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Sutherland Generating Station
Unit 4
Prevention of Significant Deterioration
Air Permit Application
Prepared for:
Interstate Power and Light
Cedar Rapids, Iowa
Prepared by:
Black & Veatch Corporation
Overland Park, Kansas
October 2007
Black & Veatch Project No. 145491
Black & Veatch File No. 32.2010
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Table of Contents
Table of Contents
Acronym List ................................................................................................................AL-1
1.0
Introduction.......................................................................................................... 1-1
2.0
Project Characterization....................................................................................... 2-1
2.1
Project Location ....................................................................................... 2-1
2.2
Project Description................................................................................... 2-2
2.2.1
Existing Sutherland Generating Station .................................... 2-2
2.2.2
SGS Unit 4 Project Description................................................. 2-2
2.3
Project Emissions................................................................................... 2-10
2.4
Federal and State Air Quality Requirements ......................................... 2-11
2.4.1
New Source Review Applicability .......................................... 2-11
2.4.2
New Source Performance Standards ....................................... 2-15
2.4.3
National Emission Standards for Hazardous Air
Pollutants ................................................................................. 2-16
2.4.4
Title V Operating Permit ......................................................... 2-18
2.4.5
Compliance Assurance Monitoring......................................... 2-18
2.4.6
Chemical Accident Prevention ................................................ 2-18
2.4.7
Title IV Acid Rain Permit Program......................................... 2-19
2.4.8
Other Iowa State Requirements............................................... 2-20
2.4.9
Emission Standards for Contaminants..................................... 2-20
2.4.10 Provisions for Air Quality Emissions Trading Programs........ 2-20
2.4.11 Green House Gases (GHG) ..................................................... 2-22
3.0
Best Available Control Technology..................................................................... 3-1
3.1
BACT Methodology ................................................................................ 3-1
3.2
Summary of the BACT Determination .................................................... 3-2
4.0
Air Dispersion Modeling Protocol and Impact Analysis..................................... 4-1
4.1
Ambient Air Quality Impact Results ....................................................... 4-1
4.2
Additional Impacts Analysis.................................................................... 4-4
Appendix A
Appendix B
Appendix C
Appendix D
IDNR Application Forms
PSD Application Checklist
Fuel Analyses
System Descriptions
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Sutherland Unit 4 Air Permit Application
Table of Contents
Table of Contents (Continued)
Appendix E
Appendix F
Appendix G
Appendix H
Appendix I
Appendix J
Flow Diagrams and Site Drawings
Equipment Performance Data
Emission Calculations
BACT Analysis
Air Dispersion Modeling Protocol and Electronic Modeling Files
Site Evaluation Study – Coal Technology Assessment
Tables
Table 2-1
Table 2-2
Table 3-1
Table 3-2
Table 4-1
Table 4-2
Maximum Hourly Emission Rates and Project PTE.............................. 2-12
Comparison of Potential Annual Emissions from the Project to
the PSD Significant Emission Rates ...................................................... 2-13
BACT Determination Summary ............................................................... 3-3
Material Handling Particulate BACT Determinations............................. 3-6
Comparison of the Project’s Maximum Modeled Impacts with the
PSD Class II Modeling Significance and Monitoring de minimis
Levels....................................................................................................... 4-2
Comparison of the Ancillary Equipment’s Maximum Modeled
Impacts with the Short-Term NAAQS .................................................... 4-3
Figures
Figure 2-1
Figure 2-2
Overview of Project Location.................................................................. 2-1
SGS Unit 4 Proposed Air Quality Control Systems ................................ 2-6
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Acronym List
Acronym List
ACI
AQIA
amsl
BACT
bhp
bhph
Btu
CAA
CAIR
CAM
CAMR
CEMS
CO
DC Circuit
DESP
EGU
EP
FGD
GHG
H2S
H2SO4
HF
Hg
IAC
ID
IDNR
IPL
km
kW
lb
LMDCT
LNB/OFA
m3
MACT
MBtu
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Activated Carbon Injection
Air Quality Impact Analysis
Above Mean Sea Level
Best Available Control Technology
Brake Horsepower
Brake Horsepower Hour
British Thermal Unit
Clean Air Act
Clean Air Interstate Rule
Compliance Assurance Monitoring
Clean Air Mercury Rule
Continuous Emissions Monitoring System
Carbon Monoxide
District of Columbia Circuit
Dry Electrostatic Precipitator
Electric Generating Units
Emission Point
Flue Gas Desulfurization
Green House Gases
Hydrogen Sulfide
Sulfuric Acid
Hydrofluoric Acid
Mercury
Iowa Administrative Code
Induced Draft
Iowa Department of Natural Resources
Interstate Power and Light
Kilometers
Kilowatt
Pound
Linear Mechanical Draft Cooling Tower
Low NOx Boiler/Overfire Air
Cubic Meters
Maximum Achievable Control Technology
Million British Thermal Unit
AL-1
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
MW
NAAQS
NESHAPS
NO2
NOx
NSPS
NSR
PAC
PM/PM10
PRB
PSD
PSEU
PTE
RICE
RMP
SCPC
SCR
SGS
SIP
SO2
tpy
μg
USEPA
VOC
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Acronym List
Megawatt
National Ambient Air Quality Standards
National Emission Standards for Hazardous Air Pollutants
Nitrogen Dioxide
Nitrogen Oxides
New Source Performance Standard
New Source Review
Powdered Activated Carbon
Particulate Matter/Particulate Matter Less than 10 Microns
Powder River Basin
Prevention of Significant Deterioration
Pollutant Specific Emission Unit
Potential to Emit
Reciprocating Internal Combustion Engines
Risk Management Plan
Supercritical Pulverized Coal
Selective Catalytic Reduction
Sutherland Generating Station
State Implementation Plan
Sulfur Dioxide
Tons per Year
Microgram
United States Environmental Protection Agency
Volatile Organic Compound
AL-2
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
1.0 Introduction
Introduction
Interstate Power and Light (IPL) is proposing to construct and operate a new
649 megawatt (MW net) supercritical pulverized coal (SCPC) fired boiler (Unit 4) at its
existing Sutherland Generating Station (SGS) located in Marshalltown, Iowa. The
proposed SGS Unit 4 and supporting ancillary equipment will join the existing coal fired
boilers (Units 1, 2, and 3) and six fuel oil fired combustion turbine generating units at the
SGS. Pursuant to the requirements of Iowa Administrative Code (IAC) [567], Chapter 33
and 40 CFR Part 52.21, IPL is hereby submitting this Prevention of Significant
Deterioration (PSD) air permit application for the construction and initial operation of
SGS Unit 4 and associated equipment. The applicable air permit application forms and
PSD application checklist are included in Appendices A and B, respectively.
In addition to the new SGS Unit 4 boiler, the Project will include a new gas fired
auxiliary boiler; emergency diesel generator; diesel fire pump and booster pump engines;
gate station natural gas heater; a 16 cell linear mechanical draft cooling tower (LMDCT);
and various material handling and storage systems associated with the storage,
conveyance, and use of fuel, combustion byproducts, and reagents. New coal unloading,
storage, and conveyance systems will not only supply SGS Unit 4, but will be designed to
service the existing coal fired units as well. This design will allow the existing coal
unloading, storage, and reclaim systems to be retired when SGS Unit 4 becomes
operational. Apart from the retirement of the aforementioned existing coal handling
equipment, no other modifications to the existing generating units and permitted air
emissions sources are proposed as part of this Project, and are not considered to be
subject to PSD review as part of this air permit application.
The Project, which is designed to provide electricity to meet the increasing energy
requirements in the region (a detailed project description is provided in Section 2.2), is
scheduled to begin commercial operation in 2013. SGS Unit 4 will be designed to burn a
wide range of fuel supplies including Powder River Basin (PRB) sub-bituminous and
Eastern and Western bituminous coals and blends thereof, as well as potential inclusion
of biomass fuel. For the purposes of this application, two coal fuel types have been
utilized to represent and conservatively bracket the proposed range of coal fuel
characteristics for this Project. The representative coal fuel types are summarized below.
A detailed ultimate fuel analysis of each representative coal fuel, as well as the
performance and alternative coal fuels, is contained in Appendix C.
•
Rawhide Mine--PRB coal with a typical sulfur content of 0.33 percent or
0.794 lb SO2/MBtu.
•
Greater Belleville (Illinois Basin) Mine--Bituminous coal with a typical
sulfur content of 3.11 percent or 5.75 lb SO2/MBtu.
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Sutherland Unit 4 Air Permit Application
1.0 Introduction
From a regulatory basis, the Project will be considered a major modification
under the New Source Review (NSR) regulations and will be subject to the PSD preconstruction air permitting program. The purpose of this air permit application is to
provide the necessary preliminary design information to describe and characterize the
proposed Project and demonstrate its compliance with the applicable PSD air
construction permit standards and regulations. In addition to this introduction, this air
permit application package provides the following analyses and supporting information
as a basis for the Iowa Department of Natural Resources (IDNR) to grant an air
construction permit for the Project:
•
Project Characterization (Section 2.0).
•
Federal and State Air Quality Requirements (Section 2.4).
•
Best Available Control Technology (Section 3.0).
•
Air Dispersion Modeling Protocol and Impact Analysis (Section 4.0).
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2.0
2.0 Project Characterization
Project Characterization
This section characterizes the proposed Project, including a description of the
Project’s location, facility and equipment, emissions, and regulatory applicability.
2.1
Project Location
The Project will be located at IPL’s existing SGS, on the east side of
Marshalltown, Iowa, within Marshall County. The specific location of the Project is
illustrated on Figure 2-1. The SGS is situated along the southern side of an east-west reach
of the Iowa River near Marshalltown. The terrain encompassing the proposed site consists
mostly of agricultural flat land within the floodplain, with some gently rolling hills located
to the north and east. Areas surrounding the site are generally used for farming and
residential purposes near the City of Marshalltown.
Project
Location
IOWA
Project
Location
Base Map Source: www.topozone.com
USGS 7.5 Minute Quadrangle:
Le Grand, IA
Figure 2-1
Overview of Project Location
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2.0 Project Characterization
Grade elevation of the main structures of the Project will be approximately
863 feet above mean sea level (amsl). The Project’s stack height will be approximately
601 feet above grade, resulting in a stack-top elevation of 1,464 feet amsl.
The nearest Class I area is the Hercules Glades Wilderness Area located
approximately 590 km south of the Sutherland facility. Given the distant proximity of
the nearest Class I area, an analysis of the impact to Class I areas is not proposed for this
Project.
2.2
Project Description
2.2.1
Existing Sutherland Generating Station
The SGS currently has the capability to provide approximately 308 MW of power
by utilizing three coal fired and six fuel oil fired units. Units 1 and 2 are dry bottom
pulverized coal fired boilers with low NOx burners. Each unit has a rated capacity of
444 MBtu/h and is designed for approximately 32 MW of electrical generation. The
units are permitted to combust coal, petroleum coke, and natural gas. Units 1 and 2 have
been in operation since 1954 and 1955, respectively. Unit 3 is a cyclone furnace boiler
permitted to combust coal, petroleum coke, and natural gas. It was installed in 1961 and
has a rated capacity of 868 MBtu/h and is designed for approximately 82 MW of
electrical output. Additionally, the SGS has six 1978 vintage simple cycle combustion
turbines (operated in pairs), each with a rated capacity of 402 MBtu/h (approximately
54 MW each), permitted to burn fuel oil.
Apart from the retirement of the existing coal unloading, storage, and reclaim
systems when SGS Unit 4 becomes operational, no other modifications to SGS’s existing
emission sources are proposed as part of this Project.
2.2.2
SGS Unit 4 Project Description
The proposed Project will provide additional generating capacity to provide
electric energy to the transmission grid at Marshalltown, Iowa. The specific objective of
the electric generating unit is to provide reliable base loaded coal fired energy. To
achieve the objective of reliable generation, the Project is designed to burn a wide range
of fuel supplies from a combustion and environmental control perspective. The primary
coal supply is intended to be subbituminous coal from the Powder River Basin in the
states of Wyoming and Montana. It is anticipated that this supply of coal will, during
certain time periods, not be adequate to supply all of the low sulfur coal supply needed to
fire IPL’s current fleet of coal fired units. During these supply inadequacies, the Project
will switch, as needed, to alternate coal supplies that are available in the market place at
that time. IPL envisions that these supplies will be from other Western and Midwestern
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2.0 Project Characterization
mines producing subbituminous and bituminous coals. From a sulfur content and other
coal parameters perspective, Illinois Basin coal was identified to establish the Air Quality
System and boiler design which in turn will provide the necessary system flexibility to
utilize a wide range of coal supplies. To summarize, the intent of the Project is to utilize
a wide range of bituminous and subbituminous coals to produce electric energy at
Marshalltown, Iowa.
This section describes and explains the major components of the Project,
including the Unit 4 boiler; auxiliary boiler; gate station natural gas heater; emergency
diesel generator; diesel fire pump and booster pump engines; cooling tower; and various
material handling and storage systems associated with the storage, conveyance, and use
of fuel, combustion byproducts, and reagents. In addition to the descriptions provide
herein, more detailed engineering system descriptions, process flow diagrams, and site
drawings are provided in Appendices D and E to further assist in characterizing the
Project and its many components.
The emission point (EP) identification numbers are included in parentheses
following the equipment title of each piece of equipment. For reference and consistency,
the EP identification numbers are used throughout this application, including the IDNR
application forms, site arrangement, and emission calculation spreadsheets, to reference
the Project’s proposed emission sources.
As depicted in the overall site arrangement included in Appendix E, SGS Unit 4
and its supporting equipment (including an onsite coal combustion byproducts storage
area) will be located to the south and southwest of the existing units at the SGS. While
application for the construction of the landfill will be made under separate cover, the
material handling activities associated with operation of the landfill (truck hauling,
material dumping, maintenance, etc.) have been accounted for in this application.
SGS Unit 4 SCPC Boiler (EP-248)
SGS Unit 4 will be a 649 MW (net) SCPC boiler with a maximum design heat
input of 6,326 MBtu/h. The SCPC technology offers superior boiler efficiency over
convention subcritical boilers due to the increased steam pressure. More detailed
information regarding the advantages of SCPC technology is included in Appendix J, Site
Evaluation Study - Coal Technology Assessment. The boiler will be designed to burn a
wide range of fuel supplies including PRB, Eastern, and Western bituminous coals and
blends thereof, as well as potential inclusion of biomass fuel. For purposes of this permit
application, the biomass blends is limited to 5 percent of the overall fuel input on a heat
content basis. From the technical review performed to date, no negative impact to overall
emissions was identified that could be associated with the use of biomass as a fuel.
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2.0 Project Characterization
Coal will be delivered to the site by rail car, where it will be unloaded, conveyed,
and stacked out in a new coal storage yard. The coal will be reclaimed and transferred
via conveyors to five new Unit 4 coal storage silos. Coal mills (called pulverizers) will
crush the coal to reduce it to the size required for efficient combustion. Pressurized air
will transport the pulverized coal from the pulverizers to the boiler’s burners. At the
burners, the coal will be mixed with additional air, and the mixture will be ignited. The
burners will be specially designed to produce low levels of NOx and promote efficient
combustion. The coal and air mixture will be burned in the area of the boiler called the
furnace.
The furnace combustion process will produce steam, which is generated in the
boiler by heating water. A boiler can be thought of as a large box that contains a burning
coal/air mixture, with the walls of the box consisting of a large number of tubes, through
which water and steam flow. Within the various sections of the boiler tubes, the water,
which is delivered to the boiler inlet, will be heated and converted to steam at the
pressure and temperature required for admission into the steam turbine. The steam
turbine generator will then generate electricity.
Before exiting to the atmosphere, the flue gas will go through a series of air
quality control devices designed to remove air contaminants from the exhaust gas. These
devices, including a selective catalytic reduction (SCR) system, fabric filter, and wet flue
gas desulfurization (FGD) system are explained in detail in Section 3.0 (Best Available
Control Technology [BACT] analysis) and are described below as a brief overview.
An SCR system will be the first of these air quality control devices and will use
ammonia in the presence of a catalyst to control the levels of NOx in the flue gas. The
SCR system reduces NOx by injecting ammonia into the exhaust gas upstream of a
catalyst bed, which converts NOx into inert nitrogen and water before leaving the stack.
The ammonia used in the SCR will be either urea or aqueous ammonia (less than 19
percent concentration).
The exhaust gas stream from the SCR will pass through the air heater and then to
a dry electrostatic precipitator (DESP). The DESP will be installed for the purpose of
beneficial reuse of fly ash and is not intended as the primary particulate control device.
The DESP will collect fly ash that can be used as an ingredient in commercial concrete or
reused by other industries (such as cement manufacturers). Fly ash that is reused will not
require disposal space in the onsite byproduct storage area.
An ESP is essentially a large enclosure placed in the ductwork between the air
heater and the induced draft (ID) fan that contains a series of charged electrodes and
parallel steel plates spaced approximately 12 to 16 inches apart. The ESP negatively
charges the electrodes and positively charges the plates to create a voltage differential.
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2.0 Project Characterization
As the particulate-laden flue gas passes between the plates and the electrodes, the ash
particles become negatively charged. The particles then migrate to the positively charged
plate, where the ash accumulates. At periodic intervals, rapping of the plates removes the
accumulated ash from the ESP, causing the accumulated ash to be collected in a hopper
for either disposal or beneficial reuse.
The exhaust gas stream from the DESP will next be ducted to a fabric filter
baghouse dust collector. The fabric filter uses fabric bags as filters to collect particulate.
The particulate-laden flue gas enters a fabric filter baghouse compartment and passes
through a layer of particulate and filter bags. The collected particulate forms a cake on
the bag, which enhances the bag’s filtering efficiency. The pressure drop across the bags
increases as the thickness of the dust cake increases. At a predetermined pressure drop
set point, the filtering bags are cleaned, dislodging a large portion of the dust cake for
collection and disposal. Mercury emissions will be controlled by a combination of fuel
blending, co-benefit control from post-combustion air quality control equipment, and
activated carbon injection (ACI) upstream of the fabric filter to meet NSPS Subpart Da
mercury emission limits. Activated carbon adheres to the mercury, allowing it to be
captured and removed by the fabric filter system.
Exhaust gas will exit the fabric filter to an FGD system. The FGD system uses
either a lime or limestone reagent in a “shower-like” or “bath-like” flue gas contact
process to scrub SO2 from the exhaust stream. Finally, the cleaned-up flue gas will
exhaust to the atmosphere through a new chimney constructed for SGS Unit 4. A block
flow diagram of the proposed air quality control systems is presented on Figure 2-2.
While SGS Unit 4 is being proposed as a base load unit and being permitted for
unlimited annual operation, the unit will be required to shut down and start up
periodically, depending on load requirements and maintenance. The boiler will be
designed to initially start up on natural gas until the load on the boiler reaches
approximately 10 percent, after which coal will be introduced into the boiler in
combination with the startup fuel for stabilization, until the boiler reaches approximately
25 percent of load.
Auxiliary Boiler (EP-249)
The Project will include a new auxiliary steam boiler to be used during startup of
the main boilers at the SGS, during periods when the main boilers are offline, and to
supply steam for onsite building heat and services. The auxiliary boiler fuel source will
be natural gas and its maximum heat input will be limited to 270 MBtu/h. The auxiliary
boiler is expected to operate no more than 2,000 hours per year.
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2.0 Project Characterization
Ammonia
Sorbent
Silo
Economizer
Steam
Generator
SCR
Air
Heater
Fabric
Filter
Dry ESP
AC
Silo
Bottom
Ash
Fly Ash
FGD
ID Fans
Fly Ash
Silo
(Saleable)
Stack
Hydro cyclones
Lime stone
Silo
Fly Ash
Silo
(Waste)
Ball
Mill
Vacuum
Filters
Reagent
Slurry
Tank
Reclaim
Water
Tank
Gypsum
Figure 2-2
SGS Unit 4 Proposed Air Quality Control Systems
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Gate Station Heater (EP-297)
Natural gas will be used during startup for both the new and existing boilers at the
SGS and will be the primary fuel for the new auxiliary boiler. The natural gas supply to
the SGS will arrive via a high-pressure natural gas pipeline. As the natural gas is
extracted from the high-pressure pipeline, a reduction in pressure will naturally cool the
gas to a temperature that is too low to be combusted in the boilers. As such, a natural gas
fired gate station heater will be used to reheat the natural gas back to a usable
temperature. The gate station heater will have a maximum heat input limit of 3 MBtu/h
and designed for continuous operation.
Emergency Generator (EP-250)
In the event of a loss of normal auxiliary power, AC power will be supplied by a
new 2,000 brake horsepower (bhp), 2,000 kilowatt (kW), No. 2 distillate fuel oil fired
emergency generator. The emergency generator will be periodically tested for
approximately 1 to 2 hours per week (typical) to confirm its ready-to-start condition. The
emergency generator is expected to operate no more than 100 hours per year for normal
testing and maintenance.
Fire Pump and Booster Fire Pump Engines (EP-251 and 252)
Pressurized fire water will be supplied by a new fire pump engine and fire booster
pump engine rated at 575 bhp and 149 bhp, respectively. These engines will burn No. 2
distillate fuel oil. Similar to the emergency generator, the fire pump engines will be
periodically tested for approximately 1 to 2 hours per week (typical) to confirm their
ready-to-start condition. The fire pump engines are expected to operate no more than
100 hours per year (each) for normal testing and maintenance.
Cooling Tower (EP-253)
The Project will utilize a new 16 cell LMDCT to dissipate waste heat from the
boiler’s steam cycle. The basic principle behind all cooling towers is to cool water using
ambient air. Circulating cooling water will remove heat from the steam, causing it to
condense. The heated circulating cooling water is transported to the cooling tower to
dissipate the heat into the atmosphere. The circulating water is sprayed into the cooling
tower as a coarse mist that cascades down a fill material. As the circulating water falls,
air contacts the water, allowing a transfer of heat from the water to the cooler
atmospheric air. The cooled circulating water is then collected in the cooling tower
basin, where it is pumped from the cooling tower back to the condenser water boxes,
repeating the process.
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During the cooling process, small water droplets, known as cooling tower drift,
escape to the atmosphere through the cooling tower exhaust. To minimize this effect, the
cooling tower will be equipped with drift eliminators to minimize the escaping water
droplets.
Material Handling – Coal (EP-254 through 279)
The existing material handling equipment for coal unloading, stockout, and
reclaim will be not be used for the operation of SGS Unit 4. Instead, a new coal
unloading, stockout, and reclaim system will be installed, replacing the existing one, to
accommodate the operation of SGS Unit 4 and existing Units 1 through 3.
The coal will be supplied by rail to the facility where is will be unloaded and sent
to the coal yard storage area via new stockout conveyors. The coal yard will consist of
active and inactive piles. Coal will be initially unloaded at a new rail car unloading
building and stocked out to the active pile areas via a stacker reclaimer system, and as
necessary, pushed to an inactive pile via bulldozers for long-term storage based on the
facility’s coal needs. Coal will be reclaimed via the stacker reclaimer, which will drop
the coal onto a new reclaim conveyor for transfer to either the coal blending area or
directly to the crusher house. At the crusher house, the coal will be reduced in size and
transferred to the SGS Unit 4 coal storage silos.
Coal for the existing units will be reclaimed via a new underground reclaim
system and transferred via conveyor to an existing coal yard transfer tower near Units 1
through 3. From that point, existing coal delivery equipment will continue to be utilized
to supply the coal to existing Units 1 through 3. The existing facility’s coal unloading,
stockout, and reclaim systems will be retired when SGS Unit 4 becomes operational.
As further described in the BACT analysis (Section 3.0), dust collectors, water
suppression, telescopic chutes, and partial or full enclosures will be utilized to control
point and fugitive dust emissions from the coal material handling systems.
Material Handling – Limestone (EP-280 through 285)
Limestone will be delivered to the plant either by rail car or truck for use in SGS
Unit 4’s wet FGD scrubber system. Limestone will be unloaded at a new limestone
unloading building and stocked out to an active pile storage area via a conveyor system,
and then as necessary, pushed to an inactive pile via bulldozers for long-term storage
based on the facility’s usage. Limestone will be reclaimed via an underground reclaim
system and conveyed to two limestone storage silos. From the storage silos, limestone
will be fed to a ball mill and processed to a slurry before for being sent to the wet FGD
system.
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2.0 Project Characterization
As further described in the BACT analysis (Section 3.0), dust collectors, water
suppression, telescopic chutes, and partial or full enclosures will be utilized to control
point and fugitive dust emissions from the limestone material handling systems.
Material Handling – Fly Ash (EP-286 through 290)
The fly ash handling system will remove fly ash waste collected from the
economizer, air heater, SCR, and the fabric filter ash hoppers for disposal, as well as
from the DESP ash hoppers for beneficial reuse as previously described. The system will
transfer fly ash material from the individual collection hoppers to either a saleable or nonsaleable fly ash storage silo. The saleable ash can also be placed in a new winter ash
storage building.
Saleable fly ash will either be loaded into closed ash hauling trucks and rail cars
and transported offsite for beneficial reuse, or conditioned and loaded into dump trucks
for placement in the onsite byproducts storage area. Saleable fly ash stored in the winter
storage building can be reclaimed via an underground reclaim system and loaded into
closed ash hauling trucks. The non-saleable fly ash will be conditioned and loaded into
dump trucks for disposal in the onsite byproducts storage area.
As further described in the BACT analysis (Section 3.0), dust collectors, water
suppression, telescopic chutes, and partial or full enclosures will be utilized to control
point and fugitive dust emissions from the fly ash material handling systems.
Material Handling – Bottom Ash
The bottom ash material handling system will remove bottom ash from the steam
generator furnace and collect coal pulverizer rejects via a submerged scrapper conveyor.
The bottom ash will then be conveyed up a dewatering slope and discharged into a threesided, ground level, outdoor concrete storage bunker. From the bunker, the bottom ash
will be loaded into ash dump trucks for offsite sales or transported directly to the onsite
byproducts storage area.
The bottom ash takes the form of a wet solid material (20 to 30 percent moisture
content), and while dewatered, remains moist during all handling, conveyance, storage,
and disposal operations. As such, the bottom ash material handling system is not a
source of fugitive dust, other than that associated with the truck transportation haul road.
Material Handling – Wet FGD Waste
The wet FGD waste handling system will remove wet FGD scrubber waste (also
known as gypsum) from the scrubber system. Twin vacuum belt filters will remove
excess water, and the moist material will then be conveyed to a storage building. From
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2.0 Project Characterization
the storage building, the gypsum will be loaded into trucks and either transported offsite
for beneficial reuse as wall board or disposed of onsite in the byproduct storage area.
The wet FGD scrubber waste takes the form of a wet solid material (10 to
15 percent moisture content), and while dewatered, remains moist during all handling,
conveyance, storage, and disposal operations. As such, the wet FGD scrubber waste
material handling system is not a source of fugitive dust, other than that associated with
the truck transportation haul road.
Material Handling – Other – PAC, Sorbent, Lime, and Biomass (EP-291
through 296)
The transportation and handling of various materials associated with bulk material
storage, material delivery, and material disposal within the site boundaries or offsite will
result in particulate emissions. These include, for example, truck deliveries (onsite or
offsite, as applicable) of limestone, ash, FGD solids, coal, ammonia, powdered activated
carbon (PAC), lime, and sorbent materials, as well as bulk material storage piles and
storage pile maintenance.
The following is contained in a summary of various other material handling
activities included in this application as part of the Project:
2.3
•
Haul roads for material deliveries and disposal.
•
Active and inactive coal storage piles.
•
Active and inactive limestone storage piles.
•
Material storage silos.
•
Saleable fly ash winter storage pile.
•
Front-end loader/bulldozing activities for loading/unloading materials and
pile maintenance.
•
Biomass fuel material handling.
Project Emissions
The Project’s controlled emissions are presented in Table 2-1, including the
maximum hourly and annual potential to emit (PTE) emissions associated with following
proposed new sources as previously described.
•
SGS Unit 4, 649 MW (net) SCPC boiler.
•
One Auxiliary Boiler, 270 MBtu/h Maximum Heat Input, Natural Gas
Fired.
•
One Gate Station Heater, 3 MBtu/h Maximum Heat Input, Natrual Gas
Fired.
•
One Emergency Generator, 2,000 bhp, Diesel Fuel Fired.
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•
One Fire Pump Engine, 575 bhp, Diesel Fuel Fired.
•
One Fire Booster Pump Engine, 149 bhp, Diesel Fuel Fired.
•
16 Cell LMDCT.
•
Coal Material Handling Equipment.
•
Fly Ash, Bottom Ash, and Wet FGD Scrubber Waste Material Handling
Equipment.
•
PAC, Lime, Sorbent Material Handling, and All Haul Road Transportation.
The basis, performance data, assumptions, and calculations used to estimate the
Project’s emissions presented in Table 2-1 are contained in Appendices F and G. In
summary, the emissions are based on worst case fuel and 100 percent capacity factor
assumptions for the main boiler and material handling emission estimates, using
controlled boiler emission estimates and United States Environmental Protection Agency
(USEPA) AP-42 material handling emission factors. Ancillary equipment, such as the
auxiliary boiler, emergency generator, fire pumps, and gate station heater, are based on
representative manufacturers’ data and USEPA AP-42 emission factor estimates, as well
as the maximum proposed annual hours of operation of the equipment.
In Table 2-2, the Project’s aggregate annual PTE is presented and compared to the
applicable PSD significant emission rates to determine which of the Project’s criteria
pollutants are subject to PSD review, as further discussed in Section 2.4.
2.4
Federal and State Air Quality Requirements
Air quality permitting in Iowa is under the jurisdiction of the IDNR. The USEPA
has given the IDNR authority to implement and enforce the federal Clean Air Act (CAA)
provisions and state air regulations under its approved State Implementation Plan (SIP).
The following subsections discuss the applicable federal and state air quality programs,
regulations, and standards.
2.4.1
New Source Review Applicability
The federal CAA NSR provisions are implemented for new major stationary
sources and major modifications under two programs: the PSD program outlined in
40 CFR 51 and 52.21, and the Nonattainment NSR program outlined in 40 CFR 51 and
52. The project site is in an attainment or unclassifiable area with respect to all
pollutants. As such, the PSD program will apply to the Project, as administered by the
state of Iowa under Chapter 33 of Section 567 of the Iowa Administrative Code (IAC
567-Chapter 33).
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Table 2-1
Maximum Hourly Emission Rates and Project PTE
Unit 4
PC Boiler
Emissions(a,c)
(lb/h)
Auxiliary
Steam Boiler
Emissions
(lb/h)
Emergency
Generator
Emissions
(lb/h)
Gate Station
Heater
(lb/h)
Fire Pump
Engine
(lb/h)
Fire Booster
Pump Engine
(lb/h)
Project PTE(b)
(tpy)
NOx
316.3
9.94
20.94
0.14
6.21
1.71
1,398
PM/PM10
113.9
1.88
0.12
0.02
0.10
0.06
517
SO2
506.1
0.16
0.49
0.002
0.20
0.07
2,217
H2SO4
25.3
0.25
0.74
0.003
0.31
0.10
111
CO
759.1
19.88
1.72
0.14
0.95
0.11
3,346
VOCs
21.5
1.34
0.87
0.02
0.37
0.12
95.7
0.000001
0.00004
0.00001
0.51
0.001
0.0004
4.80
Pollutant
Lead
Fluorides
(e)
0.115
1.1
(d)
0.0001
0
0.00009
(g)
0.003
(g)
(f)
0
(g)
H2S
0(g)
0(g)
0(g)
0(g)
0(g)
0(g)
0(g)
Total Reduced
Sulfur
0(g)
0(g)
0(g)
0(g)
0(g)
0(g)
0(g)
(a)
Based on engineering design for two coal fuels, for a unit load of 100 percent of maximum capacity.
Project controlled PTE based on 8,760 hours of operation per year for Unit 4 boiler; 2,000 hours of operation per year for the auxiliary boiler
and 100 hours of operation per year for the emergency generator and fire pump and fire pump engines, and includes PM10 emissions from the
material handling sources, cooling tower, and haul roads.
(c)
Based on a maximum boiler heat input of 6,326 MBtu/hr.
(d)
Based on the fluoride portion of the hydrofluoric acid (HF) emissions.
(e)
Lead based on fuel analysis.
(f)
Estimated based on AP-42 emission factor.
(g)
Emissions are insignificant and assumed to be zero.
(b)
Note: Detailed calculations are contained in Appendix G.
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Table 2-2
Comparison of Potential Annual Emissions from the Project to the
PSD Significant Emission Rates
Total Project Potential
Annual Emissions(a)
(tons/year)
PSD Significant
Emission Rate
(tons/year)
PSD Review
Required?
(Yes/No)
1,398
40
Yes
517
25/15
Yes
2,217
40
Yes
111
7
Yes
3,346
100
Yes
95.7
40
Yes
0.51
0.6
No
Fluorides
4.80
3
Yes
H2S
0(e)
10
No
(e)
10
No
Pollutant
NOx
PM/PM10(b)
SO2
H2SO4
CO
VOCs
Lead
(c)
(d)
Total Reduced Sulfur
0
(a)
Total Project Potential Annual Emissions are from Table 2-1.
PM/PM10 includes the material handling equipment, cooling tower, and haul roads.
(c)
Lead based on controlled AP-42 emission factor.
(d)
Based on the fluoride portion of the HF emissions.
(e)
Emissions are insignificant and assumed to be zero.
(b)
Note: Detailed emission calculations are contained in Appendix G.
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The PSD regulations are designed to ensure that the air quality in existing
attainment areas does not significantly deteriorate or exceed the national ambient air
quality standards (NAAQS), while providing a margin for future industrial and
commercial growth. PSD regulations apply to major stationary sources and major
modifications at existing major sources undergoing construction in areas designated as
attainment or unclassifiable. The primary provisions of the PSD regulations require that
major modifications and new major stationary sources be carefully reviewed prior to
construction to ensure compliance with the NAAQS, the applicable PSD air quality
increments, and the requirements to apply BACT to minimize the emissions of air
pollutants.
A major stationary source is defined as any one of the listed major source
categories which emits, or has the PTE, 100 tpy or more of any regulated pollutant, or
250 tpy or more of any regulated pollutant if the facility is not one of the listed major
source categories. Because the SGS is one of the major source categories (i.e., fossil fuel
fired boilers with greater than 250 MBtu/h heat input), and has a PTE of greater than 100
tpy for at least one regulated pollutant, it is classified as a major stationary source.
As the Project will be located at an existing major stationary source, PSD review
is required for all pollutants for which the PTE is greater than the PSD significant
emission rates. As shown in Table 2-2, the estimated potential emissions of NOx, SO2,
CO, PM/PM10, VOC, H2SO4, and fluorides resulting from the Project exceed their
respective PSD significant emission rates. Therefore, the Project’s emissions of those
criteria pollutants are subject to PSD review. Pending final rules related to the
implementation of NSR for PM2.5, the USEPA (in an October 1997 memorandum), has
authorized the use of PM10 as a surrogate for PM2.5. This application incorporates
USEPA’s PM2.5 NSR guidance. The PSD review includes a BACT analysis, air quality
impact analysis (AQIA), and an assessment of the Project’s total impact on general
residential and commercial growth, soils and vegetation, and visibility. These analyses
are included in Sections 3.0 and 4.0 of this application, respectively.
Based on comments received from IDNR during the September 24, 2007
preapplication meeting, IPL understands that PSD air construction permits typically
expire in 36 months from issuance. As this Project’s construction schedule is estimated
to take 45 to 48 months, IPL hereby requests a 48 month PSD air construction permit
expiration date.
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2.4.2
New Source Performance Standards
Standards of Performance for New Stationary Sources are contained in 40 CFR
Part 60 and adopted by reference in IAC 567-23. These standards are commonly referred
to as new source performance standards (NSPS). The following NSPSs and their
associated emission limitations are applicable to the proposed Project.
2.4.2.1 NSPS Subpart Da – Standards of Performance for Electric Utility
Steam Generating Units for Which Construction is Commenced After
September 18, 1978. As an electric utility steam generating unit with greater than
250 MBtu/h heat input, the Project’s 648 MW (net) coal fired boiler will be subject to
NSPS Subpart Da. NSPS Subpart Da includes new source emission limitations for
certain NSR/PSD pollutants, including SO2, NOx, and PM/PM10, as well as Hg. The
applicable NSPS Subpart Da emission limitations for the coal-fired boiler are as follows:
•
SO2: 1.4 lb/MWh (gross energy output) or 95 percent removal rate.
•
NOx: 1.0 lb/MWh (gross energy output)
•
PM/PM10: 0.14 lb/MWh (gross energy output) or 0.015 lb/MBtu
•
Hg:
−
66 x 10−6 lb/MWh (gross energy output) when firing subbituminous coal.
−
20 x 10−6 lb/MWh (gross energy output) when firing bituminous
coal.
−
Equation 1 of §60.45Da(a)(5)(i) for a blend of coals.
Installation of BACT controls on the new boiler will ensure compliance with the
requirements of this regulation.
2.4.2.2 NSPS Subpart Db – Standards of Performance for IndustrialCommercial-Institutional Steam Generating Units. As a steam generating unit
with greater than 100 MBtu/h, the Project’s 270 MBtu/h natural gas fired auxiliary boiler
will be subject to NSPS Subpart Db. NSPS Subpart Db includes new source emission
limitations for certain NSR/PSD pollutants including NOx, SO2, and PM/PM10. For the
natural gas fired boiler, the only applicable emission limit is 0.20 lb/MBtu of NOx (as
NO2). Compliance with NOx BACT will ensure compliance with the NSPS requirement.
Other requirements under NSPS Subpart Db include keeping records of the fuel usage
and the annual capacity factor.
2.4.2.3 NSPS Subpart IIII – Standards of Performance for Stationary
Compression Ignition Internal Combustion Engines. The Project’s emergency
diesel generator and the two emergency fire pumps will be subject to the manufacturer’s
certification requirements of compliance to NSPS Subpart IIII. The rule provides various
emission standards based on the engine’s classification, use, manufacture date, and
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engine size. The applicable standards associated with the emergency generator will be
dependent on the engine model year. Therefore, the exact emission standards applicable
to the emergency black start engine cannot be identified until the engine is purchased.
Similarly, the fire pump engines will need to meet the emission requirements listed in
Table 4 of this regulation.
Beginning with engines manufactured in model year 2007 (emergency engines)
and 2008 (fire pump engines), the onus of this rule falls on the manufacturer of these
engines as they are required to manufacture engines that comply with the rule. The
requirement of this rule for owners and operators of these units is that they purchase
certified engines. IPL will purchase certified engines that will meet the appropriate
emission limits.
2.4.2.4 NSPS Subpart Y – Standards of Performance for Coal Preparation
Plants. The coal handling system is subject to the NSPS requirements for coal
preparation plants, 40 CFR 60, Subpart Y, Standards of Performance for Coal
Preparation Plants, because it is an applicable facility as defined under Subpart Y. The
coal processing and conveying equipment and coal storage systems, except for open
storage piles, are subject to a 20 percent opacity standard in accordance with 40 CFR
60.252(c). Implementation of BACT controls on the material handling processes will
ensure compliance with this limitation.
2.4.2.5 NSPS Subpart OOO – Standards of Performance for Nonmetallic
Mineral Processing Plants. A wet FGD system will be installed to control emissions
of SO2 from the new boiler. Wet FGD systems use limestone slurry for desulfurization
and, therefore, require limestone handling, transfer, and storage to ensure proper
operation. The slurry is created from limestone which is delivered to the site via
pneumatic delivery truck or railcar. The limestone storage, transfer, and grinding
operations will be subject to NSPS Subpart OOO. NSPS Subpart OOO includes new
source limitations for PM/PM10. The applicable NSPS Subpart OOO emission limitation
for the limestone handling operation is to not exceed stack opacity of 7 percent opacity.
Implementation of BACT controls on the material handling processes will ensure
compliance with this limitation.
2.4.3
National Emission Standards for Hazardous Air Pollutants
National Emission Standards for Hazardous Air Pollutants (NESHAPS) are
contained in 40 CFR Part 63 and adopted by reference in IAC 567-23 and are emissions
standards set by the USEPA for particular source categories. These categories require the
maximum degree of emission reduction of certain HAPs that the EPA determines to be
achievable, which is known as the Maximum Achievable Control Technology (MACT).
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In fact, these standards are commonly referred to as the MACT standards. The following
MACT standards are applicable to the proposed Project.
2.4.3.1 NESHAP Subpart DDDDD – Industrial, Commercial, and Institutional
Boilers and Process Heaters. The Project’s 270 MBtu/h auxiliary boiler would
have been an affected source under the Industrial Boiler MACT, which was promulgated
on September 13, 2004. The auxiliary boiler, based on its heat input rating and capacity
factor, would have been considered a new large gas fuel boiler under this MACT. On
June 8, 2007, the United States Court of Appeals for the District of Columbia Circuit (DC
Circuit) vacated the Boiler MACT in its entirety. Subsequently, this ruling was mandated
by the Court on July 30, 2007, which means that there is currently no Industrial Boiler
MACT standard in place. A resolution to this issue may include a MACT 112(g) or
112(j) analysis of the auxiliary boiler. Since the outcome of the Boiler MACT vacatur is
not clear, IPL will await further direction from the USEPA and IDNR on this issue.
2.4.3.2
NESHAP Subpart ZZZZ – Stationary Reciprocating Internal
Combustion Engines. Currently, the Stationary Reciprocating Internal Combustion
Engines (RICE) MACT is applicable to stationary RICE greater than 500 bhp located at a
major HAP source (e.g., the SGS). The Project’s emergency diesel generator and the
main fire water pump will be greater than the 500 bhp applicability threshold. However,
a new emergency stationary RICE located at a major HAP source is subject only to the
initial notification requirements of 40 CFR 63.6645(d). Since the purpose of the
emergency diesel generator will be for emergency situations when the normal source of
power is not available to the facility, and the fire pump will be used during a fire to pump
water, these engines will be considered as “emergency” stationary RICE and, therefore,
subject only to the initial notification requirements of the RICE MACT.
2.4.3.3 NESHAP Subpart Q – Industrial Process Cooling Towers. This rule’s
standard prohibits the use of chromium-based water treatment chemicals in industrial
process cooling towers. The Project will not use chromium-based water treatment
chemicals.
2.4.3.4 Coal and Oil Fired Electric Utility Steam Generating Units. On
March 15, 2005, the USEPA signed the final rule titled, “Revision of December 2000
Regulatory Finding on the Emissions of Hazardous Air Pollutants From Electric Utility
Steam Generating Units and the Removal of Coal- and Oil-fired Electric Utility Steam
Generating Units from the Section 112(c) List.” In this rule, the USEPA determined that
it was not appropriate or necessary to regulate coal and oil fired utility units under
Section 112 of the CAA, and thus, removed those utility units from the section list of
source categories. The USEPA effectively concluded that utility HAP emissions
remaining after the implementation of other requirements of the CAA (e.g., CAMR) do
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not cause hazards to public health that would warrant regulation under Section 112. As
such, the SGS Unit 4 boiler is not required to perform a case-by-case MACT analysis.
2.4.4
Title V Operating Permit
40 CFR Part 70, Title V of the CAA established an air quality operating permit
program that provides a central point for tracking all applicable air quality requirements
for every source required to obtain a permit. Each state was also required to establish a
Title V Operating Permit Program. IAC 567-Chapter 22.101, Applicability of Title V
Operating Permit Requirements, establishes such a program. IPL will follow IAC 567Chapter 22.105a, Timely Application, which requires owners or operators of subject
facilities to submit a Title V modification application within 3 months after initial startup
of the new emission units.
2.4.5
Compliance Assurance Monitoring
The USEPA established criteria that defines what monitoring should be conducted
by a source owner or operator to provide a reasonable assurance of compliance with
emission limits and standards, to certify compliance under the Title V Operating Permit
Program. A compliance assurance monitoring (CAM) plan, in accordance with 40 CFR,
Part 64, is a required element of the Title V permit, if such a plan applies. CAM applies
to each pollutant specific emission unit (PSEU) that meets the following three conditions:
•
Is subject to an emission limitation or standard, and
•
Uses a control device to achieve compliance, and
•
Has pre-control emissions that exceed or are equivalent to the major
source threshold.
Pre-controlled emissions of PM10 and H2SO4 mist from the Project will be above
their respective major source thresholds and will be subject to an emission limitation.
Additionally, these emissions will be controlled by add-on control devices. Emissions of
SO2 and NOx are regulated under the acid rain rule and can be excluded from the CAM
rule. CAM will be addressed in the application for the Title V modification discussed
above.
2.4.6
Chemical Accident Prevention
40 CFR Part 68, Accidental Release Prevention Provisions, under CAA Section
112(r), Prevention of Accidental Releases, establishes a general duty for owners and
operators of stationary sources who produce, process, handle, or store any of a number of
regulated substances, to prevent and mitigate accidental releases of these substances by
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preparing detailed risk assessments and implementing a number of safety procedures
through the preparation of a risk management plan (RMP).
The specific requirements of the RMP for affected facilities are established in
40 CFR Part 68, Accidental Release Prevention Provisions. These regulations require the
owner or operator of an affected source to prepare and implement an RMP to detect and
prevent or minimize accidental releases of regulated substances, and to provide a prompt
emergency response to any such release to protect human health and the environment.
Affected facilities are those stationary sources that store, use, or handle any of
140 listed hazardous chemicals or flammable/explosive substances in amounts greater
than the listed threshold quantities. This list of regulated substances includes commonly
stored liquid phases of gases such as ammonia, which the SGS may store at quantities
near or above the threshold levels. Ammonia would be used in conjunction with the SCR
for NOx control.
The RMP is generally composed of three sections, including a hazard assessment,
a prevention program, and an emergency release response program. For affected
facilities, submittal of the comprehensive RMP is required by the later of the following
dates:
•
Three years after the date when a regulated substance is listed.
•
The date on which a regulated substance is first present above the
threshold quantity at the facility.
The Project’s SCR will use aqueous ammonia at less than 20 percent concentration. As such, no RMP will be required for the Project’s use of ammonia.
2.4.7
Title IV Acid Rain Permit Program
Title IV of the CAA imposes stringent requirements on electrical utilities and is
enforced through the administration of the Title IV Acid Rain Permit Program, which is
designed to achieve reductions in emissions of SO2 and NOx. The centerpiece of the
Title IV program is the establishment of an SO2 emissions allowance and trading
program.
The Title IV requirements are applicable to “affected” units, and affected units are
then classified as Phase I (1995 to 1999) or Phase II (2000 to present). The Project will
qualify as a Phase II acid rain new affected unit, subject to the following general
requirements:
•
Duty to apply for an Acid Rain Permit: Acid rain permit applications for
new units are due 24 months before the unit commences operation. An
Acid Rain Permit application will be submitted accordingly, in the
applicable time frame.
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Duty to obtain allowances: Emission allowances will be obtained as
required by the acid rain provisions.
•
Installation, operation, and certification of Continuous Emissions Monitoring Systems (CEMs): CEMs will be installed as required by the acid rain
provisions.
In addition to the above requirements, the contents of the Acid Rain Permit will
be incorporated into the modified Title V Operating Permit discussed previously. The
acid rain requirements are incorporated in IAC 567-22.125.
2.4.8
Other Iowa State Requirements
As mentioned earlier, the IDNR has permitting and review authority for all air
quality projects in Iowa through the USEPA-approved SIP. Additionally, IDNR has
promulgated regulations for new and modified air pollutant sources, which are published
in IAC Section 567-Chapters 20 through 34. Several of these regulations have already
been addressed earlier, since they incorporate federal regulations by reference. Other
applicable state regulations not previously discussed are presented below.
2.4.9
Emission Standards for Contaminants
IAC 567-23.3(2)(c), Fugitive Dust, stipulates that no person shall cause, suffer, or
allow any material to be handled, processed, transported, or stored; a building or its
appurtenances to be constructed, altered, repaired, or demolished; or a road to be used
without taking reasonable precautions to prevent particulate matter from becoming
airborne and to prevent visible fugitive dust at the property line.
Fugitive dust will be produced from the Project’s material handling, storage,
conveying, and hauling systems. IPL will comply with this regulation by applying water
or other suitable chemicals on roads, materials stockpiles, and other surfaces that can
create airborne dusts. Wherever applicable, IPL will install and use enclosures, fans, and
fabric filters to enclose and vent the handling of dusty materials, or use water sprays or
other measures to suppress fugitive dust emissions.
2.4.10 Provisions for Air Quality Emissions Trading Programs
IAC 567-34 implements the provisions for certain federal air emissions trading
programs to control emissions of specific pollutants. Two such programs that are
applicable to the Project are discussed below.
2.4.10.1 Clean Air Interstate Rule (CAIR). On May 12, 2005, the USEPA
promulgated the CAIR to address interstate transport of SO2 and NOx emissions from
eastern and midwestern states, including Iowa, which were found to contribute to
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unhealthy levels of fine particles and ozone in downwind states. Although Iowa is
currently in attainment for all NAAQS, it is included in the CAIR provisions because the
USEPA found that Iowa’s emissions contribute to downwind nonattainment of air quality
standards. As such, Iowa is required to meet the USEPA-prescribed emission targets in
two phases. The first phase begins in 2009, while the second phase begins in 2015.
The federal rule provided two options by which affected states could adopt the
CAIR: 1) adopt the USEPA’s “model” rules that require electric generating units (EGUs)
to participate in an interstate cap and trade program, or 2) establish emissions controls
and emission caps for one or more industry sectors. In May 2005, the IDNR convened a
workgroup to assist with rulemaking activities related to the adoption of the CAIR. The
majority of the workgroup members recommended that the IDNR adopt the USEPA’s
cap and trade program for regulating emissions from EGUs. Upon reviewing the CAIR
provisions, considering the recommendations from all workgroup members and all public
comments received during the comment period, IDNR adopted the USEPA’s cap and
trade program for implementing the CAIR.
Under the CAIR’s cap and trade approach, the USEPA allocates emissions
allowance budgets to the state for NOx emissions. CAIR SO2 allowances are allocated to
affected EGUs from the current allowances under the existing Acid Rain program. The
state is responsible for allocating the initial NOx allowances to CAIR-affected facilities.
Each allowance is equal to one ton of emissions. Upon initial allocation of NOx and SO2
allowances, EGUs can then trade them through a USEPA-managed trading program.
Market forces determine the trade currency (allowance) values. At the end of each year,
each affected EGU must hold one allowance for each ton of SO2 or NOx emitted.
2.4.10.2 Clean Air Mercury Rule. On May 18, 2005, the USEPA promulgated the
CAMR to address mercury emissions. The CAMR rule permanently caps and reduces
the nationwide level of mercury emissions from coal fired power plants. When fully
implemented, it is estimated that the CAMR will reduce utility mercury emissions in 48
states to 15 tons annually, a 70 percent reduction from 2002 levels. As previously
described in Section 2.4.2.1, CAMR also includes a NSPS for coal fired EGUs
constructed after January 30, 2004. Affected new sources will need to meet a stringent
emission standard for mercury and conduct emissions testing and continuous emissions
monitoring.
The first phase of the CAMR, set to occur in 2010, will place a nationwide, 38 ton
cap on mercury emissions. The second phase of the CAMR will place a nationwide,
15 ton cap on mercury emissions, which will occur in 2018. Under the CAMR, each
state is provided with an annual emissions cap for mercury. States must meet the
required targets by either 1) adopting USEPA’s “model” rules that will require affected
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coal fired EGUs to participate in a USEPA-administered interstate cap and trade
program, or 2) establish source-by-source controls to achieve the USEPA-prescribed
mercury cap.
In May 2005, the IDNR convened a workgroup to assist with rulemaking
activities related to the adoption of the CAMR. The majority of the workgroup members
recommended that the IDNR adopt the USEPA’s cap and trade program for regulating
mercury emissions from coal fired EGUs. Upon reviewing the CAMR provisions,
considering the recommendations from all workgroup members and all public comments
received during the comment period, the IDNR adopted the USEPA’s cap and trade
program for implementing the CAMR.
Under the CAMR’s cap and trade emissions trading program, each ounce of
mercury emitted annually from an affected EGU will require one mercury allowance.
The mercury allowances will be traded on a USEPA-administered open market, which
will establish the trade currency (allowance) value.
2.4.11 Green House Gases (GHG)
In early 2007, the Iowa Senate File 485 amended Iowa Code Section 455B.131
and required the IDNR to include estimates of emissions of some greenhouse gases in its
construction permitting and emissions inventory programs. This bill also instructed the
IDNR to develop a GHG inventorying method by January 1, 2008, and create a voluntary
greenhouse gas registry by January 1, 2009, to track and credit companies in Iowa that
reduce their emissions of greenhouse gases or that provide increased energy efficiency.
On July 5, 2007, Iowa joined the Climate Registry, which is a multistate and tribe
collaboration aimed at developing and managing a common greenhouse gas emissions
reporting system.
The IDNR is currently drafting rules that pertain to the voluntary Climate
Registry and mandatory GHG inventory. It is expected that the draft rules will establish a
mechanism to coordinate the information obtained in the greenhouse gas inventory with
the Climate Registry, so regulated entities do not have to report the same information
twice. The IDNR is also requiring all construction permit applications filed after July 2,
2007, to include potential greenhouse gas emissions for the project. The IDNR has
published the appropriate GHG form and emissions estimation guidance. IPL has
included the GHG form in Appendix A of this application package and estimated GHG
emissions from all combustion sources that will be installed as part of the Project.
102607-145491
2-22
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
3.0
3.0 Best Available Control Technology
Best Available Control Technology
As discussed in Section 2.4, the Project is classified as a major modification to an
existing major source. Based on the Project’s calculated PTE emissions increase
(Table 2-2), the Project is subject to a BACT review for SO2, NOx, CO, PM/PM10, VOC,
H2SO4, and fluorides. This section presents a summary of the BACT analysis
methodology and the emissions control determinations for the Project’s affected
equipment. The complete regulatory BACT analysis is included as Appendix H of this
application.
3.1
BACT Methodology
A BACT analysis was conducted for the Project’s 648 MW (net) SCPC boiler
(SGS Unit 4); auxiliary steam boiler; gate station heater; emergency generator; fire pump
and fire booster pump engines; cooling tower; and material handling systems for coal,
limestone, ash, FGD waste, and reagent. As required under the NSR/PSD regulations,
the BACT analysis employed the USEPA’s recommended top-down, five-step analysis
process to determine the appropriate BACT emission limitations for Project. In
summary, the BACT analysis was conducted in the following manner:
•
Step 1: Identify All Control Technologies
•
Step 2: Eliminate Technically Infeasible Options
•
Step 3: Rank Remaining Control Technologies by Effectiveness
•
Step 4: Evaluate Most Effective Controls and Document Results
•
Step 5: Select BACT
As the aforementioned BACT methodology suggests, if it cannot be shown that
the top level of control is infeasible (for a similar type source and fuel category) on the
basis of technical, economic, energy, or environmental impact considerations, then that
level of control must be declared to represent BACT for the respective pollutant and air
emissions source. Alternatively, upon proper documentation that the top level of control
is not feasible for a specific unit and pollutant based on a site and project-specific
consideration of the aforementioned screening criteria (i.e., technical, economic, energy,
and environmental considerations), then the next most stringent level of control is
identified and similarly evaluated. This process continues until the BACT level under
consideration cannot be eliminated by any technical, economic, energy, or environmental
considerations. BACT cannot be determined to be less stringent than the emissions limits
established by an applicable NSPS for the affected air emission source.
102607-145491
3-1
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
3.2
3.0 Best Available Control Technology
Summary of the BACT Determination
Tables 3-1 and 3-2 present a summary of the BACT emission limit
determinations, control equipment, and proposed averaging period for the Project.
Table 3-1 summarizes the BACT results for Project, with the exception of the material
handling sources, which are presented in Table 3-2.
102607-145491
3-2
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
3.0 Best Available Control Technology
Table 3-1
BACT Determination Summary
Emission Unit: 649 MW (net) SCPC Boiler (Steam Capacity Rating 4,389,000 lb/h)
Pollutant
Control Technology
Emission Basis
Avg. Period
Testing Method
SO2
Wet FGD
0.06 lb/MBtu or 98 percent
removal (whichever occurs
first) with 0.08 lb/MBtu
upper limit.
30 day
CEMS
NOx
LNB/OFA and SCR
0.05 lb/MBtu
30 day
CEMS
PM/PM10
Fabric Filter
0.012 lb/MBtu (filterable)
3 hour test
runs (average)
USEPA Method 5B
0.018 lb/MBtu (total)
3 hour test
runs (average)
USEPA Method 5B +
202 with condensable
artifact modification
Visible
Emissions
(Opacity)
Fabric Filter
10%
6-minute
average
COMS
CO
Good Combustion
Controls
0.12 lb/MBtu
8 hour
CEMS
VOC
Good Combustion
Controls
0.0034 lb/MBtu
3 hour test
runs (average)
USEPA Method 18
H2SO4
Sorbent
Injection/Fabric Filter
0.004 lb/MBtu
3 hour test
runs (average)
Controlled
Condensate Test
Method
Fluorides
Wet FGD
0.0002 lb/MBtu
3 hour test
runs (average)
USEPA Method 13B
or USEPA Method
26A
Emission Unit: Auxiliary Steam Boiler (270 MBtu/h)
Pollutant
Control Technology
Emission Basis
Avg. Period
Testing Method
SO2
Natural Gas Firing
0.0006 lb/MBtu
NA
Fuel Recordkeeping
NOx
Good Combustion
Controls
0.037 lb/MBtu
3 hour test
runs (average)
USEPA Method 7E
PM/PM10
Natural Gas Firing
0.007 lb/MBtu
NA
Fuel Recordkeeping
CO
Good Combustion
Controls
0.074 lb/MBtu
NA
Fuel Recordkeeping
VOC
Good Combustion
Controls
0.005 lb/MBtu
NA
Fuel Recordkeeping
H2SO4
Natural Gas Firing
0.0009 lb/MBtu
NA
Fuel Recordkeeping
102607-145491
3-3
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
3.0 Best Available Control Technology
Table 3-1 (Continued)
BACT Determination Summary
Emission Unit: Emergency Generator (2,000 kW)
Pollutant
Control Technology
Emission Basis
SO2
Low Sulfur Distillate Fuel Oil
< 0.05% Sulfur Fuel Oil
NOx
Good Combustion Controls
6.47 g/bhph
PM/PM10
Low Sulfur Distillate Fuel Oil
0.08 g/bhph
CO
Good Combustion Controls
0.53 g/bhph
VOC
Good Combustion Controls
0.27 g/bhph
H2SO4
Low Sulfur Distillate Fuel Oil
< 0.05 % Sulfur Fuel Oil
Emission Unit: Emergency Fire Pump (575 bhp)
Pollutant
Control Technology
Emission Basis
SO2
Low Sulfur Distillate Fuel Oil
< 0.05% Sulfur Fuel Oil
NOx
Good Combustion Controls
4.9 g/bhph
PM/PM10
Low Sulfur Distillate Fuel Oil
0.08 g/bhph
CO
Good Combustion Controls
0.75 g/bhph
VOC
Good Combustion Controls
0.29 g/bhph
H2SO4
Low Sulfur Distillate Fuel Oil
< 0.05% Sulfur Fuel Oil
Emission Unit: Emergency Fire Booster Pump (149 bhp)
Pollutant
Control Technology
Emission Basis
SO2
Low Sulfur Distillate Fuel Oil
< 0.05% Sulfur Fuel Oil
NOx
Good Combustion Controls
5.20 g/bhph
PM/PM10
Low Sulfur Distillate Fuel Oil
0.19 g/bhph
CO
Good Combustion Controls
0.33 g/bhph
VOC
Good Combustion Controls
0.36 g/bhph
H2SO4
Low Sulfur Distillate Fuel Oil
< 0.05% Sulfur Fuel Oil
Emission Unit: Cooling Tower
Pollutant
Control Technology
Emission Basis
PM/PM10
Drift Eliminators
0.0005% drift rate
Gate Station Gas Heater (3 MBtu/hr)
Pollutant
Control Technology
Emission Basis
SO2
Natural Gas Firing
0.0006 lb/MBtu
NOx
Good Combustion Controls
0.046 lb/MBtu
PM/PM10
Natural Gas Firing
0.0074 lb/MBtu
CO
Good Combustion Controls
0.046 lb/MBtu
VOC
Good Combustion Controls
0.0054 lb/MBtu
H2SO4
Natural Gas Firing
0.0009 lb/MBtu
102607-145491
3-4
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
3.0 Best Available Control Technology
Table 3-1 (Continued)
BACT Determination Summary
Emission Unit: Material Handling Systems for the Conveyance of Coal, Biomass, Ash, and Reagent
Pollutant
Emission Source
Control Technology
PM/PM10
Coal Handling
Refer to Table 3-2
Limestone Handling
Refer to Table 3-2
Fly Ash Handling
Refer to Table 3-2
FGD Waste Handling
Refer to Table 3-2
Bottom Ash Handling
Refer to Table 3-2
Biomass Handling
Refer to Table 3-2
Other Material Handling
Refer to Table 3-2
CEMS = Continuous Emissions Monitoring System.
FGD = Flue Gas Desulfurization.
g/bhph = Grams per Brake Horsepower Hour.
LNB/OFA = Low NOx Burner/Overfire Air.
MBtu = Million British Thermal Unit.
SCR = Selective Catalytic Reduction.
30 day = 30 day rolling average
102607-145491
3-5
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
3.0 Best Available Control Technology
Table 3-2
Material Handling Particulate BACT Determinations
System
Emission Source
BACT Control Technology Determination
Rotary Car Dumper (DPR-1)
Coal Unloading
100% building enclosure
Dust collection system (0.01 gr/dscf)
100% belt enclosure and dust collection system
(0.01 gr/dscf)
100% transfer tower enclosure (TT-1) and dust
collection system (0.01 gr/dscf)
100% belt enclosure
Telescopic chute and spray ring (CHE-1)
100% belt enclosure
Belt Conveyor (BC-1) Coal
Receiving
Transfer Tower (TT-1)
Belt Conveyor (BC-2)
Emergency Stockout
Belt Conveyor (BC-3)
Emergency Stockout Reclaim
Belt Conveyor (BC-4)
Stacker/Reclaimer Conveyor
Stack/Reclaimer (SR-1)
Transfer Tower (TT-2)
Coal Handling
Belt Conveyor (BC-5A)
Existing Units Reclaim
Transfer Tower (TT-3)
Belt Conveyor (BC-5B)
Existing Units Feed
Truck Loadout
Belt Conveyor (BC-6) Pile
Stockout
Belt Conveyor (BC-7) Pile
Stockout
Belt Conveyor (BC-8) Pile
Reclaim
Belt Conveyor (BC-9) Pile
Reclaim
Belt Conveyors (BC-10 and
11) Crusher Feed
Crusher House (CH-1)
Belt Conveyors (BC-12 and
13) Plant Feed (SGS Unit 4)
102607-145491
Partial belt enclosure
Dust suppression
100% transfer tower enclosure (TT-2) and dust
collection system (0.01 gr/dscf)
100% belt enclosure and dust collection system
(0.01 gr/dscf)
100% transfer tower enclosure (TT-3) and dust
collection system (0.01 gr/dscf)
100% belt enclosure
100% building enclosure
Dust collection system (0.01 gr/dscf)
Loadout chute
100% belt enclosure
Telescopic chute and spray ring (CHE-2)
100% belt enclosure
Telescopic chute and spray ring (CHE-3)
100% belt enclosure and dust collection system
(0.01 gr/dscf)
100% belt enclosure and dust collection system
(0.01 gr/dscf)
100% belt enclosure
100% crusher building enclosure (CH-1)
Dust collection system (0.01 gr/dscf)
100% belt enclosure
3-6
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
3.0 Best Available Control Technology
Table 3-2 (Continued)
Material Handling Particulate BACT Determinations
System
Coal Handling
(Continued)
Emission Source
BACT Control Technology Determination
Transfer Tower (TT-4)
100% transfer tower enclosure (TT-4) and dust
collection system (0.01 gr/dscf)
100% belt enclosure
100% boiler house enclosure and dust collection
system (0.01 gr/dscf)
Belt Conveyors (BC-14 and
15) Tripper Conveyors
Railcar/Truck Bottom Dumper
Limestone Unloading
Belt Conveyor (CVY-1)
Limestone Receiving/Stock
Out
Limestone Handling
Belt Conveyor (CVY-2)
Limestone Reclaim
Belt Conveyor (CVY-3)
Distribution Conveyor
Two Limestone Storage Silos
Fly Ash Handling
Saleable Fly Ash Storage Silo
Saleable Fly Ash Separators
Combination Railcar and
Truck Loader (from saleable
fly ash storage silo)
Saleable Fly Ash Winter
Storage Building
100% building enclosure
Dust collection system (0.005 gr/dscf)
100% belt enclosure and dust collection system
(0.005 gr/dscf)
Telescopic chute (CHE-1) and dust suppression
(DS-2)
75% storage building enclosure
100% belt enclosure
100% belt enclosure and dust collection system
(0.005 gr/dscf)
Bin vent fabric filter
Bin vent fabric filter
Exhaust vent fabric filter
Telescopic chute
Truck washdown facility
100% storage building enclosure
Dust collection system (0.01 gr/dscf)
Telescopic chute
Saleable Fly Ash Truck
Loader (from winter storage
building)
Waste Fly Ash Storage Silo
Bin vent fabric filter
Waste Fly Ash Separators
Exhaust vent fabric filter
Truck Loader (from waste fly
ash storage silo)
Telescopic chute
FGD Waste Handling
Wet Solids Material
No fugitive or point source emissions
Bottom Ash Handling
Wet Solids Material
No fugitive or point source emissions
Biomass Handling
Bale Conveyor
No fugitive or point source emissions
Hammermill
No fugitive or point source emissions
Eliminator Ginder
Dust collection system (0.01 gr/dscf)
Tube Conveyor
Dust collection system (0.01 gr/dscf)
Surge Bin w/rotary air lock
Dust collection system (0.01 gr/dscf)
102607-145491
3-7
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
3.0 Best Available Control Technology
Table 3-2 (Continued)
Material Handling Particulate BACT Determinations
System
Emission Source
BACT Control Technology Determination
Haul Roads – Material
Delivery and Disposal
Paved roads
Road surface cleaning
Wet dust suppression
Wet dust suppression and chemical surfactant
Pile best management practices
Crusting agent
Wet dust suppression and chemical surfactant
75% storage building enclosure
100% storage building enclosure
Dust collection system (0.01 gr/dscf)
Limited operation
Wet dust suppression
Active Coal Storage Piles
Other Material
Handling
Inactive Coal Storage Piles
Limestone Storage Pile
Saleable Fly Ash Winter
Storage Pile
Front End Loader/Dozer
Note: Detailed material handling process flow diagrams identifying the material handling systems, emission
sources, and particulate BACT control equipment are included in Appendix E of the air permit application.
102607-145491
3-8
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
4.0
4.0 Air Dispersion Modeling
Protocol and Impact Analysis
Air Dispersion Modeling Protocol and Impact Analysis
This section contains a summary of the air dispersion modeling protocol and the
results of the ambient air quality impact analysis (AQIA) air dispersion modeling for the
proposed Project. The AQIA was conducted in accordance with USEPA’s Guideline on
Air Quality Models (incorporated as Appendix W of 40 CFR 51) and IDNR’s Air
Dispersion Modeling Guidelines for PSD Projects, as well as a pre-application meeting
held with the IDNR and USEPA Region VII on February 7, 2007. The complete air
dispersion modeling methodology and AQIA is included as Appendix I of this
application.
4.1
Ambient Air Quality Impact Results
The AERMOD air dispersion model was used to analyze the air quality impact
resulting from the proposed Project. As fully described in Appendix I, multiple operating
scenarios based on fuel type, operating load, and worst case/conservative emission source
assumptions were analyzed in AERMOD to determine the Project’s maximum model
predicted ground level concentration for each regulated pollutant subject to PSD review.
The results of the air dispersion modeling are presented in Table 4-1 and compared to the
respective PSD modeling significance and de minimis ambient monitoring levels. The
impacts presented in Table 4-1 conservatively have all sources operating simultaneously
at their maximum design rates (exceptions are the emergency diesel generator and two
emergency diesel fire pumps which, on a short-term basis, will not be operated when the
rest of the facility is in operation, except for testing and maintenance purposes).
Annually, however, these additional emissions sources were included in the modeling of
the full facility.
As the results in Table 4-1 indicate, the Project’s model-predicted air quality
impacts are less than the modeling significance and de minimis ambient monitoring
concentrations, indicting that the Project is not subject to additional cumulative source air
dispersion modeling analysis or pre-construction ambient monitoring requirements,
respectively, as part of the PSD review process.
102607-145491
4-1
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
4.0 Air Dispersion Modeling
Protocol and Impact Analysis
Table 4-1
Comparison of the Project’s Maximum Modeled Impacts
with the PSD Class II Modeling Significance and Monitoring de minimis Levels
Operation
Typical
Operation(2)
Pollutant
Averaging
Period
AERMOD
1st High
Maximum
Impact(1)
(μg/m3)
NOx
Annual
0.59
1
14
SO2
Annual
0.39
1
--
24 hour
4.85
5
13
3 hour
15.41
25
--
Annual
0.77
1
--
24 hour
4.92
5
10
8 hour
19.19
500
575
1 hour
49.12
2,000
--
24 hour
0.01
--
0.25
PM10
CO
Fluorides
PSD Class II
Modeling
Significance
Level
(μg/m3)
PSD Class II
Monitoring
de minimis Level
(μg/m3)
(1)
Represents the first high maximum model-predicted, ground level impact from the 5 year
meteorological data set used.
(2)
On a short-term basis, typical operation includes the continuous and simultaneous operation of
the proposed Unit 4 pulverized coal boiler, auxiliary boiler, natural gas fired heater, cooling tower,
coal, limestone, ash, gypsum, and biomass material handling processes; truck deliveries; and
byproduct and waste removals. It does not include the operation of the emergency diesel generator
and two emergency diesel fire pumps, which, as allowed by IDNR, were modeled separately and
compared to the short-term NAAQS (the results of which are presented in Table 4-2).
On an annual basis, in addition to continuous and simultaneous operation of the sources listed
immediately above, the modeling includes the auxiliary boiler operating for 2,000 hours per year.
102607-145491
4-2
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
4.0 Air Dispersion Modeling
Protocol and Impact Analysis
Additionally, as allowed under IDNR rules, the Project’s ancillary equipment,
including the auxiliary boiler, emergency diesel generator, and two emergency diesel fire
pumps, were included in a separate AERMOD air dispersion modeling analysis to assess
their compliance with the applicable short-term NAAQS. As shown in Table 4-2, the
modeling results for this scenario are all below the applicable NAAQS. It is important to
note that the auxiliary boiler was conservatively included in both the short-term NAAQS
analysis presented in Table 4-2, as well as the full facility modeling presented in
Table 4-1, since it may operate both when the rest of the facility is not in operation (i.e.,
with the ancillary equipment) and when SGS Unit 4 is in operation.
Table 4-2
Comparison of the Ancillary Equipment’s Maximum Modeled Impacts with the
Short-Term NAAQS
Operation
Ancillary
Operation(2)
Pollutant
Averaging
Period
AERMOD
1st High
Maximum
Impact(1)
(μg/m3)
SO2
24 hour
4.10
20
24.10
365
3 hour
19.80
20
39.80
--
PM10
24 hour
1.58
45
46.58
150
CO
8 hour
43.02
0
43.02
10,000
1 hour
96.82
0
96.82
40,000
Background
Concentration
Value
(μg/m3)(3)
Total
(μg/m3)
NAAQS
(μg/m3)
(1)
Represents the first high maximum model-predicted, ground level impact from the 5 year
meteorological data set used.
(2)
Ancillary equipment includes the unlimited short-term operation of the auxiliary boiler,
emergency diesel generator, and two emergency diesel fire pumps for the full extent of the
averaging period of concern.
It is important to note that the auxiliary boiler was conservatively included in both the shortterm NAAQS analysis presented in this table, as well as the full facility modeling presented in
Table 4-1, since it may operate both when the rest of the facility is not in operation and when
SGS Unit 4 is in operation.
(3)
Taken from Table 4, Statewide Default Background Values of the IDNR’s Air Dispersion
Modeling Guidelines for PSD Project (Version 010605), and updated to include the most recent
background value for PM10 24 hour averaging period, as received in correspondence with IDNR
staff.
102607-145491
4-3
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
4.2
4.0 Air Dispersion Modeling
Protocol and Impact Analysis
Additional Impacts Analysis
In addition to the AQIA presented in the previous section, the PSD air quality
regulations require the preparation of an analysis of additional impacts that may result
from the proposed Project. The additional impact analysis considers the Project’s
potential impairment to visibility, soils, and vegetation, as well as projected air quality
impacts that may occur as the result of general commercial, residential, industrial, and
other growth associated with the Project. While the complete report of the Project’s
additional impact analysis is contained in Appendix I, a summary of the results concludes
that the Project will have a minimal or insignificant impact to these resources.
Additionally, because the distance to the nearest Class I area is approximately 510
km from the SGS, a regional haze visibility impairment analysis is not proposed or
required for this Project.
102607-145491
4-4
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Appendix A
Appendix A
IDNR Application Forms
102607-145491
A-1
APPENDIX A
Application Forms: Emission Units Legend
Emission Unit (EU) Name
Unit 4 Main Boiler
Auxiliary Boiler
Emergency Diesel Generator
Diesel Fire Pump
Diesel Booster Fire Pump
Linear Mechanical Draft Cooling Tower
Coal Material Handling
Rotary Car Dumper Building (a)
Unload from railcars to Hopper HPR-1 at rotary car dumper.
Rotary Railcar Dump Vault
Transfer from Hopper HPR-1 to to Belt Feeder BF-1.
Transfer from Hopper HPR-1 to to Belt Feeder BF-2.
Transfer from Belt Feeder BF-1 to Belt Conveyor BC-1.
Transfer from Belt Feeder BF-2 to Belt Conveyor BC-1.
Transfer Tower TT-1
Transfer from Belt Conveyor BC-1 to Belt Conveyor BC-4.
Coal Stockout Pile No. 1 (Emergency)
Transfer from Belt Conveyor BC-2 to Coal Stockout Pile No. 1
Transfer from Reclaim Hopper RH-1 to Belt feeder BF-3
North and South Coal Piles (Coal Stockout Pile No. 2)
Transfer from Belt Conveyor BC-4 to SR-1 Boom Conveyor/Belt
Conveyor BC-4
Transfer from SR-1 Boom Conveyor to Stockout Pile 2
Transfer Tower TT-2
Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-6.
Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-7.
Transfer from Belt Conveyor BC-8 to Belt Conveyor BC-10.
Transfer from Belt Conveyor BC-8 to Belt Conveyor BC-11.
Transfer from Belt Conveyor BC-9 to Belt Conveyor BC-10.
Transfer from Belt Conveyor BC-9 to Belt Conveyor BC-11.
Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-10.
Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-11.
Coal Stockout Pile No. 3
Transfer from Belt Conveyor BC-6 to Coal Stockout Pile No. 3
Pile 3 Vault
Transfer from Reclaim Hopper RH-2 to Belt Feeder BF-4.
Transfer from Belt Feeder BF-4 to Belt Conveyor BC-8.
Coal Stockout Pile No. 4
Transfer from belt Conveyor BC-7 to Coal Stockout Pile No. 4
Pile 4 Vault
Transfer from Reclaim Hopper RH-3 to Belt Feeder BF-5.
Transfer from Belt Feeder BF-5 to Belt Conveyor BC-9.
Associated
Emission Point No.
248
249
250a, 250b
251
252
253a through p
254 through 279
EU No.
248
249
250
251
252
253
254
254a, 254b
255a
255b
255c
255d
255
255
255
255
256b
273
257
258
274, 275
256
273
257
258
274, 275
259a/b
260a/b
and 261
a-d
259
260, 261
262a
262b
262c
262d
262e
262f
262g
262h
276
263
262
262
262
262
262
262
262
262
276
263
264a
264b
277
265
264
264
277
265
266a
266b
266
266
Emission Unit (EU) Name
Crusher House CH-1
Transfer from Belt Conveyor BC-10 to Crusher Surge Bin SB-1
Transfer from Belt Conveyor BC-11 to Crusher Surge Bin SB-1
Transfer from surge bin SB-1 to Belt Feeder BF-6.
Transfer from surge bin SB-1 to Belt Feeder BF-7.
Crusher CR-1.
Crusher CR-2.
Transfer from Belt Feeder BF-6 through Crusher CR-1 to Belt
Conveyor BC-13.
Transfer from Belt Feeder BF-7 through Crusher CR-2 to Belt
Conveyor BC-12.
Transfer Tower TT-4
Transfer from Belt Conveyor BC-12 to Tripper Conveyors BC-1
Transfer from Belt Conveyor BC-12 to Tripper Conveyors BCTransfer from Belt Conveyor BC-13 to Tripper Conveyors BC-1
Transfer from Belt Conveyor BC-13 to Tripper Conveyors BCTransfer from Belt Conveyor BC-14 to Coal Silos.
Transfer from Belt Conveyor BC-15 to Coal Silos.
Pile 2 Vault
Transfer from Reclaim Hopper RH-4 to BF-8.
Transfer from Belt Feeder BF-8 to Belt Conveyor BC-5A.
Transfer from Reclaim Hopper RH-5 to BF-9.
Transfer from Belt Feeder BF-9 to Belt Conveyor BC-5A.
Transfer Tower TT-3
Transfer from Belt Conveyor BC-5A to Belt Conveyor BC-5B.
Existing Transfer Tower
Transfer from Belt Conveyor BC-5B to Hopper HPR-2
Truck Loadout Enclosure
Transfer from the Hopper HPR-2 to future truck load out
Northgate Haul Road
Westgate Haul Road
Limestone Material Handling
Railcar/Truck Unloading Building (a)
Unload from railcars to hopper at unloader.
Railcar/Truck Unloading Vault
Transfer from Hopper HPR-1 to Belt Feeder FDR-1.
Transfer from Hopper HPR-1 to Belt Feeder FDR-2.
Transfer from Belt Feeder FDR-1 to Belt Conveyor CVY-1.
Transfer from Belt Feeder FDR-2 to Belt Conveyor CVY-1.
Limestone Building Storage-Limestone Active Pile
Transfer from receiving conveyor CVY-1 to Limestone Building
Storage
Pile Vault
Transfer from Hopper HPR-2 to Belt Feeder FDR-3.
Transfer from Hopper HPR-3 to Belt Feeder FDR-4.
Transfer from Belt Feeder FDR-3 to Belt Conveyor CVY-2.
Transfer from Belt Feeder FDR-4 to Belt Conveyor CVY-2.
EU No.
Associated
Emission Point No.
267a
267b
267c
267d
267e
267f
267
267
267
267
267
267
267g
267
267h
267
268a
268b
268c
268d
268e
268f
268
268
268
268
268
268
269a
269b
269c
269d
269
269
269
269
270
270
271
271
272
278
279
272
278
279
280 through 285
280
280a, 280b
281a
281b
281c
281d
282
281
281
281
281
282b
282
282a
283a
283b
283c
283d
283
283
283
283
Emission Unit (EU) Name
Limestone Silo 1
Transfer from Belt Conveyor CVY-2 to Limestone Silo 1.
Limestone Silo 2
Transfer from Belt Conveyor CVY-2 to Belt Conveyor CVY-3.
Transfer from Belt Conveyor CVY-3 to Limestone Silo 2.
Saleable Flyash Handling and Storage
Pneumatic Conveyor Blower Exhaust
Pneumatic Conveyor Blower Exhaust
Ash Silo bin vent fan
Ash storage building Vent Fan
Ash storage building Vent Fan
Waste Flyash Handling and Storage
Pneumatic Conveyor Blower Exhaust
Pneumatic Conveyor Blower Exhaust
Ash silo bin vent fan
Material Handling - Others
PAC Transfer to Silo
Sorbent Transfer to Day Silo
Sorbent Transfer to Long Term Silo
Transfer of Lime
Biomass Material Handling
Biomass Building (Line 1)
Biomass Building (Line 2)
Gate Station Heater (3 MBtu/hour)
EU No.
Associated
Emission Point No.
284
284
285a
285b
286
286
287
288
288
289
289
290
291
292
293
294
295
296
297
285
285
286 through 288
286a
286b
287
288a
288b
289-290
289a
289b
290
291
292
293
294
295-296
295
296
297
EU5
ATTN: Application Log in
AIR QUALITY BUREAU
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
AIR CONSTRUCTION PERMIT APPLICATION
Form EU5: Boiler Information
Please see instruction on reverse side
EXEMPTION
According to 567 Iowa Administrative Code Chapter 22.1(2)a, an indirect fired combustion source that
uses only Natural Gas or LPG and has a heating capacity of less than 10 MMBTU/hr is exempted from the
provisions of construction permits.
According to 567 Iowa Administrative Code Chapter 22.1(2)b, an indirect fired combustion source that
uses coal, fuel oil or untreated wood, seeds, pellets, other vegetable matter and has a heating capacity of less
than 1 MMBTU/hr is exempted from the provisions of construction permits.
Company Name: IPL-Sutherland Generating Station Unit 4
BOILER (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS
New Unit
Unpermitted Existing Unit
(1) Boiler ID Number: EU-248
Modification to an unit with Permit #:
(2) Rated Capacity (MMBTU/hr heat input): 6,326 (PRB-1)
(3) Construction Date: November 2008 (4) Manufacturer: TBD
(5) Model: TBD
(6) Date of Modification (if applicable):
N/A
(8) Control Device (if any): CE248 A, B,
C, D and E - SCR/PAC/FF/WFGD
(7) Serial Number (if available):
and sorbent injection
FUEL DESCRIPTION AND SPECIFICATIONS
(9) Fuel Type
Natural Gas
(cf/hr)
Fuel Oil (# )
(gal/hr)
(10) Full Load
Consumption Rate
(11) Sulfur Content wt%
Coal type:
PRB
(lb/hr)
Coal type:
IL
(lb/hr)
Other Fuels
Solid Biomass
(lb/hr)
762,157
572,084
44,000
0.33
3.11
<0.1
None
None
Up to 5% of heat
input from
biomass
(12) Requested Limit
OPERATING LIMITS & SCHEDULE
(13) Imposed Operating Limits (hours/year, or gallons fuel/year, etc.):
None
(14) Operating Schedule (hours/day, months/year, etc.):
24 hours/day, 12 months/year and 8,760 hours/year
STACK/VENT (EMISSION POINT) SPECIFICATIONS
(15) Stack/Vent ID:
EP-248
(17) Stack Height (feet) from the Ground:
601
(18) Stack Height (feet)
above the Building (If Applicable):
(20) Distance (feet) from the Property Line:
1,476
(21) Rated Flow Rate (
1,940,460 (PRB-1)
acfm
For Assistance 1-877-AIR-IOWA
scfm):
(16) Stack Opening Size:
circular, diameter (inches) is: 316.56
other, size (inches x inches) is:
(19) Discharge Style:
V (Vertical, without rain cap or with unobstructing rain cap)
VR (Vertical, with obstructing rain cap)
H (Horizontal discharge)
D (Downward discharge; for example, a goose neck stack)
EXHAUST INFORMATION
(22) Moisture Content % (if known):
6 (PRB-1)
(23) Exit Temperature (°F)
130
(1-877-247-4692)
Revised 11/2006
EU5
ATTN: Application Log in
AIR QUALITY BUREAU
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
AIR CONSTRUCTION PERMIT APPLICATION
Form EU5: Boiler Information
Please see instruction on reverse side
EXEMPTION
According to 567 Iowa Administrative Code Chapter 22.1(2)a, an indirect fired combustion source that
uses only Natural Gas or LPG and has a heating capacity of less than 10 MMBTU/hr is exempted from the
provisions of construction permits.
According to 567 Iowa Administrative Code Chapter 22.1(2)b, an indirect fired combustion source that
uses coal, fuel oil or untreated wood, seeds, pellets, other vegetable matter and has a heating capacity of less
than 1 MMBTU/hr is exempted from the provisions of construction permits.
Company Name: IPL-Sutherland Generating Station Unit 4
BOILER (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS
New Unit
Unpermitted Existing Unit
(1) Boiler ID Number: EU-249
Modification to an unit with Permit #:
(2) Rated Capacity (MMBTU/hr heat input): 268.64
(3) Construction Date: November 2008 (4) Manufacturer: TBD
(5) Model: TBD
(6) Date of Modification (if applicable):
N/A
(8) Control Device (if any):
(7) Serial Number (if available):
TBD
FUEL DESCRIPTION AND SPECIFICATIONS
(9) Fuel Type
Natural Gas
(cf/hr)
(10) Full Load
Consumption Rate
(11) Sulfur Content wt%
Fuel Oil (# )
(gal/hr)
Coal type:
(lb/hr)
Coal type:
(lb/hr)
Other Fuels
(lb/hr)
263,115
N/A
(12) Requested Limit
N/A
None
OPERATING LIMITS & SCHEDULE
(13) Imposed Operating Limits (hours/year, or gallons fuel/year, etc.):
527 million cubic feet per year of natural gas combustion. This operational limit is based on 2,000 hours per year of
natural gas combustion at the maximum rated design heat input for the auxiliary boiler.
(14) Operating Schedule (hours/day, months/year, etc.):
24 hours/day, 12 months/year and up to 527 million cubic feet per year of natural gas usage
STACK/VENT (EMISSION POINT) SPECIFICATIONS
(15) Stack/Vent ID:
(16) Stack Opening Size:
EP-249
circular, diameter (inches) is: 60
(17) Stack Height (feet) from the Ground:
other, size (inches x inches) is:
285
(18) Stack Height (feet)
(19) Discharge Style:
above the Building (If Applicable):
V (Vertical, without rain cap or with unobstructing rain cap)
11
VR (Vertical, with obstructing rain cap)
(20) Distance (feet) from the Property Line:
H (Horizontal discharge)
1,115
D (Downward discharge; for example, a goose neck stack)
(21) Rated Flow Rate (
51,850
acfm
For Assistance 1-877-AIR-IOWA
scfm):
EXHAUST INFORMATION
(22) Moisture Content % (if known):
(23) Exit Temperature (°F)
650
(1-877-247-4692)
Revised 11/2006
ATTN: Application Log in
AIR QUALITY BUREAU
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
AIR CONSTRUCTION PERMIT APPLICATION
Form EU1: Industrial Engine Information
Please see instruction on reverse side
EXEMPTION
According to 567 Iowa Administrative Code Chapter 22.1(2)r, an internal combustion engine with a brake
horsepower rating of less than 400 is exempted from the provisions of construction permits.
Company Name: IPL - Sutherland Generating Station Unit 4
ENGINE (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS
New Unit
Unpermitted Existing Unit
(1) Use of Engine:
Normal Operation
Modification to an unit with Permit #:
Emergency
Back-up
(2) Engine ID Number:
EU-250
(3) Rated Power:
2,937 bhp
(5) Manufacturer:
(6) Manufacture Date:
TBD
2,000 KW
(4) Construction Date:
November 2008
(7) Model Year & Model Number:
TBD
(8) Engine Order Date:
Fire Pump
TBD
(9) Control Device (if any):
(10) Displacement per cylinder (L):
TBD
TBD
(11) Engine Ignition Type:
Spark Ignition
(12) Engine Burn Type:
Compression
2SLB
2SRB
(13) Date of Modification (if applicable):
4SRB
FUEL DESCRIPTION AND SPECIFICATIONS
(14)
Fuel Type
Diesel Fuel (# )
(gal/hr)
(15)
Full Load Consumption Rate
138
(16)
Actual Consumption Rate
TBD
(17)
Sulfur Content wt%
0.05
Gasoline Fuel
(gal/hr)
N/A
Natural Gas
(cf/hr)
Other Fuels
(unit:
)
N/A
OPERATING LIMITS
(18) Requested Operating Limits (hours/year, or gallons fuel/year, etc.):
100 hours/year
STACK/VENT (EMISSION POINT) SPECIFICATIONS
(19) Stack/Vent ID:
EP-250a and EP-250b
(21) Stack Height (feet) from the Ground:
10
(22) Stack Height (feet)
above the Building (If Applicable):
(24) Distance (feet) from the Property Line:
1,886
(25) Rated Flow Rate ( acfm
scfm):
14,920 (total from two stacks)
(20) Stack Opening Size:
circular, diameter (inches) is: 8
other, size (inches x inches) is:
Single Stack
Dual Stack
(23) Discharge Style:
V (Vertical, without rain cap or with unobstructing rain cap)
VR (Vertical, with obstructing rain cap)
H (Horizontal discharge)
D (Downward discharge; for example, a goose neck stack)
I (Inside-Vent inside building)
EXHAUST INFORMATION
(26) Moisture Content % (if known):
(27) Exit Temperature (°F)
761
ATTN: Application Log in
AIR QUALITY BUREAU
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
AIR CONSTRUCTION PERMIT APPLICATION
Form EU1: Industrial Engine Information
Please see instruction on reverse side
EXEMPTION
According to 567 Iowa Administrative Code Chapter 22.1(2)r, an internal combustion engine with a brake
horsepower rating of less than 400 is exempted from the provisions of construction permits.
Company Name: IPL - Sutherland Generating Station Unit 4
ENGINE (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS
New Unit
Unpermitted Existing Unit
(1) Use of Engine:
Normal Operation
Modification to an unit with Permit #:
Emergency
Back-up
(2) Engine ID Number:
EU-251
(3) Rated Power:
575 bhp
(5) Manufacturer:
(6) Manufacture Date:
TBD
(4) Construction Date:
November 2008
KW
(7) Model Year & Model Number:
TBD
(8) Engine Order Date:
Fire Pump
TBD
(9) Control Device (if any):
(10) Displacement per cylinder (L):
TBD
TBD
(11) Engine Ignition Type:
Spark Ignition
(12) Engine Burn Type:
Compression
2SLB
2SRB
(13) Date of Modification (if applicable):
4SRB
FUEL DESCRIPTION AND SPECIFICATIONS
(14)
Diesel Fuel (# )
(gal/hr)
Fuel Type
(15)
Full Load Consumption Rate
29
(16)
Actual Consumption Rate
TBD
(17)
Sulfur Content wt%
0.05
Gasoline Fuel
(gal/hr)
N/A
Natural Gas
(cf/hr)
Other Fuels
(unit:
)
N/A
OPERATING LIMITS
(18) Requested Operating Limits (hours/year, or gallons fuel/year, etc.):
100 hours/year
STACK/VENT (EMISSION POINT) SPECIFICATIONS
(19) Stack/Vent ID:
EP-251
(21) Stack Height (feet) from the Ground:
12
(22) Stack Height (feet)
above the Building (If Applicable):
(24) Distance (feet) from the Property Line:
2,100
(25) Rated Flow Rate (
2,904
acfm
scfm):
(20) Stack Opening Size:
circular, diameter (inches) is: 6
other, size (inches x inches) is:
Single Stack
Dual Stack
(23) Discharge Style:
V (Vertical, without rain cap or with unobstructing rain cap)
VR (Vertical, with obstructing rain cap)
H (Horizontal discharge)
D (Downward discharge; for example, a goose neck stack)
I (Inside-Vent inside building)
EXHAUST INFORMATION
(26) Moisture Content % (if known):
(27) Exit Temperature (°F)
918
ATTN: Application Log in
AIR QUALITY BUREAU
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
AIR CONSTRUCTION PERMIT APPLICATION
Form EU1: Industrial Engine Information
Please see instruction on reverse side
EXEMPTION
According to 567 Iowa Administrative Code Chapter 22.1(2)r, an internal combustion engine with a brake
horsepower rating of less than 400 is exempted from the provisions of construction permits.
Company Name: IPL - Sutherland Generating Station Unit 4
ENGINE (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS
New Unit
Unpermitted Existing Unit
(1) Use of Engine:
Normal Operation
Modification to an unit with Permit #:
Emergency
Back-up
(2) Engine ID Number:
EU-252
(3) Rated Power:
149 bhp
(5) Manufacturer:
(6) Manufacture Date:
TBD
KW
(4) Construction Date:
November 2008
(7) Model Year & Model Number:
TBD
(8) Engine Order Date:
Fire Pump: Booster Fire Pump
TBD
(9) Control Device (if any):
(10) Displacement per cylinder (L):
TBD
TBD
(11) Engine Ignition Type:
Spark Ignition
(12) Engine Burn Type:
Compression
2SLB
2SRB
(13) Date of Modification (if applicable):
4SRB
FUEL DESCRIPTION AND SPECIFICATIONS
(14)
Diesel Fuel (# )
(gal/hr)
Fuel Type
(15)
Full Load Consumption Rate
9.5
(16)
Actual Consumption Rate
TBD
(17)
Sulfur Content wt%
0.05
Gasoline Fuel
(gal/hr)
N/A
Natural Gas
(cf/hr)
Other Fuels
(unit:
)
N/A
OPERATING LIMITS
(18) Requested Operating Limits (hours/year, or gallons fuel/year, etc.):
100 hours/year
STACK/VENT (EMISSION POINT) SPECIFICATIONS
(19) Stack/Vent ID:
EP-252
(21) Stack Height (feet) from the Ground:
12
(22) Stack Height (feet)
above the Building (If Applicable):
(24) Distance (feet) from the Property Line:
2,142
(25) Rated Flow Rate (
790
acfm
scfm):
(20) Stack Opening Size:
circular, diameter (inches) is: 5
other, size (inches x inches) is:
Single Stack
Dual Stack
(23) Discharge Style:
V (Vertical, without rain cap or with unobstructing rain cap)
VR (Vertical, with obstructing rain cap)
H (Horizontal discharge)
D (Downward discharge; for example, a goose neck stack)
I (Inside-Vent inside building)
EXHAUST INFORMATION
(26) Moisture Content % (if known):
(27) Exit Temperature (°F)
1,044
AIR QUALITY BUREAU
ATTN: Application Log in
IOWA DNR Air Construction Permit Application
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EU4: Cooling Tower Information
Please see instructions on the reverse side
Company Name: IPL-Sutherland Generating Station Unit 4
COOLING TOWER IDENTIFICATION AND DESCRIPTION
Tower 1
Tower 2
Tower 3
(1) Emission Unit Name
Mechanical Draft
Cooling Tower
(2) Emission Unit ID Number
EU-253
(3) Stack/Vent ID Number
EP-253 (a thru p)
(4) Tower Type
N,
U,
M
N,
U,
M
N,
U,
M
(N: New, U: Unpermitted, M: Modification)
(5) Current Permit Number
(6) Tower Construction Date
November 2008
(7) Tower Manufacturer
TBD
(8) Tower Model Number
TBD
(9) Number of Cells in Tower
16 (2 x 8)
(10) Tower Maximum Water Flow Rate
301,000 gallons
per minute
(11) Measured TDS Content (if known)
2,261 ppm
(12) Do You Use Additives in the Water
No
Yes
No
Yes
No
Yes
If Yes, Provide MSDS Sheets for Each
(TBD)
Additive
CONTROL EQUIPMENT INFORMATION
(13) Control Equipment
No
Yes
No
Yes
No
Yes
(14) Control Equipment ID Number
CE253
(15) Control Equipment Efficiency
0.0005% drift
STACK/VENT INFORMATION
(16) Cell Height from the Ground (ft)
53
(17) Distance from Property Line (ft)
(18) Cell Stack Size (in Dia. or in.X in.)
360
(19) Stack Discharge Style
Vertical
(20) Cell Rated Air Flow Rate
1,477,500
( acfm
scfm)
(21) Total Rated Air Flow Rate
23,640,000
( acfm
scfm)
104
(22) Exhaust Exit Temperature (°F)
OPERATING SCHEDULE
(23) Actual Operation (hours per year)
TBD
(24) Maximum Operation (hours per year) 8,760
REQUEST FOR PERMIT LIMITATIONS
(25) Are you requesting any permit limits?
No
Yes. If yes, write down all that apply
Tower
Operation Hour Limits:
TDS Limits (ppm):
Material Usage Limits:
Other:
Served
Tower 1
Tower 2
Rationale for Requesting the Limit(s):
For Assistance 1-877-AIR IOWA (1-877-247-4692)
Revised 11/2006
Tower 4
N,
U,
M
No
Yes
No
Yes
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point-Rail Car Unloading to Hopper (Rotary Railcar Dumper Building)
2)
EU ID Number:
EU-254
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-254a and EP-254b
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-254a/b, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Hopper to Belt Feeder BF-1
2)
EU ID Number:
EU-255a
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-255
Previous Permit # is:
2,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-255, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Hopper to Belt Feeder BF-2
2)
EU ID Number:
EU-255b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-255
Previous Permit # is:
2,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-255, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Feeder BF-1 to Belt Conveyor BC-1
2)
EU ID Number:
EU-255c
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-255
Previous Permit # is:
2,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-255, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Feeder BF-2 to Belt Conveyor BC-1
2)
EU ID Number:
EU-255d
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-255
Previous Permit # is:
2,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-255, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-1 to Belt Conveyor BC-2 (Transfer Tower TT-1)
2)
EU ID Number:
EU-256a
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-256
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-256, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-1 to Belt Conveyor BC-4 (Transfer Tower TT-1)
2)
EU ID Number:
EU-256b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-256
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-256, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-3 to Belt Conveyor BC-4 (Transfer Tower TT-1)
2)
EU ID Number:
EU-256c
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-256
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-256, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-2 to Coal Stockout Pile No. 1
2)
EU ID Number:
EU-257
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-257
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
CE-257, Telescopic chute and wet
suppression
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
No
If Yes, Control Equipment name/ID are:
Yes
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Reclaim Hopper RH-1 to Belt Feeder BF-3
2)
EU ID Number:
EU-258a
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-258
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-258, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Feeder BF-3 to Belt Conveyor BC-3
2)
EU ID Number:
EU-258b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-258
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-258, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Elevated Tripper to Stacking Boom Conveyor
2)
EU ID Number:
EU-259a
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-259
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-259, wet suppression
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Elevated Tripper to Belt Conveyor BC-4
2)
EU ID Number:
EU-259b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-259
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-259, wet suppression
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Stacking Boom Conveyor to Coal Pile No. 2 (North)
2)
EU ID Number:
EU-260a
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-260
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-260, wet suppression
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Stacking Boom Conveyor to Coal Pile No. 2 (South)
2)
EU ID Number:
EU-260b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-260
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-260, wet suppression
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Stacker Reclaimer to Stacking Boom Conveyor (North Coal Pile)
2)
EU ID Number:
EU-261a
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-261
Previous Permit # is:
2,400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-261, wet suppression
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Stacking Boom Conveyor to Belt Conveyor BC-4 (North Coal Pile)
2)
EU ID Number:
EU-261b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-261
Previous Permit # is:
2,400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-261, wet suppression
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Stacker Reclaimer to Stacking Boom Conveyor (South Coal Pile)
2)
EU ID Number:
EU-261c
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-261
Previous Permit # is:
2,400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-261, wet suppression
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Stacking Boom Conveyor to Belt Conveyor BC-4 (South Coal Pile)
2)
EU ID Number:
EU-261d
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-261
Previous Permit # is:
2,400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-261, wet suppression
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-4 to Belt Conveyor BC-6 (Transfer Tower-2 (TT-2))
2)
EU ID Number:
EU-262a
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-262
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-262, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-4 to Belt Conveyor BC-7 (TT-2)
2)
EU ID Number:
EU-262b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-262
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-262, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
AIR CONSTRUCTION PERMIT APPLICATION
Form EU: Emission Unit Information
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-8 to Belt Conveyor BC-10 (TT-2)
2)
EU ID Number:
EU-262c
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-262
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-262, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-8 to Belt Conveyor BC-11 (TT-2)
2)
EU ID Number:
EU-262d
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-262
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-262, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-9 to Belt Conveyor BC-10 (TT-2)
2)
EU ID Number:
EU-262e
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-262
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-262, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-9 to Belt Conveyor BC-11 (TT-2)
2)
EU ID Number:
EU-262f
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-262
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-262, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-4 to Belt Conveyor BC-10 (TT-2)
2)
EU ID Number:
EU-262g
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-262
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-262, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-4 to Belt Conveyor BC-10 (TT-2)
2)
EU ID Number:
EU-262h
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-262
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-262, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-6 to Coal Stockout Pile No. 3
2)
EU ID Number:
EU-263
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-263
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
CE-263, Telescopic chute and wet
suppression
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
No
If Yes, Control Equipment name/ID are:
Yes
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Reclaim Hopper RH-2 to Belt Feeder BF-4
2)
EU ID Number:
EU-264a
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-264
Previous Permit # is:
2,400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-264, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Feeder BF-4 to Belt Conveyor BC-8
2)
EU ID Number:
EU-264b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-264
Previous Permit # is:
2,400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-264, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-7 to Coal Stockout Pile No. 4
2)
EU ID Number:
EU-265
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-265
Previous Permit # is:
4,000 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
CE-265, Telescopic chute and wet
suppression
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
No
If Yes, Control Equipment name/ID are:
Yes
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
4
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Reclaim Hopper RH-3 to Belt Feeder BF-5
2)
EU ID Number:
EU-266a
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-266
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-266, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Feeder BF-5 to Belt Conveyor BC-9
2)
EU ID Number:
EU-266b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-266
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-266, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-10 to Crusher Surge Bin SB-1 (Crusher House-1 (CH-1))
2)
EU ID Number:
EU-267a
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-267
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-267, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-11 to Crusher Surge Bin SB-1 (CH-1)
2)
EU ID Number:
EU-267b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-267
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-267, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Crusher Surge Bin SB-1 to Belt Feeder BF-6 (CH-1)
2)
EU ID Number:
EU-267c
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-267
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-267, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Crusher Surge Bin SB-1 to Belt Feeder BF-7 (CH-1)
2)
EU ID Number:
EU-267d
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-267
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-267, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Crusher-1 (CH-1)
2)
EU ID Number:
EU-267e
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-267
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-267, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Crusher-2 (CH-1)
2)
EU ID Number:
EU-267f
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-267
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-267, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Feeder BF-6 to Belt Conveyor BC-13 through Coal Crusher CR-1 (CH-1)
2)
EU ID Number:
EU-267g
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-267
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-267, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Feeder BF-7 to Belt Conveyor BC-12 through Coal Crusher CR-2 (CH-1)
2)
EU ID Number:
EU-267h
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-267
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-267, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-12 to Belt Conveyor BC-14 (Transfer Tower-4 (TT-4))
2)
EU ID Number:
EU-268a
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-268
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-268, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-12 to Belt Conveyor BC-15 (TT-4)
2)
EU ID Number:
EU-268b
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-268
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-268, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-13 to Belt Conveyor BC-14 (TT-4)
2)
EU ID Number:
EU-268c
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-268
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-268, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-13 to Belt Conveyor BC-15 (TT-4)
2)
EU ID Number:
EU-268d
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-268
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-268, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-14 to Coal Silos and Silo Storage (Unit No. 4 Boiler House)
2)
EU ID Number:
EU-268e
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-268
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-268, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-15 to Coal Silos and Silo Storage (Unit No. 4 Boiler House)
2)
EU ID Number:
EU-268f
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-268
Previous Permit # is:
1,200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-268, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
AIR CONSTRUCTION PERMIT APPLICATION
Form EU: Emission Unit Information
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Reclaim Hopper RH-4 to Belt Feeder BF-8
2)
EU ID Number:
EU-269a
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-269
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-269, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Feeder BF-8 to Belt Conveyor BC-5A
2)
EU ID Number:
EU-269b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-269
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-269, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Reclaim Hopper RH-5 to Belt Feeder BF-9
2)
EU ID Number:
EU-269c
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-269
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-269, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Feeder BF-9 to Belt Conveyor BC-5A
2)
EU ID Number:
EU-269d
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-269
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-269, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-5A to Belt Conveyor BC-5B (Transfer Tower (TT-3))
2)
EU ID Number:
EU-270
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-270
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-270, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Belt Conveyor BC-5B to Surge Hopper HPR-2 (Existing Transfer Tower)
2)
EU ID Number:
EU-271
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-271
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are:
CE-271, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Transfer Point- Surge Hopper HPR-2 to Future Truck Loadout (Existing Transfer Tower)
2)
EU ID Number:
EU-272
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP-272
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
200 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-272,
Yes
Chute/Enclosure/Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Emergency Coal Stockout Pile No. 1 (Fugitive)
2)
EU ID Number:
EU-273
3)
EU Type:
4)
Manufacturer:
N/A
5)
Model:
N/A
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-273
Previous Permit # is:
Exposed Surface Area: 0.85 Acres
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are: CE-273, Water Cannon/Surfactant Spray
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
Only Utilized During Emergency
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Stockout Pile No. 2-North (Fugitive)
2)
EU ID Number:
EU-274
3)
EU Type:
4)
Manufacturer:
N/A
5)
Model:
N/A
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-274
Previous Permit # is:
Exposed Surface Area: 5.82 Acres
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-274, Water Cannon, Surfactant Spray
and Berm
Yes
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
Operation Hour Limits:
No
Yes
If Yes, check below and write down all that apply
Bulldozing limited to not more than 8 hours per day on this pile
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
Air Quality Impacts
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Stockout Pile No. 2-South (Fugitive)
2)
EU ID Number:
EU-275
3)
EU Type:
4)
Manufacturer:
N/A
5)
Model:
N/A
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-275
Previous Permit # is:
Exposed Surface Area: 6.68 Acres
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-275, Water Cannon, Surfactant Spray
and Berm
Yes
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
Operation Hour Limits:
No
Yes
If Yes, check below and write down all that apply
Bulldozing limited to not more than 8 hours per day on this pile
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
Air Quality Impacts
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Stockout Pile No. 3 (Fugitive)
2)
EU ID Number:
EU-276
3)
EU Type:
4)
Manufacturer:
N/A
5)
Model:
N/A
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-276
Previous Permit # is:
Exposed Surface Area: 0.85 Acres
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are: CE-276, Water Cannon, Surfactant Spray
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
Operation Hour Limits:
No
Yes
If Yes, check below and write down all that apply
Bulldozing limited to not more than 8 hours per day on this pile
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
Air Quality Impacts
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Coal Stockout Pile No. 4 (Fugitive)
2)
EU ID Number:
EU-277
3)
EU Type:
4)
Manufacturer:
N/A
5)
Model:
N/A
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-277
Previous Permit # is:
Exposed Surface Area: 0.85 Acres
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are: CE-277, Water Cannon, Surfactant Spray
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
Operation Hour Limits:
No
Yes
If Yes, check below and write down all that apply
Bulldozing limited to not more than 8 hours per day on this pile
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
Air Quality Impacts
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
North Gate Haul Road (Fugitive)
2)
EU ID Number:
EU-278
3)
EU Type:
4)
Manufacturer:
N/A
5)
Model:
N/A
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-278
Previous Permit # is:
Haul Road Length: 0.48 miles (one way)
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are: CE-278, Paving and Speed Reduction
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
West Gate Haul Road (Fugitive)
2)
EU ID Number:
EU-279
3)
EU Type:
4)
Manufacturer:
N/A
5)
Model:
N/A
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-279
Previous Permit # is:
Haul Road Length: 0.86 miles (one way)
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
Yes
If Yes, Control Equipment name/ID are: CE-279, Paving and Speed Reduction
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Railcar/Truck Unloading to Hopper HPR-1 (Limestone Dumper Area)
2)
EU ID Number:
EU-280
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-280a and EP 280b
Previous Permit # is:
600 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-280a/b,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Hopper HPR-1 to Belt Feeder FDR-1
2)
EU ID Number:
EU-281a
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-281
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
450 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-281,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EU: Emission Unit Information
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Hopper HPR-1 to Belt Feeder FDR-2
2)
EU ID Number:
EU-281b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-281
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
450 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-281,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Belt Feeder FDR-1 to Receiving Conveyor CVY-1
2)
EU ID Number:
EU-281c
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-281
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
450 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-281,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Belt Feeder FDR-2 to Receiving Conveyor CVY-1
2)
EU ID Number:
EU-281d
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-281
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
450 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-281,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Receiving Conveyor CVY-1 to Limestone Building Storage
2)
EU ID Number:
EU-282
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP-282a and b (pile)
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
600 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-282,
Yes
Telescopic Chute, Wet
Suppression and Partial Enclosure
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Vibrating Drawdown Hopper HPR-2 to Belt Feeder FDR-3
2)
EU ID Number:
EU-283a
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP-283
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-283,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Vibrating Drawdown Hopper HPR-3 to Belt Feeder FDR-4
2)
EU ID Number:
EU-283b
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP-283
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-283,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Belt Feeder FDR-3 to Reclaim Conveyor CVY-2
2)
EU ID Number:
EU-283c
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-283
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-283,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Belt Feeder FDR-4 to Reclaim Conveyor CVY-2
2)
EU ID Number:
EU-283d
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP-283
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-283,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Reclaim Conveyor CVY-2 to Limestone Silo No. 1 and Silo Storage
2)
EU ID Number:
EU-284
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP-284
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-284,
Yes
Bin Vent Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Reclaim Conveyor CVY-2 to Distribution Conveyor CVY-3
2)
EU ID Number:
EU-285a
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP-285
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-285,
Yes
Bin Vent Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Limestone Transfer Point- Distribution Conveyor CVY-3 to Limestone Silo No. 2 and Silo Storage
2)
EU ID Number:
EU-285b
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-285
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
400 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-285,
Yes
Bin Vent Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Saleable Fly Ash Transfer Point- Pneumatic Conveyor System Exhaust (Mechanical Exhaust)
2)
EU ID Number:
EU-286
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-286a and EP 286b
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
1.31 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-286
Yes
a/b, Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Saleable Fly Ash Silo and Loading Operations
2)
EU ID Number:
EU-287
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-287
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
1.31 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-287,
Yes
Bin Vent Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Saleable Fly Ash Storage Building
2)
EU ID Number:
EU-288
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-288a and EP-288b
Previous Permit # is:
20.87 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-288a/b,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Waste Fly Ash Transfer Point- Pneumatic Conveyor System Exhaust (Mechanical Exhaust)
2)
EU ID Number:
EU-289
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP ID Number:
Modification to a Permitted Source
EP-289a and EP-289b
Previous Permit # is:
1.31 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-289a/b,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Waste Fly Ash Silo and Loading Operations
2)
EU ID Number:
EU-290
3)
EU Type:
New Source
Unpermitted Existing Source
4)
Manufacturer:
TBD
5)
Model:
TBD
6a) Maximum Nameplate Capacity:
6b)
EP-290
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
20.87 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-290,
Yes
Bin Vent Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR CONSTRUCTION PERMIT APPLICATION
AIR QUALITY BUREAU
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
PAC Silo- Transfer and Storage
2)
EU ID Number:
EU-291
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-291
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
40 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-291,
Yes
Bin Vent Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Transfer of Sorbent to Day Silo and Silo Storage
2)
EU ID Number:
EU-292
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-292
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
40 tons/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-292,
Yes
Bin Vent Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Transfer of Sorbent to Long Term Storage Silo and Silo Storage
2)
EU ID Number:
EU-293
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-293
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
1 ton/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-293,
Yes
Bin Vent Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Lime Transfer to Lime Silo and Silo Storage for Water Treatment Process
2)
EU ID Number:
EU-294
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
EP-294
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
0.5 ton/hour
Maximum Process Design Capacity
(if different than 6a)
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-294,
Yes
Bin Vent Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Biomass Material Handling Operations –Line 1
2)
EU ID Number:
EU-295
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
Maximum Process Design Capacity
(if different than 6a)
EP-295
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
25 ton/hour
22 tons per hour
7)
Date of Construction:
November 2008
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-295,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
Form EU: Emission Unit Information
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instruction on reverse side
IPL-Sutherland Generating Station Unit 4
Company Name:
EMISSION UNIT (PROCESS) IDENTIFICATION & DESCRIPTION
1)
Emission Unit (EU) Name:
Biomass Material Handling Operations –Line 2
2)
EU ID Number:
EU-296
3)
EU Type:
4)
Manufacturer:
TBD
5)
Model:
TBD
New Source
Unpermitted Existing Source
6a) Maximum Nameplate Capacity:
6b)
Maximum Process Design Capacity
(if different than 6a)
EP-296
EP ID Number:
Modification to a Permitted Source
Previous Permit # is:
25 ton/hour
22 tons per hour
7)
Date of Construction:
TBD
8)
Date of Modification (if applicable)
N/A
9)
Is this a Controlled Emission Unit?
No
If Yes, Control Equipment name/ID are: CE-296,
Yes
Fabric Filter
EMISSION UNIT OPERATING SCHEDLULE (hours/day, hours/year, or other)
10)
Actual Operation
TBD
11)
Maximum Operation
8,760 hours/year
REQUESTED LIMITS
12) Are you requesting any permit limits?
No
Yes
If Yes, check below and write down all that apply
Operation Hour Limits:
Production Limits:
Material Usage Limits
Limits Based on Stack Testing
Please attach all relevant stack testing summary reports
Other:
Rationale for Requesting the
Limit(s):
13
PROCESS DESCRIPTION
Provide a description AND a drawing to show quantitatively how product or material flows through this emission unit.
Include product input and output, fuel throughput, and any parameters which impact air emissions. If space below is
insufficient, attach a separate sheet labeled EU-11A.
Please see technical support document for description of this emission unit. The process flow drawings and material handling
emission calculations are located in Appendix D and Appendix G of the Application Package, respectively.
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EU
ATTN: Application Log in
AIR QUALITY BUREAU
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
AIR CONSTRUCTION PERMIT APPLICATION
Form EU5: Boiler Information
Please see instruction on reverse side
EXEMPTION
According to 567 Iowa Administrative Code Chapter 22.1(2)a, an indirect fired combustion source that
uses only Natural Gas or LPG and has a heating capacity of less than 10 MMBTU/hr is exempted from the
provisions of construction permits.
According to 567 Iowa Administrative Code Chapter 22.1(2)b, an indirect fired combustion source that
uses coal, fuel oil or untreated wood, seeds, pellets, other vegetable matter and has a heating capacity of less
than 1 MMBTU/hr is exempted from the provisions of construction permits.
Company Name: IPL-Sutherland Generating Station Unit 4
BOILER (EMISSION UNIT) DESCRIPTION AND SPECIFICATIONS
New Unit
Unpermitted Existing Unit
(1) Boiler ID Number: EU-297
Modification to an unit with Permit #:
(2) Rated Capacity (MMBTU/hr heat input): 3 MMBTU/hr Gate Station Heater
(3) Construction Date: November 2008 (4) Manufacturer: TBD
(5) Model: TBD
(6) Date of Modification (if applicable):
N/A
(8) Control Device (if any):
(7) Serial Number (if available):
TBD
FUEL DESCRIPTION AND SPECIFICATIONS
(9) Fuel Type
Natural Gas
Fuel Oil (# )
(cf/hr)
(10) Full Load
Consumption Rate
(11) Sulfur Content wt%
(gal/hr)
Coal type:
(lb/hr)
Coal type:
(lb/hr)
Other Fuels
(lb/hr)
2,941
N/A
(12) Requested Limit
N/A
None
OPERATING LIMITS & SCHEDULE
(13) Imposed Operating Limits (hours/year, or gallons fuel/year, etc.):
None
(14) Operating Schedule (hours/day, months/year, etc.):
24 hours/day, 12 months/year
STACK/VENT (EMISSION POINT) SPECIFICATIONS
(15) Stack/Vent ID:
EP-297
(17) Stack Height (feet) from the Ground:
20
(18) Stack Height (feet)
above the Building (If Applicable):
(16) Stack Opening Size:
circular, diameter (inches) is: 15
other, size (inches x inches) is:
(19) Discharge Style:
V (Vertical, without rain cap or with unobstructing rain cap)
VR (Vertical, with obstructing rain cap)
H (Horizontal discharge)
D (Downward discharge; for example, a goose neck stack)
(20) Distance (feet) from the Property Line:
367
(21) Rated Flow Rate (
1,429
acfm
scfm):
EXHAUST INFORMATION
(22) Moisture Content % (if known):
For Assistance 1-877AIR IOWA (1-877-247-4692)
(23) Exit Temperature (°F)
700
DNR Form 542-3190-05
Revised 11/2006
EU
EMISSION POINT FORMS
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-05
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-254a
2) Stack Opening size:
circular, diameter (inches) 78
other size (inches x inches)
3) Height from ground (feet): 18
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 75,657
SCFM:
10) Does this emission point have control equipment?
No
Yes; If yes, provide control ID: CE-254a
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-254a
EP-254b
CE254a
FF
CE254b
FF
EU 254
Rotary Car Dumper
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-254b
2) Stack Opening size:
circular, diameter (inches) 78
other size (inches x inches)
3) Height from ground (feet): 18
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 75,657
SCFM:
10) Does this emission point have control equipment?
No
Yes; If yes, provide control ID: CE-254b
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-254a
EP-254b
CE254a
FF
CE254b
FF
EU 254
Rotary Car Dumper
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-255
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 12
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 7,500
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-255
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-255
CE255
FF
EU 255 a through d
Rotary Car Dumper Area
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-256
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 55
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 7,500
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-256
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-256
CE256
FF
EU 256 a through c
Transfer Tower TT-1
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-258
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 55
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 7,500
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-258
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-258
CE258
FF
EU 258 a and b
Emergency Coal Pile
Reclaim
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-262
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 65
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 7,500
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-262
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-262
CE262
FF
EU 262 a through h
Transfer Tower TT-2
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-264
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 12
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 6,927
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-264
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-264
CE264
FF
EU 264 a and b
Reclaim from Coal Pile No. 3
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID: EP-266
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 12
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 7,500
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-266
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-266
CE266
FF
EU 266 a and b
Reclaim from Coal Pile No. 4
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-267
2) Stack Opening size:
circular, diameter (inches) 48
other size (inches x inches)
3) Height from ground (feet): 125
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 30,159
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-267
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-267
CE267
FF
EU 267 a through h
Crusher House CH-1
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-268
2) Stack Opening size:
circular, diameter (inches) 63.6
other size (inches x inches)
3) Height from ground (feet): 190
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 52,948
SCFM:
10) Does this emission point have control equipment?
No
Yes; If yes, provide control ID: CE-268
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-268
CE268
FF
EU 268 a through f
Transfer Tower TT-4 and
Boiler House
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-269
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 12
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 7,500
SCFM:
10) Does this emission point have control equipment?
No
Yes; If yes, provide control ID: CE-269
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-269
CE269
FF
EU 269 a through d
Reclaim from Coal Pile 2
(North)
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-270
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 35
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 7,500
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-270
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-270
CE270
FF
EU 270
Transfer Tower TT-3
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-271
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 65
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 7,500
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-271
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-271
CE271
FF
EU 271
Existing Transfer Tower
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-272
2) Stack Opening size:
circular, diameter (inches) 30
other size (inches x inches)
3) Height from ground (feet): 50
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 12,000
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-272
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-272
CE272
FF
EU 272
Future Truck Loadout
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-280a
2) Stack Opening size:
circular, diameter (inches) 78
other size (inches x inches)
3) Height from ground (feet): 18
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 75,657
SCFM:
10) Does this emission point have control equipment?
No
Yes; If yes, provide control ID: CE-280a
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-280a
EP-280b
CE280a
FF
CE280b
FF
EU 280
Limestone Rail Car
Dumper
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-280b
2) Stack Opening size:
circular, diameter (inches) 78
other size (inches x inches)
3) Height from ground (feet): 18
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 75,657
SCFM:
10) Does this emission point have control equipment?
No
Yes; If yes, provide control ID: CE-280b
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-280a
EP-280b
CE280a
FF
CE280b
FF
EU 280
Limestone Rail Car
Dumper
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-281
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 12
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 7,500
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-281
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-281
CE281
FF
EU 281 a through d
Limestone Transfer
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-283
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 23
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 7,500
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-283
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-283
CE283
FF
EU 283 a through d
Reclaim from Limestone
Storage Pile
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-284
2) Stack Opening size:
circular, diameter (inches) 12
other size (inches x inches)
3) Height from ground (feet): 125
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 1,650
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-284
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-284
CE284
Bin Vent
EU 284
Limestone Silo-1
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-285
2) Stack Opening size:
circular, diameter (inches) 12
other size (inches x inches)
3) Height from ground (feet): 125
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 1,650
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-285
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-285
CE285
Bin Vent
EU 285 a and b
Limestone Silo-2
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-286a
2) Stack Opening size:
circular, diameter (inches) 15
other size (inches x inches)
3) Height from ground (feet): 50
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 3,681
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-286
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-286a
EP-286b
CE286a
FF
CE286b
FF
EU 286
Saleable Fly Ash Transfer
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-286b
2) Stack Opening size:
circular, diameter (inches) 15
other size (inches x inches)
3) Height from ground (feet): 50
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 3,681
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-286 b
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-286a
EP-286b
CE286a
FF
CE286b
FF
EU 286
Saleable Fly Ash Transfer
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-287
2) Stack Opening size:
circular, diameter (inches) 13.20
other size (inches x inches)
3) Height from ground (feet): 105
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 1,995
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-287
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-287
CE287
Bin Vent
EU 287
Saleable Fly Ash Silo
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-288a
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 23
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 20,204
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-288a
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-288a
EP-288b
CE288a
FF
CE288b
FF
EU 288
Saleable Fly Ash Storage
Building
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-288b
2) Stack Opening size:
circular, diameter (inches) 42
other size (inches x inches)
3) Height from ground (feet): 23
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 20,204
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-288b
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-288a
EP-288b
CE288a
FF
CE288b
FF
EU 288
Saleable Fly Ash Storage
Building
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-289a
2) Stack Opening size:
circular, diameter (inches) 9.6
other size (inches x inches)
3) Height from ground (feet): 50
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 1,500
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-289a
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-289a
EP-289b
CE289a
FF
CE289b
FF
EU 289
Waste Fly Ash Transfer
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-289b
2) Stack Opening size:
circular, diameter (inches) 9.6
other size (inches x inches)
3) Height from ground (feet):
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 1,500
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-289b
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-289a
EP-289b
CE289a
FF
CE289b
FF
EU 289
Waste Fly Ash Transfer
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-290
2) Stack Opening size:
circular, diameter (inches) 13.2
other size (inches x inches)
3) Height from ground (feet): 105
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 2,000
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-290
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-290
CE290
Bin Vent
EU 290
Waste Flyash Storage Silo
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-291
2) Stack Opening size:
circular, diameter (inches) 39.37
other size (inches x inches)
3) Height from ground (feet): 115
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 1.66
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-291
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-290
CE290
Bin Vent
EU 290
PAC Silo
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-292
2) Stack Opening size:
circular, diameter (inches) 39.37
other size (inches x inches)
3) Height from ground (feet): 115
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 1.66
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-292
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-292
CE292
Bin Vent
EU 292
Sorbent Day Storage Silo
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-293
2) Stack Opening size:
circular, diameter (inches) 39.37
other size (inches x inches)
3) Height from ground (feet): 280
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 1.66
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-293
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-293
CE293
Bin Vent
EU 293
Sorbent Long Term Storage
Silo
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-294
2) Stack Opening size:
circular, diameter (inches) 39.37
other size (inches x inches)
3) Height from ground (feet): 77
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 1.66
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-294
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-294
CE294
Bin Vent
EU 294
Lime Silo
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-295
2) Stack Opening size:
circular, diameter (inches) 30
other size (inches x inches)
3) Height from ground (feet): 50
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 24,800
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-295
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-295
CE295
FF
EU 295
Biomass Material Handling
Line -1
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EP Stack/Vent Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) EP Number ID:EP-296
2) Stack Opening size:
circular, diameter (inches) 30
other size (inches x inches)
3) Height from ground (feet): 50
4) Height from highest building level (feet): Refer to Building Profile Input Program (BPIP) Analysis in the Technical
Support Document
5) Distance from the nearest property line (feet): Refer to Plot Plan in Appendix A of the Technical Support Document
Vertical (without rain cap or with unobstructing rain cap)
VR (Vertical, with obstruction rain cap)
6) Discharge Style (check one)
D (Downward discharge; for example, a goose neck stack)
H (Horizontal discharge)
I (Inside-Vent inside building)
Exhaust Information
7) Moisture Content % (if known):
9) Rated Flow Rate:
8) Exit Temperature (Fahrenheit): 47.4 °F
ACFM: 24,800
10) Does this emission point have control equipment?
SCFM:
No
Yes; If yes, provide control ID: CE-296
Air Emissions Pathway Diagram
11)
Air Emissions Pathway Diagram
(see examples on reverse-side)
EP-296
CE296
FF
EU 296
Biomass Material Handling
Line -2
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
EP
CONTROL EQUIPMENT FORMS
For Assistance 1-877AIR IOWA (1-877-247-4692)
DNR Form 542-3190-13
Revised 11/2006
CE
IOWA DNR Air Construction Permit Application
AIR QUALITY BUREAU
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-248A
2) Emission Point(s) ID: EP-248
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Selective Catalytic Reduction (SCR)
6) Date of Construction: November 2008
7) Date of Modification: N/A
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
12)
11) Date of Hood Modification (if any): N/A
Pollutant Controlled
PM
PM10
VOC
SO2
Control
Efficiency
NOx
CO
Other(
See BACT
Analysis
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
For Assistance 1-877AIR IOWA (1-877-247-4692)
Revised 11/2006
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: N/A (See Below)
2) Emission Point(s) ID: EP-248
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Dry Electrostatic Precipitator (DESP)
6) Date of Construction: November 2008
7) Date of Modification: N/A
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
12)
11) Date of Hood Modification (if any): N/A
Pollutant Controlled
PM
PM10
VOC
SO2
NOx
CO
Other(
)
Control
Efficiency
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
The DESP is used on an as-needed basis for scavenging saleable flyash and is not considered as BACT. Compared to a
full scale ESP designed for primary particulate control, the proposed scavenging DESP is a much undersized unit that is
designed only to operate as process equipment to segregate fly ash for beneficial reuse. The installation of the
scavenging DESP does not fall under any BACT requirement, since it will not be used for primary control or emissions
compliance. Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-248B
2) Emission Point(s) ID: EP-248
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Powdered Activated Carbon (PAC) Injection
6) Date of Construction: November 2008
7) Date of Modification: N/A
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
12)
Pollutant Controlled
PM
Control
Efficiency
11) Date of Hood Modification (if any): N/A
PM10
VOC
SO2
NOx
CO
Other(Hg)
See Below
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Mercury reduction will be achieved as a co-benefit of BACT. Any additional reductions needed will be obtained by PAC
injection. Please refer to the BACT analysis in Appendix H of the Application Package.
CE1
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-248C
2) Emission Point(s) ID: EP-248
3) Manufacturer: TBD
5) Control Equipment Type:
4) Model Number: TBD
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: N/A
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any): N/A
16)
Pollutant Controlled
PM
Control Efficiency
PM10
See BACT Analysis
Other(
)
See BACT Analysis
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
For Assistance 1-877AIR IOWA (1-877-247-4692)
Revised 11/2006
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE3 Control Equipment Information for Wet Scrubbers
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station
1) CE Number ID: CE-248D
2) Emission Point(s) ID: EP-248
3) Manufacturer: TBD
5) Type of Scrubber :
4) Model Number: TBD
Packed Bed
Spray Chamber
Venturi
Other
6) Total Liquor Flow Rate (gallons per minute) : TBD
7) Recycled Liquor Flow Rate (gallons per minute) : TBD
8) Normal Liquor pH : TBD
9) Pressure drop across Scrubber (in H2O): TBD
10) Date of Construction: November 2008
11) Date of Modification: N/A
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any): N/A
16)
Pollutant Controlled
PM
PM10
Control Efficiency
VOC
Other(SO2)
See BACT Analysis
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-248E
2) Emission Point(s) ID: EP-248
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Sorbent Injection for SO3 control.
6) Date of Construction: November 2008
7) Date of Modification: N/A
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
12)
Pollutant Controlled
PM
Control
Efficiency
11) Date of Hood Modification (if any): N/A
PM10
VOC
SO2
NOx
CO
Other(SO3)
See BACT
Analysis
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Sorbent will be injected after the air heater. Please refer to the BACT analysis in Appendix H of the Application Package.
CE1
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-254a
2) Emission Point(s) ID: EP-254a
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
For Assistance 1-877AIR IOWA (1-877-247-4692)
Revised 11/2006
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-254b
2) Emission Point(s) ID: EP-254b
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-255
2) Emission Point(s) ID: EP-255
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-256
2) Emission Point(s) ID: EP-256
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-257
2) Emission Point(s) ID: EP-257
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Telescopic Chute and Wet Suppression
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
95%
VOC
SO2
NOx
CO
Other(
95%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-258
2) Emission Point(s) ID: EP-258
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-259
2) Emission Point(s) ID: EP-259
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Telescopic Chute and Wet Suppression
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
95%
VOC
SO2
NOx
CO
Other(
95%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-260
2) Emission Point(s) ID: EP-260
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Wet Suppression
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
95%
VOC
SO2
NOx
CO
Other(
95%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-261
2) Emission Point(s) ID: EP-261
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Wet Suppression
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
95%
VOC
SO2
NOx
CO
Other(
95%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-262
2) Emission Point(s) ID: EP-262
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-263
2) Emission Point(s) ID: EP-263
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Telescopic Chute and Wet Suppression
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
95%
VOC
SO2
NOx
CO
Other(
95%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-264
2) Emission Point(s) ID: EP-264
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-265
2) Emission Point(s) ID: EP-265
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Telescopic Chute and Wet Suppression
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
95%
VOC
SO2
NOx
CO
Other(
95%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-266
2) Emission Point(s) ID: EP-266
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-267
2) Emission Point(s) ID: EP-267
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-268
2) Emission Point(s) ID: EP-268
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-269
2) Emission Point(s) ID: EP-269
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-270
2) Emission Point(s) ID: EP-270
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-271
2) Emission Point(s) ID: EP-271
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-272
2) Emission Point(s) ID: EP-272
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-273
2) Emission Point(s) ID: EP-273
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Water Cannon/Surfactant Spray
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
90%
VOC
SO2
NOx
CO
Other(
90%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-274
2) Emission Point(s) ID: EP-274
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Water Cannon/Surfactant Spray/Berm
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
95%
VOC
SO2
NOx
CO
Other(
95%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-275
2) Emission Point(s) ID: EP-275
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Water Cannon/Surfactant Spray/Berm
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
95%
VOC
SO2
NOx
CO
Other(
95%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-276
2) Emission Point(s) ID: EP-276
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Water Cannon/Surfactant Spray
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
90%
VOC
SO2
NOx
CO
Other(
90%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-277
2) Emission Point(s) ID: EP-277
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Water Cannon/Surfactant Spray
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
90%
VOC
SO2
NOx
CO
Other(
90%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-278
2) Emission Point(s) ID: EP-278
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Paving and Speed Reduction
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
95%
VOC
SO2
NOx
CO
Other(
95%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-279
2) Emission Point(s) ID: EP-279
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Paving and Speed Reduction
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
95%
VOC
SO2
NOx
CO
Other(
95%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-280a
2) Emission Point(s) ID: EP-280a
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-280b
2) Emission Point(s) ID: EP-280b
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-281
2) Emission Point(s) ID: EP-281
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form CE Control Equipment Information
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-282
2) Emission Point(s) ID: EP-282
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Description: Telescopic Chute/Wet Suppression/Partial Enclosure
6) Date of Construction: November 2008
7) Date of Modification: TBD
8) Capture Hood involved:
Yes
No
9) Capture Hood Efficiency (percentage): N/A
10) Date of Hood Installation: N/A
11) Date of Hood Modification (if any):
12)
Pollutant Controlled
PM
Control
Efficiency
PM10
95%
VOC
SO2
NOx
CO
Other(
95%
13) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-283
2) Emission Point(s) ID: EP-283
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-284
2) Emission Point(s) ID: EP-284
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99%
)
99%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-285
2) Emission Point(s) ID: EP-285
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99%
)
99%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-286a
2) Emission Point(s) ID: EP-286a
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-286b
2) Emission Point(s) ID: EP-286b
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
PM10
99.9%
Other(
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-287
2) Emission Point(s) ID: EP-287
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
PM10
99%
Other(
99%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-288a
2) Emission Point(s) ID: EP-288a
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-288b
2) Emission Point(s) ID: EP-288b
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-289a
2) Emission Point(s) ID: EP-289a
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
PM10
99.9%
Other(
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-289b
2) Emission Point(s) ID: EP-289b
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
PM10
99.9%
Other(
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-290
2) Emission Point(s) ID: EP-290
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
PM10
99%
Other(
99%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-291
2) Emission Point(s) ID: EP-291
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
PM10
99%
Other(
99%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-292
2) Emission Point(s) ID: EP-292
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
PM10
99%
Other(
99%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-293
2) Emission Point(s) ID: EP-293
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
PM10
99%
Other(
99%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-294
2) Emission Point(s) ID: EP-294
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
PM10
99%
Other(
99%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
)
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-295
2) Emission Point(s) ID: EP-295
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
Form CE1 Control Equipment Information for Fabric Filter
Equipment
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Please see instructions on the reverse side
Company Name IPL-Sutherland Generating Station Unit 4
1) CE Number ID: CE-296
2) Emission Point(s) ID: EP-296
3) Manufacturer: TBD
4) Model Number: TBD
5) Control Equipment Type:
Baghouse
Cartridge Filters
Bin vent Filters
Other
6) Material filter media made of: TBD
7) Total Filter Face area of control device (ft2): TBD
8) Pressure drop across Filter (in H2O): TBD
9) Bag cleaning method :
Pulse Jet
Shaking
Reverse Air
Other
10) Date of Construction: November 2008
11) Date of Modification: TBD
12) Capture Hood involved:
Yes
No
13) Capture Hood Efficiency (percentage): N/A
14) Date of Hood Installation: N/A
15) Date of Hood Modification (if any):
16)
Pollutant Controlled
PM
Control Efficiency
Other(
PM10
99.9%
)
99.9%
17) If manufacturer’s data is not available attach a separate sheet of paper to provide the control equipment design
specifications and performance data to support the above mentioned control efficiency.
Please refer to the BACT analysis in Appendix H of the Application Package.
AIR QUALITY BUREAU
Application Log in Desk
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
1) Company Name:
AIR CONSTRUCTION PERMIT APPLICATION
Form EC: Emission Calculations
Please see instructions on reverse side
IPL-Sutherland Generating Station Unit 4
2) Emission Point (Stack/Vent) Number:
EP-248 through EP-296
3) Emission Calculation (Please see instructions for proper way to calculate). This calculation is based on (check all that apply):
Emission Factors
Mass Balance
Testing Data
Other:
Calculations:
Please refer to Appendix G of the Technical Support Document for detailed emission calculations for all emission points.
5) POTENTIAL EMISSIONS: SUMMARY OF EMISSIONS FROM THIS EMISSION POINT
Pollutant
PM
PM10
PM2.5
SO2
NOx
VOC
CO
Lead
Single HAP
Total HAPs
Concentration, Unit:
lbs/hr
tons/year
For Assistance 1-877 AIRIOWA (1-877-247-4692)
(DNR Form 542-3190-16)
Revised 11/2006
EI
AIR QUALITY BUREAU
ATTN: Application Log in
IOWA DNR Air Construction Permit Application
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Form EI Facility Emission Inventory
Please see instructions on the reverse side
Company Name:
IPL-Sutherland Generating Station
PSD Classification:
Major
Minor
Unknown
STACK/VENT EMISSIONS SUMMARY
(1)
EP ID
(2)
EU ID
(3)
Source Description
(4)
(5)
Construction Date Permit Number
PM
(6) Potential or Permitted Emission Rate (tons/yr)
PM10 SO2 NOx VOC
CO Lead HAP THAP
Please Refer to Appendices G and I of
the Technical Support Document for
a Summary of Emission Points,
Emission Units and Associated
Potential Emission Rates
(7) Total Stack Emissions
Fugitive Emission Summary
(8) Source ID:
(9) Total Fugitive Emissions
(10) Total Plant Emissions
(DNR Form 542-3190-55)
For Assistance 1-877 Air Iowa (1-877-247-4692)
Revised 10/2005
MI2
AIR QUALITY BUREAU
ATTN: Application Log In
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Company Name:
AIR CONSTRUCTION PERMIT APPLICATION
FORM MI-2: Modeling Information (Emission Source Characteristics)
Please see instructions on reverse side
IPL-Sutherland Generating Station Unit 4
TABLE 1. SUMMARY OF EXISTING STACK/VENT EMISSION SOURCES
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Emission
Point ID
Number
Stack
Height
Stack Size
Exhaust
Temperature
Discharge
Style
Exhaust
Flow Rate
Operating Hours
Air Pollutant Emission Rate (lbs/hr) (estimated actual emission rate)
(inches)
(ºF)
(feet)
PM10
(acfm)
NOx
SO2
CO
Lead
Please Refer to Appendix I, Table 2 of the Technical Support Document for the
Information Requested in this Form.
TABLE 2. SUMMARY OF EXISTING FUGITIVE EMISSION SOURCES (PSD PROJECTS ONLY)
(9)
(10)
Source ID Source Description
Number
For Assistance 1-877-AIR-IOWA
(11)
(12)
Dimensions (feet)
Air Pollutant Emission Rate (lbs/hr) (estimated actual emission rate)
(Length x Width x Height)
PM10
NOx
SO2
CO
Lead
(1-877-247-4692)
(DNR Form 542-3190-56)
Revised 10/2006
AIR QUALITY BUREAU
AIR CONSTRUCTION PERMIT APPLICATION
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
FEDERAL REGULATION APPLICABILITY
Please see instructions on the reverse side
Company Name: IPL-Sutherland Generating Station Unit 4
APPLICABILITY DETERMINATION
1)
Will this project be subject to 1990 CAA Section
112(g) (Case-by-Case MACT)
NO
YES*
DON’T KNOW
* If YES then applicant must submit an application for a case-by-case MACT determination
[IAC 567 22-1(3)”b” (8)]
2)
Will this project be subject to a New Source
Performance Standard? (40 CFR part 60)
NO
YES*
DON’T KNOW
*If YES please identify sub-part __Da, Y, OOO__________________________________
3)
Will this project be subject to a MACT (Maximum
Achievable Control Technology) Regulation?
(40 CFR part 63)
NO
YES*
DON’T KNOW
*If YES please identify sub-part ___DDDDD (Vacated), ZZZZ______________________
THIS ONLY APPLIES IF THE PROJECT EMITS A HAZARDOUS
AIR POLLUTANT – SEE TABLE A FOR LIST
4)
5)
6)
Will this project be subject to a NESHAP
(National Emission Standards for Hazardous Air
Pollutants) Regulation? (40 CFR part 61)
Will this project be subject to PSD (Prevention of
Significant Deterioration) ?
(40 CFR section 52.21)
NO
YES*
DON’T KNOW
*If YES please identify sub-part ________________________________________
NO
YES
NO
YES*
DON’T KNOW
DON’T KNOW
Was netting done for this project to avoid PSD?
*If YES please attach netting calculations
IF YOU ARE UNSURE HOW TO ANSWER ANY OF THESE QUESTIONS CALL 1-877 AIR IOWA
Federal Regulations Applicability Form Instructions
This form is designed to provide the review engineer information regarding applicable federal regulations. This project may be subject to a federal
regulation. These regulations have also been adopted by the state of Iowa in IAC 567 23.1(1), 23.1(2), 23.1(3), 23.1(4) and 23.1(5).
1)
The 112(g) provision is a transitional measure to ensure that facilities protect the public from hazardous air pollutants until EPA issues MACT
standards that apply to the facilities. If this project is already subject to a MACT regulation it will not be subject to the provisions of 112 (g).
2)
New Source Performance Standards are Federal Regulations that apply to a wide range of sources of criteria air pollutants. To locate the rule go
to http://www.access.gpo.gov/nara/cfr/waisidx_01/40cfr60_01.html
MACT regulations apply to sources of hazardous air pollutants. See Table A for a list of hazardous air pollutants. To locate the rule - go to:
3)
www.epa.gov/ttn/atw/mactfnl.html.
4)
NESHAP regulations apply to sources of the following pollutants: beryllium, mercury, vinyl chloride, radionuclides, benzene, asbestos and arsenic.
To locate the rule - go to www.access.gpo.gov/nara/cfr/waisidx_02/40cfr61_02.html
5) If you are a PSD major source and the net emissions increase from this project exceeds significance levels
(as defined by 40 CFR 52.21) this project will be subject to PSD regulations. Please contact DNR prior to
AIR QUALITY BUREAU
IOWA DNR Air Construction Permit Application
ATTN: Application Log in
7900 Hickman Rd., Suite 1
Urbandale, IA 50322
Company Name:
Form GHG: Project Greenhouse Gas Emission Inventory
Please see instructions on the reverse side
Please attach a copy of your calculations showing how the potential GHG emissions were calculated to this form
IPL-Sutherland Generating Station Unit 4
Plant Number:
64-01-012
EMISSIONS SUMMARY
(1)
EP ID
(2)
EU ID
(3)
Source Description
CO2 (tpy)
(4) Potential Emission Rate
CH4 (tpy)
N2O (tpy)
SF6 (lb/yr)
248
248
Unit 4 Boiler
5.74E+06
6.79E+02
9.70E+01
249
248
Auxiliary Boiler
3.13E+04
3.49E+00
5.37E-02
250
250
Emergency Diesel Engine
1.52E+02
4.58E-03
1.53E-03
251
251
Emergency Fire Pump (Main)
3.17E+01
9.57E-04
3.19E-04
252
252
Emergency Fire Pump (Booster)
1.04E+01
3.14E-04
1.05E-05
297
297
Gate Station Heater
1.53E+03
1.71E-01
2.63E-03
253
253
Linear Mechanical Draft Cooling Tower
0.00
0.00
0.00
254-279
254-279
Coal Material Handling
0.00
0.00
0.00
280-285
280-285
Limestone Material Handling
0.00
0.00
0.00
286-288
286-288
Saleable Flyash Handling and Storage
0.00
0.00
0.00
289-290
289-290
Waste Flyash Handling and Storage
0.00
0.00
0.00
291-294
291-294
Material Handling - Others
0.00
0.00
0.00
295-296
295-296
Biomass Material Handling
0.00
0.00
0.00
5.78E+06
6.83E+02
97.04
(5) Total Project Emissions
HFCs (lb/yr)
PFCs (lb/yr)
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Attachment 1
Coal and Limestone Handling Dust Collection Systems
Dust Collectors:
The coal & limestone handling systems will be provided with dry type dust collection
systems to reduce the amount of fugitive dust allowed to escape into the atmosphere,
from the coal & limestone handling transfer points. The dust collectors will be provided
at the following locations.
Coal handling system:
• Rail Car Unloading building and hoppers
• Crusher House building
• Mill Bunker building
Limestone handling system:
• Rail Car Unloading building and hoppers
The function of the dust collectors will be to filter the dust-laden air collected at the
various pick-up points and provide immediate storage for the dust particles removed from
the air streams.
The dust collectors will be induced draft, top access fabric filter type units enclosed in
stiffened steel plate housings. Filter cleaning will be by cyclic impulse air jet reverse
flow into the bags. The subcomponents of the collectors will include the unit housing
and hopper, filter bags, filter support cages, cleaning air distribution valve and manifold,
collector access, and all associated electrical and control devices.
Each individual dust collector system will be bounded by the inlet and outlet dust stream
ductwork, the bag cleaning mechanism supply air pipe or duct, rotary vane valve, and the
support structure as applicable.
The unfiltered air entrance will be baffled to distribute air evenly to the filter media and
to reduce the velocity of the incoming air so that larger dust particles may precipitate
directly to the bottom hoppers.
The collector housings will be all welded airtight and watertight, fabricated from not less
than 12 gauge steel plate, and stiffened to withstand the specified differential air pressure
acting on the housing as well as any other live loadings specified.
Access stairs and platforms will be provided to all areas of the structure where frequent
and convenient access is necessary. Cage type ladders are used for access to remote
areas.
Hand railings and kick plates will be provided on all open platforms and along stairways
and walkways.
082907-145491
1
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Attachment 1
For coal handling system units, the collector housings will be equipped with internal fire
protection sprinkler headers. The filter bags will be flame proofed and grounded to
dissipate static electric charges.
Filter bags will have their shape maintained by bag cages. Attachment of the open ends
of bags will be by snap rings or an equally acceptable method and will be secured to
prevent side movement of the cages.
The dust collection hoppers will be constructed with a smooth transition from the main
section to the pyramidal or troughed type bottom sections.
Each dust collector hopper will be equipped with dust level alarm units. The alarms will
utilize an admittance probe detector with solid-state logic.
A typical coal dust collection system is shown in Figure 1. A cutaway section of a
typical dust collector is shown in Figure 2.
Figure 1
Dust Collection System
082907-145491
2
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Attachment 1
Clean
Air
Dirty Air
Bag Filters
Figure 2
Cutaway Section of a Dust Collector
Bin Vent Filters
082907-145491
3
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Attachment 1
The limestone handling system will be provided with Bin vent filters on top of the
limestone storage silos, to reduce the amount of fugitive dust allowed to escape into the
atmosphere. The Bin vent filters will be typically pulse jet bag-house type, and will be
sized at the proper air to cloth ratio, based on the system requirement. The Bin vent
filters will be provided at the following locations in the limestone handling system.
•
Top of each limestone storage silo
Similar to the dust collectors described above, the Bin vent filters will be used to separate
the fine fugitive dust generated during filling of the silos. Typically, they will be pulseclean, bag, or pleated fabric type, furnishing one bin vent for each storage silo. A
centrifugal fan provided at the outlet end of the vent filter will create a slight vacuum at
the flanged inlet of the bin vent filter. Dust laden air will enter the unit and passes
through the filter bags, leaving dust on the bag exterior. Filtered air is exhausted to the
atmosphere through the exhaust fan. An electric timer actuates valves in sequence, which
releases compressed air through venturi tubes. Shock waves formed in the venture, travel
downward and release caked dust from the bag exterior, discharging the collected dust
back to the silos.
The bin vent filter components will include, filter housing, penthouse, inlet, outlet, filter
media, cage for each fabric filter bag in the vent filter, pulse clean venturi nozzles,
exhaust fan etc.
Each bin bent will be furnished with a dedicated programmable logic controller to initiate
and control the pulse cleaning sequencing. Cleaning will be automatically initiated on a
preset high differential pressure across the filter media. Pulse duration and delay between
rows will be preset by the factory and field adjustable.
Typical bin vent filters mounted on top of silos are shown in Figure 3. A sectional
elevation of a typical bin vent filter with air flow is shown in Figure 4.
082907-145491
4
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Attachment 1
Figure 3
Bin Vent Filters on the silos
082907-145491
5
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Attachment 1
Figure 4
Sectional Elevation of Bin Vent Filter
082907-145491
6
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Appendix B
Appendix B
PSD Application Checklist
102607-145491
B-1
PSD APPLICATION CHECKLIST
(Review and submit with each PSD application)
I. Pre-Application Submittal Requirements
Initial call made to Department to schedule Pre-Application Meeting and discuss application
requirements (A pre-application meeting was held on Feb. 7, 2007 in IDNR's offices.)
Dispersion modeling protocol was submitted to the Department
(Modeling protocols were submitted for IDNR's comment and review on April 11, 2007
and May 9, 2007.)
Dispersion Modeling Protocol accepted by Department
(NA)
Pre-construction monitoring was submitted to the Department
Pre-construction monitoring accepted by Department
Request made to waive pre-construction monitoring, if applicable (Pre-construction
monitoring may only be waived if predicted concentrations are below the applicable
monitoring de minimus levels)
(NA)
Determined if any support facilities and/or facilities under common control are associated
with the facility where project is proposed
Documentation to support decision was provided
PSD Pre-Application Meeting with Department Representatives
(80 percent Pre-application meeting held September 24, 2007 in IDNR's offices)
II. Required Application Forms
Fill out all application forms as directed by the individual form instructions
FI: Facility Information
Form FI signed by responsible official
EU, EU1, or EU3: Emission Unit Information (one form required for each emission unit)
Include all new and modified emission units. Remember to include ancillary units, such as
emergency generators and fire pumps, blackstart engines, cooling towers, painting and
solvent cleaning, VOC storage containers, storage piles, material handling, haul roads, etc.
CS: Control Equipment and Stack/Vent Information (one form required for each emission
point or indoor venting emission unit)
EC: Emission Calculations (one form required for each emission point or indoor venting
emission unit)
PSD Application Checklist
Page 1 of 4
EI: Facility Emission Inventory (includes all emissions from fugitive sources, exempt units,
indoor venting emission units and new and/or modified emissions units within the
previous five years)
MI-1: Modeling Information Plot Plan
MI-2: Modeling Information Emission Point Characteristics (include all emissions from
fugitive sources, exempt units, indoor venting units and new and modified emissions
units)
FRA: Federal Regulation Applicability
Include a list of all the emission units in this project subject to New Source Performance
Standards (NSPS) or National Emission Standards for Hazardous Air Pollutants
(NESHAP) with the appropriate Subpart labeled.
III.
Emission Increases for the Project
All associated emission increases were included in the calculated net emissions increases for
each pollutant including emission increases due to:
(NA)
Debottlenecked emission units
(NA)
Increased utilization of emission units
Fugitive emissions
(NA)
All emission increases at any support facilities and/or facilities under common control were
included in the project’s net emissions increase
Documentation supporting emission calculations (e.g. engineering estimates, stack test
results, etc.) were included with the application
Check the pollutants that have a “significant” net emission increase, for this project:
Pollutant
“Significant” Net Emission Increase
Particulate matter (PM)
> 24.4 tpy
PM10
> 14.4 tpy
Sulfur dioxide (SO2)
> 39.4 tpy
Nitrogen oxides (NOX)
> 39.4 tpy
Ozone (Volatile organic compounds
(VOC))
> 39.4 tpy
Carbon Monoxide (CO)
> 99.4 tpy
Lead (elemental)
> 0.54 tpy
Fluorides
> 2.4 tpy
PSD Application Checklist
Page 2 of 4
Sulfuric acid mist
> 6.4 tpy
Total reduced sulfur compounds
(including H2S)
> 9.4 tpy
CFC’s 11, 12, 113, 114, 115
> 0 tpy
Halons 1211, 1301, 2402
> 0 tpy
Municipal Waste Combustor
(MWC) acid gases
> 39.4 tpy
MWC metals
> 14.4 tpy
MWC Organics
> 3.44 x 10-6 tpy
Other pollutants regulated under the
CAA (§52.21(b)(23)(ii))
> 0 tpy
Opacity – Visible Emissions
IV.
BACT Analysis
A “top-down” BACT analysis was performed for each new or modified emission unit that is a
source of a pollutant that has a “significant” net emission increase.
Submitted documentation supporting BACT analysis
V. Dispersion Modeling Analysis
(NA)
Potential ozone plumes were evaluated for projects with VOC emissions over 100 tons per
year.
Determined if modeled concentrations of any PSD pollutant were above the applicable
modeling significance level (MSL).(Modeling results are less than the applicable MSLs.)
(NA)
If yes, full impact analyses were conducted to evaluate compliance with the NAAQS and
PSD Increment values.
(NA)
Documentation for the source inventories used for NAAQS and PSD increment in the full
impact analyses was provided.
Electronic files associated with all applicable modeling analyses (including modeling
significance levels and full impact analyses) on appropriate media (i.e. floppy, CD or
diskette).
PSD Application Checklist
Page 3 of 4
VI.
Additional Impacts Analysis
(NA)
A Class I visibility impacts analysis was completed.
(NA)
Potential impacts on endangered or sensitive species located in Class I areas that may be
affected by the proposed project were evaluated if applicable, and all necessary
documentation is included with the application.
A Class II visibility impacts analysis was completed.
A hard copy of the VISCREEN output is included with the application.
VISCREEN input and output files are provided on appropriate media (i.e. CD or diskette).
Impacts on soils and vegetation were considered, including impacts of NOx over short-term
periods and the combined impact of NOx in conjunction with SO2.
An air quality analysis for associated growth from the proposed project was conducted, if
applicable, and all necessary documentation is included with the application
VII. Proposed Permit Conditions
Is the facility proposing any of the following permit conditions:
Emission limits (including applicable averaging periods)
Test methods
Compliance demonstration methods
Monitoring requirements for all averaging periods
Recordkeeping requirements for all averaging periods
VIII. Miscellaneous
Submitted four copies of the entire application (five copies of the entire application are
necessary if the facility is locating in Linn or Polk County)
PSD Application Checklist
Page 4 of 4
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Appendix C
Appendix C
Fuel Analyses
102607-145491
C-1
Sub-Bituminous Design Range Coal
Coal Analysis
Specification Basis:
Parameter
As Received
Proximate Analysis
(%)
Moisture
Ash
Volatile Matter
Fixed Carbon
Btu
MAF Btu
Sulfur
As Received Ultimate
Analysis (%)
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen
Moisture
Heating Value
(BTU/lbm)
As received
Dry
MAF BTU
Sulfur Forms
Pyritic
Sulfate
Organic
Total
Equilibrium Moisture
Hardgrove
Grindability
at Moisture
Water Soluble
Alakalies
Water Soluble Na2O
Water Soluble K2O
Ash Fusion
Temperatures (°F)
(Reducing Atmosphere)
Initial Deformation (ID)
Softening Temperature
(Spherical)
Softening Temperature
(Hemispherical)
Fluid Temperature
(0.0625 in.)
Ash Fusion
Temperatures (°F)
(Oxidizing Atmosphere)
Initial Deformation (ID)
Softening Temperature
(Spherical)
Softening Temperature
(Hemispherical)
Fluid Temperature
(0.0625 in.)
Powder River Basin
Performance Coal
Peabody Caballo 2006-2010
Smith Seam
8,400 BTU
Powder River Basin
Design Coal- BTU
Rawhide
Smith Seam
8,100 BTU
Powder River Basin
Wyoming High S
Jacobs Ranch
Upper Wyodak Seam
High Sulfur
Typical
Minimum
Maximum
Typical
Minimum
Maximum
Typical
Minimum
Maximum
29.8
4.8
31.5
33.8
8,500
13,005
0.35
28.90
4.40
29.70
32.30
8,300
31.10
5.80
32.50
35.70
8,600
30.00
4.60
29.10
32.30
8,100
32.20
6.00
31.50
34.70
8,500
28.32
8
33.54
34.13
9,024
0.42
0.24
0.50
26.94
6.8
32.5
32.89
8,800
13,280
0.88
25.56
5.6
31.46
31.65
8,576
0.29
30.50
4.90
30.40
34.20
8,300
12,984
0.33
0.66
1.1
49.35
3.44
0.70
<0.01
0.35
4.84
11.51
29.80
48.85
3.13
0.64
0.00
0.31
4.62
10.52
28.90
49.40
3.72
0.76
0.01
0.40
5.51
12.26
31.10
48.58
3.34
0.63
0.00
0.33
4.93
11.66
30.50
47.60
3.08
0.63
0.00
0.25
4.69
10.71
30.00
48.14
3.39
0.75
0.02
0.49
5.63
12.41
32.20
51.26
3.89
0.8
<.01
0.88
6.8
9.44
26.94
49.38
3.63
0.6
53.14
4.15
1
0.66
5.6
8.74
25.56
1.1
8
10.14
28.32
8500
8,300
8,600
8,300
12,029
12,948
8100
8500
8,576
9,024
11040
13010
8,800
12,044
13,280
0.18
0.02
0.68
0.88
0.08
0
0.42
0.66
0.28
0.04
0.94
1.1
56
21.64
49
13
64
30
0.07
<.01
0.43
0.50
28.3
62
28.5
27.3
29.7
52
72
0.065
0.003
0.09
<0.01
0.39
0.48
29.1
0.075
0.006
0.071
0.005
2,100
2,070
2,190
2,170
2,065
2,305
2128
2086
2170
2,110
2,080
2,200
2,180
2,075
2,315
2170
2120
2220
2,120
2,090
2,210
2,190
2,085
2,325
2191
2111
2271
2,130
2,100
2,220
2,200
2,095
2,335
2269
2185
2353
2,180
2,135
2,255
2,210
2,105
2,305
2228
2186
2270
2,190
2,145
2,265
2,220
2,120
2,315
2247
2197
2297
2,200
2,155
2,275
2,230
2,125
2,325
2263
2183
2343
2,210
2,165
2,285
2,240
2,135
2,335
2338
2254
2422
1 of 4
Coal Analysis
Specification Basis:
Ash Mineral Analysis
(%)
Silica -- SiO2
Alumina -- Al2O3
Titania -- TiO2
Ferric Oxide -- Fe2O3
Calcium Oxide -- CaO
Magnesium Oxide-- MgO
Potassium Oxide -- K2O
Sodium Oxide -- Na2O
Phosphorous Pentoxide -P2O5
Sulfur Trioxide -- SO3
Strontium -- SrO
Barium Oxide -- BaO
Manganese Oxide- MnO2
Undetermined
Miscellaneous
Alkalies as NA2O, d.c.b
Base / Acid ratio
Silica Value
Slag Viscosity (T250)
lbs Ash/MMBTU
lbs sulfur/MMBTU
lbs Alkali as
Na2O/MMBTU
lbs H2O/MMBTU
Free Swelling Index
Mercury, Hg (ppm)
Dry Whole Coal Basis
Trace Analyis (Dry
Whole Coal Basis)
Trace Element
Summary
Antimony
Arsenic
Barium
Beryllium
Boron
Bromine
Cadmium
Chlorine
Chromium
Cobalt
Copper
Fluorine
Lead
Lithium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Strontium
Thallium
Tin
Vanadium
Zinc
Zirconium
Powder River Basin
Performance Coal
Peabody Caballo 2006-2010
Smith Seam
8,400 BTU
Powder River Basin
Design Coal- BTU
Rawhide
Smith Seam
8,100 BTU
Powder River Basin
Wyoming High S
Jacobs Ranch
Upper Wyodak Seam
High Sulfur
31.5
16
1.3
5.3
23.5
4.5
0.3
1.7
29.0
15.6
1.2
5.1
20.8
4.2
0.2
1.4
37.0
18.0
1.6
6.2
26.8
5.0
0.4
2.4
31.20
13.90
1.10
6.30
24.30
6.10
0.20
1.70
27.00
11.80
0.80
4.80
21.80
4.70
0.10
1.00
35.00
15.80
1.30
7.80
28.00
8.70
0.30
2.00
27.74
15.9
1.13
9.28
18.83
3.35
0.31
0.96
22.2
13.58
0.83
7.98
15.09
2.51
0.11
0.62
33.28
18.22
1.43
10.58
22.57
4.19
0.51
1.3
1.0
13.7
0.4
0.7
0.1
0
0.2
9.0
0.2
0.4
<0.1
1.1
15.7
0.6
0.8
0.2
0.5
13.6
0.4
0.7
0.4
10
0.2
0.4
1
16
0.6
0.8
0.89
17.85
0.27
0.43
0.13
2.91
0.45
14.13
1.33
21.57
0
6.33
0.00
0.72
0.84
46.29
2220
5.9
0.79
2078
7.73
2.00
0.1
3,506
0.0
0.0945
0.074
0.09
0.09
2135
5.7
0.82
<1
1
289
0.2
40
<20
<0.2
<501
5
3
13
56
3
2
21
0.09
<2
4
<1
<0.2
218
<1
<1
15
7
11
0.73
2015
2141
1.64
2.36
0.5
5.1
376
0.4
0.21
1.1
207
0.3
0.79
9.1
545
0.6
10
0.29
147
7
4
17
26.1
3.4
3
30
0.14
7
0.09
47
4
2.5
9
15.5
1.6
1
0
0.07
14
0.5
247
10
5.4
25
36.7
5.2
4
80
0.2
14
2
0.13
7
1.1
0.09
21
3
0.16
0.2
0
0.4
26
32
0
15
9
37
56
0
1
1
1
1
0.2
2
380
0.3
50
20
0.05
240
4
1.5
9
27.6
2
2.84
21
0.09
0.18
0.7
300
0.1
40
10
0.02
120
2
0.8
4
17
1
0
12
0.02
0.65
5
480
0.5
60
30
0.07
400
8
5.1
14
34.9
4
6.08
45
0.12
5
1.2
2
0.4
10
2
270
200
380
12
11
Page 2 of 4
0.14
7
3
20
20
Bituminous Design Range Coal
Coal Analysis
Specification Basis:
Parameter
As Received Proximate Analysis (%)
Moisture
Ash
Volatile Matter
Fixed Carbon
Btu
MAF Btu
Sulfur
As Received Ultimate Analysis (%)
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen
Moisture
Heating Value (BTU/lbm)
As received
Dry
MAF BTU
Sulfur Forms
Pyritic
Sulfate
Organic
Total
Equilibrium Moisture
Hardgrove Grindability
at Moisture
Water Soluble Alakalies
Water Soluble Na2O
Water Soluble K2O
Ash Fusion Temperatures (°F)
(Reducing Atmosphere)
Initial Deformation (ID)
Softening Temperature (Spherical)
Softening Temperature (Hemispherical)
Fluid Temperature (0.0625 in.)
Ash Fusion Temperatures (°F)
(Oxidizing Atmosphere)
Initial Deformation (ID)
Softening Temperature (Spherical)
Softening Temperature (Hemispherical)
Fluid Temperature (0.0625 in.)
Illinois Basin
Alternate Illinois Basin Coal
Peabody Gateway Typical
Illinois No. 6
11,000 BTU
Typical
Minimum
Maximum
Illinois Basin
Illinois Basin
Greater Belleville U. G.
Illinois Basin no. 6
10, 800 BTU
Typical
Minimum
Maximum
13.5
8.6
35.5
42.4
11,004
14,119
2.84
14.2
9.5
34.7
41.6
10,800
14,158
3.11
12.5
7.6
32.1
38.7
16.4
11.6
37.2
44.1
2.50
4.00
61.76
4.33
1.12
0.10
2.84
8.56
7.79
13.5
60.06
4.2
1.12
0.10
3.11
9.52
6.93
14.2
58.98
3.76
0.7
0.04
2.54
7.7
6.13
12.5
60.94
4.68
1.34
0.21
3.93
11.12
9.78
16.4
11,004
12,721
14,119
10,800
10,400
11,100
0.97
0.01
2.30
3.28
10.3
52
4.0
1.12
0.05
2.45
3.62
0.53
<0.01
1.6
1.79
0.10
3.2
53
28.5
48
28.5
58
28.5
0.094
0.005
0.94
0.005
0.04
<0.1
0.12
0.01
14,158
1,960
2,095
2,170
2,280
2,070
2,080
2,090
2,100
2,190
2,200
2,210
2,220
2020
2110
2185
2315
1920
1980
2030
2170
2160
2265
2350
2525
2,340
2,400
2,445
2,500
2,135
2,145
2,155
2,165
2,255
2,265
2,275
2,285
2325
2375
2420
2510
2200
2250
2300
2370
2450
2530
2565
2695
49.6
19.3
0.9
16.3
5.2
1
2.1
1.2
0.2
4.2
<0.1
<0.1
<0.1
43.2
16.4
0.6
13.2
2.6
0.6
1.5
0.6
0.1
2.6
<0.1
<0.1
<0.1
55.4
22.2
1.2
22.1
7.2
1.3
2.5
1.5
0.3
8.4
0.1
0.1
0.1
Ash Mineral Analysis (%)
Silica -- SiO2
Alumina -- Al2O3
Titania -- TiO2
Ferric Oxide -- Fe2O3
Calcium Oxide -- CaO
Magnesium Oxide -- MgO
Potassium Oxide -- K2O
Sodium Oxide -- Na2O
Phosphorous Pentoxide -- P2O5
Sulfur Trioxide -- SO3
Strontium -- SrO
Barium Oxide -- BaO
Manganese Oxide- MnO2
Undetermined
51.4
19.7
1
16.3
4.2
1.0
2.2
1.3
0.2
2.6
<0.1
0.1
<0.1
0
Page 3 of 4
Coal Analysis
Specification Basis:
Illinois Basin
Alternate Illinois Basin Coal
Peabody Gateway Typical
Illinois No. 6
11,000 BTU
Illinois Basin
Illinois Basin
Greater Belleville U. G.
Illinois Basin no. 6
10, 800 BTU
Miscellaneous
Alkalies as NA2O, d.c.b
Base / Acid ratio
Silica Value
Slag Viscosity (T250)
lbs Ash/MMBTU
lbs SO2/MMBTU
lbs Alkali as Na2O/MMBTU
lbs H2O/MMBTU
Free Swelling Index
Mercury, Hg (ppm)Dry Whole Coal Basis
Trace Analysis (Dry Whole Coal Basis)
Antimony
Arsenic
Barium
Beryllium
Boron
Bromine
Cadmium
Chlorine
Chromium
Cobalt
Copper
Fluorine
Lead
Lithium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Strontium
Thallium
Tin
Vanadium
Zinc
Zirconium
0.27
0.35
70.51
2475
7.8
5.157
0.1
1,226.83
0.0
0.09
0.2
0.37
68.79
2450
7.73
5.75
0.074
<1
2
32
1
159
36
0.4
1100
20
3
8
102
2
7
22
0.06
6
11
1.9
0.1
17
<1
<1
32
40
15
<0.1
2
50
1.2
150
22
0.5
759
25
2
10
99
6
7
39
0.07
8
14
2
<0.2
25
<0.1
<0.1
32
67
15
0.16
0.27
62
2290
0.39
0.5
76
2634
4.80
7.20
0.14
Source: Illinois GS
Belleville Basin
Illinois Basin Nos. 6 Seam
Dry Whole Coal Basis-ppm
Note: The characteristics of all coals to be burned in the new generating unit will be generally consistent with the fuel quality limits presented in
Appendix C and used in the preparation of this application.
Page 4 of 4
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Appendix D
Appendix D
System Descriptions
System Description Contents
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
102607-145491
Major Systems Location - Overview Drawing
Steam Generator
Steam Turbine Generator
Auxiliary Boiler
Coal Handling System
Fly Ash Handling
FGD Solids
Biomass Handling
Bottom Ash
Chimney
Emergency Generation
Fencing and Security
Gate Station Heater
Limestone Handling System
Site and Equipment Fire Protection
D-1
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Steam Generator
1.2
Function
The Steam Generator System provides for the heat transfer of heat released during the
combustion of the fuel to the feedwater and steam. This heat transfer produces main
steam at a supercritical pressure and 1080 oF temperature required by the high-pressure
turbine. Heat transfer also takes place in the reheater to increase the temperature of the
cold reheat steam to that required by the intermediate-pressure turbine. The Steam
Generator will receive a coal-air mixture from the pulverizers in the Combustion Air
System, fuel gas from the Ignitor Fuel System, combustion air from the Combustion Air
System, feedwater from the Boiler Feed System, and cold reheat steam from the Cold
Reheat System, and combustion air from the Combustion Air System. The Steam
Generator will be a field erected top supported pulverized coal, once-through
supercritical, variable pressure, balanced draft, spiral or straight furnace tube orientation
with single reheat.
1.3
Process Description
The Pulverized Coal Steam Generator System consists of the following major equipment
and components:
EQUIPMENT
QUANTITY/REDUNDANCY
Boiler and Auxiliaries
One 100% capacity system
•
Furnace wall system
•
Vertical / Spiral tube
•
Superheater, Reheater
•
SA231 - T11, T22, T91, or T347
•
Attemperators
•
Superheater, Reheater
•
Economizer
•
Plain tube in line
•
Steam Separator and Startup System
•
By Contractor
•
Boiler Casing, Refractory and Insulation
•
120 F max insul surface temperature
•
Windbox
•
By Contractor
•
Burners
•
Low NOx
•
Secondary air ports, dampers and drives
•
By Contractor
•
Scanners
•
By Contractor
•
Igniters
•
By Contractor
•
Sootblowers
•
Steam type
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
EQUIPMENT
QUANTITY/REDUNDANCY
•
Furnace high pressure water wash system
• Total coverage, including pumps and
piping.
•
Regenerative Air Preheater
•
By Contractor
•
Overfire Air Ports
•
Separated OFA
•
Safety/Relief Valves
•
Overpressure protect per Code
•
Boiler structure and enclosure
•
Galvanized structural steel for boiler,
auxiliary bay, and coal silo bay(s)
• Variable Speed Centrifugal type FD fans
with VFD motors
•
2 x 50% per boiler
•
•
2 x 50% per boiler
Single Speed Centrifugal type PA fans
• FD fan and PA fan secondary air preheat
coils
• Steam coils sized to provide minimum
CEAT – by Contractor
•
Air and gas ductwork
•
•
Vertical Type Coal pulverizers
• 5 pulverizers sized for no more that 80%
of maximum capacity at MCR Unit load point.
By Contractor
•
4 + 1 spare = 5
•
Pulverizer Inerting system
•
By Contractor
•
Gravimetric Coal feeders
•
One per pulverizer
•
Pulverized coal piping
• Carbon steel pipe with hard facing as
required on wear sections
•
Natural Gas Startup System
•
By Contractor
•
Chemical cleaning provisions
•
Connections for portable equipment
•
Burner management system
•
By Contractor
•
Valves and accessories
•
By Contractor
•
Test connections
•
•
Structural Steel and Enclosures
•
SCR, SCR catalyst, ammonia vaporization
system and related ducting
•
Ductwork, breeching, expansion joints,
piping supports, electrical controls and
instruments, motors, lube systems and
accessories
082907-145491
Facilitate boiler testing
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Combustion of pulverized coal fuel with air described in the Combustion Air System
releases radiant and convective heat energy in the steam generator furnace. The Steam
Generator System also receives feedwater from the boiler feed pumps described in the
Boiler Feed System, and cold reheat steam from the high-pressure turbine exhaust as
described in the Cold Reheat Steam System. The steam generator will use these sources
to produce steam at the required operating conditions for main steam flow to the highpressure turbine and for hot reheat steam flow to the intermediate-pressure turbine.
Boiler feedwater enters the economizer section of the steam generator, located at the
bottom of the convection pass heat recovery area, and will flow up to the economizer
outlet header. Exhaust gas will flow across the economizer tubes in a direction opposite
to the feedwater flow.
The furnace section of the steam generator will be a gastight construction of welded
membrane carbon steel tubes. The furnace tubes will be arranged in a spiral pattern to
minimize localized hot spots and minimize thermal stresses. The furnace tube
construction is dependent on the manufacturer’s specific design. The furnace will consist
of a combustion zone that is to be conservatively sized in order to minimize slagging,
fouling, and erosion risks based on the design coals.
The steam generator will consist of feedwater and steam cooled furnace walls, convection
pass walls, convection pass screen tubes, primary superheat tubes, finishing secondary
superheater tubes, reheater tube sections and steam separator and water collector vessels.
The bottom of the furnace will slope down and toward the center of the furnace from the
water walls to form a long sloping ash discharge interface leading into the bottom ash
drag chain conveyor.
The steam temperature leaving the final superheater will be controlled with firing rate
and feedwater flow control. Attemporators may also be used for emergency control. The
attemporator spray water will be supplied from the Boiler Feed System. The main steam
temperature will be maintained at 1080 °F from 75% load to rated load. The boiler water
circulation pump (if required and provided by the manufacturer) is used during startup to
maintain a minimum circulation in the boiler wall tubes cooled by feedwater and steam.
The reheater section of the steam generator will consist of horizontal tube banks with a
vertical tube section outlet. Steam from the Cold Reheat System enters the reheater inlet
header section at the bottom of the path and then flows upward in the horizontal section
of reheater tubes as a counter flow to the gas stream. Reheated steam leaves through the
outlet header located above the furnace roof panel tubes.
One method of reheat steam temperature control will include two parallel gas paths with
dampers located at the outlet of the economizer sections installed in each path. One path
will contain the primary superheater and the other path will contain the reheater. The
reheater outlet temperature will normally be controlled by adjustment of the dampers
located at the outlet of the economizer section. The balance of the flue gas flow will be
directed through the superheater path. To maintain the reheater outlet steam temperature,
the percentage of gas flow over the reheater will be increased with a decrease in load.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Another method of steam temperature control is the use of tilting burners in the furnace
to move the burner flames higher or lower in the furnace that enable greater or less heat
transfer from the flue gas to the furnace walls before the gas enters the convection pass
area of the steam generator.
The method of reheater steam temperature control will be determined by the design of the
selected manufacturer. In either case, spray attemporators are to be provided for fast
desuperheating response for any temperature excursions as part of the steam temperature
controls.
The steam generator will be top supported with thermal growth downward. Connections
to the steam generator will be designed to accommodate this expansion without excessive
stress.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Steam Turbine Generator
1.2
Function
The cylindrical rotor machine converts rotational energy to electricity with proven
reliability and efficiency in a large number of units operating at comparable conditions.
1.3
Process Description
The Steam Turbine Generator System includes the following major equipment and
components:
• Stator core and stator winding.
• Hydrogen gas cooler.
• Temperature detectors.
• Rotor and rotor coils.
• Hydrogen gas system.
• Shaft seal oil system.
• Static excitation system and power system stabilizer.
• Generator neutral grounding.
The generator will be completely enclosed and, in operation, use hydrogen gas as the
cooling medium. The ventilation system, including the fans and gas coolers, will be selfcontained and completely enclosed to prevent dirt and moisture from entering into the
generator. The stator and rotor windings will be directly cooled by hydrogen.
The generator casing will be substantially cylindrical in shape and of welded gastight
construction. The outer end shields at either end of the casing will also be of gastight
construction and support the generator bearings and shaft seals. The rotor shaft will pass
through the outer end shield out of the generator, and shaft seal devices are provided to
prevent hydrogen gas leakage.
The generator will be designed to be able to operate at 5% over and under voltage at rated
kVA output.
The generator will be rated to carry the maximum turbine output continuously at a
leading power factor of 0.95 through lagging power factor of 0.85 at constant kVA
output.
The generator winding will be wye connected and suitable for operation with the neutral
resistance grounded through a distribution transformer. Phase terminals will be brought
out separately.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
The stator and rotor winding insulation will be a Class F insulation system with class B
temperature rise.
The stator core will be supported by spring plates in the stator frame to isolate the core
from vibration. The generator will be designed for continuous operation and constructed
to withstand a sudden change in load and three-phase short circuit. Various kinds of
supervising and controlling instruments will be provided for keeping the generator in
satisfactory operation.
1.3.1 Stator Core and Stator Winding
The stator core will be built up of segmental insulated punchings of low loss silicon steel
sheets. The punchings will be assembled in an interleaved manner on rib bar and axial
ventilation holes provided to cool the stator core by hydrogen.
The stator winding will be formed by insulated bars assembled in the stator slots, and
connected to the phase belts by bus rings. The stator bars will be composed of insulated
conductors arranged in the form of transposed rectangular bars. This transposition avoids
eddy current losses under load conditions. The ground insulation system will be epoxyresin impregnation under vacuum system and classified as Class F insulation.
The stator winding will be star connected. All six terminals will be brought out of the
machine and will be available for external connections. Either end of the winding will be
designed for use as a neutral bus or for use as the main generator power leads. The
generator neutral connection rating in amperes will be the same as the generator line
terminal rating and will be based on the maximum MVA rating of the generator operating
at minimum allowable generator terminal voltage.
The main power lead terminal bushings will be spaced to permit connection to the
generator terminal conductor system. Connection to the generator terminal conductor
system to the generator high voltage line bushings will be accomplished using bolted
connection to spade type flanges. Flexible connections will be used where appropriate to
allow thermal expansion and to avoid transmittal of vibration to other equipment.
Current transformers will be installed on the generator line and neutral bushings in
quantities required to provide relay protection, metering, and control functions.
Sufficiently high accuracy class CTs will be chosen to avoid saturation and false signals.
The generator neutral will be high resistance grounded via a neutral grounding
transformer and resistor assembly. The assembly will include a sheet metal steel indoor
cubicle, a neutral grounding transformer, and a neutral grounding resistor. The resistance
value will be chosen so that the resistor kW dissipation during a phase-to-ground fault is
equal to or greater than the generator and generator terminal equipment system charging
kVA. In general, the phase-to-ground primary current range should be limited to 4 to 10
amperes, thereby minimizing damage to the main generator windings if a fault occurs.
Current through the neutral grounding system or voltage across the resistor will be used
to detect a ground fault within the generator or on the generator bus or other connected
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
equipment. The transformer and resistor will be sized to withstand resulting fault current
for 30 seconds.
The generator stator frame will be provided with four grounding pads located
diametrically opposite at four corners of the structure, each with threaded holes and
associated bolts for attachment of the station grounding conductors.
1.3.2 Hydrogen Gas Cooling
A hydrogen gas cooler will be used to cool the hydrogen gas. It will be composed of a
set of water boxes, a bundle of finned tubes set in the tube sheets, and a supporting frame.
Hydrogen gas in the generator will be carried into the hydrogen gas cooler by a fan on the
generator rotor. Hydrogen gas will flow over the surfaces of the cooling tubes, liberating
its heat to the water running inside the cooling tubes. The tube material will be copper
nickel or approved equal.
During normal operation, the hydrogen gas pressure in the generator casing will be
automatically maintained at the rated gas pressure by the gas pressure regulator. When
the generator casing is to be filled with hydrogen gas, the air inside the casing will
initially be purged by carbon-dioxide gas through the purge line and, then, this carbondioxide will be replaced by hydrogen, so as to avoid the formation of an explosive
hydrogen and air mixture in the generator casing. During these procedures, the purged
gas or air will be vented to the atmosphere through the vent pipe. To monitor the system,
instruments such as the machine gas purity meter, the machine gas pressure gauge, etc.
will be provided on the hydrogen control panel and rack. Hydrogen gas purity will be
measured and the system will be designed to scavenge a small amount of hydrogen to
allow makeup to maintain required purity. Gas dewpoint will be monitored continuously.
A hydrogen seal oil system will be provided. Oil seal glands will be provided at the
generator shaft to prevent loss of gas or air infiltration, and oil drains from the generator
bearings will be designed to prevent hydrogen from reaching the oil reservoir. The seal
oil system will be capable of regulating the oil pressure above the hydrogen pressure to
maintain a tight seal even under hydrogen pressure changes. The system will be designed
for detraining air and/or hydrogen from the oil for each cycle it passes through the seals.
Generator bearing lube oil will be used as the seal oil, eliminating any concern about
mixing of two different oil systems.
The Supplier will be responsible for demonstrating the integrity of the hydrogen seal oil
system to show that leakage rates are within guaranteed tolerances.
1.3.3 Temperature Detectors
Several resistance temperature detectors (RTDs) will be located between coils in each
phase of the stator windings to measure the temperature of the windings. Other
resistance temperature detectors will be located to measure the temperature of cooling
hydrogen gas entering and exiting the hydrogen gas cooler. In addition, several RTDs
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
will be located to measure the temperature of the hydrogen gas leaving the stator
winding.
1.3.4 Rotor and Rotor Coils
The rotor will be machined from a single alloy steel forging. Prior to machining,
extensive tests will be made to assure that the forging meets the required specifications
for physical and metallurgical properties. Longitudinal slots, machined radially in the
body, will contain the rotor coils. The rotor coils will be held in the slots against
centrifugal force by wedges. These wedges will be fitted and driven into dovetail
openings machined in the rotor slots. The rotor fan, which is provided for the ventilation
of the generator, will be multi-stage axial flow type. The fan will be assembled near the
ends of the rotor. The collector rings, which are provided for supplying excitation current
to the rotor coils from the static excitation system, will be shrunk on the rotor shaft end.
The rotor coils will consist of rectangular copper bars formed into coils. Several coils
will be assembled around each pole to form the winding. The individual turns of the
coils will be insulated from each other by insulation sheet. The coils will be insulated
from the rotor body by the slot cells made from glass/Nomex-laminated epoxy-resin. A
molded insulation ring will be provided between the coils and retaining rings, and
insulating space blocks will be provided in the end windings to support the coils. The
retaining rings restrict the movement of the coils caused by thermal deformation and
centrifugal force, and will be made from high mechanical strength, non-magnetic alloy
steel.
1.3.5 Static Excitation System and Power System Stabilizer
A potential-source controlled rectifier excitation system will be provided, which has high
performance, reliability, and response. Self excitation of the generator will be provided
by a static excitation system using a thyristor rectifier that converts the AC voltage from
the generator terminals through the excitation transformer into DC voltage. The
Automatic Voltage Regulator will be a continuously acting, micro-processor based AVR,
utilizing modern electrical technology. The voltage regulator will control the output
voltage of a thyristor rectifier that consists of rectifiers with the resulting dc power
supplied to the generator field. The excitation power will be taken from the generator
terminal voltage through the excitation transformer except during initial excitation.
A power system stabilizer will be provided in accordance with the requirements of the
governing authorities. The Supplier will be responsible for initial setup (including any
and all calculations necessary to support proposed settings and all onsite commissioning
and tuning activities related to the power system stabilizer. The power system stabilizer
function will provide a stabilization signal output to the AVR to suppress active power
disturbances.
Excitation Control Panel (Automatic Voltage Regulator; AVR). The excitation
control system will have two master controllers that constitute a duplicated-redundant
AVR system and one system controller. During normal operation, the whole excitation
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
control function will be subject to automatic control. A Standby AVR system, with
continuous follow-up for a bumpless switch-over (in case of a failure in the operating
AVR system), will also be provided. The manual excitation control function will also be
provided.
Thyristor Rectifier Cubicle. The thyristor rectifier will consist of 3-phase full-wave
thyristor bridges, equipped with 6 thyristors. A fuse will be connected in series to each
thyristor. Fans may be used to cool the thyristor tray (thyristor element) of the rectifier
with forced air. Cooling fans, if used, will be set in 2-system configuration. Normally,
only one fan system will be used for cooling, however operation will switch to the other
fan if the normal fan motor fails.
Field Circuit Breaker Cubicle. The field discharge circuit will be made of an AC
breaker in an AC circuit and discharge circuit connected to a discharge resistor (linear
resistor) and discharge thyristor in a DC circuit. The over voltage suppression will be
made of a ZNR absorber (varistor) and CR absorber in an AC/DC circuit of a thyristor
rectifier bridge.
Excitation Monitoring.
The excitation monitoring circuit will monitor the
performance of the excitation system. In case of a failure, an automatic change-over to
the stand-by channel or the shut-down of the excitation system will be initiated. The
major functions are the following:
•
Measuring of generator terminal voltage (VT-failure).
•
Measuring of field current.
•
Monitoring of the operational condition.
1.3.6 Generator Protection
The following protection functions will be provided, as a minimum, for the generator
excitation system:
•
Overexcitation protection will be provided to prevent excessive, sustained
ceiling excitation voltage from increasing damage to either the excitation
equipment or the generator. This protection will consist of the following as a
minimum:
o Overexcitation trip to trip the machine if excessive excitation remains for
a predetermined time, both in automatic and in manual operation.
o An adjustable limiting device which will automatically prevent operation
above the rated generator overexcitation capability.
•
A volts/hertz regulator will be furnished to provide a continuously acting limit
to the maximum volts/hertz. The volts/hertz will act only in the automatic
regulator.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
•
Automatic and continuous ground detection equipment will be provided to
detect grounds in the generator field. Facilities will be provided to permit inservice tests of the ground detection system at any time. Ground detection will
be relayed via a contact for remote annunciation in the main control room.
•
Underexcitation protection will be provided so that the synchronous machine
voltage regulator will be limited by means of an adjustable limiting device
which will automatically prevent operation below the rated generator capability
for underexcitation operation.
•
A voltage unbalance detector circuit will be provided. Loss of regulator sensing
voltage will transfer the regulator from automatic to manual. Remote
annunciation will be provided in the main control room for loss of metering and
regulating voltage transformer signals.
Redundant multifunction protective relays will be used to provide the protective
functions. Industry standards will be followed regarding the selection of protective
functions, as well as calculation of the settings to be used.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Auxiliary Boiler
1.2
Function
The Auxiliary Boiler provides auxiliary steam during startup and normal operation for the
following:
1.3
•
Heating steam for the deaerator during startup.
•
Shaft sealing steam for main steam turbine during startup and low load.
•
Steam for building HVAC heating (including tie to existing Units 1, 2, &
3).
•
Boiler air preheat coils.
•
Steam for pulverizer inerting system.
•
Steam for other auxiliaries (including tie to existing Units 1, 2, & 3).
Process Description
The auxiliary boiler will be natural gas fired and transfer heat to auxiliary boiler
feedwater to produce saturated steam. The natural gas fuel system shall be capable of
operating the boiler throughout its entire load range of ambient conditions with a limited
maximum heat input of 270 MBtu/h. The auxiliary boiler will provide 200,000 lb/hr of
250 psia saturated steam to the auxiliary steam header. The auxiliary boiler is expected
to operate no more than 2,000 hours per year.
The auxiliary boiler stack will discharge to the atmosphere at the specified elevation.
082907-145491
Interstate Power & Light Company
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Coal Handling System
1.2
Function
The function of the Coal Handling System will be to receive and unload coal delivered by
rail cars, provide a means to stock out and store the coal in active and reserve storage
piles, provide the means to reclaim, blend, crush the coal to the desired size, and supply
the coal to the Unit 4 silos to satisfy plant usage requirements. The coal handling system
will also be sized to serve existing Units 1, 2, and 3 by providing a separate stockout
facility to store coal unloaded by the Unit 4 unloading facility and to provide a separate
reclaim facility to reclaim coal designated for Units 1, 2, and 3.
1.3
Process Description
Drawing 145491-1CHU-S2100 is the process flow diagram of the Coal Handling System.
1.3.1 System Operation.
The new coal handling system at the Sutherland Plant will supply coal to the existing
Units 1, 2 and 3 as well as the new Unit 4.
The system will be designed to accommodate simultaneous car unloading, stacking and
silo fill operations to Units 4 and be configured to provide sufficient redundancy for nonoperating equipment.
Coal will be delivered to the power plant by unit train consisting of approximately 150
cars. Each of the rail cars will carry approximately 120 tons of coal.
The coal received in the plant will be unloaded by a rotary car dumper at a rate of 4,000
TPH. The rotary car dumper will be equipped with a rail car positioner, hopper, grizzly
and traveling hammermill for the breaking of oversize and frozen coal. The unloaded
coal will be collected by the hopper and withdrawn by two belt feeders BF-1 and BF-2.
Dust Collection System (DC) will control dust in the dumper building above the
unloading hopper.
The coal will be transferred from the feeders to unloading conveyor BC-1 which will take
it to Transfer Tower TT-1. Belt conveyor BC-1 will be equipped with the as-received
sampling system SMP-1 and 1/4 % accuracy belt scale BS-1. The discharge of conveyor
BC-1 will be equipped with inline Magnetic Separator MS-1. At Transfer Tower TT-1,
the coal would be directed to Belt Conveyor BC-4 which feeds Stacker/Reclaimer SR-1.
Under normal operating conditions the unloaded coal will be stacked out by
Stacker/Reclaimer SR-1 at 4,000 TPH. During reclaiming the boom conveyor of
Stacker/Reclaimer SR-1 will be reversed to support a reclaim capacity of either 1,200
080307-145491
Interstate Power & Light Company
Sutherland Unit 4 Air Permit Application
TPH or 2400 TPH onto Conveyor Belt BC-4. The discharge point at the top of
Stacker/Reclaimer SR-1 will be equipped with a motorized flow splitting gate, enabling
the operator to split the material flow of 4,000 TPH into two separate streams, one stream
would be sent directly to crushing and silo fill and the second stream going to stockout.
In case of a Stacker/Reclaimer SR-1 failure, the unloaded coal will be stacked out at 4000
TPH by emergency stacking conveyor BC-2, equipped with telescopic chute CHE-1 onto
a 13,300 ton capacity emergency pile.
Depending on operating requirements, the coal from the emergency pile may be
bulldozed directly into the yard storage or to the reclaim hopper RH-1, equipped with a
variable frequency drive belt feeder BF-3 at a rate of 0 – 1200 TPH, and fed onto reclaim
Conveyor BC-3 for stacking by SR-1 or sent directly to the plant as required. Belt
Conveyor BC-3 will be 48” 1200 TPH and will be equipped with Belt Scale BS-2. The
discharge of Conveyor BC-3 will be equipped with inline Magnetic Separator MS-2.
Coal for existing Units 1, 2 and 3 will be fed from reclaim hoppers RH-4 and RH-5 with
400 TPH Belt Feeders BF-8 and BF-9 onto Belt Conveyor BC-5A, 30” 400 TPH. Belt
Conveyor BC-5A will be equipped with Belt Scale BS-7.
Belt Conveyor BC-5A will discharge onto Belt Conveyor BC-5B, 30” 400 TPH at the
new Transfer Tower 3. Conveyor BC-5B will deliver coal to a new hopper, HPR-2,
located over the existing hopper in the existing coal handling system for Units 1, 2, and 3.
The new hopper will have a working capacity of 200 tons, be equipped with a cutoff gate,
and feed the existing hopper. The new hopper, HPR-2, will also be provided with a side
discharge chute that will be equipped with a cutoff gate. The side discharge chute and
gate could be used to load coal trucks in the future. Should coal trucks be loaded in the
future, an enclosed structure and dust control would be provided for loading operations.
At the discharge point of Belt Conveyor BC-4, the coal will be directed through a 3-way
flow diverting flop gate to allow the coal to be sent directly to the Crushers and Unit Silo
Fill when SR-1 is reclaiming at 1200 or 2400 TPH, or onto Belt Conveyor BC-6 or Belt
Conveyor BC-7 at a maximum rate of 4000 TPH and stock piled for blending during
reclaiming operations. A flow splitter gate would located below one leg of the 3-way flop
gate to allow a 2400 TPH flow to be split to feed Belt Conveyors BC-10 and BC-11,
1200 TPH each.
Coal directed onto Belt Conveyor BC-6 will be stockpiled using Telescopic Chute CHE-2
and reclaimed through under pile Reclaim Hopper RH-2 equipped with Variable
Frequency Drive Belt Feeder BF-4 at a rate from 0-2400 TPH onto reclaim Belt
Conveyor BC-8, 60” 2400 TPH. Belt Conveyor BC-8 will be equipped with Belt Scale
BS-3 to facilitate proportioning for blending operations. Belt Conveyor BC-8 will
discharge into a flow splitting gate to allow a 2400 TPH flow to be split into two 1200
TPH flows and be directed to both Belt Conveyors BC-10 and BC-11 simultaneously for
the crushing and unit silo fill operations.
080307-145491
Interstate Power & Light Company
Sutherland Unit 4 Air Permit Application
Coal directed onto Belt Conveyor BC-7 will be stockpiled using Telescopic Chute CHE-3
and reclaimed through under pile Reclaim Hopper RH-3 equipped with Variable
Frequency Drive Belt Feeder BF-5 at a rate from 0-1200 TPH onto reclaim Belt
Conveyor BC-9, 48” 1200 TPH. Belt Conveyor BC-9 will be equipped with Belt Scale
BS-4 to facilitate proportioning for blending operations. Belt Conveyor BC-9 will
discharge into a flow splitting gate to provide blending capability with coal from either
BC-4 or BC-8.
Belt Conveyors BC-10 and BC-11 will each be 48”, 1200 TPH and will feed coal to the
Crusher Surge Bin SB-1 located inside the Crusher House, CH-1. Each of these
conveyors will be equipped with Belt Scales BS-5 and BS-6. The discharge of these
conveyors will be equipped with inline Magnetic Separators, MS-3 and MS-4. The
surge bin will have two outlets, each equipped with a rack & pinion slide gate. Coal will
be discharged from the crusher surge bin outlets using Variable Frequency Drive Belt
Feeders BF-6 and BF-7, which will feed 1200 TPH Ring Granulator Crushers (2 x
100%), CR-1 and CR-2 respectively. The crusher house will contain a Dust Collection
System (DC).
Plant Conveyors BC-12 and BC-13 will each be 48”, 1200 TPH and will deliver crushed
coal from Crusher House CH-1 to Transfer Tower TT-4. These two conveyors will each
be equipped with metal detectors, Metal Detector MD-1 on Belt Conveyor BC-12 and
Metal Detector MD-2 on Belt Conveyor BC-13. Belt Conveyors BC-12 and BC-13 will
be equipped with swing arm as-fired sample cutters SMP-2 and SMP-3 which will
collect the coal samples from the belt and send them to the modular sampling system
house located at ground elevation.
The discharge chutework of Conveyors BC-12 and BC-13 will be provided with
motorized flop gates to provide complete cross-over redundancy to feed either of the
two Tripper Conveyors BC-14 and BC-15.
Tripper Conveyors BC-14 and BC-15 will each be 48”, 1200 TPH and will each deliver
coal to a traveling tripper, Conveyor BC-14 to Traveling Tripper TRP-1 and Conveyor
BC-15 to Traveling Tripper TRP-2. Each traveling tripper will be equipped with a single
discharge chute and will deliver coal to any selected plant silo. Dust Collection System
(DC) will provide dust control in Transfer Tower TT-4 and the coal silos.
1.3.2 Equipment Description.
Train Positioner.
The train positioner will be at the exit end of the dumper and capable of automatically
positioning a train of 150 cars each weighing 286,000 lbs. to 315,000 lbs., and four (4)
locomotives. The positioner will incorporate all necessary safety devices to prevent
damage to the train and/or positioner in event of a power failure or emergency.
080307-145491
Interstate Power & Light Company
Sutherland Unit 4 Air Permit Application
The positioner will be equipped with a hydraulic cable tensioning device. The unit train
will be under the control of the positioner arm or wheel chocks at all times. The
positioner will incorporate entry truck type chocks to insure immobilization of the train
during the offloading of the rotary coupled train. A set of exit hook and pawl chocks will
be provided and used in conjunction with the entry chocks, to hold empty cars during the
offloading of unit-rain and random cars.
Rotary Railcar Dumper.
The rotary car dumper will consist of a rotating cradle of suitable size and structural
rigidity resting on a double set of trunnion wheels mounted on foundations. The dumper
will be driven by an electromechanically driven system proven suitable for the type of
services and duty specified. The dumper will include a movable platen, stationary spill
girder and gravity setting mechanical car clamp system. The dumper will be designed for
unit car unloading.
The car dumper will consist of the following components:
Drive Mechanism, Rack & Pinion. The rotation of the dumper will be
accomplished by a single motor connected through a flexible coupling to speed
reducer unit. The low speed output shafts of the speed reducer will be flange
coupled to line shafts, which will then be coupled to the pinion strands
compete with drive rack gears located on each end ring.
Rotating Cradle. The rotating cradle will be a structural steel frame
incorporating two end rings and supported on a total of eight wheels, four under
each end ring. The rotating part of the dumper will consist of a rigid structure,
capable of withstanding as an integrated unit, all forces resulting from its function
of inverting railcars.
Platen. The platen will be a structural steel table carrying car rails and supported
on rollers. The connection of the platen to the rotating cradle will be such that the
platen will be suitably supported and guided in the event the cradle is rotated
when there is no car in the dumper.
Bucket Wheel Stacker/Reclaimer.
The bucket wheel stacker/reclaimer will be rail mounted hinged bascule, single
counterbalanced slewing/luffing boom, cell-less bucket wheel type stacker/reclaimers
with retractable trailer including an elevating conveyor, capable of both automatic and
manual stacking to and reclaiming from double stockpiles located at both sides of its
rail track.
The following are the major components of the bucket wheel stacker/reclaimer.
080307-145491
Interstate Power & Light Company
Sutherland Unit 4 Air Permit Application
Fixed Gantry. The fixed gantry will have a travel mechanism with flanged
wheels 50 % of which will be driven by electric motors and gear reducers. The
slewing mechanism will be mounted on the fixed gantry structure, incorporating
large-diameter anti-friction bearing with ring gear including its drive mechanism
and slewing ring locking assembly. Slewing drives will be variable frequency
drives.
Rotating Structure. The rotating structure will be mounted on the slewing ring
(bearing) enabling the entire structure to rotate. The rotating structure will
support boom with associated boom conveyor, operators cab, bucket wheel and
the counterweight boom. The entire boom assembly will be hinge mounted on
the rotating structure and can be raised and lowered with hydraulic lift
mechanism mounted on the rotating structure.
Belt Conveyors. The conveyor subcomponents include the conveyor belt, idlers,
pulleys, take-ups, bearings, belt cleaners, drives, motors, drive base-plates, walkways,
stringers, supports, head and tail frames, foundations, and all other appurtenances
necessary for each of the individual conveyors. The elevated portion of all conveyors
between structures, except for Conveyors BC-5A and BC-5B, will be supported by
enclosed box type trusses with solid floors. A walkway on one side of the conveyors will
be furnished for single conveyors. One walkway will be provided for dual conveyors less
than 48-inches in width. Three walkways will be provided for dual conveyors 48-inches
wide and greater. The conveyor trusses will be suitable for use with a washdown system.
Telescopic Chute. A telescopic chute will be provided at the discharge end of the stock
out conveyors to control dust emissions during stock piling of the coal. The telescopic
chute will consist of steel fabricated concentric tubular sections telescoping into each
other as required for stock piling of coal into a conical pile. The telescoping sections of
the chute will be lifted or lowered by a motorized winch.
Belt Feeders. The function of the belt feeders will be to receive coal from the hoppers
located above the feeders and feed to the belt conveyors located below the feeders at a
fixed or variable rate.
Coal Crushers. The coal crushers will be ring granulator type crushers which will be
able to produce 1200 TPH of 1-1/4 inch product while receiving raw coal of 3 x 0
inches. The crushers will have a rugged heavy-duty dust-tight frame of welded or cast
steel construction.
All internal wear parts will be made of manufacturer’s
recommended steel and will be replaceable. The main shaft will be manufacturer’s
recommended steel and will be equipped with heavy-duty roller antifriction bearings
arranged for grease lubrication. The crushers will be equipped with externally
adjustable devices to permit control of product size and to compensate for wear.
Traveling Trippers. Traveling trippers will be of the motor driven, self-propelled,
reversible, automatic and manually positioned type, designed to straddle the tripper belt
conveyors and travel over the in-plant storage/ mill silos to any desired discharge
080307-145491
Interstate Power & Light Company
Sutherland Unit 4 Air Permit Application
position. Each tripper will be rated for the conveyor capacity it serves. The tripper
machine will be equipped with single discharge chute for discharging the coal. The
tensioned over-the-chute sealing belt systems will be furnished to seal the bunker slot
openings.
Metal Detectors. The metal detectors will be of the electronic type which will
continuously monitor the conveyor belts for tramp metals. The metal detectors will be
designed to detect all types of tramp metal, whether ferrous, nonferrous, magnetic, or
nonmagnetic, from the entire width of the material being conveyed on the conveyor
belt.
Magnetic Separators. The magnetic separator will be the overhead, manual cleaning
suspended type or self-cleaning, belted in-line, type. The magnetic separator will be
housed completely inside dust covers. The self cleaning magnetic separator will be
positioned above and forward of the conveyor head pulley. The magnet will be sloped
towards a tramp iron chute. The tramp iron chute will transport tramp iron to a collection
box at grade.
Belt Scales. The primary function of the belt scale will be for feed rate control and
material inventory monitoring. The belt scales will be the 3 or 4-idler precision digital
electronic type with solid-state circuitry and built-in, self-testing devices. The scales will
also be provided with test weights for self calibration. Each belt scale will use an
environmentally sealed, temperature-compensated, load-sensing device and weigh bridge.
The scales will weigh and totalize to a value within either 1/4 % or 1/2 % of the test load
at flow rates between 25% and 100% of the scale system’s calibrated capacity.
080307-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Fly Ash Handling
1.2
Function
The Fly Ash Handling system is comprised of two separate systems. The Saleable Fly
Ash Handling System removes fly ash from the ESP hoppers and transfers it to a saleable
fly ash storage silo or a winter fly ash storage building via a continuously operating
pneumatic vacuum and vacuum/pressure conveying system. The Waste Fly Ash Handling
System removes fly ash from the fabric filter hoppers, air heater hoppers, SCR hoppers,
and economizer hoppers and transfers it via a continuously operating pneumatic vacuum
conveying system to a fly ash waste storage silo. The hopper fluidizing system for the
fabric filter is not covered in this system definition.
The saleable fly ash silo will be equipped with a silo bottom aeration system and
fluidized outlet hopper. Fly ash from the saleable storage silo will be loaded into closed
ash hauling trucks or railcars or conditioned and loaded into open dump trucks for
placement in a landfill, via a dry telescoping spout. A combination truck or rail scale
capable of weighing both carriers will be provided for the saleable fly ash silo.
The fly ash waste storage silo will be equipped with a silo bottom aeration system and
fluidized outlet hopper. Fly ash from the waste storage silo will be conditioned and
loaded into open dump trucks for placement in a landfill. The fly ash waste silo will also
be equipped with a dry telescoping spout for loading into closed ash hauling trucks.
The winter fly ash storage building will be equipped with a pressurized conveying system
to convey ash from the ESP vacuum filter/separator hopper to the building. A network of
pressure conveying line branches will be provided to distribute saleable ash within the
building.
To recover the ash from the building, a recovery air gravity conveyor system will be
provided to promote ash flow into a below grade recovery hopper. The recovery air
gravity conveyor system will work in conjunction with a front end loader. A mechanical
conveying system will transfer ash from the recovery hopper to a truck load-out system.
A truck scale will be provided for the winter storage building truck load-out system. Dust
collection and ash return equipment will be included to keep the building under negative
pressure.
1.3
Process Description
1.3.1 Saleable Fly Ash Conveying System
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
The Saleable Fly Ash Handling System will service all unit ESP hoppers, one saleable fly
ash storage silo and one fly ash winter storage building as shown in process flow diagram
M2022A.
Each collection point in the fly ash handling system will be tied into a pneumatic vacuum
conveying system via ash intake valves arranged in a straight branch line off the main
conveying lines. The conveying system will sequentially remove fly ash from the ESP
hoppers and transfer the material to either the saleable fly ash storage silo or the winter
storage building via a pressure conveying system. Each ESP hopper will be equipped
with a manual hopper isolation valve and an automatic material intake valve. The
automatic material intake valve isolates the hopper being emptied and provides a
controlled flow of ash into the conveyor line. Each valve will be arranged for air-electric
operation and will include replaceable, abrasion resistant components.
Two vacuum filter/separators (2 X 100%) located on top of the saleable fly ash storage
silo will receive and transfer the material to the saleable fly ash storage silo via a double
dump airlock valves. A third vacuum filter/separator (1 x 100%) located at ground level
next to the winter storage building will receive and transfer the ash into the winter storage
building via a pressure pneumatic conveying system for future recovery into dry ash
trucks. Each vacuum filter/separator on the saleable fly ash silo will consist of a
continuous operating filter section with filter bags, pulse jet filter bag cleaning system,
integral surge hopper and double dump airlock valve assembly for discharge into the silo.
The vacuum filter/separator for the winter fly ash storage building will consist of a
continuous operating filter section with filter bags, pulse jet filter bag cleaning system,
integral surge hopper and a pressure airlock pneumatic conveyor to convey the ash to the
winter storage building. Inside the building, a pressure conveying line will be provided
with branches to direct the ash to various areas of the building. Each branch will be
equipped with an automatic isolation valve. A dust detector will be furnished to detect
broken filter bags and prevent intrusion of ash into the exhausters.
Air intake heaters will be provided at the intake end of the ESP conveying line branches.
Automatic vacuum breaker valves will also be furnished on the mechanical exhauster
piping of each vacuum filter/separator.
Two (2 X 100%) mechanical exhausters will be furnished for the vacuum conveying
system. Each exhauster will be designed to supply motive air to convey the ash at the
specified rate. One (1 X 100%) pressure blower will be furnished for the pressure
conveying system to the winter storage building. The pressure blower will be designed to
supply motive air to convey the ash at the specified rate.
Two pneumatic conveying lines will convey material from the ESP branch lines to each
filter/separator. The two conveying lines will be capable of transporting ash to the
saleable fly ash storage silo or to the winter storage building pressure
conveying/distribution system. One conveying line will be provided to convey material
from the pressure airlock to the winter storage building including a distribution system
with automatic valves to direct ash to various areas of the building.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Branch segregating knife gate valves will be furnished on each branch line in the
pneumatic conveying system. These valves will be of the automatic, abrasion resistant
knife gate type, actuated by air cylinder operators. The conveying lines will be designed
to maintain the air velocity above the material saltation velocity, minimize bends and
provide adequate access for clearing out lines. The system will be able to start and stop
conveying with ash in the conveying pipelines. All piping, elbows, laterals, and other
fittings used on vacuum conveying pipelines will have minimum hardness ratings
designed for ash conveying service.
The saleable fly ash storage silo will be designed to receive and temporarily store
saleable fly ash from the conveying system. The silo will have pass through access for
ash discharge to railcars and trucks. The capacity of the silo will allow for up to four days
of material storage based on the unit running at MCR conditions while burning worst
case fuel. The saleable fly ash storage silo will be equipped with a fluidizing system to
promote ash discharge during unloading. The silo will also include a bin vent filter,
material level sensors and equipment access.
The silo will be equipped with a dry fly ash load out station. This station will consist of
discharge valves, telescopic chute assembly, vent fan, vent return valve, vent piping and
pendant control. A combination truck or rail scale will be provided below the silo.
1.3.2 Waste Fly Ash Conveying System
The Waste Fly Ash Handling System will service all unit fabric filter hoppers, all air
heater hoppers, all SCR hoppers, all economizer hoppers and one fly ash waste storage
silo as shown in process flow diagram M2022C.
Each collection point in the waste fly ash handling system will be tied into a pneumatic
vacuum conveying system via ash intake valves arranged in a straight branch line off the
main conveying lines. The conveying system will sequentially remove fly ash from the
hoppers and transfer the material to the fly ash waste storage silo. Each hopper will be
equipped with a manual hopper isolation valve and an automatic material intake valve.
The automatic material intake valve isolates the hopper being emptied and provides a
controlled flow of ash into the conveyor line. Each valve will be arranged for air-electric
operation and will include replaceable, abrasion resistant components.
Two vacuum filter/separators (2 X 100%) located on top of the fly ash waste storage silo
will receive and transfer the material to the fly ash waste storage silo via a double dump
airlock valves. Each vacuum filter/separator on the fly ash waste silo will consist of a
continuous operating filter section with filter bags, pulse jet filter bag cleaning system,
integral surge hopper and double dump airlock valve assembly for discharge into the silo.
A dust detector will be furnished to detect broken filter bags and prevent intrusion of ash
into the exhausters.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Air intake heaters will be provided at the intake end of each fabric filter conveying line
branch. Automatic vacuum breaker valves will also be furnished on the mechanical
exhauster piping of each vacuum filter/separator.
Two (2 X 100%) mechanical exhausters will be furnished for the vacuum conveying
system. Each exhauster will be designed to supply motive air to convey the ash at the
specified rate.
Two pneumatic conveying lines will convey material from the fabric filter branch lines to
each filter/separator. Each row of fabric filter hoppers will have an independent
conveying line. The two conveying lines will be capable of transporting ash to the fly ash
waste storage silo.
Pneumatic conveying lines will convey material from the air heater hoppers, SCR
hoppers and economizer hoppers to each filter/separator. These conveying lines will tie
into the conveying lines from the fabric filter.
Branch segregating knife gate valves will be furnished on each branch line in the
pneumatic conveying system. These valves will be of the automatic, abrasion resistant
knife gate type, actuated by air cylinder operators. The conveying lines will be designed
to maintain the air velocity above the material saltation velocity, minimize bends and
provide adequate access for clearing out lines. The system will be able to start and stop
conveying with ash in the conveying pipelines. All piping, elbows, laterals, and other
fittings used on vacuum conveying pipelines will have minimum hardness ratings
designed for ash conveying service.
The fly ash waste storage silo will be designed to receive and temporarily store fly ash
from the conveying system. The silo will have pass through access for ash discharge to
trucks. The capacity of the silo will allow for up to four days of material storage based on
the unit running at MCR conditions while burning worst case fuel. The fly ash waste
storage silo will be equipped with a fluidizing system to promote ash discharge during
unloading. The silo will also include a bin vent filter, material level sensors and
equipment access.
Ash conditioning pugmills (2 x 100%) will be provided as the primary means of ash
unloading from the fly ash storage silo. Flow control valves will be provided to meter the
ash and water into the pugmill. The silo will also be equipped with a dry fly ash load out
station. This station will consist of discharge valves, telescopic chute assembly, vent fan,
vent return valve, vent piping and pendant control.
1.3.3 Saleable Fly Ash Storage Silo, Fluidizing System and Discharge
System
A saleable fly ash storage silo will be supplied to receive and temporarily store saleable
fly ash from the vacuum conveying system. The capacity of the silo will allow for up to
4 days of saleable ash storage, including allowances for angle of repose and freeboard
clearance, based on the unit running at MCR conditions while burning worst case fuel.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
The roof of the silo will be equipped with two filter/separators, a bin vent filter, a
material level transmitter and material high level switches. A pressure/vacuum relief
assembly, along with a roof manway access hatch will also be included on the roof. The
silo will be arranged with parallel truck or railcar pass-through access and will include
platforms at both the roof elevation and the unloading floor elevation. A single jib crane
will be provided atop the silo.
The silo will be of a flat-bottom design utilizing a floor fluidizing system to promote ash
flow toward the silo discharge hopper(s) during unloading. The silo fluidizing system
will consist of a network of floor fluidizer diffuser assemblies. The area of fluidizing
coverage will be no less than 12 percent of the entire silo floor area. Fluidizing blowers
(one operating, one standby), air heaters, piping, valves and flow control accessories will
be furnished for the silo.
Ash conditioning equipment will be provided as the primary means of ash unloading at
the silo. Two ash conditioning pugmills (one operating, one standby) will be provided on
the enclosed unloading floor under the silo. Manual and air cylinder operated valves will
be provided to isolate the unloading equipment from the silo. An ash metering device
(either automatic valve with positioner and feedback loop or rotary vane feeder) will
control the flow of fly ash into the pugmill. A pressure regulating valve and flow meter
will control the flow of water into the pug mill.
To accommodate fly ash sales, the fly ash silo will be equipped with a dry load out
station which consists of a telescopic chute assembly, silo isolation valve, automatic
valve, vent fan, vent return valve, piping and a pendant control. The silo will also have
pass through access with a combination truck or rail scale for weighed ash discharge to
railcars or trucks.
The silo unloading operation will be automated to the maximum practical extent. Local
control stations will be provided to allow for the activation and control of the truck filling
operation by the truck driver, including minor adjustments to ash/water feed rates.
The truck loading area beneath the silo will be equipped with wash down facilities.
Truck wash down water will drain to a local saleable fly ash silo drainage sump. Water
collected in the saleable fly ash silo drain sump will be periodically pumped to the waste
water collection pond by one of two full capacity sump pumps (one operating, one
standby).
1.3.4 Fly Ash Waste Storage Silo, Fluidizing System and Discharge
System
A fly ash waste storage silo will be supplied to receive and temporarily store fly ash from
the vacuum conveying system. The capacity of the silo will allow for up to 4 days of ash
storage, including allowances for angle of repose and freeboard clearance, based on the
unit running at MCR conditions while burning worst case fuel.
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
The roof of the silo will be equipped with two filter/separators, a bin vent filter, a
material level transmitter and material high level switches. A pressure/vacuum relief
assembly, along with a roof manway access hatch will also be included on the roof. The
silo will be arranged with parallel truck pass-through access and will include platforms at
both the roof elevation and the unloading floor elevation. A single jib crane will be
provided atop the silo.
The silo will be of a flat-bottom design utilizing a floor fluidizing system to promote ash
flow toward the silo discharge hopper(s) during unloading. The silo fluidizing system
will consist of a network of floor fluidizer diffuser assemblies. The area of fluidizing
coverage will be no less than 12 percent of the entire silo floor area. Fluidizing blowers
(one operating, one standby), air heaters, piping, valves and flow control accessories will
be furnished for the silo.
Ash conditioning equipment will be provided as the primary means of ash unloading at
the waste silo. Two ash conditioning pugmills (one operating, one standby) will be
provided on the enclosed unloading floor under the silo. Manual and air cylinder
operated valves will be provided to isolate the unloading equipment from the silo. An
ash metering device (either automatic valve with positioner and feedback loop or rotary
vane feeder) will control the flow of fly ash into the pugmill. A pressure regulating valve
and flow meter will control the flow of water into the pug mill.
The fly ash waste silo will also be equipped with a dry load out station which consists of
a telescopic chute assembly, silo isolation valve, automatic valve, vent fan, vent return
valve, piping and a pendant control.
The waste silo unloading operations (both dry and conditioned fly ash) will be automated
to the maximum practical extent. Local control stations will be provided to allow for the
activation and control of the truck filling operation by the truck driver, including minor
adjustments to ash/water feed rates.
The truck loading area beneath the silo will be equipped with wash down facilities.
Truck wash down water will drain to a local fly ash waste silo drainage sump. Water
collected in the fly ash waste silo drain sump will be periodically pumped to the waste
water collection pond by one of two full capacity sump pumps (one operating, one
standby).
1.3.5 Fly Ash Winter Storage Building, Fluidizing System and Load-out
System
A winter storage building will be supplied to receive and temporarily store saleable fly
ash from the ESP vacuum/pressure conveying system. The fly ash storage capacity of the
building will be 30,000 tons. The building will be constructed of a concrete base,
concrete partial wall, structural steel frame, steel wall panels and steel roof panel
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
sections. Access and platforms will be provided for maintenance of equipment inside the
building. Access doors for front end loading equipment will be provided.
To fill the building, one vacuum filter/separator located at ground level will receive ash
from the ESP hoppers and discharge it through a pressure airlock into a pressure
conveying line with multiple branches to distribute the ash within the building. Each
branch will be equipped with an automatic isolation valve. Two dust collectors with ID
fans will be provided to pull dust laden air from inside the building and exhaust the
filtered air to atmosphere. The dust collector will maintain the building under a slight
negative pressure. A rotary airlock and screw conveyor will be provided at the discharge
of the dust collector hopper to convey accumulated dust back into the building.
To remove the ash from the building an air gravity conveyor will be supplied at floor
level to promote ash flow into an ash recovery hopper in conjunction with a front end
loader. Ash collected in the recovery hopper will be conveyed by screw conveyor to the
truck load-out area. The screw conveyor will discharge into a bucket elevator which will
convey the material up into a dry load out station positioned over a truck drive-through.
The load-out station consists of a telescopic chute assembly, automatic isolation valve,
vent return valve, piping to the building dust collector system and a pendant control. A
truck scale for the truck load-out system will also be provided.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – FGD Solids
1.2
Function
This document provides basic function and description for the solids material handling of
the flue gas desulfurization (FGD) addition.
The function of the Flue Gas
Desulfurization (FGD) Solids System is to collect and dewater the solids produced within
the Flue Gas Desulfurization System, and transport the dewatered solids to an enclosed
storage building or an emergency stock pile. The quality of FGD solids produced will be
of “wallboard” grade gypsum.
1.3
Process Description
There will be two 100 percent FGD Solids System trains housed in a common building.
The dewatered FGD solids will be discharged from the vacuum filters onto one of the
two FGD solids product conveyors GC-1A or 1B through motorized diverter gates.
Conveyor GC-1A will transfer the FGD solids to a transfer conveyor GC-2. The transfer
conveyor GC-2 will transfer the solids to an elevated shuttle belt conveyor GC-3, located
inside the solids storage building. The shuttle conveyor will prepare a series of conical or
elongated piles of solids inside the building. Finally the FGD solids from the storage
building as well as the emergency stock pile will be loaded onto trucks by mobile
equipment (by others).
In order to prevent fine solids from accumulating in the FGD recycle tanks, a small flow
stream will be taken from the hydrocyclone classifier overflow to be blown down to a
local drain sump that will be equipped with an agitator to keep the solids in suspension
and to be removed later using sump pumps that will transfer the sump water to the
Wastewater Collection and Treatment System.
Classifiers will be capable of being backflushed or serviced on line to remove any
pluggage that occurs.
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Biomass Handling
1.2
Function
The biomass handling system will provide the necessary functions to receive, process and
convey the processed biomass to the boiler. The design and process described herein are
based on the principles and extensive operating experience derived from the biomass fuel
operations at IPL’s Ottumwa Generating Station.
1.3
Process Description
The biomass fuel is harvested into “bales,” which are of approximate dimensions of 3 ft
by 3 ft by 8 ft (which weigh approximately 700 pounds) or 3 ft by 4 ft by 8 ft (which
weigh approximately 1,000 pounds). The bales will be delivered to the site on flatbed
trailers with 54 (3 ft by 3 ft by 8 ft) bales or 36 (3 ft by 4 ft by 8 ft) bales on each trailer.
The bales will then be unloaded with a forklift and piled in the storage building.
The bales will be picked up with the forklift and placed on a conveyor. The binding
twine will automatically be cut and retrieved from the bale prior to the bale feeding into
the “debaler,” a hammermill, which will mill the biomass before sending it through a
sizing screen.
After passing through the screen, the biomass will be collected and conveyed to the
“eliminator”, an attrition mill configured to reduce the biomass to the selected size for
pneumatic conveying to the boiler. Prior to the biomass reaching the attrition mill, a
magnetic belt traversing the feed conveyor, will collect all foreign metal objects captured
during the baling process.
A baghouse and separator will pull the biomass material from the eliminator grinder,
where the heavy material will drop down a surge bin, and the lighter material will move
into the baghouse for collection.
The biomass material will then be removed from the baghouse through the tube conveyor
to storage surge bins for pneumatic transport to the boiler. All of the equipment
downstream of the eliminator grinder will be kept at a slight negative pressure for dust
control.
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Bottom Ash
1.2
Function
The Bottom Ash System collects and removes bottom ash from the bottom of the steam
generator furnace. The system also collects coal pulverizer (pyrites) rejects. All are
gathered in the upper trough of the Submerged Scraper Conveyor (SSC) and conveyed to
a three walled ash storage bunker for periodic truck transport to a landfill.
1.3
Process Description
A mechanical system for collection, removal, dewatering and transport of bottom ash will
be provided. The system will also provide for the removal and transport of DeNOX ash,
economizer ash, coal pulverizer rejects and storage bunker drain effluent. Boiler seal
plates, which extend below the SSC upper trough water level, will provide a pressure seal
for the boiler.
Bottom ash produced in the steam generator furnace will fall into the water-filled upper
trough of the SSC. DeNOX and Economizer ash will be transferred via dry drag chain
conveyors to the SSC outside of the seal plates. Rejects from the coal pulverizers will be
sluiced to the SSC outside of the seal plates. The collected ash and coal pulverizer rejects
in the upper trough of the SSC will be conveyed up a dewatering slope and discharged
into a three-sided concrete storage bunker located indoors at the ground level, from where
it will be loaded directly into ash dump trucks for off-site sales or transport to a landfill.
The Bottom Ash System will also be designed to remove coal pulverizer rejects which
represent 1.0 percent, by weight of the as-fired coal. During normal operation of the
steam generator, each rejects hopper will continuously receive material rejected from the
coal pulverizer. Material will accumulate in each rejects hopper until transferred to the
SSC. During the transfer process, each coal pulverizer rejects jet pump will be operated
in sequence to sluice the rejects from its respective hopper through a common transport
line to the SSC. The rejects will enter the SSC at an enclosed area of the conveyor trough
outside of the steam generator seal plates or as required to prevent splashing of water
onto the lower boiler tubes. Each rejects hopper will be a self-supported steel tank
mounted near the coal pulverizer rejects outlet and will be provided with a jet pump for
intermittent hydraulic transfer of the rejects to the SSC. The coal pulverizer rejects
system will also be designed for hopper unloading following a mill trip.
Sluice water for transporting coal pulverizer rejects will be supplied from two sluice
water pumps. One primary pump and one standby pump will be provided. The sluice
water pumps will supply the required flow and pressure to the jet pumps to transport the
coal pulverizer rejects from the hoppers to the SSC. The sluice water pumps will take
their suction from the upper trough of the SSC (outside the seal plates).
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Chimney
1.2
Function
The function of the Chimney is to discharge combustion gas to the atmosphere at a
sufficient elevation to provide adequate diffusion as required by the air permit.
1.3
Description
The Chimney shall consist of a reinforced concrete shell surrounding, protecting, and
supporting a liner carrying flue gas for atmospheric dispersal. It consists of the following
four components:
•
Foundation--Shall provide support and carry the loads to the subsurface.
•
Structural Shell--Shall provide support for the contained liner and systems
and stability for the entire structure.
•
Access--Shall provide means of ingress and egress and allow for access to
the contained systems through doors, service car, ladders, and platforms.
•
Drains and Plumbing--Shall provide wastewater drains at the base of the
Chimney.
The Chimney shall occupy the area at the south end of the power block downstream of
the AQCS Scrubber Module. It shall be founded on a reinforced concrete foundation
supported on piles. The gas path shall consist of a fiberglass reinforced plastic (RFP)
liner extending from the inlet breeching connected to the ductwork downstream of the
Scrubber Module to the chimney outlet. An expansion joint shall separate the upstream
ductwork from the breeching penetrating the shell and liner. The base of the liner shall
be elevated to match the ductwork elevation.
Appurtenances shall be included to result in a complete gas dispersal system. The shell
shall contain a construction opening (to be fitted with a motorized roll up door following
construction) and a personnel door accessing the bottom of the chimney. Interior steel
and grating platforms shall be provided near the midpoint and at the top of the chimney
for access and operation of continuous emissions monitoring equipment and service of
obstruction lighting. An equipment hoist shall be provided to move materials to the
Monitoring Platform on the inside of the shell. A ladder, with required standoffs and
safety climb apparatus, and a rack-and-pinion vertical lift service car, rated at 900 pound
capacity operating at a minimum of 120 fpm, shall be provided on the shell interior for
access to the platforms. The vertical lift service car shall include a manual lowering
device for emergency operation. The Chimney shall be provided with aviation
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
obstruction lighting in accordance with FAA requirements mounted on swing-in doors
for light maintenance from the interior platforms. An electrical area shall be provided at
the base of the Chimney to contain the power and control system for the aviation lighting.
The base of the liner shall contain a drain and a piping system leading to a drain in the
Chimney foundation for removal of collected rainwater to the plant wastewater system.
The liner shall contain an ash cleanout port at its base. Ventilation of the annulaus space
shall be provided by louvers with bird screens.
The final size, arrangement, and details of the Chimney shall be determined during the
detailed design based on load requirements, equipment enclosure and access, and
regulatory and permitting restrictions.
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Emergency Generation
1.2
Function
The Emergency Generation System shall provide power for essential loads following the
loss of auxiliary power.
The Emergency Diesel Generator (EDG) shall be supplied to provide emergency
shutdown power at 480 volt ac upon the loss of normal 480 volt ac power. The EDG shall
be connected to BOP/Essential Area Load Centers and provide a backup power feed to
the essential 480 volt ac motor control center, from which it shall distribute power to
loads such as the turbine turning gear, the turning gear oil pump, jacking oil pumps (if
any), hydrogen seal oil pump, boiler fans oil pumps (if any), boiler feed pump,
lubricating oil pumps, plant control room lighting, and stack obstruction lighting.
The EDG backup operation shall be automatic. Upon loss of normal 480 volt ac power,
the automation system shall automatically start the EDG, open the two main LC breakers
and close the EDG and tie breakers. Transfer from EDG back to normal 480 volt ac
power shall be closed transition.
The EDG shall require an electric operated maintenance circuit breaker connected to a
480 volt load bank. The EDG shall be required to be tested periodically, and this electric
breaker and load bank shall allow the starting and testing of the EDG off line without
affecting the normal operation of BOP/Essential LCs 11 and 21.
1.3
Process Description
The emergency diesel generator consists of a prime mover and generator. In the event of
the loss of auxiliary power, ac power shall be supplied by the emergency generator. The
emergency generator shall consist of a 480 volt, three-phase, 60 hertz generator driven by
a direct coupled diesel engine.
The emergency diesel generator shall be connected to a 480 volt secondary unit
substation that shall feed the emergency motor control centers (MCCs) supplying power
to selected unit and common emergency loads.
The emergency diesel generator will be periodically tested to confirm its ready-to-start
condition. It will be manually started, brought up to speed and voltage, synchronized
onto a 480 volt bus, and loaded. Following completion of the test, the emergency
generator will be unloaded and manually removed from service.
The number of buses connected to the emergency diesel generator shall be limited.
Equipment requiring standby generator power shall be connected to selected 480 volt
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
buses. Loads shall be limited to those designated “essential” and “emergency,” and
connection of those loads shall be accomplished by closing a minimum number of
480 volt bus main breakers.
The emergency diesel generator shall be provided with its own “Black Start” capability,
but shall not be sized to provide this capability for the units. The emergency diesel
generator shall be capable of being started, synchronized to the system, and loaded to its
full rating without dependence on ac auxiliary power.
The fuel governing system shall be capable of isochronal or droop type speed regulation.
The generator design shall allow parallel operation for testing purposes. Bumpless
transfer schemes shall be used when switching between isochronal and droop modes.
Remote control for the emergency diesel generator shall be provided from the Main
Control Room. The operator interface shall include indication and alarms for operator
monitoring of relevant parameters and conditions, and operator controls for remotely
synchronizing and operating the generator, and manually adjusting the fuel governor and
voltage regulator.
The emergency diesel generator equipment shall be mounted in a weather proof, sound
attenuating enclosure on a double-walled fuel tank (belly tank). All transformers, motor
starters, electrical equipment, and auxiliary equipment to locally operate the generator set
shall be furnished and mounted within the confines of the steel base. All interconnecting
piping and wiring for steel base mounted equipment shall be factory installed. Three 2hole grounding pads shall be furnished and factory installed: one bronze pad attached to
the generator frame adjacent to the main lead terminal housing and two pads on each end
of the generator skid frame.
The muffler shall be on top of the enclosure. Stack height shall comply with permit.
The emergency diesel generator shall be sized according to the continuous emergency
load requirements and the motor starting requirements of the generating station during a
shutdown. The emergency load shall consist of loads required for maintaining a soft
shutdown of the generation unit’s turbine generator, steam generator, and scrubber. The
emergency generator shall be sized so that the bus voltage does not drop below 90
percent when the largest motor is started with all other loads in operation. These
emergency loads shall include, but not be limited to, the following:
•
125 VDC system battery chargers.
•
Generator seal oil pumps.
•
Turbine bearing oil pumps.
•
Turbine turning gear.
•
Elevators.
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
•
Obstruction lighting.
•
Emergency quench pumps.
•
Emergency lighting systems.
•
Control building.
•
DCS equipment rooms.
The generator and exciter shall be designed and constructed in accordance with the
following conditions:
Design Condition
Minimum net continuous rated
capacity at 80 percent power factor
2,000 kW (standby rating)
Location
Outdoors; 40° C, maximum
Rated voltage
480 wye
Electrical output characteristics
3-phase, 3-wire, 60 hertz
Generator speed, rpm
1,800
Type of excitation system
Static
“Black Start” capability
Station auxiliary ac power not available
for startup
Neutral grounding resistor
Rated 27.7 ohms, 600 volts nominal
The armature and field windings shall be coated with a fungus resistant resin. The
insulation system of the armature and field shall be Class F (155° C hot spot).
Construction shall include damper windings and shall be of the salient-pole type. The
specified exciter shall enable the generator to sustain 300 percent of rated full load
current for 10 seconds during a fault condition.
The diesel engine shall be suitable for standby service and sized to drive the emergency
generator at rated output under the following design conditions:
•
40° C maximum ambient cooling air through the radiator(s).
•
50° C maximum ambient air temperature around the engine.
•
Elevation above sea level of approximately 860 feet.
•
Glycol in cooling system suitable for an ambient temperature of - 30° F
(-34.4° C).
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
•
Outdoor location.
•
The exhaust system of the diesel engine having a silencer or muffler as
specified.
•
The fuel tank sized to provide sufficient fuel for 24 hours of continuous
operation at the expected plant load. The base fuel tank shall be double
walled satisfying the secondary containment requirements found in the
Environmental Protection Administration 40 CFR 112.7(c). The tank
shall have overfill prevention measures that include an overfill alarm and
an automatic flow restrictor or flow shutoff.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Fencing and Security
1.2
Function
The Fencing and Security System controls access into the site. The system shall also
control access to the existing Unit 1, 2 & 3 while allowing free movement between the
existing Units and Unit 4.
1.3
Description
General Arrangement Drawing 145491-DS-1000 and Site Arrangement Drawing 145491DS-1001 show the proposed Fencing System layout.
A new perimeter fence and motor-operated slide gates shall be provided around the site
as indicated on General Arrangement Drawing 145491-DS-1000. A new fence and
swing gates shall be provided around the switchyard as indicated on General
Arrangement Drawing 145491-DS-1000 and Site Arrangement Drawing 145491-DS1001.
Fencing and gates shall be composed of galvanized chain link mesh and posts and meet
the appropriate material ASTM Standard Specifications. Fencing shall include top rail,
bottom rail, bottom tension wire and three strands of barbed wire mounted on 45-degree
extension arms. Chain link mesh shall be six feet tall. Slide gates shall be capable of
remote operation and swing gates shall be manually operated.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Gate Station Heater
1.2
Function
Natural gas will be used during start up for both the new and existing boilers at the SGS,
and will be the primary fuel for the new auxiliary boiler. The natural gas supply to the
SGS will arrive via a high pressure natural gas pipeline. As the natural gas is extracted
from the high pressure pipeline across a pressure reducing control valve, the reduction in
pressure will naturally cool the gas below the dew point temperature and to a temperature
too low to be combusted in the boilers. As such, a natural gas fired gate station heater
will be used to heat the natural gas upstream of the pressure reducing device to prevent
the gas from dropping below the recommended operating temperature. The gate station
heater will have a maximum heat input limit of 3 MBtu/h and designed for continuous
operation.
1.3
Process Description
The Gate Station Heater receives high pressure natural gas from a single interface point
for the natural gas supply system provided by the Owner.
The heater uses an indirect fired heating process and an intermediate heating fluid. In this
process, natural gas is burned and the resulting hot combustion gases flow through fire
tubes located inside the lower portion of a large pressure vessel where the heat is
transferred to the water/ethylene glycol mixture surrounding the fire tubes. The
combustion gases will be exhausted to a stack after exiting the end of the fire tubes. The
surrounding fluid will then circulate up to the tubes carrying the natural gas to be heated.
These tubes are located in the upper portion of the vessel and receive heat from the hot
fluid circulating over the natural gas tubes. The cooled fluid will then flow back to the
bottom of the vessel.
The hot fuel gas is then reduced in pressure and regulated to 125 psig. Fuel gas is
provided to the auxiliary boiler and to the steam generator ignitors.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Limestone Handling System
1.2
Function
The function of the Limestone Handling System will be to receive bulk limestone by
bottom dump hopper rail cars with an alternate by truck, to provide a means to stock out
and store the limestone in an active storage pile, and to provide reclaim capacity to satisfy
plant usage requirements.
1.3
Process Description
1.3.1 System Operation:
Bulk limestone will be delivered by either bottom dump hopper rail cars or dump trucks
and will be unloaded into the limestone unloading hopper, HPR-1. Belt feeders FDR-1 &
2 will receive limestone from unloading hopper outlets and transfer it to the receiving
conveyor CVY-1 which will transfer the material at a rate of 600 TPH to the limestone
pile through a telescopic chute CHE-1. The conical shaped pile will have a total capacity
equivalent to 7-days use. The limestone pile will be enclosed by a covered steel structure
to protect the limestone from the weather.
The limestone will be reclaimed from this storage pile by two underground belt feeders
located below the vibrating drawdown hoppers which will feed the same onto the reclaim
conveyor CVY-2. The reclaim conveyor will transfer the limestone at a rate of 400 TPH
to the distribution/silo fill conveyor CVY-3, which will be running on top of the two
limestone silos of Unit 4. The reclaim conveyor will discharge the limestone into a twoway chute with motorized diverter gate, GAT-1. One leg of this chute will be used to fill
the limestone silo 1 and the other leg will transfer the limestone to the distribution/silo fill
conveyor CVY-3 to fill the silo 2 of Unit 4.
The limestone reclaiming and silo fill system will operate as needed basis, to fill the
limestone silos. During the operation of the limestone mills, a silo low level alarm will
trigger either an automatic or an operator controlled start function of the reclaim and silo
fill system.
The operators will be able to regulate the speed of the belt feeders for both the stock out
and reclaim conveyors with the help of in-line belt scales mounted on these conveyors.
An in-line magnetic separator mounted at the head/discharge section of reclaim conveyor
CVY-2 will be able to remove the harmful ferrous metal objects from the limestone flow
before they reach the silos or the mills.
Suitably designed dust control equipment will be installed at strategic locations of the
system. The limestone dust control system will control the escape to atmosphere of dust
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
particles generated at the various transfer locations in the limestone handling system.
The bottom dump rail/truck dump facility will be provided with an enclosure. A dry
induced air fabric filter bag type dust collection system, DC-1 will be provided at the
enclosure to control dust emissions during unloading railcars or trucks. The transfer
chutes below the railcar/truck dump hopper and the reclaim hoppers will be provided
with dry fog type dust suppression systems, DS-1 & 3 respectively. A spray type dust
suppression system, DS-2, will be provided at the discharge of Telescopic Chute CHE-1.
Two fabric filter bag type bin vent dust collectors BV-1 & 2 will be provided on top of
each limestone silo for Unit 4.
1.3.2 Equipment Description:
Belt Conveyors. The conveyor subcomponents include the conveyor belt, idlers,
pulleys, take-ups, bearings, belt cleaners, drives, motors, drive base-plates, walkways,
stringers, supports, head and tail frames, foundations, and all other appurtenances
necessary for each of the individual conveyors. The elevated portion of all conveyors
between structures will be supported by enclosed box type trusses with solid floors. A
walkway on the one side of the conveyors will be furnished. The conveyor trusses will
be suitable for use with a washdown system.
Telescopic chute. A telescopic chute will be provided at the discharge end of the
receiving/stock out conveyor CVY-1, to control dust emissions during stock piling of
limestone. The telescopic chute will consist of steel fabricated concentric tubular
sections telescoping into each other as required for stock piling of limestone into a
conical pile. The telescoping sections of the chute will be lifted or lowered by a
motorized winch.
The telescopic chute will be rigidly supported from the outlet flange of the head chute of
the stock out conveyor CVY-1.
Belt Feeders. The function of the belt feeders will be to receive limestone from the
hoppers located above the feeders and feed to the belt conveyors located below the
feeders at a desired rate.
Belt feeders FDR-1 & 2, will be equipped with variable speed drives, 20-degree picking
table idlers, adjustable screw take up, and other components as appropriate.
Magnetic Separator. The magnetic separator will be the overhead, self-cleaning, belted
in-line, fluid-filled type. The magnetic separator will be housed completely inside dust
covers. The magnetic separator will be mounted at the head chute of conveyor CVY-2.
The magnetic separator will be positioned above and forward of the conveyor head
pulley. The magnet will be sloped towards a tramp iron chute. The tramp iron chute will
transport tramp iron to a collection box at grade.
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Belt Scales. Conveyors CVY-1 & 2 will be provided with belt scales. The primary
function of the belt scales is for feed rate control and material inventory monitoring. The
belt scales will be the 3 or 4-idler precision digital electronic type with solid-state
circuitry and built-in, self-testing devices. The scales will also be provided with test
weights for self calibration. Each belt scale will use an environmentally sealed,
temperature-compensated, load-sensing device and weigh bridge. The scales will weigh
and totalize to a value within 1 to 2% of the test load at flow rates between 25% and
100% of the scale system’s calibrated capacity.
Limestone Storage Building. The limestone storage building will completely enclose
the conical shaped 7-day storage pile. The three sides of the building and the roof will be
fully covered to prevent the escape of limestone dust and to protect the pile from weather.
One side of the building will be open to provide access for mobile equipment and will be
provided with a dust curtain. The storage building will be constructed from steel
columns and beams and provided with girts, purlins and bracing. The roof and three
sides will be of non-insulating metal panel construction.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
System Description
1.1
System Identification – Site and Equipment Fire Protection
1.2
Function
The Site and Equipment Fire Protection System will convey water to fire hydrants, hose
stations, fixed water suppression systems and provide independent fire detection systems,
standpipe and fire hose stations, and portable fire extinguishers in the minimum
combinations required to protect equipment, buildings, structures, and their contents in
the event of fire. It is not the intent of this document to identify all of the necessary fire
protection system, but rather to clarify the minimum requirements identified at the time
of this writing.
1.3
Process Description
The Site and Equipment Fire Protection System consists of the following major
equipment and components:
•
Fire hydrants.
•
Hose stations.
•
Fixed water suppression systems.
•
Independent fire detection systems.
•
Main Fire Pumps (one electric and one diesel) and Pressure Maintenance
Pump.
•
Fire Water Booster Pumps (one electric and one diesel) and Pressure
Maintenance Pump
•
Portable fire extinguishers.
•
Piping, valves and accessories.
•
Backflow prevention as required by City.
Water supply for the Site and Equipment Fire protection System will be from two (2)
independent 24” sources supplied at interconnections to City Water mains. Underground
water mains shall be arranged in a loop header system around the Steam Generation
Building and boiler, leading to fire pumps serving the facility. See the Service Water
System Description for requirements for re-routing the City water leading to the existing
units to the north.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
The fire protection systems and components will comply with applicable state laws, building
and fire prevention codes, local ordinances, NFPA codes and standards based on industry
standard practices and the Owner’s insurance consultant’s requirements. The EPC
Contractor is to prepare a list of the proposed systems for the Owner and Owner’s insurance
consultant’s review and approval. Systems anticipated include:
•
Coal Handling (conveyors, transfer houses, crusher building, railcar
unloading, trippers, dust collectors).
•
Steam turbine operating floor, underfloor, and mezzanine.
•
Steam turbine bearings
•
Boiler feed pump turbines
•
Electrical equipment room detection (DCS, batteries, control room)
•
Administrative and warehouse areas
•
Transformer deluge systems
•
Cooling tower area hydrants (one per two cells) and dry-pipe protection
system
The fire protection systems will include the various types of fixed water suppression and
detection systems for the areas and hazards identified as requiring fire suppression or
detection. These systems operate in response to conditions such as excessive heat,
temperature rate-of-rise, or visible and invisible products of combustion.
Fire pumps shall be horizontal split-case, centrifugal type with UL-listed motor and
accessories, including UL-listed and FM-approved pump controllers. For each pressure
level, one pump will be electric motor drive while the second pump shall be diesel driven.
Each set of two pumps will be furnished in a self contained enclosure at grade, complete
with sprinklers, diesel fuel tanks, controllers, and with a fire rated wall between the two
pumps. An electric motor driven pressure maintenance pump will be required for each
pressure system.
Systems will include fire pump flow test sections and fire department pumper connections.
Portable fire extinguishers will be provided at all standpipe and fire hose stations in addition
to other key locations. The extinguishing medium selected will be dependent on hazards
encountered in the immediate area.
Aboveground piping materials will be carbon steel with welded headers. Underground
fire protection piping will be cement lined ductile iron or UL/FM approved HDPE.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Valves 2-1/2 inch and larger will be cast iron. Two inch and smaller valves will be
bronze where located in copper piping or tubing, forged or cast carbon steel where
located in carbon steel piping, and stainless steel where located in stainless steel piping or
tubing. New fire hydrants will be of the dry barrel type (frostproof) to eliminate freezing
and will be complete with connections and threads matching the existing plant and city
fire department requirements. Each hydrant will have an underground isolation valve and
valve box.
All valves except drains, vents, gauge isolations, and booster pump sensing valves will be
FM approved or UL listed indicating type.
082907-145491
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Appendix E
Appendix E
Flow Diagrams and Site Drawings
102607-145491
E-1
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Appendix F
Appendix F
Equipment Performance Data
102607-145491
F-1
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Composition of Gas Exiting Stack (lb/hr)
Fuel Type:
Case:
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - 1
M10- Run PRB-1
IL - 1
M10- Run IL-1
PRB - 2
M10- Run PRB-2
IL - 2
M10- Run IL-2
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
353,161
4,800,280
0
1,358,469
380
837,451
423,364
4,813,179
0
1,280,117
494
699,458
336,116
4,566,406
0
1,292,086
361
700,434
399,863
4,547,159
0
1,209,205
466
567,035
Total Flue Gas Flow Rate (lb/hr)
7,349,741
7,216,612
6,895,403
6,723,728
261,473
288,852
232,601
257,966
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
11,040
171,360
0
30,870
6
46,490
13,230
171,820
0
29,090
8
38,830
10,500
163,010
0
29,360
6
38,880
12,500
162,320
0
27,480
7
31,480
Total Flue Gas Flow Rate (moles/hr)
259,766
252,978
241,756
233,787
Stack Exit Conditions
Fuel Type:
Case:
Fuel Burn Rate, MBtu/hr
Fuel Higher Heating Value, Btu/lb
Fuel Burn Rate, lb/hr
Wet Molecular Weight, lb/mole
Flue Gas Density, lb/cuft
Total Gas Flow Rate, acfm
Total Gas Flow Rate leaving A/H, acfm
Temperature, F
Pressure, in w.g.
Stack Exit Velocity, ft/sec
Stack Exit Area (ft2)
Stack Diameter (feet)
PRB - 1
M10- Run PRB-1
6,326
8,300
762,157
28.29
0.0631
1,940,460
2,392,341
130
0
59.2
546.63
26.38
IL - 1
M10- Run IL-1
6,169
10,800
571,210
28.53
0.0641
1,876,128
2,337,509
130
0
57.2
546.63
26.38
PRB - 2
M10- Run PRB-2
6,017
8,300
724,913
28.52
0.0641
1,793,722
2,202,160
130
0
54.7
546.63
26.38
IL - 2
M10- Run IL-2
5,828
10,800
539,605
28.76
0.0652
1,719,350
2,135,983
120
0
52.4
546.63
26.38
Nitrogen Oxide
NOX Uncontrolled Emission Rate, lb/Mbtu
0.20
0.20
0.20
0.20
NOX Uncontrolled Emission Rate, ppmvw (actual O 2)
106
106
108
108
NOX Controlled Emission Rate, lb/MBtu
0.05
0.05
0.05
0.05
NOX Controlled Emissions, lb/hr
316.3
308.5
300.8
291.4
26
27
27
27
5,025
92.4%
380
35,493
98.6%
494
4,780
92.4%
361
33,529
98.6%
466
Moisture Added by wet FGD
Composition of Gas Exiting Stack (moles/hr)
NOX Controlled Emissions, ppmvw (actual O2)
Sulfur Dioxide
Uncontrolled SO 2 Emissions, lb/hr
Scrubber Removal Efficiency, %
Controlled SO 2 Emissions, lb/hr
Controlled SO 2 Emissions, moles/hr
6
8
6
7
Controlled SO 2 Emissions, ppmw
23.1
31.6
24.8
29.9
Controlled SO 2 Emissons, lb/MBtu
0.06
0.08
0.06
0.08
Carbon Monoxide (CO)
CO Emission Rate, lb/MBtu
CO Emission Rate, lb/hr
0.12
759
0.12
740
0.12
722
0.12
699
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Fuel Type:
Case:
Sulfur Trioxide (SO3)
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - 1
M10- Run PRB-1
IL - 1
M10- Run IL-1
PRB - 2
M10- Run PRB-2
IL - 2
M10- Run IL-2
SO2 to SO3 Conversion Rate (Boiler and SCR Total), %
2.00
2.00
2.00
2.00
Uncontrolled SO 3 Emissions, lb/hr
125.5
886.8
119.4
837.7
Uncontrolled SO 3 Emissions, moles/hr
1.57
11.08
1.49
10.47
Uncontrolled SO 3 Emissions, ppmvw (actual O2)
6.0
43.8
6.2
44.8
153.8
1086.3
146.3
1026.2
Uncontrolled SO 3 Emissions as H2SO4, lb/hr
Controlled SO 3 Emissions, lb/hr
Controlled SO 3 Emissions, lb/MBtu
Controlled SO 3 Emissions, as H2SO4 lb/hr
Controlled SO 3 Emissions, as H2SO4 lb/MBtu
Particulate (PM+PM10)
Ash Content in Fuel, percent
Unburned Carbon, lb/hr
Uncontrolled Particulate Emissions, lb/hr
Uncontrolled Particulate Emission Rate , lb/MBtu
Uncontrolled Particulate, Emissions, gr/acf
Controlled Particulate Emissions (Filterable), lb/hr
Controlled Particulate Emission Rate (Filterable), lb/MBtu
Controlled Particulate, Emissions (Filterable), gr/acf
Controlled Particulate Emissions (Filterable + Condensible), lb/hr
Controlled Particulate Emission Rate (Filterable + Condensible), lb/mmbtu
Controlled Particulate, Emissions (Filterable + Condensible), gr/acf
Volatile Organic Compounds (VOC)
VOC Emission Rate, lb/MBtu
VOC Emission Rate, lb/hr
Mercury (Hg)
Hg Emission Rate, lb/MW-hr
Ammonia Slip (NH3)
20.7
20.1
19.6
19.0
0.0033
0.0033
0.0033
0.0033
25.3
24.7
24.1
23.3
0.0040
0.0040
0.0040
0.0040
4.93%
380
30,439
4.81
1.83
75.9
0.012
0.0046
113.9
0.018
0.0068
9.52%
370
43,874
7.11
2.73
74.0
0.012
0.0046
111.0
0.018
0.0069
4.93%
361
28,952
4.81
1.88
72.2
0.012
0.0047
108.3
0.018
0.0070
9.52%
350
41,446
7.11
2.81
69.9
0.012
0.0047
104.9
0.018
0.0071
0.0034
21.51
0.0034
20.97
0.0034
20.46
0.0034
19.81
6.6E-05
6.6E-05
6.6E-05
6.6E-05
Ammonia Slip, ppmvd (at 3% O2)
Ammonia Slip, lb/hr
Fluorides as HF
HF Emission Rate, lb/Mbtu
HF Emission Rate, lb/hr
2.00
7.3
2.00
7.3
2.00
6.9
2.00
6.9
0.0002
1.27
0.0002
1.23
0.0002
1.20
0.0002
1.17
Consumables
Water (gpm)
Limestone (lb/hr)
Sorbent Injection (lb/hr)5
Powdered Activated Carbon -- PAC sorbent injection (lb/hr)
Ammonia (Anhydrous) (lb/hr)
Ammonia (Aqueous @ 19% NH 3) (lb/hr)
543
7,786
222
431
375
1,976
747
59,305
2,011
421
366
1,928
484
7,407
212
396
357
1,880
677
55,827
1,899
384
346
1,822
30,363
28,917
1,953
7,515
12,589
43,799
41,680
2,614
10,876
95,663
28,879
27,504
1,844
7,148
11,995
41,376
39,374
2,457
10,274
90,062
Waste Products
Total Fly Ash Removed (lb/hr)
Sellable Fly Ash (lb/hr)
Non-sellable Fly Ash (lb/hr)
Bottom Ash (lb/hr)
Total Byproducts [gypsum] from FGD -- dry basis (lb/hr)
Assumptions:
1. Fly Ash / Bottom Ash Split is 80/20.
2. Unit MW at Design Load is 649 MW Net
References:
1. M-10 Run: IPL Base Load Coal Plant - M-10 Run PRB-1 by Kris Gamble, 5/18/07
2. M-10 Run: IPL Base Load Coal Plant - M-10 Run IL-1 by Kris Gamble, 5/18/07
3. M-10 Run: IPL Base Load Coal Plant - M-10 Run PRB-2 (Max fuel input at mean ambient temperature) by Kris Gamble, 7/31/2007
4. M-10 Run: IPL Base Load Coal Plant - M-10 Run IL-2 (Max fuel input at mean ambient temperature) by Kris Gamble, 7/31/2007
5. SOLVAY Chemicals, SOLVAir Select Application Guide (Sorbent Injection Rate)
Notes:
1. Stack Exit Area and Stack Diameter was set by the PRB - Biomass Fuel case due to the fact that it had the greatest stack flow which drives the stack diameter.
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Composition of Gas Exiting Stack (lb/hr)
Fuel Type:
Case:
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - 2
75% of Max. Heat Input PRB-2
IL - 2
75% of Max. Heat Input IL-2
PRB - 2
50% of Max. Heat Input PRB-2
IL - 2
50% of Max. Heat Input IL-2
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
292,251
3,690,683
0
1,018,760
285
557,461
362,083
3,757,638
0
960,128
370
459,511
255,388
2,661,283
0
679,246
190
374,026
288,811
2,662,403
0
640,154
247
312,105
Total Flue Gas Flow Rate (lb/hr)
5,559,440
5,539,730
3,970,133
3,903,720
187,991
213,141
126,349
146,793
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
9,130
131,750
0
23,150
4
30,940
11,320
134,140
0
21,820
6
25,510
7,980
95,000
0
15,430
3
20,760
9,030
95,040
0
14,550
4
17,320
Total Flue Gas Flow Rate (moles/hr)
194,974
192,796
139,173
135,944
Stack Exit Conditions
Fuel Type:
Case:
Fuel Burn Rate, MBtu/hr
Fuel Higher Heating Value, Btu/lb
Fuel Burn Rate, lb/hr
Wet Molecular Weight, lb/mole
Flue Gas Density, lb/cuft
Total Gas Flow Rate, acfm
Total Gas Flow Rate leaving A/H, acfm
Temperature, F
Pressure, in w.g.
Stack Exit Velocity, ft/sec
Stack Exit Area (ft2)
Stack Diameter (feet)
PRB - 2
75% of Max. Heat Input PRB-2
4,744
8,300
571,566
28.51
0.0641
1,445,407
1,738,831
125
0
44.1
546.63
26.38
IL - 2
75% of Max. Heat Input IL-2
4,627
10,800
428,426
28.73
0.0652
1,416,164
1,725,456
120
0
43.2
546.63
26.38
PRB - 2
50% of Max. Heat Input PRB-2
3,163
8,300
381,084
28.53
0.0644
1,027,703
1,228,459
125
0
31.3
546.63
26.38
IL - 2
50% of Max. Heat Input IL-2
3,085
10,800
285,648
28.72
0.0653
996,132
1,211,621
120
0
30.4
546.63
26.38
Nitrogen Oxide
NOX Uncontrolled Emission Rate, lb/MBtu
0.20
0.20
0.20
0.20
NOX Uncontrolled Emission Rate, ppmvw (actual O 2)
106
104
99
99
NOX Controlled Emission Rate, lb/MBtu
0.05
0.05
0.05
0.05
NOX Controlled Emissions, lb/hr
237.2
231.4
158.2
154.3
26
26
25
25
3,769
92.4%
285
26,621
98.6%
370
2,513
92.4%
190
17,749
98.6%
247
Moisture Added by wet FGD
Composition of Gas Exiting Stack (moles/hr)
NOX Controlled Emissions, ppmvw (actual O2)
Sulfur Dioxide
Uncontrolled SO 2 Emissions, lb/hr
Scrubber Removal Efficiency, %
Controlled SO 2 Emissions, lb/hr
Controlled SO 2 Emissions, moles/hr
4
6
3
4
Controlled SO 2 Emissions, ppmw
20.5
31.1
21.6
29.4
Controlled SO 2 Emissons, lb/MBtu
0.06
0.08
0.06
0.08
Carbon Monoxide (CO)
CO Emission Rate, lb/MBtu
CO Emission Rate, lb/hr
0.12
569
0.12
555
0.12
380
0.12
370
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Fuel Type:
Case:
Sulfur Trioxide (SO3)
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - 2
75% of Max. Heat Input PRB-2
IL - 2
75% of Max. Heat Input IL-2
PRB - 2
50% of Max. Heat Input PRB-2
IL - 2
50% of Max. Heat Input IL-2
SO2 to SO3 Conversion Rate (Boiler and SCR Total), %
2.00
2.00
2.00
2.00
Uncontrolled SO 3 Emissions, lb/hr
94.2
665.1
62.8
443.4
Uncontrolled SO 3 Emissions, moles/hr
1.18
8.31
0.78
5.54
Uncontrolled SO 3 Emissions, ppmvw (actual O2)
6.0
43.1
5.6
40.8
115.4
814.8
76.9
543.2
Uncontrolled SO 3 Emissions as H2SO4, lb/hr
Controlled SO 3 Emissions, lb/hr
15.5
15.1
10.3
10.1
0.0033
0.0033
0.0033
0.0033
Controlled SO 3 Emissions, as H2SO4 lb/hr
19.0
18.5
12.7
12.3
Controlled SO 3 Emissions, as H2SO4 lb/MBtu
0.004
0.004
0.004
0.004
4.93%
285
22,827
4.81
1.84
56.9
0.012
0.0046
85.4
0.018
0.0069
9.52%
278
32,907
7.11
2.71
55.5
0.012
0.0046
83.3
0.018
0.0069
4.93%
190
15,220
4.81
1.73
38.0
0.012
0.0043
56.9
0.018
0.0065
9.52%
185
21,940
7.11
2.57
37.0
0.012
0.0043
55.5
0.018
0.0065
0.0034
16.13
0.0034
15.73
0.0034
10.75
0.0034
10.49
6.6E-05
Controlled SO 3 Emissions, lb/Mbtu
Particulate (PM+PM10)
Ash Content in Fuel, percent
Unburned Carbon, lb/hr
Uncontrolled Particulate Emissions, lb/hr
Uncontrolled Particulate Emission Rate , lb/mmbtu
Uncontrolled Particulate, Emissions, gr/acf
Controlled Particulate Emissions (Filterable), lb/hr
Controlled Particulate Emission Rate (Filterable), lb/MBtu
Controlled Particulate, Emissions (Filterable), gr/acf
Controlled Particulate Emissions (Filterable + Condensible), lb/hr
Controlled Particulate Emission Rate (Filterable + Condensible), lb/MBtu
Controlled Particulate, Emissions (Filterable + Condensible), gr/acf
Volatile Organic Compounds (VOC)
VOC Emission Rate, lb/MBtu
VOC Emission Rate, lb/hr
Mercury (Hg)
Hg Emission Rate, lb/MW-hr
Ammonia Slip (NH3)
6.6E-05
6.6E-05
6.6E-05
Ammonia Slip, ppmvd (at 3% O2)
Ammonia Slip, lb/hr
Fluorides as HF
HF Emission Rate, lb/MBtu
HF Emission Rate, lb/hr
2.00
5.6
2.00
5.7
2.00
4.0
2.00
4.0
0.0002
0.95
0.0002
0.93
0.0002
0.63
0.0002
0.62
Consumables
Water (gpm)
Limestone (lb/hr)
Sorbent Injection (lb/hr)5
Powdered Activated Carbon -- PAC sorbent injection (lb/hr)
Ammonia (Aqueous @ 19% NH 3) (lb/hr)
391
5,840
167
313
1,483
554
44,480
1,508
311
1,447
263
3,894
111
221
990
379
29,657
1,005
218
966
22,770
21,686
1,454
5,636
9,452
32,851
31,261
1,956
8,157
71,797
15,182
14,459
982
3,757
6,301
21,903
20,843
1,315
5,439
47,835
Waste Products
Total Fly Ash Removed (lb/hr)
Sellable Fly Ash (lb/hr)
Non-sellable Fly Ash (lb/hr)
Bottom Ash (lb/hr)
Total Byproducts [gypsum] from FGD -- dry basis (lb/hr)
Assumptions:
1. Fly Ash / Bottom Ash Split is 80/20.
2. Unit MW at Design Load is 649 MW Net
References:
1. M-10 Run: IPL Base Load Coal Plant: 75% of Maximum Heat Input - Mean Ambient PRB-2 by Kris Gamble, 5/18/07
2. M-10 Run: IPL Base Load Coal Plant: 75% of Maximum Heat Input - Mean Ambient IL-2 by Kris Gamble, 5/18/07
3. M-10 Run: IPL Base Load Coal Plant: 50% of Maximum Heat Input - Mean Ambient PRB-2 by Kris Gamble, 5/18/07
4. M-10 Run: IPL Base Load Coal Plant: 50% of Maximum Heat Input - Mean Ambient IL-2 by Kris Gamble, 5/18/07
5. SOLVAY Chemicals, SOLVAir Select Application Guide (Sorbent Injection Rate)
Notes:
1. Stack Exit Area and Stack Diameter was set by the PRB - Biomass Fuel case due to the fact that it had the greatest stack flow which drives the stack diameter.
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Composition of Gas Exiting Stack (lb/hr)
Fuel Type:
Case:
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - BM
M10- Run PRB Coal - Biomass
IL - BM
M10- Run Illinois Coal - Biomass
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
376,484
4,869,907
0
1,362,592
380
845,488
444,174
4,886,735
0
1,288,479
495
716,861
Total Flue Gas Flow Rate (lb/hr)
7,454,851
7,336,744
265,302
293,964
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
11,770
173,840
0
30,960
6
46,930
13,880
174,440
0
29,280
8
39,790
Total Flue Gas Flow Rate (moles/hr)
263,506
257,398
Moisture Added by wet FGD
Composition of Gas Exiting Stack (moles/hr)
Stack Exit Conditions
Fuel Type:
PRB - BM
IL - BM
M10- Run PRB Coal - Biomass
6,333
8,207
771,688
28.29
0.0631
1,967,862
2,427,142
130
0
60.0
M10- Run Illinois Coal - Biomass
6,187
10,488
589,902
28.50
0.0640
1,909,549
2,381,044
125
0
58.2
546.63
26.38
546.63
26.38
Nitrogen Oxide
NOX Uncontrolled Emission Rate, lb/MBtu
0.20
0.20
NOX Uncontrolled Emission Rate, ppmvw (actual O 2)
105
105
NOX Controlled Emission Rate, lb/MBtu
0.05
0.05
NOX Controlled Emissions, lb/hr
316.7
309.3
Case:
Fuel Burn Rate, MBtu/hr
Fuel Higher Heating Value, Btu/lb
Fuel Burn Rate, lb/hr
Wet Molecular Weight, lb/mole
Flue Gas Density, lb/cuft
Total Gas Flow Rate, acfm
Total Gas Flow Rate leaving A/H, acfm
Temperature, F
Pressure, in w.g.
Stack Exit Velocity, ft/sec
Stack Exit Area (ft 2)
Stack Diameter (feet)
NOX Controlled Emissions, ppmvw (actual O 2)
Sulfur Dioxide
Uncontrolled SO 2 Emissions, lb/hr
Scrubber Removal Efficiency, %
Controlled SO 2 Emissions, lb/hr
Controlled SO 2 Emissions, moles/hr
26
26
4,873
92.2%
380
33,907
98.5%
495
6
8
Controlled SO 2 Emissions, ppmw
22.8
31.1
Controlled SO 2 Emissons, lb/MBtu
0.06
0.08
Carbon Monoxide (CO)
CO Emission Rate, lb/MBtu
CO Emission Rate, lb/hr
0.12
760
0.12
742
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Fuel Type:
Case:
Sulfur Trioxide (SO3)
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - BM
M10- Run PRB Coal - Biomass
IL - BM
M10- Run Illinois Coal - Biomass
SO2 to SO3 Conversion Rate (Boiler and SCR Total), %
2.00
2.00
Uncontrolled SO 3 Emissions, lb/hr
121.7
847.1
Uncontrolled SO 3 Emissions, moles/hr
1.52
10.58
Uncontrolled SO 3 Emissions, ppmvw (actual O 2)
5.8
41.1
149.1
1037.8
Uncontrolled SO 3 Emissions as H2SO4, lb/hr
Controlled SO 3 Emissions, lb/hr
Controlled SO 3 Emissions, lb/Mbtu
20.7
20.2
0.0033
0.0033
Controlled SO 3 Emissions, as H2SO4 lb/hr
25.3
24.7
Controlled SO 3 Emissions, as H2SO4 lb/MBtu
0.004
0.004
4.93%
380
30,785
4.86
1.83
76.0
0.012
0.0045
114.0
0.018
0.0068
9.16%
371
43,591
7.05
2.66
74.2
0.012
0.0045
111.4
0.018
0.0068
0.0034
21.53
0.0034
21.04
6.6E-05
6.6E-05
Particulate (PM+PM 10)
Ash Content in Fuel, percent
Unburned Carbon, lb/hr
Uncontrolled Particulate Emissions, lb/hr
Uncontrolled Particulate Emission Rate , lb/MBtu
Uncontrolled Particulate, Emissions, gr/acf
Controlled Particulate Emissions (Filterable), lb/hr
Controlled Particulate Emission Rate (Filterable), lb/MBtu
Controlled Particulate, Emissions (Filterable), gr/acf
Controlled Particulate Emissions (Filterable + Condensible), lb/hr
Controlled Particulate Emission Rate (Filterable + Condensible), lb/MBtu
Controlled Particulate, Emissions (Filterable + Condensible), gr/acf
Volatile Organic Compounds (VOC)
VOC Emission Rate, lb/MBtu
VOC Emission Rate, lb/hr
Mercury (Hg)
Hg Emission Rate, lb/MW-hr
Ammonia Slip (NH3)
Ammonia Slip, ppmvd (at 3% O 2)
Ammonia Slip, lb/hr
Fluorides as HF
HF Emission Rate, lb/MBtu
HF Emission Rate, lb/hr
2.00
7.4
2.00
7.4
0.0002
1.27
0.0002
1.24
Consumables
Water (gpm)
Limestone (lb/hr)
551
7,531
747
56,613
Sorbent Injection (lb/hr) 3
Powdered Activated Carbon -- PAC sorbent injection (lb/hr)
Ammonia (Aqueous @ 19% NH 3) (lb/hr)
214
437
1,940
1,919
429
1,895
30,709
29,246
1,539
7,601
12,163
43,517
41,411
2,180
10,805
91,362
Waste Products
Total Fly Ash Removed (lb/hr)
Sellable Fly Ash (lb/hr)
Non-sellable Fly Ash (lb/hr)
Bottom Ash (lb/hr)
Total Byproducts [gypsum] from FGD -- dry basis (lb/hr)
Assumptions:
1. Fly Ash / Bottom Ash Split is 80/20.
2. Unit MW at Design Load is 649 MW Net
References:
1. M-10 Run: IPL Base Load Coal Plant - M-10 Run; PRB Coal Case - Biomass, by Kris Gamble 5/25/07
2. M-10 Run: IPL Base Load Coal Plant - M-10 Run; Illinos Coal - Biomass, by Kris Gamble 5/25/07
3. SOLVAY Chemicals, SOLVAir Select Application Guide (Sorbent Injection Rate)
Notes:
1. Stack Exit Area and Stack Diameter was set by the PRB - Biomass Fuel case due to the fact that it had the greatest stack flow which drives the stack diameter
Coen Auxiliary Boiler, info from Locke Equipment, at flow 200,000 lb/hr and saturated pressure
250 psi (All values at 100% full load):
Fuel
Natural Gas
Stack Gas Exit Temp
Stack Gas Flow (exhaust density = .0765 lb/ft3)
650 °F
237,980 lb/hr
=51,850 acfm
Stack Exhaust Inside Diameter
5 ft
Stack Height Above Ground
285 ft
Stack Gas Emissions:
NOx
0.037 lbm/MMBtu
CO
0.074 lbm/MMBtu
PM10
0.007 lbm/MMBtu
VOC
0.005 lbm/MMBtu
SOx
0.0006 lbm/MMBtu
Heat Input
268,640,000 Btu/hr
Dawn Equipment, Inc.
2.461 mm Btu/Hr design Heat absorbed to the process fluid (fuel gas)
3.007 mm Btu/hr burner heat release (LHV basis)
Overall Heater Thermal Efficiency = 81.82%, LHV basis
1. Stack Gas Exit Temp (Design Loads and Fuels)
Broach:
700 Deg F
2. Stack Gas Exit Vel (Design Loads and Fuels)
Broach:
20 Feet per Second
3. Stack Gas Vol Flow (Design Loads and Fuels)(acfm)
Broach:
2917 Lbs/hr – Mass Basis, or 1,429 ACFM @ 700 Deg F
4. Stack Exhaust Inside Diameter
Broach:
1’-3” at stack tip
5. Stack Ht Above Ground
Broach:
50 feet approx - for stack draft and safety reasons
6. Stack Gas Emissions (NOx, CO, PM10, SOx, VOC)(lb/h, lb/Mbtu @ Design Loads and Fuels)
Broach:
Typical Exhaust Emissions Limits = 30 ppm NOx, 50 ppm CO, & 0 SOx
(not to exceed)
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Appendix G
Appendix G
Emission Calculations
102607-145491
G-1
IPL
Sutherland Unit 4 PSD Application
Summary of Potential to Emit for Criteria Pollutants
(Tons per year)
CO
Unit 4 Boiler
Auxiliary Boiler
Emergency Generator
Fire Pump
Fire Booster Pump
Gate Station Heater
Cooling Tower
Material Handling
Coal
Transfers
Wind Erosion
Maintenance/Bulldozing
Limestone
Transfers
Wind Erosion
Maintenance/Bulldozing
Miscellaneous Transfers
Saleable Fly Ash
Waste Fly Ash
Biomass
PAC
Sorbent
Lime
Haul Roads
Delivery
TOTAL
SER
PSD Review Required?
3,324.95
19.88
1.72E-01
4.75E-02
5.50E-03
6.21E-01
---
NOx
TSP
PM10
1385.394 498.74184 498.74184
9.94
1.88
1.880
2.09E+00
0.012
0.012
3.11E-01 5.00E-03 5.00E-03
8.55E-02 3.05E-03 3.05E-03
6.12E-01 9.80E-02 9.80E-02
-11.545
11.545
-18.189
4.279
SO2
2216.6304
0.161
0.049
1.02E-02
3.35E-03
7.74E-03
---
Total
Fluorides Reduced
Sulfur
94.206792 0.5049354
0
110.83152 4.7969
0
1.343
1.32E-04
0.000
2.47E-01 0.00E+00
0.00
0.087
8.69E-06
0.000
7.45E-02 2.57E-04
0.00
1.83E-02 1.83E-06 0.00E+00 1.57E-02 5.41E-05 0.00E+00
5.99E-03 5.99E-07 0.00E+00 5.13E-03 1.77E-05 0.00E+00
7.09E-02 6.45E-06 0.00E+00 1.19E-02 0.00E+00 0.00E+00
------------VOC
Pb
H2S
H2SO4
------------------
------------------
11.532
5.201
0.962
5.368
1.314
0.297
0.216
0.801
0.017
0.003
0.003
3.6E-05
0.005
0.005
6.2E-05
5.326
5.326
2.813
1.161
0.481
1.170
0.422
0.118
0.108
0.196
0.006
0.001
0.001
3.6E-05
0.002
0.002
2.3E-05
1.037
1.037
------------------
------------------
------------------
------------------
------------------
------------------
------------------
3,345.67
100
YES
1,398.44
40
YES
530.47
25
YES
516.56
15
YES
2,216.86
40
YES
95.73
40
YES
0.5051
0.6
NO
0.00
10
NO
111.19
7
YES
4.7972
3
YES
0.0000
10
NO
IPL
Sutherland Unit 4
Unit 4 Boiler Parameters
Emissions Calculation
Basis:
Fuel Burn Rate
Fuel Burn Rate
Unit MW (net)
Hours of Operations
Number of Boilers
6,326
768,547
630
8,760
1
Table A1 Unit 4 Boiler Emissions
Emission
Pollutant
Level
(lb/mmBtu)
mmBtu/hr
lb/hr
MW
hr/yr
[1]
Mass Rate
(lb/hr)
PC Boiler
PTE (tpy)
CO
NOx
0.12
0.05
759.1
316.3
[2]
PM10
0.018
113.9
[2]
498.7
506.1
[2]
2,216.6
21.5
[2]
94.2
0.000018
0
0.115
0
[3]
0.505
0
0.004
25.3
[2]
110.8
1.1
0
[5a]
4.8
0
SO2
VOC
Lead
H2 S
H2SO4
Fluorides
Total Reduced Sulfur
0.08
0.0034
0.0002
0
[2]
[4]
[4]
3,324.9
1,385.4
Notes [ ]:
1. Based on boiler performance data at 100% of base load for PRB coal.
2. Performance data contained in Appendix F.
3. Based on fuel analysis. A 97.5% control efficiency was assumed.
4. Hydrogen sulfide and total reduced sulfur emissions are insignificant and assumed to be zero.
All sulfur contained in the coal was assumed to be emitted as either SO2 or H2SO4.
5. Fluoride emissions with assumed 98% control efficiency.
USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.1
"Bituminous and Subbituminous Coal Combustion". September 1998.
a. Table 1.1-15 "Emission Factors for Hydrogen Chloride (HCl) and Hydrogen Fluoride (HF) from
Coal Combustion".
IPL
Sutherland Unit 4 PSD Application
Auxiliary Boiler
Emissions Calculation and Stack Parameters Information
Basis:
Heat Input
Heating Value
Fuel Burn Rate
Hours of Operation
Stack Exit Conditions:
Exhaust Flow Rate
Exhaust Exit Velocity
Exhaust Temperature
Stack Diameter
Stack Height
268.64
1,021
263,115
2,000
mmBtu/hr [1]
Btu/scf[2]
scf/hr
hrs/yr
237,980
44.0116
650
60
285
lb/hr
ft/sec
°F
in
ft
Table A2 Auxiliary Boiler Emissions
Outlet
Conditions [1]
Pollutant
lb/mmBtu
526 Mscf/yr
51,850
13.4147
616.4833
5
86.8680
acfm
m/sec
K
ft
m
1.5240 m
Potential
to Emit
ton/yr
Emission Rate
g/sec
lb/hr
CO
NOx
0.074
0.037
2.5047
1.2524
19.8794
9.9397
[1]
PM/PM10
0.007
0.2369
1.8805
[1]
1.88
0.1612
[1]
0.16
1.3432
[1]
1.34
1.32E-04
0
SO2
VOC
0.0006
0.005
0.0203
0.1692
[1]
19.88
9.94
Lead
H2 S
4.90E-07
0
1.66E-05
0
1.32E-04
0
[3]
H2SO4
9.19E-04
3.11E-02
2.47E-01
[5]
2.47E-01
0
0
[4]
0
0
Fluorides
Total Reduced Sulfur
0
0
0
0
[4]
[4]
Notes [ ]:
1. Vendor data - Coen boiler performance data.
2. Assumed IPL natural gas lower heating value of 1021 Btu/scf.
3. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.4
"Natural Gas Combustion". July 1998. Table 1.4-2 "Emission Factors for Criteria Pollutants
and Greenhouse Gases from Natural Gas Combustion".
4. Hydrogen sulfide, total reduced sulfur, and fluorides emissions are insignificant and assumed to
be zero.
5. Assumed 100% conversion of SO2 to H2SO4.
IPL
Sutherland Unit 4 PSD Application
Emergency Generator Parameters
Emissions Calculation and Stack Parameters Information
Basis:
Power Rating
Heat Input
Heating Value
Fuel Burn Rate
Hours of Operation
Stack Exit Conditions
Number of Stacks
Exhaust Flow Rate
Exhaust Flow Rate
Exhaust Exit Velocity
Exhaust Temperature
Stack Diameter
Stack Height
2,937
19.32
140,000
138.00
100
[3]
HP[1]
mmBtu/hr
Btu/gal[2]
gal/hr[1]
hrs/yr
13,800 gal/yr
:
2
14,920.0
7,460.0
227.9608
761
10
10
#
acfm (total)
acfm (per stack)
ft/sec
°F
in
ft
69.4825
678.15
0.8333
3.0480
m/sec
K
ft
m
Table A3 Diesel Generator Emissions
Outlet
Pollutant
Conditions [1] Emission Rate (per stack)
g/hp-hr
g/sec
lb/hr
0.2540 m
Potential to
Emit (total)
ton/yr
CO
NOx
0.26
3.23
0.2161
2.6378
1.7150
20.9350
[1]
PM/PM10
0.02
0.0145
0.1150
[1]
1.15E-02
SO2
0.08
0.0613
0.48645
[3]
4.86E-02
0.8694
[4a]
8.69E-02
8.69E-05
0
[5a]
8.69E-06
0.00E+00
VOC
0.13
Lead
H2S
1.34E-05
0
H2SO4
Fluorides
Total Reduced Sulfur
0.12
0.0004
0
0.1095
1.10E-05
0
0.0939
0.0003
0
[1]
[6]
1.72E-01
2.09E+00
0.7449
[7]
7.45E-02
2.57E-03
0
[5b]
2.57E-04
0.00E+00
[6]
Notes [ ]:
1. Vendor data - Caterpillar Specification Sheet
2. Assumed fuel oil heating value of 140,000 Btu/gal. USEPA, AP-42, Fifth Edition, Vol. I. Appendix A
"Miscellaneous Data and Conversion Factors". September 1985.
3. Low sulfur fuel oil, 0.05%(wt).
4. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 3 "Stationary Internal Combustion Sources", Section 3.4
"Large Stationary Diesel and All Stationary Dual-fuel Engines". October 1996.
a. Table 3.4-1 "Gaseous Emission Factors for Large Stationary Diesel and All Stationary Dual-Fuel
Engines".
5. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.3 "Fuel Oil
Combustion". September 1998.
a. Table 1.3-10 "Emission Factors for Trace Elements from Distillate Fuel Oil Combustion Sources".
b. Table 1.3-11 "Emission Factors for Metals from Uncontrolled No. 6 Fuel Oil Combustion".
6. Hydrogen sulfide and total reduced sulfur emissions are insignificant and assumed to be zero.
7. Assumed 100% conversion of SO 2 to H2SO4.
IPL
Sutherland Unit 4 PSD Application
Fire Pump Parameters
Emissions Calculation and Stack Parameters Information
Basis:
Power Rating
Heat Input
Heating Value
Fuel Burn Rate
Hours of Operation
Stack Exit Conditions
Exhaust Flow Rate
Exhaust Exit Velocity
Exhaust Temperature
Stack Diameter
Stack Height
575
4.06
140,000
29.00
100
BHP[1]
mmBtu/hr
Btu/gal[2]
gal/hr[1]
hrs/yr
2,900 gal/yr
[1]
:
2,904
246.4992
918
6
12
Table A4 Fire Pump Emissions
Outlet
[1]
Pollutant
Conditions
g/bhp-hr
acfm
ft/sec
°F
in
ft
75.1329
765.372222
0.5000
3.6576
m/sec
K
ft
m
Potential
to Emit
ton/yr
Emission Rate
g/sec
lb/hr
CO
NOx
0.75
4.90
0.1197
0.7824
0.9500
6.2100
[1]
PM/PM10
0.08
0.0126
0.1000
[1]
5.00E-03
0.20445
[3]
1.02E-02
0.3654
[4a]
1.83E-02
3.65E-05
0
[5a]
1.83E-06
0.00E+00
SO2
0.16
0.0258
[1]
4.75E-02
3.11E-01
VOC
0.29
0.0460
Lead
H2S
2.88E-05
0
4.60E-06
0
0.25
0.0394
0.3131
[7]
1.57E-02
0.0009
0
0.0001
0
1.08E-03
0
[5b]
5.41E-05
0.00E+00
H2SO4
Fluorides
Total Reduced Sulfur
0.1524 m
[6]
[6]
Notes [ ]:
1. Vendor data for the Clarke UF70
2. Assumed fuel oil heating value of 140,000 Btu/gal. USEPA, AP-42, Fifth Edition, Vol. I. Appendix A
"Miscellaneous Data and Conversion Factors". September 1985.
3. Low sulfur fuel oil, 0.05%(wt).
4. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 3 "Stationary Internal Combustion Sources", Section
3.4 "Large Stationary Diesel and All Stationary Dual-fuel Engines". October 1996.
a. Table 3.4-1 "Gaseous Emission Factors for Large Stationary Diesel and All Stationary Dual-Fuel
Engines".
5. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.3 "Fuel
Oil Combustion". September 1998.
a. Table 1.3-10 "Emission Factors for Trace Elements from Distillate Fuel Oil Combustion Sources".
b. Table 1.3-11 "Emission Factors for Metals from Uncontrolled No. 6 Fuel Oil Combustion".
6. Hydrogen sulfide and total reduced sulfur emissions are insignificant and assumed to be zero.
7. Assumed 100% conversion of SO2 to H2SO4.
IPL
Sutherland Unit 4 PSD Application
Fire Booster Pump Parameters
Emissions Calculation and Stack Parameters Information
Basis:
Power Rating
Heat Input
Heating Value
Fuel Burn Rate
Hours of Operation
Stack Exit Conditions
Exhaust Flow Rate
Exhaust Exit Velocity
Exhaust Temperature
Stack Diameter
Stack Height
149
1.33
140,000
9.50
100
BHP[1]
mmBtu/hr
Btu/gal[2]
gal/hr[1]
hrs/yr
790.0
96.5625
1044
5
12
acfm
ft/sec
°F
in
ft
950 gal/yr
[1]
:
29.4322
835.372222
0.4167
3.6576
m/sec
K
ft
m
Table A5 Fire Booster Pump Emissions
Outlet
[1]
Emission Rate
Pollutant
Conditions
g/sec
lb/hr
g/bhp-hr
Potential
to Emit
ton/yr
CO
NOx
0.33
5.20
0.0139
0.2153
0.1100
1.7090
[1]
PM/PM10
0.19
0.0077
0.0610
[1]
3.05E-03
0.067
[3]
3.35E-03
0.1197
[4a]
5.99E-03
1.20E-05
0
[5a]
5.99E-07
0.00E+00
0.1026
[7]
5.13E-03
3.54E-04
0
[5b]
1.77E-05
0.00E+00
SO2
0.20
0.0084
VOC
0.36
0.0151
Lead
H2S
3.64E-05
0
1.51E-06
0
0.31
0.0129
H2SO4
Fluorides
Total Reduced Sulfur
0.0011
0
4.46E-05
0
0.1270 m
[1]
[6]
[6]
5.50E-03
8.55E-02
Notes [ ]:
1. Vendor data for the Clarke UFG8
2. Assumed fuel oil heating value of 140,000 Btu/gal. USEPA, AP-42, Fifth Edition, Vol. I. Appendix A
"Miscellaneous Data and Conversion Factors". September 1985.
3. Low sulfur fuel oil, 0.05%(wt).
4. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 3 "Stationary Internal Combustion Sources", Section
3.4 "Large Stationary Diesel and All Stationary Dual-fuel Engines". October 1996.
a. Table 3.4-1 "Gaseous Emission Factors for Large Stationary Diesel and All Stationary Dual-Fuel
Engines".
5. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.3 "Fuel
Oil Combustion". September 1998.
a. Table 1.3-10 "Emission Factors for Trace Elements from Distillate Fuel Oil Combustion Sources".
b. Table 1.3-11 "Emission Factors for Metals from Uncontrolled No. 6 Fuel Oil Combustion".
6. Hydrogen sulfide and total reduced sulfur emissions are insignificant and assumed to be zero.
7. Assumed 100% conversion of SO2 to H2SO4.
IPL
Sutherland Unit 4 PSD Application
Gate Station Heater
Emissions Calculation and Stack Parameters Information
Basis:
Heat Input
Heating Value
Fuel Burn Rate
Hours of Operation
3.007
1,021
2945.15
8,760
mmBtu/hr[1]
Btu/scf [2]
scf/hr
hrs/yr
Molecular Weights
Carbon (C)
Oxygen (O)
Nitrogen (N)
12.0107 g/gmol
15.9994 g/gmol
14.0067 g/gmol
Stack Exit Conditions:
Exhaust Flow Rate
Exhaust Exit Velocity
Exhaust Temperature
Stack Diameter
Stack Height
2,917
19.4076
700
15
20
lb/hr
ft/sec
°F
in
ft
26 Mscf/yr
1,429
5.9154
644.2611
1.25
6.0960
acfm
m/sec
K
ft
m
0.3810 m
Table A6 Gate Station Heater Emissions
Outlet Conditions [1]
lb/mmBtu
ppmv
Pollutant
Molecular
Weight
g/gmol
Potential
to Emit
ton/yr
Emission Rate
g/sec
lb/hr
CO
NOx
0.0471
0.0465
50
30
28.01
46.01
1.79E-02
1.76E-02
0.1418
0.1397
[1]
PM/PM10
0.0074
--
--
2.82E-03
0.0224
[3]
0.10
SO2
0.0006
--
--
2.23E-04
0.0018
[3]
0.01
0.0162
[3]
0.07
6.45E-06
0
VOC
0.0054
Lead 4.90E-07
H2S
-H2SO4 9.00E-04
Fluorides
Total Reduced Sulfur
---
--
--
2.04E-03
[1]
0.62
0.61
---
---
1.86E-07
0
1.47E-06
0
[3]
--
--
3.41E-04
2.71E-03
[5]
1.19E-02
0.0000
0
[4]
0.00E+00
0
---
---
0.00E+00
0
[4]
[4]
Notes [ ]:
1. Vendor data - G.C Broach Co. (Dawn)
2. Assumed IPL natural gas lower heating value of 1021 Btu/scf.
3. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 1 "External Combustion Sources", Section 1.3
"Natural Gas Combustion". July 1998.
Table 1.4-2 "Emission Factors for Criteria Pollutants and Greenhouse Gases from Natural Gas
Combustion".
4. Hydrogen sulfide, total reduced sulfur, and fluorides emissions are insignificant and assumed to be
zero since EPA has not derived an emission factor for either pollutant.
5. Assumed 100% conversion of SO 2 to H2SO4.
IPL
Sutherland Unit 4 PSD Application
Cooling Tower - Linear Mechanical Draft
Cooling Tower Emissions
Basis (per Tower):
Cycled Water TDS
Drift Rate
Cell Diameter
Stack Height
Circulating Water Flow
Exhaust Air Flow (per fan)
Number of Cells (per tower)
Number of Towers
PM10/TSP Fraction
PM2.5/PM10 Fraction
3,500
0.0005
30
53
301,000
1,477,500
16
1
ppmw
%
ft
ft
gpm
cfm
No.
No.
1.000 dimensionless
[1]
0.600 dimensionless
[2a]
Calculations:
TSP Emission (lb/hr) = Circulating Water Flow Rate (gpm) x (Drift Rate(%)/100) x Density of Circulating Water (lb/gal) x TDS (ppmw) x 60 min/hr
TSP Emission (tpy) = TSP Emission (lb/hr) x Operating Hours (hrs/yr) x 1 ton/2,000 lb
PM10 Emission (lb/hr) = TSP Emission (lb/hr) x PM10/TSP Fraction
PM10 Emission (tpy) = PM10 Emission (lb/hr) x Operating Hours (hrs/yr) x 1 ton/2,000 lb
PM2.5 Emission (lb/hr) = PM10 Emission (lb/hr) x PM2.5/PM10 Fraction
PM2.5 Emission (tpy) = PM2.5 Emission (lb/hr) x Operating Hours (hrs/yr) x 1 ton/2,000 lb
Table A7 Cooling Tower Emissions
Number
Activity
of Towers
No.
Cooling Tower - Mechanical
1
Draft
Calculations (for modeling):
Exit Velocity (per cell)
Exit Temperature (dry bulb)
Hours of
Operation
hr/yr
Circulating
Water Flow
gpm
Drift
Rate
%
Density
Circ Water
lb/gal
TDS
ppmw
8,760
301,000
0.0005
8.34
3,500
34.8372 ft/sec =
104.0000 °F
=
10.6184 m/sec
40.0000 °C
=
Potential Uncontrolled Emissions
tpy
TSP
PM10
PM2.5
11.55
11.55
6.93
Control Method
Control
Efficiency
%
NA
0
313.1500 °K
Table A8 Cooling Tower Modeling Parameters
EP
Number [3]
253a-p
Activity
Cooling Tower - Mechanical Draft
Cells
per Tower
No.
16
Controlled Emissions (per cell)
lb/hr
TSP
PM10
PM2.5
Controlled Emissions (per cell)
g/sec
TSP
PM10
PM2.5
0.1647
0.0208
0.1647
0.0988
0.0208
0.0125
Notes [ ]:
1. Assumed all particulate emissions are less than 10 microns.
2. South Coast AQMD, Air Guidance Book "Methodology to Calculate Particulate Matter (PM) 2.5 and PM 2.5 Significance Thresholds". Final. October 2006.
a. Table A "Updated CEIDARS Table with PM2.5 Fractions".
3. IDNR Air Quality Construction Permit Forms ID Number.
Potential Controlled Emissions
tpy
TSP
PM10
PM2.5
11.55
11.55
6.93
IPL
Sutherland Unit 4 PSD Application
Aggregate Transfers
Enclosed Drop Emission Calculation
Emission Factors:
TSP [1]
EF (transfer)
0.0030
EF (crushing)
0.0054
PM-10 [1]
0.0011
0.0024
PM-2.5 [2]
1.65E-04 lb/ton
3.60E-04 lb/ton
Table A9 Enclosed Transfers:
Potential to Emit Calculations
EU
Number
EP
[3]
Max
Number
Transfer Description
Max
Transferred
ton/hr
Transferred
ton/yr
2000
17,520,000
2000
17,520,000
2000
17,520,000
Potential Uncontrolled Emissions
TSP
ton/yr
PM-10
ton/yr
PM-2.5
ton/yr
26.2800
9.6360
1.4454
26.2800
9.6360
1.4454
26.2800
9.6360
1.4454
26.2800
9.6360
1.4454
105.1200
38.5440
5.7816
26.2800
9.6360
1.4454
Control
Control Method
Efficiency
%
Potential Controlled Emissions
[4]
Emission Rates
Flow
Modeling Parameters
Discharge Discharge
Exhaust
Exhaust
Exhaust
TSP
ton/yr
PM-10
ton/yr
PM-2.5
ton/yr
TSP
lb/hr
PM-10
lb/hr
PM-2.5
lb/hr
Rate
acfm
Type [5]
V/H
Height
ft
Diameter
ft
Velocity [6]
fps
Temperature [7]
°K
0.0263
0.0096
0.0014
6.00E-03
2.20E-03
3.30E-04
75,000
V
12
6.5
38
0
0.0263
0.0096
0.0014
0.0263
0.0096
0.0014
6.00E-03
2.20E-03
3.30E-04
75,000
V
12
6.5
38
0
0.0263
0.0096
0.0014
0.1051
0.0385
0.0058
2.40E-02
8.80E-03
1.32E-03
7,500
V
12
3.5
13
0
0.0263
0.0096
0.0014
1.20E-02
4.40E-03
6.60E-04
7,500
V
55
3.5
13
0
2.28E-02
8.36E-03
1.25E-03
7,500
V
65
3.5
13
0
7.20E-03
2.64E-03
3.96E-04
7,500
V
12
3.5
13
0
3.60E-03
1.32E-03
1.98E-04
7,500
V
12
3.5
13
0
3.46E-02
1.37E-02
2.05E-03
30,000
V
125
4.0
40
0
1.44E-02
5.28E-03
7.92E-04
53,000
V
190
5.3
40
0
4.80E-03
1.76E-03
2.64E-04
7,500
V
12
3.5
13
0
1.20E-03
4.40E-04
6.60E-05
7,500
V
35
3.5
13
0
1.20E-03
4.40E-04
6.60E-05
7,500
V
55
3.5
13
0
6.00E-04
2.20E-04
3.30E-05
12,000
V
65
2.5
40
0
Coal
Rotary Car Dumper Building (a)
Unload from railcars to Hopper HPR-1 at rotary car dumper.
Dust Collector
99.90
Dust Collector
99.90
Dust Collector
99.90
254
254a
254
254b
255a
255
255b
255
Transfer from Hopper HPR-1 to to Belt Feeder BF-2.
2000
17,520,000
26.2800
9.6360
1.4454
Dust Collector
99.90
0.0263
0.0096
0.0014
255c
255
Transfer from Belt Feeder BF-1 to Belt Conveyor BC-1.
2000
17,520,000
26.2800
9.6360
1.4454
Dust Collector
99.90
0.0263
0.0096
0.0014
255d
255
Transfer from Belt Feeder BF-2 to Belt Conveyor BC-1.
2000
17,520,000
Dust Collector
99.90
Rotary Car Dumper Building (b)
Unload from railcars to Hopper HPR-1 at rotary car dumper.
Rotary Railcar Dump Vault
Transfer from Hopper HPR-1 to to Belt Feeder BF-1.
Transfer Tower TT-1
Transfer from Belt Conveyor BC-1 to Belt Conveyor BC-4.
256b
256
262a
262
Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-6.
262
Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-7.
26.2800
9.6360
1.4454
52.5600
19.2720
2.8908
52.5600
19.2720
2.8908
4000
35,040,000
99.8640
36.6168
5.4925
1333
11,680,000
17.5200
6.4240
17.5200
6.4240
Transfer Tower TT-2
0.0263
0.0096
0.0014
0.0526
0.0193
0.0029
0.0526
0.0193
0.0029
Dust Collector
99.90
0.0999
0.0366
0.0055
0.9636
Dust Collector
99.90
0.0175
0.0064
0.0010
0.9636
Dust Collector
99.90
0.0175
0.0064
0.0010
0.0005
1333
11,680,000
262g
262
Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-10.
667
5,840,000
8.7600
3.2120
0.4818
Dust Collector
99.90
0.0088
0.0032
262h
262
Transfer from Belt Conveyor BC-4 to Belt Conveyor BC-11.
667
5,840,000
8.7600
3.2120
0.4818
Dust Collector
99.90
0.0088
0.0032
0.0005
262c
262
Transfer from Belt Conveyor BC-8 to Belt Conveyor BC-10.
1200
10,512,000
15.7680
5.7816
0.8672
Dust Collector
99.90
0.0158
0.0058
0.0009
262d
262
Transfer from Belt Conveyor BC-8 to Belt Conveyor BC-11.
1200
10,512,000
15.7680
5.7816
0.8672
Dust Collector
99.90
0.0158
0.0058
0.0009
262e
262
Transfer from Belt Conveyor BC-9 to Belt Conveyor BC-10.
600
5,256,000
7.8840
2.8908
0.4336
Dust Collector
99.90
0.0079
0.0029
0.0004
262f
262
Transfer from Belt Conveyor BC-9 to Belt Conveyor BC-11.
600
5,256,000
7.8840
2.8908
0.4336
Dust Collector
99.90
0.0079
0.0029
0.0004
63.0720
23.1264
3.4690
0.0631
0.0231
0.0035
31.5360
31.5360
11.5632
11.5632
1.7345
1.7345
0.0315
0.0315
0.0116
0.0116
0.0017
0.0017
31.5360
11.5632
1.7345
0.0315
0.0116
0.0017
15.7680
5.7816
0.0158
0.0058
0.0009
262b
Pile 3 Vault
264a
264
264b
264
Transfer from Reclaim Hopper RH-2 to Belt Feeder BF-4.
Transfer from Belt Feeder BF-4 to Belt Conveyor BC-8.
2400
2400
21,024,000
21,024,000
Transfer from Reclaim Hopper RH-3 to Belt Feeder BF-5.
1200
10,512,000
Transfer from Belt Feeder BF-5 to Belt Conveyor BC-9.
1200
10,512,000
15.7680
5.7816
0.8672
Dust Collector
99.90
0.0158
0.0058
0.0009
151.3728
59.9184
8.9878
0.1514
0.0599
0.0090
1200
10,512,000
15.7680
5.7816
0.8672
Dust Collector
99.90
0.0158
0.0058
0.0009
15.7680
5.7816
0.8672
Dust Collector
99.90
0.0158
0.0058
0.0009
0.0009
Pile 4 Vault
266a
266
266b
266
Crusher House CH-1
267a
267
Transfer from Belt Conveyor BC-10 to Crusher Surge Bin SB-1.
267
Transfer from Belt Conveyor BC-11 to Crusher Surge Bin SB-1.
Dust Collector
Dust Collector
99.90
99.90
0.8672
Dust Collector
99.90
1200
10,512,000
267c
267
Transfer from surge bin SB-1 to Belt Feeder BF-6.
1200
10,512,000
15.7680
5.7816
0.8672
Dust Collector
99.90
0.0158
0.0058
267d
267
Transfer from surge bin SB-1 to Belt Feeder BF-7.
1200
10,512,000
15.7680
5.7816
0.8672
Dust Collector
99.90
0.0158
0.0058
0.0009
267e
267
Crusher CR-1.
1200
10,512,000
28.3824
12.6144
1.8922
Dust Collector
99.90
0.0284
0.0126
0.0019
267b
267f
267
Crusher CR-2.
1200
10,512,000
28.3824
12.6144
1.8922
Dust Collector
99.90
0.0284
0.0126
0.0019
267g
267
Transfer from Belt Feeder BF-6 through Crusher CR-1 to Belt Conveyor BC-13.
1200
10,512,000
15.7680
5.7816
0.8672
Dust Collector
99.90
0.0158
0.0058
0.0009
267h
267
Transfer from Belt Feeder BF-7 through Crusher CR-2 to Belt Conveyor BC-12.
1200
10,512,000
15.7680
5.7816
0.8672
Dust Collector
99.90
0.0158
0.0058
0.0009
63.0720
23.1264
3.4690
0.0631
0.0231
0.0035
Transfer Tower TT-4
268a
268
Transfer from Belt Conveyor BC-12 to Tripper Conveyors BC-14.
600
5,256,000
7.8840
2.8908
0.4336
Dust Collector
99.90
0.0079
0.0029
0.0004
268b
268
Transfer from Belt Conveyor BC-12 to Tripper Conveyors BC-15.
600
5,256,000
7.8840
2.8908
0.4336
Dust Collector
99.90
0.0079
0.0029
0.0004
268c
268
Transfer from Belt Conveyor BC-13 to Tripper Conveyors BC-14.
600
5,256,000
7.8840
2.8908
0.4336
Dust Collector
99.90
0.0079
0.0029
0.0004
268d
268
Transfer from Belt Conveyor BC-13 to Tripper Conveyors BC-15.
600
5,256,000
7.8840
2.8908
0.4336
Dust Collector
99.90
0.0079
0.0029
0.0004
268e
268
Transfer from Belt Conveyor BC-14 to Coal Silos.
1200
10,512,000
15.7680
5.7816
0.8672
Dust Collector
99.90
0.0158
0.0058
0.0009
268f
268
Transfer from Belt Conveyor BC-15 to Coal Silos.
1200
10,512,000
Dust Collector
99.90
Pile 2 Vault
15.7680
5.7816
0.8672
21.0240
7.7088
1.1563
0.0158
0.0058
0.0009
0.0210
0.0077
0.0012
269a
269
Transfer from Reclaim Hopper RH-4 to BF-8.
400
3,504,000
5.2560
1.9272
0.2891
Dust Collector
99.90
0.0053
0.0019
0.0003
269b
269
Transfer from Belt Feeder BF-8 to Belt Conveyor BC-5A.
400
3,504,000
5.2560
1.9272
0.2891
Dust Collector
99.90
0.0053
0.0019
0.0003
269c
269
Transfer from Reclaim Hopper RH-5 to BF-9.
400
3,504,000
5.2560
1.9272
0.2891
Dust Collector
99.90
0.0053
0.0019
0.0003
269d
269
Transfer from Belt Feeder BF-9 to Belt Conveyor BC-5A.
400
3,504,000
5.2560
1.9272
0.2891
Dust Collector
99.90
0.0053
0.0019
0.0003
5.2560
1.9272
0.2891
0.0053
0.0019
0.0003
400
3,504,000
5.2560
1.9272
0.2891
Dust Collector
99.90
0.0053
0.0019
0.0003
Transfer Tower TT-3
270
270
Transfer from Belt Conveyor BC-5A to Belt Conveyor BC-5B.
Existing Transfer Tower
271
271
272
272
Transfer from Belt Conveyor BC-5B to Hopper HPR-2
400
3,504,000
200
1,752,000
Truck Loadout Enclosure
Transfer from the Hopper HPR-2 to future truck load out
Total Uncontrolled Emissions
5.2560
1.9272
0.2891
5.2560
1.9272
0.2891
2.6280
0.9636
0.1445
2.6280
0.9636
0.1445
653.32
243.97
36.59
Dust Collector
99.90
Dust Collector
99.90
Total Controlled Emissions
0.0053
0.0019
0.0003
0.0053
0.0019
0.0003
0.0026
0.0010
0.0001
0.0026
0.0010
0.0001
0.65
0.24
0.04
Table A9 Enclosed Transfers:
Potential to Emit Calculations
EU
EP
Number [3]
Number
Transfer Description
Max
Max
Transferred
ton/hr
Transferred
ton/yr
600
5,256,000
600
5,256,000
Potential Uncontrolled Emissions
TSP
ton/yr
PM-10
ton/yr
PM-2.5
ton/yr
7.8840
2.8908
0.4336
7.8840
2.8908
0.4336
7.8840
2.8908
0.4336
7.8840
2.8908
0.4336
Control
Control Method
Efficiency [4]
%
Potential Controlled Emissions
Emission Rates
Flow
Modeling Parameters
Discharge Discharge
Exhaust
Exhaust
Exhaust
TSP
ton/yr
PM-10
ton/yr
PM-2.5
ton/yr
TSP
lb/hr
PM-10
lb/hr
PM-2.5
lb/hr
Rate
acfm
Type [5]
V/H
Height
ft
Diameter
ft
Velocity [6]
fps
Temperature [7]
°K
0.0079
0.0029
0.0004
1.80E-03
6.60E-04
9.90E-05
75,000
V
35
6.5
38
0
0.0079
0.0029
0.0004
0.0079
0.0029
0.0004
1.80E-03
6.60E-04
9.90E-05
75,000
V
35
6.5
38
0
0.0079
0.0029
0.0004
5.40E-03
1.98E-03
2.97E-04
7,500
V
12
3.5
13
0
2.40E-03
8.80E-04
1.32E-04
7,500
V
12
3.5
13
0
1.20E-02
4.40E-03
6.60E-04
1,500
H
110
1
0.0033
0
2.40E-02
8.80E-03
1.32E-03
1,500
H
110
1
0.0033
0
3.93E-05
3.93E-05
3.93E-05
3.93E-05
6.25E-04
1.44E-05
1.44E-05
1.44E-05
1.44E-05
2.29E-04
2.16E-06
2.16E-06
2.16E-06
2.16E-06
3.44E-05
4,000
4,000
2,000
20,000
20,000
H
H
H
H
H
12
12
105
23
23
1.25
1.25
1.1
3.5
3.5
0.0033
0.0033
0.0033
0.0033
0.0033
0
0
0
0
0
3.93E-05
3.93E-05
6.25E-04
1.44E-05
1.44E-05
2.29E-04
2.16E-06
2.16E-06
3.44E-05
1,350
1,350
2,000
H
H
H
28
28
105
0.8
0.8
1.1
0.0033
0.0033
0.0033
0
0
0
1.20E-03
4.40E-04
6.60E-05
1,000
H
114.99
1.1
0.0033
0
1.20E-03
3.02E-05
4.40E-04
1.11E-05
6.60E-05
1.66E-06
5,000
5,000
H
H
114.99
279.99
1.1
1.1
0.0033
0.0033
0
0
1.41E-05
5.17E-06
7.76E-07
5,000
H
77
1.1158
0.0033
0
Limestone
Railcar/Truck Unloading Building (a)
Unload from railcars to hopper at unloader.
Dust Collector
99.90
Dust Collector
99.90
0.0237
0.0087
0.0013
0.3252
Dust Collector
99.90
0.0059
0.0022
0.0003
0.3252
Dust Collector
99.90
0.0059
0.0022
0.0003
0.0003
280
280a
280
280b
23.6520
8.6724
1.3009
281a
281
Transfer from Hopper HPR-1 to Belt Feeder FDR-1.
450
3,942,000
5.9130
2.1681
281b
281
Transfer from Hopper HPR-1 to Belt Feeder FDR-2.
450
3,942,000
5.9130
2.1681
Railcar/Truck Unloading Building (b)
Unload from railcars to hopper at unloader.
Railcar/Truck Unloading Vault
281c
281
Transfer from Belt Feeder FDR-1 to Belt Conveyor CVY-1.
450
3,942,000
5.9130
2.1681
0.3252
Dust Collector
99.90
0.0059
0.0022
281d
281
Transfer from Belt Feeder FDR-2 to Belt Conveyor CVY-1.
450
3,942,000
5.9130
2.1681
0.3252
Dust Collector
99.90
0.0059
0.0022
0.0003
10.5120
3.8544
0.5782
0.0105
0.0039
0.0006
Pile Vault
283a
283
Transfer from Hopper HPR-2 to Belt Feeder FDR-3.
200
1,752,000
2.6280
0.9636
0.1445
Dust Collector
99.90
0.0026
0.0010
0.0001
283b
283
Transfer from Hopper HPR-3 to Belt Feeder FDR-4.
200
1,752,000
2.6280
0.9636
0.1445
Dust Collector
99.90
0.0026
0.0010
0.0001
283c
283
Transfer from Belt Feeder FDR-3 to Belt Conveyor CVY-2.
200
1,752,000
2.6280
0.9636
0.1445
Dust Collector
99.90
0.0026
0.0010
0.0001
283d
283
Transfer from Belt Feeder FDR-4 to Belt Conveyor CVY-2.
200
1,752,000
2.6280
0.9636
0.1445
Dust Collector
99.90
0.0026
0.0010
0.0001
5.2560
1.9272
0.2891
0.0526
0.0193
0.0029
5.2560
1.9272
0.2891
0.0526
0.0193
0.0029
Silo 1
284
284
285a
285b
285
285
Transfer from Belt Conveyor CVY-2 to Limestone Silo 1.
400
3,504,000
10.5120
3.8544
0.5782
400
400
3,504,000
5.2560
1.9272
3,504,000
5.2560
65.70
Silo 2
Transfer from Belt Conveyor CVY-2 to Belt Conveyor CVY-3.
Transfer from Belt Conveyor CVY-3 to Limestone Silo 2.
Total Uncontrolled Emissions
Saleable Fly Ash
286
286
287
288
288
286a
286b
287
288a
288b
Pneumatic Conveyor Blower Exhaust
Pneumatic Conveyor Blower Exhaust
Ash Silo bin vent fan
Ash storage building Vent Fan
Ash storage building Vent Fan
1.31
1.31
1.31
1.31
20.84
11,476
11,476
11,476
11,476
182,558
Total Uncontrolled Emissions
Waste Fly Ash
289
289
290
289a
289b
290
Pneumatic Conveyor Blower Exhaust
Pneumatic Conveyor Blower Exhaust
Ash silo bin vent fan
1.31
1.31
20.84
11,476
11,476
182,558
Total Uncontrolled Emissions
PAC (Mercury)
291
291
Transfer to Silo
40
350,400
Total Uncontrolled Emissions
Bin Vent
99.00
0.1051
0.0385
0.0058
0.2891
Bin Vent
99.00
0.0526
0.0193
0.0029
1.9272
0.2891
Bin Vent
99.00
0.0526
0.0193
0.0029
24.09
3.61
0.21
0.08
0.01
0.0172
0.0172
0.0172
0.0172
0.2738
0.0063
0.0063
0.0063
0.0063
0.1004
0.0009
0.0009
0.0009
0.0009
0.0151
1.72E-04
1.72E-04
1.72E-04
1.72E-04
2.74E-03
6.31E-05
6.31E-05
6.31E-05
6.31E-05
1.00E-03
9.47E-06
9.47E-06
9.47E-06
9.47E-06
1.51E-04
0.3427
0.1257
0.0188
3.43E-03
1.26E-03
1.88E-04
0.0172
0.0172
0.2738
0.0063
0.0063
0.1004
0.0009
0.0009
0.0151
1.72E-04
1.72E-04
2.74E-03
6.31E-05
6.31E-05
1.00E-03
9.47E-06
9.47E-06
1.51E-04
0.3083
0.1130
0.0170
3.08E-03
1.13E-03
1.70E-04
0.5256
0.1927
0.0289
5.26E-03
1.93E-03
2.89E-04
0.5256
0.1927
0.0289
5.26E-03
1.93E-03
2.89E-04
0.5256
0.0132
0.1927
0.0048
0.0289
0.0007
5.26E-03
1.32E-04
1.93E-03
4.84E-05
2.89E-04
7.27E-06
0.5388
0.1976
0.0296
5.39E-03
1.98E-03
2.96E-04
0.0062
0.0023
0.0003
6.18E-05
2.26E-05
3.40E-06
0.0062
0.0023
0.0003
6.18E-05
2.26E-05
3.40E-06
Total Controlled Emissions
Bin Vent
Bin Vent
Bin Vent
Bin Vent
Bin Vent
99.00
99.00
99.00
99.00
99.00
Total Controlled Emissions
Bin Vent
Bin Vent
Bin Vent
99.00
99.00
99.00
Total Controlled Emissions
Bin Vent
99.00
Total Controlled Emissions
Sorbent (H2SO4)
292
293
292
293
Transfer to Day Silo
Transfer to Long Term Silo
40
1.01
350,400
8,808
Total Uncontrolled Emissions
Lime (Water Treatment)
294
294
Transfer of Lime
0.47
4,117
Total Uncontrolled Emissions
Bin Vent
Bin Vent
99.00
99.00
Total Controlled Emissions
Bin Vent
99.00
Total Controlled Emissions
Notes [ ]:
1. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 11 "Mineral Products Industry", Section 11.19.2 "Crushed Stone Processing and Pulverized Mineral Processing". Table 11.19.2-2 "Emission Factors for Crushed Stone Processing Operations". August 2004.
2. Western Governors' Association Western Regional Air Partnership (WRAP). "Background Document for Revisions to Fine Fraction Ratios Used for AP-42 Fugitive Dust Emission Factors". Final. November 1, 2006. Prepared by Midwest Research Institute.
It was assumed that the PM2.5/PM10 ratio of 0.15 recommended for the transfer of aggregate associated with conveyor transfer points subject to an open atmosphere is applicable to an enclosed conveyor transfer point.
3. IDNR Air Quality Construction Permit Forms ID Number.
4. Dust Collectors - Vendor Data
Bin Vent - BACT
5. V - Vertical Discharge, H - Horizontal Discharge
6. For horizontal releases, the exhaust velocity was set to 0.001 m/s per the "AERMOD Implementation Guide", dated September 27, 2005.
7. Represents an ambient temperature release.
IPL
Sutherland Unit 4 PSD Application
Biomass Transfers
Grain Handling Emission Calculation
Emission Factors:
EF (debaler/chipper)
EF (transfer)
TSP [1]
0.0270
0.0140
PM-10 [1]
0.0270
0.0140
PM-2.5 [2]
4.05E-03 lb/hr
2.10E-03 lb/hr
Table A10 Biomass Transfers:
Potential to Emit Calculations
EU
Number
Biomass
295
296
EP
[3]
Number of
Number
295
296
Transfer Description
Operations
No.
Biomass Building (Line 1)
Potential Uncontrolled Emissions
TSP
ton/yr
PM-10
ton/yr
PM-2.5
ton/yr
Control
Control Method
Efficiency
%
Potential Controlled Emissions
[4]
Exhaust
Exhaust
Exhaust
PM-10
ton/yr
PM-2.5
ton/yr
TSP
lb/hr
PM-10
lb/hr
PM-2.5
lb/hr
Rate
acfm
Type [5]
V/H
Height
ft
Diameter
ft
Velocity
fps
Temperature [6]
°K
4.14E-06
4.14E-06
6.21E-07
24,800
V
46.42
2.5
84.2036
0
4.14E-06
4.14E-06
6.21E-07
24,800
V
46.42
2.5
84.2036
0
0.3022
0.3022
0.0453
1.813E-05
1.813E-05
2.720E-06
1
0.1183
0.1183
0.0177
Cyclone & Baghouse
99.994
7.096E-06
7.096E-06
1.064E-06
Transfer
3
0.1840
0.1840
0.0276
Cyclone & Baghouse
99.994
1.104E-05
1.104E-05
1.656E-06
Biomass Building (Line 2)
0.3022
0.3022
0.0453
1.813E-05
1.813E-05
2.720E-06
Debaler/Chipper
1
0.1183
0.1183
0.0177
Cyclone & Baghouse
99.994
7.096E-06
7.096E-06
1.064E-06
Transfer
3
0.1840
0.1840
0.0276
Cyclone & Baghouse
99.994
1.104E-05
1.104E-05
1.656E-06
0.6044
0.6044
0.0907
3.63E-05
3.63E-05
5.44E-06
Total Uncontrolled Emissions
Total Controlled Emissions
Notes [ ]:
1. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 9 "Food and Agricultural Industries", Section 9.3.2 "Grain Harvesting". Table 9.3.2 "Emission Rates/Factors from Grain Harvesting". February 1980.
Section 9.3.2 stated that the emission rates/factors in Table 9.3.2 were for particulate with a mean aerodynamic diameter of <7 micrometers, as such, all emissions were considered to be TSP and PM10.
2. Western Governors' Association Western Regional Air Partnership (WRAP). "Background Document for Revisions to Fine Fraction Ratios Used for AP-42 Fugitive Dust Emission Factors". Final. November 1, 2006. Prepared by Midwest Research Institute.
It was assumed that the PM2.5/PM10 ratio of 0.15 recommended for the transfer of aggregate associated with conveyor transfer points subject to an open atmosphere is applicable to an enclosed conveyor transfer point.
3. IDNR Air Quality Construction Permit Forms ID Number.
4. Dust Collectors - Vendor Data
Bin Vent - BACT
5. V - Vertical Discharge, H - Horizontal Discharge
6. Represents an ambient temperature release.
Flow
Modeling Parameters
Discharge Discharge
TSP
ton/yr
Debaler/Chipper
Emission Rates
IPL
Sutherland Unit 4 PSD Application
Aggregate Transfers
Continuous Conveyor Drop (Open to Atmosphere) Emission Calculation
Emission Factor (EF) Equation [1]
EF = k(0.0032) (U/5)1.3/(M/2)1.4
Equation 1 [1]
Where:
EF = particulate emission factor (lb/ton)
k = particle size multiplier (dimensionless)
U = mean wind speed (mph)
M = material moisture content (%)
Calculated Emission Factors:
TSP
EF (lb/ton)
5.721E-04
7.326E-04
5.446E-03
PM-10
2.706E-04
3.465E-04
2.576E-03
0.74
0.35
0.053
10.0
10.5
8.8
2.1
PM-2.5
4.098E-05
5.247E-05
3.900E-04
for TSP
for PM-10
for PM-2.5
[2]
Avg PRB coal
Avg ILL coal
Limestone
[3]
[3]
[1a]
for PRB coal
for ILL coal
for limestone
Table A11 Atmospheric Transfers:
Potential to Emit Calculations
EU Number
EP
Number [4]
Transfer Description
Max
Max
Potential Uncontrolled Emissions
Control
Transferred
ton/hr
Transferred
ton/yr
TSP
ton/yr
PM-10
ton/yr
PM-2.5
ton/yr
Control Method
4000
4000
4000
4000
35,040,000
35,040,000
35,040,000
35,040,000
12.8357
12.8357
10.0238
12.8357
6.0710
6.0710
4.7410
6.0710
0.9193
0.9193
0.7179
0.9193
Wet Suppression
Wet Suppression
Telescopic Chute/ Wet Suppression
Telescopic Chute/ Wet Suppression
48.53
22.95
3.48
14.3114
6.7689
1.0250
14.3114
6.7689
1.0250
Potential Controlled Emissions
Emission Rates
Modeling Parameters
Release
Height
PM-2.5
lb/hr
ft
Efficiency [5]
%
TSP
ton/yr
PM-10
ton/yr
PM-2.5
ton/yr
TSP
lb/hr
PM-10
lb/hr
95.00
95.00
98.75
98.75
0.6418
0.6418
0.1253
0.1604
0.3035
0.3035
0.0593
0.0759
0.0460
0.0460
0.0090
0.0115
1.47E-01
1.47E-01
2.86E-02
3.66E-02
6.93E-02
6.93E-02
1.35E-02
1.73E-02
1.05E-02
1.05E-02
2.05E-03
2.62E-03
1.57
0.74
0.11
0.0894
0.0423
0.0064
2.04E-02
9.66E-03
1.46E-03
0.09
0.04
0.01
Initial
Sigma y
ft
Initial
Sigma z
ft
6
N/A
N/A
N/A
1.3944
N/A
N/A
N/A
2.7920
N/A
N/A
N/A
N/A
N/A
N/A
Coal
259a/b
260a/b and 26a-d [6]
263 [6]
265 [6]
259
260
263
265
Transfer from Belt Conveyor BC-4 to SR-1 Boom Conveyor/Belt Conveyor BC-4
Transfer from SR-1 Boom Conveyor to Stockout Pile 2-South
Transfer from Belt Conveyor BC-6 to Coal Stockout Pile 3.
Transfer from Belt Conveyor BC-7 to Coal Stockout Pile 4.
Total Uncontrolled Emissions
Total Controlled Emissions
Limestone (Scrubber)
[6]
[6]
Transfer from Receiving Conveyor CVY-1 to Storage Pile
600
5,256,000
Total Uncontrolled Emissions
Telescopic Chute/ Wet Suppression/ Partial Enclosure
Notes [ ]:
1. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 "Miscellaneous Sources", Section 13.2.4 "Aggregate Handling and Storage Piles". November 2006.
a. Table 13.2.4-1 "Typical Silt and Moisture Contents of Materials at Various Industries".
2. U.S. Department of Commerce. "Local Climatological Data - Annual Summary with Comparative Data". Des Moines Surface Station (KDSM) [WBAN: 14933], Des Moines, IA. NCDC, NESDIS, NOAA. 2006.
3. Average moisture content for PRB and Illinois coal based on boiler performance data
4. IDNR Air Quality Construction Permit Forms ID Number.
5. Wet Suppression - An average of the control efficiency for TSP and PM10 emissions from conveyor transfer points. AP-42, Section 11.19.2 (Note [1]))
Telescopic Chute - USEPA. "Stationary Source Control Techniques Document for Fine Particulate Matter". EPA Contract No. 68-D-98-026. Submitted by EC/R Incorporated. October, 1998.
Bin Vent - BACT
Partial Enclosure - Assumed control efficiency
6. Atmospheric transfer emission points included in coal pile summary as drops onto the pile, not as individual point sources.
99.38
Total Controlled Emissions
IPL
Sutherland Unit 4 PSD Application
Conveyors
Partially Covered Emission Calculation
Emission Factors:
[1]
TSP
0.0034
EF
PM-10 [1]
0.0002
PM-2.5 [2]
0.00003 lb/ton
Basis:
Emissions based on maximum rated capacity of conveyor.
Table A12 Conveyors:
EP
Number [3]
NA
Modeling
ID
Number
BC4-(1-80) Conveyor BC-4
Activity
Max
Transferred
ton/hr
ton/yr
4,000
35,040,000
Conveyor
Length
Width
ft
in
958
72
Total Uncontrolled Emissions (tons/yr)
Potential to Emit Calculations
Potential Uncontrolled Emissions
TSP
PM-10
PM-2.5
Control Method
ton/yr
ton/yr
ton/yr
59.5680
3.5040
0.5256
59.57
3.50
0.53
Wet Supression
Control
Potential Controlled Emissions Number
Efficiency [4a]
TSP
PM-10
PM-2.5 of Sources
%
ton/yr
ton/yr
ton/yr
#
95%
Total Controlled Emissions (tons/yr)
2.9784
0.1752
0.0263
2.98
0.18
0.03
80
Modeling Parameters
Emission Rates (per source)
Release
TSP
PM-10
PM-2.5
Height
lb/hr
lb/hr
lb/hr
ft
8.5000E-03
Notes [ ]:
1. USEPA, AP-42, Fourth Edition, Vol. I. Chapter 8 "Mineral Products Industry", Section 8.19.2 "Crushed Stone Processing". September 1985.
a. Table 8.19.2-2 " Uncontrolled Particulate Emission Factors for Open Dust Sources at Crushed Stone Plants"
2. Western Governors' Association Western Regional Air Partnership (WRAP). "Background Document for Revisions to Fine Fraction Ratios Used for AP-42 Fugitive Dust Emission Factors". Final. November 1, 2006. Prepared by Midwest Research Institute.
It was assumed that the PM2.5/PM10 ratio of 0.15 recommended for the transfer of aggregate associated with conveyor transfer points subject to an open atmosphere is applicable to an enclosed conveyor transfer point.
3. IDNR Air Quality Construction Permit Forms ID Number.
4. Texas Commission on Environmental Quality. Air Permit Division. "Rock Crushing Plants". Draft RG 058. February 2002.
a. Table 7 "Controls".
5.0000E-04
7.5000E-05
1.5
Initial
Sigma y
ft
Initial
Sigma z
ft
Material
Handled
5.5814
0.6977
Coal
IPL
Sutherland Unit 4 PSD Application
Vehicle Traffic
Paved Road Emissions Calculation
Emission Factor (EF) Equation [1]
EF = [k * (sL/2)^0.65 * (W/3)^1.5 - C] * (1-(P/(4*N)))
Where:
EF = particulate emission factor, lb/ton
k = particle size multiplier =
sL = surface silt loading, g/m 2 =
W = average vehicle weight, tons =
C = emission factor for 1980's vehicle fleet exhaust, brake & tire wear
P = number of days per year with at least 0.01 in of precipitation
N = number of days in the averaging period
[1a]
0.082
for TSP
0.016
for PM-10 [1a]
0.0024
for PM-2.5 [1a]
0.6
Ubiquitous Baseline (ADT <500) [1c]
see Table below
0.00047 for TSP & PM-10 [1b]
0.00036 for PM-2.5 [1b]
[2]
111.8
365
Basis:
Short Term emissions based on maximum usage/generation rates.
Table A13 Vehicle Traffic Counts:
North Gate Haul Road
Truck Capacity
Round Trips
Empty Vehicle Weight
Full Vehicle Weight
One-way Distance
Trucks per Day
PRB1-100
IL1-100
4
29
1
1
1
1
1
1
14
21
1
2
4
6
Material
Limestone
Sorbent
Powdered Activated Carbon
Ammonia (Aqueous @ 19% NH3)
Sellable Fly Ash
Non-sellable Fly Ash
Bottom Ash
Total Byproducts (gypsum)
7
[3]
Switch Grass
Lime
24
1
[3]
Coal Sales
24
82
[3]
Total -->
25
16,060
11.75
36.75
0.4791
West Gate Haul Road
Truck Capacity
Round Trips
Empty Truck Weight
Full Truck Weight
One-way Distance
tons
truck/year
tons
tons
miles
25
29,930
11.75
36.75
0.8618
tons
truck/year
tons
tons
miles
1
126
Table A14 Vehicle Traffic:
EP
Number [4]
Transport Activity
Average
Vehicle
Weight
tons
TSP
Emission
Factor
lbs/VMT
PM-10
Emission
Factor
lbs/VMT
PM-2.5
Emission
Factor
lbs/VMT
Vehicle
Mile
Traveled
VMT/yr
Potential Uncontrolled Emissions
Control Method
TSP
ton/yr
PM-10
ton/yr
PM-2.5
ton/yr
Potential to Emit Calculations
Potential Controlled Emissions
Control
TSP
PM-10
PM-2.5
Efficiency [5]
%
ton/yr
ton/yr
ton/yr
Number
of Sources
#
TSP
lb/hr
Emission Rates
(per volume source)
PM-10
PM-10
lb/hr
g/s
PM-2.5
lb/hr
Release
Height [6]
ft
Initial
Sigma y
ft
Initial
Sigma z [7]
ft
278
North Gate Haul Road
24.3
0.80
0.15
0.02
15,387.96
6.12
1.19
0.18
Water Flushing
80.00
1.22
0.24
0.035
52
5.3727E-03 1.0460E-03 1.3179E-04 1.5509E-04
3.4442
22.8896
10.6047
279
West Gate Haul Road
24.3
0.80
0.15
0.02
51,589.85
20.51
3.99
0.59
Water Flushing
80.00
4.10
0.80
0.118
93
1.0072E-02 1.9608E-03 2.4705E-04 2.9073E-04
3.4442
22.8896
10.6047
26.63
5.18
0.77
5.33
1.04
0.15
Total Uncontrolled Emissions (tons/yr)
Total Controlled Emissions (tons/yr)
Notes [ ]:
1. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 "Miscellaneous Sources", Section 13.2.1 "Paved Roads". November 2006 (Updated March 7, 2007).
a. Table 13.2.1-1 "Particle Size Multipliers for Paved Road Equation"
b. Table 13.2.1-2 "Emission Factor for 1980's Vehicle Fleet Exhaust, Brake Wear and Tire Wear"
2
c. Table 13.2.1-3 "Ubiquitous Silt Loading Default Values with Hot Spot Contributions from Anti-Skid Abrasives (g/m )"
2. U.S. Department of Commerce. "Local Climatological Data - Annual Summary with Comparative Data". Des Moines Surface Station (KDSM) [WBAN: 14933], Des Moines, IA. NCDC, NESDIS, NOAA. 2006.
3. A total of 64 trucks can be used in any combination of allotment for gypsum, switch grass, and coal sales.
4. IDNR Air Quality Construction Permit Forms ID Number.
5. Water flushing (80%) based on Ohio EPA RACM 1980 document.
6. Assumed a 285/75R24.5 tire.
7. Assumed a truck height of 22.8 ft.
IPL
Sutherland Unit 4 PSD Application
Bulldozing Traffic
Unpaved Road Emissions Calculation
Emission Factor (EF) Equation [1]
EF = k * (s/12)^a * (W/3)^b * ((365-p)/365)
Where:
EF = particulate emission factor, lb/ton
k = particle size multiplier =
a = constant =
s = surface material silt content, % =
b = constant =
W = average vehicle weight, tons =
p = number of days per year with at least 0.01 in of precipitation
4.9
for TSP
1.5
for PM-10
0.15
for PM-2.5
0.7
for TSP
0.9
for PM10 & PM2.5
2.2
for coal (as received) AP-42 13.2.4
3.9
limestone AP-42 13.2.4
0.45
for TSP, PM10, & PM2.5
see Table below
[2]
111.8
Basis:
Short Term emissions based on maximum usage/generation rates.
Bulldozing
Hours
Average Speed
Empty Vehicle Weight (FE Loader)
Full Vehicle Weight (FE Loader)
8.00
4
50
50
hrs/day/pile
mph
tons
tons
Table A15 Vehicle Traffic:
EP
Number [3]
Transport Activity
Average
Vehicle
Weight
tons
TSP
Emission
Factor
lbs/VMT
PM-10
Emission
Factor
lbs/VMT
PM-2.5
Emission
Factor
lbs/VMT
Vehicle
Mile
Traveled
VMT/yr
Potential Uncontrolled Emissions
Control Method
TSP
ton/yr
PM-10
ton/yr
PM-2.5
ton/yr
Potential to Emit Calculations
Potential Controlled Emissions
Control
TSP
PM-10
PM-2.5
Efficiency [4]
%
ton/yr
ton/yr
ton/yr
Number
of Sources
#
TSP
lb/hr
Emission Rates
(per volume source)
PM-10
PM-10
lb/hr
g/s
PM-2.5
lb/hr
Release
Height
ft
Initial
Sigma y [5]
ft
Initial
Sigma z [6]
ft
[7]
Coal Pile Bulldozing North Pile
50.0
3.68
0.80
0.08
11,680
21.47
4.68
0.47
Watering and Speed Reduction
95.00
1.07
0.23
0.023
47
5.2153E-03 1.1372E-03 1.4325E-04 1.1372E-04
24.0000
10.9767
5.0775
[7]
Coal Pile Bulldozing South Pile
50.0
3.68
0.80
0.08
11,680
21.47
4.68
0.47
Watering and Speed Reduction
95.00
1.07
0.23
0.023
53
4.6249E-03 1.0084E-03 1.2703E-04 1.0084E-04
24.0000
10.9767
5.0775
[7]
Coal Pile Bulldozing Blending Pile 3
50.0
3.68
0.80
0.08
11,680
21.47
4.68
0.47
Watering and Speed Reduction
95.00
1.07
0.23
0.023
8
3.0640E-02 6.6808E-03 8.4158E-04 6.6808E-04
40.5000
10.9767
5.0775
[7]
Coal Pile Bulldozing Blending Pile 4
50.0
3.68
0.80
0.08
11,680
21.47
4.68
0.47
Watering and Speed Reduction
95.00
1.07
0.23
0.023
8
3.0640E-02 6.6808E-03 8.4158E-04 6.6808E-04
40.5000
10.9767
5.0775
[7]
Coal Pile Bulldozing North Reclaim Pile
50.0
3.68
0.80
0.08
11,680
21.47
4.68
0.47
Watering and Speed Reduction
95.00
1.07
0.23
0.023
4
6.1280E-02 1.3362E-02 1.6832E-03 1.3362E-03
24.0000
10.9767
5.0775
Watering and Speed Reduction
and Partial Enclosure
97.50
0.80
0.20
0.020
4
4.5744E-02 1.1184E-02 1.4089E-03 1.1184E-03
22.0000
10.9767
5.0775
6.17
1.37
0.14
[7]
Limestone Pile Bulldozing
50.0
5.49
1.34
0.13
11,680
Total Uncontrolled Emissions (tons/yr)
32.06
7.84
0.78
139.42
31.25
3.12
Total Controlled Emissions (tons/yr)
Notes [ ]:
1. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 "Miscellaneous Sources", Section 13.2.2 "Unpaved Roads". Table 13.2.2-1 "Typical Silt Content Values of Surface Material on Industrial Unpaved Roads". November 2006.
2. U.S. Department of Commerce. "Local Climatological Data - Annual Summary with Comparative Data". Des Moines Surface Station (KDSM) [WBAN: 14933], Des Moines, IA. NCDC, NESDIS, NOAA. 2006.
3. IDNR Air Quality Construction Permit Forms ID Number.
4. Watering (75%) based on EPA-450/3-88-008; 15 mph speed reduction (80%) based on Ohio EPA RACM 1980 document; partial enclosure (50%) is assumed.
5. Assumed bulldozer width of 11 ft 9.6 in (Caterpillar C9).
6. Assumed bulldozer height of 10 ft 11 in (Caterpillar C9).
7. Emissions due to bulldozing operations are included in the pile EP Number.
IPL
Sutherland Unit 4 PSD Application
Coal Storage Piles Summary
Emissions Summaries
Table A16 Pile Summary
EP
Storage Pile Description
Number [1]
274
Coal Storage Pile 2 - North
Pile
Height
ft
40.00
Release
Height
ft
20.00
Init. Vert.
Dimen.
ft
9.30
[2]
40.00
20.00
9.30
194.00
[2]
73.00
36.50
16.98
[2]
194.00
[2]
73.00
36.50
16.98
92.00
[2]
92.00
[2]
36.00
18.00
8.37
100.00
[2]
100.00
[2]
40.00
20.00
9.30
Emission Rate
lb/hr-ft2
g/s-m2
1.88E-07
2.55E-07
Equivalent
Length
Width
ft
ft
1095.00 [2] 188.00
4.80E-07
6.51E-07
1263.00
[2]
188.00
8.69E-07
1.18E-06
194.00
[2]
9.98E-07
1.35E-06
194.00
1.01E-05
1.37E-05
2.11E-07
2.86E-07
[2]
- Conveyor Drop
- Wind Erosion
275
Coal Storage Pile 2 - South
- Conveyor Drop
- Wind Erosion
276
Coal Storage Pile 3
- Conveyor Drop
- Wind Erosion
277
Coal Storage Pile 4
- Conveyor Drop
- Wind Erosion
282b
Limestone Storage Pile 1
- Conveyor Drop
- Wind Erosion
274
Small Active North Pile
- Wind Erosion
Notes [ ]:
1. IDNR Air Quality Construction Permit Forms ID Number.
2. From storage pile emission data table.
IPL
Sutherland Unit 4 PSD Application
Coal Pile Erosion - Active Storage
Wind Erosion Calculations
Emission Factor (EF) Equation [1]
1.7*(s/1.5)*(f/15)*((365-p)/235)
EF =
Where:
EF = particulate (TSP) emission factor, lb/ton
s = material silt content, %
f = percentage of time the unobstructed wind speed exceeds 12 mph
p = number of days per year with at least 0.01 in of precipitation
Calculated Emission Factors:
PM-10 [1] PM-2.5 [5]
TSP
EF (transfer)
6.8773 3.4386
0.5158 lb/day/acre of surface
EF (transfer)
12.1915 6.0958
0.9144 lb/day/acre of surface
2.2
3.9
38.4
111.8
% Coal
% Limestone
%
days
[2]
[2]
[3]
[4]
coal
limestone
Table A17 Active Coal Pile Wind Erosion Emissions:
Potential to Emit Calculations
EP
Number [6]
[8]
[8]
[8]
[8]
[8]
[8]
Activity
Limestone Storage Pile
Coal Storage Pile 2 -North Pile
Coal Storage Pile 2 -South Pile
Coal Storage Pile 3
Coal Storage Pile 4
Small North Pile
Exposed
Surface Area
acre
0.19
5.41
6.24
0.85
0.85
0.29
Total Uncontrolled Emissions (tons/yr)
Potential Uncontrolled Emissions
TSP
PM-10
PM-2.5
ton/yr
ton/yr
ton/yr
0.431
0.216
0.032
6.786
3.393
0.509
7.830
3.915
0.587
1.066
0.533
0.080
1.066
0.533
0.080
0.369
0.184
0.028
17.548
8.774
1.316
Control Method
Partial Enclosure
Water Cannon/Surfactant and Berm
Water Cannon/Surfactant and Berm
Water Cannon/Surfactant
Water Cannon/Surfactant
Water Cannon/Surfactant and Berm
Control
Efficiency [7]
%
50
95
95
90
90
95
Total Controlled Emissions (tons/yr)
Potential Controlled Emissions
TSP
PM-10
PM-2.5
ton/yr
ton/yr
ton/yr
0.216
0.108
0.016
0.339
0.170
0.025
0.391
0.196
0.029
0.107
0.053
0.008
0.107
0.053
0.008
0.018
0.009
0.001
1.178
0.589
Modeling Parameters
Emission Rates
Pile
Height
TSP
PM-10
PM-2.5
lb/hr
lb/hr
lb/hr
ft
0.049
0.025
0.004
36
0.077
0.039
0.006
40
0.089
0.045
0.007
40
0.024
0.012
0.002
73
0.024
0.012
0.002
73
0.004
0.002
0.000
73
0.088
Notes [ ]:
1. USEPA. "Fugitive Dust Background Document and Technical Information Document for Best Available Control Measures". EPA-450/2-92-004. September 1992.
2. USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 "Miscellaneous Sources", Section 13.2.4 "Aggregate Handling and Storage Piles". November 2006.
a. Table 13.2.4-1 "Typical Silt and Moisture Contents of Materials at Various Industries".
3. U.S. Department of Commerce. "International Station Meteorological Climate Summary Ver 4.0 CD-ROM". Des Moines Surface Station (KDSM) [WBAN: 14933], Des Moines, IA. National Climatic Data Center, NESDIS, NOAA. 1997.
4. U.S. Department of Commerce. "Local Climatological Data - Annual Summary with Comparative Data". Des Moines Surface Station (KDSM) [WBAN: 14933], Des Moines, IA. NCDC, NESDIS, NOAA. 2006.
5. Western Governors' Association Western Regional Air Partnership (WRAP). "Background Document for Revisions to Fine Fraction Ratios Used for AP-42 Fugitive Dust Emission Factors". Final. November 1, 2006. Prepared by Midwest Research Institute.
It was assumed that the PM2.5/PM10 ratio of 0.15 recommended for the transfer of aggregate associated with conveyor transfer points subject to an open atmosphere is applicable general material handling operations.
6. IDNR Air Quality Construction Permit Forms ID Number.
7. Water cannon/surfactant (90%) based on Ohio EPA RACM 1980 document (average of chemical stabilization). Assumed berm control of 50%.
8. Emissions due to wind erosion are included in the pile EP Number.
Release Init. Vert.
Height
Dimen.
ft
ft
18.0000 16.7442
20.0000 18.6047
20.0000 18.6047
36.5000 33.9535
36.5000 33.9535
36.5000 33.9535
IPL
Sutherland Unit 4 PSD Application
Coal Pile - Active Storage
Equivalent Dimensions Calculation
Coal Storage Pile 2- North
Basis:
Height =
Length =
Width =
40 ft
1095 ft
188 ft
Coal Storage Pile 4
Basis:
Height =
Diameter =
Radius =
73 ft
194 ft
97 ft
Calculations:
Calculations:
Footprint Area of the Full Pile
=L*W
2
Area = 205,860.00 ft
Footprint Area of the Full Circle
=π*r2
2
Area = 29,559.25 ft
Coal Storage Pile 2- South
Basis:
Height =
Length =
Width =
Limestone Storage Pile 1
Basis:
Height =
Diameter =
Radius =
40 ft
1263 ft
188 ft
36 ft
92 ft
46 ft
Calculations:
Calculations:
Footprint Area of the Full Pile
=L*W
2
Area = 237,444.00 ft
Footprint Area of the Full Circle
=π*r2
2
Area =
6,647.61 ft
Coal Storage Pile 3
Basis:
Height =
Diameter =
Radius =
Small Active North Pile
Basis:
Height =
Length =
Width =
73 ft
194 ft
97 ft
40 ft
100 ft
100 ft
Calculations:
Calculations:
Footprint Area of the Full Circle
=π*r2
2
Area =
29,559.25 ft
Footprint Area of the Full Pile
=L*W
2
Area = 10,000.00 ft
IPL
Sutherland Unit 4 PSD Application
Coal Pile - Active Storage
Surface Area Calculation
Coal Storage Pile 2 North
Basis:
Coal Storage Pile 4
Basis:
Height (H) =
Overall Length (l) =
Overall Width (w) =
Angle of Repose (φ) =
Radius (R) =
Length (L) =
Width (W) =
40
1095
188
38
51.20
992.60
85.60
ft
ft
ft
°
ft
ft
ft
Calculations:
Surface Area of the Pile
= π * R (r2 + h2)^0.5 + 2 * L (r2 + h2)^0.5 +
2 * W (r2 + h2)^0.5 + L * W
2
Surf. Area = 235,525.82 ft
Coal Storage Pile 2 South
Basis:
Height (H) =
Overall Length (l) =
Overall Width (w) =
Angle of Repose (φ) =
Radius (R) =
Length (L) =
Width (W) =
40
1263
188
38
51.20
1160.60
85.60
ft
ft
ft
°
ft
ft
ft
Calculations:
Surface Area of the Pile
= π * R (r2 + h2)^0.5 + 2 * L (r2 + h2)^0.5 +
2 * W (r2 + h2)^0.5 + L * W
2
Surf. Area = 271,737.58 ft
Coal Storage Pile 3
Basis:
Height (H) =
Base Radius (Rb) =
73 ft
97 ft
Calculations:
Surface Area of the Conical Pile
= π * r (r2 + h2)^0.5
2
Surf. Area = 36,994.82 ft
Height (H) =
Base Radius (Rb) =
73 ft
97 ft
Calculations:
Surface Area of the Conical Pile
= π * r (r2 + h2)^0.5
2
Surf. Area = 36,994.82 ft
Limestone Storage Pile
Basis:
Height (H) =
Base Radius (Rb) =
36 ft
46 ft
Calculations:
Surface Area of the Conical Pile
= π * r (r2 + h2)^0.5
2
Surf. Area =
8,441.36 ft
Small Active North Pile
Basis:
Height (H) =
Length (L) =
Width (W) =
Height of Side (h) =
40
100
100
64.03
ft
ft
ft
ft
Calculations:
Surface Area of the Pile
= 4 * (0.5 * b * h)
where b = base (L or W)
2
Surf. Area = 12,806.25 ft
GHG Emissions Estimation from IPL Sutherland Generating Station Unit 4 Project
Emission Unit
Main Boiler
Limestone Usage in Main Boiler Scrubber
Aux Boiler @ 2000 hrs/yr
Emergency Engine @ 52 hrs/yr
Fire Pump @ 52 hrs per year
Booster Fire Pump @ 52 hrs/yr
Gate Station Heater
MHDR
Emission Factor
Emissions (tpy)
CO2
Units
CH4
Units
N2O
Units
CO2
CH4
N2O
6326 mmBtu/hr Utility Coal
206.19 lb/mmBtu
0.0245 lb/mmBtu
0.0035 lb/mmBtu
5.71E+06
6.79E+02
9.70E+01
29.697 tons/hr
N/A
240 lb/ton
N/A
3.12E+04
N/A
268.6
138.9
29
9.5
3
Units
Fuel
mmBtu/hr
gal/hr
gal/hr
gal/hr
mmBtu/hr
NG
Diesel
Diesel
Diesel
NG
116.38
159.69
159.69
159.69
116.38
lb/mmBtu
lb/mmBtu
lb/mmBtu
lb/mmBtu
lb/mmBtu
0.013
0.00066
0.00066
0.00066
0.013
lb/mmBtu
lb/gal
lb/gal
lb/gal
lb/mmBtu
0.0002
0.00022
0.00022
0.00022
0.0002
lb/mmBtu
lb/gal
lb/gal
lb/gal
lb/mmBtu
3.13E+04
1.52E+02
3.17E+01
1.04E+01
1.53E+03
3.49E+00
4.58E-03
9.57E-04
3.14E-04
1.71E-01
5.37E-02
1.53E-03
3.19E-04
1.05E-04
2.63E-03
Total.(tpy)
5.78E+06
6.83E+02
9.704E+01
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Appendix H
Appendix H
BACT Analysis
102607-145491
H-1
BEST AVAILABLE CONTROL
TECHNOLOGY ANALYSIS
Prepared for
Interstate Power and Light
Sutherland Generating Station
Unit 4
October 2007
PROJECT NO. 145491
Black & Veatch Corporation
Overland Park, Kansas
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Table of Contents
Table of Contents
Acronym List ................................................................................................................AL-1
1.0
Introduction and Executive Summary ................................................................. 1-1
2.0
BACT Analysis Basis .......................................................................................... 2-1
2.1
Regulatory Basis ...................................................................................... 2-1
2.1.1
Applicable NSPS Emissions Limits .......................................... 2-2
2.2
Unit Operations and Baseline Emissions Basis ....................................... 2-5
2.2.1
Coal Fired Boiler ....................................................................... 2-7
2.2.2
Auxiliary Boiler....................................................................... 2-11
2.2.3
Emergency Generator.............................................................. 2-12
2.2.4
Emergency Fire Pumps............................................................ 2-13
2.2.5
Gate Station Gas Heater .......................................................... 2-14
3.0
Coal Fired Boiler SO2 BACT Analysis ............................................................... 3-1
3.1
Step 1--Identify All Control Technologies .............................................. 3-1
3.1.1
Coal Washing ............................................................................ 3-1
3.1.2
Wet Lime- and Limestone-Based FGD Processes .................... 3-2
3.1.3
Semi-Dry Lime-Based FGD Systems ....................................... 3-6
3.2
Step 2--Eliminate Technically Infeasible Options................................... 3-9
3.2.1
Coal Washing .......................................................................... 3-10
3.2.2
Wet Lime- and Limestone-Based FGD Processes .................. 3-10
3.2.3
Semi-Dry Lime-Based FGD Systems ..................................... 3-10
3.3
Step 3--Rank Remaining Control Technologies by Effectiveness ........ 3-13
3.4
Step 4--Evaluate Most Effective Controls and Document Results........ 3-18
3.4.1
Energy Evaluation of Alternatives .......................................... 3-18
3.4.2
Environmental Evaluation of Alternatives .............................. 3-18
3.4.3
Economic Evaluation of Alternatives...................................... 3-19
3.5
Step 5--Select SO2 BACT...................................................................... 3-20
4.0
Coal Fired Boiler NOx BACT Analysis............................................................... 4-1
4.1
Step 1--Identify All Control Technologies .............................................. 4-1
4.1.1
Selective Catalytic Reduction System....................................... 4-2
4.1.2
Selective Noncatalytic Reduction System................................. 4-3
4.2
Step 2--Eliminate Technically Infeasible Options................................... 4-4
4.3
Step 3--Rank Remaining Control Technologies by Effectiveness .......... 4-4
102607-145491
TC-1
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Table of Contents
Table of Contents (Continued)
4.4
4.5
Step 4--Evaluate Most Effective Controls and Document Results.......... 4-7
4.4.1
Energy Evaluation of Alternatives ............................................ 4-8
4.4.2
Environmental Evaluation of Alternatives ................................ 4-8
4.4.3
Economic Evaluation of Alternatives........................................ 4-9
Step 5--Select NOx BACT ....................................................................... 4-9
5.0
Coal Fired Boiler PM/PM10 BACT Analysis ...................................................... 5-1
5.1
Step 1--Identify All Control Technologies .............................................. 5-1
5.1.1
Coal Washing ............................................................................ 5-1
5.1.2
Dry Electrostatic Precipitator Systems ...................................... 5-1
5.1.3
Fabric Filter Systems ................................................................. 5-3
5.1.4
Wet Electrostatic Precipitator.................................................... 5-4
5.2
Step 2--Eliminate Technically Infeasible Options................................... 5-5
5.3
Step 3--Rank Remaining Control Technologies by Effectiveness .......... 5-6
5.4
Step 4--Evaluate Most Effective Controls and Document Results.......... 5-9
5.4.1
Energy Evaluation of Alternatives .......................................... 5-10
5.4.2
Environmental Evaluation of Alternatives .............................. 5-10
5.4.3
Economic Evaluation of Alternatives...................................... 5-10
5.5
Step 5--Select PM/PM10 BACT ............................................................. 5-11
6.0
Coal Fired Boiler CO and VOC BACT Analysis ................................................ 6-1
6.1
Step 1--Identify All Control Technologies .............................................. 6-1
6.1.1
Good Combustion Controls....................................................... 6-1
6.1.2
Oxidation Catalysts ................................................................... 6-2
6.2
Step 2--Eliminate Technically Infeasible Options................................... 6-2
6.3
Step 3--Rank Remaining Control Technologies by Effectiveness .......... 6-3
6.4
Step 4--Evaluate Most Effective Controls and Document Results.......... 6-8
6.4.1
Energy Evaluation of Alternatives ............................................ 6-9
6.4.2
Environmental Evaluation of Alternatives ................................ 6-9
6.4.3
Economic Evaluation of Alternatives........................................ 6-9
6.5
Step 5--Select CO and VOC BACT......................................................... 6-9
7.0
Coal Fired Boiler Sulfuric Acid Mist BACT Analysis........................................ 7-1
7.1
Step 1--Identify All Control Technologies .............................................. 7-1
7.1.1
Wet and Semi-Dry Lime-Based FGD Systems ......................... 7-1
102607-145491
TC-2
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Table of Contents
Table of Contents (Continued)
7.2
7.3
7.4
7.5
7.1.2
Wet Electrostatic Precipitator.................................................... 7-2
7.1.3
Sorbent Injection Systems ......................................................... 7-3
Step 2--Eliminate Technically Infeasible Options................................... 7-3
Step 3--Rank Remaining Control Technologies by Effectiveness .......... 7-4
Step 4--Evaluate Most Effective Controls and Document Results.......... 7-7
7.4.1
Energy Evaluation of Alternatives ............................................ 7-7
7.4.2
Environmental Evaluation of Alternatives ................................ 7-7
7.4.3
Economic Evaluation of Alternatives........................................ 7-7
Step 5--Select H2SO4 BACT.................................................................... 7-8
8.0
Coal Fired Boiler Fluorides BACT Analysis....................................................... 8-1
8.1
Step 1--Identify All Control Technologies .............................................. 8-1
8.2
Step 2--Eliminate Technically Infeasible Options................................... 8-1
8.3
Step 3--Rank Remaining Control Technologies by Effectiveness .......... 8-4
8.4
Step 4--Evaluate Most Effective Controls and Document Results.......... 8-6
8.4.1
Energy Evaluation of Alternatives ............................................ 8-7
8.4.2
Environmental Evaluation of Alternatives ................................ 8-7
8.4.3
Economic Evaluation of Alternatives........................................ 8-7
8.5
Step 5--Select Fluorides BACT ............................................................... 8-7
9.0
Auxiliary Boiler BACT Analysis......................................................................... 9-1
9.1
SO2 BACT Analysis ................................................................................ 9-1
9.1.1
Step 1--Identify All Control Technologies................................ 9-1
9.1.2
Step 2--Eliminate Technically Infeasible Options .................... 9-1
9.1.3
Step 3--Rank Remaining Control Technologies by
Effectiveness.............................................................................. 9-1
9.1.4
Step 4--Evaluate Most Effective Controls and Document
Results ....................................................................................... 9-2
9.1.5
Step 5--Select SO2 BACT ......................................................... 9-2
9.2
NOx BACT Analysis................................................................................ 9-2
9.2.1
Step 1--Identify All Control Technologies................................ 9-2
9.2.2
Step 2--Eliminate Technically Infeasible Options .................... 9-3
9.2.3
Step 3 -- Rank Remaining Control Technologies by
Effectiveness.............................................................................. 9-3
9.2.4
Step 4--Evaluate Most Effective Controls and Document
Results ....................................................................................... 9-3
9.2.5
Step 5--Select NOx BACT......................................................... 9-4
102607-145491
TC-3
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Table of Contents
Table of Contents (Continued)
9.3
9.4
9.5
PM/PM10 BACT Analysis........................................................................ 9-4
9.3.1
Step 1--Identify All Control Technologies................................ 9-4
9.3.2
Step 2--Eliminate Technically Infeasible Options .................... 9-4
9.3.3
Step 3--Rank Remaining Control Technologies by
Effectiveness.............................................................................. 9-5
9.3.4
Step 4--Evaluate Most Effective Controls and Document
Results ....................................................................................... 9-5
9.3.5
Step 5--Select PM/PM10 BACT................................................. 9-6
CO BACT Analysis ................................................................................. 9-6
9.4.1
Step 1--Identify All Control Technologies................................ 9-6
9.4.2
Step 2--Eliminate Technically Infeasible Options .................... 9-6
9.4.3
Step 3--Rank Remaining Control Technologies by
Effectiveness.............................................................................. 9-7
9.4.4
Step 4--Evaluate Most Effective Controls and Document
Results ....................................................................................... 9-7
9.4.5
Step 5--Select CO BACT ........................................................ 9-10
VOC BACT Analysis ............................................................................ 9-10
9.5.1
Step 1--Identify All Control Technologies.............................. 9-10
9.5.2
Step 2--Eliminate Technically Infeasible Options .................. 9-12
9.5.3
Step 3--Rank Remaining Control Technologies by
Effectiveness............................................................................ 9-12
9.5.4
Step 4--Evaluate Most Effective Controls and Document
Results ..................................................................................... 9-12
9.5.5
Step 5--Select VOC BACT ..................................................... 9-13
10.0
Emergency Generator and Fire Pumps BACT Analysis.................................... 10-1
10.1 Select SO2 BACT................................................................................... 10-1
10.2 Select NOx BACT .................................................................................. 10-1
10.3 Select PM/PM10 BACT.......................................................................... 10-2
10.4 Select CO BACT.................................................................................... 10-3
10.5 Select VOC BACT................................................................................. 10-3
10.6 Select H2SO4 BACT............................................................................... 10-4
11.0
Gate Station Heater BACT Analysis ................................................................. 11-1
11.1 Select SO2 BACT................................................................................... 11-1
11.2 Select NOx BACT .................................................................................. 11-1
11.3 Select PM/PM10 BACT.......................................................................... 11-2
102607-145491
TC-4
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
Table of Contents
Table of Contents (Continued)
11.4
11.5
11.6
Select CO BACT.................................................................................... 11-3
Select VOC BACT................................................................................. 11-3
Select H2SO4 BACT............................................................................... 11-4
12.0
Cooling Tower BACT Analysis......................................................................... 12-1
12.1 Step 1--Identify All Control Technologies ............................................ 12-1
12.2 Step 2--Eliminate Technically Infeasible Options................................. 12-1
12.3 Step 3--Rank Remaining Control Technologies by Effectiveness ........ 12-1
12.4 Step 4--Evaluate Most Effective Controls and Document Results........ 12-2
12.4.1 Energy Evaluation of Alternatives .......................................... 12-2
12.4.2 Environmental Evaluation of Alternatives .............................. 12-2
12.4.3 Economic Evaluation of Alternatives...................................... 12-2
12.5 Step 5--Select BACT ............................................................................. 12-2
13.0
Material Handling Systems BACT Analysis ..................................................... 13-1
13.1 Coal Handling ........................................................................................ 13-1
13.2 Limestone Handling............................................................................... 13-3
13.3 Fly Ash Handling................................................................................... 13-4
13.4 Saleable Fly Ash Handling System........................................................ 13-4
13.5 Waste Ash Handling .............................................................................. 13-6
13.6 FGD Solids Handling............................................................................. 13-7
13.7 Bottom Ash Handling ............................................................................ 13-7
13.8 Biomass Handling.................................................................................. 13-8
13.9 Other Material Handling ........................................................................ 13-8
13.10 Step 1--Identify All Control Technologies ............................................ 13-9
13.11 Step 2--Eliminate Technically Infeasible Options................................. 13-9
13.12 Step 3--Rank Remaining Control Technologies by Effectiveness ........ 13-9
13.13 Step 4--Evaluate Most Effective Controls and Document Results...... 13-10
13.13.1 Energy Evaluation of Alternatives ........................................ 13-10
13.13.2 Environmental Evaluation of Alternatives ............................ 13-10
13.13.3 Economic Evaluation of Alternatives.................................... 13-10
13.14 Step 5--Select BACT ........................................................................... 13-10
Attachment A
Attachment B
Coal Fired Boiler Top-Down RBLC Clearinghouse Review
Results.......................................................................................................1
Auxiliary Boiler Top-Down RBLC Clearinghouse Review
Results.......................................................................................................1
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Sutherland Unit 4 Air Permit Application
Table of Contents
Table of Contents (Continued)
Tables
Table 1-1
Table 2-1
Table 2-2
Table 2-3
Table 2-4
Table 2-5
Table 2-6
Table 2-7
Table 2-8
Table 2-9
Table 2-10
Table 2-11
Table 2-12
Table 2-13
Table 3-1
Table 3-2
Table 3-3
Table 3-4
Table 3-5
Table 4-1
Table 4-2
Table 4-3
Table 4-4
Table 5-1
Table 5-2
Table 5-3
Table 5-4
Table 5-5
Table 5-6
Table 5-7
Table 5-8
Table 6-1
Table 6-2
BACT Determination Summary ............................................................... 1-5
Main Boiler Design Basis ........................................................................ 2-7
Coal and Biomass Fuel Specifications..................................................... 2-8
Sulfur and Heating Value Fuel Variability for Worst-Case
Greater Belleville (Illinois Basin) Coal ................................................... 2-9
Main Boiler Baseline Uncontrolled Emissions PRB Coal....................... 2-9
Main Boiler Baseline Uncontrolled Emissions Illinois Basin Coal....... 2-10
Auxiliary Boiler Design Basis ............................................................... 2-11
Auxiliary Boiler Baseline Emissions ..................................................... 2-11
Emergency Generator Design Basis ...................................................... 2-12
Emergency Generator Baseline Emissions ............................................ 2-12
Emergency Fire Pumps Design Basis .................................................... 2-13
Emergency Fire Pumps Baseline Emissions.......................................... 2-13
Gate Station Gas Heater Design Basis................................................... 2-14
Gate Station Gas Heater Baseline Emissions......................................... 2-14
Summary of Step 2--Eliminate Technically Infeasible Options ............ 3-11
Subbituminous Fuels SO2 Top-Down RBLC Clearinghouse
Review Results....................................................................................... 3-14
Bituminous or Bituminous Blend of Fuels SO2 Top-Down RBLC
Clearinghouse Review Results .............................................................. 3-15
Ranking of SO2 Control Technologies .................................................. 3-18
Main Boiler SO2 BACT Determination................................................. 3-20
Summary of Step 2--Eliminate Technically Infeasible Options .............. 4-4
NOx Top-Down RBLC Clearinghouse Review Results .......................... 4-5
Ranking of NOx Control Technologies.................................................... 4-7
Main Boiler NOx BACT Determination .................................................. 4-9
Summary of Step 2--Eliminate Technically Infeasible Options .............. 5-6
PM/PM10 Top-Down RBLC Clearinghouse Review Results .................. 5-8
Ranking of PM/PM10 Control Technologies.......................................... 5-10
Fabric Filter Engineering Analysis - Cost Analysis .............................. 5-12
DESP Engineering Analysis - Cost Analysis......................................... 5-13
Particulate Matter Top-Down BACT Summary .................................... 5-14
Main Boiler PM/PM10 BACT Determination ........................................ 5-15
Main Boiler Visible Emission (Opacity) BACT Determination............ 5-16
Summary of Step 2--Eliminate Technically Infeasible Options .............. 6-3
CO Top-Down RBLC Clearinghouse Review Results............................ 6-4
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Sutherland Unit 4 Air Permit Application
Table of Contents
Table of Contents (Continued)
Tables (Continued)
Table 6-3
Table 6-4
Table 6-5
Table 7-1
Table 7-2
Table 7-3
Table 7-4
Table 7-5
Table 7-6
Table 7-7
Table 8-1
Table 8-2
Table 8-3
Table 8-4
Table 9-1
Table 9-2
Table 9-3
Table 13-1
VOC Top-Down RBLC Clearinghouse Review Results ......................... 6-7
Ranking of CO/VOC Control Technologies............................................ 6-9
Main Boiler CO/VOC BACT Determinations....................................... 6-10
Summary of Step 2--Eliminate Technically Infeasible Options .............. 7-4
H2SO4 Top-Down RBLC Clearinghouse Review Results....................... 7-5
Ranking of H2SO4 Control Technologies ................................................ 7-7
Wet ESP Equipment Engineering Analysis - Cost Analysis
(WESP) .................................................................................................... 7-9
SO3 Sorbent Injection Equipment Engineering Analysis - Cost
Analysis.................................................................................................. 7-10
Sulfuric Acid Mist Top-Down BACT Summary................................... 7-12
Main Boiler H2SO4 BACT Determination............................................. 7-12
Summary of Step 2--Eliminate Technically Infeasible Options .............. 8-3
Fluorides Top-Down RBLC Clearinghouse Review Results .................. 8-5
Ranking of HF Control Technologies...................................................... 8-6
Main Boiler HF BACT Determination .................................................... 8-8
Summary of Step 2--Eliminate Technically Infeasible Options .............. 9-7
Auxiliary Boiler Catalytic Oxidation System Equipment
Engineering Analysis - Cost Analysis ..................................................... 9-9
Carbon Monoxide/Volatile Organic Compounds Top-Down
BACT Summary .................................................................................... 9-11
Material Handling Particulate BACT Determinations......................... 13-11
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Acronym List
Acronym List
AGR
AQC
BACT
bhp
bhph
Btu
Ca(OH)2
CaSO3
Advanced Gas Reburn
Air Quality Control
Best Available Control Technology
Brake Horsepower
Brake Horsepower Hour
British Thermal Unit
Calcium Hydroxide
Calcium Hydroxide
CaSO3•1/2H2O
Calcium Sulfite Hemihydrate
CaSO4•2H2O
CAA
CAMR
CDS
CEMS
CFB
CFR
CO
COMS
DESP
FGD
FPL
g/bhph
H2S
H2SO4
h/yr
HAP
HF
Hg
HHV
IAC
ID
IGCC
IPL
Calcium Sulfate Dihydrate
Clean Air Act
Clean Air Mercury Rule
Circulating Dry Scrubber
Continuous Emissions Monitoring System
Circulating Fluidized Bed
Code of Federal Regulations
Carbon Monoxide
Continuous Opacity Monitoring System
Dry Electrostatic Precipitator
Flue Gas Desulfurization
Florida Power and Light Company
Grams per Brake Horsepower Hour
Hydrogen Sulfide
Sulfuric Acid Mist
Hours per Year
Hazardous Air Pollutant
Hydrofluoric Acid
Mercury
Higher Heating Value
Iowa Administrative Code
Induced Draft
Integrated Gasification Combined Cycle
Interstate Power and Light
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JBR
KCP&L
kW
kWh
LAER
Lb/h
L/G
LIFAC
LNB/OFA
MACT
MBtu
MW
NMHC
NO2
NOx
NSPS
NSR
OAQPS
OEM
Pb
PC
PM/PM10
PRB
PSD
RACT
RBLC
RICE
SCPC
SCR
SDA
SGS
SNCR
SO2
SO3
SSC
tpy
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Acronym List
Jet Bubbling Reactor
Kansas City Power & Light
Kilowatt
Kilowatt Hour
Lowest Achievable Emission Rate
Pound per Hour
Liquid-To-Gas
Limestone Injection into the Furnace and ReActivation of
Calcium
Low NOx Burner/Overfire Air
Maximum Achievable Control Technology
Million British Thermal Unit
Megawatt
Non-Methane Hydro Carbon
Nitrogen Dioxide
Nitrogen Oxides
New Source Performance Standard
New Source Review
Office of Air Quality Planning And Standards
Original Equipment Manufacturer
Lead
Pulverized Coal
Particulate Matter/Particulate Matter Less than 10 Microns
Powder River Basin
Prevention of Significant Deterioration
Reasonably Available Control Technology
RACT/BACT/LAER Clearinghouse
Reciprocating Internal Combustion Engine
Supercritical Pulverized Coal
Selective Catalytic Reduction
Spray Dryer Absorber
Sutherland Generating Station
Selective Noncatalytic Reduction
Sulfur Dioxide
Sulfur Trioxide
Submerged Scraper Conveyor
Tons per Year
AL-2
Interstate Power and Light
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TR
USEPA
VOC
WESP
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Acronym List
Transformer Rectifier
United States Environmental Protection Agency
Volatile Organic Compound
Wet Electrostatic Precipitator
AL-3
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
1.0
1.0 Introduction and
Executive Summary
Introduction and Executive Summary
Interstate Power and Light (IPL) proposes to construct a new electric generating
facility (hereinafter referred to as the “Project”) at its existing Sutherland Generating
Station (SGS) in Marshalltown, Iowa. The Project, SGS Unit 4, will consist of one
649 MW (megawatt) (net) supercritical pulverized coal (SCPC) fired boiler, an auxiliary
steam boiler, an emergency generator, two diesel driven emergency fire pumps, a cooling
tower, and material handling systems for the conveyance of coal, biomass, ash, and
reagent. The Project is classified as a New Source Review/Prevention of Significant
Deterioration (NSR/PSD) major modification to an existing major source, and as a result
of the calculated emissions increases, is subject to a Best Available Control Technology
(BACT) review for sulfur dioxide (SO2), nitrogen oxides (NOx), carbon monoxide (CO),
particulate matter (PM)/PM10, volatile organic compounds (VOC), sulfuric acid mist
(H2SO4), and fluoride, as previously discussed in Section 2.4 of the air permit application
document. The Project is not subject to review for lead (Pb), hydrogen sulfide (H2S), or
total reduced sulfur compounds.
As required under the NSR/PSD regulations, the BACT analysis presented herein
employed a “top-down,” five-step analysis process to determine the appropriate emission
control technologies and emissions limitations for the Project. The BACT analysis was
conducted for the main boiler, the auxiliary steam boiler, the emergency diesel fire
pumps, the cooling tower, and the material handling systems related to the conveyance
and storage of coal, biomass, ash, and reagent. The BACT analysis was conducted in
accordance with the United States Environmental Protection Agency’s (USEPA’s)
recommended methodology:
•
Step 1--Identify All Control Technologies.
•
Step 2--Eliminate Technically Infeasible Options.
•
Step 3--Rank Remaining Control Technologies by Control Effectiveness.
•
Step 4--Evaluate Most Effective Controls.
•
Step 5--Select BACT.
Step 1--Identify All Control Technologies
The first step in a “top-down” analysis is to identify all available control options
for the emission unit in question. Identifying all the potential available control options
consists of those air pollution control technologies or techniques with a practical potential
for application to the emission unit and the regulated pollutant under evaluation. The
potential available control technologies and techniques include lower emitting processes,
practices, and post-combustion controls. Lower emitting practices can include fuel
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1.0 Introduction and
Executive Summary
cleaning, treatment, or innovative fuel combustion techniques that are classified as precombustion controls. Post-combustion controls would be the various add-on controls for
the pollutant being controlled.
Step 2--Eliminate Technically Infeasible Options
The second step of the “top-down” analysis is to identify the technical feasibility
of the control options identified in Step 1, which are evaluated with respect to sourcespecific factors. A control option that is determined to be technically infeasible is
eliminated. “Technically infeasible” is defined as a clearly documented case of a control
option that has technical difficulties that would preclude the successful use of the control
option because of physical, chemical, and engineering principles. After completion of
this step, technically infeasible options are then eliminated from the BACT review
process.
In Step 2, the control option is identified as technically feasible. A “technically
feasible” control option is defined as a control technology that has been installed and
operated successfully at a similar type of source of comparable size under review
(demonstrated). If the control option cannot be demonstrated, the analysis gets more
involved. When determining if a control option has not been demonstrated, two key
concepts need to be analyzed. The first concept, availability, is defined as technology
that can be obtained through commercial channels or is otherwise available within the
common sense meaning of the term. A technology that is being offered commercially by
vendors or is in licensing and commercial demonstration is deemed an available
technology. Technologies that are in development (concept stage/research and patenting)
and testing stages (bench-scale/laboratory testing/pilot scale testing) are classified as not
available. The second concept, “applicability,” is defined as an available control option
that can reasonably be installed and operated on the source type under consideration. In
summary, the commercially available technology is applicable if it has been previously
installed and operated at a similar type of source of comparable size, or a source with
similar gas stream characteristics.
Step 3--Rank Remaining Control Technologies by Control Effectiveness
The third step of the “top-down” analysis is to rank all the remaining control
alternatives not eliminated in Step 2, based on control effectiveness for the pollutant
under review. If the BACT analysis proposes the top control alternative, there would be
no need to provide cost and other detailed information in regard to other control options
that would provide less control.
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1.0 Introduction and
Executive Summary
Step 4--Evaluate Most Effective Controls
Once the control effectiveness is established in Step 3 for all the feasible control
technologies identified in Step 2, additional evaluations of each technology are performed
to make a BACT determination in Step 4. The impacts of the technology implementation
on the viability of the control technology at the source are evaluated. The evaluation
process of these impacts is also known as “Impact Analysis.” The following impact
analyses are performed:
•
Energy evaluation of alternatives.
•
Environmental evaluation of alternatives.
•
Economic evaluation of alternatives.
The first impact analysis addresses the energy evaluation of alternatives. The
energy impact of each evaluated control technology is the energy penalty or benefit
resulting from the operation of the control technology at the source. Direct energy
impacts include such items as the auxiliary power consumption of the control technology
and the additional draft system power consumption to overcome the additional system
resistance of the control technology in the flue gas flow path. The costs of these energy
impacts are defined either in additional fuel costs or the cost of lost generation, which
impacts the cost-effectiveness of the control technology.
The second impact analysis addresses the environmental evaluation of
alternatives. Non-air quality environmental impacts are evaluated to determine the cost
to mitigate the environmental impacts caused by the operation of a control technology.
Examples of non-air quality environmental impacts include polluted water discharge and
solids or waste generation. The procedure for conducting this analysis should be based
on a consideration of site-specific circumstances.
The third and final impact analysis addresses the economic evaluation of
alternatives. This analysis is performed to indicate the cost to purchase and operate the
control technology. The capital and operating/annual cost is estimated based on the
established design parameters. Information for the design parameters should be obtained
from established sources that can be referenced. However, documented assumptions can
be made in the absence of references for the design parameters. The estimated cost of
control is represented as an annualized cost ($/year) and, with the estimated quantity of
pollutant removed (tons/year), the cost-effectiveness ($/tons) of the control technology is
determined. The cost-effectiveness describes the potential to achieve the required
emissions reduction in the most economical way. The cost-effectiveness compares the
potential technologies on an economical basis. Two types of cost-effectiveness are
considered in a BACT analysis: average and incremental cost-effectiveness. Average
cost-effectiveness is defined as the total annualized cost of control divided by the annual
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1.0 Introduction and
Executive Summary
quantity of pollutant removed for each control technology. The incremental costeffectiveness is a comparison of the cost and performance level of a control technology to
the next most stringent option. It has a unit of (dollars/incremental ton removed). The
incremental cost-effectiveness is a good measure of viability when comparing
technologies that have similar removal efficiencies.
Step 5--Select BACT
The highest ranked control technology that is not eliminated in Step 4 is proposed
as BACT for the pollutant and emission unit under review.
As summarized in Table 1-1, the aforementioned BACT analysis process resulted
in the following control technology and emissions level determinations for the Project’s
affected air emissions sources and pollutants. The ton per year emissions presented in
Appendix G are proposed as BACT emission caps.
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1.0 Introduction and
Executive Summary
Table 1-1
BACT Determination Summary
Emission Unit: 649 MW (net) SCPC Boiler (Steam Capacity Rating 4,389,000 lb/h)
Pollutant
Control Technology
Emission Basis
Avg. Period
Testing Method
SO2
Wet FGD
0.06 lb/MBtu or 98 percent
removal (whichever occurs
first) with 0.08 lb/MBtu
upper limit.
30 day
CEMS
NOx
LNB/OFA and SCR
0.05 lb/MBtu
30 day
CEMS
PM/PM10
Fabric Filter
0.012 lb/MBtu (filterable)
3 hour test
runs (average)
USEPA Method 5B
0.018 lb/MBtu (total)
3 hour test
runs (average)
USEPA Method 5B +
202 with condensable
artifact modification
Visible
Emissions
(Opacity)
Fabric Filter
10%
6-minute
average
COMS
CO
Good Combustion
Controls
0.12 lb/MBtu
8 hour
CEMS
VOC
Good Combustion
Controls
0.0034 lb/MBtu
3 hour test
runs (average)
USEPA Method 18
H2SO4
Sorbent
Injection/Fabric Filter
0.004 lb/MBtu
3 hour test
runs (average)
Controlled
Condensate Test
Method
Fluorides
Wet FGD
0.0002 lb/MBtu
3 hour test
runs (average)
USEPA Method 13B
or USEPA Method
26A
Emission Unit: Auxiliary Steam Boiler (270 MBtu/h)
Pollutant
Control Technology
Emission Basis
Avg. Period
Testing Method
SO2
Natural Gas Firing
0.0006 lb/MBtu
NA
Fuel Recordkeeping
NOx
Good Combustion
Controls
0.037 lb/MBtu
3 hour test
runs (average)
USEPA Method 7E
PM/PM10
Natural Gas Firing
0.007 lb/MBtu
NA
Fuel Recordkeeping
CO
Good Combustion
Controls
0.074 lb/MBtu
NA
Fuel Recordkeeping
VOC
Good Combustion
Controls
0.005 lb/MBtu
NA
Fuel Recordkeeping
H2SO4
Natural Gas Firing
0.0009 lb/MBtu
NA
Fuel Recordkeeping
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1.0 Introduction and
Executive Summary
Table 1-1 (Continued)
BACT Determination Summary
Emission Unit: Emergency Generator (2,000 kW)
Pollutant
Control Technology
Emission Basis
SO2
Low Sulfur Distillate Fuel Oil
< 0.05% Sulfur Fuel Oil
NOx
Good Combustion Controls
6.47 g/bhph
PM/PM10
Low Sulfur Distillate Fuel Oil
0.08 g/bhph
CO
Good Combustion Controls
0.53 g/bhph
VOC
Good Combustion Controls
0.27 g/bhph
H2SO4
Low Sulfur Distillate Fuel Oil
< 0.05 % Sulfur Fuel Oil
Emission Unit: Emergency Fire Pump (575 bhp)
Pollutant
Control Technology
Emission Basis
SO2
Low Sulfur Distillate Fuel Oil
< 0.05% Sulfur Fuel Oil
NOx
Good Combustion Controls
4.9 g/bhph
PM/PM10
Low Sulfur Distillate Fuel Oil
0.08 g/bhph
CO
Good Combustion Controls
0.75 g/bhph
VOC
Good Combustion Controls
0.29 g/bhph
H2SO4
Low Sulfur Distillate Fuel Oil
< 0.05% Sulfur Fuel Oil
Emission Unit: Emergency Fire Booster Pump (149 bhp)
Pollutant
Control Technology
Emission Basis
SO2
Low Sulfur Distillate Fuel Oil
< 0.05% Sulfur Fuel Oil
NOx
Good Combustion Controls
5.20 g/bhph
PM/PM10
Low Sulfur Distillate Fuel Oil
0.19 g/bhph
CO
Good Combustion Controls
0.33 g/bhph
VOC
Good Combustion Controls
0.36 g/bhph
H2SO4
Low Sulfur Distillate Fuel Oil
< 0.05% Sulfur Fuel Oil
Emission Unit: Cooling Tower
Pollutant
Control Technology
Emission Basis
PM/PM10
Drift Eliminators
0.0005% drift rate
Gate Station Gas Heater (3 MBtu/hr)
Pollutant
Control Technology
Emission Basis
SO2
Natural Gas Firing
0.0006 lb/MBtu
NOx
Good Combustion Controls
0.046 lb/MBtu
PM/PM10
Natural Gas Firing
0.0074 lb/MBtu
CO
Good Combustion Controls
0.046 lb/MBtu
VOC
Good Combustion Controls
0.0054 lb/MBtu
H2SO4
Natural Gas Firing
0.0009 lb/MBtu
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1.0 Introduction and
Executive Summary
Table 1-1 (Continued)
BACT Determination Summary
Emission Unit: Material Handling Systems for the Conveyance of Coal, Biomass, Ash, and Reagent
Pollutant
Emission Source
Control Technology
PM/PM10
Coal Handling
Refer to Table 13-1
Limestone Handling
Refer to Table 13-1
Fly Ash Handling
Refer to Table 13-1
FGD Waste Handling
Refer to Table 13-1
Bottom Ash Handling
Refer to Table 13-1
Biomass Handling
Refer to Table 13-1
Other Material Handling
Refer to Table 13-1
CEMS = Continuous Emissions Monitoring System.
FGD = Flue Gas Desulfurization.
g/bhph = Grams per Brake Horsepower Hour.
LNB/OFA = Low NOx Burner/Overfire Air.
MBtu = Million British Thermal Unit.
SCR = Selective Catalytic Reduction.
30 day = 30 day rolling average
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2.0
2.0 BACT Analysis Basis
BACT Analysis Basis
This section describes the basis of the BACT analysis, including the regulatory
background, methodology and approach, and emission unit description and assumptions.
2.1
Regulatory Basis
The Clean Air Act Amendments of 1990 (CAA) established revised conditions
for the approval of pre-construction permit applications under the PSD program. One of
these requirements is that BACT be installed to control all pollutants regulated under the
Act that are emitted in significant amounts from new major sources or major
modifications.
The applicable state regulations governing this process can be found in Iowa
Administrative Code (IAC) [567] Chapter 22, which adopts by reference the federal
definition of BACT in 40 CFR 52.21 as “An Emissions limitation (including a visible
emission standard) based on the maximum degree of reduction for each pollutant subject
to regulation under the Act which would be emitted from any proposed major stationary
source or major modification which the Administrator, on a case-by-case basis, taking
into account energy, environmental, and economic impacts and other costs, determines is
achievable for such source or modification through application of production processes
or available methods, systems, and techniques, including fuel cleaning or treatment or
innovative fuel combustion techniques for control of such pollutant. In no event shall the
application of best available control technology result in emissions of any pollutant
which would exceed the emissions allowed by any applicable standard under 40 CFR
Parts 60 and 61. If the Administrator determines that technological or economic
limitations on the application of measurement methodology to a particular emissions unit
would make the imposition of an emissions standard infeasible, a design, equipment,
work practice, operational standard, or combination thereof, may be prescribed instead
to satisfy the requirement for the application of best available control technology. Such
standard shall, to the degree possible, set forth the emissions reduction achievable by
implementation of such design, equipment, work practice or operation, and shall provide
for compliance by means which achieve equivalent results.
To bring consistency to the BACT process, the USEPA provides as guidance to
the states the use of a “top-down” approach to BACT determinations, which utilizes the
five-step analysis process previously summarized. In practice, the top-down BACT
analysis determines the most stringent control technology and emissions limitation
combination available for a similar source or source category of emission units. At the
head of the list in the top-down analysis methodology are the control technologies and
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Sutherland Unit 4 Air Permit Application
2.0 BACT Analysis Basis
emissions limits that represent the Lowest Achievable Emission Rate (LAER)
determinations, which, under NSR/PSD regulations, represent the most effective control
alternative that must be considered under the BACT analysis process.
The following informational databases, clearinghouses, and documents were used
to identify recent control technology determinations for similar source categories and
emission units for this BACT analysis:
•
USEPA’s RACT/BACT/LAER Clearinghouse (RBLC).
•
USEPA’s National Coal Fired Utility Projects Spreadsheet (July 2007).
•
Federal/State/Local new source review permits, permit applications, and
associated inspection/test reports.
•
Technical journals, newsletters, and reports.
•
Information from air quality control (AQC) technology suppliers.
•
Engineering design on other projects.
If it cannot be shown that the top level of control is infeasible (for a similar type
source and fuel category) on the basis of technical, economic, energy, or environmental
impact considerations, then that level of control must be declared to represent BACT for
the respective pollutant and air emissions source.
Alternatively, upon proper
documentation that the top level of control is not feasible for a specific unit and pollutant
based on a site- and project-specific consideration of the aforementioned screening
criteria (e.g., technical, economic, energy, and environmental considerations), then the
next most stringent level of control is identified and similarly evaluated. This process
continues until the BACT level under consideration cannot be eliminated by any
technical, economic, energy, or environmental consideration. BACT cannot be
determined to be less stringent than the emissions limits established by an applicable
New Source Performance Standard (NSPS) for the affected air emissions source.
2.1.1
Applicable NSPS Emissions Limits
As previously discussed, a proposed BACT emissions limit, established in
accordance with the top-down, five-step process, cannot be determined to be less
stringent than the emissions limit(s) established by the applicable NSPS regulations
found in 40 CFR Part 60. The following NSPS emissions limitations are applicable to the
Project’s air emissions sources.
2.1.1.1 NSPS Subpart Da – Standards of Performance for Electric Utility
Steam Generating Units for Which Construction is Commenced After
September 18, 1978. As an electric utility steam generating unit greater than
250 MBtu/h heat input, the Project’s main boiler will be subject to NSPS Subpart Da.
NSPS
Subpart
Da
includes
new
source
emissions
limitations
for
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2.0 BACT Analysis Basis
certain NSR/PSD pollutants, including SO2, NOx, and PM/PM10. Applicable NSPS
Subpart Da emissions limitations for the coal fired boiler are as follows:
•
SO2: 1.4 lb/MWh (gross energy output) or 95 percent removal rate.
•
NOx: 1.0 lb/MWh (gross energy output).
•
PM/PM10: 0.14 lb/MWh (gross energy output) or 0.015 lb/MBtu.
•
Opacity: Less than or equal to 20 percent opacity (6 minute average)
except for one 6 minute period per hour of not more than 27 percent
opacity.
2.1.1.2 NSPS Subpart Db – Standards of Performance for IndustrialCommercial-Institutional Steam Generating Units. As a steam generating unit
greater than 100 MBtu/h, the Project’s 270 MBtu/h auxiliary boiler will be subject to
NSPS Subpart Db. NSPS Subpart Db includes new source emissions limitations for
certain NSR/PSD pollutants including NOx. Applicable NSPS Subpart Db emissions
limitations for the natural gas fired auxiliary boiler are as follows:
•
NOx: 0.10 lb/MBtu.
2.1.1.3 Reciprocating Internal Combustion Engine MACT. The reciprocating
internal combustion engine (RICE) Maximum Achievable Control Technology (MACT)
can be found at 40 CFR 63 Subpart ZZZZ, National Emission Standards for Hazardous
Air Pollutants for Stationary Reciprocating Internal Combustion Engines. Currently, the
RICE MACT is applicable to stationary RICE at a major hazardous air pollutant (HAP)
source. However, the RICE MACT does not apply to stationary RICE with a site rating
of 500 brake horsepower (bhp) or less. Because the emergency fire booster pump is an
approximately 149 bhp engine, it is not subject to the RICE MACT. The emergency fire
pump and emergency generator engines will be greater than 500 bhp (575 and 2,919 bhp,
respectively). However, new emergency stationary RICE units located at a major source
of HAPs are subject only to the initial notification requirements of 40 CFR 63.6645(d).
It is important to note that on June 12, 2006, the USEPA proposed revisions to the
RICE MACT that would expand the applicability of the RICE MACT to stationary RICE
of less than 500 bhp at a major HAP source and would include stationary RICE at area
sources of HAPs. An area source of HAP emissions is a source that is not a major source
of HAPs. If the June 12, 2006, proposed RICE MACT changes are finalized, the
Project’s emergency fire booster pump will be an affected unit under the RICE MACT,
regardless of whether the Project is a major source of HAPs. However, under the
proposed changes to the RICE MACT, as with the existing RICE MACT, a new
“emergency” stationary RICE is subject only to the initial notification requirements of the
RICE MACT. Because the emergency generator, emergency fire pump, and emergency
fire booster pump engines are all considered emergency stationary RICE units, if the
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proposed RICE MACT changes are finalized, these engines will be subject only to the
initial notification requirements.
2.1.1.4 NSPS Subpart IIII – Standards of Performance for Stationary
Compression Ignition Internal Combustion Engines. The Project’s emergency
generator, emergency fire pump, and emergency fire booster pump engines will be
subject to the manufacturer’s certification requirements of compliance to NSPS
Subpart IIII. The rule provides various emissions standards based on the engine’s use,
manufacture date, and engine size. The applicable standards associated with the
equipment will be dependent on the engine model year.
Beginning with engines manufactured in model year 2007, the onus of this rule
falls on the engine manufacturers, since they are required to manufacture engines that
comply with the rule. The requirement of this rule for owners and operators of these
engines is that they purchase certified engines.
2.1.1.5 NSPS Subpart Y – Standards of Performance for Coal Preparation
Plants. The Project’s coal conveying, storage, transfer, loading, and processing
operations will be subject to NSPS Subpart Y. NSPS Subpart Y includes new source
limitations for PM/PM10. The applicable NSPS Subpart Y emissions limitation for the
coal handling facility is as follows:
•
PM/PM10: 20 percent opacity.
2.1.1.6 NSPS Subpart OOO – Standards of Performance for Nonmetallic
Mineral Processing Plants. The Project’s proposed wet FGD system uses a limebased slurry to control the emissions of SO2. The slurry is created from bulk limestone,
which is delivered to the site via bottom dump hopper railcars or alternatively by delivery
truck. A limestone slurry system will grind the limestone and mix it with water to be
used as a reagent for the wet FGD SO2 emissions control system. Limestone is classified
as a nonmetallic mineral requiring further processing at the facility, the types of which
are covered by NSPS Subpart OOO. Therefore, the Project’s limestone handling,
storage, transfer, and grinding operations will be subject to NSPS Subpart OOO. NSPS
Subpart OOO includes new source limitations for PM/PM10. The applicable NSPS
Subpart OOO emissions limitation is as follows:
•
PM/PM10: 7 percent opacity.
2.1.1.7 NSPS Subpart HHHH – Emission Guidelines and Compliance Times
for Coal Fired Electric Steam Generating Units. This subpart establishes the
model rule comprising general provisions and the designated representative, permitting,
allowance, and monitoring provisions for the state mercury (Hg) Budget Trading
Program, under Section 111 of the CAA known as the Clean Air Mercury Rule (CAMR),
as a means of reducing national Hg emissions. Iowa has amended its air quality
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regulations to adopt the federal CAMR rules, including the Hg trading and monitoring
provisions. The SGS Unit 4 SCPC fired boiler will comply with the provisions of the
CAMR cap-and-trade program by holding sufficient Hg allowances in an amount no less
than its annual emissions of Hg.
2.2
Unit Operations and Baseline Emissions Basis
Prior to initiating this air permitting process, IPL commissioned a technology
assessment study to evaluate and compare alternative power generation processes for its
portfolio planning. The generation alternatives considered by IPL include the following:
•
SCPC.
•
Circulating Fluidized Bed (CFB).
•
Integrated Gasification Combined Cycle (IGCC).
Based on an analysis of the possible power generation alternatives (the results of
which are documented in a report entitled Site Evaluation Study – Coal Technology
Assessment (included as Appendix J of the air permit application package), IPL
concluded that the appropriate project design alternative, commensurate with the
forecasted load demand and fuel costs, would be a 649 MW (net) SCPC fired unit at the
existing SGS.
It is USEPA’s long-standing policy that the BACT analysis process does not
require a redefinition or redesign of a project. See letter from S. Page, USEPA, to
P. Plath (December 13, 2005). Therefore, based on USEPA’s policy, the BACT analysis
will focus on pollution control technologies applicable to pulverized coal boiler
technologies.
IPL proposes applicable work practice standards, such as good air pollution
control practices and proper operation and maintenance, and ton per year emission caps
as BACT during startup, shutdown, and malfunctions. While SGS Unit 4 is proposed as
a baseload unit and being permitted for unlimited annual operation, the unit will
infrequently be required to shut down and start up depending on load requirements and
system maintenance. The boiler will be designed to initially start up on clean emitting
natural gas until the load on the boiler reaches approximately 10 percent, after which coal
will be introduced into the boiler in combination with the startup fuel for stabilization,
until the boiler reaches approximately 25 percent of load.
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Startup of the boiler from cold conditions to full load is estimated to take between
8 and 12 hours. If the auxiliary boiler is used to maintain heat in the boiler, startup time
is reduced. Natural gas fuel is used in the boiler ignitors to slowly increase boiler metal
temperatures. Once boiler load has increased beyond the minimum capacity of one coal
mill (approximately 4 to 6 hours into startup), a coal mill is started and the boiler is
operated on both natural gas fuel and coal. Once stable operation on coal has been
established on two mills (approximately 25 percent load, 8 to 10 hours into startup), the
natural gas fuel is discontinued and boiler load is increased as necessary using primarily
coal fuel. As additional coal mills are started, natural gas fuel is briefly (less than an
hour) used in the appropriate individual boiler ignitors to ensure safe startup of the mill.
The AQC equipment has differing startup requirements before it becomes fully
effective. A fabric filter that controls PM/PM10 becomes effective instantaneous with the
startup of the boiler. A wet FGD that controls SO2 becomes effective instantaneous with
the startup of the boiler. An SCR that controls NOx does not become fully effective until
the flue gas temperature after the economizer of the boiler reaches approximately 550º F
to 600º F which is critical with the injection of ammonia. The SCR has an operating
temperature range of approximately 600º F to 800º F in effectively controlling NOx. The
temperature range needs to be closely adhered to in avoidance of damaging the catalyst or
possible fouling of the air heater. The estimated time of the SCR to become fully
effective is between 25 to 50 percent load (approximately 8 to 11 hours). As for CO and
VOC control, good combustion controls are used. Good combustion controls begin to
become effective at approximately 60 percent load when the boiler is tuned and it is
achieving its steam temperature. The estimated time of good combustion controls is
approximately 11 to 12 hours into startup.
As a practical and regulatory matter, a BACT determination, in addition to having
to be technically feasible as previously described, must be enforceable. For the purposes
of a BACT determination for periods of startup, shutdown, and malfunction, an important
consideration to be made is whether an emission limit is practicably enforceable as a
BACT determination. Consideration of this issue relies heavily and primarily on whether
emission measurements made during these transient events can be used to determine
compliance with a specified emission limit.
For coal fired boilers, emission tests cannot be conducted with any suitable degree
of reliability during startup, shutdown, and malfunction in order to serve as a reliable
method of demonstrating compliance with an expressed BACT emission limit. This is
similar and consistent with the regulatory provisions of the NSPS, where the operations
during periods of startup, shutdown, and malfunction are not considered representative
conditions for the purpose of conducting compliance performance tests. In other words,
the use of an emission limit to establish BACT compliance during startup, shutdown, and
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malfunction is not considered practicably enforceable. However, the regulatory
definition of BACT envisioned these types of circumstances and provided for the use of
applicable work practice standards such as good air pollution control practices and proper
operation and maintenance as a basis for measurable and practicably enforceable
compliance elements in lieu of emission standards.
The Project is proposed as a baseloaded electric generating facility and, for the
purposes of this application, is designed to operate unrestricted for 8,760 hours per year.
Ancillary air emissions sources, such as the auxiliary boiler, emergency generator, and
emergency fire pumps, will operate infrequently and typically only when the coal fired
boiler is not, or under emergency conditions. The following subsections characterize the
unit size, fuel, operating scenario, and emissions assumptions that were collectively
utilized as a basis for the BACT analysis. A more detailed Project description is provided
in Section 2.2 of the Main Application.
2.2.1
Coal Fired Boiler
Table 2-1 presents the BACT design basis for the Project’s coal fired boiler.
Table 2-1
Main Boiler Design Basis(1)
Size
Maximum Heat Input
Operating Hours
Fuel
Startup Fuel
649 MW (net)
6,326 MBtu/h(2)
8,760 h/yr
Powder River Basin (PRB) or Illinois Basin
Coals with Biomass
Natural Gas
(1)
100 percent load, average annual site conditions.
Based upon firing PRB coal.
(2)
The Project will burn low sulfur PRB and Illinois Basin coals in SGS Unit 4’s
boiler. The Project will have the capability of burning the PRB and Illinois Basin coal
separately or as a blend of the two coals. Additionally, the Project will be capable of
burning a blend of biomass (5 percent based on fuel heat input) with either PRB or
Illinois Basin coal fuel or with a blend of the PRB/Illinois Basin coal. Table 2-2 presents
the typical coal quality fuel specifications for the Rawhide Mine (PRB) coal, Greater
Belleville (Illinois Basin) coal, and biomass fuel, which are considered representative of
the fuels proposed for this Project, hereinafter, referred to as the Project’s coal fuel
alternatives.
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Table 2-2
Coal and Biomass Fuel Specifications
Greater
Belleville
Illinois Basin
Biomass
10,800
6,384
As Received
As Received
As Received
Description
Value
Rawhide Mine
PRB
Higher Heating Value
(HHV)
Btu/lbm
8,300
Ultimate Analysis
Basis
Carbon
%
48.58
60.06
41.15
Hydrogen
%
3.34
4.20
4.30
Nitrogen
%
0.62
1.12
0.48
Sulfur
%
0.33
3.11
0.10
Chlorine
%
0.00
0.10
0.12
Ash
%
4.93
9.52
4.85
Moisture
%
30.50
14.20
15.00
Oxygen (by difference)
%
11.70
7.69
34.14
For the purposes of the SO2 BACT analysis and the SO2 control technology and
emissions level determination, the Greater Belleville (Illinois Basin) coal fuel and its
range of heating value and sulfur content are considered representative of the worst-case
fuels proposed for this Project. Table 2-3 presents minimum, typical, and maximum
sulfur content and heating values of the worst-case Greater Belleville (Illinois Basin)
coal, along with the corresponding uncontrolled SO2 emissions rates.
Using the design basis presented in Table 2-1 and the fuel specifications presented
in Tables 2-2 and 2-3, the uncontrolled baseline emissions from the Project’s coal fired
boiler are presented in Tables 2-4 and 2-5 for PRB and Illinois Basin coal, respectively.
The uncontrolled emissions for the Project’s representative coal alternatives were
analyzed to determine the worst-case scenario for each pollutant. The worst-case
scenario for each pollutant is the basis for the BACT analysis.
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Table 2-3
Sulfur and Heating Value Fuel Variability for Worst-Case
Greater Belleville (Illinois Basin) Coal
Fuel Variability
Sulfur Content
(percent by
weight)
Higher Heating
Value
(Btu/lb)
Uncontrolled SO2
Emissions Rate
(lb/MBtu)
Minimum
2.50
10,400
4.81
Typical
3.11
10,800
5.76
Maximum
4.00
11,100
7.21
Table 2-4
Main Boiler Baseline Uncontrolled Emissions
PRB Coal
Pollutant
Mass Rate
(lb/h)
Emissions Level
(lb/MBtu)
SO2
5,025
0.794
NOx
1,275
0.20
PM/PM10 (filterable)
30,439
4.81
CO
759
0.12
VOC
21.51
0.0034
H2SO4
153.8
0.0243
Fluorides
26.6
0.0042
Total emissions are based on typical, baseload fuel coal specifications
for each pollutant at 6,326 MBtu/h. Items underlined represent the basis
of the BACT analysis.
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Table 2-5
Main Boiler Baseline Uncontrolled Emissions
Illinois Basin Coal
Pollutant
Mass Rate
(lb/h)
Emissions Level
(lb/MBtu)
SO2
35,493
5.75
NOx
1,234
0.20
PM/PM10 (filterable)
43,874
7.11
CO
740
0.12
VOC
20.97
0.0034
H2SO4
1,086
0.176
Fluorides
56.75
0.0092
Total emissions are based on typical, baseload fuel coal specifications for
each pollutant at 6,169 MBtu/h. Items underlined represent the basis of
the BACT analysis.
It should be noted that the unit is planning for an “as-needed” operating fly ashsegregating dry electrostatic precipitator (DESP) just downstream of the air heater and
any proposed back-end BACT equipment (except for the SCR). Compared to a full-scale
DESP designed for primary particulate control, the proposed scavenging DESP is a much
undersized version, designed only to operate as process equipment to segregate fly ash
for beneficial reuse. The installation of the as-needed DESP does not fall under any
BACT requirement, since it will not be used for primary control or emissions
compliance. Since the unit will not always operate the DESP, the particulate BACT
analysis is based on the primary particulate control device discussed in Section 5.0 of this
analysis.
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2.2.2
2.0 BACT Analysis Basis
Auxiliary Boiler
Table 2-6 presents the BACT design basis for the Project’s auxiliary boiler.
Table 2-6
Auxiliary Boiler Design Basis*
Size
Maximum Heat Input
Operating Hours
Fuel
200,000 lb-steam/h
270 MBtu/h
2,000 h/yr
Natural gas
*100 percent full load, average annual site conditions.
Based on the design basis presented in Table 2-6, the baseline emissions from the
Project’s auxiliary boiler are presented in Table 2-7.
Table 2-7
Auxiliary Boiler Baseline Emissions*
Pollutant
Mass Rate
(lb/h)
Emissions Level
(lb/MBtu)
SO2
NOx
PM/PM10 (filterable)
CO
VOC
H2SO4
0.16
9.94
1.88
19.88
1.34
0.2
0.0006
0.037
0.007
0.074
0.005
0.0009
*Emissions based on manufacturer’s performance data and maximum
fuel heat input.
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2.2.3
2.0 BACT Analysis Basis
Emergency Generator
Table 2-8 presents the BACT design basis for the Project’s emergency generator.
Table 2-8
Emergency Generator Design Basis
Size
2,000 kW
Maximum Horsepower
2,919 bhp
Operating Hours
100 h/yr*
Fuel
Low sulfur distillate fuel oil
(<0.05% sulfur)
*Operated 1 to 2 hours weekly for testing and maintenance.
Based on the design basis presented in Table 2-8, the baseline emissions from the
Project’s emergency generator are presented in Table 2-9.
Table 2-9
Emergency Generator Baseline Emissions*
Pollutant
Mass Rate
(lb/h)
Emission Level
(g/bhph)
SO2
0.49
0.15
NOx
20.94
6.47
PM/PM10 (filterable)
0.13
0.08
CO
1.72
0.53
VOC
0.87
0.27
H2SO4
0.74
0.23
*Emissions based on manufacturer’s performance data. VOC emissions
based on a USEPA AP-42 air emissions factor.
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2.2.4
Emergency Fire Pumps
Table 2-10 presents the BACT design basis for the Project’s emergency fire pump
and emergency fire booster pump engines.
Table 2-10
Emergency Fire Pumps Design Basis
Unit
Fire Pump
Fire Booster Pump
Maximum Horsepower
575 bhp
149 bhp
Operating Hours
100 h/yr*
100 h/yr*
Fuel
Low sulfur distillate fuel
oil (<0.05% sulfur)
Low sulfur distillate fuel oil
(<0.05% sulfur)
*Operated 1 to 2 hours weekly for testing and maintenance.
Based on the design basis presented in Table 2-10, the baseline emissions from
the Project’s emergency fire pumps are presented in Table 2-11.
Table 2-11
Emergency Fire Pumps Baseline Emissions(1)
Unit
Fire Pump
Fire Booster Pump
Mass Rate
(lb/h)
Emissions
Level
(g/bhph)
Mass Rate
(lb/h)
Emissions
Level
(g/bhph)
0.20
0.16
0.11
0.20
NOx + NMHC
6.21
4.90
1.71
5.20
PM/PM10 (filterable)
0.10
0.08
0.06
0.19
CO
0.95
0.75
0.11
0.33
VOC
0.37
0.29
0.12
0.36
H2SO4
0.31
0.25
0.10
0.31
Pollutant
SO2
(2)
(1)
Emissions based on manufacturer’s performance data. VOC emissions based on a
USEPA AP-42 air emissions factor.
(2)
NMHC = Non-Methane Hydro Carbon.
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2.2.5
2.0 BACT Analysis Basis
Gate Station Gas Heater
Table 2-12 presents the BACT design basis for the Project’s gate station gas
heater.
Table 2-12
Gate Station Gas Heater Design Basis*
Maximum Heat Input
3.0 MBtu/h
Operating Hours
8,760 h/yr
Fuel
Natural Gas
*Full load operation, average annual site conditions.
Based on the design basis presented in Table 2-12, the baseline emissions from
the Project’s gate station gas heater are presented in Table 2-13.
Table 2-13
Gate Station Gas Heater Baseline Emissions*
Pollutant
Mass Rate
(lb/h)
Emissions Level
(lb/MBtu)
SO2
0.002
0.0006
NOx
0.14
0.05
PM/PM10 (filterable)
0.02
0.007
CO
0.14
0.05
VOC
0.02
0.005
H2SO4
0.003
0.0009
*Emissions based on manufacturer’s performance data. PM/PM10, SO2,
and VOC emissions based on USEPA AP-42 air emissions factors.
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3.0
3.0 Coal Fired Boiler
SO2 BACT Analysis
Coal Fired Boiler SO2 BACT Analysis
This section presents the top-down, five-step BACT process that was used to
evaluate and determine the Project’s SO2 emissions limits for the main boiler. As this
analysis will demonstrate, the proposed SO2 BACT limit for the Project’s main boiler is a
emission limit of 0.06 lb/MBtu (based on a 30 day rolling average) or 98 percent SO2
removal (whichever occurs first) with a 0.08 lb/MBtu (based on a 30 day rolling average)
upper limit.
3.1
Step 1--Identify All Control Technologies
The first step in a top-down analysis, according to the EPA’s October 1990, Draft
New Source Review Workshop Manual, is to identify all available control options.
Available control options are those air pollution control technologies or techniques with a
practical potential for application to the emission unit and the SO2 emission limit that is
being evaluated. There are several pre-combustion and post-combustion FGD processes
that have demonstrated SO2 removal capabilities for use with of a pulverized coal fired
boiler. Based on the various SO2 removal alternatives, lime and limestone wet scrubbers
and lime semi-dry/dry scrubber systems are the most widely used FGD systems. In
comparing the various FGD technologies and applications, both the controlled emissions
limit and the percent of SO2 removed need to be considered. Depending on the coal
sulfur content or SO2 loading, either of these performance criteria can represent the
limiting factor for the performance that the technology can achieve. High SO2 loading
may allow for higher removal efficiencies than lower sulfur fuels on a percentage basis,
while lower sulfur fuels can achieve lower absolute emissions limits. The following
subsections review the available pre-combustion and post-combustion SO2 control
technologies.
3.1.1
Coal Washing
Pre-combustion control technology can be considered a fuel cleaning or treatment
method for reducing baseline SO2 emissions. One way of reducing SO2 emissions from a
coal fired plant is to remove the sulfur from the coal prior to the combustion process. The
basic theory of coal washing is that pure coal is lighter than rock or any impurities that
are contained in the coal. Coal washing utilizes various techniques such as high speed
coal washes or agitating liquids to produce a separation of impurities from the coal. As a
part of this separation of impurities, pyritic sulfur will be separated from the coal product.
Various reports have shown that the sulfur content in the coal is reduced from 30 to
50 percent. As the sulfur content (especially the pyritic sulfur) in the fuel decreases (e.g.,
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SO2 BACT Analysis
Illinois Basin to PRB coals), the amount of potential sulfur removal also decreases. In
addition, some of the carbon is removed with the sulfur containing underflow, which
lowers the overall recovery of useable energy from the coal reserve which in turn
influences the cost of final coal product.
Since coals from many different coal mines may be fired at this plant, the costs
for washing may vary widely between the different coals used. The costs of physical coal
cleaning are usually reported in terms of the added cost of the cleaned product over the
original run-of-mine coal. Capital costs (for construction of the coal cleaning facility)
and operating costs can be separated; however, overall costs are often reported without
identification of components. Capital costs reported by the Carbondale Coal Research
Center range from $12 to $16 per ton of coal capacity, with operating costs ranging from
$3.17 per ton to $4.40 per ton for systems featuring high Btu recovery. The USEPA
COALCVAL2.0 computer program also assumes a coal washing cost of $3.25 to $3.33
per ton, depending on the type of mine.
Western subbituminous coals are unlikely to be washed because of their
inherently low sulfur content. Because coal washing on its own cannot achieved the
desired emission reductions, post combustion controls will be included in the Project
design. Because the Project intent is to purchase non PRB coals during supply
deficiencies, coal supply availability and subsequent economics will drive the fuel supply
decision process. Consequently, the range of fuel parameters for this Project represents
the range of cost-effective fuels which generate emissions that can be effectively
controlled by post-combustion control technology. Because of the need to transport the
coal over large distances and the need to use reagents to remove sulfur and other
impurities from the flue gas, the economic evaluation will favor higher heat content and
lower sulfur coal supplies.
3.1.2
Wet Lime- and Limestone-Based FGD Processes
Wet lime- and limestone-based FGD processes are frequently applied to
pulverized coal fired boilers that combust medium-to-high sulfur eastern coals. All of the
FGD systems installed in response to Phase I of the 1990 CAA were based on a wet FGD
system using either lime or limestone as the reagent. Typically, the wet FGD processes
on a pulverized coal facility are characterized by high efficiency (> 98 percent) and high
reagent utilization (95 to 97 percent) when combined with a high sulfur fuel. The ability
to realize high removal efficiencies on higher sulfur fuels is a major difference that the
wet scrubbers have compared to semi-dry/dry FGD processes. The removal efficiency of
the various types of wet scrubbers declines as the fuel sulfur content decreases; this is the
case for low sulfur western and PRB coals. It is well known that SO2 removal
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SO2 BACT Analysis
efficiencies for wet FGD systems are generally higher for high sulfur coal applications
than for low sulfur coal applications, for the fundamental physical reason that the
chemical reactions that remove SO2 are faster if the inlet SO2 concentration is higher.
The absolute emissions level becomes a limiting factor due to a reduction in the chemical
driving forces of the reactions that are occurring.
In a wet FGD system, the absorber module is located downstream of the induced
draft (ID) fans (or booster ID fans, if required). Flue gas enters the module and is
contacted with a slurry containing reagent and byproduct solids. The SO2 is absorbed
into the slurry and reacts with the calcium to form CaSO3•1/2H2O and CaSO4•2H2O.
SO2 reacts with limestone reagent through the following overall reactions:
SO2 + CaCO3 + ½H2O → CaSO3•½H2O + CO2
SO2 + CaCO3 + 2H2O + ½O2 → CaSO4•2H2O + CO2
There are several types of wet absorber modules, and each has characteristic
advantages and disadvantages. FGD equipment vendors have specific designs for one or
more types, and all compete on a capital and operating cost basis. Depending on the
process vendor, the absorber may be a co-current or countercurrent spray tower, with or
without internal packing or trays, or a process in which the flue gas is bubbled into the
reaction tank (commonly referred to as a jet bubbling reactor (JBR)).
Regardless of the type of absorber used, the flue gas leaving the absorber will be
saturated with water, and the stack will have a visible moisture plume. Because of the
chlorides present in the mist carry-over from the absorber and the pools of low pH
condensate that can develop, the conditions downstream of the absorber are highly
corrosive to most materials of construction. Highly corrosion-resistant materials are
required for the downstream ductwork and the flue stack. Careful design of the stack is
needed to prevent the “rainout” from condensation that occurs in the downstream
ductwork and stack. These factors contribute to the relatively high capital costs of the
wet FGD SO2 control alternative.
The reaction products are typically dewatered by a combination of hydrocyclones
and vacuum filters. The resulting filter cake is suitable for landfill disposal. In early
lime- and limestone-based FGD processes, the byproduct solids were primarily calcium
sulfite hemihydrate (CaSO3•1/2H2O), and the byproduct solids were mixed with fly ash
(stabilization) or fly ash and lime (fixation) to produce a physically stable material. In
the current generation of wet FGD systems, air is bubbled through the reaction tank (or in
some cases, a separate vessel) to practically convert all of the CaSO3•1/2H2O into
calcium sulfate dihydrate (CaSO4•2H2O), which is commonly known as gypsum. This
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step is termed “forced oxidation” and has been applied to both lime- and limestone-based
FGD processes. Compared to calcium sulfite hemihydrate, gypsum has much superior
dewatering and physical properties, and forced oxidized FGD systems tend to have few
internal scaling problems in the absorber and mist eliminators. Dewatered gypsum can
be landfilled without stabilization or fixation. Many FGD systems in the United States
are using the forced-oxidation process to produce a commercial grade of gypsum that can
be used in the production of portland cement or wallboard. Marketing of the gypsum can
eliminate or greatly reduce the need to landfill FGD byproducts.
The absorber vessels are fabricated from corrosion-resistant materials such as
epoxy/vinylester-lined carbon steel, rubber-lined carbon steel, stainless steel, or
fiberglass. The absorbers handle large volumes of abrasive slurries. The byproduct
dewatering equipment is also relatively complex and expensive. These factors result in
relatively higher initial capital costs. Wet FGD processes are also characterized by
higher raw water usage than semi-dry FGD systems. This can be a significant
disadvantage or even a fatal flaw in areas where raw water availability is in short supply.
Numerous suppliers offer FGD processes using limestone slurry as the reagent.
The various wet FGD technologies that use lime/limestone slurry as the reagent are as
follows:
•
Countercurrent Spray Tower.
•
Double Contact Spray Tower.
•
Jet Bubbling Reactor (JBR).
•
FLOWPAC.
For the purposes of this analysis, all of the wet FGD systems identified, while
having different equipment, will generally meet the emissions rate objective and have
similar operating characteristics.
3.1.2.1 Countercurrent Spray Tower. A countercurrent spray tower has become
one of the most widely used absorber types in wet lime- and limestone-based FGD
service. Flue gas enters at the bottom of the absorber and flows upward. Slurry with
10 to 15 percent solids is sprayed downward from higher elevations in the absorber and is
collected in a reaction tank at its base. The SO2 in the flue gas is transferred from the flue
gas to the recycle slurry. The hot flue gas is also cooled and saturated with water.
Recycled slurry is pumped continuously from the reaction tank to the slurry spray
headers. Each header has numerous individual spray nozzles that break the slurry flow
into small droplets and distribute them evenly across the cross section of the absorber.
Prior to leaving the absorber, the treated flue gas passes through a two-stage, chevrontype mist eliminator that removes entrained slurry droplets from the gas. The mist
eliminator is periodically washed to keep it free of solids.
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In the reaction tank, the SO2 absorbed from the flue gas reacts with soluble
calcium ions in the recycle slurry to form insoluble calcium sulfite and calcium sulfate
solids. In forced-oxidization processes, air is bubbled through the slurry to convert all of
the solids to calcium sulfate dihydrate (gypsum). A lime or limestone reagent slurry is
added to the reaction tank to replace the calcium consumed.
To control the solids content of the recycle slurry, a portion of the slurry is
discharged from the reaction tank to the byproduct dewatering equipment. Depending on
the ultimate disposal of the byproduct solids, the dewatering equipment may include
settling ponds, thickeners, hydrocyclones, vacuum filters, and centrifuges. The liquid
that is separated from the byproduct solids slurry is stored in the reclaim water tank.
Water in the reclaim water tank is returned to the absorber reaction tank as makeup water
and used to prepare the reagent slurry.
3.1.2.2 Double Contact Spray Tower. The double contact spray tower uses the
same process chemistry as the countercurrent spray tower, but the flue gas and slurry
flow countercurrently in the first section of the absorber module and co-currently in the
second stage. In this design, the recycled slurry is evenly distributed across the absorber
by low-pressure fountain type nozzles. The resulting fountains of slurry fall back down
into the reaction tank. Because of the lower nozzle pressure, the solids level in the
recycle slurry can be raised to 15 to 25 percent without resulting in an unacceptable rate
of nozzle wear. Compared to the countercurrent design, the dual contact spray tower
operates at a higher flue gas velocity since there is less concern about the entrainment of
slurry droplets in the flue gas. This alternative may use either a vertical gas flow mist
eliminator or a horizontal gas flow mist eliminator that can also operate at a higher
velocity than vertical gas flow mist eliminators.
3.1.2.3 Jet Bubbling Reactor. The absorber module for this technology is unique in
the FGD industry because the surface area required for absorption of SO2 from the flue
gas is created by bubbling the flue gas through a pool of slurry rather than by recycling
slurry through the flue gas, which is the process used in other absorber types. Flue gas is
pre-cooled with makeup water and slurry prior to entering the JBR’s inlet plenum. The
inlet plenum is formed by upper and lower deck plates. From this plenum, the flue gas is
directed through multiple, 6 inch diameter, sparger tube openings in the lower deck.
These tubes are submerged a few inches beneath the level of slurry in the integral
reaction tank located at the base of the JBR. The bubbling action of the flue gas as it
exits the sparger tubes and rises through the slurry promotes SO2 absorption. The gas
then leaves the reaction tank area and the outlet plenum via gas risers that pass through
both the lower and upper decks. An external horizontal gas flow mist eliminator removes
the residual mist carried over from the JBR.
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To establish the liquid-gas contact needed to absorb SO2 from the flue gas
requires energy. In a spray tower system, this energy is provided by the spray pumps that
produce a large number of fine droplets. In a JBR, this energy is provided by the fans
necessary to account for the pressure drop across the spargers. Therefore, the JBR has
two to three times as great a gas pressure drop as a spray tower FGD system, but less than
20 percent of the pumping horsepower requirement.
3.1.2.4 FLOWPAC. The FLOWPAC process is similar to a JBR in that the flue gas is
forced to bubble through a limestone slurry. The flue gas enters the absorber under a
sieve tray and passes up through holes in the sieve tray and into a turbulent limestone
slurry bed. SO2 is removed from the flue gas as the flue gas is contacted with the
limestone slurry.
The FLOWPAC absorber is a cylindrical tank with a central recycle tank and
downcomers located on the circumference of the tank. The sieve tray encircles the
absorber recycle tank. Oxidation air is added into the recycle tank of the absorber along
with agitation. The oxidation air lowers the effective density in the recycle tank, which
causes circulation out of the recycle tank and through the downcomers. This circulation
eliminates the need for large absorber recycle pumps. After the flue gas travels through
the limestone slurry, it passes through a vertical mist eliminator prior to exiting to a
chimney.
3.1.3
Semi-Dry Lime-Based FGD Systems
Semi-dry spray dryer absorber (SDA) FGD processes have been extensively used.
US utilities have installed numerous SDA FGD systems on boilers using low sulfur fuels.
These installations, primarily located in the western United States, use either lignite or
subbituminous coals such as PRB as the boiler fuel and generally have spray dryer
systems designed for a maximum fuel sulfur content of less than 2 percent. The semi-dry
lime-based FGD system has an inherent removal efficiency limitation of 94 percent from
inlet concentration.
The semi-dry FGD process uses calcium hydroxide [Ca(OH)2] produced from the
lime reagent as either a slurry or as a dry powder to the flue gas in a reactor designed to
provide good gas-reagent contact. The SO2 in the flue gas reacts with the calcium in the
reagent to produce primarily calcium sulfite hemihydrate (CaSO3•1/2H2O) and a smaller
amount of calcium sulfate dihydrate (CaSO4•2H2O) through the following reactions:
SO2 + Ca(OH)2 → CaSO3•½H2O + ½H2O
SO2 + Ca(OH)2 + ½O2 → CaSO4•2H2O
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Water is also added to the reactor (either as part of the reagent slurry or as a
separate stream) to cool and humidify the flue gas, which promotes the reaction and
reagent utilization. The amount of water added is typically sufficient to cool the flue gas
to within 30° to 40° F of the flue gas adiabatic saturation temperature. Significantly less
water is used in these semi-dry FGD processes compared to wet FGD processes.
The reaction byproducts and excess reagent are dried by the flue gas and removed
from the flue gas by a particulate control device (either fabric filter or DESP). Fabric
filters are preferred for most systems, because the additional contact of the flue gas with
the particulate on the filter bags provides additional SO2 removal and higher reagent
utilization. A portion of the reaction byproducts collected is recycled to the reagent
preparation system in order to increase the utilization of the lime.
Because of the large amount of excess lime present in the FGD byproducts, the
byproducts (and fly ash, if present) will experience pozzolanic (cementitious) reactions
when wetted. When wetted and compacted, the byproduct makes a fill material with low
permeability (low lengthening characteristics) and high bearing strength. However, other
than as structural fill, this byproduct has limited commercial value and typically must be
disposed of as a waste material.
The semi-dry FGD processes offer benefits in addition to SO2 removal, including
the lack of a visible vapor plume and SO3 removal. Because the semi-dry FGD systems
do not saturate the flue gas with water, there is no visible plume from the stack under
most weather conditions. Environmental concerns with SO3 emissions are also reduced
with the semi-dry scrubber. SO3 is formed during combustion and will react with the
moisture in the flue gas to form sulfuric acid (H2SO4) mist in the atmosphere. An
increase in H2SO4 emissions will increase PM10 emissions. The gas temperature leaving
the reactor is lowered below the sulfuric acid dew point, and significant SO3 removal will
be attained as the condensed acid reacts with the alkaline reagent. By removing SO3 in
the flue gas, the condensable particulate matter emissions can be reduced. This will
reduce the potential for any SO3 plume that may cause opacity in stacks. Similar type
SO3 removal is not achievable with a wet scrubber.
The following four variants of semi-dry FGD processes are described further in
this analysis:
•
SDA.
•
Circulating Dry Scrubber (CDS).
•
Flash Dryer Absorber.
•
Limestone Injection into the Furnace and ReActivation of Calcium
(LIFAC).
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3.1.3.1 Spray Dryer Absorber. All current SDA designs use a vertical gas flow
absorber. These absorbers are designed for co-current or a combination of co-current and
countercurrent gas flow. In co-current applications, gas enters the cylindrical vessel near
the top of the absorber and flows downward and outward. In combination-flow
absorbers, a gas disperser located near the middle of the absorber directs a fraction of the
total flue gas flow upward toward the slurry atomizers.
In both cases, the atomizers are located in the roof of the absorber. Both rotary
and two-fluid nozzles have been applied to this approach. The atomizer produces an
umbrella of atomized reagent slurry through which the flue gas passes. The SO2 in the
flue gas is absorbed into the atomized droplets and reacts with the calcium to form
calcium sulfite and calcium sulfate. Before the slurry droplet can reach the absorber wall,
the water in the droplet evaporates and a dry particulate is formed.
Some vendors base their designs on a single large rotary atomizer per absorber;
others use up to three smaller rotary atomizers per absorber. Two-fluid atomizers are
installed as an array of up to 16 nozzles per atomizer; all three approaches to spray
atomizers have been successfully applied.
The flue gas, then containing fly ash and FGD byproduct solids, leaves the
absorber and is directed to a fabric filter. The fly ash and byproduct solids collected in
the fabric filter are pneumatically transferred to a silo for disposal. To improve both
reagent utilization and spray solids drying efficiency, a large portion of the solids
collected is directed to a recycle system, where it is slurried and re-injected into the spray
dryer along with the fresh lime reagent.
3.1.3.2 Circulating Dry Scrubber. The CDS FGD process is a semi-dry, lime-based
FGD process that uses a circulating fluid bed contactor rather than an SDA. The CDS
absorber module is a vertical solid/gas reactor between the unit’s air heater and its
particulate control device. Water is sprayed into the reactor to reduce the flue gas
temperature to the optimum temperature for reaction of SO2 with the reagent. Hydrated
lime [Ca(OH)2] and recirculated dry solids from the particulate control device are
injected concurrently with the flue gas into the base of the reactor just above the water
sprays. The gas velocity in the reactor is reduced, and a suspended bed of reagent and fly
ash is developed. The SO2 in the flue gas reacts with the reagent to form predominantly
calcium sulfite. Fine particles of byproduct solids, excess reagent, and fly ash are carried
out of the reactor and removed by the particulate removal device (either a fabric filter or
DESP). More than 90 percent of these solids are returned to the reactor to improve
reagent utilization and increase the surface area for SO2/reagent contact.
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The CDS FGD system produces an extremely high solids load on the particulate
removal device as a result of recycling the byproduct/fly ash mixture. For this reason,
some CDS FGD system vendors prefer to use an DESP rather than a fabric filter. Most
of the recycled material can be collected in the first field of an DESP with minimal effect
on the overall DESP sizing. In contrast, a fabric filter in this same service would require
special design features to avoid the reduced bag life associated with frequent bag
cleaning.
3.1.3.3 Flash Dryer Absorber. The flash dryer absorber is a variation of CDS
technology. In this system, the fly ash is mixed with lime or limestone and water in a
mixer/hydrator prior to being injected into the flash dryer. The flue gas is evaporatively
cooled and humidified by the water being absorbed onto the dry particulate.
Furthermore, SO2 is removed from the flue gas stream by the reaction with the lime or
limestone. The dry particulate is then removed in a fabric filter. A portion of the dry
particulate from the fabric filter is collected for disposal.
3.1.3.4 Limestone Injection into Furnace and ReActivation of Calcium. In
the early 1980s, Tampella Power Inc. of Finland began development of a humidification
process that would enhance the effectiveness of the furnace-injection FGD process by
humidifying the flue gas and installing a solid/gas contact reactor upstream of the
particulate control device. This process is referred to by the acronym LIFAC. The two
major differences between the LIFAC process and the furnace-injection process are the
use of a reactor to enhance reagent contact with the flue gas and the recirculation of a
portion of the fly ash and byproduct solids collected in the particulate control device to
the reactor. This recirculation greatly improves the effectiveness of the process’s reagent
usage and its SO2 removal efficiency.
This process is offered only by Tampella Power or one of its affiliated companies,
and has been applied to full-scale, coal fired utility boilers in Finland, Russia, Canada,
and the United States.
3.2
Step 2--Eliminate Technically Infeasible Options
Step 2 of the BACT analysis involves the evaluation of all the identified available
control technologies in Step 1 of the BACT analysis to determine their technical
feasibility. A control technology is technically feasible if it has been previously installed
and operated successfully at a similar type of source of comparable size, or there is
technical agreement that the technology can be applied to the source. Available and
applicable are the two terms used to define the technical feasibility of a control
technology. The following subsections review the control technologies identified in
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Step 1 of the BACT analysis and determine if they are technically feasible. Table 3-1
summarizes the evaluation of the technically feasible SO2 options.
3.2.1
Coal Washing
Coal washing is a demonstrated technology of reducing SO2 emissions from a
coal fired boiler; however, the effectiveness of coal washing is dependent on the coal
type. As discussed in Subsection 3.1.1, coal washing utilizes various techniques such as
high speed coal washes or agitating liquids to produce a separation of impurities from the
coal. The pyretic sulfur will be separated from the coal product. Since IPL is proposing
to utilize various types of coals, the effectiveness of coal washing will differ greatly. IPL
is not aware of large-scale facilities that perform coal washing on western subbituminous
coal, such as PRB, which is considered one of the design coals for the main boiler.
Therefore, the supply of PRB coal that has been washed cannot be considered a reliable
source for this Project. Coal washing is determined to be technically infeasible because
PRB coal that has been washed may not be available.
3.2.2
Wet Lime- and Limestone-Based FGD Processes
A wet lime- and limestone-based FGD process have been demonstrated
technologies of controlling SO2 emissions from a coal fired boiler and are commercially
available from several vendors. Wet lime- and limestone-based FGD processes, which
include the countercurrent spray tower, double contact spray tower, jet bubbling reactor,
and FLOWPAC, are equal for comparative purposes. Wet lime- and limestone-based
FGD processes are considered technically feasible and will be considered further.
3.2.3
Semi-Dry Lime-Based FGD Systems
Semi-dry SDA FGD processes have been extensively used on coal fired boilers
for controlling SO2 emissions. However, the following four variants of semi-dry FGD
processes are analyzed further in this analysis:
•
SDA.
•
CDS.
•
Flash Dryer Absorber.
•
LIFAC.
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Table 3-1
Summary of Step 2--Eliminate Technically Infeasible Options
Technically Feasible (Yes/No)
Technology Alternative
Available
Applicable
Coal Washing
Yes
No – PRB coal that has been washed
may not be available. Coal washing is
not technically feasible.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes – However, SDA has limited
removal SO2 efficiency over the
Project range of sulfur in fuels and
will not be considered further.
No – No installations comparable in
size to this Project. Long-term high
removal efficiency not demonstrated
on range of sulfur in fuels of this
Project.
Yes – However, SDA has limited
removal SO2 efficiency over the
Project range of sulfur in fuels and
will not be considered further.
No – No installations comparable in
size to this Project. Long-term high
removal efficiency not demonstrated
on range of sulfur in fuels of this
Project.
Wet Lime or Limestone FGD(1)
Spray Tower
Double Contact Spray Tower
JBR
FLOWPAC
Dry and Semi-Dry Lime FGD
SDA
CDS
Yes
Flash Dryer Absorber
Yes
LIFAC
Yes
(1)
All alternate technologies in wet lime or limestone FGD (i.e., spray tower, double
contact spray tower, JBR, FLOWPAC) are equal for comparative purposes.
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3.2.3.1 Spray Dryer Absorber. As discussed in Subsection 3.1.3.1, all current SDA
designs use a vertical gas flow absorber that are for co-current or counter-current gas
flow. All SDA systems are commercially available from several vendors. The systems
are all considered technically feasible. However, SDAs cannot meet the expected BACT
performance criteria when burning the proposed higher sulfur bituminous coal. A
removal efficiency of 94 percent with a SDA would only result in a 0.35 lb/MBtu outlet
emissions rate at the stack when firing the higher sulfur fuels proposed for this Project. If
the IPL SGS Unit 4 was to be permitted to burn only PRB coal, then a SDA would be
considered further as a SO2 control technology. As such, the SDA will not be considered
further due to IPL’s range of sulfur in the proposed fuels.
3.2.3.2 Circulating Dry Scrubber. As discussed in Subsection 3.1.3.2, the CDS
FGD process is a semi-dry, lime-based FGD process that uses a circulating fluid bed
contactor rather than an SDA. CDS FGD processes have only been domestically applied
to smaller coal-fired boilers, which are all under 100 MW. Since IPL’s main boiler is
rated at 649 MW (net), the size and scale differences are too great. According to EPA’s
NSR Manual (Draft), technologies that have not yet been applied to full scale operations
need to be considered available. Thus, the CDS FGD process is not considered
technically feasible and will not be considered further.
3.2.3.3 Flash Dryer Absorber. The flash dryer absorber is a demonstrated
technology of controlling SO2 emissions from a coal fired boiler and is commercially
available. An advantage of the flash dryer absorber is the minimal footprint that is
required of the control equipment. The reactor, absorbent preparation system, and the
particulate collector offers a small footprint compared to other SO2 control technologies.
The flash dryer absorber is considered technically feasible. However, flash dryer
absorbers cannot meet the expected BACT performance criteria when burning the
proposed higher sulfur bituminous coal. A removal efficiency of 90 percent with a flash
dryer absorber would only result in a 0.58 lb/MBtu outlet emissions rate at the stack
when firing the higher sulfur fuels proposed for this Project. As such, the flash dryer
absorber will not be considered further due to IPL’s range of sulfur in the proposed fuels.
3.2.3.4 Limestone Injection into Furnace and ReActivation of Calcium. The
LIFAC process is a demonstrated technology of controlling SO2 emissions from a coal
fired boiler on a limited number of installations and is considered commercially
available. As described in Subsection in 3.1.3.4, the first step in the LIFAC process is
limestone furnace injection (approximately 25 to 35 percent SO2 removal). The next step
involves the flue gas humidification with dry ash recycle (SO2 removal up to 85 percent).
The last step utilizes slurry ash recycle (increases the SO2 removal to 90 percent).
However, LIFAC cannot meet the expected BACT performance criteria when burning the
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proposed higher sulfur bituminous coal. A removal efficiency of 90 percent with LIFAC
would only result in a 0.58 lb/MBtu outlet emissions rate at the stack when firing the
higher sulfur fuels proposed for this Project. In addition, LIFAC has not been applied
domestically to similar sized boilers as proposed for the Project. LIFAC has been
designed for plant capacities ranging from 25 to 200 MW. LIFAC will not be considered
further because it is not technically feasible for the Project.
3.3
Step 3--Rank Remaining Control Technologies by
Effectiveness
A search of the information contained in the USEPA BACT/LAER Clearinghouse
and other sources specified in Section 2.1 was conducted to determine the top level of
SO2 control for coal fired pulverized coal boilers. A search was also conducted for
recently permitted coal fired facilities whose BACT determinations have not yet been
included in the current BACT/LAER Clearinghouse database. The results of this search
for all coal fired boilers are listed in Attachment A, Table A-1, of this BACT analysis.
Tables 3-2 and 3-3 (subbituminous and bituminous fuels, respectively) list the SO2
BACT determinations that have the closest attributes when compared to IPL’s SGS
Unit 4, which include fuel type, boiler technology, and size of boiler.
A review of the SO2 BACT determinations in Tables 3-2 and 3-3 indicates the
following:
•
The most stringent SO2 permit proposed for a 2 x 980 MW pulverized
coal boiler installation is 0.04 lb/MBtu, based on a 30 day average at
Florida Power and Light Company (FPL), Glades Power Park located in
Florida. The Glades Power Park proposed site is located approximately
100 miles from the Everglades National Park (Class I area). The close
proximity of the Class I area and compliance with the stringent criteria
were major factors in FPL proposing the SO2 emissions limit. Note, the
PSD Air Permit Application was submitted on December 19, 2006, and
the Air Permit Application remains “incomplete” (SFWMD WRAC
Meeting on May 30, 2007, in Clewiston, Florida). Furthermore, the
Florida Public Service Commission rejected the proposal for Glades
Power Park on June 6, 2007, and the project was cancelled. This project is
not considered further in this analysis, since the air permitting process did
not result in a final BACT determination, much less a commercial
demonstration of the proposed emission limit over a long-term period.
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Table 3-2
Subbituminous Fuels
SO2 Top-Down RBLC Clearinghouse Review Results
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Table 3-3
Bituminous or Bituminous Blend of Fuels
SO2 Top-Down RBLC Clearinghouse Review Results
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•
•
•
•
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The next most stringent permitted SO2 requirement for a pulverized coal
boiler installation is 0.06 lb/MBtu at City Public Services of San Antonio,
Calaveras Lake Station at J.K. Spruce located in Texas. Note, this is the
most restrictive SO2 removal limit required in permit that has been issued
at this time. The FGD system at this facility is documented to be a wet
FGD and is based upon burning PRB coal.
There are four proposed permits with SO2 removal limits of
0.06 lb/MBtu. All four projects are for pulverized coal boiler installations
that burn a subbituminous coal and have a wet FGD as the documented
SO2 control technology. The following are the four projects: 2 x 750 MW
pulverized coal boiler installation at 0.06 lb/MBtu, based on a 24 hour
basis at Sithe Global Desert Rock Power Plant located in New Mexico;
500 MW pulverized coal boiler installation at 0.06 lb/MBtu at BHP
Billiton, Cottonwood Energy Center located in New Mexico; 750 MW
pulverized coal boiler installation at 0.06 lb/MBtu, based on a 24 hour
basis at Touquop Energy Project located in Nevada; and 2 x 750 MW
pulverized coal boiler installation at 0.06 lb/MBtu, based on a 24 hour
basis at Sierra Pacific and Nevada Power, Ely Energy Center located in
Nevada. However, unlike IPL SGS Unit 4, none of these units fire a high
sulfur coal as a primary alternate coal.
The next most stringent SO2 emissions limit that has been permitted is
0.065 lb/MBtu for a 750 MW pulverized coal boiler installation at
Western Farmers Electric Cooperative, Hugo Station located in Oklahoma.
The project proposes to burn a subbituminous coal and utilize a wet FGD
for SO2 control.
The next most stringent SO2 emissions limit that has been proposed is
0.065 lb/MBtu for a 750 MW pulverized coal boiler installation at LS
Power Development, Elk Run Energy Station located in Iowa. The project
proposes to burn a subbituminous coal and utilize a semi-dry FGD for
SO2 control. The proposed SO2 emissions limit has a tiered emissions
limit approach. The first tier is an emissions limit of 0.065 lb/MBtu when
the inlet SO2 emissions rate is equal to or below 1.0 lb/MBtu SO2. The
second tier is an emissions limit of 0.09 lb/MBtu when the inlet SO2
emissions rate is greater than 1.0 lb/MBtu SO2. Both the proposed Tier 1
and Tier 2 are based on 30 day averages.
The next most stringent SO2 emissions limit that has been permitted is at
0.09 lb/MBtu for four projects. The following are the four projects: a
200 MW pulverized coal boiler installation at the Newmont Mining
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SO2 BACT Analysis
Corporation, TS Power Plant located in Nevada, with dry FGD as the SO2
control (24 hour averaging for coal with a sulfur content greater than
0.45 percent; however, the SO2 limit is 0.065 when the coal has a sulfur
content less than 0.45 percent); a 100 MW pulverized coal boiler
installation at Black Hills Corporation, Wygen 3 located in Wyoming,
with SDA as the SO2 control (12 month averaging); a 500 MW pulverized
coal boiler installation at Wisconsin Public Service, Weston Unit 4 located
in Wisconsin, with dry FGD as the SO2 control (12 month averaging); and
3 x 530 MW pulverized coal boiler installation at LS Power Development,
White Pine Energy Station located in Nevada, with dry FGD as the SO2
control (24 hour averaging).
•
Another permitted project that is as stringent as the 0.09 lb/MBtu limit
for SO2 control is the Kansas City Power & Light (KCP&L), Iatan
Generating Station (Unit 2). Iatan 2 is a 800 MW pulverized coal boiler
permitted to burn a subbituminous coal with a wet FGD for SO2 control
(30 day averaging).
The permit was issued on January 31, 2006;
however, a collaboration agreement between KCP&L and Sierra Club
revised the permit limits in 2007, and the SO2 limit set netted out of PSD
and BACT review. The unit’s on-line commercial date is set for June 1,
2010.
•
Sunflower’s Holcomb Station draft air permit, which is proposed,
determined a BACT limit of 0.095 lb/MBtu as BACT for three 700 MW
pulverized coal coal fired units in western Kansas firing PRB coal and
utilizing semi-dry FGD technology for SO2 control.
Based upon the technologies identified as technically feasible and available in
Steps 1 and 2, the following technologies presented in Table 3-4 are ranked in a “TopDown Approach” methodology. The proposed fuel alternatives of the Project and design
considerations of the main boiler are the reasons for a wet FGD with a BACT emission
limit of 0.06 lb/MBtu or 98 percent SO2 removal (whichever is higher in emissions).
While FPL’s Glades Power Park proposed a more stringent emission limit, the decision to
do so was apparently based on limited sulfur fuel and driven by Class I visibility
concerns rather than a case-by-case BACT determination; and as discussed in
Section 3.3, the project has since been cancelled and is not considered further. Wet FGD
is the top control as evident in a review of previous determinations and 0.06 lb/MBtu
represents the most stringent BACT limit actually permitted for a similar type unit as the
Project.
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Table 3-4
Ranking of SO2 Control Technologies
Control Option
Control Effectiveness (lb/MBtu)
Wet FGD System (Lime or Limestone)
0.06
Notes:
1. No other technologies are ranked, but wet FGD is based upon Step 2.
2. All wet FGD systems are expected to be similar in operating characteristics.
3.4
Step 4--Evaluate Most Effective Controls and Document
Results
In the following subsections, the technically feasible emissions control
alternatives are evaluated with respect to their energy, environmental, and economic
impacts on the Project. Although there are several types of SO2 control technologies
available, as previously described in Section 3.1, only the wet FGD systems are capable
of the SO2 removal efficiencies necessitated by the fuel flexibility requirements of this
Project, as described in Section 3.2. All of the described alternate wet FGD technologies
will have similar energy, environmental, and economic evaluations. Therefore, the
following evaluation is based on a wet FGD.
3.4.1
Energy Evaluation of Alternatives
In the wet lime/limestone processes (spray tower), the majority of the energy
consumption is attributed to reagent preparation for grinding the limestone and the high
pumping power requirements dictated by the high liquid-to-gas (L/G) ratio required for
these processes. The high sulfur fuel (Illinois Basin coal) that will be used at this facility
requires more limestone grinding and higher L/G, hence a higher auxiliary power usage.
The ability to increase the L/G ratio at the expense of higher energy use allows this
system the capability of achieving the high emissions removal rates required for this
facility. Designing for both PRB and Illinois coal firing will result in some equipment
inefficiencies as a result of the larger sized equipment being run when firing PRB.
However, there are no significant energy impacts that would preclude the use of a wet
FGD, as presented in this evaluation.
3.4.2
Environmental Evaluation of Alternatives
When considering any FGD technology, there are potential environmental
impacts associated with either direct operation or secondary impacts. While there are no
significant environmental impacts that would preclude the use of a wet FGD, several
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SO2 BACT Analysis
potential environmental impacts are examined below for the wet FGD control technology
systems:
•
Visible Stack Gas Visible Plume--A wet FGD system can result in a
visible moisture plume almost year-round.
•
Water Consumption--All of the wet FGD systems utilize a significant
amount of water to facilitate limestone preparation and to reduce the flue
gas temperature to saturation, where the scrubbing of SO2 occurs. For
comparison purposes, water consumption rates for semi-dry lime FGD
systems are approximately 20 to 30 percent less than that required for wet
lime/limestone FGD processes.
However, from a facility-wide
perspective, the use of a wet FGD allows for the recycling of cooling
tower blowdown water back to the scrubber module instead of discharging
to the river, which is an environmental advantage of a wet FGD for this
Project.
•
Byproduct Disposal--The gypsum waste product from the wet FGD
systems is a stable, landfill suitable product. The gypsum is nontoxic and
can be used in the production of wallboard. Gypsum has been previously
safely stored in landfills as a dry product or by a method called gypsum
stacking, where the product is pumped to a disposal area. With gypsum
stacking, the excess free water is allowed to settle and is collected for
return to the process. The common drawback to the FGD processes
evaluated thus far is the large disposal site requirement for byproduct
disposal. For the wet lime and limestone FGD systems, fly ash is
collected before the FGD system, allowing for the potential sale of fly ash.
This presents a potential for less landfilling than the circulating lime
processes, which would have the ash and byproduct as an inseparable
mixture. The large available land area at the facility site will allow for the
safe storage of the material in an onsite landfill.
3.4.3
Economic Evaluation of Alternatives
Wet FGD systems represent the top control alternative for the reduction of SO2
emissions from the Project. There are no significant economic impacts that would
preclude the use of a wet FGD, as presented in this analysis. Since wet FGD represents
the only viable SO2 control technology option and represents the top control alternative, a
comparative economic analysis is not warranted or required by the BACT review
process.
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SO2 BACT Analysis
Step 5--Select SO2 BACT
IPL has determined that a wet limestone FGD represents BACT for the Project’s
main boiler as the most appropriate SO2 control technology for the facility.
As stated in Subsection 3.1.2, the wet FGD processes for a SCPC boiler are
characterized by high efficiency (> 98 percent) and high reagent utilization (95 to
97 percent) when starting with a high sulfur fuel. The removal efficiency is reduced as
the fuel sulfur content decreases; this is the case for low sulfur western and PRB coals.
The absolute emissions level becomes a limiting factor due to a reduction in the chemical
driving forces of the reactions that are occurring. As a result, for installations that burn a
range of fuels, there is a bottom emissions limit that the original equipment manufacturer
(OEM) vendors will guarantee, with the reduced removal efficiency as a secondary
criteria. For this Project, it is expected that the reduced efficiency would be between 95
to 98 percent, based on the inlet sulfur content of the proposed fuels.
Based on the “top-down” approach, completion of the BACT analysis in Steps 1
through 5, and the entire range of fuels proposed for the Project, IPL proposes a wet FGD
for the Project with a BACT emission limit of 0.06 lb/MBtu (based on a 30 day rolling
average) or 98 percent SO2 removal, whichever occurs first, with a 0.08 lb/MBtu (based
on a 30 day rolling average) upper limit. Table 3-5 summarizes the Project’s SO2 BACT
determination for the main boiler.
Table 3-5
Main Boiler SO2 BACT Determination
Control Technology
Emission Limit (lb/MBtu)
Wet FGD System
0.06 lb/MBtu(1) or 98 percent removal (whichever
occurs first) with 0.08 lb/MBtu(1) upper limit.
(1)
Based on a 30 day rolling average.
IPL’s proposed SO2 BACT limits are based on engineering evaluation and a
review of various OEM’s technical literature. There was no literature found or
engineering calculations performed that would indicate that co-firing with a biomass
blend of 5 percent would change the proposed BACT emissions limit.
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4.0
4.0 Coal Fired Boiler
NOx BACT Analysis
Coal Fired Boiler NOx BACT Analysis
This section presents the top-down, five-step BACT process used to evaluate and
determine the Project’s NOx emissions limit for the main boiler. As this analysis will
demonstrate, the proposed NOx BACT limit for the Project’s main boiler is an emissions
limit of 0.05 lb/MBtu on a 30 day average basis.
4.1
Step 1--Identify All Control Technologies
The first step in a top-down analysis, according to the EPA’s October 1990, Draft
New Source Review Workshop Manual, is to identify all available control options.
Available control options are those air pollution control technologies or techniques with a
practical potential for application to the emission unit and the NOx emissions limit that is
being evaluated.
NOx is defined as the combination of nitrogen oxide (NO) and nitrogen dioxide
(NO2). Typically, the NOx that is formed in coal fired plants consists of 90 to 95 percent
NO, with the balance occurring as NO2. NOx in the flue gas is a result of oxidizing either
nitrogen in the combustion air (thermal NOx) or nitrogen in the fuel (fuel NOx).
Generally, when burning coal, less than 25 percent of the NOx produced is thermal NOx,
and the balance is fuel NOx. NOx production occurs predominantly within the flame
zone, where localized high temperatures sustain the NOx-forming reactions.
NOx controls may be divided into two categories: combustion related NOx
formation control and post-combustion emission reduction. Combustion related NOx
formation control processes reduce the quantity of NOx formed in the combustion
process. A post-combustion technology reduces the NOx emissions in the flue gas stream
after the NOx has been formed in the combustion process. Both of these methods may be
used independently or in combination to achieve the degree of NOx emissions reduction
required.
Combustion control methodologies seek to suppress NOx formation during the
combustion process. Unfortunately, low NOx emissions are often counterproductive to
combustion efficiency. Typically, combustion control methods include low NOx burners
(LNB), overfire air (OFA), gas reburn, and advanced gas reburn (AGR). While none of
these combustion control methods alone can achieve the NOx BACT emission levels
currently being permitted for new coal fired units, they are considered standard
equipment and form the baseline in new boiler design emissions estimates. Therefore,
LNB/OFA is not only cost-effective, but is also considered the basis of the NOx baseline
emissions for the Project in this BACT analysis.
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NOx BACT Analysis
Post-combustion controls are flue gas treatments that reduce NOx after its
formation. The post-combustion alternatives include Selective Noncatalytic Reduction
(SNCR) and SCR. All post-combustion control technologies rely on the injection of a
nitrogen compound into the flue gas to react with (and remove) NOx. For this BACT
analysis, aqueous ammonia is the reagent utilized with the SCR systems.
4.1.1
Selective Catalytic Reduction System
In an SCR system, ammonia is injected into the flue gas stream just upstream of a
catalytic reactor. The ammonia molecules in the presence of the catalyst dissociate a
significant portion of the NOx into nitrogen and water.
The aqueous ammonia is received and stored as a liquid. The ammonia is
vaporized and subsequently injected into the flue gas by compressed air or steam as a
carrier. Injection of the ammonia must occur at temperatures above 600° F to avoid
chemical reactions that are significant and operationally harmful. Catalyst and other
considerations limit the maximum SCR system operating temperature to 840° F.
Therefore, the system is typically located between the economizer outlet and the air
heater inlet. The SCR catalyst is housed in a reactor vessel, which is separate from the
boiler. The conventional SCR catalysts are either homogeneous ceramic or metal
substrate coated. The catalyst composition is vanadium-based, with titanium included to
disperse the vanadium catalyst and tungsten added to minimize adverse SO2 and SO3
oxidation reactions. An economizer bypass may be required to maintain the reactor
temperature during low load operation. This will reduce boiler efficiency at lower loads.
A number of alkali metals and trace elements (especially arsenic) poison the
catalyst, significantly affecting reactivity and life. Other elements such as sodium,
potassium, and zinc can also poison the catalyst by neutralizing the active catalyst sites.
Poisoning of the catalyst does not occur instantaneously, but is a continual steady process
that occurs over the life of the catalyst. As the catalyst becomes deactivated, ammonia
slip emissions increase, approaching design values. As a result, catalyst in a SCR system
is consumable, requiring periodic replacement at a frequency dependent on the level of
catalyst poisoning. However, effective catalyst management plans can be implemented
that significantly reduce catalyst replacement requirements.
There are two SCR system configurations that can be considered for application
on pulverized coal boilers: high dust and tail end. A high dust application locates the
SCR system before the particulate collection equipment, typically between the
economizer outlet and the air heater inlet. A tail end application locates the catalyst
downstream of the particulate and FGD control equipment.
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NOx BACT Analysis
The high dust application requires the SCR system to be located between the
economizer outlet and the air heater inlet in order to achieve the required optimum SCR
operating temperature of approximately 600° to 700° F. This system is subject to high
levels of trace elements and other flue gas constituents that poison the catalyst, as
previously noted. The tail end application of SCR would locate the catalyst downstream
of the particulate control and FGD equipment. Less catalyst volume is needed for the tail
end application, since the majority of the particulate and SO2 (including the trace
elements that poison the catalyst) have been removed. However, a major disadvantage of
this alternative is a requirement for a gas-to-gas reheater and supplemental fuel firing to
achieve sufficient flue gas operating temperatures downstream of the FGD operating at
approximately 125° F. The required gas-to-gas reheater and supplemental firing
necessary to raise the flue gas to the sufficient operating temperature is costly. The higher
front end capital costs and annual operating cost for the tail end systems present higher
overall costs compared to the high dust SCR option with no established emissions control
efficiency advantage. Therefore, this analysis will only consider the use of a high dust
SCR system.
4.1.2
Selective Noncatalytic Reduction System
Selective noncatalytic NOx reduction systems rely on the appropriate reagent
injection temperature and good reagent/gas mixing rather than a catalyst to achieve NOx
reductions. SNCR systems can use either ammonia (Thermal DeNOx) or urea (NOxOUT)
as reagents.
The optimum temperature range for the injection of ammonia or urea is 1,550° to
1,900° F. The NOx reduction efficiency of the SNCR system decreases rapidly at
temperatures outside this range. Injection of reagent below this temperature window
results in excessive ammonia slip emissions. Injection of reagent above this temperature
window results in increased NOx emissions. A pulverized coal boiler operates at
temperatures of between 2,500° and 3,000° F. Therefore, the optimum temperature
window in a pulverized coal boiler occurs somewhere in the backpass of the boiler. To
further complicate matters, this temperature location will change as a function of unit
load. In addition, residence times in this temperature range are very limited, further
detracting from optimum SNCR performance. Finally, there is no provision for
feedforward control of reagent injection, relying only on feedback control. This results in
overinjection of reagent and high ammonia slip emissions.
SNCR systems are less efficient NOx reduction systems than SCR systems. In
general, SNCR systems on large pulverized coal fired boilers will only be capable of up
to 25 percent NOx reduction while maintaining an acceptable ammonia slip. This low
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NOx BACT Analysis
NOx emission reduction and the lack of any operational advantage over a standard SCR
system for a new plant installation prevents this technology from being considered further
in this BACT analysis.
4.2
Step 2--Eliminate Technically Infeasible Options
Step 2 of the BACT analysis involves the evaluation of all the identified available
control technologies in Step 1 of the BACT analysis to determine their technical
feasibility. A control technology is technically feasible if it has been previously installed
and operated successfully at a similar type of source of comparable size, or there is
technical agreement that the technology can be applied to the source. Available and
applicable are the two terms used to define the technical feasibility of a control
technology. From a review of the aforementioned post-combustion NOx control
technologies, it can be concluded that each are technically feasible as control technology
alternatives for the Project’s main boiler. However, since SNCR cannot meet the currentday BACT emissions limit on its own, the SNCR will not be considered further. As such,
only the SCR system will be considered further in the BACT analysis. It should be noted
that the basis for NOx BACT assumes inclusion of LNB and OFA as a fundamental
component of the boiler design. Table 4-1 summarizes the evaluation of the technically
feasible NOx options.
Table 4-1
Summary of Step 2--Eliminate Technically Infeasible Options
Technically Feasible (Yes/No)
Technology Alternative
Available
Applicable
SCR
SNCR
Yes
Yes
Yes
Yes – However, SNCR has limited
NOx removal and will not be
considered further.
4.3
Step 3--Rank Remaining Control Technologies by
Effectiveness
A search of the information contained in the USEPA BACT/LAER Clearinghouse
and other sources specified in Section 2.1 was conducted to determine the top level of
NOx control for pulverized coal boilers. A search was also conducted for recently
permitted coal fired facilities whose BACT determinations have not yet been included in
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NOx BACT Analysis
the current BACT/LAER Clearinghouse database. The results of this search for all coal
fired boilers are listed in Attachment A, Table A-2, of this BACT analysis. Table 4-2
lists the NOx BACT determinations that have the closest attributes when compared to
IPL’s SGS Unit 4, which include fuel type, boiler technology, and size of boiler.
Table 4-2
NOx Top-Down RBLC Clearinghouse Review Results
A review of the NOx BACT determinations in Table 4-2 indicates the following:
•
The most stringent NOx removal permit proposed for a 2 x 980 MW
pulverized coal boiler installation is 0.05 lb/MBtu, based on a 30 day
rolling average at the FPL Glades Power Park located in Florida. The
Glades Power Park proposed site is located approximately 100 miles from
the Everglades National Park (Class I area). The close proximity of the
Class I area and compliance with the stringent criteria were major factors
in FPL proposing the NOx emissions limit. Note, the PSD Air Permit
Application was submitted on December 19, 2006, and the Air Permit
Application remains “incomplete” (SFWMD WRAC Meeting on May 30,
2007, in Clewiston, Florida). LNB and SCR are documented as the
control technology.
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•
The next most stringent NOx removal permit proposed for a 750 MW
pulverized coal boiler installation is 0.05 lb/MBtu, based on a 12 month
rolling average at the LS Power Development, Elk Run Energy Station
located in Iowa. The second part to the NOx emissions limit for Elk Run
is to meet a 0.07 lb/MBtu limit, based on a 30 day rolling average.
•
The most stringent NOx emissions limit in place for a pulverized coal
boiler firing PRB fuel is 0.05 lb/MBtu utilizing LNB and SCR. This
emissions limit has been permitted on 750 and 800 MW units in Texas at
the CPS of San Antonio J.K. Spruce and LS Power Sandy Creek Energy
Stations, respectively. Ozone nonattainment concerns in San Antonio
were the drivers for the low emissions limit in this case, not BACT.
•
There are three other permits that have been permitted with a NOx
removal limit of 0.05 lb/MBtu. All three projects are for pulverized coal
boiler installations that burn a subbituminous coal and have LNB and SCR
as the documented NOx control technology. The following are the three
projects: a 750 MW pulverized coal boiler installation at Western Farmers
Electric Cooperative, Hugo Station located in Oklahoma; a 100 MW
pulverized coal boiler installation at Black Hills Corporation, Wygen 3
located in Wyoming; and a 750 MW pulverized coal boiler installation at
Louisville Gas and Electric Company, Trimble County Generating Station
located in Kentucky. These three projects are very similar to SGS Unit 4.
•
There are four projects with proposed NOx removal limits of
0.06 lb/MBtu (based on a 24 hour rolling average). All four projects are
for pulverized coal boiler installations that burn a subbituminous coal and
have LNB and SCR as the documented NOx control technology. The
following are the four projects: 2 x 750 MW pulverized coal boiler
installation at Sithe Global Desert Rock Power Plant located in New
Mexico; 500 MW pulverized coal boiler installation at BHP Billiton,
Cottonwood Energy Center located in New Mexico; 750 MW pulverized
coal boiler installation at Touquop Energy Project located in Nevada; and
2 x 750 MW pulverized coal boiler installation at Sierra Pacific and
Nevada Power, Ely Energy Center located in Nevada.
•
The next most stringent NOx emissions limit in place for a permitted
pulverized coal boiler firing PRB fuel is 0.067 lb/MBtu (with a 24 hour
rolling average) for TS Power Plant, Newmont Nevada Energy Investment
(200 MW) located in Nevada. It utilizes LNB and SCR as the documented
NOx control technology.
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NOx BACT Analysis
•
The next most stringent NOx emissions limit in place for permitted
pulverized coal boilers is 0.07 lb/MBtu. Table A-2 includes no fewer
than 10 pulverized coal boiler units permitted or proposed at this level.
•
Sunflower’s Holcomb Station Draft air permit, which is proposed,
determined a BACT limit of 0.07 lb/MBtu, on a 30 day rolling average, as
BACT for three 700 MW pulverized coal coal fired units in western
Kansas firing PRB coal and utilizing LNB/OFA and SCR technology.
•
The next most stringent NOx emissions limit in place for a permitted
pulverized coal boiler is 0.08 lb/MBtu for KCP&L’s Hawthorne Power
Station (570 MW). Of the units listed here, based on a review of available
records, the Hawthorne unit is the only one operating and actually
demonstrating compliance with the stated emissions level.
It is important to note that of the NOx emissions limits summarized above (with
the exception of one), none are in actual operation at this time and demonstrating the
stated NOx emissions limits.
Based upon the technologies identified as technically feasible and available in
Steps 1 and 2, the following technologies presented in Table 4-3 are ranked in a “TopDown Approach” methodology.
Table 4-3
Ranking of NOx Control Technologies
Control Option
Control Effectiveness (lb/MBtu)
SCR
0.05 (30 day rolling average)
No other technologies ranked; SCR based upon Steps 1 and 2.
4.4
Step 4--Evaluate Most Effective Controls and Document
Results
In the following subsections, the technically feasible control alternatives are
evaluated in a comparative approach with respect to their energy, environmental, and
economic impacts on IPL SGS Unit 4. The following evaluation is based on an SCR
system.
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NOx BACT Analysis
4.4.1
Energy Evaluation of Alternatives
The SCR system consumes electrical energy for SCR aqueous ammonia transport
and vaporization, as well as for an incremental ID fan demand to overcome the SCR draft
losses due to pressure drop across the catalyst. While the energy costs of postcombustion NOx control are real and quantifiable, they do not in and of themselves
eliminate the control technology from further consideration.
4.4.2
Environmental Evaluation of Alternatives
When considering post-combustion NOx control technologies, there are potential
environmental impacts associated with their direct operation or secondary effects.
Several potential environmental impacts are examined below for post-combustion NOx
control technology systems:
•
Hazardous Waste--The vanadium content of the SCR catalyst may
contribute to its classification as a hazardous waste. Therefore, spent
catalyst may need to be handled and disposed of using appropriate
hazardous waste procedures. As such, recycling of SCR catalysts for
vanadium has become common.
•
Aqueous Ammonia Storage and Ammonia Slip--The use of ammonia in
post-combustion NOx control systems introduces an element of
environmental risk. Additionally, ammonia that is not consumed in the
chemical reaction NOx control process is eventually released from the stack
in a process known as ammonia slip. When catalyst surfaces are relatively
new, ammonia slip will be very low. However, as the catalyst ages and
becomes either deactivated or poisoned, ammonia slip emissions will
gradually increase.
H2SO4--The SCR catalyst oxidizes approximately 2 to 3 percent of the
SO2 in the flue gas to SO3. Once the flue gas cools below 600° F, the
ammonia present in the flue gas may react with SO3 to form ammonium
sulfate and bisulfate salts, thus reducing the H2SO4 to some degree. This
formation may be dependent on the unit’s operating conditions and
particular plume dispersion characteristics at the given time of stack
discharge, which is dependent upon the temperature reached once the flue
gas has left the stack. However, if ammonium sulfate compounds are not
formed, the SO3 will react with the moisture in the flue gas to form H2SO4
in the atmosphere.
•
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•
4.0 Coal Fired Boiler
NOx BACT Analysis
As previously noted in Subsection 4.1.1, the performance and effectiveness of SCR systems are directly dependent on the temperature of the flue
gas when it passes through the catalyst. Vanadium/titanium catalysts have
been used on the majority of SCR system installations. The flue gas
temperature range for optimum SCR operation using a conventional
vanadium/titanium catalyst is approximately 600 to 750° F.
At
temperatures above 800° F, permanent damage to the vanadium/titanium
catalyst can occur. Thus, the environmental impact of an SCR system that
is operating outside of its temperature range is limited or no control of
NOx emissions.
4.4.3
Economic Evaluation of Alternatives
SCR systems represent the top control alternative for the reduction of NOx
emissions from the Project. There are no significant economic impacts that would
preclude the use of an SCR system, as presented in this analysis. As SCR represents the
only viable NOx control technology option and represents the top control alternative, a
comparative economic analysis is not warranted or required by the BACT review
process.
4.5
Step 5--Select NOx BACT
IPL has determined that the top NOx control alternative, LNB/OFA combined
with an SCR system, represents NOx BACT for the Project’s main boiler, corresponding
to an emissions limit of 0.05 lb/MBtu on a 30 day average basis. Table 4-4 summarizes
the Project’s NOx BACT determination for the main boiler.
IPL’s proposed NOx BACT limit is based on engineering evaluation and a review
of various OEM’s technical literature. No literature was found nor engineering
calculations performed that would indicate that co-firing with a biomass blend of
5 percent would change the proposed BACT emissions limit.
Table 4-4
Main Boiler NOx BACT Determination
Control Technology
Emission Limit (lb/MBtu)
SCR
0.05 (30 day rolling average)
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5.0
5.0 Coal Fired Boiler
PM/PM10 BACT Analysis
Coal Fired Boiler PM/PM10 BACT Analysis
This section presents the top-down, five-step BACT process used to evaluate and
determine the Project’s PM/PM10 emissions limit for the main boiler. As this analysis
will demonstrate, the proposed PM/PM10 particulate emissions (filterable) limit of 0.012
lb/MBtu (based on USEPA Test Method 5B) and total (filterable + condensable)
PM/PM10 emissions limit of 0.018 lb/MBtu (based on USEPA Test Method 5B and 202,
with artifact modification including SO3 and VOC) will represent PM/PM10 BACT.
5.1
Step 1--Identify All Control Technologies
The first step in a top-down analysis, according to the EPA’s October 1990, Draft
New Source Review Workshop Manual, is to identify all available control options.
Available control options are those air pollution control technologies or techniques with a
practical potential for application to the emission unit and the PM/PM10 emissions limit
that is being evaluated. There are several pre-combustion and post-combustion
particulate removal systems which have demonstrated performance that is adequate to
reliably achieve BACT-level particulate emissions limits on pulverized coal fired boilers.
These control technologies include the following:
•
Coal washing.
•
DESP.
•
Fabric filter.
•
WESP.
The following subsections describe and evaluate these technologies.
5.1.1
Coal Washing
Pre-combustion control technology such as coal washing can be considered as a
method for reducing particulate emissions. Coal washing utilizes various techniques such
as high speed coal washes or agitating liquids to produce a separation of impurities from
coal.
However, coal washing is not considered a primary control technology for
particulate as the majority of the particulate is inherent in the coal. A complete
discussion of coal washing is included in Subsection 3.1.1.
5.1.2
Dry Electrostatic Precipitator Systems
Initially, DESPs were installed in power plants in the 1950s and 1960s, when 30
to 40 percent plume opacity was considered acceptable. However, these DESPs were
inadequate when later regulations forced some utilities to move to lower sulfur coals with
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PM/PM10 BACT Analysis
high resistivity ash. The existing DESPs, designed for other conditions, were unable to
meet the higher removal efficiencies required. As a result, it was not unusual for coal
fired power plants to suffer reductions in capacity due to excessive particulate emissions
or stack opacity. This lack of performance was not due to the inability of the DESP
technology to meet the high emission control levels required, but was more an issue of
the operating conditions and requirements moving outside of the original design
condition envelope.
Through improvements in the technology and increased sizing, DESPs have
demonstrated increased performance to meet newer regulations. DESPs of the necessary
size and efficiency are available to control emissions from this size of unit. This increase
in performance has allowed DESPs to remain the most widely used particulate removal
technology for large coal fired installations.
DESPs remove particulate by first charging fly ash particles. A utility DESP is
essentially a large enclosure placed in the ductwork between the air heater and the ID
fans. A series of parallel steel plates spaced approximately 12 to 16 inches apart is
located within the DESP. Discharge electrodes made of rigid steel pipe-like shapes or
stretched wires are located between and parallel to the plates. Transformer rectifier (TR)
sets negatively charge the discharge electrodes and positively charge the plates to create a
voltage differential. As the particulate-laden flue gas passes between the plates and the
wires, the ash particles become negatively charged. The particles then migrate to the
positively charged plate, where the ash accumulates. At various frequencies of time,
rapping of the plates removes the accumulated ash from the plates. The impact of the
rapping shears the ash particles from the plate, causing the accumulated ash to fall into
the hopper for collection. The ash handling system can then remove the ash for disposal
or beneficial reuse. However, some of the dust is re-entrained and carried to the next
DESP collection field downstream of the DESP.
DESP collection efficiency and cost are dependent on the DESP size and
characteristics of the fly ash. The ease with which an DESP can collect fly ash is a
function of the particulate and flue gas properties, such as particle size, resistivity, flue
gas temperature, and flue gas composition. Factors such as these, along with flue gas
flow rates and particulate emissions rates, determine the specific collection area or
physical size of an DESP. The definition of specific collection area is the square feet of
collection area per thousand acfm of flue gas treated. Operation also depends on the
accuracy of electrode and plate alignment, uniformity and smoothness of gas flow
through the DESP, rapping of the plates, and the size and electrical stability of the TR
sets.
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PM/PM10 BACT Analysis
A fly ash property that significantly affects the sizing of precipitators is ash
resistivity. When firing subbituminous coals, the resulting fly ash resistivity is high. The
high resistivity significantly deteriorates the DESP efficiency unless properly conditioned
with a flue gas conditioning system or a much larger DESP is sized to control PM/PM10.
When firing bituminous coals, the resulting fly ash resistivity is low which does not
require a flue gas conditioning system or a larger DESP. Resistivity is a measure of how
easily the particulate acquires an electric charge. Fly ash resistivity varies with the
moisture content, chemical composition, and temperature of the ash in the flue gas. The
higher the ash resistivity, the more difficult it is to remove ash from the flue gas with an
DESP. The major coal property affecting the fly ash resistivity for DESPs is the coal
sulfur content. SO3 formed during combustion of the coal coats the fly ash particles and
lowers surface resistivity.
For the IPL SGS Unit 4 (which will fire the Project’s coal alternatives), the design
of the DESP will be severely challenged because of the changes in fly ash characteristics.
While technically feasible, it would be the least desirable technology to be operated on a
coal fired power plant.
5.1.3
Fabric Filter Systems
Fabric filter is a technology design that can meet particulate emissions limits on
many coal fired boilers. Fabric filters use fabric bags as filters to collect particulate. The
particulate-laden flue gas enters a fabric filter compartment and passes through a layer of
particulate and filter bags. The collected particulate forms a cake on the bag, which can
enhance the bag’s filtering efficiency. The pressure drop across the bags increases as the
thickness of the dust cake increases. At a predetermined set point, the filtering bags are
cleaned, dislodging a large portion of the dust cake. These bag cleaning cycles can vary
from every 30 minutes to as long as 6 to 8 hours, depending on ash loading, flue gas flow
rate, filter cake properties, and other operational parameters.
Fabric selection is a very important feature of fabric filter operation. There are
many fibers that can be used effectively as filters, with different properties that determine
their appropriate applications. Several different finishes and textures have been
developed for bag materials in order to increase their use and efficiency in filtration. In
general, fibers can be made into woven or felted fabrics. In utility coal fired fabric filter
applications, PPS felted bags have been used. There are also many coatings and chemical
treatments available to provide lubrication and other properties to fibers to improve their
performance.
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PM/PM10 BACT Analysis
With proper management of the bag life, the fabric filter offers an advantage over
DESP applications. The advantage relates to the characteristics of the fabric filter that
allow low emissions rates to be maintained independent of the wide range of ash
characteristics and the fabric filter characteristics that allow the collected material on the
bags to be contacted with the flue gas more thoroughly and over a longer period of time
as compared to an DESP. This operational advantage is significant when considering the
control of Hg and SO3 emissions when firing two distinctly different coals. Control of
both of these pollutants is shown to be increased in a fabric filter as compared to an
DESP. While just the ash retained on the bags can assist in controlling these pollutants,
the advantage is particularly evident when adsorbents, such as activated carbon, hydrated
lime, or trona, are injected upstream of the fabric filter to aid in the control of these
pollutants. The additional contact time that the fabric filter provides directly relates to
higher control efficiencies at lower adsorbent injection rates.
5.1.4
Wet Electrostatic Precipitator
A WESP collects particles based on the same principle as a DESP; negatively
charged particles are collected on positively charged surfaces. However, a WESP
operates quite differently from a DESP. The collecting surfaces are wet instead of dry
and are flushed with water rather than being rapped to remove the particulate. Typically,
a WESP is installed downstream of an existing wet FGD system where the flue gas is
already saturated, so the amount of added water is minimized. The particulate collection
efficiency is enhanced by a lack of re-entrainment after contact with the wet walls (as
contrasted with re-entrainment during rapping on a DESP). Therefore, the WESP is well
suited for fine particulate or acid mist applications by reducing opacity, sulfuric acid
mist, and other aerosols. It is not well suited for handling uncontrolled particulate
emissions levels from a boiler. The amount of sludge wastewater produced for storage in
that form would not be technically feasible.
The WESP collecting fields impart a negative charge to the particles and collect
them on positively charged collecting electrodes. Each collection field is equipped with
independent electrical bus sections, each having a dedicated high voltage TR and
controller. The controllers for each TR are located in an environmentally controlled
enclosure. Each electrical field has a separate discharge electrode support frame
suspended by alumina insulators. A heater-blower system dedicated to each module
supplies warm purge air for each of the insulator compartments. The discharge electrode
support frames are constructed from stainless steel, and discharge electrodes are
suspended from the upper guide frame and held in the tube center line. The discharge
electrode is a rigid electrode that is constructed from stainless steel and contains split
corona generating elements that are welded to the electrode in an opposed orientation.
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Sutherland Unit 4 Air Permit Application
5.0 Coal Fired Boiler
PM/PM10 BACT Analysis
A WESP can be installed in either horizontal or vertical gas flow orientation. In a
horizontal gas flow orientation, the WESP is very similar to a common DESP. The
collection plates are arranged in parallel horizontal paths with discharge electrodes
hanging between them. Vertical gas flow WESPs are usually of the tubular collection
plate type. The collection plates are arranged in an array of vertical pipes or channels,
with a discharge electrode hanging down the center of the pipe or channel. Channel
shapes, such as squares or hexagons, have more efficient packing densities than circular
pipes (with a small loss in the maximum voltage that can be applied before sparking) and
are more common. When multiple electrical stages are used (analogous to the electrical
fields in a horizontal gas flow DESP), the stages are stacked one above the other. Two to
three fields are common.
Several major hurdles exist with the use of a WESP as a primary filter collection
device. First, the flue gas must be saturated with moisture prior to entering the ESP to
allow the WESP to work correctly. This requires that a quenching system be installed to
add water to the flue gas to reduce the flue gas temperature to the saturation point, or the
WESP needs to be installed downstream of an existing wet FGD system. Secondly, the
WESP adds additional cost, increases water demand on the plant, and generates a visible
moisture plume at the stack outlet. In addition to these issues, the capital cost of a WESP
is very high compared to other technologies due to the higher cost of the alloy materials
required for the WESP. A higher grade of material is required to withstand the highly
corrosive conditions presented by the wet and acidic flue gas stream.
For these reasons, applications rarely find it economically feasible or beneficial to
install a WESP for primary particulate control.
5.2
Step 2--Eliminate Technically Infeasible Options
Step 2 of the BACT analysis involves the evaluation of all the identified available
control technologies in Step 1 of the BACT analysis to determine their technical
feasibility. A control technology is technically feasible if it has been previously installed
and operated successfully at a similar type of source of comparable size, or there is
technical agreement that the technology can be applied to the source. Available and
applicable are the two terms used to define the technical feasibility of a control
technology.
Coal washing is a process that aids in the removal of mineral ash matter. Since
IPL is proposing to utilize various types of coals, the effectiveness of coal washing will
differ greatly. IPL is not aware of large-scale facilities that perform coal washing on
western subbituminous coal, such as PRB, which is considered one of the design coals for
the main boiler. Therefore, the supply of PRB coal that has been washed cannot be
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Sutherland Unit 4 Air Permit Application
5.0 Coal Fired Boiler
PM/PM10 BACT Analysis
considered a reliable source for this Project. Coal washing is determined to be
technically infeasible because PRB coal that has been washed may not be available.
Based on a review of the aforementioned PM/PM10 control technologies, it can be
concluded that both a DESP and fabric filters are technically feasible as control
technology alternatives for the Project’s main boiler. These two technologies will be
considered further in the BACT analysis for primary particulate control. A WESP is
considered technically feasible and available for primary particulate control; however,
WESPs cannot meet the expected BACT performance criteria. As such, the WESP will
not be considered further due to limited particulate control. Table 5-1 summarizes the
evaluation of the technically feasible PM/PM10 options.
Table 5-1
Summary of Step 2--Eliminate Technically Infeasible Options
Technically Feasible (Yes/No)
Technology Alternative
Available
Applicable
Coal Washing
Yes
DESP
Fabric Filter
WESP
Yes
Yes
Yes
No – PRB coal that has been washed
may not be available. Coal washing is
not technically feasible.
Yes
Yes
Yes – However, WESP has limited
particular removal and will not be
considered further.
5.3
Step 3--Rank Remaining Control Technologies by
Effectiveness
A search of the information contained in the USEPA BACT/LAER Clearinghouse
and other sources specified in Section 2.1 was conducted to determine the top level of
PM/PM10 control for pulverized coal boilers. A search was also conducted for recently
permitted coal fired facilities whose BACT determinations have not yet been included in
the current BACT/LAER Clearinghouse database. The results of this search for all coal
fired boilers are listed in Attachment A, Table A-3, of this BACT analysis. As is the
current trend in particulate BACT emissions limits, the review is limited to those sources
that were permitted with both front-half and back-half emissions limits. Table 5-2 lists
the PM/PM10 BACT determinations that have the closest attributes when compared to
IPL’s SGS Unit 4, which include fuel type, boiler technology, and size of boiler.
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
5.0 Coal Fired Boiler
PM/PM10 BACT Analysis
A review of the PM/PM10 BACT determinations in Table 5-2 indicates the
following:
•
PM/PM10 (filterable)--The lowest PM/PM10 (filterable) emissions limit
permitted for a pulverized coal boiler unit is 0.012 lb/MBtu. There are
eight projects that have established 0.012 lb/MBtu as BACT for PM/PM10.
All of the pulverized coal boiler units in the eight projects burn a
subbituminous coal and have a fabric filter as the documented PM/PM10
control technology. The following are the eight projects: a 100 MW
pulverized coal boiler installation at Black Hills Corporation, Wygen 3
located in Wyoming; a 200 MW pulverized coal boiler installation at
Newmont Mining Corporation, TS Power Plant located in Nevada; 3 x
700 MW pulverized coal boilers at Sunflower Electric Power, Holcomb
Power Station located in western Kansas; a 900 MW pulverized coal
boiler installation at Intermountain Service Corporation, Unit 3 located in
Utah; a 500 MW pulverized coal boiler installation at Black Hills
Corporation, Wygen 3 located in Wyoming; a 750 MW pulverized coal
boiler at Xcel Energy, Comanche Station (Unit 3) located in Colorado; a
116 MW pulverized coal boiler at Rocky Mountain Power, Inc., Hardin
Generator Project located in Montana; and a 600 MW pulverized coal
boiler at Otter Tail Power Company located in South Dakota.
•
PM10 (filterable)--The next lowest PM10 (filterable) emissions limit
proposed for a pulverized coal unit firing a PRB coal is 0.012 lb/MBtu at
LS Power Development, Elk Run Energy Station located in Iowa. In
addition, Elk Run proposes the following limits for PM/PM10: PM10
(filterable + condensable) is 0.030 lb/MBtu, PM (filterable) is
0.015 lb/MBtu, and PM (filterable + condensable) is 0.033 lb/MBtu. All
limits for Elk Run are based on a 3 hour average, and a fabric filter is
utilized for PM/PM10 control technology.
•
PM/PM10 (filterable)--The next lowest PM/PM10 (filterable) emissions
limit permitted for pulverized coal boiler units includes several units
ranging from 0.013 to 0.015 lb/MBtu.
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
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PM/PM10 BACT Analysis
Table 5-2
PM/PM10 Top-Down RBLC Clearinghouse Review Results
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Sutherland Unit 4 Air Permit Application
•
5.0 Coal Fired Boiler
PM/PM10 BACT Analysis
PM/PM10 (filterable + condensable)--The lowest PM/PM10 (filterable +
condensable) emissions limit permitted for a pulverized coal unit firing a
PRB coal is 0.018 lb/MBtu, which utilizes a fabric filter for PM/PM10
control technology. This limit was established for at least three projects
including: a 220 MW pulverized coal boiler at Municipal Energy Agency
of Nebraska, Whelan Energy Center located in Nebraska; a 660 MW
pulverized coal boiler at Omaha Public Power District, Nebraska City
Unit 2 located in Nebraska (under construction); and 3 x 700 MW
pulverized coal boilers at Sunflower Electric Power, Holcomb Power Plant
located in Kansas. Sunflower’s Holcomb Station draft air permit
determinations of BACT for PM/PM10 are 0.012 and 0.018 lb/MBtu for
filterable and total (filterable and condensable), respectively, with a fallback limit of 0.035 lb/MBtu (filterable and condensable based on stack
testing).
•
PM/PM10 (filterable + condensable)--The lowest PM/PM10 (filterable +
condensable) emissions limit permitted for a pulverized coal unit firing a
bituminous coal is 0.018 lb/MBtu. This limit was established for the
Santee Cooper, Santee Cooper Cross Generating Station, which has 2 x
660 MW pulverized coal boilers (DESP for control) and Santee Cooper,
Pee Dee Generating Station, which also has 2 x 660 MW pulverized coal
boilers (DESP and fabric filter for control). The two projects listed above
are located in South Carolina. The Santee Cooper Cross Generating
Station has one unit operating (commercial operation in January 2007),
and one unit still under construction.
Based on the technologies identified as technically feasible and available in
Steps 1 and 2, the following technologies presented in Table 5-3 are ranked in a “TopDown Approach” methodology.
5.4
Step 4--Evaluate Most Effective Controls and Document
Results
In the following subsections, the technically feasible control alternatives are
evaluated in a comparative approach with respect to their energy, environmental, and
economic impacts on the Project.
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Sutherland Unit 4 Air Permit Application
5.0 Coal Fired Boiler
PM/PM10 BACT Analysis
Table 5-3
Ranking of PM/PM10 Control Technologies
Control Option
Control Effectiveness (lb/MBtu)
DESP
PM/PM10 (filterable) limit of 0.012 lb/MBtu(1);
PM/PM10 (filterable + condensable) limit of
0.018 lb/MBtu(2)
Fabric Filter
PM/PM10 (filterable) limit of 0.012 lb/MBtu(1);
PM/PM10 (filterable + condensable) limit of
0.018 lb/MBtu(2)
(1)
The test method for the associated limit is based on USEPA Test Method 5B.
The test method for the associated limit is based on USEPA Test Method 5B and
202, with artifact modification including SO3 and VOC.
(2)
5.4.1
Energy Evaluation of Alternatives
A disadvantage of a fabric filter is the higher pressure drop through the filter,
resulting in increased fan power and energy requirements. However, this additional
energy requirement of the fabric filter is generally offset by, or less than that required by,
the TR sets and hopper heaters of an DESP. The fabric filter does provide a small
advantage for startup operations in that the DESP cannot control emissions until the flue
gas and DESP temperatures are within operating ranges.
5.4.2
Environmental Evaluation of Alternatives
There are no environmental impacts that would preclude the use of fabric filters
or DESP to control the Project’s emissions of PM/PM10.
5.4.3
Economic Evaluation of Alternatives
An economic evaluation and cost comparison of the technically feasible
alternative control technologies identified in Section 5.3 (Step 3) are presented below for
the following top control options:
•
DESP.
•
Fabric filter.
The cost estimates are based on budgetary quotes from equipment manufacturers
and engineering cost estimates in accordance with the USEPA’s Office of Air Quality
Planning and Standards (OAQPS) Control Cost Manual.
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
5.0 Coal Fired Boiler
PM/PM10 BACT Analysis
Tables 5-4 and 5-5 present the total capital investment for the installation of a
fabric filter or DESP on the Project’s main boiler, respectively. As described in the
tables, the purchased equipment cost includes the respective particulate control
technologies, ash handling systems, ductwork, and fans differential. The direct
installation costs, which include balance-of-plant items such as foundations and supports,
handling and erection, electrical, piping, insulation, and paint, were calculated as a
percentage of the purchased equipment cost and totaled with the purchased equipment
cost to estimate the total direct costs of each control alternative. Finally, the total capital
investment was calculated as the summation of the total direct costs and total indirect
costs (including engineering and owner’s costs) and an allowance for funds used during
construction.
Tables 5-4 and 5-5 also present the annualized operating costs for the installation
of an DESP or fabric filter on the Project’s main boiler. As described in the tables, the
operating fixed and variable direct annual costs include operating labor, maintenance
labor and materials, bag and cage replacement costs, and auxiliary and ID fan power
costs. The indirect annual costs, which include the capital recovery costs, are totaled
with the direct annual costs to estimate the total annual costs for the control system.
5.5
Step 5--Select PM/PM10 BACT
IPL has determined that the top control of a fabric filter represents PM/PM10
BACT for the Project’s main boiler. Table 5-6 summarizes the top-down evaluation of
the PM/PM10 control alternatives, including economic, energy, and environmental
considerations, in accordance with the BACT determination methodology previously
discussed.
Since both the DESP and fabric filter meet the top-ranked control technology
emissions limit, the decision to select the fabric filter alternative considers the added
potential for additional SO3 and Hg removal, as previously described. In addition, the
fabric filter has the lowest annualized cost. The total capital investment to install the
DESP and the fabric filter technology on the Project’s main boiler is shown in Tables 5-4
and 5-5, respectively.
Therefore, IPL proposes a fabric filter and PM/PM10 particulate emissions
(filterable) limit of 0.012 lb/MBtu (based on USEPA Test Method 5B) and total
(filterable + condensable) PM/PM10 emissions limit of 0.018 lb/MBtu (based on USEPA
Test Method 5B and 202, with artifact modification including SO3 and VOC) as BACT
for the Project, which is equivalent to the most stringent level in the RBLC for pulverized
coal fired boilers of similar operation and size.
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Sutherland Unit 4 Air Permit Application
5.0 Coal Fired Boiler
PM/PM10 BACT Analysis
Table 5-4
Fabric Filter Engineering Analysis - Cost Analysis
Technology:
Date: 6/29/2007
Fabric Filter
Cost Item
$
CAPITAL COST
Direct Costs
Purchased equipment costs
Fabric Filter System
Initial FF bag inventory
Ash handling system
ID fan upgrades
Flue gas ductwork
Instrumentation and controls
Subtotal capital cost (CC)
Taxes
Freight
Total purchased equipment cost (PEC)
$16,280,000
$1,641,000
$1,016,000
$1,964,000
$4,417,000
$323,000
$25,641,000
$1,795,000
$1,282,000
$28,718,000
Direct installation costs
Foundation & supports
Handling & erection
Electrical
Piping
Insulation
Painting
Demolition
Relocation
Total direct installation costs (DIC)
Site preparation
Total direct costs (DC) = (PEC) + (DIC)
Indirect Costs
Engineering
Owner's cost
Construction management
Start-up and spare parts
Performance test
Contingencies
Total indirect costs (IC)
Allowance for Funds Used During Construction (AFDC)
Total Capital Investment (TCI) = (DC) + (IC)
ANNUAL COST
Direct Annual Costs
Fixed annual costs
Maintenance labor and materials
Total fixed annual costs
Variable annual costs
Byproduct disposal
Bag replacement cost
Cage replacement cost
ID fan power
Auxiliary power
Total variable annual costs
Total direct annual costs (DAC)
Indirect Annual Costs
Cost for capital recovery
Total indirect annual costs (IDAC)
Total Annual Cost (TAC) = (DAC) + (IDAC)
102607-145491
Remarks/Cost Basis
(CC) X
(CC) X
7.0%
5.0%
$4,308,000
$2,872,000
$2,872,000
$718,000
$574,000
$144,000
$0
$3,000
$11,491,000
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
15.0%
10.0%
10.0%
2.5%
2.0%
0.5%
0.00%
0.01%
$200,000
$40,409,000
Engineering estimate
$4,849,000
$1,212,000
$4,041,000
$1,212,000
$81,000
$6,061,000
$17,456,000
(DC) X
12.0%
(DC) X
3.0%
(DC) X
10.0%
(DC) X
3.0%
Engineering es 0.2%
(DC) X
15.0%
$7,117,000
[(DC)+(IC)] X 8.20%
3 years (project time length)
$64,982,000
$1,212,000
$1,212,000
(DC) X
$2,862,000
$859,000
$179,000
$1,328,000
$551,000
$2,917,000
3.0%
29.7
21,469
21,469
2,384
988
tph and
bags and
cages and
kW and
kW and
11
120
50
0.06
0.06
$/ton
$/bag
$/cage
$/kWh
$/kWh
3 yr bag replacement rate
6 yr cage replacement rate
6 in. H2O d.p.
Engineering estimate
$4,129,000
$6,134,000
$6,134,000
(TCI) X
9.44%
CRF at 7% interest & 20 year life
$10,263,000
5-12
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
5.0 Coal Fired Boiler
PM/PM10 BACT Analysis
Table 5-5
DESP Engineering Analysis - Cost Analysis
Technology:
Date:
Electrostatic Precipitator (ESP)
Cost Item
$
CAPITAL COST
Direct Costs
Purchased equipment costs
ESP
Ash handling system
ID fan
Flue gas ductwork
Subtotal capital cost (CC)
Instrumentation and controls
Taxes
Freight
Total purchased equipment cost (PEC)
$13,860,000
$1,009,000
$1,228,000
$3,413,000
$19,510,000
$390,000
$1,366,000
$976,000
$22,242,000
Direct installation costs
Foundation & supports
Handling & erection
Electrical
Piping
Insulation
Painting
Demolition
Relocation
Total direct installation costs (DIC)
Site preparation
Total direct costs (DC) = (PEC) + (DIC)
Indirect Costs
Engineering
Owners Cost
Construction and field expenses
Contractor fees
Start-up
Performance test
Contingencies
Total indirect costs (IC)
Allowance for Funds Used During Construction (AFDC)
Total Capital Investment (TCI) = (DC) + (IC)
ANNUAL COST
Direct Annual Costs
Fixed annual costs
Maintenance labor and materials
Total fixed annual costs
Variable annual costs
Byproduct disposal
ID fan power
Auxiliary power
Total variable annual costs
Total direct annual costs (DAC)
Indirect Annual Costs
Cost for capital recovery
Total indirect annual costs (IDAC)
Total Annual Cost (TAC) = (DAC) + (IDAC)
102607-145491
Remarks
(CC) X
(CC) X
(CC) X
2.0%
7.0%
5.0%
$3,336,000
$2,224,000
$4,448,000
$556,000
$445,000
$111,000
$0
$2,000
$11,122,000
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
15.0%
10.0%
20.0%
2.5%
2.0%
0.5%
0.00%
0.01%
$200,000
$33,564,000
Estimate
$4,028,000
$1,007,000
$3,356,000
$3,356,000
$1,007,000
$67,000
$5,035,000
$17,856,000
(DC) X
(DC) X
(DC) X
(DC) X
(DC) X
(DC) X
(DC) X
12.0%
3.0%
10.0%
10.0%
3.0%
0.2%
15.0%
[(DC)+(IC)] X
8.20%
$6,325,000
6/29/2007
3 years (project time length)
$57,745,000
$2,155,000
$2,155,000
from CUECost
$2,862,000
$664,000
$320,000
$3,846,000
29.7 tph and
1,192 kW and
575 kW and
11 $/ton
0.06 $/kWh
0.06 $/kWh
3 in. H2O d.p.
Engineering estimate
$6,001,000
$5,451,000
$5,451,000
(TCI) X
9.44%
CRF at 7% interest & 20 year life
$11,452,000
5-13
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
5.0 Coal Fired Boiler PM/PM10 BACT Analysis
Table 5-6
Particulate Matter
Top-Down BACT Summary
Emissions
Emissions,
lb/h
Emissions
Reduction,
tpy
Total
Capital
Cost,
$1,000
Total
Annualized
Cost,
$1,000/yr
Control CostEffectiveness,
$/ton
Fabric Filter
(0.012 lb/MBtu)
74
192,137
64,982
10,263
DESP
(0.012 lb/MBtu)
74
192,137
57,745
43,941
--
--
Control
Alternative
Uncontrolled
Baseline
102607-145491
Energy
Impacts
Economic Impacts
Incremental
CostEffectiveness,
$/ton
Environmental Impacts
Incremental
Increase Over
Baseline,
kWh/yr
Toxic
Impacts
(Yes/No)
Adverse
Environmental
Impacts
(Yes/No)
53
29,542,439
No
No
11,452
60
14,144,681
No
No
--
--
--
--
--
--
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5.0 Coal Fired Boiler
PM/PM10 BACT Analysis
It should also be noted that the majority of issued permits in the RBLC do not
properly account for condensable artifacts such as ammonia slip, SO3, and VOC. These
artifacts exist i nthe vapor phase until exiting the stack, rendering them uncontrollable by
the primary particulate control device such as a fabric filter or DESP. In fact, the test
methods currently promulgated will actually form particulate that would otherwise exist
as vapor in the back half train of the reference methods. Table 5-7 summarizes the
Project’s PM/PM10 BACT determination for the main boiler.
IPL’s proposed PM/PM10 BACT limit is based on engineering evaluation and a
review of various OEM’s technical literature. No literature was found nor engineering
calculations performed that would indicate that co-firing with a biomass blend of
5 percent would change the proposed BACT emissions limit.
Table 5-7
Main Boiler PM/PM10 BACT Determination
Control Technology
Emission Limit (lb/MBtu)
Fabric Filter
PM/PM10 (filterable) limit of 0.012 lb/MBtu(1);
PM/PM10 (filterable + condensable) limit of
0.018 lb/MBtu(2)
(1)
The test method for the associated limit is based on USEPA Test Method 5B.
The test method for the associated limit is based on USEPA Test Method 5B
and 202, with artifact modification including SO3 and VOC.
(2)
As indicated in Subsection 2.1.1.1 NSPS Subpart Da – Standards of Performance
for Electric Utility Steam Generating Units for Which Construction is Commenced After
September 18, 1978, the visible emission (opacity) limit for the main boiler is to not
discharge into the atmosphere any gases that exhibit greater than 20 percent opacity
(6 minute average), except for one 6 minute period per hour of not more than 27 percent
opacity. A search of the information contained in the USEPA BACT/LAER
Clearinghouse and other sources specified in Section 2.1 was conducted to determine the
top level of visible emission control for pulverized coal boilers. The results of the review
indicated the following:
•
The lowest emission limit currently in place for a PC boiler is 10 percent
opacity (6 minute average) with a 20 percent opacity (6 minute average)
for shutdown for the Comanche Station (Unit 3), Public Service Company
of Colorado (Permitted: July 5, 2005) located in Colorado. The control
technology was listed as fabric filter.
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•
5.0 Coal Fired Boiler
PM/PM10 BACT Analysis
The next lowest emission limit currently in place for a PC boiler is 10
percent opacity (6 minute average) for the Gascoyne Generating Station,
Montana Dakota Utilities (Permitted: June 3, 2005) located in North
Dakota. The control technology was listed as fabric filter.
•
The next lowest emission limit currently in place for a PC boiler is
10 percent opacity (6 minute average) for Maidsville, Longview Power,
LLC (Permitted: March 6, 2005) located in West Virginia. The control
technology was listed as dry solid injection with fabric filter and wet
scrubber.
Further review of the informational databases discussed in Section 2.1 indicated
that PC boilers have not been required to install additional visible emission controls
because the particulate matter control equipment ensures the control of opacity. IPL
proposes a fabric filter and a visible emission limit of 10 percent opacity (6 minute
average) based on continuous opacity monitoring system (COMS) as BACT for the
Project, which is equivalent to the most stringent level in the RBLC for pulverized coal
fired boilers of similar operation and size. Table 5-8 summarizes the Project’s visible
emission BACT determination for the main boiler.
IPL’s proposed visible emission BACT limit is based on engineering evaluation
and a review of various OEM’s technical literature. No literature was found nor
engineering calculations performed that would indicate that co-firing with a biomass
blend of 5 percent would change the proposed BACT emissions limit.
Table 5-8
Main Boiler Visible Emission (Opacity) BACT Determination
Control Technology
Emission Limit (% Opacity)
Fabric Filter
10(1)
(1)
6 minute average based on a continuous opacity monitoring system (COMS).
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6.0
6.0 Coal Fired Boiler CO
and VOC BACT Analysis
Coal Fired Boiler CO and VOC BACT Analysis
This section presents the top-down, five-step BACT process used to evaluate and
determine the Project’s CO and VOC emissions limits for the main boiler. CO and VOC
emissions are related as products of incomplete combustion and, as such, are addressed
together in this control technology determination. As this analysis will demonstrate, the
proposed CO and VOC BACT limits for the Project’s main boiler are emissions limit of
0.12 lb/MBtu and 0.0034 lb/MBtu, respectively.
6.1
Step 1--Identify All Control Technologies
The first step in a top-down analysis, according to the USEPA’s October 1990,
Draft New Source Review Workshop Manual, is to identify all available control options.
Available control options are those air pollution control technologies or techniques with a
practical potential for application to the emission unit and the CO and VOC emission
limits that are being evaluated. CO and VOC related compounds (generally expressed as
non-methane hydrocarbons) are formed during the combustion process as a result of the
incomplete oxidation of the carbon contained in the fuel; or simply, they are the products
of incomplete combustion. The following subsections review the CO and VOC control
technologies.
6.1.1
Good Combustion Controls
As products of incomplete combustion, CO and VOC emissions are very
effectively controlled by ensuring the complete and efficient combustion of the fuel in the
boiler (i.e., good combustion controls). Typically, measures taken to minimize the
formation of NOx during combustion inhibit complete combustion, which increases the
emissions of CO and VOC. High combustion temperatures, adequate excess air, and
good air/fuel mixing during combustion minimize CO and VOC emissions. These
parameters also increase NOx generation, in accordance with the conflicting goals of
optimum combustion to limit CO and VOC, but lower combustion temperatures to limit
NOx. The products of incomplete combustion are substantially different and often less
pronounced when the unit is firing high sulfur bituminous coals, which is the rationale for
the slightly higher BACT emissions limits found on units permitted to burn low sulfur
PRB subbituminous coals. In addition, depending on the manufacturer, good combustion
controls vary in terms of meeting CO emissions limits.
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6.0 Coal Fired Boiler CO
and VOC BACT Analysis
6.1.2
Oxidation Catalysts
This control process utilizes a platinum/vanadium catalyst that oxidizes CO to
CO2 and VOC to CO2 and water. The process is a straight catalytic oxidation/reduction
reaction requiring no reagent. Catalytic CO and VOC emissions reduction methods have
been proven for use on natural gas and oil fueled combustion turbine sources, but not coal
fired boilers. The primary technical challenge for including an oxidation catalyst on a
coal fired boiler is the location of the catalyst in a high temperature regime, which would
most likely be prior to the economizer. This location, along with the potential fouling
effects of the flue gas, would render the catalyst ineffective on even a short-term basis.
6.2
Step 2--Eliminate Technically Infeasible Options
Step 2 of the BACT analysis involves the evaluation of all the identified available
control technologies in Step 1 of the BACT analysis to determine their technical
feasibility. A control technology is technically feasible if it has been previously installed
and operated successfully at a similar type of source of comparable size, or there is
technical agreement that the technology can be applied to the source. Available and
applicable are the two terms used to define the technical feasibility of a control
technology.
The application of an oxidation catalyst to a coal fired boiler presents many
substantial challenges that render this control technology not technically feasible for
further consideration as a control alternative for CO and VOC. A review of the RBLC
reveals that the database contains no record of add-on control equipment for the control
of CO and VOC, and IPL is not aware of this control technology having ever been
applied to a solid fuel boiler. Technical challenges that render an oxidation catalyst
control technically infeasible for this Project include the following:
•
The oxidation catalyst will not only oxidize CO and VOC, but will also
oxidize a predominant portion of SO2 to SO3. The combination of this
SO3 with SCR-related ammonia injection will likely result in the quick
fouling of the air heater.
•
Acid gases and trace metals in the flue gas from the combustion of solid
fuel will quickly poison the catalyst, making the control technology
ineffective in its intended role.
Good combustion controls are considered technically feasible for the control of
CO and VOC and are considered further in the BACT analysis.
CO catalyst is
eliminated from further consideration. Table 6-1 summarizes the evaluation of the
technically feasible CO and VOC options.
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and VOC BACT Analysis
Table 6-1
Summary of Step 2--Eliminate Technically Infeasible Options
Technically Feasible (Yes/No)
Technology Alternative
Available
Applicable
Good Combustion Controls
Oxidation Catalyst
Yes
Yes
Yes
No – There are no documented
installations on coal fired pulverized
coal boilers that demonstrate it as a
viable option.
6.3
Step 3--Rank Remaining Control Technologies by
Effectiveness
A search of the information contained in the USEPA BACT/LAER Clearinghouse
and other sources specified in Section 2.1 was conducted to determine the top level of CO
and VOC control for pulverized coal boilers. A search was also conducted for recently
permitted coal fired facilities whose BACT determinations have not yet been included in
the current BACT/LAER Clearinghouse database. The results of this search for all coal
fired boilers are listed in Attachment A, Tables A-4 and A-5, of this BACT analysis. As
previously discussed, CO and VOC emissions, as products of incomplete combustion, are
by their nature a function of the specific boiler type and the fuel characteristics, and are
thus reflected in the emissions guarantees that vendors are willing to make. As such, the
following review is limited to those CO and VOC determinations made for pulverized
coal boilers firing low sulfur PRB coal. Table 6-2 lists the CO BACT determinations,
which have the closest attributes when compared to IPL’s SGS Unit 4, that include fuel
type, boiler technology, and size of boiler.
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and VOC BACT Analysis
Table 6-2
CO Top-Down RBLC Clearinghouse Review Results
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6.0 Coal Fired Boiler CO
and VOC BACT Analysis
A review of the CO BACT determinations in Table 6-2 indicates the following:
•
CO:
−
The most stringent CO emissions limit proposed for a pulverized
coal boiler unit firing bituminous or subbituminous coal is at a
level of 0.10 lb/MBtu.
There are five projects that have
established 0.10 lb/MBtu as BACT for CO. All of the pulverized
coal boiler units at the five projects propose to utilize good
combustion controls as the documented CO control technology.
The following are the five projects: a 750 MW pulverized coal
boiler installation at Louisville Gas and Electric Company,
Trimble County Generating Station located in Kentucky; 2 x
750 MW pulverized coal boiler installations at Peabody Energy,
Thoroughbred Generating Station located in Kentucky; 2 x
750 MW pulverized coal boiler installation at Sithe Global Desert
Rock Power Plant located in New Mexico; 750 MW pulverized
coal boiler installation at Touquop Energy Project located in
Nevada; and 2 x 750 MW pulverized coal boiler installation at
Sierra Pacific and Nevada Power, Ely Energy Center located in
Nevada.
−
The next most stringent CO emissions limit permitted to date for a
pulverized coal boiler (600 MW) firing a bituminous coal at a level
of 0.11 lb/MBtu is Longview Power, LLC, Maidsville Plant
located in West Virginia.
−
The next most stringent CO emissions limit permitted to date for a
pulverized coal boiler (2 x 615 MW) firing a subbituminous coal at
a level of 0.12 lb/MBtu is Wisconsin Energy, Elm Road
Generating Station located in Wisconsin.
−
The next most stringent CO emissions limit permitted to date for a
pulverized coal boiler (750 MW) firing a subbituminous coal at a
level of 0.13 lb/MBtu is Xcel Energy, Comanche Station Unit 3
located in Colorado.
−
The next most stringent CO emissions limits permitted to date for
a pulverized coal boiler firing a subbituminous coal at levels of
0.135, 0.14, and 0.14 lb/MBtu are for Louisiana Generating (Big
Cajun II), KCP&L (Iatan 2), and BHP Billiton (Cottonwood
Energy), respectively.
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−
6.0 Coal Fired Boiler CO
and VOC BACT Analysis
The next most stringent CO emissions limits proposed to date for
a pulverized coal boiler (750 MW) firing a subbituminous coal at a
level of 0.15 lb/MBtu is LS Power Development, Elk Run Energy
Station located in Iowa. The limit is based on a 30 day rolling
average.
−
The next most stringent CO emissions limit permitted to date for a
pulverized coal boiler firing PRB fuel is at a level of 0.15 lb/MBtu
for several units identified in Table A-4, including Municipal
Energy Agency of Nebraska, Whelan Energy Center, and
Newmont TS Power Plant. Sunflower’s Holcomb Units are also
permitted at this level, although they are proposed as SCPC
boilers.
Table 6-3 lists the VOC BACT determinations that have the closest attributes
when compared to IPL’s SGS Unit 4, which include fuel type, boiler technology, and size
of boiler.
A review of the VOC BACT determinations in Table 6-3 indicates the following:
•
VOC:
−
The most stringent VOC emissions limit proposed for a pulverized
coal unit firing a bituminous coal is 0.0024 lb/MBtu. Ozone
nonattainment concerns are the drivers for this LAER
determination. This limit was established for the Santee Cooper,
Santee Cooper Cross Generating Station, which has 2 x 660 MW
pulverized coal boilers (good combustion controls) and Santee
Cooper, Pee Dee Generating Station, which also has 2 x 660 MW
pulverized coal boilers (good combustion controls). The two
projects listed above are located in South Carolina. The Santee
Cooper Cross Generating Station has one operating unit
(commercial operation date in January 2007) and one unit still
under construction. It is unknown if the Santee Cooper Cross
Generating Station demonstrated compliance with 0.0024 lb/MBtu.
−
The most stringent VOC emissions limit currently permitted for a
PRB pulverized coal application is 0.0025 lb/MBtu on a 750 MW
boiler at CPS Energy’s J.K. Spruce Unit in Texas. Ozone
attainment concerns in San Antonio are the drivers for the low
emission limits in this case, not BACT.
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and VOC BACT Analysis
Table 6-3
VOC Top-Down RBLC Clearinghouse Review Results
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6.0 Coal Fired Boiler CO
and VOC BACT Analysis
−
The next most stringent VOC emissions limit currently permitted
for a subbituminous/bituminous blend coal pulverized coal
application is 0.0027 lb/MBtu on a 900 MW boiler at
Intermountain Power Service Corporation, Intermountain Power
Station Unit 3 in Utah.
−
The next most stringent VOC emissions limit for a PRB coal
pulverized coal application is 0.0030 lb/MBtu on the cancelled
Bull Mountain Project.
−
The next most stringent VOC emissions limit currently permitted
for a subbituminous/bituminous blend coal pulverized coal
application is 0.0032 lb/MBtu on a 750 MW boiler at Louisville
Gas and Electric Company, Trimble County Generating Station
located in Kentucky.
−
The next most stringent VOC emissions limit currently permitted
for a PRB coal pulverized coal application is 0.0034 lb/MBtu on
the Centennial Hardin Power Project in Montana and Omaha
Public Power District’s Nebraska City Unit 2.
−
The next most stringent VOC emissions limit proposed is
0.0035 lb/MBtu for Sunflower’s Holcomb Station Draft permit,
Elk Run Energy Station, Comanche Station, and Wisconsin
Energy’s Oak Creek Power Plant.
−
Other recent stringent VOC emissions limits permitted to date at a
level of 0.0036 lb/MBtu include a 790 MW plant located at the
MidAmerican Energy Co., Council Bluffs facility in Council
Bluffs, Iowa. All of the previously listed units limit VOC
emissions through the use of good combustion controls.
Based on the technologies identified as technically feasible and available in
Steps 1 and 2, the following technologies presented in Table 6-4 are ranked in a “TopDown Approach” methodology.
6.4
Step 4--Evaluate Most Effective Controls and Document
Results
In the following subsections, the technically feasible control alternatives are
evaluated in a comparative approach with respect to their energy, environmental, and
economic impacts on the Project.
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and VOC BACT Analysis
Table 6-4
Ranking of CO/VOC Control Technologies
Control Effectiveness
Control Option
CO (lb/MBtu)
VOC (lb/MBtu)
Good Combustion Controls
0.12
0.0034
No other technologies ranked, but good combustion controls are based on
Step 2.
6.4.1
Energy Evaluation of Alternatives
There are no significant energy impacts that would preclude the use of good
combustion controls to limit the emissions of CO and VOC.
6.4.2
Environmental Evaluation of Alternatives
As previously discussed, the typical good combustion control measures taken to
minimize the formation of CO and VOC, namely higher combustion temperatures,
additional excess air, and optimum air/fuel mixing during combustion are often
counterproductive to the control of NOx emissions during combustion. A proper balance
of this phenomenon is a necessary task in obtaining and complying with the
manufacturer’s guarantees, since overly aggressive CO and VOC limits can jeopardize
NOx emissions design considerations.
6.4.3
Economic Evaluation of Alternatives
Since there is only one feasible control technology to limit the emissions of CO
and VOC from the Project’s main boiler, a comparative cost analysis is not applicable.
6.5
Step 5--Select CO and VOC BACT
IPL has determined that good combustion controls represent CO and VOC BACT
for the Project’s main boiler. Consistent with the top control identified in Section 6.3,
IPL proposes a CO BACT emissions limit of 0.12 lb/MBtu and a VOC BACT emissions
limit of 0.0034 lb/MBtu. The proposed BACT levels are based on the units
demonstrating compliance with the evaluated BACT emissions level for a similar type
boiler and fuel as discussed in Section 6.3, as well as expected manufacturer’s guarantee
levels. Table 6-5 summarizes the Project’s CO and VOC BACT determinations for the
main boiler, based on an 8 hour and 3 hour test run averaging period, respectively.
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6.0 Coal Fired Boiler CO
and VOC BACT Analysis
Table 6-5
Main Boiler CO/VOC BACT Determinations
Emission Limit (lb/MBtu)
Control Technology
CO
VOC
Good Combustion Controls
0.12
0.0034
IPL’s proposed CO and VOC BACT limits are based on engineering evaluation
and a review of various OEM’s technical literature. No literature was found nor
engineering calculations performed that would indicate that co-firing with a biomass
blend of 5 percent would change the proposed BACT emissions limit.
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7.0
7.0 Coal Fired Boiler Sulfuric
Acid Mist BACT Analysis
Coal Fired Boiler Sulfuric Acid Mist BACT Analysis
This section presents the top-down, five-step BACT process used to evaluate and
determine the Project’s H2SO4 emission limit for the main boiler. As this analysis will
demonstrate, the proposed H2SO4 BACT limit for the Project’s main boiler is an
emissions limit of 0.004 lb/MBtu (based on Controlled Condensate Test Method).
7.1
Step 1--Identify All Control Technologies
The first step in a top-down analysis, according to the EPA’s October 1990, Draft
New Source Review Workshop Manual, is to identify all available control options.
Available control options are those air pollution control technologies or techniques with a
practical potential for application to the emission unit and the sulfuric acid mist emission
limit that is being evaluated. Sulfuric acid is present in the flue gases generated from the
combustion of coal, because a small fraction of the SO2 produced is further oxidized to
SO3. SO3 reacts with water in the flue gas to form sulfuric acid vapor. Sulfuric acid can
cause air heater fouling and equipment corrosion downstream, and when the flue gas
containing sulfuric acid vapor is cooled, it condenses to form a submicron aerosol mist as
it is emitted to the atmosphere.
In addition to the SO3 formed during combustion, SCR catalysts used for NOx
control further oxidize a fraction of SO2 to SO3. The combination of furnace and SCR
oxidation has the capability to produce significant quantities of SO3. In addition, the SO3
content in the furnace exit gas can limit SCR operation at lower unit loads because of the
lower flue gas temperatures that result from the low load operation. The potential to form
ammonium sulfate salts that will foul active catalyst sites increases at the lower
economizer outlet flue gas temperatures.
Effective controls for H2SO4 include only post-combustion controls and include
lime-based semi-dry scrubbers, wet FGDs, wet ESPs, and alkali injection systems. These
control technology alternatives are described below.
7.1.1
Wet and Semi-Dry Lime-Based FGD Systems
Semi-dry FGD systems were discussed in detail, along with their consideration as
SO2 control alternatives, in Subsection 3.1.3. Historically, semi-dry scrubbers, in
combination with fabric filters, have been determined as the top BACT control
technology for H2SO4 for similar sized boilers using the same fuels as this Project. The
gas temperature leaving a lime-based semi-dry scrubber is lowered below the sulfuric
acid dew point, and significant SO3 removal is attained as the condensed acid reacts with
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Acid Mist BACT Analysis
the alkaline reagent and fly ash. By removing SO3 in the flue gas in this process, H2SO4
is effectively controlled.
The wet lime FGD processes were previously described, along with their
considerations as SO2 control alternatives in Subsection 3.1.2. As discussed, a wet FGD
is typically installed downstream of a pulverized coal boiler and is usually the last control
device for any emissions control before exiting the stack. The JBR described in
Subsection 3.1.1.3 includes other added benefits, such as the removal of condensed SO3.
The gypsum crystals produced in a JBR have a relatively larger size distribution, since
there is less attrition due to circulation through slurry recycle spray pumps. Also, the
JBR’s ability to remove more than 80 percent of the fine (less than 10 μm) particulate
matter from the flue gas is substantially better than conventional spray absorbers. This
increased particulate removal directly increases the removal of condensed SO3 from the
system compared to most other competing wet scrubber designs, which remove virtually
no SO3. SO3 is formed during combustion and will react with the moisture in the flue gas
to form H2SO4 mist in the atmosphere. An increase in H2SO4 emissions will increase
PM10 emissions. The gas temperature leaving the reactor is lowered below the sulfuric
acid dew point and significant SO3 removal will be attained as the condensed acid reacts
with the alkaline reagent.
It should be noted that of recently, Alstom is developing a proprietary “Integrated
AQCS” system which combines a SDA/FF with a downstream wet FGD. Both of the
components, wet FGD and SDA have been used separately on many installations.
However, the separate systems have not been combined together for an AQCS integrated
solution. The primary requirement for the system to be viable will be the ability to route
the purge stream from the Wet FGD to the SDA to eliminate waste water treatment which
has not been demonstrated in practice.
As previously discussed, a wet FGD system has been determined as BACT for
SO2. Normally, an SDA is not included as part of the air quality control system when
SO2 control is being accomplished by a wet FGD or other control device.
7.1.2
Wet Electrostatic Precipitator
The WESP process is described in some detail, along with its consideration as a
PM/PM10 control alternative, in Subsection 5.1.4. In high sulfur coal applications, the
addition of a WESP is a feasible control alternative that allows sulfuric acid mist to
condense and be collected as particulate or absorbed into the water stream along the
charged collection surfaces.
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Acid Mist BACT Analysis
7.1.3
Sorbent Injection Systems
Injection of finely divided alkalis into the flue gas has been demonstrated for the
removal of SO3 from flue gases. Most commercial experience is from units firing high
sulfur oil where trace metals, mainly vanadium, increase SO2 oxidation. Magnesiumbased compounds have been used successfully for decades to capture SO3 in oil fired
units. As coal fired units burning high sulfur bituminous coals have been retrofitted with
SCR systems (primarily in the east), interest in the injection of alkali compounds directly
into the flue gas duct of a unit has increased. Sorbents such as sodium bisulfite, trona,
and hydrated lime have recently been tested on large coal fired units, with reported
results showing the achievement of high control efficiencies of SO3 in high sulfur
applications.
7.2
Step 2--Eliminate Technically Infeasible Options
Step 2 of the BACT analysis involves the evaluation of all the identified available
control technologies in Step 1 of the BACT analysis to determine their technical
feasibility. A control technology is technically feasible if it has been previously installed
and operated successfully at a similar type of source of comparable size, or there is
technical agreement that the technology can be applied to the source. Available and
applicable are the two terms used to define the technical feasibility of a control
technology.
From a review of the aforementioned H2SO4 control technologies, it can be
concluded that alkali injection systems and WESP are technically feasible as control
technology alternatives for the Project’s main boiler. As such, each will be considered
further in the BACT analysis. A dry FGD system is considered technically feasible and
applicable for this Project; however, a wet FGD is proposed as SO2 BACT. As discussed
in Subsection 7.1.1, Alstom is developing a proprietary “Integrated AQCS” system that
combines a SDA/FF with a downstream wet FGD. This arrangement of control
equipment has not yet reached the licensing and commercial sales stage of development
for a similar size of unit as the Project. Therefore, a dry FGD system with a wet lime
FGD process is not considered technically feasible. In addition, the requirements to
handle both lime and limestone on the same site, as well as additional nonsaleable grade
of ash, would make this system combination (dry and wet FGD) environmentally and
economically not a good choice. Table 7-1 summarizes the evaluation of the technically
feasible H2SO4 options.
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Acid Mist BACT Analysis
Table 7-1
Summary of Step 2--Eliminate Technically Infeasible Options
Technically Feasible (Yes/No)
Technology Alternative
Available
Applicable
FF/Wet FGD/WESP
FF/Wet FGD/FF with Sorbent
Injection
Dry FGD/FF/Wet FGD
Yes
Yes
Yes
Yes
Yes
No – Dry FGD/FF/Wet FGD is being
developed, and it has not been utilized
in practice.
7.3
Step 3--Rank Remaining Control Technologies by
Effectiveness
A review of the information contained in the USEPA BACT/LAER Clearinghouse and other sources specified in Section 2.1 was conducted to determine the top level
of H2SO4 control for pulverized coal boilers. A search was also conducted for recently
permitted coal fired facilities whose BACT determinations have not yet been included in
the current BACT/LAER Clearinghouse database. The results of this search for all coal
fired boilers are listed in Attachment A, Table A-6, of this BACT analysis. Table 7-2
lists the H2SO4 BACT determinations that have the closest attributes when compared to
IPL’s SGS Unit 4, which include fuel type, boiler technology, and boiler size.
A review of the H2SO4 BACT determinations in Table 7-2 indicates the
following:
•
The lowest H2SO4 emission limit permitted for a low sulfur PRB fuel
boiler is 0.000184 lb/MBtu, utilizing an SDA/fabric filter at the City
Utilities of Springfield Southwest Power Station. However, it appears that
this yet-to-be demonstrated limit was taken so that the Project would not
be subject to BACT review for H2SO4 and, as such, does not appear to
represent an actual BACT determination.
102607-145491
7-4
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
7.0 Coal Fired Boiler Sulfuric
Acid Mist BACT Analysis
Table 7-2
H2SO4 Top-Down RBLC Clearinghouse Review Results
102607-145491
7-5
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
7.0 Coal Fired Boiler Sulfuric
Acid Mist BACT Analysis
•
The next lowest H2SO4 emission limit permitted for subbituminous coal
fuel boilers is 0.0037 lb/MBtu for three projects. The first utilizes a wet
FGD at CPS of San Antonio, Calaveras Lake Station (San Antonio,
Texas), and the second utilizes a dry FGD at Western Famers Electric
Coop, Hugo Station (Oklahoma City, Oklahoma). The third project
utilizes a dry FGD and fabric filter as H2SO4 control at Sandy Creek
Energy Associates, Sandy Creek Energy (Waco, Texas).
Ozone
nonattainment concerns in San Antonio, Oklahoma City, and Waco,
respectively, are the drivers of the low emission limit in these cases, not
BACT.
•
The next most stringent H2SO4 emission limit permitted for a pulverized
coal boiler is 0.0038 lb/MBtu firing a subbituminous/bituminous blend of
coal at Louisville Gas and Electric Company, Trimble County Generating
Station (Kentucky). Trimble County Generating Station utilizes a wet
ESP for H2SO4 control.
•
Several H2SO4 emission limits that are being proposed between 0.004 and
0.005 are evident from the review of low sulfur PRB fired boilers utilizing
wet FGD/dry FGD/fabric filter control technologies, including
Sunflower’s Holcomb project at 0.004 lb/MBtu and Elk Run Energy
Station at 0.0042 lb/MBtu.
The wide range of H2SO4 emission limits proposed for subbituminous and blends
of subbituminous with bituminous coal fired boilers (as summarized above) is, in large
part, due to the fact that the emission reductions proposed are actually the result of an
assumed collateral control benefit from control technologies used to limit emissions of
SO2 and PM/PM10, and the variability in the assumed SO2 to SO3 conversion and fuel
sulfur content. IPL is not aware of any data demonstrating continuous long-term
compliance with the H2SO4 BACT determination emission limits proposed and
summarized above. The first BACT determination that has been permitted or proposed
utilizing bituminous coal (which is a coal being proposed by the Project) is for 2 x
750 MW pulverized coal boilers at Peabody Energy, Thoroughbred Generating Station
located in Kentucky. The H2SO4 emission limit permitted was for 0.00497 lb/MBtu.
This is significant because bituminous coals have a much greater sulfur content than
subbituminous coals, which makes the level of control a limit of the technology.
102607-145491
7-6
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
7.0 Coal Fired Boiler Sulfuric
Acid Mist BACT Analysis
Based upon the technologies identified as technically feasible and available in
Steps 1 and 2, the following technologies presented in Table 7-3 are ranked in a “TopDown Approach” methodology.
Table 7-3
Ranking of H2SO4 Control Technologies
Control Option
Control Effectiveness (lb/MBtu)
FF/Wet FGD/WESP
FF/Wet FGD with Sorbent Injection
0.004
0.004
7.4
Step 4--Evaluate Most Effective Controls and Document
Results
In the following subsections, the technically feasible control alternatives are
evaluated in a comparative approach with respect to their energy, environmental, and
economic impacts on the Project.
7.4.1
Energy Evaluation of Alternatives
While the energy impact of a WESP is considerably greater than that of sorbent
injection, there are no significant energy impacts that would preclude the use of these
technologies to limit H2SO4.
7.4.2
Environmental Evaluation of Alternatives
When considering any WESP technology, there are potential environmental
impacts associated with the direct operation of the technology. In general, the impacts
are consistent with that of a wet FGD, which is the creation of a visible stack plume,
increased water consumption, and the requirements of a wastewater treatment system.
However, since a WESP is typically located after a wet FGD, its environmental impacts
are essentially shared.
The sorbent injection systems result in no environmental impacts.
7.4.3
Economic Evaluation of Alternatives
The economic evaluations of the WESP and sorbent injection control alternatives
have been assessed in this BACT analysis and are presented in Section 7.5.
102607-145491
7-7
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
7.0 Coal Fired Boiler Sulfuric
Acid Mist BACT Analysis
Tables 7-4 and 7-5 present the total capital investment for the installation of a
WESP or sorbent injection system on the Project’s main boiler, respectively. As
described in the tables, the purchased equipment costs include the respective sulfuric acid
mist control technologies. The direct installation costs, which include balance-of-plant
items such as foundations and supports, handling and erection, electrical, piping,
insulation, and paint, were calculated as a percentage of the purchased equipment costs
and totaled with the purchased equipment costs to estimate the total direct costs of each
control alternative. Finally, the total capital investment was calculated as the summation
of the total direct costs and total indirect costs (including engineering and owner’s costs)
and an allowance for funds used during construction.
Tables 7-4 and 7-5 also present the annualized operating costs for the installation
of a wet ESP or sorbent injection system on the Project’s main boiler. As described in
the tables, the operating fixed and variable direct annual costs includes operating labor,
maintenance labor and materials, and auxiliary and ID fan power costs. The indirect
annual costs, which includes the capital recovery costs, is totaled with the direct annual
costs to estimate the total annual costs for the control system.
7.5
Step 5--Select H2SO4 BACT
IPL has determined that a wet FGD/fabric filter, in combination with sorbent
injection, represents the H2SO4 BACT for the Project’s main boiler. This is also the top
control technology evident in recent permits for similar sized units and fuels.
Since the H2SO4 BACT control technology determination is actually a collateral
benefit of the wet FGD/fabric filter BACT determination for SO2 and PM/PM10 and not a
technology installed expressly for the purpose of controlling H2SO4, the development of
an emission limit (and eventual compliance) has to be carefully considered and estimated
on the basis of assumptions relative to variations in fuel sulfur content (refer to
Table 2-3), SO2 to SO3 conversion during the combustion process and across the SCR.
The following assumptions form the basis for the H2SO4 BACT limitation for the
proposed control technology:
•
Oxidation conversion of a total of 2.0 percent of SO2 to SO3 in the
combustion process and across the SCR catalyst is assumed.
•
Fuel sulfur variability as presented in the BACT basis, Table 2-3.
102607-145491
7-8
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
7.0 Coal Fired Boiler Sulfuric
Acid Mist BACT Analysis
Table 7-4
Wet ESP Equipment Engineering Analysis - Cost Analysis
(WESP)
Technology:
Date: 6/29/2007
Wet Electrostatic Precipitator (WESP)
Cost Item
$
CAPITAL COST
Direct Costs
Purchased equipment costs
WESP system includes casing, electrical systems,
penthouse blower and heater, access provisions
Ash handling system
Booster fans
Electrical system upgrades
Flue gas handling system
Subtotal capital cost (CC)
Instrumentation and controls
Taxes
Freight
Total purchased equipment cost (PEC)
Remarks/Cost Basis
$30,025,000
$2,454,000
$4,662,000
$1,350,000
$3,681,000
$42,172,000
$843,000
$2,952,000
$2,109,000
$48,076,000
(CC) X
(CC) X
(CC) X
2.0%
7.0%
5.0%
5.0%
10.0%
10.0%
2.5%
2.0%
0.5%
0.00%
0.00%
Direct installation costs
Foundation & supports
Handling & erection
Electrical
Piping
Insulation
Painting
Demolition
Relocation
Total direct installation costs (DIC)
$2,404,000
$4,808,000
$4,808,000
$1,202,000
$962,000
$240,000
$0
$0
$14,424,000
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
Site preparation
Buildings
Waste water treatment system
Total direct costs (DC) = (PEC) + (DIC)
$557,654
$0
$6,339,000
$63,058,000
Engineering estimate
N/A
Estimate
$6,306,000
$3,153,000
$6,306,000
$946,000
$126,000
$12,612,000
$29,449,000
(DC) X
(DC) X
(DC) X
(DC) X
(DC) X
(DC) X
Indirect Costs
Engineering
Owner's cost
Construction management
Start-up and spare parts
Performance test
Contingencies
Total indirect costs (IC)
Allowance for Funds Used During Construction (AFDC)
Total Capital Investment (TCI) = (DC) + (IC)
ANNUAL COST
Direct Annual Costs
Fixed annual costs
Maintenance materials and labor
Total fixed annual costs
Variable annual costs
Auxiliary power
ID fan power
Service water
Total variable annual costs
Total direct annual costs (DAC)
Indirect Annual Costs
Cost for capital recovery
Total indirect annual costs (IDAC)
Total Annual Cost (TAC) = (DAC) + (IDAC)
102607-145491
$3,793,000
10.0%
5.0%
10.0%
1.5%
0.2%
20.0%
[(DC)+(IC)] X 8.20%
1 year(s)
$96,300,000
137.47
$1,892,000
$1,892,000
(DC) X
$131,000
$348,000
$764,000
$1,243,000
3.0%
235 kW and
625 kW and
727 gpm and
0.06 $/kWh
Engineering estimate
0.06 $/kWh
4" water pressure drop
2 $/1,000 gal Engineering estimate
$3,135,000
$9,091,000
$9,091,000
(TCI) X
9.44%
CRF at 7% interest & 20 year life
$12,226,000
7-9
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
7.0 Coal Fired Boiler Sulfuric
Acid Mist BACT Analysis
Table 7-5
SO3 Sorbent Injection Equipment Engineering Analysis - Cost Analysis
(SO3 Sorbent Injection)
Technology:
SO3 Sorbent Injection
Cost Item
Date:
$
CAPITAL COST
Direct Costs
Purchased equipment costs
Base Injection Equipment
Subtotal capital cost (CC)
Instrumentation and controls
Taxes
Freight
Total purchased equipment cost (PEC)
$2,379,569
$2,379,569
$48,000
$167,000
$119,000
$2,714,000
Direct installation costs
Foundation & supports
Handling & erection
Electrical
Piping
Insulation
Painting
Demolition
Relocation
Total direct installation costs (DIC)
Site preparation
Total direct costs (DC) = (PEC) + (DIC)
Indirect Costs
Engineering
Owners Cost
Construction and field expenses
Contractor fees
Start-up
Performance test
Contingencies
Total indirect costs (IC)
Allowance for Funds Used During Construction (AFDC)
Total Capital Investment (TCI) = (DC) + (IC)
ANNUAL COST
Direct Annual Costs
Fixed annual costs
Maintenance labor and materials
Total fixed annual costs
Variable annual costs
Reagent
Byproduct disposal
Auxiliary power
Total variable annual costs
Total direct annual costs (DAC)
Indirect Annual Costs
Cost for capital recovery
Total indirect annual costs (IDAC)
Total Annual Cost (TAC) = (DAC) + (IDAC)
102607-145491
(CC) X
(CC) X
(CC) X
2.0%
7.0%
5.0%
$407,000
$271,000
$543,000
$68,000
$54,000
$14,000
$0
$0
$1,357,000
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
15.0%
10.0%
20.0%
2.5%
2.0%
0.5%
0.00%
0.01%
$50,000
$4,121,000
Estimate
$495,000
$124,000
$412,000
$412,000
$124,000
$8,000
$618,000
$2,193,000
(DC) X
(DC) X
(DC) X
(DC) X
(DC) X
(DC) X
(DC) X
12.0%
3.0%
10.0%
10.0%
3.0%
0.2%
15.0%
[(DC)+(IC)] X
8.20%
(DC) X
3.0%
$777,000
10/24/2007
Remarks
3 years (project time length)
$7,091,000
$123,630
$123,630
$1,319,000
$50,000
$14,000
$1,383,000
1.00 tph and
0.95 tph and
25 kW and
150 $/ton
6 $/ton
0.06 $/kWh
Engineering estimate
$1,506,630
$669,000
$669,000
(TCI) X
9.44%
CRF at 7% interest & 20 year life
$2,175,630
7-10
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
7.0 Coal Fired Boiler Sulfuric
Acid Mist BACT Analysis
Tables 7-4 and 7-5 provide the economic analysis for installation of the wet ESP
and sorbent injection technology, respectively. Table 7-6 summarizes the top-down
evaluation of the sulfuric acid mist BACT control alternatives, including economic,
energy, and environmental considerations, in accordance with the BACT determination
methodology previously discussed. Table 7-7 summarizes the Project’s H2SO4 BACT
determination for the main boiler.
Since a WESP and sorbent injection meet the top ranked control technology
emission limit, the decision to select sorbent injection is based on the control technology
with the lowest annualized cost and infinite incremental cost increase. Therefore, IPL
proposes a sulfuric acid mist limit of 0.004 lb/MBtu (based on Controlled Condensate
Test Method) as BACT for the Project. The proposed H2SO4 BACT limit is based on
engineering evaluation and review of various OEM technical literature. There was no
literature found or engineering calculations performed that would indicate that co-firing
with a biomass blend of 5 percent would change the proposed BACT emission limit.
102607-145491
7-11
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
7.0 Coal Fired Boiler Sulfuric Acid Mist BACT Analysis
Table 7-6
Sulfuric Acid Mist
Top-Down BACT Summary
Emissions
Environmental Impacts
Control CostEffectiveness,
$/ton
Incremental
CostEffectiveness,
$/ton
Incremental
Increase
Over
Baseline,
kWh/yr
Toxic
Impacts
(Yes/No)
Adverse
Environmental
Impacts
(Yes/No)
12,226
2,625
∞
7,537,216
No
No
7,091
2,176
467
219,000
No
No
--
--
--
--
--
--
Emissions,
lb/h
Emissions
Reduction,
tpy
Total
Capital
Cost,
$1,000
Total
Annualized
Cost,
$1,000/yr
Wet FGD/FF/WESP
(0.004 lb/MBtu)
24.7
4,657
96,300
Sorbent Injection
(0.004 lb/MBtu)
24.7
4,657
Uncontrolled
Baseline
1,088
--
Control Alternative
Energy
Impacts
Economic Impacts
--
Table 7-7
Main Boiler H2SO4 BACT Determination
102607-145491
Control Technology
Emission Limit (lb/MBtu)
FF/Wet FGD with Sorbent
Injection
0.004
7-12
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
8.0
8.0 Coal Fired Boiler
Fluorides BACT Analysis
Coal Fired Boiler Fluorides BACT Analysis
This section presents the top-down, five-step BACT process used to evaluate and
determine the Project’s fluorides emission limit for the main boiler. Fluoride emissions
are formed from hydrogenation of fuel-bound fluorides forming hydrogen fluoride (HF).
As this analysis will demonstrate, the proposed fluorides (as HF) BACT limit for the
Project’s main boiler is an emissions limit of 0.0002 lb/MBtu.
8.1
Step 1--Identify All Control Technologies
The first step in a top-down analysis, according to the EPA’s October 1990, Draft
New Source Review Workshop Manual, is to identify all available control options.
Available control options are those air pollution control technologies or techniques with a
practical potential for application to the emission unit and the sulfuric acid mist emission
limit that is being evaluated. Fluorides levels are fuel specific, present in the coal in trace
amounts, and generally emitted as HF. As with other acids, for example, H2SO4 as
previously discussed, HF (and thus fluorides) is cost-effectively controlled as a collateral
benefit of the modern SO2 air pollution control equipment considered in this BACT
analysis. A description of the SO2 control alternatives is presented in Section 4.3 of this
BACT analysis.
8.2
Step 2--Eliminate Technically Infeasible Options
Step 2 of the BACT analysis involves the evaluation of all the identified available
control technologies in Step 1 of the BACT analysis to determine their technical
feasibility. A control technology is technically feasible if it has been previously installed
and operated successfully at a similar type of source of comparable size, or there is
technical agreement that the technology can be applied to the source. Available and
applicable are the two terms used to define the technical feasibility of a control
technology.
Coal washing utilizes various techniques such as high speed coal washes or
agitating liquids to produce a separation of impurities from the coal. The trace elements
such as fluorine will be separated from the coal product. Since IPL is proposing to utilize
various types of coals, the effectiveness of coal washing will differ greatly. IPL is not
aware of large-scale facilities that perform coal washing on western subbituminous coal,
such as PRB, which is considered one of the design coals for the main boiler. Therefore,
the supply of PRB coal that has been washed cannot be considered a reliable source for
102607-145491
8-1
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
8.0 Coal Fired Boiler
Fluorides BACT Analysis
this Project. Coal washing is determined to be technically infeasible because PRB coal
that has been washed may not be available.
A wet lime- and limestone-based FGD process have been demonstrated
technologies of controlling fluoride emissions from a coal fired boiler and are
commercially available from several vendors. Wet lime- and limestone-based FGD
processes, which include the countercurrent spray tower, double contact spray tower, jet
bubbling reactor, and FLOWPAC, are equal for comparative purposes. Wet lime- and
limestone-based FGD processes are considered technically feasible and will be
considered further.
Dry and semi-dry lime FGD systems are considered technically feasible and
applicable for this Project; however, a wet FGD is proposed as SO2 BACT. As discussed
in Subsection 7.1.1, Alstom is developing a proprietary “Integrated AQCS” system that
combines a SDA/FF with a downstream wet FGD. This arrangement of control
equipment has not reached the licensing and commercial sales stage of development for a
similar size of unit as the Project. In addition, IPL is unaware of any other type of dry
and semi-dry lime FGD systems (CDS, Flash Dryer Absorber, and LIFAC) that are
combined with a wet lime FGD process to control fluorides. Therefore, a dry and semiFGD system with a wet lime FGD process is not considered technically feasible. In
addition, the requirements to handle both lime and limestone on the same site, as well as
additional nonsaleable grade of ash, would make this system combination (dry and wet
FGD) environmentally and economically not a good choice.
As discussed in Subsection 3.2.3.4, the LIFAC process is a demonstrated
technology of controlling SO2 emissions from a coal fired boiler on a limited number of
installations and is considered commercially available. LIFAC has not been applied
domestically to similar sized boilers as proposed for the Project. LIFAC has been
designed for plant capacities ranging from 25 to 200 MW. LIFAC will not be considered
further because it is not technically feasible for the Project.
Table 8-1 summarizes the evaluation of the technically infeasible HF options,
which is very similar to the SO2 options that were identified earlier in Table 3-1.
102607-145491
8-2
Interstate Power and Light
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8.0 Coal Fired Boiler
Fluorides BACT Analysis
Table 8-1
Summary of Step 2--Eliminate Technically Infeasible Options
Technically Feasible (Yes/No)
Technology Alternative
Available
Applicable
Coal Washing
Yes
No – PRB coal that has been washed may
not be available. Coal washing is not
technically feasible.
Spray Tower
Yes
Yes
Double Contact Spray Tower
Yes
Yes
Jet Bubbling Reactor
Yes
Yes
FLOWPAC
Yes
Yes
SDA/FF/Wet FGD
Yes
No – SDA/FF/Wet FGD is being
developed, and it has not been utilized in
practice.
CDS/FF/Wet FGD
Yes
No – No installations comparable in size
to this Project for a CDS.
Flash Dryer Absorber/FF/Wet
FGD
Yes
No
LIFAC
Yes
No – No installations comparable in size
to this Project. Long-term high removal
efficiency not demonstrated on range of
sulfur in fuels of this Project.
Wet Lime or Limestone FGD(1)
Dry and Semi-Dry Lime FGD
(1)
All alternate technologies in wet lime or limestone FGD (i.e., spray tower, double contact
spray tower, JBR, FLOWPAC) are considered comparatively equal.
102607-145491
8-3
Interstate Power and Light
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8.3
8.0 Coal Fired Boiler
Fluorides BACT Analysis
Step 3--Rank Remaining Control Technologies by
Effectiveness
A search of the information contained in the USEPA BACT/LAER Clearinghouse
and other sources specified in Section 2.1 was conducted to determine the top level of
fluorides control for pulverized coal boilers firing subbituminous and bituminous coal. A
search was also conducted for recently permitted coal fired facilities whose BACT
determinations have not yet been included in the current BACT/LAER Clearinghouse
database. The results of this search for all coal fired boilers are listed in Attachment A,
Table A-7, of this BACT analysis. Table 8-2 lists the HF BACT determinations that have
the closest attributes when compared to IPL’s SGS Unit 4, which include fuel type, boiler
technology, and boiler size.
A review of the HF BACT determinations in Table 8-2 indicates the following:
•
The most stringent fluorides emission limit permitted to date for a
pulverized coal boiler burning a bituminous coal is an emission limit of
0.00010 lb/MBtu for the Longview Power, LLC, Maidsville Plant located
in West Virginia. This unit controls fluorides with wet FGD, limestone
injection, and a fabric filter.
•
The next most stringent fluorides emission limit permitted to date for a
pulverized coal boiler burning a bituminous coal is an emission limit of
0.000159 lb/MBtu for the Peabody Energy Thoroughbred Generating
Station located in Kentucky (wet FGD as control).
•
The most stringent fluorides emission limit permitted to date for a
pulverized coal boiler burning a PRB subbituminous coal is an emission
limit of 0.00020 lb/MBtu for the Wisconsin Public Service Weston Unit
No. 4 located in Wisconsin (dry FGD as control).
•
The most stringent fluorides emission limit proposed to date for a
pulverized coal boiler burning a bituminous coal/petcoke is an emission
limit of 0.000230 lb/MBtu for the Florida Power and Light Glades Power
Park located in Florida (wet FGD as control).
•
The next most stringent fluorides emission limit permitted to date for a
pulverized coal boiler burning a bituminous coal is an emission limit of
0.00030 lb/MBtu for the Santee Cooper Cross Generating Station located
in South Carolina (wet FGD as control).
•
The next most stringent fluorides emission limit proposed to date for a
pulverized coal boiler burning a bituminous coal/petcoke is an emission
limit of 0.000341 lb/MBtu for the Santee Cooper Pee Dee Generating
Station located in South Carolina (wet FGD as control).
102607-145491
8-4
Interstate Power and Light
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8.0 Coal Fired Boiler
Fluorides BACT Analysis
Table 8-2
Fluorides Top-Down RBLC Clearinghouse Review Results
102607-145491
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
8.0 Coal Fired Boiler
Fluorides BACT Analysis
•
The most stringent fluorides emission limit permitted to date for a
pulverized coal boiler burning a PRB subbituminous coal is an emission
limit of 0.00037 lb/MBtu for the City Utilities of Springfield Southwest
Power Station (dry FGD as control).
•
The next most stringent fluorides emission limit permitted to date for a
pulverized coal boiler burning a PRB subbituminous coal is an emission
limit of 0.0004 lb/MBtu for Omaha Public Power District’s Nebraska City
Unit 2 and the Municipal Energy Agency of Nebraska Whelan Energy
Center (dry FGD as control).
•
The next most stringent fluorides emission limit permitted to date for a
pulverized coal boiler burning PRB is 0.00044 lb/MBtu for LS Power’s
Plum Point Power Station in Arkansas. This unit also controls fluorides
through a dry FGD and a fabric filter.
•
The next most stringent fluorides emission limit proposed to date for a
pulverized coal boiler (750 MW) burning PRB is 0.00067 lb/MBtu for the
LS Power Development, Elk Run Energy Station in Iowa. This unit also
controls fluorides through a dry FGD and a fabric filter.
Based on the technologies identified as technically feasible and available in
Steps 1 and 2, the following technologies presented in Table 8-3 are ranked in a “TopDown Approach” methodology.
Table 8-3
Ranking of HF Control Technologies
Control Option
Control Effectiveness (lb/MBtu)
Wet FGD System (Lime or Limestone)
0.0002
Notes:
1. No other technologies ranked but wet FGD, based on Step 2.
2. All wet FGD systems expected to be similar in operating characteristics.
8.4
Step 4--Evaluate Most Effective Controls and Document
Results
Since fluorides are a collateral control benefit of the SO2 reduction technology,
the energy, environmental, and economic impacts would be those caused by the BACT
selected SO2 technology.
102607-145491
8-6
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
8.0 Coal Fired Boiler
Fluorides BACT Analysis
8.4.1
Energy Evaluation of Alternatives
The energy evaluations of the SO2 control alternatives assessed in this BACT
analysis are presented in Section 3.4.
8.4.2
Environmental Evaluation of Alternatives
The environmental evaluations of SO2 control alternatives assessed in this BACT
analysis are presented in Section 3.4.
8.4.3
Economic Evaluation of Alternatives
The economic evaluations of SO2 control alternatives assessed in this BACT
analysis are presented in Section 3.4.
8.5
Step 5--Select Fluorides BACT
IPL has determined that a wet FGD system represents the fluorides BACT for the
Project’s main boiler. This is also the top control technology evident in recent permits
for similar sized units and fuels.
Fluorides BACT control technology determination is a collateral control benefit
of the wet FGD BACT determination for SO2 and not a technology installed expressly for
the purpose of controlling fluorides. The actual removal efficiency and effectiveness of
these collateral emissions controls are difficult to exactly quantify since little, if any, data
are available, and IPL is not aware of full scale commercial demonstration of compliance
with the top control emission limits presented in Section 8.3.
However, fluorides in the form of HF emissions can be controlled by the use of
the wet FGD scrubber system. The lower flue gas temperatures produced by the wet
FGD scrubber help to condense HF into a liquid. HF readily dissolves in water and will
react with calcium in the wet FGD to form calcium fluoride in solution.
Recent manufacturer guaranties have indicated a 90 to 98 percent control
effectiveness of fluorides (as HF) associated with the SO2 emission control equipment
proposed as BACT for this Project. Based on a 98 percent control effectiveness and the
inlet fluorides concentration in the fuel, the proposed BACT emission limit for fluorides
(as HF) is 0.0002 lb/MBtu. Table 8-4 summarizes the Project’s fluorides (as HF) BACT
determination for the main boiler.
The proposed HF BACT limit is based on an engineering evaluation and a review
of various OEM technical literature. There was no literature found or engineering
calculations performed that would indicate that co-firing with a biomass blend of
5 percent would change the proposed BACT emission limit.
102607-145491
8-7
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
8.0 Coal Fired Boiler
Fluorides BACT Analysis
Table 8-4
Main Boiler HF BACT Determination
Control Technology
Emission Limit (lb/MBtu)
Wet FGD System (Lime or
Limestone)
0.0002
102607-145491
8-8
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0
9.0 Auxiliary Boiler BACT Analysis
Auxiliary Boiler BACT Analysis
The objective of this analysis is to determine BACT for the emissions from the
auxiliary boiler. The small size and limited hours of operation (2,000 hours) for the
auxiliary boiler greatly limits the amount of emissions that will be produced by this unit.
The unit will fall under the guidelines of 40 CFR Part 60, Subpart Db, Standards of
Performance for Industrial-Commercial-Institutional Steam Generating Units. This
section proposes control limits that meet or exceed the limits set forth in this regulation.
9.1
SO2 BACT Analysis
This section presents the top-down, five-step BACT process used to evaluate and
determine the Project’s SO2 emission limit for the 270 MBtu/h natural gas fired auxiliary
boiler.
9.1.1
Step 1--Identify All Control Technologies
The only potential control technology identified to limit SO2 emissions from an
auxiliary boiler is fuel selection. Selecting a low sulfur fuel generates very low SO2
emissions. The auxiliary boiler proposes to burn natural gas; thus, the SO2 emissions will
be negligible.
9.1.2
Step 2--Eliminate Technically Infeasible Options
Fuel selection was the only control technology identified to limit SO2 emissions
from the auxiliary boiler. There were no other SO2 control technologies identified for the
Project’s 270 MBtu/h auxiliary boiler.
9.1.3
Step 3--Rank Remaining Control Technologies by Effectiveness
A review of information contained in the USEPA BACT/LAER Clearinghouse
(Attachment B) and other sources specified in Section 2.1 revealed that burning natural
gas (low sulfur fuel) was identified as the top BACT control technology for auxiliary
boilers. The results of the review indicate the following:
•
The lowest emission limit currently in place for an auxiliary boiler is
0.0006 lb/MBtu for three projects: the Wisconsin Public Service Weston
Plant - Unit 4 (Permitted: October 2004), the Interstate Power and Light
Emery Generating Station (Permitted: December 2002), and the MidAmerican Energy Company project located in Pottawattamie County
(Permitted: June 2003). The only control technology that can be inferred
from the projects is the utilization of natural gas (low sulfur fuel).
102607-145491
9-1
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
9.1.4
Step 4--Evaluate Most Effective Controls and Document Results
In the following subsections, the technically feasible control alternatives are
evaluated with respect to their energy, environmental, and economic impact to the
auxiliary boiler. The only feasible control technology is low sulfur fuel.
9.1.4.1 Energy Evaluation of Alternatives. There are no significant energy
impacts that would preclude the use of low sulfur fuel as the SO2 control technology as
presented in this evaluation.
9.1.4.2 Environmental Evaluation of Alternatives. There are no significant
environmental impacts that would preclude the use of low sulfur fuel as the SO2 control
technology as presented in this evaluation.
9.1.4.3 Economic Evaluation of Alternatives. There are no significant economic
impacts that would preclude the use of low sulfur fuel as the SO2 control technology as
presented in this evaluation.
9.1.5
Step 5--Select SO2 BACT
The proposed use of natural gas (low sulfur fuel) is the BACT for the auxiliary
boiler. The estimated SO2 emission is 0.0006 lb/MBtu, which will be in compliance with
the NSPS limit (Subpart Db). The value of 0.0006 lb/MBtu is the default SO2 emission
rate prescribed by 40 CFR 75 Appendix D for the calculation of SO2 impacts utilizing
natural gas in a boiler.
9.2
NOx BACT Analysis
This section presents the top-down, five-step BACT process used to evaluate and
determine the Project’s NOx emission limit for the 270 MBtu/h natural gas fired auxiliary
boiler.
9.2.1
Step 1--Identify All Control Technologies
As discussed in Section 4.0, NOx controls may be divided into two categories:
combustion related NOx formation control and post-combustion emission reduction.
Typically, NOx formation combustion control methods include LNB, OFA, gas reburn,
and AGR. Post-combustion controls are flue gas treatments that reduce NOx after its
formation. The post-combustion alternatives include SNCR and SCR. All postcombustion control technologies rely on the injection of a nitrogen compound (aqueous
ammonia) into the flue gas to react with (and remove) NOx.
102607-145491
9-2
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
9.2.2
Step 2--Eliminate Technically Infeasible Options
A review of the aforementioned NOx control technologies concluded that LNB,
OFA, and SCR are the only technologies that are technically feasible as control
technology alternatives for the Project’s 270 MBtu/h auxiliary boiler. Gas reburn, AGR,
and SNCR technologies are not available for an auxiliary boiler; therefore, these options
were determined to be technically infeasible.
9.2.3
Step 3 -- Rank Remaining Control Technologies by Effectiveness
A review of information contained in the USEPA BACT/LAER Clearinghouse
(Attachment B) and other sources specified in Section 2.1 revealed that good combustion
practices, LNB, and gas recirculation were identified as the top BACT control
technologies for auxiliary boilers burning natural gas. The results of the review indicated
the following:
•
The lowest emission limit currently in place for an auxiliary boiler is
0.035 lb/MBtu for the Sempra Energy Resources Copper Mountain Power
(Permitted: May 2004) located in Nevada. The control technology was
listed as LNB with either internal or external flue gas recirculation.
•
The next lowest emission limit currently in place for an auxiliary boiler is
0.036 lb/MBtu for the Energetix Lawton Energy Cogen Facility
(Permitted: December 2006). The control technology was listed as dryLNB.
•
The next lowest emission limit currently in place for an auxiliary boiler is
0.037 lb/MBtu for the Sierra Pacific Power Company Tracy Substation
Expansion Project (Permitted: August 2005). The control technology
was listed as best combustion practices.
9.2.4
Step 4--Evaluate Most Effective Controls and Document Results
In the following subsections, the technically feasible control alternatives are
evaluated in a comparative approach with respect to their energy, environmental, and
economic impacts to the auxiliary boiler.
9.2.4.1 Energy Evaluation of Alternatives. All the control alternatives identified
in Subsection 9.2.1 would have an adverse energy impact. However, there are no
significant energy impacts that would preclude the use of good combustion practices and
the burning of natural gas as NOx control technology as presented in this evaluation.
9.2.4.2 Environmental Evaluation of Alternatives. SCR and SNCR would have
an adverse environmental impact. However, there are no significant environmental
impacts that would preclude the use of good combustion practices and the burning of
natural gas as NOx control technology as presented in this evaluation.
102607-145491
9-3
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
9.2.4.3 Economic Evaluation of Alternatives. All the control alternatives
identified in Subsection 9.2.1 would have a negative economic impact. However, there
are no significant economic impacts that would preclude the use of good combustion
practices and the burning of natural gas as NOx control technology as presented in this
evaluation.
9.2.5
Step 5--Select NOx BACT
The proposed use of good combustion practices is BACT for the auxiliary boiler.
The estimated NOx emission level supplied by the vendor is 0.037 lb/MBtu, which will
be in compliance with the NSPS limit (Subpart Db).
9.3
PM/PM10 BACT Analysis
This section presents the top-down, five-step BACT process used to evaluate and
determine the Project’s PM/PM10 emission limit for the 270 MBtu/h natural gas fired
auxiliary boiler.
9.3.1
Step 1--Identify All Control Technologies
The following are the potential control technologies that can be used to limit PM
from an auxiliary boiler:
•
Fuel selection.
•
Post-combustion particulate removal system.
9.3.1.1 Fuel Selection. The fuels typically burned in an auxiliary boiler are either
distillate fuel oil or natural gas. IPL proposes to burn only natural gas, which is a very
low PM/PM10 emitter.
9.3.1.2 Post-Combustion Particulate Removal Systems. The following postcombustion particulate removal systems have been identified to remove particulate on
auxiliary boilers:
•
DESP.
•
Fabric filter.
•
WESP.
Section 5.0 describes these particulate control technologies in more detail.
9.3.2
Step 2--Eliminate Technically Infeasible Options
A review of the aforementioned PM/PM10 control technologies concludes that
DESP, fabric filter, and WESP are technically feasible as control technology alternatives
for the Project’s 270 MBtu/h auxiliary boiler that burns natural gas.
102607-145491
9-4
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
9.3.3
Step 3--Rank Remaining Control Technologies by Effectiveness
A review of information contained in the USEPA BACT/LAER Clearinghouse
(Attachment B) and other sources specified in Section 2.1 reveal that good combustion
practices are identified as the top and only BACT control technologies utilized for
auxiliary boilers burning natural gas. The results of this review indicated the following:
•
The lowest emission limit currently in place for an auxiliary boiler is
0.004 lb/MBtu for the Sierra Pacific Power Company Tracy Substation
Expansion Project (Permitted: August 2005) located in Nevada.
•
The next lowest emission limit currently in place for an auxiliary boiler is
0.0075 lb/MBtu for two plants, which includes the Wisconsin Public
Service Weston Plant - Unit 4 (Permitted: October 2004) and Interstate
Power and Light Emergency Generating Station (Permitted: December
2002).
•
The next lowest permitted plant is the Mid-American Energy Company
project located in Pottawattamie County in Iowa, which was permitted in
June 2003 at 0.0076 lb/MBtu.
9.3.4
Step 4--Evaluate Most Effective Controls and Document Results
In the following subsections, the technically feasible control alternatives are
evaluated in a comparative approach with respect to their energy, environmental, and
economic impacts to the auxiliary boiler.
9.3.4.1 Energy Evaluation of Alternatives. DESP, fabric filter, and WESP would
all require additional auxiliary power; thus, they all would have an adverse energy
impact. However, there are no significant energy impacts that would preclude the use of
good combustion practices and the burning of natural gas as particulate control
technology presented in this evaluation.
9.3.4.2 Environmental Evaluation of Alternatives. DESP, fabric filter, and
WESP would all create additional waste; thus, they all would have an adverse
environmental impact. There are no significant environmental impacts that would
preclude the use of good combustion practices and the burning of natural gas as
particulate control technology presented in this evaluation.
9.3.4.3 Economic Evaluation of Alternatives. DESP, fabric filter, and WESP
would all represent a significant cost; thus, they all would have a negative economic
impact. There are no significant economic impacts that would preclude the use of good
combustion practices and the burning of natural gas as particulate control technology
presented in this evaluation.
102607-145491
9-5
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
9.3.5
Step 5--Select PM/PM10 BACT
The proposed use of good combustion practices and low sulfur fuel have been the
only control measures used on these small boilers. Therefore, the proposed BACT for
PM/PM10 is to ensure as complete fuel combustion as possible and to fire natural gas.
The estimated PM/PM10 emission level supplied by the vendor is 0.007 lb/MBtu, which
will be in compliance with the NSPS limit (Subpart Db).
9.4
CO BACT Analysis
This section presents the top-down, five-step BACT process used to evaluate and
determine the Project’s CO emission limit for the 270 MBtu/h natural gas fired auxiliary
boiler.
9.4.1
Step 1--Identify All Control Technologies
As discussed in Section 6.0 for the coal fired boiler BACT analysis, CO is formed
during the combustion process because of incomplete oxidation of the carbon contained
in the fuel. The auxiliary boiler has similar characteristics of a coal fired boiler in terms
of CO production. CO control technologies identified are good combustion controls and
oxidation catalysts. Good combustion controls are the optimization of the design,
operation, and maintenance of the auxiliary boiler. The factors for good combustion
include the air to fuel mixture, residence time, and optimum temperatures in the
combustion chamber. As for oxidation catalysts, it converts CO in the flue gas to CO2 at
temperatures ranging from 500º F to 700º F.
9.4.2
Step 2--Eliminate Technically Infeasible Options
Based on a review of the aforementioned CO control technologies, it can be
concluded that good combustion controls and oxidation catalysts are technically feasible
as control technology alternatives for the Project’s 270 MBtu/h auxiliary boiler.
However, the oxidation catalyst will not only oxidize CO, but will also oxidize a
predominant portion of SO2 to SO3. The combination of this SO3 with moisture in the
flue gas creates sulfuric acid, which can lead to a corrosive environment in the auxiliary
boiler’s ductwork/stack. Table 9-1 provides a summary of Step 2--Eliminate Technically
Infeasible Options.
102607-145491
9-6
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
Table 9-1
Summary of Step 2--Eliminate Technically Infeasible Options
Technology Alternative
Technically Feasible (Yes/No)
Good Combustion Controls
Oxidation Catalyst
Yes
Yes
9.4.3
Step 3--Rank Remaining Control Technologies by Effectiveness
A review of information contained in the USEPA BACT/LAER Clearinghouse
(Attachment B) and other sources specified in Section 2.1 revealed that catalytic
oxidation was identified as the top BACT control technology for auxiliary boilers burning
natural gas. The results of the review indicated the following:
•
The lowest emission limit currently in place for an auxiliary boiler is
0.0164 lb/MBtu for the Interstate Power and Light Emery Generating
Station (Permitted: December 2002) located in Iowa. The control
technology was listed as catalytic oxidation.
•
The next lowest emission limit currently in place for an auxiliary boiler is
0.036 lb/MBtu for the Sempra Energy Resources Copper Mountain Power
(Permitted: May 2004) located in Nevada. The control technology was
listed as best combustion practices.
•
The next lowest emission limit currently in place for an auxiliary boiler is
0.08 lb/MBtu for the Wisconsin Public Service Weston Plant - Unit 4
(Permitted: October 2004). The control technology was listed as good
combustion practices.
It is important to note that the BACT determination of catalytic oxidation for the
Emery Generating Station was apparently based on its extended usage of up to
6,000 hours per year. The auxiliary boiler for this Project is proposing to limit usage to
no more than 2,000 hours per year. The intermittent operation of the Project’s auxiliary
boiler is a consideration when considering the economic impact of catalytic oxidation
versus good combustion practices.
9.4.4
Step 4--Evaluate Most Effective Controls and Document Results
In the following sections, the technically feasible control alternatives are
evaluated in a comparative approach with respect to their energy, environmental, and
economic impacts to the auxiliary boiler.
102607-145491
9-7
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
9.4.4.1 Energy Evaluation of Alternatives. There are no significant energy
impacts that would preclude the use of good combustion practices as CO control
technology as presented in this evaluation. However, the catalytic oxidation system
consumes electrical energy to overcome catalytic oxidation draft losses because of a
pressure drop across the catalyst. While the energy costs of post-combustion CO control
are real and quantifiable, they do not in and of themselves eliminate the control
technology from further consideration.
9.4.4.2 Environmental Evaluation of Alternatives. There are no significant
environmental impacts that would preclude the use of good combustion practices as CO
control technology as presented in this evaluation. The oxidation catalysts will have an
environmental impact because of the disposal waste that is generated from the spent
catalyst.
9.4.4.3 Economic Evaluation of Alternatives. An economic evaluation and cost
comparison of the technically feasible alternative control technologies identified in
Subsection 9.4.3 (Step 3) are presented below for the following top control options:
•
Good combustion practices.
•
Catalytic oxidation.
The cost estimates are based on budgetary quotes from equipment manufacturers
and engineering cost estimates in accordance with the USEPA’s Office of Air Quality
Planning and Standards (OAQPS) Control Cost Manual.
Table 9-2 presents the total capital investment costs for the installation of a
oxidation catalyst on the Project’s 270 MBtu/h natural gas fired auxiliary boiler. As
described in the table, the purchased equipment costs include reactor housing and
ductwork. The direct installation costs, which include balance-of-plant items such as
foundations and supports, handling and erection, electrical, piping, insulation, and paint,
were calculated as a percentage of the purchased equipment costs and totaled with the
purchased equipment costs to estimate the total direct costs of each control alternative.
Finally, the total capital investment is calculated as the summation of the total direct cost
and total indirect costs (including engineering and owner’s cost) and an allowance for
funds used during construction. No capital cost analysis is presented for good
combustion controls, since it is inherent to the supply of the auxiliary boiler.
102607-145491
9-8
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
Table 9-2
Auxiliary Boiler Catalytic Oxidation System
Equipment Engineering Analysis - Cost Analysis
IPL - Auxiliary Boiler Catalytic Oxidation System Engineering Analysis - Cost Analysis
Sutherland Generating Station
Technology:
Catalytic Oxidation
Cost Item
Date: 6/29/2007
$
Remarks/Cost Basis
CAPITAL COST
Direct Costs
Purchased equipment costs
Reactor housing
Initial catalyst
Flue gas handling: ductwork and fans
Subtotal capital cost (CC)
Taxes
Freight
Total purchased equipment cost (PEC)
$412,000
$53,000
$424,000
$889,000
$62,000
$44,000
$995,000
Engineering estimate
Engineering estimate
Engineering estimate
(CC) X
(CC) X
7.0%
5.0%
Direct installation costs
Foundation & supports
Handling & erection
Electrical
Piping
Insulation
Painting
Demolition
Relocation
Total direct installation costs (DIC)
$149,000
$149,000
$100,000
$25,000
$100,000
$10,000
$0
$0
$533,000
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
(PEC) X
15.0%
15.0%
10.0%
2.5%
10.0%
1.0%
0.00%
0.00%
Site preparation
Buildings
Total direct costs (DC) = (PEC) + (DIC)
Indirect Costs
Engineering
Construction and field expenses
Owner's cost
Start-up
Performance test
Contingencies
Total indirect costs (IC)
Allowance for Funds Used During Construction (AFDC)
Total Capital Investment (TCI) = (DC) + (IC)
$50,000
$25,000
$1,603,000
$192,000
$80,000
$160,000
$48,000
$8,000
$240,000
$728,000
$96,000
$10,000
$48,000
$5,000
$63,000
Variable annual costs
Auxiliary and ID fan power
Catalyst replacement
Catalyst disposal
Total variable annual costs
$46,000
$11,000
$30
$57,030
12.0%
5.0%
10.0%
3.0%
0.5%
15.0%
[(DC)+(IC)] X
8.20%
1 year(s)
0.1 FTE and
(DC) X
3.0%
Engineering estimate
99 kW and
9,600 lb and
100,000 $/year
0.06 $/kWh
6 $/ton
Estimated manpower level
Engineering estimate
5 yr catalyst replacement rate
5 yr catalyst replacement rate
$120,030
Indirect Annual Costs
Cost for capital recovery
Total indirect annual costs (IDAC)
$229,000
$229,000
Total Annual Cost (TAC) = (DAC) + (IDAC)
$349,000
102607-145491
(DC) X
(DC) X
(DC) X
(DC) X
(DC) X
(DC) X
$2,427,000
ANNUAL COST
Direct Annual Costs
Fixed annual costs
Operating labor
Maintenance labor & materials
Catalyst activity testing
Total fixed annual costs
Total direct annual costs (DAC)
Engineering estimate
Engineering estimate
(TCI) X
9.44%
CRF at 7% interest & 20 year life
9-9
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
Table 9-2 also presents the annualized operating costs for the installation of a
oxidation catalyst system on the Project’s 270 MBtu/h natural gas fired auxiliary boiler.
As described in the table, the operating fixed and variable direct annual costs include
operating and support labor, maintenance labor and materials, and various testing and
sampling costs. The indirect annual costs, which include the capital recovery costs, is
totaled with the direct annual costs to estimate the total annual cost for the control
system. No annual cost analysis is presented for good combustion controls, since it is
inherent to the supply of the auxiliary boiler.
9.4.5
Step 5--Select CO BACT
Table 9-3 summarizes the top-down evaluation of the CO control alternatives,
including economic, energy, and environmental considerations, in accordance with the
BACT determination methodology previously discussed. As Table 9-3 illustrates, the
selected BACT CO control technology is not the top-ranked control alternative, which
consists of catalytic oxidation and an associated emission limit of 0.0164 lb/MBtu.
However, the total capital and annualized costs of catalytic oxidation on a limited use
auxiliary boiler are considered cost-prohibitive.
IPL has determined that good combustion practices represent CO BACT for the
Project’s 270 MBtu/h natural gas fired auxiliary boiler. The CO emission level supplied
by the vendor is 0.074 lb/MBtu.
9.5
VOC BACT Analysis
This section presents the top-down, five-step BACT process used to evaluate and
determine the Project’s VOC emissions limit for the 270 MBtu/h natural gas fired
auxiliary boiler.
9.5.1
Step 1--Identify All Control Technologies
As discussed in Section 6.0 for the coal fired boiler BACT analysis, VOCs are
formed during the combustion process because of incomplete oxidation of the carbon
contained in the fuel. The auxiliary boiler has similar characteristics of a coal fired boiler
in terms of VOC production. The VOC control technologies identified are good
combustion controls and oxidation catalysts.
102607-145491
9-10
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
Table 9-3
Carbon Monoxide/Volatile Organic Compounds
Top-Down BACT Summary
Emissions
Emissions,
lb/h
Emissions
Reduction,
tpy
Total
Capital
Cost,
$1,000
Total
Annualized
Cost,
$1,000/yr
Control CostEffectiveness,
$/ton
Oxidation Catalyst
(0.0164 lb/MBtu)
4.4
68.2
2,427
349
5,123
Uncontrolled
Baseline
20
--
--
--
--
Control Alternative
102607-145491
Energy
Impacts
Economic Impacts
Incremental
CostEffectiveness,
$/ton
--
Environmental Impacts
Incremental
Increase Over
Baseline,
kWh/yr
Toxic
Impacts
(Yes/No)
Adverse
Environmental
Impacts
(Yes/No)
0
No
No
--
--
--
9-11
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
9.5.2
Step 2--Eliminate Technically Infeasible Options
Based on a review of the aforementioned VOC control technologies, it can be
concluded that good combustion controls and oxidation catalysts are technically feasible
as control technology alternatives for the Project’s 270 MBtu/h auxiliary boiler.
However, the oxidation catalyst will not only oxidize VOC, but will also oxidize a
predominant portion of SO2 to SO3. Combination of this SO3 with moisture in the flue
gas creates sulfuric acid that could lead to a corrosive environment in the auxiliary
boiler’s ductwork/stack.
9.5.3
Step 3--Rank Remaining Control Technologies by Effectiveness
A review of information contained in the USEPA BACT/LAER Clearinghouse
(Attachment B) and other sources specified in Section 2.1 revealed that good combustion
practices was identified as the top BACT control technology for auxiliary boilers burning
natural gas. The results of the review indicated the following:
•
The lowest emission limit currently in place for an auxiliary boiler is
0.005 lb/MBtu for the Sierra Pacific Power Company Tracy Substation
Expansion Project (Permitted: August 2005). The control technology
was listed as best combustion practices.
•
The next lowest emission limits currently in place for an auxiliary boiler
are 0.0054 lb/MBtu for two projects, which include the Wisconsin Public
Service Weston Plant - Unit 4 (Permitted: October 2004) and the
Interstate Power and Light Emery Generating Station (Permitted:
December 2002). The control technology listed for both projects was best
combustion practices.
9.5.4
Step 4--Evaluate Most Effective Controls and Document Results
In the following subsections, the technically feasible control alternatives are
evaluated in a comparative approach with respect to their energy, environmental, and
economic impacts to the auxiliary boiler.
9.5.4.1 Energy Evaluation of Alternatives. There are no significant energy
impacts that would preclude the use of good combustion practices as VOC control
technology as presented in this evaluation. However, the catalytic oxidation system
consumes electrical energy to overcome catalytic oxidation draft losses because of a
pressure drop across the catalyst. While the energy costs of post-combustion VOC
control are real and quantifiable, they do not in and of themselves eliminate the control
technology from further consideration.
102607-145491
9-12
Interstate Power and Light
Sutherland Unit 4 Air Permit Application
9.0 Auxiliary Boiler BACT Analysis
9.5.4.2 Environmental Evaluation of Alternatives. There are no significant
environmental impacts that would preclude the use of good combustion practices as VOC
control technology as presented in this evaluation. The oxidation catalyst control
alternative would have an environmental impact because of the disposal waste that is
generated from the spent catalyst.
9.5.4.3 Economic Evaluation of Alternatives. An economic evaluation and cost
comparison of the technically feasible alternative control technologies identified in
Subsection 9.4.3 (Step 3) are presented below for the following top control options:
•
Good combustion practices.
•
Catalytic oxidation.
The cost estimates are based on budgetary quotes from equipment manufacturers
and engineering cost estimates in accordance with USEPA’s Office of Air Quality
Planning and Standards (OAQPS) Control Cost Manual.
The costs and economic impacts for CO and VOC control are identical for the
auxiliary boiler. Therefore, Table 9-1, which contains the total capital investment and
total annual costs for catalytic oxidation, are not repeated in this section. Refer to
Subsection 9.4.4.3 of this report.
9.5.5
Step 5--Select VOC BACT
IPL has determined that the top control of good combustion practices represents
VOC BACT for the Project’s 270 MBtu/h natural gas fired auxiliary boiler. The
estimated VOC emission level supplied by the vendor is 0.005 lb/MBtu. Table 9-3
summarizes the top-down evaluation of the VOC control alternatives, including
economic, energy, and environmental considerations, in accordance with the BACT
determination methodology previously discussed.
102607-145491
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
10.0 Emergency Generator and
Fire Pumps BACT Analysis
10.0 Emergency Generator and Fire Pumps BACT Analysis
In the event of the loss of normal auxiliary power, ac power will be supplied by a
new 2,937 bhp, 2,000 kW, No. 2 fuel oil fired emergency generator. Additionally, a new
emergency fire pump and fire booster pump will supply emergency fire water to the
Project using 575 and 149 bhp diesel engines, respectively. The emergency generator
and fire pumps will be periodically tested for no more than 1 to 2 hours per week
(100 h/y) to confirm its ready-to-start condition. Because of their small size, infrequent
operation, and status as emergency equipment, the installation of post-combustion
emission controls such as SCR and SNCR for NOx, or FGD systems for SO2, or oxidation
catalyst for CO, while technically feasible for emergency generators and fire pumps, are
far from cost-effective as control devices and are therefore not practical as BACT control
alternatives. As such, IPL has determined that BACT for the emergency generator and
fire pumps is limited operation and good combustion controls while firing low sulfur
(0.05 percent) distillate fuel oil based on manufacturer’s emission estimates presented in
Appendix F. The proposed BACT determinations have no adverse environmental or
energy impacts and are summarized below for each pollutant.
10.1
Select SO2 BACT
The emergency generator and fire pumps will emit small quantities of SO2 as a
result of the oxidation of sulfur in the fuel. A review of the informational databases
discussed in Section 2.1 indicated that low sulfur distillate fuel oil is the most stringent
permitted control for similar types of units operated in the manner proposed by IPL. No
post-combustion FGD system has ever been applied to a generator/fire pump this small
that is firing a low sulfur oil. Therefore, low sulfur fuel oil (containing less than
0.05 percent sulfur) is proposed as the BACT. The BACT control is good combustion
control and low sulfur fuel oil.
10.2
Select NOx BACT
A review of the information contained in the RBLC indicated the following:
•
The most stringent NOx emission limit permitted for a small diesel
generator is the Duke Energy Field Services, LP, Mooreland Cryogenic
Plant located in Oklahoma.
The emission limit is 2.0 g/bhph
(approximately 0.0059 lb/kW).
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Sutherland Unit 4 Air Permit Application
10.0 Emergency Generator and
Fire Pumps BACT Analysis
•
The next most stringent NOx emission limit permitted for a small diesel
generator is the Arizona Clean Fuel Yuma, LLC, located in Arizona. The
emission limit is 4.0 g/bhph (approximately 0.012 lb/kW).
Further review of the informational databases discussed in Section 2.1 indicated
that emergency generators and fire pumps have not been required to install additional
NOx controls because their operation is of an intermittent nature. As discussed in
Subsection 2.1.1.4, the engines must meet the applicable NSPS, which will apply
depending on the year of engine manufacture. The proposed BACT levels for NOx
presented in Table 1-1 are based on the estimated emission levels supplied by vendors,
which will be in compliance with the NSPS limit. The BACT control is good combustion
control.
10.3
Select PM/PM10 BACT
A review of the information contained in the RBLC indicated the following:
•
The most stringent PM/PM10 emission limit permitted for an internal
combustion engine firing fuel oil to date is a requirement equivalent to
0.07 g/bhph (approximately 0.00021 lb/kWh) for the Ace Ethanol, LLC,
Stanley Plant (1.38 MW unit), located in Wisconsin. The control
technology for this unit is complete combustion.
•
The next most stringent PM/PM10 emission limit permitted for an internal
combustion engine firing fuel oil to date is a requirement equivalent to
0.2 g/bhph (approximately 0.00059 lb/kWh) for the Arizona Clean Fuels
Yuma, LLC (1.60 MW unit), located in Arizona. The control technology
for this unit is complete combustion.
The emergency generator and fire pumps will emit small quantities of particulates
consisting of ash in the fuel and residual carbon and hydrocarbons caused from
incomplete combustion. A review of the informational databases discussed in Section 2.1
indicated that good combustion control was the most stringent control permitted for
similar units. Therefore, because of the very low operating hours of the emergency
generator and fire pumps, good combustion control and engine design are proposed as
BACT.
As discussed in Subsection 2.1.1.4, the engines must meet the applicable NSPS,
which will depend on the year of engine manufacture. The proposed BACT levels
presented in Table 1-1 are based on the estimated emissions level supplied by vendors,
which will be in compliance with the NSPS limit. The BACT control is good combustion
control.
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Sutherland Unit 4 Air Permit Application
10.4
10.0 Emergency Generator and
Fire Pumps BACT Analysis
Select CO BACT
A review of the information contained in the RBLC indicated the following:
•
The units with the most stringent CO emission limit permitted for a small
diesel generator are the Okemo Mountain Inc. Mill River Lumber and the
Sithe Mystic facilities. These facilities are in nonattainment areas where
higher removal standards exist. The emission limit for these sites is
0.6 g/bhph (approximately 0.0018 lb/kWh).
•
The next most stringent CO emission limit for a small diesel generator is
the Ace Ethanol, LLC, Stanley Plant located in Wisconsin. The emission
limit for this site is 1 g/bhph (approximately 0.003 lb/kWh).
The control technologies for CO emissions evaluated for use on the emergency
generator and fire pumps are catalytic oxidation and proper design to minimize
emissions. Because of the intermittent operation and low emissions, add-on controls
would be prohibitively expensive. Thus, good combustion control is proposed as BACT
for controlling the CO emissions from the emergency generator.
As discussed in Subsection 2.1.1.4, the engines must meet the NSPS that will
apply, depending on the year of engine manufacture. The proposed BACT levels for CO
presented in Table 1-1 are based on the estimated emissions level supplied by vendors,
which will be in compliance with the NSPS limit. The BACT control is good combustion
control.
10.5
Select VOC BACT
A review of the information contained in the RBLC indicated the following:
•
The unit with the most stringent VOC emission limit for a small diesel
generator is the Ace Ethanol, LLC, Stanley Plant located in Wisconsin.
The emission limit for this site is 0.120 g/bhph (approximately
0.00035 lb/kWh).
The control technologies for VOC emissions evaluated for use on the emergency
generator and fire pumps are catalytic oxidation and proper engine design to minimize
emissions. Because of the intermittent operation and low emissions, add-on controls
would be prohibitively expensive. Thus, good combustion control is proposed as BACT
for controlling the VOC emissions from the emergency generator and fire pumps.
As discussed in Subsection 2.1.1.4, the engines must meet the applicable NSPS,
which will depend on the year of engine manufacture. The proposed BACT levels for
VOC presented in Table 1-1 are based on the estimated emission level supplied by
vendors, which will be in compliance with the NSPS limit. The BACT control is good
combustion control.
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Sutherland Unit 4 Air Permit Application
10.6
10.0 Emergency Generator and
Fire Pumps BACT Analysis
Select H2SO4 BACT
The emergency generator and fire pumps will emit small quantities H2SO2 as a
result of the oxidation of SO2 in the exhaust. A review of the informational databases
discussed in Section 2.1 indicated that low sulfur distillate fuel oil was the most stringent
permitted control for similar types of units. Therefore, low sulfur fuel oil (containing less
than 0.05 percent sulfur) is proposed as BACT. The BACT control is good combustion
control and low sulfur fuel oil.
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11.0 Gate Station
Heater BACT Analysis
11.0 Gate Station Heater BACT Analysis
The gate station heater receives high-pressure natural gas from a single interface
point for the natural gas supply system. As the natural gas is extracted from the high
pressure pipeline across a pressure reducing control valve, the reduction in pressure will
naturally cool the gas below the dew point temperature and to a temperature too low to be
combusted in the boilers. As such, a natural gas fired gate station heater will be used to
heat the natural gas upstream of the pressure reducing device to prevent the gas from
dropping below the recommended operating temperature. The gate station heater will
have a maximum heat input limit of 3 MBtu/h and designed for continuous operation.
Because of its small size, the installation of postcombustion emission controls, such as
SCR and SNCR for NOx, or FGD systems for SO2, or oxidation catalyst for CO, while
technically feasible for the gate state heater, are far from cost-effective as control devices
and are therefore not practical as BACT control alternatives. As such, IPL has
determined that BACT for the gate station heater, which is similar to a process heater, is
good combustion controls while firing low sulfur pipeline natural gas. The proposed
BACT determinations have no adverse environmental or energy impacts and are
summarized below for each pollutant.
11.1
Select SO2 BACT
The gate station heater will emit small quantities of SO2 as a result of the
oxidation of sulfur in the fuel. A review of the informational databases discussed in
Section 2.1 indicated that low sulfur pipeline natural gas is the most stringent permitted
control for similar types of units operated in the manner proposed by IPL. No
postcombustion FGD system has ever been applied to a gate station heater or process
heater this small that is firing low sulfur pipeline natural gas. Therefore, low sulfur
pipeline natural gas is proposed as the BACT. The BACT control is good combustion
control and low sulfur pipeline natural gas.
11.2
Select NOx BACT
A review of the information contained in the RBLC indicated the following:
•
The most stringent NOx emission limit permitted for a gate station heater
is the Wisconsin Public Service, Weston Plant located in Wisconsin. The
emission limit is 0.024 lb/MBtu for a 0.75 MBtu/h natural gas gate station
heater. Firing natural gas is documented as the control technology.
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Interstate Power and Light
Sutherland Unit 4 Air Permit Application
•
11.0 Gate Station
Heater BACT Analysis
The next most stringent NOx emission limit permitted for a small natural
gas heater is the Interstate Power and Light, Emery Generating Station
located in Iowa. The emission limit is 0.0490 lb/MBtu for a 9.0 MBtu/h
natural gas heater. LNB is documented as the control technology.
•
The next most stringent NOx emission limit permitted for a small natural
gas heater is Cresent City Power, LLC, located in Louisiana. The
emission limit is 0.095 lb/MBtu for a 19.0 MBtu/h natural gas heater.
LNB and good combustion practices are documented as the control
technology.
Further review of the informational databases discussed in Section 2.1 indicated
that gate station heaters or small process heaters have not been required to install
additional NOx controls because of their size. The proposed BACT levels for NOx
presented in Table 1-1 are based on the estimated emission levels supplied by vendors.
The BACT control is LNB and good combustion control.
11.3
Select PM/PM10 BACT
A review of the information contained in the RBLC indicated the following:
•
The most stringent PM/PM10 emission limit permitted for a gate station
heater is the Wisconsin Public Service, Weston Plant located in
Wisconsin. The emission limit is 0.0033 lb/MBtu for a 0.75 MBtu/h
natural gas gate station heater. Firing natural gas is documented as the
control technology.
•
The next most stringent PM/PM10 emission limit permitted for a small
natural gas heater is Cresent City Power, LLC, located in Louisiana. The
emission limit is 0.007 lb/MBtu for a 19.0 MBtu/h natural gas heater.
Firing natural gas and good combustion practices are documented as the
control technology.
•
The next most stringent PM/PM10 emission limit permitted for a small
natural gas heater is the Interstate Power and Light, Emery Generating
Station located in Iowa. The emission limit is 0.0075 lb/MBtu for a
9.0 MBtu/h natural gas heater. Firing natural gas is documented as the
control technology.
The gate station heater will emit very small quantities of particulates from burning
pipeline natural gas. A review of the informational databases discussed in Section 2.1
indicated that firing pipeline natural gas was the most stringent control permitted for
similar units. Therefore, the proposed BACT control is pipeline natural gas and good
combustion controls.
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11.4
11.0 Gate Station
Heater BACT Analysis
Select CO BACT
A review of the information contained in the RBLC indicated the following:
•
The most stringent CO emission limit permitted for a gate station heater
is the Wisconsin Public Service, Weston Plant located in Wisconsin. The
emission limit is 0.02 lb/MBtu for a 0.75 MBtu/h natural gas gate station
heater. Firing natural gas is documented as the control technology.
•
The next most stringent CO emission limit permitted for a small natural
gas heater is Cresent City Power, LLC, located in Louisiana. The
emission limit is 0.08 lb/MBtu for a 19.0 MBtu/h natural gas heater. Good
combustion practices is documented as the control technology.
•
The next most stringent CO emission limit permitted for a small natural
gas heater is the Interstate Power and Light, Emery Generating Station
located in Iowa. The emission limit is 0.082 lb/MBtu for a 9.0 MBtu/h
natural gas heater. Good combustion practices is documented as the
control technology.
Further review of the informational databases discussed in Section 2.1 indicated
that gate station heaters or small process heaters have not been required to install
additional CO controls because of their size and because it would be prohibitively
expensive. The proposed BACT levels for CO presented in Table 1-1 are based on the
estimated emission levels supplied by vendors. The BACT control is good combustion
control.
11.5
Select VOC BACT
A review of the information contained in the RBLC indicated the following:
•
The most stringent VOC emission limit permitted for a gate station heater
is the Wisconsin Public Service, Weston Plant located in Wisconsin. The
emission limit is 0.0013 lb/MBtu for a 0.75 MBtu/h natural gas gate
station heater. Firing natural gas is documented as the control technology.
•
The next most stringent VOC emission limit permitted for a small natural
gas heater is Cresent City Power, LLC, located in Louisiana. The
emission limit is 0.005 lb/MBtu for a 19.0 MBtu/h natural gas heater.
Good combustion practices is documented as the control technology.
•
The next most stringent VOC emission limit permitted for a small natural
gas heater is the Interstate Power and Light, Emery Generating Station
located in Iowa. The emission limit is 0.0054 lb/MBtu for a 9.0 MBtu/h
natural gas heater. Good combustion practices is documented as the
control technology.
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Sutherland Unit 4 Air Permit Application
11.0 Gate Station
Heater BACT Analysis
Further review of the informational databases discussed in Section 2.1 indicated
that gate station heaters or small process heaters have not been required to install
additional VOC controls because of their size and because it would be prohibitively
expensive. The proposed BACT levels for VOC presented in Table 1-1 are based on the
estimated emission levels supplied by vendors. The BACT control is good combustion
control.
11.6
Select H2SO4 BACT
The gate station heater will emit small quantities of H2SO2 as a result of the
oxidation of SO2 in the exhaust. A review of the informational databases discussed in
Section 2.1 indicated that low sulfur pipeline natural gas is the most stringent permitted
control for similar types of units operated in the manner proposed by IPL. Therefore, low
sulfur pipeline natural gas is proposed as the BACT. The BACT control is good
combustion control and low sulfur pipeline natural gas.
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12.0 Cooling Tower BACT Analysis
12.0 Cooling Tower BACT Analysis
A new multicell linear mechanical draft cooling tower will be used to dissipate
heat from the condensing water of the Project’s main boiler. Particulate from cooling
towers is generated by the presence of dissolved and suspended solids in the cooling
tower circulation water, which is potentially lost as “drift” or moisture droplets that are
suspended in the air moving out of the cooling tower. A portion of the water droplets
emitted from the tower exhausts will evaporate, leaving the suspended or dissolved solids
in the atmosphere.
12.1
Step 1--Identify All Control Technologies
The particulate emissions from the cooling towers can be controlled by
minimizing the amount of water drift that occurs and/or minimizing the amount of
dissolved solids in the water. This can be accomplished by using high efficiency drift
eliminators, a decreased number of cycles of circulating water concentration, or a
combination of both. The number of cycles of water concentration is limited by the
amount of water available for use, since lower levels of concentration require increased
cooling tower blowdown and more water intake to offset the blowdown.
12.2
Step 2--Eliminate Technically Infeasible Options
A review of drift eliminators as particulate control technology for cooling towers
concluded that they are technically feasible for the specific type of application discussed
in Section 11.1. In addition, drift eliminators were the only control technology identified
as technically feasible.
12.3
Step 3--Rank Remaining Control Technologies by
Effectiveness
A review of information contained in the USEPA BACT/LAER Clearinghouse
and other sources specified in Section 2.1 revealed that drift eliminators are most
frequently identified as the top BACT control technologies for cooling towers. The
results of this review indicate the following:
•
The lowest emission limit currently in place for a utility sized cooling
tower is 0.0005 percent drift for a variety of plants, including the
Newmont Mining Corporation TS Power Plant located in Nevada
(Permitted: May 2005), the Omaha Public Power District Nebraska City
Station located in Nebraska (Permitted: March 2005), the Mustang
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12.0 Cooling Tower BACT Analysis
Energy Project located in Oklahoma (Permitted: February 2002), the
Wallula Power Plant located in Washington (Permitted: October 2002),
and the Rocky Mountain Power Project located in Colorado (Permitted:
August 2002).
12.4
•
The lowest permitted plant in Iowa is the Mid-American Energy Company
project located in Pottawattamie County, which was permitted in June of
2003 at 0.0005 percent drift.
•
The Longview Project in West Virginia and the Weston Unit 4 project in
Wisconsin have been permitted at a drift rate of 0.002 percent.
•
The Duke Energy Satsop Combustion Turbine Project in Grays Harbor
County, Washington, and the Cornbelt Plant in Illinois have been
permitted at a drift rate of 0.001 percent.
Step 4--Evaluate Most Effective Controls and Document
Results
In the following subsections, the technically feasible control alternatives are
evaluated in a comparative approach with respect to their energy, environmental, and
economic impacts to the Project.
12.4.1 Energy Evaluation of Alternatives
There are no significant energy impacts that would preclude the use of drift
eliminators as particulate control technologies as presented in this evaluation.
12.4.2 Environmental Evaluation of Alternatives
There are no significant environmental impacts that would preclude the use of
drift eliminators as particulate control technologies as presented in this evaluation.
12.4.3 Economic Evaluation of Alternatives
There are no significant economic impacts that would preclude the use of drift
eliminators as particulate control technologies as presented in this evaluation.
12.5
Step 5--Select BACT
The proposed cooling tower BACT for this Project is the use of drift eliminators
for particulate control, with a cooling tower design drift rate of 0.0005 percent.
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13.0 Material Handling
Systems BACT Analysis
13.0 Material Handling Systems BACT Analysis
This section presents the top-down, five-step BACT process used to evaluate and
determine the Project’s particulate emission controls for the material handling systems
used to store and convey coal, limestone, fly ash, and biomass. Many of the material
handling system components subject to particulate BACT review are described below.
13.1
Coal Handling
The function of the coal handling system is to receive and unload coal delivered
by rail cars; provide a means to stock out and store the coal in active and reserve storage
piles; provide the means to reclaim, blend, and crush the coal to the desired size; and
supply the coal to the Unit 4 silos to satisfy plant usage requirements. The coal handling
system will also be sized to serve existing Units 1, 2, and 3 by providing a separate
stockout facility to store coal unloaded by the Unit 4 unloading facility and to provide a
separate reclaim facility to reclaim coal designated for Units 1, 2, and 3.
Coal will be delivered to the facility by unit train consisting of approximately 150
cars. Each of the rail cars will carry approximately 120 tons of coal. The coal received
in the plant will be unloaded by a rotary car dumper. The rotary car dumper will be
equipped with a rail car positioner, hopper, grizzly, and traveling hammermill for the
breaking of oversize and frozen coal. The unloaded coal will be collected by a hopper
and withdrawn by two belt feeders (BF-1 and BF-2). A dust suppression system (DS-1)
will control dust at BF-1 and BF-2, as well as Conveyor BC-1 loading points. A dust
collection system (DC) will control dust in the dumper building above the unloading
hopper.
The coal will be transferred from the feeders to unloading Conveyor BC-1, which
will take it to a transfer tower (TT-1). At TT-1, the coal will be directed to BC-4, which
feeds the stacker/reclaimer (SR-1). Under normal operating conditions, the unloaded coal
will be stacked out by Stacker/Reclaimer SR-1. During reclaiming, the boom conveyor
of Stacker/Reclaimer SR-1 will be reversed to support reclaim onto BC-4. In case of a
Stacker/Reclaimer SR-1 failure, the unloaded coal will be stacked out by an emergency
stacking conveyor, BC-2, equipped with a telescopic chute (CHE-1) and spray ring for
dust suppression.
Depending on operating requirements, the coal from the emergency pile may be
bulldozed directly into the yard storage or to the reclaim hopper (RH-1) and fed onto
Reclaim Conveyor BC-3 for stacking by SR-1 or sent directly to the plant as required.
Coal for existing Units 1, 2, and 3 will be fed from Reclaim Hoppers RH-4 and RH-5
onto a belt conveyor (BC-5A). Belt Conveyor BC-5A will discharge onto Belt Conveyor
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13.0 Material Handling
Systems BACT Analysis
BC-5B, at Transfer Tower TT-3. Conveyor BC-5B will deliver coal to a new hopper,
HPR-2, located over the existing hopper in the existing coal handling system for Units 1,
2, and 3. A side discharge chute and gate will be used to load coal trucks in an enclosed
structure and DC.
At the discharge point of Belt Conveyor BC-4, the coal will be directed through a
three-way flow diverting flop gate to allow the coal to be sent directly to the crushers or
onto Belt Conveyor BC-6 or Belt Conveyor BC-7 and stockpiled for blending during
reclaiming operations. Coal directed onto Belt Conveyor BC-6 will be stockpiled using a
telescopic chute (CHE-2) and reclaimed through an under-pile reclaim hopper (RH-2)
onto reclaim Belt Conveyor BC-8. Belt conveyor BC-8 will discharge into a flow
splitting gate; coal is directed simultaneously to both Belt Conveyors BC-10 and BC-11
for crushing.
Coal directed onto Belt Conveyor BC-7 will be stockpiled using Telescopic Chute
CHE-3 and reclaimed through an under-pile reclaim hopper (RH-3) onto the reclaim Belt
Conveyor BC-9. Belt Conveyor BC-9 will discharge into a flow splitting gate to provide
blending capability with coal from either BC-4 or BC-8.
Belt Conveyors BC-10 and BC-11 will feed coal to the crusher surge bin (SB-1)
located inside the crusher house (CH-1). Coal will be discharged from the crusher surge
bin outlets to feed two ring granulator crushers (CR-1 and CR-2). The crusher house will
contain a DC. Plant Conveyors BC-12 and BC-13 will deliver crushed coal from
Crusher House CH-1 to Transfer Tower TT-4. The discharge chutework of Conveyors
BC-12 and BC-13 will be provided with motorized flop gates to provide complete
crossover redundancy to feed either of the two tripper conveyors (BC-14 and BC-15).
Tripper Conveyors BC-14 and BC-15 will deliver coal to a traveling tripper--Conveyor
BC-14 to Traveling Tripper TRP-1 and Conveyor BC-15 to Traveling Tripper TRP-2.
Each traveling tripper will be equipped with a single discharge chute and will deliver coal
to any selected plant silo. A DC will provide dust control in Transfer Tower TT-4 and
the coal silos.
The following is a summary of the new coal handling equipment that is subject to
a particulate BACT review for the Project:
•
Coal Unloading--Rotary Car Dumper (DPR-1).
•
Coal Receiving--Belt Conveyor (BC-1).
•
Transfer Tower (TT-1).
•
Emergency Stockout--Belt Conveyor (BC-2).
•
Emergency Stockout Reclaim--Belt Conveyor (BC-3).
•
Stacker/Reclaimer Conveyor--Belt Conveyor (BC-4).
•
Stack/Reclaimer (SR-1).
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13.0 Material Handling
Systems BACT Analysis
•
Transfer Tower (TT-2).
•
Exiting Units Reclaim--Belt Conveyor (BC-5A).
•
Transfer Tower (TT-3).
•
Existing Units Feed--Belt Conveyor (BC-5B).
•
Truck Loadout.
•
Pile Stockout--Belt Conveyor (BC-6).
•
Pile Stockout--Belt Conveyor (BC-7).
•
Pile Reclaim--Belt Conveyor (BC-8).
•
Pile Reclaim--Belt Conveyor (BC-9).
•
Crusher Feed--Belt Conveyors (BC-10 and 11).
•
Crusher House (CH-1).
•
Plant Feed (SGS Unit 4)--Belt Conveyors (BC-12 and 13).
•
Tripper Conveyors--Belt Conveyors (BC-14 and 15).
•
Transfer Tower (TT-4).
13.2
Limestone Handling
The function of the limestone handling system is to receive bulk limestone by
bottom dump hopper rail cars (or, alternatively, by truck) to provide a means to stock out
and store the limestone in an active storage pile and to provide reclaim capacity to satisfy
plant usage requirements. Bulk limestone will be delivered by either bottom dump
hopper rail cars or dump trucks and will be unloaded into the limestone unloading
hopper, HPR-1. Belt Feeders FDR-1 and 2 will receive limestone from the unloading
hopper outlets and transfer it to the receiving conveyor, CVY-1, which will transfer the
material to the limestone storage pile through a telescopic chute, CHE-1, with wet
suppression. The conical shaped limestone storage pile will be enclosed by a covered
steel structure to protect the limestone from the weather.
The limestone will be reclaimed from the storage pile by two underground belt
feeders located below the vibrating drawdown hoppers, which will feed Reclaim
Conveyor CVY-2.
The reclaim conveyor will transfer the limestone to the
distribution/silo fill conveyor (CVY-3). This conveyor will have a two-way chute with
motorized diverter gate to fill each of two limestone silos equipped with fabric filter bin
vents.
The following is a summary of the limestone material handling equipment that is
subject to a particulate BACT review for the Project:
•
Limestone Unloading--Railcar/Truck Bottom Dumper.
•
Limestone Receiving/Stockout--Belt Conveyor (CVY-1).
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13.3
•
Limestone Reclaim--Belt Conveyor (CVY-2).
•
Distribution Conveyor--Belt Conveyor (CVY-3).
•
Two Limestone Storage Silos.
13.0 Material Handling
Systems BACT Analysis
Fly Ash Handling
The fly ash handling system is composed of two separate systems: saleable and
waste. The saleable fly ash handling system removes fly ash from the DESP hoppers and
transfers it to a saleable fly ash storage silo or a winter fly ash storage building via a
continuously operating pneumatic vacuum and vacuum/pressure conveying system. The
waste fly ash handling system removes fly ash from the fabric filter hoppers, air heater
hoppers, SCR hoppers, and economizer hoppers and transfers it via a continuously
operating pneumatic vacuum conveying system to a fly ash waste storage silo.
Fly ash from the saleable storage silo will be loaded into closed ash hauling trucks
or railcars for offsite sales, or conditioned and loaded into open dump trucks for
placement in a landfill via a dry telescoping spout. The winter saleable fly ash storage
building will be equipped with a pressurized conveying system to convey ash from the
DESP vacuum filter/separator hopper to the building. A mechanical conveying system
will transfer ash from the recovery hopper to a truck loadout system. Dust collection and
ash return equipment will be included to keep the building under negative pressure. Fly
ash from the waste storage silo will be conditioned and loaded into open dump trucks for
placement in a landfill. The fly ash waste silo will also be equipped with a dry
telescoping spout for loading into closed ash hauling trucks.
The following sections provide detailed descriptions of the two fly ash handling
systems.
13.4
Saleable Fly Ash Handling System
The saleable fly ash handling system will service all unit DESP hoppers, one
saleable fly ash storage silo, and one fly ash winter storage building. Each collection
point in the fly ash handling system will be tied into a sealed, pneumatic vacuum
conveying system. The conveying system will sequentially remove fly ash from the
DESP hoppers and transfer the material to either the saleable fly ash storage silo or the
winter storage building via a pressure conveying system.
Two vacuum filter/separators located on top of the saleable fly ash storage silo
will receive and transfer the material to the saleable fly ash storage silo via a double
dump airlock valve. A third vacuum filter/separator, located at ground level next to the
winter storage building, will receive and transfer the ash into the winter storage building
via a pressure pneumatic conveying system for future recovery into dry ash trucks. Each
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13.0 Material Handling
Systems BACT Analysis
vacuum filter/separator on the saleable fly ash silo will consist of a continuous operating
filter section with filter bags, a pulse jet filter bag cleaning system, an integral surge
hopper, and a double dump airlock valve assembly for discharge into the silo. The
vacuum filter/separator for the winter fly ash storage building will consist of a continuous
operating filter section with filter bags, pulse jet filter bag cleaning system, integral surge
hopper, and a pressure airlock pneumatic conveyor to convey the ash to the winter
storage building. Inside the building, a pressure conveying line will be provided with
branches to direct the ash to various areas of the building.
Two pneumatic conveying lines will convey material from the DESP branch lines
to each filter/separator. The two conveying lines will be capable of transporting ash to
the saleable fly ash storage silo or to the winter storage building pressure
conveying/distribution system. One conveying line will be provided to convey material
from the pressure airlock to the winter storage building, a distribution system with
automatic valves will direct ash to various areas of the building.
The saleable fly ash storage silo will be designed to receive and temporarily store
saleable fly ash from the conveying system. The silo will have pass-through access for
ash discharge to railcars and trucks. The saleable fly ash storage silo will be equipped
with a bin vent filter and fluidizing system to promote ash discharge during unloading. A
combination truck and rail car loading station will load saleable fly ash via a telescopic
chute assembly. The truck loading area beneath the saleable fly ash storage area will be
equipped with washdown facilities.
A winter storage building will receive and temporarily store saleable fly ash from
the DESP vacuum/pressure conveying system. To fill the building, one vacuum
filter/separator located at ground level will receive ash from the DESP hoppers and
discharge it through a pressure airlock into a pressure conveying line with multiple
branches to distribute the ash within the building. Each branch will be equipped with an
automatic isolation valve. Two dust collectors with ID fans will be provided to pull dust
laden air from inside the building. The dust collector will maintain the building under a
slight negative pressure. A rotary airlock and screw conveyor will be provided at the
discharge of the dust collector hopper to convey accumulated dust back into the building.
An air gravity conveyor, in conjunction with a front-end loader, will recover fly
ash in the winter storage building to an ash recovery hopper. Ash collected in the
recovery hopper will be conveyed by screw conveyor to a truck loadout area. The screw
conveyor will discharge into a bucket elevator, which will convey the material up into a
dry loadout station positioned over a truck drive-through. Trucks will be loaded via a
telescopic chute assembly.
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13.5
13.0 Material Handling
Systems BACT Analysis
Waste Ash Handling
The waste fly ash handling system will service the fabric filter hoppers, air heater
hoppers, SCR hoppers, economizer hoppers, and one fly ash waste storage silo. Each
collection point in the waste fly ash handling system will be tied into a pneumatic
vacuum conveying system via ash intake valves arranged in a straight branch line off the
main conveying lines. The conveying system will sequentially remove fly ash from the
hoppers and transfer the material to the fly ash waste storage silo.
Two vacuum filter/separators located on top of the fly ash waste storage silo will
receive and transfer the material to the fly ash waste storage silo via the double dump
airlock valves. Each vacuum filter/separator on the fly ash waste silo will consist of a
continuously operating filter section with filter bags, pulse jet filter bag cleaning system,
integral surge hopper, and double dump airlock valve assembly for discharge into the
silo. A dust detector will be furnished to detect broken filter bags and prevent intrusion of
ash into the exhausters.
Two pneumatic conveying lines will convey material from the fabric filter branch
lines to each filter/separator. Each row of fabric filter hoppers will have an independent
conveying line. The two conveying lines will be capable of transporting ash to the fly
ash waste storage silo. Pneumatic conveying lines will convey material from the air
heater hoppers, SCR hoppers, and economizer hoppers to each filter/separator. These
conveying lines will tie into the conveying lines from the fabric filter.
The fly ash waste storage silo will be designed to receive and temporarily store fly
ash from the conveying system. The silo will have pass-through access for ash discharge
to trucks. The fly ash waste storage silo will be equipped with a bin vent filter and
fluidizing system to promote ash discharge during unloading. Ash conditioning pugmills
will be provided as the primary means of ash unloading from the fly ash storage silo.
Flow control valves will be provided to meter the ash and water into the pugmill. The
silo will also be equipped with a dry fly ash loadout station equipped with a telescopic
chute assembly.
A summary of the saleable and waste fly ash handling equipment subject to
particulate BACT review for the Project is provided below:
•
Saleable fly ash storage silo.
•
Saleable fly ash separators.
•
Combination railcar/truck loader (from saleable fly ash storage silo).
•
Saleable fly ash winter ash storage building.
•
Saleable fly ash truck loader (from winter storage building).
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13.6
•
Waste fly ash storage silo.
•
Waste fly ash separators.
•
Truck loader (from waste fly ash storage silo).
13.0 Material Handling
Systems BACT Analysis
FGD Solids Handling
The FGD solids handling system will collect and dewater the solids produced
within the wet FGD and transport the dewatered moist solids to an enclosed storage
building or an emergency stockpile. The quality of FGD solids produced will be of
“wallboard” grade gypsum. Two vacuum filters will dewater the FGD solids. The
dewatered FGD moist solids will be discharged from the vacuum filters onto one of the
two FGD solids product conveyors (GC-1A or 1B) through motorized diverter gates.
Conveyor GC-1A will transfer the FGD moist solids to Transfer Conveyor GC-2. The
Transfer Conveyor GC-2 will transfer the moist solids to an elevated shuttle belt
conveyor, GC-3, located inside of the FGD solids storage building. The shuttle conveyor
will prepare a series of conical or elongated piles of solids inside the building. Finally,
the FGD moist solids from the storage building, or the emergency stockpile as necessary,
will be loaded onto trucks. The FGD solids are disposed of as moist solids and either
hauled by trucks offsite or to the onsite byproduct storage area.
The FGD solids take the form of a wet solid material. The FGD solids are
dewatered, but remain moist during all handling, conveyance, and storage operations and
do not create any fugitive dust except for that resulting from truck transportation.
13.7
Bottom Ash Handling
The bottom ash handling system collects and removes bottom ash from the
bottom of the steam generator furnace and collects coal pulverizer (pyrites) rejects. All
are gathered in the upper trough of a submerged scraper conveyor (SSC) and conveyed to
a three-walled ash storage bunker.
Bottom ash produced in the steam generator furnace will fall into the water-filled
upper trough of the SSC. DeNOx and economizer ash will be transferred via dry drag
chain conveyors to the SSC outside of the seal plates. Rejects from the coal pulverizers
will be sluiced to the SSC outside of the seal plates. The collected ash and coal
pulverizer rejects in the upper trough of the SSC will be conveyed up a dewatering slope
and discharged into a three-sided concrete storage bunker located indoors. Periodically,
the bottom ash will be loaded directly into ash dump trucks for offsite sales or transport
to the onsite byproducts storage area.
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13.0 Material Handling
Systems BACT Analysis
The bottom ash takes the form of a wet solid material. The bottom ash is
dewatered, but remains moist during all handling, conveyance, and storage operations
and does not create any fugitive dust except for that resulting from truck transportation.
13.8
Biomass Handling
The biomass fuel is harvested into bales, which are of approximate dimensions of
3 feet by 3 feet by 8 feet and weigh approximately 700 pounds or 3 feet by 4 feet by
8 feet and weigh approximately 1,000 pounds. The bales will be delivered to the site on
flatbed trailers with 54 (3 feet by 3 feet by 8 feet) bales or 36 (3 feet by 4 feet by 8 feet)
bales on each trailer. The bales will then be unloaded with a forklift and piled in the
storage building.
The bales will be picked up with the forklift and placed on a conveyor. The
binding twine will automatically be cut and retrieved from the bale prior to the bale
feeding into the “debaler,” a hammermill, which will mill the biomass before sending it
through a sizing screen.
After passing through the screen, the biomass will be collected and conveyed to
the “eliminator,” an attrition mill configured to reduce the biomass to the selected size for
pneumatic conveying to the boiler. Prior to the biomass reaching the attrition mill, a
magnetic belt traversing the feed conveyor will collect all foreign metal objects captured
during the baling process.
A fabric filter and separator will pull the biomass material from the eliminator
grinder, where the heavy material will drop down a surge bin, and the lighter material
will move into the fabric filter for collection.
The biomass material will then be removed from the fabric filter through the tube
conveyor to storage surge bins for pneumatic transport to the boiler. All of the equipment
downstream of the eliminator grinder will be kept at a slight negative pressure for dust
control.
13.9
Other Material Handling
The transportation and handling of various materials associated with bulk material
storage, material delivery, and material disposal within the site boundaries or offsite will
result in particulate emissions. These include, for example, truck deliveries (onsite or
offsite, as applicable) of limestone, ash, FGD solids, and coal, as well as bulk material
storage piles and pile maintenance.
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13.0 Material Handling
Systems BACT Analysis
A summary of various other material handling activities is provided as follows:
•
Haul roads for material deliveries and disposal.
•
Active coal storage piles.
•
Inactive coal storage piles.
•
Limestone storage pile.
•
Saleable fly ash winter storage pile.
•
Front-end loader/bulldozing activities for loading/unloading materials and
pile maintenance.
13.10 Step 1--Identify All Control Technologies
Particulate emissions from the Project’s material handling systems are generally
the result of (depending on the specific material) material storage, material conveyance,
unloading, processing/crushing, and haul roads. For those systems that can be easily
enclosed, the most predominant and effective particulate control technology is an
enclosure with a fabric filter dust collection system. In those circumstances where
particulate capture is difficult to achieve (thereby reducing the control effectiveness of a
fabric filter dust collection system), the application of water or chemical surfactants (i.e.,
wet suppression) can be used. These types of operations typically include partially
enclosed material handling transfer points, storage piles, and haul roads. Telescopic
chutes and pneumatic transfer systems are often used in combination with other dust
control techniques such as dust suppression spray rings at unloading points and stockout
points. Particulate emissions from haul roads and front-end loading activities are
effectively controlled by paving, road washing, and/or wet suppression as previously
discussed.
13.11 Step 2--Eliminate Technically Infeasible Options
A review of the aforementioned material handling control technologies concluded
that they are each technically feasible for the specific type of application discussed in
Section 12.1.
13.12 Step 3--Rank Remaining Control Technologies by
Effectiveness
A review of information contained in the USEPA BACT/LAER Clearinghouse
and other sources specified in Section 2.1 revealed that wet suppression, covered
conveyance, and fabric filter dust collection systems are most frequently identified as the
top BACT control technologies for material handling processes. Fabric filter dust
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13.0 Material Handling
Systems BACT Analysis
collection systems achieve in excess of 99 percent control efficiency, with typical grain
loading rates of 0.01 gr/dscf for coal and ash handling and 0.005 gr/dscf for limestone
handling.
13.13 Step 4--Evaluate Most Effective Controls and Document
Results
In the following subsections, the technically feasible control alternatives are
evaluated in a comparative approach with respect to their energy, environmental, and
economic impacts to the Project.
13.13.1 Energy Evaluation of Alternatives
There are no significant energy impacts that would preclude the use of the
material handling particulate control technologies presented in this evaluation.
13.13.2 Environmental Evaluation of Alternatives
There are no significant environmental impacts that would preclude the use of the
material handling particulate control technologies presented in this evaluation.
13.13.3 Economic Evaluation of Alternatives
Because the highest level of technically feasible controls are proposed (i.e.,
building enclosures, 100 percent conveyance belt enclosures, water suppression, dust
collectors, and telescopic chutes) for the Project’s material handling systems, a
comparative economic analysis is not required.
13.14 Step 5--Select BACT
IPL has determined that for those material handling systems that can be
reasonably and economically enclosed, the use of a 100 percent enclosure, wet
suppression, and a fabric filter dust collection system represents particulate BACT. Road
pavement and surface cleaning and wet suppression will control particulate emissions
from delivery/haul roads and front-end loader operation. Material off-loading activities
will employ pneumatic conveyance and telescopic chutes to control particulate emissions.
The aforementioned control technologies represent the top control technologies evident in
recent permits for similar sized units, fuels, and processes.
Table 13-1 summarizes the material handling particulate emission sources
(explained in detail in Section 13.1) and the selected BACT control technology.
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13.0 Material Handling
Systems BACT Analysis
Table 13-1
Material Handling Particulate BACT Determinations
System
Emission Source
BACT Control Technology Determination
Rotary Car Dumper (DPR-1)
Coal Unloading
100% building enclosure
Dust collection system (0.01 gr/dscf)
100% belt enclosure and dust collection system
(0.01 gr/dscf)
100% transfer tower enclosure (TT-1) and dust
collection system (0.01 gr/dscf)
100% belt enclosure
Telescopic chute and spray ring (CHE-1)
100% belt enclosure
Belt Conveyor (BC-1) Coal
Receiving
Transfer Tower (TT-1)
Belt Conveyor (BC-2)
Emergency Stockout
Belt Conveyor (BC-3)
Emergency Stockout Reclaim
Belt Conveyor (BC-4)
Stacker/Reclaimer Conveyor
Stack/Reclaimer (SR-1)
Transfer Tower (TT-2)
Belt Conveyor (BC-5A)
Existing Units Reclaim
Transfer Tower (TT-3)
Coal Handling
Belt Conveyor (BC-5B)
Existing Units Feed
Truck Loadout
Belt Conveyor (BC-6) Pile
Stockout
Belt Conveyor (BC-7) Pile
Stockout
Belt Conveyor (BC-8) Pile
Reclaim
Belt Conveyor (BC-9) Pile
Reclaim
Belt Conveyors (BC-10 and
11) Crusher Feed
Crusher House (CH-1)
Belt Conveyors (BC-12 and
13) Plant Feed (SGS Unit 4)
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Partial belt enclosure
Dust suppression
100% transfer tower enclosure (TT-2) and dust
collection system (0.01 gr/dscf)
100% belt enclosure and dust collection system
(0.01 gr/dscf)
100% transfer tower enclosure (TT-3) and dust
collection system (0.01 gr/dscf)
100% belt enclosure
100% building enclosure
Dust collection system (0.01 gr/dscf)
Loadout chute
100% belt enclosure
Telescopic chute and spray ring (CHE-2)
100% belt enclosure
Telescopic chute and spray ring (CHE-3)
100% belt enclosure and dust collection system
(0.01 gr/dscf)
100% belt enclosure and dust collection system
(0.01 gr/dscf)
100% belt enclosure
100% crusher building enclosure (CH-1)
Dust collection system (0.01 gr/dscf)
100% belt enclosure
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13.0 Material Handling
Systems BACT Analysis
Table 13-1 (Continued)
Material Handling Particulate BACT Determinations
System
Coal Handling
(Continued)
Emission Source
BACT Control Technology Determination
Transfer Tower (TT-4)
100% transfer tower enclosure (TT-4) and dust
collection system (0.01 gr/dscf)
100% belt enclosure
100% boiler house enclosure and dust collection
system (0.01 gr/dscf)
Belt Conveyors (BC-14 and
15) Tripper Conveyors
Railcar/Truck Bottom Dumper
Limestone Unloading
Belt Conveyor (CVY-1)
Limestone Receiving/Stock
Out
Limestone Handling
Belt Conveyor (CVY-2)
Limestone Reclaim
Belt Conveyor (CVY-3)
Distribution Conveyor
Two Limestone Storage Silos
Saleable Fly Ash Storage Silo
Saleable Fly Ash Separators
Combination Railcar and
Truck Loader (from saleable
fly ash storage silo)
Saleable Fly Ash Winter
Storage Building
Fly Ash Handling
100% building enclosure
Dust collection system (0.005 gr/dscf)
100% belt enclosure and dust collection system
(0.005 gr/dscf)
Telescopic chute (CHE-1) and dust suppression
(DS-2)
75% storage building enclosure
100% belt enclosure
100% belt enclosure and dust collection system
(0.005 gr/dscf)
Bin vent fabric filter
Bin vent fabric filter
Exhaust vent fabric filter
Telescopic chute
Truck washdown facility
100% storage building enclosure
Dust collection system (0.01 gr/dscf)
Telescopic chute
Saleable Fly Ash Truck
Loader (from winter storage
building)
Waste Fly Ash Storage Silo
Bin vent fabric filter
Waste Fly Ash Separators
Exhaust vent fabric filter
Truck Loader (from waste fly
ash storage silo)
Telescopic chute
FGD Waste Handling
Wet Solids Material
No fugitive or point source emissions
Bottom Ash Handling
Wet Solids Material
No fugitive or point source emissions
Biomass Handling
Bale Conveyor
No fugitive or point source emissions
Hammermill
No fugitive or point source emissions
Eliminator Ginder
Dust collection system (0.01 gr/dscf)
Tube Conveyor
Dust collection system (0.01 gr/dscf)
Surge Bin w/rotary air lock
Dust collection system (0.01 gr/dscf)
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13.0 Material Handling
Systems BACT Analysis
Table 13-1 (Continued)
Material Handling Particulate BACT Determinations
System
Emission Source
BACT Control Technology Determination
Haul Roads – Material
Delivery and Disposal
Paved roads
Road surface cleaning
Wet dust suppression
Wet dust suppression and chemical surfactant
Pile best management practices
Crusting agent
Wet dust suppression and chemical surfactant
75% storage building enclosure
100% storage building enclosure
Dust collection system (0.01 gr/dscf)
Limited operation
Wet dust suppression
Active Coal Storage Piles
Other Material
Handling
Inactive Coal Storage Piles
Limestone Storage Pile
Saleable Fly Ash Winter
Storage Pile
Front End Loader/Dozer
Note: Detailed material handling process flow diagrams identifying the material handling systems, emission
sources, and particulate BACT control equipment are included in Appendix E of the air permit application.
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Attachment A
Attachment A
Coal Fired Boiler Top-Down RBLC
Clearinghouse Review Results
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Attachment B
Attachment B
Auxiliary Boiler Top-Down RBLC
Clearinghouse Review Results
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Appendix I
Appendix I
Air Dispersion Modeling Protocol and Electronic Modeling Files
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I-1
October, 2007
Ms. Lori Hanson
Lead Worker, Air Quality Modeling Group
Iowa Department of Natural Resources
7900 Hickman Road; Suite 1
Urbandale, IA 50322
RE:
Revised PSD Dispersion Modeling Protocol and Results for Interstate Power
and Light (IPL) Sutherland Generation Station Unit 4, Marshalltown, Iowa
Dear Ms. Hanson:
Interstate Power and Light (IPL) submitted a preliminary PSD Dispersion Modeling
Protocol to the Iowa Department of Natural Resources (IDNR) on April 11, 2007. Based
on IDNR protocol comments dated May 2, 2007, and a pre-application meeting on
September 24, 2007, IPL is submitting via this letter, a revised Protocol with
corresponding modeling results. This Protocol will provide the basis of a mutually agreed
upon final Ambient Air Quality Impact Analysis (AAQIA) in support of the air
construction permit application.
Should you have any questions concerning the content of this letter, please contact me at
319-786-4476, or by e-mail at [email protected]
Sincerely,
Alan Arnold
Senior Environmental Specialist
Interstate Power and Light
Cc:
Jeff Beer, IPL Project Director
Andy Byers, Environmental Manager, Black & Veatch
Tim Hillman, Air Permitting Manager, Black & Veatch
1
Ambient Air Quality Impact Analysis and Results
Sutherland Generating Station Unit 4
As discussed in the pre-application introductory meeting held at IDNR’s office on
February 7, 2007, Interstate Power and Light (IPL) is proposing to install Sutherland
Generating Station Unit 4 (SGS4), a nominal 649 megawatt (MW) (net) supercritical
pulverized coal-fired (PC) boiler at the existing Sutherland Generating Station located on
the east side of Marshalltown, Iowa. The specific location of the SGS4, also referred to as
“Project”, is illustrated in Figure 1.
In addition to the new boiler, new material handling equipment will be installed for coal,
limestone, ash, gypsum, and biomass. The coal material handling system will be designed
to accommodate the unloading of coal in amounts capable of sustaining annual facility
operations and will consist of a railcar unloader, fuel blending facility, active and longterm coal storage piles, and conveyor systems. Similarly, the other material systems will
be designed to store, process, and transport their materials. The Project will also include
ancillary equipment such as a cooling tower, auxiliary boiler, natural gas fuel heater,
emergency diesel generator, and two emergency diesel fire pumps. Site arrangements for
the proposed Project are contained in Attachment 1. As a part of this submittal, the main
boiler, material handling systems and each auxiliary equipment have been evaluated in an
Ambient Air Quality Impact Analysis (AAQIA).
Marshall County Iowa is in attainment or unclassifiable for all pollutants. As such, the
Prevention of Significant Deterioration (PSD) program will apply to the proposed Project.
The PSD regulations are designed to ensure that the air quality in existing attainment areas
does not significantly deteriorate or exceed the National Ambient Air Quality Standards
(NAAQS) while providing a margin for future industrial and commercial growth.
The Sutherland Generating Station is an existing major source; therefore, PSD
applicability is based on comparing the emissions increase of each pollutant against the
PSD significant emission rates (SERs) as defined in Chapter 33 of the IDNR Air Quality
Program Rules. For each regulated pollutant that is subject to PSD review and for which a
modeling significant level (MSL) exists, an air dispersion modeling analysis must be
performed. Potential-to-emit calculations for the proposed Project (contained in
Attachment 2) demonstrate that NOx, SO2, PM/PM10, and CO, exceed the SERs thereby
requiring modeling.
2
Project
Location
IOWA
Project
Location
Base Map Source: www.topozone.com
USGS 7.5 Minute Quadrangle:
Le Grand, IA
Figure 1
Project Location
Therefore, IPL is submitting via this letter, an AAQIA Protocol with corresponding
modeling results (hereinafter referred to as the Protocol) that describes the air quality
impact analysis methodology and results for the proposed Project for review and comment.
The modeling results presented herein rely upon the methodologies discussed in this
Protocol. After IDNR review and approval, this Protocol will provide the basis of a
mutually agreed upon modeling methodology in support of the air construction permit
application.
PRE-CONSTRUCTION MONITORING
Pre-application monitoring applicability is determined by comparing each pollutant's
maximum model predicted concentration to the applicable Monitoring De Minimus Level.
If the maximum model predicted concentration for a pollutant is less than the applicable
Monitoring De Minimus Level, then an exemption from pre-application monitoring
requirements can be requested for that pollutant.
3
In the event the maximum model predicted impacts exceed the applicable Monitoring De
Minimus Level for a given pollutant, then the existing ambient air quality monitoring
network may evaluated for representativeness of these data to the site location (in
cooperation with IDNR Ambient Air Monitoring staff) pursuant to requesting a waiver
from the pre-application monitoring requirements for that pollutant.
Using the methodologies presented herein, modeling to determine the proposed Project’s
pre-construction monitoring requirements was conducted and is presented in Table 1. The
results indicate that for all applicable pollutants and averaging periods the proposed Project
is less than the respective Monitoring De Minimus Levels. Additionally, as presented in
Attachment 2, the proposed project’s potential-to-emit of VOC is less than 100 tpy, which
according to footnote 1 of 40 CFR 52.21(i)(8)(i) is the trigger threshold for the gathering
of pre-application ambient air quality data for ozone. As such, IPL requests an exemption
from the pre-application monitoring requirements for all pollutants including ozone.
Table 1
Comparison of the Project’s Maximum Modeled Impacts
with the PSD Monitoring de minimis Levels
Operation
Typical
Operation(b)
Pollutant
Averaging
Period
AERMOD
1st High
Maximum
Impact(a)
(μg/m3)
NOx
Annual
0.59
14
SO2
24 hour
4.85
13
PM10
24 hour
4.92
10
CO
8 hour
19.19
575
Fluorides
24 hour
0.01
0.25
PSD Class II
Monitoring de
minimis Level
(μg/m3)
(a)
Represents the first high maximum model-predicted, ground-level impact
from the 5-year meteorological data set used.
(b)
Typical operation includes the continuous and simultaneous operation of
the proposed Unit 4 PC boiler, auxiliary boiler, natural gas fired heater,
cooling tower, coal, limestone, ash, gypsum, and biomass material handling
processes, truck deliveries and coal combustion byproducts removals. On
an annual basis, in addition to the above source operations, the modeling
includes the auxiliary boiler operating for 2,000 hours per year.
VOC EMISSIONS
Typically emissions of VOCs are not modeled. Furthermore, since the proposed project
will result in a net emission increase of less than 100 tons per year of VOC (see
Attachment 2), an analysis of the potential effects of ozone is not required by the IDNR.
However, an evaluation of VOC emissions and subsequent ozone formation is provided in
4
the Soils and Vegetation portion of the Additional Impacts Analysis by using a
conservative screening methodology based on the “VOC/NOX Point Source Screening
Tables” developed by Scheffe (EPA-OAQPS-TSD-SRAB, 1988).
MODELING METHODOLOGY
The air dispersion modeling methodology and AAQIA that are proposed for those
regulated pollutants which are determined to have a potential to emit (PTE) greater than
the PSD SER and thus subject to PSD review are discussed in the following sections. The
AAQIA is conducted in accordance with United States Environmental Protection Agency's
(USEPA) Guideline on Air Quality Models (incorporated as Appendix W of 40 CFR 51)
and the IDNR’S Air Dispersion Modeling Guidelines For PSD Projects dated January 6,
2005, as well as a mutually agreed upon modeling methodology initiated by this revised
Protocol.
DISPERSION MODEL
Consistent with the Appendix W Guideline on Air Quality Models, the American
Meteorological Society/Environmental Protection Agency (AMS/EPA) Regulatory Model
(AERMOD) (Version 07026) air dispersion model was used to predict maximum groundlevel concentrations associated with the proposed Project’s emissions. AERMOD is the
product of AMS/EPA Regulatory Model Improvement Committee (AERMIC), formed to
introduce state-of-the-art modeling concepts into USEPA’s air quality models. AERMOD
incorporates air dispersion based on planetary boundary layer turbulence structure and
scaling concepts, including treatment of both surface and elevated sources, and both simple
and complex terrain. The AERMOD model includes a wide range of options for modeling
air quality impacts of pollution sources.
The AERMOD model was used to determine the maximum predicted ground-level
concentration for each appropriate pollutant and applicable averaging period resulting from
the emission sources at the proposed Project location.
DISPERSION COEFFICIENT
With the introduction of AERMOD, the choice of the use of the simple rural or urban
dispersion coefficient is no longer available. The AERMOD model has the option of
assigning specific sources to have an urban effect, thus enabling AERMOD to employ
enhanced turbulent dispersion associated with anthropogenic heat flux, parameterized by
population size of the urban area. Since the proposed Project is not located in an urbanized
area, urban boundary layer option will not be invoked.
SOURCE CHARACTERIZATION
As previously noted, IPL is proposing to install SGS4, a nominal 649 MW (net)
supercritical PC-fired boiler and associated systems at the existing Sutherland Generating
Station. The associated systems include ancillary equipment such as a cooling tower,
auxiliary boiler, natural gas fuel heater, emergency diesel generator, two emergency diesel
5
fire pumps, and new material handling equipment that will be installed for coal, limestone,
ash, gypsum, and biomass. The coal material handling system will consist of a railcar
unloader, fuel blending facility, active and long-term coal storage piles, and conveyor
systems. Similarly, the limestone and ash systems will be designed to store, process, and
transport their respective materials. Each proposed air emissions source (including fugitive
emissions) was evaluated, quantified, and included in the air dispersion modeling analysis
by applying the following methodologies:
Point Sources
• Includes:
o PC boiler, auxiliary boiler, natural gas fuel heater, emergency diesel
generator, two emergency diesel fire pumps, dust collectors/bin vents, and
cooling tower exhaust cells
• Source Details:
o Vertical Discharge:
ƒ Actual exit temperature, diameter, and velocity
ƒ For vent and dust collector releases that exit vertically, the exit
temperature was represented as 0 degrees Kelvin which forces the
model to use each hour’s ambient temperature from the
meteorological file as the release temperature
o Horizontal Discharge:
ƒ Actual exit temperature and stack diameter, and an exit velocity of
0.001 meters/second (such that the model retains the thermal
buoyancy and eliminates the momentum buoyancy) 1
ƒ For vent and dust collector releases that exit horizontally, the exit
temperature was represented as 0 degrees Kelvin which forces the
model to use each hour’s ambient temperature from the
meteorological file as the release temperature
• Emissions:
o Based on projected fuel burn rates, preliminary engineering design
estimates, vendor data, and AP-42 emission factors. For annual average
period modeling, the IDNR’s Air Dispersion Modeling Guidelines for PSD
Projects was used to account for the proposed annual source operation
limitations (e.g., 2,000 hours per year for the auxiliary boiler).
• Controls:
o Various pre- and post-combustion controls and good combustion practices
for the combustion sources, drift eliminators for the cooling tower, and
water suppression and dust collectors/bin vent filters for the captured (nonfugitive) material handling sources.
1
EPA AERMOD Implementation Guide (September 27, 2005). Available at
http://www.epa.gov/scram001/7thconf/aermod/aermod_implmtn_guide.pdf .
6
Area Sources
• Includes:
o Material load-in (conveyor drop) and wind erosion from open air coal and
limestone storage piles
• Source Details:
o Above emissions combined to create a single storage pile emission rate
o Horizontal dimensions equal to that of each proposed pile
o Release height equal to the median height of the base of the pile and the
highest drop height
o Initial vertical dimension of each pile set equal to the pile height divided by
4.32
• Emissions:
o Based upon AP-42 emission factors for material drops3 using maximum
system rated capacities for load-in and industrial wind erosion4 assuming
daily disturbances for active piles
• Controls:
o Water sprays/wetted material drops onto piles to achieve a 95 percent dust
control factor5
o Water sprays/wetted material and reduced drop heights (e.g., telescopic
chutes6 provide a 75 percent control) to achieve a 98.75 percent dust control
factor
o Water sprays/wetted material, reduced drop heights, and wind blocking
structures (berms/walls assumed to provide a 50 percent control based on
blocking wind from two of the four sides) to achieve a 99.38 percent dust
control factor
Volume Sources
• Includes:
o Open conveyor(s), haul roads, pile maintenance activities
• Source Details:
o Open conveyor(s):
ƒ Series of alternating volume sources traversing the length of each
individual open conveyor
ƒ Initial vertical dimension set equal to the height of the conveyor
galley divided by 4.32
2
USEPA’s User’s Guide for the Industrial Source Complex (ISC3) Dispersion Models Volume I - User
Instructions (EPA-454/B-95-003a), as well as Trinity’s BREEZE ISC and AERMOD User’s Guide, Version
3.5, Table 3-1.
3
USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 Miscellaneous Sources, Section 13.2.4 Aggregate
Handling and Storage Piles. November 2006.
4
USEPA. Fugitive Dust Background Document and Technical Information Document for Best Available
Control Measures. EPA-450/2-92-004. September 1992.
5
Wet Suppression - An average of the control efficiency for TSP and PM10 emissions from conveyor
transfer points. AP-42, Section 11.19.2 Crushed Stone Processing and Pulverized Mineral Processing
6
Telescopic Chute - USEPA. Stationary Source Control Techniques Document for Fine Particulate Matter.
EPA Contract No. 68-D-98-026. October, 1998
7
ƒ
•
•
Initial lateral dimension set equal the center to center distance
divided by 2.152
ƒ Release height set equal to the conveyor elevation above ground at
the source’s placement along the conveyor route
o Haul roads (per modified TCEQ Air Quality Modeling Guidelines7):
ƒ Series of alternating volume sources traversing the length of each
individual road
ƒ Initial vertical dimension set equal to twice the vehicle height
divided by 4.3
ƒ Initial lateral dimension set equal to the road width divided by 2.15
ƒ Release height set equal to height of the vehicle’s tire
o Pile maintenance activities:
ƒ Series of alternating volume sources traversing the length of each
individual pile
ƒ Initial vertical dimension set equal to twice the vehicle height
divided by 4.3
ƒ Initial lateral dimension set equal to the bulldozer width divided by
2.15
ƒ Release height set equal to half the height of the pile plus the height
of the bulldozer’s tire
Emissions:
o Open conveyor emissions based upon AP-42 factors.8
o Haul road emissions based upon AP-42 emission factors for paved roads9
using maximum project material consumption and waste production rates
for consumable material deliveries (e.g., limestone, sorbent, powder
activated carbon, switch grass, etc.) and waste material disposals (e.g., fly
ash, bottom ash, gypsum, etc.)
o Pile maintenance activities are assumed to be the result of the
bulldozers/scrapers in contact with the piles as they traverse over each pile
pushing material on an as needed basis. Emissions are based upon AP-42
emission factors for unpaved roads9 with bulldozers/scrapers maintaining
each pile for 8 hours/day.
Controls (from published Ohio EPA document on fugitive emissions10):
o Open conveyor controls consist of watering/wetted material to achieve a 95
percent dust control factor
o Haul road controls consist of water flushing to achieve a 80 percent dust
control factor
o Pile maintenance controls consist of watering/wetted material and speed
reduction to achieve a 95 percent dust control factor
7
TCEQ’s Air Quality Modeling Guidelines, RG-25 (Revised), February 1999.
USEPA, AP-42 Table 8.19.2-2 Uncontrolled Particulate Emission Factors for Open Dust Sources at
Crushed Stone Plants, September 1985.
9
USEPA, AP-42, Fifth Edition, Vol. I. Chapter 13 Miscellaneous Sources, Section 13.2.2 Unpaved Roads.
10
Ohio EPA’s Reasonably Available Control Measures for Fugitive Dust Sources “RACM”, 1980, Table
2.1.1-3 Controlling Fugitive Dust from Paved and Unpaved Surfaces.
8
8
o Watering, speed reduction, and wind blocking structures (berms/walls
assumed to provide a 50 percent control based on blocking wind from two
of the four sides) to achieve a 97.5 percent dust control factor
Additional modeling methodologies include special considerations for the ancillary
combustion sources. Per IDNR guidance, the emergency diesel generator and two
emergency diesel fire pumps will only be operated when the rest of the facility is not in
operation (except for test and maintenance purposes). As such, and in accordance with
IDNR modeling guidelines, these sources (along with the inclusion of the auxiliary boiler
for conservatism) were evaluated in a separate air dispersion modeling analysis with
unrestricted daily operation for comparison to, and assurance of compliance with, the
applicable short-term National Ambient Air Quality Standards (NAAQS).
BUILDING DOWNWASH
The dispersion of a plume can be affected by nearby structures when the stack is short
enough to allow the plume to be significantly influenced by surrounding building
turbulence. This phenomenon, known as structure-induced downwash, generally results in
higher model predicted ground-level concentrations in the vicinity of the influencing
structure. Sources included in a PSD permit application are subject to Good Engineering
Practice (GEP) stack height requirements outlined in 40 CFR Part 51, Sections 51.100 and
51.118. For these analyses, the buildings and structures of the proposed Project were
analyzed to determine the potential to influence the plume dispersion from the proposed
Project’s emission sources. Structure dimensions and relative locations were entered into
the USEPA’s Plume Rise Model Enhancement (PRIME) version of the Building Profile
Input Program (BPIP) to produce an AERMOD input file with direction specific building
downwash parameters.
RECEPTOR GRID
The air dispersion modeling receptor locations were established at appropriate distances to
ensure sufficient density and aerial extent to adequately characterize the pattern of
pollutant impacts in the area. Specifically, a nested rectangular grid network that extends
out 10 km from the center of the proposed location was used. As specified in the IDNR Air
Dispersion Modeling Guidelines for PSD Projects, the nested rectangular grid network
will consists of the following six tiers:
•
•
•
•
•
•
50 m along the facility fence line
50 m extending from the fence line to 0.5 km
100 m extending from 0.5 km to 1.5 km
250 m extending from 1.5 km to 3 km
500 m extending from 3 km to 5 km
1000 m extending from 5 km to 10 km
9
As necessary, a 50-m fine grid was placed over areas of maximum concentration that
occurred beyond the fence line and 50-m grid to ensure the true maximum concentration is
identified. Figure 2 illustrates the six tier grid.
50 m boundary spacing
50 m spacing
100 m spacing
250 m spacing
500 m spacing
1,000 m spacing
Figure 2
Receptor Grid
TERRAIN ELEVATIONS
Terrain elevations at receptors were obtained from 7.5-minute United States Geological
Survey (USGS) Digital Elevation Model (DEM) files and incorporated into the AERMOD
model. There is no distinction in AERMOD between elevated terrain below release height
10
and terrain above release height, as with earlier regulatory models that distinguished
between simple terrain and complex terrain. For applications involving elevated terrain, the
user must now also input a hill height scale along with the receptor elevation. To facilitate
the generation of both receptor elevations and hill height scales for AERMOD, a terrain
preprocessor, called AERMAP, has been developed by USEPA.
Using AERMAP (Version 06341), terrain elevations were determined using a method that
locates the maximum terrain elevation near each receptor. This method ensures that the
highest (most conservative) elevation of the surrounding nearby terrain points in the DEM
files are used for each receptor. As for hill height scale, AERMAP searches for a
surrounding terrain height that has the greatest influence on dispersion at each individual
receptor. In order to appropriately calculate the hill height scale, the DEM array and
domain boundary must include all terrain features that exceed a 10% elevation slope from
any given receptor. According to the IDNR Modeling Checklist the maximum distance at
which terrain in Iowa could exceed a 10 percent slope is 3.6 km. The DEM domain
boundary, at a minimum, extends 3.6 km beyond the furthest receptor in each direction.
METEOROLOGICAL DATA
The AERMOD model utilizes a file of surface boundary layer parameters and a file of
profile variables including wind speed, wind direction, and turbulence parameters. These
two types of meteorological inputs are generated by the meteorological preprocessor for
AERMOD, which is called AERMET (Version 06341). AERMET requires hourly input of
specific surface and upper air meteorological data. These data at a minimum include the
wind flow vector, wind speed, ambient temperature, cloud cover, and morning radiosonde
observation, including height, pressure, and temperature. AERMET includes three stages
of preprocessing of the meteorological data. The first two stages extract, quality check, and
merge the available meteorological data. The third stage requires input of certain surface
characteristics (surface roughness, Bowen ratio, and Albedo) representative of the area.
IDNR has provided five years (2000-2004) of pre-processed (AERMOD ready) surface
and upper air meteorological data for specific geographical areas throughout Iowa. As
illustrated in Figure 3, the proposed Project is located in the Des Moines (DM)
geographical area.
As such, surface and upper air meteorological data from Des Moines and Omaha (OM)
meteorological stations, respectively, were used in the AERMOD model. IDNR has
already confirmed that the provided data files are appropriate for use in and meet the
percent complete requirements of the AERMOD model. Additionally, since the
meteorological files provided by IDNR are AERMOD-ready, Stage 3 of the AERMET
process, inputting site characteristics (Bowen, Albedo, surface roughness), will not need to
be performed.
11
MODELING ANALYSIS
Based on the air dispersion modeling methodology outlined previously, source release
parameters and emission rates for use in the air dispersion modeling were developed and
are presented in Tables 2, 3, and 4. SGS4 will be able to operate on a range of coals, as
well as a blend of coal with up to 5 percent biomass. Additionally, the unit will potentially
operate at reduced loads. For these reasons, performance data was developed for multiple
coals, both with and without blends of biomass, as well as reduced loads including 75 and
50 percent. Emission calculation details for all sources are provided in Attachment 2. The
maximum model predicted ground-level concentrations for each of the modeled scenarios
associated with the proposed Project was then determined for each regulated pollutant that
is subject to PSD review and for which a Modeling Significance Level (MSL) exists.
Project
Location
Figure 3
IDNR Meteorological Stations
The first high maximum model-predicted impacts for the proposed Project’s continuously
operating emissions sources as compared to the MSLs are presented in Tables 5 and 6.
Table 5 presents an overall summary of the highest modeled impact out of all operating
scenarios (i.e., out of various loads and fuels) while Table 6 presents each individual
12
operating scenario’s maximum impact for review. The impacts presented in Tables 5 and
6 conservatively have all sources given in Tables 2-4 operating simultaneously at their
maximum design rates (exceptions are the emergency diesel generator and two emergency
diesel fire pumps which, on a short-term basis, will not be operated when the rest of the
facility is operation, except for testing and maintenance purposes, and were included in a
separate short-term analysis discussed below). Annually, the auxiliary boiler was included
in the modeling of the full facility, using IDNR’s guidance for restricted annual operation,
as it may operate with the rest of the facility in any given year for up to 2,000 hours. As
presented in Tables 5 and 6, the maximum model-predicted impacts are below all
respective MSLs. Therefore, no further PSD modeling analyses are required.
As mentioned previously and allowed by the IDNR, the ancillary combustion sources,
including the auxiliary boiler, emergency diesel generator, and two emergency diesel fire
pumps, were included in a separate air dispersion modeling analysis with unrestricted daily
operation for comparison to and assurance of compliance with the applicable short-term
NAAQS. As shown in Table 7, the modeling results for this scenario are all below the
applicable NAAQS. It is important to note that the auxiliary boiler was conservatively
included in both the short-term NAAQS analysis presented in Table 7, as well as the full
facility modeling presented in Tables 5 and 6 since it may operate both when the rest of the
facility is not in operation and when SGS4 is in operation.
SOURCE INVENTORIES
Since the modeling results given in Tables 5 and 6 indicate model-predicted concentrations
below the MSLs for all pollutants, no cumulative analysis with source inventories will be
required.
BACKGROUND VALUES
Since the modeling results given in Tables 5 and 6 indicate model-predicted concentrations
below the MSLs for all pollutants, no ambient pollutant background values will be
required.
13
Table 2
Stack Parameters and Pollutant Emission Rates for Unit 4 PC Boiler(a)
ID(b)
EP248A
EP248B
EP248C
EP248D
EP248E
EP248F
EP248G
EP248H
EP248I
EP248J
Percent
Load
(%)
100
100
100
100
100
100
75
75
50
50
Source
Type
Discharge
Style
Stack
Height(d)
(ft)
Point
Point
Point
Point
Point
Point
Point
Point
Point
Point
Vertical
Vertical
Vertical
Vertical
Vertical
Vertical
Vertical
Vertical
Vertical
Vertical
601
601
601
601
601
601
601
601
601
601
Exit
Temp
(oF)
Exit
Velocity
(ft/s)
130
130
130
120
130
125
125
120
125
120
59.2
57.2
54.7
52.4
60.0
58.2
44.1
43.2
31.3
30.4
(a)
Diameter
(in)
Exhaust
Flow Rate
(acfm)
Operating
Hours
316.56
316.56
316.56
316.56
316.56
316.56
316.56
316.56
316.56
316.56
1,940,460
1,876,128
1,793,722
1,719,350
1,967,862
1,909,549
1,445,407
1,416,164
1,027,703
996,132
8,760
8,760
8,760
8,760
8,760
8,760
8,760
8,760
8,760
8,760
Detailed Unit 4 performance and emissions calculations can be found in Attachment 2.
IDs are the same as those that appear in the air dispersion modeling files.
Short-term and annual emission rates are the same since Unit 4 is assumed to operate 8,760 hours per year.
(d)
Sutherland Generating Station’s base elevation is 863 ft (263 m).
(e)
PM10 emission rates given above represent total PM/PM10, including both filterable and condensable particulate matter.
(f)
Conservatively assumed fluoride emissions as HF emissions.
(b)
(c)
14
Emission Rate (lb/hr)(c)
NOx
316.3
308.5
300.8
291.4
316.7
309.3
237.2
231.4
158.2
154.3
SO2
380.0
494.0
361.0
466.0
380.0
495.0
285.0
370.0
190.0
247.0
PM10(e)
113.9
111.0
108.3
104.9
114.0
111.4
85.35
83.25
57.00
55.50
CO
759.0
740.0
722.0
699.0
760.0
742. 0
569.0
555. 0
380.0
370. 0
F(f)
1.27
1.23
1.20
1.17
1.27
1.24
0.95
0.93
0.63
0.62
Table 3
Stack Parameters and Pollutant Emission Rates for the Ancillary Combustion Equipment(a)
ID
(b)
EP297
Description
(c)
EP249(d)
EP250A(e)
EP250B(e)
EP251(e)
EP252(e)
Natural Gas Heater
Auxiliary Boiler
Maximum hourly
emission rate
Diesel Generator
Maximum hourly
emission rate – Stack 1
Diesel Generator
Maximum hourly
emission rate – Stack 2
Diesel Fire Pump
Maximum hourly
emission rate
Diesel Fire Pump
Booster Maximum
hourly emission rate
Source
Type
Discharge
Style
Stack
Height(f)
(ft)
Exit
Temp
(oF)
Exit
Velocity
(ft/s)
Diameter
(in)
Exhaust
Flow Rate
(acfm)
Operating
Hours
NOx
SO2
PM10
CO
F
Point
Vertical
20.00
700
19.41
15
1,430
8,760 hr/yr
0.14
0.002
0.022
0.142
0
Point
Vertical
285.00
650
44.00
60
51,850
24 hr/day
9.94
0.16
1.88
19.88
0
Point
Vertical
10.00
761
227.96
10
7,460
24 hr/day
N/A
0.49
0.12
1.72
0.003
Point
Vertical
10.00
761
227.96
10
7,460
24 hr/day
N/A
0.49
0.12
1.72
0.003
Point
Vertical
12.00
918
246.50
6
2,900
24 hr/day
N/A
0.20
0.10
0.95
0.001
Point
Vertical
12.00
1,044
96.56
5
790
24 hr/day
N/A
0.07
0.06
0.11
4E-4
(a)
Emission Rate (lb/hr)
Detailed performance and emissions calculations can be found in Attachment 2.
IDs are the same as those that appear in the air dispersion modeling files.
Short-term and annual emission rates are the same since this source is assumed to operate 8,760 hours per year.
(d)
The auxiliary boiler is an ancillary piece of equipment but may operate as needed when the rest of the proposed Project is still operational. Therefore, it was included in the short-term modeling demonstration for the proposed
Project as a whole (with unlimited daily operations), the annual modeling demonstration for the proposed Project as a whole (using IDNR guidance for sources with restricted annual operations – limited to 2,000 hours per year), and
the short-term NAAQS demonstration which also include the emergency diesel generator and emergency diesel fire pumps operating simultaneously for 24-hours per day.
(e)
The emergency diesel generator and two emergency diesel fire pumps will only be operated when the rest of the facility is not in operation (except for test and maintenance purposes). As such, and in accordance with IDNR
modeling guidelines, these sources (along with the inclusion of the auxiliary boiler for conservatism) were evaluated in a separate analysis where they were operated 24 hours per day and their impacts compared to the short-term
NAAQS.
(f)
Sutherland Generating Station’s base elevation is 863 ft (263 m).
(b)
(c)
15
Table 4
Stack Parameters and Pollutant Emissions for the Cooling Tower and Material Handling Sources(a)
Stack /
Release
Height,
(ft)(d)
Exit
Temp(e)
(oF)
Exit
Velocity
(ft/s)
Exhaust
Flow Rate
(acfm)
Operating
Hours
(hr/yr)
Source
Discharge
Emission Unit
Diameter
PM10 Emission
Type
Style(c)
Description
(in)
Rate(c)
Cooling Tower
Linear Mechanical
LMCT1A
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 1A
Linear Mechanical
LMCT1B
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 1B
Linear Mechanical
LMCT2A
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Point
Vertical
Draft Cell 2A
Linear Mechanical
LMCT2B
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Point
Vertical
Draft Cell 2B
Linear Mechanical
LMCT3A
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 3A
Linear Mechanical
LMCT3B
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 3B
Linear Mechanical
LMCT4A
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 4A
Linear Mechanical
LMCT4B
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 4B
Linear Mechanical
LMCT5A
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 5A
Linear Mechanical
LMCT5B
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 5B
Linear Mechanical
LMCT6A
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 6A
Linear Mechanical
LMCT6B
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 6B
Linear Mechanical
LMCT7A
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 7A
Linear Mechanical
LMCT7B
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 7B
Linear Mechanical
LMCT8A
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 8A
Linear Mechanical
LMCT8B
Point
Vertical
53
104
34.84
360
1,477,500
8,760
0.16
(f)
Draft Cell 8B
(a)
Detailed performance and emission calculations can be found in Attachment 2.
(b)
IDs are the same as those that appear in the air dispersion modeling files.
(c)
For horizontal releases, exit velocity was set equal to 0.001 m/s and exit temperature was set equal to 0 K which represented an ambient temperature release.
(d)
Sutherland Generating Station’s base elevation is 863 ft (263 m).
(e)
Sources that release at ambient temperature have a modeled exit temperature of 0 K (-459.7 °F) which simulates such.
(f)
Emission rate is lb/hr.
(g)
Emission rate is lb/(hr-ft2).
Modeling
ID(b)
16
Init.
Lat.
Dim.
(ft)
Init.
Vert.
Dim.
(ft)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
X
Length
(ft)
Y
Length
(ft)
N/A
Table 4 (continued)
Stack Parameters and Pollutant Emissions for the Cooling Tower and Material Handling Sources(a)
Stack /
Release
Height,
ft(d)
Exit
Temp(e)
(oF)
Exit
Velocity
(ft/s)
Exhaust
Flow
Rate
(acfm)
Source
Discharge
Emission Unit
Diameter
PM10 Emission
Type
Style(c)
Description
(in)
Rate(c)
Coal
Rotary Railcar
EP254a
Dump Dust
Point
Vertical
12.00
-459.7
38.00
78.00
75,000
8,760
2.20E-03
Collector (a)
Rotary Railcar Vent
EP254b
Point
Vertical
12.00
-459.7
38.00
78.00
75,000
8,760
2.20E-03
Dust Collector (b)
Rotary Railcar
EP255
Vault Vent Dust
Point
Vertical
12.00
-459.7
13.00
42.00
7,500
8,760
8.80E-03
Collector
Transfer Tower 1
EP256
Point
Vertical
55.00
-459.7
13.00
42.00
7,500
8,760
4.40E-03
Dust Collector
Transfer Tower 2
EP262
Point
Vertical
65.00
-459.7
13.00
42.00
7,500
8,760
8.36E-03
Dust Collector
Belt Feeder BF-4 to
EP264
Belt Conveyor BCPoint
Vertical
12.00
-459.7
12.00
42.00
7,500
8,760
2.64E-03
8 Dust Collector
Belt Feeder BF-5 to
EP266
Belt Conveyor BCPoint
Vertical
12.00
-459.7
13.00
42.00
7,500
8,760
1.32E-03
9 Dust Collector
Crusher House 1
EP267
Point
Vertical
125.00 -459.7
40.00
48.00
30,000
8,760
1.37E-02
Dust Collector
Unit 4 Boiler House
EP268
and Transfer Tower
Point
Vertical
53,000
8,760
190.00 -459.7
40.00
63.60
5.28E-03
4 Dust Collector
Pile 5 Vault Vent
EP269
Point
Vertical
12.00
-459.7
13.00
42.00
7,500
8,760
1.76E-03
Dust Collector
Transfer Tower 3
EP270
Point
Vertical
35.00
-459.7
13.00
42.00
7,500
8,760
4.40E-04
Dust Collector
Existing Transfer
EP271
Tower Dust
Point
Vertical
55.00
-459.7
13.00
42.00
7,500
8,760
4.40E-04
Collector
Future Truck Load
EP272
Point
Vertical
65.00
-459.7
40.00
30.00
12,000
8,760
2.20E-04
Out Dust Collector
(a)
Detailed performance and emission calculations can be found in Attachment 2.
(b)
IDs are the same as those that appear in the air dispersion modeling files.
(c)
For horizontal releases, exit velocity was set equal to 0.001 m/s and exit temperature was set equal to 0 K which represented an ambient temperature release.
(d)
Sutherland Generating Station’s base elevation is 863 ft (263 m).
(e)
Sources that release at ambient temperature have a modeled exit temperature of 0 K (-459.7 °F) which simulates such.
(f)
Emission rate is lb/hr.
(g)
Emission rate is lb/(hr-ft2).
Modeling
ID(b)
17
X
Length
(ft)
Y
Length
(ft)
Init.
Lat.
Dim.
(ft)
Init.
Vert.
Dim.
(ft)
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
Operating
Hours
(hr/yr)
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
Table 4 (continued)
Stack Parameters and Pollutant Emissions for the Cooling Tower and Material Handling Sources(a)
EP274
Emission Unit
Description
Coal (cont.)
Coal Pile 2 North
EP275
Coal Pile 2 South
EP274
Coal Pile 2 Reclaim
EP276
Coal Stock out Pile 3
EP277
Coal Stock out Pile 4
EP259
Transfer from
elevating tripper to
Belt Conveyor 4
Modeling
ID(b)
EP280a
EP280b
EP281
EP283
EP284
EP285
LMESPile
Limestone
Railcar Dump Dust
Collector
Railcar Vent Dust
Collector
Railcar Vault Vent
Dust Collector
Limestone Pile Hopper
Vault Vent Dust
Collector
Limestone Silo 1 Dust
Collector
Limestone Silo 2 Dust
Collector
Limestone Storage Pile
Stack /
Release
Height,
ft(d)
Exit
Temp(e)
(oF)
Exit
Velocity
(ft/s)
Diameter
(in)
Exhaust
Flow
Rate
(acfm)
Operating
Hours
(hr/yr)
PM10 Emission
Rate(c)
X
Length
(ft)
Source
Type
Discharge
Style(c)
Area
Area
Area
Circular
Area
Circular
Area
N/A
N/A
N/A
20.00
20.00
20.00
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
8,760
8,760
8,760
1.88E-07
4.80E-07
2.11E-07
(g)
N/A
36.50
N/A
N/A
2,328
N/A
8,760
N/A
36.50
N/A
N/A
2,328
N/A
Volume
N/A
6.00
N/A
N/A
N/A
Point
Vertical
35.00
-459.7
38.00
Point
Vertical
35.00
-459.7
Point
Vertical
12.00
Point
Vertical
Point
Y
Length
(ft)
Init.
Lat.
Dim.
(ft)
Init.
Vert.
Dim.
(ft)
(g)
1,095
1,263
100
188.0
188.0
100
N/A
N/A
N/A
9.30
9.30
9.30
8.69E-07
(g)
N/A
N/A
N/A
16.98
8,760
9.98E-07
(g)
N/A
N/A
N/A
16.98
N/A
8,760
0.0693
(f)
N/A
N/A
1.39
2.79
78.00
75,000
8,760
6.60E-04
(f)
N/A
N/A
N/A
N/A
38.00
78.00
75,000
8,760
6.60E-04
(f)
N/A
N/A
N/A
N/A
-459.7
13.00
42.00
7,500
8,760
1.98E-03
(f)
N/A
N/A
N/A
N/A
12.00
-459.7
13.00
42.00
7,500
8,760
8.80E-04
(f)
N/A
N/A
N/A
N/A
Horizontal
110.00
-459.7
0.0033
12.00
1,500
8,760
4.40E-03
(f)
N/A
N/A
N/A
N/A
Point
Horizontal
110.00
-459.7
0.0033
12.00
1,500
8,760
8.80E-03
(f)
N/A
N/A
N/A
N/A
Circular
Area
N/A
18.00
N/A
N/A
1,104
N/A
8,760
1.01E-05
(g)
N/A
N/A
N/A
8.37
(a)
Detailed performance and emission calculations can be found in Attachment 2.
IDs are the same as those that appear in the air dispersion modeling files.
(c)
For horizontal releases, exit velocity was set equal to 0.001 m/s and exit temperature was set equal to 0 K which represented an ambient temperature release.
(d)
Sutherland Generating Station’s base elevation is 863 ft (263 m).
(e)
Sources that release at ambient temperature have a modeled exit temperature of 0 K (-459.7 °F) which simulates such.
(f)
Emission rate is lb/hr.
(g)
Emission rate is lb/(hr-ft2).
(b)
18
(g)
Table 4 (continued)
Stack Parameters and Pollutant Emissions for the Cooling Tower and Material Handling Sources(a)
Modeling
ID(b)
EP292
EP293
EP286a
EP286b
EP287
EP288a
EP288b
EP289a
EP289b
EP290
EP294
Emission Unit
Description
Sorbent Injection
Sorbent Short Term
Silo Bin Vent
Sorbent Long Term
Silo Bin Vent
Fly Ash
Saleable Fly Ash
Conveyor Blower
Bin Vent 1
Saleable Fly Ash
Conveyor Blower
Bin Vent 2
Saleable Fly Ash
Silo Bin Vent
Saleable Fly Ash
Storage Bin Vent 1
Saleable Fly Ash
Storage Bin Vent 2
Waste Fly Ash
Conveyor Blower
Bin Vent 1
Waste Fly Ash
Conveyor Blower
Bin Vent 2
Waste Fly Ash Silo
Bin Vent
Lime
Lime Silo Bin Vent
Source
Type
Discharge
Style(c)
Stack /
Release
Height,
ft(d)
Point
Horizontal
115.00
-459.7
0.003
13.20
5,000
8,760
4.40E-04
(f)
N/A
N/A
N/A
N/A
Point
Horizontal
280.00
-459.7
0.003
13.20
5,000
8,760
1.11E-05
(f)
N/A
N/A
N/A
N/A
Point
Horizontal
12.00
-459.7
0.003
15.00
4,000
8,760
1.44E-05
(f)
N/A
N/A
N/A
N/A
Point
Horizontal
12.00
-459.7
0.003
15.00
4,000
8,760
1.44E-05
(f)
N/A
N/A
N/A
N/A
Point
Horizontal
105.00
-459.7
0.003
13.20
2,000
8,760
1.44E-05
(f)
N/A
N/A
N/A
N/A
Point
Horizontal
23.00
-459.7
0.003
42.00
20,000
8,760
1.44E-05
(f)
N/A
N/A
N/A
N/A
Point
Horizontal
23.00
-459.7
0.003
42.00
20,000
8,760
2.29E-04
(f)
N/A
N/A
N/A
N/A
Point
Horizontal
28.00
-459.7
0.003
9.60
1,350
8,760
1.44E-05
(f)
N/A
N/A
N/A
N/A
Point
Horizontal
28.00
-459.7
0.003
9.60
1,350
8,760
1.44E-05
(f)
N/A
N/A
N/A
N/A
Point
Horizontal
105.00
-459.7
0.003
13.20
2,000
8,760
2.29E-04
(f)
N/A
N/A
N/A
N/A
Point
Horizontal
77.00
-459.7
0.003
13.39
5,000
8,760
5.17E-06
(f)
N/A
N/A
N/A
N/A
(f)
N/A
N/A
N/A
N/A
Exit
Temp(e)
(oF)
Exit
Velocity
(ft/s)
Diameter
(in)
Exhaust
Flow
Rate
(acfm)
Operating
Hours
(hr/yr)
PM10 Emission
Rate(c)
PAC
EP291
PAC Silo Bin Vent
Point
Horizontal 115.00 -459.7 0.003
13.20
1,000
8,760
4.40E-04
(a)
Detailed performance and emission calculations can be found in Attachment 2.
(b)
IDs are the same as those that appear in the air dispersion modeling files.
(c)
For horizontal releases, exit velocity was set equal to 0.001 m/s and exit temperature was set equal to 0 K which represented an ambient temperature release.
(d)
Sutherland Generating Station’s base elevation is 863 ft (263 m).
(e)
Sources that release at ambient temperature have a modeled exit temperature of 0 K (-459.7 °F) which simulates such.
(f)
Emission rate is lb/hr.
(g)
Emission rate is lb/(hr-ft2).
19
X
Length
(ft)
Y
Length
(ft)
Init.
Lat.
Dim.
(ft)
Init.
Vert.
Dim.
(ft)
Table 4 (continued)
Stack Parameters and Pollutant Emissions for the Cooling Tower and Material Handling Sources(a)
Modeling ID(b)
EP295
EP296
NORTHR1-33
SOUTHR1-38
NBPHR1-6
SBPHR1-6
NRPHR1-3
LMSPHR1-3
EP279A-CO
EP278A-AZ
Emission Unit
Description
Biomass
Biomass Dust
Collector 1
Biomass Dust
Collector 2
Haul Roads
North Pile Haul
Road Srcs 1-33
South Pile Haul
Road Srcs 1-38
North Blending Pile
3 Haul Road Srcs 16
South Blending Pile
4 Haul Road Srcs 16
North Reclaim Pile
Haul Road Srcs 1-3
Limestone Pile Haul
Road Srcs 1-3
West Gate Haul
Road Srcs 1-93
North Gate Haul
Road Srcs 1-52
Stack /
Release
Height,
ft(d)
Exit
Temp(e)
(oF)
Exit
Velocity
(ft/s)
Diameter
(in)
Exhaust
Flow
Rate
(acfm)
Operating
Hours
(hr/yr)
X
Length
(ft)
Y
Length
(ft)
Init.
Lat.
Dim.
(ft)
Init.
Vert.
Dim.
(ft)
Source
Type
Discharge
Style(c)
Point
Vertical
46.42
-459.7
84.20
30.00
24,800
8,760
4.14E-06
(f)
N/A
N/A
N/A
N/A
Point
Vertical
46.42
-459.7
84.20
30.00
24,800
8,760
4.14E-06
(f)
N/A
N/A
N/A
N/A
Volume
N/A
20.00
N/A
N/A
N/A
N/A
8,760
1.62E-03
(f)
N/A
N/A
15.26
18.60
Volume
N/A
20.00
N/A
N/A
N/A
N/A
8,760
1.41E-03
(f)
N/A
N/A
15.26
18.60
Volume
N/A
36.50
N/A
N/A
N/A
N/A
8,760
8.91E-03
(f)
N/A
N/A
15.26
33.96
Volume
N/A
36.50
N/A
N/A
N/A
N/A
8,760
8.91E-03
(f)
N/A
N/A
15.26
33.96
Volume
N/A
18.00
N/A
N/A
N/A
N/A
8,760
1.78E-02
(f)
N/A
N/A
15.26
16.74
Volume
N/A
18.00
N/A
N/A
N/A
N/A
8,760
1.49E-02
(f)
N/A
N/A
15.26
16.74
Volume
N/A
3.44
N/A
N/A
N/A
N/A
8,760
1.96E-03
(f)
N/A
N/A
22.89
10.60
Volume
N/A
3.44
N/A
N/A
N/A
N/A
8,760
1.05E-03
(f)
N/A
N/A
22.89
10.60
(f)
N/A
N/A
5.58
0.70
PM10 Emission
Rate(c)
Open Conveyor
Conveyor BC4 Srcs
BC4_1-80
Volume
N/A
1.50
N/A
N/A
N/A
N/A
8,760
5.00E-04
1-80
(a)
Detailed performance and emission calculations can be found in Attachment 2.
(b)
IDs are the same as those that appear in the air dispersion modeling files.
(c)
For horizontal releases, exit velocity was set equal to 0.001 m/s and exit temperature was set equal to 0 K which represented an ambient temperature release.
(d)
Sutherland Generating Station’s base elevation is 863 ft (263 m).
(e)
Sources that release at ambient temperature have a modeled exit temperature of 0 K (-459.7 °F) which simulates such.
(f)
Emission rate is lb/hr.
(g)
Emission rate is lb/(hr-ft2).
20
Table 5
Comparison of the Project’s Maximum Modeled Impacts
with the PSD Class II Modeling Significance Levels
Operation
Typical
Operation(b)
Averaging
Period
Annual
AERMOD
1st High
Maximum
Impact(a)
(μg/m3)
0.59
PSD Class II
Modeling
Significance Level
(μg/m3)
1
SO2
Annual
24 hour
3 hour
0.39
4.85
15.41
1
5
25
PM10
Annual
24 hour
0.77
4.92
1
5
CO
8 hour
1 hour
19.19
49.12
500
2,000
Pollutant
NOx
(a)
Represents the first high maximum model-predicted, ground-level impact for
all operating scenarios from the 5-year meteorological data set used.
(b)
On a short-term basis, typical operation includes the continuous and
simultaneous operation of the proposed Unit 4 PC boiler, auxiliary boiler, natural
gas fired heater, cooling tower, coal, limestone, ash, gypsum, and biomass
material handling processes, truck deliveries, and coal combustion byproduct
removals. It does not include the operation of the emergency diesel generator
and two emergency diesel fire pumps, which, as allowed by IDNR, were
modeled separately and compared to the short-term NAAQS (the results of
which are presented in Table 7).
On an annual basis, in addition to continuous and simultaneous operation of the
sources listed immediately above, the modeling includes the auxiliary boiler
operating for 2,000 hours per year.
21
Table 6
Individual Scenario Comparison of the Project’s Maximum Modeled Impacts
with the PSD Class II Modeling Significance Levels (a)
Typical
Operation
by
Operating
Scenario(b)
Percent
Load
(%)
Annual
1 ug/m3
EP248A
EP248B
EP248C
EP248D
EP248E
EP248F
EP248G
EP248H
EP248I
EP248J
100
100
100
100
100
100
75
75
50
50
0.57
0.57
0.58
0.59
0.57
0.58
0.58
0.58
0.57
0.57
NOx
SO2
Annual
1 ug/m3
0.28
0.37
0.28
0.39
0.27
0.38
0.26
0.35
0.21
0.29
PM10
24-hour
5 ug/m3
3.45
4.57
3.42
4.85
3.42
4.68
3.15
4.28
2.57
3.52
3-hour
25 ug/m3
11.27
14.84
11.03
15.41
11.21
15.23
9.71
13.14
7.47
10.23
Annual
1 ug/m3
0.77
0.77
0.77
0.77
0.77
0.77
0.77
0.77
0.77
0.76
24-hour
5 ug/m3
4.90
4.90
4.90
4.91
4.90
4.90
4.91
4.91
4.92
4.92
CO
8-hour
500 ug/m3
18.25
18.11
18.07
19.19
18.16
18.56
17.43
17.86
16.00
16.36
1-hour
2,000 ug/m3
47.86
47.54
47.43
49.12
47.60
48.37
43.24
43.64
35.42
35.58
(a)
Represents the first high maximum model-predicted, ground-level impact for each individual operational
scenario from the 5-year meteorological data set used.
(b)
IDs are the same as those that appear in the air dispersion modeling files.
On a short-term basis, typical operation includes the continuous and simultaneous operation of the proposed
Unit 4 PC boiler, auxiliary boiler, natural gas fired heater, cooling tower, coal, limestone, ash, gypsum, and
biomass material handling processes, truck deliveries, and coal combustion byproducts removals. It does not
include the operation of the emergency diesel generator and two emergency diesel fire pumps, which, as
allowed by IDNR, were modeled separately and compared to the short-term NAAQS (the results of which are
presented in Table 7).
On an annual basis, in addition to continuous and simultaneous operation of the sources listed immediately
above, the modeling includes the auxiliary boiler operating for 2,000 hours per year.
22
Table 7
Comparison of the Ancillary Equipment’s Maximum Modeled Impacts with the
Short-term National Ambient Air Quality Standards
Operation
Ancillary
Operation(b)
Averaging
Period
24 hour
3 hour
AERMOD
1st High
Maximum
Impact(a)
(μg/m3)
4.10
19.80
Background
Concentration
Value
(μg/m3)(c)
20
20
Total
(μg/m3)
24.10
39.80
NAAQS
(μg/m3)
365
PM10
24 hour
1.58
45
46.58
150
CO
8 hour
1 hour
43.02
96.82
0
0
43.02
96.82
10,000
40,000
Pollutant
SO2
(a)
-
Represents the first high maximum model-predicted, ground-level impact from the 5-year
meteorological data set used.
(b)
Ancillary equipment includes the unlimited short-term operation of the auxiliary boiler, emergency
diesel generator, and two emergency diesel fire pumps for the full extent of the averaging period of
concern.
It is important to note that the auxiliary boiler was conservatively included in both the short-term
NAAQS analysis presented in this table, as well as the full facility modeling presented in Table 5
since it may operate both when the rest of the facility is not in operation and when SGS4 is in
operation.
(c)
Taken from Table 4 Statewide Default Background Values of the IDNR’s Air Dispersion Modeling
Guidelines for PSD Project (Version 010605) updated to include the most recent background value
for PM10 24-hour averaging period as received in correspondence with IDNR staff.
23
ADDITIONAL IMPACTS ANALYSIS
Federal PSD regulations require the preparation of an analysis of additional impacts due to
construction and operation of a new major stationary source or major modification to an
existing major source. The analysis considers projected air quality impacts that may occur
as the result of general commercial, residential, industrial, and other growth associated
with the new major stationary source, as well as impairment to vegetation, soils, and
visibility. Additionally, this analysis identifies the proposed Project’s impacts upon
threatened and endangered species.
GROWTH
The proposed project is to be located at the existing Sutherland Generating facility in
Marshall County, specifically near Marshalltown, Iowa. IPL’s electric generating load and
capability indicates a capacity deficiency for regulated load beginning in 2010, and that the
deficit will continue to grow every year thereafter. The load and capability takes into
account all owned generation added to date, as well as all purchased power contracts with
accredited capacity that are currently performing, including eight wind contracts. IPL’s
firm demand continues to grow on average, under normal weather conditions,
approximately 40 MWs per year from the current projected load of approximately 2,916
WM in 2007, increasing to a net system peak load of approximately 3,256 MWs in 2016.
The load demand growth is evident for both existing and new energy users, including
residential, commercial, and industry sales classes. Therefore, the addition of SGS Unit 4
is intended to meet the aforementioned demand growth of IPL’s service area and provide
reliability and flexibility in fleet-wide operation, especially as it relates to IPL’s older,
smaller coal-fired units that may have to be operated differently, fuel switched, or even
shutdown
Because the proposed project is being installed to meet the existing and current projected
electrical demands of the surrounding area, it is anticipated that little growth will be
associated with its operation. There will be an increase in the local labor force during the
construction phase of the Project, but this increase will be temporary, short-lived, and will
not result in permanent/significant commercial and residential growth occurring in the
vicinity of the project. Any temporary labor that may come from outside the commuting
area will be absorbed into the surrounding hotel network.
Project employment reflecting full-time jobs directly tied to the operation of proposed
Project is estimated to be approximately 85 people. This will result in minor amounts of
secondary employment created by the economic activity of the plant. Due to the expected
small number of staff that will be required to operate and maintain the Project, the effects
to ambient air quality from growth associated with Project operation are expected to be
insignificant.
Population increase is a secondary growth indicator of potential increases in air quality
levels. Changes in air quality due to population increase are related to the amount of
vehicle traffic, commercial/institutional facilities, and home fuel use. According to the US
Census Bureau, the population of Marshall County has increased by 2.7 percent between
24
the 1990 and 2000 censuses. Since the Project is not serving to attract local business,
rather it’s simply intended to meet the electric demands of the area, the net number of new,
permanent jobs outside of the Project is estimated to be small. It can be concluded that the
air quality impacts associated with secondary growth will not be significant because the
increase in population due to the operation of the Project will be very small, compared to
the overall existing population size of the surrounding area. Therefore, further air quality
modeling analyses for the effects of growth are not proposed for this Project.
VEGETATION
While the model-predicted impacts from the Project are well below the secondary
NAAQS, designed to protect flora and fauna, when considering pollutant effects on plants,
it is important to recognize that the many factors that play a major role in determining
whether a given quantity of pollutant will produce a predictable level of effect vary
tremendously in nature. These factors include the type of exposure (acute or chronic),
influences of stress from other biotic (insects and disease) or abiotic (edaphic or climatic)
factors, the type of response measured, and the species or population under study.
The NSR Workshop Manual states that the analysis of air pollution impacts on vegetation
should be based on an inventory of species found in the impact area, i.e., significant impact
area (SIA). Since the emissions from the proposed Project did not result in any
exceedances of the significant impact levels, thus no SIA exists, an area with a 3-km radius
centered at the facility was chosen for this analysis. A review of information gathered
from topographic maps and aerial photography concluded that there are no state parks or
designated sensitive areas within this 3-km area.
A field survey of a 3-km radius (a 6x6-km area) surrounding the Sutherland facility was
conducted in April 2007 for plant species mainly sensitive to NOx and SO2. For all other
applicable PSD pollutants, the US Department of Agriculture’s Natural Resources
Conservation Service (NRCS) was utilized to determine the inventory of plant species in
the surrounding area.
According to the NRCS, there are a total of 35 different plant species that are located
within Marshall County (included in Attachment 3). For the purpose of defining the
quantitative/qualitative impacts from the pollutants outlined in the following sections,
other than NOx and SO2 which were identified via the site survey, it was conservatively
assumed that for each pollutant a “sensitive” species is included in the list of 35 and that all
35 plant species are within the 3-km radius study area. The results from the modeling
analysis are presented in Table 8 and were utilized to determine the effects on nearby
vegetation. The following subsections briefly describe the potential effects of the PSD
applicable pollutants emitted by the proposed Project on the nearby vegetation.
Carbon Monoxide
Carbon monoxide does not poison vegetation since it is rapidly oxidized to form carbon
dioxide which is used for photosynthesis. However, extremely high concentrations can
reduce the photosynthetic rate. According to the EPA document A Screening Procedure
for the Impacts of Air Pollution Sources on Plant, Soils, and Animals, hereafter referred to
25
as EPA Screening Document, for the most sensitive vegetation, a CO concentration of
1,800,000 micrograms per cubic meter (1 week averaging period) could potentially reduce
the photosynthetic rate. The maximum model-predicted 1-hour CO impact of 49.12 μg/m3
produced by the proposed Project, as referenced in Table 8, is significantly lower than this
screening level (even at a conservative 1 hour averaging period). Consequently, no
adverse impacts to vegetation at or near the proposed Project are expected from CO
emissions.
Table 8
Project’s Maximum Modeled Impacts
Pollutant
CO
NO2
SO2
HF
Averaging
Period
1 hour
1 hour
4 hours
24 hours
1 month
1 year
1 hour
3 hours
1 hour
AERMOD 1st High
Maximum Impact*
(μg/m3)
49.12
20.74
10.91
5.41
1.65
0.59
30.98
15.41
0.08
*
Represents the first high maximum model-predicted,
ground-level impact from the Project for the 5 year
meteorological data set used.
Nitrogen Oxides
Different species of plants exhibit considerable divergence in terms of resistance to
nitrogen oxides. All nitrous gases turn the edges of leaves brown or brownish black and
cause blotches. Plant cells start to shrink and protoplasms detach themselves from the cell
wall. This process ultimately results in the damaged parts of the cell drying out.
Poisoning by nitrous gases is mainly due to nitrogen dioxide. However, for the purpose of
this study, vegetation in the area surrounding the Project was examined with regard to the
presence of plants sensitive to all NOx species that may be emitted by the facility.
NOx Methods
This study incorporated published information gathered from topographic maps, aerial
photography, and soil surveys. These data were coupled with field surveys of a 3-km
radius surrounding the Sutherland facility conducted in April 2007. The plant
communities in the vicinity were identified on the basis of the structure (e.g., grassland and
forest), position in landscape (e.g., upland and wetland), and dominant plant species. Plant
26
species were identified following the Flora of the Great Plains (Great Plains Flora
Association, 1986, University Press of Kansas, Lawrence, KS). It is noted that in some
instances land use classifications are used in lieu of plant communities, since in many areas
the natural vegetation has been completely eliminated or highly modified.
The sensitivity of the plant communities identified to NOx is determined on the basis of
EPA plant species sensitivity listing provided in Air Quality Criteria for Oxides of
Nitrogen11. The table is available from the Iowa Department of Natural Resource through
their website12. Table 9 is a list of plant species and the sensitivity of each to NOx that was
extracted from the 1993 EPA publication. That stated, it is noted that most studies of NOx
sensitivity to plants to date have dealt with agricultural or otherwise economically valuable
plant species. The majority of the plants encountered during this study are not included in
the EPA list. Therefore, the EPA list is used as a guideline to the potential sensitivity of
the dominant plant species found in each listed category. For instance, silver maple
dominates the riparian woodland along the Iowa River but it is not included in the EPA
list. However, the EPA list does include two species of maple as being plants having
intermediate tolerance to NOx. Because all of the species are closely related (member of
the genus Acer) logic follows that silver maple may also have intermediate tolerance to
NOx, resulting in a rating of NOx tolerance for riparian woodland of ‘intermediate’ until it
is proven otherwise. Similar reasoning was used to establish the tolerance of the other
categories.
The categories identified for the study are listed below by tolerance and composition here
but are described below in the results sections:
Tolerant
• Woodland (upland deciduous)
• Pasture
• Emergent Wetland
• Native Prairie
• Urban/Residential
• Commercial/Industrial
Intermediate
• Woodland (riparian)
• Cropland (corn, soy beans)
Sensitive
• Cropland (alfalfa, clover)
Using aerial photography, the study area was divided into a grid-work of 12 acre parcels.
Figure 4 presents the aerial photography of the 3-km radius surrounding the Sutherland
facility and the 12-acre parcel grid-work. The 12 acre parcel was chosen subjectively by
considering the final size of the map and selecting a parcel of land that was small enough
to meaningfully illustrate distribution yet large enough to not make the parcel evaluation
11
US EPA. “Air Quality Criteria for Oxides of Nitrogen, Volume II of III. EPA/600/8-91/049bF. August,
1993.
12
http://www.iowacleanair.com/prof/progdev/files/nox_veg_impacts.pdf
27
SENSITIVE
Table 9
Relative Sensitivities of Plants to Nitrogen Dioxide
INTERMEDIATE
TOLERANT
Conifers
European larch
Colorado blue spruce
Nikko fir
White fir
White spruce
Trees and Shrubs (non conifers)
European white birch
Japanese maple
Japanese zelkova
Little-leaf linden
Norway maple
Silver maple
Field Crops and Grasses
Alfalfa (lucerne)
Barley
Oats
Red clover
Spring clover
Spring vetch
Tobacco
Fruit Trees and Shrubs
Apple (wild)
Pear (wild)
Annual bluegrass
Potato
Rye
Sweet corn
Wheat
Crabapple
Grapefruit
Japanese pear
Orange
28
Austrian pine
English yew
Hinoki cypress
Japanese black pine
Loblolly pine
Pitch pine
Virginia pine
Beech
Black locust
Black poplar
Elder
English oak
European hornbeam
Ginkgo (Maidenhair tree)
Green ash
Scotch elm
Sweetgum
White ash
White oak
Eastern cottonwood
Kentucky bluegrass
Tall fescue
Smooth brome
SENSITIVE
Table 9 (continued)
Relative Sensitivities of Plants to Nitrogen Dioxide
INTERMEDIATE
TOLERANT
Garden Crops
Carrot
Bush bean
Asparagus
Celery
Celery
Bush Bean
Leek
Tomato
Cabbage
Lettuce
Carrot
parsley
Kohlrabi
Pea
Onion
Pinto bean
Rhubarb
Soybean
Ornamental Shrubs and Flowers
Azalea
Cape jasmine
Carissa
Bougainvillea
Common zinnia
Croton
Chinese hibiscus
Dahlia
Daisy
common petunia
Flossflower
Gladiolus
Oleander
Fuchsia
Japanese morning glory
Pyracantha
Gardenia
Lily-of-the-valley
Rose
Plantain lily
Snapdragon
Ligustrum
Rose
Sweet Pea
Oleander
Shore juniper
Tuberosus begonia
Paperbark tree
Spring heath
Petunia
Weeds
Common mugwort
Cheeseweed
Lamb’s-quarters
Common plantain
Chickweed
Nettle-leaved goosefoot
Horseweed
Common chickweed
Pigweed
Sunflower
Dandelion
Red root
Notes:
Species listed in bold italics are dominate species found in the study are that were not
included in the 1993 EPA list but because other closely related species (same genus) are
listed, the bold italics species is subjectively considered to have a similar tolerance.
Source:
Table 9-6, “Air Quality Criteria for Oxides of Nitrogen”, Volume II of III, EPA/600/891/049bF, August, 1993.
unduly onerous. Each 12 acre parcel was assessed and placed in one of the above
categories. The categories were color coded and mapped to illustrate the distribution of
NOx sensitivity and plant communities in the project area (Figure 5).
29
NOx Results
The study identified nine (9) categories of plant communities or general land use in the
project vicinity that are described below. Each community is ranked with regard to NOx
tolerance based on the 1993 EPA study and that is also briefly discussed. Table 9 provides
the species sensitivity ratings from the EPA study.
Figure 4
Aerial Photo of the Parceled Area
30
Figure 5
Distribution of Study Categories
TOLERANT AREAS
Woodland (Upland Deciduous). Upland deciduous woodlands are found only on the loess
hills north of the Iowa River. These native woodlands are dominated by native oaks
(Quercus spp.) and ashes (Fraxinus spp.). The presence of non-native honey locust
(Gleditsia triacanthos) and the occasional black locust (Robinia pseudoacacia) attest to a
moderate level of disturbance in much of this area. Most of these woods have been
degraded by logging activity in the past and today are becoming dotted with rural
residences. The understory is either dense and overgrown, or practically lacking due to use
for holding livestock. If present, the dominant species in the understory are usually
coralberry (Symphoricarpos orbiculatus), Missouri gooseberry (Ribes missouriense),
31
poison ivy (Toxicodendron radicans), and roughleaf dogwood (Cornus drummondii)
which are all native, and multiflora rose (Rosa multiflora), an introduced species. Ground
cover, like understory, may or may not be present. Native species present in this area are
mostly composed of spring flowering species such as violets (Viola sp.), trout lilies
(Erythronium sp.), and phlox (Phlox divaricata). Because the habitat present is
comparatively xeric, the species diversity for the area appears to be rather low and
composed of types able to withstand a substantial level of continued disturbance. This
community is considered NOx ‘tolerant,’ since oaks, ash, and locust are included in the
1993 EPA listing.
Pasture. Pastures are open grasses areas that generally are hayed or used for grazing
livestock. These are planted grasslands composed of smooth brome (Bromus inermis).
Few other species occur in these areas other than introduced or otherwise aggressive native
plants. Also included in this category are a few small parcels of land that have been
planted to warm season grasses in an attempt to re-establish the tallgrass prairie that was
once present across the region. Warm season grass plantings usually contain the three or
four dominant grass species of the native prairie (described below) but have an extremely
limited diversity of native forbs present compared to historical conditions.
This community is considered NOx ‘tolerant,’ since the dominant species (brome and
fescue) are managed agricultural species with the ability to adapt to an extremely wide
range of growing conditions. That ability is presumed here to include at least average or
better resistance to pollutants such as NOx.
Emergent Wetland. Emergent wetlands in the study area are represented by non-wooded
habitats dominated by either canary reed grass (Phalaris arundicnacea) or broad-leaf
cattail (Typha latifolia) or both. Canary reed grass is an aggressive, weedy, and introduced
species that tends to grow in near monocultures where the ground is periodically
inundated. Cattail is also aggressive, weedy, and grows in monocultures but it is native
and typically grows in sites that are permanently wet. Few other species of consequence
grow in these areas which have mostly been disturbed by forest clearing, trenching, or
farming. This community is considered NOx ‘tolerant,’ since the dominant species are
both widely distributed species with aggressive growing tendencies. For this reason the
Emergent Wetland category is here presumed to include at least average or better
resistance to pollutants such as NOx.
Urban/Residential. Areas included in this category are either residential or light
commercial. Also included here are schools, churches, and other public areas. Vegetation
in these areas may be partially lacking but is predominantly present as lawns of fescue
(Festuca sp.) and bluegrass (Poa sp.) or areas landscaped with an assortment of nursery
reared ornamental flowers, shrubs and trees. This category is considered NOx tolerant
since many of the species used in landscaping in the area are included on the EPA list as
‘tolerant,’ such as pine, poplar, oak ash, elm, locust., and Kentucky bluegrass.
32
Dense Commercial/Industrial (no vegetation). These are areas dominated by industrial
and commercial development where vegetation is completely lacking, thus resulting in the
areas being categorized as NOx tolerant.
INTERMEDIATE AREAS
Woodland (Riparian). Riparian forest is primarily located along the floodplains of major
waterways in the region. In the study area this includes the area in close proximity to the
Iowa River. Most of the species found in this habitat are native to the region. Silver maple
(Acer saccharinum) is the dominant canopy species in the project area but cottonwood
(Populus deltoides), willows (Salix spp.), and box elder (Acer negundo) at times be
common. If an understory is present saplings of the same species are usually dominant.
Ground cover may be completely lacking due to scouring from seasonal flooding or the
area may support dense colonies of weedy, although native, herbaceous species such as
giant ragweed (Ambrosia trifida) or stinging nettle (Urtica dioica).
This habitat is determined to be of intermediate tolerance due to the dominance of silver
maple. Although EPA (1993) does not list silver maple, the species of maple studied were
included as intermediate tolerance.
Cropland (corn, soy beans). Cropland dominates the study area in the vicinity of the
Sutherland facility. With but minor exceptions, fields are planted to soy beans one year,
rotated to corn the next, and back to soy beans the following year. According to the 1983
EPA criteria, corn is considered to be tolerant to NOx, while soy beans are considered to
have intermediate tolerance to NOx. While cropland is mapped as having ‘intermediate’
tolerance to NOx, an averaged score for the area would have to be something greater than
intermediate but less than tolerant.
Native Prairie. Tallgrass prairie dominated by bluestem grasses (Andropogon ssp.),
Indiangrass (Sorghastrum avenaceum), and switchgrass (Panicum virgatum) historically
covered most of this region, but today has been virtually eliminated from most of Iowa by
agricultural, commercial, and urban development. No relics of the native prairie were
encountered within the study area.
SENSITIVE AREAS
Cropland (alfalfa, clover). Clover and alfalfa are grown in some areas of central Iowa for
hay but no such crops were observed within the area studied.
NOx Summary
Nine categories of plant communities/land use were identified as potentially occurring in
the project study area. Seven of these areas were found to be present. The Cropland
(alfalfa, clover), a NOx sensitive category, was not found in the project study area. The
Native Prairie, a NOx intermediate category, was likewise not found to occur in the study
area. Figure 5 illustrates that approximately the east two-thirds of the study area is rated as
having intermediate sensitivity to NOx. This includes the categories Woodland (riparian)
and Cropland (corn, soybeans). The west third of the study area mostly lies within the city
33
limits of Marshalltown. These areas are mostly urban, residential, commercial or industrial
and vary from having landscape plantings (lawns, specimen trees, gardens, and etc.) to no
vegetation, resulting in these areas being classed NOx tolerant.
According to the Air Quality Criteria for Oxides of Nitrogen13, the 1-hour NO2
concentration which results in 5% foliar injury for the most susceptible plant species is
7,520 micrograms per cubic meter. According to the EPA Screening Document, the
minimum nitrogen dioxide concentrations at which adverse growth effects or tissue injury
occurred for the most sensitive vegetation are: 3,760 micrograms per cubic meter (4 hours
averaging time), 564 micrograms per cubic meter (1 month averaging time), and 94
micrograms per cubic meter (1 year averaging time). The graph listed in the US Fish and
Wildlife Service document “A Biologist’s Manual for the Evaluation of Impacts of Coalfired Power Plants on Fish, Wildlife, and their Habitats” depicts metabolic and growth
effects occurring for nitrogen dioxide at levels of 1,200 micrograms per cubic meter (1
hour) and 500 micrograms per cubic meter (24 hour).
The maximum model-predicted impacts, as presented in Table 8, are 20.74 μg/m3 for 1hour, 10.91 μg/m3 for 4-hours, 5.41 μg/m3 for 24-hours, 1.65 μg/m3 for 1-month, and 0.59
μg/m3 for annual. These impacts are significantly below the aforementioned screening
levels and as such, no adverse impacts to vegetation at or near the proposed Project are
expected from nitrogen oxides stack emissions.
Particulate Matter
Exposure to a given mass concentration of airborne PM may lead to widely varying
phytotoxic responses, depending on the particular mix of deposited particles. Effects of
particulate deposition on individual plants or ecosystems are difficult to characterize
because of the complex interactions among biological, physicochemical, and climatic
factors. The diverse chemistry and size characteristics of ambient PM and the lack of clear
distinction between effects attributed to phytotoxic particles and to other air pollutants
further confuse the understanding of the direct effects on foliar surfaces. The majority of
the documented toxic effects of particles on vegetation reflect their chemical content (e.g.,
acid/base, trace metal, nutrient), surface properties, or salinity. Studies indicate many
phytotoxic gases are deposited more readily, assimilated more rapidly, and lead to greater
direct injury of vegetation than do most common particulate materials (Guderian, 198614).
Any PM deposited on above-ground plant parts may potentially exert physical or chemical
effects. The effects of inert PM are mainly physical; whereas those of toxic particles are
both chemical and physical. Deposition of inert PM on above-ground plant organs
sufficient to coat them with a layer of dust may result in changes in radiation received, a
rise in leaf temperature, and the blockage of stomata. The key phytotoxic factor leading to
13
14
http://www.iowacleanair.com/prof/progdev/files/nox_veg_impacts.pdf
Guderian, R. (1986) Terrestrial ecosystems: particulate deposition. In: Legge, A. H.;
Krupa, S. V., eds.
Air pollutants and their effects on the terrestrial ecosystem. New York, NY: John Wiley &
Sons; pp. 339-363. (Advances in environmental science and technology: v. 18).
34
plant injury is usually the chemical composition of PM, more specifically, the alkalinity of
the applied dust.
Foliar uptake of available metals could result in metabolic effects in above-ground tissues.
All but 10 of the 90 elements that comprise the inorganic fraction of the soil occur at
concentrations of < 0.1% (1000 μg/g) and are termed “trace” elements or trace metals.
Trace metals with a density greater than 6 g/cm , referred to as “heavy metals,” are of
particular interest because of their potential toxicity for plant and animals. Only a few
metals, however, have been documented to cause direct phytotoxicity in field conditions.
Although some trace metals are essential for vegetative growth or animal health, they are
all toxic in large quantities, though only copper, nickel, and zinc have been documented as
frequently being toxic. Toxicity due to cadmium, cobalt, and lead has been seen only
under unusual conditions (Smith,1990c15). Generally, only the heavy metals cadmium,
chromium, nickel, and mercury are released from stacks in the vapor phase.
3
Due to good combustion practices and the utilization of a highly effective air pollution
control train adept at removing trace elements, the proposed Unit 4 will emit negligible
amounts of these compounds. Consequently, no adverse impacts to vegetation at or near
the proposed Project are expected from PM stack emissions.
Sulfur Dioxide
The response of plants to SO2 exposure is a complex process that involves not only the
pollutant concentration and duration of exposure but also the genetic composition of the
plant and the environmental factors under which exposure occurs. The response of a given
species or variety of plants to a specific air pollutant cannot be precisely predicted on the
basis of the known response of related plants to the same pollutant; neither can the
response of a plant be predicted on the basis of its response to similar doses of other
pollutants. Because of the variation in response shown by different plant species and
different cultivars of the same species, making generalizations is difficult. In general,
regardless of the condition of exposure, for a given plant species or variety there is a
critical SO2 concentration and duration of exposure above which plant injury will occur.
Such injury results from exceeding the plant’s capability to transform toxic SO2 and sulfite
into much less toxic sulfate and ultimately to transfer or break down the sulfate.
Possible plant responses to SO2 and related sulfur compounds include: 1) increased growth
and yield due to fertilization effects; 2) no detectable response; 3) injury manifested as
growth and yield reductions without visible symptoms on the foliage; 4) injury exhibited as
chronic or acute symptoms on foliage with or without associated reduction in growth and
yield; and 5) death of plants or plant communities.
A number of species of plants are sensitive to low concentrations of SO2, and some may be
used as bio-indicators of such pollution. However, even sensitive species may be
15
Smith, W. H. (1990c) Forest nutrient cycling: toxic ions. In: Air pollution and forests:
interactions between air contaminants and forest ecosystems. 2nd ed. New York, NY:
Springer-Verlag; pp. 225-268. (Springer series on environmental management).
35
asymptomatic, depending on the environmental conditions before, during and after
exposure to SO2. Because of the absence of empirical data quantifying losses in growth or
yield in relation to SO2 exposure, sensitive species are generally identified on the basis of
visible symptoms.
Visible damage to parts of plants above ground level are due to the direct action of SO2
entering the leaves via the stomata. It physiologically and biochemically impairs the
photosynthesis, the respiration and the transpiration due to its detrimental effect on the
pore aperture mechanism. Indirect damage is above all due to soil acidification (damage to
mycorrhiza) and results in stunted growth. The conversion of SO2 to acid rain can take
several days to occur. Therefore, when considering the effects nearby the facility it is
mostly SO2 that is acidified on the ground by dew, snow, frost, and rain, rather than while
the SO2 is airborne16.
SO2 Methods
This study incorporated published information gathered from topographic maps, aerial
photography, and soil surveys. These data were coupled with field surveys of a 3-km
radius surrounding the Sutherland facility conducted in April 2007. The plant
communities in the vicinity were identified on the basis of the structure (e.g., grassland and
forest), position in landscape (e.g., upland and wetland), and dominant plant species. Plant
species were identified following the Flora of the Great Plains (Great Plains Flora
Association, 1986, University Press of Kansas, Lawrence, KS). It is noted that in some
instances land use classifications are used in lieu of plant communities, since in many areas
the natural vegetation has been completely eliminated or highly modified.
The plant communities/land use categories identified for the study are listed below and are
described in the results:
• Woodland (upland deciduous)
• Woodland (riparian)
• Pasture
• Emergent Wetland
• Native Prairie
• Urban/Residential
• Commercial/Industrial
• Cropland (corn, soy beans)
The sensitivity of plant species to SO2 is not well studied when considering natural floras.
Most studies examine plant communities in a very broad sense, such as a coniferous or
deciduous forest. These plant communities are composed of numerous dominant species
and hundreds of less common species. A literature review suggests that a very small
percentage of the species comprising most local floras has been critically examined with
regard to SO2 sensitivity. In central Iowa where most counties have a flora of about 30016
Mulgrew and Williams, Biomonitoring of Air Quality Using Plants,
http://www.umweltbundesamt.de/whocc/AHR10/III-GP-5.htm
36
350 species (University of Iowa Herbarium (http://www.cgrer.uiowa.edu/herbarium/),
perhaps only 15 of those 300 species have been studied to any extent and more than likely
the plants studied are widespread weeds or economically important species rather than
dominant or secondary components of the natural flora. Ultimately, it is difficult to make
more than gross generalizations about the affect, albeit real, of SO2 to whole plants
communities. Comments made herein with regard to SO2 sensitivity are based strictly on
previously published reports.
SO2 Results
Similar to the NOx analysis, the study area was divided into a grid-work of 12 acre parcels
using aerial photography (see Figure 4). The 12 acre parcel was chosen subjectively by
considering the final size of the map and selecting a parcel of land that was small enough
to meaningfully illustrate distribution yet large enough to not make the parcel evaluation
unduly onerous. Each 12 acre parcel was assessed based on a field assessment and aerial
photography and the dominant community in each 12 acre parcel was mapped. The
distribution of plant communities in the project vicinity is illustrated in Figure 6. The plant
communities identified are described in the following sections.
Woodland (Riparian). Riparian forest is primarily located along the floodplains of major
waterways in the region. In the study area this includes the area in close proximity to the
Iowa River. Most of the species found in this habitat are native to the region. Silver maple
(Acer saccharinum) is the dominant canopy species in the project area but cottonwood
(Populus deltoides), willows (Salix spp.), and box elder (Acer negundo) at times be
common. If an understory is present saplings of the same species are usually dominant.
Ground cover may be completely lacking due to scouring from seasonal flooding or the
area may support dense colonies of weedy, although native, herbaceous species such as
giant ragweed (Ambrosia trifida) or stinging nettle (Urtica dioica). This habitat is
determined to be of intermediate tolerance due to the dominance of silver maple. Although
EPA (1993) does not list silver maple, the species of maple studied were included as
intermediate tolerance.
According to Davis and Wilhour (197617), selected species of maple (Acer) are ‘sensitive’
to SO2. Sensitive is not defined but other plant species (no maples) are listed as ‘very
sensitive.’ Although silver maple was not one of the species listed by Davis and Wilhour,
it is assumed here that silver maple would exhibit sensitivity levels similar to some of the
species listed, such as box elder (Acer negundo) and mountain maple (Acer glabrum).
Therefore, the Riparian Forest can be considered a sensitive plant community.
Woodland (Upland Deciduous). Upland deciduous woodlands are found only on the loess
hills north of the Iowa River. These native woodlands are dominated by native oaks
(Quercus spp.) and ashes (Fraxinus spp.). The presence of non-native honey locust
(Gleditsia triacanthos) and the occasional black locust (Robinia pseudoacacia) attest to a
moderate level of disturbance in much of this area. Most of these woods have been
degraded by logging activity in the past and today are becoming dotted with rural
residences. The understory is generally dense and overgrown, or practically lacking due to
17
http://fs.fed.us/air.documents/0_plantsb.pdf
37
Figure 6
Distribution of the Plant Communities
use for holding livestock. If present, the dominant species in the understory are usually
coralberry (Symphoricarpos orbiculatus), Missouri gooseberry (Ribes missouriense),
poison ivy (Toxicodendron radicans), and roughleaf dogwood (Cornus drummondii)
which are all native, and multiflora rose (Rosa multiflora), an introduced species. Ground
cover, like understory, may or may not be present. Native species present in this area is
mostly composed of spring flowering species such as violets (Viola sp.), trout lilies
(Erythronium sp.), and phlox (Phlox divaricata). Because the habitat present is
comparatively xeric, the species diversity for the area appears to be rather low and
composed of types able to withstand a substantial level of continued disturbance.
38
The SO2 sensitivity of this plant community is difficult to assess based on species
composition for lack of definitive and comparative data that is species specific. It is clear
that oaks and ash, the dominant species in this community, are probably sensitive to SO2 to
at least a small degree (Grill, D., Muller, M., Tausz, M. Strnad, B., Wonisch, A. and
Raschi, A. 2004. Effects of sulphurous gases in two CO2 springs on total sulphur and
thiols in acorns and oak seedlings. Atmospheric Environment 38: 3775-3780; Jensen, K. F.
1981. Forest Service Technical Report, Northeastern Forest Experiment Station,
Broomall, PA).
Pasture. Pastures are open grasses areas that generally are hayed or used for grazing
livestock. These are planted grasslands composed of smooth brome (Bromus inermis).
Few other species occur in these areas other than introduced or otherwise aggressive native
plants. Also included in this category are a few small parcels of land that have been
planted to warm season grasses in an attempt to re-establish the tallgrass prairie that was
once present across the region. Warm season grass plantings usually contain the three or
four dominant grass species of the native prairie (described below) but have an extremely
limited diversity of native forbs present compared to historical conditions.
No information could be found regarding the SO2 sensitivity of brome (Bromus sp.) and
brome is a planted or otherwise introduced plants. Therefore, pasture as described herein
is conservatively considered to be SO2 sensitive.
Emergent Wetland. Emergent wetlands in the study area are represented by non-wooded
habitats dominated by either canary reed grass (Phalaris arundicnacea) or broad-leaf
cattail (Typha latifolia) or both. Canary reed grass is an aggressive, weedy, and introduced
species that tends to grow in near monocultures where the ground is periodically
inundated. Cattail is also aggressive, weedy, and grows in monocultures but it is native
and typically grows in sites that are permanently wet. Few other species of consequence
grow in these areas which have mostly been disturbed by forest clearing, trenching, or
farming.
Emergent wetland as herein described is not considered SO2 sensitive. No information
could be found regarding SO2 sensitivity to canary reed grass and broad-leaf cattail. Both
plants demonstrate very aggressive growth under a wide range of disturbed habitat
conditions and it is reasonable to assume that affects from SO2 are probably negligible.
Urban/Residential. Areas included in this category are either residential or light
commercial. Also included here are schools, churches, and other public areas. Vegetation
in these areas may be partially lacking but is predominantly present as lawns of fescue
(Festuca sp.) and bluegrass (Poa sp.) or areas landscaped with an assortment of nursery
reared ornamental flowers, shrubs and trees. This area is considered SO2 tolerant since it is
mostly developed. It is recognized, however, that there may be ornamental species present
that are known to be SO2 sensitive, such as gladiolas.
39
Dense Commercial/Industrial (no vegetation). These are areas dominated by industrial
and commercial development where vegetation is completely lacking, thus resulting in the
areas being considered SO2 tolerant.
Cropland (corn, soy beans). Cropland dominates the study area in the vicinity of the
Sutherland facility. With but minor exceptions fields are planted to soy beans one year,
rotated to corn the next, and back to soy beans the following year. According to the
University of Nebraska (http://www.panhandle.unl.edu/potato/html/air_pollutants.htm)
corn is not sensitive to SO2, while soy beans are considered sensitive.
Native Prairie. Tallgrass prairie dominated by bluestem grasses (Andropogon ssp.),
Indiangrass (Sorghastrum avenaceum), and switchgrass (Panicum virgatum) historically
covered most of this region, but today has been virtually eliminated from most of Iowa by
agricultural, commercial, and urban development. No relics of the native prairie were
encountered within the study area.
SO2 Summary
Seven categories of plant communities/land use were identified as occurring in the project
vicinity. Three categories of sensitivity to SO2 can be more-or-less recognized based on a
sampling of literature, non-sensitive or tolerant, sensitive or intermediate tolerance, and
very sensitive. None of the plant communities present appear to be composed of dominant
species that have been identified as very sensitive to SO2.
The riparian and upland woodlands, due to the dominance of maple and oak (respectively),
should be considered communities with sensitive or intermediate tolerance for SO2. The
cropland is considered sensitive if soy beans are planted but tolerant if corn is planted. The
remaining communities are not sensitive to SO2. By considering the distribution of plant
communities/land use in Figure 6 is evident that most of the region surrounding the
Sutherland Energy Center is to some degree sensitive to SO2.
According to the Criteria Document18 for SO2, for the most sensitive vegetations, an
exposure of 790-1,570 micrograms per cubic meter at 3-hours duration or 1,310-2,620
micrograms per cubic meter at a duration of 1-hour will cause visible injury to the plant.
The SO2 impacts produced by the proposed Project, as referenced in Table 8, are 30.98
μg/m3 for 1-hour and 15.41 μg/m3 for 3-hour. The impacts are significantly lower than
these sensitive levels; consequently, no adverse impacts to vegetation at or near the
proposed Project are expected from SO2 stack emissions.
Ozone
The direct effect of ozone to plants is the destruction of chlorophyll and in particular
chlorophyll b. There is a considerable difference in the sensitivity of various plants to
ozone. Acute symptoms of ozone damage are necrosis, chlorosis, and so-called water
marks. Ozone causes noticeable leaf damage in many crop and tree species. Research
indicates this damage occurs at concentrations commonly monitored during the warm
18
Air Quality Criteria for Particulate Matter and Sulfur Oxides (1982): Volume III. U.S. Environmental
Protection Agency, Washington, D.C., EPA/600/8-82/029CF.
40
months (i.e. 60 ppb to 120 ppb). Certain varieties of soybeans, clover, onions, spinach,
muskmelon and alfalfa are especially susceptible. Trees, such as lilac, aspen and ash are
also sensitive.
Ozone is not directly emitted from pollutant sources, such as the Unit 4 boiler and ancillary
equipment proposed for this Project. Instead, it is formed in a reversible reaction between
O2, O3, NOx, and VOCs. The increase in ozone formation due to emissions of NOx and
VOC from the Project was estimated using a conservative screening methodology
approved by IDNR based on the “VOC/NOx Point Source Screening Tables” developed by
Scheffe19. This conservative methodology is used to identify estimated incremental ozone
plumes on an hourly basis. For the proposed Project, the ozone impact estimated from the
Scheffe tables was less than 0.010 ppm (19.6 micrograms per cubic meter) on an hourly
basis. In the article “The Response of Native, Herbaceous Species to Ozone: Growth and
Fluorescence Screening,” New Phytologist, 120 (1992):29-37, Reiling and Davison found a
reduction of growth rate in certain plants after being fumigated with 139.7 μg/m3 O3 for
2 weeks. The impacts related to the proposed Project estimated from the Scheffe tables are
well below this level. Consequently, no adverse impacts to vegetation at or near the
proposed Project are expected from ozone formation due to the operation of the Project.
Fluorides
Signs of inorganic fluoride phytotoxicity, such as chlorosis, necrosis and decreased growth
rates, are most likely to occur in the young, expanding tissues of broadleaf plants and
elongating needles of conifers. The induction of fluorosis has been clearly demonstrated in
laboratory, greenhouse, and controlled field plot experiments.
Toxicity is specific not only to plant species, but also to ionic species of fluoride, e.g.,
aluminum fluoride and hydrogen fluoride. However, most of the studies performed
involved the fumigation of plants with hydrogen fluoride. According to GreenFacts, leaf
necrosis has been known to occur at concentrations of 0.17 and 0.27 micrograms per cubic
meter (exposure of 99 and 83 days, respectively) in the case of grapevines. The German
Federal Ministry for Economic Cooperation and Development20 also references that for the
highly sensitive Crocus, an exposure to a hydrogen fluoride concentration of 2 micrograms
per cubic meter (276 hours exposure) can cause extremely severe leaf necrosis.
The maximum model-predicted impact of 0.08 μg/m3 for 1-hour, as presented in Table 8,
is significantly below the screening levels, even at a conservative 1 hour averaging period,
and as such, no adverse impacts to vegetation at or near the proposed Project are expected
from fluoride stack emissions.
19
Scheffe, R.D. “VOC/NOx Point Source Screening Tables”. US EPA, Office of Air Quality Planning and
Standards. September, 1988.
20
German Federal Ministry for Economic Cooperation and Development. Environment Handbook –
Document on Monitoring and Evaluating Environmental Impacts, Volume III: Compendium of
Environmental Standards. http://144.16.93.203/energy/HC270799/HDL/ENV/enven/begin3.htm#Contents
41
SOILS
A soil inventory was completed by obtaining a soil survey within the 3-km radius study
area surrounding the facility. The soil survey was obtained from the Natural Resource
Conservation Service. The different soil types that were found to be in excess of 1% of the
total land area of the 3-km study area are listed in Table 10 and Attachment 3. The most
abundant soil type in the vicinity of the Project was Tama silty clay loam, at 18.75%.
According to the US Department of Agriculture Soil Conservation Service, the Tama silty
clay loam series consists of very deep, well drained soils formed in loess. Tama silty clay
loam soils are on interfluves and side slopes on uplands and on treads and risers on stream
terraces. The full range of slope is from 0 to 20 percent. Tama silty clay loam soils are
well drained. Surface runoff potential is negligible to high. Tama silty clay loam soils that
are nearly level to gently sloping are cultivated with the principal crops being corn,
soybeans, small grains, and legume hays. Tama silty clay loam soils that are on steeper
slopes are commonly used as pasture lands. The native vegetation found within Tama silty
clay loam soils are big bluestream, little bluestream, switchgrass, and other grasses of the
tall grass prairie.
Sulfates and nitrates caused by SO2 and NOx deposition onto the soil can be either
beneficial or detrimental to soil depending on its composition. However, the proposed SO2
and NOx emission rates and consequently the impacts generated by the Project are not
expected to have an adverse impact upon soils in the immediate vicinity since they are
below the secondary NAAQS.
Table 10
Soil Types
Ackmore silt loam
Lindley loam
Ackmore-Colo complex
Muscatine-Urban land complex
Bremer silty clay loam
Nevin silty clay loam
Colo silty clay loam
Nodaway silt loam
Colo-Ely complex
Nodaway silt loam, channeled
Colo-Hanlon-Lawson complex
Pits
Colo-Urban land complex
Tama silty clay loam
Dinsdale silty clay loam
Tama silty clay loam, benches
Downs silt loam
Tama-Urban land complex
Fayette silt loam
Water
Lawler loam
Zook silty clay loam
Lawson silty clay loam
NOTES:
Data taken from the Natural Resources Conservation Service’s Web
Soil Survey (http://websoilsurvey.nrcs.usda.gov/app/) for the 6x6-km
domain in Marshall County, Iowa.
42
IDNR’S SOILS AND VEGETATION ANALYSIS TOOL
INDR recently completed an analysis tool for determining the impacts emissions have on
soils and vegetation. This analysis tool is being used in conjunction with the analysis
above and is attached as Attachment 5. The analysis for lead was not conducted since the
emission level did not exceed the applicable PSD SER. As seen in the analysis, all
pollutants are below their applicable screening levels except for fluoride on a 10-day
averaging period. However, review of the screening document utilized by IDNR to
generate this tool, shows a screening level of 0.5 μg/m3 for fluorine on a 10-day average.
The conservative 1-hour maximum impact of 0.07 μg/m3, as referenced in Table 8, is well
below the screening level. The results from the screening tool indicate that there are no
adverse impacts expected to soils and vegetation at or near the proposed Project.
THREATENED AND ENDANGERED SPECIES
Various species of wildlife and plants have been rendered extinct or have been so depleted
in numbers that they are in danger of or threatened with extinction as a consequence of
economic growth and development unrestrained by adequate concern and conservation.
The US Congress passed the Endangered Species Preservation Act in 1966 and
subsequently the Endangered Species Act of 1973 to conserve to the extent practicable the
various species of wildlife and plants facing extinction since these species are of esthetic,
ecological, educational, historical, recreational, and scientific value.
An “endangered” species is one that is in danger of extinction throughout all or a
significant portion of its range. A “threatened” species is one that is likely to become
endangered in the foreseeable future. On April 11, 2007, IPL sent a letter to the US Fish
and Wildlife Service requesting information of the potential impacts on endangered species
from the proposed Project. On May 17, 2007, the US Fish and Wildlife Service responded
stating that there are four species found in the Project area (including the distribution line
upgrade project): the bald eagle, the prairie bush clover, the northern monkshood, and the
western prairie fringed orchid. However, according to the US Fish and Wildlife Service
and the Natural Resources Conservation Service’s websites, there is a more exhaustive list,
therefore, these sources were utilized for this analysis. The following subsections briefly
describe the potential effects of the PSD applicable pollutants produced by the proposed
Project on the nearby threatened and endangered species
Wildlife Species
According to the US Fish and Wildlife Service, there are a total of 14 animal species that
are listed as being threatened or endangered in the state of Iowa; however, only 7 of those
listed actually occur in the state. For this analysis, it was conservatively assumed that all
14 animal species are found in the 3-km radius study area. A list of these is contained in
Attachment 3.
Information pertaining to the affects the pollutants emitted from the proposed Project
would have on these 14 threatened or endangered animals is minimal. Therefore, it was
conservatively assumed that a comparison to information provided in laboratory
43
experiments that were performed on test species would suffice. Lethal concentrations are
usually reported as several different values, with the most common ones being: the LC50
which is the concentration of the chemical in air that kills 50% of the test animals in a
given time and the lethal concentration low (LCLo) which is the lowest concentration of a
chemical in air reported to have caused death in humans or animals. Table 11 presents a
summary of the laboratory findings for the PSD pollutants of concern for the proposed
Project.
From the impacts referenced above, the emissions from the proposed Project are not
expected to adversely impact the animal species; therefore, it is assumed that these
emissions will not put at risk the efforts to conserve the 14 listed threatened and
endangered species.
Plant Species
According to the Natural Resources Conservation Service, there are a total of 154 plant
species in Iowa that are listed on either the federal or state level as being threatened or
endangered; however, none of these 154 plant species are found in Marshall County. A list
of these is contained in Attachment 3. From the inventory referenced above, there are
several plant species, e.g. violets and trout lilies, which are within the 3-km radius study
area for the proposed Project that are similar (same genus) to some of those found on the
threatened or endangered list. From the impacts referenced above, the emissions from the
proposed Project are not expected to adversely impact the most sensitive vegetation;
therefore, it is assumed that these emissions will not put at risk the efforts to conserve these
threatened and endangered species.
Table 11
Lethal Concentrations of Select Pollutants on Laboratory Animals
Chemical
Value
CO
LC50 – 2,103 mg/m3 (4 hours)
NO2
SO2
Ozone
HF
Test Animal
Rat
3
Guinea Pig
3
LC50 – 16.8 mg/m (4 hours)
Rat
LCLo – 123 mg/m3
Dog
LC50 – 346 mg/m3 (24 hours)
Mouse
LC50 – 57.3 mg/m (1 hour)
3
LC50 – 41.9 mg/m
Mouse
3
LC50 – 1,062 mg/m (1 hour)
44
Rat
VISIBILITY
A visibility analysis is performed to determine the impact that a proposed PSD source
would have on Class II sensitive areas such as state parks, wilderness areas, or scenic sites
and over looks. Since the modeling results given in Tables 5 and 6 indicate the proposed
Project will not have a significant impact for any pollutant, IPL has chosen to analyze the
visibility impacts upon the nearest state park, Union Grove, located approximately 14 km
northeast of the proposed Project location. Additionally, the IDNR has requested that
visibility analyses be performed on the Rock Creek State Park, the nearest state park
considering the predominant wind flows in this portion of the state, located approximately
29 km south of the proposed Project location. Figures 7 and 8 respectively illustrate the
locations of the Union Grove and Rock Creek State Parks with respect to the proposed
Project location. As defined in the CAA, the PSD requirements provide for a system of
area classifications. Class I areas are generally national parks and wilderness areas. Class
II areas, such as the state park, can accommodate well-managed and industrial growth. As
such, visibility analyses were performed to evaluate the potential for visibility impairment
inside the selected Class II scenic vista.
A visibility impairment screening analysis was conducted at the aforementioned Class II
area to provide a conservative indication of the perceptibility of plumes from the proposed
main boiler emission source. The analysis was performed in accordance with the
USEPA’s Workbook for Plume Visual Impact Screening and Analysis (Revised) (EPA454/R-92-023, October 1992, hereinafter referred to as the “Workbook”), using the
VISCREEN model. It should be noted that the visibility impairment analyses and model
VISCREEN are typical for assessments in PSD Class I areas where visibility preservation
is a factor in the permit approval process. However, since no applicable Class II visibility
model is available, this model and the methodology for Class I areas as outlined in the
Workbook were used.
45
45o
55o
Union Grove
State Park
Project
Location
Figure 7
Location of Union Grove State Park for Visibility Analyses
46
Project
Location
Rock Creek
State Park
o
o
182
175
Figure 8
Location of Rock Creek State Park for Visibility Analyses
In accordance with the Workbook’s visual screening procedures, the VISCREEN plume
visual impact screening model would first be used with default worst-case Level 1
screening parameters. However, it is important to note that Level 1 analyses incorporate
numerous worst-case default assumptions and parameters. As such, and in accordance
with USEPA guidance, a more representative worst-case Level 2 screening analysis with
situation-specific meteorological parameters was conducted. Tables 12 and 13 present the
Level 2 visual screening parameters used in the VISCREEN modeling respectively for
Union Grove and Rock Creek. Many of the input parameters for a Level 2 analysis are the
same as the default worst-case values for a Level 1 analysis specified in the Workbook.
The shaded parameters in Tables 12 and 13 designate the more representative, situationspecific inputs of the Level 2 analysis. The situation-specific Level 2 screening parameters
are described below.
47
Table 12
VISCREEN Level 2 Model Inputs
Level 2
(Representative Worst-Case Analysis)(a)
VISCREEN Modeling Parameter
Union Grove State Park
Maximum Emissions
Particulate Emissions(b)
114.0 lb/h
NOx (as NO2) Emissions
(b)
316.7 lb/h
Primary NO2 Emissions
0 lb/h (model default)
Soot Emissions
0 lb/h (model default)
(b)
Sulfate Emissions (SO4)
25.30 lb/h
Source-Observer Distance
13.87 km
Minimum Source-Class II Distance
13.87 km
Maximum Source-Class II Distance
14.98 km
Background Visual Range
(c)
40 km
Plume-Source-Observer Angle(a)
11.25 degrees
(a)
Background Ozone Concentration
Stability Class
0.04 ppm
(c,d)
D
(c,d)
Wind Speed
2.00 m/sec
(a)
1.5 g/cm3
Background Fine Particulate Density
Background Fine Particulate Size Index(a)
(a)
Background Coarse Particulate Density
Background Coarse Particulate Size
Index(a)
2.5 g/cm3
6.0 μ/m
Plume Particulate Density(a)
2.5 g/cm3
Plume Particulate Size Index(a)
2.0 μ/m
(a)
2.0 g/cm3
Plume Soot Density
Plume Soot Size Index(a)
0.1 μ/m
(a)
1.5 g/cm3
Plume Primary SO4 Density
Plume Primary SO4 Size Index(a)
(a)
0.3 μ/m
0.5 μ/m
VISCREEN model default values.
(b)
Highest emissions of all operating scenarios.
Worst-case situation specific parameter.
(d)
Five years of meteorological data analyzed from Des Moines as obtained and analyzed by
the IDNR visibility tool. Represents the meteorological conditions that are only expected to
be worse than these conditions approximately 4 days per year.
(c)
48
Table 13
VISCREEN Level 2 Model Inputs
Level 2
(Representative Worst-Case Analysis)(a)
VISCREEN Modeling Parameter
Rock Creek State Park
Maximum Emissions
Particulate Emissions(b)
114.0 lb/h
NOx (as NO2) Emissions
(b)
316.7 lb/h
Primary NO2 Emissions
0 lb/h (model default)
Soot Emissions
0 lb/h (model default)
(b)
Sulfate Emissions (SO4)
25.30 lb/h
Source-Observer Distance
29.22 km
Minimum Source-Class II Distance
29.22 km
Maximum Source-Class II Distance
34.42 km
Background Visual Range
(c)
40 km
Plume-Source-Observer Angle(a)
11.25 degrees
(a)
Background Ozone Concentration
Stability Class
0.04 ppm
(c,d)
D
(c,d)
Wind Speed
4.00 m/sec
(a)
1.5 g/cm3
Background Fine Particulate Density
Background Fine Particulate Size Index(a)
(a)
Background Coarse Particulate Density
Background Coarse Particulate Size
Index(a)
2.5 g/cm3
6.0 μ/m
Plume Particulate Density(a)
2.5 g/cm3
Plume Particulate Size Index(a)
2.0 μ/m
(a)
2.0 g/cm3
Plume Soot Density
Plume Soot Size Index(a)
0.1 μ/m
(a)
1.5 g/cm3
Plume Primary SO4 Density
Plume Primary SO4 Size Index(a)
(a)
0.3 μ/m
0.5 μ/m
VISCREEN model default values.
(b)
Highest emissions of all operating scenarios.
Worst-case situation specific parameter.
(d)
Five years of meteorological data analyzed from Des Moines as obtained and analyzed by
the IDNR visibility tool. Represents the meteorological conditions that are only expected to
be worse than these conditions approximately 4 days per year.
(c)
49
The worst-case Level 1 VISCREEN stability class default value of ‘F’ and wind speed of 1
m/sec were found not to be representative of the general climatological conditions in the
vicinity of the proposed Project. IDNR has developed a tool for determining more
representative conditions of the area. The tool performs joint frequency distributions for a
given meteorological dataset (Des Moines in this case) to find the combination of stability
class and wind speed, which is expected to be worse than 99 percent of the conditions
existing in the area. That is, for only 1 percent of the time (i.e., about 4 days per year) are
the conditions expected to be worse than those selected for these analyses. These analyses
are consistent with the methodologies in the Workbook. They consider the persistence as
well as the frequency of occurrence of the stabilities and wind speeds insomuch as the
transport times to the Class II areas may be of sufficient length to allow the plume to break
up and not remain visible.
Based on the instructions contained within the IDNR visibility tool, if the conservative
Class I visibility thresholds are exceeded using the 1 percent meteorological conditions, the
next worst stability class and wind speed combination should be used until the conditions
under which the visibility thresholds are not exceeded is found. Tables 14 and 15 give the
worst-case meteorological conditions summary indicating the cumulative frequencies of all
applicable combinations of stability class and wind speed respectively for Union Grove
and Rock Creek. For Rock Creek, the 1 percent condition was found to be suitable in
demonstrating Class II visibility below the conservative Class I visibility thresholds. For
Union Grove, however, the 1 percent condition was yet too conservative. The areaspecific Level 2 worst-case conditions for Union Grove were determined by the tool to be
“E,4” and occur during the night-time hours from 1 to 6 am. The next condition of “D,2”,
which occurs only 0.01 percent more of this same time period, was required to be used in
the analysis to demonstrate the conservative Class I visibility thresholds were not
exceeded. The results of the meteorological analyses are presented back in Tables 12 and
13 as the shaded stability class and wind speed values used in the analysis that indicated no
exceedance.
Results of the VISCREEN modeling are included in Tables 16 and 17 for Union Grove and
Rock Creek State Parks, respectively. As previously noted, the modeling methodology
utilized for this analysis is designed for Class I areas. The areas presented in this analysis
are classified as Class II and, as such, has no set criteria from which to evaluate visual
impacts. Therefore, the conservative Class I criteria were used in the analysis.
CLASS I AREA IMPACTS ANALYSIS
The nearest Class I areas are the Rainbow Lake Wilderness Area and Hercules-Glades
Wilderness Area located approximately 510 and 590 km, respectively, from the proposed
Project. Given the magnitude of these distances, no Class I area analyses are proposed for
this Project.
50
Table 14
Worst-case Meteorological Conditions Summary for Union Grove State Park(a)
Dispersion
Condition
(stability,
wind
speed)
F,1
F,2
E,1
F,3
E,2
D,1
E,3
E,4(b)
D,2(c)
E,5
D,3
D,4
D,5
D,6
D,7
D,8
σyσzu
(m3/s)
1.93E+04
3.85E+04
5.01E+04
5.78E+04
1.00E+05
1.18E+05
1.50E+05
2.01E+05
2.36E+05
2.51E+05
3.54E+05
4.72E+05
5.90E+05
7.08E+05
8.26E+05
9.44E+05
Transport
Time
(hours)
7.7
2.6
7.7
1.5
2.6
7.7
1.5
1.1
2.6
0.9
1.5
1.1
0.9
0.7
0.6
0.5
Frequency (f) and Cumulative Frequency (cf) of
occurrence of given dispersion condition associated with
source-site wind directions for given time of day (%)
1-6
f
0.10
0.16
0.01
0.47
0.03
0.01
0.14
0.12
0.01
0.19
0.03
0.06
0.10
0.14
0.15
0.05
cf
0.10
0.26
0.27
0.74
0.77
0.78
0.92
1.04
1.05
1.24
1.27
1.33
1.43
1.57
1.72
1.77
(a)
7-12
f
0.03
0.03
0.04
0.05
0.00
0.05
0.05
0.06
0.03
0.01
0.13
0.10
0.16
0.32
0.30
0.27
cf
0.03
0.06
0.10
0.15
0.15
0.20
0.25
0.31
0.34
0.35
0.48
0.58
0.74
1.06
1.36
1.63
13-18
f
0.01
0.01
0.02
0.01
0.01
0.00
0.02
0.01
0.00
0.06
0.06
0.08
0.21
0.29
0.29
0.29
cf
0.01
0.02
0.04
0.05
0.06
0.06
0.08
0.09
0.09
0.15
0.21
0.29
0.50
0.79
1.08
1.37
19-24
f
0.17
0.08
0.01
0.33
0.02
0.00
0.12
0.26
0.00
0.27
0.02
0.12
0.05
0.09
0.09
0.07
cf
0.17
0.25
0.26
0.59
0.61
0.61
0.73
0.99
0.99
1.26
1.28
1.40
1.45
1.54
1.63
1.70
Represents output from the IDNR visibility tool design to determine the joint frequency distribution for
combinations of stability class and wind speed. Des Moines meteorological data downloaded from the IDNR
website was used in the analysis.
(b)
This condition is the first occurrence of a cumulative frequency combination of stability and wind speed above
1 percent and was the starting point for the visibility analysis. Note that this combination reaches a 1 percent
occurrence during the night-time hours of 1 to 6 am when no visible plume would be detected.
(c)
This condition is the next worst-case combination (only occurring 0.01 percent more of the time) and was used
to demonstrate visibility impacts below the conservative Class I visibility thresholds.
51
Table 15
Worst-case Meteorological Conditions Summary for Rock Creek State Park(a)
Dispersion
Condition
(stability,
wind
speed)
F,1
F,2
E,1
F,3
E,2
D,1
E,3
E,4
E,5
D,2
D,3
D,4(b)
D,5
D,6
D,7
D,8
(a)
σyσzu
(m3/s)
4.77E+04
9.54E+04
1.32E+05
1.43E+05
2.65E+05
3.47E+05
3.97E+05
5.29E+05
6.62E+05
6.94E+05
1.04E+06
1.39E+06
1.73E+06
2.08E+06
2.43E+06
2.78E+06
Transport
Time
(hours)
16.2(c)
5.4
16.2(c)
3.3
5.4
16.2(c)
3.3
2.3
1.8
5.4
3.3
2.3
1.8
1.5
1.3
1.1
Frequency (f) and Cumulative Frequency (cf) of
occurrence of given dispersion condition associated with
source-site wind directions for given time of day (%)
1-6
f
0.03
0.05
0.01
0.14
0.03
0.04
0.06
0.16
0.09
0.03
0.06
0.16
0.17
0.29
0.26
0.16
cf
0.00
0.05
0.05
0.19
0.22
0.22
0.28
0.44
0.53
0.56
0.62
0.78
0.95
1.24
1.50
1.66
7-12
f
0.00
0.00
0.00
0.03
0.00
0.01
0.00
0.03
0.00
0.00
0.06
0.12
0.21
0.35
0.27
0.24
cf
0.00
0.00
0.00
0.03
0.03
0.03
0.03
0.06
0.06
0.06
0.12
0.24
0.45
0.80
1.07
1.31
13-18
f
0.00
0.01
0.00
0.01
0.02
0.00
0.01
0.03
0.03
0.00
0.10
0.08
0.18
0.36
0.40
0.29
19-24
cf
0.00
0.01
0.01
0.02
0.04
0.04
0.05
0.08
0.11
0.11
0.21
0.29
0.47
0.83
1.23
1.52
f
0.13
0.05
0.03
0.16
0.02
0.02
0.19
0.28
0.20
0.01
0.04
0.16
0.26
0.26
0.33
0.26
cf
0.00
0.05
0.05
0.21
0.23
0.23
0.42
0.70
0.90
0.91
0.95
1.11
1.37
1.63
1.96
2.22
Represents output from the IDNR visibility tool design to determine the joint frequency distribution for
combinations of stability class and wind speed. Des Moines meteorological data downloaded from the IDNR
website was used in the analysis.
(b)
This condition is the first occurrence of a cumulative frequency combination of stability and wind speed above
1 percent and was the starting point for the visibility analysis. Note that this combination reaches a 1 percent
occurrence during the night-time hours of 1 to 6 am when no visible plume would be detected.
(c)
Dispersion conditions with transport times longer than 12 hours are not added to the cumulative frequency
summation.
Table 16
VISCREEN Level 2 Model Results for Union Grove State Park
Delta E
Contrast
Background
Theta
(Degrees)
Distance
(km)
Plume
Criteria
Plume
Criteria
Sky
10
15.0
1.379
4.94
0.011
0.08
Sky
140
15.0
0.840
2.00
-0.017
0.08
Terrain
10
13.9
3.286
3.96
0.030
0.09
Terrain
140
13.9
0.533
2.00
0.015
0.09
52
Table 17
VISCREEN Level 2 Model Results for Rock Creek State Park
Delta E
Contrast
Background
Theta
(Degrees)
Distance
(km)
Plume
Criteria
Plume
Criteria
Sky
10
34.4
0.341
3.00
0.003
0.05
Sky
140
34.4
0.163
2.00
-0.004
0.05
Terrain
10
29.2
0.446
3.35
0.005
0.06
Terrain
140
29.2
0.084
2.00
0.003
0.06
MODELING DATA SUBMITTAL
Electronic files, including all input and output files, of the air dispersion modeling analyses
are included on electronic media in Attachment 5.
Please review the proposed modeling methodology and results and provide comments.
Should you have any questions concerning the content of this letter, please contact me at
319-786-4476, or by e-mail at [email protected]
Sincerely,
Alan Arnold
Senior Environmental Specialist
Interstate Power and Light
Cc:
Jeff Beer, IPL Project Director
Andy Byers, Environmental Manager, Black & Veatch
Tim Hillman, Air Permitting Manager, Black & Veatch
53
Attachment 1
Project Arrangements
Attachment 2
Performance and Emissions Calculations
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Composition of Gas Exiting Stack (lb/hr)
Fuel Type:
Case:
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - 1
M10- Run PRB-1
IL - 1
M10- Run IL-1
PRB - 2
M10- Run PRB-2
IL - 2
M10- Run IL-2
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
353,161
4,800,280
0
1,358,469
380
837,451
423,364
4,813,179
0
1,280,117
494
699,458
336,116
4,566,406
0
1,292,086
361
700,434
399,863
4,547,159
0
1,209,205
466
567,035
Total Flue Gas Flow Rate (lb/hr)
7,349,741
7,216,612
6,895,403
6,723,728
261,473
288,852
232,601
257,966
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
11,040
171,360
0
30,870
6
46,490
13,230
171,820
0
29,090
8
38,830
10,500
163,010
0
29,360
6
38,880
12,500
162,320
0
27,480
7
31,480
Total Flue Gas Flow Rate (moles/hr)
259,766
252,978
241,756
233,787
Stack Exit Conditions
Fuel Type:
Case:
Fuel Burn Rate, MBtu/hr
Fuel Higher Heating Value, Btu/lb
Fuel Burn Rate, lb/hr
Wet Molecular Weight, lb/mole
Flue Gas Density, lb/cuft
Total Gas Flow Rate, acfm
Total Gas Flow Rate leaving A/H, acfm
Temperature, F
Pressure, in w.g.
Stack Exit Velocity, ft/sec
Stack Exit Area (ft2)
Stack Diameter (feet)
PRB - 1
M10- Run PRB-1
6,326
8,300
762,157
28.29
0.0631
1,940,460
2,392,341
130
0
59.2
546.63
26.38
IL - 1
M10- Run IL-1
6,169
10,800
571,210
28.53
0.0641
1,876,128
2,337,509
130
0
57.2
546.63
26.38
PRB - 2
M10- Run PRB-2
6,017
8,300
724,913
28.52
0.0641
1,793,722
2,202,160
130
0
54.7
546.63
26.38
IL - 2
M10- Run IL-2
5,828
10,800
539,605
28.76
0.0652
1,719,350
2,135,983
120
0
52.4
546.63
26.38
Nitrogen Oxide
NOX Uncontrolled Emission Rate, lb/Mbtu
0.20
0.20
0.20
0.20
NOX Uncontrolled Emission Rate, ppmvw (actual O 2)
106
106
108
108
NOX Controlled Emission Rate, lb/MBtu
0.05
0.05
0.05
0.05
NOX Controlled Emissions, lb/hr
316.3
308.5
300.8
291.4
26
27
27
27
5,025
92.4%
380
35,493
98.6%
494
4,780
92.4%
361
33,529
98.6%
466
Moisture Added by wet FGD
Composition of Gas Exiting Stack (moles/hr)
NOX Controlled Emissions, ppmvw (actual O2)
Sulfur Dioxide
Uncontrolled SO 2 Emissions, lb/hr
Scrubber Removal Efficiency, %
Controlled SO 2 Emissions, lb/hr
Controlled SO 2 Emissions, moles/hr
6
8
6
7
Controlled SO 2 Emissions, ppmw
23.1
31.6
24.8
29.9
Controlled SO 2 Emissons, lb/MBtu
0.06
0.08
0.06
0.08
Carbon Monoxide (CO)
CO Emission Rate, lb/MBtu
CO Emission Rate, lb/hr
0.12
759
0.12
740
0.12
722
0.12
699
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Fuel Type:
Case:
Sulfur Trioxide (SO3)
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - 1
M10- Run PRB-1
IL - 1
M10- Run IL-1
PRB - 2
M10- Run PRB-2
IL - 2
M10- Run IL-2
SO2 to SO3 Conversion Rate (Boiler and SCR Total), %
2.00
2.00
2.00
2.00
Uncontrolled SO 3 Emissions, lb/hr
125.5
886.8
119.4
837.7
Uncontrolled SO 3 Emissions, moles/hr
1.57
11.08
1.49
10.47
Uncontrolled SO 3 Emissions, ppmvw (actual O2)
6.0
43.8
6.2
44.8
153.8
1086.3
146.3
1026.2
Uncontrolled SO 3 Emissions as H2SO4, lb/hr
Controlled SO 3 Emissions, lb/hr
Controlled SO 3 Emissions, lb/MBtu
Controlled SO 3 Emissions, as H2SO4 lb/hr
Controlled SO 3 Emissions, as H2SO4 lb/MBtu
Particulate (PM+PM10)
Ash Content in Fuel, percent
Unburned Carbon, lb/hr
Uncontrolled Particulate Emissions, lb/hr
Uncontrolled Particulate Emission Rate , lb/MBtu
Uncontrolled Particulate, Emissions, gr/acf
Controlled Particulate Emissions (Filterable), lb/hr
Controlled Particulate Emission Rate (Filterable), lb/MBtu
Controlled Particulate, Emissions (Filterable), gr/acf
Controlled Particulate Emissions (Filterable + Condensible), lb/hr
Controlled Particulate Emission Rate (Filterable + Condensible), lb/mmbtu
Controlled Particulate, Emissions (Filterable + Condensible), gr/acf
Volatile Organic Compounds (VOC)
VOC Emission Rate, lb/MBtu
VOC Emission Rate, lb/hr
Mercury (Hg)
Hg Emission Rate, lb/MW-hr
Ammonia Slip (NH3)
20.7
20.1
19.6
19.0
0.0033
0.0033
0.0033
0.0033
25.3
24.7
24.1
23.3
0.0040
0.0040
0.0040
0.0040
4.93%
380
30,439
4.81
1.83
75.9
0.012
0.0046
113.9
0.018
0.0068
9.52%
370
43,874
7.11
2.73
74.0
0.012
0.0046
111.0
0.018
0.0069
4.93%
361
28,952
4.81
1.88
72.2
0.012
0.0047
108.3
0.018
0.0070
9.52%
350
41,446
7.11
2.81
69.9
0.012
0.0047
104.9
0.018
0.0071
0.0034
21.51
0.0034
20.97
0.0034
20.46
0.0034
19.81
6.6E-05
6.6E-05
6.6E-05
6.6E-05
Ammonia Slip, ppmvd (at 3% O2)
Ammonia Slip, lb/hr
Fluorides as HF
HF Emission Rate, lb/Mbtu
HF Emission Rate, lb/hr
2.00
7.3
2.00
7.3
2.00
6.9
2.00
6.9
0.0002
1.27
0.0002
1.23
0.0002
1.20
0.0002
1.17
Consumables
Water (gpm)
Limestone (lb/hr)
Sorbent Injection (lb/hr)5
Powdered Activated Carbon -- PAC sorbent injection (lb/hr)
Ammonia (Anhydrous) (lb/hr)
Ammonia (Aqueous @ 19% NH 3) (lb/hr)
543
7,786
222
431
375
1,976
747
59,305
2,011
421
366
1,928
484
7,407
212
396
357
1,880
677
55,827
1,899
384
346
1,822
30,363
28,917
1,953
7,515
12,589
43,799
41,680
2,614
10,876
95,663
28,879
27,504
1,844
7,148
11,995
41,376
39,374
2,457
10,274
90,062
Waste Products
Total Fly Ash Removed (lb/hr)
Sellable Fly Ash (lb/hr)
Non-sellable Fly Ash (lb/hr)
Bottom Ash (lb/hr)
Total Byproducts [gypsum] from FGD -- dry basis (lb/hr)
Assumptions:
1. Fly Ash / Bottom Ash Split is 80/20.
2. Unit MW at Design Load is 649 MW Net
References:
1. M-10 Run: IPL Base Load Coal Plant - M-10 Run PRB-1 by Kris Gamble, 5/18/07
2. M-10 Run: IPL Base Load Coal Plant - M-10 Run IL-1 by Kris Gamble, 5/18/07
3. M-10 Run: IPL Base Load Coal Plant - M-10 Run PRB-2 (Max fuel input at mean ambient temperature) by Kris Gamble, 7/31/2007
4. M-10 Run: IPL Base Load Coal Plant - M-10 Run IL-2 (Max fuel input at mean ambient temperature) by Kris Gamble, 7/31/2007
5. SOLVAY Chemicals, SOLVAir Select Application Guide (Sorbent Injection Rate)
Notes:
1. Stack Exit Area and Stack Diameter was set by the PRB - Biomass Fuel case due to the fact that it had the greatest stack flow which drives the stack diameter.
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Composition of Gas Exiting Stack (lb/hr)
Fuel Type:
Case:
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - 2
75% of Max. Heat Input PRB-2
IL - 2
75% of Max. Heat Input IL-2
PRB - 2
50% of Max. Heat Input PRB-2
IL - 2
50% of Max. Heat Input IL-2
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
292,251
3,690,683
0
1,018,760
285
557,461
362,083
3,757,638
0
960,128
370
459,511
255,388
2,661,283
0
679,246
190
374,026
288,811
2,662,403
0
640,154
247
312,105
Total Flue Gas Flow Rate (lb/hr)
5,559,440
5,539,730
3,970,133
3,903,720
187,991
213,141
126,349
146,793
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
9,130
131,750
0
23,150
4
30,940
11,320
134,140
0
21,820
6
25,510
7,980
95,000
0
15,430
3
20,760
9,030
95,040
0
14,550
4
17,320
Total Flue Gas Flow Rate (moles/hr)
194,974
192,796
139,173
135,944
Stack Exit Conditions
Fuel Type:
Case:
Fuel Burn Rate, MBtu/hr
Fuel Higher Heating Value, Btu/lb
Fuel Burn Rate, lb/hr
Wet Molecular Weight, lb/mole
Flue Gas Density, lb/cuft
Total Gas Flow Rate, acfm
Total Gas Flow Rate leaving A/H, acfm
Temperature, F
Pressure, in w.g.
Stack Exit Velocity, ft/sec
Stack Exit Area (ft2)
Stack Diameter (feet)
PRB - 2
75% of Max. Heat Input PRB-2
4,744
8,300
571,566
28.51
0.0641
1,445,407
1,738,831
125
0
44.1
546.63
26.38
IL - 2
75% of Max. Heat Input IL-2
4,627
10,800
428,426
28.73
0.0652
1,416,164
1,725,456
120
0
43.2
546.63
26.38
PRB - 2
50% of Max. Heat Input PRB-2
3,163
8,300
381,084
28.53
0.0644
1,027,703
1,228,459
125
0
31.3
546.63
26.38
IL - 2
50% of Max. Heat Input IL-2
3,085
10,800
285,648
28.72
0.0653
996,132
1,211,621
120
0
30.4
546.63
26.38
Nitrogen Oxide
NOX Uncontrolled Emission Rate, lb/MBtu
0.20
0.20
0.20
0.20
NOX Uncontrolled Emission Rate, ppmvw (actual O 2)
106
104
99
99
NOX Controlled Emission Rate, lb/MBtu
0.05
0.05
0.05
0.05
NOX Controlled Emissions, lb/hr
237.2
231.4
158.2
154.3
26
26
25
25
3,769
92.4%
285
26,621
98.6%
370
2,513
92.4%
190
17,749
98.6%
247
Moisture Added by wet FGD
Composition of Gas Exiting Stack (moles/hr)
NOX Controlled Emissions, ppmvw (actual O2)
Sulfur Dioxide
Uncontrolled SO 2 Emissions, lb/hr
Scrubber Removal Efficiency, %
Controlled SO 2 Emissions, lb/hr
Controlled SO 2 Emissions, moles/hr
4
6
3
4
Controlled SO 2 Emissions, ppmw
20.5
31.1
21.6
29.4
Controlled SO 2 Emissons, lb/MBtu
0.06
0.08
0.06
0.08
Carbon Monoxide (CO)
CO Emission Rate, lb/MBtu
CO Emission Rate, lb/hr
0.12
569
0.12
555
0.12
380
0.12
370
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Fuel Type:
Case:
Sulfur Trioxide (SO3)
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - 2
75% of Max. Heat Input PRB-2
IL - 2
75% of Max. Heat Input IL-2
PRB - 2
50% of Max. Heat Input PRB-2
IL - 2
50% of Max. Heat Input IL-2
SO2 to SO3 Conversion Rate (Boiler and SCR Total), %
2.00
2.00
2.00
2.00
Uncontrolled SO 3 Emissions, lb/hr
94.2
665.1
62.8
443.4
Uncontrolled SO 3 Emissions, moles/hr
1.18
8.31
0.78
5.54
Uncontrolled SO 3 Emissions, ppmvw (actual O2)
6.0
43.1
5.6
40.8
115.4
814.8
76.9
543.2
Uncontrolled SO 3 Emissions as H2SO4, lb/hr
Controlled SO 3 Emissions, lb/hr
15.5
15.1
10.3
10.1
0.0033
0.0033
0.0033
0.0033
Controlled SO 3 Emissions, as H2SO4 lb/hr
19.0
18.5
12.7
12.3
Controlled SO 3 Emissions, as H2SO4 lb/MBtu
0.004
0.004
0.004
0.004
4.93%
285
22,827
4.81
1.84
56.9
0.012
0.0046
85.4
0.018
0.0069
9.52%
278
32,907
7.11
2.71
55.5
0.012
0.0046
83.3
0.018
0.0069
4.93%
190
15,220
4.81
1.73
38.0
0.012
0.0043
56.9
0.018
0.0065
9.52%
185
21,940
7.11
2.57
37.0
0.012
0.0043
55.5
0.018
0.0065
0.0034
16.13
0.0034
15.73
0.0034
10.75
0.0034
10.49
6.6E-05
Controlled SO 3 Emissions, lb/Mbtu
Particulate (PM+PM10)
Ash Content in Fuel, percent
Unburned Carbon, lb/hr
Uncontrolled Particulate Emissions, lb/hr
Uncontrolled Particulate Emission Rate , lb/mmbtu
Uncontrolled Particulate, Emissions, gr/acf
Controlled Particulate Emissions (Filterable), lb/hr
Controlled Particulate Emission Rate (Filterable), lb/MBtu
Controlled Particulate, Emissions (Filterable), gr/acf
Controlled Particulate Emissions (Filterable + Condensible), lb/hr
Controlled Particulate Emission Rate (Filterable + Condensible), lb/MBtu
Controlled Particulate, Emissions (Filterable + Condensible), gr/acf
Volatile Organic Compounds (VOC)
VOC Emission Rate, lb/MBtu
VOC Emission Rate, lb/hr
Mercury (Hg)
Hg Emission Rate, lb/MW-hr
Ammonia Slip (NH3)
6.6E-05
6.6E-05
6.6E-05
Ammonia Slip, ppmvd (at 3% O2)
Ammonia Slip, lb/hr
Fluorides as HF
HF Emission Rate, lb/MBtu
HF Emission Rate, lb/hr
2.00
5.6
2.00
5.7
2.00
4.0
2.00
4.0
0.0002
0.95
0.0002
0.93
0.0002
0.63
0.0002
0.62
Consumables
Water (gpm)
Limestone (lb/hr)
Sorbent Injection (lb/hr)5
Powdered Activated Carbon -- PAC sorbent injection (lb/hr)
Ammonia (Aqueous @ 19% NH 3) (lb/hr)
391
5,840
167
313
1,483
554
44,480
1,508
311
1,447
263
3,894
111
221
990
379
29,657
1,005
218
966
22,770
21,686
1,454
5,636
9,452
32,851
31,261
1,956
8,157
71,797
15,182
14,459
982
3,757
6,301
21,903
20,843
1,315
5,439
47,835
Waste Products
Total Fly Ash Removed (lb/hr)
Sellable Fly Ash (lb/hr)
Non-sellable Fly Ash (lb/hr)
Bottom Ash (lb/hr)
Total Byproducts [gypsum] from FGD -- dry basis (lb/hr)
Assumptions:
1. Fly Ash / Bottom Ash Split is 80/20.
2. Unit MW at Design Load is 649 MW Net
References:
1. M-10 Run: IPL Base Load Coal Plant: 75% of Maximum Heat Input - Mean Ambient PRB-2 by Kris Gamble, 5/18/07
2. M-10 Run: IPL Base Load Coal Plant: 75% of Maximum Heat Input - Mean Ambient IL-2 by Kris Gamble, 5/18/07
3. M-10 Run: IPL Base Load Coal Plant: 50% of Maximum Heat Input - Mean Ambient PRB-2 by Kris Gamble, 5/18/07
4. M-10 Run: IPL Base Load Coal Plant: 50% of Maximum Heat Input - Mean Ambient IL-2 by Kris Gamble, 5/18/07
5. SOLVAY Chemicals, SOLVAir Select Application Guide (Sorbent Injection Rate)
Notes:
1. Stack Exit Area and Stack Diameter was set by the PRB - Biomass Fuel case due to the fact that it had the greatest stack flow which drives the stack diameter.
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Composition of Gas Exiting Stack (lb/hr)
Fuel Type:
Case:
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - BM
M10- Run PRB Coal - Biomass
IL - BM
M10- Run Illinois Coal - Biomass
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
376,484
4,869,907
0
1,362,592
380
845,488
444,174
4,886,735
0
1,288,479
495
716,861
Total Flue Gas Flow Rate (lb/hr)
7,454,851
7,336,744
265,302
293,964
Oxygen
Nitrogen
Chlorine
Carbon Dioxide
Sulfur Dioxide
Moisture
11,770
173,840
0
30,960
6
46,930
13,880
174,440
0
29,280
8
39,790
Total Flue Gas Flow Rate (moles/hr)
263,506
257,398
Moisture Added by wet FGD
Composition of Gas Exiting Stack (moles/hr)
Stack Exit Conditions
Fuel Type:
PRB - BM
IL - BM
M10- Run PRB Coal - Biomass
6,333
8,207
771,688
28.29
0.0631
1,967,862
2,427,142
130
0
60.0
M10- Run Illinois Coal - Biomass
6,187
10,488
589,902
28.50
0.0640
1,909,549
2,381,044
125
0
58.2
546.63
26.38
546.63
26.38
Nitrogen Oxide
NOX Uncontrolled Emission Rate, lb/MBtu
0.20
0.20
NOX Uncontrolled Emission Rate, ppmvw (actual O 2)
105
105
NOX Controlled Emission Rate, lb/MBtu
0.05
0.05
NOX Controlled Emissions, lb/hr
316.7
309.3
Case:
Fuel Burn Rate, MBtu/hr
Fuel Higher Heating Value, Btu/lb
Fuel Burn Rate, lb/hr
Wet Molecular Weight, lb/mole
Flue Gas Density, lb/cuft
Total Gas Flow Rate, acfm
Total Gas Flow Rate leaving A/H, acfm
Temperature, F
Pressure, in w.g.
Stack Exit Velocity, ft/sec
Stack Exit Area (ft 2)
Stack Diameter (feet)
NOX Controlled Emissions, ppmvw (actual O 2)
Sulfur Dioxide
Uncontrolled SO 2 Emissions, lb/hr
Scrubber Removal Efficiency, %
Controlled SO 2 Emissions, lb/hr
Controlled SO 2 Emissions, moles/hr
26
26
4,873
92.2%
380
33,907
98.5%
495
6
8
Controlled SO 2 Emissions, ppmw
22.8
31.1
Controlled SO 2 Emissons, lb/MBtu
0.06
0.08
Carbon Monoxide (CO)
CO Emission Rate, lb/MBtu
CO Emission Rate, lb/hr
0.12
760
0.12
742
Emissions Calculations - Stack
Project
Date
Engineer
Basis
Fuel Type:
Case:
Sulfur Trioxide (SO3)
Interstate Power and Light (IP&L)
17-Oct-07
William Stevenson
Stack
PRB - BM
M10- Run PRB Coal - Biomass
IL - BM
M10- Run Illinois Coal - Biomass
SO2 to SO3 Conversion Rate (Boiler and SCR Total), %
2.00
2.00
Uncontrolled SO 3 Emissions, lb/hr
121.7
847.1
Uncontrolled SO 3 Emissions, moles/hr
1.52
10.58
Uncontrolled SO 3 Emissions, ppmvw (actual O 2)
5.8
41.1
149.1
1037.8
Uncontrolled SO 3 Emissions as H2SO4, lb/hr
Controlled SO 3 Emissions, lb/hr
Controlled SO 3 Emissions, lb/Mbtu
20.7
20.2
0.0033
0.0033
Controlled SO 3 Emissions, as H2SO4 lb/hr
25.3
24.7
Controlled SO 3 Emissions, as H2SO4 lb/MBtu
0.004
0.004
4.93%
380
30,785
4.86
1.83
76.0
0.012
0.00