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ALAe:tKA RESOUR .E ....
U.S.DEPT.OF Il~'.L:.ol
Coal-Gasification Combined-
Cycle Power Plant Alternative
for the Railbelt Region of
Alaska
Volume XVII
Ebasco Services Incorporated
August 1982
Prepared for the Office of the Governor
State of Alaska
Division of Policy Development and Planning
and the Governor's Policy Review Committee
under Contract 2311204417
()Battelle
Pacific Northwest Laboratories
LEGAL NOTICE
This report was prepared by Battelle as an account of sponsored
research activities.Neither Sponsor nor Battelle nor any person acting
on behalf of either:
MAKES ANY WARRANTY OR REPRESENTATION,EXPRESS OR
IMPLIED,with respect to the accuracy,completeness,or usefulness of
the information contained in this report,or that the use of any informa-
tion,apparatus,process,or composition disclosed in this report may not
infringe privately owned rights;or
Assumes any liabilities with respect to the use of,or for damages result-
ing from the use of,any information,apparatus,process,or composition
disclosed in this report.
I
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~\
L JJ
MAR
Coal-Gasification Combined-Cycle
Power Plant Alternative for the
Railbelt Region of Alaska
Volume XVII
Ebasco Services Incorporated
Bellevue,Washington 98004
August 1982
Prepared for the Office of the Governor
State of Alaska
Division of Policy Development and Planning
and the Governor's Policy Review Committee
under Contract 2311204417
Battelle
Pacific Northwest Laboratories
Richland,Washington ~9352
ACKNOWLEDGMENTS
The major portion of this report was prepared by the Bellevue,Washington,
and Newport Beach,California,offices of Ebasco Services Incorporated.Their
work includes the Introduction,Technical Description,Environmental and Engi-
neering Siting Constraints,Environmental and Socioeconomic Considerations and
Institutional Considerations.Capital cost estimates were prepared by
S.J.Groves and Sons of Redmond,Washington,and reviewed by the Ebasco cost
estimating department in New York City.Cost of energy estimates were pre-
pared by Battelle,Pacific Northwest Laboratories of Richland,Washington.
iii
PREFACE
The state of Alaska,Office of the Governor,commissioned Battelle,
Pacific Northwest Laboratories (Battelle-Northwest)to perform a Railbelt
Electric Power Alternatives Study.The primary objective of this study was to
develop and analyze long-range plans for electrical energy development for the
Railbelt Region (see Volume I).These plans will be used as the basis for
recommendations to the Governor and Legislature for Railbelt electric power
development,including whether Alaska should concentrate its efforts on
development of the hydroelectric potential of the Susitna River or pursue
other electric power alternatives.
Preliminary assessment of coal-gasifier combined-cycle power plants
indicated that they may offer the potential for efficiently utilizing the
abundant Alaskan coal resources to generate a gas turbine-compatible fuel,
thereby capitalizing on the high efficiency of combined-cycle technology.The
ability of this process to accept pulverized,run-of-mine Beluga coal suggests
that it will have a'very low fuel cost.A modest plant size is appropriate
for anticipated future capacity requirements of the Railbelt Region.Thus,a
nominal 220-MW-capacity plant was selected for study.This report,Volume XVII
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-fired steam-electric 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 Laboratories for
the Office of the Governor,State of Alaska,Juneau,Alaska.
Ebasco Services,Inc.1982.Chakachamna Hydroelectric Alternative for
the Railbelt Region of Alaska.Prepat'ed 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 Region of Alaska.Prepared by Ebasco Services Incorporated and
Battelle,Pacific Northwest Laboratories for the Office of the Governor,
State of Alaska,Juneau,Alaska.
Ebasco Services,Inc.1982.Wind Energy Alternative for the Railbelt
Region of Alaska.Prepared by Ebasco Services Incorporated and Battelle,
Pacific Northwest Laboratories for the Office of the Governor,State of
Alaska,Juneau,Alaska.
Ebasco Services,Inc.1982.Coal-Fired Steam-Electric Power Plant
Alternatives for the Railbelt Re 1ion of Alaska.Prepared by Ebasco
Services Incorporated and Battel e,Pacific Northwest Laboratories for
the Office of the Governor,State of Alaska,Juneau,Alaska.
vi
SUMMARY
Substantial deposits of accessible and surface-mineable coal in the
Beluga area 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 a
coal-gasifier combined-cycle power plant located in the Beluga area and
supplied by coal taken from proposed surface mines in the Beluga Coal Field.
The plant design selected for study is a nominal 220-MW coal-gasifier
combined-cycle plant utilizing two combustion turbines of 74.5 MW capacity
each and a heat recovery steam generator supplying a steam turbine generator
of 100 MW rated capacity.Gross plant rating is thus 249 MW;net rating,less
internal loads of 29 MW,is 220 MW at standard conditions.The annual average
heat rate is estimated to be approximately 9287 Btu/kWh.A forced outage rate
of 8 percent and a scheduled outage rate of 7 percent would provide an
equivalent annual availability of 86 percent.Sulfur recovery is by multiple
Claus units followed by Stretford tail gas cleanup.Heat rejection is by
mechanical draft wet-dry cooling tower.The plant would be located in the
Beluga area,northwest of Cook Inlet.Power would be transmitted by 345-kV
line approximately 75 miles to the proposed Anchorage-Fairbanks intertie.
Overnight capital cost for the proposed plant was estimated to be
3284 $/kW.Working capital (54-day emergency coal supply plus 30-day O&M
costs)was estimated at 26 $/kW.Fixed and variable operation and maintenance
costs were estimated to be 16.87 $/kW/yr and 0.67 mills/kWh,respectively.
Levelized busbar energy costs were estimated for various capacity factors and
years of first commercial operation using forecasted Cook Inlet natural gas
prices prepared elsewhere in the Railbelt Electric Power Alternatives Study.
For a 1991 startup date and an 85 percent capacity factor,a levelized busbar
power cost of 63 mills/kWh was estimated.All costs are in January 1982
dollars.
vii
Environmental effects of the proposed plant are expected to be relatively
minor when compared to alternate fuel-combustion technologies.Overall NO x
emission levels would be controlled to the applicable NO standard of 0.014x
volume percent of total flue gas.Sulfur dioxide released to the environment
is minimized through incorporating sulfur removal,recovery and tail gas
cleanup units in the process.Total sulfur emissions are estimated to be
0.0075 lb/MMBtu (as sulfur).Particulate release could be controlled through
conventional technology to an estimated 0.009 lb/MMBtu.Other emissions are
estimated to be 0.003 lb/MMBtu hydrocarbons and 0.010 lb/MMBtu carbon monoxide.
Gross water requirements total 1525 gpm at full power,of which 1303 gpm
would be consumed and 222 gpm discharged.Estimated land requirements for the
plant are 80 acres plus land required for transmission line,gas pipeline and
access road right-of-ways.
The estimated peak construction work force of 1000 personnel could
produce severe boom-bust effects in the Beluga area.
A potential constraint to development is the need for a developed Pacific
Rim market for Beluga coal.The outlook for development of such a market
appears to be excellent.Beluga coal could be available as early as 1986 but
certainly by 1988 (Swift 1981).
viii
CONTENTS
DISCUSSION
~VV~~~AND AUXILIARY SYSTEMS DESCRIPTION
Gasifier Plant
Combined-Cycle Plant
Electric Plant
Water and Wastewater Treatment Systems
Solid Waste Disposal Systems
SYSTEM •
Access Roads •
Construction Water Supply
Construction Transmission Lines
Airstrip
Landing Facility •
Construction Camp Facilities
AND MAINTENANCE
General Operating Procedures
Operating Parameters
ix
iii
v
vii
1.1
2.1
2.1
2.8
2.26
2.32
2.38
2.44
2.46
2.47
2.49
2.49
2.49
2.49
2.51
2.51
2.51
2.52
2.53
2.53
2.57
2.6.3 Plant Life · · ··· ·· ··2.58
2.6.4 Operating Work Force ····· ··2.59
2.6.5 General Maintenance Requirements •····2.59
3.0 COST ESTIMATES ..· · ·· ·
··· ·
3.1
3.1 CAPITAL COSTS'.· · · · · · ·· ·
3.1
3.1.1 Construction Costs ··· · · · ·
3.1
3.1.2 Payout Schedule · ·
·· ·
···3.1
3.1.3 Escalation · · ·· · · ···3.1
3.1.4 Economics of Scale · ·
··· · ·
3.4
3.1.5 Working Capital · · ·
· · ···3.4
3.2 OPERATION AND MAINTENANCE COSTS · · · · · ·
3.4
3.2.1 Operation and Maintenance Costs ·· · · ·
3.4
3.2.2 Escalation · · · · ·····3.5
3.2.3 Economics of Scale ··· · · · ·
3.5
3.3 FUEL AND FUEL TRANSPORTATION COSTS •· · · · ·
3.6
3.4 COST OF ENERGY .· · · · · · ·· ·
3.6
4.0 ENVIRONMENTAL AND ENGINEERING SITING CONSTRAINTS · · ··4.1
4.1 ENVIRONMENTAL SITING CONSTRAINTS · · · · · ·
4.1
4.1.1 Water Resources ····· · · ·
4.1
4.1.2 Air Resources ·· · · ·
·· ·
4.2
4.1.3 Aquatic and Marine Ecology · · · · · ·
4.3
4.1.4 Terrestrial Ecology · · · · ···4.3
4.1.5 Socioeconomic Constraints ···· · ·
4.3
4.2 ENGINEERING SITING CONSTRAINTS ·· · · · ·
4.4
4.2.1 Site Topography and Geotechnical
Characteristics · · · · · · · ·
4.4
x
4.2.2 Access Road and Transmission Line
Considerations 4.5
4.2.3 Water Supply Considerations.4.5
5.0 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS 5.1
5.1 WATER RESOURCE EFFECTS 5.1
5.2 AIR RESOURCE EFFECTS 5.1
5.3 AQUATIC AND MARINE ECOSYSTEM EFFECTS 5.3
5.4 TERRESTRIAL ECOSYSTEM EFFECTS •5.3
5.5 SOCIOECONOMIC EFFECTS 5.4
6.0 INSTITUTIONAL CONSIDERATIONS .6.1
6.1 FEDERAL REQUIREMENTS 6.1
6.2 STATE REQUIREMENTS ·6.5
6.3 LOCAL REQUIREMENTS ·6.5
6.4 LICENSING SCHEDULE ·6.5
7.0 REFERENCES 7.1
xi
FIGURES
2.1 Plot Plan
2.2 General Process Flow Diagram.
2.3 Gasifier Section:Process Flow Diagram
2.4 Combined-Cycle Section:Process Flow Diagram
2.5 One-Line Diagram
2.6 Beluga Station Switchyard
2.7 Water Balance Diagram
2.8 Sulfur and Ash Balance
2.9 Willow Substation
2.10 Construction Work Force Requirements
2.11 Construction Schedule
3.1 Cost of Energy Versus Capacity Factor and
Year of First Commercial Operation
xii
2.2
2.5
2.11
2.13
2.37
2.39
2.40
2.45
2.50
2.52
2.55
3.8
TABLES
2.1 Gasifier Section Flow Identification For Figure 2.3
2.2 Combined-Cycle Section Flow Identification for
Figure 2.4
2.3 Typical Test Data from the Shell-Koppers Process.
2.4 Combustion Turbine with Generator Design Parameters
2.5 Heat Recovery Steam Generator Design Parameters
2.6 Steam Turbine Generator Unit Design Parameters
2.7 Condenser Design Parameters
2.8 Wet/Dry Cooling Tower Design Parameters
2.9 Pump Design Parameters
2.10 Fuel Oil and Condensate Tank Design Parameters
2.11 Miscellaneous Equipment Design Parameters
2.12 Plant Staffing Requirements
3.1 Bid Line Item Costs for Beluga Area Coal-Gasifier
Combined-Cycle Project
3.2 Payout Schedule for Beluga Area Coal-Gasifier
Combined-Cycle Project
3.3 Estimated Coal Prices:Beluga Station •
3.4 Year-of-Occurrence Energy Costs
5.1 Primary Environmental effects
6.1 Federal Regulatory Requirements
6.2 State Regulatory Requirements
xiii
2.15
2.16
2.18
2.28
2.30
2.31
2.32
2.33
2.34
2.35
2.36
2.60
3.2
3.3
3.7
3.9
5.2
6.3
6.6
1.0 INTRODUCTION
The integration of a coal gasifier with combined-cycle technology would
allow the use of coal resources abundant in the Railbelt Region to fuel an
efficient,technically proven,combined-cycle-type generating plant.In a
plant of this type,coal is gasified in an air-or oxygen-blown gasifier,
producing a low-or medium-heating value gas (150 or 300 Btu/ft3 ),respec-
tively.This fuel is used in combustion turbines to generate electricity.
Steam is produced from the combustion turbine exhaust.This steam,along with
steam produced in the gas cooler section of the gasifier,is used in a steam
turbine to produce additional electricity.
Suitable gasifiers for this plant are not now commercially available.
However,several first-generation gasifier units in a basic 1000 ton/day
prototype module size are being built for demonstration in Europe in the
1983-1984 time frame.Other designs are being built for commercial operation
during 1984 in the Republic of South Africa.It is expected that second-
generation gasifier technology required to support a plant such as that
described in this report will be available by 1985 when design validation
operational data are available from units now under construction.
The combined-cycle portion of the plant would use modified combustion
turbine designs such as those being developed in West Germany.Combined cycle
technology has,in general,been widely used for the last 15 years in the
electric utility industry.
The principal advantage of this alternative is that it will allow rela-
tively abundant Alaskan coal resources to be efficiently utilized to generate
a fuel that is suitable for combustion turbines and thus capitalize on the
high efficiency and other advantages of combined-cycle technology.An overall
efficiency of 37 percent is projected at the 220-MW size.Since the coal must
be in a finely pulverized state for gasifier use,the entire output of a mine
(including fines)is acceptable as feed.Because of the high cycle efficiency,
and the ability to use the lowest cost coal,this alternative will have a very
low fuel cost.
1.1
The gas produced contains no tars,phenols,condensible hydrocarbons or
organic sulfur compounds.The only byproducts are elemental sulfur,a small
amount of ammonia,and the gasifier ash.Other advantages of this alternative
include low air emissions and the capability of a plant to be expanded in a
modular fashion.
Because the gasifier operates at very high temperatures,a high quality
synthesis gas is formed that consists essentially of hydrogen and carbon
monoxide.Therefore,this alternative has the potential for converting part
of the synthesis gas to methanol during non-electrical peak periods if the
power plant is operated in a peaking mode.Sale of methanol could increase
project revenues and result in a lower cost of electricity.
The primary disadvantages of this alternative are that optimum gasifier
systems are not yet commercially available,and present turbine designs must
be modified to accommodate a higher mass flow.A coal gasifier combined-cycle
plant will have higher capital costs,require more operators and greater
maintenance than a coal-fired power plant of comparable size.A greater land
area will be required for this alternative than a comparable conventional coal
plant;and as the gasifier will contain tall towers and stacks as well as
large coal piles,the aesthetic intrusion of the plant could be locally
significant.Another potential problem may exist with the disposal of large
quantities of process and cooling water.
The power plant described in this report will utilize two 45-ton/hour
entrained-flow,oxygen-blown gasifiers and two large-frame combustion turbine
generators,each producing approximately 74.5 MW.A nominal 100-MW steam
turbine generator,operating off a waste heat recovery boiler,will be used,
resulting in a total gross output of approximately 250 MW.The auxiliary
plant load will be approximately 30 MW,and therefore the net output will be
220 MW.Sulfur recovery will be by multiple Claus units with Stretford tail
gas cleanup.A wet-dry cooling tower will be used for waste heat rejection.
The plant will be located in the Beluga area of Cook Inlet.
Coal quality assumptions used for this study are typical of the Beluga
fields and are as follows:
1.2
Heating Value
Ash Content
Moisture
Sulfur
Nitrogen
Ash Softening Temperature
Ash Na 2
Hardgrove Grindability Index
1.3
8,000 Stull b
8%avg -11%~max
28%
0.20%
0.60%
2350°F
0.10%
30
2.0 TECHNICAL DISCUSSION
2.1 PROCESS AND AUXILIARY SYSTEMS DESCRIPTION
The fuel for the combined-cycle plant will be medium-Btu gas (MBG)
generated by the gasification of Beluga coal using an entrained flow gasifier
of the Shell design.The gas treatment section of the gasifier plant will be
of the Koppers design.The Shell design was selected on the basis of the high
moisture content of Beluga coal and the requirement for the power plant to be
capable of operating in a load-following mode.
The input coal is pulverized,then fed to the gasifier reactor by means
of pressurized lockhoppers.The coal reacts with oxygen in the reactor at
temperatures above the ash fusion point,in substochiometric combustion,to
produce hydrogen,carbon monoxide and a small amount of carbon dioxide.The
product gas has a heating value of about 300 Btu/ft 3•Ash in the coal is
fused into small pellets that are removed through lockhoppers.The product
gas is cooled,giving its sensible heat to produce steam for the
steam-bottoming cycle.After cooling,unreacted coal and ash particles are
removed from the product gas and are recycled to the coal input section.The
product gas is then passed to a gas cleanup section where sulfur is removed.
The combined-cycle plant design is based on using two currently available
General Electric gas turbine generators,rated at approximately 74.5 MW each,
in combination with a General Electric steam turbine generator rated at
approximately 100 MW.The heat recovery steam generators (HRSGs),one to each
gas turbine,and the gas cooler heat exchanger will collectively generate
the steam required for the steam turbine.The plant will also include an
oxygen plant,coal handling facilities,and sulfur recovery units
(Figure 2.1).Water injection will be used for NO control in the gasx
turbines.
2.1
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FIGURE 2.1.Plot Plan
At International Standards Organization (ISO)referenced conditions (59°F
and sea level),plant performance in the combined-cycle mode would be as
follows:
Plant Output (net)
Heat Rate
220,000 kW
9,287 Btu/kWh (approximate)
Distillate oil is suggested as an emergency and black-start fuel.
Main steam of 1175 psig,952°F,has been selected for the steam cycle,
based on a gas turbine exhaust temperature of 985°F.This design uses a 35°F
approach temperature for the main steam,and falls in the range of readily
available steam turbine generator sets.A 30°F approach temperature has been
used on the feedwater heater,the economizer,and the evaporative sections in
the steam generator.The steam turbine used for this design will be a
full-condensing turbine,bottom-exhausting with the condenser mounted
underneath.
The major process flows are shown in Figure 2.2.Combusted gas is
expanded through the gas turbine,driving both the 74.5-MW generator and the
integral free-shaft gas turbine air compressor on each unit.Exhaust gas from
each turbine flows through multi-pressure HRSGs (one for each gas turbine),
where the heat is utilized to help generate 1200 psig superheated steam used
to drive the steam turbine generator,and 150 and 50 psig saturated steam for
other plant uses.The gas is exhausted to the stack on exiting the steam
generator.A bypass damper and stack are provided for each steam generator so
that the combustion turbine can be operated independently of its HRSG.
The combined high-pressure steam flow of 775,780 lb/hr is expanded
through a common steam turbine,driving a 100-MW generator,with 1175 psig,
952°F inlet conditions.Exhaust steam from the turbine is condensed in a
vacuum condenser,which is cooled by the circulating water system employing a
wet-dry cooling tower.The cooling tower can be operated in either a wet or
dry mode,and is expected to operate in the dry mode during the winter months,
eliminating the potential for fog plumes and icing about the tower,and
reducing power plant makeup water requirements.
2.3
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FIGURE 2.2.General Process Flow Diagram
2.5
The steam and feedwater system is an integrated plant design and is
extremely complex.Saturated steam at three pressures,50 psig,150 psig and
1200 psig,is generated collectively by the HRSGs,the gas cooler heat
exchanger,the feedwater heater,and various sulfur condensers and reaction
boilers in the sulfur removal plant.The 50 psig saturated steam is used for
feedwater deaeration and/or process steam in the effluent water strippers.
The 150 psig saturated steam is used in the sulfur removal plant,with the
condensate being returned to the deaerator tank.The 1200 psig saturated
steam is superheated in the superheater section of each HRSG prior to use as
main steam in the steam generators.
Condensate is pumped from the condenser to the condensate storage tank.
Deaerator feed pumps take suction from the condensate tank,pumping the water
through the low-pressure economizer sections of the HRSGs to the deaerator.
Both the low-pressure and high-pressure boiler feed pumps take suction from
the deaerator storage tank.
The low-pressure feed pump feeds the low-pressure evaporator sections of
the HRSGs and provides the suction feed for the intermediate-pressure feed
pump.A portion of the low-pressure feed pump discharge is fed through a
sulfur condenser and reaction boiler in the sulfur plant where heat is
absorbed;the heated water being returned to mix with the low-pressure
saturated steam entering the deaerator.The 50 psig low-pressure saturated
steam generated in the low-pressure evaporator sections of the HRSGs is used
as deaerator feed and as process steam for the effluent water strippers.
The intermediate-pressure feed pump feeds the IP evaporator sections of
the HRSGs,which produce 150 psig saturated steam.A portion of IP pump
discharge is used as cooling water in the reaction boiler and sulfur condenser
and the heated discharge is mixed with the 150 psig saturated steam entering
the sulfur melter and reboiler.The 150 psig saturated steam is used
exclusively in the sulfur melter and reboiler.Condensate from the sulfur
melter and reboiler is fed back to the deaerator storage tank.
The high-pressure feed pump takes suction from the deaerator tank and
discharges the water through heat exchangers in the gas cycle to the HRSG
economizer sections.Part of the economizer outlet flows are fed to the gas
2.7
cooler,generating saturated HP steam,which is collected in an independent
steam drum.The remaining portion of the HP economizer outlets is fed to the
HP evaporator sections of the HRSGs where saturated steam is produced.The
saturated steam from the independent steam drum is passed through the gas
cooler,producing superheated steam that is subsequently mixea with the steam
from each HRSG,producing the high-pressure main steam for the steam turbine
generator.
2.1.1 Gasifier Plant
Because of the requirement for load following capability,an entrained
flow gasifier was selected.Fixed-bed gasifiers,such as Lurgi,and others,
operate best at constant throughput and constant temperatures.Fluidized bed
gasifiers,such as Westinghouse,could be considered if the time variation of
the output were slow enough,i.e.,the material residence time is about 15
minutes,so it would take times on the order of tens of minutes for the
gasifier to respond to a change of fuel input.With entrained flow gasifiers,
the particle residence times are small fractions of a minute.Since it is
desirable to keep the rate of change of the steam power system components to
about 5 percent per minute,both a fluidized bed gasifier and an entrained
flow gasifier are potentially compatible.However,when considering the
facility·s intended application where it would be the largest generating plant
within the utility grid system,it is desirable to have a more rapid response
time to changes in system load.For this reason,an entrained flow gasifier
was selected.
Because of the high moisture content of Beluga coal,20 to 28 percent,
the Shell system was selected.In the Shell system,the coal is fed as a dry
powder through lockhoppers,rather than a coal-water slurry,which is used in
the Texaco process.The extra water brought in with a coal slurry (approxi-
mately 50 percent by weight)combined with the moisture already contained in
the coal would exceed process requirements and require more carbon to be
combusted to heat the extra water vapor,thus reducing gasifier efficiency.
The Shell gasifier has been piloted using a coal feed at a capacity of
150 tons/day,and similar units using residual fuel oil have been operated in
the oil industry for a number of years.Two Shell units for gasifying coal
2.8
are now being constructed in Europe at the thousand ton/day size,the basic
module of a commercial plant.Both the Shell and Texaco units are approxi-
mately at the same level of development and demonstration at commercial
scale.Therefore,selection of the Shell process over the Texaco process on
the basis of feedstock moisture will have no adverse effect on the schedule of
the proposed facility under study.
Another major design choice concerns the use of either an airblown
gasifier to make low-Btu gas or an oxygen-blown gasifier to produce medium-Btu
gas.This choice will ultimately be made on the basis of a detailed capital
cost and operating cost estimate for the power plant.An airblown gasifier
requires a larger physical size for the gas-flow-train components,a larger
number of gasifier reactor vessels,larger product gas cleanup equipment and
other components because of the substantial increase in mass flow (almost
double)when air is used as the oxidant.
The use of oxygen requires an air separation plant to produce oxygen and
the power to drive the separation plant.This power is generated by the
plant's steam-bottoming cycle,and since the bottoming-cycle efficiency
improves with size,the incremental cost for this power is less.In light of
this and of the high cost of shipping and erecting equipment in Alaska,as
well as the simplification in gasification plant start-up that can be achieved
using previously liquefied and stored oxygen,the oxygen-blown gasifier was
selected.
The production of medium-Btu gas as an intermediate product also permits
the option of running the gasifier at 100 percent load all of the time and
converting the excess MBG not required for electricity production to methanol.
Methanol could be stored and used as a peak shaving fuel in the combustion
turbines,or as a product for sale in commerce;the revenues received being
used to offset the cost of generating electricity.
The following sections discuss the various components of the coal-
gasifier combined-cycle plant in detail.Detailed process flow diagrams of
the gasifier section and combined-cycle section are presented in Figures 2.3
and 2.4,respectively.Tables 2.1 and 2.2 present details of each flow
diagram1s process streams.Much of the following information regarding
2.9
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COOl.!"'-I"-roweR FIGURE 2.4.Combined-Cycle Section:Process Flow Diagram 2.13
TABLE 2.l.Gasifier Section Flow Identification for Figure 2.3
Input Pressure Temperature
Stream Fluid Component (lb/hr)(psig)(·F)
1 Raw Coal Feed Raw Coal 219,702 atm NA
2 Ory Coal Feed Pulv.Coal 162,580 atm
3 Water Vapor H2O 57,122 atm 300
4 Hot Ai r Air 1.1(atm)400
5 Carrier Gas N2 100 80
6 Entrained Coal Flow Coal,N2 2(atm)
7 Separated Carrier Gas N2
8 Lock-Hopper Pressurization N2 600
9 Fines Ash Recycle Ash,Coal 600
10 Coal Feed Coal 575
11 Coal Feed Coal 550
12 Gasifier Product CO,H2,H2S,Ash 450
13 Recycle Product Gas CO,H2,H2S 450
14 Mixed Raw Product Gas CO,H2,H2S,Ash 450
15 Gasifier Steam Steam 500
16 Oxygen O2 500 200
17 Slag Ca/Si0 2 450 2,400
18 Superheated Steam 1,275 940
19 Reactor Cooling Water In H2O 1,300 200
20 Reactor Cooling Water Out H2O 1,290
21 Raw Product Gas CO,H2,H2S,Ash 440
22 Steam Drum Outlet Steam
23 Super Heated Steam Steam 1,275 940
24 Boiler Feedwater H2O 1,300
25 Cooled Raw Gas CO,H2,H2S
26 Cooled Raw Gas CO,H2, H2S
27 Raw Gas CO,H2, H2S
28 Raw Gas CO,H2, H2S
29 Dri ed Raw Gas CO,H2, H2S
30 Recycle Gas CO,H2, H2S
31 Sour Product Gas CO,H2,H2S
32 Product Gas CO,H2 275 120
33 Scrubber Waste Water H20,NH 3 300 220
34 Selexol 275 90
35 Preheated Product Gas 250 350
36 Ammonia Product NH 2
37 Sulfur Product S
INTERCONNECTIONS
FIGURE 2.3 FIGURE 2.4
Stream Unit No.Stream No.Unit No.Stream No.
A Product Gas 6.3 35 8 3
B Main Steam 5.1 23 10 32
C Comb Prod/Hot Air 1.7 4 9 35
D Boiler Feed Water 5.2 24A 13 11
E Boiler Feed Water 6.2 24B 13 11
F Heated BFW 6.2 24C 9 28
2.15
TABLE 2.2.Combined-Cycle Section Flow Identification for Figure 2.4
Input Pressure Temperature Enthalpy
Stream Fluid Component (1 b/hr)(psig)(oF)(Btu/lb)
1 High Pressure Product Gas CO,H2 290,000 425 330
3 Product Gas CO,H2 290,000 250 300
4A+4B Product Gas CO,H2 143,800 250 300
5A+5B Exhaust Gas CO 2, H2O 2,027,240 1,000 278
6 Low Pressure Steam Steam 39,120 50 298 1,179
6A+6B Low Pressure Steam Steam 19,560 50 298 1,179
7 Condensate H2O 787,320 108 110
7A+7B Condensate H2O 393,660 108 110
8 Water H2O 787,320 200 168
8A+8B Water H2O 393,660 200 168
9 Low Pressure Steam Steam 73,500 148 365 337.6
10 Condensate H2O 119,420 200 250 218.5
11 Boiler Feed Water H2O 775,780 1,300 250 218.5
12A+12B Condensate H2O 19,560 200 250 218.5
13 Condensate H2O 80,300 200 250 218.5
14 Condensate H2O 5,040 200 250 218.5
15 Condensate H2O 1,020 200 250 218.5
16 Low Pressure Steam Steam 10,800 50 302 1,179
17 Low Pressure Steam Steam 5,040 50 302 1,179
18 Low Pressure Steam Steam 1,020 50 302 1,179
19 1nt.Pressure Feed Water H2O 74,240 200 250 218.5
20 1nt.Pressure Feed Water H2O 72,220 380 250 218.5
20A+20B Int.Pressure Feed Water H2O 36,110 380 250 218.5
21 Process Steam Steam 72,220 150 366 1,196
21A+21B Process Steam Steam 36,110 150 366 1,196
22 Process Steam Steam 500 150 366 1,196
23 Process Steam Steam 73,000 150 366 1,196
24 Boiler Feed Water H2O 2,020 380 250 218.5
25 Process Steam Steam 1,280 150 366 1,196
26 Blow Down H2O 740 50 NA NA
27 Low Pressure Steam Steam 34,380 50 298 1,179
28 Boiler Feed Water H2O 775,780 1,275 310 1,183
28A+28B Boiler Feed Water H2O 387,890 1,275 310 1,183
29A+298 Boiler Feed Water H2O 161,800 1,250 550 549.1
30A+30B Boiler Feed Water H2O 226,090 1,250 550 549.1
30 Boiler Feed Water H2O 452,180 1,250 550 549.1
31A+31B L.P.Steam Steam 161,800 1,200 569 1,183.2
32A+32B L.P.Steam Steam 226,090 1,200 569 1,183.2
32 L.P.Steam Steam 452,180 1,200 569 1,183.2
33A+33B L.P.Steam Steam 387,890 1,175 952 1,472
33 L.P.Steam Steam 775,780 1,175 952 1,472
34A Condensate H2O 775,780 1.16 107 1,033
34B Condensate H2O 775,780 36.5 107 75
35A+35B Exhaust Gas CO 2, H2O 2,027,240 270 NA
35 Exhaust Gas CO 2, H2O 4,054,480 270 NA
38A+38B Comb Air Air 1,183,440 atm 80 NA
41 Make Up Water H2O 27,440 50 60 NA
2.16
sulfur removal and recovery and tail gas cleanup has been modified from simi-
lar systems presented in Electric Power Research Institute (1978).Table 2.3
presents test data on the Shell-Koppers process using Wyodak,Wyoming,subbi-
tuminous coal,which is similar to Beluga coal.Data similar to this can be
expected with the proposed design using Beluga coal.
Coal Gasification
The coal gasification section consists of a number of individual process
units,including coaf preparation,air separation,coal gasification and gas
cooling,and ammonia recovery.Process descriptions of each unit follow ana
should be read in conjunction with the process flowsheet (Figure 2.3).
Coal Preparation (Figure 2.3,Units 1 and 2).The purpose of the coal
preparation unit is to provide coal,sized smaller than 70 mesh without exces-
sive surface moisture,for feeding to the gasification unit.
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 site by mine-
mouth conveyor.The mine-mouth conveyor will feed the storage pile directly.
The conveyor will be sized for a capacity of 500 tons/hour.It will have a
35°troughing idler,be 36 inches in width,travel at a velocity of 350 feet
per minute,and be weather protected its entire length.
Stacking and Reclaiming--Initial coal deliveries will be used to estab-
lish a compacted dead and long-term storage pile.This pile will consist of
two sections,one on each side of a below-grade reclaim tunnel,and will
contain a 45-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 for full-load
operation.
Once the dead storage pile has been established and compacted,subsequent
coal deliveries will be transported by an inclined/overhead conveyor tripper
2.17
TABLE 2.3.Typical Test Data from the Shell-Koppers Process
Using Subbituminous Coal
Coal Feed Analysis
Carbon
Hydrogen
Oxygen
Sulfur
Nitrogen
Ash
Coal
Process Inputs
percent by weight,as fired
percent by weight,as fired
percent by weight,as fired
percent by weight,as fired
percent by weight,as fired
percent by weight,as received
lower heating value,Btu/lb,as received
75.6
6.0
16.8
0.9
0.7
35.0
7,380
Gasification Efficiency (percent)
Thermal Efficiency (percent)
Wet Synthesis Gas Composition (percent by volume)
Process Input
Coal
Coal
Oxygen
Process Steam
Units
As Received
As Fired
99 percent by volume
t/MMft 3
Product
Gas
25.28
15.26
12.33
0.37
83
97.5
Water
Hydrogen
Carbon Monoxide
Carbon Dioxide
Methane
Hydrogen Sulfidel
Carbonyl Sulfide
Nitrogen
Argon
Source:Vogt and Van der Burgt (1980).
2.18
2.6
32.5
62.8
1.3
0.3
0.3
0.2
from the unloading hoppers to form the live storage pile.The traveling belt
tripper will have a capacity of 500 tons/hour.It will be mounted on flanged
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 will be 1400 feet.
The live storage pile should be covered with a corrugated,galvanized-
sheet steel IIA II frame roof.This structure will also support the overhead
conveyor tripper enclosed in a penthouse at the apex of the roof.The cover
will be 1400 feet long and 60 feet wide.The bottom edge of the roof will be
35 feet above grade and its apex will be 60 feet 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 ft2 .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
coal from the stack and discharge it onto 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 130 tons/hour.Dual capacity is provided to
ensure that plant requirements can be met in the event anyone conveyer is
down.Provision is also made for metal detection,magnetic separation,
automatic sampling,and weighing of coal.
Detailed engineering
may either be insidewi11
the
Sampling--A coal sampling system will be provided.
establish the exact location of the system,which
plant or in a separate sample house in the yard.
Plant Storage--In-plant silo storage capacity will be 10 hours.The
silos are situated above the pulverizers (mills)for gravity feed and will be
provided with a fire protection system.Each silo will be designed for mass
flow with stainless steel liners.They will be 24 feet in diameter and
approximately 40 feet high.Each silo is sized for a capacity of 240 tons.
2.19
Pulverizers--The mills are located at the lowest elevation of the plant
and serve to pulverize and dry the coal in preparation for feed to the
gasifier.The mills are extremely large,heavy-duty,slow-speed,high-energy
consuming machines.There will be a total of three mills,one under each
silo.Hot air or combustion gases will be used to remove moisture from the
coal.Each mill will have a capacity of 45 tons/hour and will pulverize the
coal to 70 mesh sieve.The coal product is weighed and transported to the
gasifier by bucket elevator.
Air Separation Plant (Figure 2.3,Unit 20).The air separation plant
design is conventional,based on compression,air purification,and cryogenic
separation of air into oxygen and nitrogen.A small amount of the nitrogen is
used as inert gas for coal conveying and for tank blanketing;the remainder is
vented.Air separation plant technology is available from several vendors as
standard plant units.
The air separation unit will consist of two parallel plants,each
designed for about 50 percent of the total oxygen demand of the gasifier
plant,or about 1000 tons/day.Electric motor drives will be provided for the
air compressors and oxygen compressors.
Coal Gasification and Gas Cooling (Figure 2.3,Units 3,4,5 and 6).The
coal gasifier plant consists of a coal feed system,the coal gasifier
(reactor),a fines separation system,and a heat recovery system.The design
of the Shell coal gasification system is based on a modular concept,with two
parallel gasifiers each sized for about 45 tons of coal per hour,or about
21 billion Btu/day.Use of two gasifiers provides several advantages:
•The building blocks form a pre-engineered,standardized plant that
may be fully designed with all components identified and ready for
procurement,thus reducing cost as well as the lead time required
from commitment to installation .
•Reliability and capability for turndown of the overall plant are
enhanced,since the individual gasifier units may be operated in
various modes,and the shutdown of anyone gasifier does not
interrupt the operation of the complete system.
2.20
Each module train consists of coal and recycled fines lockhoppers,a
gasifier,ash lockhoppers and conveyors,a gas quench scrubber/waste heat
boiler,and a recycled gas cooler and compressor.The crushed,dried coal is
conveyed pneumatically from the lockhoppers and injected through horizontal
feed pipes using inert nitrogen gas as a transport medium.Oxygen is fed into
the coaxial feed pipe to produce an oxygen-coal jet within the gasifier.
Recycled gas is also fed at the exit of the gasifier to solidify the entrained
slag particles before they enter the gas cooler.Fines and ash that are
carried over from the reactor and gas cooler are collected in two cyclones in
series,and the gas is cooled in a heat exchanger using boiler feed water.
The fines and ash are recycled to the gasifier via the fines lockhopper.
The Shell Koppers design provides for gas heat recovery.The objective
of the heat recovery system is to cool the product gas and to use the sensible
heat recovered to generate electricity.Heat recovery starts with a waste
heat boiler operating on the hot coal gas stream immediately after the gases
leave the gasifier and have been quenched with recycle gas.The operating
temperature of the heat exchanger metal surfaces is maintained below 900°F by
the careful arrangement of heat sink streams.
The product gas passes through an ash and fines recovery cyclone,a
feedwater heater and a clean gas regenerative heater,followed by quench
cooling in a venturi quench scrubber feeding into a quench scrubbing column.
The cooled gas is then split into two streams.One stream,representing about
43 percent of the flow,or 75 percent of the total gas produced,is compressed
and recycled to the gasification process,while the remainder of the product
gas is fed to the sulfur removal section.The water from the bottom of the
gas scrubber contains ammonia,carbon dioxide,hydrogen sulfide,char fines,
and ash fines,and is sent to the ammonia recovery section.
Ammonia Recovery (Figure 2.3,Unit 14).The purpose of this process unit
is to recover the ammonia produced from the nitrogen entering the gasification
unit with the coal and oxygen,and to clean the water so it can be recycled
back to the venturi scrubber.
2.21
The water from the venturi scrubber,which generally exhibits high
ammonia concentrations,is decanted in a settling tank to remove most of the
ash fines and then filtered and pumped to an ammonia removal column.The
underflow solids from the settling tank are removed via a slurry pump,
dewatered and disposed of with the slag.
The ammonia removal column concentrates the ammonia in an aqueous
solution that is suitable for distribution as fertilizer.This aqueous
ammonia is further processed using the Phosam-W-Process (licensed by U.S.
Steel Corp.)for conversion to anhydrous ammonia with the water recycled to
the venturi scrubbing system.
The quantity of ammonia produced as byproduct from the gasification
depends largely upon the nitrogen content of the coal and the temperature of
gasification.For this process,the ammonia produced should be between
approximately 65 to 75 percent of the nitrogen in the coal (0.6 percent by
weight)or approximately 0.42 percent (by weight)of the coal.The final
selection of-the process design depends upon an assessment of the market for
the ammonia.
Gas Cleanup Section
The product gas preparation section consists of the following process
units:sulfur removal,sulfur recovery,and tail gas cleanup.Descriptions
of these units follow.
Sulfur Removal (Figure 2.3,Unit 7).This unit consists of a hydrolysis
subsystem for carbonyl sulfide (COS)conversion and an absorber section for
hydrogen sulfide (H 2S)removal.The hydrolysis subsystem is designed to
convert COS to H2S by hydrolysis and reduce the sulfur in the gasifier
product to 10 ppm,which is suitable for methanol synthesis.The system
consists of a gas preheater,a catalytic converter containing a hydrolysis
catalyst (Topsoe CKA or equivalent)that converts the COS present in the gas
to H2S,and a gas cooler.Provisions are made to adjust the steam-to-gas
ratio in the process gas because the conversion of COS to H2S over the
catalyst is favored by low temperature and a high steam-to-gas ratio.
2.22
From the hydrolysis unit the gas passes to a Selexol Scrubbing System (a
proprietary Allied Chemical process designed to selectively remove sulfur from
the gasifier product).In the absorber the gas is counter-currently contacted
by a stream of lean Selexol solvent,which is a physical solvent consisting of
the dimethylether of polyethylene glycol.
Selexol can absorb approximately 9 times as much H2S as carbon dioxide
(C0 2 )under similar conditions of temperature,pressure,and solvent loading.
This property makes it possible to remove H2S to low levels,while retaining
CO 2 in the gas (The CO 2 provides some advantages when medium-Btu gas is to
be used as fuel for combustion turbines).
The absorber-bottom liquid is flashed in a flash drum to recover absorbed
hydrogen (H 2 )and carbon monoxide (CO).The flashed gas is recycled by a
recycle compressor to the absorber feed.Solvent from the flash tank is
heated by exchange with solvent in the solution exchanger and passes to the
stripper,where the acid gas is stripped from the solvent by steam.The acid
gases in the stripper overhead are cooled in the stripper condenser and water
is separated in the reflux drum,from which it is pumped back to the stripper.
The acid gases flow to the sulfur recovery unit for further processing.
A steam-heated reboiler is provided to generate stripping steam.From
the bottom of the stripper,lean regenerated solvent is pumped through the
leanrich solution exchanger and then cooled by refrigerant in the solution
cooler before returning to the absorber to complete the cycle.
Sulfur Recovery (Figure 2.3,Units 15 and 16).The sulfur recovery unit
consists of two sections to insure that the sulfur recovery system is aaequate
to meet the potential range of sulfur in the coal.The first section consists
of a train of modified Claus-type units that convert most of the H2S pro-
duced to elemental sulfur.The tail gas from the Claus units is further
processed in a sulfur recovery unit (such as a Beavon unit or equivalent).
For coals with a sulfur content of less than 0.5 percent,such as Beluga coal,
it may be possible to eliminate the Claus section and use a modified Beavon-
Stretford sulfur removal system.
The conversion of H2S to sulfur (5)in a Claus unit is based on the
reaction between H25 and sulfur dioxide (502)'in which H25 reacts with
502 to form 5 and water (H 20)according to the following reaction:
2H 5 +50 --7 35 +2H °222
Part of the H25 is usually burned with air to provide the S02 required;
however,in this plant this does not provide sufficient 502 needed for the
above reaction due to the low sulfur content of Beluga coal.50me sulfur is
therefore burned to produce S02'and this is recycled to the process.Com-
bustion air to the sulfur combustion unit is supplied by an air blower,and
the combustion gas containing 502 is cooled by generating medium-pressure
steam.The gas then passes to the first sulfur condenser,where it is cooled
by generating additional low-pressure steam.The 50 2-rich gas is combined
with the H2$-rich acid gas at this point and is then reheated in the first
reheater before entering the first catalytic reactor,where H25 and 502
react over a catalyst to form free sulfur.
Most of the sulfur is produced in the first catalytic reactor from which
the gas flows to a sulfur condenser where the sulfur is condensed and drained
to a sulfur product tank.To obtain the desired degree of conversion,this
process is repeated in the second and third reactor stages,which have similar
reheaters,catalyst converters and condensers (third stage not shown in
Figure 2.3).The tail gas from the final condenser goes to the tail gas
sulfur recovery unit.All sulfur that is produced drains into the sulfur
product tank from where it is distributed to disposal by a steam-traced
pipeline.The sulfur used to produce 502 is recycled to the same pit.
The tail gas cleanup unit provides for the final cleanup of the vent
gases from the sulfur recovery process,which contain some sulfur as 502,5,
and H2S.The selected process is the Beavon-5tretford sulfur removal pro-
cess that consists of two sections:a hydrogenation section to convert sulfur
compounds including free sulfur to H25,and a 5tretford section to oxidize
the H25 in an aqueous solution to elemental sulfur.The elemental sulfur is
floated from the solution and then melted and sent to the Claus unit sulfur
product tank.
2.24
The hydrogenation section consists of a feed preheater,a hydrogenation
reactor and reactor effluent cooler that generates steam.The tail gas is
mixed with a reducing gas produced by the partial combustion of process waste
fuel gas,and the mixture flows to the hydrogenation reactor,where the
hydrogenation and hydrolysis reactions take place converting all COS,carbon
disulfide (CS 2),S02'and S into H2S.
The hydrogenated tail gas is cooled in the reactor effluent cooler by
generating low-pressure steam,and then flows to the Stretford oxidation
unit.This unit consists of a venturi scrubber,absorber,oxidizer tank,and
sulfur separation and melting equipment.
The cooled tail gas is first contacted with oxidized Stretford solution
in the venturi scrubber,where most of the H2S is absorbed.The gas and
solution from the venturi gas scrubber discharge into the bottom section of
the absorber and the gas passes counter current with fresh oxidized Stretford
solution to the top of the absorber,where the cleaned and treated tail gas is
vented to the atmosphere.A combustor is provided in the vent line from the
absorber to burn any untreated H2S and other combustibles in case of a
shutdown of the Stretford section.
The bottom of the absorber is sized to allow sufficient residence time
for the sulfide oxidation reaction to go to completion according to the
following overall reaction:
HS +1/2 a --~S +H a222
The solution from the absorber flows to the oxidizer tank where the
solution is aerated.Sulfur slurry overflows from this tank into the sulfur
slurry tank and the oxidized solution flows to the balance tank,from where it
recycles back to the venturi gas scrubber and absorber.A cooling tower and
circulating water pump are provided with the balance tank to maintain heat and
water balances of the unit.
The sulfur slurry that flows to the slurry tank is agitated gently to
become deaerated and is then pumped to the sulfur melter.The hot dilute
2.25
solution and molten sulfur flow to the sulfur decanter where the sulfur and
solution separate.The sulfur is withdrawn from the bottom of the decanter
and flows to the Claus unit sulfur pit.The hot solution is released from the
top of the decanter,and returns to the balance tank after being quenched with
a stream of cool recycle solution.
Ancillary Systems and Utilities
The principal ancillary systems supporting the operation of the process
units discussed in previous sections are:1)the inert gas system,and
2)flare headers,flares,and safety equipment.
Inert Gas System.The inert gas system includes provisions for coal
conveying,tank safety blanketing,process purging operations,and safety
uses.The nitrogen obtained from the air separation plant section is used as
the source of inert gas.A storage volume is provided for surges and startup
of the plant.
Flare Headers,Flares,and Safety Equipment.This unit includes the
distributed system of process unit relief valve flare headers,process vent
headers,the flare stacks and their ignition systems,and any liquid knock-out
vessels and pumps associated with it.As part of this unit are the safety
equipment and systems for firefighting,including firefighting tanks and
pumps,monitors and interconnecting pipelines.The underground process and
storm water drain system is part of this unit.
2.1.2 Combined-Cycle Plant
The combined-cycle plant consists of two gas turbine generators rated at
approximately 74.5 MW each in combination with a steam turbine rated approxi-
mately 100 MW (Figure 2.4).The three turbines,together with the two heat
recovery steam generators (one steam generator for each gas turbine)and other
required auxiliary equipment,are housed in a common building approximately
185 feet wide x 300 feet long and 90 feet high.The building will be of steel
construction with aluminum-sandwiched insulation siding,and will be served by
an overhead crane.
2.26
Combustion Turbines
Each combustion turbine is a large-frame industrial-type with an axial
flow multi-staged compressor and power turbine on a common shaft.The
combustion turbine is directly coupled to an electric generator,and can be
started,synchronized,and loaded in about one-half-hour under normal
conditions.
Each combustion turbine/generator package also includes an inlet air
filtration system,fuel system,water injection system,lube oil cooling,and
various minor subsystems as required and furnished by the manufacturer.
Combusion turbine/generator design parameters are presented in Table 2.4.
The inlet air filter is a high-efficiency fixed-media-type suitable for
removing particulates from the inlet air.The use of an evaporative cooler
has not been anticipated because of the low air temperatures in Alaska,but a
cooler could be added later if further study justifies the expenditure.
The fuel system includes the fuel-oil forwarding skid and the fuel-gas
metering equipment.The combustion turbine is furnished with one liquid and
one gas fuel nozzle in each of the 10 annular combustors.One nozzle will be
sized for the medium-Btu coal gas and the other nozzle will be sized for
distillate oil.Liquid fuel is pumped from the fuel forwarding skid to the
combustion turbine,where a high-pressure pump forwards the fuel to the fuel
nozzles.Gaseous fuel must be furnished to the combustion turbine at about
250 psig.
The water injection system is used to limit the emissions of oxides of
nitrogen (NO).Water is pumped from the demineralized water storage tankx
and injected ~irectly into the combustors.This limits the peak flame
temperature,which in turn limits the formation of thermal NO.Thex
injection rate is a function of load,ambient temperature,and the type of
fuel.Typical water injection rates at base load are about 50 gpm per
engine.Demineralized water is required to limit formation of deposits on the
turbine blades.
Other miscellaneous systems furnished with the combustion turbine
include:the starting package complete with electric motor and torque
2.27
2.28
Number:Two required
TABLE 2.4.Combustion Turbine with Generator Design Parameters
(Based on General Electric MS7001E or Equal)
74,450 kW at ISO Conditions
(59°F,Sea Level)
10,655 Btu/kWh
597 lb/sec
985°F
1985°F
5 in.water
10 in.water
29 ft wide by 70 ft long
by 13 ft high
Base Rati ng
Accessory compartment complete with starting motor,motor control center for
all base-mounted motors,lubrication system,hydraulic control system,atomiz-
i ng air system,and coo Ti ng water system.
Excitation compartment complete with static excitation equipment.
Turbine Type:Simple-cycle,single-shaft,three-bearing.
Generator Type:Hydrogen-cooled unit rated 110 MVA at 13.8 kV,0.9 pf with
30 psig hydrogen pressure at 10°C.
Performance:(Each Turbine)
Heat Rate (LHV)
Air Flow
Turbine Exhaust Temperature
Turbine Inlet Temperature
Inlet Pressure Drop
Exhaust Pressure Drop
Dimensions (turbine
generator only)
Combustion Turbine Features:
Fuel system capable of utilizing medium-Btu gas or liquid fuel.
Fire protection system (low-pressure C02).
NO x control system utilizing water injection.
Switchgear compartment complete with generator breaker,potential trans-
formers,disconnect link for auxiliary feeder,and a customer power takeoff.
converter;a lube oil system for bearing lubrication;a cooling water system
for cooling the lube oil system;a CO 2 system for fire protection and
generator purge;and a controls system for controlling the entire gas turbine
generator package.
The combustion turbines are normally operated from a central control
room,but controls provided with the unit allow either local or remote
unattended operation.Operation of the combustion turbines is essentially an
automated process,but operator presence is required to achieve proper
coordination with boiler control functions.Under normal conditions,all
combustion turbines are in operation at their baseload rating.
Heat Recovery Steam Generators (HRSGs)
The high-pressure steam for the steam turbine generator will be generated
in the two HRSGs and the coal gas cooler.The coal gas cooler will serv~as
part of the evaporator section for both steam generators,utilizing part of
the economizer outlet flows as feed and generating saturated steam in a
separate steam drum.The saturated steam from the separate drum is fed back
to the gas cooler producing superheated steam that is then mixed with the
steam from each HRSG producing high-pressure main steam for the steam turbine
generator (Figure 2.4).All low-and intermediate-pressure sections are
similarly independent.
The HRSGs are physically housed together with the gas turbines,on a
one-for-one basis.The HRSG package includes the steam generator complete
with ductwork from the combustion turbine to the steam generator,a bypass
damper and bypass stack,and a steam generator exhaust stack.During startup
and other load conditions,the bypass damper may be operated to provide the
required flexibility.By closing the bypass damper,the combustion turbine
exhaust is routed to the stack and does not reach the steam generator.
The HRSGs are the dual pressure design type with a nominal main steam
outlet pressure of 1200 psig at 900°F,intermediate-pressure saturated steam
at 150 psig and low-pressure 50 psig saturated steam.Specific design loads
for each section of the HRSG are defined in Table 2.5.The HRSGs are designed
for continuous operation.
2.29
Steam Turbine Generator
TABLE 2.5.Heat Recovery Steam Generator Design Parameters
All steam generator controls will be located in a common area in the
central control room.
2.30
be located on a pedestal at one end of the
In addition to the combustion generators,
and condenser,the building will also contain
Two required
Watertube,forced-circulation (General Electric)or two-drum
natural-circulation (Deltak or Henry Vogt),dual-pressure.
Steam Generation in the HRSGs is integrated with steam genera-
tion from other sources.The HRSGs will be designed with
independent sections as listed below.
Outlet Inlet Outlet
Flow Pressure Temperature Temperature
Section (lb/hr)(psig)(0 F)_(OF)
LP Economizer 393,660 108 110 200
LP Evaporator 19,560 50 250 Sat.Steam
IP Evaporator 72,220 150 250 Sat.Steam
HP Economizer 387,890 1250 310 550
HP Evaporator 161,800 1200 550 Sat.Steam
HP Superheater 397,890 1175 569 952
Number:
~:
Performance:
The turbine generator will
combined-cycle plant building.
steam generators,steam turbine
The main steam from the HRSGs is conveyed to a common turbine generator
set rated a nominal 100,000 kW.The turbine generator will be a direct-
connected multivalve,multi-stage condensing unit,mounted on a pedestal with
a bottom exhaust for mounting the condenser under the turbine.Design
parameters for the turbine generator are shown in Table 2.6.The turbine
generator set will be furnished complete with lube oil and electrohydraulic
control systems as well as the gland seal system and the generator cooling and
sealing equipment.
Number:
TABLE 2.6.Steam Turbine Generator Unit Design Parameters
One required
Turbine Type:
Generator Type:
Multistage,straight-condensing,bottom exhaust
Hydrogen-cooled unit rated 100 MW at 18 kV,0.9 pf with
30 psig hydrogen pressure at 10°C
Performance:Base Rating
Steam Inlet Pressure
Steam Inlet Temperature
Exhaust Pressure
Exhaust Temperature
Speed
100 MW
1175 psig
952°F
2 to 4"hg
92°F
3600 rpm
Features:Common-base-mounted with direct-drive couplings.Accessories
include multiple inlet control valves,electric hydraulic
control system,lube oil system with all pumps and heat
exchangers for cooling-water hook-up,gland steam system and
generator cooling.Excitation compartment complete with
static excitation equipment.Switchgear compartment complete
with generator breaker potential transformers.
the feedwater pumps,condensate pumps,vacuum pumps,feedwater deaerator,
instrument and service air compressors,motor control centers,control room,
house boiler and diesel generator.The house boiler will be sized to provide
building heating and freeze protection to all exposed equipment.The diesel
generator will be sized for black startup service.
Condenser
The condenser design will be single-shell,two-pass,with a divided water
box and hotwell.The hotwell will be designed to have sufficient storage to
allow proper level control for surging and shall be properly baffled to keep
the condensate at saturation temperature.
Tube sheets will be Muntz metal,with inhibited Admiralty tubes,except
for 70-30 copper nickel tubes in air removal sections and impingement areas.
The condenser design data are listed in Table 2.7.
2.31
TABLE 2.7.Condenser Design Parameters
Number:One required
Condenser Type:Single-Shell -2-pass
Perf onnance:
Features:
Heat Load
Saturation Temperature
Inlet Water Temperature
Outlet Water Temperature
Terminal Temperature Differential
Cooling Water Flow
Single-shell,2-pass -111
-18 gage
Admiralty Tubes
Divided water box and hotwell
764 x 10 6 Btu/hr
92°(1.5 11 Hg)
nOF
87°F
5°F
102,000 gpm
Cooling Tower
The cooling tower shall be the wet-dry type mechanical draft design of
material most suitable for the cold weather conditions found in the Beluga
area (see Table 2.8).
Three 50-percent-capacity vertical pit-type circulating water pumps will
be mounted in an enclosure at the cooling tower basin.The pumps will be
mounted 4 feet above the water level and have self lubricating,cutless rubber
design shaft bearings (see Table 2.9).
Other Major Equipment
Design parameters for other required equipment are shown in Tables 2.10
and 2.11.
2.1.3 Electric Plant
Two types of prime movers are utilized for electrical generation (see
Figure 2.5),including two gas-fired combustion turbines with generators rated
74.5 MW each and one steam turbine generation unit rated at 100 MW.Each gas
turbine will deliver approximately 80 MVA to the switchyard.The steam
2.32
TABLE 2.8.Wet-Dry Cooling Tower Design Parameters
Number:One required
Type:Parallel Path Wet-Dry
Performance:Heat Load 836 x 10 6 Btu/hr
Cooling Water Flow 112,000 gpm
Inlet Water Temperature 87°F
Outlet Water Temperature 72°F
Design Basis -15°F approach to 10 percent of the time wet bulb
temperature of 57 of at Anchorage.Design coldest
dry bulb (97.5 percent of time)is 20°F at
Anchorage.
Features:One fan required for each cell.Integral air-cooled heat
exchanger sections for IId ry ll cold weather use.
turbine will add 90 MVA,resulting in a total of 250 MVA delivered to the
switchyard.The coal gasifier plant will use approximately 30 MVA of this
total,resulting in 220 MVA for export.
Combustion Turbine Generators
These are II pac kaged ll units
support the turbine generator.
0.9 pf,83 MVA,with generation
and as such include all equipment required to
The generators are nominally rated at 74.5 MW,
voltage at 13.8 kV.
The package generally includes:
(a)13.8-kV switchgear that houses the generator grounding transformer
and generator air-circuit breaker.
(b)Non-segregated phase bus duct runs to the generator and main
transformer.
(c)A master control panel for overall operation and monitoring.
(d)A unit auxiliary transformer,13.8/4.16 kV,sized to support the
ancillary load (assumed to be 2 MVA).
(e)A 4.16-kV switchgear with air-circuit breakers for other loads
(e.g.,800-hp cranking motor).The largest load is fed from the
plant common 4.16-kV switchgear.
The step-up transformers for each gas turbine are rated 80 MVA,13.8/138 kV.
2.33
Performance:(each pump)Capacity 1740 gpm (100 percent plant
capacity)
TOH 3168 ft at 250'F
NPSH 20 to 24 ft
Motor 2000 hp
IP Feed Pumps
Number:Two required
~:Horizontal,single-stage centrifugal,frame-
mounted,complete with motor drive.
Performance:(each pump)Capacity 20 gpm (100 percent plant
capacity
TOH 870 ft
Water Temp.250'F
Inlet Press 200 psig
LP Feed Pumps
Number:Two requi red
~:Horizontal,multistage centrifugal,double-
suction frame-mounted,complete with motor
drive
Performance:(each pump)Capacity
Performance:(each pump)Capacity
270 gpm (100 percent plant
capacity)
480 ft
250'F
10 to 12 ft
825 gpm (50 percent plant
capacity)
150 ft
120'F
Vacuum
1600 gpm (100 percent plant
capacity)
150 ft
HO'F
Two requ ired
Horizontal split-case,multistage,double-
suction,frame-mounted,complete with electric
motor drive and lube oil system.
TOH
Water Temp.
NPSH
Vertical-shaft single-stage centrifugal,
complete with vertical mounted motor.
Three required
TOH
Water Temp.
NPSH
Two required
Three required
Vert cal shaft pit pumps with submerged
suct on,discharge column complete with
vert cal-mounted electric motor.
Horizontal,single-stage centrifugal-mounted,
complete with motor drive
Capacity 66,000 gpm (50 percent plant
capacity)
TOH 45 ft
Water Temp.40 to 80'F
Submerged Suction
2.34
Pump Design Parameters
(each pump)
Number:
TABLE 2.9.
~:
Number:
Number:
~:
TOH
Water Temp.
Performance:
Performance:(each pump)Capac i ty
~:
~:
Feed Pumps
Oeaerator Feed Pumps
Condensate Pumps
Number:
Cooling Water Circulating
Pumps
TABLE 2.10.Fuel Oil and Condensate Tank Design Parameters
Condensate Tank
Number:
Size:
Service:
Features:
Deaerator and Storage Tank
Number:
One required
Fixed roof -carbon steel
150,000 gals (approx.5-day supply)
Condensate storage
Steam heating coils,suitable insulation,
plastic-lined
One required
Si ze:
Water Flow Out:
Steam Flow In:
Design Pressure:
Operating Pressure:
Fuel Oil Tanks
Number:
Size:
Service:
Features:
Integral connected unit with deaerator mounted on
top of 5 min-storage tank.Stainless steel troughs
and baffle plates.
39,370-lb storage
472,400 lbjhr
50 psig
60 psig
25 psia
Two required
Floating roof
89,580 BBL
5 -96"courses,120 ft diameter x 40 ft high.
Distillate oil,specific gravity of 0.82 -0.86
Stairway,platform,floating roof seal,fixed roof
supports
2.35
~:
Number:
TABLE 2.11.Miscellaneous Equipment Design Parameters
Air Compressors
Number:Two required
~:Reciprocating,single-cylinder,oil free,water-cooled,
frame-mounted with motor.
Performance:50 actual cubic feet per minute (ACFM)each 115 psig
discharge pressure
Diesel Generator
One required
Air-start,skid-mounted,mUltlcylinder diesel,complete
with 1-1/2-MW generator,0.8 pf
Heating Steam Boiler
Number:One required
~:Fire-tube forced-draft Scotch Marine-type.
Performance:40,000 lb/hr
50 psig saturated
Steam Turbine Generator
The generator is rated 100 MW,0.9 pf,110 MVA,with generation voltage
at 18 kV.The unit auxiliary transformer is three-winding 20 MVA,18-4.16/
4.16 kV.The two secondary windings supply 4.16-kV busses 3A and 3B.The
step-up transformer is rated 90 MVA 18/138 kV.
Station Service Transf'ormer
This transformer is used to supply power for the steam turbine generator
auxiliaries required for startup and to provide power for the coal handling
areas,oxygen,and gasifier plants.It is a three-winding,30-MVA,138-4.16/
4.16-kV transformer.The two secondary windings feed 4.16-kV common switchgear
2.36
I:!lBK.~TO W5T.
BtLUGA PLAIJT
1\1\d 1\"'",,,.""
\fBUS \
~•TIE. ...r1--'---Q--/--.34~KV
•~~~~~~AfU2~J~~A~F 10 WillOW
~~~1?>e./:H5 K.'I
•IlAIIJ BUS ...
I~~KV
51'11 TCHYARD
MT~
90MVA
13BIIBK.V
J...
<J
-
l 1.,,,,,:,
)1200 ...TYP.
eH B o.B GA51FIER B
))
I)~
CM IJ?2
,)
4.16KV SWGR
).
~
CM IJ~I
MT I ).....1....J MT 2 ).uJ2IKV STAlIOIJ SER'itCl
80MVA <J OOMVA <J )OMVA
,...-<J_II:la/I311kl 1138113.81<.V I':'M~<J"'T£MVA
I)UATI I U~I<.)
30CJ0A 2MVA u.Lu 2MVA •:lOOOA I I I <J\..v ..1'~.K~"UAT 3
<J 20 MV
8:l>MVA I I GJ 83 MVA I I r-<..)IIOMVA IOM~"T'2MVA
GAS IURBIUE GA:;TURBIIJE )ZOOOA )2000 A '-...>'STEAM lURBltJE '''I.)1.)'-r I 1200A 1200"'
4.16kV IA 4.16KV IB 4.16KV CA r-t 1 4.16KV CB 4.16KV 13A !4.IE.KV3B1'\\\.!.!.1
N.
W
'"
FIGURE 2.5.One-Line Diagram
buses A and B.The 4.16-kV Busses CA and CB supply dual switchgear trains A
and B for the following:
4.16-kV coal handling switchgear A and B
4.16-kV oxygen plant switchgear A and B
4.16-kV gasifier switchgear A and B
In addition,ties to the steam turbine 4.16-kV switchgear 3A and 3B (Steam
Turbine Startup Supply)are fed from this bus.
Switchyard
The switchyard is basically 138 kV consisting of seven bays,as shown in
Figure 2.6.One parameter for selecting this voltage was the inclusion of a
tie line to the existing Beluga Station,which at present has a 138-kV tie
line to Anchorage.
The switchyard is a two-bus arrangement,with a main and a transfer bus.
Each bay has a 138-kV circuit-breaker,three disconnect switches and a 138-kV
tower.The bus tie bay has a 138-kV circuit-breaker and two disconnect
switches.The transmission voltage is 345 kV for export of approximately
220 MVA.An autotransformer,345-kV circuit-breaker and two disconnect
switches comprise this portion.
2.1.4 Water and Wastewater Treatment Systems
Various water and wastewater treatment facilities will be incorporated
into the plant design to produce appropriate unit makeup water and permit the
reuse of process water.The facilities that will be required for this station
are briefly described below.The anticipated water balance diagram is pre-
sented in Figure 2.7.
Makeup Water Treatment System
The makeup water treatment system is a multicomponent system comprised of
pretreatment and demineralization sections.It is designed to provide demin-
eralized water for steam-cycle makeup,including boiler blowdown,reaction
hydrolysis water and injection for NO control.It also supplies the systemx
reservoir for potable,and heating,ventilating and air-conditioning
2.38
330
x
~OW
x
x~.I A
=P-V'
2:3 2:0 15 15 13 13 ZO Z3 40 30 ZI ZI ZI S4 1
~~-----x x x 1 fT1 x---XI---X x X x.1
III 1.!2~I r!!.10
I\l I
x J X
\ll _.~
III ...d2"h i'-..I n::n r,.q ./"x ~I \ (~l<>:lf+--I--C:::::>---{lX'q.---<=_......,....Rl:1--+--'~~'Y1
;;7 '\~:l1 x.~I e
\#~~8::.JJ '-/8
"'l X X~~;.<I FEN
I ~--~X
t
A ~!....\ll MAIN r=l.------'::~i;g 'J 345 XV AUTO TRAN:$F'
1\11 "1 TRA N !I F l-----""r-.X
~/~X ~
:L-----v ~X ~I
\ll MAIN rJ--l-----""~~/8~TRAN:$F"J__l-----""H-+-m:::;t::::>!~-=o---<~4---==>---+f-X X X )(X--
No.2 ~
~~
::sTATION r::-----.:c::>-:\ll ~ERV.----~r:s:
~X F"R J----""X
I z.:..-X ~r
TIE LINE ~--;:Y"X ~r
TO f:--------k:0 '-.Ji\II EXI:5TING 1-----18
I If)BELUG,A "'
I J~:T f:::~~t ~7LY~~~:5FT----X /38 Js~;1~YD ~7 -
w
~
N.
Itl
U)
~
w-J--~--l-~~.._jl~.J ...?-~.~J-_....'1:Q_-~..~~kL~L-l~1--1--._..~'I:
.:5ECTION A-A
FIGURE 2.6.Beluga Station Switchyard
SYS
100
N.
.j:::.o
-----~..-3·-~32 OoRY T(JI'/Elf (JPf:IfAT10It!
I
154 1 22 (ALf SEI'AKATIOH I
EVAPORATION I PLANT
PI?ETREATMEIff.l 958 ...\~__-<,.
GASIF/ER-VEHTI/KI )~'IlIFT
fFIRE f/(oUalO 0 5CRU8BEK 0.1
SYSTEM IS
r l!::-
TEM LOSS DEMINEKALlZEIl "I----r~..l COOl./N6 TOWER ~\,.,./0 I .137
I TlJoR81f/E I 100 I /5 I r POTA8LE /AlATER IIFLOOR DRAINS II 11 i
If/JECTIOf/5 t'AND WAC 5UPPLY IAHO SUMPS I:..-....L:L.........,
SYSTEM lOSS --SYSTEM LOSS I IAUJ:COOLlH6 1 !cONOENSE.t',.----'i...8 ....3 I L-__--'
l 22
VARIOUS f°t/OENSATE I------5ULFUoR LY..!__SLAG I
STEAM STORA6E I+-RECOVERY QUENCHING
AND 21 SYSTEMS 11
CONDENSER I l----fi;iiii:-;;:D;w(l_.\01 "HEAT IlEt:OVERYf~IlEQIJII?£IfEJ(1,
-1---+lSTEII/lf 6lHIltATrJIt I AMMONIA I EQUALIZATION (I ISAHITAKY NAS'fE-l I OIL/NATER I rDEWATEIlIH6 1
Ii,RECOVEKY NEUTRIILlZATION I iWEK T.fWNENT I ISEPARATOR
'------'12
18 22 TfJ
5 SLAG
"10 DISPOSAL
SOUR WATER 10
TREATMENT
40 ~7
ICOAL PILE YA.t'O ORAINAb!
LEACNATE SYSrEM r--i'l
2)FlO/AlS AilE OAIL Y AVERAGES AT
DISCHAlif#TO IOO"/.CAPACITY FACTO!f.
I?EClIVI1'/6 WATE.t'
BoDY
222 WET TONER OPE.t'AT/Of{
8.5 DRY TOWEll OPEIUT/Of{
FIGURE 2.7.Water Balance Diagram
requirements.Pretreatment will remove suspended particulate material and
residual organics and will consist of gravity filtration and activated carbon
filtration.Following pretreatment,,steam-cycle makeup and turbine-injection
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 (one as standby)each producing 75 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
wastewater collection sump.Waste biological solids produced by the plant
will undergo aerobic digestion.The system will be sized for a flow of
approximately 6000 gallons per day and the aeration tank will provide a
retention period of 24 hours.
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 receiving body.
Equalization/Neutralization Facility
Wastewater from demineralizer regeneration will be produced and conveyed
on an intermittent basis to the equalization/neutralization tank having a
corrosion-resistant lining.The tank 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
2.41
9.0.The tank will have a minimum 36-hour detention period for the wastewater
flows generated on the maximum regeneration activity day.This capacity,
together with the pH control system,will provide adequate neutralization to
enable discharge to the receiving water body.
Coal Pile Runoff Pond Facility
Runoff and filtrate from the coal storage pile will be directed to col-
lection ditches located on the periphery of the pile and then conveyed to the
coal pile runoff pond that will be capable of retaining the one-in-ten-year,
24-hour rainfall event and,therefore,only storms in excess of this event
will be discharged.The holding pond will provide gravity setting for coal
fines (suspended matter)washed out of the pile;this water will then be used
for dust-suppression purposes.Pond effluent in excess of the desi~n storm
event will undergo pH adjustment,as necessary,to a range of 6.0 to 9.0,by
the addition of caustic reagents and will be discharged to the yard and area
drainage system.
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
activities.Therefore,this discharge will be directly discharged to the
receiving water body.
Gasifier Water Supply
The gasification section will require water for slag-quenching and
product-gas-scrubbing.During evacuation from the lockhopper,the slag will
be dewatered and the water recycled to the lower quench section of the
gasifier.Makeup water for this system will be supplied from the cooling
tower basin during "we t"tower operation and directly from the supply source
during "dry"tower operation.A portion of the recycle flow is blowndown to
maintain system water quality within desirable limits and to prevent scale
accumulation.
Makeup water for the product gas scrubbing system will be derived
directly from the supply source.Following gas scrubbing,the effluent from
2.42
this unit process will be discharged to the ammonia recovery unit where
anhydrous ammonia will be produced.Most of the water extracted during the
ammonia recovery process will be recycled to the venturi scrubber;a small
portion will be blowndown to maintain appropriate water quality levels.This
blowdown will be treated in the bio-oxidation system prior to ultimate
discharge.
Bic-oxidation Treatment System
This treatment system will consist of an equalization/neutralization
basin,a biological and physical/chemical treatment system and a wet-air
oxidation system.In general,waste streams from the sulfur recovery units
and ammonia recovery system will be treated in this manner prior to dis-
charge.It should be noted,however,that not all waste streams from these
process units are necessarily accounted for in the flow diagram or discharged
to this treatment unit.Due to the proprietary nature of many of these
resource recovery processes,some waste streams will be collected and treated,
also by proprietary means,as part of the overall process.For example,a
Texaco-developed proprietary process consisting of insoluble metal sulfide
precipitation and ammonia stripping is presently utilized to treat tailgas
treatment condensate.
The equalization basin for the bio-oxidation system will have the func-
tions of collecting,thoroughly mixing and neutralizing all waste streams
destined for biological treatment to provide a constant flow rate and to avoid
shock upsets of the system.The basin will be provided with mixer-aerators to
insure a homogeneous feed to the biological system.Construction will be of
reinforced concrete,because of the nature of the waste streams involved.
The biological treatment unit is based on a conventional activated sludge
system to reduce biodegradable organics.However,powdered activated carbon
(PAC)will be added directly to the aeration basin for adsorption of nonbic-
degradable organics and ammonia as well as cyanides and thiocyanates.The
carbon will also help to buffer the system against upsets due to toxic shock
and provide surfaces on which the activated sludge biota may grow.Waste
sludge disposal and carbon regeneration will be accomplished simultaneously in
a wet-air oxidation system.
2.43
In the wet-air reactor,adsorbed organics will De oxidized and the
adsorptive capacity of the carbon will be restored.Regenerated carbon will
be recycled to the aeration tank while some makeup of powdered activated
carbon will be necessary due to regeneration losses.During regeneration,the
suspended ash associated with the carbon slurry will accumulate at the bottom
of the reactor and will be periodically blown down from the unit for disposal
to the solid waste disposal area.The effluent from this treatment system
will be gravity-filtered through sand,chlorinated and subsequently mixed with
the other plant waste streams prior to discharge.
2.1.5 Solid Waste Disposal Systems
The facility will produce two major solid byproducts that will require
ultimate disposal:ash (slag)and sulfur.A mass balance of these two
byproducts is provided in Figure 2.8.
Most of the ash in the coal feed agglomerates into essentially carbon-
free molten slag droplets that are quenched and solidified in the lower quench
section of the reactor.This slag settles through the quench water into the
lockhopper.The lockhopper contents are periodically dumped onto a screen
from which the slag is conveyed to an open hopper for temporary storage.
Water from the screen is collected in a sump and recycled.
From the hoppers located at the plant site,the slag will be trucked to a
permanent solid waste disposal site,assumed to be situated in close proximity
to the plant island.To permanently dispose of the slag generated over the
25-year life of the plant,a site encompassing 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.
Slag formed in the gasification unit will be a generally insoluble glassy
material with the consistency of pea gravel.It will contain some larger
material up to approximately 1 inch in size and some finer particles.Based
on a limited amount of available data,there is no indication that there would
be a problem of leaching inorganic salts into the ground or surface streams
from a slag disposal site;therefore,a disposal area liner is not specified.
2.44
"ULFUR PRODiJCT
.J1
Ql Jl
~«
cD <!J
.J W
~:3
u..
5:'JO_b/HR
COAL HAND'_'N<2 SULF'JR .
SASIFIER 50oLBIt<R SULFUR 33 '1l.B/~l<COMS TuRBINES
-;TRANSFER Z3J=OL8;HR SULFUR REMOVAL SULFUR
ASH
I ~III
:I:'$23.750 LB/HR ..--....
(J)
.J a
SL.640 ~.~
~
5ULf"L.JR VENT GAS
RE.COVERY 5 Ul/HR(S)o 02 I-B/Hl<(H2S)
/.OLB/HR (COS)
479 LB/HR ...
~,
FIGURE 2.8.Sulfur and Ash Balance
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 completed it will be covered with topsoil and reseeded to
minimize infiltration 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 slag material.
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 disposal area will be collected behind a small
berm located at the anticipated toe of the slag pile.This water will then be
used for dust suppression purposes.
The quantity of sulfur produced as a byproduct of coal gasification will
amount to approximately 45,000 tons over the life of the power plant.This is
a potentially valuable resource but its sale and reuse will depend on an
assessment of local market conditions at the time of project development.
Should a market not be found,the effluent from the sulfur recovery units will
be dried and trucked to an onsite disposal area.The disposal site will
2.45
encompass an area of approximately 2 acres,and will be lined with an imper-
meable material to prevent any leachate from entering the groundwater.The
site will also be developed in benches and revegetated to minimize runoff
infiltration,and will be surrounded by runoff diversion channels.
2.2 FUEL SUPPLY
The proposed station described in this report will use coal from the
currently undeveloped Beluga Field.The plant will 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 will 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 4:1.Production levels
of up to 11,700,000 TPY could be sustained for 30 years without significant
depletion of the reserves (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 and environ-
mental and licensing activities,it appears that Beluga coal could be avail-
able 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.
Run-of-mine quality of Chuitna lease coal is expected to be as
f 011 ows :(a)
(a)Note that a composite "Railbelt Standard"coal (Section 1.0)was used for
plant design.
2.46
Heating Value
Ash Content
Moisture
Hardgrove Grindability Index
Ash Softening Temperature
Ash Na 20
Sulfur
Nitrogen
2.3 TRANSMISSION SYSTEM
7500-8200 Btu/lb
7-8%
20-28
20-25%
2350°F
0.95%
0.16-0.18%
N.A.
Preliminary design calculations were made for a 75-mile,345-kV trans-
mission line to transmit the 220 MW generated by the coal-gasifier combined-
cycle plant from Beluga to Willow.The following assumptions were made for
this preliminary estimation:
•This line was considered independent of the existing network.
•The line goes from Beluga to Willow,where the proposed Anchorage-
Fairbanks intertie,which has sufficient capacity,will absorb the
total generated power.
•The existing system at Willow will be a 345-kV system as recommended
by Commonwealth Associates,Inc.(1981).
Three voltage levels were studied:138 kV,220 kV and 345 kV.A 138-kV
voltage is too low to transmit 220 MW a distance of 75 miles;the surge
impedance loading for this line would only be around 50 MW.
A 230-kV voltage line has a surge impedance loading of 135 MW.This type
of line with VAR compensation and adequate conductor size could adequately
transmit the 220 MW.
A 345-kV voltage line has a surge impedance loading of 300 MW.This type
of line with VAR compensation and adequate conductor size could also ade-
quately transmit the 220 MW.A double-circuit 230-kV transmission line may
also be an attractive alternative.Initial investment may be higher than the
345 kV alternative,because 230-345 kV transformation at Willow has to be
built and transmission towers for a double-circuit 230-kV transmission line
2.47
may be heavier than the 345-kV towers.However,I 2R losses may be lower.
The results obtained from the preliminary study are as follows:
Line Size of Losses
Vo ltage No.of Type of Conductor I2R Reactive
(kV)Circuits Conductor (MCM)Regulation MW ~ort
230 1 ACSR 636 11.9 percent 14.5 Capacitors
345 1 ACSR 795 3.5 percent 4.5 Reactors
230(a)2 ACSR 636 3.0 percent(a)3.8 None
(a)Estimated values.
From these preliminary calculations,a 345-kV ACSR,single-circuit,
795 MCM is recommended.However,additional studies will have to be done to
fully justify these parameters.
From an electrical point of view,interconnections with the transmission
system may substantially modify the results.This line should not be studied
independently because capital investment and losses of alternate line con-
figurations will have to be fully evaluated.A complete system study is
recommended.
The lowest initial investment will be the single-circuit 230-kV line;
however,the losses appear excessive.Differential losses of 10 MW between
the 345-kV and 230-kV alternate may result in a loss in revenue of ~4,000,000
per year,for a load factor of 80 percent and a cost of 66/kWh for energy.
A double-circuit 230-kV line may also be an attractive alternative.
Initial investment may be higher than the 345-kV alternative,and transfor-
mation from 230 kV to 345 kV at Willow will have to be added.The 345-kV
option will have the advantage of uniform voltages with the system recommended
by Commonwealth Associates,Inc.(1981)for an Anchorage-Fairbanks intertie.
The physical line arrangements will be as follows:To incorporate the
proposed Beluga station output,a 345-kV substation at or near Willow (or some
other convenient place)appears desirable and should have a configuration as
2.48
depicted in Figure 2.9.The 345-kV lines to Anchorage and Beluga and Nenana
would terminate here.This substation will provide flexibility and relia-
bility to the system load flow.Connecting the Chugach Beluga station into
the system at Willow avoids the underwater crossing at Knik Arm currently in
use from the Beluga combustion turbine installation to Anchorage.
2.4 SITE SERVICES
The construction and operation of a 220-MW coal-gasifier combined-cycle
power plant will require a number of related services to support all work
activities at the site.These site services include the following:
•access roads
•construction water supply
•construction transmission lines
•airstrip
•landing facility
•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 in the Beluga area.Good
bearing subgrade will be required to support the heavy gasiftcation reactor
vessels as they are moved to the site.Where possible,the existing road will
be used.Hence,no more than 5 miles of additional road construction is
anticipated.
2.4.2 Construction Water Supply
A complete water supply,storage and distribution system will be
installed.Due to the remote nature of any site developed,a one-million
gallon water storage tank has been assumed with one-half of this storage
capacity dedicated to fire protection purposes.Construction water supply to
the project site should be at least 150 gpm.
2.4.3 Construction Transmission Lines
Power requirements during the construction phase will be supplied by
constructing a 25-kV transmission line tapped from an existing transmission
2.49
09"2
U\
)(1-)(~
0 oz
~
~
~)C
~~
~x
~:\t
'")C ~~
'-a I...J'NJJ ~0 ~•c::0
Q)""x ~~It
I\)
~
ClO,c
C)
1'1,)
'"'""f\a
0
-1t
,Z g",041
S>lNlI9HI~:/f't.Z
system.A transmission line length of 20 miles is assumed and will be derived
from the existing Chugach Electric Association system at either the town of
Beluga or Tyonek.
2.4.4 Airstrip
For the general power plant location,the existing airstrip will be
used.It is anticipated that all personnel travel will be by air with
prearranged commercial charter carriers.All perishable goods will be flown
in.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 in the 18,000-to 30,000-pound category.
2.4.5 Landing Facility
The site will use the existing marine landing facility to receive all
construction materials,equipment and supplies.A paved and fenced interim
storage area will be provided.A heavy duty haulage road would De provided
from the landing area to the access road.
2.4.6 Construction Camp Facilities
A 1,000-bed labor camp will be provided.All personnel housed in this
camp will be on single status.Provisions will be made to accommodate a work
force containing females (separate bathroom and locker facilities).
The camp will have its own well water supply.A sewage treatment facil-
ity,waste incinerator and garbage compactor will also be provided.The
complex will also have a dining hall and recreation hall.
Since it is unlikely that all personnel would be willing to come to the
jobsite 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 1,000 ft2 each and could remain after completion of construction to
house vendor personnel for repair work during plant operation.
2.51
2.5 CONSTRUCTION
of a 220-MW station will
The distribution of
Figure 2.10.Construc-
a work force of approxi-
The number of workers necessary for construction
vary over the approximate 3-year construction period.
this work force over the schedule duration is shown in
tion is estimated to peak early in year two,requiring
mately 1,100 personnel.
Construction of this 220-MW station will follow normal acceptable con-
struction methods.A program of this magnitude begins with orderly devel-
opment of the following requirements:
1.Construction camp and utility services,such as electric light and
power,water for industrial and potable use and fire protection,
sanitary facilities,telephone communications,etc.
30z520IS/05o
1150
12D~
/I 50
liDO
ltJGO
/000
'li0
900
Mo
flOD
750
~700
~(,5"0
~'00
~5$0
~;00
450
400
350
~oo
250
MONTHS
/'lOT E:00 IS nof inc/udt!".."dar Pt!r.sonn~/,o""Ur p~r~onn,1,A-£t!'n!fl;,t!t!'rs,
or fr",,,sm/ss/o,,1/"..CDnsfrllc fio"I'lrson",1 /ocol-,o'ttl sd...
FIGURE 2.10.Construction Work Force Requirements
2.52
2.Temporary construction office facilities (with heating and ventilation
furnished by contractors as required).
3.Temporary and permanent access roads.
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
equipment,cranes,rigging equipment,welding equipment,trucks and
other vehicles,tools)and other related types of construction
equipment 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 strict compliance with OSHA
regulations.
Following completion of these site
systems construction will be initiated.
overall construction process as well as
schedule are presented in Figure 2.11.
2.6 OPERATION AND MAINTENANCE
preparation activities,power plant
The activities involved in the
the plant's detailed development
2.6.1 General Operating Procedures
The plant has been designed for operation as a base-loaded plant with
load following capability;however,it could be operated as a peaking unit
with the excess product gas from the gasifiers being converted to methanol
during off peak hours.(The methanol conversion plant has not been included
in this report,however.)Cold starts of the combined-cycle plant should be
expected to take a minimum of 9 hours.The first gas turbine is started and
synchronized with the bypass damper positioned to partially bypass the steam
generator.The second steam generator is started and synchronized in
2.53
ACTIVITY
•DESIGN CRITERIA
YEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5
JIFIMIAIMIJIJIAlslolNID JIFIMIAIMIJIJIA1SIOINID JIFIMIAIMIJIJIAISIOINID
•POWER GENERATION
COMB.TURBINE UNITS
PLOT PLAN,GA.
HRSG &STEAM TURBINE
DETAIL ENGINEERING
~S;.;.P.;;;,EC.;.;S;...;;.&..;.P,;.;.O..;..-o ....E_NG.;,.I_N,;;;,EE;;,;,R.;.;,;IN....G;;....-__
HEAT BALANCE
FABRICATION INSTALLATION------------.-----~
-
•COAL GASIFICATION
EQUIPMENT
ENGINEERING
•COAL SYSTEM
EQUIPMENT
ENGINEERING
•OXYGEN PLANT
EQUIPMENT
ENGINEERING
•WATER SYSTEM
EQUIPMENT
ENGINEERING
•SUPPORT SYSTEM
FRONT END ENGINEERING
EQUIPMENT
ENGINEERING
•CHECK OUT,CALIBRATION
START-UP &TEST
I-_-._-~S-P-E-C-S-&-P-.O-.--c-)----E;;;;;N ....G;;;.;IN....E;;;;E;;.;R.;,;.IN;.;;G;....--..__F~R~A!!.O~_....._-E~V.,!;R.:!..S~~_....._I~~~TI~N __..
X
SPECS &P.O.ENGINEERING _FABRICATION INSTALLATIONL..---..:.....:;;.;,.;;~..;,.,,;,,;;.;.-(X)----=.:..:.;:.;,;,,;,,=.:::.:...::.:...::....-...--- - - - - - ----- - - - - ----- -......- - - - ---..
FRONT END
ENGINEERING SPECS &P.O.ENGINEERING FABRICATION INSTALLATION~~~~~~--~~---OX-~~~~~-~------------~----~---------------..
ENGINEERING CONSTRUCTIONo--";;;;'';';;;;';'=';';;';';~-''---------4 - - - - - - - - - - - ---....
SPECS &P.O.FABRICATION INSTALLATION..--.;;;.;..;;;..;..;;....;;.........;..---.._-- ------------.....----------...
-
~-----------------------~
FIGURE 2.11.Construction Schedule
2.55
similar manner.A vacuum is pulled in the condenser,using the vacuum pumps
and the steam turbine warmed over the course of several hours,in accordance
with manufacturers'instructions.The bypass dampers can be repositioned as
required during the start-up period to control steam flow,and opened fully
when the steam turbine is loaded.
The plant cold start is based on using distillate oil from the emergency
fuel tanks on one of the gas turbines.A diesel generator started on
compressed air will provide the power for starting the gas turbine.
Once the gas turbine is producing power,the gasifier train can be
started and operation on distillate oil continued until the gasifier produces
sufficient quantities of fuel gas.
Hot starts are accomplished by starting and synchronizing the first gas
turbine using distillate oil.The heat recovery steam generator is then
loaded and the steam turbine started.After the steam turbine is up to speed,
the second gas turbine is started,the second steam generator is loaded and
the plant is brought up to load.At this time the oxygen plant is started and
brought up to load.The gasifier is started with a mixture of oil and coal.
When it has reached operating temperature,the oil is shut off and operations
are sustained on coal while the first gas turbine is switched to MBG.When
the system is stabilized,the other turbine is switched to MBG and full load
assumed.
2.6.2 Operating Parameters
Operating experience on coal-gasifier combined-cycle plants is somewhat
limited when compared to coal-or oil-fired power plants.Therefore,
conclusions on operating parameters are based on the available data on
gas-fired combined-cycle plants supplemented by EPRI (1978)data and known
experience on gas turbines and steam turbines.
The forced outage rate can be expected to be about 8 percent.Initial
operation experience on some earlier plants indicates higher forced outages in
the first few years,but this is attributed to problems associated with
starting up a new-type plant,and development of the current gas turbine
design.We would expect to see a slight increase in forced outages as the
2.57
plant ages,but do not anticipate the "technology development"-type outages
experienced by some of the earlier plants.Variations in plant sizes should
not affect the forced outage rate provided that the same "experience factor"
is involved with the gas turbines used.
Cycling the plant will have a negative effect on all the plant machinery,
due to the numerous system stress reversals encountered with this type
operation,and a higher forced outage rate should be anticipated if the plant
is run as a peaking unit.
The coal-gasification combined-cycle plant reliability is very dependent
on an adequate preventative maintenance program,and scheduled outrage rates
can be expected to be about 7 percent.Again,plant size will not affect the
scheduled outage rate,but cycling service will necessitate more frequent
inspections,which will result in a higher scheduled outage rate.An
equivalent plant availability of approximately 86 percent should be obtained
with the forced and scheduled outage rates of 8 percent and 7 percent,
respectively.
The plant heat rate of approximately 9,287 Btu/kWh is not expected to
vary significantly with plant size within the range of 100 MW to 400 MW,but
should rise slightly as the plant ages.The heat rate will,however,vary
considerably with plant loading,as the efficiency of the gas turbines
deteriorates rapidly as the load is reduced.At extremely low load
conditions,in the 20 to 30 MW range,heat rates as high as 14,000 to
16,000 Btu/kWh should be anticipated.For a combined-cycle plant in load
following service,consideration should,be given to using a larger steam
turbine and varying the steam turbine output with supplementary duct burner
firing.Duct burner firing would raise the heat rate,but offers a distinct
advantage in heat rate over gas turbine cycling for the variable load plant.
2.6.3 Plant Life
Based on the life of the gas turbine units,the plant should have a
25-year life expectancy.It is expected that the gas turbine units and
gasifier components will be partially rebuilt a number of times during the
scheduled (and unscheduled)outages.
2.58
oyees.
n-
2.6.4 Operating Work Force
The plant will require an operating staff of approximately 110
Of this total,approximately 71 represent operating staff while
tenance personnel.An estimate of the plant's staffing requi~~,n~v,+
sented in Table 2.12.Employment of these personnel will
the life of the plant.
2.59
Plant systems will be operated from the control room loc
plant building.Some of the systems and equipment will also
from local stations.In general,controls are automatic,al~n(JUqln
can override the automatic controls and operate the plant
supplement the operational controls,the station will be equ
alarm system,fire protection system,proper lighting,and a
communication system.
Periodic maintenance will be performed on all pressure
machinery,heat sensitive equipment,and other operating equi
malfunctions,leaks,corrosion and other such abnormalities.
maintenance should be performed in accordance with an establi
program.This would include the complete strip down and
the turbines as required or suggested by the equipment
replacement of refractory linings in the gasifier components
accomplished every 2 or 3 years during scheduled maintenance
system elements,such as the gas cleanup train and air
are commercial units,will require minimal maintenance during
inspections.In addition,the maintenance programs will monitor
tation and erosion prevention programs of the plant site initi
cleanup phase of construction.Trained maintenance crews will
tional maintenance and will correct emergency malfunctions.
major maintenance functions will be performed during the plant's SClne(Jl
outages.
2.6.5 General Maintenance Requirements
TABLE 2.12.Plant Staffing Requirements
Power(a)Gasifier(a)Coal(b)
Job Title Plant Plant Yard
Plant Superintendent 1
Operations Engineer 1 4
Shift Superintendent 4 4
Control Room Operators and 4 8
Auxiliary Operators
Chemist 1 1
Chemical Technician 4
Results Engineer 1 1
Results Technician 1 1
Instrument and Controls Engineer 1 1
Instrument and Controls Technician 4 4
Storekeeper 1
Clerical 2 1
Maintenance Superintendent 1 1
Maintenance Engineer 1 1
Maintenance Foreman 2 1
(Electrical/Mechanical)
Mechanics (6-Man Crews)6 4
Maintenance Foreman 1 1
(Instrument and Controls)
Mechanics (2-Man Crews)2 4
Labor Foreman 1 1
Labor Crew 4 4
Fire Protection/Security Staff 4 0
Coal Yard Foreman 3
Tractor Operator 7
Breaker House Operator 3
Ash Plant Operator 4
Disposal Site Operators 3
Maintenance Mechanic 1--
Total 43 46 21
Plant Total:110
(a)Three 8-hour shifts and seven-days-a-week operation.
(b)Two 8-hour shifts,seven-days-a-week operation.
2.60
3.0 COST ESTIMATES
3.1 CAPITAL COSTS
3.1.1 Construction Costs
Construction costs in January 1982 dollars have been developed for the
major bid line items common to a coal-gasifier combined-cycle power plant.
These lines items costs have been broken down into the following categories:
labor and insurance,construction supplies,equipment operation costs,
equipment rental,and permanent materials.Results of this analysis are
presented in Table 3.1.The equivalent unit capital cost of the plant is
3284 $/kW.
3.1.2 Payout Schedule
A payout schedule has been developed for the entire project and is
presented in Table 3.2.The payout schedule was based on a 36-month basis
from start of construction to project completion.
3.1.3 Capital Cost Escalation
Estimates of real escalation in capital costs for the plant are presented
below.These estimates were developed from projected total escalation rates
(including inflation)and subtracting a Gross National Product deflator series
which is a measure of inflation.
Materi a1sand Construction
Equipment Labor
Year (Percent)(Percent)
1981 1.0 0.5
1982 1.2 1.7
1983 1.2 1.7
1984 0.7 1.3
1985 -0--0-
1986 -0.1 -0.1
1987 0.3 0.3
1988 0.8 0.8
1989 1.0 1.0
1990 1.1 1.1
1991 1.6 1.6
1992 -on 2.0 2.0
3.1
TABLE 3.l.Bid Lint Jtem Costs for Beluga Area Coal-Gasifier Combined-Cycle
Project a (January 1982 Dollars)
Construction Equipment
Labor and Construction Repair Equipment Permanent Total
Bid Line Item Insurance Supplies Labor Rent Materials Direct Cost
I.Improvements to Site 370,300 425,000 324,400 13,800 1,133,500
2.Earthwork and Piling 956,800 121,500 296,200 479,900 8,662,500 10,516,900
3.Circulating Water System 5,021,500 690,000 44,900 69,800 7,740,000 13,566,200
4.Concrete 9,521,200 914,500 1,025,600 623,300 4,156,500 16,241,100
5.Structural Steel and Lift Equipment 2,135,100 805,000 1,050,000 12,035,000 16,025,100
6.Buildings 1,223,600 147,200 256,000 2,610,700 4,237,500
7.Turbine Generator 5,716,900 172,500 275,000 33,200,000 39,364,400
8.Steam Generator and Accessories 3,995,100 115,000 220,000 11,000,000 15,330,100
9.Coal Gasification Plant 10,120,800 920,000 1,500,000 36,100,000 48,640,800
10.Air Quality Control System 6,343,200 575,000 200,000 21,740,000 28,858,200
II.Air Separation Plant 5,250,200 230,000 800,000 31,000,000 37,280,200
12.Other Mechanical Equipment 11,128,100 345,000 165,000 25,642,000 37,280,100
13.Coal and Ash Handling 2,934,200 920,000 400,000 9,800,000 14,054,200
14.Piping 15,960,500 1,035,000 360,000 22,000,000 39,355,500
15.Insulation and Lagging 632,600 201,300 150,000 3,500,000 4,483,900
16.Instrumentation 1,613,000 138,000 40,000 12,550,000 14,341,000
w 17.Electrical Equipment 12,651,000 172,500 75,000 28,200,000 41,098,500.
N 18.Painting 3,162,800 115,000 75,000 2,000,000 5,352,800
19.Off-Site Facilities 2,451,400 211,100 3,621,100 2,693,600 979,200 9,956,700
20.Waterfront Construction 28,700 63,500 47,300 350,000 489,500
2I.Substation 1,043,700 23,000 11,000 4,035,500 5,113,200
22.Construction Camp Expenses 8,628,500 28,787,800 37,416,300
23.Indirect Construction Costs a~d 19,159,700 89,590,900 2,123,900 2,818,800 113,693,300
Architect/Engineer Services(b
SUBTOTAL 130,048,900 126,230,330 7,600,200 12,634,100 277,315,200 553,828,700
Contractor's Overhead and Profit 72 ,300,000
Contingencies 96,400,000
TOTAL PROJECT COST 722,528,700
(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 $72,300,000 for engineering services and $41,393,300 for other indirect costs including construction equip-
ment and tools,construction related buildings and services,nonmanual staff salaries,and craft payroll related
costs.
TABLE 3.2.Payout Schedule for Beluga Area Coal-Gasifier
Combined-Cycle Project
Cost per Month Cumulative Cost
Month (Do 11 ars)(Do 11 ars)
1 8,403,500 8,403,500
2 10,324,100 18,727,600
3 10,324,100 29,051,700
4 12,952,100 42,003,800
5 12,583,000 54,586,800
6 12,583,000 67,169,800
7 14,904,900 82,074,700
8 12,342,300 94,417,000
9 11,898,600 106,315,600
10 19,078,700 125,394,300
11 18,756,500 144,150,800
12 23,049,200 167,200,000
13 23,049,200 190,249,200
14 28,990,600 219,239,800
15 29,404,600 248,644,400
16 29,404,600 278,049,000
17 29,404,600 307,453,600
18 29,404,600 336,858,200
19 29,404,600 366,262,800
20 27,191,500 393,454,300
21 27,191,500 420,645,800
22 27,191,500 447,837,300
23 25,653,000 473,490,300
24 25,467,300 498,957,600
25 25,467,300 524,424,900
26 25,467,300 549,892,200
27 24,750,300 574,642,500
28 24,750,300 599,392,800
29 22,560,500 621,953,300
30 21,673,300 643,626,600
31 16,621,700 660,248,300
32 15,988,400 676,236,700
33 13,950,700 690,187,400
34 13,950,700 704,138,100
35 9,195,400 713,333,500
36 9,195,200 722,528,700
3.3
3.1.4 Economics of Scale
3.2 OPERATION AND MAINTENANCE COSTS
3.2.1 Operation and Maintenance Costs
$3,711,000 (16.87 $/kW/yr)
3.4
Staff (110 Persons)
Fixed Costs
The operation and maintenance costs for the 200-MW size plant,expressed
in January 1982 dollars,are as follows:
At present,coal gasifiers have a limited maximum unit capacity of about
1,000 tons/day.Therefore,increasing a facility·s power output can only be
achieved by the addition of gasifier modules.As a result,significant
economies of scale would not be realized by increasing plant size.
Developmental research is proceeding in this area,however,and Shell
Koppers unit capacities of approximately 2300 tons/day are planned for about
1990.In the future,then,economies of scale could be realized for many site
development costs,including temporary facilities,construction equipment and
construction labor.These savings would be brought about by increasing
facility capacity through an increase in component capacity.For example,in
the range of considered plant sizes (up to approximately 300 MW)utilization
of larger-unit-capacity gasifiers,100-MW combustion turbines,and larger heat
recovery boilers would necessitate only a slight increase in the construction
work force over that required for smaller unit sizes.In addition,the plant
could be constructed within the same time frame as a smaller plant,resulting
in a reduction of unit cost on a per megawatt basis.
3.1.5 Working Capital
Working capital costs,including a 54-day emergency coal supply,
179,000 bbl of No.2 fuel oil,and 30-day O&M costs,are estimated to be
$65.30.The cost of the emergency coal supply is based on a forecasted 1991
price of $1.80/MMBtu delivered coal to the plant site.The price of No.2
distillate is estimated to be $8.23 MMBtu in 1991.
Variable Costs
Operating Supplies
and Expenses
Maintenance Supplies
and Expenses
3.2.2 Escalation
~460,000 (0.27 mills/kWh)
~694,000 (0.4 mills/kWh)
Estimated real escalation of fixed and variable operation and maintenance
costs are as follows:
3.2.3 Economics of Scale
Year
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
Escal ation
(Percent)
1.5
1.5
1.6
1.6
1.7
1.8
1.8
2.0
2.0
2.0
2.0
Costs associated with personnel salaries are generally the major compo-
nent of operation and maintenance costs for energy generating facilities.In
light of this fact economies of scale would result from larger unit capacities
because the personnel requirements are more a function of items or equipment
and,therefore,would not increase in direct proportion to additional capac-
ity.These savings are only achievable if the facility is planned for
operation in the mid-1990s,because increased gasifier unit capacities will
not be available until this time.
3.5
3.6
3.3 FUEL AND FUEL TRANSPORTATION COSTS
3.4 COST OF ENERGY
0%
3%
0%
0%
25 years
0%
100%Debt Financing
Equity Financing
Interest on Debt
Federal Taxes
State Taxes
Bond Life
General Inflation
These costs are based on the following financial parameters:
Estimated prices for Beluga coal are developed in another report in this
series (Swift 1981).Coal for the proposed Beluga Station would be supplied
from the currently undeveloped Beluga 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 mine-mouth price stream is shown in
Table 3.3.This analysis,of course,presumes development of an export
Pacific Rim market
Estimated busbar energy cost from the proposed Beluga Station is
63 mills/kWh.This is a levelized lifetime cost,in January 1982 dollars,
assuming a 1991 first year of commercial operation and an 85 percent capacity
factor.Estimated busbar energy costs for other capacity factors and other
startup dates are shown in Figure 3.1.Year-of-occurrence energy costs and
capital,O&M and fuel component costs for a plant coming on line in 1991 are
shown in Table 3.4.Year-of-occurrence costs are sensitive to escalating fuel
costs.
The escalation factors given in Sections 3.1 and 3.2 were employed.Weighted
average capital cost escalation factors were derived using a labor/material
ratio of 25 percent/75 percent.
3.7
(a)2.1 percent annual escala-
tion rate from 1980 base
price.
1.69
1.72
1.76
1.80
1.83
1.87
1.91
1.95
1.99
2.03
2.08
2.12
2.16
2.21
2.26
2.30
2.35
2.40
2.45
2.50
2.55
2.61
2.66
Beluga Coal
Mine Mouth{a)
(~/MMBtu)Year
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
TABLE 3.3.Estimated Coal Prices:Beluga Station
(January 1982 dollars)(Swift 1981)
175-.c
==I TCO 2005~--VI
150 r°E TCO 2000
~
f-
125 ~TCO 1995I/'l
0u TCO 1991
~
(,)
c::wz 100w
c::<:
CO
I/'l
:J
CO 75
0w
N
:::iw 50>w
oJ
0w
f-25<:
~
f-
I/'l
W
o
3.8
FIGURE 3.1.Cost of Energy Versus Capacity Factor and Year of
First Commercial Operation (TCO)(January 1982
dollars)
o 25 50
CAPACITY FACTOR (%)
75 100
TABLE 3.4.Year-of-Occurrence Energy Costs (1991 First Year
of Operation;January 1982 dollars)
Unit Unit Unit Total
Cap i ta1 Costs O&M Costs Fuel Costs Unit Costs
Year (mills/kWh)(mills/kWh)(mi lls/kWh)(mill s/kWh)
1991 28.9 10.9 16.7 56.5
1992 28.9 11.1 17.0 57.0
1993 28.9 11.3 17.4 57.6
1994 28.9 11.5 17.7 58.2
1995 28.9 11.8 18.1 58.8
1996 28.9 12.0 18.5 59.4
1997 28.9 12.3 18.9 60.0
1998 28.9 12.5 19.3 60.7
1999 28.9 12.7 19.7 61.4
2000 28.9 13.0 20.1 62.0
2001 28.9 13.3 20.5 62.7
2002 28.9 13.5 21.0 63.4
2003 28.9 13.8 21.4 64.1
2004 28.9 14.1 21.8 64.8
2005 28.9 14.4 22.3 65.6
2006 28.9 14.6 22.8 66.3
2007 28.9 14.9 23.2 67.1
2008 28.9 15.2 23.7 67.8
2009 28.9 15.5 24.2 68.7
2010 28.9 15.9 24.7 69.5
2011 28.9 16.2 25.3 70.4
2012 28.9 16.5 25.7 71.1
2013 28.9 16.8 26.3 72.0
2014 28.9 17.2 26.8 72.9
2015 28.9 17.5 27.4 73.8
3.9
4.0 ENVIRONMENTAL AND ENGINEERING SITING CONSTRAINTS
This section presents many of the constraints that would be evaluated
during a siting study.Special attention is given to the applicability of
these constraints to the Beluga area.The purpose of such a study is to
identify a preferred location(s)and possibly viable alternative locations for
the construction and operation of the generating station.Through this
process,environmental and engineering constraints are minimized,which
subsequently minimizes project costs.
Many of the constraints placed upon the development of a coal-gasifier
combined-cycle power plant are regulatory in nature;therefore,the discussion
presented in this section is complemented by the identification of power plant
licensing requirements presented in Section 6.
4.1 ENVIRONMENTAL SITING CONSTRAINTS
4.1
Potential environmental siting constraints include effects
resources,air resources,aquatic and marine ecology,terrestri
socioeconomic considerations.
Water resource siting constraints generally center
water availability and water quality.The power plant requ
source of water for its efficient operation.It is general
minimize flow reduction of potential water supply
reliability.For this reason,it is necessary to examine
average yearly and monthly flows for potential water
consideration will have to be given to intake structure
avoid freezing and ice-related problems.Consideration
and geometry will also be important to avoid local flow
the vicinity of the structure(s)during low flow peri
of water must be sought.Potential sources include
groundwater and sea water.Sea water is suitable for
Groundwater sources exist in this area,with well yiel
high as 1000 gpm near the larger surface water bodies.
4.1.1 Water Resources
generally range from 10 gpm to 100 gpm away from surface water bodies.
Another alternative could include groundwater for process use and salt water
for cooling purposes.The use of groundwater or sea water could,however,
significantly increase power plant costs.This cost increase would have to be
evaluated in light of the potential impact of utilizing surface water
resources.
Water quality can represent a significant siting criterion,in that
receiving stream water quality standards could prohibit plant effluent ais-
charge.Poor makeup water quality can impact water management requirements by
requiring either an extensive water treatment facility prior to plant use,as
could be the case if groundwater were used,or by limiting plant recycle,thus
requiring a costly internal treatment/recycle facility.
4.1.2 Air Resources
The air resources siting process involves the determination of those
areas within the overall study location where power plant siting would appear
feasible from a regulatory point of view.A full discussion of the air-
related regulatory requirements appears in Section 6;however,the major
factors that must be evaluated include:
•proximity to areas designated Class I under Prevention of
Significant Deterioration (PSD)regulations
•proximity to non-attainment areas for ambient air quality standards
•general dispersion capability of the area.
These factors are evaluated through the use of computerized mathematical
models that develop estimates of atmospheric diffusion and,subsequently,the
concentration of various air pollutants.Input to the model consists of the
characteristic emissions from the plant and local meteorological data.
Of the three factors listed above,the location of the Class I area at
Tuxedni Bay could pose the most severe siting constraint for development of a
coal gasifier/combined-cycle facility in the Beluga region.The ~llowable
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
4.2
each potential site must be analyzed in detail.The Class I visibility regu-
lations could significantly affect this minimum distance.
4.3
4.1.3 Aquatic and Marine Ecology
Plant makeup water and discharge requirements may be large when compared
to the surface water resources of the Beluga area.Therefore,it is possible
that wastewater discharge may impact site selection.Baseline oata would need
to be developed,and an identification of exclusion and avoidance areas made,
to be considered in association with intake and discharge structure develop-
ment.Exclusion and avoidance areas would primarily be based upon an
tory of fish spawning habitat and upstream migration pathways,fish
habitat and downstream migration pathways,important benthic habitat,
and/or endangered species and their critical habitats,and an asse~;sment
potential entrainment and impingement impacts.
4.1.4 Terrestrial Ecology
Since habitat loss is generally considered to repre
nificant impact on wildlife,an identification of i
especially critical habitat of threatened or endangered ,n,o(',CC
required.Based upon this inventory,exclusion,avoi
areas would be delineated and factored into the overall
A number of important and sensitive species inhabi
These include moose and black bear;small fur bearers,
and muskrat;and various bird species,including
nesting birds,such as seagulls,puffins and
sideration of these species and their habitats wi
plant siting process.
Major socioeconomic constraints center about
and community and regional socioeconomic impacts
Potential exclusionary land uses will consist
lands set aside for public purposes,areas
lation (federal,state or local laws),areas re a
4.1.5 Socioeconomic Constraints
areas in which a coal-gasifier combined-cycle installation might preclude or
not be compatible with local activities (e.g.,urban areas or Indian reser-
vations),or areas presenting safety considerations (e.g.,aircraft facil-
ities).Avoidance areas will generally include areas of proven archaeological
or historical importance not under legislative protection,and prime agri-
cultural areas.
Minimization of the boom/bust cycle will be a prime concern.Through the
application of criteria pertaining to community housing,population,infra-
structure and labor force,preferred locations will be identified.The Beluga
area is remote and significant boom/bust related impacts on small communities
(i.e.,Tyonek)would likely result from plant construction.Socioeconomic
criteria will thus be heavily weighted in the overall site evaluation process.
4.2 ENGINEERING SITING CONSTRAINTS
The development of the coal-gasifier combined-cycle station could be
constrained by a number of factors bearing upon the engineering aspects of the
project.These factors,which are discussed below,include site topography
and geotechnical characteristics,access road distance,transmission line
distance and water supply requirements.
4.2.1 Site Topography and Geotechnical Characteristics
In general,the power plant should be sited on relatively flat terrain,
which will minimize the amount of required grading and excavation.It will
also minimize 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 any major surface water
resources.
Another major criterion is the avoidance of areas with poor soil condi-
tions.Such areas can cause significant construction and reliability problems
due to poor foundation suitability.Soil-related foundation problems can be
expected in the Beluga area due to the presence of highly organic soil
(muskeg).The presence of this soil will probably require the installation of
extensive pilings under major structures.
4.4
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,all potential sites fall within regions of high seismic
activity (Zone 3).While this will not preclude development nor differentiate
between sites,it will increase construction costs,because more material will
be required to ensure plant foundation and disposal area dike stability.
A final geotechnical criterion concerns the opportunity for use of onsite
borrow material.Sites that contain an adequate supply of borrow material can
be far less costly,especially if alternate sites would require hauling this
material over long distances.
4.2.2 Access Road and Transmission Line Considerations
Siting a power plant in close proximity to existing roads and transmis-
sion lines minimizes cost and also minimizes the environmental effects associ-
ated with land disturbance.Route selection should comply with established
safety and reliability standards;for example,the maximum allowable grade is
approximately 6 percent.Route selection will also be affected by soil and
meteorological conditions,because potential frost heave problems and other
soil related characteristics can significantly add to the cost of road
facilities.Also,wind,temperature and ice load can significantly affect
transmission line design.
4.2.3 Water Supply Considerations
The power plant requires a reliable water supply source for its efficient
operation.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
acceptable source of water,and
•The plant should be sited where the maximum static heaa 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 acquisi-
tion;land disruption;associated construction-related environmental impacts;
4.5
investment and operating costs;and the potential reliability problems associ-
ated 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.,a duplicate pipeline),and the need to minimize the operating costs
associated with water pumping.
4.6
5.0 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS
The construction and operation of a 220-MW coal-gasifier combined-cycle
generating facility will create changes or impacts to the land,water,air,
and socioeconomic environments in which it is located.A summary of the
primary impacts of the plant on the environment is presented in Table 5.1.
Following preliminary plant design,these primary effects are then analyzed
and evaluated in light of existing environmental conditions to determine the
potential significance of the impact and the need for additional mitigative
measures.Further discussion of the impacts listed in Table 5.1 is provided
below.
5.1 WATER RESOURCE EFFECTS
Water resource impacts associated with the construction and operation of
a coal-gasifier combined-cycle power plant are generally mitigated through
appropriate plant siting criteria and a water and wastewater management
program.The plant water system will normally employ water treatment and
recycle to satisfy regulatory requirements on discharge and to minimize water
consumption.Achievement of these water quality requirements will preclude
adverse impacts on the water resource.Certain waste streams in the gasifier,
however,may require more extensive treatment systems than those normally
associated with steam-electric or combustion turbine technologies.
5.2 AIR RESOURCE EFFECTS
The air resource impacts associated with a coal-gasifier combined-cycle
power generation facility are relatively minor when compared with alternate
fuel-combustion technologies.Nitrogen oxide emissions can be controlled
through water or steam injection techniques.A major advantage of a gasifier
over other coal combustion technologies is the elimination of significant
sulfur oxide emissions.The associated hydrogen sulfide emissions are
controlled through a treatment process,such as the Stretford process.
Particulate emissions can be controlled,if necessary,through conventional
techniques,such as baghouses.Achievement of regulatory requirements will
preclude any significant impacts from these emissions to the air resource.
5.1
TABLE 5.1.
Air
Primary Environmental Effects
Controlled Gasifier Emissions (Anderson and Ti 11man 1979)
Particulate Emissions
Sulfur Oioxide Emissions
Nitrogen Oxide Emissions
Hydrocarbon Emi ss ions
Carbon Monoxide Emissions
Controlled Combustion Turbine Emissions
Particulate Emissions
Sulfur Oioxide Emissions
Nitrogen Ox i de Emi ss ions
Water
Pl ant Water Requirements
Plant Discharge Requirements
Aquatic and Marine Ecosystems
Anadromous Fi sh
Other
Terrestri a1 Ecosystem
Wil dl ife Habitat
Food Chain
Human Presence
Land
Plant
Transmission
Road
Ash Di sposa1
Socioeconomic
Construction Work Force
Operating Work Force
Relocations
Land Use Changes
Recreation
Capital Investment
Operating Investment
Fue 1 Purchases
0.009 lb/MMBtu
0.046 lb(MM
J
Btu (0.0025 lb
S/MMBtu)a
0.1351b/MMBtu
0.003 lb/MMBtu
0.010 lb/MMBtu
Negligible
Negligible (0.007 lb S/MMBtu)(aJ
Variable.Water injection
contro 11 ed to meet NO x standard
of 0.014 percent by volume of
gaseous emissions.
1,303 gpm wet tower operation
208 gpm dry tower operation
222 gpm wet tower operat i on
85 gpm dry tower operation
No impact anticipated
NO significant impact anticipated
Loss of habitat at the plant site
and along access road corri dor
No significant impact anticipated
Increased human presence at plant
site and along access road corri dor
30 acres
75 miles at 345-kV line (could
share existing transmission corri-
dor for much of this distance)
5 mil es of grave 1 road
50 acres
Peak reQui rement of approx imate ly
1000 personne 1
110 personne 1
None
Increased access to plant site and
along road and transmission
corridors
See 1and use changes above
30 percent withi n reg i on
70 percent outside region
84 percent withi n regi on
16 percent outs i de reg i on
100 percent within region
(aJ Total of various sulfur compounds based on sulfur mass balance--refer to
Figure 2.9.
5.2
Ice fog may be produced during cold weather conditions by water or steam
injection;however,the requirement for water or steam injection may be elimi-
nated when ice fog is deemed a traffic hazard.In addition,water vapor can
be added to the air from the cooling tower.The formation of these plumes
will be eliminated,however,by the use of a wet/dry cooling tower system.No
offsite local climatic effects of system operation will be detectable.
As with other combustion-based technologies,operation of a coal-gasifier
combined-cycle plant will release carbon dioxide to the atmosphere.Increas-
ing concern has been expressed regarding long-term effects of the increase in
atmospheric CO 2 ,apparently resulting from combustion of fossil fuels.Of
particular concern is the potential IIgreenhousell effect of increased atmo-
spheric CO 2 concentration.No feasible measures are currently available for
control of CO 2 production--other than possible regulation of the global
amounts of fossil fuels burned.No controls on CO 2 production,however,
currently exist.
5.3 AQUATIC AND MARINE ECOSYSTEM EFFECTS
A potentially significant impact can occur from water withdrawal and
effluent discharge.However,proper design and location of the plant1s intake
and discharge structures should sufficiently mitigate any major adverse
effects.Attainment of regulatory requirements on plant discharges through
properly engineered systems should mitigate any potential toxic effects.
5.4 TERRESTRIAL ECOSYSTEM EFFECTS
The greatest impact resulting from coal-gasifier combined-cycle power
plants on the terrestrial biota is the loss of habitat due to human distur-
bance.The amount of land required is approximately 30 acres for the actual
plant site and 50 acres for the waste disposal area.A much larger area may
be required for road access and transmission and pipeline corridors (see
Table 5.1).Significant populations of moose,caribou,black bear and
waterfowl are located in the Cook Inlet area.Therefore,siting studies for
the actual plant location and for road,gas pipeline,and transmission
5.3
corridors should be performed to minimize impacts to these species.A care-
fully selected site should not significantly impact these populations.
Some potential exists for the disturbance of the flora and fauna due to
cooling tower drift emissions and coal and waste pile dusting.Proper control
and site management devices should sufficiently mitigate this impact.
5.5 SOCIOECONOMIC EFFECTS
Most of the communities located near the Beluga coal fielas are small in
population and have an infrastructure that is not highly developed.In light
of this,the construction and operation of a 220-MW coal-gasifier combined-
cycle plant has a high potential to impact these local communities and cause a
boom/bust cycle.This impact may be significant,for 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 infra-
structure must be anticipated.
Since a coal-gasifier combined-cycle power plant represents a capital-
intensive technology,the largest portion of expenditures outside the region
will be attributed to equipment.Approximately 70 percent of the project
capital expenditures will be spent in the lower 48 states,while 30 percent
will be spent within the Railbelt.Operating and maintenance expenditures
spent outside the Railbelt will be approximately 16 percent.
5.4
6.0 INSTITUTIONAL CONSIDERATIONS
This section presents an inventory of major federal,state of Alaska and
local environmental regulatory requirements that will be associated with the
development of a 220-MW coal-gasifier combined-cycle power plant located in
the Beluga area on Cook Inlet.
The discussion is limited to major environmental regulatory requirements.
The identification of more specific requirements can be accomplished only
after detailed studies regarding project design and location are available.
These requirements could be important in Alaska,where much of the land is
owned by the federal or state government.
6.1 FEDERAL REQUIREMENTS
Since the operating experience with coal gasifier facilities to date has
been limited,the Environmental Protection Agency (EPA)has yet to promulgate
industry-wide standards to control the waste streams emitted.In cases such
as this,the EPA generally applies the limitations from an industry that
closely resembles the process in question.In light of this procedure,it can
be expected that the effluent limitations from a number of point source
categories,including steam-electric generation,oil refining,coking,mining
and coal preparation and handling,will be applied to similar waste streams
occurring at a coal-gasifier combined-cycle facility.These specific point
source categories are enumerated because various aspects of them have been
applied to gasification plants in the past.In addition,the EPA initiated a
program to develop Pollution Control Guidance Documents (PCGDs)for each major
synfuel technology.The initial PCGDs were to be non-binding,non-regulatory
documents to inform industrial designers and permitting officials of what EPA
believes to be the best and most cost-effective ways to control pollution from
synfuel plants.Second-generation PCGDs were to have more regulatory
authority.Due to many reasons this program was,however,cancelled following
issuance of only a few draft documents.At present it is uncertain whether
the program will be reinstituted.
6.1
The permits that would be required for both a conventional coal-fired
facility and the proposed coal gasifier combined-cycle power plant are
identified only through their inclusion in Table 6.1.For discussion of those
permits,refer to the institutional considerations section of the reports
Coal-Fired Steam-Electric Power Plant Alternative for the Railbelt Region and
Natural Gas-Fired Combined Cycle Power Plant Alternative for the Railbelt
Region (Ebasco Services Incorporated 1982a,1982b).Further discussion is
provided here,however,of permits required for a synfuels facility that need
not be obtained for a coal-fired or natural gas-fired combined-cycle plant.
Under "the Toxic Substances Control Act (TSCA),a new chemical substance
or one with a significant new use will trigger a manufacturer's responsibility
to submit a premanufacture notification (PMN)90 days prior to manufacturing
if the chemical is not on EPA's chemical inventory.The EPA is currently
considering whether synfuels are new chemicals that must be reviewed under the
PMN program before production can begin.Until the consideration is complete,
EPA is requesting that synfuel manufacturers submit to EPA,in advance of the
PMN,a description of the chemical(s)expected to be produced.It is
recommended that owners and operators of a synfuels plant file a PMN if one
has not been previously filed for the system employed in their facility and
the coal that the facility will process.
Applicability of the Resource Conservation and Recovery Act (RCRA)
hazardous waste management program to the synfuels industry has some unique
aspects worth further consideration.Congress has specifically exempted solid
waste originating from the extraction,benefaction,and processing of ores and
minerals,including coal,from RCRA control until studies can be completed to
clarify the exact hazards of such wastes.The exemption has been interpreted
by EPA (in a memo dated January 12,1981,from Alfred Lindsey,Deputy Director
of EPA's Industrial and Hazardous Waste Division)to apply to the gasification
of coal,and wastes produced by gasification operations provided they are
"unique"to the ore processing operation.The exemption includes wastes
produced during direct gasification and liquefaction of coal,including wastes
that may not become mixed with spent ash,such as sludges and condenser
liquids.However,the exemption has not been applied to hazardous
6.2
TABLE 6.1.Federal Regulatory Requirements
Agency
u.s.Environmental
Protection Agency
u.s.Army Corps of
Engineers
Federal Aviation
Administration
National Marine
Fisheries Service!
Fish and Wildlife
Service
Requirement
National Pollutant
Discharge Elimination
System
Prevention of
.Significant
Deterioration
Hazardous Waste
Management Facility
Operation Permit
Premanufacture
Notification
Environmental Impact
Statement
Construction Activity
in Navigable Water
Discharge of Dredged
or Fill Material
Air Navigation
Approval
Threatened or
Endangered Species
Review
Scope
Discharges to
Water
Air Emissions
Hazardous
Waste
Toxic
Substances
A11 Impacts
Construction
in Water
Di scharges to
Water
Air Space for
Transmission
Lines
Air,Water,
Land
Statute
or Authority
33 USC 1261
et seq.;
section 1342
42 USC 7401
et seq.;
section 7475
42 USC 6901
et seq.;
section 6925
15 USC 2601
et seq.;
section 2605
42 USC 4332
33 USC 401
et seq.;
33 USC 1251
et seq,;
section 1342
49 USC 1304,
1348, 1354,
1431,1501
16 USC 1531
et seq.
Land UseAdvisoryCouncil
on Historic
Preservation
Determination that
Site is not
Archeo logi ca lly
Significant
Determination that Land Use
Site does not Infringe
on Federal landmarks
16 USC 402 aa
et seq.
16 USC 416
et seq.
Department of
the Interior -
Office of
Surface Mining
All Federal
Agencies
Surface Coal
Mining Permit
Executive Order
No.11990
Executive Order
No.11988
6.3
Surface Coal
Mining
Operations
Development in
Wetlands
Development in
Floodplains
30 USC 1201
et seq.;
section 1256
wastes,such as spent cleaning solvents,cooling tower blowdown,ion exchange
regeneration wastes,or wastes resulting from the refining of crude oil
extracted from coal.Gasification plant operators cannot take advantage of
the exemption from RCRA permitting requirements available to those who dispose
of hazardous wastes with high volume wastes from coal combustion,because EPA
does not include coal gasification in the definition of "coal combustion"for
purposes of this exemption.An RCRA permit will therefore be necessary for
this facility unless all hazardous wastes are transported off the project site
for disposal.
The coal mines,coal unloading facilities and coal preparation facilities
(defined as facilities where coal is crushed,screened,sized,cleaned,dried
or otherwise prepared and loaded for transit to a consumption facility)will
all be subject to the provisions of the Surface Mining Control and Reclamation
Act (SMCRA).This act authorizes the Office of Surface Mining (OSM)to issue
permits for all surface mining operations.These permits cover not only the
mines themselves,but all activities conducted in connection with the mines.
The OSM currently has extensive authority to impose operation and reclamation
requirements on a mine-mouth power plant.Although OSM's regulations have
been currently stayed from enforcement due to challenges in federal courts,
they are still OSM's strategy and can be imposed should OSM prevail in the
courts.(Note that the state of Alaska only regulates coal mined on state
lands.)
The project will undoubtedly require the preparation of an EIS under NEPA
in conjunction with the application to the Corps of Engineers for a permit to
discharge dredged or fill material into a navigable waterway pursuant to
Section 404 of the Clean Water Act,and a permit to construct in a navigable
waterway under Section 10 of the Rivers and Harbors Act of 1899.Both of
these permits must be obtained for construction of water intake and discharge
structures for the proposed facility.
6.4
6.2 STATE REQUIREMENTS
On the state level,it is not expected that any unusual environmental
regulatory requirements will be imposed upon the coal-gasifier combined-cycle
facility.Explanations of state requirements,given in Table 6.2,can be
found in the institutional considerations section of another report in this
series (Ebasco Services Incorporated 1982a).
6.3 LOCAL REQUIREMENTS
The Cook Inlet region is controlled by some of the most sophisticated
local requirements in the entire state of Alaska.This is largely due to its
proximity to Anchorage,one of the major population centers in the state.As
a result,a coal-gasifier combined-cycle plant will most likely be subject to
rather detailed requirements on a local level.The plant will likely be sited
in either the Matanuska-Susitna Borough or the Kenai Peninsula Borough.
6.4 LICENSING SCHEDULE
It is expected that the licensing schedule for this facility will closely
approximate that presented for a coal-fired facility,taking about 43 months
to complete.This estimated schedule may be delayed,however,due to lack of
experience of regulatory agencies in evaluating synfuel technologies.These
agencies may require extended periods of time for analysis of the environ-
mental impacts of the project and for development of permit requirements to
properly control those impacts.
The Matanuska-Susitna Borough is a second-class borough with powers of
land use planning,platting and zoning with which development can be con-
trolled.The Borough has acquired areawide powers for the regulation of ports
and ambulances,and also controls education and the assessment and collection
of taxes within its borders.
The Kenai Peninsula Borough has areawide powers of platting and zoning
and can control local land use.Plans to develop land in the Borough must be
approved by the local zoning board,which can regulate land use,building
6.5
Agency
Alaska Department
of Envi ronmenta 1
Conservation
TABLE 6.2.State Regulatory Requirements
Requirement Scope
State Certification Discharges to
that Discharges Comply Water
with CWA and State
Water Quality
Requirements
Air Quality Control Air Emissions
Permit to Operate
Solid Waste Management Solid Waste
Facility Operation
Statute
or Authorit:t,
30 USC 1201
et seq.;
section 1341
Alaska
Statute
46.03.140
Alaska
Statute
46.03.100
Alaska Department
of Natural
Resources
Water Rights Permit
Coal Exploration
Permit
Coal Lease
Appropriation
of Water
Development of
Coal Mine on
State Lands
Mining of Coal
on State Lands
Alaska
Statute
46.15.030-185
Alaska
27.20.010
Alaska
Statute
27.05.150
Alaska Office of
the Governor
Alaska Department
of Fish and Game
Coastal use Permit
Anadromous Fish
Protection Permit
Land Use Alaska
Statute
46.40
Fish Protection Alaska
Statute
16.05.870
Critical Habitat
Permit
6.6
Fish and Game
Protection
Alaska
Statute
16.20.22
and .260
location and size t the size of open spaces and population distribution.In
addition t 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.These programs do not have permit provisions t but they do
require that the plans for a proposed facility be approved by the Borough
prior to construction.
6.7
7.0 REFERENCES
Anderson,L.L.and D.A.Tillman.1979.Synthetic Fuels from Coal.John
Wiley and Sons,New York,New York.
Bechtel Corporation.1980.Preliminary Feasibility Study,Coal Export
Program,Bass-Hunt-Wilson Coal Leases,Chuitna River Field,Alaska.Bechtel
Corporation,San Francisco,California.
Commonwealth Associates,Inc.1981.Feasiblility Study of Electric Intercon-
nection Between Anchorage and Fairbanks.Engineering Report R-2274,Alaska
Power Authority,Anchorage,Alaska.
Ebasco Services,Inc.1982a.Coal-Fired Steam-Electric Power Plant Alterna-
tives for the Railbelt Region of Alaska.Prepared by Ebasco Services
Incorporated and Battelle,Pacific Northwest Laboratories for the Office of
the Governor,State of Alaska,Juneau,Alaska.
Ebasco Services,Inc.1982b.Natural Gas-Fired Combined-Cycle Power Plant
Alternative for the Railbelt Refion of Alaska.Prepared by Ebasco Services
Incorporated and Battelle,Paci ic Northwest Laboratories for the Office of
the Governor,State of Alaska,Juneau,Alaska.
Electric Power Research Institute (EPRI).1978.Preliminary Design Study for
an Intefirated Coal Gasification Combined-Cycle Power Plant.EPRI AF-880,
Researc ProJect 986=4,Electrlc Power Research Instltute,Palo Alto,
California.
Swift,W.H.1981.Alaska Coal:Future Availability and Price Forecasts.
Battelle,Pacific Northwest Laboratories,Richland,Washington.
Vogt,E.V.and M.J.Van der Burgt.1980."Status of the Shell-Koppers
Process."Chemical Engin~ering Processes,pp.65-72.
7.1