3.4). Bradley Lake, a 94-MW
project, has been authorized (1962) for development by the Corps of Engineers,
and Grant Lake (7.3 MW) has been studied at the feasibility level. The
1,600-MW Susitna project is being studied. About 8,400 MW have been
identified at 23 potential ••more economical" sites in the Railbelt region. It
is not yet known how many smaller hydro installations are possible in the
Railbelt region, although such studies are underway by the U.S. Army Corps of
Engineers, Alaska District.
3.5 FUEL CELLS
The fuel cell is fundamentally composed of two electrodes (an anode and a
cathode) separated by an electrolyte (see Figure 3.5). Electrical energy is
3.38
TABLE 3.8. Potential Hydroelectric Resources in the
(2.5 MW or greater)Railbelt Region
Project
1. Ruby
2. Woodchoper
3. Junction Island
4. Big Delta
5. Gerstle
6. Johnson
7. Cathedral Bluffs
8. Fortymi 1 e
9. Bruskasna
10. Carlo
11. Healy
12. Tazimina
13. Crescent Lake
14. Ingersol (Lackbuna Lake)
15. Lowe (Keystone Canyon)
16. Chackachamna
17. Coffee ·
18. Upper Beluga
19. Yentna
20. Talachulitna (Shell)
21. Skwentna (Hayes)
22. Lower Chulitna
23. Tokichitna
24. Keetna
25. Whiskers
26. Lane
27. Gold
28. Devils Canyon
29. Watana
30. Vee
31. Dena 1 i
32. Million Dollar
33. Cleave
34. Wood Canyon
35. Snow
36. Bradley Lake
Stream
Yukon River
Yukon River
Tanana River
Tanana River
Tanana River
Tanana River
Tanana River
Fortymile River
Nenana River
Nenana River
Nenana River
Tazimina River
Lake Fork of Crescent River
Kijik River
Lowe River
Chackachamna River
Beluga River
Beluga River
Yentna River
Skwentna River
Skwentna River
Chulitna River
Chulitna River
Talkeetna River
Susitna River
Susitna River
Susitna River
Susitna River
Susitna River
Susitna River
Susitna River
Copper River
Copper River
Copper River
Snow River
Bradley Creek
Note: Project numbers correspond to numbered boxed on the Potential
Hydroelectric Resources location map, Figure 3.4.
3.39
w .
+:>o
0
HEAT
OR
STEAM
FUEL
_r!'
)1111
REFORMER
•
GAS C~EANUP L
~
AND f DESULFURIZER
FUEL PROCESSOR
~ CARBON DIOXIDE
____ ..... dl_,
_j HYDROGEN ANODE(-) DC CURRE~T r -
ELECTROLYTE
CATHODE(+)
0 2 0R AIR --n GAS-TIGHT
SEPARATIO!:!.J WATER
" HYDROGEN --ANODE(-)
ELECTROLYTE
02 OR AIR CATHODE(+) ---,,________,, [_
WATER
FUEL CELL STACK
(two cells shown)
FIGURE 3.5. Fuel Cell Plant
~ ~ ~ ;...
-
LOAD
(DC)
INVERTER
-
AC CURRENT --
extracted from the cell by a process whereby fuel and oxygen are
electrochemically combined in the electrolyte. The fuel and oxidant must be
in the gaseous form, but the electrolyte may be an aqueous acid, an aqueous
alkaline, a molten salt, or a solid type. Electrodes are thin, porous, and
electrical-conducting. Catalysts are included to speed up the reaction.
3.5.1 Technical Characteristics
Most of the cells currently being produced use phosphoric acid as the
electrolyte, and hydrogen-rich fuel and oxygen (or air) as the reactant
gases. Hydrogen reacts at the anode to form electrons and positive 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 supplying a
utility distribution grid.
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 (12QOOF) 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 easily attainable. Cogeneration with such fuel cells is also a possibiity
for the utility interested in supplying district heat or industrial process
heat.
A third-generation fuel cell utilizing the 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
exper1mental results w1th lanthanum cobalt oxides indicate that the solid
electrolyte fuel cell could be a promising candidate for commercial uses in
power generation during the 1990s.
3.41
A complete fuel cell plant typically consists of a fuel processor, a fuel
cell section, and an 1nverter and power conditioner. The individual fuel cell
produces an output of about 0.8 V under load. Individual cells may be
connected in series to provide greater output voltage and connected in
parallel to provide greater output current. Current fuel cell designs utilize
456 cells stacked in a cell stack assembly to produce 300 VDC at a current of
500 amps. The cell stacks can be connected in series or parallel to produce
megawatt quantities of power at 2000-3000 VDC.
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 mass production techniques in a factory environment,
unit costs may be reduced. Using the modular arrangement, it is conceivable
that modules can be added and/or shifted to new locations, depending upon
changes in local load conditions.
Fuel cells consume several types of fuel, depending upon the type of
electrolyte. Present-day 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
C02 and more H2 by the shift reaction. In the molten-carbonate and
sol1d-oxide fuel cells, carbon monoxide acts as a fuel, being catalyzed on the
electrode surface to form H2 and co 2 in the presence of steam. The
molten-carbonate cell must have carbon dioxide 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.
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. The electrolytes have
effic1encies as follows:
Electrolyte Efficiency (Percent)
Phosphoric acid 37
Moltan Carbonate 50
3.42
Heat Rate (Btu/kWh)
9,200
6,820
Advanced fuel cells operating at higher temperatures may be used with a
steam bottoming cycle, resulting in efficiencies of more than 60%. The
overall efficiency of the fuel cell steam bottoming cycle system using coal
gasification is at about 50%.
The efficiency of fuel cell plants is practically constant over wide
ranges of loads. This means that they are suitable for partial load operation
to meet "spinning reserve" requirements of a utility grid.
Fuel cells can respond to load changes very quickly and are thus suitable
for use in a load-following (cycling) mode. The time constant of the hydrogen
generating equipment is the control factor. As an example, a demonstration
plant has been built which is designed to follow a load change between 35% and
100% of full power with1n 2 seconds.
Molten-carbonate cells using fuel from coal gasification 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, then surplus of fuel will be available
from the gasifier when the 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 high electrical
load periods, thus reducing the required capacity of the gasification plant.
One other difficulty with using the carbonate cell in cycling service is
adverse effects of thermal cycling. Because of the high operating
temperature, 12000F, it is difficult to accomplish thermal cycling a number
of times without the probability of cracking the electrolyte tile. For these
reasons, the molten carbonate cell is more suitable for base load operation.
The reliability of a fuel cell plant depends to some extent on the type
of fuel which 1s used; plants are expected to be extremely reliable when a
clean fuel is used. An availability of 95% is predicted for first generation
plants. At present fuel cell manufacturers recommend a re-work of the cells
every 10,000 operating hours. Scheduled outages for maintenance will
therefore be less than the more conventional coal or gas-fired plants.
3.43
3.5.2 Siting and Fuel Requirements
The modular design of the fuel cell offers considerable flexibility in
siting. Because of the small size of the early commercial plants (40 KW to 10
MW), fuel cell plants 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 system.
The principal siting constraint for such plants would be the source of
fuel supply. 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.
A fuel cell plant were integrated with the synthetic fuel plant, the same
s1ting requirements that apply to the synthetic fuels conversion plant would
prevail. A medium Btu gas fuel could be transported by pipeline for moderate
distances, allowing remote or dispersed siting of the fuel cell generation
plants.
Demonstration fuel cell plants vary in size from 25 KW to 11 MW.
Assuming no on-site fuel storage, small fuel cell installations would have the
following general area requirements: a 40-KW plant would require less than
one acre; a 4.8-MW plant would require one to two 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 500 MW molten-carbonate plant, will
probably take more than the 120 acres for the same size conventional fossil
steam plant. But as new coal-fired plants are required to have more and more
air pollution control equipment and require solid waste disposal areas, the
fuel cell plant of the mid 1990s (which is inherently free from needing air
pollution controls) will likely require less area than the future coal
plants.
Little, if any, external water is required for the fuel cell plant as the
water formed by the fuel cell process is usually sufficient for cooling and
3.44
heat recovery systems. The fuel stacks are normally cooled by the process
gases passing through the structure, although forced air cooling has also been
satisfactorily tested.
In order to provide the fuel cell with hydrogen, 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. The New York City fuel cell
will use either naphtha or methane gas as its fuel supply.
The shortage of liquid and gaseous fossil energy (required to obtain
hydrogen) has prompted some research in developing fuel cells that would use
coal-derived gaseous fuels directly. Coal can supply hydrogen and carbon
monoxide as gaseous fuels, but the carbon monoxide cannot be used in
hydrogen-oxygen 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 cell fuel processor.
3.5.3 Costs
Capital costs for phosphoric acid fuel cell plants are not yet
competit1ve with conventional power plants now being installed in the United
States. In addition, the high cost of suitable fuel for ~he fuel cell,
contributes to costs of power currently exceeding that of conventional coal
plants. However, currently, conventional fossil-fuel plants are undergoing a
dramatic cost increase, due in part to emission controls required by the New
Source Performance Standards required by the Clean Air Act Amendments of
1977. Since the fuel cell produces virtually no air pollution, fuel cell
capital cost should become increasingly more competitive with the conventional
fossil plant. Furthermore, mass production of phosphoric acid cells should
result in a decrease in "real'' (i.e. adjusted for inflation) capital cost.
Estimated costs, in 1980 dollars, for phosphoric acid power plants using
naphtha as fuel are given in Table 3.9.
3.45
TABLE 3.9. Estimated Costs of Fuel Cell Generation Facilities
Plant Type Capacity
Phosphoric Acid Greater than
500 MW
Moltan Carbonate
3.5.4 Environmental Considerations
Capital
Cost
($/kW)
$650
0 and M Cost
($/kW)
$3.30
Cost of Power
($/kW)
Fuel cell systems operate at approximately 20 to 1200oc depending upon
the electrolyte, thus product water at elevated temperatures will be
produced. For aqueous hydroxide systems, characteristic cell operating
temperatures are 20 to 900C. A typical value given for waste heat disposal
is about 30% of the heat of reaction, to avoid electrolyte decomposition.
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 1-MW and 10-MW
plant, this corresponds to a water production rate of approximately 2,700
gal/day and 27,000 gal/day, respectively (Davis and Rozeau 1977). Depending
upon the specific fuel cell type, this product water can either be discharged
from the plant, or if in the form of steam, utilized to drive a conventional
steam turbine in a bottoming cycle or utilized in the fuel processor to reform
the hydrocarbon fuel. Addit1onal makeup water may also be utilized 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 management plan incorporating
suitable waste heat rejection technologies would be implemented 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 technologies. Sulfur and nitrogen will be gasified, not
oxidized, and can easily be recovered from process streams. Fuels which are
essentially free of such pollutants, such as hydrogen or natural gas, will not
3.46
lead to any pollutant emissions. 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 impacts over
combustion technologies. Heat rejection must be considered in fuel cell
technologies, but these design considerations will avoid any adverse
environmental impacts.
Fuel cells will produce heated water and may require additional makeup
water for cooling. The quantity of intake water, 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 from intake and discharge of water. Because water
use requirements vary, no direct per megawatt comparison can be made with
another plant. Due to the small plant size (10 MW), 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
relatively slight s1nce the air pollution potential is very low and small land
areas are required. Noise and other potential disturbance factors are also
relat1vely low. Furthermore, these plants would be sited within or adjacent
to developed areas where access road requirements would be minimal.
3.5.5 Socioeconomic Considerations
Sites for fuel cell plants would be determined by fuel type and source.
Locations should be constrained by the population size of the community since
construction work force requirements are large and may cause significant
impacts in small communities. Approximately 90 persons would be required to
construct a 10 MW plant for a period of less than 1 year. Impacts would be
minor to moderate in Anchorage, Fairbanks, Soldatna, Kenai, Valdez, Wasilla,
and Palmer. An estimated five workers would be required to operate such a
plant.
Expenditures that would flow out of the region due to development of a
fuel cell facility would include investment in high-technology equipment. It
3.47
can be expected that 80% of the project expenditures would be made outside the
region, with 20% spent within the Railbelt.
3.5.5 Application to Railbelt Energy Demand
Fuel cells represent an emerging technology. It is not yet commercially
available and has thus not been applied in Alaska. Present-day prototype fuel
cells, which generally use phosphoric acid as the electrolyte, are expected to
be commercially available in the next few years. The molten-carbonate cell
has been under development at a modest level for about 25 years. Since good
progress and accelerated effort have characterized the past few years of this
development, this second-generation fuel cell could be generating multi-
megawatt power on a demonstration basis within 3 to 4 years. Commercial
availability is not anticipated until after 1990, however.
The phosphoric acid fuel cell in electric power generation has been
developed to the point of satisfactory operation in several small
demonstration 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 4.5 MW output is under construction 1n New York City and
one with an output of 10-MW is under construction in Tokyo, Japan. Commercial
production facilities are being built by a major electrical equipment
manufacturer, with 11-MW modules to be available around 1985.
The molten-carbonate cell is about 5 years behind the phosphoric acid
cell technology. The U.S. Department of Energy is funding a significant
effort to achieve a molten carbonate system demonstration in the 1986 to 1987
time frame. Fabrication processes are being developed with current funding
from DOE and EPRI.
Potential obstacles to commercialization of fuel cells for electric power
generation are threefold: insufficient orders, national fuel policy, and
technical developmen· •
Enough orders must be generated to take advantage of the economies of
scale which are needed to produce fuel cells at a cost that utilities can
afford. No one utility is currently in a financial position to sponsor the
potentially high cost of developing production facilities for fuel cells, so
3.48
it is assumed that the development timetable will 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 tap a slipstream 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 which 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 fuel cell.
3.49
4.0 STORAGE TECHNOLOGIES
The utilization of energy storage techniques has, within the last
25 years, become an important component in serving the nation's overall
electric energy needs. This technology does not, by itself, add to the
overall generating capacity of a system, but it does utilize otherwise unused
capacity available from base load plants during off-peak hours. This energy is
stored and subsequently reused during the peak demand hours.
Although many energy storage methods are technically feasible, the only
energy storage system in widespread commercial use is hydroelectric
pumped-storage. Battery storage systems. Although not currently in
commercial use may become commercially available within the next ten years.
Selected characteristaics of hydroelectric pumped storage and battery storage
systems are compared in Table 4.1.
4.1 HYDROELECTRIC PUMPED-STORAGE
Hydroelectric pumped-storage plants provide a unique solution to the
problems of increasing base-load plant factors and providing peaking
capacity. Water is pumped from a lower reservoir to an upper reservoir during
the 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. The system pumping losses and generating
inefficiencies are more than compensated for by the differential power
production costs of the baseload plants used to fill the upper reservior and
the cycling plants whose operation is displaced by operation of the
pumped-storage plant as a operating facility.
Pumped-storage plants had their commercial origins in the United States
in 1929. The first domestic installation was the 7-MW Rocky River Plant near
New Milford, Connecticut. This 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
4.1
TABLE 4.1. Comparison of Storage Technologies on Selected Characteristics
First Stage
Attributes
1. Aesthetic Intru-
siveness
A. Visual Impacts
B. Operating Noise
C. Odor
2. Impacts on Biota
A. Aquatic/Marine
(gpm)(a)
B. Terrestrial
(acres){b)
3. Cost of Energy
A. Capital Cost
($/kW)
B. O&M Cost
($/kW) c. Fuel Cost
D. Cost of Power
( $/kW)
4. Health & Safety
A. Public
5. Consumer Effort
6. Adaptability to
Growth
A. Adjustments in
plant scale
7. Re 1 i ability
A. Availability (%)
8. Expenditure Flow
From Alaska
A. Capital Cost (%)
Pumped Storage
25 MW
Significant
Minor
Minor
(Municipal Waste)
Site-Specific
Site-Specific
950
7.40
Safe
Utility operated.
No individual or
colliTlunity effort
required.
Units can be added
easily if planned.
85
55
4.2
Battery Storage
Battery Storage
First Stage
Attributes
B. Operation and
Maintenance
Cost (%)
C. Fue 1 Cost
9. Boom/Bust
A. Ratio of Con-
struction to
Operating
Personnel
B. Magnitude of
Impacts
TABLE 4.1. (Contd)
Pumped Storage
25 MW
250:10
Minor in vicinity
of Anchorage.
Moderate to severe
Battery Storage
Battery Storage
in allother locations.
10. Control of Technology
A. Utility
B. I nd i vi du a 1
Second Stage
Attribute
1. Commercial Avail-
ability
2. Railbelt Siting
Opportunities
3. Product Type
4. Generating Capacity
A. Range in Unit
Seale (MW)
Primary Control
Limited through
regulatory
agencies and
government.
Mature
None identified
Peaking
1.5-400
(a) Recirculating cooling water systems.
(b) All facilities.
4.3
1988-1992
None identified
Peaking
significant 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 (1,800 feet).
Changes in the needs of the total electrical generating system further
contributed to the development of the pumped-storage technology. The early
1950s saw the use of pumped storage for energy trading purposes among
relatively small utility companies. In some areas, as energy consumption
grew, conventional hydro capacity was no longer sufficient to satisfy peak
power demands; pumped storage was a relatively economical way of filling the
gap. With the advent of today's large base-load thermal generating plants,
pumped storage complements these plants, maximizing use of these efficient
plants.
4.2.1 Technical Characteristics
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, for example, 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.
Man-Made Upper and/or Lower Reservoir. As the name implies, this
approach consists of constructing the complete reservoir using perimeter
containment dikes. This type of 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. This approach would use underground natural
rock caverns or an underground rock excavation for the lower reservoir
and would have an underground powerhouse associated with it. The upper
reservoir may be either natural or man-made, as described above, or it
may use the storage reservoir of an existing conventional hydro plant.
Conversion of Existing Hydro Plant. An existing conventional hydro plant
would be converted entirely to pumped-storage. The existing reservoir
4.4
would be used as the upper reservoir, and the lower reservoir would be
formed by constructing a lower dam downstream of the existing dam. A
modification of this approach has a seasonal pumped-storage arrangement
built in conjunction with a conventional hydro project. During periods
of high river flow, the excess water normally discharged over the
spillway of the existing structure could, during off peak hours, be used
to run pump/turbines to pump water to an off-site 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 existing
river.
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 4.1.
Several dam types are used to form the reservoir, generally dependent on
the valley conditions, local geology, availability of construction materials,
and cost. Typical dams may include concrete gravity, concrete arch, or an
earth and rockfill dam with an impervious central core. Typically, perimeter
dikes are constructed of earth and rockfill with an impervious central core or
an impervious liner.
Upper reservoirs are provided with an emergency spillway. This structure
conveys excess water caused by accidental overpumping away from the reservoir
in a controlled manner. A when formed by a dam structure lower reservoirs
also includes a spillway. The function of this spillway is similar to that
for a conventional hydro dam. Since a lower reservoir dam would normally be
located along an existing stream or river, the spillway would discharge flood
flows associated with the existing waterway. Water conductors between the
reservoirs may be rock tunnels or above-ground steel 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
4.5
UPPER
RESERVOIR
~
UPPER
RESERVOIR
PRESSURE
PENSTOCK
(reversible flow)
SURGE
TANK
POWER
HOUSE
A-ELEVATION TRASH RACK
DAM
PENSTOCK
B·PLAN
GENERATOR/MOTOR
PUMP/TURBINE
SURGE TANK
HEAD
~ r .J-~
.·-
\
b) J ) LOWER
( ( . RESERVOIR
(_ z .. / -,
·~
FIGURE 4.1. Schematic of a Pumped Storage Hydro Plant
lower to the upper reservoir. During peak demand hours, the pump/turbine
units 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 protect this
equipment. Underground powerhouses are constructed in natural or man-made
caverns. This scheme is used in certain topographic conditions, particularly
narrow canyons, for which there is no convenient site for a conventional
powerhouse. Its use is also dependent on site geology and cost. Underground
powerhouses would also be required for underground pumped-storage concepts.
4.2.2 Siting and Fuel Requirements
The operation and success of a pumped-storage project are influenced
primarily by site characteristics. Availability of water, land, transmission
lines, and access roads is an important consideration in the site selection
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.
Topography also determines the extent of dam construction required to contain
the reservoir; maximum utilization of natural embankments is desired. The
length of the water conductors is, to a large extent, dependent on
topography. A longer line of flow will add to construction costs and result
in larger generating losses and pumping costs. It is desirable to have the
shortest possible horizontal distance between the upper and lower reservoirs.
Geologic conditions have the potential for affecting 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 (tunnels
versus above ground penstocks) and whether an underground powerhouse can be
considered.
4.7
Sites characterized by high seismic activity should be avoided although,
if necessary, a project could be designed to resist seismic loads at an
overall increase in cost. Embankment slopes would have to be built flatter;
additional restrictions would be placed on fill materials; and structures
would be more massive.
Availability of construction materials is an important consideration in
the site selection process. All concrete structures will require quantities
of fine and coarse aggregate. Depending on the configuration of potential dam
structures, a considerable amount of fill material could also 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.
All siting considerations must be evaluated in conjunction with the
overall project power needs. It is unlikely that any single site will ideally
satisfy all requirements, and it will therefore be necessary to evaluate the
relative technical and economic merits of several candidate sites before
selecting a single site.
The fuel requirements for a pumped storage project consist of the
electricity required to compensate for electrical, and mechanical losses
during plant operation. This electricity is normally supplied from
base-loaded oil, gas, coal or nuclear plants. Water is, of course, required
for system operation.
4.2.3 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 and
waterways vary considerably and may have little relationship to the installed
generating capacity. An installed capacity cost of $950/kW (1981 dollars) is
generally accepted for low capacity pumped-storage projects (less than 100
MW). Installed costs in dollars per kW are a function of capacity, and
generally decrease as plant capacity increases; however, for very large
pumped-storage plants (greater than 100 MW), installed costs begin to rise.
4.8
Plant size, number of pump/turbine units, annual generation, operating
head, and site-specific conditions for individual plants are major 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.
Historical data (U.S. DOE 1979) indicate weighted annual operating and
maintenance costs to be $7.40/kW-Yr in 1981 dollars. This information is
tabulated in Table 4.2.
TABLE 4.2. Estimated Costs of Hydroelectric Pumped Storage Facilities
Operating and Cost of
Capital Cost Maintinance Cost Power
Plant caeacit~ ~$/kW} ~$/kW/~r) ($/kW}
Less than 100 MW 950 $7.40
500 MW 500 $7.40
Greater than 1000 MW 600 plus $7.40
4.2.4 Environmental Considerations
The impacts of a hydroelectric pumped storage facility on the water
resources associated with both the upper and lower reservoir can be similar to
those of a conventional hydroelectric facility, which are discussed in
Section 3.4.4. 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 experience adverse impacts due to possible modifications in the
water quality regime if there are differences in the water quality
characteristics of the upper and lower reservoirs (i.e., from introduction of
lower quality water from the 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 will also affect the lower reservoir, again depending upon
site-specific characteristics and whether the lower reservoir is a natural or
man-made water body.
4.9
Both reservoirs could experience increased scouring and elevated
turbidity levels associated with the pumping process and hydroelectric
facility discharge design. Proper engineering and plant operation can
minimize these impacts.
Creation of a man-made reservoir, either upper or lower, may affect the
local hydrologic regime because of increased groundwater seepage and
evaporation. Proper site selection criteria and design should minimize these
impacts.
Underground caverns used for water storage, whether natural or man-made,
may experience adverse impacts on water quality due to the potential solvation
or reaction with the local rock media. These impacts are site specific, and
can be minimized by proper site selection and design.
No impacts on air quality result from the use of pumped storage
techniques. Development of an artificial reservior may produce some changes
in the microclimate. These changes will pertain mainly to temperature and
humidity values near the reservoir and will not be perceptible offsite.
Biological impacts of pumped storage are similar to those of conventional
hydroelectric plants. Depending on the size, pumped storage projects
typically 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. Potential effects most difficult to
mitigate are: 1) loss of shoreline spawning areas in lower and upper
reservoirs; 2) loss of rearing habitat; 3) increased mortalities 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 from increased access. Plant operation may result in:
altered nutrient movement, affecting primary production; water flow pattern
changes, modification of 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
4.10
the lower reservoir or at downstream locations, possibly resulting in fish
mortalities. Competition and predation between and within species may also be
changed.
Mitigative procedures are possible for many impacts and are frequently
incorporated into the design of the facility. 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 terrestrial impacts of pumped storage facilities are similar to
those of conventional hydroelectric developments (see Section 3.4.4) 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. Pumped storage reservoirs
can be developed in dry basins such as timber areas using perimeter
containment dikes.
Pumped storage sites in the Railbelt region have not been identified. It
is quite likely, however, that primarily lowland (versus mountainous) wildlife
populations, particularly moose and caribou, would be negatively affected by
inundation of habitat.
The primary action to be taken to reduce terrestrial impacts would be to
site pumped storage facilities in areas of low wildlife value. Other actions
could include enhancing the value of a reservoir to certain wildlife.
4.1.5 Socioeconomic Considerations
Since pumped storage is a labor-intensive technology, impacts will vary
with both plant scale and location. The construction workforce requirements
range from 250 for a 100 MW Plant to 1,500 for a 1000 MW Plant, for a period
of 5 to 7 years. Plant operation and maintenance requires a staff of
approximately 10, regardless of plant size. The large differential in
construction and operating personnel may cause a boom/bust cycle in remote
areas.
4.11
More specifically, a 100-MW Plant would have minor socioeconomic impacts
if located near Anchorange. 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 immigrants. Small and very small
communities would be severely affected by a 100-MW Plant because of the
substantial increase in population.
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
sufficiently long (5 to 7 years) to result in semi-permanent settlement by the
workforce dependents and secondary inmigrants.
It is estimated that approximately 55% of the project expenditures would
flow out of the region while 45% would remain within the Railbelt.
4.1.6 Potential Application to Railbelt Region
The commercial availability of pump/turbines is comparable to the
availability of conventional hydroelectric machinery. Commercially operating
pump/turbines have been built with capacities ranging from 1.5 MW up to 400 MW
at TVA's Raccoon Mountain project, with larger units anticipated for the
future.
There are currently 28 pumped storage projects in operation in the United
States, with an installed capacity of 12,900 MW. No pumped-storage
hydroelectric plants, however, have been constructed in the Railbelt region.
The outlook for their continued use and expansion in some areas of the United
States is bright, assuming favorable site conditions and a significant,
well-integrated generating power base and distinct peaking power
requirements. These requirements are not entirely satisfied in the Railbelt
region at present. Site conditions in the Railbelt are suitable for
pumped-storage development but there is not significant base load generating
capacity. As of 1976 the state's total generating capacity was approximately
940 MW; however, the generating stations are not incorporated into a
well-integrated system as would be required for the pumped-storage concept to
work effectively. No pumped-storage hydroelectric plants have been
constructed in the Railbelt region.
4.12
4.2 STORAGE BATTERIES
Battery storage systems could be used in electric utility service to
serve in a load leyeling capacity. In hours of low demand, electricity would
be converted from high-voltage a.c. into lower voltage d.c. and stored in the
batteries. During peak hours the process would be reversed to carry part of
the utility•s load.
4.2.1 Technical Characteristics
Several new types of storage batteries are under development for utility
application. Among these are the sodium-sulfur battery, the zinc-chlorine
battery, zinc-bromine battery, and the Redox fluid battery. Table 4.3 gives
some performance parameters for four battery types.
The most important criterion for storage in electric power systems is
long life: the ability to undergo 2,000 to 3,000 cycles of charge and
discharge over a 10-to-15 year period (Kathammer 1979}.
TABLE 4.3. Battery Performance Parameters (Kalhammer 1979)
Estimated
Battery Type
Lead-Acid
Utility Design
Improved
Zinc-Chlorine
Utility Design
Soli urn-Sulfur
Utility Design
Redox
Operating
Temperature
(Degrees
Celsius)
Ambient
30-50
300-350
100 or less
Estimated
Cycle Life
2,000
2,000(?)
2,000
(a}
(a) 20 years estimated (Thaller 1979)
4.13
Estimated
Cost
(Do 11 ars Per
Kilowatt-
Hour)
80
50
50
?
Avail abi 1 ity
(Year)
(Prototypes
or Early
Commercial
Models)
1984
1984
1986
?
EPRI has indicated that three criteria must be met in order for a 100 MWh
battery plant be acceptable to the utility industry. These criteria are:
1) installed cost less than $25/kWh plus $75/kW (in 1977 dollars),
2) overall plant efficiency greater than 65%, are to a-c conversion, and
3) Minimum siting restrictions (Energy Development Associates 1979).
Sodium-sulfur batteries, under development by General Electric use molten
sodium as the negative electrode, molten sulfur/sodium polysulfide as the
positive electrode and beta alumina as the solid electrolyte separator (Bast
and Mitoff 1980). A nitrogen blanket is required, to prevent spontaneous
ignition of the 300oC sodium and sulfur. The sodium-release problem is
under investigation (Bast and Mitof 1980).
The zinc chlorine battery is being developed by Energy Development
Associates. The cell consists of a zinc electrode, a chlorine electrode, and
aqueous zinc chioride electrolyte. Important safety and environmental impact
considerations revolve around accidental release and dispersion of toxic
amounts of chlorine (Energy Development Associates 1979).
The zinc-bromine battery developed by Gould is based on a cell design of
titanium electrodes, permeable microporous cell divider, and two electrolyte
pumping systems that circulate aqueous zinc bromide solution. Two problems
inherent to the system are low coylombic efficiency resulting from reaction of
zinc with dissolved bromine, and the tendency for zinc to electro deposit
dendritically, which can lead to short-circuiting of the cell (Putt, 1979).
The Redox flow cell uses chromium chloride and iron chloride solutions,
which are pumped through a "stack" of flow cells. In each flow cell, the
fluids are separated by a 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.
This system has advantages of relatively low pressure and temperature,
independent sizing of energy-storage capacity, (tank sizes), and reactants
that stay in solution, and minimal environmental impact from accidental spill
or equipment failure (Pruce, 1979). Cost is also potentially lower because of
system simplicity and predicted long component life.
4.14
Battery prototypes are to be tested in the Battery Energy Storage Test
Facility (BEST), sponsored jointly by DOE and EPRI. In order 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
30,000 kWh lead acid battery coupled to a 10,000 kW ac-dc converter
(Kalhammer (1980).
4.2.2 Siting and Fuel Requirements
TO BE SUPPLIED
4.2.3 Costs
TO BE SUPPLIED
4.2.4 Environmental Considerations
TO BE SUPPLIED
4.2.5 Socioeconomic Considerations
TO BE SUPPLIED
4.15
4.2.6 Appllcability to Railbelt Region
Battery-storage systems may be applicable to Railbelt electrical system
for road leveling.
The data in Table 4.3 indicates that prototype or early commercial
battery systems will be in operation before 1990. Commercialisation of the
technology may depend on utility acceptance. This could put battery storage
systems in the proper time frame for consideration in the Railbelt Electric
Alternatives Study.
The need for load leveling facilities such as battery storage systems is
greatly dependent upon the load and generation characteristics of the utility
system. In general, battery storage systems would be considered for utility
systems having substantial daily peaking characteristics, inexpensive baseload
capacity and relatively little hydroelectric capacity. The current Railbelt
electric energy system, although not having substantial hydroelectric
capacity, exhibits only modest daily peaking characteristics and does not have
low cost baseload generating capacity.
4.16
5.0 FUEL SAVER TECHNOLOGIES
Candidate fuel saving technologies for Railbelt application include
cogeneration, tidal power, wind power, and solar power. These technologies
supply energy to the power grid but typically cannot be assigned capacity
credits because of the intermittent availability of the energy source.
Capacity credit can be assigned 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.
For cogeneration cycles, source of energy is the thermodynamic potential
available from the simultaneous generation of electricity and process heat.
Electrical power is produced from cogenerating installations only when there
is a demand for heat. Wind power is available only when wind speeds are
sufficient to support generation. Solar power is available only when solar
radiation is available. Tidal power is dependent upon tidal patterns. All of
these technologies can augment an electrical supply system, but they can not
form the basis of such a network unless substantial energy storage capacity is
provided. Consequently, these technologies are normally regarded as fuel
saver technologies. Each of these fuel saving technologies is described in
the following four sections. A comparison of selected characteristics of the
fuel saver technologies discussed in this chapter is provided in Table 5.1.
5.1 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 may be used for industrial
process heating applications. Opportunities for cogeneration occur when
large, stable demands for heat and electricity occur simultaneously.
Typically, the demand for heat becomes the driving variable. Cogeneration
opportunities exist only in association with industrial or commercial
development. Cogeneration capacity can be expanded simultaneously with
increases in industrial capacity. A major barrier to the development of
5.1
U1 .
First Stage
Attributes
1. Aesthetic Intru-
siveness
A. Visual Impacts
B. Operating Noise c. Odor
2. Impacts on Biota
A. Aquatic/Marine
(gpm)(a)
B. Terrestrial
(acres) (b)
3. Cost of Energy
A. Capital Cost
($/kW)
B. O&M Cost
($/kW)
C. Fuel Cost
D. Cost of Power
($/kW)
4. Health & Safety
A. Public
5. Consumer Effort
6. Adaptability to
Growth
A. Adjustments in
plant scale
7. Reliability
A. Availability (%)
TABLE 5.1. Comparison of Fuel Saver Technologies
on Selected Characteristics
Cogeneration
20 MW
Minor to Moderate
Minor
Minor
(Municipal Waste)
180
8
850
2.50
Tidal
Moderate to Significant
Minor
Minor
Site-Specific
Site-Specific
3000
Safe. Possible Safe
long-term air
quality degradation
Utility operated.
No individual or
community effort
required.
Dup 1 i cate effort
required.
Base load
Utility operated. No
individual or community
effort required.
Additional units can be
added. •
Provides intermittent
power.
Minor
Minor
Minor
Wind
2.5 MW
Significant
Minor
Minor
Solar
10 MW
Solar-Thermal Photovoltaic
0 150 0
2
Oil
800
200 50
7
60
Safe
Gas
56
1500
40
Safe
Utility or community Utility operated. No
operated. individual or
effort required
Additional units can Duplicate effort
11000
be added. required for solar-
thermal. Photovoltaic
units can be added easily.
Provides inter-Provides inter-
mittent power. Jnittent power.
U1
w
First Stage
Attributes
8. Expenditure Flow
From Alaska
A. Capital Cost (%)
B. Operation and
Maintenance
Cost (%)
C. Fuel Cost
9. Boom/Bust
10.
1.
2.
3.
4.
A. Ratio of Con-
struction to
Operating
Personnel
B. Magnitude of
Impacts
Control of Technology
A. Util1ty
B. Individual
Second Stage
Attribute
Commercial Avail-
ability
Railbelt Siting
Opportunities
Product Type
Generating Capacity
A. Range in Unit
TABLE 5.1. (Contd)
Cogeneration
20 MW Tidal
67 33
30:15 300:30
Minor to moderate Minor in vicinity of
in all locations. Anchorage. Significant
to severe in all other
locations.
Primary Control Primary Control
Limited through Limited through
regulatory agencies and
agencies and government.
government.
80
12:0
Wind
2.5 MW
Minor in all
other locations.
Primary Control
Limited through
regulatory agenci«~s
and government.
Mature Commercially available but Commerically avai'l-
not mature. ble but not matur«!.
Oil refineries, Knik Arm, Turnagain Arm, Coastal locations;
military & Upper Cook Inlet along ridgelines or
academic • hills in the interior.
installations
2.5-100 400 KW -240 MW 1-45
(a) Recirculating cooling water systems.
(b) A 11 f ac i 11t i es •
80
Solar
10 MW
Solar-Thermal Photovoltaic
60:25 100:10
Minor in vicinity of
Anchorage & Fairbanks.
Moderate to severe in
all other locations.
Primary Control
Limited through
regulatory agencies
and government.
Photovoltaic cells are
commercially available
but not through mass
production
No sites identified
cogeneration was removed with the passage of the Public Utility Regulatory
Policies Act of 1978. The Act essentially allows industries and other
non-utility generators to sell power to a utility at a fair market value.
The size of a cogeneration system generally ranges from 25 to 100 MW,
although it is becoming economic to bui\d systems in the 5 to 25 MW range
where high electricity costs prevail, such as those encountered in small
communities in the Railbelt region. 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.
5.1.1 Technical Characteristics
Cogeneration facilities are classified into those using "topping"
thermodynamic cycles and those using "bottoming" cogeneration cycles. Both
exist commercially although the topping cycles predominate. Topping cycles
are used at installations whose primary purpose is to produce low quality heat
for process or space heating applications. Topping cycles capture available
energy at temperatures above those required for process or space heat
applications. Bottoming cycles are used to capture otherwise rejected
low-level heat and to convert this heat into useful work. Three topping
cycles are available: 1) steam turbine topping cycle, 2) combustion turbine
topping cycle, and 3) diesel generator topping cycle. Cycle selection is
usually determined by relative power and steam demand; fuel availability and
cost; and process heat utilization system designs.
Steam Turbine Topping Cycle
In the steam turbine topping cycle, as depicted in Figure 5.1, high
pressure/high temperature steam is raised in the boiler, passed through a
non-condensing turbine, and 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 decreased, the power generation/steam
production ratio is increased.
5.4
STACK GAS
r
AIR BOILER
HIGH
PRESSURE
STEAM
4 BOILER FEEDWATER
---+ASH
ELECTRICITY
GENERATOR
PROCESS
STEAM
FIGURE 5.1. Simplified Schematic of Steam Tubrine Topping Cycle
System capacity is generally determined by manufacturing or space heat
steam needs. Manufacturers with requirements for only one steam quality 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 generation is determined by boiler
efficiency plus turbine-generator heat rates. A typical small-scale,
wood-fired cogeneration system 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
4200-4500 Btu/kWh, and an overall efficiency of about 85%.
The primary advantage of the steam cycle is its ability to utilize
virtually any fuel directly. Solid fuels such as coal, peat, biomass, and
5.5
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 5.2, integrate a
combustion turbine and a waste heat boiler in order to simultaneously produce
electricity and steam. Alternatively, the exhaust from the combustion turbine
may be passed through a exhaust gas lair heat exchanger for warm air for
process purposes. This cycle is ideal for oil refineries.
LIQUID OR
GASEOUS FUEL
AIR COMBUSTION
TURBINE 1=::::::::::::1 GENERATOR ELECTRICITY
WASTE STEAM TO
HEAT WASTE HEAT PROCESS .__~::.:...:...:..--t.,.l BOILER
BOILER FEEDWATER t
STACK
GAS
FIGURE 5.2. Simplified Schematic of Combustion Turbine Topping Cycle
5.6
The combustion turbine technology is described in Section 3.1. The
second major component of the system is the waste heat boiler. These
components are typically finned watertube boilers accepting turbine exhaust
gases at about 9000F and exhausting them at 350-450oF, depending on the
the quantity of S02 in the exhaust stream. An economizer for feedwater
heating is typically added to remove heat from the stack gas.
The primary advantage of a combustion turbine cycle is the high
electrical power/steam ratio. The power/steam ratio for combustion turbines
may be up to four times that associated with 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 is
about the same as that associated with steam turbine topping cycles. Typical
heat rates are in the 5000-6000 Btu/kWh range.
A potential drawback of combustion turbine topping cycles is the
petroleum based 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., 500 Btu/ft3) and methanol
have been proposed. However, solid fuels such as coal, peat, biomass, and
municipal waste cannot be used unless gasified. The gas produced from solid
fuels must be upgraded in order to optimize the power cycle. 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 in waste heat boilers. Diesel cycles are
appropriate for institutional and high-density residential installations.
They may be appropriate for smaller manufacturing establishments such as
seafood processing plants or where power costs dictate their use.
Diesel generation, which has been described in Section 3.3, has three
potential advantages over combustion turbine-based systems: 1) the highest
5.7
power/steam ratios, typically twice those associated with combustion turbines;
2) the ability 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
significant 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 gas from coal and biomass has been used
successfully in diesel generation; however, this results in substantial
derating of the equipment.
Bottoming Cycles
Currently available bottoming cycle technology converts reject steam into
electricity by use of large, specially designed condensing turbines which can
handle saturated steam. The concept of this form of cogeneration is
illustrated in Figure 5.3.
Cogeneration systems exhibit high thermodynamic efficiencies in
comparison 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 cogenerat1on systems, other than diesel, depend
upon operating at full loads. Turbines are quite inefficient when operated at
less than 70-80% of capacity.
5.1.2 Siting and Fuel Requirements
All cogeneration systems must be located at or close to steam or process
heat users. Typically, the cogeneration system will be located on the
manufacturer•s premises, although some have been located up to 1 mile away.
Systems producing heat for district heating must be located in close proximity
to heating loads, although hot water generally can be transported over longer
distances than steam. Since cogeneration systems are usually located at or
near manufacturing or high-density, commercial-residential heat loads, they
5.8
STACK GAS
_ ....
BOILER
PROCESS
STEAM
----~~ t----. I
PROCESS
''----f{ fP---..
BOILER
STEAM
1 .. ~.,_.....;...F.;;;.;EE;;;.;D;...W......,A_T ..... E;...R_-ff J CON DEN SATE
~--------~----~ASH
ELECTRICITY
CONDENSER
FIGURE 5.3. Simplified Schematic of a Bottoming Cycle
are also located near electrical load centers. Proximity to fuel sources is
not required unless the fuel is 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 as discussed in Section 5.1.1. Steam turbine topping and bottoming
cycles can be fueled by virtually any combustible energy source. Combustion
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 a
number of site-specific variables. Typical values for cogeneration facilities
are normally in the 4500-6500 Btu/kWh range depending on cycle, power/steam
ratio, process steam conditions, and other parameters.
5.1.3 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 5.2.
5.9
TABLE 5.2. Cost Summary for Steam and Combustion Turbine Cycles
Steam Combustion Diesel
Turbine Turbine Generator
Toppi~8) Topping Topping
Cycle Cycle Cycle
caeacitx {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.
Operating and maintenance costs depend on cycle, capacity, degree of
complexity, and the type of operators otherwise required at the site. For
example at refineries, maintenance can be accomplished by plant crews. A
maintenance crew must be hired for other applications. Labor and maintenance
costs are somewhat higher for steam turbine systems than for combustion
turbine systems, primarily because of the complex water circuit. However, if
synthetic fuel systems (e.g., low Btu gasifiers) are tied to combustion
turbines, this differential may disappear. Representative values for a
combustion turbine cycle would be about $2.50/kW/yr.
Despite the complexities and costs associated with cogeneration, the
price of power from such systems is generally lower than that associated with
condensing power stations. This is 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 production, and the power generation cycle can be treated as
an incremental investment; therefore, many of the operating costs can be
treated in incremental fashion. It is also significant that cogenerated power
costs are generally less sensitive to rising fuel prices than condensing power
cycles because of the highly favorable heat rates associated with cogeneration
systems.
5.10
5.1.4 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.
With a steam topping cycle, a minimal 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
requirements, 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 3-4
times per kW-hr when compared to a conventional condensing plant. Cooling
water requirements would correspondingly increase. Boiler feedwater and
blowdown would remain essentially unchanged from the original facility.
All potentially adverse water resourace impacts associated with the
construction and operaion of a cogeneration facility are generally minimized
through appropriate plant siting and water, wastewater, and solid waste
management program (refer to Appendix A). 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.
A variety of atmospheric impacts may be associated with the development
of cogeneration facilites. This variety arises from the fact that many
different fuels, processing systems, facility sizes, and combustion techniques
may be used. For existing facilities the incremental impacts on air quality
resulting from cogeneration systems are probably negligible unless a great
deal of additional fuel is consumed. These systems use heat or power that
have already been generated for other purposes, and they extract a portion of
the available energy for electric power generaton. Cogeneration may then be
characterized as having a very low atmosphere impact when compared to other
combustion systems.
5.11
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 associated with oil and gas combustion facilities. As with
existing systems, the impacts may be construed to be minimal because the
emissions are basically associated with the industrial process or system to
which the cogeneration facility is attached.
Conversion of an existing steam production facility to a cogeneration
system is not expected to result in significant incremental impacts on aquatic
or marine ecosystems. This is attributable to minimal additional water
requirements and, for steam topping cycles, the elimination of waste heat
dissipation to the aquatic environment.
Aquatic ecosystem impacts associated with the construction and operation
of a complete cogeneration facility would be dependent upon fuel and process
type and would be similar to those experienced with comparable steam cycle
facilities (refer to Appendix C).
Incremental terrestrial ecosystem impacts associated with the addition of
electrical generating facilities to an existing steam plant will be minimal.
Generally, less than a 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. Biological effects of construction and operation of a complete
cogeneration facility would be dependent upon fuel and process type, but would
be similar to those experienced with comparable steam cycle facilties (refer
to Appendix D).
5.1.5 Socioeconomic Considerations
Several potential sites for cogeneration have been identified in the
Railbelt. The refineries located in Kenai and Fairbanks are prime sites for
cogeneration as well as the proposed refinery at Valdez. Other sites having
potential for cogeneration are located primarily in Anchorage and Fairbanks,
including industries, military installations, universities, hospitals, and
large apartment complexes.
5.12
The size of the construction work force will vary from 25 to 250
depending on scale of plant. 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 (3,173 and 4,326, respectively). A boom/bust
cycle can be avoided in these communities through the installation of
construction camps.
Expenditures on a cogeneration facility would flow primarily out of
Alaska. This is because of the amount of equipment compared to the moderate
sized workforce and relatively short construction time. The estimated
percentage breakdown of project investment is approximately 67% outside of
Alaska and 33% made within the state.
5.1.6 Potential Application to 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 5.4), have the most potential for
cogeneration in the Railbelt region. Generally, oil refineries have a
potential for producing 11-12 kWh/bbl; of that, 50 to 67% would be available
for distribution outside of the producing industry's needs (Gyftopoulos,
Lazrridis, and Widner 1974). Existing oil refining capacity has a potential
for approximately 50-MWe of generating capacity. About 210 million kWh/yr of
saleable energy could be produced refinery annual load factor of 80%. The
proposed Alpetco refinery has the potential to generate approximately
300 million kWh/yr.
Other petroleum-related activities in the Railbelt region with
cogeneration potential include oil pipeline pumping stations, natural gas
pipeline pumping stations, and natural gas liquefaction (LNG) facilities if
such plants are developed.
Outside the petroleum industry, manufacturing focuses on lumber and fish
processing. The 51 lumber mills in the region are small (e.g., 1 MBF/D), and
5.13
PETROLEUM REFINING IN THE
RAILBELT AREA
in Barrels Per Day
(Bbi!D)
SOURCE: "Petroleum Refineries in the U.S. and
U.S. Territories." DOE/EIA 0111 (80)
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 5.4.
USGS ALASKA MAP E
are well below the scale required for cogeneration. The fish processing
industry has a low potential for cogeneration (Resource Planning Associates
1977), although some cogeneration may be occurring in these industries (Census
of Manufacturers 1976).
Industry in the Railbelt currently generates 414 million kWh/yr and
military installations generate 334 million kWh/yr. This represents 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.
5.2 TIDAL POWER
Tidal 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).
Development of tidal power plants has been slow because the technology for
low-head, high-discharge turbo-machinery is still being developed. In its
present state of technology, 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 identified with
significant tidal power potential. Estimates indicate that up to 2,600 MW of
tidal power energy may be available on the Knik Arm and Turnagain Arm of Cook
Inlet. Studies sponsored by the State of Alaska will more thoroughly define
potential project costs and environmental effects. The preliminary results of
the studies may be available by Spring 1981.
The underlying principles of tidal power plants are similar to those of
hydropower, but instead of water flowing in one direction, water flows back
and forth between the basin and sea through reversible turbines. The
electrical energy that can be developed at any tidal site depends on a number
of interrelated factors, including usable head, which varies continuously with
5.17
tidal fluctuations, area of the tidal basin, capacity of sluiceways to fill or
empty the basin, capacity of turbine and generating units, and the mode of
operation.
Tidal power's major benefit is that, like hydropower, the operation of
the plant utilizes a renewable energy resource. The primary disadvantage is
that the generation of electricity is dependent on the cyclical pattern of
tides. Since the 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 demand.
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 fluctuation
is amplified by shoaling effects. By the time the tidal flow reaches the
coast, the surface level variation is amplified three or four times. Further
amplifications occur in certain estuaries where level variations increase by
another factor of two to four.
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
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.
5.2.1 Technical Characteristics
Tidal power projects consist of one or more reservoirs (or basins), a
barrage, and a transmission link to a system grid. A typical plan of a tidal
power project is depicted in Figure 5.5. The barrage usually consists of a
powerhouse, a sluiceway section, and dike or dam connections to shore, thus
forming a controlled tidal basin. The powerhouse contains turbines,
5.18
\ BARRAGE
)\
\ '
SHORE
SCALE 0 500 1000 ft.
FIGURE 5.5. Plan of a Tidal Power Plant
generators, control and switching apparatus, and transformers. Additional
components may include trash racks on both sides of turbine water passages,
concrete forebay, and tailrace approaches.
Existing tidal generating plants range in size from less than 1 MW to
240 MW. Generating efficiencies are on the order of 60%.
Tidal power is a relatively inflexible technology for the following
reasons:
• Because power generation is a function of cyclical tidal
characteristics, there is no way to accommodate demand occurring out
of phase with the tides.
• Full power is only available at maximum tide levels
• Tidal power plants have no dependable capacity in the sense that the
plant can serve a continuous load over extended intervals of time.
Due to these characteristics, tidal power developments must be used in
conjunction with complementary cycling generating capacity or energy storage
systems. An alternativae approach to compensate for the intermittant
characteristics of tidal power generation would be to design and operate the
project to include pumped-storage to artificially prolong the natural tidal
cycle. A tidal pumped-storage facil ily still must be complemented by flexible
load plants, such as pumped-storage, hydroelectric, or cycling thermal plants.
Refinements in the areas of equipment technology and construction
procedure are necessary to accelerate commercialization of this technology.
Specific obstacles to the development of tidal power technology have included
limited availability of low-head turbo-generator units and the difficulties
and expense of barrage construction. Recent renewed interest in low head
hydropower development is helping to spur the manufacture of necessary
equipment. In addition, the cost of cofferdams construction can be brought
down through the development of prefabricated barrage sections.
State-of-the-art barrage construction methods involve prefabrication of the
power station in sections, in drydocks, or on slipways. Each caisson section
includes a horizontal water duct incorporating an intake, space for a
turbo-generator set, and draft tube (Figure 5.6). Provision for two or more
5.20
TYPE A-BULB TYPE TURBINE, DIRECTLY COUPLED GENERATOR
:I : o'
•. f1.
------------
TYPE B-BULB TYPE TURBINE, GEAR COUPLED GENERATOR
TYPE C-TUBE TURBINE, DIRECTLY COUPLED GENERATOR
. "
. .. . . .. ~ .
. ·. . . . .
.. ,. . .
TYPE D-STRAIGHT-FLOW TURBINE WITH RIM GENERATOR
FIGURE 5.6. Types of Turbine/Generator Sets for a Tidal Power Plant
5.21
turbo-generater sets might be incorporated in a single caisson. Sections are
then floated to the barrage site and sunk at slack water level onto dredged,
level, rock-rubble foundations. This caisson method has been used to build a
tidal-power station at Kislaya Bay, USSR.
5.2.2 Siting Requirements
Ideal sites for a tidal power plant should have large tidal ranges and
large water areas capable of being dammed by a short barrage. Three site
conditions are necessary for an economically viable tidal power development:
1) a mean tidal range of about 20 ft; 2) an estuary or coastal indentation
that, when dammed, will not substantially reduce the tidal range; and 3) an
interconnected electrical generating system with surplus off-peak power which
can provide capacity during slack tide periods. Without any one of these
three prerequisites, a tidal-energy development will probably be precluded
although the latter constraint can be overcome by constructing a complementary
energy storage system.
Foundation conditions should be level hard rock, although shallow
sedimentary 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.
5.2.3 Costs
Detailed cost information on tidal power facilities is not yet available,
but will be provides later based on the findings of two current studies:
Acres American Cook Inlet Study and Retherford's Angoon Study. Based on
information from preliminary studies, Cook Inlet installed 1980 capital costs
could range from $2,660 to $3,460 per kilowatt (Stone and Webster 1977).
Estimated operation and maintenance costs are not yet available.
5.2.4 Environmental Considerations
The placement of a barrage to harness tidal power separates a natural
embayment into two artificial basins. This separtion can cause major changes
in the water circulation patterns of the unrestricted outer basin. The
present hydrologic regime of the Knik Arm of Cook Inlet, the prime tidal power
candidate site, is governed by large tidal fluctuations in this shallow,
5.22
narrow basin. Because of this characteristic, waters are well-mixed
laterally, longitudinally, and vertically with each tidal cycle. In summer,
there is a net outward movement of inlet waters caused by large inflow of
glacial meltwater from tributary streams, while in winter with reduced runoff,
there is practically no net outflow (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 wouid be
greatly affected. Waters would probably not be as well mixed and lateral
separation could be expected. There would also be a reduction in the amount
of water exchanged between the Knik Arm and the Upper Inlet. 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. The
magnitude of this impact, however, would depend upon the plant's specific
design characteristics.
Circulation and flow patterns in the mid-Inlet and "outer" 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 large freshwater discharge of
the Susitna River. If, however, the tidal power project encompasses both the
Knik Arm and the Turnagain Arm of if the project is coupled with a Susitna
River energy development project in the future, significant Cook Inlet
circulation pattern changes 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 cause an
increase in pollutant concentrations. Constricting the water flow to a few
5.23
intake and outlet conduits would also 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
concentrations 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 one of low energy.
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.
Water transportation may also be affected by tidal power projects which
obstruct navigable waters. This can be overcome through the construction of
locks, which then places constraints on the volume of boats traveling to and
from an estuary. This could be significant to the traffic entering the Port
of Anchorage, but is dependent upon the specific location of the barrage.
There will be no impacts on air quality or meteorological resources
resulting 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 the restriction of movement of
aquatic organisms, such as salmonids, 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 a number of 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).
5.24
Restricted flow inside the bay could result in increased siltation from
the large quantities of sediment discharge by the Matanuska River and other
Knik Arm tributaries, resulting in habitat destruction and increased benthic
organism mortality. Flow patterns may be altered outside the tidal barrier,
resulting in changes in movement of plankton and other marine organisms. One
advantage of such a structure may be to reduce turbidity 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 may occur if a tidal power development were to occur on
Turnagain Arm because of the many similarities between the two areas. Salmon,
though 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.
Marine manuel habitat reduction will result from the barrier presented by
the tidal power barrage and by the modification of shoreline vegetation 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 negataively affected if anadromous fish
passages through the barrage were reduced.
The Knik and Turnagain tributaries of Cook Inlet are environmentally
sensitive 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 during seasonal migration periods on these areas.
These groups of birds also use Palmer Flats and Eagle River Flats of the Knik
tributary. Irregular tidal cycles could alter the intertidal biotic
communities of these areas and reduce their value to waterfowl and various
shorebirds.
Both tributaries are also used by harbor seals. Establishment of a
barrage would effectively end their use of these areas. Lastly, only the Knik
5.25
tributary 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. Losses to marine mammals
could, however, not be relieved. Waterfowl and various shorebird habitats
could be kept relatively unchanged by maintaining tidal cycles similar to
normal ones. This would not be possible if tidal energy production was
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, provided densities of fish-eating raptors on
these streams are not at saturation levels for reasons other than food
availability. If this were the case, then losses could not be mitigated.
5.2.5 Socioeconomic Considerations
A tidal power plant requires a large construction workforce and a small
operating workforce, creating the potential for a boom/bust cycle. During a
period of 7 years a workforce of 200 to 500 would be required for a 240-MW
plant. The size of the construction workforce would not vary greatly with
plant scale since excavation and barrage construction are general requirements
independent of generating capacity. A staff of 20 to 50 would be required
during the operating phase.
Since the two tidal sites identified in the Railbelt are located close to
Anchorage, impacts on the surrounding area due to construction should be
minimal. The pt~oject offers potential emJ.JluylllenL Lo unemployed persons s1d1ng
in Anchorage and the upper Kenai Peninsula. Therefore, a workforce would not
have to be brought in from other areas of Alaska, which would avoid increasing
the demand for housing or services.
Since tidal power is a labor-intensive technology and participation by
the Anchorage and upper Kenai Peninsula labor force is expected, the
expenditures for labor should be kept primarily within the region. Some of
the expenditures for capital, particularly those for embankment materials,
would also remain within the region. Therefore, approximately 67% of the
5.26
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.
5.2.6 Application to Railbelt Energy Demand
The Railbelt region has one significant area for tidal power
development--Cook Inlet, which has 35-ft tidal fluctuations. Up to 2,600 MW
of potential, including 750 MW from an identified site on Knik Arm just north
of Anchorage, could be developed. However, Cook Inlet sites also has the
disadvantage of shallow water, deep sediment layers, and icing conditions.
Severe ice conditions in Knik Arm and Turnagain Arm will complicate the
design and operation of a tidal development for Cook Inlet. The tide
fluctuation prevents formation of solid ice sheet on Cook Inlet, as the rapid
rise and fall in water level tends to continuously break up the ice. These
broken ice sheets form ice floes which tend to move back and forth within the
estuary. Experience at the Port of Anchorage Marine Terminal, for example,
indicates that ice builds up in thick layers on piles supporting the wharf
until a non-uniform honeycomb has been formed under the entire structure.
This ice layering lasts for about 3 months. Scouring action of the ice flows
will damage concrete surfaces unless these are protected by steel armoring.
An additional problem is presented by cold winter air temperatures in
combination with repeated submergence and exposure of concrete surfaces by
tidal action. Each cycle of the tide becomes a freeze-thaw cycle under these
conditions. Concrete surfaces become scoured and spalled as a result of the
combination of frost action and falling ice. Steel piles and sheet steel
armoring of concrete surfaces will be necessary to ensure surface and
structural integrity of normally exposed concrete surfaces.
5.3 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
5.27
may come to play a significant role in electric power generation in rural
areas, small communities, and possibly for large interconnected energy
systems.
Large wind turbines are being developed in response to this renewed
interest and are in a demonstration phase. In 1979 a MOD-1 2-MW, 200 ft
diameter turbine was completed at Boone, North Carolina. Three MOD-2 wind
turbines, rated at 2.5-MW capacjty, are under construction near Goldendale,
Washington by the Bonneville Power Administration, U.S. Department of Energy,
and NASA. These and other wind turbines in the 1-MW range of rated output are
available for production, but benefits of assembly line production have not
been realized. Commercially available, mass produced wind machines are at
present quite small and only available in unit sizes of about 5 kW, with the
maximum at 45 kW. This section will focus on large wind turbines of 0.1 MW
rated capacity or more such as might by employed as centralized power
generating facilities by a utility.
5.3.1 Technical Characteristics
Wind energy is characteristically a diffuse source of energy in which the
theoretical output of an individual wind machine is a function of the third
power of the speed of the wind, wind machine efficiency, and area intercepted
by the turbine blades. Wind is converted to electric power in two steps. The
first involves the conversion of the kinetic energy in the flowing wind to
rotational energy. The flow of the wind past an aerodynamically designed
blade moves it around its axis of rotation, extracting energy from the wind.
The second step is the conversion of rotational energy to electric energy
through the use of a generator.
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: 1) horizontal axis; 2) vertical axis; and 3) cross wind horizontal
axis.
Horizontal axis rotor systems represent the conventional windmill-type
machine whose axis of blade rotation is horizontal and parallel to the wind
direction. This is the design being used for development of the megawatt-size
systems and is illustrated in Figure 5.7. Vertical axis rotor systems have a
5.28
A ~
45ft
*
WIND r>
300ft dia.
200ft
•
CONTROLLABLE Tl P
~ROTOR
rNACELLE
It I
if-l
....._TOWER
r-SWITCHGEAR AND
~ TRANSFORMER \ .-~1 l
FOUNDATION
FIGURE 5.7. Schematic of a MOD-2 Wind Turbine Generator
vertical axis of blade rotation. The most common representatives of this
system are the Savonius and Darrieus machines (Figure 5.8). Vertical axis
systems are generally less efficient than the horizontal rotor systems, but
since they do not need a tower, their construction costs are less and have the
added advantage of being insensitive to wind direction. Cross-wind horizontal
5.29
FIGURE 5.8. A Vertical Axis Wind Turbine (Darrieus Type)
5.30
axis systems are of the familiar paddle-wheel design and do not represent an
improvement over either of the other two designs (Inglis 1978). At the
current stage of development it appears that horizontal axis designs will be
preferred for megawatt-scale machines.
Wind generators operate within well-defined wind speed ranges. The
11 power output profile 11 depicts the power output of the turbine as a function
of the wind speed. The power profile for the M00-2 (Figure 5.9) indicates the
cut-in speed (14 mph), rated speed (28 mph), and cut-out speed (47 mph).
Since wind turbines must be designed to fit load system and wind conditions,
in some cases a smaller wind turbine with a lower cut-in speed, a lower rated
speed, and a lower power rating may be preferred to a larger machine with
higher cut-in wind speeds.
The production of wind power electricity is an intermittent process owing
to 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 capacity factor, for wind turbines
will probably range between 30 and 50%, but this factor is extremely sensitive
to the wind pattern at the site.
Weather factors such as 1c1ng or high winds act to reduce the machine
reliability. Equipment life in the harsh climate of the Railbelt region may
pose a problem, which requires careful study. Towers and blades must be able
to withstand storms, winds, icing, or snow loading. Tower foundations need to
withstand repeated freezing and thawing. High mechanical loads are
experienced during tower and blade icing conditions. Equipment exposed to the
elements may experience lubrication problems in sub-zero temperatures.
Grouping of wind turbines into ••wind farms 11
, as at Gambell, Alaska, can
reduce problems associated with equipment failures. Any one turbine could be
shutdown for repair or maintenance without greatly affecting the farm•s
output. The overall reliability of the farm 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
5.31
32 CUT-IN RATED CUT-OUT
~
-V) 2.4 = C'CJ ~
C'CJ
~
!1)
E -1-1.6 :::::> a.
1-
:::::>
0
a:::
1..1..1
3: 0.8 0 a.
o~-----L--
o 8 16 24 32 40 48
WINDS PEED (mph at hub)
FIGURE 5.9. Power Profile of the M00-2 Wind Machine
or a wind farm may be developed at sites where the wind pattern closely
approximates the load pattern. This helps alleviate storage requirements and
load management difficulties.
In a grid with existing hydro capacity, storage can be accomplished by
displacement of hydro production, that is, by simply not using as much water
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
5.32
hydro facility will already be scheduled to provide peaking power.
Simple-cycle combustion turbines may also be used in conjunction with wind
systems in a manner similar to hydro power.
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.
5.3.2 Siting Requirements
The siting of the wind turbines is crucial in wind energy conversion
systems. The most significant siting consideration is average wind speed and
variability. These depend on large-scale weather patterns but are also
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
incremental increases in wind speed is important (Hill 1977). Extremely high
winds and turbulance may damage the wind turbines, and any 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
conditions. Undesirable meteorlogical conditions in addition to turbulance
include glazing conditions, blowing sand or dust, heavy accumulations of snow,
and extreme cold.
5.3.3 Costs
The major costs associated with the development of wind power are the
equipment and erection costs. The operations and maintenance (0 and M) costs
are difficult to project because of a lack of standardization and little
operating experience. Consequently, the 0 and M costs are uncertain but are
projected to be small when compared to the initial installation costs.
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 mo~e machines. Estimates provided by the Boeing Company for this level
of production for the MOD-2 turbines being installed near Goldendale,
5.33
Washington indicate a cost of about $800 per installed kilowatt capacity.
Currently, the 2.5 MW M00-2 machine sells for $6.5 million each. Boeing also
estimates that the cost of power produced by these turbines will be in the
range of 4 to 5 cents per kilowatt-hour. Costs of installation at remote
locations are uncertain, particularly if there is considerable difficulty in
shipping the units or installing them onsite. Because of the remoteness of
prime locations, the costs of installed wind turbine power capacity are
expected to be significantly higher than those associated with more accessible
locations (Inglis 1978; BPA 1981; Hill 1978).
5.3.4 Environmental Considerations
Wind turbines extract energy from the atmosphere and therefore have the
potential of causing 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 for a single 2.5-MW facility would be approximately
1500 ft. 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
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 associated with 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.
Wind powered energy requires varying amounts of land area for
development. The amounts of area required depend on number, spacing, and
5.34
types of wind-powered units used. This can range from approximately 2 acres
for one 2.5-MW generating unit to over 100 square miles for a 1000 MW wind
farm. These developments, due to requirements for persistent high-velocity
winds, would probably be established in remote areas.
Because of the land requirements involved, the potentially remote siting
locations and the possible need for clearing of vegetation, the greatest
impact resulting from wind energy projects on terrestrial biota would be loss
or disturbance of habitat. Wind generating structures could also affect
migratory birds by causing collisions. Other potential impacts include low
frequency noise emanating 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, however, are presently
unclear.
Environmentally sensitive areas in the Railbelt region presently proposed
for wind energy development are exposed coastal areas along the Gulf of
Alaska, and possibly hilltops and ridgelines in the interior. Alteration of
coastal bluffs could negatively 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 utilize 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 {endangered species), and other birds, if situated in
migratory corridors. Inland development of wind energy could negatively
affect Dall sheep, mountain goat, moose, and caribou if situated on critical
range lands.
These terrestrial impacts can generally be mitigated. Habitat lost
through development is irreplaceable. However, these losses can be minimized
by siting plants in areas of low wildlife use. This would include avoiding
critical ranges of big game, traditional haul-out areas of seals and nesting
5.35
colonies of birds, and known migratory bird corridors or key feeding areas.
The feasibility of mitigation will, of course, depend on the size of the wind
energy development.
5.3.5 Socioeconomic Effects
Construction of a 1 to 2 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 on-site operating work force, and minimal
maintenance 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, population size of a community 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 increase in work force size and length of construction period.
The cost breakdown for a wind turbine investment is based on the
assumption 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. Therefore, approximately 80% of the expenditures
would be sent outside the region while 20% would remain within Alaska.
5.3.6 Potential Application to Railbelt Energy Demand
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.
Studies to identify wind energy resources in the Railbelt would require a
significant data base. Such a data base is currently lacking, as can be seen
on Figure 5.10, which shows mean wind speeds from available monitoring
5.36
,,
' ~ \lfJO
il910
... ,.
TAIIUWTN
/fJIC.
AVERAG.E WIND SPEEDS
in Miles Per Hour
SOURCE: T. Wentink.
\J Available Meteorological Stations
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 5.10.
USGS ALASKA MAP E
stations in the Railbelt region. Currently available literature is not
adequate to comprehensively identify potential wind energy conversion system
sites in the Railbelt region. Studies necessary to assess wind energy
potential include: preparing and examining detailed contour patterns of the
terrain, modelling selected sites, monitoring meteorological conditions at
prime sites for at least 1 year (preferably 3 years), analyses using modelled
and measured data, developing site-specific wind duration curves, and
selecting final sites.
Wentink and his colleagues at the University of Alaska have conducted a
preliminary assessment of wind power potential in Alaska. The results of
these studies indicated a potential for favorable sites for wind energy
development at exposed coastal locations and possibly along ridgelines or
hills in the interior (Wentink 1979). A Battelle-Northwest study that
addressed the nature of wind patterns in the Cook Inlet area generally
concluded that sites with marginal potential exist in this area.
5.4 SMALL WINO ENERGY CONVERSION SYSTEMS
Small wind energy conversion systems {SWECS) are wind machines with rated
output of 100 kW or less. Typically these machines would be sited in a
dispersed manner, at individual residences or in small communities, as
compared to the large wind energy conversion systems (Section 5.3) which would
be sited, generally in clusters, as centralized power production facilities.
Small wind energy conversion systems are available in horizontal and in
vertical axis configuration. The horizontal areas machines (Figure 5.11)
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 revolve in conformance with changing wind direction, requiring
provision of head bearings and slip rings and machine orientation devices.
Although of lower efficiency than horizontal axis machines. The vertical
axis generator (Figure 5.8) is located in a fixed position near the grounmd,
minimizing tower structure and eliminating. 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.
5.39
FIGURE 5.11. A Typical Horizontal Axis Small Wind Machine
A number of small wind machines are now in commercial production in sizes
ranging from 0.1 to 37 kW (A.D. Little, 1979).
Historically, battery-charging systems have been the primary application
for Small Wind Energy Conversion Systems in Alaska; however, this is beginning
to change. Figure 5.12 shows some of the many possible ways of using SWECS, a
few of which are used in Alaska.
The subject of this study is concerned with SWECS which interface
directly with the utility grid. Off-grid installations are not considered.
5.4.1 Technical Characteristics
The three most common types of small wind generator systems are induction
(AC) generators, synchronous (AC) generators, and DC generators. SWECS using
induction generators are designed to operate in parallel with an existing
utility grid. The induction generator is actually an induction motor. With
the wind blowing at a velocity that causes the rotor to turn faster than the
induction motor's rated rpm, the device acts like a generator and produces
5.40
FIGURE 5.12. Block Diagram of SWECS configurations
presently being used and under study.
energy. The resulting power will be synchronized with the local utility power
frequency allowing power to be supplied to the utility system. The utility
power source provides the reference frequency.
SWECS using synchronous alternators are capable of generating 60-cycle
alternating current with or without a synchronizing utility grid. This
capability is possible because of synchronizing microprocessors controls
incorporated innto the wind machine.
SWECS which generate DC power are typically used for charging batteries
in remote sites. Either a brush-type DC motor or an alternator and DC
rectifier is 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.
5.41
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).
The maximum heat loss from a building occurs in extreme, cold weather
with high winds. Since winter months are typically windier than summer in
most parts of Alaska, any electricity used for space heating, either directly
or indirectly, (furnace motor,
power available from the wind.
activities are usually limited
is increased.
fans, circulating pump) would coincide with
Also, in periods of high wind, people's
to indoors where lighting and appliance usage
On-grid SWECS are usually not considered as base load units and are given
little capacity credit, operating only in a fuel-saver mode. However, in
regions as diverse climatically as the Railbelt, studies have shown (Timm
1980) that with simple load management techniques, wind machines can be given
significant capacity credit in grids without storage.
If SWECS are added to an existing hydroelectric grid, storage is built
into the grid system: when the wind is blowing, less water is run through the
turbines; during periods of calm, that water is then used to follow load, much
like a large battery storage system (BPA 1980). If enough grid-connected wind
generated capacity were installed, hydroelectric pump-storage could be used to
store surplus energy.
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 their smal) size allowing
for incremental additions, SWECS are extremely adaptable to any growth pattern.
Historically, the market for SWECS has been remote sites where power
costs were very high. Because of the extreme environmental condition they are
subjected to, wind generators must be properly designed and installed to
provide adequate reliability with little maintenance. The availability of
wind energy depends on the site and the application, and it cannot be answered
without better wind data.
5.42
5.4.2 Siting Requirements
A wind speed of 7 to 10 mph is required to start most SWECS producing
power. An annual average of 10 mph is usually considered a lower economic
cut-off for most applications; however, this is very dependent on the site,
energy costs, and particular wind generator design.
Turbulence is the worst energy of SWECS. It can be caused by trees,
buildings, and topography. Because wind acts like a fluid in that it slows
down when it encounters an object or rough terrain, the higher up from the
ground, the stronger the wind. Thus each site must be evaluated for terrain
(Figure 5.13) and what affect that may have on wind speeds at different
heights (Figure 5.14).
A small wind machine which 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 becauase of the high transmission line losses.
5.4.3 Costs
Depending on the application, the cost of money, tax credits, and the
type of system, installation of 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 5.3). A operation and maintenance figure of 1% of installed
costs equal to $50-$200/year would be representative, but depends on the
system.
--=i>
9D"d-: ----.. -.. .._...._
-
FIGURE 5.13. Local Terrain Can Significantly Affect the
Performance of a Wind Machine
5.43
180
w 160
0 WINDSPEED < 140 ....
0::
:::> 120 Cl)
w 100 > 0
al 80 < -:I: 60 ~ w 40 :I:
2 3 4 5 6 7 8 9 10 11 12
INCREASE FACTOR
FIGURE 5.14. Example of Increase In Energy Available In the Wind
with An Increased Tower Height
TABLE 5.3. Estimated Costs of Small Wind Energy Conversion Systems
Rate of Capita 1 Operation and Cost of
Capacity Costs Maintenance Costs Power
{kW} {$/kW} {$/kW/tr} ($/kW)(a)
2 2500 25 0.09-0.15
10 2500 20 0.09-0.15
(a) Ranges given based on capacity factors of 0.3 to 0.5.
5.4.4 Environmental Impacts
Studies have shown some enhancement of local wildlife due to downwind
shelters, as well as a possible adverse impact on low flying night migratory
birds in bad weather. However, the kill rate is not significant.
Aesthetic intrusiveness is difficult to assess and highly subjective.
Many people surveyed have found small wind machines to be visually pleasing.
Small generators noise is not significant with proper blade design.
Small wind machines mounted on towers require no more than 100 sq ft at
the base plus any exclusion area which the owner wishes to fence off for
safety reasons (usually no more than about 5 blade diameters).
5.44
Radio frequency interference can be mitigated with proper blade design
(nonmetallic) and siting.
Potential safety risks involve the possibility of tower or blade failure
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 maintenance;
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.
5.4.5 Socioeconomic Impacts
By siting SWECS in 11 Wind farms, .. rows of generators can be lined up as a
wind break for combined utilization 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 resulting from construction or operation
of a facility is foreseen. The necessary manpower, talent, and expertise is
currently available within the Railbelt.
The chief advantage of SWECS 1s 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
manufactured in the Railbelt region, a significant portion of the capital cost
could also stay in the region.
How convenient this technology is to the consumer depends on the system.
Induction generator systems require only an annual inspection and lubrication
of the wind generator. Synchronore generator systems being installed today
are totally microprocessor-controlled and need no maintenance other than
periodic generator inspection and lubrication. Maintenance contracts are
presently available which would free the consumer from any maintenance
responsibilities.
5.45
The individual consumer's level of control can range from a totally
manual system to a totally automatic SWECS. Most installations do allow the
individual to be considerably closer to the actual source of power and gives
him the ability to exercise more control over his production and consumption
than if the power were generated off-site by a utility.
5.4.6 Potential Application to the Railbelt Region
Until recently there were only a handful of SWECS manufacturers. Today
there are over 50 with a half dozen mass producing generators at a respectable
rate (20-200/month). The demand, however, is far outpacing the supply, and
several manufacturers report back orders of 120, or more, days. However,
60-90 days is generally quoted as delivery time and the major manufacturers
hope to be selling from inventory by the end of 1981.
A dealership and repair network is already in existence in the Railbelt
region and would grow as the number of installed WECS increases. Engineering
and design expertise is also present in the region. Five system design
organizations, four suppliers and one installer are currently operating in the
Railbelt (Energactions 1981).
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 the market penetration and
mass production has brought the unit cost down and manufacturers have
internalized major R&D efforts, then widespread use of SWECS may become a
reality.
Wind data have historically been collected from airports at a height
usually no greater than 30ft. Wind generators are typically not located near
airports (which are usually sited in locations protected from winds) and are
placed at least twice as high as conventional meteorlogical stations. A few
examples will illustrate the problem:
• 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.
5.46
• In Homer the recorded annual average is 9 mph at the airport, while
on the "spit" the average is reported to be closer to 13 mph.
Further 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 is recorded as 4 mph, yet as one climbs out
of the valley the average wind speed almost triples near Murphy Dome.
This suggests that existing data are not very helpful in determining the
potential of SWECS in the Railbelt. The number of mountain passes with
channeling effects, glaciers with their constant source of winds, and coastal
regions with the windy maritime influences yield thousands of potential SWECS
sites in the Railbelt. A recent study done by Battelle-Northwest 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 any
candidate sites to be selected or site specific costs to be identified for
large wind systems.
Because of the lack of data taken for siting small wind machines there is
no quantitative means for assessing the possible contribution SWECS would have
in the Railbelt region. However, since most of the population lives in two
known areas of low winds (Anchorage and Fairbanks), it_is reasonable to assume
that without large-scale utilization of "wind farms," only a small percentage
of the total Railbelt load could be met by wind power {less than 10%) in the
next 5 years. If a decision were made to develop clusters of SWECS then this
contribution could become significant in the midterm (5 to 10 years).
5.5 SOLAR ELECTRIC
Two basic methods for generating electric power from solar radiation are
under development, solar thermal conversion and photovoltaic systems. Solar
thermal systems convert solar radiation to heat in a working fluid. This
working fluid can include water, steam, air, various solutions, and molten
metals. Energy is realized as work when the fluid is used to drive a
5.47
turbine. Photovoltaic systems is a more direct approach. Solar energy is
converted to electric energy by the activation of electrons in photosensitive
substances.
At present, commercially available photovoltaic cells are made of silicon
wafers and 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 have
been proposed capable of converting 30 to 40% of the sunlight falling on them
to electricity.
Both solar technologies suffer from the same constraints. Available
solar energy is diurnally and seasonally variable and is subject to
uncertainties of cloud cover and precipitation. Solar energy resources must
be employed as a 11 fuel saving .. option or they must be installed with adequate
storage capacity. In addition, if the diurnal and annual lead cycles are out
of phase with solar energy potential cycles, the inducements for development
of this resource are further reduced. The energy demand and solar
availability cycles are out of phase in the Railbelt region, where demand
generally peaks in winter and at night.
5.5.1 Technical Characteristics
Solar Photovoltaic Systems
Photovoltaic cells operate by transferring the energy in light to
electrons in a semiconductor material. Transfer occurs when a light photon
collides with an atom in the same conductor material with enough energy to
dislodge an electron from a fixed position and 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 then created, whi~h then induces a voltage specific to
the cell material.
Photovoltaic cells commonly come in modular units with voltages of 3 to
24 volts and current outputs from the milliamp range to around 3 amps. The
cells are load-sensitive; as the load is increased, the voltage decreases.
5.48
These cells, being modular in nature, can be easily added together, up to the
limits of various ancillary systems. Ancillary systems include voltage
conversion, energy storage systems, and backup electricity generating systems
(Hill 1977). In general, photovoltaic system conversion efficiencies range
from approximately 2 to 13%.
These cells are well-suited for outer space, application in remote
locations such as navigational aids, and irrigation pumps, where their high
cost per kilowatt-hour can be justified.
Two of the most developed photovoltaic devices are concentrated sunlight
photovoltaic systems and cogeneration photovoltaic systems.
Concentrated Sunlight Photovoltaics. Parabolic reflectors are used for
concentrating sunlight onto an array of solar cells in order to reduce the
number of cells required for a given power output. Conversion efficiencies as
high as 18% have been reported for cells operating in sunlight concentrated
300 times. It is believed that design improvements will result in cells that
have an efficiency of at least 20%, with slight increases in costs. Parabolic
reflectors have one specific disadvantage: in order to work well, automatic
tracking mechanisms must be provided to keep the reflectors focused at the sun
as the sun moves across the sky. With the sun low in the sky during the
winter months in Alaska or in early and late afternoon, these systems would be
very inefficient.
Cogeneration Photovoltaic Systems. The attractiveness of photovoltaic
devices can be increased significantly if the energy not converted to
electricity can be used. Energy not converted to electricity appears as
thermal 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 600F and 1700F, can be used for space heating and for
domestic hot water heating.
Using photovoltaics in a cogeneration mode reduces the electrical
efficiency 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, it is preferable to accept these
losses of efficiency and to use the thermal output from the cells directly
5.49
rather than to maximize cell performance. The use of these systems could be
more efficient than using straight photovoltaic systems for certain
applications. But, even in the "lower 48" states these are expensive options.
Solar Thermal Systems
Solar thermal systems use focused sunlight to provide concentrated
thermal energy. This energy is then used to raise steam or impart heat to
some other working fluid, which is then used to drive turbo-generaters to
produce electricity. The two most advanced solar thermal systems are
described below.
Power Towers. A power tower uses solar energy to raise a working-fluid
to high temperatures for the generation of electricity or process heat.
Optical studies show the best way to generate high temperatures using solar
energy is with a point-focusing array of mirrors that track the sun (a
heliostat). The solar insolation is focussed on a boiler set atop a large
tower. Heliostats that concentrate sunlight 1,000 times are used to raise the
temperature in the boiler to 500°C, and the resulting steam can be used to
produce electricity and process heat through cogeneration.
The first 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 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. The best sites for
commercial-scale towers would be in the desert because of the high solar
flux. These systems are still experimental and will not be available until
possibly the late 1990s. A typical density packed 60-MW tower would cover
roughly 160 acres (Metz and Hammond 1978). Efficiencies are climate-sensitive
and can range from 10 to 70%.
Parabolic Dish Collectors. Solar energy systems can provide a regime of
intermediate operating temperatures 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 simple low-temperature
5.50
collectors used for space and water heating. These types of collectors could
be used for process heat, crop irrigation, and decentralized generation of
electricity.
One such system is the parabolic tracking dish. This 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
circulated through a small heat engine (Hill 1977).
5.5.2 Siting Requirements
Solar electric generating systems are optimally located in areas with
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 high 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 "tilt" 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 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.
5.5.3 Costs
Costs of photovoltaic systems are extremely high compared to other
technologies, mainly because of technical dificulties associated with
developing efficient cells. The costs of photovoltaic cells are much higher
than what they were projected by previous research and development progress.
Today•s cost for a 4-ft2 photovoltaic array (18 volts, 2.5 amps) with a
rated capacity of 30 watts is $500 or about $17/watt of capacity. Costs as
low as $11 per watt of capacity have been reported by the federal government
5.51
when buying in large quantities. DOE expects these costs to be $2/watt in
1982 and $.50/watt in 1986, and as low as $.10-.20/watt in the mid-1990s.
The average life of a typical photovolatic cell is about 20 years, so
provisions for replacement will have to be included in the maintenance costs.
Other costs include maintenance of battery storage systems, voltage conversion
systems, and the auxiliary backup system. Operating labor costs include
cleaning the photovoltaic array (removing ice, snow and dirt), checking
batteries and conversion systems, and maintaining a backup system if one is
used.
The construction of residential or district photovoltaic systems should
not be labor-intensive, since photovoltaic arrays can be easily assembled into
large units, and ancillary systems are also modular in nature.
Cost estimates for solar thermal systems in the 10 to 100 MW capacity
range, are provided in Table 5.4. Construction time is estimated at 5 years,
and the system life is projected for 30 years.
TABLE 5.4. Estimated Costs for Solar Thermal Systems
Operating and Cost of
Capital Costs Maintenance Costs Power(
CaEacit~ {$/kW) {$/kW/~r}(a) ($/kW) b)
10 MW 1500 30-40 0.10
100 MW 1200 27-36 0.08
5.5.4 Environmental Considerations
Photovoltaic systems do not require cooling water or other continuous
process feedwater for their efficient 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. In light of the small plant capacities that would be
considered for the Railbelt and the absence of cooling water requirements,
water resource effects should be minimal.
5.52
The development of solar thermal conversion systems would produce water
resource effects similar to other of steam cycle facilities. Boiler feedwater
and condenser cooling water will be required and will necessitate proper
management techniques (refer to Appendix A). Water requirements are extremely
site-specific as efficiencies ranging from 10 to 70% are possible depending
upon climatic factors. However, in light of the small capacities considered,
impacts should not be significant.
Solar thermal conversion systems may also be operated utilizing a working
fluid other than water. Fluids such as liquid sodium, sodium hydroxide,
hydrocarbon oils, and sodium and potassium nitrates and nitrites have the
potential to adversely affect water quality through accidental spills and
normal system flushing. Specialized transportation and handling techniques
will be required to minimize spill risk and properly mitigate potential
impacts.
Water resource impacts would also occur if pumped storage facilities were
utilized as the energy storage technology for either photovoltaic or solar
thermal conversion systems. Pumped storage impacts are discussed in
Section 4.1.
Solar thermal and photovoltaic electric power conversion systems have no
impact on ambient air quality because they do not emit gaseous pollutants.
Water vapor plumes may emanate from cooling systems associated with solar
thermal processes, however. These plumes will be substantially reduced
because solar thermal systems operate best in full sunlight when the air tends
to be well below saturation. The water droplets are quickly evaporated into a
dry atmosphere. The plumes can also be mitigated by using dry or wet/dry
cooling tower systems.
Some modification 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 climatic response of these facilities
will be similar to that of any comparably large construction project.
Due to minimal water requirements, the operation of photovoltaic systems
will have insignificant impacts on fresh or marine aquatic biota but solar
5.53
thermal conversion plants may have impacts similar to those of other steam
cycle plants (refer to Appendix C). These impacts, however, should be small
and easy to mitigate in light of the small plant capacities considered.
The major terrestrial impact associated with photovoltaic or solar
thermal conversion systems is habitat loss. If these systems are located in
remote areas, the potential for wildlife disturbance through increased human
access may also be significant. Spills of non-water working fluids if used,
could adversely affect local ecosystems. In general, however, impacts to the
terrestrial biota of the Railbelt region should be minimal, since power plant
capacities for both photovoltaic and thermal conversion systems will be
small.
5.5.5 Socioeconomic Impacts
Both solar photovoltaic and solar thermal .conversion systems require a
large construction work force and a small operating and maintenance staff.
The work force for a photovoltaic plant would be larger because of the
construction of solar arrays. A 10-MW photovoltaic plant would require a
construction work force of 100 and an operating and maintenance work force
of 10. A 10-MW central receiver would require a construction work force of 60
and an operating and maintenance staff of 25. The impacts of either 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, both solar
electric generating options require large investments in high technology
equ1pment. The percentage breakdown of project investment is 80% spent
outside Alaska, and 20% would remain in Alaska.
5.5.6 Potential Application to the Railbelt Region
To estimate the availabilty of solar energy in Alaska, insolation data
collected at Fairbanks and at Matanuska, near Anchorage, was examined. The
data reflect the influence of both cloudiness and the annual cycle in sun
angle at these locations. At Fairbanks the total daily solar radiation on a
horizontal surface is 13 Btu/ft2 in December and 1,969 Btu/ft2 in June.
At Matanuska these values range from 48 Btu/ft2 in December to 1,730
5.54
Btu/ft2 in June. In comparsion, in the arid southwestern United States
January values of 1,200 Btu/ft2 are common with many areas having July
values over 2,500 Btu/ft2. Even in less favored areas such as Minnesota,
these same values vary from 550 Btu/ft2 to 2,000 Btu/ft2 during the year.
These data indicate that while there is an abundant supply of solar energy on
a horizontal surface in midsummer in Alaska, the mid-winter values are an
order of magnitude less than those of even poor sites in the remainder of the
country. The obvious lack of sunshine in the winter restrains the development
of solar energy in the Railbelt region. Even on south-facing vertical walls,
the daily total solar radiation in Matanuska is only 300 Btu/ft2 in
December, which indicates that the mere reorientation of collecting surfaces
will not alleviate the siting constraint.
None of the existing or developing solar photovoltaic technologies
represents an economically viable form of large-scale electric power
generation in the Railbelt. Current systems provide only a few watts of
output and are not currently planned for large-scale application.
5.55
6.0 LOAD SHAPING
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 facilities to meet the annual peak
load. Activities which reduce the magnitude of load peaks will thus reduce
the investment in generating capacity required to meet peak load.
Load shaping refers to electric utility industries• attempts to improve
load factors. Generally, an increase in load factors result in loads being
satisfied more economically. The economies are due to decreased use of
intermediate and peaking units, which are more expensive to operate relative
to base-load units.
Load shaping is effected through load management and supply management
alternatives. 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 objective of load management is to shift, shed, or shave
peak loads to derive a more economical load profile. Supply management refers
to attempts to use generating units, especially intermediate and peak loaded
units, and available energy storage units in the most economical manner,
including the storage of off-peak energy for use during peak periods (EPRI
1979, 1980).
6.1 LOAD MANAGEMENT TECHNIQUES
Load management procedures involve changes in equipment and/or
consumption patterns on the customer-side of the meter. The customer may be
either an end user of electric power (e.g., residential or industrial) or
utility distributing power from a wholesaler to end-use consumers. Any
technique considered, however, must be assessed in terms of its effect on the
existing load profile and on the utility's planning and operating systems.
This section summarizes five general load management methods that may be
applied to the Railbelt region. The five general methods are:
6.1
1) Direct Control by the Utility of Customer Loads
2) Passive Control of Customer Loads
3) Incentive Pricing of Electricity
4) Education and Public Involvement Programs
5) Thermal Energy Storage.
6.1.1 Direct Load Control
Direct load control is the control by electric utilities of specific
customer loads. These loads are cycled or deferred during periods of local or
system peak loads or emergencies. Residential loads associated with the use
of space and water heaters can be controlled by direct means, but
interruptions in this type of service can result in customer inconvenience or
discomfort. Economic incentive (i.e., lower rates) may be provided to
compensate for customer inconvenience (IEEE 1980). The effectiveness of these
incentives depends on their operating parameters and importance to customers.
Studies evaluating loads that can be controlled have been conducted
primarily in urban areas in states with load characteristics different from
those found in the Railbelt. Such nationwide studies constitute the most
complete set of data on load shaping. To present these data in their complete
context, it is necessary to show a variety of load shaping experiences
including some not applicable (e.g., air conditioning) to the Railbelt. Such
general data are presented in this section while a more specific discussion of
applications affecting the Railbelt region can be found in Section 6.1.3.
The types of electrical loads that have been selected most frequently for
direct load control are as follows (ERA 1980):
·Class of Service
Loads Residential Commercial Industrial
Water Heaters X X
Central Air Conditioners X X
Central Space Heaters X X
Swimming Pool Pumps s
Nonessential Loads X X
6.2
A recent Electric Power Research Institute (EPRI) study summarized
another study which surveyed 2,000 U.S. households and obtained electrical
consumption by major appliance from August 1976 to July 1977 (EPRI 1979).
Tables 6.1 and 6.2 contain information cited by EPRI in their 1979 study.
Table 6.1 shows market penetration for major electric appliances. Table 6.2
presents daily electric consumption by appliance per month. Unfortunately,
the study did not contain data on time-of-day characteristics. Nevertheless,
the information in Tables 6.1 and 6.2 indicates the importance of the
residential loads listed above for direct control.
Unfortunately, appliances currently used for lighting, cooling, and
refrigeration in residences are not designed to permit load management. In
time, refrigeration should have potential for load management if thermal
storage can be economically incorporated into the design. Electric clothes
drying is a substantial load that usually can be shifted to offrpeak hours.
In the commercial sector, water heating and space heating offer the most
potential while other potentially controllable loads include lighting, air
TABLE 6.1. Regional Market Penetration for Major Electric
Appliances {Western U.S.)
Freezer
Range
Appliances
Cooktop and Oven
Dishwasher
Clothes Washer
Clothes Dryer
Water Heater
Central Air Conditioning
Room Air Conditioning
Swimming Pool Pump
Electric Heater
Source: EPRI 1979, p. B-42.
6.3
Penetration
(Percent)
37.89
37.89
29.21
42.37
84.21
45.00
11.84
6.58
18.16
3.68
3.16
TABLE 6.2. Average Daily Electric Consumption by Appliance Per Month
(kW-hr/day)
Appliance
Refrigerator
Freezer
Range
Clothes Washer
Clothes Dryer
Dishwasher
Water Heater
Central Air Conditioner
Room Air Conditioner
Swimming Pool Pump
Electric Heat
Cook top
Separate Oven
August
4.80
4.13
1.84
0.24
2.70
0.36
11.66
21.96
6.54
3.03
1.57
1.45
1.00
Source: EPRI 1979, p. 43-44.
1976
Sept.
4.81
4.10
1.95
0.25
2. 72
0.37
10.42
14.53
4.63
2. 72
1.30
1.52
1.21
Oct.
4.57
3.88
2.20
0.26
2.83
0.39
10.50
4.41
1.42
3.20
1.77
1. 70
1.55
May
4.73
3.78
1.87
0.25
2.74
0.42
10.49
11.22
2.23
4.83
1.97
1.16
1.16
1977
June
4.87
3.84
1.74
0.23
2.68
0.39
9.42
25.23
5.96
4.53
1.60
1.12
1.11
July
4.97
3.81
1. 76
0.21
2.40
0.36
9.45
31.25
8.98
2.20
1.80
1.10
0.97
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. Irrigation pump
motors, as well as space heating of animal dwellings, grain drying, feed
grinding, and specific dairy cooling operations have a potential for load
management (Arthur D. Little 1979).
Control devices to implement direct load control entail switching of
specific circuits or appliances are listed in Table 6.3. Clock-based controls
have been applied as well as remote control of customer loads by the utility
through a communication system. Communication technologies for direct load
control are: communication via power lines, including ripple systems,
power-line carrier, and waveform modification; telephone and coaxial cable; an
radio systems. Special or separate meters are not necessary for direct load
control (Institute of Electrical and Electronic Engineers 1980).
6.4
TABLE 6.3. Direct Control and Communication Systems
Local Control Equipment
Clock Timer Switches
Temperature Sensing Controllers
Photocontrollers
Load Levelers
Communication System
Ripple Control Systems
Power Line Carrier Control Systems
Line Wave Alternation Systems
Radio Control Systems
Telephone Control Systems
Source: Economic Regulatory Administration 1980.
The chief distinction between control systems is whether or not the
control is local or remote. Local systems depend on the use of a timing or
physical sensing device to determine when end-use devices should be employed.
Remote systems permit a utility to control loads through direct communication.
Clock-timer switches are electrically driven controls which automatically
turn external circuits on or off at a preset time of day. These switches have
been in use for a number of years, in particular, for off-peak electric water
heater control. Temperature sensing controllers are outdoor thermostat-cycle
timers which can be employed to control heating or air conditioning loads. In
a test case run by Georgia Power Co. on central air conditioners, the results
indicated a reduction in the diversified peak demand of 1.4 kW per central air
conditioner unit controlled by the thermostat. Photocontrollers are
light-sensitive controllers which have been used to control outdoor lighting
but could also be used to control appliances where use did not depend upon
specific time-of-day operation. A single circuit load leveler removes one
circuit or load from service when a predetermined current load in priority
circuit 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
can control up to five loads in sequence. The multicircuit load levelers 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 percent
average reduction of kW demand (Economic Regulatory Administration 1980).
6.5
Ripple control systems use the utility's existing transmission and
distribution network to transmit control signals. Although bi-directional
ripple systems have been recently developed, most systems employed over the
years are uni-directional 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
(200-1500 Hz). Radio control systems utilize 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 likely
potential for telephone control systems would be for meter reading.
6.1.2 Passive Controls
Passive controls are those load-limiting devices that are owned by the
customers themselves and installed on their property. From the utilities'
standpoint, these types of control systems are less reliable than the more
active forms of demand control because they are controlled by the owner, not
the utility. A major advantage exists, however, because there is no direct
investment in the control equipment by the utility. These controls are
similar to direct controls except that the customer, not the utility, retains
the ultimate control over their operation.
These controls are often implemented through the use of economic
incentives and disincentives to encourage change in consumption patterns.
However, unlike active controls, power is always available to loads controlled
by passive controls if the customer desires. Thus, the load management
benefits to the utility with passive controls are not as dependable as under
direct controls.
6.1.3 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
differentiated rates, interruptible rates and inverted rates.
6.6
Time Differentiated Rates: There are two fundamental types of time-
differentiated rates. 1) rates based on time-differentiated
accounting costs (TDAC); and 2) rates based on time-differentiated
marginal costs (TDMC). Accounting costs include capital and
operating cost components consistent with cost definitions used to
meet revenue requirements (PHB 1979). These accounting costs are
average costs of producing power. As opposed to accounting costs,
marginal costs refer to incremental costs incurred to supply
additional increments of electrical output.
The allocation of costs to specific time (rating) periods enables
the design of rates that give explicit signals to customers about
the costs they impose for use at various times. TDSAC rates may be
determined by methods analogous to those used in designing embedded
cost rates. The use of TDUC (marginal), costs, results in higher
incremental costs for the use of electricity during peak periods.
This provides greater disincentives for curbing peak period
consumption. 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 (Electric
Utility Rate Design Study 1979).
If demand is very price sensitive, time-of-day pricing can cause
changes in load shapes. Moreover, time-of-use pricing should
promote efficiency in the allocation of resources to the extent that
consumers are willing to pay prices that reflect marginal costs. In
a nation-wide survey (Elrick and Lavidge, Inc. 1977) conducted for
the electric Utility Rate Design Study to measure residential
response to time-differentiated rates, the following conclusions
were reached:
1. majority of residential customers who had not experienced time-
differentiated pricing or load controls preferred voluntary
reductions and/or more power as ways to handle growth in peak load;
6.7
2. residential customers, when faced with limited power, preferred
voluntary reductions to time-differentiated pricing or controls;
3. almost 80 percent of the residential users and more than 50 percent
of the commercial and industrial customers stated that they would
reduce energy consumption to save money or avoid higher charges when
faced with time differentiated peak use charges four times as great
as 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 straight forward rate of this type is exemplified by a
discount or credit to customers who agree to have some portion of
their loads reduced under system conditions as identified above.
Special rates might also be available to customers whose loads are
regulated by control devices or other means.
The implementation of 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.
Inverted Rates: As opposed to the usual declining block structure,
inverted rates cause price increases as consumption of electrical
energy rises. The rationale behind this aproach is the notion that
new capacity tends to be more costly than existing capacity.
Therefore, the growth in electricity consumption which tends to
increase costs over time should be dampened by the price mechanism.
At the present time, incentive pricing measures are in effect in the
Railbelt area (e.g., Anchorage Municipal Light and Power has an elective
time-of-day rate schedule for residential customers). One advantage of
incentive pr1c1ng is that requirements for capital equipment are relatively
low, and, through an educational program, customers can be informed of the
6.8
benefits of modifying their consumption patterns. Also, for larger customers,
the costs of metering represent a relatively small percent of their total
electric bill. Meters would permit large customers who monitor their energy
consumption to determine cost savings realized by altering energy consumption
patterns.
6.1.4 Education and Public Involvement
The need in all load management options to alter individuals' electricity
consumption patterns makes effective communication with customers a
prerequisite to successful implementation of any load management echnique.
This means that education and public involvement programs are needed for each
of the options described above and are potentially an effective load
management tool in themselves. The effectiveness of such programs depends on
the current relationship between the utility and its customers and the
attitude and awareness of the public. In areas where people pride themselves
on their individualistic lifestyles, it is doubtful that appeals to the
general need to modify consumption patterns will be effective. This method of
load management is also not as reliable as the other ones in that the utility
has virtually no control over the exact amount of load that will be shifted.
Under present 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 actually strive
through the promulgation of information and incentive programs to retard the
growth in use of electrical energy.
Today utilities foster conservation and load management in their
advertising whether in public newspapers or in informative materials included
with the electrical bill--for example, 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, insulating, etc. These and other public involvement techniques
merit consideration in pursuing load management objectives.
Although some state regulatory commissions may prohibit utilities from
promoting electrical consumption and now require the utility to promote load
reduction, the Alaska Public Utility Commission (APUC) has no orders to this
6.9
effect. The APUC, of course, encourages energy conservation and load
reduction activities on the part of utilities and their customers. However,
APUC does not monitor the loads of various utilities in Alaska.
6.1.5 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. In most applications, customers purchase storage equipment to obtain
the operating cost reduction through low, off-peak rates for service. If the
storage devices are appropriately sized, the customer should not experience
inconvenience or discomfort irrespective of the fact that the storage unit
might be controlled by the utility.
On-off switching of storage heating elements or compressors may employ
the same communication and control technologies as direct and voluntary load
control. A separate meter is usually used to distinguish the power
requirement of the storage system from the balance of customer load. Thermal
energy storage is a useful method used to smooth out or reduce the disparity
in supply and demand periods of various energy systems
Similarly, energy produced by solar collectors, industrial waste, or base
loaded generators during off peak periods is used to heat a fluid, which is
pumped to storage for use at a later time. Presently, water is the fluid
which is commonly considered because of its abundance, low cost, nontoxic
nature and relative ease of handling.
Storage systems include deep sea insulated bags with steel reinforcing
nets, flexible bags under non-cohesive overburden, fixed volume tanks with
separating disks, or underground porous rock formations (aquifers). The
Alaska coastline at the Railbelt area has been identified as suitable for
undersea storage, the criteria being at 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 ft3) storing water at a pressure of 420 psi, a
temperature of 450°F and at 900ft will cost about $1/ft3 for storage
only. The stored hot water can be used for feed water 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.
6.10
Energy storage equipment available for space heating and cooling, and
water heating is the residential and commercial sectors are listed in
Table 6.4.
A room electric storage heater consists 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 and foyers and for heating small rooms such as
bathrooms. Dynamic storage heaters are similar in construction to static room
storage heaters, but the dynamic heaters utilize fan forced convection to
achieve better control of room temperature. Dynamic room storage heaters can
be used for heating single-or multi-family dwellings and office buildings
(ERA 1980).
Central ceramic storage heating units adjust thermal charging of ceramic
brick core with off-peak power and have thermostatically controlled fan-forced
convective discharge. An average size heater, e.g., 20 kW size, weighs over
3000 pounds. Central storage heating systems of the ceramic brick type have
potential in the residential housing sector. In the industrial sector. a
stored heat installation in a large warehouse has been undertaken.
Hydronic central storage systems 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 used to heat air or
TABLE 6.4. Thermal Energy Storage Equipment
1. Storage Heaters
-Static Room Storage Heaters
-Dynamic Room Storage Heaters
-Central Ceramic Storage Heaters
-Hydronic Central Storage Heaters
In-Ground Heat Storage
2. Storage Air Conditioners
3. Storage Domestic Hot Water Heaters
4. Multiple Reservoir Storage
5. ACES -Annual Cycle Energy System
6. SESS -Supplemental Electric Storage System
7. CEIS-Constant Energy Input System
Source: ERA 1980.
6.11
water that is circulated through the space to be heated. Hydronic storage
units for moderate size residential homes are available. The units consist of
a sealed and insulated water tank of 212 gallons heated to 2650 -2800F
and 50 psig and with a weight of about a half ton. Hydronic storage can be
used for commercial heating (and cooling) as well. In-ground heat storage
beneath a building can be convenient. This thermal reservoir can be charged
with resistance heat which is radiated to the building at different times
depending upon building temperature (Economic Regulatory Administration 1980).
Storage air conditioning utilizes chilled water or a mixture of water and
ice which is produced by the operation of the air conditioner compressor
during off-peak periods to supply cooling load during peak periods. Central
storage air conditioning using chilled water is currently used in the
commercial sector but little data is available in the residential area. The
combination ice and chilled water storage system appears to be better suited
for residential use. Storage domestic water heaters can be managed by cycling
loads or off-peak operation. A clock-timer switch or remote controlled switch
is used to break the hot water tank circuit. The control of water heating is
the simplest and most often used approach of residential shifting (ERA 1980).
Bulk storage devices include multiple reservoir storage, annual cycle
energy systems {ACES), supplemental electric storage systems (SESS), and
constant energy input systems (CEIS). The multiple reservoir consists of a
number of storage media which 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 permits 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 (Economic Regulatory Administration 1980).
6.2 LOAD MANAGEMENT APPLICATIONS
Load management techniques are in current use in many industrialized
countries. The earliest use of load management was found in Europe. In the
6.12
United States, there are many load management programs that have been
completed or are in various stages of development by electric utilities.
These projects are too numerous to summarize here and the reader is referred
to recent summaries published by Energy Utilization System (EUS), Inc. (1979)
and Electric Power Research Institute (1980). These load management
strategies range from time-of-day pricing to direct control over customer
appliances and have been undertaken by large investor-owned utilities and
small public utilities. Many of these programs have proved to be
cost-effective, although in general, they are in experimental or demonstration
phases and findings are not conclusive.
It is also important to recognize that the feasibility of load management
techniques depends on a specific electric utility's planning and operating
system, load profile, type of loads, and other socioeconomic factors.
Therefore, although favorable results have been obtained by some winter
peaking utilities outside Alaska, implementation of such programs should be
attempted only after detailed utility-specific studies.
At present, the opportunity for load management in the Railbelt region
appears to be limited mainly because only a few loads are controllable. For
example, in the AMP&L residential class, less than 10% of the customers have
all-electric homes and even less 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. New
opportunities for load management in the commercial sector appear to be
limited because of the present use of energy-saving devices in most of the
office buildings. Potential areas for load management could be found in the
Anchorage municipal dock area and local military bases.
Anchorage Municipal Light and Power has a time-of-day rate in effect.
The AMP&L rate structure reflects energy conservation and load management
objectives. The ''all-electric" rate schedule has been eliminated, and a rate
schedule with a 12-month ratchet(a) clause has been adopted.
(a) A demand ratchet clause causes maximum past or present demands to be taken
into account in establishing billings for present and subsequent periods.
This type of clause has the effect of increasing a customer's billing rate
for the entire year if demands during peak periods exceed certain levels.
6.13
Although there appear to be few additional opportunities for applying
load management techniques in the Railbelt region, further shaving of winter
peaks is possible and might be more beneficial than other generation options.
The daytime winter peaks are about twice as large as the night loads. With a
peak load of about 120 MW, a 10% reduction in load would represent 12 MW. The
control of water heaters might be economical although AMP&L considered unit
water heaters with some thermal storage but determined, based on preliminary
economic analysis, that they were not cost-effective. During the winter, the
heating load is uniform all day. This does not leave room for shifting
heating loads to other hours. An additional constraint that must be
considered is the need for scheduled maintenance of generating units.
Scheduled maintenance is generally accomplished in the summer during periods
of low load.
In the Fairbanks area, load management possibilities also appear to be
limited. Like Anchorage, there is little or no industrial load. The
commercial load is relatively flat from 8:00 a.m. to 5:00 p.m. Fairbanks
Municipal has built into their rate structure load and energy-conserving
features. In Fairbanks, oil is used for heating, and it is expensive;
however, electricity is even more expensive on a comparable basis. One area
where load reduction might be possible would be controlling electric auto
engine heaters. Initial analysis suggests, however, that the nature of this
load makes it difficult to control even though it contributes significantly to
load peaks.
In summary, load management is an option that the Railbelt utilities are
employing at the present time. In the future, it will continue to be a useful
technique for shaping loads in a manner compatible with future resource
development and electrical consumption patterns. These techniques, however,
can only be employed within the context of the utilities• planning and
operating systems. Should low-cost power become widely available in the
future, resulting in expansion of space and water heating electrical loads.
Then implementation of aggressive load management programs may become
desirable. The need for such a program, however, would depend upon the type
of generation and storage capacity available in the future. Use of
6.14
hydroelectric generation, for example, or construction of energy storage
systems, would reduce the need for load management techniques.
6.3 COST-EFFECTIVENESS OF LOAD MANAGEMENT ALTERNATIVES
Load management programs are considered to be cost-effective if the
capacity and energy cost savings (benefits) exceed the incremental cost of
alternative generation and transmission sources. In addition, customer
acceptance and technical feasibility need to be considered in making an
assessment of a load management technique (Baron 1979).
6.3.1 Capital Costs
Two types of capital costs need to be considered when evaluating a load
management option. First, the costs that are expended in acquiring any
hardware for implementing load management should be determined. Table 6.5
presents cost information for various direct control load management
techniques. A summary of payback period calculations for thermal energy
storage systems is contained in Table 6.6.
The second type of capital costs to consider in evaluating load
management options are those costs that are deferred or eliminated as a result
of load management programs. The capital costs for new electric generating
facilities are high and any savings realized by delaying such construction
should be compared to the cost of implementing a load management program.
6.3.2 Changes in Revenue
Load management techiques in conjunction with conservation programs might
affect a utility's revenue significantly. The potential effect of this on a
utility's revenue requirements should be assessed. Of particular consequence
is the potential effect of incentive pricing on a utility's revenue, at least
in the short term. For utilities subject to regulation, approval by the
Alaska Public Utilities Commission would be necessary.
6.3.3 Timing
An advantage of load management programs is that they can be implemented
rather quickly. Therefore the cost of pursuing this option is not incurred
6.15
TABLE 6.5. Load Control Cost Summary
Average Per Point Installed Control Total Per Point Installed Cost as a
Installed Hardware and Transmission Function of Total Customers
Slstem Cost ($} Cost ($1 1 000} I.ooo 5,000 Io.ooo 2o.ooo 4o.ooo ao.ooo Ioo.ooo
Radio 85 500 585 185 135 110 97 91 90
Ripple 110 850 960 280 195 152 131 120 118
Unidirectional PLC 95 950 1,045 285 190 142 118 107 104
50% Bidirectional PLC 140 950 1,090 330 235 187 163 152 149
Q) Hybrid 90 515 605 193 141 115 103 96 95
....... Priority Relay 55 55 55 55 55 55 55 55 Q)
Load Management Thermostat 95 95 95 95 95 95 95 95
Source: EPRI 1980.
0'\
.......
-....J
TABLE 6.6. Thermal Energy Storage Systems Summary of Payback
Period Calculations
Potential Payback Period Payback Period Payback Period
Thermal Storage kW Savings Percent (Con Ed Percent (Jersey Central Percent (Con Ed Percent
S.~::stem Base S.~::stem Winter/Summer IC ($)(a) R) Years(b) Percent R) Years(b) IC ($)(a) R) Years(b)
Room Ceramic Electric Baseboard B 2,210 3.1 B.B 3,664 5.2
Central Ceramic Electric Furnace 12 1,285 1.8 4,g 2,520 3.4
Pressuri :zed Water Electric Furnace 12 2,593 3.5 10.0 3,920 5.4
In-Ground Electric Baseboard 8 131 0.2
Annual Cycle Heat Pump with 8 3 8,292 11.97 33.64 12,500 18.13
Energy System Electric Water Heater
Daily Cycle Heat Pump 12 3 5,130 8.8 24.8 7,694 13.2
Energy Systems
Dual Heating System Electric Furnace 10 675 0.95 2.7 1,000 1.4
(a) Includes maintenance.
(b) Percent R is presently offered time-of-day rate.
Source: EPRI 1980.
Payback Period
(Jersey Central
Percent R) Years(b)
14.6
g,?
15.1
0.5
50.95
37.2
4.0
over a long period of time prior to realizing any benefits. This is unlike
the situation typically experienced when constructing a major power plant.
In spite of the fact that load management programs can be implemented
more rapidly than many generation technologies, it should not be assumed that
it can be accomplished in a very short period of time. For example, EPRI
concluded that it takes two to three years to conduct a small load management
test (EPRI 1980).
6.3.4 Operation and Maintenance Costs
Once installed, the operation and maintenance costs associated with the
active or passive load management techniques should be minimal. Such
activities include ongoing assessment of the effectiveness of the program and
the routine maintenance associated with the equipment. In addition, as new
buildings and new facilities are constructed, they will be incorporated into
the load management program. For this reason, the load management system will
expand with the load.
6.4 ENVIRONMENTAL, INSTITUTIONAL, AND REGULATORY CONSIDERATIONS
Successful implementation of a load management program may present
certain institutional and regulatory benefits. Several broad areas of
environmental, institutional, and regulatory concerns should be evaluated in
assessing the merit of a load management option. In particular, a successful
load management program will defer and possibly eliminate the need for certain
energy facilities. Any delay or elimination of the need for such facilities
will have environmental benefits. The extent of benefits to the environment
are assessed by comparing the load management plan to the specific generation
option that is foregone. In general, air and water emissions will be
alleviated and all impacts associated with resource extraction will be avoided.
6.4.1 Changing Consumption Impacts
The idea of controlling an individual's use of energy, although prudent
from an energy standpoint, can arouse concerns regarding individual choice and
freedom. In the case of direct control load management techniques, the
individual homeowner or commercial customer relinquishes considerable control
6.18
of personal energy use. Such control measures do not rely on the supply and
demand mechanism, but rather on overall economic considerations and the belief
that a fair program will be developed for all customers.
Pricing and other less active control measures will not give the utility
as much control over individual customer loads as the direct measures, but
they will alter individual consumption patterns nevertheless. In most areas
where load management has been tried, programs have been well accepted. With
an effective public communications program by the local utilities, it is
expected that similar results could be expected in the Railbelt region.
6.4.2 Rate Design Activities: State and Federal Regulation
Reent activities on the part of regulatory bodies have led to several
attempts at curbing load peaks. Because of the multiplicity of rate designs
and objectives, a review of the actions of individual states is not included
in this profile. It is significant, however, that some states have made major
advances in this regard. Of particular importance to the electric utility
industry is the Public Utility Regulatory Policies Act (PURPA) of 1978.
The Public Utility Regulatory policies Act of 1978, part of the National
Energy Act, set standards for electric utilities with respect to: 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 be designed to reflect the cost of providing such service.
In general, the energy component of a rate may not decrease as kilowatt-hour
consumption increases, except when it is demonstrated that the costs of
providing electric service 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 costs vary seasonally. Electric utilities 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
6.19
electric consumers such load management techniques as the state regulatory
authority (or the nonregulated electric utility) has determined are
practicable and cost-effective; reliable; and provide useful energy or
capacity management advantages to the electric utility.
6.20
7.0 ELECTRIC ENERGY CONSERVATON IN BUILDINGS
The majority of buildings constructed in the Railbelt reflect 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
11 Alaska-specific 11 approach towards design of a building's thermal envelope.
While the technology is available, most people still do not understand
the economic benefits of energy conservation. A certain resistance to the
concept of conservation remains. To many, the term implies a return to a
lower standard of living. This is unfortunate, and stems from a
misunderstanding of the term.
Conservation technologies as defined in this profile do not consist of
turning back the thermostat and wearing an extra sweater in the evenings. Nor
do they describe the myriad of gadgets and devices purported to save energy.
Some of these devices are worthwhile; many are not. Collectively, the good
ones will benefit the individual homeowner or building user. It is difficult,
however, to quantify their impact on energy use in Alaska's Railbelt.
It is much easier to imagine the benefits of significantly reducing a
structure's overall heating load; this is the type of conservation addressed
in this study. A handful of individuals in the Railbelt have reduced their
fuel bills by as much as 70% simply 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.
The measures addressed in this report, if implemented on a large scale,
would contribute to reducing fuel demands in the Railbelt region. While
relatively little electric space heating is currently found in The Railbelt,
building conservation could significantly reduce the demand for electricity if
low cost electricity became widely available and electrical space heating
became common.
7.1 METHODS OF CONSERVATION
Conservation, or thermal efficiency, is not difficult to achieve in most
buildings. It is in fact the end product of applied current knowledge and of
7.1
techniques already commonly used. The following four factors determine the
efficiency of any building, and through proper implementation offer the
greatest potential for energy savings in both new construction and retrofit of
existing
1)
2)
3)
4)
structures:
An insulation envelope to reduce conduction
Sealing to minimize infiltration of air
Vapor barrier to retard moisture transfer
Efficient space heating and hot water systems.
These factors are discussed with regard to new construction and the
I
concept of an 11 Alaska-specific 11 design. The "Alaska-specific" design is a
house that has been developed with particular consideration to the severity of
the regional climate. It incorporates building techniques that allow for
additional insulation to resist heat transfer and enhance thermal efficiency.
The design could and should become even more specific with regard to
location. For instance, a structure in Fairbanks would be more heavily
insulated than one in Anchorage, to accommodate the more severe Interior
climate.
7.1.1 Conduction
Conduction is the transfer of heat through a solid material. In
build1ngs this occurs through the 11 envelope," which is made up of the walls,
windows, floors and ceiling separating the interior conditioned space from the
elements. The resistance of heat transfer through these components is
measured in "R values," a unit of thermal resistance--the greater the R-value,
the greater the resistance. The two major ways of reducing conductive heat
losses are to reduce the total area of the envelope exposed to the exterior,
and to provide thermal resistance in the materials comprising the envelope.
Two fundamental parameters apply to minimizing surface area.
(1) Structures should be built multi-story rather than spread out with a large
roof area (California "ranch" style), and (2) the simpler the shape, the more
energy-efficient. For example a round or square building has the least area
exposed to the elements; on the other hand, the increased exterior surface of
a building elongated along the east/west axis is offset by solar gain it is
able to use as a result of its orientation.
7.2
Window area is critical since this component of the envelope loses more
heat than other areas. Windows can lose up to ten times the amount of heat of
the adjacent walls. An energy-efficient design incorporates the least amount
of window area without jeopardizing aesthetics or livability of the interior
space--granted, a subjective judgement. The orientation of windows is also
important. Southerly or easterly orientation can gain heat during most of the
year, and thus contibute to the heating of the interior space. Conversely,
northerly or westerly windows lose a larger amount of heat and should be kept
to a minimum. Additionally, window heat loss can be reduced by using
hermetically sealed thermal units in a wooden frame, and by incorporating
multiple glazing; the more panes, the greater the savings. Conductive losses
through multiple glazing will remain high, but can be further reduced by using
thermal shutters or movable insulation that can be placed over the windows at
night or during cloudy periods.
There is considerable disagreement, and not much practical information,
on the best window insulation system for Alaska. Several manufacturers are
making shutters, most at fairly high cost. None have yet been proven
effective in Alaska, though there is a significant amount of product testing
going on. Some quantifiable answers should be available in the next year.
Walls, floors, and ceilings can become more resistant to heat loss by
adding more insulation than has been recommended in the past. However, the
structural design must provide for a sufficiently thick shell to accommodate
additional insulating material. Walls in particular pose a problem for the
designer of Alaska-specific housing because of traditional framing systems.
In these systems, the wall is made up of wooden studs and plates, which
contribute significantly to conductive heat loss. Because wood is a poor
insulator, it provides a direct heat transfer between the interior and
exterior.
Several methods (Figure 7.1) 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. This increases the R-value of the stud wall, while
radically slowing down the conduction loss through framing members. Because
7.3
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.
A second approach, known as the "cross-hatch" method (Figure 7.1), is to
nail 2x2 or 2x4 furring strips perpendicular to the wall studs, usually on the
inside of the wall. The horizontal members are placed usually at 2 feet on
center, and the interior finish nailed to them. This results in reducing the
area of transfer by conduction to a 1 1/2-in. square at each junction of the
framing members.
Two 11 cross-hatch 11 designs are in use. In one design the exterior wall is
insulated and a vapor barrier applied. The "cross-hatch" is then added.
Electrical cables and 11 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 R-value and leaving the structural integrity
of the exterior wall intact.
The third wall system employed is the double wall, where two 2x4 walls
are set a specified distance apart, and joined only at the top plate. The
space between is filled with insulation. The main advantage to this approach
is that the walls may be set any distance apart and filled with relatively
inexpensive fiberglass or cellulose insulation. Conduction losses may be
reduced to a minimum.
How cost-effective these wall systems are varies throughout the region,
and further study is needed. It is important, however, to note 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.
While urethane insulation can be used to give high R-values in thinner 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 R-values in excess
of R-60, which is adequate in most of the Railbelt. The problem lies at the
7.4
'-1 EXTERIOR SIDING .
<.n
2x12 TOP PLATE TO
TIE WALLS TOGETHER
.1'1
"
bk-
r------1:.:::
~t>~<
1'---,k
1'5:1
DOUBLE 2x4 WALLS
12"-16" INSULATION
VAPOR BARRIER
GYPSUM BOARD
EXTERIOR SIDING
RIGID INSULATION
2x6 STUDS 2x6 STUDS
6" INSULATION 6" INSULATION
VAPOR BARRIER VAPOR BARRIER
GYPSUM BOARD 2x2 FURRING
GYPSUM BOARD
EXTERIOR SIDING-
1. DOUBLE WALL 2. RIGID FOAM WALL 3. "CROSS-HATCH" WALL
FIGURE 7.1. Energy Conserving Wall Systems
point where the roof meets the wall. Here, the available space for insulation
becomes too thin to accommodate sufficient insulation and still provide for
air circulation. Ample air circulation must be provided to prevent "sweating"
or condensation and subsequent deterioration of the insulation and surrounding
wood.
The solution lies in using an "arctic" or "Arkansas" truss (Figure 7.2).
The arctic truss is constructed with raised ends so that a constant line of
insulation can extend to the roof edge, while still allowing room for
ventilation. Even if extra insulation is not applied at the time of
construction, this strategy allows for future upgrading over the entire roof
area.
In the past, designers and builders mistakenly believed that floor
insulation could be minimized, and the extra applied to the ceiling. Recent
studies are showing that adequate floor insulation minimizes stratificaton of
air temperatures between floor and ceiling. The hypothesis is that the colder
floor in standard construction drives warmer air to the ceiling, adding to
heat loss.
Conductive heat loss can also be reduced by using insulated headers over
wall openings rather than solid wood, and wood !-beams in the floor and closed
roof systems. These methods present a much smaller area to the exterior than
their counterparts constructed of solid timber.
7.1.2 Infiltration
"Infiltration is air leakage through cracks and interstices, around
windows and doors, and through floors and walls, into a building; its
magnitude depends on type of construction, workmanship, and condition of the
building, and cannot be effectively controlled by the occupants"
(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, window and door frames, door operation,
furnace combustion air and ventilation devices.
The primary measure to reduce this heat loss is caulking critical areas
such as the sole plate and around window and door casings. Texas Power and
7.6
NOTE LESS INSULATION
AT ROOF EDGE
NOTE RAISED END
AND CONSTANT
LINE OF
INSULATION
STANDARD TRUSS ARCTIC OR ARKANSAS TRUSS
FIGURE 7.2. Energy Conserving Roof
Light Co. have found that the sole plate of the walls, which is seldom caulked
in conventional construction, accounts for 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 should be sealed as tightly as
possible. Caulking should be used freely, to close all holes in the
envelope. 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 the addition of an
arctic entry, which is basically an enclosed porch. The outer door provides
for 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 combustion air for any furnace can contribute heavily to
infiltration. 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
7.7
to thoroughly seal around the penetration in the envelope. A damper that
prevents infiltration when the furnace is not operating should also 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
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, this 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, the figure can be as high as one ACH.
The problem is 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. An air exchanger
unit is inexpensive and manufacturers claim an efficiency rate of 65 to 70%.
These units have some operating problems in colder climates. Condensation
tends to form on the coils, resulting in ice formation and subsequent failure
of the unit. This problem is not insurmountable, and more testing is being
done to further develop these units. It is likely that they will become an
integral part of the Alaska-specific house.
All of these measures are fairly inexpensive when compared to the
resulting reduction in the number of air changes per hour (the standard
measure for infiltration) and the subsequent fuel savings.
7.1.3 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
climate where 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.
7.8
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 with care towards the warm side of the
insulation. While a vapor barrier is installed in most new Alaskan buildings,
they are often poorly installed, resulting in leaks and penetrations that
allow moisture transfer.
7.1.4 Space Heating and Hot Water System Efficiency
Hot water heaters account for about 15% of the fuel consumption in many
homes. It is pointless to fix a number to the exact load that hot water
systems add to overall demand since there are so many variables, such as
lifestyle, perferred 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 insulation--resulting in an
insulation factor of approximately R-6. By covering the unit with an
insulation jacket, the R-value can easily be raised to R-20 or 25. 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
setbacks, stack robbers and water pre-heaters are all worthy of
implementation. Collectively, they may result in considerable savings.
Primary heating units can consume excessive amounts of energy due to
improperly maintained burners, dirty stacks, and even dirty intake filters.
All of these are easily fixed by a service person at a reasonable cost.
A more difficult problem might arise if a furnace is larger than
necessary. This can result from an improper judgement in initial design or
following an extensive retrofit of a building wherein the heat load is reduced
dramatically. This furnace will be operating at less than design efficiency,
and consequently using more fuel than necessary. At current fuel prices, it
is difficult to justify replacement of expensive furnace equipment. However,
7.9
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.
7.1.5 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--it is more difficult,
and often more costly, to rebuild, particularly when adding additional
insulation to existing walls.
Much depends on the design and condition of the existing structure. It
may not be cost-effective to do a total upgrade on a fairly new building;
caulking and other simple measures may be best here. On the other hand, an
older structure with little or no insulation could easily incorporate a total
upgrade, and pay back the investment in a few years.
If the structure has an attic space, additional insulation can be added.
It may be desirable to use a rigid insulation at the junction of the roof and
wall, 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 finish
surfaces on both sides. If additional insulation is desired, it is usually
necessary to add a second wall either outside or on the interior. This is
often done using rigid insulation and applying a new skin. It is
labor-intensive and thus costly; usually it is considered after other retrofit
measures, if at all. In an older building with high fuel bills, it may well
prove cost-effective.
It is relatively easy to upgrade windows in older buildings 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.
7.10
Adding a proper vapor barrier when retrofitting is difficult unless all
interior finish surfaces are removed. Barring this, several paints are
available that will act as a vapor barrier. While not as effective as a
continuous polyethylene vapor barrier, the paints will nonetheless help keep
the insulation dry, a most important consideration in a thermally efficient
house.
Infiltration can be reduced in the retrofit by caulking the entire
perimeter 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%.
An effective measure that reduces infiltration is the addition of an
11 arctic entry" to frequently used exterior doorways. Such an addition greatly
reduces the volume of cold air entering the house when doors are opened.
The potential effectiveness of these retrofit measures is demonstrated in
Tables 7.1 and 7.2.
7.2 TECHNICAL CHARACTERISTICS
7.2.1 Conversion Efficiencies
How energy-efficient a structure will be depends on the extent of
conservation measures employed; this should not be confused with conversion
efficiency. Conservation technologies as defined within the context of this
profile can be said to be 100% efficient in that once installed they are
working to their full potential. The amount of energy saved by building
conservation measures depends upon the lifestyle of the occupants and weather
conditions.
7.2.2 Coincidence to Load/Reliability
The relationship of conservation to load/reliability is different from
those of technologies that generate power. The ability to quickly adapt to or
affect peak loading is negligible since conservation is static. However, if
conservation were implemented on a fairly large scale, the base load would be
7.11
so reduced that generation facilities would be capable of handling peak
loading with little or no strain on their systems.
In some northwestern states, utilities provide refunds and 'no interest'
loans to incorporate conservation technology in an effort to offset demand.
It is becoming increasingly clear to utilities that the implementation of
conservation measures provides an attractive alternative to construction of
costly new facilities.
In terms of reliability, the advantages of energy conservation are
obvious. Once insulation, weatherstripping, and the like are installed, they
will generally last as long as the structure with little or no maintenance.
They are unaffected by disruptions in fuel supply or other outside factors.
Conservation will continue to reduce the heating load of a structure at a
constant level, relative to the differential between indoor and outdoor
temperature, throughout the useful life of the insulation and scaling
techniques employed.
7.2.3 Ada~~~1lity to Growth
~
Conservation technologies are easily adapted to growth patterns because
of its simplicity and dispersed nature. However, like all construction, it is
site-intensive and is thus as sensitive to sudden 'boom' growth situations as
new construction. The inherent danger is that conservation measures can be
slighted 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.
7.2.4 Type of Demand Serviced
Electricity for space heating does not currently comprise a large
percentage of the Railbelt's heating demand. Electric heat generally tends to
serve as a supplemental heat source during extremely cold periods through the
use of portable radiant heaters. Thus, conservation measures as defined
herein will have little overall effect on the immediate electrical demand.
However, should changing relative fuel prices result in a future shift to use
7.12
of electricity for space heating in the future, building conservation may have
a significant impact on future electrical demand.
7.2.5 Complementary Technologies
Once conservation technologies are applied, they are an inherent part of
the building's character and as such are applicable and complementary to all
other space heating technologies. Conservation complements 'hard
technologies• such as fossil fuel heaters in that it lessens their work load.
In general the •soft technologies,• such as active and passive solar,
cannot be effectively applied in Alaska unless conservation measures are first
applied to reduce the total heating load in both new and retrofit structures.
Once this is done, solar can supplement the heating load of many structures.
Much depends on correct building orientation and availability of good solar
access.
7.3 COSTS
The cost of conservation is difficult to define on a large scale at this
point, due to its dispersed nature. Retrofit costs for each existing
structure will vary substantially depending on its original construction and
the condition at the time of retrofit.
Virtually no cost studies on conservation have been performed in the
Railbelt area. Preliminary cost estimates recently performed in Northwest
alaska showed unit costs ranged between $1.30/MMG for simple caulking and
weatherstripping to $16.50/MMBTU for a full wall/roof insulation upgrade on an
existing building.
The example of the Alaska-specific design cited earlier in the profile
{Tables 7.1 and 7.2 demonstrates the cost per million Btu {MMBTU) of a typical
installation. It is estimated that this "superinsulated" house will cost an
additional $7,000 over a standard structure. Extra costs include heavier
insulation, extra structural members, additional labor for "detailing" the
house to plug air leaks, shutters over the windows, and an
exchanger. Very preliminary studies done by AKREA show an additional
investment of 5 to 7% for these measures. Adding the high ened cost of 7% to
7.13
TABLE 7 .1. Effects of Conservation on Heat Loss for Retrofit of
House and for Alaska-Specific Design
Potentia 1 Payback Period Payback Period Payback Period Payback Period Thermal Storage kW Savings Percent (Con Ed Percent (Jersey Centra 1 Percent (Con Ed Percent (Jersey Centra 1
Slstem Base Slstem Winter /Surrmer ~ R} Years(b) Percent R} Years(b) ~ R) Years(b) Percent R) Years(b)
Room Ceramic Electric Baseboard 2,210 3.1 8.8 3,664 5.2 14.6
Central Ceram1c Electric Furnace 12 1,285 1.8 4.9 2,520 3.4 9.7
Pressurized Water Electric Furnace 12 2,593 3.5 10.0 3,920 5.4 15.1
In-Ground Electric Baseboard 131 0.2 0.5
Annua 1 Cyc 1 e Heat Pump with 8,292
Energy System Electric Water Heater
11.97 33.64 12,500 18.13 50.95
Daily Cycle Heat Pump 12 5,130
Energy Systems
8.8 24.8 7,694 13.2 37.2
Oua 1 Heat i n9 System Electric Furnace 10 675 0.95 2.7 1,000 1.4 4.0
(a) Includes maintenance.
(b) Percent R is presently offered time-of-day rate.
Source: EPRI 1980.
a $100,000 conventional house. It must be reaffirmed that these figures are
very rough and may be high. Assuming that the investment results in the
estimate of $70000 is financed for 30 years at 15% interest, cost per million
Btus would be $7.80. State of Alaska home loan programs at 10% would bring
this figure down, as would the conservation loan program at 5% interest. As a
comparison, fuel oil in the region averages a cost of $11.60 per million Btu
at present.
Conservation in both new and retrofit generally require no additional
maintenance once installed.
7.4 ENVIRONMENTAL IMPACTS
Building conservation technologies have few detrimental environmental
impacts. The materials employed are by and large non-toxic. Air, water and
land are unaffected by conservation. The technology need not have any impact
on community aesthetics; indeed, the "styles .. of buildings do not have to
change at all. It is the building envelope that is affected, not necessarily
the exterior of the structure.
7.14
-.....! .
I-'
U1
TABLE 7.2. Comparative Annual Heating Loads and Costs: Retrofit of
Representative House and Alaska-Specific Design
Annual Annual Savings Annual Costs Heating Annual Original
Oil(a,b) Electricity(c) Oil ( a,b) Electricity( c) Load Savings Load
Location/Case (MMBtu) (MMBtu) Saved (%) ($) ($) ($) ($)
Homer: 10364 Degree days Cost/MMBtu $8.6g(b)
Case 1 -Before retrofit 179.4 2081 3014
Case 2 -After retrofit 104.3 75 4.18 870 1260 1211 1754
Case 3 -Alaska-Specific Design 54.1 125.3 69.8 1453 2105 628 909
Anchorage: 10911 Degree days Cost/MMBtu $8.40(b) $1.60(C)
Case 1 -Before retrofit 189 646 1852
Case 2 -After retrofit 110 79 41.8 270 774 376 1078
Case 3 -Alaska-Specific design 57 132 69.8 451 1294 195 558
Fairbanks: 14345 Degree days Cost/MMBtu $8.2o(b)
Case 1 -Before retrofit 248.1 2879 8340
Case 2 -After retrofit 144.4 103.8 41.8 1204 3488 1675 4852
Case 3 -Aaska-Specific design 74.9 173.3 69.8 2010 5823 869 2517
(a) 138,000 Btu/gal, 70% furnace efficiency with the following January 1951 oil prices =Homer -$11.60/MMBtu;
Fairbanks -$11.60/MMBtu.
(b) Anbchorage case is for gas @ $3.42/MMBtu.
(c) Electricity at the following prices: Anchorage -$0.035/kWh; Fairbanks -$0.10/kWh; Homer -$0.06/kWh.
The possibility of injury or death to either the consumer and installer
is negligible, and would ·most likely not result in any increase beyond what is
now experienced in the light construction industry.
7.5 SOCIOECONOMIC IMPACTS
Since conservation technologies require little or no operational
maintenance other than that already necessary in the home, there is little
inconvenience to the individual after the initial installation with the
exception of movable insulation/shutters. However, this would seem to be a
relatively minor inconvenience when compared with the control an individual
gains over heat loss.
The individual further reduces his dependence on outside fuel sources,
over which there is no control in terms of cost and availability. In times of
disruption of fuel supplies to the dwelling, a wood stove will normally supply
all of the dwelling's heating needs.
As conservation measures become more widely implemented, new business
opportunities will result and existing business will be vitalized. Consulting
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 create local jobs and enhance local economies.
It is difficult to determine the impact of conservation on employment
because many homeowners will probably do their own work, but retrofitting jobs
should help to balance the loss of jobs in new construction due to high
interest rates. The duration of these jobs and ousinesses is, again,
difficult to determine without more research.
Certain skills and businesses can be adapted to accommodate a variety of
services. For example, materials used in conservation can easily complement
the inventories of local hardware and general mercantile stores or entirely
new 11 conservation specialty .. stores that would likely develop in larger
communities. Also, existing home repair contractors and handymen can easily
include conservation technologies as a part of their services.
7.16
On a regional level conservation measures will result in a reduction of
fossil fuel expenditures. Since these revenues will remain in the hands of
the consumer~ they are effectively dispersed within the private sector and
will ripple through local economies as spending power.
Community and Regional governments could also have smaller expenditures
for fuel~ with a resultant reduction in operation costs and taxes to the
community. The reduction in energy demand will reduce the need for
investments in additional power plants. Because most conservation measures
tend to be lower in cost over the long term than investments in generating
facilities~ proper long-range planning could result in significant economic
benefits throughout the region.
7.6 POTENTIAL APPLICATION IN THE RAILBELT REGION
It is difficult to address and quantify the effectiveness of conservation
technologies because it is influenced by the quality of the existing
structure~ its use~ and its occupants. Lack of a regional data base assessing
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.
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 7.1.
Each of the three cases were then considered for three population centers of
the Railbelt--Homer, Anchorage~ and Fairbanks--and summarized in Table 7.2.
The retrofit measures returned savings of 41.8% of the annual heating load in
comparison to the base case and the Alaska-specific design returned savings of
72.3%. The costs of retrofits and dollar savings are discussed in
Section 7.3.
7.7 COMMERCIAL MATURITY
Building conservation technologies are immediately available as mature,
well-developed technologies. Building conservation can be easily implemented
7.17
into existing and new construction at a regional scale without complex
manufacturing or distribution systems. The materials and techniques are
available throughout the Railbelt. Indeed, nothing more exotic than standard
insulations and caulking compounds are needed for most application. Those
items not readily available will soon be, as interest and understanding
grows. Given that the ••state of the art" is here, it is up to the designers,
builders and consumers to understand the benefits of conservation from an
economic standpoint. It is lack of knowledge as to the ratio between dollars
spent on conservation and dollars saved from reduced fuel billsrather than the
availability and level of development that has led to the relative slow growth
of conservation technologies.
The lack of public awareness is perhaps the greatest impediment to the
expanded commercialization of conservation measures. Education of consumers
is needed to debunk the notion that conservation means a return to
pre-industrial revolution lifestyles. Education is equally important for
designers, planners and installers, who must understand the care and subtle
differences with which different conservation measures must be employed to
achieve maximum effectiveness.
Additional obstacles resulting from building codes and policies of
financial institutions will need to be addressed as public demand for
conservation increases. The problem of outdated and conflicting codes has
never been addressed in Alaska, and needs more research to determine whether
indeed they might pose a problem.
Developers and financial institutions have historically attempted to
reduce the front end costs of construction in order to increase
marketability. The concept of life-cycle costing needs to be promoted to
consider the technologies that increase heating efficiency and thus reduce
operating and maintenance costs over the life of the building. While
practiced to some extent in commercial building, this concept needs to be
expanded and applied to residential 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
7.18
as much as 9% more in value than its inefficient neighbor. While this
phenomenon has not yet become the standard in Alaska, it is doubtful that such
factors can be ignored in the future in light of escalating fuel prices.
7.19
8.0 ELECTRIC ENERGY SUBSTITUTES
8.1 PASSIVE SOLAR FOR SPACE HEATING
In the purest sense, passive solar uses no mechanical means such as fans
or pumps to distribute heat from the sun into the living space. It relies on
a combination of a thermally efficient building envelope to contain heat,
south glazing to capture solar
energy for release at night or
distribute heat by convection.
8.1.1 Types of Systems
energy, some form of thermal mass to store this
during cloudy periods, and design techniques to
Essentially, the building is the system.
Three different strategies (see Figure 8.1) of passive solar heating have
been studied or implemented in the Railbelt region. Although other options
are available, none have been seriously considered to date, and are not
discussed here.
The simplest of solar strategies, direct gain, uses south facing windows
to bring sun directly into the living space. Because of the potential for
significant heat loss through these windows at night or during cloudy periods,
multiple glazing and insulated sash should be used in window construction. In
addition, thermal shutters should be placed over the windows during periods of
potential heat loss.
Indirect gain (greenhouse/sunspace) is achieved by attaching a solar
greenhouse to the living unit. This system 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 energy enters the greenhouse
through south glazing. A portion is transferred by various means of venting
into the main living area. At night, or during cloudy periods, heat loss from
the house is buffered by the greenhouse.
Several factors will affect the performance of indirect gain
installations. A poorly insulated or inefficient greenhouse design will not
allow much heat transfer into the house; most of the energy from solar gain
will be used up in the greenhouse. And like direct gain installation, a
significant amount of heat is lost back out the glass without night
8.1
'
DIRECT GAIN
' ...
"':::_ ..... ::: --
············· ·············
INDIRECT GAIN
•
:::::...._~ ::::: --
:::::.._ --:::::--
:::::_ ..-. :::::-
MASS WALL
DEFINITION: THE BUILDING SPACE IS DIRECTLY
HEATED BY THE SUN, THE SOLAR HEAT IS STORED
IN THE MASS OF THE HOUSE.
REQUIREMENTS: SOUTH FACING GLASS WALL
USUALLY DOUBLE OR TRIPLE GLAZED TO PREVENT
HEAT LOSS.
WALL FLOOR TO CEILING MASS WITH SOLAR
EXPOSURE AND SIGNIFICANT CAPACITY FOR
THERMAL STORAGE
DEFINITION: SOLAR COLLECT! ON AND STORAGE
FORM A SPACE THAT IS THERMALLY ISOLATED
FROM THE BUILDING SPACE AS IN A LEAN-TO
GREENHOUSE, A GLAZED ATRIUM, OR A SUN
PORCH. THE BUILDING DRAWS FROM THIS
SPACE AS THE COMFORT REQ U I REJIAENTS DICTATE.
REQUIREMENTS: SOUTH FACING, GLASS ENCLOSED
COLLECT I ON SPACE THERMALLY Ll NKED TO A
THERMAL STORAGE MASS: FLOOR WALLS, BENCHES,
ROCK BEDS, WATER TANKS.
THIS SOLAR COLLECTION SPACE MUST BE
ATTACHEDTOTHE HOUSE, YET DISTINCT.
OPTIONAL REFLECTANCE DEVICE TO CONCENTRATE
SOLAR RADIATION ON GLASS.
INTERFACE TO BUILDING FOR RADIATION,
CONVECTIVE OR CONDUCTIVE HEAT GAIN.
DEFINITION: A GLASS COVERED MASS COLLECTS
AND STORES SOLAR HEAT DIRECTLY FROM THE
SUN AND THEN TRANSFERS HEATTOTHE BUILDING
SPACE AT A TIME LAG, e.g., TROMBE WALL.
REQUIREMENTS: SOUTH FACING GLASS WALL
USUALLY DOUBLE OR TRI·PLE GLAZED TO PREVENT
HEAT LOSS.
A THERMAL STORAGE MA.SS DIRECTLY BEHIND
THE GLASS WALL.
OPTIONAL REFLECTIVE DEVICE TO CONCENTRATE
SOLAR RADIATION.
FIGURE 8.1. Passive Solar Systems Appropriate for Alaska
8.2
insulation. Even so, the greenhouse will have higher temperature than the
outside air, thus tempering heat loss from the south wall of the house. To be
truly effective, however, solar gain must be trapped for use at night.
In the mass wall concept, sunlight passes through the glazing and strikes
a water or concrete mass. Some of the heat passes directly into the living
space; how much depends on the particular design. The remainder is
transmitted to the storage mass, to be released to the living space when the
sun is not shining. As in the other concepts, the glazing must be well
insulated and thermal shutters should be installed for night time or cloudy
periods.
8.1.2 Design Considerations
Several important considerations must be taken into account when
designing a passive solar building.
The proper amount of south facing glass varies in relation to the square
footage of the building and the thermal efficiency of the structural
envelope. Placing glazing to the south indiscriminately will not ensure an
effective solar design; indeed, overglazing may result in a total heating load
higher than the "standard" home constructed today. During the coldest and
darkest parts of the winter, the amount of solar radiation available may not
be enough to offset heat losses through the glass.
Movable insulation is an important factor in the optimum performance of
solar in the region. Although benefits can be derived from south facing glass
without shutters, the truly effective system will use insulation to retard
heat loss through glass, the weakest point in the building's envelope.
Some form of storage mass should be applied in all systems to soak up
excess solar gain and to dampen the wide swings in the interior temperatures,
which can result from the variation of available solar radiation. In direct
gain and sunspace applications, concrete floors and walls, water drums and
containers are all used to provide mass. Even adding an additional layer of
gypsum board to walls receiving insoiation will help regulate temperatures.
Finally, the thermal efficiency of the structure will have an
overwhelming impact on the performance of solar heat. Obviously, solar is
8.3
less effective in Alaska than in the southern United States; a structure built
to the same specifications as those in more temperate climates will gain
little benefit from the sun. A building heavily insulated in recognition of
Alaska's severe climate will have a reduced heating load. Once this load is
reduced, passive solar becomes much more attractive as a heating source.
8.1.3 Technical Characteristics
Solar Conversion Efficiencies
Passive solar applications are a prime example of a site intensive
technology. Since they rely on the sun, they do not produce a constant amount
of energy as a central fuel-fired plant might. The conversion efficiencies of
passive solar technologies vary with the type of system (direct gain,
greenhouse, etc.) used. Other factors that can also affect efficiency
include, but are not limited to: orientation, obstructions and shading,
exterior temperatures, building heat loss, and angles of incidence.
Because the amount of energy produced will vary with each installation,
it is impossible to quantify actual efficiencies until some existing systems
in the Railbelt region are monitored. Some examples will help illustrate the
broad range of possibilities.
A direct gain system using vertical glass (double pane), oriented due
south with no obstructions or shading, will transmit approximately 75% of the
available solar insolation when the sun is striking the glazing at a
perpendicular angle (see Figure 8.2) for percentages of efficiency at the
different angles of incidence. The direct gain system offers the highest
efficiency of any solar approach, as the only variable affecting the solar
gain is irregularities in the glazing itself. The disadvantage is that the
benefits can be eradicated by heat loss back out the windows at night and
during cloudy periods. Movable insulation will alleviate the problem, and
indeed, is necessary for optimum performance.
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 a sizeable impact on usable heat for the main structure. A
8.4
-... ,_ ....
3!:
1-<(
.. a. <.;I
Ql--< ....
-:r a: ... ....
"' z
~ a:: ,_
"' G2 -• a:-'
~~
"'w-2 .. :
<( ~;~~~~~·~~· ~·~~~~~~~~~~~~~~~~~~~ :i MONTH 9 12 I 2 J 4 a: ... :r ,...
·1.
= "" ...
Ill ::
'1. a:: ...
>
<.;1 = "' z
2.
Monthly thermal performance of double glazed windows in
Anchorage, Alaska, with and without nighttime use of R-9
insulating shutter.
-Witn Shutter
• • ••• Witnouc Shutter
_Monthly thermal performance of triple glazed windows in.
Anchorage, Alaska, with and without nighttime use of R-9
insulating shutter.
J~~~~~~~~r-~r-~r-~~~.~~-r~-r~-r~-r~~
Soum E•mJWeu
9 10 11 14 I 2 J 4
Nann
--With Snuuor
•...... Wttnout Shuucr
'l 10 11 12 1 2 J •
3.~ Monthly thermal performance of quadruple glazed windows
in Anchorage, Alaska, with and witho~t nighttime use of
R-9 insulating shutter.
FIGURE 8.2. Solar Gain Versus Heat Loss with Various Windows
8.5
11.
minimally insulated greenhouse will use most or all of the solar gain to
maintain ambient temperature within it. A thermally efficient application
using night insulation over the windows will provide a significant amount of
heat to the living area. Table 8.1 gives some examples.
The conversion efficiencies of the mass wall (concrete/water) concept is
the most difficult to quantify. To our knowledge, no applications exist in
the Railbelt.(a) ·Thus far, only one study of Trombe walls in residential
applications in the Railbelt has been generated (AREA 1980). This study has
used computer simulation to model performance using 150 cu ft wall sizes.(a)
While these results listed in Table 8.2 show that the mass wall has merit,
they are computer models and not actual tested installations.
The space between the glazing and the Trombe wall can reach temperatures
as high as 130 to 200°F. Since heat transfers from warm to cold, exterior
temperatures will have an impact on the system's efficiency. The colder the
outside air is, the more heat will be lost back out the glazing because of the
high temperatures encountered in the space between the Trombe wall and the
glazing. The efficiency of Trombe walls in Alaska is still uncertain, and no
real projections can be made without further study.
Water as a storage medium when placed directly behind south glazing is
approximately 50% more efficient than concrete. The most common containments
include 55-gallon drums, steel culverts, and commercially manufactured large
volume plastic tubes. There is some concern that water placed close to
exterior glazing, without night insulation at the windows, might freeze and
burst its containment. There are therefore no known water wall applications
in the region. With proper design techniques to alleviate this problem, water
walls may prove to be efficient.
Two other storage mediums used for passive solar systems include rock bed
storage and phase change materials (PCM). In rock bed storage solar heated
air is moved through a container of rocks which provide heat storage. Since
air will not move readily through the rock bin by convection, some type of fan
(a) Energy Alternatives for the Railbelt, Alaska Center for Policy Studies,
1980.
8.6
co .
........
TABLE 8.1. Usable Solar Heat for the Main Structure from an
Attached Greenhouse At Anchorage, Alaska(a)
Yearly Solar % of
Yearly Heat Radiation Heat to Heat to
Greenhouse Type Load (MMBtu) (MMBtu) House (MMBtu) House
R-2 (All glass manufactured
greenhouse-2 panes)
61 42.4 -18.6 -30.5%
R-19 Insulation (130 ft2 31.7 2.7 9%
glazing-unshuttered) 34.4
w/shutters (R-10)(b) 22.1 12.3 36%
R-30 Insulation (130 ft2 28.3 6.1 18%
glazing-unshuttered) 34.4
w/shutters (R-10) 1R.7 15.7 46%
R-50 Insulation (130 ft2 25.9 8.5 25%
glazing-unshuttered) 34.4
w/shutters (R10) 16.3 18.1 53%
(a)
(b)
Asumes an a• x 20• greenhouse with 130 ft2 south glazing, opaque end walls and
roof, one insulated door in end, full solar access with due south orientation.
Assumes shutters closed 12 hours per day during the heating season (September-May).
TABLE 8.2. Comparative Heating Needs of Home Built to ASHRAE
90-75 vs. Passive Solar Design
Heating Needs
ASHRAE 90-75 Annual
Heating Load(a) (MMBtu)
Passive Design
Annual Heating
Load (MMBtu)
Percent Decrease in
Heating Load
Heat Provided by
Sunlight {MMBtu)(b)
Sunlight as a Percent
of Passive Heating
Load
Heat Provided by
Backup Fuel (MMBtu)
Passive Design
Heating Savings
(MMBtu)
Percent Reduction
in Fuel Consumption
Homer
155
89
43%
47
53%
42
113
73%
Location
Matanuska
Valley Fairbanks
162 218
89 111
45% 49%
42 40
47% 36%
47 71
115 147
71% 67%
is used in almost all cases. The disadvantage of rock storage is that it
requires a large amount of material. In most retrofits it will not be
economically feasible to incorporate storage adjacent to collection surfaces.
While more cost-effective in new construction, the sheer volume of material
and space needed will likely make other options more attractive.
Phase change materials incorporate a chemical compound, encapsulated in
containers, that is capable of storing the latent heat associated with the
8.8
change from solid to liquid. PCMs change from a solid to a liquid at a
temperatures (810F in several models) within the range of warm air
temperatures commonly encountered in passive solar installation. Fully
charged, they release this heat back to the space, slowly changing from a
liquid to a solid as they give up energy.
Phase change materials offer several advantages. They are relatively
lightweight and provide more Btu stored per volume needed than other storage
mediums. They therefore are useful in retrofit applictions, where concrete or
water systems may prove too costly and heavy for the existing structure. They
can also be incorporated into benches or planting boxes near south glazing,
minimizing aesthetic impact.
Their major disadvantage is that they are costly and enjoy no long-term
track record of success, since they have been on the market only a short
time. Even so, they may offer significant benefits in terms of utilizing
excess solar gain. The potential of these new products in passive solar for
the Railbelt should be studied further.
Type of Demand Serviced
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 heating demand of structures that
solar would have little effect on the immediate demand for electricity.
The ability of passive solar to affect the load curve will hinge directly
on the storage capacity of systems installed. A simple direct gain system
with no storage will require full backup heating at night and dur1ng periods
of no sun in order to alleviate wide swings in temperature inside the
dwelling. The addition of storage mass will help dampen these swings and
reduce dependence 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 affect on demand would be to reduce the base load. 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
8.9
peak Joad would be reduced because the carryover of heat in the storage system
would offset load during the peak loading hours.
Complementary Technologies
A thermally efficient building is necessary for optimum performance of
solar. The amount of heat available from the sun does not equal heat loads in
"typical" buildings during much of the winter months. By reducing the heating
load through conservation, solar becomes much more attractive as a heat
source.
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 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 virtually all
of the DHW needs in the summer, and act as a preheater for the main system
during much of the spring and fall months.
Finally, even with a combination of solar and conservation, a backup
space heating system is required. A typical large home in Anchorage might use
between 100 and 150 thousand Btu/hr during the colder winter months to
maintain ambient temperature.
same size will use only 35-45
what a quality wood stove can
A super-insulated passive solar home of the
thousand Btu/hr. This figure falls well within
supply.
Burning with wood is not for everyone. Other alternatives include
conventional central heating systems (downsized to compensate for reduced
energy demands of a well insulated passive solar structure) or "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.
8.1.4 Siting Considerations
Insolation
Insolation is the determining factor in the success of any solar
application. Insolation is "the total amount of solar radiation--direct,
diffuse and reflected--striking a surface exposed to the sky. This incident
8.10
solar radiation is measured in langleys per minute, or Btu per square foot per
hour or per day" (Mazria 1979).
Insolation varies throughout the Railbelt region, depending on local
factors such as latitude and percentage of cloud cover throughout the year. A
very broad average figure for the Railbelt would be 300,000 Btu/sq ft on a
horizontal surface. Compare this with insolation at Albuquerque, New Mexico,
with approximately 700,000 Btu/sq ft available on a horizontal surface.
A factor not yet adequately quantified is the amount of solar radiation
available on a vertical surface. The sun is so low in the Railbelt region
during the winter as to be a possible disadvantage because of obstructions in
the sun's path (see later section). On the other hand, the relatively
horizontal orientation of winter time solar radiation is an advantage in
maximizing efficiency of solar applications. The greatest amount of energy is
intercepted when the sun's rays strike the collector surface at a
perpendicular angle. The greater the variance from this, the more radiation
is reflected away from the giazing surface, unusable as heat in the
structure. Because of the low sun angles prevalent during the heating season
in the Railbelt, vertical glass becomes an excellent collector.
Research shows that the difference in percentages of solar gain between
vertical glass and tilted glass is minimal.(a) It is obviously cheaper to
install vertical glass, particularly stock manufactured window units, than to
custom design and install tilted glazing. This is particularly true when
retrofitting existing building stock for passive solar.
Only Anchorage and Fairbanks are currently measuring vertical
insolation. Longer term data gathering, at several additional sites, is
necessary to form a scientific base of solar radiation available. Until this
data base exists, designers are severely limited in their ability to
"fine-tune" actual applications.
(a) A general rule of thumb for optimum tilt of glass is latitude plus 150.
Thus, in Anchorage: 610 latitude plus 150 = 760--very close to
vertical.
8.11
Orientation
Most of the solar radiation usable for space heating is found in the
southern sky. The collection area should therefore be oriented as close to
due south as possible, although a variance of 200 or so from true south in
either direction will not seriously affect performance (see Table 8.3). New
construction can, of course, be easily oriented correctly, provided that the
topography of the building site will allow siting to the south.
Site planners in residential and commercial development have generally
failed to consider the advantages of proper orientation when designing
subdivisions and building sites. It is thus impossible for some existing
TABLE 8.3. Percentage of Radiation Striking a Surface at
Given Incident Angles(a)
Incident Angle(a)
(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.
In other words, at Oo, the sun is
absolutely perpendicular to the collection
surface.
8.12
structures to realize the benefit of solar heat. However, many existing
buildings could justifiably be retrofitted using various solar gain methods.
Solar Obstruction/Shading
The sun is low on the horizon during much of the winter in the Railbelt.
It rises to a high of only 60 in Anchorage and 40 in Fairbanks at noon on
December 21, the shortest day of the year. Because of this, objects of even
insignificant height can block solar radiation. The shadow cast behind a
10 ft high object in Fairbanks on December 21 will reach a length of 128 ft
(see Figure 8.3).
The problem is less significant in low density areas, particularly rural
sites. The lack of large trees and tall buildings in the region helps
minimize obstructions and shadows, but the mountainous terrain causes some
solar obstruction.
8.1.5 Costs
There has been virtually no work done in the Railbelt on capital costs
for passive solar, mainly because there have been so few actual
installations. In addition, most solar buildings in the region rely on heavy
insulation and efficient thermal envelopes to first reduce heat load and it is
often difficult to differentiate between costs for solar and those general
building costs.
Our preliminary studies show an increase of anywhere between 6 to 10%
above normal construction costs for a passive solar, superinsulated home (AREA
1980). Thus, in a $100,000 "typical" home, an added expenditure of $6 to 10
thousand could be expected. Total heating load would be reduced by 65 to 75%
through conservation and solar measures.
This particular example is an 11 extreme" case. Capital costs will be less
with structures employing lesser degrees of insulation, scaling 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.
Some broad examples will help to illustrate the possibilities. They are by no
means concise or all-encompassing.
8.13
----
NORTH SLOPE
SOUTH SLOPE ..
BUILDINGS ON A NORTH SLOPE WILL CAST LONGER SHADOWS
• SHADED All YEAR
filii FALL AND SPRING SHADING m WINTER SHADING
-s·= ,_ ___ 21' -_,
---------128' -----------..lJ
SHADOW lENGTHS BEHIND A 10 FOOT HIGH OBSTRUCTION
AT 64° NORTH LA T1 TUDE
~IGURE 8.1. Solar Shading Considerations
8.14
JUNE 21 MARCH 21 9 ~¢
/ ~~
~~--~
10'
Assumption 1: A 1500-ft2 home in Fairbanks built to ASHRAE 90-75
standards with a 218-MMBtu heating load.
Assumption 2. Conservation (superinsulation) and passive solar gain
with concrete storage mass (150 ft3) will cut the
heat load to 71 MMBtu, a savings of 147 MMBtu.
Assumption 3. Operation and maintenance costs are $25.00/yr.
With the above assumptions, cost per MMBtu are presented for several variables:
A. $6,000 capital cost--
1. 15% interest, 30-yr term, conventional
2. 10% interest, 30-yr term State Loan
3. 5% interest, 20-yr term, Alternate Energy Loan
B. $10,000 capital cost--
1. 15% interest, 30-yr term, conventional
2. 10% interest, 30-yr term State Loan
3. 5% interest, 20-yr term, Alternate Energy Loan
$6.38/MMBtu
$4.49/MMBtu
$3.58/MMBtu
$10.53/MMBtu
$ 7.38/MMBtu
$ 5.86/MMBtu
By comparison, the cost ot fuel oil in the region as of January 1981 is:
Anchorage $8.40/MMBtu
Homer
Fairbanks
$8.69/MMBtu
$8.20/MMBtu
It is worth noting here that conservation and solar technologies are virtually
inflation proof once installed. Fuel oil is not.
These examples constitute broad averages only, and represent only one
particular case, a superinsulated new house with maximum solar
considerations. Until further study is done, particularly with solar
retrofits (no assessment has been done in the Railbelt), these figures should
be received with caution. Even so, they show economic potential in many parts
of the region, particularly in view of the fact that the examples do not
reflect added tax incentives nor address future fuel inflation costs.
In the examples a figure of $25 dollars per year was set aside for
operation and maintenance costs. This reflects a "worst case;" in reality
these costs may approach zero, as passive systems are extremely simple, with
few or no moving parts. Much depends on the particular system, but it can be
8.15
generally stated that passive systems will last the life of the building with
little added cost beyond initial construction.
8.1.6 Environmental Impacts
Environmental impacts from passive solar tecnologies are minimal, almost
non-existent. No traceable air or water pollution has been recorded in
dispersed application. Solar is an ideally benign fuel source with regards to
the environment.
The potential detriments of solar on 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,
it is in the hands of the designers to 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, there are
just as many or more examples of successful installations. 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, save for the expanse of south facing glass.
Reflected glare off south glazing is a potential problem in solar
application. How much of a problem it might be 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 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. It is during the spring and fall that the phenomenon could cause
problems to passing motorists and pedestrians. The small number of solar
system installation in the Railbelt region precludes answers at this time.
Consumer safety poses no real problem with passive solar. As most
systems are simple and benign, danger to the consumer is far less than, say, a
central fuel-fired furnace system. Workers certainly face a higher percentage
8.16
of danger when installing systems, but potential injury and death is limited
to the sphere of those the worker might encounter in standard construction.
8.1.7 Socioeconomic Impacts
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 in order 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
subdivisions and site planning procedures. This type of legislation has been
adopted in a few states. The 1979-80 session of the Alaska legislature passed
SB 438, a bill relating 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 rea 1 property."
However, the wording implies a policy statment 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 which 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
there have been studies done in the southern parts of the United States, 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 "typical" 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
planning process including proper orientation and placement of structures.
From a purely economic standpoint, the second option will be chosen
8.17
unanimously. But, shadows would probably negate solar gain during December
and early January in such cases. However, because of the long heating season,
solar would still be beneficial during a large part of the winter.
Consumer Convenience and Control
Passive solar offers the following advantages. It
• requires virtually no maintenance or replacement of parts during the
building•s lifetime, as the components are a part of the structure ,
• requires little or no operator attention with the exception of
thermal shutters
• is safe
• can provide a significant portion of heating needs in case of power
failure or fuel shortages
• reduces dependence on uncontrollable factors affecting fossil fuel
pricing and availability
• reduces fuel expenditures and thus provides more income to the
individual.
Potential disadvantages include:
• necessity of operating shutter
• wi~e temperature swings within a heated space if no storage mass is
present to regulate the variance in available solar radiation.
Regional Economics
As passive solar is a decentralized technology, it will create jobs and
new capital ventures at a local as well as at a regional level. Since the
skills required to design and install systems are relatively straight forward,
using standard materials and techniques, it is likely that most ~f the human
resource needed exists in the region. If pursued on a fairly widespread
scale, the potential for long-lasting jobs in new and existing businesses is
promising. Though 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).
8.18
An increase in employment and business at the regional level would very
likely result in an increase in the amount of capital staying in the region,
further providing economic benefits outside the construction sector.
Certainly, the extra income available to the consumer by reduced fuel
expenditures will find its way into the region's economy. While an in-depth
economic analysis cannot be done until the degree of penetration of the solar
technologies in the marketplace can be better assessed, preliminary study and
common sense indicate that solar will indeed have a positive impact on the
economy.
8.1.8 Potential Application to the Railbelt Region
A combination of energy conservation and passive solar in new
construction can cut energy demands by 60-70% in an individual dwelling. The
potential of passive solar and conservation in existing buildings is difficult
to quantify without knowing the structure's existing condition and solar
access. A 30-50% reduction in the heating load is conceivable combining these
two technologies. Without an assessment of existing building stock, it is
difficult to make an aggregate projection.
Passive solar is an emerging technology in the Railbelt. At this point,
only a handful of structures have been designed specifically to take advantage
of the maximum amount of available solar radiation.
Passive solar technologies use materials and building techniques common
to the building trades--an important attraction. The fact that passive solar
in the Railbelt is best exemplified by an energy-efficient house coupled with
south glazing makes it easily accessible to the present skills of the designer
and builder.
Development of a thorough understanding of the economy 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 a number of techniques: a thermally efficient building
envelope, south glazing, a completely unbroken 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
8.19
region. There are a few components not stocked in the state that would help
to 'fine-tune• passive system; they are available on fairly short notice from
suppliers in the lower United States.
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, educated field work will be necessary
to implement successful systems. Interest among builders in the region toward
passive solar technology appears to be high; it will be necessary to educate
the trades to the details of implementing systems to ensure that they work to
their designed efficiency.
Existing financial practices present an additional obstacle to the
development of 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 passive solar is to be successful; operation and maintenance
costs (i.e., fuel) over the life of the building must be integrated into the
overall cost. It is not clear how widely accepted the concept of life cycle
costing is among lending institutions. There have been scattered reports of
bankers• resistance to extra costs for solar. On the other hand, of six
passive solar houses designed by this author in 1980, not one was refused a
loan by the several lending institutions in the Anchorage area, 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. This
quote by an appraiser taken from the First Railbelt Alternatives Study(a)
illustrates the problem:
11 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 ovvurrences and, unfortunately,
there haven't been enough fact occurrences to give a true and
accurate answer.11
(a) Energy Alternatives for the Railbelt, Alaska Center for Policy Studies,
1980.
8.20
Most Alaskan appraisers of solar homes did not understand the value of
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 there have been several administrative problems in the
first year of the loan program operation, consumer interest is high, and work
continues on ironing out the flaws. It is an important step toward solving
some of the financial obstacles listed herein.
8.2 DISPERSED ACTIVE SOLAR TECHNOLOGIES
"Active'' solar systems require auxilliary pumping energy to function
properly. These systems differ from "passive" solar energy application, which
require very little or no auxiliary energy. Active solar energy use is an
accepted technology, with thousands of installed systems throughout the United
States.
Three varieties of dispersed active solar systems are currently available
for use 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 fabricated by the sheet metal unions or plumbing shops are available,
particulary in the Fairbanks area.
8.2.1 Types of Systems
The flat-plate solar collector {Figure 8.4) is the most common
configuration used today in active solar energy systems. Active systems
employing flat-plate collectors are the most common type used to retrofit
8.21
TRANSPARENT COVER PLATE
PASSES SUNLIGHT BUT TRAPS
HEAT AS A GREENHOUSE
DOES.
INSULATION KEEPS
HEAT IN
FLOW PASSAGES WHERE FLUID IS HEATED
FIGURE 8.4. Schematic of a Typical Liquid Flat-Plate Collector
homes and businesses with solar energy because they offer greater installation
flexibility. In flat-plate liquid-based collectors, the absorbing surface has
several tubes running 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, or both.
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 as copper 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
minimize this loss of heat, the bottom and sides of a flat-plate collector are
insulated, and a glass or plastic cover is placed above the absorber with an
8.22
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 true efficiency of double glazing needs further research.
There are currently less than 20 operating systems in the Railbelt area,
and none have been monitored to determine efficiency of double glazing.
For year-round use in the Railbelt, a liquid-type flat-plate collector
must incorporate antifreeze in the heat exchange fluid to prevent freezing.
Figure 8.5 shows a typical Alaskan installation for an active space heating
system.
A version of the flat-plate collector which may be applicable for Alaska
is called SolaRoll.
"The system consists of a unique exchanger/absorber plate made of a
flexible elastic monomer which can withstand freezing and has an
anticipated 30-year lifetime. It is a black material, and
SOLAR
~-COLLE:CTOR HEAT STORAGE
===~=~
\PUMP OR FAN
AUXILARY
HEATER
0
~==t==
VALVE
HEATED
SPACE
FIGURE 8.5. Typical Active Space Heating System
8.23
performance tests indicate that SolaRoll encased in a standard site
built or locally manufactured insulated collector frame performs
better than average metal solar collectors. It is tailored for
do-it-yourself installation. No nails, screws, plumbing elbows or
tees, or battens are needed for assembly. There is also no need for
soldering, welding, sealant, or paint. SolaRoll is an example of
the types of technological advances which continue to make solar
collectors cheaper and better."(a)
Active systems require an energy storage system to be truly effective.
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 8.5).
Active solar systems for Domestic Hot Water (DHW) systems use the same
type of collectors used for space heating systems. Figure 8.6 shows a typical
DHW 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 there is a much closer match between resource availability and end-use 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 provide for a great portion of midwinter needs,
during fall and spring months it will supply a large portion of the load.
During summer, 100% of hot water can be had from the sun.
Systems Using Air As The Working Fluid
Active air collectors (see Figure 8.7) are usually thicker than
liquid-based collectors because they handle higher volumes--that is, a given
volume of air absorbs fewer Btu than a similar volume of liquid. In order to
keep the collector temperature low, thus improving efficiency, more air must
(a) Richard Seifert, Energy Alternatives for the Railbelt, Alaska Center for
Policy Studies, 1980.
8.24
~\
' '
AUXILARY HEATER r=b~ TOLOAO
' \
\
I
c=Jd. ~
STORAGE
TANK ~c=Jc::Jy I
'""' ~= PUMP! ---···I
FIGURE a.s. !!,L
BLACK A PLATE BSORBER
AIR IN
An Active D "' = = wATER FRo•
Alaska Sola~~!;ic Hot Water S s ~:J"TtT•O" lgn Manual, 19~0tem (From Seifert ' Draft '
GLAZING
INSULATION
FINS TO SURFACE INCREASE
Schemat . . AREA lC Vlew of a Typical A
8.25
COLLECTOR HOUSING
i r Co 11 ector
pass through the system. One approach to this technology (untested in Alaska)
is to pump the hot air directly into the living space. Preliminary
calculations show this to be effective when combined with a thermostatically
controlled fan. A more common approach used in the lower United States
involves ducting the heated air from the collector into a rock bed to provide
storage for use at a later time. 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.
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 Ra1lbelt, space heat is needed at least 9-10 months of the year; in
fact, 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 500-600 solar homes. This 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.
8.2.2 Technical Characteristics
Active Solar Conversion Efficiencies
In the Railbelt, active solar collectors make effective use of 30-40% of
the sun's energy that strikes their surface. This is their raw performance
under optimal conditions; it assumes no obstructions in the sun's path, and
collector tilted perpendicular to the sun on an average annual basis (usually
at the latitude angle for domestic hot water, and latitude plus 10-150 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 excessive heat loss back out the glazing. A differential of 100-1800F is
generally acceptable. The "optimum" situation described above assumes that
the temperature of the collecton fluid is about 14QOF.
A collector's efficiency can only approach 30-40% if the heated medium is
used directly, 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
8.26
flat-plate domestic hot water system with an ethylene glycol collecting fluid,
will reduce efficiency by another 8-12%. In space heating installations where
heat is transferred from the collection fluid into a storage medium and then
again to a distribution fluid, an additional 8-12% loss can occur.
Until some monitoring of installed systems in the Railbelt is undertaken,
actual performances cannot be fully quantified.
Coincidence to Load
The ability of an active solar installation to supply heating loads
(whether it be space or hot water) depends to a great degree 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 there is little
existing data, it is believed that active solar will 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, but we do not yet know
how much. 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 active solar system is limited.
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
consume less energy than a standard building. Building conservation is
therefore not only a complementary but also a necessary technology that should
go hand in hand with 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.
Active solar ranks alongside the rest of the dispersed technologies in
terms of adaptability to future growth. The simple fact that it is dispersed
means that solar can be put into place quickly, with little lead time, by
installers with a minimum of training. Whether active solar will be
cost-effective on a large scale is impossible to determine at this point; the
fact that the technology is available and could be implemented is well-known.
8.27
/
8.2.3 Siting Considerations
The same meteorological considerations apply to active solar systems as
were discussed for passive solar systems. See Section 8.1.3. 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
perpendicular to the sun's rays will capture the maximum amount of radiation.
Orientation
As discussed in Section 8.1.3 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 southern United
States indicates that active solar hot water systems will still perform very
well when oriented as much as goo off of south.(a) No testing has yet
been done to verify this phenomenon in the Railbelt, but the potential
ramifications may be significant from the perspective of retrofit of active
solar systems to existing housing. Most housing in the region has been
oriented haphazardly in relation to solar access. Collectors can be mounted
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, it is simpler, less costly, and
generally more aesthetically pleasing to mount the collector "in line" with
the roof of an existing structure.
The number of existing structures adaptable to active solar space and/or
hot water heating in the Railbelt is not yet known. Actual 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 8.1.3.
(a) Collector Location: No Taboos on East or West, Solar Age Magazine, page
26, December 1980.
8.28
8.2.4 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 what
is probably the best cost analysis to date on active solar in Alaska. They
used several models of houses: a standard home, a retrofitted structure, and
a 11 Superinsulated 11 house for cost comparisons. In addition, they looked at
hot water heating. Assuming a collector cost of $15/ft2 (including storage)
with financing at 9.5% interest over 20 years with nothing down, they
formulated results based on several different collector sizes, in an attempt
to define the 11 0ptimum 11 investment. As can be expected, hot water heating was
the best investment, at unit costs ranging from $12.53/MMBtu for 15% of the
load, to $24.30/MMBtu for 61.6% of the load. These figures are for the
Fairbanks area. The standard house case was the worst, ranging from $12.83 to
34.16/MMBtu, for 5.2% to 37.3% of the heating load, respectively._ The
retrofitted home's unit cost ranged from $12.60 to $32.31/MMBtu, for 6.3% to
39.1% respectively. Finally, the costs for superinsulated homes ranged from
$12.61 to $31.10/MMBtu, for 7.5% to 41.9%, respectively. These cost figures
are projections only; there have not been enough installations to know actual
initial capital costs.
Operation and maintenance costs will be a part of every active solar
system; just how much depends on the type and size of the installation, as
well as the care given to design and construction. A very broad estimate must
be made, since there is little precedent in Alaska. An average figure of
$25-50 dollars per year over the life of the system seems likely, for such
items as burned out pumps, piping or ducting repairs, and glycol solution once
a year if the system is drained down annually.
8.2.5 Environmental Impacts
The environmental effects of active solar energy utilization are almost
entirely positive. Once the system is manufactured and installed, it should
supply 10-20 years of pollution-free energy at an average rate of
8.29
400 Btu/SF-day in the Railbelt. Early concern over the aesthetic devaluation
of neighborhoods due to large numbers of roof-mounted solar collectors has
been supplanted in the southern United States by the increased real estate
appraisal values for homes with solar systems.
Injuries and deaths accredited to the solar technologies are rare; since
most installations tend to be small and relatively simple to install, the
hazard rate is no higher than that involved in standarad light construction.
8.2.6 Socioeconomic Impacts
Were active solar to be employed on a widespread basis, it is likely that
it would enjoy the same socioeconomic benefits that the other dispersed
technologies enjoy. Design and installation would be provided by Alaskan
firms, on a widely dispersed basis. As a result, cash flow would also tend to
be dispersed, with more of it staying in the region than if a large
centralized project were undertaken. There would, however, be an outflow as
both manufactured collectors and components for job-built collectors would be
shipped in from the continental United States to a large degree.
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. How positive the benefits would be depend on the
amount of market penetration, but in general, the socioeconomic impact of
active solar would likely 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
obvious. An ability to maintain ambient temperatures in the dwelling (or hot
water supply) during times of fuel disruption is an additional advantage.
Finally, the investment is inflation proof, something that cannot be said for
most traditional fuel sources.
8.30
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 (EPDM) absorber can eliminate this
requirement.
As so few systems have been installed in the region, it is difficult to
estimate how much time the consumer would spend on maintenance and operation.
A figure of 3 to 6 hours per month for a well-defined system is a reasonable
estimate.
8.2.7 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, there are many
constraints on the use of active solar energy in Alaska. The low winter sun
angle coupled with extreme, low temperatures make 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 there are no currently available
definitions of solar access angles for the state. Until latitude-specific,
economic-based definitions of solar access data are gathered, it must be
assumed that for a site with unobstructed south view, the collector will not
be useful between December 1 and January 15 at the southern extreme of the
Railbelt, and December 15 to February 1 in Fairbanks.
Though no in-depth studies have been done, preliminary work in various
Anchorage neighborhoods has shown that as much as 35-45% of the existing
building stock may be adaptable to retrofits for active and/or passive
solar.(a)
It would be extremely difficult to determine the overall potential of
active solar at this point. The number of dwellings with solar access is
(a) Alaska Renewable Energy Associates, in-house study, 1980.
8.31
unknown; the actual performances of active systems are undocumented; market
penetration of active solar technologies is difficult to assess as
availability is still fairly low in the region.
In a study performed in 1980 by the Alaska Center for Policy studies,
Richard Seifert of the University of Alaska Institute of Water Resources
writes:
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
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 percent of the maximum possible.
Even 20-25% 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 will remain so until and unless front end
costs come way down.
Active hot water heating on the other hand could conceivably provide for
a significant reduction for electric power demand. Prospects for offsetting
load year-round 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. Assuming that 40-50% of the building stock had
good solar access, 20-25% of the energy needed for water heating could be
displaced.
All of these figures are based on broad assumptions, and as such must be
considered weak. Further work needs to be done to define active solar's
impact in the region.
8.32
Several dealers sell active collectors, most of them for hot water
heating and as 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
how effective their particular systems were, and did not know the optimal
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. There simply has not been enough demand for active solar for many
to have experience with it in the Railbelt.
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 scare off a banker looking at a solar investment. The largest single
obstacle centers around the complete lack of knowledge pertaining to active
solar use in Alaska. Until technical and economic feasibility is
demonstrated, a large segment of the population will likely remain skeptical.
8.3 WOOD FUEL FOR SPACE HEATING
A number of factors point to wood as an alternative to gas, oil and
electricity 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 utilization.
This profile examines the nature and extent of wood usage for home heating in
the Railbelt area, including the potential for demand growth and adaptability
of the alternative to increased demand.
8.3.1 Technical Characteristics
Table 8.4 lists mechanical and physical properties of tree species found
along the Railbelt (USDA 1974). For the consumer, the column representing
millions of Btu per cord is the important consideration. This column
illustrates the relative superiority of birch {prevalant in the Railbelt area)
over other species by a significant margin. Wood containing 20% moisture {MC)
is considered acceptable for good combustion.
8.33
Types of Units
This report does not assess the relative merits of specific wood-fired
heating units now available for home use. Many types and styles of varying
quality are on the market, and though consumer sophistication has grown with
the popularity of using wood as an alternative heat source, choice of units is
often governed by personal subjectivity and economics to a degree that makes
it difficult to analyze the factors leading to the purchase of particular
types.
Fireplaces are still in use for some home heating needs, chiefly as a
~condary source. Few, if any, masonry fireplaces are being incorporated in
new residential construction; most new installations have fireboxes and
chimneys of steel. Fireplaces do not permit any draft control and generally
have little capability to radiate what heat they do produce.
Fireplace inserts provide an opportunity to utilize an installed
fireplace while incorporating some of the advantages of wood stoves, such as
draft control, baffling for secondary combustion, and improved heat
TABLE 8.4. Railbelt Wood Characteristics(a)
Moisture
Content, (%) Specific for Green Wood 10 6 Btu Cord Heart-Sap-Gravity Weight/Cu Ft,
Area Species wood wood {Green} 20% MC(b) 20% MC(b)
Coast: Sitka Spruce 41 142 .37 27.7
Hemlock 85 170 .42 31.4
Interior: White Spruce 34 128 .37 27.7
Black Spruce 34 128 .38 28.4
Aspen 95 113 .35 26.2
Birch 89 72 .48 35.9
Cottonwood 162 146 .31 23.3
(a) Values are given for a standard 128-cu ft cord, containing 90 cu ft of
solid wood and bark.
{b) Derived from Galliet, Marks, and Renshaw (1980).
8.34
15.2
17.2
15.2
15.6
14.1
19.3
12.5
radiation. Many of these units draw combustion air from the outside, thus
cutting the loss of warm air from the structure.
Box or chunk stoves are the simplest and most common type available.
They come in many forms, including kitchen, Franklin, potbelly and parlor
stoves. These 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.
Air-tight box stoves have controlled-draft damper systems, some with
automatic thermostats, to give more positive control of both primary and
secondary combustion air. Most introduce air below and above the fire. Some
designs preheat incoming combustion air. Others incorporate
thermostatically-controlled heat exchangers to recapture heat for space
heating.
Base-burning airtight stoves take the principles of the controlled draft
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, 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 still need frequent
tending.
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
gases from fresh fuel are driven through the glowing coals. 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 its
8.35
proper burning position. Thus, even a fresh load of fuel will not cool to the
fire below. Volatile gases from the new fuel wood are also released more
slowly for more efficient burning.
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.
Mixed fuel systems are also available, they incorporate many of the
features described above while providing the advantage of flexibility in fuel
choice. Estimates of conversion efficiencies for these eight stove types, and
for standard fireplaces, are given in Table 8.5.
Conversion Efficiencies
For wood fuel to reach combustion temperatures, its inherent moisture
must be heated and turned to steam. Therefore, the moisture content is
TABLE 8.5. 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 stove
Conversion
Efficiency
up to 10%
15 -25%
20 -30%
40 -50%
40 -60%
50 -65%
50 -60%
50 -60%
Typical
Heat
Output (Btu)
30 -50,000
53,000
40,000
20,000
50,000
40 -50,000
15 -40,000
112,000
Installed
Cost ($)
1129
299
339
700
6000
Source: Matson/Oregon State University Extension Service.
8.36
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 and a
oxygen deficiency will result, leading to incomplete combustion, which results
in a plume of dense black smoke.
Inherent moisture values vary according to species, as shown in
Table 8.4. Moisture content of 20% is considered acceptable by most technical
sources and wood stove manufacturers.
Consumers have considerable control over motsture content of wood. The
type of wood used and the length of drying time are two factors. In addition,
cutting wood during the dry seasons will usually ensure a lower moisture
content.
It should be remembered that 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 cause the introduction of unwanted air, as well
as signal the end of the stove's useful life. Also note that 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.
In some respects, the effectiveness of converting to wood heating as
either backup or full-time system varies widely with the area to be heated and
the structural implications 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 house or
building.
Reliability
Wood as an alternative fuel is generally reliable year-round, although
consumers must plan for harvest or purchase of a wood supply. Important
8.37
factors include wood type and quality and storage. Reliability is also
governed by the condition or nature of the heated structure. Design features
which 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.
8.3.2 Siting Considerations
Most wood used in the study area (see Table 8.6) for fuel is harvested by
small operators or individuals using chainsaws and pickups or snowmachines.
It appears that wood is gathered year round and is typically gathered from
areas accessible by public roads.
TABLE 8.6. Survey of Wood Suppliers(a)
Distance Public Private # Cords Primary Delivered
Anchorage: Traveled (mi) Land
Supplier: 1 50 to 90 X
2 90 X
3 80 X
4 35 X
5 5
6 2
(Note:) Primary Anchorage commercial
Fairbanks:
Supplier: 1
2
3
40
25
50
X
X
X
land
X
X
X
supplier wi 11
Annual!_l
6
N.A.
45
15
500
25
not reveal
400
400
200
(a) In house survey by Alaska Renewable Associates, 1981.
8.38
Wood T,lQe
Birch
Birch
Birch
Birch
Birch
Birch
data.
Spruce
Spruce
Spruce
Price
$85
90
85
75
95
80
80
90
85
There is only one fully committed commercial firewood supplier in
Anchorage who considers his operation to be full-time and relies on it as a
sole source of income. He will not disclose any data concerning wood sources
or volume as he feels it to be 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. Distance traveled
ranged from 2 miles to 90 miles (one-way). The source of wood is state and
private lands but the greater amount is taken from private lands being cleared
for development. Birch is the most common wood in the Anchorage area and
ranges from $75 to $95 per delivered cord.
Spruce is most common in Fairbanks and ranges from $80 to $90 per cord.
Distances traveled range from 25 to 50 miles (one-way) and State land is the
primary source.
All suppliers stated that their sales were limited only by accessibility
to harvest areas, and not to resource shortage.
8.3.3 Costs
Wood fuel compares very favorably with other sources, especially when
harvested by the dispersed, individual method. This will continue to be the
case, unless transportation fuel costs rise dramatically.
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. Planting costs per acre are high for both types, averaging
$150-$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
proceed in the Railbelt area.
8.39
The unit cost for wood heating is difficult to assess over the life of
the structure, as several assumptions must be made. These 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 woodburning unit will vary, dependent on the
intended end use and quality of the unit. Simple box stoves can be put into
place for as little as $350-400, though the useful life will in almost all
cases be under 10 years. Well built airtight stoves will range in cost from
$700-$1600, and will last 20-30 years with a significantly higher heat output
than the type listed above. The wood furnace units with full ductwork can run
$3000-$6000, particularly if a multipurpose unit is purchased (e.g., oil/wood).
Two useful units for expressing wood fuel cost values are "cost per cord"
and "cost per (106) million Btu." Table 8.7 lists typical costs for both
figures. These figures are based on costs quoted by commercial suppliers in
each area and do not take into consideration the efficiency and combustion
units.
TABLE 8.7. Relative Wood and Oil Costs for Railbelt Area
Wood:
Oil:
Location
Fairbanks
Anchorage
Fairbanks
Anchorage
Costs/Cord(a)/Gallon(b)
$80.00
$90.00
$ 1.13
$ 1.16
Cost/MBtu
$5.48
$6.30
$8.20
$8.20
(a) 90 ft3 of wood within 128 gross cubic feet (4'x4'x8') used
for standard cord.
(b) At January 1981 prices, assuming 138,000 Btu/gallon.
(c) Does not consider combustion efficiency.
8.40
Operation and maintenance costs are difficult to assess as 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 which accumulate creosote in the stack with lower burn
temperatures. Professional stack cleaning ranges from $60-$85 in the region.
Obviously, the homeowner could do this work himself and save considerable
expense.
Other items of maintenance 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/yr. Again, this is hypothesis, and
will vary with the individual.
8.3.4 Environmental and Socioeconomic Impacts
The two primary potential environmental impacts of wood fuel center on
safety issues and air quality. The use of wood for heating poses two safety
issues: fire hazards, and air quality effects. House fires resulting from
the use of 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 can increase creosote buildup as well as spark
emissions 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 the use of a spark arrestor screen in the flue, proper use
of the stove itself, and burning a hot fire with well seasoned wood.
Table 8.8 summarizes data on residential fires attributed to .. failures in
heating systems 11
• Anchorage data refer to heating systems in general; 11 Wood
specific 11 data is not separately available. Fairbanks data are available for
wood~specific systems. The data for the two Municipalities are categorized
differently and are thus difficult to compare. The Fairbanks data are the
most useful because of the high usage of wood there. The low occurance of
8.41
Area
Municipality( a)
of Anchorage
Municipality(b)
of Fairbanks
TABLE 8.8. Wood Heat Fire Hazards
Year
1980
1979
1980
1979
1978
1977
1976
1975
Total
Residential Fires
326
777
Not Available
166
66
81
107
119
Fires
Attributable
To Heating
Sys tern Failures
No. %
23
29
(a) John Fullenwider-Deputy Fire Marshall, Fire Protection
Municipality of Anchorage
Chimney Fires
No. %
1
1 ~0.3~ 0.1 )
7 (4)
4 (6)
5 (6)
9 (8)
4 (3.4)
Division,
(b) Eric Mohromon, Fire Inspector, Municipality of Fairbanks
chimney fires suggests that safety is not a problem. Furthermore, chimney
fires have decreased while wood consumption has increased.
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
combustable 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 particulate 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
8.42
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.
No effort has ever been made to quantify public perception of woodburning
aesthetics. Certinly, wood smoke creates a visual and odor impact which is
not pleasing to all. However, there is as yet no indication that this is of
major concern to many.
Socioeconomic impacts associated with the use of wood fuel for space
heating center on four areas: 1) consumer convenience, 2) adaptability to
growth, 3) land use, and 4) regional economic impacts.
Convenience/Control for Consumer
Wood fuel provides an independent source of heat in case of power
failure. Heating systems are available in the Railbelt which accommodate wood
as well as other fuels (coal, oil and/or gas), and are capable of rapid and
easy changeover should the need arise. Firewood is also a relatively
inexpensive heat source, particularly if the labor for producing the wood
supply is provided by the user. 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, in order 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, this would
require up to 120 hours per year. Approximately 2 hours per month would also
be required for cleaning the stove and maintaining the wood pile.
8.43
Adaptability to Growth
Suppliers of wood-burning units in the Railbelt area are capable of
meeting considerably greater demand for both primary and secondary heating
systems. Available systems include a number of models which can accommodate
other fuels (coal, oil, gas) and which 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
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 8.9 shows the number of personal
use permits issued by year, the estimated number of cords taken, and the
number of commercial sales to firewood distributors in each area. These
figures do not represent the total wood fuel consumption in the area since the
cutting from private lands is not monitored. In the case of commercial
cutters this is significant because a large portion of their annual take 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' harvestors 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)/ 28% for the North Central District
(Fairbanks).
(a)
(b)
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.
8.44
TABLE 8.9. Summary of State Firewood Permits
North Central District
Personal Use Permits Commercial Sales
No. of No. or ) No. of{b) Year Permits Increase (%) Cords a sales No. of Cords
Jan
1981 400 4,ooo(a) 7 700
1980 2300 28 21,000 60 6,000
1979 1800 125 18,800 22 2,200
1978 800 110 1,800 0 0
1977 380 3,800 0 0
Source: Dept Nataural Resource, Div of Forest, Land & Water Mgt.
South Central District
Jan
1981 74 222(C)
1980 960 49 3,ooo(c)
1979 643 1,829{C)
1978 Not available
1977 Not available
(a) Estimated at 10 per permit
(b) Issued by bid to commercial suppliers
{c) Estimated at 3 cords per permit
(unknown at this time)
14 1,175
0 0
Source: Dept Natural Resources, Division of Forest, Land & Water Mgt.
South Central District Office
It has been stated that approximately 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{a) 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 shows that in 1979 6.5% or approximately 910 of the
(a) Source: Heather Stockard, Environmental Technician, Fairbanks North Star
Borough
8.45
homeowners in the municipality possessed permits to cut firewood. It is also
known that 36% of the 1800 permits issued in 1979 were issued to people who
live within the municipality 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 private lands.
To further define the increase in wood heating, AKREA surveyed major wood
stove suppliers in the Anchorage area. Based on dealer estimates, average
sales increased 300% from 1978 to 1980. The increase seems to be leveling out
for 1981, with a 25% increase expected. Clearly this is a ve~y rough
indication of the trend, but it appears to be the only available data. It is
possible that 1981 sales might exceed the expected 25% because of a state loan
program that provides for the purchase of wood stoves.
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
accessible 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, it is clear that 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 g1ven to access
across private and public lands, and distinction between wood cutting and
deadwood gathering. Pressure will probably be brought to bear to permit use
of these areas by small commercial operators within certain guidelines, if
demand continues 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
commercial logging operations, and the possible utilization of other sources
of fuel such as driftwood along rivers, streams and coastal areas.
Additionally, wood is now being recovered from the lands being disposed of by
the state for development of agricultural sites.
8.46
Land Use
The nature and extent of environmental degradation from wood fuel
harvesting will depend upon harvest methods and enforcement of land use
regulations. Dispersed, small-scale wood fuel harvest will tend to follow
other developments 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.
Long-time government policy requiring "primary" manufacture of Alaskan
wood harvested for commercial export was directed at boosting local
economics. On the state level, this policy was recently declared
unconstitutional.
Although federal and state government and Native corporations own the
largest areas of commercially viable timber, future plans for these areas are
not known at this time.
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
secondary jobs, including those in direct industry support and community
infrastructure 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 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.
8.47
8.3.5 Application to Railbelt Energy Demand
The Railbelt region contains large reserves of commercial and
non-commercial grade timber.(a) The bulk of the Railbelt forests are of the
Interior Forest Type with birch, spruce, aspen and cottonwood the dominant
species. {The fuelwood characteristics of these species is provided in
Table 8.4) Regeneration of these forests is slow, but could be improved with
mechanical seeding techniques.
A large number of site-specific or small-scale forest studies and
inventories have been conducted in the Railbelt area, though the data base
remains incomplete on a regional scale. A 1967 U.S. Forest Service study
remains the most recent comprehensive attempt to inventory the forest
resources of Southc~ntral, Interior and Western Alaska to date, and is the
basis for estimates of available Railbelt forest resources used in this report.
Table 8.10 provides a summary of forest resource data, including total
wood volume, standing wood energy, and annual potential wood energy figures.
In general, there is an abundant supply of wood of several types 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 utilization by Native
corporations, the State of Alaska, and 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.
(a) Commercial timber stands are those having a potential wood formaton rate
of 20 ft3;acre or more.
8.48
TABLE 8.10. Wood Energy Summary/Railbelt Area
Forest Type
and Total Wood Volume Standing Wood Energy Annual Potential Wood Energy
Unit Number(a) {mi 11 ion cu ft} {Billions Btu} {Billions Btu}
Commercial(b) Non-commercia 1 Commercial{b) Non-commercial Commercial(b) Non-commercial
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
co .
.p. Coastal 1.0
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
RAILBELT TOTAL 4,835.8 2,862.2 839.547 287,250 16,573 11,400
(a) Units correspond to units designated by USFS (1967) that fall within the Railbelt area.
(b) Commercial timber stands defined as those representing 20 cu ft/acre/yr or more of potential gr.owth.
Source: Calvin Kerr, Reid Collins, Inc.
Private ownership is increasing because of state lands disposal programs
and land transfers under the Alaska Native Claims Settlement Act. Preliminary
indications are that most Native land with commerical forest potential will be
placed under long-term management. Most small-lot private landowners prefer
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 but
two potentially severe land management problems associated with wood
harvesting.
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.
8.3.6 Commercial Availability of Wood Burning Units
The relative simplicity of wood stove installation and operation, the
adaptability of units to a variety of structural heating requirements,
combined with the aesthetic attraction of wood heating to many people have
made wood popular in an area where wood has long had a foothold as a practical
heat source.
Figures in recent studies point to a dramatic increase in wood burning in
the residential sector. There are many people, usually outside the larger
urban areas, depending on wood for their sole heating source. In the larger
population centers, wood heat tends to be more of a secondary source, although
it appears that this may be changing to some degree.
Based on a relatively casual comparison of wood-burning systems available
in the Railbelt area with data on systems available nationwide, it appears
local suppliers have kept pace with recent developments in wood system
8.50
technology. Technological improvements have been made without greatly
complicating wood burning for the average consumer, while at the same time
increasing the variety and performance of available units.
How much heat can be provided by wood 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
could supply all needs during less severe months.
While it is difficult to determine the amount of space heating energy
that would contribute to the region, a figure of 10-15% of total demand is
quite realistic if favorable market penetration is·assumed.
8.51
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R.7
APPENDIX A
WATER RESOURCE IMPACTS ASSOCIATED WITH 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 use impacts, water quality impacts, and hydrologic impacts. Most of the
potential impacts can be satisfactorily mitigated through the appropriate
power plant site selection, engineering design and operating procedures.
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 identified, the discussion generally applies to all steam cycle
facilities.
WATER CONSUMPTION EFFECTS
Since the operation of any steam cycle power plant requires a substantial
water supply for cooling and other plant uses, consumptive water losses
associated with the plant 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 the hydraulic
conductiv1ty of the aquifer serving as the supply. It should be noted that
th Railbelt region's surface water supplies are plentiful, and therefore the
use of groundwater should be limited. Groundwater use can be envisioned in at
leasr two applications: 1) the use of Ranney well collectors in alluvial
aquifers close to a river system to mitigate entrainment of aquatic organisms
and impingement impacts; and 2) the possible use of groundwater in coastal
areas to supply a plant's freshwater 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 steam cycle employed,
A.l
the site, and the specific water management techniques used to maximize water
reuse and minimize power plant makeup requirements. Estimates of these water
requirements are presented in Table A.1 for various steam cycles and plant
capacities.
To comply with existing federal and state regulations, once-through
cooling water systems will likely be limited to coastal areas employing salt
water cooling and interior sites will utilize some form of recirculating
cooling water system (see Appendix F).
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 A.2. Selected USGS streamflow data for
these resources are presented in Table A.3.
Since water withdrawal impacts are relative to the flow of the river, a
comparison of the information presented in Tables A.1 and A.3 can provide an
overview of potential effects. If it is assumed that all water demand
represents total consumption (as it would for a zero discharge plant), then
the maximum water consumption for any of the plants identified in Table A.1,
using a recirculating cooling water system would be less than 1% of the
average flow for rivers identified in Table A.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, say 200 MWe, total plant demand
(again for a zero discharge plant) represents less than 10% of minimum flow
for all but the smallest streams of Table A.3. These conclusions suggest that
impacts on water flow should not be significant.
WATER QUALITY EFFECTS
Construction and operation of all steam cycle facilities can
significantly affect water quality. For most steam cycle facilities,
construction impacts are primarily associated with runoff and erosion from the
site while the soil is exposed. Other common pollutant sources include
construction camp and site domestic and sanitary wastes, concrete batch plant
wastewaters, construction dewatering, and dredge spoil. The development of
geothermal fields requires large quantities of drilling mud, which require
A.2
)::> .
w
TABLE A.l. Estimated Water Use Associated with Various Steam Cycle Facilities
Plants Utilizing Once Through Cooling Water Slstems Plants Utilizing Recirculation Cooling Water Ststems
Approximate
Cooling(a) Cooling(c) Thermal
Total Plant Demand (1000 g~m)(b} Efficiency Water Water
Steam Clcle (Percent) {g~m/MW} 20 MW 50 MW 200 MW 400 MW 600 MW (g~m/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
Geothermal 7-16 845 16.9 42.2 169 15
Nuclear 30 620 124 248 372 11
Combined
Cycle 40 150 7.5 30 3
(a) Based upon estimates presented in Kim et al. 1975 and adjusted for thermal efficiencies.
(b) Cooling water requirements assumed to represent 100% of total plant demand.
(c). Derived from methodology presented in Nelson 1974.
Total Plant Demand (1000 g~m)(d)
20 MW 50 MW 200 MW 400 MW 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 A.2. Power Plant Water Supply Sources in the Railbelt
WATER RESOURCES POSSIBLE FACILITY TYPE
Cook Inlet All
Prince William Sound All except geothermal
Susitna River All
Matanuska River All
Copper River Coal, synfuel, geothermal
Gulkana River Coal, synfuel
Tanana River Nuclear, geothermal
Nenana River Coal, synfuel, nuclear
Chen a River Geotherma 1
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 plant
operation are greatly dependent upon the type of steam cycle and the size of
the plant. Potential spures of water pollution include cooling system
blowdown, fuel pile runoff, demineralizer regeneration wastewater, ash
handling and flue gas disulfurization waste, geothermal fluid discharges
(geothermal technologies only), fuel oil releases, radioactive wastes (nuclear
plants only) and miscellaneous cleaning wastes.
Cooling Water Blowdown:
In general, the operation of all steam cycles require substantial amounts
of cooling water and therefore produce cooling water blowdown. The quantity
and quality of this wastewater depend upon the type of cooling system used and
the specific characteristics of the source. In general, total dissolved
solids (TDS), chlorine, and waste heat are the primary pollutants of concern.
A.4
TABLE A.3. Streamflow Data for Selected Railbelt Locations
U.S.G.S. Years of Average Flow Maximum Flow Minimum Flow
Station Name and Location Number Record cfs 1000 gpm cfs 1000 gpm cfs Hi()O gpm
Susitna River near Cantwell 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 (17,000)(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 Riv,er near Two Rivers 15949300 10 680 305 16,800 7,540 20 9
):>
Ul Chena River near North Pole 15493000 5 756 339 12,300 5,521 50 22
Chena River at Fairbanks 15514000 29 1,450 651 74,400 33,393 (160)(b) 72
Nenana R her 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 utilizing solid fuel, i.e., coal and various forms of
biomass, require management of fuel pile runoff. For coal, this wastewater is
generally low in pH, high in sulfates and iron, and has various concentrations
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, for example,
metals in municipal solid waste.
Demineralizer Regeneration Wastewaters
All steam cycle facilities except geothermal power cycles produce
demineralizer regeneration wastewaters which 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 byproduct of
combustion, although the amounts vary greatly with the type of fuel.
Wastewater produced during ash handling, and ash tran~port, and leacttates 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, bottom 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 are associated with oil-fired power
plants and other facilities which may use oil as an auxiliary fuel. These
include fuel storage areas and the accidental release of oil through spillage
A.6
or tank rupture. Potentially significant impacts which may result from oil
releases are generally mitigated through the mandatory implementation of a
Spill Prevention Control and Countermeasures (SPCC) Pl~n, as required under 40
CFR 110 and 40 CFR 112. This plan is intended to ensure the complete
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 from the release of radioactive wastes with nuclear
facilities are generally mitigated through compliance with Nuclear Regulatory
Commission guidelines. However~ accidental releases are possible; therefore,
all potential transmission media, including ground and surface water
resources, are extensively studied during project development to minimize any
impacts related to such releases.
Miscellaneous Wastewaters
All steam cycle plants have many other miscellaneous wastewaters that are
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, SS, and metals are the effluents of most concern.
All of these enumerated wastewaters are strictly managed within a
specific steam cycle facility. The management vehicle is generally termed a
••water and wastewater management plan" and in some technologies is developed
in conjunction with a ••solid waste management plan••. The purpose of these
studies is to balance environmental, engineering, and cost considerations, and
develop a plant design and operational procedures operation that ensures plant
reliability and environmental compatibility, and minimizes costs.
For plants developed in the Railbelt region, relevant regulations would
include the 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
A.?
parameters of concern in all Alaska waters depending upon the specific water
resource's designated use; the 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.
Downstream water quality will also be altered, as receiving stream standards
are rarely identical to the existing site-specific water quality regime 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 avoided if the plant is designed to operate in a "zero
discharge .. mode. This is technically possible for all steam cycle facilities,
but can be extremely costly.
Values for selected rivers in the Railbelt region are given in
Table A.4. Based on these values, there does not appear to be any
extraordinary or unusual water quality characteristic which would preclude
construction or operation of a properly designed steam cycle facility. 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 a number of wastewater streams,
most significantly cooling tower blowdown. "Standard'' power plant water
management technologies will be required to mitigate any adverse water quality
impacts. Also, based on the sufficiently high bicarbonate levels and alkaline
pH values, appears these natural waters to have sufficient assimilative
capacity to mitigate effects from potential acid rain events.
HYDROLOGIC IMPACTS
Impacts to the hydrological regime of ground and surface water resources
can result from the physical placement of the power plant and its associated
facilities, and from the specific location and operation of a generating
plant's intake and discharge structures. The siting of the power plant may
A.8
TABLE A.4. Water Quality Data for Selected Alaskan Rivers(a)
U.S.G.S. silica iron manganese calcium magnesium sodium potassium
River/Location Station No. flow cfs --'!!9LL mg/1 mg/1 mg/1 mg/1 --'!!9LL mg/1
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
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
)::> Gulkana River at Sourdough 15200280 286 . 6,130 1.0
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 A.4. (Cant d)
U.S.G.S. silica iron manganese calcium magnesium sodium potassium
River/Location Station No. flow cfs ...!!!9LL mg/1 mg/1 mg/1 mg/1 ...!!!9LL mg/l
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
Susitna 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 River near Healy 15518000 102 51 5.0 0.11 169 7.0
57 14 1.1 0.09 74 7.0
):::> Gulkctna River at Sourdough 15200280 110 0.15 0.03 10.1 7.5 .
I-' 40 0.04 0.15 11.0 7.1 0
Talke!etna 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
Chakachutna 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
Fortymile River near Steel Creek 65 37 0.5 0.47 116 7.4
necessitate the elimination or diversion of surface water bodies and will
modify the areas's runoff pattern. Stream diversion and flow concentration
may result in increased stream channel erosion and downstream flooding.
Proper site selection and design can minimize these impacts. If, after
siting, localized impacts remain a concern, various 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 power plant's makeup water system and wastewater discharge system. The
physical placement 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
facility siting and structure orientation. Discharge of power plant
wastewaters may create localized disturbances in the flow regime and velocity
characteristics of the receiving water body. This potential problem is
minimized through proper diffuser design, location, 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. Hydrologic impacts due to reduced streamflow should
therefore not be significant.
A.ll
APPENDIX B
AIR EMISSIONS FROM FUEL COMBUSTION TECHNOLOGIEs(a)
Air pollution is the presence of contaminants such as undesirable gases
or particles in the outside (ambient) atmosphere in quantities and of
sufficient 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, combined cycle plants,
and diesel generators are potentially major sources of energy-induced air
pollution because they discharge potentially polluting products of combustion
into the atmosphere.
The discussion addresses the general nature of air pollution ar1s1ng from
fuel combustion, the broad regulatory framework that has been implemented to
control air pollution, and the regulatory considerations which apply to the
Railbelt region. The appendix also compares the emissions of the different
fuel combustion technologies used in electric power generation, and finally,
discusses the general nature of siting requirements which affect the
construction of combustion-fired generating facilities in the Railbelt region.
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.
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. Man-made
particulate matter includes smoke, metal fumes, soil-generated dust, cement
(a) Technologies fueled by coal, petroleum distillates and residuals,
synthetic and natural gases and biomass.
B.l
dust, and grain dust. On the basis of data collected by the U.S.
Environmental Protection Agency (EPA), total suspended particulate matter
(TSP) 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 non-combustible minerals. Particulate matter would be
emitted in large quantities from fuel combustion plants which use solid fuels
(coal, peat, wood, municipal waste) or residual oil, if high-efficiency
control equipment were not used. Particulates are removed from flue gas by
use of electrostatic precipitators or fabric filters (baghouses). They are
routinely required, however, and collection efficiencies can be very high (in
excess of 99%).
Sulfur Dioxide
Sulfur dioxide (S0 2) is a gaseous air pollutant which is emitted during
combustion of fuels that contain sulfur. Coal and residual oil contain sulfur
in amounts of a few tenths of a percent to a few percent, while pipeline
natural gas, wood, and most municipal wastes contain relatively little
sulfur. Sulfur dioxide, like particulate matter, has been identified as being
harmful to human health, and it appears to be particularly serious when
combined with high concentrations of particulate matter. It is damaging to
many plant species, including several food crops such as beans.
Nitrogen Oxides
Nitrogen oxides (N0 2 and NO, primarily) are gaseous air pollutants
which form as a result of high-temperature combustion or oxidation of
fuel-bound 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 nitrogen oxides has developed more
slowly than for most other air pollutants. Lack of chemical reactivity with
conventional scrubbing compounds is the main difficulty. Thus current control
strategies focus on control of NOx production. Principal strategies include
B.2
control of combustion temperatures (lower combustion temperatures retard
formation of NOx) and control of combustion air supplies to minimize
introduction 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
suboptimal combustion conditions and can be reduced by using appropriate
firing techniques. However, CO emissions can never be eliminated completely,
using even the most modern combustion techniques and clean fuels. CO
emissions are regulated under the Clean Air Act because of their toxic effect
on humans and animals.
Unburned Hydrocarbons
TO BE SUPPLIED
Water Vapor .
Plumes of condensed water vapor will emanate from a wet cooling tower as
its exhaust is cooled below its saturation point. The plume will persist
downwind of the tower until the water vapor is diluted to a level below
saturation. In cold or cool, moist climates the plumes are particularly long
because the ambient air can hold little added moisture. Formation of these
plumes is particularly hazardous during "fogging" 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 generation, fogging, and icing can be controlled or
virtually eliminated through the use of wet/dry or dry cooling towers.
Noise and Odor
Noise levels beyond the plant property line can be controlled by
equipment design or installation of barriers. Odors can be anticipated if
B.3
municipal wastes or some biomass fuels are to be used. Generally noise and
odors are not as great a concern as the air pollutants contained in exhaust
gasses.
Acid Precipitation
The S02 and NOx emissions from major fuel-burning facilities have
been related to the occurrence of acid rainfall downwind of major industrial
areas. It is possible that Congress will soon enact laws to restrict these
emissions because of the effects of acid rain. The theoretical framework for
explaining acid rain formation, the acidification of lakes, the effects on
soils, vegetation, wildlife and structures, and the tracing of problems to
specific source emissions is not yet fully understood. Much research is in
progress,and recent research indicates that some remote areas of the western
United States have been affected by acid rain.
On initial assessment, it appears that Alaskan lakes are not so sensitive
to acid rain as lakes in eastern Canada and the northeastern United States.
Furthermore, the total emissions into the Alaska environment are much less
than emissions from industrialized areas of the midwest and northeastern
United States (Galloway and Cowling 1978}. It is unlikely that acid rainfall
will ever present problems in Alaska similar to those in the eastern portion
of the continent. There is currently no basis for assessing the impacts of
acid rainfall which might develop because of increased fuel combustion in
Alaska. In the development of any of these technologies, however, the
planning agencies must be aware that a significant researach effort is being
mounted against acid rainfall and that a regulatory framework may be developed
within the next 2 to 10 years to analyze and mitigate the impacts of acid
rainfall.
COMPARISON OF PROJECTED EMISSIONS
The critical comparison of fuel combustion technologies for their impacts
on air quality is determined by the anticipated rate of emissions of each of
the pollutants. Emission levels for the various technologies are presented
for sulfur dioxide in Table 8.1, for particulates in Table 8.2, and for
nitrogen oxides in Table 8.3. Data are taken from EPA publications or the
8.4
TABLE B.1. Sulfur Dioxide Emissions for Various Technologies
Technolo9y
Emissign Rate
{lb/10 Btu}
Steam Electric
Coal(a) 0.10
on(b) 0.20
Gas 0.0006
Wood 0.15
Combustion Turbine
Oil 0.30
Gas(c)
(a) 70% scrubbing of 0.18% S Coal.
(b) New Source Performance Standard.
( c ) Neg 1 i g i b 1 e •
20
67
131
0
99
269
Annual Emissions at 75%
Load Factor (Tons/Yr)
Facility Size (MWe)
50 200 400 600
169 674 1348 2022
329 1314 2628 3942
1 4 8 12
246
673
enforced New Source Performance Standards. Emissions from wood-fired boilers,
though officially published, are felt to be estimated somewhat high,
especially for sulfur dioxide.
The development of these tables are based on various assumptions. A 33%
efficiency of conversion is assumed for steam electric plants, and a 25%
efficiency for combustion turbines. For the power plant sizes provided in the
tables, emissions are directly proportional to the heat rate input for a given
technology. The following heat input factors were assumed: for coal
10,000 Btu/lb; for oil 20,000 Btu/lb, for wood 5,000 Btu/lb; and for natural
gas 1,000 Btu/standard cubic foot.
REGULATORY FRAMEWORK
In 1970, the federal Clean Air Act established the national strategy in
air pollution control. The Act established New Source Performance Standards
B.5
TABLE 8.2. Particulate Matter Emissions for Various Technologies
Technology
Emissio~ Rate
pb/10 Btu}
Steam Electric
Coal(a) 0.03
Oi 1 (a) 0.03
Gas (b) 0.01
Wood(c) 0.02
Combustion Turbine
Oil 0.05
Gas(d)
New Source Performance Standard
Typical.
Annual Emissions at 75%
Load Factor (Tons/Yr)
Facility Size (MWe)
20 50 200 400 600
20 49 197 394 591
20 49 197 394 591
7 16 66 131 197
131 329
46 125
(a)
(b)
(c) Assumes mechanical collection. Using electrostatic precipitators
or baghouse~ emissions may be reduced by 90%.
(d) Negligible.
(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 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
is capable of burning any amount of coal, or if such use is planned, is
(a) 11 The term standard of performance means a standard for emissions of air
pollutants which reflect the degree of emissions limitation achievalbe
through the application of the best system of emission reduction. 11
(Pub. L. 91-604, HR 17255, Dec. 31, 1970).
8.6
TABLE B.3. Nitrogen Oxides Emissions for Various Technologies
Techno log~
Emissign Rate
~lb/10 Btu) 20
Steam Electric
Coal(a) 0.6 394
Oil (a) 0.3 197
Gas(a) 0.2 131
Wood(b) 1.0 657
Combustion Turbine
Oil 0.59 530
Gas(c)
(a) New Source Performance Standard
(b) Probably significantly overstated.
(c) Comparable to oil.
Annual Emissions at 75%
Load Factor (Tons/Yr)
Facility Size (MWe)
50 200 400 600
986 3942 7884 11826
493 1971 3942 5913
329 1314 2628 3942
1643
1272
subject to the coal-fired power plant standards. Standards of allowable
emissions for each fuel combustion technology for each major pollutant for a
range of sizes for power plants are presented in Tables B.1 through B.3. The
standards are being enforced for both newly constructed and significantly
retrofitted facilities and represent the expected level of controlled
emissions from these power plants.
In Alaska, the Department of Environmental Conservation enforces
regulations 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 (S0 2 and TSP) throughout the United States. Pristine areas of
B.7
national significance, (Class I areas), were set aside with very small
increments in 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 standards. State and
local agencies may take over the administration of these programs through the
development of a state implementation plan acceptable to the EPA. See
Table B.4 for National Ambient Air Quality Standards and allowable PSD
increments.
The PSD program is currently administered by the U.S. 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 sulfur dioxide and suspended particulates) 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 on-site
monitoring of air quality and meteorological conditions prior to the issuance
of a permit to construct. 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 the construction of 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; this requirement presents
a significant constraint to the development of nearby facilities.
A potentially important aspect of the PSD program to development of
electric power generation in the Railbelt region is that Denali National Park
(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
B.8
OJ .
TABLE 8.4. 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-h(a} 24-h(a} Annual 3-h 24-h Annual 30-h 24-h Annual
Total Suspended
Particulate Matter
(llg/m3)
Sulfur Dioxide
(llg/m3)
Nitrog,en Dioxide
(J.Jg/m3)
Carbon Monoxide(e)
(mg/m3)
None
260
1300(b)
None
150(b) so( b) 3(c)
75
365(d) ao(d)
None 100(d)
None
N/A -Not applicable (no standards have been issued).
(a) Not be to exceeded more than once per year.
(b) Secondary or welfare-protecting standard.
None
512
N/A
N/A
(c) Arnnual geometric mean, advisory indicator of compliance.
(d) Primary or health-protecting standard.
37
91
N/A
N/A
19
20
N/A
N/A
None
25
N/A
N/A
10
5
N/A
N/A
5
2
N/A
N/A
(e) Carbon monoxide primary ambient air quality standards are as follows. The value not to be exceeded more
than 1 hr/yr is 40 mg/m3 (may be changed to 29 mg/m3); the value not to be exceeded more than one 8-h
period per year is 10 mg/m3.
existing coal-fired electric generating unit (25 MWe) at Healy. Although the
PSO program does not affect existing units, an expanded coal-burning facility
at Healy would have to comply with Class I PSO 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 man-made air pollution. The impact of
visibility requirements on Class I areas are not yet fully known.
SITING STRATEGY
Based on information on emissions and regulations, several general
conclusions can be drawn that bear on the siting 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 at least
20 miles, but each case should be carefully analyzed to reliably choose a
site. The forthcoming visibility regulations may require a greater distance.
Based on regulatory constraints, it would be preferable to site any of these
facilities well away from the non-attainment 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.
Many acceptable sites should exist for coal-fired power plants in the
Beluga, Kenai, Susitna, Nenana, and Glenallen areas, near the available coal
fields. 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.
B.lO
APPENDIX C
AQUATIC ECOLOGY IMPACTS ASSOCIATED WITH STEAM CYCLE POWER PLANTS
The construction and operation of steam-electric plants have three
potential areas of impacts on aquatic ecosystems: water quality effects from
construction stormwater runoff, water withdrawal for power plant use, and
process water discharge. The degree of each potential impact will depend on
the size, location, and operating characteristics of the plant. Unless a
specific cycle is identified, the discussion generally applies to all steam
cycle facilities.
CONSTRUCTION AREA RUNOFF
Construction area runoff can increase turbidity and siltation in
receiving waters adjacent to site construction. For inland waters where steam
cycle facilities could potentially be sited, including the Susitna, Copper,
and Tanana Rivers, the main effect of this siltation could be the destruction
of these productive aquatic ecosystems. Spawning areas could be eliminated by
inundating gravel with fine sediment particles that smother eggs or inhibit
fry emergence (especially for salmonids); benthic organisms could be smothered
and light penetration reduced, thereby inhibiting the growth of aquatic
plants. Salmon, trout, char, grayling, burbot, sheefish, and whitefish
species, which are common in many of the major rivers of the Railbelt region
(ADFG 1978), could be affected.
Runoff into the marine environment, especially where existing suspended
sediment levels are typically low like outer Cook Inlet or Prince William
Sound, could also smother benthic organisms and reduce light penetration.
Organisms potentially affected include scallops, clams, crabs, shrimp, trout,
char, salmon, herring, smelt, halibut, and other bottom fish (ADFG 1978).
Silt laden runoff, if severe, may also clog or damage the gills of these
organisms. Organisms such as razor clams, which live in the intertidal area,
may be the most susceptible to being smothered. Populations of important food
C.1
chain organisms like zooplankton and zoobenthos may be reduced because of
decreased algae production resulting from reduced light penetration.
The impact from construction runoff would depend on the efficiency of
erosion control measures and location of the site. Potential problems in both
the fresh and marine waters can be minimized or eliminated by implementing
appropriate site runoff and erosion control measures such as runoff collection
systems, settling ponds, and other runoff treatment facilities.
Intake structures, by virtue of their function, have the potential to
impinge or entrain aquatic organisms. Entrainment is the incorporation of
small organisms, like plankton, fish eggs, larvae, and small fish, into the
plant's water supply flow. Entrainment in once-through cooling water systems
can often result in acute and chronic effects to organisms through thermal
shock, pressure change, mechanical damage, or chemical additions. Organisms
entrained in closed cycle cooling systems would have a greater chance of
mortality because of continued cycling within the system. Impingement refers
to the interception, often injurious, of larger organisms, especially juvenile
fish by intake screens. Impingement can cause injury or death from abrasion,
increased predation, or exhaustion of the organisms.
The sport and commercially important fish of inland waters could be
adversely affected by impingement and entrainment. Larval forms are
particulary susceptible to entrainment while juvenile salmon are susceptible
to impingement. Important marine species with larval forms that could be
damaged by entrainment or impingement include crab, shrimp, clams, scallops
and many marine fish.
Entrainment and impingement effects are dependent on type and location of
the intake and the rate of water withdrawal. The use of adequately designed
screening equipment and proper velocity characteristics at the intake
structure will help minimize impacts by reducing numbers of organisms impinged
or entrained. The proper location of intakes away from known migratory routes
of important species will also help reduce these impacts. The use of
subsurface intakes, like Ranney wells, at sites not prone to permafrost,
should eliminate impingement and entrainment of freshwater or marine
C.2
organisms. Other factors being equal, the plant that requires the most water
will have the greatest impact (see Table A.1, Appendix A for comparison).
WATER WITHDRAWAL
Withdrawal of water in significant amounts from inland streams can alter
flow patterns and reduce aquatic habitat downstream. This may be partially
offset by the amount of water discharged, if both the intake and discharge are
on the same body of water. The loss of habitat is highly dependent on the
size, type, and location of the steam plant. Considering the most probable
locations (Appendix A) for the types and sizes of plant considered for the
Railbelt region, the effects on habitat loss would probably not be very
significant (worst case is 10% of minimum flow estimates; see Tables A.1 and
A.3, Appendix A). If other areas in the Railbelt region are chosen as plant
sites, the impacts of withdrawals could be more severe. If all other factors
are equal, the plant that uses the most water will most contribute to habitat
loss.
WATER DISCHARGE
Attraction of organisms to thermal discharges may interfere with normal
migration patterns. A particular concern in Alaska would be a situation in
which marine organisms are attracted and become acclimated to a heated
discharge from a once-through cooling water system which is then interrupted
or stopped; the almost instantaneous temperature change back to ambient levels
can result in thermal shock and subsequent mortalities to these organisms. In
Cook Inlet or Prince William Sound migrating or feeding salmon, herring,
crabs, shrimp and other important marine organisms could be affected (ADFG
1978). In inland waters this problem would not be as significant because of
the use of recirculating cooling water systems, which would eliminate or
greatly reduce any heated water discharge. Proper plant siting and cooling
system design could reduce or eliminate thermal impacts. With other factors
constant, the plant that utilizes the most water would have the greatest
impact.
The chemical composition of the intake water is altered during its
passage through the steam plant. The changes in the composition are generally
C.3
dependent on the specific steam cycle and its capacity (see Appendix A), but
general alterations include: 1) chemicals, such as chlorine, are added to
control biological fouling and deposition of materials on cooling system
components; 2) constituents of the intake water are concentrated during
recirculation through evaporative cooling systems; and 3) corrosion products
from structural components of the cooling system are present. Other potential
pollutants from steam cycles include: low pH, high metal concentrations,
biochemical oxygen demand, radionuclides, and petroleum products. When
discharged in sufficient quantity, these can cause immediate impacts such as
death of organisms or long-term changes in the aquatic ecosystem. Of
particular concern would be the effects on the commercial and recreationally
important fish and shellfish species that reside in both the fresh and marine
systems of the Railbelt region.
Some effluents, like heavy metals and radionuclides, could have negative
effects far from the site of their initial discharge, while others like low pH
and BOD will have the most impact close to the discharge. Some of these
effluents would have less impact on marine systems than in fresh water
systems. Total dissolved solids (TSD), can be especially high in geothermal
plants. High TSD would have little effect on the marine environment because
TSO is already much higher in seawater than in fresh water. Low pH discharges
would be more easily neutralized in the marine systems. Most other discharges
could have negative effects on both fresh water and marine systems, but the
marine environment's much larger area for dilution more easily reduces
impacts.
The discharge water is often treated to remove many of those potentially
hazardous compounds before discharge (e.g., dechlorination can be accomplished
with so 2 gas). Also, proper diffuser location and a large receiving water
system like the Copper or Susitna Rivers can help mitigate negative effects.
If the area is highly sensitive, a "zero discharge" system can be designed.
Acid rain, resulting from SOV emissions {Appendix B), can cause
" significant changes in the pH level of a water body which, if severe, can
reduce or eliminate certain species. The severity depends on the amount of
acid rain, the size and buffering capacity of the receiving water, and the
C.4
sensitivity of the aquatic organisms to pH change. Acid rain would have no
effect on the marine environment because of its buffering capacity. Most
freshwater systems in the Railbelt region are also well buffered (see
Table A.4, Appendix A), and significant impacts would not be expected.
Generally, coal-fired plants would have the greatest potential for
contributing to acid rain, and natural gas the lowest for similar sized
plants. Emissions of this type can be reduced by proper plant design (e.g.,
appropriate flue gas desulfurization techniques).
C.5
APPENDIX D
IMPACTS OF STEAM CYCLE POWER PLANTS ON TERRESTRIAL ECOLOGY
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
wildlife. Other terrestrial impacts include those resulting from air
emissions, fuel and waste storage areas, and human intrusions. Approximate
1 and area requ i rements for various types of steam cycle facilities are
compared in Table D.l.
TABLE D.l. Approximate Land Requirements of Steam Cycle Power Plants
Land Area
Electrical Per Unit
Steam Cycle Generating Land Area (Acres) Capacity
Power Plants caeacit~ (MW} {All facilities} {Acres)
Natural Gas-F1red 20 to 600 8 to 670 0.4-1.1
Giomass-Fired 5 to 60 10 to 50 0.8-2.0
Natural Gas-Fired 1o(a) 3 0.3
Distillate-Fired 1o(a) 4 0.4
Nuclear 800 to 1,200 100 to 150 0.1
Geothermal 10 5 (excluding wells) 0.5
(a) The Fuel Use Act limits the maximum electrical generating capacity to
approximately 10 MW.
D.1
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
for development of steam cycle facilities contain seasonal ranges of moose,
caribou, brown and black bear, mountain goat, and Dall sheep (Table D.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 for financial reasons.
AIR EMISSION EFFECTS
The release of toxic chemicals into the air can negatively affect
vegetation and subsequently wildlife. Sulfur and nitrogen oxides 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 accumulate 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 sulfur and nitrogen oxides 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:
1) decreased aerial growth; 2) direct injury to foliage of coniferous and
D.2
TABLE D.2. Possible Watersheds Associated with the Development of Steam Cycle Power Plants
in the Railbelt Region and Prominent Wildlife Found at these Locations (Wildlife
Information was Taken from Alaska Regional Profiles 1974)
Watershed
Energy Prince
Technology Cook Wi 11 i am Susitna Matanuska Copper Gulkana Tanana Nenana Chen a
Species Inlet Sound River River River River River River River
Energy Technology
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
0 Moose X X X X X X X X X w Caribou X X X X X X
Bison X
Mo1mtai n 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.
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 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, particulates 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 particulates {<1~m) are
difficult to control. Small particulates can cause greater impacts on soils,
plants, and wildlife than larger particulates because they contain a greater
fraction of potentially toxic trace elements (e.g., mercury, selenium,
arsenic, bromine. chlorine, and others) in a state more readily available for
chemical interaction (Dvorak 1978).
Trace elements would primarily enter the soil through direct deposition,
plant litter decomposition, and the washing of particulates 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 existing 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.
Particulates 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 particulates, which can interfere with the diffusion of co 2,
02, and water vapor between the leaf air spaces and air. In addition,
particulates may adversely affect plant absorption and reflectance of incident
solar radiation. 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.
D.4
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
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, wh1ch may lower photosynthetic rates and 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
populations in areas adjacent to power plant sites or access roads may be
subjected to greater hunting pressure, poaching, road kills, and other forms
of human disturbance. This may be particularly severe for power plants
located 1n isolated areas. Wildlife populations ir1 these areas are nut only
more sensitive to disturbance but also more vulnerable to exploitation. Of
the var1ous steam cycle plant types, human disturbance impacts are probably
greatest with geothermal plants, since these are more likely to be sited in
isolated locations near their fuel sources. In addition to human disturbance
impacts, 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
byproduct of human intrusion; however, the severity of this disturbance is
uncertain. Potential impacts from noise could be related to hearing loss and
stress in animals. Noise could also interfere with the auditory cues for
communication among certain wildlife. Auditory cues can include those for
territorial defense, mate attraction, alarm calls, and nesting behavior of
D.5
passerine birds. Stress impacts 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.
COLLISION EFFECTS
Another wildlife impact results from birds colliding with the cooling
towers associated with 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 significance of this impact. Bird collision impacts,
however, can be mitigated 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.
0.6
APPENDIX E
SOCIOECONOMIC IMPACTS ASSOCIATED WITH ENERGY
DEVELOPMENT IN THE RAILBELT REGION
Two types of decisions made during the overall Railbelt energy
development process will result in community and regional impacts. The
decision to site a facility at a particular location will affect the people
living in that area. 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
population with insufficient infrastructure to support the new demands. The
in-migration of workers to a community will have an impact on land
availability, housing supply, commercial establishments, electric energy
availability, 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
population of the area, the existing infrastructures, the size of the
construction workforce, and the duration of the construction period. The bust
occurs with the out-migration of a large construction workforce, which leaves
the community with underutilized housing and facilities. Development of a
power plant therefore has the potential to affect the community at both the
beginning and end of the construction phase.
Two indicators of a boom/bust cycle have been developed. Since the
permanent staff required to operate a plant is typically much smaller than the
construction labor force, the population will decrease dramatically following
E.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 workforce to community size. These two measures are provided
for each technology in the attribute matrix.
The secondary effect of power plant construction is impact on the growth
of the local and regional economies. The increase in number of permanent
residents will usually cause the introduction of new businesses and jobs to
the community. This may be perceived as either a positive or negative effect,
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;
this 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
population 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 workforce, 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 1980). The population of boroughs
and census areas within the Railbelt is presented in Table E.l. Anchorage
(Figure 1.1) 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,
E.2
TABLE E.1. Population of the Railbelt (1980) Incorporated Areas
1980 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 2 664 2
Total 284,822 100
Source: U.S. Bureau of Census. 1980 Census of Population and Housing
Preliminary Reports.
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 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
particular, has seen rapid growth over the last decade. Since 1970, the
population 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 well as 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
opportunities were greatest in Anchorage, Valdez-Chitina-Whittier, and the
Cordova-McCarthy areas where unemployment rates were lower than the state
E.3
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.
Small communities (500-1,000 population, including North Pole and Delta
Junction) and very small communities (less than 500 population) should be able
to accommodate the demands for services resulting from installation of a
small-scale project, but will have more difficulty in absorbing the impacts of
large projects, particularly labor-intensive projects. Intermediate sized
communities with a population size ranging from 1,000 to 5,000 (Homer, Kenai,
Soldotna, Seward, Palmer, Wasilla, Cordova, Valdez) would be affected by the
influx of a large population (250 or more) but would be able to meet the
demands created by a smaller influx, particularly if construction camps are
used to reduce the need for new housing. Large communities (Fairbanks,
population 22,521) and very large communities (Anchorage, population 173,992)
should be able to absorb the impacts caused by an influx of a population of
500 or less, but could be significantly affected by the in-migration of a
population of 1,000 or more. The magnitude of impacts from the in-migration
of the workforce, and their dependants are summarized according to population
size of communities in Table E.2.
The magnitude of the boom depends on the number of workers, their marital
status, and the number of dependents who relocate to the site. The potential
for a boom/bust cycle is also highly dependent on the local labor market since
available labor would reduce the influx of the construction workforce.
Because of the relatively sparse population of the Interior, a boom/bust cycle
will likely occur if a large facility is located in the northeastern region of
the Railbelt. If the site is located within an approximate 50-mile radius of
Fairbanks, a boom is less likely, since many workers could commute to the site
from Fairbanks. The impact of project construction will also be mitigated by
the sizeable Fairbanks labor market and high unemployment rate.
A boom/bust cycle would be less probable in the Anchorage and upper Kenai
areas. Labor requirements for power plant construction should be met by the
Anchorage labor market and may even attract the unemployed labor pool in the
upper Kenai Peninsula. In 1979 the occupational classification of craft
E.4
TABLE E.2. Magnitude of Impacts from Powerplant Construction
as a Ratio of Population Increase to Community Size
Population
Increase
1000+
500-999
250-499
100-249
50-99
0-49
Very Small
_j_ 500)
Severe
Severe
Severe
Severe
Small
(500-1,000)
Severe
Severe
Severe
Significant
Significant Moderate
Moderate Minor-
Moderate
Magnitude of Impact
Minor
Moderate
Significant
Severe
Community Size
Intermediate
(1,000-5,000)
Severe
Significant
Moderate-
Significant
Moderate-
Significant
Moderate
Minor
Large
{Fairbanks}
Moderate
Moderate
Moderate
Minor
Minor
Minor
Ratio of
Population Increase
to Community Size
.01 or 1 ess
.02 -.10
.11 -• 39
.40 or greater
Very Large
{Anchorage)
Minor
Minor
Minor
Minor
Minor
Minor
workers, operators, and laborers represented 32% of the labor force
statewide. This category includes maintenance repairers, carpenters, heavy
equipment operators, and truck drivers, among other occupations. Employment
in these 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 specialized in heavy construction are
located (Alaska Department of Labor 1989).
Rapid growth due to power plant construction will be most dramatic in the
interior Railbelt region, which is delineated by the railroad from Wasilla to
E.5
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
and very small towns which would have difficulty in meet1ng 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 a homogenous economic base. The size of the operating and
maintenance workforce, although usually substantially smaller than the
construction workforce, is another factor contributing to the permanent
population.
REGIONAL IMPACTS
The Railbelt region should not be affected by the boom/but cycle in
population since power plant siting is location-specific. It w1ll, 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
employment and through indirect employment arising from expenditures on goods
and services supplied to the project. Indirect employment will result from
projects 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 Ra1lbelt 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 which capture all costs associated with power plant
construction. The assumptions made regarding the flow of capital for each
category are presented in Table E.3. The proportion of expenditures allocated
to the site improvement, equipment, and labor catagories will vary with each
technology and is presented in the detailed description of the individual
technology.
E.6
TABLE E.3. Flow of Expenditures Sent Outside and to the Rail belt
Percent of Percent of
Expenditures Expenditures
Spent Outside Spent Within
Categor,Y Subcategor_y the Railbelt the Railbelt
Site Improvements Land 15 85
Grading
Foundation
Concrete
Equipment Mechancial 100 0
Instrumentation
Electrical
Piping
Labor Supervisory 20(a) 80
Engineering
Skilled Laborers
(a) Expenditures on l<abor 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, would be purchased within the Railbelt, as well as tools,
light machinery, and supplies. Cement and rebar would be purchased outside of
Alaska; these are estimated to average approximately 15% of site improvement
expenditures. Construction supervisory and engineering personnel are normally
provided by the project developers while skilled labor may be provided fully
from the local workforce. For estimation purposes, it was assumed that 20% of
the workforce would be derived from outside Alaska, while 80% would be Alaska
residents. In compliance with Alaska State labor laws, 60% of the labor force
must be Alaska residents, if found qualified.
E.7
Capital-intensive technologies that require a small or highly skilled
labor force will have a less beneficial effect on the regional economy.
Conversely, 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
technologies, 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.
E.8
APPENDIX F
WASTE HEAT REJECTION SYSTEMS IN STEAM CYCLE PLANTS
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 from 0.01 to 0.1
cfs/MW. Appendix A presents more detailed 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). Figure F.l presents a schematic diagram of
the typical features of a condenser cooling water system.
ONCE-THROUGH SYSTEM
A once-through system is one in which the total water requirement for the
condenser is pumped from the supply source through the condenser on a single
pass basis 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
power plant sites located within the coastal region. The water resources of
Cook Inlet and Prince William Sound are prime candidates for this technology,
if not precluded by environmental or regulatory constraints.
RECIRCULATING SYSTEMS
In a recirculating cooling water system, an additional heat sink is used
to lower the spent condenser cooling water's elevated temperatures to permit
the reuse of the condenser cooling water. Recirculation can be accomplished
with various heat dissipation systems which transfer the absorbed heat to the
atmosphere primarily by evaporation. The heat dissipation systems usually
F.l
, .
N
WATER
SOURCE
INTAKE
STRUCTURE
STRUCTURE
EVAPORATION
DRIFT
MAKEUP
HEAT
DISSIPATION
CO~OENSER '
SYSTEM
CHEMICAL "------4
TREATfJENT
TYPES OF HEAT DISSIPATION SYSTEMS
COOLING POND/ LAKE
SPRAY POND
MECHANICAL DRAFT TOWER
NATURAL DRAFT TOWER
DRY TOWER
WET /DRY TOWER
BIOCIDE
TREATUENT
FIGURE F.l. Typical Condenser Cooling Water System
POWER
PLANT
considered for a recirculating cooling water system include cooling
ponds/lakes, spray ponds, and wet cooling towers (natural draft and mechanical
draft), dry cooling towers and wet/dry cooling towers.
Cooling Ponds and Lakes
A cooling pond operates in a manner similar to once-through cooling,
except the body of water used is largely isolated from natural waters. Heat
is transferred from the heated water in the cooling pond by radiation,
conduction and evaporation prior to the water being recirculated from the pond
to the condenser inlet. Area requirements for dissipation of waste heat from
a cooling lake or pond are on the order of 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 also required to eliminate the effects of fog to
off-site roads, buildings, etc. 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 Railbelt's cold weather will cause
these localized icing conditions and thus will severely limit the development
of cooling ponds. Even at Anchorage over half the days during the year will
have temperatures ar or below freezing.
The cooling pond is a proven, effective and economical heat sink in areas
where suficient level land can be purchased at reasonable cost. The rugged
topography of much of the Railbelt presents an obstacle to development of
cooling ponds because abundant, inexpensive level land is not readily
available.
Spray Ponds and Spray Canals
Land requirements of cooling lakes can be reduced, by a factor of up to
20, by use of sprays. As with cooling ponds, however, a buffer zone of about
1,000 to 1,500 ft 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
F.3
spraying it via floating spray modules. However, spray ponds are similar to
cooling ponds in that their cooling effectiveness depends upon local
temperature, relative humidity and wind conditions.
In order 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 will be derived based
upon comparative cooling efficiency and cost.
Cooling Towers
There are two basic types of cooling towers: the wet tower that carries
away heat by evaporation and sensible heat transfer, and the dry tower that
relies on air to carry away heat and, in principle, functions like an
automobile radiator.
Wet Cooling Towers:
The two types of wet cooling towers, mechanical and natural draft towers,
differ in the method of inducing air flow from the heated water to the ambient
air.
When operated in the closed cycle mode, wet cooling towers require makeup
water to compensate for losses sustained throuqr evaporation and drift (the
carryover of small water droplets by air). As evaporation occurs, the natural
salts in the cooling water become concentrated; to prevent buildup and
deposition on the components of the system, they are continuously returned to
supply as blowdown or recycled to other water
users within the plant.
F.4
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.
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 Btu to the
atmosphere.
Natural Draft Cooling Towers. A wet natural draft cooling tower consists
of the familiar large reinforced concrete chimney (Figure F.2) which 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 600ft. 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 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 compared to mechanical draft
units: operating costs are lower since fans are not needed to move the air;
noise leveis are reiativeiy iow, 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
F.5
AIR AND WATER VAPOR OUT
UPPER
STIFFENING
BEAM
VOID
HOT-WATER
DISTRIBUTION
SYSTEM
FILL
t ···· .. ·-
HOT-WATER RISERS
REINFORCED
...;.....-CONCRETE
SHELL
AIR IN
4 111
COLD-WATER COLLECTING BAS IN
FIGURE F.2. Natural Draft Cooling Towers
an 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.
In a relatively new design, a fan-assisted natural draft cooling tower,
fans assist the natural airflow to increase 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.
F.6
Mechanical Draft Cooling Towers. Mechanical draft cooling towers and
natural draft cooling towers operate on the same basic thermodynamic
principle--that is, cooling takes place by evaporation and sensible heat
transfer. In mechanical draft towers, fans are used to pull air through the
fill section. Mechanical draft towers are of modular construction.
Figure F.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 flex1bility, greater control of cold-water temperature,
and less visual impact of the structure due to its lower profile. However,
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 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 these mechanical draft units places a
severe restriction on their use in cold environments, which includes the
entire Railbelt region. The effects of ice fog formation and icing can be
mitigated by purchasing large amounts of land surrounding the cooling towers
or by siting them in non-sensitive areas.
Dry Cooling Towers
Dry cooling towers remove heat from a circulating fluid through
conduction to the air being circulated past the heat exchanger tubes. In
contrast to wet towers there is no direct contact between the circulating
F.7
Air Outlet
FIGURE F.3. Mechanical-Draft Wet Cooling Tower (Cross Flow)
cooling water and the ambient air. The heat exchanger tubes are generally
tinned to increase the heat-transfer area. The theoretically lowest
temperature that a dry cooling system can 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 theoretically lowest temperature that a wet
cooling tower 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. Turbine warmer condenser cooling water
will increase turbine back pressures, resulting in reduced station capacity
for a given size generating facility.
The advantage of a dry cooling tower system is its ability to function
without large quantities of cooling water. Theoretically, this allows power
plant siting with minimal consideration of water availability, and eliminates
thermalichemical pollution from biowdown. From an cost/benefit standpoint,
dry cooling towers can permit optimum siting with respect to environmental,
safety, and load distribution criteria without fogging or dependence on a
supply of cooling water. Other advantages, compared to wet cooling towers,
F.8
include elimination of drift, elimination of fogging and icing problems, and
elimination of blowdown disposal. Thus, dry cooling towers present an
environmental advantages 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 problems may be encountered.
Noise generation problems for mechanical draft dry towers will be more severe
than those of wet cooling towers because of increased air flow requirements.
And, the aesthetic impact of natural-draft dry towers, which would be much
taller than a wet natural draft 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 in
the order of 20% more than a once-through system and 15% more than a wet
cooling tower system. Dry cool1ng towers now being used for European and
African steam cycle plants of 200 MW or smaller capactities in areas of cool
climates and winter peak loads. The use of dry towers to meet cooling
requirements of larger .facilities with summer peak loads requires new turbine
designs to achieve optimum efficiencies at the higher backpressures imposed by
use of dry cooling systems.
Wet-Dry Mechanical Draft Cooling Towers
In this combination tower, a dry cooling section is added to 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
F.9
adjustable louvers used to control the two air flows (Figure F.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 temperatures (e.g., 35°F). Such are expected to operate as
11 wet only 11 units in summer. Thus, water would be conserved only in winter.
The units would be operating efficiently throughout the year and aesthetic and
environmental impacts would be reduced.
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. This combined wet-dry system
can be of great advantage to plants in geographical locations where the
incremental contribution of cooling tower moisture to the atmosphere could
1ncrease the occurrence of fog to an unacceptable degree. The potential for
fogging and icing conditions exists throughout the Railbelt region. The
wet/dry cooling towers therefore reprPsent the preferred alternative from an
environmental point of view for the Railbelt.
F.lO
FIGURE F.4. Mechanical Draft Wet-Dry Cooling Tower
F .11
APPENDIX G
FUEL AVAILABILITY AND PRICES
Many of the technologies discussed in the report rely on fossil fuels
(oil, gas, coal, peat) and renewable fuels such as municipal waste and
biomass. The future availability and prices of these fuels is essential to
assessing each technology from the standpoint of both supply and
conservation.
Each of the various fuels now have different prices, even if reduced to
dollars per/million Btu (MMBtu). Price differentials are expected to continue
in the future, although the differentials between fuels may change markedly
with time.
Each fuel must be addressed separately, with recognition of the Railbelt
region•s geographic differences and appreci~tion of the factors that determine
prices. A set of preliminary reports on these issues is planned for
completion in June 1981, with the expectation of minor modifications in
s·ubsequent months. This appendix summarizes preliminary findings.
NATURAL GAS
Natural gas is currently the predominant non-transportation fuel for both
direct end-use and electrical power generation in the Cook Inlet Region. The
cost of gas to the electric utilities now ranges from about 24 to 109¢/MMBtu
for use in combustion turbines and from $1.55 to $2.46 per MMBtu for
residential direct end-use. These prices are the lowest in the United States
primarily as a result of long term contracts signed when there was an excess
of natural gas and the producers, lacking a major market outlet, faced a
"buyer•s market."
This price situation is not expected to continue in the future. Under
the most optimistic (from the consumer•s point of view) conditions, rapid
increases in natural gas prices may occur about 1990, although it is quite
possible that gas prices will increase markedly in the mid-1980s.
G.1
Natural gas is not currently available in the Interior regions
(Fairbanks, Ternana Valley). Should North Slope gas become available in the
mid to late 1980s, its city gate cost (made up of well head price plus
conditioning cost plus a share of transmission tarrifs) is expected to be far
higher than in Cook Inlet--somewhere near $6.00/MMBtu. Depending on many
variables, its cost may be competitive with liquid fuels.
PETROLEUM PRODUCTS
Distillate fuel oils (such as home heating oil, diesel fuel, and
combustion 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.
Petroleum products are generally sold under short-term contracts on a lot
bid basis. Long term contracts are virtually nonexistent. Recent fuel oil
prices in $/MMBtu are as follows:
Utility Combustion Turbine Fuel
Home Heating Oil (#2)
Anchorage
6.99
8.00
Fairbanks
6.22
8.36
Unlike natural gas and coal, which are subject to either regulation or
marketability constants, petroleum product prices are now directly related to
the world price of crude oil with appropriate adjustments for locational
transportation and refining costs.
We believe the price of petroleum products will increase in real terms
(i.e., over and above inflation) at about 3% per year on the average, and a
sound body of economic theory (that OPEC seems to be acting on or at least
striving toward) seems to support this forecast. This forecast of an annual
3% increase assumes that the Persian Gulf or other major producing regions do
not become involved in major political upheavals or war.
G.2
PROPANE AND BUTANE
If a petrochemical plant is constructed in Alaska based on natural gas
liquids (ethane, propane, butane) extracted from North Slope natural gas, then
large quantities of propane and butane would become available. These
products, known as low-pressure or liquified petroleum gases (LPGs) or "bottle
gas," are generally not shipped in large quantities except by pipeline or by
rail and truck. Specially designed ships have recently been developed for
international trade. Since the quantity of these products originating in
Alaska would be large, shipment out of the state would be required and the
price in Alaska will be rough by equivalent to the price paid in the final
market (ca. California) less the cost of ocean shipment.
COAL
Sub-bituminous coal is a major resource in Alaska. It currently supports
electrical power generation and some direct space heating in the Interior.
The only current major coal mining activity is located near Healy, supplying
the Fairbanks utilities as well as military installations. Coal reserves in
that region appear ample for many decades to come. Coal from the Healy mine
is currently priced at about $1.25/MMBtu.
Little coal appears to be used in the Cook Inlet region. However,
research conducted at Battelle-Northwest suggests that there is an excellent
chance for a "world scale" mining operation to develop in the next few years
in the Beluga region, with the primary impetus being the rapidly growing coal
market in East Asia. Such a large-scale development could make coal available
at mine mouth at about $1.00/MMBtu for power generation in the Cook Inlet
region. If an export mine at Beluga is not developed, then coal sufficient to
support a mine-mouth generation plant could still be provided, but at a
substantially higher cost. Coal from the Healy mine could be supplied to the
Cook Inlet region via the Alaska Railroad. The cost of such a supply system
will be estimated as part of the Railbelt Electric Power Alternatives Study.
Alternative sources of coal in the Railbelt exist in the Natanuska Valley
(Evans Jones Mine now abandoned) and on the Kenai Peninsula. The Natanuska
G.3
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.
Future coal prices are not expected to escalate substanitally in real
terms and will be established under long-term contracts probably with
provisions for labor cost adjustments.
PEAT
Peat is an abundant resource in the Matanuska and Susitna Valleys, on the
Kenai Peninsula and in the Fairbanks region. 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.
At the present time, no estimates of peat costs including harvesting and
preparation have been developed for Alaska conditions.
WOOD
Wood is used extensively in the non-metropolitan areas of the Railbelt
for space heating. It is also used as a reliable back-up fuel.
Wood costs are currently on the order of $5.00 to $6.40/MMBtu.
Wood is generally not regarded as a primary fuel for electric power
generation unless substantial quantities of wood wastes are available from
logging and sawmill operations. The main deterrent is the relatively high
cost of harvesting and transporting a high bulk, low Btu content fuel.
MUNICIPAL WASTE
Municipal waste is a candidate for central station fuel in urban areas
where collection already takes place and disposal occurs at relatively few
landfill sites. The solid waste materials currently generated in Greater
Anchorage have been estimated to contain sufficient energy to fuel a 20-MW
power plant. However, the economics appear marginal relative to coal-fired
plants. This will be further investigated.
G.4
SYNTHETIC FUELS
There is considerable interest in the development of synthetic fuels
derived from low-cost and abundant reserves of coal and, to a lesser extent,
peat. A number of processes are in the research and development stage and a
few (e.g. low Btu gasification of coal) are nearing the commercial
demonstration scale. These are capitally intensive projects and their
economic success is primarily dependent on their ability to displace oil and
natural gas at world prices and to achieve economies of scale in large
installations. In order to reduce transportation costs, such plants are
expected to be located at mine mouth or near the location of the basic
resource.
Two firms, Placer Amex Inc. and Cook Inlet Region Inc., are studying the
possibility of gasification of Beluga's low-Btu 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 gasificaton operation.
HYDROGEN
If surplus electrical generating capacity from underwater conventional
hydroelectric or tidal systems is available, hydrogen could be produced by
electrolysis of the surplus electrical energy that might otherwise be lost.
New hydrogen could be stored and used at a later date in fuel cells to
generate electrical energy.
Alternatively, hydrogen could be supplied as a gas in a manner similar to
natural gas for direct end use. Due to the physical and chemical nature of
hydrogen, it is unlikely that existing natural gas distribution systems or
appliances could 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 there is little research and
development activity aimed at commercial applications.
6.5
APPENDIX H
AESTHETIC CONSIDERATIONS
This appendix presents methodologies for assessing aesthetic
considerations, specifically visual, noise, and odor impacts. The objective
of these methodologies is to provide a comparison of the typical aesthetic
impacts of the candidate electric energy technologies. The magnitude of
aesthetic impacts from the candidate electrical generating technologies are
assessed in this appendix.
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 1mpact 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
components should be defined, including both man-made 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 of the landscape such as
form, line, color, and texture of the landscape should be used as a basis for
description. Visual quality criteria 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
H.l
components is caused by the way change is exposed to the viewer. Criteria
should be developed to assess visual sensitivity and may include viewing
distance, viewer location, and viewing frequency. The visual quality of each
landscape unit should be evaluated with attention paid to areas that are
vulnerable to any man-made changes.
The third phase involves identification of the elements of the project
that cause impacts and their effect on viewers. The various attitudes and
values of the individual viewers should be taken into account as well as
differences in the location 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 through
mapping the areas from which the power plant and associated project elements
could be viewed, and evaluating these areas with respect to 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 should address
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 the introduction of a power plant into the landscape 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
1 i--i-h 1 -• ~ -T hl U 1 e.ec ... r1c energy ..,ec .. no.og1es are summar1zeu 1n saute~~ . .~.. 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.
H.2
TABLE H.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.
Geothermal 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 man-made structure into sea-
scape. Altered wave pattern.
Wind Larqe 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.
H.3
Based on the visual concerns of each technology, it can be concluded that
off-site impacts will be significant for coal-fired steam electric,
geothermal, nuclear, pumped-storage, solar, large-scale hydroelectric and
tidal, and wind farms (Table H.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,
identifying potential sources of noise impacts, predicting of noise levels,
and determining of 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 should be collected throughout one
year in order to account for seasonal variation. In addition, data are
collected throughout the day in order to determine day/night average sound
levels. Isolines are drawn to indicate the decibel levels at various
distances. Other data that should be collected from the survey include wind
speed, temperature, and relative humidity, as these affect noise levels.
Potential sources of noise impacts from power plants should be
identified, including pre-construction, construction, and operating
activities. Noise predictions 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 should be determined in a
controlled environment without wind attenuation or topographical shieldings.
Noi~e impact criteria should be estabished based on the objectives of
protecting people from hearing loss and from negative health and welfare
effects. The Occupational Health and Safety Act (OSHA) regulates on-site
sources of noise to protect personnel. Off-site noise, which is reguiated
through the Noise Control Act, can affect residences, commercial activities,
wildlife habitats, and domesticated animals. Maximum noise levels that are
H.4
established for various categories of land uses should be considered in the
siting and plant design processes.
An increase in noise levels due to power plant construction and operation
should be calculated at various receptor areas. The noise levels of the
various power plant components should be evaluated for their cumulative
impact. Mitigation measures should be identified as well as noise sources
that are difficult to mitigate. Receptors and noise levels should then be
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 impacts. Noise related impacts
generally associated with each of the various technologies are summarized in
Table H.2. For those facilities in which noise could be a potential problem,
it may be necessary to site the vents and turbines well away from residential
or commercial areas in order to comply with ambient noise regulations.
Consideration should be made 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 (U.S. Environmental Protection Agency 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.
H.5
TABLE H.2. Magnitude of Off-Site Aesthetic Impacts
from Power Plant Construction
Technology Visual Noise Odor
Coal
(20 MW) Moderate Minor Minor
(200 MW) Significant Moderate Minor
Oil and Natural Gas
(10 MW) Minor Minor Minor
Biomass
(25 MW) Moderate Minor Significant
(Municipal
Waste)
Geothermal
(50 MW) Significant Moderate to Significant
significant
Nuclear
(1000 MW) Significant Minor Minor
Combustion Turbine
(70 MW) Minor Moderate to Minor
significant
Combined Cycle
(200 MW) Moderate Minor to Minor
significant
Diesel
(50 KW) Minor Minor to Minor
significant
(15 MW) Minor Minor to Minor
significant
Fuel Cells
(10 MW) Minor Minor Minor
Hydroelectric
( 2.5 MW) Moderate to Minor Minor
Significant
Pumped-Storage
(100 MW) Significant Minor Minor
Cogeneration
(25 MW) Minor to Minor Minor
Moderate
H.6
TABLE H.2. (contd)
Technology Visual Noise Odor
Tidal
( N/A)( a) Moderate to Minor Minor
Significant
Wind
(2 MW) Minor Minor Minor
(100 MW) Significant Moderate Minor
Solar
(10 MW) Significant Minor Minor
(a) Rated capacity will not alter basin design.
Since an odorant may be a complex mixture of many components in extremely
high dilution of air, a chemical analysis is not a sufficient measurement of
odor. Noxious odors must be diluted in order to be evaluated by a panel of
judges. Since odor is a logarithmic function of the stimulus, it is
appropriate for the concentrations of the odorous substance to be distributed
along an exponential scale. The substance should 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 11 extreme 11 • 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
intensity, conditions under which the substance will be odorous or odorless
should be 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 dispersal to avoid adverse impacts.
H.7
The approach to odor control of inorganic gases such as hydrogen sulfide
and organic vapors such as hydrocarbons is to reduce the odorant in
concentration through diluting the odor by ventilation or dispersal, or
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 needed to
be rid of the odor may be considerably greater than is predicted by the
calculations.
Since the dispersal of gas from a stack can be calculated theoretically,
it should be possible to predict the maximum level of odor that can be emitted
from a stack without causing a nuisance. If the actual rate is higher than
the calculated value, then the dispersal should be increased {by raising the
stack) or the concentration should be decreased {by an abatement device), or
both.
Off-site 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
while the odor impacts of the other technologies should be minor.
H.B
APPENDIX I
COST ESTIMATING METHODOLOGY
The conceptual capital cost estimates and operating and maintenance
est1mates 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 and then applying a location
adjustment factor for the construction and operation of a similar plant in the
Alaska Railbelt. Average 1980 costs were developed through a survey of powP.r
plant costs for recently completed facilities, and projected cost estimates
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. In light of the fact that only a few of the
technologies are presently represented in the Railbelt region, costs for
facilities developed in the contiguous U.S. were utilized to maximize the use
of the large available data base and to ensure cost comparability among
technologies.
Location adjustment factors were developed based upon an analysis of
considerations which contribute to higher Alaskan construction costs. Cost
adjustment factors developed by the Department of the Army (1978) were also
used. Factors which are the prime contributors to the higher construction
costs in Alaska include remoteness, limited accessibility, short construction
season, and severe climatic conditions. In the Railbelt region, for example,
there is but 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 thP. long summer day also adds to the cost of construction. Workers
receive overtime pay for working a 60-hour week instead of the traditional
40 hours.
1.1
The Department of the Army has developed cost adjustment factors for
numerous locations within the United States and many foreign countries. The
data was developed from bid experience and is intended for use as a guideline
in the preparation and review of conceptual cost estimates for budgetary
purposes. Adjustment factors identified for specific Railbelt locations
include:
Area
Alaska (General)
Anchorage
Elmendorf AFB
Fairbanks
Fort Greeley (Big Delta)
Kenai Peninsula
Location
Adjustment
Factor
1.32
1.7
1.90
1.9
2.2
2.1
These location adjustment factors reflect the average statistical
differences 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 and is assumed to have a factor
of 1.00.
Based upon these considerations, location adjustment factors of 1.4 to
1.9 were utilized in this study to develop capital cost estimates while a
factor of 1.5 was used for operating and maintenance cost estimates. Values
at the upper end of the range were utilized for labor intensive technologies
requiring extended construction 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 combustion turbines and diesel facilities.
The assignment of an adjustment factor also included a consideration of the
potential site locations of the technology in the Railbelt region.
While the costs generated through the use of these adjustment factors
provide order of magnitude estimates suitable for a comparative decision
I.2
making process, it should be realized that limitations exist when using only a
single adjustment factor. For capital cost estimates associated with the
construction of a power plant facility, there are actually three factors
involved (equipment, material, and labor) and a different multiplier 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,
operating and maintenance 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 catagories.
The development of adjustment factors associated with each of the above
categories requires additional, more detailed study which is beyond the level
associated with these technology profiles. The use of a single adjustment
factor provides conceptual, order of magnitude cost estimates suitable for a
comparative decision-making process.
I.3
APPENDIX J
SYNTHETIC FUEL TECHNOLOGIES
A number of the technologies described in this report operate only on
liquid or gaseous hydrocarbon fuel. Among these technologies are combustion
turbinPs, combined cycle plants and diesel-electric plants. Other
technologies, including steam-electric plants and fuel cells, will accept
liquid or gaseous 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
processes which synthesize liquid or gaseous hydrocarbon fuels from coal.
These processes are considered within the scope of this study because of the
availability of substantial coal resources in the Railbelt region (see
Appendix G).
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 thR English economy in the 18th century. These distillation
gases contained about 500-600 Btu/ft 3 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: 11 town
gas 11 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, Franze Fischer,
Hans Tropsch, Mathias Peer, and other notable German scientists, a range of
process types and products has been developed.
The principles employed are conceptually simple, and are varied depending
upon the products sought. Coal is a heterogeneous solid substance with
hydr~gen/carbon (H/C) ratios of about 0.5 to 0.8 depending upon rank. This
contrasts 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
J.1
larger than the molecules of liquid or gaseous fuels. In order to accomplish
conversion of 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 (indirect liquefaction through the
production and reaction of synthesis gas, a mixture of CO and H2).
Simultaneously, the coal molecule is fragmented into smaller units. While
some of the coal convers1on reactions are exothermic (heat releasing), most
are endothermic (heat consuming). 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
(e.g., 150 Btu/ft3), medium Btu gas (e.g., 350 Btu/ft3), and high Btu gas
or substitute natural gas (e.g., 900-1000 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
ind1rect liquefaction such as the Sasol I and Sasol II plants using the
Fischer-Tropsch process. Details of these processes are presented in
subsequent paragraphs.
SITING REQUIREMENTS
Synthetic fuel plants are, for the most part, similar to large
petrochemical complexes. Table J.1 gives scale factors for such plants by
syn-fuel type. Due to the large scale of these plants, siting requirements
are strongly dependent upon the economic availability of the coal resource.
Land requirements for typical synthetic fuels plants are measured in
thousands of acres (not including the coal mine). The land must provide 30-90
days coal storage, land for the primary facility itself, land for ancillary
facilities such as an on-site power plant and/or a cryogenic oxygen separation
plant, and land for product storage. The Modderfontain site in South Africa
(Sasol II), for example, exceeds 12,000 acres.
The site must have transportation facilities for moving coal to the
fac1l1ty if mine-mouth sites are not available, and for transporting the
J.2
TABLE J.l. Typical Sizes of Coal Conversion Facilities
Facility Daily Coal
10€>
Oail~ OutEut
TyEe Consumption (Tons) Btu As Product
Producer Gas (Low Btu Gas) 40 -800+ 680-12,800 4.5-85+ X 106 SOCF
Subst1tute Natural Gas 20,000 250,000 250 x 106 SOCF
Synthetic Crude Oi 1 20,000-22,000 330,000 50,000 bbl
Methanol 28,000 2 0,000 11,000 tons
Synthetic Motor Fuels
(Fischer-Tropsch) 35,000 250,000 42,000 bbl
Source: Sl1epcevich et al. 1977.
product from the facility. The only exception to the latter requirement is
low Btu gas, which must be used on-site due to the expense of transporting the
low energy content gas.
The site must have access to copious quantities of water for process
cooling and other requirements. Water serves as a source of hydrogen for
altering the H/C ratio in the water gas shift reaction. Water also is the
sink for waste heat generated by the exothermic reactions. Table J.2
identifies water requirements as a function of end product. Water
requirements for indirect liquefaction (methanol, Fischer-Tropsch) ore similar
to those for SNG production. Cooling water requirements are the most
significant; however, they can be minimized by use of air-to-air heat
rejection systems. However, water requirements of 4 million gal/day may be
considered typical values, and sites must be selected with such quantities (or
more) being available.
Electricity should be available, unless on-site generation is used as
would probably be the case in the Railbelt area. Where on-site generation is
used, land and water requirements will escalate accordingly.
J.3
TABLE J.2. Water Requirements for Coal Conversion Processes
End Product
Low and Medium Btu Gas
Substitute Natural Gas
Synthetic Crude Oils
Water Requirements (gal/106 Btu)
Process Cooling Blowdown
2-5
3-13
1-2
20
16
9
4
3
2
Source: Anderson and Tillman 1979.
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.
Gasification
In low Btu gasification, coal is fed into a fixed bed, entrained bed, or
fluidized bed reactor. There it is reacted with air and steam. The air is
used to combust a portion of the coal, thus supplying heat for the endothermic
pyrolysis and gasification reactions. Steam is used to drive key gasification
reactions such as the steam-carbon, water-gas shift, and methane reformation
reactions. The steam-carbon reaction converts solid carbon molecules to
carbon monoxide, while also generating hydrogen gas. The water-gas shift
increases the hydrogen concentration at the expense of carbon monoxide.
Methane reformation converts methane (CH 4) to 1 co and 3 H2•
The gas resulting from this process contains about 50% nitrogen due to
the use of air and has a heating value of approximately 150 Btu/SDCF. It is
"wet" and 11 dirty11
, and must be burned immediately in a boiler to preserve the
sensible heat of the gas.
The fundamental difference between low and medium Btu gas production is
the oxidant used to generate heat for driving endothermic reactions. Medium
J.4
Btu gasifiers employ cryogenically separated pure oxygen. Thus, nitrogen gas
is not part of the product 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
on-site. While it may be burned as a fuel, it may also be used as a feedstock
for the production of chemicals. Figure J.1 shows a schematic of a medium Btu
gas plant. By way of comparison, low Btu gasifiers do not have the oxygen
plant with its attendent energy expenditures. Table J.3 shows typical product
gas composition for various gasifiers producing low and medium Btu gaseous
fuels.
Thermal efficiencies for gasification can be defined as fuel value of
product gas divided by total energy and fuel input (including electricity used
for 02 production). Typical values are in the 75-90% range depending upon
gasifier design, product type, and extent of waste heat recapture.
Liquefaction
Indirect liquefaction begins with medium Btu gas, as shown in Table J.3
for 02 blown gasifiers. The gas can be shifted to a volumetric H2/CO
ratio of 2:1 and reacted over a catalyst to produce methanol (CH 3oH). This
process is essentially commercial today, and is shown in Figure J.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 J.3.
The thermal efficiencies of indirect liquefaction are in the 40 to 45%
range depending upon severity of treatment, final product, plant design, and
the specifics of coal composition.
Direct (hydrogenation) liquefaction processes treat coal under elevated
temperatures and pressures with hydrogen. Catalysis may or may not be
employed to aid in fracturing the molecule and, more importantly, donating
J.5
Medium Btu ..
Gas ..
Gasifier
·I Coal Preparation I Coal .... 02 : ....-
··~
Ash N2 .... Steam ..
Steam • Water
Plant Fuel/Heat •
Cryogenic
Air ... Separation ..
Plant
FIGURE J.1. Flowsheet of Medium Btu Gas Plant
hydrogen to the fragments. Figure J.4 shows direct hydrogenation by the
solvent extraction process; Figure J.5 shows a flow sheet for catalytic
hydrogenation.
Products resulting from direct hydrogenation include syn-crudes, boiler
fuels, and naptha. Thermal efficiencies are typically in the 60-65% range.
Direct hydrogenation is at the pilot plant scale of development and
commercialization is expected within the next 10-15 years.
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
South Africa and other countries, and from pilot plant experiences. Costs
are, therefore, highly uncertain. Estimated capital costs are presented in
J.6
TABLE J.3. Gas Composition and Higher Heating Values
from Various Coal Gasifiers
Higher
Heating
Composition (Percent Volume} Value
Gasifier co C0 2_ H -2-CH 4 N -2-Other (Btu/SDCF)
Wellman-Galusha 28.6 3.4 15.0 2.7 50.3 150
(Air Blown)
Lurgi (Air Blown) 13.3 13.3 19.6 5.5 48.3 150
Koppers-Totzek . 52.2 10.0 36.0 1.5 300
(02 Blown)
Lurgi (02 Blown) 16.3 31.5 39.4 9.0 2.4 0.8 350
Table J.4. Total 1980 capital costs for a 50 x 103 bbl/day coal
l1quefaction plant 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 operation and maintenance costs are estimated at
about $330 million (not including depreciation) for a 50,000 bbl/day refinery
(Tillman 1981).
World oil prices would have to rise to $60/bbl ($10/106 Btu) for coal
liquifaction preocesses to be economicly competitive at current estimates of
capital and O&M costs of liquifaction plants (Tillman, 1981). This is about
double the current world price of oil (Perry, 1980). Because of the higher
thermal efficiencies and lower capital costs of coal gasification costs, coal
gasification would be competitive at much lower prices. Values frequently
quoted range from $5-6/106 Btu.
J.?
Air
Separation
'-----,r------l Recycle
Oxygen Tars and Oils
-----L----. Medium .---------.
Coal Gas
P . ~ Gasification !--
Btu Gas Methanol Methanol
reparation Preparation Synthesis
Steam
Fuel Gas Steam/Power
Manufacturer .....,_....-j Plant
Air
FIGURE J.2. Methanol Production Flowsheet
Air LPG
Separation I Oxygen Medium Gasoline
Gas Btu Gas Oils _r Gasification 1-Synthesis Clean-up Chemicals ' Coal I Preparation -
Steam Tar, Oil, Naphtha
~ Fuel Gas Steam/Power
Manufacture Plant
Air
FIGURE J.3. Fischer-Tropsch Synthesis Flowsheet
J.8
Air
Separation
Oxygen
Steam
r-Acid-Gas t--Gasification ~
Removal
Syngas
Hydrogen
Production
Coal Coal Product
Preparation ~~ Dissolving ~ Flashing
r1 Hydrotreating
Naphtha
Plant
Fuel Gas Acid-Gas
Removal 1-1---.....
.._----------~: Filter ~~---~~ Distillation
Light
.-----...J...-,1 Fuel Oil
Hydrotreater J
I
FIGURE J.4. Solvent Extraction Process Flowsheet
J.9
Heavy
Fuel Oil
Coal
Preparation
Air
Separation
Plant Fuel Gas t
Gas Treating
Light Oil
1
Coal
Hydrogenation
Liquefier
Oxygen Hydrogen
Production
~
Steam
Naphtha
.-------------Boiler
Product
Distillation
Solids
Separation
Char
Fuel
FIGURE J.5. Catalytic Hydrogenation Flowsheet
TABLE J.4. Capital Costs for Coal Conversion Facilities
( 1977 Do 11 ars )
Process
Low Btu Gas
Medium Btu Gas
Methano 1
Fischer-Tropsch
Solvent Extraction
Catalytic Hydrogenation
Capital Cost
$200/106 Btu Capacity
$350/106 Btu Capacity
$23,000-$30,000/Bbl-Day
$21,500-$28,000/Bbl-Day
$16,500-$21,500/Bbl-Day
$15,500-$20,000/Bbl-Day
Sources: Sliepcevich et al= (1977); Anderson and Tillman
(1979).
J.10
APPENDIX K
SELECTION OF CANDIDATE ELECTRIC ENERGY TECHNOLOGIES
MAGNETOHYDRODYNAMIC GENERATORS
Technology and Siting Requirements
Magnetohydrodynamis (MHO) is an energy conversion technology that has the
potential to increase the efficiency of electrical generation plants from
about 84% to 48% (Corman & Fox 1976).
In an open cycle MHO generation system, fossil fuel is burned at a
sufficiently high temperature so 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 passed through a magnetic field, this produces an electric current
in the gas. The current (DC) can be removed directly with metal rods or
"electrodes."
The d-e output of the MHO channel is converted to ac in solid state
inverters (Corman & Fox 1976). The gases exit through a series of heat
exchangers and a steam generator, which drives an a-c generator.
Seed material K2co 3 is used to both increase conductivity and tie up
sulfur as K2so 4 • The seed recovery system and integral clause plant
converts K2so 4 to seed material plus elemental sulfur. Problems which may
delay implementation of MHO technology include predicted poor forced outage
rate, short life expentancy, inflexible operation (difficult at minimum load),
difficult operation and control, corrosion problems, poor potential for
retrofit (Corman and Fox 1976).
Current Status of Development
A 250 hr 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 Bute, Montana.
K.1
It was estimated in 1976 that a commercial MHO facility could be
operational by 2003 (Corman and Fox 1976). In an International Energy Agency
study, the reference start year for a coal-fired MHO electric power plant was
2005 (IEA). However, funding of MHO has been cut from $60.5 million in
FY 1981 to zero in 1982. Confirmation of the engineering feasibility of MHO
and commercial demonstration will become the reasonability of the industry
(DOE 1981).
Applicability to the Railbelt Region
The time scale for development of commercial MHO conversion systems is
not consistent with the time frame of the Alaska Railbelt Electric
Alternatives study.
An open cycle MHO facility would be located at a large central
fossil-fired power plant. Gaseous emissions of NOx and 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 consume only 60% as
much make-up water as a conventional steam plant, and use less than 40% of the
total water requirement of a conventional plant (Corman and Fox 1976).
FAST BREEDER FISSION REACTORS
Technology and Siting Requirements
A fast breeder reactor (FBR) is a facility designed to generate
electricity by using the heat produced by controlled nuclear fission of
plutonium. A breeder produces more plutonium from uranium than it consumes.
When isotope 238u (which constitutes 99.3% of natural uranium) in the fuel
absorbs a neutron, it decays to 239pu, which is the main energy source for
the breeder. The heat generated by fission is removed by the liquid sodium
coolant in the primary loop. Heat is exchanged to an intermediate sodium
loop. From the intermediate coolant loop, heat is exchanged to water coolant
in the steam generator. At that stage, the steam cycle is similar to that of
any other conventional thermal power plant {fossil or nuclear).
The overall thermal efficiency of an FBR is slightly higher than that of
a light water reactor {LWR) because it operates at higher temperature. The
product of a comercial breeder facility would be about 1000 MWe, baseload
power. K.2
Siting considerations are the same as those for conventional nuclear
plants. These include adequate water available for cooling, geologic and
seismic stability, and 100-400 acres of land remote from a large population
center. In addition, access to reprocessing facility is required by an FBR.
Impacts from a breeder plant, like any large thermal power plant include local
impacts during construction, heat release to the environment and fog created
by cooling towers.
A principal problem for breeder development is in the fuel cycle.
Reprocessing and facrication facilities for breeder fuel must be built for
continuing breeder operation. Fuel reprocessing provides for recovery and
purificaton of plutonium contained in the spent fuel, so it can be recycled.
Fuel fabrication prepares the recovered fuel for recycle in a power plant.
Current Status of Development
Current U.S. experiene with breeders is being acquired at the Fast Flux
Test Facility (FFTF) which achieved full power in December 1980. The reactor
capacity is 400 MW thermal, approaximately equivalent to 133 MWe, but is not
being used for generation of power. The Clinch River Breeder Reactor (CRBR)
will generate 350 MWe. The CRBR has been restored to the FY-1982 DOE budget
(DOE 1981).
The conceptual Design Study reactor (CDS) is a 1000 MWe gross facility.
The proposed schedule calls for completion in 10 years. A 1200 MWe commercial
prototype reactor is expected to be op~rational about 2001, with the first
commercial plant to be in the 2006-2023 time frame (DOE 1979).
Applicability to the Railbelt Region
Breeder reactors will not be established on the commercial market by the
year 2000, and are thus out of the time considerations of this project.
FISION REACTORS
Technology and Siting Requirements
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
K.3
heavy isotopes of hydrogen, deuterium (D) and tritium (T) are employed in OT
fusion, the first likely commercial candidate. The reaction is as follows:
io + IT + plasma energy ~He + 6n + fusion energy
Deuterium is present in water in sufficient quantities to be available for
millions of years. The other f~el atom, 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
(Dingee 1979) via an intermediate heat extra or possibly closed-cycle MHO.
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 fission plant. A site should be near a load
center, with cooling water available, satisfactory geology and seismology,
transportation facilities to burrial site for solid radioactive wastes. In
addition, large land area is required to preclude effects on the public of
magnetic fields, and interference on electtrical and communication systems.
The inventories of tritium 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. But large heat releases and fog acreated by
cooling towers may have significant impact on the siting of the plant.
Current Status of Development
Energy breakeven requires the product of confinement time (sec) and
density (ions/cc) to be greater than 200 trillion at a temperature over
100 million°F. No fusion device has yet to reach "breakeven" --where
fusion energy release is just equal to the energy supplied to run it.
expected that breakeven will first be reach by Tokamak Fusion Test Reactor
sometimes in 1983 (Blake, 1980).
K.4
Applicability to the Railbelt Region
This time scale is not consistent with the Railbelt Electric Energy
Alternative Study.
OCEAN CURRENT ENERGY CONVERSION
Technology and Siting Requirements
There have been a number of proposals for the extraction of power from
ocean currents. These are, in principal, relatively simple
installations--such as turbines and paddle wheels (Isaacs and Schmitt 1980).
DOE has supported preliminary studies of a large ducted turbine for ocean
current energy conversion. The device is an undersea, moored, ducted turbine,
driven by current flow kinetic energy, which drives electrical generators and
transmits power to shore with a sea-floor cable. The structure envisioned is
on the order of 200 to 300 feet in diameter, and has a rotational speed of
1 RPM. The proposed structure would be of hollow aluminum construction. An
individual unit would provide 75 MWe (Lissaman et al. 1980). The designers of
this device have proposed mooring 132, such turbines in the Florida current to
deliver 10,000 MWe to the Florida power grid.
The Florida current of the gulf stream is the only candidate for U.S.
Production of Energy from ocean currents (Booda 1978). Even a major current
has very low energy density, equivalent to about 5 em of water head, or about
1000 times lower than for thermal gradients. 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
6 to 8 times that of the Alaska current.
The Impacts of ocean current power extraction include
(No serious impacts identified --look for ref.)
K.5
Status of Development
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 it was projected that ocean turbines could be commercialized by
1999. However, that assumed that DOE_funded work would continue and a
full-scale prototype would be complete in 1985. Since Ocean Energy systems
has no funding for FY1982 and beyond (U.S. DOE 1981) the development of ocean
current energy conversion is in doubt.
Applicability to the Railbelt Region
The future of ocean current power in the U.S. Is uncertain at this time.
Apparently, it will not be commercial in the U.S. by the year 200, which puts
it out of the time scale of this study. 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 TECHNOLOGY AND SITING REQUIREMENTS
Salinity gradient energy conversion is a large potential source of
power. The concept involves converting the energy of mixing of high and low
saline waters into usable energy.
The energy density of this process is equivalent to about 240 m of water
head, or an OTEC Plant with a temperature difference of 23°F (Isaacs and
Schmitt 1980). The energy available represents a theoretical power of 2 MW
for a flow rate of 1 m3/sec for a freshwater river flowing into the sea
(Olsson, Wick and Isaacs 1979).
There have been three approaches for extracting power from salinity
gradients: 1) osmotic exchange against a hydrostatic pressure, or
pressure-retarded osmosis; 2) the dialytic batter, or inverse electrodialysis
(Isaacs and Schmitt 1980). and 3) vapor exchange between two solutions or
inverse vapor.
Pressure-retarded osmosis uses the osmotic pressure gradient (about
23 atm) across a semipermeable membrane which separates seawater (at 35 parts
K.6
per thousand salinity) and freshwater. To convert the osmotic pressure, one
releases the pressurized solution through a hydroturbine (McCormick 1979).
This concept requires large amounts of fresh water, and must be sited at a
river.
The dialytic battery is made of anionic-permeable and cationic-permeable
membranes in a battery type container. Salt water is passed between alternate
membrane 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,
prefereably at elevated temperatures. Due to lower vapor pressure of salt
water, water vapor will transfer from fresh water to salt water in an
evacuated chamber. Power can be extracted if a turbine is placed in the vapor
flow between the two solutions (Olsson, Wick and Isaacs 1979).
The third scheme uses no membranes, but 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).
The energy density of a salinity gradient is a function of the
concentration differences. The energy density of a system of saturated brine
(260 partys per thousand) and fresh water is about 20 times greater than a
seawater (35 parts per thousand) and fresh water sy~tem (Isaacs and Schmitt
1980).
Energy densities for Alaskan salinity gradient resources would be
slightly lower than values presented because lower salinity of the sea water.
The salinity of sea water off alaska is 31.5-32 parts per thousand most of the
year (U.S. Department of the Interior 1970, p. 83) about 10% less than salt
water in the referenced experiments.
Status of Development
Salinity gradient energy conversion is in the experimental stage.
Salinity gradient research was conducted by DOE Under Ocean Energy System,
K.7
which will no longer be funded as of FY1982 (U.S. DOE 1981). Therefore, the
commercialization of this technology is uncertain at best.
Applicability to the Railbelt Region
Considering the current low state of development of salinity gradient
energy conversion technology and the funding situation, this will not be an
option in the time frame under consideration to meet Railbelt power
requirements.
SPACE PWER SATELLITES
Technology and Siting Requirements
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 consists of an array of
inclined planar solar panels 3 m wide in long continuous rows. Power is
converted from de to ac and stepped up to 500 kV for transmission (Brown
et al. 1980, p. 328). The microwave power transmission link cannot be scaled
down economically to powers less than a gigawatte (1000 megawatts) {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 capacity of 5 gigawatts.
The rectenna requires a large area of relatively flat land with an area
of low population density. Variables which exclude rectenna siting include
inland water, military reservations, population density, marshland, or
perennially flooded areas, interstate highways and unacceptable topography.
Potential exclusion areas include Indian reservations, national forests and
wild and scenic rivers. Other variables which impact 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, p. 127).
The Ground Receiving Station (GRS) should be near the load center, but
located to avoid radio interference. An optimum location would be a desert
area. A prototype assessment or environmental impact of siting and
K.8
construction of a GRS Used the California desert about 250 km north of
Los Angeles for baseline data (Bachrach 1980, p. 525).
The land area required is about 400 km2 at 350 latitude. At the
latitude of the Railbelt area, about 630, an area of about 1200 km2 would
be needed (Reinhartz 1980). Construction of a Ground Receiving Station in a
desert area at 360 is expected to require 25 months, with an average work
force of 2500. Approximately 450 workers would be required for 24-hours, 365
days per year operation (Bachrack 1980, p. 525). 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 dispoace existing land uses, totally
disrupt the ecology of the stie, and have great socioeconomic impact from the
immigration of construction workers. The most significant environmental issue
from satellite power transmission is long term exposure to low level
microwaves on telecommunication, particularly interference with defense
requirements (Valentino 1980).
Current Status of Development
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
commercial operation of power satellites in the year 2000 (Schwenk 1980). The
SPS assessment program has been completed, and the program is closed. There
is no SPS funding for TY1981 or FY1982 (Riches 1981). 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).
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Prospects for Railbelt Application
An SPS system does not currently appear to be a candidate technology for
supplying power to Alaska for several reasons:
-The time scale for development is uncertain; funding has been
discontinued indefinitely.
The projected size of generation system, 5 GWe (5000 MWe) is much
larger than demand forecasts for the Railbelt region.
The northern latitude location 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.
OCEAN THERMAL ENERGY CONVERSION
Technology and Siting Requirements
Ocean thermal energy conversion (OTEC) uses the temperature difference
between surface water and ocean depths to generate electricity. A schematic
diagram of a closed-cycle OTEC Plant is shown in Figure 1. A conventional
thermodynamic cycle is used with ammonia or propane as the working fluid. The
working fluid is boiled by the warm sea water, 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 feet deep
originates in the ARctic or Antarctic, and has a temperature of 39 to 44°F
(Booda 1978).
The efficiency of the OTEC closed-cycle is limited by Carnot efficiency
of a heat engine. The 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 hhave
to pump 30,000 cubic feet of sea water per second (Forbes et al. 1979).
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OTEC powerplants are suitable for tropical or subtropical seacoasts or
offshore regions. A minimum temperature difference of about 300F and depth
of about 2000 ft is required. Power would be transmitted to the load center
by de electricity in 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.
Status of Commercial Development
A demonstration of the feasibility of OTEC Has been performed by DOE.
The DOE budget for OTEC has been reduced from $34.6 million in FY81 to zero in
FY82. DOE considers it the responsibility of the private sector to develop
marketable systems once technical feasibility is established (U.S. DOE 1981).
A commercial prototype OTEC powerplant was envisioned about 1990
(Richards 1979). The reference start year for a commercial operation a
100 MWe ocean thermal gradient electric powerplant was taken to be 2000 in an
International Energy Agency study (IEA 1980). The commercial sector will
determine the actual development schedule for OTEC.
Railbelt Feasibility
Sites for OTEC plants are generally restricted to 200 north and south
of the equator (Booda 1978). OTEC power cannot be considered in alaska
because the concept depends on warm (800F) tropical ocean surface
temperatures. The mean surface temperature off the south coast of Alaska
varies from 420F in winter to 540F in summer (U.S. Department of the
Interior 1970, p. 83).
OCEAN WAVE ENERGY SYSTEMS
Technology and Siting Requirements
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
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efforts include a full-scale wave energy conversion program with the
International Energy Agency (IEA). The apparatus, known as "Kaimei," is a
cavity resonator system, shown in Figure 1. There are three air turbines on
the deck of Kaimei which have been designed and constructed in Japan, the
United Kingdom, and the United States. The turbines are excited by the air
motions above the rising and falling of the internal surface of the water, as
shown in Figure 2. Each turbo-generating system is designed to deliver 125 kW
in a 2 meter sea with a period of 6 seconds (McCormick 1979).
Another DOE-sponsored effort has been in wave-focusing systems. Wave
focusing is accomplished by four techniques: 1) radient wave interaction,
2) Fresnel-type focusing, 3) refraction, and 4) channeling.
Radient wave interaction occurs when a body is in resonance with the
incident wave. Fresnel-type focusing is done by a lens type structure which
causes wave diffraction or refraction. A refraction wave energy device called
DAM-ATOLL, which was developed at Lockheed, is shown in Figure 3. The device
is a submerged dome which causes incident waves to refract and focus on a
vertical axis turbine located at the center of the dome. The device, a
lenticular hump on the sea floor, could be produced 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). The U.S. wave energy program
has concentrated on wave focusing systems and the cavity resonator because
larger structures are not justified by the low energy density. Also, large
structures undergoing significant motions while moored at sea is the opposite
of standard ocean engineering practice (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 36oF temperature
difference (Isaacs and Schmitt 1980). Siting requirements will include
location in the ocean with consistent waves, near a load center. Such a
facility would probably be used as a "fuel saver."
The DOE considers only the northern half of the Pacific coast a promising
area. It is estimated that between 5 and 50 megawatts per kilometer of
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coastline could be generated (Booda 1978). The northern California and Oregon
coasts have waves of height 5 feet and over 20 to 30% of the time in spring
and winter, and 30 to 40% of the time in summer and autumn. Off the Alaskan
coast, the frequency of waves of height 5 feet and over varies from less than
5% in the spring to 10 to 20% in the fall (U.S. Department of the Interior
1970).
The potential impact impediment is navigation. How about scientific
effects, effects on marine life?
Status of Commercial Development
Currently, wve energy systems are in the developmental stages. Problems
requiring resolutin include the need to withstand large storm waves, corrosion
and fouling, energy storage and/or transmission, capital costs of fabrication
and installation (Forbes et al. 1979).
An International Energy Agency study assumed 1990 as the reference
starting year for commercial operation of a 2 MWe wave powerplant (IEA 1980).
Wave energy research programs have been supported by DOE and are dependent 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
FY1982 (U.S. DOE 1981), the fate of wave energy development is uncertain.
Applicability to the Railbelt Region
The coast of Alaska is not an optimum location for wave energy
powerplants, as shown by wave height/frequency statistics. In addition, the
development of wave energy technology is uncertain, and may not be available
in the time frame under consideration.
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