HomeMy WebLinkAboutAPA576Coal-Fired eam Elee rie
Power P an Iternatives
for the ai belt egion
of Alaska
Volume X I
Ebasco 5enkes nc:orporated
August 1982
IS
HD
9685
U6
R35
v.12
Prepared for t e Offic:e of the Go ernor
State of Alaska
Omslon of PoBey De elopment and Planning
and the Governor's Polic:y Review Committee
under Contrad 2311204417
LEGAL NOTICE
This report was prepared by Battelle as an account of sponsored
research activities.Neither Sponsor nor Battelle nor any person acting
on behalf of either:
MAKES ANY WARRANTY OR REPRESENTATION,EXPRESS OR
IMPLIED,with respect to the accuracy,completeness,or usefulness of
the information contained in this report,or that the use of any informa-
tion,apparatus,process,or composition disclosed in this report may not
infringe privately owned rights;or
Assumes any liabilities with respect to the use of,or for damages result-
ing from the use of,any information,apparatus,process,or composition
disclosed in this report.
'~i.:\E
A.L!'.;..PI{j\T:1 ,~.'f-'-",'-'Y Y':~~-~,~~-'-~~--'r
•
•
u.s"DbI~r"l'.G ...'L.,,-~.;:.._I.~_t"\"',-:
Coal-Fired Steam-Electric Power Plant
Alternatives for the Railbelt Region
of Alaska
Volume XII
Ebasco Services Incorporated
Bellevue,Washington 98004
August 1982
Prepared for the Office of the Governor
State of Alaska
Division of Policy Development and Planning
and the Governor1s Policy Review Committee
Under Contract 2311204417
Battelle
Pacific Northwest Laboratories
Richland,Washington 99352
Ho
C1 ,1/rr":::-\l.;\.__
~.'.j !"•:A \J'/
')~;,."-.1\~J
I ",
\.)I I d
ACKNOWLEDGMENTS
The major portion of this report was prepared by the Bellevue,Washington,
and Newport Beach,California,offices of Ebasco Services Incorporated.Their
work includes the Introduction,Technical Description,Environmental and
Engineering Siting Constraints,Environmental and Socioeconomic Considerations
and Institutional Considerations.Capital cost estimates were prepared by
S.J.Groves and Sons of Redmond,Washington,and reviewed by Ebasco personnel
of the E~asco Cost Estimating Department in New York City.Cost of energy
estimates were prepared by Battelle,Pacific Northwest Laboratories of
Richland,Washington.
iii
,
PREFACE
The state of Alaska,Office of the Governor,commissioned Battelle,
Pacific Northwest Laboratories (Battelle-Northwest)to perform a Railbelt
Electric Power Alternatives Study.The primary objective of this study was to
develop and analyze long-range plans for electrical energy development for the
Railbelt Region (see Volume I).These plans will be used as the basis for
recommendations to the Governor and Legislature for Railbelt electric power
development,including whether Alaska should concentrate its efforts on
development of the hydroelectric potential of the Susitna River or pursue
other electric power alternatives.
Preliminary assessment of pulverized coal-fired steam-electric plants
indicated that they may offer the potential for production of relatively low-
cost power in the Region with the advantage of plant sizes that would be com-
patible with the modest future additional electric-demand forecast for the
Region.For these reasons,pulverized coal-fired steam-electric plants of
200-MW rated capacity were selected for in-depth study.This report,
Volume XII of a series of seventeen reports,documents the findings of this
study.
Other power-generating alternatives selected for in-depth study included
natural gas-fired combined-cycle power plants,the Chakachamna hydroelectric
project,the Browne hydroelectric project,large wind energy conversion sys-
tems and coal-gasification combined-cycle power plants.These alternatives
are examined in the following reports:
Ebasco Services,Inc.1982.Natural Gas-Fired Combined-Cycle Power
Plant Alternative for the Railbelt Region of Alaska.Prepared by
Ebasco Services Incorporated and Battelle,Pacific Northwest Labora-
tories for the Office of the Governor,State of Alaska,Juneau,
Alaska.
Ebasco Services,Inc.1982.Chakachamna Hydroelectric Alternative
for the Railbelt Region of Alaska.Prepared by Ebasco Services
Incorporated and Battelle,Pacific Northwest Laboratories for the
Office of the Governor,State of Alaska,Juneau,Alaska.
v
Ebasco Services,Inc.1982.Browne Hydroelectric Alternative for
the Railbelt Retion of Alaska.Prepared by Ebasco Services Incor-
porated and Bat elle,Paclflc Northwest Laboratories for the Office
of the Governor,State of Alaska,Juneau,Alaska.
Ebasco Services,Inc.1982.Wind Energy Alternative for the
Railbelt Region of Alaska.Prepared by Ebasco Services Incorporated
and Battelle,Paclflc Northwest Laboratories for the Office of the
Governor,State of Alaska,Juneau,Alaska.
Ebasco Services,Inc.1982.Coal-Gasification Combined-Cycle Power
Plant Alternative for the Railbelt Region of Alaska.Prepared by
Ebasco Services Incorporated and Battelle,Pacific Northwest Labora-
tories for the Office of the Governor,State of Alaska,Juneau,
A1 ask a.
vi
SUMMARY
Substantial deposits of accessible and surface-mineable coal in the Beluga
and Nenana areas of the Railbelt Region of Alaska provide an opportunity for
the development of coal-based,electric-generating facilities to meet future
electric demand in the Railbelt Region.The purpose of this study is to
examine the technical,economic and environmental characteristics of pulverized
coal-fired power plants located in the Railbelt Region.Two locations were
selected for examination:a site in the Beluga area north of Cook Inlet,and
an alternative site near the community of Nenana,north of Denali National
Park.Coal for the Beluga site would be taken from proposed surface mines in
the Beluga coal field,and coal for the Nenana site would be taken from the
existing Usibelli Mine at Healy.
Conceptual plant designs were developed for each location.The plant
design selected was a 200-MW-capacity pulverized coal-fired steam-electric
power plant.Mechanical draft wet/dry heat rejection was utilized as was a
suite of flue gas controls sufficient to meet current New Source Performance
Standards.Coal delivery to the Beluga Station would be by conveyor or truck
from minemouth;delivery to the Nenana Station would be by unit train from the
Usibelli Mine.Power from the Beluga Station would be transmitted to a pro-
posed substation at Willow on the proposed Anchorage-Fairbanks intertie;power
from the Nenana Station would be transmitted to a substation located at Nenana
on the proposed Anchorage-Fairbanks intertie.
Cost estimates prepared for the two plants indicate an overnight capital
cost of 2050 $/kW for the Beluga Station and of 2010 $/kW for the Nenana
Station.Fixed and variable O&M costs for the stations were estimated to be
16.70 $/kW/yr and 0.6 mills/kWh,respectively.Using delivered fuel cost
estimates prepared elsewhere in the Railbelt Electric Power Alternatives
Study,busbar power costs were estimated.Assuming a 1990 startup date,
levelized busbar power costs were estimated to be 50 mills/kWh for the Beluga
Station and 55 mills/kWh for the Nenana Station.All costs are in January
1982 dollars.
vii
CONTENTS
ACKNOWLEDGMENTS
PREFACE
SUMMARY
1.0 INTRODUCTION
2.0 TECHNICAL DESCRIPTION
2.1 PROCESS AND AUXILIARY SYSTEM DESCRIPTION
2.1.1 Fuel Handling System .
2.1.2 Steam-Generator .
2.1.3 Turbine-Generator
2.1.4 Electrical Plant Designs
2.1.5 Heat Rejection System.
2.1.6 Condensate and Feedwater System.
2.1.7 Water Quality Control
2.1.8 Air Quality Control
2.1.9 Ash Handling System
2.1.10 Solid Waste Disposal System
2.1.11 Other Major Plant Equipment
2.2 FUEL SUPPLY
2.2.1 Nenana Station
2.2.2 Beluga Station
2.3 TRANSMISSION LINE SYSTEM.
2.4 SITE SERVICE~.
2.4.1 Access Roads
2.4.2 Construction Water Supply
ix
iii
v
vi i
1.1
2.1
2.1
2.6
2.8
2.11
2.13
2.17
2.18
2.21
2.25
2.26
2.27
2.28
2.29
2.29
2.30
2.32
2.36
2.36
2.37
2.4.3 Construction Transmission Lines
2.4.4 Airstrip
2.4.5 Railroad Spur
2.4.6 Landing Facility
2.4.7 Construction Camp Facilities
2.5 CONSTRUCTION
2.6 OPERATION AND MAINTENANCE
3.0 COST ESTIMATES
3.1 CAPITAL COSTS
3.1.1 Construction Costs
3.1.2 Payout Schedule
3.1.3 Escal ation
3.1.4 Economics of Scale
3.2 OPERATION AND MAINTENANCE COSTS
3.2.1 Operation and Maintenance Costs.
3.2.2 Escalation .
3.2.3 Economics of Scale
3.3 FUEL AND FUEL TRANSPORTATION COSTS.
3.3.1 Nenana Station
3.3.2 Beluga Station
3.4 COST OF POWER .
4.0 ENVIRONMENTAL AND ENGINEERING SITING CONSTRAINTS .
4.1 ENVIRONMENTAL SITING CONSTRAINTS
4.1.1 Water Resources
4.1.2 Air Resources
x
2.37
2.37
2.37
2.38
2.38
2.38
2.40
3.1
3.1
3.1
3.1
3.6
3.6
3.6
3.6
3.7
3.8
3.8
3.8
3.8
3.8
4.1
4.1
4.1
4.2
4.1.3 Aquatic and Marine Ecology.···· ·
4.3
4.1.4 Terrestrial Ecology · ····4.4
4.1.5 Socioeconomic Constraints ·· ····4.4
4.2 ENGINEERING SITING CONSTRAINTS ·· · ···4.4
4.2.1 Site Topography and Geotechnical
Characteri stics ··· ·· ···4.5
4.2.2 Access Road,Railroad and Transmission
Line Considerations ·· ··· ··4.5
4.2.3 Water Supply Considerations · ··· ·
4.6
5.0 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS ··5.1
5.1 SUMMARY OF FIRST ORDER ENVIRONMENTAL IMPACTS.···5.1
5.2 ENVIRONMENTAL AND SOCIOECONOMIC EFFECTS.·· ·
5.1
5.2.1 Water Resou rce Effects ·· ··· ·
5.1
5.2.2 Air Resource Effects · ·· · · ·
5.1
5.2.3 Aquatic and Marine Ecosystem Effects.· ··5.2
5.2.4 Terrestrial Ecosystem Effects ·····5.3
5.2.5 Socioeconomic Effects.···· · ·
5.3
6.0 INSTITUTIONAL CONSIDERATIONS ···· ··· ·
6.1
6.1 FEDERAL REQUIREMENTS ·····6.1
6.1.1 Air . .······ ·
·6.1
6.1.2 Water .··· ·····6.4
6.1.3 Solid Waste.· ·······6.5
6.1.4 Co a1 Min i ng .···· · · ·
6.7
6.1.5 National Environmental Policy Act · ·
··6.7
6.1.6 Other Federal Requirements.· · · ··6.9
6.2 STATE REQUIREMENTS .·······6.11
xi
r
6.2.1 Air 6.11
6.2.2 Water 6.12
6.2.3 Sol id Waste 6.14
6.2.4 Coal Mining 6.14
6.2.5 Other State Laws .6.15
6.3 LOCAL REQUIREMENTS .6.15
6.4 LICENSING SCHEDULE 6.16
7.0 REFERENCES 7.1
xii
~
FIGURES
1.1 Railbelt Study Area
2.1 Simplified Process Flow Diagram
2.2 Water Balance Diagram
2.3 Plot Plan
2.4 Mass-Flow Boiler Bin Configuration
2.5 Typical Direct-Firing System for Pulverized Coal.
2.6 Nenana Station Switchyard
2.7 Beluga Station Switchyard
2.8 Boiler Feedwater Treatment System
2.9 Nenana and Beluga Station Switchyards and Tie Lines
2.10 Willow Substation
2.11 Construction Workforce Requirements
2.12 Project Schedule
3.1 Cost of Power Versus Capacity Factor
3.2 Cost of Power Versus First Year of Commercial
Operation
6.1 Licensing Schedule.
xiii
1.4
2.2
2.4
2.5
2.9
2.10
2.14
2.16
2.23
2.33
2.34
2.39
2.41
3.10
3.11
6.17
TABLES
2.1 Estimated Characteristics of Treated Coal Pile Runoff.
2.2 Plant Staffing Requirements
3.1 Bid Line Item Costs for Beluga Area Station.
3.2 Bid Line Item Costs for Nenana Area Station
3.3 Payout Schedule for Beluga Area Station
3.4 Payout Schedule for Nenana Area Station
3.5 Estimated Coal Prices:Beluga and Nenana Stations
5.1 Primary Environmental Effects
6.1 Permits,Approvals,and Certifications Required
for a Coal-Fired Power Plant in Alaska.
xiv
2.22
2.49
3.2
3.3
3.4
3.5
3.9
5.2
6.2
1.0 INTRODUCTION
Coal-fired steam-electric generation is a conventional,widely utilized
technology that presently supplies more power in the United States than any
other conversion technology.In a power plant of this type,coal is burned in
a boiler,generating steam at a high pressure and temperature.This steam
expands through a condensing steam turbine,which drives an electric generator.
Conversion efficiencies for this type of power generation are in the vicinity
of 35 percent (-9750 Btu/kWh).Efficiency is related to unit size,with larger
units tending to be more efficient.
The use of this technology for power generation is as old as the electric
power industry itself.It is used whenever an economic source of coal can be
obtained and siting and environmental requirements can be met.
Coal-fired steam-electric generation has seen some development in Alaska,
with several small plants operating in the Railbelt region.A 25-MW coal-
fired plant located near Healy is operated by the Golden Valley Electric
Association.The Fairbanks Municipal Utility System operates four units,
totaling 29 MW,at their Chena station.Several other small units are located
at the University of Alaska and at some military installations in the Fairbanks
and Anchorage areas.All of these installations utilize coal from the Nenana
coal fields near Healy.
Coal-fired steam-electric units can be designed for load-following capa-
bility.However,most of the large,modern,high pressure units have design
limitations on rapid changes in load and are consequently base-loaded.
This technology,using conventional pulverized coal-fired boilers,is
mature and presently available for power generation.An alternative form of
this technology could utilize "advanced"atmospheric fluidized bed combustion
(AFBC)to produce steam.With AFBC,air is forced up through a perforated
plate in the bottom of the boiler and imparts a fluid motion to the bed mate-
rial,which usually consists of coal and limestone.While there are a number
of differences between AFBC and a conventional system,the major advantage of
AFBC is that coal is burned in intimate contact with limestone,thereby greatly
1.1
reducing sulfur dioxide (50 2 )emissions.Under some circumstances U.S.Envi-
ronmental Protection Agency (EPA)limitations may be achieved in an AFBC sys-
tem without the use of flue gas desulfurization (FGD)systems.This technology
is still emerging with respect to electric utility service,although smaller
demonstration atmospheric fluidized bed combustors are being used to produce
heating steam.It is estimated that a 200-MW generating plant using AFBC
would be available for order by 1988,and for commercial operation by 1995.
Coal-fired steam-electric generation has several significant advantages
compared to other alternatives.There are substantial coal deposits to utilize
in the Railbelt Region of Alaska.The technology is mature and well developed,
and plants can be built that are extremely reliable.
Disadvantages of this technology include environmental effects,aesthetic
intrusiveness and solid waste disposal.Environmental effects of primary con-
cern include emissions of nitrogen oxides (NO ),sulfur oxides (SO ),andxx
particulates.Aesthetic intrusion of the plant can be significant compared to
other alternatives.The disposal of large quantities of solid waste in the
form of ash and spent FGD waste could also be a problem depending upon the
specific site location.
Coal-fired steam-electric plants have been installed in unit sizes up to
1300 MW,although the typical range at this time is between 200 and 800 MW.
At the low end,10 MW appears to be the smallest practical size.
The power plant described in this report is fired with pulverized coal
and is rated at 200 MW nominal capacity.Two potential sites are considered,
one in the vicinity of the community of Nenana and the second near the Beluga
district of the Susitna field (Refer to Figure 1.1).The plant is of conven-
tional design,using dry FGD scrubbers for 50 2 control,baghouse particulate
removal and wet/dry mechanical draft cooling towers for heat rejection.
Coal quality assumptions used for this study are typical of the Nenana
and Beluga fields and are as follows:
1.2
Heati ng Va lue
Ash Content
Moi sture
Su lfur
Nitrogen
Ash Softening Temperature
Ash Na 2
Ha rdgrove Gri ndabil ity Index
1.3
8,000 8tu/lb
8 %av9 -11 %max
28%
0.20%
0.60%
2350°F
0.10%
30
...
COAL RESOURCES
_FIELDS HAVING SUPERIOR POTENTIAL
~OTHER FIELDS r
a ~a 'OOMII"
•
FIGURE 1.1.Railbelt Study Area
1.4
2.0 TECHNICAL DESCRIPTION
Coal-fired steam-electric generating stations are a well-known technol-
ogy.Mechanically pulverized coal is mixed with air and blown into a furnace
for combustion.The walls of the furnace are lined with tubing through which
is passed high pressure water that is transformed into saturated steam by the
thermal energy of the combustion process.The saturated steam is then passed
through heat exchangers (superheaters)that are exposed to a hot flue gas
stream and become superheated by absorbing more energy.The superheated steam
is then piped to the steam turbine where the energy is transformed into mechan-
ical energy.This mechanical rotating energy drives an electric generator.
The steam,after releasing all of its usable energy,is condensed by cold
water and pumped back into the steam-generator for reuse.
2.1 PROCESS AND AUXILIARY SYSTEM DESCRIPTION
Typical pressures for steam-electric generating stations include
1800 psig,2400 psig and 3500 psig,with some heat rate improvement with
higher pressures.Design parameters of the station described in this report
have been selected to be a 2400 psig pressure rating with 1000°F superheat and
1000°F reheat temperatures and a nameplate rating of 200 MW.One-thousand
degrees is the upper limit normally selected for superheating.Although the
heat rate can be substantially improved with higher superheating temperatures,
the industry has tended to avoid high temperatures for reliability reasons.
A process flow diagram is shown in Figure 2.1.The steam-generator will
require 113 tons of coal per hour to generate 1.39 million pounds of steam per
hour,with an energy of 1462 Btu per pound of steam.The coal is blown into
the furnace using preheated primary air and mixed with additional preheated
air for complete combustion.Nitrogen oxide (NO)control can be either byx
excess air control or by recirculation of combustion gases.Other antipollu-
tion controls are in the exhaust of the steam-generator;they include a lime
slurry feed for sulfur byproduct suppression,a baghouse for particulate col-
lection and a 270-foot stack.
2.1
D'tY-'N~T
MECe1A"lIc,..6.L
OIl...A'FT :.oo_,t-J~
To""-'E.R.
C.Oj.JDEt.J~A."~
POI..Ili»l".E.R.
-41 5'1..IO~l...b/I-o\~
--c..12.:.u\,..t>....q•.J<::.
!,ATER..
Put-H"
TO swrTCHYAJC.D
A~a
B T~I<Jt:>M\'":r.loIOl.J
StYSTEM
'ZOOM'W ~-----+
TR.ANbFORI.-\E-R
GEf-lERATOR
lOIN
PIl.E:~UIle
1'uQ......e
IF
PW~P
:~~:-I I~.,..~_.
'"~~~t__HeI>._1_ER_7 _
Miceli.fEED
PUMPS
1-4'<;H
r"Re,,",,:>u~'E.-,
TUI<i!>,UE
MAI"-l5,TE,A.M
1-40T R.E ...E,&.T
'F='J~l'
I --
FURNI<..U,
~IGH PIlE....';)ull.E
HE:....Tt2';IA.tolO'l
\.'!fl "\0'"ca/1-41Z.
____~·~~~::':_~~/\-lR ~_
1:.'1)(,O"L8/r-l.R
----------------_.----
(G"'''"","S)
LL I
lL---0~n BOiceI'
SuptR.UT'.R aRUM
--V
RE.~eA.Te:R
~
L-l i,
E.cmJDMI'Z.E:R
~'r
AIR.INQ=
REGEI-JERAT i'lE
"U1~(,eii:
D=~..Pl!.1 .....1l.'I'
AJ'"."""'"(.oIC
F'ib-l.tllo."e.R.~
p~......n~
::)IL
leoAl &'COS~
SiTA.CK,
N.
N
FIGURE 2.1.Simplified Process Flow Oiagram
The furnace will have sootblowers on the tubing wall that will permit
cleaning of the heat exchanger surfaces during operation.These sootblowers
will either blow saturated steam from the drum or compressed air from special
air compressors.
The steam from the steam-generator is expanded in the high pressure
turbine and routed through the furnace reheater to be reheated and further
expanded in the intermediate pressure turbine and subsequently the low pres-
sure turbine.The low pressure turbine exhausts to the condenser,which
operates at a vacuum,setting the pressure at which the steam condenses.
Noncondensable gases are removed by vacuum pumps.The condenser is cooled by
water that is recycled through a wet/dry cooling tower that exchanges the
waste heat to the atmosphere by either a water-to-air (dry)heat exchanger
during the winter months or by evaporation (wet heat exchange)during the
summer months or by a combination of both.The choice of a wet/dry cooling
tower is intended to eliminate the plume of supersaturated moisture in the air
often seen over cooling towers and to minimize icing conditions in the vicin-
ity of cooling towers.This system also reduces the overall plant makeup
water requirements and therefore minimizes wastewater discharges.The antici-
pated water balance diagram for the power plant is presented in Figure 2.2.
The condensate from the steam cycle is pumped from the condenser through
condensate heaters fed by extraction steam from the turbine to the deaerator
where gases including oxygen are removed from the water.This condensate sys-
tem may include a polishing demineralizer installed to provide higher water
purity and to reduce the boiler blowdown rate for the system.A chemical
injection system controls pH and residual oxygen concentration.
From the deaerator,the feedwater is pumped again through feedwater
heaters,fed by extraction steam from the turbine,back to the steam-
generator.The inlet feedwater temperature at the steam-generator is about
470°F.Here the feedwater is further heated by an economizer in the furnace
exhaust to about saturation temperature.
A typical plant arrangement is shown in the plot plan (Figure 2.3).The
basis is the arrangement of the turbine building,the pulverizer/heater bay
2.3
The furnace will have sootblowers on the tubing wall that will permit
cleaning of the heat exchanger surfaces during operation.These sootblowers
will either blow saturated steam from the drum or compressed air from special
air compressors.
The steam from the steam-generator is expanded in the high pressure
turbine and routed through the furnace reheater to be reheated and further
expanded in the intermediate pressure turbine and subsequently the low pres-
sure turbine.The low pressure turbine exhausts to the condenser,which
operates at a vacuum,setting the pressure at which the steam condenses.
Noncondensable gases are removed by vacuum pumps.The condenser is cooled by
water that is recycled through a wet/dry cooling tower that exchanges the
waste heat to the atmosphere by either a water-to-air (dry)heat exchanger
during the winter months or by evaporation (wet heat exchange)during the
summer months or by a combination of both.The choice of a wet/dry cooling
tower is intended to eliminate the plume of supersaturated moisture in the air
often seen over cooling towers and to minimize icing conditions in the vicin-
ity of cooling towers.This system also reduces the overall plant makeup
water requirements and therefore minimizes wastewater discharges.The antici-
pated water balance diagram for the power plant is presented in Figure 2.2.
The condensate from the steam cycle is pumped from the condenser through
condensate heaters fed by extraction steam from the turbine to the deaerator
where gases including oxygen are removed from the water.This condensate sys-
tem may include a polishing demineralizer installed to provide higher water
purity and to reduce the boiler blowdown rate for the system.A chemical
injection system controls pH and residual oxygen concentration.
From the deaerator,the feedwater is pumped again through feedwater
heaters,fed by extraction steam from the turbine,back to the steam-
generator.The inlet feedwater temperature at the steam-generator is about
470°F.Here the feedwater is further heated by an economizer in the furnace
exhaust to about saturation temperature.
A typical plant arrangement is shown in the plot plan (Figure 2.3).The
basis is the arrangement of the turbine building,the pulverizer/heater bay
2.3
r
~E~AI'OR.Io."",,'-I
4S ~200 ~>,I -'),.....--
SUR<>E TANK U"lDEl<Fl.GW SO\.I~
WATER La.T To eoono",.......
,:rt 1
~• I I A~~
TROU,;H
F60
"''1'!>'TCM
!
CO'ltlW~f:R
11
AUX,LIA,,-'i
C;OOLI'-lc;
rl DISC"AIl6f:.''-If:~
N'FI:lRAT'OlJ ~IFT=Ll 0
'
COOlIN';TOW Ell
i!lrPA'O/O tlURI>lG
~COOl"J••
~CTIOt..l
OPllUT,olJ
wl\T1:lI ':>L)PPLY
~U~
I'x>'Lf:1t
..
1;<
'"..
~~..~;1~~g~~"~~I Il~O..,,g ..~~-",.
HoLo''-Ie;J ~
I'>A!>'IJ .2
It ~
iJ
p~~
11
1
211
oe "',I<ERA-
LI1U.l----t
"''1'!>,e.M
is
EGUAL,lATIOU
AIlD
IlfUTIAUtATIOI<
16111 (wer TC>Nf;~O!'foRA:nO'.l)
1.iI (DIO.'(,,,,,,,til <:>hUn<>.l)
~DTE':>·.
I-~~L.O'w,,=,,4,Q.E b:PRf~t.OIN
6AlLOlAPl<1l ""'lUTE (Ii""').
2-FL.DW'O ARE Of.,LY A~IRA6e<o AT
100"!-"'".UTY """,,"0••
'Ii
~
rL
uJ
~
1%
lluwOFf
HOlOINe;
f'l:)jJD
TO BOlT OM ASH
COW~EYOR
1941(weT rOWf:I{~TIOIJ)
POTA~LE
WATER
AHO HIiAc.
SUPPL'1'
1lJ1 (Dili 10WCI(O~lUT\()I,j)
14
WJ..TtIt
f1lf.TR"TIEHT~
5'1'!>Tf:101 h
~....m'RY
'Nl!>T!WAnR
,IleATMeWT
I,.'"
"
Rl1I\1D1=~,Ir,t..l,D
L..iAUl"U
r-
110
FlOOIt
DRAi"'~~
~I'!o
TO Re.CEM""
SnEAM
O,L/WATU.
&ErUAT01'.
ri r;;;-~~~
9"'
fJ ~~:
~2 I..~, I
pH
GOIITlD
O"",T ~PPRE'>"ION
-~
It-
i:;
.."07.
~
Ji
'"f
::>on
!f;
~
IOJ ..OfF
~OU>I'JG
/t1'JD
<OOAL
'i>lOIUoGE
/>R£A
Y>JlD
OUlt.lI>GE
S~!>TlM
ASH DISPOSAL AREA~
,
100
,
W~TE
...--l e-Ol~:~~~OI.II-
"uMP
L-
e.lo1ER';EWCY
t CO>l>lecT10t.l
--I
OVERfLO'O :
I
~~
IloPpt~
COOLlll6
"'ATER
1?>7
fL-,.
I s J ~"
------.."WEfT 1>1<;
N.
+>0
FI GURE 2.2.Water Sal ance Diagram
LEGE~D
CD TU~e.IIJ~e>IjILDIt-.lGo
CD BOII..E.R
®~PRA'(DRYER
CD ~A(::II-\OUC:>e.
®FAN HOUSE
@ LlME ~LAl(Erl
CD e~I4AU~T c:,TAcK.
®FLy A.C)11 ,=,ILO
®I-IYDRA:TCI>LIME.5TO~AC:2E.TANK.
@ 5OTTOM A.C)I-I '::II La
@ CONDENSAJE e;,loRA(;:)E:.i~K.
@ '3TA.RT UP TlU.~&~ItME.R
®AUXILIARY T~N~t=ORME.R
®MAl \-.l T~A~FoRME.R
®ADMlloJl':>TRATIOlJ 2:lUILDIN~
@ RAW WATE.1t c::,iORAC:.e:TA~K
@ COOLING TOWE.R
@ I NOOOR.~iOIUo.C:2E.
@ MACl-lllJE:~HOP
@ GARA<:lE.
®COl]'SfTRUC.iIO!-J O~~IC.e:
@ STA.RT-UP GAC::J ~iTO~e.
@ FAMILY ?iATUS ~LI':>\~c;
@ ~~t-.1GJLe ~TA.iUS CAMP
@ RECR-CATION ~U'LDI1-J6
@ ME.':1&I-I"'l.~
@ COAL-DEAD ~OICA6r:.PILE;
@ COAoL-LI'JE:.~O~E:PIl.-E.
®COlJ\lE.YOR
@J CotJC;i~Uc:.T101oJ E.Qlllf'MEtoJT PA~"\toJ~
•
TO A.IR:"'''''I~
LIa.'1'DOWN
A~~
-~
I
I
I
LJL J~IT~Y~ilD
PLOT PLAN
@
@
@
================-':::--:::....1.:;1-:C:.z /;z:/=='.1!-JILJ \ \~l C TO AI r.'=>T~7 7 ~~-\~~
U1
N.
FIGURE 2.3.Plat Plan
and the steam-generator (boiler)with its accessories that lead to the stack.
The basic arrangement of the turbine building and boiler building has been
chosen for compact design minimizing the length of major piping.This arrange-
ment can be turned as a block in any direction to suit the transmission line
direction and/or the fuel delivery system and water supply system.
A plot plan arrangement can be highly variable depending on the site
topography,prevailing wind direction,the location of the railroad spur and
access roads near the site,the direction of the transmission lines,water
supply source and other factors.The suggested arrangement attempts to mini-
mize the impact of windblown coal dust and of cooling tower moist air discharge
on the other parts of the plant and on the environment.
2.1.1 Fuel Handling System
The principal components of the fuel handling system include the coal
unloading station,stacking and reclaiming facilities,a coal sampling station,
in-plant storage and mills.
Coal Unloading Station
The type of coal unloading station required for the plant is dependent on
the coal transportation system.For the purposes of this study,it is assumed
that coal will be delivered to the Beluga site by mine'mouth conveyor,and
that delivery to the Nenana site will be by rail.The mine mouth conveyor at
the Beluga site will feed the storage pile directly.The conveyor will be
sized for a capacity of 500 tons per hour.It will have a 35 0 troughing idler,
be 36 inches in width,travel at a velocity of 350 feet per minute,and be
weather-protected its entire length.
At the Nenana site,bottom-dump rail cars will discharge into a series of
below-grade hoppers positioned directly beneath the track.From these hop-
pers,a conveyor tripper will distribute the coal over the length of the stor-
age pile.One coal shipment a day will be required assuming a unit train
consisting of 48 cars,each having a 50-ton capacity.Unloading will be at a
rate of approximately 10 cars per hour and will require approximately 5 hours.
The below grade unloading hoppers will be sized to unload two 50-ton-capacity
rail cars simultaneously and feed the inclined conveyor at a rate of 500 tons
2.6
.....
The bot-
60 feet
per hour.The inclined conveyor will be sized identical to the Beluga site
mine mouth conveyor,with an inclination not to exceed 16°.
A thawing shed will be installed just ahead of the unloading hoppers at
the Nenana site.The 200-foot thawing system,sized to cover 4 rail cars each
50 feet long,will consist of infrared radiant heaters that project heat to
the bottom and sides of the coal cars as they proceed through the shed tunnel.
Assuming an unloading rate of 1 car every 6 minutes,a thaw shed with heaters
installed along 4 car lengths will heat each car for 24 minutes by the time it
reaches the dumping pit.
Stacking and Reclaiming Facilities
The compacted dead (long-term storage)pile will consist of two sections,
one on each side of a below-grade reclaim tunnel,and will contain a 90-day
supply of coal for the plant.The V-shaped groove between the dead storage
piles (over the reclaim tunnel)will be used for a live storage pile.The
live storage capacity will be a 9-day supply at full load plant operation.
The live storage pile will be covered with a corrugated galvanized sheet
steel "A"frame roof.It will be supported by steel columns,beams,and
rafters.This structure will also support the overhead conveyor tripper,
enclosed in a penthouse at the ap'ex of the roof.The traveling belt tripper
will have a capacity of 500 tons per hour.It will be mounted on fl anged
wheels that engage parallel rails supported on either side of the belt.The
tripper will be electric-motor-driven and will move continuously back and
forth,reversing automatically at the ends of travel over the length of the
live storage pile.The length of the traveling belt tripper travel will be
1400 feet.
The live storage cover will be 1400 feet long and 60 feet wide.
tom edge of the roof will be 35 feet above grade and its apex will be
above ground level.
The entire coal storage pile (dead and live)will occupy an area of
approximately 250 feet by 1500 feet,or 375,000 ft 2 .The dead storage pile
will be 25 feet high.The coal will be reclaimed in the concrete reclaimer
tunnel below ground.Two 100 percent traveling rotary plow feeders will draw
2.7
-
coal from the stack and discharge it on a conveyor for transport to the plant.
The reclaimer conveyor discharges to an inclined conveyor that will take the
coal to the coal gallery.There,the coal will be transferred to conveyors
feeding the plant silos.The inclined conveyor will consist of two 100-
percent-capacity conveyor belts in a weather-protected common enclosure.Each
belt will have a capacity of 125 tons/hr.The plant's full load feed rate is
113 tons/hr.
Cost Sampling Station
A coal sampling system will be provided,either inside the plant or in a
separate sample house in the yard.
In-Plant Storage
In-plant silo storage capacity will be 10 hours.Five silos,each with a
capacity of 240 tons,are situated above the mills for gravity feed.They
will be provided with a fire protection system.Each boiler silo will be
designed for mass flow with stainless steel liners.They will be 24 feet in
diameter and approximately 40 feet high.Their configuration will be as shown
in Fig ure 2.4.
Mills
The mills (pulverizers)serve to pulverize and dry the coal in prepara-
tion for burning.There will be a total of five coal pulverizers (mills),one
under each silo located at the lowest elevation of the plant.Each mill will
be supplied with hot air from the air preheater.The hot air will remove
moisture from the coal and transport the pulverized coal to the burners.A
typical firing system is illustrated in Figure 2.5.Each mill will have a
capacity of 23 tons per hour and will pulverize the coal to pass 70 percent
through a 200 mesh sieve and at least 98 percent through a 50 mesh sieve.
2.1.2 Steam-Generator
The steam-generator will be an indoor type designed to burn run-of-mine
pulveri zed coal.Main steam capacity will be 1.39 x 10 6 lb/hr at 2400 psi,
1005°F.The furnace will be of waterwall construction with steam drum and gas
2.8
•
BOILER 81N
i
'0
-~
':}
_I
~
"-
.1
aJ
I/6 I
I
24'
304-28
.5TAIAlL£5::;'
L.INc!f -
FIGURE 2.4.Mass-Flow Boiler Bin Configuration
pass superheaters,economizer and air heater.Single pass reheat will be pro-
vided with a capacity of 1.17 x 10 6 lb/hr at 100SoF.Economizer outlet
temperature will be 470°F.
A balanced draft design will be utilized.
The steam generator will be provided with light oil torch ignition,
safety valves,instrumentation and controls,a boiler blowdown system and soot
blowers.
A summary of the steam generation design parameters is provided below:
2.9
I..
COLD (TeMPERING)A"-'.-I,--,-R_-+-I
FROM FORCED DRAFT
FAN
TEMPERING RIR
DAMPER ---.......1
HOT AIR FROM BOILER
AIR HEATER
(:5l!GOAIDARY AIR)
HOT AI DAMPER
BOILER
FRONT W.tILL
BA5EMENT FLOOR
PRIMARY
AIR FAN
PRIMARY AIR
CONTROL
DAMPER
BURNER
rL-...L...-V WIN D BOX
-----~
-----:::---
PULVERIZED '-«:=::,
FUEL au R;:"N=£~R=-,j-<
--:::=~:::::::::======-:::i::::::=======~W ~-------~
o 0
RAW COAL
BUNKER
FEE.D R
PULVER IZ.ER---+---
,.....L---....I--t1I------l
FIGURE 2.5.Typical Direct-Firing System for Pulverized Coal
Steam Flow at Superheater Outlet
Steam Pressure at Superheater Outlet
Steam Temperature at Superheater Outlet
Feedwater Temperature at Economizer Inlet
Steam Flow Through Reheater
Steam Temperature at Reheater Inlet
Steam Temperature at Reheater Outlet
Enthalpy at Reheater Inlet (Approximate)
1.39 x 10 6 lb/hr
2525 psig
100S o F
470°F
1.17 x 10 6 lb/hr
595°F
100S o F
1300 Btu
2.10
rI
I
[
Fans and motors shall be rated as follows,referred to the maximum
continuous rating of the steam-generator:
Forced Induced Recircu-
Draft Draft 1at i nyFan Fan
Fan(a--
Margin for Volume (%)20 20 15
Margin for Static Head (%)44 44 32
Margin for Temperature (OF)25 100
Max i mum Speed (rpm)1200 900 900
The steam-generator will be housed in a building 135 feet square and
180 feet high.One wall will be common with an auxiliary bay of 150 feet by
55 feet and 105 feet high.The opposite 150-foot wall will be on one side
common with the steam-generator wall and on the other side common with the
turbine-generator building wall.
On the other side of the steam-generator building,opposite to the
auxiliary bay,will be the combustion air and exhaust handling equipment
leading to the stack.This building will be 135 feet wide by 200 feet long
and 70 feet high,with one 135-foot wall common with the steam-generator
building.All buildings will be of steel construction insulated with
aluminum-sandwiched insulation.
2.1.3 Turbine-Generator
The turbine is to be of the 200 MW rating,with seven extraction stages
and bottom exhaust.The seven extractions are to be used for feedwater heat-
ing and air preheating for the boiler.Turbine design conditions are as
follows:
Throttle Pressure
Superheat Temperature
2400 psig
1000°F
(a)The recirculating fan may be required for NO x control and is not illu-
strated in Figures 2.1 and 2.5.
2.11
Reheat Temperature
Turbine Backpressure
Final Feedwater Temperature
1000°F
1.5 in.Hg
470°F
>ilk
The generator is to be designed for maximum capability of the turbine
with a power factor of 0.85.
All equipment is to be designed for indoor installation.The turbine-
generator is to be equipped with all local and control room supervisory instru-
mentation,including a valve testing station and protective devices.Oil
reservoir,oil cooler,and ac and dc oil pumps as well as the gland seal system
(including piping as normally supplied with the turbine-generator)are to be
included.
The turbine-generator will be located on a pedestal 108 feet long,33 feet
wide and 30 feet high that is situated in a turbine building 200 feet long,
100 feet wide and 50 feet high.One section over the center of the turbine-
generator will have a width of 45 feet to accommodate a bridge crane of 85 tons
capacity protruding 37 feet above the basic building for a total height of
87 feet.This building will also be of steel construction,with aluminum-
sandwiched insulation siding.
In addition to the turbine-generator,condenser,condensate pumps,some
of the feedwater heaters,feedwater pumps and other miscellaneous equipment,
the turbine building will also contain the control room,water transfer pumps,
service water pumps,instrument air compressors,service air compressors,
demineralizers,motor control centers,house boilers and a diesel-generator.
The house boilers are to be designed so that with both boilers in opera-
tion the buildings can be kept at 60°F,and with one boiler in operation the
buildings can be maintained above a minimum of 40°F.The boilers will also
provide freeze protection for all exposed equipment,including the cooling
tower basin.At the Beluga site,the house boilers will be approximately
45,000 lb/hr;approximately 60,000 lb/hr will ,be required at the Nenana field
site.
2.12
2.1.4 Electrical Plant Designs
Differing electrical plant designs will be required for Nenana and Beluga.
Nenana Station
The proposed electrical configuration for the plant at Nenana is as fol-
lows:the generator output voltage is assumed to be 20 kV (which is an aver-
age of the standard voltage used by the two largest manufacturers).The main
transformer elevates this to 138 kV,the basic switchyard voltage,to match
the voltage of the existing tie line to Fairbanks from Healy.The existing
line will be opened and brought into the new 138-kV switchyard.Startup power
for this station can be supplied from Fairbanks,from Healy,or from the south
over the proposed North/South 345-kV tie line.This tie line is discussed in
Section 2.3.
The auxiliary and startup transformers have three windings 138 kV delta
to 4.16/4.16 kV.Two trains for auxiliary power buses A and B are thus setup
at 4.16 kV.
Ratings of the major pieces of equipment are as follows:
•Generator,247 MVA;0.85 PF,200 MW,20 kV
•Main Transformers,220 MVA,20 kV delta to 128 kV wye
•Auxiliary Transformers,3 winding 20 MVA,20 kV delta to 4.16/4.16 kV
delta
•Startup Transformer,3 winding 20 MVA,138 kV delta to 4.16/4.16 kV
~e
•Switchgear 4.16 kV medium voltage Bus A and Bus B,2000 Amp 350 MVA,
approximately 10 air circuit breakers each
•Power Centers,motor-control centers distribution panels,etc.,as
requ ired.
The switchyard configuration is shown in Figure 2.6.Major pieces of
equipment are as follows:
•Main and Transfer Buses
2.13
...
~~O-"J ..,
"
7"r"/
/FAIRe:ANI\S
)
\'l'I
.J ~4
N
-z:
,~"~
111
~"MAIN~
~-;TRAN';)
)
It)
.::j;;-111 START-UP/j tt1~-.\)~TRANSF J ~45KVm
I 10 t
~--~
I l --...
Wlltow SlJ~STA.
.:l~"~
eU~TIE
(1l
,,;~
'l!...~,$
"-
~~
rf\
HEAL.YN
~
N
N
t--'
-Po
N.
!--lOTE..:
-::>EE FIGURE 2.7 BELUGA .5TATION
.5W/TCHYARD FOR ..5/MILAR cONFIGURATION
WITH MORE DETAIL.
FIGURE 2.6.Nenana Station Switchyard
,
1t
•Six 138-kV bays each consisting of one 138-kV circuit breaker and three
138-kV disconnect switches.These bays are used for the main trans-
former,startup,bus tie lines to Fairbanks and Healy and the 345-kV
autotransformer.
•One 345-kV bay with two disconnect switches and circuit breaker for
the 345-kV line to the Willow Substation.
Beluga Station
The proposed electrical configuration for the plant at Beluga is as fol-
lows.The generator output voltage is assumed to be 20 kV (same as Nenana).
The main transformer elevates this to 169 kV,the basic switchyard voltage.
Since the existing combustion turbine plant near Beluga is transmitting
at this level,a tie line between the two plants at 169 kV will improve relia-
bility of the overall system and supply startup power for the Beluga Station.
The output of the new plant will be elevated to 345 kV through an autotrans-
former and transmitted to a proposed new 345 kV substation at Willow,which
has outlets to the north (Fairbanks)and to the south (Anchorage).This sub-
station and associated tie lines are discussed in Section 2.3.The auxiliary
and startup transformer setups would be the same as Nenana.
Ratings of the major pieces of equipment are the same as Nenana,except
the main transformer will be 200 MVA,20 kV delta to 169 kV wye.The switch-
yard configuration is shown in Figure 2.7.
Major pieces of equipment are as follows:
•Main and Transfer Buses
•Five 169-kV bays each consisting of one 169-kV circuit breaker and
three disconnect switches.These bays are used for the main trans-
former,startup,bus tie line to the existing Chugach Electric
Beluga plant,and the 345-kV autotransformer.
•One 345-kV bay with two disconnect switches and circuit breaker will
be for the 345-kV line to Willow.
2.15
7ii%h!llli':-iibt·:~-~::'C'.;uj;.,:~_~"""".~;,;:~~.~"==-""~.,...._.....,.._.==~
34/
28 ..20 ..15 ~15 ~15 I:'20 ze 40 :'0 21 ZI ,21 54
X--r--1 X lx 1 x x x TT'1~,1 1 ~:r
x IIII I~~¥
X ~A6~KV AUTO TRAN5F
x..
FENC.E ....
~><-~~I ,~I-X X X X X
WILLOW
*
....
~
I
~
'C..,...-
~
~
~t\/l ~-
~I
~~
...:i2:"J
~
~r-
'\I
~t--
1\
'4-
-I-
x H-+-a::::;J!:::>oI~-=~c}--<u::::l>--+
~
+J~~~+-a=---Q~
f\j5TART-Lf'l-
ii TRANSF i·
I.:
,
~
l\l
......
en
N.
54
FIGURE 2.7.Beluga Station Switchyard
~
2.1.5 Heat Rejection System(a)
The steam exiting the turbine is condensed and returned to the boiler for
reuse.The condensing is effected in the condenser where circulating cooling
water is used to cool the steam.The circulating cooling water is passed
through a cooling tower for conveying the rejected heat to the atmosphere.
The condenser is to be a single shell two pass with divided water box and
hotwell.The hotwell is to have enough storage to allow proper level control
for surging and shall be properly baffled to keep the condensate at saturation
temperature.The condenser shall include Muntz Metal tube sheets and inhibited
Admiralty tubes with 70-30 copper nickel tubes in the air removal sections and
the impingement areas.The condenser is to be shop fabricated,including tub-
ing,and should be suitable for sea and barge shipment.The condenser will be
used in a wet/dry cooling tower application.It should include an 18-foot
condenser neck with dogbone-type rubber expansion joint for connection to the
turbine exhaust.Condenser design data are as follows:
I
ti
l't
Heat load·
Tubes
Maximum Water Velocity
Cooling Water Flow
Surf ace Area
Backp ressure
946 x 10 6 Btu/hr
1"18 BWG x 36 ft
6.5 ft/sec
41.5 lb/hr
120,000 ftZ
1.5 in.Hg
The cooling towers for the two sites will differ considerably.The towers
shall be of the wet-dry-type mechanical-draft design of a material most suit-
able for very cold weather conditions as found in Alaska south of Fairbanks.
The intent is to have low water consumption,avoid visible tower plumes and
minimize icing conditions.The tower for the Nenana plant location will have
a far greater percentage of capacity in the dry portion of the tower than in
(a)While there may be some potential for using waste heat from the Nenana
power plant for district heating purposes,an analysis of this option was
considered to be outside the scope of this study,as use of this energy
source would have little impact on the demand for or the cost of elec-
trical energy.
2.17
the wet section,compared to the tower that would be used for the Beluga plant
location.The significant data are as follows:
Heat Load
Water Loading
Cold Water Temperature
91.0 x 10 Btu/hr
41.5 x 10 6 ft/hr
80°F
The above is based on a 23°F approach to a 10 percent of the time wetbulb
temperature of 57°F at Anchorage and a 21°F approach to a 59°F wetbulb tempera-
ture at Fairbanks.The design coldest drybu"lb temperature 97.5 percent of the
time is _20°F for Anchorage and _50°F for Fairbanks.
Three circulating water pumps of the vertical pit type for cooling tower
basin installation are required.The pumps are to be mounted 4 feet above
water level in an enclosed structure.The thrust bearing should be in the
motor and the shaft bearings should be of cutless rubber design of the self-
lubricating type.Each pump is to be designed for the following capability:
Water Temperature
Water Flow
Total Dynam~c Head
Speed
40 to 80°F
14 x 10 6 lb/hr
70 ft
720 rpm
The pump length should be kept to a minimum so that at 130 percent capac-
ity the required net positive suction head (NPSH)is not exceeded.The pumps
shall also be designed to run at 130 percent capacity and have a steadily ris-
ing characteristic toward shutoff for parallel operation.
2.1.6 Condensate and Feedwater System
The condensate and feedwater system receives condensate from the con-
denser hotwell at a temperature of approximately 40 to 80°F and a pressure of
1.5"Hg.The condensate is passed through a polishing demineralizer,(a)
(a)The polishing demineralizer may not be required and is not included in the
cost estimates.
2.18
four condensate heaters,a deaerating feed tank and is then raised to steam-
generator pressure by feed water pumps (Figure 2.1).After passing through two
high pressure feedwater heaters,the feedwater is supplied to the steam-
generator at a temperature of 470°F and a pressure of approximately 2500 psi.
The principal equipment in the condensate and feedwater system includes the
condensate pumps,condensate and feed water heaters (including the deaerating
feed tank)and feedwater pumps.
Condensate Pumps
Three vertical motor-driven canned pumps designed for indoor installation
are requ i red.Each wi 11 have a capacity of 50 percent.The thrust beari ngs
will be in the motors.The capabilities of each pump and motor are as follows:
Condensate Temperature
Condensate Flow
Total Dynamic Head
Speed
lOO°F
585 x 10 3 lb/hr
600 ft
900 rpm
The condensate pump length should be such that the distance between
impeller eye and suction flange shall not be less than NPSH required when
running -at 130 percent of design capacity.The pumps shall be designed for
parallel operation over the full range of operating capacity.
Condensate/Feedwater Heaters
The feedwater heating system will have six closed-type feedwater heaters
and one open-type feedwater heater (deaerator).The closed-type feedwater
heaters consist of two high pressure heaters and four low pressure heaters.
The high pressure heaters will be of hemispherical h~ad design and the low
pressure heaters will be ~olted head channel design.The high pressure
heaters are of the integral desuperheating and draincooling design.The low
pressure heaters are to have integral drain coolers.The high pressure
heaters will cascade drain to the deaerator and the low pressure heaters will
cascade drain to the condenser.All heaters shall be of the U-tube removable
shell design complete with roller-type supports.
2.19
The U-tubes in the high pressure heaters are to be Monel,5/8 inches in
diameter.For the low pressure heaters,they are to be 90-10 copper-nickel
and 3/4 inches in diameter.Representative design data for the heaters are as
follows:
Steam Channel
Channel She 11 Flow Flow Surf ace
(psig)(psig)(10 3 1b/hr)(10 6 1b/hr)(ft 2 )
HP-l 3700 640-Vacuum 115.0 1.31 8020
HP-2 3700 275-Vacuum 55.2 1.31 5300
LP-4 350 75-Vacuum 55.4 1.17 4590
LP-5 350 50-Vacuum 57.0 1.17 5500
LP-6 350 50-Vacuum 31.0 1.17 5630
LP-7 350 50-Vacuum 45.0 1.17 7450
The deaereator mounted on top of a five-minute capacity storage tank is
to be integrally connected and equipped with stainless steel troughs and baffle
plates.Design conditions for the deaerator are as follows:
Water Storage
Water Flow (In)
Steam and Drain Flow
Water Flow (Out)
Des i gn Pressu re
Operating Pressure
110 x 10 3 1b
1.17 x 10 6 Tb/hr
140 x 10 3 1b/hr
61.39 x 10 1b/hr
150 psig
120 psi a
Feedpumps
Three motor-driven,50-percent-capacity feedpumps for indoor installation
will be required.The feedpumps are to be of the multistage barrel-type with
an interstage takeoff for reheat desuperheating.Each feedpump is to be com-
plete with motors,shaft-driven and electric-driven oil pump,oil cooler and
oil tank,all mounted on a common base plate.The glands are to be sealed by
mechnica1 seals.Each pump is to be designed for the following capability:
2.20
Feedwater Temperature
Feedwater Flow
Total Dynamic Head
Suction Pressure
Net Positive Suction Head
Speed
340°F
695 x 10 3 lb/hr
6900 ft
100 psig
less than 50 ft
3600 rpm
The pumps should be able to operate out to 130 percent flow and the char-
acteristic should be steadily rising toward shut-off without exceeding 120 per-
cent of the design head.
2.1.7 Water Quality Control
The anticipated water balance for the power plant was presented in Fig-
ure 2.2.Due to the fact that "drll solid waste disposal systems and a wet/dry
cooling tower will be utilized at this station,the only station blowdown that
will occur will be excess coal pile runoff and yard runoff.Coal pile runoff
discharge will be relatively infrequent as all precipitation and snowmelt per-
colating and running off the coal pile will be collected in a holding basin
designed to contain the one-in-ten-year,24-hour rainfall event.Impounded
water will subsequently be utilized for dust suppression and equipment wash-
down purposes.The anticipated concentrations of impurities in this waste
stream following treatment are presented in Table 2.1.
Various water and wastewater treatment facilities are routinely incor-
porated into a power plant design to produce boiler feedwater and permit the
reuse of process water.The facilities that will be required for this station
are briefly described below.It should be noted that a small wastewater
treatment/recycle facility may be required to treat either cooling tower blow-
down or bottom ash trough water to allow recycle and insure a zero discharge
mode of operation.Based upon existing data,this system does not appear to
be required and therefore is not described below or included in the cost
estimates.
2.21
TABLE 2.1.Estimated Characteristics of Treated Coal
Pile Runoff
Parameter
Total Dissolved Solids
Suspended Solids
Iron
Magnesium
Sulfate
pH (units)
Concentration(a)
250
50
20
25
25
6.0 -9.0
(a)All concentrations expressed in mg/L unless
otherwise noted.
Boiler Feedwater Makeup Treatment System
The boiler feedwater makeup treatment system is designed to provide demin-
eralized water for steam cycle makeup,including boiler blowdown and sootblow-
ing purposes,as well as potable,heating,ventilating,and air conditioning
requirements (Refer to Figure 2.8).The treatment system will consist of two
major stages:pretreatment and demineralization.Pretreatment accomplishes
the removal of suspended particulate material and residual organics and will
consist of gravity filtration and activated carbon filtration.Following
pretreatment,steam cycle makeup will undergo demineralization for dissolved
solids removal.This system will consist of cation exchange,degasification,
anion exchange,and mixed bed demineralization.The entire treatment system
will consist of three parallel,50 percent duty trains producing 50 gallons
per minute of demineralized water.
Sanitary Waste Treatment Facility
A prefabricated-type aerobic biological treatment unit will be provided
to manage the power plant's sanitary wastes.The package treatment plant will
consist of a screening-communitor chamber,an aeration tank,a clarifier and a
chlorine contact chamber.Treated effluent will be discharged to the waste-
water collection sump.Waste biological solids produced by the plant will
2.22
ACTIVATED
CARBON
F'lLTRATION
I
PRETREATME.NT
GRAVITY ~AND
FfLTRATION
ALUM /ANIONIC
POLYM£R
PR£GHLORINATION I WATER U:5E.:1
I ,/.POTABLE WATER
~UPPLY
2.HVAC,~Y5TEMRAW
WATER
O£MINERALIZATION CAT/ON
EXCHANGER
NEUTRALIZATION
BA5/N
/
/
ANION
EXCHANGER
O£6Ajl FI £R
"""
/
/
/
/
/
/
/
RE:.GENE.RANT
CHEMICAL~
R£c;£N£RATION
:5Y~TcM
OEMINERAl.lZeO WAT"E.R U~E'5:
I..5TEAM CYCLE MAKE UP _I
2.600T BLOWING
3.OEMINERAL/ZEA REGENERATION
---PRODUCT WATER
---PROCE.:5:>WA.5TEWATER5
FIGURE 2.8.Boiler Feedwater Treatment System
2.23
Floor Drainage Treatment Facility
This facility will provide treatment for the removal of suspended solids
and oil/grease and will require both a primary and secondary treatment stage.
The primary stage will consist of a gravity oil/water separator that will
accomplish both suspended solids and floatable oil removal.The secondary
stage will consist of treatment for the removal of emulsified oils,utilizing
either cartridge-type separators or chemical coagulation.This prefabricated
facility will be designed to handle an average daily flow of 10 gpm.The
treated effluent will be discharged to the wastewater collection sump for
reuse.
F'
undergo aerobic digestion.
mately 6000 gallons per day
period of 24 hours.
The system will be sized for a flow of approxi-
and the aeration tank will provide a retention
p
o
o
f
4
o·
c
Equalization/Neutralization Facility
Wastewater from demineralizer regeneration and condensate polisher
regeneration will be produced and conveyed on an intermittent basis to the
equalization/neutralization tank having a corrosion resistant lining.The
ta~k will have a pH monitoring and control system that consists of a pH
sensing/control device to automatically add acid or caustic reagents as
required to adjust the pH to within a range of 6.0 to 9.0.The wastewater
will then be discharged to the wastewater collection sump.The tank will have
a minimum 36-hour detention period for the wastewater flows generated on the
maximum regeneration activity day.The capacity of the tank will,therefore,
be approximately 10,000 gallons.Thi s capacity,together with the pH control
system,will provide adequate neutralization to enable wastewater reuse.
Coal Pile Runoff Holding Pond Facility
Runoff and filtrate from the coal storage pile will be directed to collec-
tion ditches located on the periphery of the pile and then conveyed to the coal
pile runoff pond for treatment prior to disposal to the yard and area drainage
system.
The holding pond will provide gravity setting for coal fines (suspended
matter)washed out of the pile.The pond will be capable of retaining the
2.24
o·
2
s
d
A
t
t
h
h
s
a
one-in-ten-year,24-hour rainfall event and,therefore,only storms in excess
of this event will be discharged.For the plant located near the Beluga coal
field,the runoff holding pond will have a capacity of approximately
470,000 gallons,a surface area of approximately 6250 ft 2 and a water depth
of approximately 10 feet.The capacity of the pond associated with the Nenana
coal field plant will be approximately 700,000 gallons,encompassing approxi-
mately 9400 ft 2 at a lQ-foot water depth.Pond effluent in excess of the
design storm event will undergo pH adjustment,as necessary,to a range of 6.0
to 9.0 by the addition of caustic reagents.
Yard and Area Drainage System
The yard and drainage system will convey all runoff from the plant site
to minimize potential site flooding.This discharge is not considered to be a
pollutant source or wastewater requiring treatment,because no contamination
of this discharge will occur onsite due to either process or materials storage
ac t i vi tie s.
2.1.8 Air Quality Control
Due to the low sulfur content in the coal (0.2%by weight)and the strin-
gent emission requirements of the New Source Performance Standards,the air
quality control configuration for the plant will be a semi-dry flue gas desul-
furization (FGD)system followed by a fabric filter baghouse.
The FGD system will consist of two spray dryer vessels using a lime
slurry.The FGD system will be designed to remove 70 percent of the sulfur
dioxide from the gas stream at rated load,which corresponds to 1.6 x 10 6
ACPM(a)at 250°F.Control of the spray dryer will be governed by both the
temperature and S02 concentration of the exit flue gas.The flow of lime to
the system will average 900 pounds of lime per hour.Lime pebbles will be
hydrated onsite by a single slaker with a capacity of 900 pounds of lime per
hour and pneumatically transported to two storage silos each located near a
spray dryer.Each silo will have a 3-month holding capacity,a volume of
approximately 39,000 ft 3•Each silo will also be approximatey 55 feet high
with a diameter of approximately 30 feet and include a 15-foot conical
(a)Actual Cubic Feet per Minute.
2.25
section.From the silos,the hydrated lime will be pneumatically transported
to mixing tanks provided below each spray dryer vessel.The two mixing tanks
will be sized for a 10-day capacity,with each tank requiring a volume of
approximately 3200 ft 3 Each tank will also be about 12 feet high,with a
diameter of approximately 20 feet.
The fabric filter baghouse for particulate removal will consist of four
parallel rows of compartments.Fabric filters will be designed to achieve a
particulate removal efficiency of 99.75%,in order to achieve a maximum emis-
sion rate of 0.03 lb per 10 6 Btu heat input to the boiler.Filter cleaning
will be by both reverse air and shaker methods and will be automatically pro-
grammed to be activated every 1/2 hour to 1 hour.The baghouse and associated
ash hoppers will be weather enclosed.Filter bags will be synthetic fabric
coated with acid-resistant polymer resin for a service life of approximately
3 years.Continuous baghouse hopper ash removal will be required via a pneu-
matic conveyor to a flyash storage silo.The conveyor will be sized for
22,000 lb/hr.
2.1.9 Ash Handling System
A steam-generator that burns coal produces solid refuse classified,in
general,as ash.The ash is of two types:bottom ash and fly ash.Bottom
ash is the material dropped out of the combustion products in either a dry or
molten state to the furnace bottom and collected in water impounded in bottom-
ash hoppers.Fly ash consists of fine particles that leave the furnace with
the flue gas and are collected in the baghouse system.
The total quantities of ash to be generated are a function of the ash con-
tent of.the coal and the steam-generator coal-firing rate.Based upon the coal
quality and the plant's design specifications discussed in previous sections
of this report,and assuming a fly ash/bottom ash ratio of 70/30,the antici-
pated quantities of ash are as follows:
Total Ash Production Rate
Bottom Ash Production Rate
Fly Ash Production Rate
Average
9.0 tons/hour
2.7 tons/hour
6.3 tons/hour
2.26
Maximum
12.0 tons/hour
3.6 tons/hour
8.4 tons/hour
Bottom Ash
The bottom ash will be continuously removed from the boiler.A water-
filled trough is to be located below the boiler hopper openings and will con-
tain a steel-drag bar-chain conveyor arrangement.This equipment will be
sized for a maximum capacity of 3.6 tons per hour based on a maximum coal ash
content of 11 percent.At the end of the trough,the drag bar will lift the
ash out of the water to an elevation about 20 feet above ground level.In
doing so the ash will be automatically dewatered to a moisture content of
approximately 20 percent and then discharged onto a conveyer belt.This con-
veyer will bring the ash to a storage silo.This silo will be located next to
the boiler house and is to be 30 feet in diameter and 8-1/2 feet high,with a
conical section 15 feet long.The silo will be raised to allow 15 feet clear-
ance for ash trucks.Special ash trucks of about 50-ton-capacity will trans-
port the ash to the permanent disposal site.
Fly Ash
The fly ash collected in the baghouse hopper and in the duct hoppers and
the baghouse,will be transported pneumatically (or by vacuum)to a fly ash
storage silo.This silo is to be 40 feet in diameter and will have a 20-foot
vertical section with a 2D-foot cone.The silo will be raised to allow a
IS-foot clearance for loading the ash trucks below.Trucks will transport the
ash to the final disposal site.Plant process waste water will be used to wet
down the fly ash to prevent the wind from carrying the ash away and to maxi-
mize ash compaction at the disposal site.
2.1.10 Solid Waste Disposal System
From the storage silos located at the plant site,all plant solid waste
will be trucked to a permanent solid waste disposal site,assumed to be situ-
ated in close proximity to the plant island.To permanently dispose of the
waste quantities generated over the 35-year life of the plant,a site encom-
passing approximately 50 acres,at an average depth of 50 feet,will be
required.It is anticipated that the area will consist of a natural ravine to
be ultimately enclosed by an earthen dyke.The final placing and compaction
of the ash will be carried out by a large rubber-tired spreading dozer.
2.27
To ensure compliance with the prOV1Sl0ns of the Resource Conservation and
Recovery Act and the state's solid waste management regulations,the disposal
area will be lined with an impermeable synthetic liner.The disposal site
will also be developed through a series of benches so that areas within the
site will reach their final elevation in stages.Once an area has been com-
pleted it will be covered with topsoil and reseeded to minimize leachate and
dust related problems.Disposal will start at the shallow end of the site,
away from the future dam site,to minimize the amount of exposed ash.
Lined drainage courses will be provided at the sides of the disposal area
to prevent excessive accumulation of water and consequent pile instability.
Runoff and seepage from the ash pile will be collected behind a small berm
located at the anticipated toe of the ash pile.This water will then be uti-
lized for ash pile dust suppression.
Because winter conditions could prevent the transportation of ash from
the plant to the final disposal site,should this distance prove to be con-
siderable,a temporary emergency ash storage area will be provided at the
plant.
To prevent water pollution,the area will be designed like a pond and
will be 6 feet deep,150 feet long,50 feet wide at the rim,and lined with
3 feet of clay.
2.1.11 Other Major Plant Equipment
Other equipment required for plant operation will include:
•Two condenser vacuum pumps,6.5 scfm at 70°F free dry air at I-inch
absolute and 475 scfm at 70°free dry air q.t 15-inch absolute con-
/denser pressure.'
•Two vertical pit-type service water pumps,4000 gpm each,80 feet
head.
•Three instrument air compressors,150 scfm,100 psig,oil free air
with receiver and dual instrument air dryer.
•Two sootblower air compressors,700 scfm at 300 psig.
2.28
•One service air compressor,520 scfm at 100 psig .
•Sixteen pumps,200 to 600 gpm and 100 to 300 feet head for miscella-
neous services.
All above listed equipment will include motors,baseplate,heat exchangers,
receivers,controls,oil pumps,etc.,as necessary to make them complete units.
2.2 FUEL SUPPLY
A principal factor in the selection of the reference locations for the
plants described in this report was the availability of fuel.The Beluga
Station would be located in sufficient proximity to the Beluga Coal Field to
allow delivery of coal by truck or conveyor.The Nenana Station would be
located near the Alaska Railroad in the vicinity of the community of Nenana,
allowing delivery of coal from the Usibelli Mine at Healy by unit train or
multiple carload lots.A location remote from the Nenana coal field was
chosen to minimize potential conflict with the Class I Prevention of Signifi-
cant Deterioration air quality area at Denali National Park.
2.2.1 Nenana Station
The proposed Nenana Station would receive coal from the existing Usibelli
Coal Mine at Healy.Deliveries would be by the Alaska Railroad using a unit
train or by multiple carload lots.A once-daily unit train operation could be
supported by a consist of locomotives and 45 bottom-dump hoppers of 50-ton
capac ity.
The Usibelli Coal Mine produces coal from the Nenana Field,currently at
a rate of about 700,000 tons per year (TPY).Existing production is directed
to the 25-MW mine mouth Healy Generation Plant of Golden Valley Electric Asso-
ciation.Additional coal is crushed and delivered via the Alaska Railroad to
the Fairbanks Municipal Utilities System coal-fired units at Fairbanks (29 MW),
the University of Alaska cogeneration units (13 MWe)and military installations
at Clear AFB,Eielson AFB and Fort Wainwright (37 MWe).No export coal is cur-
rently shipped,although test shipments have been made to Korea.
2.29
Existing mine capacity is about 2 million TPY,and with the possibility
of expansion,by addition of draglines,to 4 million TPY.At this higher rate
of production,mine life would be expected to be about 60 years (Swift 1981).
Maximum consumption for the 200-MW plant described in this report could be
expected to be about 950,000 TPY,(a)resulting in total mine production of
1,650,000 TPY,well within existing production capabilities.
The quality of Nenana coal is as follows:(b)
Heating Value (average)
Ash Content
''''oi sture
Hardgrove Gri ndabi 1 ity Index
Ash Softening Temperature
Ash Na 20
Sulfur
Nitrogen
2.2.2 Beluga Station
8000 Btu /l b
7-8%average,11%maximum
25-30%
-34 as mined
2100°F
0.08%
<0.25%
0.60%
The proposed Beluga Station would use coal from the currently undeveloped
Beluga Field.The plant would be essentially mine mouth,with coal deliveries
by truck or conveyor.
The surface-mineable Chuitna Lease (used as a reference field for the
Beluga region)is located about 12 miles from tidewater on the west side of
Cook Inlet.The mine area would also be about 12 miles from the existing
Chugach Electric Association Beluga Generation Station.
A recent report by Bechtel Corporation (Bechtel 1980)indicates mineable
reserves of 350 million tons with a stripping ratio of 4.4.Production levels
(a)Assuming a maximum capacity factor of 87%.
(b)Note that a composite "Rai lbelt Standard"coal (Section 1.0)was used for
plant design.
2.30
in the
2)instal-
A capaci ty
this time
of up to 11,700,000 TPY could be sustained for 30 years without significant
depletion of the reserves that have received the greatest attention (Swift
1981).
The Beluga Field could be economically opened with the establishment of
an export market.The outlook for development of such a market appears to be
excellent,and allowing time for mine design and development,environmental
and licensing activities,it appears that Beluga coal could be available as
early as 1986 but more certainly by 1988 (Swift 1981).
It is also possible that electric power development of sufficient size
could justify opening of the Beluga Field.Current thinking is that an
installed coal-fired capacity of approximately 800 MW would allow economic
development of this coal.
In conclusion,it appears that coal could be available by 1988
Beluga area given either 1)the development of an export market;or
lation of substantial (800 MW)electric power generating capacity.
increment of this size,however,does not appear to be warranted in
frame.
Run-of-mine quality of Chuitna lease coal is expected to be as follows:(a)
Heati ng Value
Ash Content
Moisture
Hardgrove Grindability Index
Ash Softening Temperature
Ash Na20
Su lfur
Nit rogen
7500-8200 Btu/lb
7-8%
20-28%
20-25%
2350°F
0.95%
0.16-0.18
N.A.
(a)Note that a composite "Railbelt Standard"coal (Section 1.0)was used for
plant design.
2.31
-----------------------------p--
2.3 TRANSMISSION LINE SYSTEM
An engineering report prepared by Commonwealth Associates (1981)recom-
mends construction of 160 miles of new transmission lines at 345 kV from Healy
to Willow with 138 kV exits at Healy and Willow.However,this study did not
consider the 200-IVlW plants proposed at Nenana and Beluga in this report.
Using the Commonwealth report as a basis,and in the absence of a trans-
mission line study including plants proposed in this report,the following
transmission line arrangement is suggested (refer to Figure 2.9).The hub of
the transmission system would be a 345-kV substation at Willow (refer to Fig-
ure 2.10).Transmission lines (345 kV)from Anchorage,Beluga,and Nenana
would terminate here.This substation will provide flexibility and relia-
bility to the system load flow.The tie line to the north would run approxi-
mately 160 miles to the proposed 200-MW Nenana Station.The existing 138-kV
line from Fairbanks to Healy would be opened and connected into the Nenana
Substation.This arrangement will allow Fairbanks,Healy,and the tie line to
Willow to receive the power generated at Nenana.This flexibility will also
allow startup power to be drawn from any of these possible sources.The
switchyard voltage level of 138 kV at Nenana was selected on this basis.
Using the projected peak demands for Anchorage and Fairbanks through the
years 1984-1995 (as listed in the Commonwealth report)and assuming no further
generation is added in Fairbanks as replacements or new units,the Nenana area
plant can supply Fairbanks needs for many years.Assuming the coal supply is
adequate,additional units can be added to Nenana as required.Additional
138-kV lines may be necessary to Fairbanks as well as increasing the capacity
of the existing line.The size of the 345/138-kV autotransformer at Nenana
will be determined after a study indicates the anticipated load flow on the
tie line.
A new 345-kV line of approximately 75 miles in length,from Willow to the
proposed 200-MW Beluga Station will tie the output of this plant into the sys-
tem.Again,the sizing of the autotransformer for the 345-kV line must be
2.32
l.
~E~IJ-;- -z.m..,v~
I
~'D""W
'5.e:..5T ATIOI\I o ....~.
,--------l
I ~l::vSUBS""A
;&:,.dIE IJfp.c
iJ ''"...~~~,'"
,ll
of
I
I
I
169 KV 6w YO I------.....
h'l!~i~
I-~.-.1-
,---1-------,
I ~B>E LUc:iAI~::5,E 'STJ:\.I
L ~U"'D~fC I
I -z.'t.O /oM)ft ~4-s,''<3SI'-V 1
I ~
~ll/l
I ~'-Q-/~1~~2.~7 I->JAoJ'-2 '<?,""WI.&J I "~/~I (jj .".a.P.!".
I
I
I
ISo't.
"""t.£.$
E.)<'~TIN&'''-91<11 Likl E~
TO
POINT MAC.KENZ/E
BELUGA COMB.TUAe,
PU~NT
EXISTING I~~KV ~W YI
?iI<I:
Ul
1'!>6 K"-:r
.----t~~1~'S-~~~.,..~~- -
~.r;:;'-TI~'dl~-I
"4:u..
v
ww
N.
FIGURE 2.9.Nenana and Beluga Station Switchyards and Tie Lines
.---_.;:::::;:::;::---
~Zi~
~tK:>I(45 ~~JENA~
»»
I Irrx
-
N....
X .....
""
0
x ctl
N
N
........
X X
0 ..§
CO i ';
i F'E~E
X ~.....X.....
.....
""
r ....
I c-.,
x
LW
N
N
~
2C 'x-''
~
FIGURE 2.10.Willow Substation
2.34
(
determined after the system study is completed.The probability of future
additional units at Beluga is a factor to be considered.
At present,there is an existing Chugach Electric combustion turbine plant
near Beluga with approximately 300 MW of capacity.This plant's outlet voltage
is 169 kV.Several lines connect this plant to Anchorage by an underwater
crossing of the Knik Arm.This existing route was considered for the proposed
Beluga coal plant output.However,in our estimation,the overhead tie line
to Willow is more feasible than an underwater crossing.The inclusion of a
169-kV tie line between the existing combustion turbine plant and the proposed
fossil plant will add flexibility.The turbine plant switchyard will need
modification to add this line.The startup power required for the Beluga
fossil plant could then be drawn from the combustion turbine plant or the tie
line from Willow.The fossil plant switchyard voltage of 169 kV was selected
based on this arrangement.
With this configuration,the output of the Beluga fossil plant can then
be transmitted from Willow to either Anchorage or Fairbanks.
Presently,there is a 110-kV line in operation from Anchorage (Mackenzie)
to Willow.It appears that large blocks of power will be transmitted over this
tie;for this reason,replacement of this line by a 345-kV tie would enhance
the North-South overall transmission system.This line is approximately
52 miles long and its inclusion would mean construction of a 345-kV substation
or terminal at Mackenzie.
As previously stated,the above proposed tie line arrangement is offered
without the benefit of the system study necessary to give a firm base to this
proposed arrangement.Load flow estimates are necessary to determine the
transfer capability,I 2R losses and reactive power requirements.
The previously cited study indicated a 9 percent loss if 70 MW was trans-
mitted on the tie line at 345 kV using 2-1272 KCMIL ASCR conductors per phase.
Towers were based on a 1200-ft span.
The major pieces of equipment at the Willow Substation will be as follows:
•345-kV Main and Transfer Buses
2.35
pimifi,4iM4 A4LQ'
•Four bays each consisting of one 345-kV circuit breaker and three
345-KV disconnect switches.
The transmission line system will also require the following:
•The addition of a 169-kV bay at the existing Beluga combustion tur-
bine plant
• A tie line at 169 kV from the existing Chugach Electric Beluga com-
bustion turbine plant to the Beluga coal-fired plant,a distance of
approximately 50 miles
•The addition of a 345-kV terminal at Mackenzie
• A tie line at 345 kV from Willow to Mackenzie,a distance of 52 miles
• A tie line at 345 kV from Willow to Nenana,a distance of 160 miles
•Rerouting of the existing 138-kV line from Healy to Fairbanks into
the Nenana switchyard.
2.4 SITE SERVICES
The construction and operation of a 200-MW coal-fired power plant will
require a number of related services to support all work activities at the
site.These site services could include the following,depending upon the
actual location of the power plant:
•Access Roads
•Construction Water Supply
•Construction Transmission Lines
•Airstrip
•Railroad Spur (Nenana site)
•Landing Facility (Beluga site)
•Construction Camp
2.4.1 Access Roads
Gravel roads with a 9-inch gravel base will be required to connect the
plant site with the equipment landing facility for the Beluga site and with
2.36
the Anchorage-Fairbanks Highway (Route 3)for the Nenana site.For both loca-
tions it has been assumed that approximately 20 miles of access road will be
re qui red.
2.4.2 Construction Water Supply
A complete water supply,storage and distribution system will be installed.
Due to the remote nature of either general location,a one-million gallon water
storage tank has been assumed,with one-half of this storage capacity dedicated
to fire protection purposes.Water supply to the project site should be by
means of a 150 gpm well(s).
2.4.3 Construction Transmission Lines
Power requirements during the construction phase will be supplied by con-
structing a 25-kV transmission line tapped from an existing transmission sys-
tem.At a potential Beluga field site a transmission line length of 20 miles
is assumed and will be derived from the existing Chugach Electric Association
system at either the town of Beluga or Tyonek.For the Nenana area site,the
25-kV transmission line system is assumed to be derived from the existing
Healy-Fairbanks intertie and be approximately 20 miles in length.
2.4.4 Airstrip
For either general power plant location,a 4,000-foot-long,60-foot-wide
gravel airstrip will be provided.It is anticipated that all personnel travel
will be by air with pre-arranged commercial charter carriers.All perishable
goods will be flown in.Equipment for construction will be flown in only under
extraordinary circumstances.The largest airplane that will be able to land
on the strip will be the size of a DC-3.
The airstrip will be lighted using an above-ground distribution system to
provide for the possibility of night-time medical emergency traffic.No con-
trol tower will be required.All air traffic will be on a Visual Flight Rule
(VFR)basis only.
2.4.5 Railroad Spur
A railroad spur will be constructed at the Nenana field site due to the
proximity of the Alaskan railroad.The spur will be utilized to receive fuel
2.37
from the mine,operating supplies and equipment shipments received in
Anchorage.The length of this spur has been conservatively estimated to be
approximately 20 miles.
2.4.6 Landing Facility
The Beluga field site will require construction of a marine landing facil-
ity to receive all construction materials,equipment and supplies.The landing
facility would be located on Cook Inlet and be suitably dredged to accommodate
military-type landing craft for delivery of goods.A paved,fenced interim
storage area will be provided.A heavy-duty haulage road will be provided
from the landing area to the access road.
2.4.7 Construction Camp Facilities
A SOD-bed labor camp will be provided.The camp layout is presented in
the plot plan (Figure 2.3).All personnel housed in this camp will be on sin-
gle status.Provisions will be made to accommodate a work force containing
females (separate bathroom and locker facilities).
The camp will have its own well water supply.A sewage treatment facil-
ity,waste incineratQr,and garbage compactor will also be provided.The
complex will also have a dining hall and recreation hall.
Since it is unlikely that all personnel would be willing to come to the
job site on single status only,a mobile-home park will be provided for 16
supervisory personnel in family status.These mobile homes will be approxi-
mately 1000 ft 2 each and could remain after completion of construction to
house vendor personnel for repair work during plant operation.
2.5 CONSTRUCTION
The number of workers necessary for construction of a 200-I\1W station will
vary over the approximate 4-1/2 year construction period.The distribution of
this work force over the construction period is shown in Figure 2.11.Con-
struction is estimated to peak in year 2,requiring a workforce of approxi-
mately 500 personnel.
2.38
.500
543z
FIR:ST WINTER ~HUTOOWN
I
zoo
100
1&1 400
\J
~Li:
~300
~
YEAR~
NOTE;Ooe~not include vendor per:50nnel,own~r per601."e(.
01""A/~eng inee-r$located at ~ite.
FIGURE 2.11.Construction Workforce Requirements
Construction of this 200-MW station will follow normal acceptable con-
struction methods.A program of this magnitude begins with orderly develop-
ment of the following requirements:
1)Construction camp and utility services,such as electric light and
power,water for industrial and potable use and fire protection,
sanitary facilities,telephone communications,etc.
2)Temporary construction office facilities (with heating and ventila-
tion furnished by contractors as required)
3)Temporary and permanent access roads,railroad spur (for Nenana
Station)and marine landing facility (Beluga Station)
4)Temporary enclosed and open laydown storage facilities
5)Delivery of various types of construction equipment and vehicles,
such as earth-moving equipment,concrete and materials hauling
2.39
equipment,cranes,rigging equipment,welding equipment,trucks and
other vehicles,tools,and other related types of construction equip-
ment by truck,rail,or landing craft or a combination of these
depending on the site
6)Temporary office and shop spaces for various subcontractors
7)Settling basins to collect construction area storm runoff
8)Permanent perimeter fencing and security facilities
9)Safety and first aid facilities in compliance with OSHA regulations.
Following completion of these initial construction site related activ-
ities,power plant systems construction will be initiated.The activities
involved in the overall construction process as well as the plant's detailed
development schedule are presented in Figure 2.12.
2.6 OPERATION AND MAINTENANCE
When the coal-fired steam-electric power plant begins commercial opera-
tion,the facility will provide employment for approximately 109 employees.
Of this total approximately 67 will represent operating staff,while 42 will
be maintenance personnel.An estimate of the plant's staffing requirements is
presented in Table 2.2.Employment of these personnel will continue through-
out the 35-year life of the plant.
Plant systems will be operated from the control room located in the main
plant building.Some of the systems and equipment will also be controlled
from local stations.In general,controls are automatic,although operators
can override the automatic controls and operate the plant manually.To supple-
ment the operational controls,the station will be equipped with an alarm
system,fire protection system,proper lighting,and a radio-telephone communi-
cation system.For both station locations,two diesel generators of approxi-
mately 1,500 kW capacity will be required to provide enough power for startup
and safe shutdown of the units under trip and black-out conditions.
2.40
YEAR 1 -YEAR 2 YEAR 3 YEAR 4
J A S·0 N ·D J F M A M J J A S 0 N D J F M A M J .J A S 0 N D
J.F M A M J J A S 0 N D••rn •16 64 1I3 tI2 11 80 iii 58 57 66 55 64 53 62 61 60 49 49 47 48 46 44 43 42 41 40 39 38 .:r1 38 3S 34 33 32 31 30 29 28
I
UTE~An1..E R~..l.EoJ......PRba D~V
•=
II:
Do
.~
I E
.~,l-
ll:,'U•
0
II:,>
,
EPA PSO EVIEW
2.41
.-..:...
-- -.--- ---
PSO APPROVAL --l----,
I
,I
!
!,
I
Project Schedule
i
REP
PPL
FIGURE 2.12.
I
SCHEDULE
- ---~-
PROCEDURE r.-~lXIST EST
A M J
.72 71 70
ENVIRONMENTAL STUDIES (REFER TO FIGURE 6-0
AOes
PROJECT 'ROC.SCHEDULE AND COST ESTIMATE
COOLING SYSTEM
WASTE WATER AND SOLID WASTE MANAGEMENT
DEY SITE,PLOT PLAN.GAS flO.ONE LINE PROJECTIZE
SDD/CDC-OPDD
.:lRINGS AND SOIL REPORT
INTAKE DISCHARGE SYSTEM
STACK HEIOtn:
PLANT OnlMIUTION STUDIES
LICENSING
LOCAL BUILDING PERMITS (REFER TO SECTION 6.3)
CONCEPTUAL ENGINEERING STUDIES
ENVIRONMENTAL REPORT APPLICATION (REFER TO FIGURE 6-0
PREVENTION OF SIGNIFICANT DETERIORATION IPSDI APPLICATION
SITE SOIL INVESTIGATION
STATE LICENSING AND PERMITS (REFER TO FIGURE 6-0
CONCEPTUAL DESIGN
;-
e-
SITE PREPARATION -CLEARING
A M
12 71
YEAR 1
JJASONOJFM
70 61188 S7 88 66 64 8382 81
..kc-I--:
YEAR 2
AMJJASO
80 68 68 57 68 55 64
~~::FIN
YEAR I YEAR 4
F M
60 019
YEAR IS :
ONDJFM
30 28 28 27 28 2S
N D
17 18
J F M A
15 14 13 12
YEAR 0
M J J
11 10 t
A
8
S
7
o
8
N
5
D
4
J
3
YEAR 7
F M A M
2 1
ic.w.PPG
-~-~T~
~,.--~UNGND PPG.DUCT
-1--
'ONS .su...f CONT dRAOINO
I-
...
I
...
I...
;-
,
EXCAV BACKFILL.ORADING DRAINAGE
ROAD,RAILROAD DRA~HGS
FABRICATION &DELFIN~~81~~ALCLIENTREVW
ROADS,WALKWAYI,FENCES
EXCAVATION
-GRADINGEARTHWORK
iT
_'LET ~!'~-J--------------.-A-'L-RO-A-O----------+-----+-+---+-+---t---==F-=1F-=t---=-I--+-1--+-t---.I;'--+f--.PRELlMDWGS
--~=~="'""==c===--------------+-_+-+_CWSriuDIESQRCULATINGWATERSYSTEM-'IPING -~-!
--------------COO--U-NO-T-OW-E-R-.U-'-E-RST-R-UCT-U-RE---+-+--1NT~~,DI~STUDY ~+-SPEC-t--:c,.L~~~l
COOLING TWR FDN AND BASIN
INTAKE STRUCTURE AND EQUIPMENT
I
SPEC-f---;c,.LJ~J FIN l:--BID eJL.~
FIN~BlD~VAL~PO
COOLING TWR BASIN,INTAKE _....
Fls.~EL JeL CW..J,
---1----'Ii I,
.;.,j-~---
I'I I
~oi--
I,
, 1
--1--
_.J.._
C.T.'ON.BASI
---._--
c.Y.SUPERSTR
EOUIP
-===~§~~~~~:=============~~~~~~~~~~~~~~~~~~~~~~=====t=:t==t==t==i==i==j==j==j==j~=j~==~==~==~==t==tl==t==t~o~J~.~LR~IST~L:i!~E*~PR$EL~O~E~S~IG~N\==I!~~:;:~'~I.J..~L~O~~IG~Ng:.~O~~~A'~W~IN~G~·=*:::!i::=t=:=:=1=:=*~'ct'=:=~~=~'=F'*ST~R~',ON~~~~='~*'~IE~O~:FD~NS~I:::!~=+~hd=~t=l:::=t=t=t=t=t:=t=t=tj=t=1=t::j=:j:::Z21--+--I--+--_CONCRETE -lITRUCTURALFDNS:BOILEAAREA I-;,:--_
EQUIPMENT AND flOORS PRELIM IOESlrlN FINAL DESIGN.D~AWI~GS _1-_1_i__I ,.srL :o:.s .E~:~~_t-T-GIAccBs:_~'+,_-I--I--.,.I--+--I--+-I-_j.-+--J.-+---+-S ~~I--2f--
TURBINE "RE"..t-~.-I--~!---1---.,...~~~f----
:===================~~~===j=tj=tj=tj~t=~=t=~=+=t:=+=tj=t::j=+::j=I~~=*=L~OE~.~IJ~N~.~O$R~A~"$N~G~S~:§~~_~=_~~.,=_~_==t~t:~~jl~t~'=:t~~t==~4!~~=gll~T~!o~'~EO~I~'~'~~=-*"~~':~T"U~R~~~G~EJ~_~CO~N~LD~t,~-~:t=t:::t=t::j=t::j=+::j=t=j~:tj~:t=~~=f--PEDESTAL ----~-_.--r--I""'"~-t :!~I-----------------------..-LO-OA-y----I--+-I--+-+--+-+---t-+--jl-+-I-+-I--+-I--+-+-_+-+_--t-+--I--I+V!~~R!LD 1---J--iDESIGN&DRAWiNGS.=-l:I.SILOEiAV _.~~~8~~EEl.---+---+.--::.....+--+--'!--+-+---t-+---t-+--t-+--jI-+--jI-+-I-a:i=j--t--+--t--
:
__~_CH !2UI~_+-:-I
_~j:!E~~.-J~--:::.L--!-+--j'-+-I--+-I-I--+--i--+-I--+-I--j.-+--+-I-
.JRS-I-
I ::OAL MDLG CbNC",
-4--
I I I I t cHMV
~~-
I ;ADCS~~C I
I I
-~-
r--....-
_..._J...__
-1--
--_....----,...1--1--4--.-
JESIG~•DRAWI~GS
DES&DWGQtIMNEY
AQCS -r~E!!.~'!..L2.~
--------------------=-=====-+---i--+--+-+__j-+,-f-+-l-+-t--t-t--t-+--+--t--+-+=.--+-_1ENob_RJA_O-L-I--TUN~:kjG~~:A:~:~NS.COAL HANDLING
~!~,,+~::-+...-I-+--j-+--j-+I-f-+-If-+-I--+-+--+-".A~ST~EL
,
COALSIL~
"T..sfEELU CRANE
1 'L'I
L...._.J._
ERECTION ~,
STR STL CONTA CT------,...
-----....
"_-__.J
_;:r__
--~---~
-..,.--~
1-.
FINISH DES.DWGS
SPEC---;Ci~~T FIN ~BIDEVAL~PO..1----..l-FABRICATION.DELOFCOLllLOALDBUPPORTS
PRELDES
SILO BAY
COAL SILOS
STACK
STEEL -TURBINE BUILDING -...,-
--~--~--
BUILDINGS -TURBINE BUILDING WALLS.SIDING
BOILER AREA
SPEC ~~~~T fiN ~BlDEVAL.PO
I I I
-._-
I
I
I I
I
FIGURE 2.12.(contd)
2.43.
YEAR 1 YEAR 2 YlAR 3 YEAR 4 YEAR 5 Y AR'YEAR 7A M J J A S 0 N D J F M A M J J A S 0 I~D J F M A M J J A S 0 N D J F M A M J J A S 0 N D J F M A M ~J A S 0 N D J F M A127110Il9685768 65 64 83 82 81 80 ll9 58 57 58 55 64 52 51 50 49 48 47 48 45 44 43 42 41 40 39 38 37 38 35 34 33 32 31 30 29 28 27 28 25 24 23 21 :lO 19 18 17 M J J A I 0 N D J F M A M J181514131211109•7 •5 4 3 2 1OOALANDASHHANDLINGCOALHLOO..!!."--~ECJ.IM SYSTEMRECLAIMSYSTEM,
,I'-1--1--.
TRANIFER SYSTEM PURCHASE ORO~~~---+--TRANSFER SYSTEM
__~HDU!!ON_--FURNACE ASH EQUIPMENT .1-_ll(C -...------I---FURNACE ASH EQUIP,-
PIPING DESIGN AND DRAWINGS MEat CONTRACT UNDERGROUND PIPING-UNDERGROUND
~CLIENT WBIDEVAL ,\,,
SPEC-REVW FIN ..0 FABRICATE AND DELIVER \
".RH.8F COHO
.....INSYSt"EM ,,,,I '-....-~-----<',
OTHER OTHER.VI:..
INSULATION PI'E AND EQUIPMENT ,INSULATION.LAGGING
,!;-IIAIlC',.........~.U~INSTRUMENTATION -BASIC I DESIGN ENGINEERINQ-CNTRL.INST CONTRACT-
-.CLIENT FIN <--
BID EVAL
FA86DE'L
,,
SPEC REVW .PO -co-unACOWUTER...--
J.C-I--::CLIENT FIN ..--IUD EVAL ...coooel.rJ.CON1'1lOI..REVW .PO FAS.DELCOMBCONTROLS ------Z
CLIENT BIDEV"F1BRICATION.D~L I ---~~-:---J.-..J.,N.~UX.1T8Y 0 ...--
SPEC-I--::~REVW FIN <-.PO -START.tJP ;::ll--ELECTRICAL EQUIPMENT -TRANSF.--- - -
-~,~.- -- --.-1--1.-c-FOUNDAnON DESIGN a:ffif-~C-CLIENT BID EVAL --.......
I--::REVW FIN <-.PO ,,
FAS.DEL :-•BA •T8 FLR',-SWOR.POWER CTRS.MOTOR CONTROL C'TRS ~SWITCHGEAR.POWER CTRS.YCC -..._..-----1 ..--- - -
..;1-
CLIENT FIN ~I F1..JEL --CONTROL:r~6THEL ~"C
SPEC-I-----,REVW DEYAL&PO ~BTG AND OTHER BOARDS -f-.._-1 !--_..----+----.-j
I I T-G-,.....,
OENlGENLEADSANDPROT
RAY OR WNDINO.JNDERGROUHD COHO ~~.I[MG
,:--.-.+......-ICONDUIT.I I ~-8A,.T8STEEL
EXPOSED eb..oJIT.CABLE tRAYS.ETCEXPOSEDCONOCABLETRAYS.ETC ~CLIENT BII~~AL--:_EXC ;-1--..-- -
ISPEC-REVW FIN e-,.--FABRICATION.DEL -H IELEC COrhRACTS ....I UN~RGROUND CONDUIT AND GROU~NG ,
UNDERGROUND CONDUIT.GROG I I
....EC '---:CLIENT FIN e-81DEYAL --:,---FAB~ICA1IDN~DEL
'a POWER AH~-l-CONTROL WIRING ."REVW .PO .J LPOWERANDCONTROLWIRING - ---------
PAINTING '~'NT :o...l.,AI.......
YARD
liTE 'RE'cONTR
t.......- -
ASH PONDS
ASH PONDS I
I I
MAKE-uP WELL ...-!------......-....
LANDSCAPING i CllHTIIACT f-=.1---
FIGURE 2.12.(contd)
2.47 .
TABLE 2.2.Plant Staffing Requirements
Job Tit 1e
Plant Superintendent
Operations Engineer
Shift Superintendent
Control Roo~Operators and
Auxiliary Operators
Chemi st
Chemical Technician
Results Engineer
Results Technician
I&C Engi neer
I&C Technician
Storekeeper
Storekeeper Help
Clerical
Maintenance Superintendent
Maintenance Engineer
Maintenance Foreman (Elec/Mech)
Mechanics (6-Man Crews)
Maintenance Foreman (I&C)
Mechanics (6-Man Crews)
Labor Foreman
Labor Crew
Fire Protection/Security
Coal-Yard Crew &Ash Disposal
Foreman
Caterpillar Operator
Breaker House
Equipment Maintenance
Caterpillar-Truck Operators
Bottom &Fly Ash
Permanent Ash Disposal Site
Scrubber
Auxiliary Operators
Equipment Operator
Mechanics
Total
Staff
Required
1
1
4
8
1
1
1
1
1
4
1
1
3
1
1
2
12
1
6
2
8
4
3
4
3
1
3
4
3
12
3
8
109
NOTE:The above staffing is required for three
8-hour shifts and seven-days-a-week
operation.
2.49
To prevent mechanical failure,periodic maintenance will be performed on
all pressure systems,rotating machinery,heat sensitive equipment,and other
operating equipment for malfunctions,leaks,corrosion and other such abnormal-
ities.In addition,the maintenance programs will monitor the revegetation
and erosion prevention programs initiated during the cleanup phase of construc-
tion.Trained maintenance crews will perform operational maintenance and will
correct emergency malfunctions.
In general,all major maintenance functions will be performed during the
plant's annual scheduled outages.The length of time required for these sched-
uled outages is estimated to be approximately 675 hours per year for plants
ranging in size from 100 MW to 300 MW.This value corresponds to a scheduled
outage rate(a)of 8 percent.
The power plant will also experience periods of forced outage,defined as
the occurrence of a component failure or other condition that requires the unit
be removed from service.Estimates of forced outage hours and forced outage
rates(b)for various-size units are presented below:
Forced Outage Hours Forced Outage Rate
Unit Si ze (h0 urs /yea r)(percent)
150 390 4.8
200 460 5.7
250 535 6.6
If properly maintained,power plants in the size range of 150 MW to 250 MW
should be able to experience heat rates of approximately 10,000 Btu/kWh over
their entire plant life.
(a)
(b)
Scheduled Outage HoursScheduledOutageRate=S . H +S h d 1 dOterVlceoursc e u e u age
F d A t R t
Forced Out age Hoursorceuagea e = .Servlce Hours +Forced Outage Hours
2.50
Hours x 100
x 100
___________________________________\1 _
3.0 COST ESTIMATES
3.1 CAPITAL COSTS
3.1.1 Construction Costs
Construction costs have been developed for the major bid line items com-
mon to coal-fired power plants.These line item costs have been broken down
into the following categories:labor and insurance,construction supplies,
equipment repair labor,equipment rental,permanent materials,and subcon-
tracts.Results of this analysis are presented in Table 3.1 for the Beluga
Station and in Table 3.2 for the Nenana Station.
Equivalent unit capital costs are as follows:
Beluga Station
Nenana Station
2050 ~/kW
2110 ~/kW
3.1.2 Payout Schedule
Payout schedules have been developed for the entire project.Table 3.3
contains monthly payouts for the Beluga project,and rable 3.4 contains monthly
payouts for the Nenana project.Payout schedules for both projects were based
on a 48-month basis from start of project to completion.
Equivalent annual payouts are as follows:
Beluga Station Nenana Station
Year $%$%-
1 72,006,000 17.6 76,720,600 18.2
2 119,372,000 29.1 121,283,000 28.8
3 121,096,600 29.5 126,740,600 30.1
4 97,687,500 23.8 96,622,200 22.9
3.1
TABLE 3.1.Bid Line Item Costs for Beluga Area Station(a)(January 1982 Dollars)
Construction Labor Construction Equipment
and Insurance Supplies Repair Labor Equipment Rent
Permanent
Materials
Total
Subcontracts Direct Cost
W
N
l.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
Improvements to Site
Earthwork and Piling
Circulating Water System
Concrete
Struct,Steel,Lifting Equip.,Stacks
Buildings
Turbine-Generator
Steam Generator and Accessories
Air Quality Control System
Other Mechanical Equipment
Coal and Ash Handling
Piping
Insulation and Lagging
Instrumentation
Electrical Equipment
Painting
Off-Site Facilities
Waterfront Construction
Substation
Indirect Construction Cost and
Architect/Engineer Services(b)
Subtotal
Contractor's Overhead and Profit
Contingencies
TOTAL PROJECT COST
$350,000
2,541,000
2,511,000
5,733,000
1,757,000
682,000
1,800,000
15,764,000
12,400,000
576,000
14,435,000
1,000,000
1,015,000
1,275,000
44,515,000
$106,354,000
21,000,000
$2,100
3,888,000
174,200
540,000
22,000
50,907,000
$55,533,300
9,000,000
2,562,000
$2,562,000
$901,000
5,706,000
2,391,000
1,091,000
92,000
2,084,000
$12,265,000
$110,000
16,000
1,235,000
2,387,000
7,155,000
800,000
19,500,000
21,800,000
27,100,000
8,950,000
1,500,000
9,000,000
1,100,000
2,686,000
9,000
$103,348,000
10,000,000
5,000,000
1,500,000
3,000,000
30,000,000
3,000,000
600,000
$53,100,000
$1,363,100
12,151,000
16,311,200
9,751,000
8,912,000
1,482,000
21,300,000
37,564,000
39,500,000
8,950,000
7,076,000
23,435,000
1,500,000
3,000,000
31,000,000
2,115,000
3,000,000
600,000
4,075,000
100,077 ,000
$333,162,300
30,000,000
47,000,000
$410,162,300
(a)
(b)
The project cost estimate was developed by S.J.Groves and Sons Company.No allowance has been made for land and land rights,client charges
(owner's administration),taxes,interest during construction or transmission costs beyond the substation and switchyard.
Includes $39,229,000 for construction camp,$31,300,000 for engineering services,and $29,548,000 for other indirect costs including construction
equipment and tools,construction related buildings and services,nonmanual staff salaries,and craft payroll related costs.
-_.'"----~------1
L..wnw t t <»_.r#tttlfttt eM af ,iM,rnttW Mtt'*1~r---~.~-_.W 'P'>ri.•......'w ''"y,",...".,'",.....'I>...,"rt'(HM'·n ..?!,,'it 5,"'h ,(,,'f',,',r
TABLE 3.2.Bid Line Item Costs for Nenana Area Station(a)(January 1982 Dollars)
Construction Labor Construction Equipment Permanent Total
and Insurance Supplies Repair Labor Equipment Rent Materia~Subcontracts Direct Cost
I.Improvements to Site $350,000 $2,100 $$901,000 $110,000 $$1,363,100
2.Earthwork and Piling 2,100,000 13,000 5,400,000 16,000 7,529,000
3.Circulating Water System 2,561,000 174,200 2,391,000 1,235,000 11,500,000 17,861,200
4.Concrete 5,982,000 540,000 1,091,000 2,387,000 10,000,000
5.Struct,Steel,Lifting Equip.,Stacks 1,757,000 7,155,000 8,912,000
6.Bui ldings 682,000 800,000 1,482,000
7.Turbine-Generator 1,800,000 19,500,000 21,300,000
8.Steam Generator and Accessories 15,662,000 138,000 12,000 21,800,000 37,612,000
9.Air Quality Control System 12,400,000 27,100,000 39,500,000
10.Other Mechanical Equipment 8,950,000 8,950,000
II.Coal and Ash Handling 1,937,000 18,000 150,000 5,785,000 7,890,000
12.Pip in 9 14,435,000 9,000,000 23,435,000
13.Insulation and Lagging 441,000 46,000 11,000 1,049,000 1,547,000w.14.Instrumentation 3,000,000 3,000,000w
15.Electrical Equipment 12,720,000 1,150,000 800,000 18,000,000 32,670,000
16.Painting 1,142,000 58,000 25,000 575,000 1,800,000
17.Off-Site Facilities 4,827,000 3,600,000 3,260,000 11,687,000
18.Waterfront Construction N/A
19.Substation -Switchyard 1,623,000 34,000 143,000 3,017,000 4,817,000
20.Indirect Construction Cost and
Architect/Engineer Services(b)54,943,000 42,560,000 2,882,000 2,617,000 9,000 103,011,000
SUbtota 1 $135,362,000 $44,733,300 $2,882,000 $17 ,141,000 $132,748,000 $11,500,000 $344,366,300
Contractor's Overhead and Profit 21,000,000 9,000,000 30,000,000
Cont i ngenc i es 47,000,000
TOTAL PROJECT COST $421,366,300
--
N/A =Not Applicable.
(a)The project cost estimate was developed by S.J.Groves and Sons Company.No allowance has been made for land and land rights,client charges
(owner's administration),taxes,interest during construction or transmission costs beyond the substation and switchyard.
(b)Includes $40,816,000 for construction camp,$31,300,000 for engineering services,and $30,895,000 for other indirect costs including construction
equipment and tools,construction related buildings and services,nonmanual staff salaries,and craft payroll related costs.
TABLE 3.3.Payout Schedule for Beluga Area Station
(January 1982 Dollars)
Mooth
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
Cost per Month,Doll ars
789,400
7,310,700
7,287,500
7,287,500
6,831,700
8,762,700
7,413,500
7,539,700
7,364,100
7,285,600
2,017,300
2,017,300
2,017,300
7,154,500
8,676,200
10,489,800
10,489,800
10,541,600
10,914,500
10,914,500
10,914,500
10,914,500
13,031,200
13,313,900
10,830,900
10,458,000
10,458,000
10,458,000
10,458,000
10,458,000
10,458,000
10,458,000
10,406,200
8,884,500
8,884,500
8,884,500
8,660,200
8,985,600
8,985,600
8,985,600
8,985,600
8,985,600
8,985,600
8,985,600
8,985,600
8,985,600
3,963,400
4,193,500
3.4
Cumulative Cost,Dollars
789,400
8,100,100
15,387,600
22,675,100
29,506,800
38,269,500
45,683,000
53,222,700
60,685,800
67,971 ,400
69,988,700
72,006,000
74,023,300
81,177 ,800
89,854,000
100,343,800
110,833,600
121,375,200
132,289,700
143,204,200
154,118,700
165,033,200
178,064,400
19.1,378,300
202,209,200
212,667,200
223,125,200
233,583,200
244,041,200
254,499,200
264,957,200
275,415,200
285,821,400
294,705,900
30 3,590,400
312,474,900
321,135,100
330,120,700
339,106,300
348,091,900
357,077 ,500
366,063,100
375,504,870
384,034,300
393,019,900
402,005,500
405,968,900
410,152,400
::..hA.....,__
~
TABLE 3.4.Payout Schedule for Nenana Area Station
(January 1982 Dollars)
Mooth Cos t .e.er Moo th,_DolJ ars 9umulative _~ost,Dollars
1 75'4,800 754,800
2 7,552,800 8,307,600
3 7,529,300 15,837,900
4 7,529,300 23,366,200
5 7,078,000 30,444,200
6 9,104,500 39,548,700
7 7,768,100 47,316,800
8 7,894,900 55,211,700
9 7,818,200 63,029,900
10 7,640,700 70,670,600
11 3,025,000 73,695,600
12 3,025,000 '76,720,600
13 3,025,000 79,745,600
14 7,880,300 87,625,900
15 8,731,100 96,357,000
16 10,521,900 106,878,900
17 10,521,900 117,400,800
18 10,573,200 127,974,000
19 10,942,400 138,916,400
20 10,942,400 149,858,800
21 10.942,400 160,801,200
22 10,942,400 171,743,600
23 12,988,000 184,731,500
24 13,272 ,000 198,003,600
25 11,633,900 209,637,500
26 11,264,700 220,902,200
27 11 ,264,700 232,166,900
28 11,264,700 243,431,600
29 11 ,264,700 254,696,300
30 11,264,700 265,961,000
31 10,725,800 276,686,800
32 10,725,800 287,412,600
33 10,674,500 298,087,100
34 8,885,700 306 ,972,800
35 8,885,700 315,858,500
36 8,885,700 324,744,200
37 8,665,200 333,409,400
38 8,948,800 342,358,200
39 8,948,800 351,307,000
40 8,948,800 360,255,800
41 8,794,100 369,049,900
42 8,794,100 377 ,844,000
43 8,794,100 386,638,100
44 8,794,100 395,432,200
45 8,794,100 404,226,300
46 8,794,100 413,020,400
47 4,057,700 417,078,100
48 4,288,300 421,366,400
3.5
3.1.3 Escalation
Estimates of real escalation in capital costs for the plant are presented
below.These estimates were developed by Ebasco from projected total escal a-
tion rates (including inflation)and subtracting a Gross National Product
deflator series (a measure of inflation).
Year
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992 -on
3.1.4 Economics of Scale
l"1ateri a1sand
Equipment
(Percent)
1.0
1.2
1.2
0.7
-0-
-0.1
0.3
0.8
1.0
1.1
1.6
2.0
Construction
Labor
(Pe rcent)
0.5
1.7
1.7
1.3
-0-
-0.1
0.3
0.8
1.0
1.1
1.6
2.0
In the range of the considered plant sizes (150 MW through 250 MW)there
is a negligible difference in construction costs per kilowatt hour of genera-
tion.No significant cost-related economies of scale can be found in this
range of plant sizes.
3.2 OPERATION AND MAINTENANCE COSTS
3.2.1 Operation and Maintenance Costs
The operation and maintenance costs for the 200 MW size plant,expressed
in January 1982 "Alaskan"dollars,are as follows:
3.6
,-:
~
Fixed Costs
Staff (109 Persons)
Variable Costs
Operating Supplies
and Expenses
Maintenance Supplies
and Expenses
3.2.2 Escalation
$3,342,700/yr (~16.70/kW-yr)
$315,000/yr(a)(0.2 mills/kWh)
$597,100/yr(a)(0.4 mills/kWh)
Estimated real escalation of fixed and variable operation and maintenance
costs(b)are as follows:
Year
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991 -on
Escalation
(Percent)
1.5
1.5
1.6
1.6
1.7
1.8
1.8
2.0
2.0
2.0
2.0
~
(a)@ 85%capacity factor.
(b)Escalation series used by Ebasco for project cost estimating.
3.7
3.2.3 Economics of Scale
In the range of considered plant sizes (150 MW through 250 MW)there is a
negligible difference in operation and maintenance costs per kilowatt hour of
generation.No cost-related economies of scale can be found in this range of
plant sizes.
3.3 FUEL AND FUEL TRANSPORTATION COSTS
Estimated prices for Beluga and Nenana coal are developed in the report
Alaska Coal:Future Availability and Price Forecasts (Swift 1981),produced
in conjunction with this study.
3.3.1 Nenana Station
Coal for the proposed Nenana Station would be supplied from the Usibelli
Coal Mine,Inc.via the Alaska Railroad,probably by a unit train operation.
Future coal prices were estimated based on estimates of base coal prices,FOB
Healy,plus tentative ARR unit train rates.Real escalation was based on esti-
mated real increases in minemouth coal costs as well as railroad diesel fuel
costs.The resulting time series of delivered prices is shown in Table 3.5.
3.3.2 Beluga Station
Coal for the proposed Beluga Station would be supplied from the currently
undeveloped Bel~ga Field by truck and conveyor.Future prices were calculated
by estimating a weighted average delivered price of four competing Pacific Rim
coals at Japan.Alaska-Japan transportation costs were backed out resulting
in a net back mine-mouth price.Real escalation was based on the composite
effect of estimated supply functions for each competing Pacific Rim coal.The
resulting minemouth price stream is shown in Table 3.5.This analysis,of
course,presumes development of an export Pacific Rim market.
3.4 COST OF POWER
Estimated busbar power costs from the proposed Bel~ga and Nenana Stations
are shown in Figure 3.1.Costs shown are levelized lifetime busbar power
3.8
~
I
I
I
I,,
------------------------------------------..j4.,---
'!
TABLE 3.5.Estimated Coal Prices:Beluga and Nenana Stations
(January 1982 $)(Swift 1981)
Nenana Coal Be 1ug a
FOB FOB (b)Coa 1
Hea ly (a)Nenana Mine Mouth(c)
Year $/MMBtu)(Z/MMBtu)--i '£/MMB tu)
1980 1.43 1.75
1981 1.46 1.78
1982 1.49 1.81
1983 1.52 1.84
1984 1.55 1.88
1985 1.58 1.91
1986 1.61 1.94
1987 1.64 1.98
1988 1.68 2.01 1.69
1989 1.71 2.05 1.72
1990 1.74 2.09 1.76
1991 1.78 2.12 1.80
1992 1.81 2.16 1.83
1993 1.85 2.20 1.87
I 1994 1.89 2.24 1.91
1995 1.92 2.28 1.95I19961.96 2.32 1.99I19972.00 2.36 2.03!
I 1998 2.04 2.41 2.08
I 1999 2.08 2.45 2.12
2000 2.12 2.49 2.16
f 2001 2.16 2.54 2.21
I 2002 2.21 2.58 2.26
2003 2.25 2.63 2.30
j 2004 2.29 2.68 2.35
I 2005 2.34 2.73 2.40
2006 2.39 2.77 2.45
J
2007 2.44 2.82 2.50
2008 2.48 2.88 2.55
!2009 2.53 2.93 2.61',
1
2010 2.58 2.98 2.66
-
(a)2%annual escalation rate from 1980 base price.
(b)1.8%annual escalation rate from 1980 base price.
(c)2.1%annual escalation rate from 1980 base price.
3.9
I
~
--------------......."",,,"",,,,,_n_,_...1
NENANA STATION
I
I
BELUGA STATION
50 100
CAPACITY FACTOR (%)
100
.r::.
e:::::S:
<Cd!!!.co VI
Vl =:::J .-co5
ell-50wVI
NO
::iU
we::::
>w~:s:
0
Q..
a
a
FIGURE 3.1.Cost of Power Versus Capacity Factor
(January 1982 dollars)
costs,expressed in January 1982 dollars.The costs are based on the follow-
ing financial parameters:
Debt Financing 100%
Equity Financi ng 0%
Interest on Debt 3%
Federal Taxes
State Taxes
Year of First Commercial
Operation
Bond Life
General Inflation
None
None
1990
30 years
0%
The escalation factors shown in this report were employed.Weighted
average capital cost escalation factors were derived using a labor/material
ratio of 44%/56%.
3.10
Levelized lifetime power costs for the plant will rise over time because
of the forecasted c8ntinuing escalation in capital,O&M and fuel costs.Esti-
mated levelized busbar power costs for the two stations,expressed as a func-
tion of the first year of commercial operation and assuming an 85%plant
capacity factor,are shown in Figure 3.2.These costs are expressed in
January 1982 do 11 ars.
..co::::~«.:.0:
a::I --Vl~
::::l=
a::IE0;::
L.L.JV)
!::::!oL:du
>0::::
L.L.J L.L.J
......J~oa..
100
NENANA STAT ION
\
\
BELUGA STATION
50
o
1985 1990 1995 2000 2005 2010
FIRST YEAR OF COMMERCIAL OPERATION
FIGURE 3.2.Cost of Power Versus First Year of Commercial
Operation (January 1982 dollars)
3.11
...----------------,-"-
~----
4.0 ENVIRONMENTAL AND ENGINEERING SITING CONSTRAINTS
An environmental impact statement will likely be required for construc-
tion and operation of a 200-MW coal-fired power plant at either the Beluga or
Nenana sites (see Section 6.1.5).Council of Environmental Quality regula-
tions implemented pursuant to the National Environmental Policy Act of 1969
require that an environmental impact statement include a discussion and evalu-
ation of alternative site locations.This requirement is usually satisfied
through the performance of a site evaluation study.The purpose of such a
study is to identify a preferred site location(s)and possibly viable alterna-
tive locations for the construction and operation of the generating station.
The following subsections present many of the constraints that would be
evaluated during a siting study,with special attention given to their applica-
bility to the two locations considered in this study.It should be realized
that many of the constraints placed upon the development of a coal-fired power
plant are regulatory in nature and therefore the discussion presented in this
section is complemented by the identification of power plant licensing require-
ments presented in Section 6.0.
4.1 ENVIRONMENTAL SITING CONSTRAINTS
4.1.1 Water Resources
Water resource siting constraints generally center about two topics:
water availability and water quality.The power plant requires a reliable
source of water for operation.Siting and design analyses generally attempt
to minimize flow reduction of potential water supply sources while maximizing
plant reliability.For this reason,it is necessary to examine low flows as
well as average annual and monthly flows.For the Nenana location,water
availability should not represent a constraint that would deter development.
The quantities of water required by the plant are an extremely small percentage
«1 percent)of the Nenana River'sminimum recorded low flow.Special consid-
eration will have to be given to intake structure location since freezing and
4.1
ice-related problems may affect design and operational reliability.Considera-
tion of stream morphology and geometry will also be important to avoid local
flow reduction effects during low flow periods.
At the Beluga location,large river systems do not exist and therefore
smaller streams will have to be analyzed to determine their suitability as a
supply source.Potential groundwater supply sources exist in this area,with
well yields estimated to be as high as 1000 gpm near the larger surface water
bodies.Yields,however,generally range from 10 gpm to 100 gpm away from
surface water bodies.Another alternative could include groundwater for pro-
cess use and salt water for cooling purposes.The use of these alternatives
could,however,significantly affect power plant costs.This cost increase
would have to be evaluated in light of the potential impact of utilizing
surf ace water resources.
Existing water quality can represent a significant siting constraint.
First,receiving stream water quality standards if particularly stringent,
could prohibit plant effluent discharge.Secondly,makeup water quality
requirements may mandate the provision of an extensive water treatment facil-
ity if the quality of the water source is inferior.This consideration should
not prove restrictive at either potential plant location.The water quality
of the Nenana River and most other surface water resources is acceptable from
a makeup water management viewpoint.However,if the Beluga plant utilizes a
groundwater supply system,an extensive treatment system may be required since
groundwater is generally highly mineralized.
4.1.2 Ai r Resources
The air resources siting process involves the determination of those areas
within the overall study location where power plant siting would appear feas-
ible from a regulatory point of view.A full discussion of the air-related
regulatory requirements appears in Section 6.0;however,the major factors
that must be evaluated include:
•Proximity to Class I PSD areas.
•Proximity to non-attainment ambient air quality areas.
•General dispersion capability of the area.
4.2
..............
These factors are evaluated through the use of a computerized mathemat-
ical model that develops estimates of atmospheric diffusion and the resulting
concentration of various air quality parameters.Input to the model consists
of the characteristic emissions ("source term")of the plant and local meteoro-
1ogi cal data.
Of the three factors listed above,the Denali National Park Class I area
could pose the most severe siting constraint for the development of a coal-
fired facility.The allowable increments of air quality deterioration are
extremely small in Class I areas.A minimum distance from this area would
probably be at least 20 miles,but each potential site should be analyzed in
detail to insure a proper evaluation.The Class I visibility regulations
could significantly effect this minimum distance.The proposed Nenana loca-
tion is approximately 40 miles north of the current park boundary.
In the Fairbanks and Anchorage areas,the levels of carbon monoxide (CO)
exceed the primary National Ambient Air Quality Standards.The state regula-
tory agencies are required to reduce CO emissions in these two airsheds in
order to attain the standards.This goal will be accomplished by requiring
any new or mod1fied major source to install the lowest achievable emission
rate for CO emissions and to obtain offsets for the actual CO emissions.
Consequently,the construction of a coal-fired power plant in or near these
non-attainment areas will entail the most demanding pollution controls as well
as a lengthy and detailed regulatory review.While these requirements will
not preclude development,they will entail rigorous analyses during the plant
siting process,especially for the Nenana location,which also poses a Class I
area restriction.
4.1.3 Aquatic and Marine Ecology
Since the plant's makeup and discharge requirements are relatively small,
entrainment and impingement impacts and wastewater discharge impacts will prob-
ably not be site-differentiating.The major activity in this area during the
siting process,would,therefore,be identification of exclusion and avoidance
areas to be considered in association with intake and discharge structure
development.The delineation of these areas would primarily be based upon an
inventory of fish spawning habitat and upstream migration pathways,fish
4.3
nursery habitat and downstream migration pathways,important benthic habitat
and rare and/or endangered species and their critical habitats.
4.1.4 Terrestrial Ecology
Since habitat loss is generally considered to represent the most signifi-
cant impact on wildlife,identification of important wildlife areas,especially
critical habitat of threatened or endangered species,must be identified.
Based upon this inventory,exclusion,avoidance and preference areas would be
factored into the plant siting process.A number of important and sensitive
species inhabit both potential site areas,including moose,caribou,brown and
black bear,and Dall sheep.
4.1.5 Socioeconomic Constraints
Major socioeconomic constraints center about potential land use conflicts
and community and regional socioeconomic impacts derived from project activ-
ities.Potential exclusionary land use conflicts would consist of those areas
that contain lands set aside for public purposes,areas protected and pre-
served by legislation (federal,state or local laws),areas related to national
defense,areas in which a coal-fired installation might preclude or not be
compatible with local activities (e.g.,urban areas or Indian reservations),
or those areas presenting safety considerations (e.g.,aircraft facilities).
Avoidance areas would generally include areas of proven archeological or his-
torical importance not under legislative protection,and prime agricultural
areas.
Minimization of the boom/bust cycle will also be a prime criterion.
Through the application of criteria pertaining to community housing,popula-
tion,infrastructure and labor force;preferred locations and mitigation
measuring will be identified.Because the potential power plant sites are
remote and will likely cause significant boom/bust impacts on nearby small
communities,socioeconomic criteria would be heavily weighted in the overall
site evaluation process.
4.2 ENGINEERING SITING CONSTRAINTS
The development of engineering criteria for use during the site evalua-
tion process is necessary to minimize engineering and construction problems
4.4
.....
and,thereby,facility investment and operating costs.The development of
either the Nenana or Beluga Station could be constrained by a number of factors
bearing upon the engineering aspects of the project.These factors include
site topography and geotechnical characteristics,access road distance,trans-
mission line distance,and water supply distance.
4.2.1 Site Topography and Geotechnical Characteristics
In general,the power plant should be sited in relatively flat terrain.
This will minimize the amount of grading and excavation,and will also mini-
mize the potential for adverse environmental impacts due to rainfall runoff
transport of suspended solids to nearby waterways.The plant should also be
sited above the 100-year floodplain of major streams.
Another major criterion is the avoidance of areas with poor soil condi-
tions as these can cause significant construction and reliability problems due
to poor suitability as a foundation for structures.Soil-related foundation
problems can be expected in the Beluga area due to the presence of highly
organic soil (muskeg)that will probably require extensive piling to be placed
under major structures and equipment foundations.In the Nenana area,a site
free of permafrost must be selected.
Seismic activity can also be an important site differentiating factor,
with preference given to those sites located in regions of low activity.In
this study,however,the potential locations fall within regions of high seis-
mic activity (Zone 3).While this will not preclude development nor differen-
tiate between the sites,it will increase construction costs as more material
will be required to insure plant foundation and disposal area dike stability.
A final geotechnical-related criterion concerns the availability of borrow
material.Sites that contain an adequate supply of borrow material can be far
less costly,especially if alternate sites must haul in this material over
long distances.
4.2.2 Access Road,Railroad and Transmission Line Considerations
Siting a power plant in close proximity to existing roads,rail service
and transmission lines minimizes the cost associated with extension of these
4.5
facilities and also minimizes the environmental effects associated with land
disturbance.From an economic point of view,access roads,railroad spurs and
transmission interties should be limited to a maximum distance of approximately
20 miles in flat terrain and 10 miles in rough terrain.The allowance for
roads and railroad spurs should be sufficient to insure compliance with estab-
lished safety and reliability standards,for example,the maximum allowable
grades (approximately 1.5 percent and 6 percent for railroads and roads,
respectively).Route selection will also be affected by soil and meteorolog-
ical conditions.Permafrost,potential frost heave problems and other soil-
related characteristics can significantly add to the cost of road facilities,
and wind,temperature and ice load can significantly affect transmission line
desi gn.
4.2.3 Water Supply Considerations
The power plant requires a reliable water supply source for its opera-
tion.To ensure that this requirement is met,two criteria are generally
employed during the siting process:
•The plant should be sited within approximately 15 miles of an accept-
able source of water,and
•The plant should be sited where the maximum static head between the
water source and the end use facility (the plant itself or a makeup
water reservoir)is less than approximately 1500 feet.
The first criterion reflects the need to minimize right-of-way acqulsl-
tion,land disruption,construction-related environmental impacts,investment
and operating costs,and the potential reliability problems associated with
"pumps-in-series"operation.The second criterion reflects the limits of the
state-of-the-art regarding the ability to pump vertically while maintaining
system reliability,the need to minimize system redundancies (e.g.,duplicate
pipeline),and the need to minimize operating costs associated with water
pump i ng •
4.6
..
5.0 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS
5.1 SUMMARY OF FIRST ORDER ENVIRONMENTAL IMPACTS
The construction and operation of a 200-MW coal-fired steam-electric gen-
erating facility will create changes or impacts to the land,water,air and
socioeconomic environments in which it is located.These impacts are directly
related to the primary effects of the plant on the environment.A summary of
these effects is presented in Table 5.1.These primary effects are analyzed
and evaluated in light of existing environmental conditions to determine the
significance of the impact and the need for mitigative measures.
5.2 ENVIRONMENTAL AND SOCIOECONOMIC EFFECTS
5.2.1 Water Resource Effects
The design of the proposed stations minimizes adverse water resource
impacts by incorporating "dry"solid waste disposal facilities and a wet/dry
cooling tower system.These components result in small makeup water require-
ments and minimal wastewater discharges.Significant,difficult-to-mitigate
impacts are therefore not anticipated.
5.2.2 Air Resource Effects
The power plant will be required to meet the Best Available Control Tech-
nology (BACT)for atmospheric emissions,which is at least as stringent as the
New Source Performance Standards (NSPS).In addition,the national emission
standards for hazardous air pollutants must be met.Finally,the plant must
demonstrate that applicable state and federal atmospheric ambient air quality
criteria and prevention of significant deterioration (PSD)increments will not
be exceeded.To demonstrate compliance with these regulations,a I-year onsite
air quality and meteorology monitoring program must be carried out.In light
of these regulatory restrictions,significant,difficult-to-mitigate air
resource impacts are not expected.
Increasing concern has been expressed regarding the long-term effects of
the CO 2 production of combustion-based power plants.Of particular concern is
the potential "greenhouse"effect of increased atmospheric CO 2 concentration.
5.1
TABLE 5.1.Primary Environmental Effects
Air
Particulate Emissions
Sulfur Dioxide Emissions
Nitrogen Oxide Emissions
Water
Plant Water Requirements
Plant Water Discharge
Process Water
Coal Pile Runoff
Land
Land Requirements
Plant Is 1and
Solid Waste Disposal Site
Socioeconomic
Construct ion Workf orce
Operati ng Workforce
(a)Assumes 70%reduction.
60.4 lb/hr (0.03 lb/10 6 Btu)
377 lb/hr «0.6 lb/10 6 BtU)(a)
1207 lb/hr (0.60 lb./10 6 Btu)
1947 gpm (Wet Cooling)
287 gpm (Dry Cooling)
None
Infrequent «4 events/35 yr.life)
25 acres
50 acres
500 personnel
109 personnel
Because the source of carbon for a coal-fired plant
would contribute to the buildup of atmospheric CO 2 ,
ling production of CO 2 currently exist.
5.2.3 Aquatic and Marine Ecosystem Effects
is a fossil fuel,the plant
No regulations control-
Relatively small power plant water requirements and infrequent wastewater
discharges will minimize the potential for adverse aquatic ecosystem impacts.
5.2
b
.----oIIIll
Assuming that the intake and discharge structures are properly designed and
located,significant,difficult-to-mitigate impacts should not occur.
5.2.4 Terrestrial Ecosystem Effects
The greatest impact on the terrestrial biota resulting from the develop-
ment of the proposed plants will be the loss or alteration of habitat.Both
potential power plant locations contain seasonal ranges of moose and caribou.
In addition,the Nenana location is within the range of brown bear.While the
plant's total land requirements are modest,approximately 75 acres,distur-
bance of these range areas will lower the carrying capacity of the land to
support these species.This could represent a significant terrestrial eco-
system impact,depending upon the plant's specific location.Wildlife
impacts,however,can be minimized by siting the plant outside of important
wildlife areas.
5.2.5 Socioeconomic Effects
Most of the communities located near both the Beluga and Nenana locations
are generally small in population and have an infrastructure that is not highly
developed.In light of this,the construction and operation of a 200-MW coal-
fired plant has a high potential to impact local communities and cause a boom/
bust cycle.This impact will be most significant in the Beluga region where
the largest community in the area,Tyonek,has a population of only 239.While
a construction camp will mitigate this impact to some degree,disruption of
the area's infrastructure must be anticipated.
If the Nenana site is located within an approximate 50-mile radius of
Fairbanks,a boom due to construction will be a less likely event,since many
of the 500 construction personnel could commute to the site from Fairbanks.
The impact of project construction would also be mitigated by the sizeable
Fairbanks labor market and high unemployment rate.A site located further
than 50 miles from Fairbanks would,however,create impacts similar to those
anticipated at a Beluga location.
5.3
•
6.0 INSTITUTIONAL CONSIDERATIONS
This section presents an inventory of major federal,State of Alaska,and
local environmental regulatory requirements that would be associated with the
development of either the Beluga Station or the Nenana Station.The inventory
is divided into three subsections,setting forth federal,state,and local
environmental licensing requirements.A list of these requirements is pre-
sented in Table 6.1.The discussion of the environmental study requirements
associated with environmental report preparation under the National Environ-
mental Policy Act of 1969 is included in Subsection 6.1.
6.1 FEDERAL REQUIREMENTS
6.1.1 Air
Air pollution controls are placed on new coal-fired power plants through
the provisions of the Clean Air Act (CAA).The CAA is implemented primarily
through permitting programs that would ensure compliance with national ambient
air quality standards (NAAQS)and that would prevent significant deterioration
in areas where NAAQS are being met.Through a permit,a power plant is
required to restrict emissions in accordance with new source performance
standards (NSPS),national emission standards for hazardous air pollutants
(NESHAP),and visibility protection requirements.
The permitting program and controls to which a power plant will be sub-
ject are largely dependent upon its location.As the two proposed plant loca-
tions are situated in areas in which air pollution levels are in compliance
with NAAQS,the plant will be subject to the prevention of significant deterio-
ration (PSD)permitting program administered by EPA in accordance with CAA
Sections 160-169.Currently,EPA retains authority to issue this PSD permit
in the state of Alaska,although the state is now in the process of developing
its own PSD permitting program which,when finalized,will transfer to the
state this permitting authority.Until that time,EPA will continue to issue
these permits based on rules found at 40 CFR 32.21.
Under these rules,major sources of pollution cannot begin construction
until a PSD permit has been issued.A power plant is considered a "major
6.1
''''!Ut *11 b
TABLE 6.1.Permits,Approvals,and Certifications Required for a Coal-Fired Power
Plant in Alaska
O'l.
N
Agency
U.S.Environmental
Protection Agency
U.S.Army Corps
Of Engineers
Alaska Department
of Environmental
Conser vat ion
Alaska Department of
Natural Resources
U.S.Environmental
Protection Agency
Alaska Department
of Environmental
Conservati on
U.S.Environmental
Protection Agency
Alaska Department of
Environmental Conservation
Alaska Office of
the Governor
Federal Aviation
Administration
Name Scope Statute or Authority
National Pollutant Discharges to Water 33 USC 1251 et.seq.,
Discharge Elimination Section 1342
Construction Activity Construction in Water 33 USC 401 et.seq.,
in Navigable Water Section 403
Discharge of Dredged Discharges to Water 33 USC 1251 et.seq.,
Fill Material Section 1342
State Certification that Discharges to Water 33 USC 1251 et.seq.,
Discharges comply with Section 1341
CWA and State Water
Quality Requirements
Water Rights Permit Appropriation of Alaska Statute
Water 46.15.030-185
Prevention of Significant Air Emissions 42 USC 7401 et.seq.,
Deterioration Permit Section 7475
Air Quality Control Air Emissions Alaska Statute
Permit to Operate 46.03.140
Hazardous Waste Manage-Hazardous Waste 42 USC 6901 et.seq.,
ment Facility Operation Section 6925
Solid Waste Management Solid Waste Alaska Statute
Facility Operation 46.03.100
Coastal Use Permit Land Use Alaska Statute
46.40
Air Navigation Approval Air Space 49 USC 1304,1348,
1354,1431,1501
Agency Name
TABLE 6.1.(contd)
Scope Statute or Authority
0'\.
w
National Marine Fisheries
Service/Fish &Wildlife
Service
Advisory Council on
Historic Preservation
Alaska Department of
Fish and Game
Department of the Interior
Office of Surface Mining
Alaska Department of
Natural Resources
Threatened or Endangered
Species Review
Determination that Site
Does Not Infringe On
Federal Landmarks
Determination that Site
Is Not Archeologically
Significant
Anadromous Fish
Protection Permit
Critical Habitat
Permit
Surface Coal Mining
Permit
Coal Exploration
Permit
Coal Lease
Air,Water,Land
Land Use
Land Use
Fish Protection
Fish and Game
Protection
Surf ace Coal
Mining Operations
Development of Coal
Mine of State Lands
Mining of Coal on
State Lands
16 USC 1531 et.seq.
16 USC 461 et.seq.
16 USC 402aa et.seq.
Alaska Statute
16.05.870
Alaska Statute
16.20.220 and .260
30 USC 1201 et.seq.,
Section 1256
Alaska Statute
27.20.010
Alaska Statute
38.05.150
source"if the heat input rate is greater than 250 MBtu/hr and if the plant
has the potential to emit at least 100 tons per year of any air pollutant
after controls have been applied.To obtain a PSD permit,an applicant must
demonstrate that the source or modification will comply with the NAAQS's ,the
NSPS's,the NESHAP's,and PSD increments.In addition,the applicant must
conduct analyses relative to the effects on soils,vegetation,visibility,and
area growth.
PSD increments are specified maximum allowable increases in the ambient
concentrations of SO and particulate matter,over a designated "baseline"x
concentration of these pollutants.These increments are based upon the classi-
fication of the attainment area as either Class I,II,or III.The allowable
PSD increments increase from Class I to Class III,therefore,disregarding
other considerations,Class I areas are the most restrictive for new industrial
growth.Class I areas in Alaska include Denali National Park,the eastern
boarder of which is near the Nenana field.If the plant is located within
10 km of this Class I area,additional pollution controls must be applied.
However,the proposed Nenana Station would be to the north,near the community
of Ne nan a (F igure 1.1)
Requirements will be imposed in order to protect visibility in designated
Class I areas.Under rules promulgated on December 2,1980 (45 FR 80084),new
sources that require PSD permits may be required to conduct additional studies
to determine the source's effects upon the visibility in the Class I area.
Note that CAA Section 165 requires that PSD permits be denied for sources that
would cause adverse air impacts on these federal Class I areas.
6.1.2 Water
The preservation of the quality of the surface waters of the United States
is accomplished in accordance with the Clean Water Act (CWA).There are two
major regulatory programs mandated by this act with which a coal-fired power
plant must comply.
Controls will be imposed upon the discharge of pollutants by the power
plant through the National Pollutant Discharge Elimination System (NPDES)
permit.This permit is issued by the EPA pursuant to CWA Section 402,and
regulations for its issuance are found in 40 CFR 122.The issuance of an
6.4
NPDES permit to a new discharge source will trigger the environmental review
requirements of the National Environmental Policy Act (NEPA),as discussed
below.Because the discharge cannot take place without a permit being issued,
an application must be filed at least 180 days before the discharge is sched-
uled to commence.
The EPA has established effluent limitations for pollutant discharges on
an industry-by-industry basis.New limitations for steam-electric generating
units were proposed on October 14,1980.When these become final,they may
include more stringent controls on discharges than those presently in effect,
especially with respect to discharge of toxic pollutants such as chlorine.
Other aspects of these regulations may be relaxed however,such as those
limiting pollutant concentrations in bottom ash transport water.The EPA is
also in the process of developing effluent limitations controlling the dis-
charge of toxic pollutants under the authority of CWA Section 307.
Pursuant to Section 404 of the CWA,a permit must be obtained from the
U.S.Army Corps of Engineers (Corps)to discharge dredged or fill material
into waters of the United States.Coal-fired power plants may need a Sec-
tion 404 permit for construction activities such as the building of water
intake or outfall structures,loading or unloading facilities,and trans-
missTon power lines.
With respect to the same activities,a power plant may also be required
to obtain a permit under Section 10 of the Rivers and Harbors Act (RHA)of
1899 for the placement of structures or the conduct of work in or affecting
navigable waters of the United States.This permit is also issued by the
Corps using the same application forms and processing procedures as those
required for the Section 404 permit.
The processing of either of these permits can take 6 months or more,and
requires that an EIS be prepared accordi ng to the requirements of NEPA.
6.1.3 Solid Waste
The Resource Conservation and Recovery Act (RCRA),as amended in 1980,
imposes controls upon the handling of solid waste in the United States.At
present,the major emphasis has been placed upon the control of hazardous
solid waste.A formal hazardous waste management program that sets forth
6.5
identification and handling requirements for generators of hazardous wastes;
marking and manifesting requirements for transporters of hazardous waste;and
a permitting program for hazardous waste treatment,storage and disposal
facilities is currently being administered by the EPA.
The operation of a 200-MW coal-fired power plant could involve the gen-
eration,transportation,treatment,storage or disposal of hazardous wastes.
Power plant wastes that may be hazardous include water treatment wastes,boiler
blowdown,boiler waterside and fireside cleaning wastes,coal storage pile
runoff,cooling tower blowdown,floor drainage wastes,storm water runoff,and
sanitary and laboratory wastes.(Some power plant wastes,such as high-volume
wastes produced by the combustion of coal [fly ash,bottom ash,and flue gas
desulfurization sludge]and certain other wastes that are mixed with these
high-volume wastes,are currently excluded from control as hazardous.)Accord-
ingly,the owners and operators of the power plant may have to comply with the
standards applicable to generators and transporters of hazardous waste,and
may also be required to obtain an RCRA permit from the EPA to operate a hazard-
ous waste treatment,storage or disposal facility.
The RCRA permit need only be obtained from the EPA if hazardous waste in
amounts exceeding 1000 kg/month will be treated,stored,or disposed of on the
plant site.If the waste is transported offsite for ~isposal in a licensed
facility (such as a municipal dump),a permit need not be obtained.Further-
more,certain types of facilities,such as neutralization tanks,transport
vehicles,vessels,or containers used for neutralization of wastes that are
hazardous only due to corrosivity (40 CFR 264.1(g)),have been excluded from
RCRA permit requirements.(This exclusion does not apply to surface
impoundments.)
If an RCRA permit for operation of a hazardous waste treatment,storage
or disposal facility is necessary for the power plant,it must be obtained
before construction of the hazardous waste management facilities can com-
mence.EPA only recently began accepting applications for RCRA permits from
new treatment,storage and disposal facilities.Although no such permits have
been issued yet,EPA anticipates the processing of RCRA permits to take at
least 1 year.
6.6
..
6.1.4 Coal Mining
The Surface Mining Control and Reclamation Act (SMCRA)applies to surface
coal mine operations and to the surface effects of underground coal mining.
Activities that must receive a pennit under StvlCRA include coal exploration,
surface mining,surface effects of underground mining,coal processing plants
and support facilities outside the actual mine pennit area,coal processing
plants and support facilities within the actual mine pennit area and,in gen-
eral,any activity conducted on the surface of lands "in conjunction with"the
mining itself.As the power plant located either near Nenana or near Beluga
could be developed in conjuction with the coal mine and,therefore,incor-
porate one or more of these activities into the plant's operation,a SMCRA
pennit for mining-related operations could be required.
Prior to issuance of a pennit,an applicant must submit a reclamation
plan describing the condition of the land prior to mining and explaining how
the land will be restored after mining.The pennit applicant must also submit
a perfonnance bond with the application,to be returned when reclamation of
the site is complete.
The SMCRA pennanent program perfonnance standards that must be met by
pennitees are primarily designed to protect water quality,ensure land recla-
mation after the mining operations are over,and ensure that certain safety
measures are taken.Numerous challenges to the permanent program that have
been filed in various courts (In re:Pennanent Surface Mining Regulation
Litigation,Civil Action No.79-1144,DOC;and Virginia Surface Mining and
Reclamation Association v.Andrus,Civil Action No.78-0-224-8,WD Va)have
resulted in the suspension of portions of the program's regulations,and
delays in the implementation of the pennit program.
6.1.5 National Environmental Policy Act
Section 102(2)(c)of the National Environmental Policy Act (NEPA)requires
the preparation of an environmental impact statement (EIS)as a prerequisite
for "major federal actions significantly affecting the quality of the human
environment."Such actions include the issuance of licenses or pennits to pri-
vate parties for the construction of projects that would affect the environ-
ment.The issuance of a CWPS Section 10/404 permit by the Corps,as well as
6.7
-
an NPDES permit to a new source (discussed above)both require the preparation
of an EIS.(Neither a PSD nor an RCRA permit,by contrast,is considered
"major federal actions"that could trigger NEPA requirements.)Accordingly,
compliance with the requirements of NEPA is necessary for a 200-MW coal-fired
power plant.
The Council on Environmental Quality (CEQ)promulgated regulations imple-
menting NEPA in 1978 (see 40 CFR 1500-1508).These regulations require virtu-
ally all federal agencies to promulgate regulations that conform with CEQ's
regulations.Among other provisions,the CEQ regulations require that:
•An agency be designated as the lead EIS agency when more than one
federal agency must prepare an EIS.The lead agency has primary
responsibility for EIS preparation and is to coordinate with all
other interested agencies.(The lead agency is also encouraged to
coordinate with any state agency that implements an EIS-type pro-
cess.)Normally,EPA or the Corps or Engineers is the lead EIS
agency for power plant projects.
• A scoping process be used to determine the scope of the EIS.
• A standard EIS format be used.The heart of this format is the pre-
sentation of the proposed project and of alternatives to the proposed
project,and the environmental impacts of the proposal and the alter-
natives.For proposed power plant projects these alternatives
include alternative fuels and plant sites.EIS's for power plants
must also consider the environmental impacts of associated transmis-
sion systems and indirect impacts (e.g.,the impact of coal mining,
processing and transport).
In addition,it is recommended that applicants who know that their pro-
posed project will activate the EIS process consult with the applicable federal
agency to start the EIS scoping process even before the permit application is
submitted.Note that while the actual EIS preparation is the responsibility
of the federal agency,it has become common practice for the regulatory agen-
cies to require the utility applicant to prepare an "environmental report"
(ER)that is utilized by the agency in preparing the EIS.
6.8
EPA's NEPA rules that conform with CEQ's NEPA rules are found at 40 CFR 6.
For guidance on preparing applicant ERs,EPA has also issued a document enti-
tled Environmental Impact Assessment Guidelines for New Source Fossil Fueled
Steam Electric Generating Stations (EPA-130/6-79-001).This document should
be used in conjunction with EPA's NEPA rules.EPA's NEPA rules allow for the
preparation of the EIS by a third-party contractor,if EPA is the lead agency
and if EPA and the applicant agree.
The Corps'NEPA rules that apply to CWA Section 404 and RHA Section 10
permitting are found in Appendix B of 33 CFR 230 (see 45 FR 56779,Aug.25,
1980)and in the Corp's proposed amendments to its permitting rules (see
45 FR 62732,Sept.19,1980).These rules should be followed if the Corps is
designated as the lead NEPA agency.
Finally,on September 8,1980 (45 FR 59189),CEQ issued three memoranda
that are intended to further the purposes of NEPA.Two of the memoranda empha-
size the need for EISs to analyze the effects of a proposed federal action on
prime or unique agricultural land.The third memorandum emphasizes the need
to protect rivers that are on the nationwide inventory of rivers that appear
to qualify for inclusion in the Wild and Scenic Rivers System (which was
created pursuant to the Wild and Scenic Rivers Act,a law discussed below).
6.1.6 Other Federal Requirements
In reviewing federal environmental requirements to which a fossil fuel-
fired power plant may be subject,it is necessary to consider certain addi-
tional regulatory programs.Although these programs may not include permitting
requirements,they contain certain requirements that can affect location and/or
construction of a power plant.
The National Historic Preservation Act requires that federal agencies
that license projects that could affect structures listed or eligible for
listing in the National Register of Historic Places take such effects into
account.The agency issuing the license must consult with the appropriate
state agency and must give the Advisory Council on Historic Preservation an
opportunity to comment on the proposal.
6.9
The Wild and Scenic Rivers Act has created a National Wild and Scenic
River System that consists of river sections that possess outstanding scenic,
recreational,geologic,biological,historic,cultural,or similar values.
The purpose of the Act is to preserve these river sections in a free-flowing
condition,and to protect their immediate environs for the IIbenefit and enjoy-
ment of present and future generations.1I Under this act,any proposed project
that would affect the free-flowing characteristics of the river section
included in the system must be disapproved if it would have a direct adverse
effect on the values for which the river section is so included.Thus,
although a proposal for a power plant to be sited on a river section included
in the system might be approved,such approval would be highly controversial.
The Endangered Species Act of 1973 requires the U.S.Fish and Wildlife
Service and the National Marine Fisheries Service to publish lists of IIthreat-
ened ll or lI en dangered ll plant and animal species (as defined by the Act),
together with the species 'critical habitats and the ranges over which they
are threatened or endangered.This act requires that all federal agencies
insure that their actions (such as authorizing or approving proposed projects)
do not jeopardize the existence of any listed species or result in the destruc-
tion or adverse modification of species·habitats.If it is determined that a
threatened or endangered species is present in the area of a proposed project,
this act requires that a biological assessment be conducted to determine if
such a species is likely to be affected by the proposed project.Compliance
with the environmental review requirements of the Endangered Species Act is
usually incorporated into the NEPA review process for a project.
The Fish and Wildlife Coordination Act requires any federal agency that
is to license,pennit,or otherwise authorize a proposed project,to consult
with the U.S.Fish and Wildlife Service and any other agency administering
wildlife resources in the project area when a proposed project would control
or modify a water body.The purpose of the consultation is to prevent loss of
or damage to,as well as,where possible,development and improvement of the
wildlife resources in the project area.This act defines wildlife resources
broadly,and includes the vegetation upon which the wildlife depend.It allows
the relevant federal agency to impose siting restrictions or mitigation or
6.10
enhancement measures upon the project.Note that compliance with this act
also occurs during the NEPA review.
Executive Order 11988 (May 24,1977)requires that if an agency proposes
to allow activity in a floodplain,it must consider alternatives to the pro-
posed activity and must include an evaluation of the proposal's affect in an
EIS,if one is prepared.If the planned activity will occur on federal lands,
it must also comply with Executive Order 11990 (May 24,1977)that prohibits
construction on wetlands unless there is no practical alternative.
Pursuant to Section 1101 of the Federal Aviation Act of 1958,the Federal
Aviation Administration (FAA)requires that notice be given to the FAA before
a construction permit is filed for any proposed construction or alteration
that would be over 200 feet above gound level or would be within a specified
proximity to an airport.This notice to FAA may have to be filed for various
power plant structures or transmission lines.
The Comprehensive Environmental Response,Compensation,and Liability Act
of 1980 broadens the federal government's ability to clean up hazardous sub-
stance releases that threaten the public health or the environment.The Act
establishes a Post-Closure Liability Trust Fund that is to be comprised of
revenues from a tax on hazardous wastes that is to be imposed on the owners/
operators of disposal facilities that have received RCRA permits or interim
status.However,the tax will not apply to hazardous waste that will not
remain at such a disposal facility after the facility is closed.Hazardous
waste management facilities at power plants that have obtained interim status
or a final permit under RCRA will be subject to this tax if the hazardous
waste in such facilities will remain after plant closure.
6.2 STATE REQUIREMENTS
6.2.1 Air
The emission of contaminants into the air is controlled in Alaska by
requlrlng sources of air pollution to obtain an air quality control permit to
operate.Contaminants that can trigger permit requirements include dust,
fumes,mist,smoke,fly ash and other particulate matter,vapor,gas,odorous
substances,and any combination thereof.Due to the emission of contaminants
6.11
that accompanies the burning of coal as fuel,a coal-fired power plant must
obtain an air quality control permit to operate.
Applications for air quality control permits to operate should be filed
with the Alaska Department of Environmental Conservation (DEC)at least 30 days
prior to the commencement of operations.Applications must be accompanied
by:one set of plans and specifications describing the construction planned;
a set of maps or aerial photographs showing land use and zoning around the
facility;an engineering report describing planned operation,points of emis-
sion,estimates of the quantity and types of air emissions;a description of
air quality control devices;an evaluation of the impact the air contaminants
would have on ambient air;and plans for emission reduction during an air
pollution episode.
Alaska statutes limit the DEC to 30 days for its review of an application
for an air quality permit.However,it asks that applicants submit their fed-
eral PSD permit applications to the DEC at the same time that the application
is submitted to EPA.The DEC will not start its 30-day review period until it
receives a letter from the applicant officially requesting an air quality con-
trol permit to operate.Using this procedure,the DEC can review the relevant
information through EPAls review period,taking advantage of the year1s worth
of monitoring data and other information contained on the PSD permit applica-
tion.Then when the actual review period begins for the state permit,issuance
can be accomplished efficiently.The emission control requirements that may
be imposed upon the facility are set forth is Alaska Statute 46.03.140.Vari-
ances may be obtained in accordance with procedures in Alaska Statutes
46.03.170.Permits are usually issued for periods of 5 years.
6.2.2 Water
Section 401 Certification
According to Section 401 of the CWA,no federal license or permit to con-
duct any activity that may result in a discharge into navigable waters may be
issued until the state in which the activity occurs certifies that the dis-
charge will comply with the requirements of the CWA and state water quality
control requirements.As a coal-fired power plant generally must obtain
6.12
various federal permits involving such discharges (e.g.~NPDES permit~Sec-
tion 404 dredge and fill permit),it usually must obtain Section 401 certi-
fication of its activities from the state.
In Alaska,Section 401 certification is issued by the DEC pursuant to the
administrative procedures in Alaska's Administrative Code (18 AAC 15).Appli-
cations for such a certificate are made by submitting a written request to the
DEC,accompanied by copies of the facility·s federal permit applications.
Certificates will be valid for up to 5 years.
Approval of Wastewater Treatment Facilities
Should the power plant include facilities that collect,treat,and dispose
of wastewater,the plans for those facilities must be approved by the DEC
before construction can commence.Engineering reports,plans~specifications~
a timetable for construction,and other information that may assist the DEC in
its assessment of the impact of the activity on Alaska's waters must be sub-
mitted to the DEC.The DEC will issue its determination regarding the pro-
posed construction within 30 days of receipt of complete plans.
Wastewater Discharge Permit
The discharge of wastewater into or upon the waters of the surface of the
land or into a publicy operated sewerage system cannot be conducted in Alaska
unless the discharge has been permitted by the DEC.As wastewater has been
defined in Alaska to include sewage~waterborne industrial waste~and other
wastes that are waterborne or in a liquid state,the discharge of wastewater
by a power plant would be subject to this permit requirement.Alaska's regu-
lations~however,provide that when the EPA issues an NPDES permit for a
particular discharge,the NPDES permit will be adopted as the required state
permit (Alaska Statues 46.03.110(e)).
Water Rights Permit
Any person who desires to take waters of the state of Alaska for exclusive
use must obtain a water rights permit from the Alaska Department of Natural
Resources (DNR).As the preservation of water for common use is a major con-
cern in Alaska,this is often one of the most difficult state permits to
6.13
obtain.The application for this permit should be submitted as far in advance
of commencement of construction as possible (at least 6 months)and should be
accompanied by plans and specifications for any dam that may be built.The
permit review procedures,described in Alaska Statute 46.15.030-185,include
an opportunity for comment by all present users of the water whose rights may
be affected by the proposed new use.
6.2.3 Solid Waste
The development and operation of a solid waste disposal facility in the
State of Alaska is subject to a permit issued by the DEC.The application for
such a permit must include:detailed plans and specifications;certification
of compliance with local zoning;a detailed report on the waste to be handled,
methods of operation,equipment to be used,and ultimate site use.Applica-
tions must be submitted to DEC at least 60 days prior to the commencement of
operations.Permits may be issued for periods of up to 5 years.
6.2.4'Coal Mi ni ng
The State of Alaska only regulates coal mining activities conducted on
state lands.If the development of a source of fuel for the proposed facility
requires the conduct of work on.coal deposits on state lands,prior approval
for such work must be obtained from the DNR for the plan of operations (Alaska
Statutes 27.20.010).
DNR will issue a prospecting permit glvlng the applicant the right to
search for coal on state lands for a period of 2 years (Alaska Statute
27.20.010).A prospecting permit may be renewed for one additional 2-year
period.
If,during the permit's life,the applicant discovers a coal seam and can
satisfy the DNR that coal is present in commercial quantities,DNR may convert
the permit to a lease for the mineral-bearing lands.DNR may include stipula-
tions describing the procedures that must be followed during mining.These
stipulations could contain requirements controlling the conduct of active
mining,as well as reclamation requirements to be satisfied when closing the
site.
6.14
~
It should be noted that other permits,such as those described elsewhere
in this inventory,might also be necessary for coal mining operations.
6.2.5 Other State Laws
In addition to the primary environmental protection permits described
above,the State of Alaska has implemented a series of regulatory programs
designed to protect the state's natural resources.These programs that require
a permit,state approval,or state certification are listed and briefly des-
cribed below:
1.Alaska Coastal lone Management Program -Alaska Statute 46.40 -In
accordance with the requirements of the federal Coastal lone Manage-
ment (ClM)Act,Alaska has prepared a ClM plan setting forth guide-
lines for the use of Alaska's coastal areas.Before a federal agency
may issue a license or permit to an applicant for a facility in a
coastal zone,the federal agency must confirm that the activity is
consistent with the Alaska ClM.The ClM program in Alaska is admin-
istered by the Office of the Governor.
2.Anadromous Fish Protection Permit -Alaska Statute 16.05.870 -All
projects that will affect the natural flow of a specified anadromous
river,lake or stream supporting anadromous fisheries or that require
use of equipment in such waters must receive a permit from the Alaska
Department of Fish and Game.Based upon the source of water used by
a power plant and ultimate plant design,receipt of this permit may
be necessary.
3.Critical Habitat Permit -Alaska Statutes 16.20.220 and 260 -Any
development within a critical habitat for fish or game must be
approved by the Department of Fish and Game prior to commencement of
construction.Permits may be obtained by filing a proposal with the
Department.
6.3 LOCAL REQUIREMENTS
The environmental regulatory requirements imposed at the local level
differ throughout Alaska.
6.15
The area surrounding the Beluga coal field is located in the Kenai Penin-
sula Borough.That organized borough has areawide powers of platting and
zoning and can control local land use.Plans to develop land in the Borough
must be approved by the local zoning board,which can regulate land use,build-
ing location and size,the size of open spaces,and population distribution.
In addition,the Kenai Peninsula Borough has a solid waste disposal program
and an air pollution control program with which the proposed power plant may
be required to comply.Those programs do not have permit provisions,but they
do require that the plans for a proposed facility be approved by the Borough
prior to construction.
The area surrounding the Nenana coal field is not in an organized borough.
As a result,formal zoning requirements or land use plans for that area have
not been developed.
6.4 LICENSING SCHEDULE
This subsection presents a tentative front-end licensing schedule (Fig-
ure 6.1)for the construction of a coal-fired power plant in Alaska.It takes
into consideration the major federal,state and local environmental regulatory
requirements that must be satisfied.(A list of these requirements may be
found in Tab 1e 6.1.)
The schedule indicates that the total licensing will take approximately
43 months.The activities that are on the critical path to commencement of
construction of the project include:development of the plan of study for the
project,procurement and installation of field monitoring equipment,the
gathering of air quality and meteorological data,analysis of terrestrial
ecology field data,preparation and review of the PSD permit application,
preparation and review of the application for the state's Certificate of
Public Convenience and Necessity,(a)and preparation and review of the
applications for the NPDES and Corps'Section 404/10 permits (which are on the
critical path due to the requirement that the permits cannot be issued until
30 days after the final environmental impact statement is completed).
(a)Issued by the Alaska Public Utilities Commission to anyone wishing to own,
operate,manage or control a public utility.
6.16
I MONTHS TO CONSTR.PERMIT
.--"-_....- -
_..•~
TASKTITLE 43 42 41 40 39 38 37 36 35
34 33 32 f31 30 29 28 27 26 25 24 23 22 21 20 19 18 17 .16 15 14 13 12 11 10 9 8 7 8 6 ..3 2 1..-PLAN OF STUDY
LIT &.DATA SURVEY"SURFACE WATER QUALITY I
LIT &.DATA SURVEY·GROUND WATER HYDROLOGY I
LIT &.DATA SURVEY·TERRESTRIAL ECOLOGY I
LIT &.DATA SURVEY·NOISE I d
LIT &.DATA SURVEY·LAND USE I I w ,¢.d a:.-~.0 tilLIT&.DATA SURVEY·SURF WATER HYDROLOGY &.HYDRO I FIELD a:a:""~~f--f--
I oJ Z II:
-LIT &.DATA SURVEY·METEOROLOGY MONITORING EQUIP w w ~f--1-0 f--C!l
LIT &.DATA SURVEY·AQUATIC ECOLOGY II:Cl ~-0 z
INSTALLED Cl dI f--""lZ f--:::i
LIT &.DATA SURVEY·GEOLOGY/SOILS I z II:ll.0.ZII:::l o-f--""-f--
SITE RECONNAISSANCE w I-w «
w oil II::I:
FIELD MONITORING EQUIP PROC &.INSTL z II:ll.oJ
Cl w .«
oJ 0FIELDDATA·SURFACE WATER QUALITY z 0 0-._---_.--.w .
FIELD DATA ..GROUND WATER/GEOLOGY m•
FIELD DATA·TERRESTRIAL ECOLOGY LEGEND:
FIELD DATA ..NOISE I-MAJI01'!~ILESIONEFIELDDATA·LAND USE ...,....
FIELD DATA·HYDROGRAPHICS &.DISPERSION '-NORMAL ACTIVITIES
FIELD DATA·AIR QUALITY/METEOROLOGY t-'-..,MOST CRITICAL ACTIVITIES
FIELD DATA·AQUATIC ECOLOGY &.ICHTHYOPLANKTON I ---RESTRAINT
DATA ANALYSIS·SURFACE WATER QUALITY
DATA ANALYSIS·GROUND WATER HYDROLOGY FROM WTR USE &.-J
WASTE MGT STUDY -I
DATA ANALYSIS ..TERRESTRIAL ECOLOGY FROM AQCS STUDY--,
DATA ANALYSIS·NOISE I t
DATA ANALYSIS·LAND USE TO E.R.
..MONITORING
DATA ANALYSIS·SURF WTR HYDROLOGY &.HYDROTHERMAL I SITE I ,
SECTION
DATA ANALYSIS·AIR QUALITY/METEOROLOGY SELECTION I
SUBMIT
DATA ANALYSIS ..AQUATIC ECOLOGY ~FROM AQCS STUDY
ERTO
DATA ANALYSIS ..GEOLOGY/SOILS AGENC"!'
ER·REFERENCES/INDEX SECTION
ER·NEED FOR POWER SECTION f---~--I--1---~!'--...,
ER·EXISTING ENVIRONMENT SECTION -
ER·ALTERNATE SITE &.SOURCES SECTION -r--.--\
ER ..ALTERNATE PLANT SECTION FROM WTR USE &._..,._-.-~...l \
ER·PLANT DESCRIPTION SECTION WASTE MGT STUDY I .---l,
ER ..ENVIRO EFFECTS DURING CONSTRUCTION SECTION -.-4 \
ER·ENVIRO EFFECTS DURING OPERATION I ....;~.....\
ER·MONITORING SECTION I FROM TERR'L \
ER·SOCIOECONOMIC EFFECTS SECTION I ECOLOGY ~-\ISSUE Issue
ER ..BENEFIT/COST ANALYSIS SECTION I D~TA~NAL I --~.......PSD NPDES ISSUE SEC 10 &lOR -
ER·ENVIRONMENTAL APPROVALS SECTION 7Rot~CIP~r------..l I)PERMIT ......PERMIT \SEC 404....\PERMIT -
PSD PERMIT·I
~GDS SPECIFICATION I--NPDES PERMIT/EIS ~!'t"--
USACOE SEC 10 AND/OR SEC 404 PERMIT/EIS FROM INTAKE &.__
RCRA DETERMINATION
DISCH STUDY \..
STATE AIR 1/--'\."flCRA f--
401 CERTIFICATION SUBMIT V DETERMINATION
COMPLETED f--
WATER RIGHTS PSD APPL'N I
SOLID WASTE DISPOSAL &.COAL PROSPECTING I I
FEDERAL SURFACE MINING CONTROL AND.RECLAMA..TION ACT , , ,, ,,I I ,I I I I I , ,I I I I ,I I I I I , , , , ,I.
FIGURE 6.1.Licensing Schedule
6.17
In order for an appl"icant to prepare permit applications and an environ-
mental report~it is necessary to develop conceptual engineering information
on the systems of the generating plant that can impact the environment.Once
that information is available~the development of a plan for satisfaction of
the licensing requirements can proceed.It is suggested that representatives
of the State of Alaska be included in the planning process as early as pos-
sible,in order to properly take advantage of the program for coordinated
permitting which is under development and which will probably be in effect by
the time this or an alternate project is initiated.Alaska hopes to have a
single contact in the state coordinate applications for~processing and
issuance of permits by state~local and perhaps even federal permits.The
existence of such a contact could ease the burden on the applicant with
respect to the time and effort that must be expended during the licensing
proces s.
In general,site construction cannot begin until environmental require-
ments indicated in Figure 6.1 are satisified.More specifically,according to
the Clean Air Act and EPA regulations~if a PSD permit is required for a proj-
ect~an applicant may not begin continuous construction or enter into binding
agreements or contracts for construction programs that can not be cancelled or
modified without substantial loss until the PSD permit and all other necessary
air quality/air emission approvals have been obtained.No dredged/fill mate-
rial activity or other activity in surface waters can begin without a CWA
Section 404/10 permit and no construction of a RCRA hazardous waste management
facility can begin before a RCRA permit has been issued.Some site clearance
activities can begin and some equipment can be purchased before permit issue.
Such activity would require permission from state and federal agencies and
would take place at the applicant's own risk.
6.19
~iJtrft•~.
7.0 REFERENCES
Bechtel Corporation.1980.Preliminary Feasibility Study,Coal Export Pro-
gram,Bass-Hunt-Wilson Coal Leases,Chuitna River Field,Alaska.Bechtel
Corporation,San Francisco,California.
Commonwealth Associates Inc.1981.Feasibility Study of Electrical Inter-
connection Between Anchorage and Fairbanks.Engineering Report R-2274.
Alaska Power Authority.Anchorage,Alaska.
Swift,W.H.1981.Alaska Coal:Future Availability and Price Forecasts.
Battelle,Pacific Northwest Laboratories,Richland,Washington.
7.1