United States
Environmental Protection
Agency
Office of Research and
Development
Washington, DC 20460
EPA/600/2-91/029
July 1991
v>EPA Sourcebook:
NOX Control
Technology Data
control itechnology center
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the ENVIRONMENTAL PROTECTION TECH-
NOLOGY series. This series describes research performed to develop and dem-
onstrate instrumentation, equipment, and methodology to repair or prevent en-
vironmental degradation from point and non-point sources of pollution. This work
provides the new or improved technology required for the control and treatment
of pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the contents necessarily
reflect the views and policy of the Agency, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
-------
EPA-600/2-91-029
July 1991
SOURCEBOOK:
NOX CONTROL TECHNOLOGY DATA
by:
Lisa M. Campbell
Diana K. Stone
and
Gunseli S. Shareef
Radian Corporation
Progress Center
3200 E. Chapel Hill Rd./Nelson Hwy.
Research Triangle Park, North Carolina 27709
EPA Contract No. 68-02-4286
Work Assignment Nos. 92,102, and 117
EPA Project Officer
Charles B. Sedman
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Printed on Recycled Paper
-------
SOURCEBOOK:
NOX CONTROL TECHNOLOGY DATA
CONTROL TECHNOLOGY CENTER
Sponsored By:
Emission Standards Division
Office of Air Quality Planning and Standards
U. S. Environmental Protection Agency
Research Triangle Park, NC 27711
Air and Energy Engineering Research Laboratory
Office of Research and Development
U. S. Environmental Protection Agency
Research Triangle Park, NC 27711
Center for Environmental Research Information
Office of : ^search and Development
U. S. Environmental Protection Agency
Cincinnati, OH 45268
11
-------
CONTENTS
Figures v
Tables vi
1. Introduction 1
1.1 Objectives and Approach 1
1.2 Report Organization 3
2. NO Formation 5
2.1 Thermal NO 5
2.2 Fuel NO 8
2.3 Prompt NOX 10
3. Combustion Sources 11
3.1 Combustion Turbines 11
3.1.1 Source Description 11
3.1.2 NOX Emissions 13
3.2 Stationary Internal Combustion Engines 14
3.2.1 Source Description 14
3.2.2 NOX Emissions 14
3.3 Non-Utility Boilers and Heaters 17
3.3.1 Source Description 17
3.3.2 NOX Emissions 18
3.4 Municipal Waste and Sludge Incinerators 19
3.4.1 Source Description 19
3.4.2 NOX Emissions 20
4. Combustion Controls for NOX Emissions 21
4.1 Combustion Turbine Controls 21
4.1.1 Dry Control 21
4.1.2 Wet Injection 22
4.2 Stationary Internal Combustion Engine Controls 23
4.2.1 Injection Timing Retard 23
4.2.2 Pre-lgnition Chamber Combustion
"Clean Burn" Technology 23
4.2.3 Air to Fuel Ratio 23
4.2.4 Wet Injection 24
4.3 Combustion Controls for Other Sources 24
4.3.1 Low Excess Air (LEA) 24
4.3.2 Low NOX Burners (LNB) 25
4.3.3 Overfire Air (OFA) 27
4.3.4 Burners Out of Service 29
4.3.5 Reburn 30
4.3.6 Flue Gas Recirculation (FGR) or Exhaust
Gas Recirculation (EGR) 30
4.3.7 Reduced Combustion Air Temperature 32
4.3.8 Derating/Load Reduction 32
111
-------
CONTENTS (Continued)
5. Post-Combustion NO Control Technologies 33
5.1 Selective Catalytic Reduction 33
5.2 Non-selective Catalytic Reduction 37
5.3 Selective Non-catalytic Reduction (SNCR) 37
5.3.1 Thermal DeNCL® 38
5.3.2 NOxOut® 40
6. Status of NOX Control Technology Applications 41
6.1 Combustion Turbines 41
6.1.1 Combustion Controls 43
6.1.2 Selective Catalytic Reduction 43
6.2 Stationary Internal Combustion Engines 43
6.2.1 Combustion Controls 44
6.2.2 Selective Catalytic Reduction 45
6.2.3 Non-selective Catalytic Reduction 45
6.3 Non-Utility Boilers and Heaters 45
6.3.1 Combustion Controls 45
6.3.2 Selective Catalytic Reduction 47
6.3.3 Selective Non-catalytic Reduction 48
6.4 Municipal Waste and Sludge Incineration 48
6.4.1 Selective Non-catalytic Reduction 48
6.4.2 Selective Catalytic Reduction (Japan) 48
7. NOX Control Data 50
7.1 Combustion Turbines 50
7.1.1 Combustion Controls/Wet Injection 50
7.1.2 Combustion Controls/Dry Low NOX 51
7.1.3 Selective Catalytic Reduction 51
7.2 Stationary Internal Combustion Engines 52
7.2.1 Combustion Controls 52
7.2.2 Non-selective Catalytic Reduction 53
7.2.3 Selective Catalytic Reduction 53
7.3 Non-Utility Boilers and Heaters 54
7.3.1 Combustion Controls 54
7.3.2 Selective Non-catalytic Reduction 54
7.3.3 Selective Catalytic Reduction 56
7.4 Municipal Waste and Sludge Incineration 56
7.4.1 Combustion Controls 56
7.4.2 Selective Non-catalytic Reduction 57
7.4.3 Selective Catalytic Reduction (Japan) 57
8. References 58
Appendices
A. NOX Control Data - Combustion Turbines A-1
B. NOX Control Data - Stationary Internal Combustion Engines B-1
C. NOX Control Data - Non-Utility Boilers and Heaters C-1
D. NOX Control Data - Municipal Waste and Sludge Incinerators D-1
E. NOX Control Data - West Germany E-1
F. NOX Control Data - Japan F-1
G. Partial Vendor Listing G-1
H. Conversion Factors H-1
IV
-------
FIGURES
Number Pafle
1 Temperature Dependence of the Three Sources of NOX
for a Coal-Fired Furnace 6
2 Effect of Air-to-Fuel Ratio on Thermal NOX Emissions 7
3 Thermal NOX Formation Dependence on Flame Temperature 9
4 Gas Turbine with Can-Annular Combustor 12
5 Cylinder Events for a Two Stroke Cycle Diesel Engine 15
6 Staged Air Burner 26
7 Staged Fuel Burner 28
8 NOX Reburning with Gas 31
9 SCR System Process Flow Diagram for Gas Turbine/HRSG System
(HRSG: heat recovery steam generator) 34
10 Effect of Temperature and Oxygen on NOX Conversion 35
11 Schematic Diagram for Selective Non-Catalytic Reduction 39
-------
TABLES
Number Page
1 NOX Control Technology Applicability 42
2 NOX Control Technology Applicability - Combustion Turbines 42
3 NOX Control Technology Applicability - Stationary 1C Engines 44
4 West Germany Site Visits (1C Engines) 46
5 NOX Control Technology Applicability - Non-Utility Boilers and Heaters 47
6 NOX Control Technology Applicability - Waste Incinerators 49
7 NOX Control Levels - Combustion Turbines 51
8 NOX Control Levels - Stationary Internal Combustion Engines 53
9 NOX Control Levels - Non-Utility Boilers and Heaters 55
10 NOX Control Levels - Waste Incineration 57
A-1 Combustion Turbines (Gas-fired and Dual Fuel-fired) A-3
B-1 Stationary 1C Engines (Gas-tired) B-3
B-2 Stationary 1C Engines (Excluding Gas-fired Units) B-9
C-1 Coal-fired Boilers C-3
C-2 Gas-fired Boilers C-9
C-3 Oil-fired Boilers C-11
C-4 Wood/Waste Boilers C-13
C-5 Refinery Heaters C-14
D-1 Waste Incinerators D-3
F-1 SCR Sites for Combustion Turbines F-2
F-2 SCR Sites for Stationary 1C Engines F-2
F-3 Industrial Boilers Fitted with SCR for Dirty Fuels F-3
F-4 Waste Sludge Incinerators Fitted with SCR F-4
VI
-------
SECTION 1
INTRODUCTION
Emissions of nitrogen oxides (NOX) are an environmental issue which has been attracting
increasing regulatory attention at the local, State, and Federal level. Concerns over ozone abatement
and control, acid rain, the growth in stationary source combustion systems, and implementation of
prevention of significant deterioration (PSD) increments for NOX have all contributed to the increased
attention. A number of states, in addition to California, are now focusing on NOX emission sources. In
addition several Federal New Source Performance Standards (NSPS) have been issued which regulate
NOX including utility and industrial boilers, nitric acid plants, gas turbines, and municipal waste
combustors.
A wide variety of new and emerging NOX control technologies are being marketed in the United
States, as well as in Europe and Japan. The performance reported by vendors for many of these
systems have not been well documented in the literature. Very little data are available to demonstrate
the actual applicability and long-term operating performance of the current generation of NOX control
technologies.
There is interest among the State and local regulatory agencies as to the level of NOX control
that can be achieved with current technology. State and local officials are not always familiar with
some of the newer technologies currently being marketed and often have difficulty in reviewing permit
applications for major NOX emission sources. In some states, the permitting process has been slowed
by the uncertainty over the availability and performance of NOX control technology. This has resulted in
a large number of requests to the U.S. Environmental Protection Agency (EPA) for assistance in the
NOX control area. As part of an effort to respond to these requests, EPA's Control Technology Center
(CTC) has initiated the current study to develop a reference book of information on NOX controls. This
report presents the results of this study.
1.1 OBJECTIVES AND APPROACH
The primary objective of this study was to compile a reference book to serve as a source of
information on the availability and applicability of technologies for controlling NOX emissions from
stationary industrial combustion sources. An additional objective was to provide EPA a reference tool
for responding to requests for guidance and assistance in developing future regulatory strategies.
There are many stationary industrial combustion source types that are significant NOX emitters.
However, this study and report focus on only those most frequently included in new source permit
applications and cover the following combustion source types:
1
-------
combustion turbines
internal combustion (1C) engines
non-utility boilers and heaters
municipal waste and sludge incinerators
All non-utility combustion sources (less than 1,000 x 106 Btu/hour heat input) were included
except hospital waste incinerators, hazardous waste incinerators, and glass furnaces.
At the onset of this study, requests for permit applications, final permit conditions, and both initial
compliance and subsequent annual compliance test data were made to a number of EPA Regional and
State/local regulatory agencies, by telephone and/or letter. The agencies contacted during this study
include the following:
State Agencies:
California
I
Bay Area Air Quality Management District
California Air Resources Board
Fresno County Air Pollution Control District
Kern County Air Pollution Control District
Monterey Bay Unified Air Pollution Control District
Resource Management Agency Air Pollution Control District
Sacramento Air Pollution Control District
San Diego Air Pollution Control District
Santa Barbara Air Pollution Control District
South Coast Air Quality Management District
Stanislaus County Air Pollution Control District
Colorado Air Pollution Division
Commonwealth of Massachusetts Department of Environmental Protection
Connecticut Pollution Control Agency
Michigan Pollution Control Agency
Minnesota Pollution Control Agency
New York State Department of Environmental Conservation
Ohio Air Pollution Control Agency
Rhode Island Division of Air and Hazardous Materials
Texas Air Control Board
Utah Bureau of Air Quality
Virginia Department of Air Pollution Control
EPA Regional Offices
Region 1
Region 2
2
-------
Region 3
Region 4
Region 5
Region 6
Region 7
Region 8
Region 9
Northeast States for Coordinated Air Use Management (NESCAUM)
Only minimal data were received as a result of this effort. As it was beyond the scope of the
project to survey all the regulatory agencies and collect the available information on-site, the data
presented in this report are of limited nature and are based on the following information sources:
a) BACT/LAER Clearinghouse on-line data base,
b) EPA Region 9,
c) California Air Resources Board,
d) West Germany site visits,
e) Environmental Catalyst Consultants, Inc.
Two other areas of interest in NOX control-cost data and detailed emission test data-are not
included in this report. Costs are deserving of a separate report and their site-specific nature requires
considerably more detailed analyses than possible in the following discussions. Emission test data
require intense scrutiny to determine validity and relevance to the specific application. This effort is
also outside the scope of this study.
Both cost and performance data are available from the sources cited in the Appendices and may
be addressed by future CTC efforts.
The information contained in the BACT/LAER Clearinghouse is provided by the state control
agencies on a voluntary basis and includes projects that have obtained permit approval, although some
projects may be cancelled later. However, for the purposes of the sourcebook, the Clearinghouse
information does reflect BACT/LAER applicability decisions by the regulatory community.
1.2 REPORT ORGANIZATION
The sourcebook is divided into eight sections. Section 2 contains a description of NOX formation
mechanisms during combustion, followed by Section 3 which is a discussion of the major combustion
source types [combustion turbines, stationary internal combustion (1C) engines, industrial boilers and
heaters, and municipal waste incinerators]. Process descriptions of NOX control technologies are
presented in Sections 4 and 5. Section 6 presents the current status of NOX control technology
applications. This section briefly describes and presents in matrix form the control technologies
-------
applicable to each combustion source (and fuel). In Section 7, permitted NOX emissions levels are
summarized by combustion source, fuel type, and control technology. References used in developing
the sourcebook are listed in Section 8. Detailed data supporting the discussion in Sections 5, 6, and 7
and contact names for further information are given in Appendices A - H.
-------
SECTION 2
NOX FORMATION
The principles of NOX control are best understood when the principles of NOX formation are
known. The term NOX represents the combination of nitric oxide (NO) and nitrogen dioxide (NO2);
however, the flue gas resulting from fossil fuel combustion consists primarily of NO, with NO
representing 90 to 95 percent of the total NOX due to kinetic limitations in the oxidation of NO to
NO2.1
NOX formation occurs by three fundamentally different mechanisms.1 One mechanism (thermal
NOX) arises from the thermal dissociation and subsequent reaction of nitrogen (N2) and oxygen (O2)
molecules in the combustion air. The second mechanism (fuel NOX) stems from the evolution and
reaction of fuel-bound nitrogen compounds with oxygen. A third mechanism (prompt NOX) involves the
intermediate formation of hydrogen cyanide (HCN), followed by oxidation of HCN to NO. Natural gas
and most distillate oils have no chemically bound fuel nitrogen and essentially all NOX formed is
thermal NOX. Residual oils and coals all have fuel bound nitrogen and when these are combusted,
NOX is formed by all mechanisms. The formation of prompt NOX is only significant in very fuel-rich
flames.
The temperature dependence of each NOX type (i.e. thermal, fuel, and prompt NOX) for a coal-
fired furnace is given in Figure 1.1 These mechanisms are described in more detail below.
2.1 THERMAL NOX
At high temperatures, both N2 and O2 molecules in the combustion air are dissociated into their
respective atomic states, N and O. The subsequent reaction of these atoms to create thermal NOX is
described by the well-known Zeldovich equations:2
Nz + 0 - NO + N (1)
N + O2 - NO + O (2)
The rates of these reactions are highly dependent upon the stoichiometric ratio in the primary
combustion zone (i.e., the molecular equivalent air-to-fuel ratio, with "rich and lean" describing the fuel
amount), flame temperature, and residence time at the flame temperature.
The maximum thermal NOX production occurs at a slightly lean fuel mixture ratio due to the
excess availability of oxygen for reaction within the hot flame zone. As shown in Figure 2, the very
-------
15
eo
S 10
ox
05
1200
1600
Temperature (*C)
Figure 1. Temperature Dependence of the Three Sources of
for a Coal-Fired Furnace
-------
NOx
Rich
Lean
Alr-to-Fuel Ratio
Figure 2. Effect of Air-to-Fuel Ratio on Thermal NOX Emissions
-------
rapid decrease in NOY formation for either rich or lean combustion indicates that control of local flame
A
stoichiometry is critical in achieving reductions in thermal NOX. For a given stoichiometry, the thermal
NOX generation decreases rapidly as the flame temperature drops below the adiabatic temperature as
shown in Figure 3.2 The local flame temperature decreases rapidly along the flame axis as heat is
radiated out of the flame. Therefore, almost all of the thermal NOX is generated in the flame core.
Maximum reduction of NOX generation can thus be achieved by localized control of both the flame
temperature and stoichiometry for each individual combustion chamber or burner.
2.2 FUEL NOX
The mechanisms by which nitrogen compounds (primarily organic) contained in fossil fuels are
evolved and react to form NOX are much more complex than the Zeldovich model. Nevertheless,
several studies indicate that the luel-bound nitrogen compounds react to form NOX in two separate
mechanisms, one a solid-phase char nitrogen reaction (with solid fuels) and the other a homogeneous
gas-phase reaction resulting from evolution and cracking of volatile compounds (solid and liquid fuels).
The char nitrogen reaction is not well understood, although the data show that the char nitrogen
conversion to NOX is dependent on the flame temperature, stoichiometric ratio, and on the char
characteristics. The precise relationships, however, are not known. Conversion rates to NOX of 15 to
35 percent have been documented.4
The gas-phase reaction is postulated to include a number of intermediate species (e.g., HCN,
HOCN, NH2) which are produced at rapid reaction rates. The decay rate of the intermediate species
into N2 (fuel-rich) and NOX (fuel-lean) is slower by at least an order of magnitude. These reaction
rates are strongly dependent upon the stoichiometric ratio and the gas phase fuel nitrogen
concentration and weakly dependent upon the flame temperature and the nature of the organic nitrogen
compound. It is the weak influence of temperature on gas-phase NOX conversion that reduces the
effectiveness of NOX controls which rely on temperature effects in the combustion of nitrogen-bearing
fuels.
Low NOX operation for high nitrogen containing fuels involves introducing the fuel wit;. a
substoichiometric amount of air. In this situation fuel nitrogen is released in a reducing atmo nere
which is favorable for reduction -D N2 rather than oxidation to NOX. The balance of the combustion air
enters above or around the rich flame and combustion is completed. Here, as with thermal NOX,
controlling excess O2 is an important part of controlling NOX formation.
8
-------
NOx
3200 3800
Flame Temperature *F
Figure 3. Thermal NOX Formation Dependence on Flame Temperature 3
-------
2.3 PROMPT NOX
Prompt NOX is produced by the formation first of intermediate HCN via the reaction of nitrogen
radicals and hydrocarbons (HC),
NO + HC + Hz - HCN + H2O (3)
followed by the oxidation of the HCN to NO. The formation of prompt NOX has a weak temperature
dependence and a short lifetime of several microseconds; it is only significant in very fuel-rich flames,
which are inherently low-NOx emitters.
10
-------
SECTION 3
COMBUSTION SOURCES
When considering NOX control, it is critical to understand that the combustion source and its
operation can affect NOX formation and the performance of control technologies. The description of the
major combustion source types included in this study (i.e., combustion turbines, stationary 1C engines,
boilers and heaters, and waste incinerators) as well as the relationship between NOX formation and
characteristics of the combustion source type are discussed below.
3.1 COMBUSTION TURBINES
3.1.1 Source Description
Gas turbines are rotary internal combustion engines fueled by natural gas, diesel or distillate fuel
oils (occasionally residual or crude oils). The basic gas turbine consists of a compressor, combustion
chambers, and a turbine. The compressor delivers pressurized combustion air to the combustors at
compression ratios of up to 20 to 1. Injectors introduce fuel into the combustors and the mixture is
burned with exit temperatures up to 2,000°F. The hot combustion gases are rapidly quenched by
secondary dilution air and then expanded through the turbine which drives the compressor and
provides shaft power. In some applications, exhaust gases are also expanded through a power turbine.
While simple-cycle gas turbines have only the three components described above, regenerative-
cycle gas turbines also use hot exhaust gases (800 to 1,100°F) to preheat the inlet air between the
compressor and the combustor. This makes it possible to recover some of the thermal energy in the
exhaust gases and to increase thermal efficiency. A third type of turbine is the combined-cycle gas
turbine. The combined-cycle turbine is basically a simple-cycle unit which exhausts to a waste heat
boiler to recover thermal energy from the exhaust gases. In some cases, the waste heat boiler also
has duct burners designed to bum additional fuel to supplement steam production, a process which is
referred to as supplementary firing.
The design of the combustor is a major factor in determining achievable NOX levels. The three
combustor configurations used are annular, can-annular, and silo. The annular combustor has one
doughnut-shaped combustor, to which a number of short nozzles are attached, encircling the gas
turbine body. Combustion air is combined with fuel in each of these nozzles. Fuel and air then enter
the single annulus located around the turbine circumference. Combustion and dilution take place in the
single annulus. The can-annular combustor (see Figure 4) has several combustor cans arranged in an
11
-------
Combustor Cans
Figure 4. Gas Turbine With Can-Annular Combustor
12
-------
annular configuration around the turbine centerline. The silo combustor configuration has one or two
large combustors located outside the body of the gas turbine. Combustors may be arranged either
horizontally or vertically.
All combustors have four basic zones: the inlet diffuser zone, the primary combustion zone the
secondary combustion and dilution zone, and the outlet transition zone. The inlet diffuser zone reduces
the incoming gas velocity. If the velocity of the combustion air is not sufficiently reduced, residence
time within the combustor will be too short for complete combustion and flame instability can occur.
Ignition occurs in the primary combustion zone. The fuel is injected into the combustion zone
through a nozzle. The air first enters the area between the combustor liner and the shroud, or casing.
The flow of air between the liner and the shroud serves the dual function of heating the air and cooling
the liner. Combustion in this zone occurs at near stoichiometric fuel-air ratios.
The materials of the combustor liner and turbine cannot withstand the high combustion
temperatures. Therefore, the secondary combustion zone provides not only for the complete
combustion of the fuel, but also provides additional air to quickly dilute the hot gases to a temperature
more compatible with combustor and turbine materials. In the outlet transition zone, the hot combustion
gases are passed through a duct leading to the turbine inlet vanes.
3.1.2 NOX Emissions5
NOX is the primary pollutant produced by combustion turbines. Factors affecting NOX formation
include turbine design, ambient conditions, turbine load, and fuel type. The design parameters that
affect the production of NOX in the combustor most significantly are combustor inlet temperature and
pressure and the firing temperature. As predicted by the Zeldovich equations (see Section 2.1), NOX
emissions rise rapidly with increasing firing temperatures. NOX formation is also directly related to
combustor pressure; with increased pressure resulting in increased NOX emissions.
Turbine efficiency is largely determined by the combustor firing temperature and pressure.
Therefore, turbine models with regenerators, which are used to increase efficiency by increasing the
combustor inlet air temperature, have higher NOX emissions than the same models without
regeneration. Many cogeneration/combined-cycle systems also employ natural gas-fired duct burners
for exhaust temperature control.
Turbine NOX emissions change with changes in ambient temperature, pressure, and especially
humidity. Increases in humidity have a quenching effect on the combustor zone peak temperature,
thereby reducing thermal NOX formation. The effect of temperature on NOX emissions changes as
humidity changes. At low humidity, NOX levels increase with an increase in temperature. At high
humidity, the effect of temperature on NOX formation depends on the range over which the temperature
Changes. Increases in ambient pressure increase gas compressor outlet pressures which in turn
increase NOX emissions. For example, NOX emissions from a turbine installed at an elevation of one
13
-------
mile above sea level decrease by about 10 percent compared to a similar turbine operating at sea
level.
"Base load" and "peak load" are terms used by manufacturers to describe specific turbine
operating conditions. Base load is the level of power the turbine can produce at the maximum inlet
temperature which can be maintained continuously without damaging the turbine. Peak load ratings are
typically 5-10 percent higher than the base load. At this level of power for continuous long-term
operation, damage will result to the turbine. However, for short periods of operation (generally <1,000
hours annually), this level of power can be produced without excessive maintenance costs. Since
increased turbine load is achieved by increasing the combustor temperature and pressure, turbine NOX
emissions increase with increased bad.
Natural gas is presently the most common turbine fuel. Many new gas turbines are installed with
dual-fuel nozzles which fire natural gas as the primary fuel and distillate oil as the backup fuel.
Digester gas, refinery gas, and coal-derived gas have also been used.
3.2 STATIONARY INTERNAL COMBUSTION ENGINES
3.2.1 Source Description
Stationary reciprocating 1C engines use two methods to ignite the fuel-air mixture in the
combustion chamber, and are either compression ignition (Cl) units fueled by diesel oil or a
combination of natural gas and diesel oil (dual), or spark ignition (SI) fueled by natural gas or gasoline.
In Cl engines (see Figure 5), air is first compression heated in the cylinder, and the diesel fuel is
injected into the hot air where ignition is spontaneous. In SI engines combustion is spark initiated with
the natural gas or gasoline being introduced either by injection or premixed with the combustion air in a
carburetted system. Either 2- or 4-stroke power cycle designs with various combinations of fuel
charging, air charging, and chamber design are available.
3.2.2 NQX Emissions
Due to the high flame temperatures and pressures of 1C engines, the majority of NOX formed is
thermal NOX.6 As diesel fuel and natural gas are the predominate fuels for this source, little fuel NOX
is formed, except in engines that fire residual and/or crude oils. Formation of prompt NOX is also
negligible in compression ignited engines which operate with large amounts of excess air.
14
-------
Exhaust Vato
FlMI VllJOCfUf
Fuel
Compression
^ Intaka Ports Covered
B. Exhaust VaN* doem
Combustion
A. Fuel Errlare Cylinder
by ln|ectlon
B. Combustion by
AutotgnHton
Power Stroke
A. PWon Moves Down
D.
to Crankshaft
Scavenging
A Air Blown Into Cylinder
B. Exhaust Oases Purged
Figure 5. Cylinder Events for a Two Stroke Cycle Diesel Engine
-------
When fuel is injected into the cylinder, rt undergoes a series of reactions that lead to ignition.
The time between the start of injection of the fuel and the start of combustion (as measured by the
onset of energy release) is called the ignition delay. Initial combustion occurs around the periphery of
the fuel jet, where the air/fuel ratio is close to the stoichiometric ratio.
During ignition delay, some of the fuel is pre-mixed with air and evaporates. After ignition occurs,
the pre-mixed charge burns extremely rapidly, thereby quickly releasing energy. Most of the burning
takes place as a diffusion flame after the pre-mixed charge has burned.
NOX emissions are directly affected by the amount of pre-mixing which, in turn, is a function of
the ignition delay. When the ignition delay is large, there is more pre-mixing and a greater energy
release rate at the start of combustion. This generally leads to higher temperatures and, accordingly,
higher NOX emissions.
In general, engine load does not have a profound effect on the brake-specific (NOX rate to power
output ratio) NOX emission rates for diesel-fueled engines, although the total mass emission rates
increase as the engine load increases. At very low engine loads, almost all of the energy is released
during the pre-mixed stage. Consequently, brake-specific emissions under these conditions are
relatively high. As load increases, the amount of pre-mixed burning remains relatively constant while
the amount of diffusion burning increases linearly. The amount of NOX produced during this stage is
proportional to the amount of fuel consumed because most of the diffusion burning takes place at
stoichiometric conditions. Thus, as engine load increases, the concentration of NOX in the exhaust gas
increases. However, the brake-specific NOX emission rate remains roughly the same since power
output also increases by the same factor.
Brake-specific NOX emission rates for dual-fuel compression ignition engines are sensitive to
load. Emission rates are greatest at high loads. Dual-fuel engines generally bum a homogeneous
charge of fuel. A compression ignition engine is unthrottled; the air-fuel ratio of the charge decreases
as engine load increases. At high loads, combustion occurs closer to the point where maximum NOX is
produced.
Pre-ignition chamber engines have lower baseline NOX emissions than direct fuel injection
engines. Shorter ignition delay combined with the generally richer combustion conditions in the pre-
ignition chamber results in smoother combustion and lower peak temperatures. In addition, there are
significant heat transfer losses as the combustion gas goes from the pre-ignition chamber to the main
combustion chamber, lowering peak temperatures.
16
-------
3.3 NON-UTILITY BOILERS AND HEATERS
3.3.1 Source Description
Boilers--
Industrial boilers are typically classified by the type of firing mechanism employed, the heat
transfer mechanism, and the type of fuel fired. Firing mechanisms include either burners, spreader-
fed, or mass-fed. With burners, the fuel is injected into the boiler through a nozzle and burns while
suspended within the boiler combustion chamber. Mass-fed and spreader-fed boilers are used for most
solid fuel industrial boilers. They combust the fuel on a grate in the boiler.
Watertube is the most common mechanism used for heat transfer in industrial boilers. In
watertube boilers, the water for steam generation is contained in banks of tubes suspended in the boiler
combustion chamber and flue. Firetube boilers invert this configuration and pass hot flue gasses
through tubes suspended in a water drum.
Industrial boilers are fired with a wide variety of fossil and nonfossil fuels, including natural gas,
fuel oil, and coal. Nonfossil fuels fired in industrial boilers include wood, bark, agricultural waste,
municipal waste, and industrial waste.
Fired Heaters--
Many designs of fired heaters are available. All fired heaters have a radiant section and the
majority have a convection section. The radiant section is located within the firebox and contains the
burners and a single row of tubular coils. The primary heating of the feedstocks occurs within the
radiant section. As the name implies, radiation is the primary method of heat transfer.
The tube coil in the radiant section consists of a number of tubes connected in series by
180 degree return bends. Each set of consecutive tubes is considered a "pass" or parallel stream.
The convection section is located after the radiant section and also contains a set of tubes. The
convection section recovers the residual heat of the flue gas before it goes to the stack. The
temperature of the flue gas leaving the radiant section usually ranges from 1,500 -1,800°F.7
Two basic draft types are available to supply combustion air and to remove flue gas. These are
natural-draft and mechanical-draft. Natural-draft heaters rely on the natural stack effect to remove flue
gas and induce the flow of combustion air into the firebox. In a mechanical-draft heater, a fan supplies
the combustion air and removes flue gas. A mechanical-draft heater can use either an induced-draft,
forced-draft, or induced-draft/forced-draft (balanced draft) design.
Combustion air preheaters are often used to improve the efficiency of a fired heater. In the air
preheater, heat is transferred from the flue gas to the combustion air. Therefore, less heat is required
to heat the combustion air which allows a greater proportion of the total heat released to be absorbed
17
-------
in the radiant section. Also, less fuel is required to reach the required combustion temperature. In
addition, the preheater raises the adiabatic flame temperature above that of ambient air heaters.
3.3.2 NOX Emissions
NOX emissions from boilers and fired heaters depend on several design and operating
parameters including fuel type, burner type, combustion air preheat, firebox temperature, draft type,
excess air level, and heater load.
The most important design parameter affecting NOX emissions from a boiler/fired heater is fuel
type (i.e., the nitrogen content of the fuel). Coal firing can be expected to generate higher NOX
emissions per unit of energy input than comparable oil-fired units, and likewise for gas-fired units. In
addition, fluctuations in fuel composition and heating value may affect NOX emissions.
Another design factor having a large effect on NOX emissions is burner type. Oil-fired burners
differ primarily in the methods used to atomize the oil prior to combustion. Steam atomization is used
almost exclusively in fired heaters. Steam atomized oil burners can be divided into two categories:
conventional and staged combustion air oil burners. Conventional oil burners have a single combustion
zone in which all of the air is fed to the atomized fuel oil. Staged combustion air oil burners make use
of at least two separate air injection sections. Decreased NOX emissions are achieved with these
burners by operating a primary air/fuel injection section at substoichiometric air conditions and injecting
secondary air downstream of the primary section to complete combustion.
Although adjustments of the combustion air distribution between the primary and secondary air
registers is not used as a practical response to minor fluctuations in heater performance, the
combustion air distribution can be adjusted to increase flame length (and reduce peak flame
temperature), and thus minimize NOX emissions.
As discussed in Section 4.3.7, the use of combustion air preheat causes an increase in the
amount of NOX formed by virtue of increased flame temperature. Increasing the degree of preheat will
likewise cause an increase in NOX emissions.
The firebox temperature required for a given application influences NOX emissions because of the
relation between firebox temperature and flame temperature. High firebox temperature applications are
expected to have higher NOX emissions. The fractional use of firebox capacity can reduce NOX
emissions by lowering firebox temperature.
Heater/boiler draft type affects NOX emissions due to differences in the extent of fuel/air mixing
between natural and mechanical draft air supply systems. For a given excess oxygen level and
ambient combustion air supply, mechanical draft is expected to yield higher concentrations of NOX than
natural draft due to enhanced air/fuel mixing in the combustion zone and increased combustion
intensity. However, since mechanical draft units can be operated at lower excess air levels and higher
18
-------
thermal efficiencies than those with natural draft, the NOY emission factor per unit of energy input under
A
actual operating conditions could be lower for mechanical draft versus natural draft.
It is well demonstrated that an increase in the excess air level of a fired heater under typical
operating conditions results in an increase in NOX emissions due to the resulting higher peak flame
temperature. Fired heaters are operated over a wide range of stack oxygen levels, depending largely
on operator preference. Some excess air is required to ensure complete combustion, but operations
are often well above this minimum required excess air level. The minimum stack oxygen level
achievable for a given heater is a function of fuel type, draft type, the presence or absence of air leaks,
burner design, rate of fuel/air mixing, and the method of distributing air to the burners in multiple burner
furnaces. Minimum oxygen levels are expected to be higher for oil firing than for gas firing because of
the inherent problems associated with combustion air/fuel oil mixing. Because mechanical draft allows
more precise control of combustion air supply, they can be operated at lower excess air levels than with
natural draft. Similarly, the minimum possible long term average excess air levels that can be achieved
in new fireboxes is expected to be lower than that demonstrated for existing heaters/boilers because of
the absence of air leaks, better air and fuel controls, etc. in new equipment.
3.4 MUNICIPAL WASTE AND SLUDGE INCINERATORS
3.4.1 Source Description
The most common type of refuse incinerator consists of a refractory-lined chamber with a grate
upon which refuse is burned. Combustion products are formed by heating and burning of refuse on the
grate. Municipal waste combustors (MWCs) include mass burn, modular, and refuse-derived fuel (RDF)
combustors, with fluidized bed combustors being a minor subset of RDF. The most prevalent types of
sewage sludge incinerators are multiple hearth and fluidized bed units. In multiple hearth units, the
sludge enters the top of the furnace where it is first dried by contact with the hot, rising, combustion
gases, and then burned as it moves slowly down through the lower hearths. At the bottom hearth, any
residual ash is then removed. In fluidized bed reactors, the combustion takes place in a hot,
suspended bed of sand with much of the ash residue being swept out with the flue gas. Temperatures
in a multiple hearth furnace are 600°F in the lower, ash cooling hearth; 1,400 to 2,000°F in the central
combustion hearths, and 1,000° to 1,200°F in the upper, drying hearths.7 Temperatures in a fluidized
bed reactor are fairly uniform, from 1,250 to 1,500°F. In both types of furnace, an auxiliary fuel may be
required either during start-up or when the moisture content of the sludge is too high to support
combustion. A more detailed description of MWC technology is available in Reference 8 to this report.
19
-------
3.4.2 NOX Emissions
The factors influencing production of fuel NOX in an incinerator include the distribution of the
combustion air (underfire versus overfire), the fuel nitrogen content, and the total excess air rates.
Thermal NOX formation rates increase with temperature, oxygen availability, heat release rate, and flue
gas residence time at high temperature.
The relative contribution of fuel and thermal NQX to the total NOX emitted from an incinerator is
dependent on the design and operation of the furnace and the nitrogen content of the refuse burned.
Testing has demonstrated a seasonal increase in NOX emissions during the summer months.9 It is
theorized that the higher emissions are due to the higher nitrogen content of the fuel because the raw
refuse contains more yard waste, which has a high nitrogen content. At temperatures less than
2,000°F, typical of MWCs, NOX emissions are influenced mainly by oxidation of fuel nitrogen. Thus,
generally, 75-80 percent of the total NOX emitted form incinerators may be fuel NOX.9
20
-------
SECTION 4
COMBUSTION CONTROLS FOR NOX EMISSIONS
As discussed earlier, NOX is formed in the combustion process from the nitrogen and oxygen in
the combustion air and from organic nitrogen chemically bound within the molecular structure of the
fuel. The key parameters controlling the rate of NOX formation for a given fuel and combustor design
are the local oxygen concentration, temperature, and time history of the combustion products. Each of
these parameters, within the temperature range of NOX formation, are determined by the system design
and operation. The combustion system, therefore, determines the NOX formed and represents the only
control capability for reducing the rate of NOX formation. Techniques concerned with reducing NOX
formation are applied in this region and are collectively referred to as "combustion controls". All other
NOV control techniques applied in downstream zones work to reduce the NOY formed during
A A
combustion and are grouped in the category of post-combustion control (see Section 5). A listing of
vendor contacts for combustion controls is presented in Appendix G.
Combustion control technologies discussed below are grouped according to the following source
categories: combustion turbines, 1C engines, and other. Combustion turbine controls discussed in
Section 4.1 include dry control and wet injection. 1C engine controls discussed in Section 4.2 include
injection timing retard, pre-ignition chamber combustion, air to fuel ratio, and wet injection. The controls
discussed in Section 4.3 are applicable to other combustion sources including boilers, process heaters,
and municipal waste incinerators. These controls include low excess air, low NOX burners, overfire air,
burners out of service, flue gas recirculation, rebum, reduced combustion air temperature, and
derating/load reduction.
4.1 COMBUSTION TURBINE CONTROLS
4.1.1 Dry Control
Extensive progress has been made in commercializing dry low NOX combustors for natural gas-
fired gas turbine applications.1^'11'12'1'*'14 NOX reductions of up to 60 percent have been achieved,
and in special instances, reductions of over 80 percent have been reported. Emissions in the range of
25-50 ppm at 15 percent O2 have been achievable for the large, natural gas-fired heavy duty
turbines.1 ^ One system is being offered which is targeted for 9 ppmv NOX emission; (see Section
7.1.2, p. 51 and Reference 14). However, additional development is needed prior to commercialization
of oil-fired applications.
21
-------
Although combustors are proprietary, similarities among designs can be noted. The technologies
are based upon reducing the flame turbulence and intensity, enhancing the fuel/air mixing, and
establishing fuel-lean zones within the combustor. They generally rely on staged combustion with the
first stage used as a pilot burner followed by a secondary stage of multiple fuel injection nozzles. The
second stage often burns a lean, premixed fuel/air mixture in order to assure a uniform mixture and the
avoidance of high temperature regions in the combustor. The control of the two burner zones and the
preparation and control of premix air complicates the combustor control systems. The control system
can be based on using variable geometry, and/or variable air flow scheduling.
The Japanese experience is that the combustion control needed to transfer load between burner
stages (e.g. to transfer from low to high load) is difficult to achieve. A step change in NOX emissions at
the load transfer point indicates a step change in combustion conditions. Step changes are, in general,
not desirable from the point of view of engine stability and durability. Impacts of the fuel preparation
and control systems, and combustion hardware required by the dry low NOX systems upon the
reliability of the combustion system have not been demonstrated in the U.S. Technology applicable to
one particular model is not directly transferable to another model.
4.1.2 Wet Injection
The principal requirements in using wet injection for NOX reduction are to inject sufficient water or
steam at the proper location in the flame envelope, and with appropriate dispersion, to reduce the peak
flame temperature without degrading the combustion efficiency. Although it is easier to ensure uniform
mixing if steam is used, water can be effective as well. Energy extracted from combustion to vaporize
the water causes additional temperature reduction. Furthermore, steam may not be available.
The major factor affecting NOX reduction is the water/steam-to-fuel ratio. The NOX reduction
achievable for a particular unit is directly related to the amount of water or steam which can be injected
before serious impacts on combustor performance occur. The impacts include flame outs, reduced
thermal efficiency expressed as a heat rate penalty, large increases in carbon monoxide (CO) and HC
emissions, and pressure pulsations which result in significantly reduced combustor reliability. Higher
corrosion rates may also be experienced. The highest ratio sustainable will vary depending on the
tradeoff between NCL emissions and CO and HC emissions and combustor design characteristics.
Water/steam injection can be accomplished in a variety of ways ranging from premixing with the
intake air or fuel to injecting it directly into the combustor. The effectiveness of the method is a
function of the atomization and mixing of the water/steam within the combustion charge. Metering and
controls should be provided for injection at varying loads. Requirements for wet injection include a
large water supply, on the order of the fuel rate, and water purification (to boiler feed water quality) to
prevent corrosion. Wet injection is applicable to gas or liquid fuels.
22
-------
4.2 STATIONARY INTERNAL COMBUSTION ENGINE CONTROLS
4.2.1 Injection Timing Retard
Ignition in a normally adjusted 1C engine is set to occur shortly before the piston reaches its
uppermost position (top dead center, or TDC). At TDC, the air or air-fuel mixture is at maximum
compression. The timing of the start of injection or of the spark is given in terms of the number of
degrees that the crankshaft must still rotate between this event and the arrival of the piston at TDC.
Retarding the timing beyond TDC, the point of optimum power and fuel consumption, reduces the
rate of NOX production. Retarding causes more of the combustion to occur during the expansion
stroke, thus lowering peak temperatures, pressures, and residence times. This practice carries with it a
fuel consumption penalty. Typical retard values range from 2° to 6° depending on the engine.6
Beyond these levels, fuel consumption increases rapidly, power drops, and misfiring occurs. Also, HC,
CO, and visible emissions increase, and elevated exhaust temperatures shorten exhaust valves and
turbocharger service lives. Increasing the fuel injection rate has been used on some diesel systems to
partially mitigate the CO and HC emissions and fuel consumption effects of retarded injection timing. A
high injection rate, however, results in increased mixing of air and fuel and a subsequently hotter flame
at the initiation of combustion. There is, therefore, a NOX trade-off with this modification. Injection
timing retard is an applicable control with all 1C engine fuels.
4.2.2 Pre-lqnition Chamber Combustion - "Clean Burn" Technology
The use of a pre-ignition chamber can improve fuel efficiency and reduce NOX emissions. The
system is designed to burn lean fuel/air mixtures. The fuel charge is introduced into the pre-chamber
as a rich mixture and ignited by a spark-plug. Since it burns in the absence of excess oxygen, NOX
formation is inhibited. This "torch" of burning fuel expands into the power cylinder where it thoroughly
ignites a lean mixture at reduced temperatures. Therefore, combustion is completed in an overall lean
mixture at temperatures which are adequate for combustion but below those where NOX formation
occurs. This NOX control is currently applied to gas-fired engines only.
4.2.3 Air To Fuel Ratio
In injection type engines, which include all diesel and many dual fuel and gas varieties, the air to
fuel ratio for each cylinder can be adjusted by controlling the amount of fuel that enters each cylinder.
These engines are therefore operated lean where combustion is most efficient and fuel consumption is
optimum.
23
-------
The most practical use of air-to-fuel ratio adjustment as a control technique is to change the
setting toward leaner operation. The oxygen availability will increase but so will the capability of the air
and combustion products to absorb heat. Consequently, the peak temperature will fall, resulting in
lower NOX formation rates. The limiting factor for lean operation is the increased emissions of
hydrocarbons at the lower temperatures.
Carbureted engines are beset by large variations in cylinder to cylinder air-to-fuel ratios.
Therefore, they must operate near the stoichiometric ratio to ensure that no individual cylinder receives
a charge which is too lean to ignite.
4.2.4 Wet Injection
As with combustion turbines, wet injection can reduce NOX emissions from 1C engines.6 Wet
control effectiveness correlates inversely with excess air levels. Since wet controls reduce peak
temperature by increasing the charge mass, the technique is more effective in a low excess air system
than in one with much excess air and hence, much thermal mass. Presumably, systems with high
excess air absorb all the heat that can be transferred to a fluid in the short time between combustion
and peak temperature. The application of this control to 1C engines has been limited due to
inaccessbility of water injection. A more plausible application of wet controls may be in the
development of water-fuel mixture injection.
4.3 COMBUSTION CONTROLS FOR BOILERS, HEATERS, AND WASTE COMBUSTORS
There are two fundamental ways of controlling the flame stoichiometry: regulating the overall
fuel/air ratio supplied (low excess air), or gross staging of combustion (low NOX burners, overfire air
ports, removing burners from service, derating, reburn). In addition to being influenced by burner
design and fuel/air stoichiometry, the flame temperature can be reduced from its peak value by the
introduction of heat absorbing inerts (recirculated flue gas) or by reduction in the temperature of the
combustion air supplied to the burners.
4.3.1 Low Excess Air (LEA)
For all conventional combustion processes, some excess air is required in order to ensure that all
fuel molecules can find and react with oxygen. In the LEA approach to NOX control, less excess air
(oxygen) is supplied to the combustor than normal, (see discussion of LEA on p. 19). The lower O2
concentration in the burner zone reduces the flame temperature and the formation of thermal NOX. In
the starved-air flame zone, fuel bound nitrogen is converted to nitrogen thus reducing formation of fuel
24
-------
NOX. The limiting criteria which define minimum acceptable excess air conditions are increased
emissions of carbon monoxide and opacity, and a reduction in flame stability.
With LEA firing, the primary concern is improved aerodynamic mixing and eliminating
nonuniformities in air and fuel distributions. Adjustments of air registers, fuel injector positions, and
overfire air dampers are operational controls which can reduce the minimum excess air level possible
while still maintaining adequate air/fuel distribution. However, LEA controls require closer operator
attention to ensure safe operation. Another requirement for continuous LEA operations is to employ
continuous O2 (and preferably CO) monitoring. Also, accurate and sensitive air and fuel flow controls
and instrumentation are required for adjusting air flow at various loads.
New designs and most existing combustion operations will incorporate LEA firing as standard
practice. LEA operation has an economic incentive since it results in increased fuel efficiency. The
reduced airflow decreases the volume of combustion air to be heated, allowing more heat of
combustion to be transferred, thus lowering fuel requirements for a given output. LEA operations may
be used as the primary NOX control method or in combination with other NOX controls such as low-NOx
burners, overfire air, or flue gas recirculation. LEA operations are applicable to all combustion sources
and fuels.
4.3.2 Low NOX Burners (LNB)
Low NOX burners control NOX formation by carrying out the combustion in stages. These
burners control the combustion staging at and within the burner rather than in the firebox. Low NOX
burners are designed to control both the stoichiometric and temperature histories of the fuel and air
locally within each individual burner flame envelope. This control is achieved through design features
which regulate the aerodynamic distribution and mixing of the fuel and air.
As with overfire air (see Section 4.3.3), the burner staging delays combustion and reduces the
peak flame temperature, thus reducing thermal NOX formation. The sub-stoichiometric oxygen
introduced with the primary combustion air into the high temperature, fuel nitrogen evolution zone of the
flame core reduces fuel NOX formation. Thus, low-NOx burners are effective for reducing NOX
emissions independent of fuel. There are two distinct types of designs for low NOX burners: staged air
burners and staged fuel burners.
Staged Air Burners-
Staged air burners (see Figure 6) have been in service since the early 1970's and were the first
type of burner designed to specifically reduce NOX emissions.15 They are designed to reduce flame
turbulence, delay fuel/air mixing, and establish fuel-rich zones for initial combustion. The reduced
availability of oxygen in the initial combustion zone inhibits fuel NOX conversion. Radiation of heat from
25
-------
STAGED AIR IS MIXED
WITH THE COMBUSTION
PRODUCTS FROM THE
PRIMARY ZONE. THIS
LOWERS THE PEAK FLAME
TEMPERATURE WHICH
LIMITS THE FORMATION
OF NO.
SUB-STOICHIOMETRIC
CONDITIONS IN PRIMARY ZONE
INCREASE THE AMOUNT OF
REDUCING AGENTS (H2 & CO).
STAGED AIR
SECONDARY AIR
PRIMARY AIR
Figures. Staged Air Burner
26
-------
the primary combustion zone results in reduced temperature as the final unburned fuel gases mix with
excess air to complete the combustion process. The longer, less intense flames resulting from the
staged stoichiometry lower flame temperatures and reduce thermal NOX formation.
Staged air burners maintain the firebox in an oxidizing environment, minimizing slag/soot
formation and corrosion potential when firing dirty fuels. Lower oxygen levels are also possible with all
the combustion air admitted through the burners.
Staged air burners generally lengthen the flame configuration so their applicability is limited to
installations large enough to avoid flame impingement on internal surfaces. The installation of
replacement burners may require substantial changes in burner hardware, including air registers, air
baffles and vanes, fuel injectors, and throat design. Existing burners can incorporate staged air burner
features by modifying fuel injection patterns, installation of air flow baffles or vanes, or reshaping the
burner throat. Staged air burners are effective with all fuel types.
Staged Fuel Burners--
A more effective concept for NOX reduction is staging of the fuel rather than the air. Staged fuel
burners (see Figure 7) mix a portion of the fuel and all of the air in the primary combustion zone.
The high level of excess air greatly lowers the peak flame temperature achieved in the primary
combustion zone, thereby reducing formation of thermal NOX. The secondary fuel is injected at high
pressure into the combustion zone through a series of nozzles which are positioned around the
perimeter of the burner. Because of its high velocity, the fuel gas entrains furnace gases and promotes
rapid mixing with first stage combustion products. The entrained furnace gases simulate flue gas
recirculation (see Section 4.3.6). Heat is transferred from the first stage combustion products prior to
the second stage combustion. As a result, second stage combustion is achieved with lower partial
pressures of oxygen and temperatures than would normally be encountered.
Unlike the staged air burner, staged fuel burners are only designed for gas firing. The staged
fuel burner is able to operate with lower excess air levels than the staged air burner due to the
increased mixing capability resulting from the high pressure second stage fuel injection. An additional
advantage of the staged fuel burner is a compact flame. Cooling of the combustion products from the
first stage zone in the staged air burner is accomplished primarily by radiation to the process.
However, in a staged fuel burner the entrained furnace products give additional cooling to the flame.
This particular characteristic permits more intense combustion with reduced NOX levels.
4.3.3 Overfire Air (OFA)
In this combustion system, conventional burners are used to introduce the fuel and sub-
stoichiometric quantities of combustion air (primary air). The remaining combustion air (secondary air)
is introduced approximately 1/3 of the distance down the firebox through overfire air ports. The overfire
27
-------
SECONDARY COMBUSTION
HIGH AIR TO FUEL
RATIO IN PRIMARY ZONE
SECONDARY FUEL
COMBUSTION
AIR,
SECONDARY FUEL
CONNECTION
PRIMARY FUEL
CONNECTION
Figure 7. Staged Fuel Burner
28
-------
air system reduces NOX formation by two mechanisms. Staging the combustion air partially delays the
combustion process, resulting in a cooler flame and suppressed thermal NOX formation. The staging of
the combustion air also allows deprivation of oxygen and less mixing of fuel and air in the combustion
region where fuel nitrogen evolves, thereby reducing fuel NOX formation.
The degree of staging is limited by operational problems (e.g., high CO and hydrocarbon
emissions) due to low primary air flow rate creating incomplete combustion conditions. Also, a staged
flame is larger and extends further into the furnace. This can lead to flame impingement causing
refractory damage and/or tube failures. This diminishes the applicability of staging techniques for high
heat release ranges.
This method is effective with all fuels.7 However, there is an increased potential for furnace tube
wastage due to local reducing conditions when firing coal or high sulfur fuel oil, There is also a greater
tendency for slag accumulation in the furnace when firing coal. With reduced airflow to the burners,
there may be reduced mixing of the fuel and air. Additional excess air may be required to ensure
complete combustion, resulting in a decrease in efficiency. The OFA technique is more attractive in
original designs than in retrofit applications for cost considerations. Additional duct work, firebox
penetrations, and extra fan capacity may be required in retrofit situations. Physical obstructions or
insufficient space between the top row of burners and the radiant section exit may not permit the
installation of OFA ports and the enlarged combustion zone required.
4.3.4 Burners Out of Service
Burners out of service is a variation of the staged combustion technique for reduction of NOX
formation. It is a low cost retrofit NOX control measure for existing fireboxes. Ideally, all of the fuel flow
is diverted from a selected number of burners to the remaining firing burners. Since airflow is
maintained unchanged among all the burners, a staged combustion effort is obtained. The fuel-
admitting burners fire more fuel-rich than normal, with the remaining air required for combustion being
admitted through the inactive burners. NOX is reduced by decreasing the excess air available in the
active burner zone. This reduces both fuel and thermal NOX formation and thus, is applicable to all
fuels.
In many cases, burners cannot handle any or all of the increased fuel flow, necessitating a
significant reduction in the firing load rating. Since a reduction in load is not desirable and often not
feasible, this technique is not always viable. Its application requires a minimum of four burners and
extensive engineering on selection of burners out of service and control of air flow to ensure
satisfactory staging conditions. It is usually most effective to place the air-rich burners or air ports in
the region of highest heat release. To avoid flame stability and vibration problems, the number of
burners taken out of service should not exceed 25 percent. Operational impacts such as corrosion and
soot/slag formation are other significant considerations.
29
-------
4.3.5 Reburn
Reburn, also referred to as in-fumace NOX reduction or staged fuel injection (see Figure 8),
involves passing the burner zone products through a secondary flame or fuel-rich combustion process.
This process is designed to reduce NOY formation without generating CO emissions. This NOV control
A A
approach diverts a fraction of the fuel to create a secondary flame or fuel rich zone downstream of the
burner (primary combustion zone). Sufficient air is then supplied to complete the oxidation process.
These reactions are NOX forming as well as NOX reducing. Laboratory results indicate a maximum
reduction in NOX is achieved when the reburning zone stoichiometry is approximately 0.9 (90 percent
theoretical air).16 Other variables which are directly related to reburning effectiveness are burner zone
NOX concentration, reburning zone residence time, and temperature. The flame zone stoichiometry has
been shown to have little influence.
Reburning can be implemented either by redistributing the fuel and air through the existing burner
pattern or by installing additional fuel and air ports above the burner pattern. The latter approach is
likely to yield the best results.
The burner pattern plus overfire air ports provides an existing, potential capability to implement
the reburning NOX control approach. In fact, the burners out of service (see Section 4.3.4) mode of
operation implemented on some units to achieve fuel-rich primary combustion may also result in partial
reburning. LEA and recirculated flue gas (see below) controls are combustion modification techniques
often combined with reburning.
4.3.6 Flue Gas Recirculation (FGR)
The flue gas recirculation approach to NOX control is based on recycling a portion of cooled flue
gas back to the primary combustion zone. The flue gas recirculation system reduces NOX formation by
two mechanisms. The recycled flue gas is made up of combustion products which act as inerts during
combustion of the fuel air mixture. This additional mass is heated and lowers the peak flame
temperature, thereby reducing the amount of thermal NOX formation. To a lesser extent, FGR also
reduces thermal NOX formation by lowering the oxygen concentration in the primary flame zone. The
decrease in flame temperature alters the distribution of heat and lowers the fuel efficiency.
The recycled flue gas may be pre-mixed with the combustion air or injected directly into the flame
zone. Discrete injection allows more precise control of the amount and location. In order for FGR to
reduce NOX formation, flue gas must enter the flame zone. FGR has been used for many years,
principally as a means of improving temperature control at reduced firing rates. In this application, the
flue gas is generally introduced below the burner or above the combustion zone.
30
-------
Burnout Zone
Completion
Air
Returning Zone
(fuel rich)
Burner*
(excectalr)
Oat Injector*
Figure 8. NQ< Reburning with Gas
31
-------
As FGR beneficial effects are limited to reduction of thermal NOX, the technique is applied
primarily to natural gas or distillate oil combustion. In these applications, the thermal NOX component
is virtually 100 percent of the total NOX. The amount of recirculation is limited by flame stability.
Typically, 15-20 percent is employed. Flue gas recirculation for NOX control is more adaptable to new
designs than as a retrofit application.
4.3.7 Reduced Combustion Air Temperature
This NOX control technique is limited to equipment with combustion air preheaters. For fired
heater and boiler applications all of or a fraction of the combustion air bypasses the preheater.
Reducing the amount of combustion air preheat lowers the primary combustion zone peak temperature,
which inhibits thermal NOX production. Because the beneficial effects are limited to the reduction of
thermal NOX, this approach is economically attractive for only natural gas and distillate oil fuel
applications.
Although NOX emissions decrease significantly with reduced combustion air temperature,
significant loss in efficiency will occur if flue gas temperatures leaving the stack are increased as a
consequence of bypassing the air preheaters. Enlarging the surface area of existing economizers or
installation of an economizer in place of an air preheater can be used to partially recover the heat loss.
4.3.8 Derating/Load Reduction
Thermal NOX formation generally increases as the heat release rate or combustion intensity
increases. Reduced combustion intensity can be accomplished by load reduction, or derating, in
existing units and by installation of an enlarged firebox in new units. Reduced firing rates can lead to
several operational problems. The reduced mass flow can cause improper fuel-air mixing during
combustion, creating CO and soot emissions. This situation is alleviated by operating at excess air
levels higher than normally maintained at the original design load. This increase in O2 levels reduces
thermal operating efficiency and increases fuel NOX generation. The net effect of decreasing thermal
NOX formation while increasing fuel NOX is case specific.
When the combustion unit is designed for a reduced heat release rate, the problems associated
with derating are largely avoided. An enlarged firebox produces NOX reduction similar to load reduction
on existing units, without necessitating an increase in excess air levels. This NOX control is applicable
to all fuel types.
32
-------
SECTION 5
POST-COMBUSTION NOX CONTROL TECHNOLOGIES
This section describes NOX reduction techniques applied downstream of the combustion zone to
reduce the NOX formed during the combustion process. The three post-combustion NOX control
technologies described include selective catalytic reduction (SCR), non-selective catalytic reduction
(NSCR), and selective noncatalytic reduction (SNCR). A listing of control equipment vendor contacts is
presented in Appendix G.
5.1 SELECTIVE CATALYTIC REDUCTION
A schematic of the SCR process is shown in Figure 9. In this process, ammonia (NH3), usually
diluted with air or steam, is injected through a grid system into the flue/exhaust gas stream upstream of
a catalyst bed. On the catalyst surface, the ammonia reacts with NOX to form molecular nitrogen and
water. Depending on system design, NOX removal of 80-90 percent and higher are achievable. The
major reactions that occur in the presence of the catalyst are the following:
6/VO + 4/VH, - 5A/2 + 6H2O W
2NO + 4/VH, + 2O2 -
The reaction of NH3 and NOX is favored by the presence of excess oxygen (air-rich conditions). The
primary variable affecting NOX reduction is temperature. Optimum NOX reduction occurs at catalyst
bed temperatures between 600° and 750°F for conventional (vanadium or titanium-based) catalyst
types, and 470°-510°F for platinum catalysts. Performance for a given catalyst depends largely on the
temperature of the flue gas being treated (see Figure 10). A given catalyst exhibits optimum
performance between a temperature range of ±50°F for applications where flue gas O2 concentrations
are greater than 1%. Below this optimum temperature range, the catalyst activity is greatly reduced,
allowing unreacted ammonia to slip through. Above 850°F, ammonia begins to be oxidized to form
additional NOy. The ammonia oxidation to NO increases with increasing temperature. Depending on
A A
the catalyst substrate material, the catalyst may be quickly damaged due to thermal stress at
temperatures in excess of 850°F. It is important, therefore, to have stable operations and thus uniform
flue gas temperatures for this process to achieve optimum NOX control.
33
-------
HRSQ
Stack
DOHitton Ak Blower
NH/AirMbmr
Flow Control^—'
Valve
NOx/O2 Monitor*
Vaporizer
Rgure 9. SCR System Process Flow Diagram for Gas Turbine/HRSG System
(HRSG: heat recovery steam generator)
-------
100-
80-
60-
40-
20-
1% 0.5%"'
Spao*V«k»dty-10,000 1/h
200 250 300 350 400 450 500
Catafyrt Temperature *C
Figure 10. Effect of Temperature and Oxygen on NO* Conversion
35
-------
A new family of zeolite catalys* ias been developed which are capable of functioning at higher
temperatures than conventional catalysts. Zeolites,are claimed to be effective over the range of 600° to
1,125°F, with the optimum temperature range stated as 675° to 1,0750F.18'19'20 For zeolite catalysts
and applications, ammonia oxidation to NOX begins at around 850° and is predominant at temperatures
in excess of 960°F.20 Zeolites suffer the same performance and potential damage problems as
conventional catalysts when used outside their optimum temperature range. In particular, at around
1020°F, the zeolite structure may be irreversibly degraded due to loss of pore density.19 Zeolite
catalysts have not been continuously operated commercially at temperatures above 960°F due to
ammonia oxidation to NOX and potential damage to the catalyst.20
With zeolite catalysts, the NOX reduction reaction takes place inside a molecular sieve ceramic
body rather than on the surface of a metallic catalyst. This difference is reported to reduce the effect of
particulates/soot, SOg/SOg conversion, heavy metals, etc. which poison, plug, and mask metal type
catalysts. These catalysts have been in use in Europe since the mid-1980's, with approximately
100 installations on-stream.19 Process applications range from gas to coal fuel. Typically, NOX levels
are reduced 80-90 percent. Refer to Appendix E where performance of SCR units employing zeolite
catalysts are reported for some selected sites in West Germany. Zeolite catalysts are currently being
purchased for U.S. installations.
The optimal effectiveness of the catalytic process is also dependent on the NH3/NOX ratio.
Ammonia injection rates must be controlled to give a 1:1 NH3/NOX mole ratio. As the mole ratio of
NH3/NOX increases to approximately 1:1, the NOX reduction increases. Operating above a 1:1 ratio or
with insufficient catalyst volume will result in unreacted ammonia slipping through the catalyst bed. On
stream analyzers and quick feedback control are required to optimize the NOX removal and minimize
NH3 emissions.
Another variable which affects NOX reduction is space velocity, the ratio of flue gas flow rate to
catalyst volume, or the inverse of residence time. For a given catalyst volume, increased flue gas rate
decreases the conversion of NOX. Conversely, for a given flue gas flow rate, increased catalyst volume
improves the NOX removal effectiveness.
Site-specific factors including operating temperatures and fuel type affect the performance and
emission rates achievable with SCR. There are a number of operating considerations with SCR. First,
potential catalyst poisoning by either metals, acid gases, or paniculate entrainment is detrimental. For
detailed discussion of SCR catalyst poisoning see Reference 21. The potential loss of catalyst activity
due to these fuel effects results in the use of an excess of catalyst to maintain the required process
efficiency over an extended period of time. Second, ammonia emissions result. In a properly designed
and controlled system, ammonia emissions should be less than 10 ppm. Also, flue gas temperatures
may not be in the proper operating range, which will require reheat. An increase in back pressure due
to pressure drop across the catalyst results in a decrease in fuel efficiency. In addition, the formation of
ammonium sulfate and bisulfate in the presence of SO3 and unreacted ammonia presents corrosion
36
-------
and plugging concerns in heat exchange equipment downstream of the reactor. Most of the problems
have been successfully addressed in commercial operation, in the U.S. and abroad.
5.2 NON-SELECTIVE CATALYTIC REDUCTION (NSCR)
Non-selective catalytic reduction systems are often referred to as "three-way conversion" catalyst
systems since they reduce NOX, unburned hydrocarbon, and CO simultaneously. To operate properly,
the combustion process must be with an air-to-fuel ratio slightly fuel-rich of stoichiometric. Under this
condition, in the presence of the catalyst, the oxides of nitrogen are reduced by the carbon monoxide,
resulting in nitrogen and carbon dioxide.
Sulfur resistant catalysts supports of titanium, molybdenum or tungsten are available for SOg-
laden stream applications. Deposits are controlled by control of NH3 slip to below 5 ppmv.
For additional information on specific catalyst performances as a function of variables such as
NHg/NO ratio, space velocity, HNg-slip, the reader should consult with contacts provides in Appendix G,
pp. G-1 and G-2.
NSCR systems primarily utilize the following reaction in reducing NOX:
2CO + 2NOX - 2COz + /V2 (6)
The catalyst used to promote this reaction is generally a mixture of platinum and rhodium. The catalyst
operating temperature limits are 700 to 1,500°F, with 800 to 1,200°F being the most desirable.
Temperatures above 1 ,500°F result in catalyst sintering.
Typical NOX conversion ranges from 80-95 percent with corresponding decreases in CO and HC.
Potential problems associated with NSCR applications include catalyst poisoning by oil additives (e.g.,
phosphorous, zinc) and inadequate control systems.22 NSCR is currently limited in application to 1C
engines with fuel rich ignition systems.
5.3 SELECTIVE NON-CATALYTIC REDUCTION (SNCR)
There are two commercially available selective non-catalytic reduction processes: Thermal
DeNOx®, which uses ammonia as the reducing agent, and NOxOUT®, which uses urea as the
reducing agent. Each has their distinct differences but from a process approach they are similar.
37
-------
5.3.1 Thermal
Thermal DeNOx® (TON) developed by Exxon is an add-on NOX control technique which reduces
NOX to N2 without the use of a catalyst. Figure 1 1 shows a process flow diagram for a thermal DeNOx
system applied to an oil- and gas-fired boiler. The TON process injects gaseous ammonia to react with
NOY in the air rich flue gas. The ammonia and NOV react according to the following competing
A A
reactions:
2A/O + 4/vK, + 2Ofe - 3/Vz + BH2O (7)
4/VH, + 5O2 - 4/VO + 6H2O (8)
Temperature is the primary variable for controlling the selective reaction. In the temperature range of
1,600°F to 2,200°F, the first reaction dominates, resulting in a reduction of NOX- Above 2,200°F, the
latter reaction dominate, causing increased NOX production. Below 1,600°F, neither reaction is of
sufficient activity to either produce or destroy NOX. NOX reduction performance is maximized in the
relatively narrow temperature range of 1,600-1,900°F, with an optimum temperature of approximately
1,750°F. The 300° reaction window can be lowered to a range of 1,300-1,500°F by introducing
hydrogen, a readily oxidizable gas.23
Without the use of catalyst to increase the reaction rates, adequate time at optimum temperatures
must be available for the NOX reduction reaction to occur. Design considerations should allow ample
residence time and good mixing in the required temperature range. Long residence times (>1 second)
at optimum temperatures will tend to promote relatively high performance even with less than optimum
initial mixing or temperature/velocity gradients. However, when the NH3 injection zone is characterized
by low temperatures and/or steep temperature declines, a loss of process efficiency results.
The initial ratio of ammonia injected to NOX concentrations is another parameter to control the
process. Maximum NOX reductions (40-60 percent) require 1.5-2.0 NH3/NOX injection ratios. At these
ratios, significant concentrations of NH3 can exit the convective zone, creating corrosive ammonium
sulfates and/or a visible NH3 stack plume.1 (Unreacted ammonia emissions from a Thermal DeNOx®
system are usually higher than from SCR systems.)
Selection of the optimum NH3 injection location also affects NOX reduction performance and NH3
slip. In most Thermal DeNOx applications today, the injection grids are being replaced by wall
injectors. The temperatures and velocity profiles will change significantly with load. This necessitates
the use of multiple NH3 injection points to achieve the desired NOX reduction for a range of operating
loads.
38
-------
AMMONIA
DISPERSION
SYSTEM-
-STACK
N2 - WATER VAPOR
t
NO,
n
BURNERS
-NH3 - CARRIER
NH3 EVAPORATOR
Rgure 11. Schematic Diagram for Selective Non-Catalytic Reduction
39
-------
5.3.2 NOxOUT®
In the NOxOUT® process, a urea type (or amine salt) compound is injected into the oxygen-rich
upper furnace and/or high temperature convection section of a boiler to promote NOX reduction as
shown below:
NHZ + NO - A/2 + HZO (9)
The exact chemical mechanism is not fully understood, but involves the decomposition of urea
[C(N H2)2O]. The likely decomposition products include the NH2 groups. The reaction takes place at
temperatures of 1,700 to 3,000°F.24
Originally developed for the Electric Power Research Institute (EPRI) in the late 1970's, the
process is currently licensed by Fuel Tech where proprietary additives that allow NOX reduction
capability over a temperature range of 800-2,100°F have been developed. As with the other post-
combustion NOX control systems, temperature is the primary control variable for the selective reactions.
NOX reductions up to 80 percent are achievable with this technology.24 The performance of the urea
injection process is limited by the time/temperature/flow characteristics of the flue gas. Residence time
in the temperature window and the urea to NOX ratio impact the performance in a similar manner as for
Thermal DeNOx. The NOX reduction capability is limited by mixing because the reaction times are
relatively fast.
The capital costs associated with urea injection tend to be less than those of ammonia injection.
Urea is injected in liquid form, eliminating the need for a compressor. The hazards of ammonia storage
are also alleviated. The lower capital costs are offset however by higher operating costs; urea is more
expensive than ammonia. The urea injection process may better accommodate changing conditions
due to varying loads by altering the solution formulation, in addition to multiple injection points for
varying temperature/load requirements.
Further information on TON and NOxOUT performance are available from the two contacts
provided in Appendix G, p. G-5.
40
-------
SECTION 6
STATUS OF NOX CONTROL TECHNOLOGY APPLICATIONS
This section describes the applications of NOX control technologies to various combustion
sources including combustion turbines, stationary 1C engines, boilers/heaters, and waste incinerators.
The emphasis is on commercial applicability of the technologies excluding those that are in the
developmental and/or research stage.
The information presented in this section reflects the status of NOX control applications in the
U.S., Japan, and West Germany. Major sources of information used include the following:
(a) BACT/LAER Clearinghouse on-line data base
(b) EPA Region 9
(c) California Air Resources Board
(d) West Germany site visits (1C engine/boiler SCR applications; vendors)
(e) Environmental Catalyst Consultants, Inc.2^
As pointed out in Sections 4 and 5, the applicability of a control technology is dependent on
several factors including combustion source type and fuel type. Table 1 presents an overview of the
NOX control technology applications by combustion source type. The control technologies are divided
into two major groups - combustion controls and post-combustion controls. The former comprises a
variety of techniques described in Section 5. As shown in the table, combustion modifications and
selective catalytic reduction have been applied to all of the combustion source types included in this
study.
NOX control technology applications are summarized by combustion source type as well as fuel
type in the following subsections. Detailed listings by facility name, location, size, start-up/permit date,
specific control technology, NOX permit level, and state contact name are provided in Appendices A
through D. Although the emphasis is on applications in U.S., information on NOX control technology
applications in West Germany and Japan are also presented in this section (see Appendices E and F,
respectively).
6.1 COMBUSTION TURBINES
Table 2 summarizes the current NOX control applications in U.S., Japan, and West Germany for
combustion turbines fired with gas, dual fuel, and oil. In some of the applications identified, the specific
41
-------
TABLE 1. NOX CONTROL TECHNOLOGY APPLICABILITY3'15
Control Technology
Combustion Controls0
Post-combustion Controls
Selective catalytic reduction
Non-selective catalytic
reduction
Selective non-catalytic
reduction
Stationary
Combustion Combustion Boilers/
Turbines Engines Heaters
XXX
XXX
X
X
Waste
Incinerators
X
X
X
aRefer to Appendices A, B, C, D, E, and F tor facility-specific data.
"Commercial applications in U.S., Germany, and Japan.
Includes a variety of combustion techniques to reduce NOX formation in the combustion zone
depending on the source: wet injection, timing retard, staged combustion, low excess air, burners out
of service, flue gas recirculation, overfire air, dry combustion controls, reduced air preheat, clean burn,
and derating.
TABLE 2. NOY CONTROL TECHNOLOGY APPLICABILITY - COMBUSTION TURBINESa'b
Fuel
Natural Dual
Control Technology0 Gas Oil Fuel
Combustion Controls
Wet injection XXX
Dry low NOX X
Combustor design X X
Post-combustion Controls
Selective catalytic reduction X X X^
aRefer to Appendices A and F for facility-specific data.
Commercial applications in U.S., Japan, and West Germany.
cMay involve application of more than one control technology on a turbine (e.g., steam injection and
selective catalytic reduction).
42
-------
control technologies are implemented in conjunction with other technologies, for example, wet injection
followed by selective catalytic reduction.
6.1.1 Combustion Controls
For gas-fired and dual fuel-fired combustion turbines, the primary methods of NOX control are
low-NOx emitting combustor designs and/or injection of steam or water into the combustor. Low NOX
combustor design and wet injection are used either individually or simultaneously to achieve the
required NOX levels.
There are relatively few oil-fired combustion turbines in the U.S., and the NOX combustion
controls applied are the same as those applied for gas or dual fuel-fired turbines. About 40 percent of
the 140+ combustion turbine applications identified are reported to use wet injection and about
five percent are reported to employ low NOX combustor design as methods for NOX control. In about
five percent of the applications, wet injection and low NOX combustor design are collectively cited as
the NOX control method.
6.1.2 Selective Catalytic Reduction
This technology is the only post-combustion NOX control technology widely applied to combustion
turbines. In the data sets reviewed, SCR was reported as the applied technology in 30 percent of the
applications . Majority of these applications involve SCR systems accompanied by wet injection as the
preliminary NOX control mechanism.
Geographically, application of SCR has been more common in California, followed by the
Northeastern States, where the NOX regulations are more strict than elsewhere in the U.S. Application
of SCR to combustion turbines in the U.S. has been limited to gas or dual fuel-firing only. However,
SCR has been applied to two kerosene-fired combustion turbines in Japan (see Appendix F).26 One of
these units is a 141 MW unit with an SCR system operating since 1981. The other SCR unit is
installed on a 3 MW turbine and has been operating since 1984.
SCR catalyst life in turbine applications has generally exceeded expectations. In Japan gas-fired
SCR applications are typically 8-10 yrs between catalyst changes. In the U.S. one installation is
expecting 7 years catalyst life on a gas-fired turbine.27
6.2 STATIONARY INTERNAL COMBUSTION ENGINES
Commercially available control technologies 1C applied to engines are summarized in Table 3 for
four fuel type categories: natural gas, dual fuel, oil, and "other" which includes engines fired with
43
-------
landfill gas, refinery gas, process gas, and digester gas. More than two thirds of the engines identified
use natural gas as the primary fuel.
TABLE 3. NOX CONTROL TECHNOLOGY APPLICABILITY - STATIONARY 1C ENGINESa'b
Control Technology"
Combustion Controls
Injection timing retard
Pre-ignrtion chamber combustion (clean burn)
Air to fuel ratio
Stratified charge
Turbocharging
Wet injection
Derating
Fuel
Natural Gas/
Dual Fuel Oil
X X
X X
X
X
X
X
Other0
X
X
Post-combustion Controls
Selective catalytic reduction X XX
Non-selective catalytic reduction X
^Refer to Appendices B, E and F for facility-specific data.
"Commercial applications in U.S., West Germany, and Japan.
^Landfill gas, refinery gas, process gas, and digester gas.
"May involve application of more than one control technology on an engine (clean burn engine and
wet injection).
From an NOX control viewpoint, the most important distinction between different engine models
and types for reciprocating engines is rich-burn versus lean-bum. As indicated earlier, exhaust from
rich-burn engines has little or no excess air while the exhaust from lean burn engines is characterized
with medium to high levels of O2.
6.2.1 Combustion Controls
For natural gas-fired engines, engine design in general and clean burn or pre-ignition chamber
combustion have been the most commonly applied NOX control technology in the past decade. These
two technologies account for over 75 percent of the applications identified as permitted and/or applied
in this study.
In oil-fired engines, the most common techniques employed include injection timing retard and
clean burn.
44
-------
6.2.2 Selective Catalytic Reduction
This technology has been applied only to lean-burn reciprocating and diesel engines where the
exhaust gas O2 concentrations are high as the SCR reaction mechanisms require presence of oxygen
(See Section 5.1). In the U.S., applications have been limited to natural gas-fired engines in the past
oe
decade with a recent application to a dual fuel-fired diesel engine. ° This unit has been operating
since September 1988.
In Japan, SCR has also been applied to oil-fired diesel engines as well (see Appendix F). Two of
these three units started operation in the 1978-1980 time frame, with another unit coming on-line in
1989. In West Germany, SCR has been applied to engines firing natural gas, dual fuel, landfill gas as
well as oil. Table 4 identifies the 1C engine SCR sites visited in Germany as part of this study and
presents the information collected (see Appendix E for trip reports).
6.2.3 Non-selective Catalytic Reduction
As described in Section 5.2, application of NSCR requires fuel-rich engine operation or the
addition of reducing agents in the flue gas upstream of the catalyst. Therefore, application of this
technology has been limited to rich-burn engines. In this study, a number of NSCR applications on
gas-fired rich burn engines have been identified. All of these engines are located in California and
have been permitted in early to mid-1980s (see Appendix B).
6.3 NON-UTILITY BOILERS AND HEATERS
As indicated earlier, the applicability of a technology is influenced by several factors. For boilers
and process heaters, the major factor is fuel type. Gas and oil-fired boilers and heaters have very
similar characteristics with regard to boiler design and control applicability. Solid fuel (coal and wood)
boilers and heaters have very different designs compared to oil/gas designs. Within the solid fuel boiler
category, these designs include, pulverized coal, stoker (coal and wood), and fluid bed. Table 5
summarizes the current technology applications in the U.S. relative to the boiler and fuel type.
6.3.1 Combustion Controls
Low NOX combustion technologies include the following air and fuel staging technologies which
have been used jointly or individually: low excess air, over fire air, flue gas recirculation, and low NOX
45
-------
TABLE 4. WEST GERMANY SITE VISITS (1C ENGINES)"
Site
NO, Control
Size Fuel Technology
Start-up
Date
Operating Hours
(November 1989)
NOX
Permit
Level
Stadtwerke Drdetch
155 kW (5 units) Natural Gas
Stadtwerke Norderetedl 2MW(6unlts) Natural Gas
UnrvflrsHat
700 kW (2 units) Natural Gas
500 kW (2 units)
SCR (5 units) 1986
SCR (6 units) December 1985
SCR
1987
14.000- 17.000 250 ppm at 12% O2
(166 ppm at 15% O2)
9000 425 ppm at 5% 02
(158 ppm at 15% O2)
2000 230 ppm at 7% 02
(98 ppm at 15% 02)
Landeszentralbank 750 hp
Pelssenberg 6 MW
Dual Fuel
Dual Fuel
SCR January 1987 4800 266 ppm at 5% 02
(99 ppm at 15% O2)
SCR December 1987 9300 532 ppm at 5% 02
(197 ppm at 15% O2)
Depogas
KarlReum
1.5MW(3un»s)
460 kW (3 units)
LandflR gas
Propane
SCR (3 units)
Combustion
Modification
1988
March 1989
600
2000
225 ppm
234 pppi at 8.2% O2;
source test
(109 ppm at 15% 02)
"See Appendix E for trip reports.
-------
TABLE 5. NOX CONTROL TECHNOLOGY APPLICABILITY - NON-UTILITY
BOILERS AND HEATERSa'b
Coal Coal/Wood Gas/Oil
Control Technology Pulverized Conventional Fluid
Bed
Combustion Controls0 XX XX
Low excess air
Overfire air
Flue gas recirculation
Low NOX burners
Post-combustion Controls
Selective catalytic reduction X XX
Selective non-catalytic reduction X XX
^Refer to Appendices C, E, and F for facility-specific data.
"Commercial applications in U.S., West Germany, and Japan.
cMay involve concurrent application of more than one technology.
burners. Almost all recently permitted gas/oil and pulverized coal boilers use low NOX burners. Most
of these boilers also use other combustion modification technologies, with the most recently used
technology combination being low NOX burner plus flue gas recirculation.
Since 1985, over ten coal-fired boilers were permitted to use low NOX combustion technologies
as the primary method of NOX control. Also, over 25 oil and gas fired boilers are identified as using
low NOX combustion technologies for NOX control. Over half of these boilers are identified as
employing low NOX burner plus flue gas recirculation.
6.3.2 Selective Catalytic Reduction
On boilers and heaters, SCR has been applied at over 15 gas-fired refinery process heaters and
boilers in California. (See Appendix C, pp. C-3 and C-4.) The refinery systems were permitted in early
1980s and the boiler systems were permitted in the late 1980's.
In Japan, SCR has been applied to over 50 industrial boilers firing gas, oil, and coal.25 Over
60 percent of these boilers fire oil, followed by gas firing (25 percent), and coal firing (15 percent). The
boiler sizes range from 50 to 1,500 million Btu per hour heat input with start-up dates from 1977 to
1989. See Appendix F for a listing of SCR applications in Japan on dirty fuels.
47
-------
6.3.3 Selective Non-catalytic Reduction
SNCR technology has been widely applied to fluid bed combustion boilers and wood-fired boilers.
Operation of these boilers is characterized by relatively low NOX emissions and allows for sufficient
residence time and mixing in the temperature window required by the technology. For example, fluid
bed combustors have low emission levels of NOX due to the low combustion temperatures (1600-
1,800°F). These boilers have high temperature cyclones which are used to recycle char and bed
material back to the fluid bed. The cyclones provide ideal mixing of ammonia with the combustion
gases resulting in good removal efficiency with reasonable ammonia to NOX ratios.
Since the mid-1980's, over 20 sites are identified as having permits granted based on the
application of SNCR. Almost all of the sites are coal or wood/bioamass-fired fluid bed boilers and
conventional wood/biomass-fired boilers. The exceptions involve gas-fired boilers and a CO boiler.
6.4 MUNICIPAL WASTE AND SLUDGE INCINERATION
Over 80 municipal waste sites are identified from the survey information as being permitted
between 1980 and 1990 (see Appendix D, Table D-1). Table 6 summarizes the application status of
NOX controls for waste incineration. NOX emissions are identified as being controlled using combustion
controls at about 90 percent of the sites. The combustion controls identified include: boiler
design/modification, combustion control, and overfire air.
6.4.1 Selective Non-catalytic Reduction
At seven sites (municipal waste/tire/sludge), SNCR was identified as the means of NOX control.
Except for two sites in California, the remaining were recently permitted in 1989 -1990.
6.4.2 Selective Catalytic Reduction (Japan)
In Japan, application of SCR for controlling NOX emissions from waste incineration has been
extensive.25 For example, two sites in Japan have operated with SCR systems since 1986. In
addition, there are 16 SCR units on plants incinerating sewage sludge in Japan (see Appendix F).
48
-------
TABLE 6. NOV CONTROL TECHNOLOGY APPLICABILITY - WASTE INCINERATORS3'13
Control Technology Municipal Waste
Combustion Modifications
Boiler design X
Overfire air X
Combustion control X
Post-combustion Controls
Selective catalytic reduction X
Selective non-catalytic reduction X
aRefer to Appendices D and F for facility-specific information.
^Commercial applications in U.S. and Japan.
49
-------
SECTION 7
NOV CONTROL DATA
This section describes the NOX control levels achieved using the technologies discussed in the
previous section. The following subsections focus on the NOX emission limits as specified in the
permits (not necessarily identical to actual NOX emission levels) by combustion source/fuel type and
control technology. Facility-specific emissions limits as well as other information for each combustion
source/facility are presented in Appendices A through D for combustion turbines, engines,
boilers/heaters, and incinerators, respectively. Performance levels for the West German and Japanese
units are summarized in Appendices E and F, respectively. Conversion factors for expressing NOX
limits as ppm at 15 percent O2, pounds per million Btu, grams per brake horsepower per hour, and mg
per cubic meter are included in Appendix H.
7.1 COMBUSTION TURBINES
NOX permit limits identified for the turbines included in this study are summarized in Table 7,
organized by fuel type and control technology applied.
7.1.1 Combustion Controls/Wet Injection
As indicated in Section 6, wet injection is the most commonly applied NOX control technology for
gas turbines. The NOX permit limits shown in Table 7 reflect the performance levels considered
achievable when water or steam injection is the only control applied (i.e., not in conjunction with SCR or
other combustion controls). The wide range of performance for gas-fired and dual fuel-fired turbines
are indications of the increasing stringency of NOX permit levels in the country throughout the past
decade, particularly in California and the Northeastern States.
For gas-fired turbines, most of the recent permits have specified 25 to 42 ppm at 15 percent O2
as the NOX limit. For dual fuel-fired turbines, NOX limits are specified for both gas firing and oil firing.
These levels have ranged from 25 to 79 ppm and 40 to 129 ppm at 15 percent O2 over the past
decade for gas and oil, respectively. However, recent permits for dual fuel-fired turbines have
commonly allowed for 2£= to 42 ppm for gas firing and 40 to 65 ppm for oil firing, respectively, both at
15 percent O2-
50
-------
TABLE 7. NOX CONTROL LEVELS - COMBUSTION TURBINES a'b
Control Technology
NOV Permits Limits (ppm NOV at 15% O9)
* A &
Natural Gas
Oil
Dual Fuel
Combustion Controls
Wet injection
Dry low NOX
Post-combustion Controls
Selective catalytic reduction
25-195
32-188
5-25c
10-25C
25-79 (gas)/40-129 (oil)
8-10 (gas)/12-18 (oil)*
j^Refer to Appendices A and F for facility-specific data.
"Commercial applications in U.S. and Japan.
°ln combination with combustion controls.
"Units in Japan.
eBased on two units in Eastern U.S.
7.1.2
Combustion Controls/Dry Low
In the four permits identified where combustor design has been specified as the method of NOX
control, the NOX limits range from 32 to 188 ppm, with the 32 ppm limit imposed on a unit permitted in
1990 in New York and the 188 ppm limit imposed on a unit permitted in 1981. In a few cases,
combustor design and wet injection have been reported together as the NOX control technology, with
permit levels ranging from 25 to 75 ppm at 15 percent O2-
Recognizing the pressure to reduce emissions, all major vendors have development programs
that should allow them to provide guarantees of 25 ppm or lower.28 Some vendors now guarantee
25 ppm with special low NOX combustors. Recently, a turbine has been sold with a NOX emission
guarantee of 9 ppm without water or steam injection (on natural gas) or SCR.14 It is recognized,
however, that the new generation of turbines will have difficulty matching these very low levels without
water or steam injection because of the higher firing temperatures which make them inherently higher
NOX producers.14-28
7.1.3
Selective Catalytic Reduction
SCR is considered applicable, in combination with combustor design and/or wet injection, to
reduce NOX emission levels to 5-25 ppm at 15 percent O2 on natural gas and dual fuel-fired turbines,
as evidenced by the large number of permits issued recently in California and the Northeastern States.
Most of the recent permit specifications involve NOX levels of 5 to 10 ppm for gas firing. In the permits
51
-------
identified for dual fuel-fired turbines, NOX limits for gas firing are specified as 8.2 to 10 ppm, with the oil
firing NOX limits set at 11.7 to 40 ppm, both at 15 percent O2.
Two turbines firing kerosene in Japan are identified as employing SCR to reduce NOX emissions
(see Appendix F). One of these turbines is a 141 MW unit equipped with an SCR system that has
been in operation since 1981.26 The SCR system reduces inlet NOX levels of 60 to 80 ppm to 10 ppm
at the outlet, both at 15 percent O2. The second SCR system is installed on a 3 MW unit and is
capable of reducing the inlet NOX levels from 100 ppm to 25 ppm at 15 percent O2. This unit has
been operational since 1984.
7.2 STATIONARY INTERNAL COMBUSTION ENGINES
Table 8 summarizes the NOX emission limits for the 1C engine applications. These limits reflect
the emission reductions achievable based on the fuel employed as well as the recent technological
developments in NOX control.
7.2.1 Combustion Controls
A majority of the -120 1C engine applications identified implement combustion controls. For
natural gas or dual fuel-fired engines that make up roughly 75 percent of the 1C engine population in
this study, primary controls involved clean burn or low NOX engine design. The emission levels for
these engines range from a low of 0.75 g/hp-hr (approximately 80 ppm at 15 percent O2) for a recently
permitted unit in California to a 16.5 g/hp-hr (approximately 1,760 ppm at 15 percent O2) for a unit
permitted in 1980 in Alabama. The recent developments and modifications in engine design have
allowed for low levels for NOX emissions. The unit visited in West Germany exhibits NOX emission
levels comparable to that observed in U.S.; 109 ppm at 15 percent O2 on propane gas (see Appendix
E for trip report).
Of the 17 oil-fired engine applications in U.S., 10 employ injection timing retard as the primary
method of NOX control. With this method, NOX emission levels of 520 to 1,158 ppm of NOX at
15 percent O2 are considered achievable.
NOX emission levels for nine engines operating on landfill gas and digester gas range from 1.5 to
2 g/hp-hr (approximately 160 to 210 ppm at 15 percent O2). All of these units employ clean burn
engines for NOX control. The majority of these engines were permitted in early to mid-1980's. Except
for one engine, the remaining eight are located in California.
52
-------
TABLE 8. NOY CONTROL LEVELS - STATIONARY INTERNAL COMBUSTION ENGINESa>b
Control Technology
Combustion Controls
Natural Gas/
Dual Fuel
0.75- 16.5g/hp-hr
(~80-1 ,760 ppm
at 15% O2)
NOX Permit Limits
Oil
520 - 1,158 ppm
at 15% O2
Other0
1.5 -2 (160 to
21 0 ppm at
15%O2)
Injection timing retard
Pre-ignition chamber combustion
(clean burn)
Air to fuel ratio
Stratiffied charge
Turbocharging
Wet injection
Derating
Post-Combustion Controls
Selective catalytic reduction
Non-selective catalytic reduction
70 - 90% (U.S.)
96-190 ppm at
15% O2
(Germany)"
1.0- 1.5g/hp-hr
(110 to 160 ppm at
15% O2)
90 -150 ppm
(Japan)
^Refer to Appendices B, E, and F for facility-specific data.
"Commercial applications in U.S., West Germany, and Japan.
cLandfill gas, refinery gas, process gas, digester gas.
"Site visits.
7.2.2
Non-selective Catalytic Reduction
Eight rich-bum engines are identified as implementing NSCR for NOX control. All of these
engines are located in California and have been permitted in early to mid-1980's. As shown in Table 8,
NOX emission limits required for these units range from 1.0 to 1.5 g/hp-hr (approximately 110 to 160
ppm at 15 percent O2).
7.2.3
Selective Catalytic Reduction
Application of SCR to 1C engines in U.S. has been limited. Of the two units identified in this
study, one is a dual fuel-fired engine in Massachusetts and the other one is a natural gas-fired unit in
53
-------
California.28 The NOX permit limits on these units are 40 tons/yr and 100 Ib/day, with reported NOX
control efficiencies of 90 and 70 percent, respectively.
Of the three oil-fired engine/SCR applications in Japan, two have started operation in 1978 -1980
with one start-up in 1989.25 The two older units are reported to emit NOX at 90-150 ppm levels.
As discussed in Section 6, SCR has been applied to natural gas, dual fuel, landfill gas, and oil-
fired 1C engines in West Germany. Of the six sites visited that employ SCR, thirteen engines at three
of the sites fire natural gas; two engines at two sites fire dual fuel; and three engines at the remaining
site fire landfill gas (see Table 4 on page 46; see Appendix E for trip reports). All of the SCR units at
these sites employ zeolite catalysts and have been operational since 1985 -1988. NOX permit limits
on dual fuel-fired engines are specified at 99-197 ppm (at 15 percent O2) while the natural gas-fired
engines are permitted at 98-166 ppm (at 15 percent O2).
7.3 NON-UTILITY BOILERS AND HEATERS
Table 9 presents a summary of the NOX control limits identified in this study for boilers and
heaters by fuel type. NOX control levels are presented for U.S. as well as Japanese applications,
where available.
7.3.1 Combustion Controls
As indicated earlier, achievable NOX emission levels are greatly dependent on fuel nitrogen. The
NOX levels reported for the different fuel types provide an illustration of the importance of this variable:
73-258 nanograms per Joule (approximately 40 to 145 ppm at 15 percent O2) for coal-fired boilers and
7.7-43 nanograms per Joule (approximately 5 to 30 ppm at 15 percent O2) for gas-fired boilers.
Influence of boiler design is illustrated by the lower NOX levels for coal-fired fluid bed boilers which are
operated at lower temperatures than conventional boilers, hence resulting in lower emissions. The
lowest emission limit of 7.7 nanograms per Joule is reported for a small gas-fired boiler. All of the gas-
fired boilers are reported to employ a combination of combustion controls. Only two units fired with oil
are identified. These residual oil-fired boilers have permit levels of 52-164 nanograms per Joule
(approximately 30 to 100 ppm at 15 percent O2).
7.3.2 Selective Non-catalytic Reduction
As discussed in Section 6.3.3, SNCR has been widely applied to fluid bed combustion boilers and
wood-fired boilers. Other applications identified involve refinery heaters.
54
-------
TABLE 9. NOX CONTROL LEVELS - NON-UTILITY BOILERS AND HEATERSa-b
Ln
Control Technology
Combustion Controls0
Conventional
Coal
Fluid Bed
73-258 86 - 129
(40-145ppm)d (50-75 ppm)d
NOX Emission Limits (nanogram/Joule)
Wood Gas
7.7 - 43
(5 to 30 ppm)d
Oil
52 - 164
(30-100 ppm)d
Low excess air
Overfire air
Flue gas recirculation
Low NOX burners
Post Combustion Controls
Selective catalytic reduction
Selective noncatalytic reduction
60 - 250 ppm 213 ppm
(Japan) (Germany site
visit)
< — 43-114 > >
(25-65 ppm)d
13-21.5
(10- 15ppm)d
15-30
(Japan)
2L5
(15 ppm)d
25 - 50 ppm
(Japan)
64.5
(40 ppm)d
?Refer to Appendices C, E, and F for facility-specific data.
"Commercial applications in U.S., West Germany, and Japan.
°May involve concurrent application of more than one technology.
dAt 15 percent O2.
-------
For the wood and coal-fired SNCR applications, about 70 percent of the sites have NOX permit
levels of 43 nanograms per Joule (approximately 25 ppm at 15 percent O2) or less and the
remaining sites have permit emission levels of 45 to 202 nanograms per Joule (approximately 25
to 35 ppm at 15 percent O2). One site has a permit emission rate of 114 nanograms per Joule
(approximately 65 ppm at 15 percent O2), significantly higher than others.
Of the two heater/SNCR applications, the oil-fired steam generator has an emission limit of 65
nanograms per Joule (approximately 40 ppm at 15 percent O2) and the process heater has an
emission limit of 21.5 nanograms per Joule (approximately 15 ppm at 15 percent O2). The much
higher emission limit for the oil field generator is due to the fuel nitrogen content of the oil.
7.3.3 Selective Catalytic Reduction
On boilers and heaters, SCR has been applied at several gas-fired refinery process heaters and
a few gas-fired boilers; all permitted in California. Permit emission levels for all of the sites are 13 to
21.5 nanograms per Joule (approximately 10 to 15 ppm at 15 percent O2).
The coal-fired boiler site visited in West Germany employs three SCR units that started operation
in 1985 -1988 (see Appendix E). The permitted NOX levels are specified at 213 ppm. In Japan, SCR
has been applied to over 50 industrial boilers firing gas, oil, and coal (see Appendix F). Typical oil-fired
boiler NOX reductions range from 80 to 90 percent with emission levels of 25 to 50 ppm NOX. In coal-
fired boiler applications, emission reductions range from 40 to 80 percent with emissions of 60 to
250 ppm NOX. NOX reductions are 90 percent with emission levels of 15 to 30 ppm NOX for typical
gas-fired boiler applications.
7.4 MUNICIPAL WASTE AND SLUDGE INCINERATION
Table 10 summarizes the NOX control levels considered achievable by state agencies for waste
incinerators.
7.4.1 Combustion Controls
Emission levels for waste incinerators controlled by combustion controls range from 34 to 344
nanograms per Joule. Among the incinerator population controlled by combustion techniques,
there are no apparent trends based or oermit date. The majority of the incinerators have permit limits
between 108 and 258 nanograms per joule. The variation in permit levels is likely due to differences in
state BACT/LAER determinations relative to incinerator type.
56
-------
TABLE 10. NOV CONTROL LEVELS - WASTE INCINERATION3'5
NO Emission Limit
Control Technology (nanograms/Joule)
Combustion Controls 34 - 344
Boiler design
Overfire air
Post-Combustion Control
Selective catalytic reduction 21.5 - 43C
Selective non-catalytic reduction 32-146
^Refer to Appendices D and F for facility-specific information.
bCommercial applications in U.S. and Japan.
°Japanese applications.
7.4.2 Selective Non-catalytic Reduction
Permitted NOX emission limits for the seven sites identified range from 32 to 146 nanograms per
Joule. The tire burners have the lowest permit levels of 32 (California) and 52 (Connecticut)
nanograms per Joule.
7.4.3 Selective Catalytic Reduction (Japan)
Two waste incineration sites in Japan have operated with SCR systems since 1986. One
system reduces NOX by 45 - 55 percent for a flue gas having 100-150 ppm NOX resulting in an
emission rate less than 0.1 pounds per million Btu. The other system reduces NOX by 70 - 80 percent
for a flue gas having 100-160 ppm NOX resulting in an emission rate less than 21.5 nanograms per
Joule. There are 16 SCR units on plants incinerating sewage sludge in Japan (see Appendix F).
These systems obtain 80 - 90 percent NOX reduction also resulting in emission rates less than 21.5
nanograms per Joule.
57
-------
SECTION 6
REFERENCES
1. Bosch, H. and Janssen, F. Catalytic Reduction of Nitrogen Oxides. A Review on the
Fundamentals and Technology. Catalysis Today. Volume 2, No. 4, March 1988.
2. Johnson, R.H. and Wilkes, C.E. Emissions Performance of Utility and Industrial Gas Turbine.
Paper presented at the American Power Conference, April 23-25, 1979.
3. Roessler, W.U., et al. Assessment of the Applicability of Automotive Emission Control
Technology to Stationary Engines. EPA-650/2-74-051 (NTIS PB 237115), July 1974.
4. Chen, S.L., et al. Influence of Coal Composition on the Fate of Volatile and Char Nitrogen
During Combustion. 19th Symposium (International) on Combustion. Published by Combustion
Institute, Pittsburgh, PA, pp. 1271-1280, 1982. EPA-600/D-83-032 (NTIS PB83-183194). 1982.
5. U.S. Environmental Protection Agency. Standards Support and Environmental Impact
Statement. Volume 1: Proposed Standards of Performance for Stationary Gas Turbines.
Research Triangle Park, NC. EPA-450/2-77-017a (NTIS PB 272-422). September 1977.
6. U.S. Environmental Protection Agency. Stationary Internal Combustion Engines. Standards
Support and Environmental Impact Statement. Volume 1: Proposed Standards of
Performance. Research Triangle Park, NC. EPA-450/2-78-125a (NTIS PB83-113563).
January 1979.
7. U.S. Environmental Protection Agency. Control Techniques for Nitrogen Oxides Emissions from
Stationary Sources - Revised Second Edition. Research Triangle Park, NC. EPA-450/3-83-002
(NTIS PB84-118330). January 1983.
8. U.S. Environmental Protection Agency. Municipal Waste Combustors-Background Information
for Proposed Standards: Control of NOX Emissions, Vol. 4. Research Triangle Park, NC.
EPA-450/3-89-27d (NTIS PB90-154873). August 1989.
9. Clarke, M.J. Technologies for Minimizing the Emission of NOX from MSW Incineration. Paper
presented at the International Conference on Municipal Waste Combustion, Hollywood, FL.
April 11-14, 1989.
10. Angello, L. and Lowe, P. Gas Turbine Nitrogen Oxide (NOX) Control-Current Technologies and
Operating Experiences. In Proceedings: 1989 Joint Symposium on Stationary Combustion
NO Control. San Francisco, CA. March 6-9,1989, Vol. 2, EPA-600/9-89-062b (NTIS PB89-
220537), p. 9-19, June 1989.
11. Angello, L. and Lowe, P. Dry Low NOX Combustor Development for Electric Utility Gas Turbine
Applications - A Status Report. Paper presented at the 34th ASME International Gas Turbine
Conference. Toronto, Canada. June 4-8, 1989.
12. Trends in Low-NOx Combustion Design and Experience. Gas Turbine World. Vol. 20, No. 2.
March-April 1990. pp 12-15.
58
-------
13. Davis, Jr., L.B. Dry Low NOX Combustion for General Electric Heavy Duty Gas Turbines. In
Proceedings: 82nd A&WMA Annual Meeting. Vol. 5, Paper 89/75.4, 25 pp. Published by Air &
Waste Management Association. Pittsburgh, PA. 1989.
14. Siemens Getting Ready to Introduce a Family of Third-Generation Machines. Gas Turbine
World. Vol. 20, No. 4. July-August, 1990, pp 12-14.
15. Martin, R.R. and Johnson, W.M. NOX Control in Fired Heaters. Presented at 1984 Winter
National Meeting of American Institute of Chemical Engineers. Atlanta, GA. March 11-14,
1984.
16. Bortz, SJ. and Offen, G.R. Reburning with Low and Medium Btu Gases. In Proceedings:
1987 Joint Symposium on Stationary Source Combustion NCL Control (New Orleans, LA,
March 1987), Vol. 1, EPA-600/9-88-026a (NTIS PB89-139695), p. 12-1, December 1988.
17. Ando, J. NOX Abatement for Stationary Sources in Japan. EPA-600/7-79-205 (NTIS PB80-
113673). August 1979.
18. Personal Communication. Watkins, S., Radian Corporation, with K. Burns, Engelhard
Corporation. August 17, 1990.
19. Cer-NOx. Ceramic Molecular Sieve (SCR) NOX Abatement System. Steuler International
Corporation, Mertztown, PA. Undated.
20. Personal Communication. Stone, O.K., Radian Corporation, with S.M. Turner, Norton
Company, September 27,1989.
21. Yang. R.T., et al. Catalyst Poisoning in the Selective Catalytic Reduction Reaction. In
Proceedings: 1989 Joint Symposium on Stationary Combustion NCL Control, San Francisco,
CA, March 6-9, 1989, Vol. 2, EPA-600/9-89-062b, p. 8-1 (NTIS PB89-220537). June 1989.
22. Thring, R.H. and Hull, R.W. NOX Control Technology Database for Gas-Fueled Prime Movers,
Phase 1. Gas Research Institute, Chicago, IL Report No. GRI-87/0229. April 1988.
23.
Thermal DeNOx Process. Exxon Technology, Exxon Research and Engineering Company,
Florham Park, NJ. Undated.
24. Hofmann, J.E., et al. NOX Control in a Brown Coal-Fired Utility Boiler. In Proceedings: 1989
Joint Symposium on Stationary Combustion NOX Control, San Francisco, CA. March 6-9,
1989, Vol. 2, EPA-600/9-89-062b (NTIS PB89-220537), p. 7A-53, June 1989.
25. Environmental Catalyst Consultants, Inc., P.O. Box 637, Springhouse, PA. 19477
Phone 215-628-4447.
26. Keller, F.L. and Feit, E. Pfizer Cogeneration Plant Uses Advanced NO Abatement System,
Diesel and Gas Turbine Worldwide. June 1989.
27. Stambley, I. SCR Experience in U.S. Showing Better than Expected Performance, Gas Turbine
World, Vol. 20, No. 2, March-April 1990, pp. 16-21.
28. Riley, J.R., et al. Can Manufacturing Capacity Keep Up with New Orders for CTs? Power
Engineering, April 1990, pp 45-47.
59
-------
APPENDIX A
NOY CONTROL DATA
^
COMBUSTION TURBINES
A-1
-------
Description of Terms Used In the Following Table(s)
Facility ID:
Permit Date:
NQ, Primary Limit:
NOX Secondary Limit:
NQ, Control Efficiency:
Contact Name:
A/F:
FGR:
LNB:
LNC:
NSCR:
SCR:
SNCR:
Identifier used in the BACT/LAER Clearinghouse or region/county where
facility is located
Permit or start-up date (unit may be canceled after permit approval)
NO, permit limit
NQ, permit limit expressed in different units or for back-up fuel
NO, control efficiency as stated in the permit
State agency contact
Air to fuel ratio
Rue gas recirculation
Low NQ, burner
Low NO, combustion
Non-selective catalytic reduction
Selective catalytic reduction
Selective non-catalytic reduction
A-2
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
i>
FACILITY ID
AK-0004
AK-0005
AK-0008
AK-0018
AK-0012
AL-0040
ARTESIA
RICHMOND
BREA
MODESTO
SPRECKLES
EL SEGUNDO
GAVIOTA
WILMINGTON
CORONA
CORONA
CA-0274
CORONA
SAN FRANCISCO
MARTINEZ
KERN
NEWHALL
CA-0159
SANTA ANA
CA-0044
COMPANY NAME
PRUDHOE BAY CONSORTIUM
CHUGACH ELECTRIC ASSOCIATION, UNIT #4
ANCHORAGE MUNICIPAL LIGHT t POWER
ALASKA ELECTRICAL GENERATION ft TRANSMISSION
ALASKA ELECTRICAL GENERATION ft TRANSMISSION
CHAMPION INTERNATIONAL
O'BRIEN ENERGY SYSTEMS
CHEVRON
SANTA FE ENERGY
O'BRIEN ENERGY SYSTEMS
AMERICAN COGENERATION TECHNOLOGY
CHEVRON
CHEVRON
COGENERATION COMPANY
CORONA COGENERATION, INCORPORATED
GRISWOLD CONTROLS
MOJAVE COGENERATION CO., L.P.
O'BRIEN ENERGY SYSTEMS
UNITED AIR LINES
MARTINEZ COGENERATION
KERN BLUFF LTD
TENNECO
SIERRA LTD.
KLONDIKE EQUALITY ENTERPRISES
CROWN ZELLERBACH, INC.
FACILITY SIZE
303 MHP
26 MW
82 MW
38 MW
80 MW
35 MW
22.2 MW
99 MW
11.6 MW
40.9 MW
57.6 MW
77 MW
17.5 MW
3.3 MW
48 MW
49.7 MW
26.7 MW
21.8 MW
50 MW
48.6 HW
22 MW
11.34 MMCF/D
22 MW
32 MW
NOX PRIMARY
PERMIT DATE PERMIT LIMIT
09/29/81 150 PPM
08/06/82 130 LB/H
10/15/84 75 PPM AT 15X 02, DRY
03/29/85 75 PPM AT 15X 02
03/18/87 75 PPMVD AT 15X 02
11/30/88 42 PPM AT 15X 02
9 PPMV AT 15X 02
10 PPMV AT 15X 02
9 PPMV AT 15X 02
5 PPMV AT 15X 02
7 PPMV AT 15X 02
90X REDUCTION
19 PPMV AT 15X 02
9 PPMV AT 15X 02
6 PPMV AT 15X 02
9 PPMV AT 15X 02
10 PPMV AT 15X 02, DRY, GAS FIRING
9 PPMV AT 15X 02
16 PPMV AT 15X 02
25 PPMV AT 15X 02
5 PPMV AT 15X 02
9 PPMV AT 15X 02
4.04 LB/H EA
9 PPMV AT 15X 02
03/01/82 42 PPM N02 AT 15X 02
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
FACILITY ID
AK-0004
AK-0005
AK-0008
AK-0018
AK-0012
AL-0040
ARTESIA
RICHMOND
BREA
MODESTO
SPRECKLES
EL SEGUNDO
GAVIOTA
WILMINGTON
CORONA
CORONA
CA-0274
CORONA
SAN FRANCISCO
MARTINEZ
KERN
NEWHALL
CA-0159
SANTA ANA
CA-0044
COMPANY NAME
PRUDHOE BAY CONSORTIUM
CHUGACH ELECTRIC ASSOCIATION, UNIT #4
ANCHORAGE MUNICIPAL LIGHT ft POWER
ALASKA ELECTRICAL GENERATION t TRANSMISSION
ALASKA ELECTRICAL GENERATION I TRANSMISSION
CHAMPION INTERNATIONAL
O'BRIEN ENERGY SYSTEMS
CHEVRON
SANTA FE ENERGY
O'BRIEN ENERGY SYSTEMS
AMERICAN COGENERATION TECHNOLOGY
CHEVRON
CHEVRON
COGENERATION COMPANY
CORONA COGENERATION, INCORPORATED
GRISWOLD CONTROLS
MOJAVE COGENERATION CO., L.P.
O'BRIEN ENERGY SYSTEMS
UNITED AIR LINES
MARTINEZ COGENERATION
KERN BLUFF LTD
TENNECO
SIERRA LTD.
KLONDIKE EQUALITY ENTERPRISES
CROWN ZELLERBACH, INC.
NOX SECONDARY
PERMIT LIMIT NOX
DRY CONTROLS
569 T/YR WATER INJECTION
WET CONTROLS
H20 INJECTION
H20 INJECTION
67 LB/H STEAM INJECTION
SCR
SCR
SCR
SCR
SCR
SCR
SCR
SCR
SCR
SCR
CONTROL
40 PPMV AT 15X 02, DRY, OIL FIRED SCR AND STEAM INJECTION
SCR
SCR
SCR
SCR
SCR
0.016 LB/HMBTU STEAM INJECTION
SCR
& SCR
WATER/STEAM INJECTION
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
01
FACILITY ID
AK-0004
AK-0005
AK-0008
AK-0018
AK-0012
AL-0040
ARTESIA
RICHMOND
BREA
MODESTO
SPRECKLES
EL SEGUNDO
GAVIOTA
WILMINGTON
CORONA
CORONA
CA-0274
CORONA
SAN FRANCISCO
MARTINEZ
KERN
NEWHALL
CA-0159
SANTA ANA
CA-0044
COMPANY NAME
PRUDHOE BAY CONSORTIUM
CHUGACH ELECTRIC ASSOCIATION, UNIT #4
ANCHORAGE MUNICIPAL LIGHT ft POWER
ALASKA ELECTRICAL GENERATION ft TRANSMISSION
ALASKA ELECTRICAL GENERATION t TRANSMISSION
CHAMPION INTERNATIONAL
O'BRIEN ENERGY SYSTEMS
CHEVRON
SANTA FE ENERGY
O'BRIEN ENERGY SYSTEMS
AMERICAN COGENERATION TECHNOLOGY
CHEVRON
CHEVRON
COGENERATION COMPANY
CORONA COGENERATION, INCORPORATED
GRISWOLD CONTROLS
MOJAVE COGENERATION CO., L.P.
O'BRIEN ENERGY SYSTEMS
UNITED AIR LINES
MARTINEZ COGENERATION
KERN BLUFF LTD
TENNECO
SIERRA LTD.
KLONDIKE EQUALITY ENTERPRISES
CROWN ZELLERBACH, INC.
NOX CONTROL
EFFICIENCY CONTACT NAME PHONE NUMBER
DAVID TETTA (206)-442-1193
PAUL BOYS (206)-442-1567
DAVE ESTES (907)-465-2666
JON SANDSTEDT (907) -465 -2666
JON SANDSTEDT (907)-465-2666
70 KEN BARRETT (205)-271-7861
LINK TRAN (415)-974-7631
95.86 TOM PAXSON (805)-861-3682
DOUG WOLF (415)-771-6000
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
6)
FACILITY ID
CA-0047
CA-0084
CA-0046
CA-0098
CA-0064
CA-0095
CA-0095
CA-0105
CA-0111
CA-0109
CA-0139
CA-0144
CA-0112
CA-0067
CA-0147
CA-0122
KERN
MONTEREY BAY
CA-0115
CA-0155
CA-0221
CA-0167
CA-0136
CA-0137
CA-0138
COMPANY NAME
SOUTHERN CALIF. EDISON CO.
CARDINAL COGEN
TOSCO CORP.
SIMPSON COGENERATION PROJECT
UNIVERSITY CO-GENERATION LTD., 1983-1
NORTHERN CALIFORNIA POWER AGENCY
NORTHERN CALIFORNIA POWER AGENCY
IBM COGENERATION PROJECT
WITCO CHEMICAL CORP.
GETTY OIL CO.
NORTHERN CALIFORNIA POWER
WILLAMETTE INDUSTRIES
SHELL CALIFORNIA PRODUCTION CO.
PROCTOR t GAMBLE
SUNLAW/INDUSTRIAL PARK 2
GILROY ENERGY CO.
AMERICAN COGENERATION CORPORATION
AMERICAN COGEN TECHNOLOGY
ENERGY RESERVE, INC.
UNION COGENERATION
AES PLACER ITA, INC.
WESTERN POWER SYSTEM, INC.
KERN ENERGY CORP.
SOUTHEAST ENERGY, INC.
MORAN POWER, INC.
FACILITY SIZE
64.5 MW EA
464.4 MMBTU/H
500 MMBTU/H
3.08 MMBTU/H
38.7 MW
25.8 MW
25.8 MW
49 MW
350 MMBTU/H
3.5 MW
25.8 MW
230 MMBTU/H
22 MW
217 MMBTU/H
412.3 MMBTU/H
60 MW
23 MMBTU/HR
220.4 MMBTU/HR
322.5 MMBTU/H
16 MW
519 MMBTU/H
26.5 MW
8.8 MMCF/D
8 MMCF/D
8 MMCF/D
PERMIT DATE
04/25/83
06/29/83
12/13/83
01/06/84
03/21/84
09/05/84
09/05/84
12/01/84
12/19/84
03/29/85
04/01/85
04/26/85
04/30/85
06/07/85
06/28/85
08/01/85
09/12/85
09/16/85
10/04/85
01/17/86
03/10/86
03/15/86
04/18/86
04/18/86
04/18/86
NOX PRIMARY
PERMIT LIMIT
44.5 PPM
42 PPM AT 15X 02
45 PPM AT 15X 02
3264 LB/D
199 LB/D
62 PPMD AT 15X 02
42 PPMD AT 15X 02
25 PPM AT 15X 02
0.18 LB/MMBTU OIL
7.6 LB/H
75 PPM
15 PPMVD AT 15X 02
42 PPM AT 15X 02
62 PPM AT 15X 02, OIL
9 PPMVD AT 15X 02
25 PPMDV AT 15X 02
10 PPMV AT 15X 02
17 PPMV AT 15X 02
185.4 LB/D
25 PPMV AT 15X 02
629 LB/D
9 PPMVD AT 15X 02
8.29 LB/H
8.29 LB/H
8.29 LB/H
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
FACILITY ID
COMPANY NAME
NOX SECONDARY
PERMIT LIMIT
NOX CONTROL
CA-0047 SOUTHERN CALIF. EDISON CO.
CA-0084 CARDINAL COGEN
CA-0046 TOSCO CORP.
CA-0098 SIMPSON COGENERATION PROJECT
CA-0064 UNIVERSITY CO-GENERATION LTD., 1983-1
CA-0095 NORTHERN CALIFORNIA POWER AGENCY
CA-0095 NORTHERN CALIFORNIA POWER AGENCY
CA-010S IBM COGENERATION PROJECT
CA-0111 UITCO CHEMICAL CORP.
CA-0109 GETTY OIL CO.
CA-0139 NORTHERN CALIFORNIA POWER
CA-OH4 WILLAMETTE INDUSTRIES
CA-0112 SHELL CALIFORNIA PRODUCTION CO.
CA-0067 PROCTOR ft GAMBLE
CA-OU7 SUNLAU/INDUSTRIAL PARK 2
CA-0122 GILROY ENERGY CO.
KERN AMERICAN COGENERATION CORPORATION
MONTEREY BAY AMERICAN COGEN TECHNOLOGY
CA-0115 ENERGY RESERVE, INC.
CA-0155 UNION COGENERATION
CA-0221 AES PLACERITA, INC.
CA-0167 WESTERN POWER SYSTEM, INC.
CA-0136 KERN ENERGY CORP.
CA-0137 SOUTHEAST ENERGY, INC.
CA-0138 MORAN POWER, INC.
140 LB/H/TURBINE
75 LB/H
0.2 LB/MMBTU GAS
195 PPMVD AT 15X 02
35 LB/H
7 PPMVD AT 15X
0.023 LB/MMBTU
0.023 LB/MMBTU
0.02 LB/MMBTU
WATER INJECTION
STEAM INJECTION
STEAM INJECTION
H20 INJECTION, SCR
H20 INJECTION
H20 INJECTION
H20 INJECTION; SCR
H20 INJECTION
H20 INJ
H20 INJ. W/SELECTIVE CATALYTIC REDUCTION
H20 INJECTION
H20 INJECTION
SCR & STEAM INJ.
STEAM INJ./QUIET COMBUSTOR
SCR
SCR
WATER INJECTION & SELECTIVE CATALYTIC REDUCTION
H20 INJECTION & SCR
H20 INJECTION AND SCR
H20 INJECTION, SELECTIVE CAT. REDUCTION
STEAM INJ. & LOW NOX CONFIG.; SCR
STEAM INJ. & LOW NOX CONFIG.; SCR
STEAM INJ. & LOW NOX CONFIG.; SCR
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
A>
FACILITY ID
CA-0047
CA-0084
CA-0046
CA-0098
CA-0064
CA-0095
CA-0095
CA-0105
CA-0111
CA-0109
CA-0139
CA-0144
CA-0112
CA-0067
CA-0147
CA-0122
KERN
MONTEREY BAY
CA-0115
CA-0155
CA-0221
CA-0167
CA-0136
CA-0137
CA-0138
COMPANY NAME
SOUTHERN CALIF. EDISON CO.
CARDINAL COGEN
TOSCO CORP.
SIMPSON COGENERATION PROJECT
UNIVERSITY CO-GENERATION LTD., 1983-1
NORTHERN CALIFORNIA POWER AGENCY
NORTHERN CALIFORNIA POWER AGENCY
IBM COGENERATION PROJECT
WITCO CHEMICAL CORP.
GETTY OIL CO.
NORTHERN CALIFORNIA POWER
WILLAMETTE INDUSTRIES
SHELL CALIFORNIA PRODUCTION CO.
PROCTOR t GAMBLE
SUNLAW/ INDUSTRIAL PARK 2
GILROY ENERGY CO.
AMERICAN COGENERATION CORPORATION
AMERICAN COGEN TECHNOLOGY
ENERGY RESERVE, INC.
UNION COGENERATION
AES PLACERITA, INC.
WESTERN POWER SYSTEM, INC.
KERN ENERGY CORP.
SOUTHEAST ENERGY, INC.
MORAN POWER, INC.
NOX CONTROL
EFFICIENCY
97
92
80
87
60
92.5
80
87
87
87
CONTACT NAME
MATT HABER
RICK SUGAREK
MATT HABER
BRIAN YEH
TOM PAXSON
KEN SELOVER
KEN SELOVER
VICTOR REYES
JIM HANSON
TOM PAXSON
R. SWAN
KEITH DUVAL
TOM PAXSON
JIM HANSON
BOB PEASE
JIM HANSON
THOMAS PAXSON
F. THOITS
TOM PAXSON
STEVE HILL
ROBERT PEASE
SIMEON BUGAY
TOM PAXSON
TOM PAXSON
TOM PAXSON
PHONE NUMBER
(415)-974-8209
(415)-974-7631
(415)-974-8209
(818)-572-6256
(805)-861-3682
(916) -823-4443
(916) -823-4443
(415)-771-6000
(415)-974-8218
(B05)-861-3682
(707)-463-4391
(805) -654-2845
(805) -861 -3682
(415)-974-8218
(818)-572-6174
(415)-974-8218
(805)-861-3682
(408) -443- 1135
(805)-861-3682
(415)-771-6000
(818)-572-6174
(209)-443-3239
(805)-861-3682
(805) -861 -3682
(805)-861-3682
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
CD
FACILITY ID
CA-0289
CA-0288
CA-0162
CA-0163
CA-0164
CA-0189
CA-0192
CA-0177
S. COAST AQMD
CA-0186
CA-0251
CA-0230
CA-0221
CA-0221
CA-0249
CA-0262
CA-0262
CA-0262
CA-0179
CA-0179
CA-0297
CA-0293
CA-0296
CA-0273
CA-0335
COMPANY NAME
MONARCH COGENERATION
MONARCH COGENERATION
PG t E, STATION T
DOUBLE 'C' LIMITED
KERN FRONT LIMITED
O'BRIEN ENERGY SYSTEMS/MERCHANTS REF.
CITY OF SANTA CLARA
MIDWAY - SUNSET PROJECT
CALIFORNIA INSTITUTE OF TECHNOLOGY
U.S. BORAX ft CHEMICAL CORP.
SAN JOAQUIN COGEN LIMITED
POWER DEVELOPMENT CO.
AES PLACER I TA, INC.
AES PLACERITA, INC.
BAF ENERGY
MIDWAY-SUNSET COGENERATION CO.
MIDWAY-SUNSET COGENERATION CO.
MIDWAY-SUNSET COGENERATION CO.
COMBINED ENERGY RESOURCES
COMBINED ENERGY RESOURCES
MOBIL OIL
MOBIL EXPLORATION & PRODUCING US, INC.
TEXACO-YOKUM COGENERATION PROJECT
MOJAVE COGENERATION CO.
CITY OF ANAHEIM GAS TURBINE PROJECT
FACILITY SIZE
92.2 MMBTU/H
92.2 MMBTU/H
396 MMBTU/H
25 MW
25 MW
359.5 MMBTU/H
973 MMBTU/H
4.29 MW
45 MW
48.6 MW
49 MMBTU/H
530 MMBTU/H
530 MMBTU/H
887.2 MMBTU/H
75 MW
75 MW
75 MW
2 KU
25.94 MW
81.4 MMBTU/H
3.11 MW
24.5 MW
490 MMBTU/H
442 MMBTU/H
PERMIT DATE
04/18/86
04/18/86
08/25/86
11/04/86
11/04/86
12/30/86
01/05/87
01/06/87
01/20/87
02/20/87
06/19/87
06/22/87
07/02/87
07/02/87
07/08/87
01/27/88
01/27/88
01/27/88
02/26/88
02/26/88
09/27/88
09/27/88
11/01/88
01/12/89
09/15/89
NOX PRIMARY
PERMIT LIMIT
192.5 LB/D
192.5 LB/D
25 PPM AT 15X 02
193.98 LB/D, TOTAL
193.98 LB/D, TOTAL
30.3 LB/H
42 PPMVD AT 15X 02
113.4 LB/H EA
9 PPMV AT 15X 02
40 LB/H
250 LB/D
36 LB/D
289 LB/D
340 LB/D
9 PPM AT 15X 02
B5 LB/H EA, NAT GAS
85 LB/H EA, NAT GAS
85 LB/H EA, NAT GAS
199 LB/H
199 LB/D
90.7 LB/D
91 LB/D
190 LB/D
0.031 LB/MMBTU, GAS
90 LB/D
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
FACILITY ID
CA-0289
CA-0288
CA-0162
CA-0163
CA-0164
COMPANY NAME
MONARCH COGENERATION
MONARCH COGENERATION
PG ft E, STATION T
DOUBLE 'C' LIMITED
KERN FRONT LIMITED
NOX SECONDARY
PERMIT LIMIT
22 PPMVD AT 15X 02
22 PPMVD AT 15X 02
63 LB/H
4.5 PPMVD AT 15X 02
SCR
SCR
STEAM INJ.
H20 INJ. &
H20 INJ. &
NOX CONTROL
AT STEAM/FUEL RATK
SELECTED CATALYTIC
SELECTED CATALYTIC
) = 1.7/1
REDUCTION
REDUCTION
CA-0189 O'BRIEN ENERGY SYSTEMS/MERCHANTS REF.
CA-0192 CITY OF SANTA CLARA
CA-0177 MIDWAY - SUNSET PROJECT
S. COAST AQMD CALIFORNIA INSTITUTE OF TECHNOLOGY
CA-0186 U.S. BORAX ft CHEMICAL CORP.
CA-02S1 SAN JOAQUIN COGEN LIMITED
CA-0230 POWER DEVELOPMENT CO.
CA-0221 AES PLACERITA, INC.
CA-0221 AES PLACERITA, INC.
CA-0249 BAF ENERGY
CA-0262 MIDWAY-SUNSET COGENERATION CO.
CA-0262 MIDWAY-SUNSET COGENERATION CO.
CA-0262 MIDWAY-SUNSET COGENERATION CO.
CA-0179 COMBINED ENERGY RESOURCES
CA-0179 COMBINED ENERGY RESOURCES
CA-0297 MOBIL OIL
CA-0293 MOBIL EXPLORATION ft PRODUCING US, INC.
CA-0296 TEXACO-YOKUM COGENERATION PROJECT
CA-0273 MOJAVE COGENERATION CO.
CA-0335 CITY OF ANAHEIM GAS TURBINE PROJECT
15 PPMVD AT 15X 02
16.31 PPMV
25 PPM AT 15X 02 DRY
6 PPMVD AT 15X 02
9 PPMVD AT 15X 02
9 PPMVD AT 15X 02
9 PPMVD AT 15X 02
30.1 LB/H
140 LB/H EA, OIL FIRING
140 LB/H EA, OIL FIRING
140 LB/H EA, OIL FIRING
0.047 LB/MHBTU
0.047 LB/MHBTU
0.031 LB/MMBTU
0.15 LB/MHBTU, OIL
H20 INJ., & SCR
WATER INJECTION
H20 INJECTION
SCR
WATER/STEAM INJECTION; SCR
H20 INJECTION AND FLUE GAS RECIRCULATION
H20 INJECTION AND SCR
STEAM INJECTION AND SCR
STEAM INJECTION AND SCR
STEAM INJECTION AND SCR
H20 INJ., "QUIET COMBUSTOR"
H20 INJ., "QUIET COMBUSTOR"
H20 INJ., "QUIET COMBUSTOR"
WATER INJECTION AND SCR
H20 INJ, LOW NOX DESIGN; SCR
H20 INJECTION MOLECULAR SIEVE TYPE CATALYST
H20 INJECTION AND SCR
STEAM INJECTION AND SCR
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
FACILITY ID
CA-0289
CA-0288
CA-0162
CA-0163
CA-0164
CA-0189
CA-0192
CA-0177
S. COAST AOMO
CA-0186
COMPANY NAME
MONARCH COGENERATION
MONARCH COGENERATION
PC t E, STATION T
DOUBLE 'C' LIMITED
KERN FRONT LIMITED
O'BRIEN ENERGY SYSTEMS/MERCHANTS REF.
CITY OF SANTA CLARA
MIDWAY - SUNSET PROJECT
CALIFORNIA INSTITUTE OF TECHNOLOGY
U.S. BORAX t CHEMICAL CORP.
NOX CONTROL
EFFICIENCY
75
95.8
95.8
73
80
CONTACT NAME
TOM PAXSON
TOM PAXSON
LINH TRAN
TOM PAXSON
TOM PAXSON
DAVID CRAFT
ELLEN LINDER
TOM PAXSON
BRIEN YEH
LINH TRAN
PHONE NUMBER
<805)-861-3682
(805)-861-3682
(415)-974-7631
(805) -861 -3682
(805)-861-3682
(408) -443- 1135
(415)-771-6000
(805) -861 -3682
(818)-572-6256
(415)-974-7631
CA-0251 SAN JOAQUIN COGEN LIMITED
CA-0230 POWER DEVELOPMENT CO.
CA-0221 AES PLACER1TA, INC.
CA-0221 AES PLACERITA, INC.
CA-0249 BAF ENERGY
76 SEYED SADREDIN (209)-468-3474
WILLIAM THOMPSON (818)-572-6185
ROBERT PEASE (818)-572-6174
ROBERT PEASE (818)-572-6174
80 FRED THOITS (408)-443-1135
CA-0262
CA-0262
CA-0262
CA-0179
CA-0179
MIDWAY-SUNSET COGENERATION CO.
MIDWAY-SUNSET COGENERATION CO.
MIDWAY-SUNSET COGENERATION CO.
COMBINED ENERGY RESOURCES
COMBINED ENERGY RESOURCES
81
81
SHIRLEY RIVERA
SHIRLEY RIVERA
SHIRLEY RIVERA
TOM PAXSON
TOM PAXSON
(415)-974-7043
(415)-974-7043
(415)-974-7043
(805)-861-3682
(805)-861-3682
CA-0297 MOBIL OIL
CA-0293 MOBIL EXPLORATION & PRODUCING US, INC.
CA-0296 TEXACO-YOKUM COGENERATION PROJECT
CA-0273 MOJAVE COGENERATION CO.
CA-0335 CITY OF ANAHEIM GAS TURBINE PROJECT
65
69.6
F. THOITS
F. THOITS
F. THOITS
TOM PAXSON
(408)-443-1135
(408)-722-7879
(408)-443-1135
(805)-861-3682
FRED DEL ROSARIO (818)-572-6439
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
to
FACILITY ID
CA-0320
CA-0318
CO-0015
CT-0027
CT-0031
CT-0022
CT-0022
CT-0025
DE-0006
FL-0029
FL-0042
FL-0043
KS-0009
KY-0048
LA-0053
LA-0011
LA-0054
MI -0054
MI -0053
Ml -0053
MI -0053
MI -0082
NC-0051
NC-0051
NC-0051
COMPANY NAME
BADGER CREEK LIMITED
O'BRIAN CALIFORNIA COGEN II, LIMITED
C I HARROW CHEMICAL INC.
DOWNTOWN COGENERATION ASSOC.
CCF-1
O'BRIEN COGENERATION
O'BRIEN COGENERATION
CAPITOL DISTRICT ENERGY CENTER
DELMARVA POWER
K1SSIMMEE UTILITIES
ORLANDO UTILITIES COMMISSION
TROPICANA PRODUCTS, INC.
VULCAN MATERIALS CO.
TEXAS GAS TRANSMISSION CORP.
APPLIED ENERGY SERVICES
DOW CHEMICAL, USA
BASF WYANDOTTE CO.
MIDLAND COGENERATION VENTURE
GREAT LAKES GAS TRANSMISSION
GREAT LAKES GAS TRANSMISSION
GREAT LAKES GAS TRANSMISSION
ADA COGENERATION
PANDA-ROSEMARY CORP.
PANDA- ROSEMARY CORP.
PANDA-ROSEMARY CORP.
FACILITY SIZE
457.8 MMBTU/H
49.5 MW
271 MMBTU/H
71.9 MMBTU/H
110 MMBTU/H GAS
499.9 MMBTU/H
499.9 MMBTU/H
738.8 MMBTU/H
100 MW
400 MMBTU/H
35 MW
45.4 MW
39.1 MW
14300 HP
1412.5 MMBTU/H
100 MW
394.7 MMBTU/H
984.2 MMBTU/H
4000 HP
12500 HP
12500 HP
245 MMBTU/H
1047 MMBTU/H GAS
499 MMBTU/H GAS
1060 MMBTU/H OIL
PERMIT DATE
10/30/89
01/04/90
08/01/89
08/19/87
05/18/88
08/08/88
08/08/88
10/23/89
08/23/88
03/30/84
09/01/88
05/30/89
07/23/81
02/26/88
11/14/83
09/13/84
02/16/88
02/16/88
02/16/88
02/16/88
06/21/88
09/06/89
09/06/89
09/06/89
NOX PRIMARY
PERMIT LIMIT
0.0135 LB/MMBTU
350.4 LB/D
65 PPMV AT 15X 02
42 PPMVD AT 15X 02
36 PPMVD AT 15X 02
39 PPMVD AT 15X 02
39 PPMVD AT 15X 02
42 PPMVD AT 15X 02
42 PPM
79 PPM GAS FIRED
42 PPM AT 15X 02, i
42 PPMDV AT 15X 02
NSPS
0.015 X BY VOLUME
414 LB/H
1194 LB/H
330 LB/H
42 PPMDV AT 15X 02
42 PPMDV AT 15X 02
173 LB/H
83 LB/H
277 LB/H
GASFIRING
GASFIRING
GASFIRED
GASFIRED
GASFIRING
GAS
, 1HAVG
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
FACILITY ID
COMPANY NAME
NOX SECONDARY
PERMIT LIMIT
NOX CONTROL
CA-0320 BADGER CREEK LIMITED
CA-0318 O'BRIAN CALIFORNIA COGEN II, LIMITED
CO-001S CIHARROW CHEMICAL INC.
CT-0027 DOWNTOWN COGENERATION ASSOC.
CT-0031 CCF-1
14.6 LB/H
62 PPMVD AT 15X 02 OILFIRING
63 PPMVD AT 15X 02 OILFIRING
STEAM INJECTION AND SCR
SCR
STEAM
WATER INJECTION
WATER INJECTION
co
CT-0022
CT-0022
CT-0025
DE-0006
FL-0029
FL-0042
FL-0043
KS-0009
KY-0048
LA-0053
LA-0011
LA-0054
MI-0054
MI-0053
MI-0053
O'BRIEN COGENERATION
O'BRIEN COGENERATION
CAPITOL DISTRICT ENERGY CENTER
DELMARVA POWER
KISSIMMEE UTILITIES
ORLANDO UTILITIES COMMISSION
TROPICANA PRODUCTS, INC.
VULCAN MATERIALS CO.
TEXAS GAS TRANSMISSION CORP.
APPLIED ENERGY SERVICES
DOW CHEMICAL, USA
BASF WYANDOTTE CO.
MIDLAND COGENERATION VENTURE
GREAT LAKES GAS TRANSMISSION
GREAT LAKES GAS TRANSMISSION
40 PPMVD AT 15X 02 OILFIRED
40 PPMVD AT 15X 02 OILFIRED
62 PPMVD AT 15X 02 OILFIRING
129 PPM OIL FIRED
65 PPM AT 15X 02 OIL
1813 T/YR
188 PPMV
WATER INJECTION
WATER INJECTION
STEAM INJECTION
LOW NOX BURNER/H20 INJ.
WATER INJECTION
STEAM INJECTION
STEAM INJECTION
COMB. CONTRL
COMBUSTOR DESIGN
STEAM INJ
MI-0053
MI-0082
NC-0051
NC-0051
NC-0051
GREAT LAKES GAS TRANSMISSION
ADA COGENERATION
PANDA-ROSEMARY CORP.
PANDA-ROSEMARY CORP.
PANDA-ROSEMARY CORP.
0.17 LB/MMBTU
0.17 LB/MMBTU
0.26 LB/MMBTU
H20 INJECTION
H20 INJECTION
H20 INJECTION
H20 INJECTION
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
FACILITY ID
CA-0320
CA-0318
CO-0015
CT-0027
CT-0031
CT-0022
CT-0022
CT-0025
DE-0006
FL-0029
FL-0042
FL-0043
KS-0009
KY-0048
LA-0053
LA-0011
LA-0054
MI -0054
MI -0053
MI -0053
MI -0053
MI -0082
NC-0051
NC-0051
NC-0051
COMPANY NAME
BADGER CREEK LIMITED
O'BRIAN CALIFORNIA COGEN II, LIMITED
CIMARRON CHEMICAL INC.
DOWNTOWN COGENERATION ASSOC.
CCF-1
O'BRIEN COGENERATION
O'BRIEN COGENERATION
CAPITOL DISTRICT ENERGY CENTER
DELMARVA POWER
KISSIMMEE UTILITIES
ORLANDO UTILITIES COMMISSION
TROPICANA PRODUCTS, INC.
VULCAN MATERIALS CO.
TEXAS GAS TRANSMISSION CORP.
APPLIED ENERGY SERVICES
DOW CHEMICAL, USA
BASF WYANDOTTE CO.
MIDLAND COGENERATION VENTURE
GREAT LAKES GAS TRANSMISSION
GREAT LAKES GAS TRANSMISSION
GREAT LAKES GAS TRANSMISSION
ADA COGENERATION
PANDA-ROSEMARY CORP.
PANDA-ROSEMARY CORP.
PANDA-ROSEMARY CORP.
NOX CONTROL
EFFICIENCY CONTACT NAME
TOM PAXSON
DAVID CRAFT
CATHY RHODES
MARK HULTMAN
MARK HULTMAN
MARK HULTMAN
MARK HULTMAN
MARK HULTMAN
J. CUGNINI
40 TERESA HERON
BARRY ANDREWS
BARRY ANDREWS
CHARLES WHITMORE
JAMES DILLS
NAN KILLEEN
BHARAT CONTRACTOR
BHARAT CONTRACTOR
GREGORY EDWARDS
LINDA WARDELL
LINDA WARDELL
LINDA WARDELL
59 DHRUMAN SHAH
SAMMY AMERSON
SAMMY AMERSON
SAMMY AMERSON
PHONE NUMBER
(805)-861-3682
(408)-443-1135
(303)-331-8593
(203)-566-8230
(203)-566-8230
(203)-566-8230
(203) -566-8230
(203) -566- 8230
(302)-736-4791
(904)-488-1344
(904) -488- 1344
(904) -488- 1344
(913)-551-7020
(502)-564-3382
(504) -342-8940
(504)-342-8940
(504)-342-8940
(517)-373-7023
(517)-373-7023
(517)-373-7023
(517)-373-7023
(517)-373-7023
(919)-733-3340
(919)-733-3340
(919)-733-3340
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
FACILITY 10
NC-0051
NJ-0006
NJ-0008
NV-0003
NV-0005
NY-0013
NY-0027
NY -0026
NY -0022
NY-0024
NY -0031
NY -0032
NY -0029
NY-0037
NY-0038
NY
NY -0033
NY
NY -0040
NY -0039
NY- 0036
OR -0006
PA-0027
PA-0052
R 1-0004
COMPANY NAME
PANDA-ROSEMARY CORP.
CIBA-GEIGY CORP.
COGEN TECHNOLOGIES
NEVADA PWR CO.. CLARK STATION UNIT *7
NEVADA PWR CO., CLARK STATION UNIT 08
TBG/GRUMMAN
TRIGEN
KAMINE CARTHAGE
KAMINE SOUTH GLENS FALLS
LONG ISLAND LIGHTING CO.
INDECK - YERKS ENERGY SERVICES, INC.
L & J ENERGY SYSTEM COGENERATION
INDEC/OSWEGO HILL COGENERATION
MEGAN-RACINE ASSOCIATES, INC.
EMPIRE ENERGY - NIAGARA COGENERATION CO.
KAMINE NATURAL DAM
KAMINE SYRACUSE COGENERATION CO.
GAS SYRACUSE
JMC SELKIRK, INC.
FULTON COGENERATION ASSOCIATES
ONE I DA COGENERATION FACILITY
PACIFIC GAS TRANSMISSION CO.
TEXAS EASTERN TRANSMISSION CO.
AMTRAK
OCEAN STATE POWER
FACILITY SIZE
509 MMBTU/H OIL
4000 HP
40 MW
73.5 MW
73.5 MW
16 MW
193 MMBTU/H
113 MMBTU/H
40 MW
75 MW
40 MW
40 MW
40 MW
430 MMBTU/H
416 HMBTU/H
50 MW
79 MW
79 MW
80 HW
500 MMBTU/H
417 HMBTU/H
14000 HP
18500 HP
20 MW
1059 HHBTU/H
PERMIT DATE
09/06/89
01/03/85
06/03/87
10/01/79
09/11/80
03/10/88
07/01/88
07/01/88
09/01/88
11/01/88
11/04/88
01/15/89
02/07/89
03/06/89
05/02/89
08/09/89
09/01/89
09/15/89
11/21/89
01/29/90
02/26/90
05/19/87
07/07/82
10/12/88
12/13/88
NOX PRIMARY
PERMIT LIMIT
134 LB/H
11.06 LB/H
9.6 PPMVD AT 15X 02
0.34 LB/MMBTU
0.34 LB/MMBTU
75 PPM + NSPS CORREC
0.2 LB/MMBTU
0.1 LB/MMBTU, GAS
42 PPM, GAS
55 PPM
42 PPM AT 15X 02, GAS
42 PPM AT 15X 02, GAS
42 PPM AT 15X 02, GAS
42 PPM GAS
42 PPM GAS FIRING
42 PPMV
36 PPM, NAT GAS
25 PPMV
25 PPM GAS FIRING
36 PPM GAS FIRING
32 PPM GAS
154 PPM
150 PPM
42 PPM AT 15X 02
9 PPMVD AT 15X 02
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
O>
FACILITY ID
NC-0051
NJ-0006
NJ-0008
NV-0003
NV-0005
NY-0013
NY-0027
NY -0026
NY -0022
NY-0024
NY -0031
NY -0032
NY-0029
NY- 0037
NY -0038
NY
NY -0033
NY
NY -0040
NY-0039
NY-0036
OR -0006
PA-0027
PA -005 2
R I -0004
COMPANY NAME
PANDA -ROSEMARY CORP.
CIBA-GEIGY CORP.
COGEN TECHNOLOGIES
NEVADA PWR CO., CLARK STATION UNIT #7
NEVADA PWR CO., CLARK STATION UNIT «8
TBG/GRUMMAN
TRIGEN
KAMINE CARTHAGE
KAMINE SOUTH GLENS FALLS
LONG ISLAND LIGHTING CO.
INDECK - YERKS ENERGY SERVICES, INC.
L * J ENERGY SYSTEM COGENERATION
1NDEC/OSWEGO HILL COGEHERAT10N
MEGAN-RACINE ASSOCIATES, INC.
EMPIRE ENERGY - NIAGARA COGENERATION CO.
KAMINE NATURAL DAM
KAMINE SYRACUSE COGENERATION CO.
GAS SYRACUSE
JMC SELKIRK, INC.
FULTON COGENERATION ASSOCIATES
ONE1DA COGENERATION FACILITY
PACIFIC GAS TRANSMISSION CO.
TEXAS EASTERN TRANSMISSION CO.
AMTRAK
OCEAN STATE POWER
NOX SECONDARY
PERMIT LIMIT
0.26 LB/MMBTU
0.2 LB/MMBTU
0.145 LB/MMBTU, KEROSENE
65 PPM, OIL
65 PPM AT 15X02, OIL
65 PPM AT 15X 02, OIL
65 PPM AT 15X 02, OIL
65 PPM OIL
65 PPM OIL FIRING
65 PPMV
65 PPM, OIL
65 PPMV
42 PPM OIL FIRING
65 PPM OIL FIRING
50.3 LB/H
NOX CONTROL
H20 INJECTION
H20 INJECTION
H20 INJECTION & SCR
WATER INJECTION
WATER INJECTION
COMBUSTION CONTROLS AND H20 INJECTION
COMBUSTION CONTROL
COMBUSTION CONTROL
STEAM INJECTION
WATER INJECTION
STEAM INJECTION
STEAM INJECTION
H20 INJECTION
H20 INJECTION
STEAM INJECTION
STEAM INJ
WATER INJECTION
STEAM INJ
STEAM INJECTION
H20 INJECTION
COMBUSTION CONTROL
COMBUSTION CONTROL
NATURAL GAS
H20 INJ.
SCR AND H20 INJECTION
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
FACILITY ID
NC-0051
NJ-0006
NJ-0008
NV-0003
NV-0005
NY-0013
NY-0027
NY-0026
NY -0022
NY -0024
NY-0031
NY-0032
NY-0029
NY -0037
NY- 0038
NY
NY-0033
NY
NY -0040
NY -0039
NY -0036
OR -0006
PA-0027
PA- 0052
RI-0004
COMPANY NAME
PANDA-ROSEMARY CORP.
CIBA-GEIGY CORP.
COGEN TECHNOLOGIES
NEVADA PWR CO., CLARK STATION UNIT #7
NEVADA PWR CO., CLARK STATION UNIT *8
TBG/GRUMMAN
TRIGEN
KAMINE CARTHAGE
KAMINE SOUTH GLENS FALLS
LONG ISLAND LIGHTING CO.
1NDECK - YERKS ENERGY SERVICES, INC.
L & J ENERGY SYSTEM COGENERATION
1NDEC/OSWEGO HILL COGENERATION
MEGAN-RACINE ASSOCIATES, INC.
EMPIRE ENERGY - NIAGARA COGENERATION CO.
KAMINE NATURAL DAM
KAMINE SYRACUSE COGENERATION CO.
GAS SYRACUSE
JMC SELKIRK, INC.
FULTON COGENERATION ASSOCIATES
ONE I DA COGENERATION FACILITY
PACIFIC GAS TRANSMISSION CO.
TEXAS EASTERN TRANSMISSION CO.
AMTRAK
OCEAN STATE POWER
NOX CONTROL
EFFICIENCY CONTACT NAME
SAMMY AMERSON
55 THOMAS MICA1
95 WILLIAM KUEHNE
JIM HANSON
LARRY BOWERMAN
78.7 JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
JAMES HARRINGTON
WENDY SIMS
VERNON BUTLER
THOMAS HUYNH
DOUG MCVAY
PHONE NUMBER
(919)-733-3340
(609)-984-3033
(609) -292-6716
(415)-974-8038
(415)-974-8213
(518)-457-2044
(518)-457-2044
(518)-457-2044
(518)-457-2044
(518) -457- 2044
(513)-457-2044
(518)-457-2044
(518)-457-2044
(518)-457-2044
(518)-457-2044
(518)-457-2044
(518)-457-2044
(518)-457-2044
(518)-457-2044
(518)-457-2044
(518)-457-2044
(503)-229-6414
(215)-597-2711
(215)-875-5632
(40D-277-2808
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AMD DUAL FUEL-FIRED)
FACILITY ID
R 1-0008
TX-0130
TX-0149
TX-0152
TX-0151
TX-0150
TX-0178
TX-0048
VA-0161
VT-0005
WA-0007
COMPANY NAME
PAUTUCKET POWER
PETRO-TEX CHEMICAL CORP.
AMCO CHEMICALS CORP.
TEXAS PETRO CHEMICALS CORP.
TEXAS GULF CHEMICALS CO.
EXPLORER PIPELINE CO.
CHAMPION INTERNATIONAL CORP.
FORMOSA PLASTIC CORP.
RICHMOND POWER ENTERPRISE PARTNERSHIP
ARROWHEAD COGENERATION CO.
PUGET SOUND POWER & LIGHT
FACILITY SIZE
533 MMBTU/H
982.3 MSCFH
415 MMBTU/H
92 MW
78 MW
1100 HP
1342 MMBTU/H
38.4 MW
1163.5 MMBTU/H
282 MMBTU/H, GAS
100 MW EA
PERMIT DATE
01/30/89
12/21/82
03/01/84
06/08/84
06/11/84
06/20/84
03/05/85
05/29/86
12/12/89
12/20/89
08/23/82
NOX PRIMARY
PERMIT LIMIT
9 PPMVD AT 15% 02 GASFIRING
237.9 LB/H
95 PPM
1047 T/YR
1366 T/YR
15.1 T/YR.5G/HP-HR
720.34 T/YR
640 T/YR
8.2 PPMVD 15% 02 NAT GAS
9 PPMVD AT ISO COND &15X02, 1H AVG
480 LB/H
00
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
FACILITY ID
R I -0008
TX-0130
TX-0149
TX-0152
TX-0151
COMPANY NAME
PAUTUCKET POWER
PETRO-TEX CHEMICAL CORP.
AMCO CHEMICALS CORP.
TEXAS PETRO CHEMICALS CORP.
TEXAS GULF CHEMICALS CO.
NOX SECONDARY
PERMIT LIMIT NOX CONTROL
18 PPMVD AT 15X 02, OILFIRING SCR
H20 INJECTION
STEAM INJECTION
STEAM INJECTION
STEAM INJECTION
TX-0150
TX-0178
TX-0048
VA-0161
VT-0005
UA-0007
EXPLORER PIPELINE CO.
CHAMPION INTERNATIONAL CORP.
FORMOSA PLASTIC CORP.
RICHMOND POWER ENTERPRISE PARTNERSHIP
ARROWHEAD COGENERATION CO.
PUGET SOUND POWER & LIGHT
11.7 PPMVD 15X #2 OIL
2061 T/YR
STEAM INJECTION
STEAM INJECTION AND SCR
WATER INJECTION AND SCR
WATER INJECTION
CO
-------
TABLE A-1. COMBUSTION TURBINES (GAS-FIRED AND DUAL FUEL-FIRED)
FACILITY ID
RI-0008
TX-0130
TX-0149
TX-0152
TX-0151
TX-0150
TX-0178
TX-0048
VA-0161
VT-0005
WA-0007
COMPANY NAME
PAWTUCKET POWER
PETRO-TEX CHEMICAL CORP.
AMCO CHEMICALS CORP.
TEXAS PETRO CHEMICALS CORP.
TEXAS GULF CHEMICALS CO.
EXPLORER PIPELINE CO.
CHAMPION INTERNATIONAL CORP.
FORMOSA PLASTIC CORP.
RICHMOND POWER ENTERPRISE PARTNERSHIP
ARROWHEAD (^GENERATION CO.
PUGET SOUND POWER & LIGHT
NOX CONTROL
EFFICIENCY CONTACT NAME
DOUG MCVAY
JIMMY RANDALL
37 RANDY HAMILTON
J. RANDALL
J. RANDALL
R. HAMILTON
J. CUNNINGHAM
RANDY HAMILTON
ART ESCOBAR
80 JOHN PERREAULT
PAUL BOYS
PHONE NUMBER
(40D-277-2808
<512)-451-5711
(512)-451-5711
(512)-451-5711
(512)-451-5711
(512)-451-5711
(512)-451-5711
(512)-451-5711
(804) -786-6079
(802)-244-8731
(206)-442-1567
-------
APPENDIX B
NOX CONTROL DATA
STATIONARY INTERNAL COMBUSTION ENGINES
B-1
-------
Description of Terms Used in the Following Table(s)
Facility ID:
Permit Date:
NQ< Primary Limit:
NQ, Secondary Limit:
NQ, Control Efficiency:
Contact Name:
A/F:
FGR:
LNB:
LNC:
NSCR:
SCR:
SNCR:
Identifier used In the BACT/LAER Clearinghouse or region/county where
facility is located
Permit or start-up date (unit may be canceled after permit approval)
NQ, permit limit
NQ, permit limit expressed in different units or for back-up fuel
NQ, control efficiency as stated in the permit
State agency contact
Air to fuel ratio
Rue gas reclrculation
Low NQ, burner
Low NQ, combustion
Non-selective catalytic reduction
Selective catalytic reduction
Selective non-catalytic reduction
B-2
-------
TABLE B-1. STATIONARY 1C ENGINES (GAS-FIRED)
FACILITY ID
BAAQMD
BAAQMO
VENTURA
CA-0073
VENTURA
KCAPCD
MONTEREY
KERN
CA-0260
CA-0078
SAN DIEGO
KINGS
KERN
CO-0001
CO-0001
CO-0001
CO-0002
CO-0002
CO-0002
CO-0003
CO-0004
CO-0004
CO-OOOS
CO-0005
CO- 0005
COMPANY NAME
PG&E LOS MEDANOS COMPRESSOR
PAUL MASSON VINEYARDS COGENERATION
SANTA FE ENERGY SILVERTHREAD LEASE
SANTA FE ENERGY
ARGO PETROLEUM FERNDALE LEASE
NATURAL GAS PROGRESSIVE OPERATION
SOLEDAD COGENERATION ASSOCIATION
SHELL CA PRODUCTION INCINERATOR/KERNRIDGE
SHELL CALIFORNIA PRODUCTION CO.
SHELL CALIFORNIA PRODUCTION
SAN DIEGO MARRIOTT HOTEL TOWER I
CA DEPT OF CORRECTIONS/CORCORAN PRISON
EXXON SAN JOAOUIN PRODUCTION
CO INTERSTATE GAS, CHEYENNE
CO INTERSTATE GAS, CHEYENNE
CO INTERSTATE GAS, CHEYENNE
CO INTERSTATE GAS, DEERTRA1L
CO INTERSTATE GAS, DEERTRAIL
CO INTERSTATE GAS, DEERTRAIL
CO INTERSTATE GAS, FLANK
CO INTERSTATE GAS, KIT CARSON
CO INTERSTATE GAS, KIT CARSON
CO INTERSTATE GAS, TOTEM/LONG
CO INTERSTATE GAS. TOTEM/LONG
CO INTERSTATE GAS, TOTEM/LONG
FACILITY SIZE
4130 HP
300 KU
180 HP
180 HP
200 HP
2133 HP
1100 KU
1680 HP
600 HP
225 BHP
1150 HP
31.46 MMBTU/HR
525 HP
12000 HP
5130 HP
5130 HP
6000 HP
425 HP
16000 HP
13320 HP
16000 HP
370 HP
370 HP
8550 HP
1340 HP
PERMIT DATE
01/08/81
03/27/81
12/02/82
12/02/82
09/30/83
10/19/83
03/05/84
05/29/84
11/14/84
12/02/85
03/09/87
12/18/87
04/25/88
09/12/80
09/12/80
09/12/80
10/24/80
10/24/80
10/24/80
10/24/80
09/12/80
09/12/80
09/12/80
09/12/80
09/12/80
NOX PRIMARY NOX SECONDARY
PERMIT LIMIT PERMIT LIMIT
1.75 GRAMS/HP HR 275 LBM/DAY
30 PPM
124 PPMV AT 15X 02
150 PPM
50 PPM AT 15X 02
1.5 GRAMS/BHP HR
1 GRAM/BHP HR 4.7 LB/HR
4.05 LBM/HR 1.08 G/HP HR
100 LB/D
50 PPMVD 0.805 G/HP-H
1.4 GRAMS/BHP HR 280 PPMVD AT 3X 02
0.22 LBM/MMBTU 0.75 GRAMS/BHP HR
27.84 LBM/DAY 1 GRAM/BHP HR
158.6 LB/H
39.24 LB/H
68 LB/H
79.3 LB/H
10.2 LB/H
211.4 LB/H
83.1 LB/H
211.4 LB/H
8.9 LB/H
8.9 LB/H
216.6 LB/H
53.16 LB/H
-------
TABLE B-1. STATIONARY 1C ENGINES (GAS-FIRED)
00
FACILITY 10
BAAQMD
BAAOMD
VENTURA
CA-0073
VENTURA
KCAPCD
MONTEREY
KERN
CA-0260
CA-0078
SAN DIEGO
KINGS
KERN
CO-0001
CO-0001
CO-0001
CO-0002
CO-0002
CO-0002
CO- 0003
CO-0004
CO-0004
CO-OOOS
CO-0005
CO-0005
COMPANY NAME
PG&E LOS MEDANOS COMPRESSOR
PAUL MASSON VINEYARDS COGENERATION
SANTA FE ENERGY SILVERTHREAD LEASE
SANTA FE ENERGY
ARGO PETROLEUM FERNDALE LEASE
NATURAL GAS PROGRESSIVE OPERATION
SOLEDAD COGENERATION ASSOCIATION
SHELL CA PRODUCTION INCINERATOR/KERNRIDGE
SHELL CALIFORNIA PRODUCTION CO.
SHELL CALIFORNIA PRODUCTION
SAN DIEGO MARRIOTT HOTEL TOWER I
CA DEPT OF CORRECTIONS/CORCORAN PRISON
EXXON SAN JOAOUIN PRODUCTION
CO INTERSTATE GAS, CHEYENNE
CO INTERSTATE GAS, CHEYENNE
CO INTERSTATE GAS, CHEYENNE
CO INTERSTATE GAS. DEERTRAIL
CO INTERSTATE GAS, DEERTRAIL
CO INTERSTATE GAS, DEERTRAIL
CO INTERSTATE GAS, FLANK
CO INTERSTATE GAS, KIT CARSON
CO INTERSTATE GAS, KIT CARSON
CO INTERSTATE GAS, TOTEM/LONG
CO INTERSTATE GAS, TOTEM/LONG
CO INTERSTATE GAS, TOTEM/LONG
NOX CONTROL
NOX CONTROL EFFICIENCY
STRAT. CHARGE ft ENGINE MODIFICATION
NSCR
COMPRESSOR DESIGN
NSCR 96
NSCR, RICH BURN CAT CONVERTER 86
CATALYTIC CONVERTER-NSCR
RICH BURN CATALYTIC CONVERTER 90
SCR 70
NON-SELECTIVE CATALTYIC REDUCTION 90
LEAN BURN 92
LEAN BURN/ENGINE DESIGN
NSCR, A/F
DESIGN
DESIGN
DESIGN
DESIGN
DESIGN
DESIGN
DESIGN
DESIGN
DESIGN
DESIGN
DESIGN
STATE
CONTACT NAME
B. NISHIMURA
DOUG WOLF
KEITH DUVAL
KEITH DUVAL
KEITH DUVAL
IVAN NZO
B. NISHIMURA
IVAN NZO
VI J I SADASIVAN
KEITH DUVAL
BOB BATTEN
MARK POINDEXTER
THOMAS PAXSON
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
PHONE NUMBER
(408)-443-1135
(415)-771-6000
(805)-654-2664
(805)-654-2664
(805)-654-2664
(805)-861-3682
(408)-443-1135
(805) -861 -3682
(818)-572-6214
(805)-654-2845
(619) -694-3316
(209)-584-1411
(805) -861 -3682
(303)-837-3763
(303) -837-3763
(303)-837-3763
(303)-837-3763
(303) -837-3763
(303)-837-3763
(303)-837-3763
(303)-837-3763
(303) -837-3763
(303)-837-3763
(303)-837-3763
(303)-837-3763
-------
TABLE 8-1. STATIONARY 1C ENGINES (GAS-FIRED)
00
6.
FACILITY ID
CO- 0005
CO-0006
CO- 0006
CO-0006
CO-0010
CO-0011
CT-0001
IA-0020
IL-0043
KS-0002
LA- 0043
MI -0015
MI -0016
ND-0009
NM-0006
NM-0006
NM-0009
NM-0009
NM-0009
NM-0009
NM-0009
NM-0010
NM-0010
NM-0010
NM-0010
COMPANY NAME
CO INTERSTATE GAS, TOTEM/LONG
CO INTERSTATE GAS, UATKINS
CO INTERSTATE GAS, UATKINS
CO INTERSTATE GAS, UATKINS
PANHANDLE EAST. PIPE LINE CO., FRED.
PANHANDLE EAST., FT. LUPTON
ALGONQUIN GAS TRANSMISSION CO.
NORTHERN NATURAL GAS
NATURAL GAS PIPELINE CO.
PANHANDLE EAST. PIPE LINE CO.
TRANSCONTINENTAL GAS PIPELINE CORP.
ANR STORAGE CO.
MICHIGAN WISCONSIN PIPE LINE CO.
WESTERN GAS PROCESSORS, LTD.
EL PASO NATURAL GAS CO., WASHINGTON RANCH
EL PASO NATURAL GAS CO., WASHINGTON RANCH
LLANO, INC.
LLANO, INC.
LLANO, INC.
LLANO, INC.
LLANO, INC.
TRANSWESTERN PIPELINE CO., RED BLUFF STA.
TRANSWESTERN PIPELINE CO., RED BLUFF STA
TRANSWESTERN PIPELINE CO., RED BLUFF STA.
TRANSWESTERN PIPELINE CO., RED BLUFF STA.
FACILITY SIZE
16 MMBTU/H
30000 HP
1350 HP
10800 HP
4500 HP
2246 BRAKE HP EA
40 BHP
4000 HP
4000 HP
1669 HP
2250 HP
3750 HP
4000 HP
4000 BHP
4500 HP
4500 HP
1100 HP
1100 HP
1100 HP
1100 HP
1100 HP
1596 HP
1073 HP
1588 HP
2647 HP
PERMIT DATE
09/12/80
09/12/80
09/12/80
09/12/80
11/25/81
05/29/80
03/05/82
02/04/86
03/01/89
07/28/80
10/14/83
04/01/80
11/01/80
09/11/84
05/14/82
05/14/82
06/22/82
06/22/82
06/22/82
06/22/82
06/22/82
05/03/82
05/03/82
05/03/82
05/03/82
NOX PRIMARY NOX SECONDARY
PERMIT LIMIT PERMIT LIMIT
2.52 LB/H
396.5 LB/H
17.84 LB/H
142.72 LB/H
5.5 G/HP-H
55 LB/H EA
0.0135 X BY VOL
250 PPM, 15X 02
9 G/BHP-H 79.4 LB/H
700 PPM 15X 02 (D)
29.7 LB/H
12 G/HP-H
12.3 G/HP-H
2.2 LB/H PER ENGINE
2.45 G/HP-H
2.45 G/HP-H
2.2 G/HP-H
2.2 G/HP-H
2.2 G/HP-H
2.2 G/HP-H
2.2 G/HP-H
4 G/HP-H
5 G/HP-H
4 G/HP-H
4 G/HP-H
-------
TABLE B-1. STATIONARY 1C ENGINES (GAS-FIRED)
FACILITY ID
CO-0005
CO- 0006
CO-0006
CO- 0006
CO-0010
CO- 00 11
CT-0001
IA-0020
IL-0043
CD KS-0002
*> LA-0043
MI -0015
MI -0016
NO -0009
NM-0006
NM-0006
NM-0009
NM-0009
NM-0009
NM-0009
NM-0009
NM-0010
NM-0010
NM-0010
NM-0010
COMPANY NAME
CO INTERSTATE GAS, TOTEM/LONG
CO INTERSTATE GAS, UATKINS
CO INTERSTATE GAS, UATKINS
CO INTERSTATE GAS, UATKINS
PANHANDLE EAST. PIPE LINE CO., FRED.
PANHANDLE EAST., FT. LUPTON
ALGONQUIN GAS TRANSMISSION CO.
NORTHERN NATURAL GAS
NATURAL GAS PIPELINE CO.
PANHANDLE EAST. PIPE LINE CO.
TRANSCONTINENTAL GAS PIPELINE CORP.
ANR STORAGE CO.
MICHIGAN WISCONSIN PIPE LINE CO.
WESTERN GAS PROCESSORS, LTD.
EL PASO NATURAL GAS CO., WASHINGTON RANCH
EL PASO NATURAL GAS CO., WASHINGTON RANCH
LLANO, INC.
LLANO, INC.
LLANO, INC.
LLANO, INC.
LLANO, INC.
TRANSWESTERN PIPELINE CO., RED BLUFF STA.
TRANSUESTERN PIPELINE CO., RED BLUFF STA
TRANSWESTERN PIPELINE CO., RED BLUFF STA.
TRANSUESTERN PIPELINE CO., RED BLUFF STA.
NOX CONTROL
NOX CONTROL EFFICIENCY
DESIGN
DESIGN
DESIGN
ENGINE MODIFICATIONS 55
ENG DESIGN & MODIFICATIONS
MANUFACTURER'S GUARANTEE
ENGINE DESIGN
DESIGN & OPERATING PRACTICES
PRE- IGNITION CHAMBER
CLEAN BURN ENGINE, MOD. COMB. W/CONT 55
RETARDED IGNITION
COMBUSTION MODIFICATIONS
COOPER ENERGY SERVICES
COOPER ENERGY SERVICES
NEW DESIGN
NEW DESIGN
NEW DESIGN
NEW DESIGN
NEW DESIGN
LOW NOX ENGINE
LOW NOX ENGINE
LOW NOX ENGINE
LOW NOX ENGINE
STATE
CONTACT NAME
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
JOHN DALE
JOHN COURCIER
JON KNODEL
C. ROMAINE
CHARLES WHITMORE
HARENDRA RAOL
DAVID FERRIER
GREGORY EDWARDS
GARY HELBLING
SHANKAR ANANTHAKRISHNA
SHANKAR ANANTHAKRISHNA
SHANKAR ANANTHAKRISHNA
SHANKAR ANANTHAKRISHNA
SHANKAR ANANTHAKRISHNA
SHANKAR ANANTHAKRISHNA
SHANKAR ANANTHAKRISHNA
SHANKAR ANANTHAKRISHNA
SHANKAR ANANTHAKRISHNA
SHANKAR ANANTHAKRISHNA
SHANKAR ANANTHAKRISHNA
PHONE NUMBER
(303) -837-3763
(303)-837-3763
(303)-837-3763
(303)-837-3763
(303)-837-3763
(303)-837-3763
(617)-223-4448
(913)-551-7020
(217)-782-2113
(913)-551-7020
(504)-342-8940
(517)-373-
-------
TABLE B-1. STATIONARY 1C ENGINES (GAS-FIRED)
00
FACILITY ID
NM-0010
NM-0011
NM-0012
NM-0013
NM-0013
NM-0014
PA-0028
PA- 0043
PA-0048
PA-0063
TX-0101
TX-0104
TX-0125
TX-0125
TX-0128
TX-0128
TX-0133
TX-0134
VA-0107
WV-0001
COMPANY NAME
TRANSUESTERN PIPELINE CO.. RED BLUFF STA.
TRANSUESTERN PIPELINE CO.. MALJAMAR STA.
TRANSUESTERN PIPELINE CO.. KEMNITZ STA.
TRANSUESTERN PIPELINE CO., BITTER LAKE CO.
TRANSUESTERN PIPELINE CO., BITTER LAKE CO.
TRANSUESTERN PIPELINE CO., ISLER NO. 1 STA.
TENNESSEE GAS PIPELINE CO.
NATIONAL FUEL GAS SUPPLY CORP.
CONSOLIDATED GAS TRANSMISSION CORP.
NATIONAL FUEL GAS SUPPLY CORP.
GETTY OIL CO.
VALERO TRANSMISSION CO.
PHILLIPS PETROLEUM CO.
PHILLIPS PETROLEUM CO.
LIQUID ENERGY CORP.
LIQUID ENERGY CORP.
ENSERCH EXPLORATION CO.
UESTAR TRANSMISSION CO.
ANR PRODUCTION CO.
CONSOLIDATED GAS SUPPLY CORP.
FACILITY SIZE
2585 HP
1073 HP
1072 HP
1050 HP
1596 HP
1588 HP
15500 HP
2850 HP
4200 HP
3000 HP
2000 HP
1000 HP EA
585 HP
220 HP
2000 HP
3200 HP
780 HP
1100 HP
600 HP
1600 HP
PERMIT DATE
05/03/82
05/03/82
05/03/82
05/03/82
09/23/82
05/08/82
03/01/83
02/01/88
05/10/88
06/13/89
10/12/82
09/09/82
12/15/82
12/15/82
11/10/82
11/10/82
12/28/82
12/07/82
03/03/88
09/14/81
NOX PRIMARY
PERMIT LIMIT
5 G/HP-H
5 G/HP-H
5 G/HP-H
5 G/HP-H
4 G/HP-H
4 G/HP-H
3 G/BHP-H
3 G/HP-H
2 G/BHP-H
77.2 T/YR
34.8 T/YR
62.1 T/YR
23.4 T/YR
4 G/HP-H
1.75 G/HP-H
7.7 T/YRO G/HP-H)
21.2 T/YR<2 G/HP-H)
1.6 LB/H
7.33 G/SEC
NOX SECONDARY
PERMIT LIMIT
13.2 LB/H
7.2 T/YR
-------
TABLE B-1. STATIONARY 1C ENGINES (GAS-FIRED)
FACILITY ID
NM-0010
MM-0011
NM-0012
NM-0013
NM-0013
NM-OOU
PA-0028
PA -0043
PA-0048
-------
TABLE B-2. STATIONARY 1C ENGINES (EXCLUDING GAS-FIRED UNITS)
FACILITY 10
AK-0019
CA-0101
CA-0101
KERN
CA-0103
CA-0103
CA-0171
CA-0151
CA-0151
SAN DIEGO
CO
-------
TABLE B-2. STATIONARY 1C ENGINES (EXCLUDING GAS-FIRED UNITS)
FACILITY ID
AK-0019
CA-0101
CA-0101
KERN
CA-0103
COMPANY NAME
GREENS CREEK MINING CO.
SANTA CRUZ COGENERATION
SANTA CRUZ COGENERATION
NOX
SECONDARY
PERMIT LIMIT
ASSOC.
ASSOC.
29.8
LB/H
PACIFIC ENERGY RESOURCES, INC.
PACIFIC LIGHTING ENERGY
SYSTEMS
6.25
LB/H
NOX CONTROL
ENGINE
ENGINE
CLEAN
ENGINE
DESIGN
DESIGN
BURNING OPERATION
DESIGN, CLEAN
BURN
CD
O
CA-0103 PACIFIC LIGHTING ENERGY
CA-0171 SF SOUTHEAST TREATMENT PLANT
CA-0151 GENSTAR GAS RECOVERY SYSTEMS
CA-01S1 GENSTAR GAS RECOVERY SYSTEMS
SAN DIEGO CUMMINS POWER GEN/LAJET ENERGY CO.
CA-0286 LAJET ENERGY CO.
CA-0191 TRICOUNTY SUN ENERGY SHERATON HOTEL
CA-0175 POPPY RIDGE PARTNERS
CA-0209 GSF ENERGY, INC.
CA-0190 CITY OF VENTURA UASTEUATER TREATMENT PLANT
5.4 G/BHP-H
0.8 G/BHP-H
PRECHAMBER IGNIT
CLEAN BURN ENGINE
LEAN-BURN COMBUSTION
LEAN-BURN COMBUSTION
ENGINE DESIGN/WATER INJECTION
H20 INJ., ENGINE DESIGN
NONSELECTIVE CATALYST
PRE-STRATIFIED CHARGE EMIS CONTROL SYS.
CLEAN BURN ENGINE
ENGINE DESIGN
SANTA BARBARA EXXON CO. USA SANTA YNEZ UNIT EXPANSION
FL-0025 SEBRING UTILITIES COMMISSION
FL-0041 PU VENTURES
FL-0040 KEY WEST ELECTRIC SYSTEM
HI-0002 HAWAIIAN ELECTRIC
HI-0002 HAWAII ELECTRIC LIGHT CO., INC.
HI-0002 HAWAII ELECTRIC LIGHT CO., INC.
HI-0003 MAUI ELECTRIC CO., INC
HI-0005 MAUI PINEAPPLE CO., LTD.
HI-0005 MAUI PINEAPPLE CO., LTD.
12.1 G/HP-H DIESEL FIRING
68.4 LB/H, 3H AVG
68.4 LB/H, 3H AVG
68.4 LB/H 3H AVG
35 LB/H, 3H AVG, 0.1X S MAX IN FUEL OIL
23 LB/H, 3H AVG, 0.1X S MAX IN FUEL OIL
INJ. TIMING RETARD
COMBUSTION CONTROL
TIMING RETARDATION
INJ. TIMING RETARD 4 DEC
4 DEC IGNITION RETARD
4 DEC IGNITION RETARD
4 DEC IGNITION RETARD
2 DEC IGNITION RETARD
2 DEG IGNITION RETARD
-------
TABLE B-2. STATIONARY 1C ENGINES (EXCLUDING GAS-FIRED UNITS)
FACILITY ID
AK-0019
CA-0101
CA-0101
KERN
CA-0103
CA-0103
CA-0171
CA-0151
CA-0151
SAN DIEGO
CA-0286
CA-0191
CA-0175
CA-0209
CA-0190
SANTA BARBARA
FL-0025
FL-0041
FL-0040
HI -0002
HI -0002
HI -0002
HI -0003
HI -0005
HI -0005
COMPANY NAME
GREENS CREEK MINING CO.
SANTA CRUZ COGENERATION ASSOC.
SANTA CRUZ COGENERATION ASSOC.
PACIFIC ENERGY RESOURCES. INC.
PACIFIC LIGHTING ENERGY SYSTEMS
PACIFIC LIGHTING ENERGY
SF SOUTHEAST TREATMENT PLANT
GENSTAR GAS RECOVERY SYSTEMS
GENSTAR GAS RECOVERY SYSTEMS
CUMMINS POWER GEN/LA JET ENERGY CO.
LAJET ENERGY CO.
TR1 COUNTY SUN ENERGY SHERATON HOTEL
POPPY RIDGE PARTNERS
GSF ENERGY, INC.
CITY OF VENTURA UASTEUATER TREATMENT PLANT
EXXON CO. USA SANTA YNEZ UNIT EXPANSION
SEBRING UTILITIES COMMISSION
PU VENTURES
KEY WEST ELECTRIC SYSTEM
HAWAIIAN ELECTRIC
HAWAII ELECTRIC LIGHT CO.. INC.
HAWAII ELECTRIC LIGHT CO., INC.
MAUI ELECTRIC CO., INC
MAUI PINEAPPLE CO., LTD.
MAUI PINEAPPLE CO., LTD.
NOX CONTROL STATE
EFFICIENCY CONTACT NAME
JON SANDSTEDT
B. NISHIMURA
B. NISHIMURA
60 TUAN NGO
FRED THOITS
CRAIG ULLERY
STEVE HILL
CRAIG ULLERY
CRAIG ULLERY
CRAIG ANDERSON
CRAIG ANDERSON
90 KEITH DUVAL
A. KENNARD
TED KOWALCZYK
KEITH DUVAL
SANJIB MUKHERJI
ED PALAGYI
BARRY ANDREWS
BARRY ANDREWS
20 JIM HANSON
20 NOLAN HIRAI
20 NOLAN HIRAI
20 WILFRED NAGAM1NE
18 TYLER SUGIHARA
18 TYLER SUGIHARA
PHONE NUMBER
(907)-465-2666
(408) -443- 1135
(408)-443-1135
(805) -861 -3682
(408) -443- 1135
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-771-6000
(619)-694-3318
(619)-694-3318
(805)-654-2845
(916)-366-2107
(818)-572-6186
(805) -654 -2845
(805)-964-8111
(904)-488-1344
(904) -488- 1344
(904)-488-1344
(415)-974-8218
(808)-548-6410
(808)-548-6410
(808) -543 -8200
(808) -543 -8200
(808)-543-8200
-------
TABLE B-2. STATIONARY 1C ENGINES (EXCLUDING GAS-FIRED UNITS)
03
1
NJ
FACILITY ID
HI -0007
HI -0007
HI -0008
KS-0004
KS-0007
KS-OOU
KS-0017
MA-
NJ-0002
NJ-0003
OH-01S7
R 1-0005
TX-0030
TX-0113
TX-0189
UT-0036
COMPANY NAME
CITIZENS UTILITIES CO.
CITIZENS UTILITIES CO.
MAUI ELECTRIC CO.. LTD.
CITY OF OTTAWA
CITY OF AUGUSTA
CITY OF BELOIT
CITY OF KINGMAN
PFIZER CHEMICAL COMPANY
TRENTON DISTRICT ENERGY CO.
HOFFMANN -LAROCHE, INC.
COGENERATION PARTNERS OF AMERICA
NORTHEAST LANDFILL POWER
SHELL OIL CO.
ORGANIC FUEL PRODUCTION, INC.
3M
LENT COGENERATION ASSOCIATES
FACILITY SIZE
7.86 MW
7.86 MW
12.5 MW
6000 KW EA
6000 KW
6000 KW
3495 HP
3710 HP
6 MKW EA
23.3 MKW
9.62 MMBTU/H
2400 BHP
1215 HP
4.2 MMCF/YR
8386 BHP
16950 KW
FUEL
DIESEL
DIESEL
OIL
DUAL FUEL
DUAL FUEL
DUAL FUEL
DIESEL
DIESEL
LANDFILL GAS
FUEL GAS
DIGESTER GAS
DUAL FUEL
DUAL FUEL
PERMIT DATE
09/19/89
09/19/89
12/30/89
12/02/80
05/29/81
05/26/82
03/01/83
07/13/87
07/08/80
08/17/81
04/06/88
12/12/89
03/27/81
02/16/83
05/30/86
10/22/87
NOX PRIMARY
PERMIT LIMIT
590 PPM, DRY AT 15X 02, FULL LOAD
667 PPM, DRY AT 15X 02,50-74.99% LOAD
595 PPM DRY AT 15X 02
1150 PPM 15X 02 (D)
1150 PPM 15X 02 (D)
1150 PPMV 15X 02, DRY BASIS
1150 PPMV, 15X 02, DRY
40 T/YR
1869 T/YR
2272 T/YR
0.68 LB/HMBTU
1.25 G/BHP-H
10 G/HP-H
0.21 T/YR
889 T/YR
249.87 T/YR
-------
TABLE B-2. STATIONARY 1C ENGINES (EXCLUDING GAS-FIRED UNITS)
FACILITY ID
COMPANY NAME
NOX SECONDARY
PERMIT LIMIT
NOX CONTROL
HI-0007 CITIZENS UTILITIES CO.
HI-0007 CITIZENS UTILITIES CO.
HI-0008 MAUI ELECTRIC CO.. LTD.
KS-OOOA CITY OF OTTAWA
KS-0007 CITY OF AUGUSTA
605 PPM DRY AT 15X 02, 75-99.99X LOAD
342.78 LB/H, 3H AVG
256.1 LB/H, 3H AVG
5 DEGREE IGNITION RETARD
03
CO
KS-0014 CITY OF BELOIT
KS-0017 CITY OF KINGMAN
MA- PFIZER CHEMICAL COMPANY
NJ-0002 TRENTON DISTRICT ENERGY CO.
NJ-0003 HOFFMANN-LAROCHE, INC.
OH-0157 COGENERATION PARTNERS OF AMERICA
RI-0005 NORTHEAST LANDFILL POWER
TX-0030 SHELL OIL CO.
TX-0113 ORGANIC FUEL PRODUCTION, INC.
TX-0189 3M
UT-0036 LEHT COGENERATION ASSOCIATES
5.92 LB/H
EFFICIENT OPERATION OF THE UNIT
SCR
USE OF MANUFACT. ENG. HOD.
RETARD. FUEL INJ. TIMING
CLEAN BURN TECHNOLOGY
LEAN BURN
DERATED OLD ENGINES
ENGINE REDESIGNED TO CONTROL NOX
-------
TABLE B-2. STATIONARY 1C ENGINES (EXCLUDING GAS-FIRED UNITS)
FACILITY ID
HI -0007
HI -0007
HI -0008
KS-0004
KS-0007
KS-0014
KS-0017
MA-
NJ-0002
_ NJ-0003
5
* OH-0157
RI-0005
TX-0030
TX-0113
TX-0189
UT-0036
COMPANY NAME
CITIZENS UTILITIES CO.
CITIZENS UTILITIES CO.
MAUI ELECTRIC CO., LTD.
CITY OF OTTAWA
CITY OF AUGUSTA
CITY OF BELOIT
CITY OF KINGMAN
PFIZER CHEMICAL COMPANY
TRENTON DISTRICT ENERGY CO.
HOFFMANN-LAROCHE, INC.
COGENERATION PARTNERS OF AMERICA
NORTHEAST LANDFILL POWER
SHELL OIL CO.
ORGANIC FUEL PRODUCTION, INC.
3M
LEHT COGENERATION ASSOCIATES
NOX CONTROL STATE
EFFICIENCY CONTACT NAME
18.6 TYLER SUGIHARA
18.6 TYLER SUGIHARA
20 WILFRED NAGAMINE
CHARLES WHITMORE
CHARLES WHITMORE
CHARLES WHITHORE
CHARLES WHITMORE
90 JOHN MATTESON
LARRY KARAS
LARRY KARAS
DALE KRYGIELSKI
DOUG MCVAY
BILL TAYLOR
GARY WALL IN
RANDY HAMILTON
DAVE KOPTA
PHONE NUMBER
(808) -543-8200
(808)-543-8200
(808) -543-8200
(913)-551-7020
(913)-551-7020
(913)-551-7020
(913)-551-7020
(413)-784-1100
(212)-264-9538
(212)-264-9538
(419)-693-0350
(40D-277-2808
(214)-767-1594
(512)-451-5711
(512)-451-5711
(80D-538-6108
-------
APPENDIX C
NOX CONTROL DATA
NON-UTILITY BOILERS AND HEATERS
C-1
-------
Description of Terms Used in the Following Table(s)
Facility ID:
Permit Date:
NQ Primary Limit:
NQ, Secondary Limit:
NQ Control Efficiency:
Contact Name:
A/F:
FOR:
LNB:
LNC:
NSCR:
SCR:
SNCR:
Identifier used in the BACT/LAER Clearinghouse or region/county where
facility is located
Permit or start-up date (unit may be canceled after permit approval)
NQ, permit limit
NQ, permit limit expressed in different units or for back-up fuel
NQ control efficiency as stated in the permit
State agency contact
Air to fuel ratio
Rue gas recirculation
Low NQ, burner
Low NQ, combustion
Non-selective catalytic reduction
Selective catalytic reduction
Selective non-catalytic reduction
C-2
-------
TABLE C-1. COAL-FIRED BOILERS
FACILITY ID
REGION IX
AMAOOR
REGION IX
REGION IX
CA-0092
CA-0120
CA-0128
CA-0372
SAN JOAQUIN
CA-0129
CA-0372
CA-0128
CA-0129
CA-0158
CA-0092
CA-016S
KERN
REGION IX
CA-0178
CA-0180
REGION IX
CA-0282
CA-0129
CA-0128
REGION IX
COMPANY NAME
RIO BRAVO/POSO CREEK, KERN
AMERICAN LIGNITE COGENERATION
CORN PRODUCTS/STOCKTON
COGENERATION NATIONAL CORPORATION
RIO BRAVO REFINING CO.
SCE - BIOGEN POWER PROJECT
CORN PRODUCTS
COGENERATION NATIONAL CORP.
COGENERATION NATIONAL CORPORATION
COGENERATION NATIONAL CORP.
COGENERATION NATIONAL CORP.
CORN PRODUCTS
COGENERATION NATIONAL CORP.
BMCP
RIO BRAVO REFINING CO.
PYROPOWER CORP.
PYROPOWER CORPORATION
MT. POSO COGEN COMPANY/KERN
MOUNT POSO COGENERATION CO.
GWF POWER SYSTEMS CO.
KERR MCGEE/TRONA, CA
GWF POWER SYSTEMS CO., INC.
COGENERATION NATIONAL CORP.
CPC INTERNATIONAL
GWF POWER SYSTEHS/TORRANCE, KERN
FACILITY SIZE
240 MMBTU/HR
50 MHBTU/HR
300 MMBTU/HR
37.5 MW
212 MMBTU/HR
620 MMBTU/HR
620 MMBTU/HR
279.6 MMBTU/HR
279.6 MMBTU/HR
280 MMBTU/HR
49.9 MW
300 MMBTU/HR
220 T/D
389 MMBTU/HR
640 MMBTU/HR
640 MMBTU/HR
50 MW
50 MW
274 MHBTU/HR
710,000 LMB/HR
202 MMBTU/HR
79 MMBTU/HR
178 MMBTU/HR
DATE ISSUED
12/21/83
12/85
12/85
02/28/85
04/26/85
10/29/85
12/13/85
12/13/85
12/13/85
12/13/85
12/16/85
12/31/85
06/20/86
10/22/86
12/01/86
12/01/86
1/87
01/12/87
01/28/87
1988
02/11/88
02/25/88
03/02/88
1989
NOX PRIMARY NOX SECONDARY
PERMIT LIMIT PERMIT LIMIT
78 PPMV AT 3X 02
61.4 LBM/HR 247.97 TON/YR
50 PPM
30 PPHV AT 3X 02
0.2 LB/HHBTU
34 PPH DRY 9.2 LB/H
30 PPHV AT 3X 02
30 PPH AT 3X 02
30 PPHV AT 3X 02
30 PPHV AT 3X 02 12 LB/H/UNIT
30 PPM AT 3X 02
42 LB/H 50 PPM
30 PPMDV AT 3X 02
0.039 LB/MHBTU
78 PPH AT 3X 02 38.9 LB/H
0.092 LB/HHBTU 58.6 LB/H
0.092 LBM NOX/HMBTU 58.6 LBM NOX/HR
65 PPMV AT 3X 02
0.1 LB/MMBTU
28 PPM AT 3X 02
0.09 LB/MHBTU
360 LB/D 0.074 LB/MMBTU
199 LB/D, NAT GAS 140 LB/D, #2 OIL
684 LB/D, NAT GAS 512 LB/D, #2 OIL
22 PPMV AT 3X 02
-------
TABLE C-1. COAL-FIRED BOILERS
FACILITY ID
REGION IX
AHADOR
REGION IX
REGION IX
CA-0092
CA-0120
CA-0128
CA-0372
SAN JOAQUIN
CA-0129
O
i.
CA-0372
CA-0128
CA-0129
CA-0158
CA-0092
CA-0165
KERN
REGION IX
CA-0178
CA-0180
REGION IX
CA-0282
CA-0129
CA-0128
REGION IX
COMPANY NAME
RIO BRAVO/POSO CREEK, KERN
AMERICAN LIGNITE COGENERATION
CORN PRODUCTS/STOCKTON
COGENERATION NATIONAL CORPORATION
RIO BRAVO REFINING CO.
SCE - BIOGEN POWER PROJECT
CORN PRODUCTS
COGENERATION NATIONAL CORP.
COGENERATION NATIONAL CORPORATION
COGENERATION NATIONAL CORP.
COGENERATION NATIONAL CORP.
CORN PRODUCTS
COGENERATION NATIONAL CORP.
BMCP
RIO BRAVO REFINING CO.
PYROPOUER CORP.
PYROPOUER CORPORATION
MT. POSO COGEN COMPANY/KERN
MOUNT POSO COGENERATION CO.
GUF POWER SYSTEMS CO.
KERR MCGEE/TRONA, CA
GWF POWER SYSTEMS CO., INC.
COGENERATION NATIONAL CORP.
CPC INTERNATIONAL
GWF POWER SYSTEMS/TORRANCE, KERN
N
NOX CONTROL E
LOU BED TEMP & STAGED COMB
CIRCULATING BED COMBUSTION
SELECTIVE NON-CATALYTIC REDUCTION, NH3 INJ.
STAGED COMBUSTION, NSCR
SCNR
SHCR ft AMMONIA INJ
NSCR
SCNR
STAGED COMBUSTION & AMMONIA INJ.
SNCR
LOW TEMP., STAGED COMBUSTION, AMMONIA INJ.
NH3 INJ. AT NH3/NOX RATIO = 6.1 TO 1 , BY WT.
AMMONIA INJ. /STAGED COMBUSTION/SEE NOTES
STAGED ft LOU TEMP COMB., NH3 INJ.
FLUID BED COMBUST, PRIMARY/SEC. AIR, AMMONIA INJ.
STAGED COMBUSTION, AMMONIA INJ.
AMMONIA INJECTION SYSTEM
FLUE GAS RECIRCULATION. LOW NOX BURNER
STAGED COMBUSTION, LOW NOX BURNER
IOX CONTROL STATE
FFICIENCY CONTACT NAME
EARL UITHYCOHBE
90
TOM PAXSON
80 LINH TRAN
SEYED SADREDIN
SEYED SADREDIN
SEYED SADREDIN
SEYED SADREDIN
SEYED SADREDIN
60 LINH TRAN
80 JIM HANSON
80 TOM PAXSON
50 JIM HANSON
53 TOM PAXSON
53 THOMAS PAXSON
50 MATT HABER
LINH TRAN
96
S. LOPEZ
51 SEYED SADREDIN
56 SEYED SADREDIN
PHONE NUMBER
(916)-862-1233
(805)-861-3682
(415)-974-7631
(209)-462-8526
(209)-682-8526
(209)-462-8526
(209)-462-8526
(209)-682-8526
(415)-974-7631
(415)-974-8218
(805) -861 -3682
(415)-974-8218
(305) -361 -3682
(805)-861-3682
(415)-974-8209
(415)-974-7631
(415)-771-6000
(209)-468-3474
(209)-468-3474
-------
TABLE C-1. COAL-FIRED BOILERS
FACILITY 10
CT-0067
CT-0056
HI -0009
KY-0007
KY-0007
KY-0007
MI -0048
Ml -0051
NC-0037
NC-0039
O
1
in
NC-0050
NV-0010
NY-0016
NY-OOU
NY-0030
OH -0069
OH-0145
PA-0047
PA-0046
PA-0044
PA- 0035
PA-0034
PA- 0036
PA -0045
PA-0042
COMPANY NAME
A E S THAMES, INC.
A E S THAMES, INC.
APPLIED ENERGY SERVICES - BARBERS POINT 1
TENNESSEE VALLEY AUTHORITY
TENNESSEE VALLEY AUTHORITY
TENNESSEE VALLEY AUTHORITY
COGENTRIX MICHIGAN LEASING CORP.
CITY OF WYANDOTTE, DEPT. OF MUN. SERV
COGENTRIX CAROLINA LEASING CORP.
COGENTRIX CAROLINA LEASING CORP.
COGENTRIX OF ROCKY MOUNT
WHITE PINE POWER PROJECT
NORTHERN ENERGY GROUP
FORT DRUM HEATING PLANT
UNITED DEVELOPMENT GROUP - NIAGARA INC.
CENTRAL STATE UNIVERSITY
WM. H. ZIMMER GENERATING STATION
SIGNAL FRACKVILLE ENERGY
WESTWOOO ENERGY PROPER I TES
NORTHEASTERN POWER CO.
J. PAGNOTTI ENTERPRISES
SHERIDAN COAL CO.
FOSTER WHEELER POWER
ARCHBALD POWER CORP.
PANTHER CREEK ENERGY
FACILITY SIZE
923 MMBTU/HR
923 MMBTU/HR
2150 MMBTU/HR
200 MMBTU/HR
1430 MMBTU/HR
1579 MMBTU/HR
214 MMBTU/HR
369 MMBTU/HR
202 MMBTU/HR
202 MMBTU/HR
375 MMBTU/HR
750 MW
250 MMBTU/HR
190 MMBTU/HR
577 MMBTU/HR
66 MMBTU
11968 MMBTU/HR
425 MMBTU/HR
540 MMBTU/HR
1082 MMBTU/HR
550 MMBTU/HR
283 MMBTU/HR
240 MHBTU/HR
1170 MMBTU/HR
DATE ISSUED
08/09/89
08/09/89
01/25/90
12/13/85
04/15/86
05/04/88
07/31/87
12/07/87
05/28/86
07/07/86
07/20/89
08/06/85
12/11/85
04/01/87
09/25/88
07/01/85
02/05/87
12/02/85
01/06/86
06/27/86
11/01/86
12/01/86
12/29/86
01/16/87
02/17/88
NOX PRIMARY NOX SECONDARY
PERMIT LIMIT PERMIT LIMIT
0.36 LB/MMBTU
0.36 LB/MMBTU
236.5 LB/H 25 PPM
0.56 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.4 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.55 LB/MMBTU. BIT. COAL 0.45 LB/MMBTU, SUB. COAL
0.17 LB/MMBTU
0.6 LB/MMBTU
0.5 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.4 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.25 LB/MMBTU
0.42 LB/MMBTU
-------
TABLE C-1. COAL-FIRED BOILERS
O
FACILITY ID
CT-0067
CT-0056
HI -0009
KY-0007
KY-0007
KY-0007
Ml -0048
MI -0051
NC-0037
NC-0039
NC-OOSO
NV-0010
NY-0016
NY-OOU
NY -0030
OH -0069
OH-0145
PA -0047
PA-0046
PA-0044
PA-0035
PA- 0034
PA-0036
PA-004S
PA-0042
COMPANY NAME NOX CONTROL
A E S THAMES, INC.
A E S THAMES, INC.
APPLIED ENERGY SERVICES - BARBERS POINT 1 SHCR
TENNESSEE VALLEY AUTHORITY
TENNESSEE VALLEY AUTHORITY
TENNESSEE VALLEY AUTHORITY
COGENTRIX MICHIGAN LEASING CORP. DESIGN & OPERATING PRACTICES
CITY OF WYANDOTTE, DEPT. OF MUN. SERV EQUIP. DESIGN
COGENTRIX CAROLINA LEASING CORP. CONTROL OF EXCESS AIR
COGENTRIX CAROLINA LEASING CORP. CONTROL OF EXCESS AIR
COGENTRIX OF ROCKY MOUNT CONTROL OF EXCESS AIR
WHITE PINE POWER PROJECT PROPER BOILER DESIGN ft COMBUSTION TECHNIQUES
NORTHERN ENERGY GROUP COMBUSTION CONTROL
FORT DRUM HEATING PLANT COMBUSTION CONTROL
UNITED DEVELOPMENT GROUP - NIAGARA INC. COMBUSTION CONTROL
CENTRAL STATE UNIVERSITY
UM. H. ZIMMER GENERATING STATION LOU NOX BURNER
SIGNAL FRACKVILLE ENERGY
WESTWOOD ENERGY PROPER ITES
NORTHEASTERN POWER CO.
J. PAGNOTTI ENTERPRISES
SHERIDAN COAL CO.
FOSTER WHEELER POWER
ARCHBALD POWER CORP.
PANTHER CREEK ENERGY
NOX CONTROL STATE
EFFICIENCY CONTACT NAME
SUSAN AMARELLO
SUSAN AMARELLO
62 NOLAN HIRAI
JAMES DILLS
JAMES DILLS
JAMES DILLS
DHRUMAN SHAH
PHILIP KURIKESU
MIKE SEWELL
MIKE SEWELL
SAMMY AMERSON
GLEN GENTRY
JAMES HARRINGTON
JAMES HARRINGTON
65 JAMES HARRINGTON
TIM WILSON
35 THOMAS TUCKER
BILL SCHILDT
BILL SCHILOT
BILL SCHfLDT
BILL SCHILDT
BILL SCHILDT
BILL SCHILDT
BILL SCHILDT
BILL SCHILDT
PHONE NUMBER
(203)-566-8230
(203) -566- 8230
(808) -543-8200
(502) -564 -3382
(502)-564-3382
(502)-564-3382
(517)-373-7023
(313)-567-0710
(919)-733-3340
(919)-733-3340
(919)-733-3340
(702)-885-4670
(518)-457-2044
(518)-457-2044
(518)-457-2044
(513)-225-4435
(513)-251-8777
(71 7) -787- 9256
(717)-787-9256
(71 7) -787-9256
(717)-787-4324
(717)-787-4324
(71 7) -787- 4324
(717)-787-9256
(717)-787-9256
-------
TABLE C-1. COAL-FIRED BOILERS
FACILITY ID
PA- 0049
PA-0044
PA-OOS8
PA-0057
PA-0062
UT-0034
VA-0033
VA-0034
VA-0044
VA-0044
9
-g
VA-0044
Wl-0041
COMPANY NAME
EDENSBURG POWER CO.
NORTHEASTERN POWER CO.
NORTH BRANCH ENERGY PARTNERS LP
SCRUBGRASS POWER CORP.
CAMBRIA COGEN, INC.
UTAH POWER & LIGHT CO.
UNION CAMP
COGENTRIX OF VIRGINIA, INC.
TULTEX CORP.
TULTEX CORP.
TULTEX CORP.
FORT HOWARD CORP.
FACILITY SIZE
617 MMBTU/HR
513 MMBTU/HR
563 MMBTU/HR
599 MMBTU/HR
559 MMBTU/HR
400 MW
245 MMBTU/HR
200 MMBTU/HR
12 MMBTU/HR
93.3 MMBTU/HR
3 MMBTU/HR
505 MMBTU/HR
DATE ISSUED
06/06/88
06/17/88
09/26/88
01/18/89
05/26/89
10/01/86
07/01/85
06/12/86
12/18/86
12/18/86
12/18/86
09/21/88
NOX PRIMARY
PERMIT LIMIT
0.6 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.3 LB/MMBTU
335.5 LB/H
0.49 LB/MMBTU
643.86 T/YR
0.6 LB/MMBTU
0.35 LB/MMBTU
0.14 LB/MMBTU
3.6 LB/H
0.49 LB/MMBTU
NOX SECONDARY
PERMIT LIMIT
120 LB/H
4.22 LB/H EA
13.33 LB/H
5.77 T/YR
-------
TABLE C-1. COAL-FIRED BOILERS
FACILITY ID
PA -0049
PA- 0044
PA -0058
PA-0057
PA-0062
UT-0034
VA-0033
VA-0034
VA-0044
f. VA-0044
2
VA-0044
UI-0041
COMPANY NAME NOX CONTROL
EDENSBURG POWER CO.
NORTHEASTERN POWER CO.
NORTH BRANCH ENERGY PARTNERS LP
SCRUBGRASS POWER CORP. COMBUSTION CONTROL
CAMBRIA COGEN, INC. COMBUSTION CONTROL
UTAH POWER ft LIGHT CO. LOW NOX BURN
UNION CAMP ENGINEERING DESIGN
COGENTR1X OF VIRGINIA, INC.
TULTEX CORP.
TULTEX CORP.
TULTEX CORP.
FORT HOWARD CORP. PROPER BED OPERATION
NOX CONTROL STATE
EFFICIENCY CONTACT NAME
BRUCE FRY
MIKE SAFKO
BRUCE FRY
WILLIAM CHARLTON
BRUCE FRY
35 L. MENLOVE
(CATHERINE MILLER
(CATHERINE MILLER
(CATHERINE MILLER
(CATHERINE MILLER
(CATHERINE MILLER
ALLEN HUBBARD
PHONE NUMBER
(412)-645-7100
(717)-826-2531
(412)-645-7129
(814)-724-8530
(412)-645-7100
(80D-538-6108
<804)-786-1433
(804)-786-H33
(804)-786-1433
(804)-786-1433
(804)-786-1433
(608)-266-3450
-------
TABLE C-2. GAS-FIRED BOILERS
FACILITY ID
AR-0002
AL-0036
AL-0036
AL-0036
KERN
CA-0066
VENTURA
KERN
SACRAMENTO
SACRAMENTO
CA-0193
9 KINGS
ID
CA-0231
VENTURA
CA-0234
MBUAPCD
SAN JOAQUIN
SAN JOAQUIN
SACRAMENTO
CA-0292
CA-0281
MONTEREY BAY
LA-0047
MI-0109
OH-0107
COMPANY NAME
ARKANSAS EASTMAN CO.
GENERAL ELECTRIC
GENERAL ELECTRIC
GENERAL ELECTRIC
SNACK FOODS PLANT
APPLIED POWER TECHNOLOGY
ROCKWELL INTERNATIONAL
PETRO-LEWIS CORPORATION
FOLSOM PRISON
US GOVERNMENT McCLELLAN
NAVAL STATION TREASURE ISLAND
CA DEPT. OF CORRECTIONS/CORCORAN
DOUGLAS AIRCRAFT CO.
VENTURA COASTAL CORPORATION
VENTURA COASTAL CORP.
BAF ENERGY AMERICAN I COGENERATION
COGENERATION NATIONAL CORPORATION
CORN PRODUCTS, A DIV. OF CPC INTNL.
SMUD/CAMPBELL SOUP COMPANY
WESTINGHOUSE ELECTRIC CORP.
VENTURA COASTAL CORP.
MOBIL EXPLORATION & PRODUCING, INC.
TRUNKLINE LNG
DOW CHEMICAL CO.
KAISER ALUMINUM t CHEMICAL CORP.
FACILITY SIZE
78 MMBTU/H
99.48 MMBTU/H
99.48 MMBTU/H
246.9 MMBTU/H
72 MMBTU/H
307.1 MMBTU/H
2 MMBTU/H
62.5 MMBTU/H
48 MMBTU/H
62 MMBTU/H
24 MMBTU/H
43.9 MMBTU/H
33.5 MMBTU/H
31.4 MMBTU/H
31.4 MMBTU/H
150 MMBTU/H
79.4 MMBTU/H
178 MMBTU/H
100 MMBTU/H
380 MMBTU/H
27.2 MMBTU/H
62.5 MMBTU/H
72.5 MMBTU/H
40.35 MMBTU/H
16.8 MMBTU/H
PERMIT DAT
7/14/1987
10/14/1988
10/14/1988
10/14/1988
11/11/83
11/29/83
03/22/85
10/29/85
06/12/86
10/29/86
12/19/86
02/08/87
04/23/87
08/31/87
08/31/87
10/26/87
02/25/88
03/02/88
08/09/88
08/17/88
11/17/88
04/14/89
05/27/1987
02/21/1989
09/24/1986
NOX PRIMARY
PERMIT LIMIT
13.3 LB/H
9.9 LB/H
14.9 LB/H
0.15 LB/HMBTU
75 PPMVD AT 3X 02
35.4 LB/H
0.18 T/YR
0.03 LMB/MMBTU
40 PPMVD AT 3X 02
40 PPMVD AT 3X 02
40 PPMVD AT 3X 02
40 PPMVD AT 3X 02
68 LB/D TOTAL
30 PPMVD AT 3X 02
25.7 LB/D
40 PPMVD AT 3X 02
199 LBM/DAY
684 LBM/DAY
40 PPMVD AT 3X 02
140 LB/D
0.89 LB/H
40 PPMVD AT 3X 02
7.25 LB/H
0.07 LB/MMBTU
0.1 LB/MMBTU
NOX SECONDARY
PERMIT LIMIT
0.1 LB/MMBTU
0.15 LB/MMBTU
37 LB/H
0.05 LB/MMBTU
250 LBM/DAY
35 PPMVD AT 3X 02
3X EXCESS 02 & 20X FGR
30 PPMVD AT 3X 02
69 PPMVD AT 3X 02
0.106 LBM/MMBTU
0.16 LBM/MMBTU
0.015 LB/MMBTU
22 PPMV AT 3X 02
0.1, LB/MMBTU
-------
TABLE C-2. GAS-FIRED BOILERS
FACILITY ID
COMPANY NAME
NOX CONTROL
NOX CONTROL STATE
EFFICIENCY CONTACT NAME
PHONE NUMBER
AR-0002 ARKANSAS EASTMAN CO.
AL-0036 GENERAL ELECTRIC
AL-0036 GENERAL ELECTRIC
AL-0036 GENERAL ELECTRIC
KERN SNACK FOODS PLANT
CA-0066 APPLIED POWER TECHNOLOGY
VENTURA ROCKWELL INTERNATIONAL
KERN PETRO-LEWIS CORPORATION
SACRAMENTO FOLSOM PRISON
SACRAMENTO US GOVERNMENT McCLELLAN
CA-0193 NAVAL STATION TREASURE ISLAND
O KINGS CA DEPT. OF CORRECTIONS/CORCORAN
O CA-0231 DOUGLAS AIRCRAFT CO.
VENTURA VENTURA COASTAL CORPORATION
CA-0234 VENTURA COASTAL CORP.
MBUAPCO BAF ENERGY AMERICAN I COGENERATION
SAN JOAQUIN COGENERATION NATIONAL CORPORATION
SAN JOAQUIN CORN PRODUCTS, A DIV. OF CPC INTNL.
SACRAMENTO SMUD/CAMPBELL SOUP COMPANY
CA-0292 UEST1NGHOUSE ELECTRIC CORP.
CA-0281 VENTURA COASTAL CORP.
MONTEREY BAY MOBIL EXPLORATION t PRODUCING, INC.
LA-0047 TRUNKLINE LNG
MI-0109 DOW CHEMICAL CO.
OH-0107 KAISER ALUMINUM t CHEMICAL CORP.
SUSAN LOHR (501)-562-7444
LOW NOX BURNERS 50 KENNETH BARRETT (205)-271-7861
LOW NOX BURNERS 50 KENNETH BARRETT (205)-271-7861
LOW NOX BURNERS 50 KENNETH BARRETT (205)-271-7861
LNB & SULFUR FUEL OIL THOMAS PAXSON (805)-861-3682
LNC JOE SLAMOVICH (415)-974-8235
LNB STAN COWEN (805)-654-2458
SCR t REDUCED FIRING RATE 70 TOM PAXSON (805)-861-3682
FGR A. KENNARD (916)-366-2107
FGR t LNB A. KENNARD (916)-366-2107
LOW NOX BURNERS/FGR BOB MISHINURA (415)-771-6000
FGR MARK POINDEXTER (209)-584-1411
FLUE GAS RECIR. & OXYGEN TRIM TRAN VO (818)-572-6126
02 TRIM t FGR TERRI THOMAS (805)-654-2844
FGR/OXYGEN TRIM TERRI THOMAS (805)-654-2849
LNB t FGR FRED THOITS (408)-443-1135
LNB ft FGR 51 SEYED SADREDIN (209)-468-3676
LNB 56 SEYED SADREDIN (209)-468-3676
FGR & LNB BRUCE NIXON (916)-386-6623
LOU NOX BURNERS SCR/FGR HARI DOSS (415)-771-6000
T. THOMAS (805)-654-2844
FGR FRED THOITS (408)-443-1135
LOW NOX BURNERS SCR/FGR KAREN PESSON (504)-342-1206
FLUE GAS RECIRC./LOW EXCESS AIR 50 RANDAL TELESZ (517)-373-7023
FGR/STAGED COMB. DALE KRYGIELSKI (419)-666-4248
-------
TABLE C-3. OIL-FIRED BOILERS
FACILITY ID
KERN
CA-0113
CA-0113
CA-0113
CA-0113
KERN
KERN
KERN
OH-0117
WI-0037
COMPANY NAME
HOPCO
BERRY HOLDING CO.
BERRY HOLDING CO.
BERRY HOLDING CO.
BERRY HOLDING CO.
OETRO- LEWIS CORPORATION
ANGUS PETROTECH
DELANO GROWERS GRAPE PRODUCTS
OWENS-ILLINOIS INC.
WISCONSIN TISSUE MILLS, INC.
FACILITY SIZE
62. 5 MMBTU/HR
62.5 MMBTU/HR
31. 5 MMBTU/HR
31.5 MMBTU/HR
62.5 MMBTU/HR
62.5 MMBTU/HR
50 MMBTU/HR
32 MMBTU/HR
10.3 MMBTU/HR
146.4 MMBTU/HR
PERMIT DATE
12/04/84
10/02/85
10/02/85
10/02/85
10/02/85
10/26/85
11/29/85
03/17/89
11/26/86
10/10/88
NOX PRIMARY
PERMIT LIMIT
1.7 LBM/DAY
7.5 LB/HR
0.2 LB/MMBT
0.2 LB/MMBT
7.5 LB/HR
0.12 LMB/HHBTU
199 LB/DAY
10.6 LBH/HR
0.145 LB/MMBTU
0.38 LB/MMBTU
NOX SECONDARY
PERMIT LIMIT NOX CONTROL
WET SCRUBBER
FLUE GAS RECIRCULATION
6.26 LB/H LOW NOX BURNER; FLUE GAS
6.26 LB/H LOW NOX BURNER; FLUE GAS
FLUE GAS RECIRCULATION
SCR & REDUCED FIRE RATE
LNB, FGR, SCR
254.4 LBM/DAY LNB, FGR, ft 02 TRIM
LOW EXCESS AIR
RECIRCULATION
RECIRCULATION
-------
TABLE C-3. OIL-FIRED BOILERS
FACILITY ID
KERN
CA-0113
CA-0113
CA-0113
CA-0113
KERN
KERN
KERN
OH-0117
WI-0037
COMPANY NAME
HOPCO
BERRY HOLDING CO.
BERRY HOLDING CO.
BERRY HOLDING CO.
BERRY HOLDING CO.
OETRO-LEWIS CORPORATION
ANGUS PETROTECH
DELANO GROWERS GRAPE PRODUCTS
OWENS-ILLINOIS INC.
WISCONSIN TISSUE MILLS, INC.
NOX CONTROL
EFFICIENCY
70
70
61.8
61.8
70
71
51
CONTACT NAME
THOMAS PAXSON
TOM PAXSON
TOM PAXSON
TOM PAXSON
TOM PAXSON
THOMAS PAXSON
THOMAS PAXSON
THOMAS PAXSON
DALE KRYGIELSKI
DANIEL JOHNSTON
PHONE NUMBER
(805)861-3682
(805)-861-3682
(805)-861-3682
(805)-861-3682
(805)-861-3682
(805)861-3682
(805)861-3682
(805)861-3682
(419) -693-0350
(608) -267-9500
-------
TABLE C-4. WOOD/WASTE BOILERS
DISTRICT
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
REGION IX
NOX PRIMARY NOX SECONDARY NOX CONTROL STATE
COMPANY NAME FACILITY SIZE PERMIT DATE PERMIT LIMIT PERMIT LIMIT NOX CONTROL EFFICIENCY CONTACT NAME PHONE NUMBER
PROCTOR ft GAMBLE/LONG BEACH
ULTRAPOWER/CHINESE STATION
D I NUBA ENERGY/TANKE ENERGY 198 MMBTU/HR 3/87
SIERRA FOREST PRODUCTS
ABS ENERGY
CHOWCHILLA BIOMASS
MENDOTA BIOMASS POWER, LTD
HONEY LAKE POWER
COLMAC ENERGY INCORPORATED
NORTH FORK/YANKE ENERGY
THERMAL ENERGY DEVT. CO. 20.5 MW 1989
INDUSTRIAL POWER TECH.
WOODLAND BIOMASS POWER, LTD
FIVE POINTS BIOMASS POWER PLANT
SANGER BIO MASS ENERGY COMPANY
WHEELABRATOR SIGNAL ENERGY
BURNEY FOREST PRODUCTS
SIERRA PACIFIC INDUSTRIES
.265 LB/MMBTU
.147 LB/MMBTU
.12 LB/MMBTU
.108 LB/MMBTU
.061 LB/MMBTU
.25 LB/MMBTU
.072 LB/MMBTU
.10 LB/MMBTU
.10 LB/MMBTU
.147 LB/MMBTU
.105 LB/MMBTU
.063 LB/MMBTU
.08 LB/MMBTU
.25 LB/MMBTU
.08 LB/MMBTU
.12 LB/MMBTU
.12 LB/MMBTU
.110 LB/MMBTU
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
SNCR
40
68
50
55
75
70
40
40
50
-------
TABLE C-5. REFINERY HEATERS
FACILITY ID
CA-0057
CA-0046
CA-0046
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0030
BAAOMO
SANTA BARBARA
COMPANY NAME
EXXON CO., USA
TOSCO CORP.
TOSCO CORP.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
GETTY OIL CO.
PACIFIC REFINERY MODIFICATION
CHEVRON USA t GAVIOTA OIL t GAS FAC.
FACILITY SIZE
165 MMBTU/H
40 MMBTU/H
119 MMBTU/H
22 MMBTU/H
26 MMBTU/H
12.5 MMBTU/H
15 MMBTU/H
66.5 MMBTU/H
15 MMBTU/H
28 MMBTU/H
57 MMBTU/H
19 MMBTU/H
18 MMBTU/H
240 BBL/D
275 MMBTU/HR
9.44 MMBTU/HR
PERMIT DATE
12/10/80
02/19/82
02/19/82
04/08/82
04/08/82
04/08/82
04/08/82
04/08/82
04/08/82
04/08/82
04/08/82
04/08/82
04/08/82
08/24/82
09/28/83
02/06/86
NOX PRIMARY NOX SECONDARY
PERMIT LIMIT PERMIT LIMIT
40 PPM AT 3X 02 207 LB/D
40 PPM AT 3X 02
40 PPM AT 3X 02
40 PPM N02 AT 3X 02
40 PPM N02 AT 3X 02
40 PPM N02 AT 3X 02
40 PPM N02 AT 3X 02
40 PPM N02 AT 3X 02
40 PPM N02 AT 3X 02
40 PPM N02 AT 3X 02
40 PPM N02 AT 3X 02
40 PPM N02 AT 3X 02
40 PPM N02 AT 3X 02
0.15 LB/MMBTU PER GEN.
20 PPM NOX AT 3X 02
1.42 LB/HR
-------
TABLE C-S. REFINERY HEATERS
2
en
FACILITY ID
CA-0057
CA-0046
CA-0046
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0045
CA-0030
BAAOMD
SANTA BARBARA
COHPANY NAME
EXXON CO.. USA
TOSCO CORP.
TOSCO CORP.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
CHEVRON USA, INC.
GETTY OIL CO.
PACIFIC REFINERY MODIFICATION
CHEVRON USA t GAVIOTA OIL t GAS
NOX CONTROL
LOU NOX BURNERS & THERMAL DE-NOX
LOU NOX BURNERS / SCR
NOX CONTROL STATE
EFFICIENCY CONTACT
70 LEONARD CLAYTON
70 JIM KARAS
LOU NOX BURNERS/1 SCR UNIT FOR BOTH FURNACES 70 JIM KARAS
ONE SCR UNIT ON FURN. 7,8,9,10
ONE SCR UNIT ON FURM. 7,8,9,10
ONE SCR UNIT ON FURNACES 1,2,3
ONE SCR UNIT ON FURN. 7,8,9,10
ONE SCR UNIT ON FURNACES 1,2,3
ONE SCR UNIT ON FURNACES 4,5,6
ONE SCR UNIT ON FURN. 7,8,9,10
ONE SCR UNIT ON FURNACES 4,5,6
ONE SCR UNIT ON FURNACES 1,2,3
ONE SCR UNIT ON FURNACES 4,5,6
SNCR
NH3 INJ t SCR
FAC.LNB
JOHN SUANSON
JOHN SUANSON
JOHN SUANSON
JOHN SUANSON
JOHN SUANSON
JOHN SUANSON
JOHN SUANSON
JOHN SUANSON
JOHN SUANSON
JOHN SUANSON
63 JOE SLAMOVICH
85 LEONARD CLAYTON
BILL MASTER
PHONE NUMBER
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-771-6000
(415)-974-8235
(415)-771-6000
(805)-964-8111
-------
APPENDIX D
NOY CONTROL DATA
^V
MUNICIPAL WASTE AND SLUDGE INCINERATORS
D-1
-------
Description of Terms Used in the Following Table(s)
Facility ID:
Permit Date:
NQ, Primary Limit:
NQ Secondary Limit:
NQ, Control Efficiency:
Contact Name:
A/F:
FGR:
LNB:
LNC:
NSCR:
SCR:
SNCR:
Identifier used in the BACT/LAER Clearinghouse or region/county where
facility is located
Permit or start-up date (unit may be canceled after permit approval)
NOX permit limit
NOX permit limit expressed in different units or for back-up fuel
NOX control efficiency as stated in the permit
State agency contact
Air to fuel ratio
Flue gas recirculation
Low NQ, burner
Low NQ, combustion
Non-selective catalytic reduction
Selective catalytic reduction
Selective non-catalytic reduction
D-2
-------
TABLE 0-1. WASTE INCINERATORS
FACILITY ID
AL-0029
AL-0029
CA-0021
CA-0107
SCAOMD
CA-0132
CA-0132
CA-0280
CA-0121
CA-0154
CA-0130
CA-0185
CT-0002
CT-0004
CT-0023
CT-0023
CT-0029
CT-0029
CT-0046
CT-0094
CT-0006
CT-0006
CT-0006
CT-0010
CT-0010
COMPANY NAME
HUNTSVILLE SOLID WASTE AUTHORITY
HUNTSVILLE SOLID WASTE AUTHORITY
WATSON ENERGY SYS, INC.
COMMERCE REFUSE-TO-ENERGY
COMMERCE RE FUSE -TO- ENERGY
NORTH COUNTY RESOURCE RECOVERY ASSOC.
NORTH COUNTY RESOURCE RECOVERY ASSOC.
NEA MESQUITE POWER
WESTERN POWER GROUP
TRI -CITIES RESOURCE RECOVERY
KAISER ENGINEERS CORP.
STANISLAUS WASTE ENERGY CO.
MID-CONNECTICUT RESOURCE RECOVERY FAC.
OGDEN MARTIN SYSTEMS OF BRISTOL
AMERICAN REF FUEL OF SE CONNECTICUT
AMERICAN REF FUEL OF SE CONNECTICUT
EXETER ENERGY LIMITED PARTNERS
EXETER ENERGY LIMITED PARTNERS
MATTABASSETT DISTRICT
NOX CONTROL
NOX CONTROL EFFICIENCY
COMBUSTION DESIGN
COMBUSTION DESIGN
COMBUSTION MODIFICATION
THERMAL DE-NOX t COMBUSTION MOO. 50
THERMAL DE-NOX/COMB. MODIFICATIONS 50
STAGED COMBUSTION, DESIGN
BOILER DESIGN & OVER/UNDERFIRE AIR
FLUID BED/PYROLSIS
MULT. HEARTH FURNACE W/RECIR FL
COMBUSTION MODIFICATION; FGR
STAGED COMBUSTION; FGR 25
AMMONIA INJECTION 40
OPTIMUM COMBUSTION
OPTIMUM COMBUSTION
COMBUSTION TECHNIQUES
COMBUSTION TECHNIQUES
THERMAL DE-NOX 50
THERMAL DE-NOX 50
COMBUSTION METHODS
CONNECTICUT RESOURCES RECOVERY AUTHORITYCOMBUSTION METHODS
WALLINGFORD R.R. ASSOC, L.P.
WALLINGFORD R.R. ASSOC, L.P.
WALLINGFORD R.R. ASSOC, L.P.
BRIDGEPORT RESOURCE RECOVERY FACILITY
BRIDGEPORT RESOURCE RECOVERY FACILITY
COMBUSTION CONTROLS
COMBUSTION CONTROLS
COMBUSTION CONTROLS
COMBUSTION METHODS
COMBUSTION METHODS
STATE
CONTACT NAME
SUE ROBERTSON
SUE ROBERTSON
BOB BAKER
T. HUNT
T. HUNT
JUDITH LAKE
BOB BAKER
HARRY DILLON
JIM HANSON
BRIAN BATEMAN
JIM HANSON
BOB BAKER
ALFRED CONKLIN
ALFRED CONKLIN
MARK HULTMAN
MARK HULTMAN
MARK HULTMAN
MARK HULTMAN
MARK PEAK
ANITA MASIH
JOSEPH ULEVICUS
JOSEPH ULEVICUS
JOSEPH ULEVICUS
JOSEPH ULEVICUS
JOSEPH ULEVICUS
PHONE NUMBER
(205) -271 -7861
(205)-271-7861
(415)-974-8220
(818)-572-6203
(818)-572-6203
(619)-565-5908
(415)-974-8923
(619) -339-4650
(415)-974-8218
(415)-771-6000
(415)-974-8218
(415)-974-8923
(203) -566-8230
(203) -566- 8230
(203)-566-8230
(203) -566- 8230
(203) -566- 8230
(203) -566- 8230
(203)-566-8230
(203)-566-8230
(203)-566-8230
(203)-566-8230
(203)-566-8230
(203)-566-8230
(203)-566-8230
-------
TABLE D-1. WASTE INCINERATORS
FACILITY I
AL-0029
AL-0029
CA-0021
CA-0107
SCAOMD
CA-0132
CA-0132
CA-0280
CA-0121
CA-0154
CA-0130
CA-0185
CT-0002
CT-0004
CT-0023
CT-0023
CT-0029
CT-0029
CT-0046
CT-0094
CT-0006
CT-0006
CT-0006
CT-0010
CT-0010
D COMPANY NAME
HUNTSVILLE SOLID WASTE AUTHORITY
HUNTSVILLE SOLID WASTE AUTHORITY
WATSON ENERGY SYS, INC.
COMMERCE REFUSE-TO-ENERGY
COMMERCE REFUSE-TO-ENERGY
NORTH COUNTY RESOURCE RECOVERY ASSOC.
NORTH COUNTY RESOURCE RECOVERY ASSOC.
NEA MESQUITE POWER
WESTERN POWER GROUP
TRI -CITIES RESOURCE RECOVERY
KAISER ENGINEERS CORP.
STANISLAUS WASTE ENERGY CO.
MID-CONNECTICUT RESOURCE RECOVERY FAC.
OGDEN MARTIN SYSTEMS OF BRISTOL
AMERICAN REF FUEL OF SE CONNECTICUT
AMERICAN REF FUEL OF SE CONNECTICUT
EXETER ENERGY LIMITED PARTNERS
EXETER ENERGY LIMITED PARTNERS
MATTABASSETT DISTRICT
CONNECTICUT RESOURCES RECOVERY AUTHORITY
WALLINGFORD R.R. ASSOC, L.P.
WALLINGFORD R.R. ASSOC, L.P.
WALLINGFORD R.R. ASSOC, L.P.
BRIDGEPORT RESOURCE RECOVERY FACILITY
BRIDGEPORT RESOURCE RECOVERY FACILITY
FACILITY SIZE
116.3 MMBTU/H
129.4 MMBTU/H
1440 T/D
330 T/0
330 T.P.D.
46.4 T/H RDF
1024 T/D
416 MMBTU/H
40 T/H MANURE
480 T/D
480 T/D MSW
400 T/D
249 MMBTU/H, COAL
325 T/D MSW
300 T/D
300 T/D
12320 LB/H
12320 LB/H
2 T/H
1300 SCFM
5.83 T/H
5.83 T/H
5.83 T/H
31.23 T/H
31.23 T/H
PERMIT DATE
10/06/87
10/06/87
01/03/80
05/08/84
05/08/84
11/30/84
04/02/85
07/01/85
11/21/85
12/03/85
12/31/85
08/11/86
04/18/85
09/09/85
12/12/88
12/12/88
06/22/89
06/22/89
09/29/89
09/29/89
12/05/89
12/05/89
12/05/89
02/15/90
02/15/90
NOX PRIMARY
PERMIT LIMIT
11.63 LB/H
0.46 LB/MMBTU
40 LB/H
40 LB/HR
200 PPMV, 8 H AVG
200 PPM AT 12X C02, 2 HAVG
135 LB/H
200 PPMVD AT 12X 02
68.5 LB/H
175 PPM AT 12X C02, 3 HAVG
0.6 LB/MMBTU HEAT INPUT
0.6 LB/MMBTU HEAT INPUT
0.6 LB/MMBTU
0.6 LB/MMBTU
0.12 LB/MMBTU
0.12 LB/MMBTU
0.08 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
0.6 LB/MMBTU
NOX SECONDARY
PERMIT LIMIT
0.1 LB/MMBTU
59.2 LB/H
83 LB/H
966 LB/D
169 LB/H
0.02 LB/MMBTU
200 PPMDV
0.347 LB/MMBTU
-------
TABLE D-1. WASTE INCINERATORS
O
cn
FACILITY ID COMPANY NAME
CT-0010
CT-OOOS
CT-0005
CT-OOOS
FL-0030
FL-0033
FL-0036
FL-0037
FL-0038
FL-0039
GA-0017
HI -0004
IN-0026
NA-0001
MA-0002
HA-0004
MA-0004
MO-0002
MO-0005
Ml -0039
MI -0066
Ml -0090
MM-0009
NC-0053
NH-0001
BRIDGEPORT RESOURCE RECOVERY FACILITY
CONN. RESOURCE RECOVERY AUTHORITY
CONN. RESOURCE RECOVERY AUTHORITY
CONN. RESOURCE RECOVERY AUTHORITY
MCKAY BAY REFUSE-TO-ENERGY PROJECT
PUBLIC WORKS & UTILITIES
WEST PALM BEACH SOLID WASTE RESOURCE REC
SOUTH BROWARD COUNTY RESOURCE RECOVERY F
NRG RECOVERY GROUP
PASCO COUNTY
RESOURCE RECOVERY DEVELOPMENT AUTHORITY
CITY ft COUNTY OF HONOLULU, H- POWER
OGDEN MARTIN SYSTEMS OF INDIANAPOLIS
REFUSE FUELS, INC.
ENERGY ANSWERS CORP.
NESWC RESOURCE RECOVERY FACILITY
NESWC RESOURCE RECOVERY FACILITY
MUNICIPAL INCINERATOR PULASKI HWY
N.E. MARYLAND WASTE DISPOSAL AUTHORITY
CE - RESOURCE RECOVERY SYSTEMS
JACKSON COUNTY BOARD OF PUBLIC WORKS
KENT COUNTY DEPT. OF PUBLIC WORKS
HENNEPIN ENERGY RESOURCE CO.
GASTON COUNTY MSW DISPOSAL FACILITY
VI CON RECOVERY SYSTEMS
FACILITY SIZE
31.23 T/H
326 MMBTU/H
326 MMBTU/H
326 MMBTU/H
1000 T/D WASTE
1050 T/D
700 T/D RDF
863 T/D
250 T/D
1200 T/D
100 MMBTU/H
850 T/D
726 T/D
960 T/D RDF
600 T/0 RDF EA
19.6 MMBTU/H
750 T/D EA, WASTE
600 T/D MSW
2010 T/D
45.7 T RDF/H EA
200 T/D
125 MMBTU/H
1212 T/D
460 T/D
140 T/D
PERMIT DATE
02/15/90
03/01/90
03/01/90
03/01/90
07/02/82
01/27/84
12/16/86
05/15/87
02/19/88
09/22/88
04/05/84
11/19/87
03/24/86
03/23/81
03/15/82
05/27/82
05/27/82
01/25/80
09/10/81
11/09/84
03/18/86
09/15/87
01/27/87
05/18/90
05/22/87
NOX PRIMARY NOX SECONDARY
PERMIT LIMIT PERMIT LIMIT
0.6
0.6
0.6
0.6
300
132
0.32
0.56
385
0.643
32
260
272
0.7
0.5
0.155
0.32
2.6
227
226
311
400
250
150
0.33
LB/MMBTU
LB/MMBTU
LB/MMBTU
LB/MMBTU
LB/H
LB/H
LB/MMBTU
LB/MMBTU
PPMDV
LB/MMBTU
LB/H
PPMV, DRY AT 12X C02 340 LB/H, 3H AVG
PPMV AT 12X C02
LB/MMBTU RDF 0.3 LB/MMBTU OIL
LB/MMBTU
LB/MMBTU
LB/MMBTU
PPH 11.4 T/YR
LB/H 999 T/YR
LB/H
PPMV DRY AT 12X C02
PPMV 1H AVG 35 PPMV 3H AVG
PPM CORR. TO 12% C02
PPMV CORR TO 7X 02
LB/MMBTU 17.5 LB/H MAX
-------
TABLE D-1. WASTE INCINERATORS
FACILITY ID
CT-0010
CT-0005
CT-0005
CT-0005
FL-0030
FL-0033
FL-0036
FL-0037
FL-0038
FL-0039
GA-0017
HI -0004
IN-0026
MA-0001
MA- 0002
HA -0004
MA-0004
HD-0002
MD-0005
MI -0039
MI -0066
MI -0090
MN-0009
NC-OOS3
NH-0001
COMPANY NAME
BRIDGEPORT RESOURCE RECOVERY FACILITY
CONN. RESOURCE RECOVERY AUTHORITY
CONN. RESOURCE RECOVERY AUTHORITY
CONN. RESOURCE RECOVERY AUTHORITY
MCKAY BAY REFUSE-TO-ENERGY PROJECT
PUBLIC WORKS ft UTILITIES
NOX CONTROL
NOX CONTROL EFFICIENCY
COMBUSTION METHODS
COMBUSTION CONTROLS
COMBUSTION CONTROLS
COMBUSTION CONTROLS
COMBUSTION TECHNIQUE
DESIGN
WEST PALM BEACH SOLID WASTE RESOURCE RECOPERATION
SOUTH BROWARD COUNTY RESOURCE RECOVERY
NRG RECOVERY GROUP
PASCO COUNTY
RESOURCE RECOVERY DEVELOPMENT AUTHORITY
CITY ft COUNTY OF HONOLULU, H- POWER
OGDEN MARTIN SYSTEMS OF INDIANAPOLIS
REFUSE FUELS, INC.
ENERGY ANSWERS CORP.
MESWC RESOURCE RECOVERY FACILITY
NESWC RESOURCE RECOVERY FACILITY
MUNICIPAL INCINERATOR PULASK1 HUY
N.E. MARYLAND WASTE DISPOSAL AUTHORITY
CE - RESOURCE RECOVERY SYSTEMS
JACKSON COUNTY BOARD OF PUBLIC WORKS
KENT COUNTY DEPT. OF PUBLIC WORKS
HENNEPIN ENERGY RESOURCE CO.
GASTON COUNTY MSW DISPOSAL FACILITY
VI CON RECOVERY SYSTEMS
FOPERATION
COMBUSTION CONTROL
FURNACE DESIGN, OPER. PROCEDURES
COMBUSTION CONTROL
COMBUSTION CONTROLS
BOILER DESIGN
BOILER DESIGN
INCINERATOR DESIGN
PROPER COMBUSTION TECHNIQUES
OPTIMUM COMB. CONO. SPECIFIED
COMBUSTION MODIFICATION TECHNIQUES
COMBUSTION CONTROL
COMBUSTOR TECHNOLOGY
COMBUSTION CONTROLS
STATE
CONTACT NAME
JOSEPH ULEVICUS
JOSEPH ULEVICUS
JOSEPH ULEVICUS
JOSEPH ULEVICUS
JOHN SVEC
BOB KING
MICHAEL BRANDON
MICHAEL BRANDON
BARRY ANDREWS
BARRY ANDREWS
PAUL IZANT
DAVID TUN I SON
DAVID JORDAN
JOHN COURCIER
JOHN COURCIER
JOHN COURCIER
JOHN COURCIER
ED VOLLBERG
BOB BLASZCZAK
RANDAL TELESZ
LYNN FIEDLER
RANDAL TELESZ
LOUIS CHAMBERLAIN
SAMMY AMERSON
JAMES MARSTON
PHONE NUMBER
(203)-566-8230
(203)-566-8230
(203) -566- 8230
(203) -566-8230
(904) -488- 1344
(904)-488-1344
(404) -347-2864
(404) -347- 2864
(904)-488-1344
(904)-488-1344
(404) -656-4867
(808) -548-6410
(317)-633-5497
(617)-223-4448
(617)-223-4448
(617)-223-4448
(617)-223-4448
(215)-597-8990
(215)-597-8186
(517)-373-7023
(517) -373-7023
(5 17) -373- 7023
(612)-296-7625
(919)-733-3340
(603)-271-1370
-------
TABLE 0-1. WASTE INCINERATORS
FACILITY I
NH-0002
NJ-0007
NY-0020
NY- 0002
NY-0012
NY-0019
NY-0017
NY-0018
OH -0080
OH-0074
D COMPANY NAME
SIGNAL ENVIRONMENTAL SERVICES
AMERICAN REF-FUEL OF ESSEX COUNTY
SIGNAL BROOKLYN
HOOKER ENERGY CORP.
DUTCHESS COUNTY RESOURCE RECOVERY
I SLIP RESOURCE RECOVERY AGENCY
REFUSE INCINERATION
AMERICAN REFFUEL
MONTGOMERY CNTY NORTH t SOUTH REDUCTION
ALTERNATIVE FUELS INDUSTRIES
FACILITY SIZE
288 T/D
3000 T/D
2360 T/D REFUSE
400 T/D
259 T/D
375 T/D
750 T/D
300 T/D
120 T/D
PERMIT DATE
12/09/87
12/11/85
07/23/81
10/14/83
11/30/84
01/31/86
11/06/86
06/17/85
NOX PRIMARY
PERMIT LIMIT
0.61 LB/MMBTU
95 LB/H
0.7 LB/MMBTU COAL
50 LB/H
32.4 LB/H EA
6.6 LB/T HSU
255 PPMDV
3.2 LB/T
16.6 LB/H
NOX SECONDARY
PERMIT LIMIT
65.8 LB/H MAX
300 PPMVD AT 7X Ot
0.3 LB/MMBTU OIL
OH-0087 MILL CREEK TREATMENT PLANT • MSD
OH-0087 MILL CREEK TREATMENT PLANT - MSD
OH-0155 BFI OF OHIO & MICHIGAN, INC.
OH-0155 BFI OF OHIO & MICHIGAN, INC.
OK-0021 OGDEN MARTIN SYSTEMS OF TULSA, INC.
OK-0021 OGDEN MARTIN SYSTEMS OF TULSA, INC.
OR-0004 OGDEN MARTIN SYSTEMS OF MARION, INC.
PA-0037 DRAVO ENERGY RESOURCES
PA-0055 CHESTER SOLID WASTE ASSOCIATES
PA-0056 LANCASTER COUNTY SOLID WASTE MANAGEMENT
PA-0070 GLENDON ENERGY CO.
PR-0001 SAN JUAN RESOURCE RECOVERY FACILITY
PR-0001 SAN JUAN RESOURCE RECOVERY FACILITY
RI-0007 OUONSET POINT RESOURCE RECOVERY FACILITY
TX-0158 CITY OF CLEBURNE
375 T/D
375 T/D
275 T/D
600 T/D
448 T/D
400 T/D
250 T/D
1040 T/D
1040 T/D
375 T/D
1.6 T/H
12/31/86
12/31/86
04/27/88
04/27/88
03/20/86
03/20/86
12/19/83
07/23/87
09/23/88
02/22/89
02/05/90
09/25/89
09/25/89
10/04/89
02/27/85
5 LB/T DRY
5 LB/T DRY
0.01 LB/MMBTU
6 LB/T CHARGED
200 LB/H
100 LB/H
122.2 LB/H
300 PPMV
235 PPMV, DAILY AVG
300 PPMV, DAILY AVG
200 PPMV, 24H
147 PPMV, 12 MON AVG
50.58 LB/H
300 PPMVD AT 12X C02
17.08 T/YR
492 T/YR
241 PPMV, 1H AVG
-------
TABLE D-1. WASTE INCINERATORS
FACILITY ID
NH-0002
NJ-0007
NY -0020
NY -0002
NY-0012
NY-0019
NY-0017
NY -0018
OH -0080
OH- 00 74
OH-0087
OH-0087
OH-0155
OH-01SS
OK- 0021
OK-0021
OR-0004
PA-0037
PA-0055
PA -0056
PA -00 70
PR -0001
PR-0001
Rl-0007
TX-01S8
COMPANY NAME
SIGNAL ENVIRONMENTAL SERVICES
AMERICAN REF-FUEL OF ESSEX COUNTY
SIGNAL BROOKLYN
HOOKER ENERGY CORP.
DUTCHfcSS COUNTY RESOURCE RECOVERY
(SLIP RESOURCE RECOVERY AGENCY
REFUSE INCINERATION
AMERICAN REFFUEL
MONTGOMERY CNTV NORTH fc SOUTH REDUCTION
ALTERNATIVE FUELS INDUSTRIES
MILL CREEK TREATMENT PLANT - MSO
MILL CREEK TREATMENT PLANT -MSO
BFI OF OHIO I MICHIGAN, INC.
BFI OF OHIO ft MICHIGAN, INC.
OGDEN MARTIN SYSTEMS OF TULSA, INC.
OGDEN MARTIN SYSTEMS OF TULSA, INC.
OGDEN MARTIN SYSTEMS OF MARION, INC.
DRAVO ENERGY RESOURCES
CHESTER SOLID WASTE ASSOCIATES
LANCASTER COUNTY SOLID WASTE MANAGEMENT
GLENDON ENERGY CO.
SAN JUAN RESOURCE RECOVERY FACILITY
SAN JUAN RESOURCE RECOVERY FACILITY
NOX CONTROL
COMBUSTION CONTROL
SNCR
CONTRL METHOD: TEMP t E.A.
PROPER BOILER DESIGN
COMBUSTION CONTROL
FURNACE DESIGN
FURNACE DESIGN
COMBUSTION CONTROL
EQUIPMENT DESIGN I OPERATION
COMBUSTION CONTROL
COMBUSTION CONTROL
SNCR
COMBUSTION CONTROL
COMBUSTION CONTROL
QUONSET POINT RESOURCE RECOVERY FACIL1TYCOHBUSTION CONTROL
CITY OF CLEBURNE
NOX CONTROL STATE
EFFICIENCY CONTACT NAME
JAMES MARSTON
ROBERT YEATES
60 PAUL KAHN
BARRY TORNICK
JAMES HARRINGTON
JAMES HARRINGTON
DICK FORGE A
DICK FORGE A
VICTORIA HATHAUAY-SARVER
THOMAS TUCKER
PEG GROEBER
PEG GROEBER
DALE KRYG1ELSKI
DALE KRYGIELSKI
JIM VAN SANDT
JIM VAN SANDT
WENDY SIMS
BILL SCHILDT
THOMAS MCGINLEY
KANUBHAI PATEL
THOMAS MCGINLEY
HARISH PATEL
HARISH PATEL
DOUG MCVAY
JAMES RANDALL
PHONE NUMBER
(603) -271 -1370
(609)-292-0418
(212)-264-6674
(212)-264-9579
(518)-457-2018
(518)-457-2044
(518) -457-2044
(51B)-457-2044
(513)-225-4438
(513)-251-8777
(513)-251-8777
(513)-251-8777
(419)-693-0350
(419)-693-0350
(918)-744-1000
(91S)-744-1000
(503)-229-6414
(717)-787-9256
(215)-270-1920
(71 7) -657-4587
(215)-270-1920
(212)-264-6683
(212)-264-6683
(40D-277-2808
(512)-451-5711
-------
TABLE D-1. WASTE INCINERATORS
FACILITY ID COMPANY NAME
O
(b
UT-0038
UT-0032
UT-0035
UT-0037
VA-0026
VA-0024
VA-0055
VA-OUO
VT-0003
VT-0003
UI-OOS1
BFI MEDICAL WASTE SYSTEMS, INC.
KATY SEGHERS
PREFERRED REDUCTION SERVICES, INC.
CONTINENTAL THERMAL DESTRUCTION
NORFOLK NAVAL SHIPYARD
ARLINGTON/ALEXANDRIA WASTE-TO-ENERGY PLT
1-95 ENERGY/RESOURCE RECOVERY FACILITY
OGDEN/MARTIN SYSTEMS OF ALEXANDRIA
VI CON RECOVERY SYSTEMS
VI CON RECOVERY SYSTEMS
P. H. GLATFELTER CO.
FACILITY SIZE
1350
500
1000
2100
180000
975
750
302000
240
120
7
LB/H
T/D
LB/H
LB/H
LB/D
T/D
T/D
T/YR
T/D
T/D
T/H DRY
PERMIT DATE
02/24/84
05/19/89
12/13/89
03/26/84
10/04/84
01/12/87
07/26/88
03/20/84
09/11/86
01/09/90
NOX PRIMARY
PERMIT LIMIT
6.95
29.9
3.8
3.7
0.7
151.3
79
3.6
36
285
LB/H
LB/H
LB/H
LB/H
LB/MMBTU
LB/H
LB/H
LB/T
LB/H
PPM AT 7X 02
NOX SECONDARY
PERMIT LIMIT
215 PPM
250 PPM
602.3 T/YR
310 T/YR
-------
TABLE D-1. WASTE INCINERATORS
o
1
0
FACILITY
UT-0038
UT-0032
UT-0035
UT-0037
VA-0026
VA-0024
VA-0055
VA-OUO
VT-0003
VT-0003
Ul-0051
ID COMPANY NAME
BFI MEDICAL WASTE SYSTEMS, INC.
KATY SEGHERS
PREFERRED REDUCTION SERVICES, INC.
CONTINENTAL THERMAL DESTRUCTION
NORFOLK NAVAL SHIPYARD
ARLINGTON/ALEXANDRIA WASTE -TO- ENERGY PLT
1-95 ENERGY/RESOURCE RECOVERY FACILITY
OGDEN/MARTIN SYSTEMS OF ALEXANDRIA
VI CON RECOVERY SYSTEMS
VI CON RECOVERY SYSTEMS
P. H. GLATFELTER CO.
NOX CONTROL
COMBUSTION CONTROL
GAS SCRUBBER
COMBUSTION CONTROL
COMBUSTION CONTROLS
COMBUSTION CONTROL
COMBUSTION MODIFICATION
SNCR
NOX CONTROL STATE
EFFICIENCY CONTACT NAME
DAVE KOPTA
DAVID KOPTA
DAVE KOPTA
DAVE KOPTA
JAMES LEHAN
KATHERINE MILLER
CATHY TAYLOR
JACK SCHUBERT
LARRY MILLER
HAROLD GARABEDIAN
50 PAUL YEUNG
PHONE NUMBER
(80D-538-6108
(80D-533-6108
(80D-558-6108
(80D-538-6108
<804)-786-4867
<804)-786-4867
<804)-786-4867
(804)-786-0172
(802)-828-3395
<802)-244-8731
(6061-266-0672
-------
APPENDIX E
NOX CONTROL DATA
WEST GERMANY
Page
Trip Report, Cooper Energy Services International, Inc. (Dusseldorf) E-2
Trip Report, DEPOGAS (Berlin) E-5
Trip Report, Energie und Wasserversorgung (Nuremburg) E-7
Trip Report, H. Krantz, GmbH (Aachen) E-10
Trip Report, Karl Reum, GmbH (Hardheim) E-12
Trip Report, Landeszentralbank Niedersachsen (Hanover) E-14
Trip Report, MAN Technologie AG (Augsburg) E-16
Trip Report, Peissenberger Kraftwerksgesellschaft, GmbH (Peissenberg) E-18
Trip Report, Stadtwerke Dreieich (Dreieich) E-21
Trip Report, Stadtwerke Norderstedt (Norderstedt) E-23
Trip Report, Universitat Technique (Hamburg-Harburg) E-26
E-1
-------
TRIP REPORT
I. PURPOSE
The U.S. Environmental Protection Agency (EPA) is gathering information to provide State and
local agencies with information on NOX control technologies for stationary industrial combustion
sources. The objective of the European field trips is to collect design, operating history, and cost
information from state-of-art NOX control sites.
II. PLACE AND DATE
Cooper Energy Services International, Inc.
Morsenbroicher Weg 200
4000 Dusseldorf 30, West Germany
November 9, 1989
III. SITE CONTACT
Herr Kontaer, Cooper Vulcan
IV. DISCUSSION
Cooper Energy Services International. Inc. was visited by Radian Corporation to acquire data on
state-of-the-art NOX control for 1C engines and combustion turbines in West Germany. Performance
specifications for engines and gas turbines was obtained, as well as TA Luft regulations for combustion
sources.
Background
Cooper Vulken is a joint venture company, 70 percent owned by Cooper Industries in the U.S.
and 30 percent owned by Brammer Vulcan, a manufacturer of ship engines. Cooper Bessemer
manufacturers combustion turbines in conjunction with Rolls Royce. Cooper Bessemer has developed
and marketed combustion turbines with dry low NOX combustors as well as clean bum 1C engines with
low NOy emissions.
TA Luft Regulations
The NOy control requirements specified by the TA Luft for combustion turbines is 300 mg/m3
NOX at 15 percent 02 on a drY basis- max'™1111 (refer to Appendix H for unit conversion factors).
However, if the combustion turbine is greater than 30 percent efficient, the NOX control requirements are
proportional to the efficiency as follows:
E-2
-------
(actual thermal efficiency, %/30 %) x (300 mg/m3)
(put in conversion of mg/m3 ppm/16/MMBtu).
The CO and VOC (non-methane) emission limits for combustion turbines are 100 mg/m3 and
150 mg/m3, respectively. Some VOC pollutants have special limits such as aldehydes at 20 mg/m3 and
carcinogens at 5 mg/m3, maximum. The regulations for gas turbines are expected to be changed
within a year. The new NOX limit is anticipated to be roughly half of the existing level, or 150 mg/m3 at
15 percent oxygen, with no variance based on thermal efficiency. Existing units are expected to be
required to meet the new lower limits by 1994.
For natural gas-fired engines, the regulations are different for 2-stroke and 4-stroke engines. For
2-stroke engines, the NOX emissions limit is 800 mg/m3 at 5 percent oxygen (equivalent to the
300 mg/m3 at 15 percent 02 required for gas turbines). The emission limits for CO and VOC (non-
methane) are 650 mg/m3 and 150 mg/m3, respectively, at 5 percent oxygen.
For 4-stroke natural gas-fired engines, the maximum NOX concentration in the flue gas is
500 mg/m3 at 5 percent oxygen. The CO and VOC emission limits are the same as for the 2-stroke
engines, 650 mg/m3 and 150 mg/m3, respectively.
No emissions offsetting is allowed in West Germany by the TA Luft. The regulations are imposed
such that emissions cannot exceed the guidelines; however, in some cases the maximum limit may be
required to be lower than the standard guideline.
Cooper Bessemer Combustion Turbines
The Cooper 2000 gas turbine (12 MW) operates at 30 percent thermal efficiency without wet
injection with a dry low NOX combustor. The Cooper 2000 gas turbine can achieve a 170 mg/m3 NOX
limit at 15 percent oxygen without wet injection. This NOX level is below the current TA Luft requirement
of 300 mg/m3; however, to meet the anticipated future requirement of 150 mg/m3, the gas turbine
would need to be operated at 5 to 10 percent derate. The CO emissions from the Cooper 2000 gas
turbine is above 100 mg/m3 at full load. A new combustor for the Cooper 2000 is now available which
has low NOX and meets the CO emission limit required by the TA Luft. One Cooper 2000 gas turbine
with the new combustors was installed at the Ruhrgas Werne Station near Dortmond.
The Cooper 6000 gas turbine (24 MW) can achieve 340-350 mg/m3 NOX at full load. The
Cooper 6000 has a thermal efficiency between 34 and 37 percent; therefore, the current TA Luft
requirement is 340 mg/m3 to 370 mg/m3 NCy
Rolls Royce has launched a new development program to design and market a dry low NOX
combustor which can achieve 10 ppmv NOX for commercial availability in 1994.
E-3
-------
Cooper Bessemer 1C Engines
Cooper Bessemer uses the clean-bum technology to control NOX emissions in both the 2-stroke
and 4-stroke natural gas-fired 1C engines. The clean bum technology consists of premixing a rich
mixture of air and fuel in a premix chamber, which is easily ignited. The flame then ignites a lean
mixture of fuel and air within the combustion chamber. The dean bum engine operates below
300 mg/m3 NOX. The most efficient operation and lowest emissions of NO*, CO. and VOC are
achieved in the 80 to 100 percent load range.
There are about 20 clean burn engine units in operation. The largest clean burn engine available
from Cooper Bessemer is an 11,000 hp 2-stroke model. Three 11,000 hp units are installed at two sites:
Bierwenge and Krummhoem. Most clean burn engine units are owned and operated by Ruhrgas.
E-4
-------
TRIP REPORT
I. PURPOSE
The U.S. Environmental Protection Agency (EPA) is gathering information to provide State and
local agencies with information on NOX control technologies for stationary industrial combustion
sources. The objective of the European field trips is to collect design, operating history, and cost
information from state-of-art NOX control sites.
II. PLACE AND DATE
DEPOGAS
Berlin, Federal Republic of Germany
November 20, 1989
III. SITE CONTACTS
Herr Bottcher, DEPOGAS
Herr Schneider, DEPOGAS
IV. DISCUSSION
The DEPOGAS facility was visited by Radian Corporation to gather information on the facility's
SCR system for NOX control. Facility personnel provided SCR system design and operating history
information, as well as a power plant tour within the facility.
Background
DEPOGAS operates a cogeneration power plant at the Berlin-Wannsee municipal waste disposal
site. This landfill was closed in 1980. In 1983 an existing oil-fired boiler at the Hahn-Meitner Institute
was converted to fire landfill gas. Gas collection/treatment and cogeneration plant construction was
conducted in 1986-1987, with power plant start-up in early 1988. The cogeneration plant began
continuous operation in March 1988, with official power plant commissioning in October 1988.
The 4.5 MWe power plant consists of three 1.5 MWe gas engines, the largest engines operating
in Europe on landfill gas. The engine manufacturer is MWM Diesel in Hamburg (Herr Groth, Project
Manager, phone number: 040-752-040).
E-5
-------
SCR System Design
The SCR system was supplied by Steuler and uses a ceramic molecular sieve catalyst. The
reactor housing is approximately 2m x 2m x 3m. The catalyst blocks are 150mm x 150mm x 300mm,
with approximately 25 cpi (cells per square inch).
The NH3 injection is supplied by an aqueous solution of 25 percent NH3 in water. There is a
small heat exchanger prior to the catalyst to reduce the engine exhaust temperature from 52CP C to a
target SCR operating temperature of 430" C. The NOX operating limit for each engine is approximately
225 ppm (see Appendix H for unit conversion factors).
SCR Operating History
During engine commissioning, using standard ignition plugs, NOX emissions levels were on the
order of 300-400 ppm. The SCR system injected NH3, at about 25-30 liters/hr, intermittently for
approximately 6 months in 1988 to reduce the NOX emissions below the required level.
Initially the landfill gas had a methane content of 45-50 percent but then dropped to 35 percent.
Engine load then had to be reduced to 70 percent of the rated capacity. MWM obtained some different
chamber plugs (with the electrodes covered, not open) which both improved combustion and lowered
the NOX emissions. Since July 1988, NH3 has only been injected periodically when there is a problem.
Typically the units operate at approximately 175 ppm without NH3 injection, based on the performance
of the new ignition system.
The operating history for the engines is as follows:
Unit
1
2
3
Operating Hours
7240
7435
6090
Number of Starts
1580
1680
1450
NH3 has been injected only on the order of 600 hours on each engine. The SCR units have had no
catalyst replacement. The only SCR operating problems have involved the NH3 resistance of pump/
valve/piping gasket materials.
E-6
-------
TRIP REPORT
I. PURPOSE
The U.S. Environmental Protection Agency (EPA) is gathering information to provide State and
local agencies with information on NOX control technologies for stationary industrial combustion
sources. The objective of the European field trips is to collect design, operating history, and cost
information from state-of-art NOX control sites.
II. PLACE AND DATE
Energie und Wasserversorgung
Nuremburg, West Germany
November 13, 1989
III. SITE CONTACTS
Herr Wilfried Burau, Manager of DeNOy and DeSOx plant
Herr Gerhard Eckert - Plant Manager
IV. DISCUSSION
The Energie und Wasserversorgung facility was visited by Radian Corporation to gather
information on the facility's SCR system for NOX control. Facility personnel provided SCR design and
operating history information, as well as a power plant tour within the facility.
Background
The Energie und Wasserversorguny facility operates three coal-fired cogeneration boiler which
produce 125 tons/hr steam per boiler. The boilers have been in operation since 1982. In 1985, the first
boiler were retrofitted to include an SCR NOX control system. By 1988, all three boilers had been
retrofitted with SCR and were in commercial operation. The SCR DeNOx system is located downstream
of a desulfurization system and an electrostatic percipitator for paniculate removal.
SCR System Design
The SCR system for each of the three coal-fired boilers was manufactured by Norton Company.
The SCR catalyst is located downstream of the DeSOx system, where flue gas passes through the
DeSOx plant absorber and filters at 68* C, and enters the DeNOx plant at 70-75" C after passing through a
fan. The volumetric flow rate of the flue gas from each boiler is around 160,000 m3/hr. The flue gas is
heated from around 75° C to 32CF C as it passes through a hot regenerator box. It is then heated from
E-7
-------
32CP to 350" C with a gas duct burner before reaching the SCR catalyst. Ammonia is premixed with a
side stream of flue gas and is injected upstream of a static mixer. The normal NH3/NOX molar ratio is
0.9. The flue gas passes through two vertical SCR catalyst beds and then through a cold regenerator
box which cools the flue gas to 80° -90° C before exiting the stack. Every six minutes a 4-way valve is
switched to redirect flue gas from the cdd regenerator to the hot regenerator.
The SCR catalyst volume is 43 m3 in the catalyst bed, with a bed height of 0.4 m. The catalyst
itself is Norton zeolite NC310 consisting of cylinders 1/4" long x 1/4" diameter with) 1/8" opening. The
pressure drop across the catalyst bed is 8-10 millibars. The SCR system is designed to achieve
92 percent NOX reduction, or the guarantee limit of 200 mg/m3 NOX concentration (refer to Appendix H
for unit conversion factors). The S02 concentration reaching the SCR catalyst is 400 mg/m3, maximum.
The typical operating parameters include 3,500 to 4,000 hours per year operation; 900 mg/m3
(maximum) NOX emissions upstream of the SCR system (normally 500-750 mg/m3); 1600 mg/m3 SO2
upstream of the DeSOx system, and 80 to 150 mg/m3 SC-2 at the inlet of the DeNOx system. The SCR
catalyst is sensitive to high paniculate loading. The maximum paniculate concentration is 30 mg/m3,
with the normal concentration at 10 mg/m3.
The ammonia storage system consists of two ammonia tanks, 50 m3 capacity each, for a two
week supply of ammonia for all three catalyst trains.
SCR Operating History
The SCR catalyst system has been in operation for about 10,000 hours, during which time design
and operating problems have been experienced. For example, an extensive heat up period, about
20 hours, is required for the catalyst bed to reach 350° C after start-up. The natural gas-fired burners
which heat the flue gas to the catalyst operating temperature (350° C) are unstable when starting up due
to condensation which collects inside the burners when they are not in operation. In addition, problems
are occasionally encountered with the electronic switching of the 4-way values directing flue gas to the
hot and cold regenerator boxes.
One of the SCR catalyst beds (train 1) was blinded by high paniculate loading in the flue gas.
The pressure drop across the catalyst bed increased to 20-25 mbars, which fluidized the catalyst bed
and eventually entrained the catalyst out of the bed with the flue gas. The catalyst was deposited in the
cold regenerator box which was subsequently washed with citric acid. Likewise, catalyst was entrained
out of the reactor during start-up (from train 3) due to high pressure drop across the catalyst bed
caused by paniculate blinding. As a result, a monitor was installed to measure the paniculate loading to
the SCR system. Operation of the boilers is now limited to 200,000 m3/hr flue gas flow rate to prevent
fluidizing the catalyst bed.
E-8
-------
Perm Conditions
The NOX concentration limit required by the TA Luft is 400 mg/m3; however, the SCR
manufacturer's guarantee is 200 mg/m3. The maximum NH3/NOX molar ratio is 0.94. The plant has a
90 minute variance after the catalyst reaches 350° C before NOX emissions are regulated.
The maximum sulfur content of the coal fired in the boilers is 1.0 percent by weight. Typically,
the sulfur content actually ranges between 0.8 and 1.0 percent. The maximum SC>2 emissions rate from
the plant is 200 mg/m3.
The facility is permitted to operate 240 hours per year bypassing the DeSOx and/or DeNOx
systems.
SCR System Costs
The capital cost of the entire DeNOx SCR system was 42 million Deutsche Marks (DM) in 1985-
1986 (current exchange rate is about 1.5 DM to a dollar). Each catalyst train, containing 43 m3 of
catalyst, cost 900,000 DM for the catalyst itself. The labor cost required to replace the 43 m3 of catalyst
is 100,000 DM.
The annual costs for ammonia for NOX control and natural gas for duct burners is 101,000 DM
and 276,000 DM, respectively. The maintenance and operating labor and supervision requirements for
both the DeNC^ and DeSOx plants require an additional 34 men per shift over the base power plant
requirements. The annualized cost for capital charges and labor for both the DeNOx and DeSOx plants
is 20 million DM.
E-9
-------
TRIP REPORT
I. PURPOSE
The U.S. Environmental Protection Agency (EPA) is gathering information to provide State and
local agencies with information on NOX control technologies for stationary industrial combustion
sources. The objective of the European field trips is to collect design, operating history, and cost
information from state-of-art NOX control sites.
II. PLACE AND DATE
H. Krantz, GmbH and Company
Postfach 2040
5100 Aachen, West Germany
November 9, 1989
III. SITE CONTACT
Herr Vaessen, Krantz
IV. DISCUSSION
The H. Krantz Company was visited by Radian Corporation to gather information on Krantz's
NOX control technique. Krantz personnel provided design and operating information for the Krantz NOX
control technology.
Background
H. Krantz Gmbh and Company working in joint collaboration with the Karlsruhe Nuclear
Research Center, have developed a technique for removing both NOX and SO2 from boiler flue gas.
The process consists of adsorbing SOX and NOx contained In the flue gas on activated coke in a single
reactor.
Reaction Mechanisms
Rue gas is passed through a fixed bed of activated coke at a temperature between 100* and
12CPC. S02 reacts on the surface of the activated coke with oxygen and water vapor to form sulfuric
acid according to the following eouation:
2 S02 + O2 + 2 H20-> 2 H2S04
The sulfuric acid that is formed is absorbed on the surface of the activated coke. Thus, the activated
coke acts both as an absorbent and catalyst. 100 kg activated coke can adsorb up to 15 kg of SO2.
E-10
-------
In addition, anhydrous ammonia is added to the flue gas upstream of the activated coke reactor
which also selectively reduces NOX across the catalyst bed.
Process Design
A multiple way-sorption filter is used which functions as an activated coke reactor. The system
comprises two filter beds, stacked vertically, through which flue gas passes successively. The flue gas
passes first through the lower filter bed where most of the SO2 is removed, and enters a deflection
chamber where ammonia is added. NOX is reduced in the upper filter bed. Following saturation of the
activated coke in the lower bed, the coke is removed. Coke from the upper bed is then changed into
the lower bed and fresh coke is added to the upper bed. The spent coke can subsequently be used in
other processes.
Residence time in the reactor is 10 to 20 seconds, with a flue gas flow rate of 0.1 to 0.15 m/sec.
The pressure drop across the reactor is 15 to 50 mbar. The NOX removal which is achieved is around
80 percent.
The NH3 to NOX molar ratio is 1.0. Ammonia slip is no greater than 10 ppm at 3 percent
oxygen.
Operating History
The activated coke reactors have been used in a pilot system in Dusseldorf for removal of NOX
and SC>2. The Dusseldorf plant bums black coal as a fuel source in a boiler with 7000 m3/hr exhaust
gas flow rate. The activated coke filters were installed in 1986 for testing purposes. The spent coke
from the Desseldorf pilot facility is burned in a cement kiln. Fresh activated coke is supplied by Rhine
Brown Company in Koln. The testing program at Dusseldorf has not been completed.
System Costs
The material costs for the Krantz activated coke system include 400 DM per ton for activated
coke, not including transportation costs (current exchange rate is about 1.5 DM to a dollar). The
consumption rate of activated coke is based on 100 kg coke per 15 kg SC-2 removed.
E-11
-------
TRIP REPORT
I. PURPOSE
The U.S. Environmental Protection Agency (EPA) is gathering information to provide State and
local agencies with information on NOX control technologies for stationary industrial combustion
sources. The objective of the European field trips is to collect design, operating history, and cost
information from state-of-art NOX control sites.
II. PLACE AND DATE
Karl Reum GmbH
Industriestrasse 9
6969 Hardheim, West Germany
November 10, 1989
III. SITE CONTACT
Herr Rolf, Karl Reum GmbH
IV. DISCUSSION
The Karl Reum facility was visited by Radian Corporation to gather information on the facility's
combustion modifications for NOX control. Facility personnel provided engine design and operating
history information, as well as a power plant tour within the facility.
Background
The Karl Reum facility operates three 460 kW 1C engines to provide heating and electricity for the
facility. The engines are manufactured by Jenbacher Werke A. G. (model number JW324G) and utilize
combustion modifications to control NOX. The engines fire propane as the primary fuel with natural gas
as a backup fuel.
Engine Design
The Jenbacher Werke engines are 16 cylinder machines which utilize two turbo chargers each
for NOX control. Air and fuel are premixed prior to being fired. The temperature of the premixed air/fuel
mixture is about 45>C. The combustion temperature ranges between 800° and 900° C.
The engines are equipped with a catalytic oxidation system to control CO emissions.
E-12
-------
Operating History
The engines were started up in March 1989. Initially, the site experienced problems with
operating the engines; however, no major problems have been encountered since July 1989 (as of
November 1989).
The hours of operation and number of starts per engine (as of November 1989) are as follows:
>
Engine
1
2
3
Hours of Operation
2025
2125
2060
Number of Starts
616
596
707
Permit Conditions
Compliance testing for the TA Luft was performed in July 1989. The tests are repeated every
three years. The emissions tests for NOX showed 440 mg/nr* NOX at 8.2 percent oxygen (see
Appendix H for unit conversion factors).
E-13
-------
TRIP REPORT
I. PURPOSE
The U.S. Environmental Protection Agency (EPA) is gathering information to provide State and
local agencies with information on NOy control technologies for stationary industrial combustion
sources. The objective of the European field trips is to collect design, operating history, and cost
information from state-of-art NOX control sites.
II. PLACE AND DATE
Landeszentralbank Niedersachsen
Georgsplatz 5
3000 Hannover, West Germany
November 8, 1989
III. SITE CONTACTS
Herr Wlndhain, Landeszentralbank
Herr Adolf, Landeszentralbank
IV. DISCUSSION
The Landeszentralbank facility was visited by Radian Corporation to gather information on the
facility's SCR system for NOX control. Facility personnel provided SCR design and operating history
information, as well as a power plant tour within the facility.
Background
The Landeszentralbank operates a dual fuel (90 percent natural gas mixed with 10 percent oil)-
fired 1C engine to produce heat and electricity for the bank building. No provisions to sell electricity
back to the grid are in place. The engine, manufactured by MWM Diesel, has a 750 hp capacity. NOX
emissions are controlled by a zeolite catalyst SCR system manufactured by Steuler International. CO
emissions are also controlled by a platinum-palladium catalytic oxidation system which comprises the
first layer of catalyst within the SCR catalyst housing, according to Steuler design specifications. The
SCR system was installed in 1986 and started-up in January 1987.
E-14
-------
SCR System Design
The CO/SCR catalyst system is located upstream of the waste heat boiler. The exhaust gas
temperature from the engine ranges between 320° and 48ff C. The SCR catalyst is designed for
85 percent NOX removal. The normal ammonia flow rate is 8 kg NH3/hr (25 percent aqueous
ammonia).
The SCR catalyst bed consists of around 200 catalyst blocks in the reactor, each block being
152 mm x 152 mm x 300 mm within the first five layers. A sixth layer with blocks
158 mm x 120 mm x 120 mm is included. The site personnel claim that the sixth layer is not a CO
catalyst; however, the Steuler design specifications discuss CO catalyst as part of the design.
SCR Operating History
The SCR catalyst system has performed according to the design specifications since start-up.
The NOX outlet concentration and ammonia flow rates are presently the same as the initial rates with
fresh catalyst. No replacement of catalyst has been required. The catalyst was examined in
October 1988 with no visible signs of blinding or poisoning. The total catalyst operating time (as of
November 1989) is 4,800 hours.
The site has had problems with corrosion of the ammonia storage tank and ammonia injection
system. The ammonia storage tank originally was a PVC tank designed for 20° C maximum ambient
temperature. The actual ambient temperature during the summer reaches 30° C, therefore, the PVC tank
was replaced with a stainless steel tank.
The SCR unit was not in operation at the time of the visit due to computer problems, therefore,
no actual operating conditions were obtained.
Permit Conditions
The NOy emission limit required by the TA Luft is 500 mg/m3 (about 266 ppmv) at 5 percent
oxygen (refer to Appendix H for unit conversion factors). The governmental compliance test was
conducted on June 5, 1987.
SCR System Costs
The capital cost of the entire SCR system, including ammonia storage tanks, was 600,000 DM
(current exchange rate is about 1.5 DM to a dollar) in 1986. The Steuier guarantee was for two years of
operation.
E-15
-------
TRIP REPORT
I.
PURPOSE
The U.S. Environmental Protection Agency (EPA) is gathering information to provide State and
local agencies with information on NOx control technologies for stationary industrial combustion
sources. The objective of the European field trips is to collect design, operating history, and cost
information from state-of-art NOX control sites.
II. PLACE AND DATE
MAN Technologic AG
Augsburg, West Germany
November 17,1989
III.
SITE CONTACT
Herr Albert Jost, MAN Technologic
IV.
DISCUSSION
The MAN Technologic facility was visited by Radian Corporation to gather information on the
NOX control systems applied to engines they manufacture. Facility personnel provided a summary of
their recent NOX control experience.
Background
MAN is a major European manufacturer of 1C engines. Over the last several (2-3) years, they
have installed the following engine NOx control systems:
Number of Engine
(Approximate)
150
100
11
Fuel
Gas
Gas
Dual Fuel
(6 - 9% Diesel)
Size Range, MWe
0.1 - 0.4
0.1 - 0.3
1.0- 1.4
NOX Control
Three-Way Catalyst
Lean Bum
SCR
E-16
-------
SCR System Design
The MAN diesel engines equipped with SCR systems are at three different locations. The first,
near Regansburg in Bavaria, consists of four 1C engines. They were installed before the more stringent
TA Luft requirements were enacted. These units operate below a limit of 800 mg/m3 at 5 percent 02,
with the engine exhaust typically running at about 2,500 mg/m3 at 5 percent 02 (see Appendix H for
unit conversion factors). They are dual fuel units which operate primarily on natural gas, with 6 percent
of the heat input from diesel oil, as pilot fuel. These units are not designed for diesel oil only operation
(9 percent diesel oil for pilot fuel is the normal amount for dual fuel engines designed to have oil-only
capability).
These initial SCR units were designed with a lower 6 percent oil split to minimize potential
impacts of oil firing on the catalyst. The four dual fuel engines have each been in operation for
12,000+ hours. (Normal operating hours for combined heat and power installations are on the order of
4,000 - 6,000 hours/year.) No major problems occurred during the first 10,000 hours; the plant had to
clean the catalyst but it was not a major problem. Engine exhaust temperatures are on the order of
52CP C, with the SCR catalyst typically operating at 350 - 38CP C depending on the catalyst type, with
temperature regulation.
The second MAN engine SCR site in operation is near Frankfurt. These 5 engines operate on a
9 percent oil dual fuel split, with diesel oil-only capability in emergency/back-up situations. These five
units each have approximately 2,000 hours of dual fuel operation. They have no extensive experience
on diesel only operation. The emission limit is 500 mg/m3 at 5 percent 02-
The last two MAN engines equipped with SCR systems are under construction at a third site and
have no operating experience yet.
E-17
-------
TRIP REPORT
I. PURPOSE
The U.S. Environmental Protection Agency (EPA) is gathering information to provide State and
local agencies with information on NOX control technologies for stationary industrial combustion
sources. The objective of the European field trips is to collect design, operating history, and cost
information from state-of-art NOX control sites.
II. PLACE AND DATE
Peissenberger Kraftwerksgesellschaft GmbH
Bergwerkstrasse 14
8123 Peissenberg, West Germany
November 15, 1989
III. SITE CONTACTS
Walter Manhart, Peissenberger Kraftwerksgesellschaft
Hans Wagner, Steuler Industriewerke
Elkie Scheyer, Steuler Industriewerke
IV. DISCUSSION
Background
The Peissenberg facility consists of a 6 MW two-cycle 1C engine cogeneration facility to supply
heat and electricity to industrial and residential consumers within a one kilometer radius. The
Peissenberg site fires dual fuel (94% natural gas combined with 6% No. 2 fuel oil) as the primary fuel
source, with No. 2 fuel oil as a secondary fuel during natural gas curtailment. The engine is equipped
with a zeolite catalyst SCR system manufactured by Steuler International for NOX control. The
Peissenberg unit started up in December 1987.
SCR System Design
The SCR system is designed and guaranteed to meet 500 mg/m3 NOX concentration at
5 percent oxygen in either dual- or oil-fired mode of operation. Inlet NOX concentration is 2000-2400
mg/m3 in dual fuel operation and 5000-6000 mg/m3 in diesel fuel operation at 5 percent oxygen (see
Appendix H for unit conversion factors). Therefore, the NOX reduction efficiency is 80 to 85 percent for
E-18
-------
dual fuel-firing and greater than 85 percent reduction for oil-firing. The SCR system is guaranteed for
20,000 hours operation or three years, whichever is less.
The SCR catalyst volume is 8 m3 and is manufactured in a honeycomb structure. The catalyst
bed presently consists of five layers, 300 mm per layer, for a total depth of 1.5 m. Pressure drop across
the catalyst bed is about 85 mm. w.g. The catalyst reactor is located upstream of the waste heat boiler.
The flue gas temperature ranges between 480° and 520° C. The ammonia injection system is shut down
if the exhaust temperature reaches 525° C. At the upper 52GP C operation temperature, about 5-8 percent
of the ammonia that is injected is oxidized to form additional NQ,.
Ammonia injection rates are 50-65 1/hr for dual fuel-firing and 230-150 l/hr for diesel fuel-firing.
Aqueous ammonia is used in the Peissenberg SCR system, and is stored in a 60 m3 underground tank.
The ammonia injection grid is located about 2 to 2.5 m. upstream of the SCR catalyst. A 90° bend in the
ductwork is located about 1 m. from the catalyst reactor. The design flue gas flow rate reaching the
SCR catalyst is about 32,000 m3/hr; however, the actual flue gas flow rate is 35,000-36000 mP/hr. NQ,
content is only measured in the SCR outlet stream, no measurement of inlet NO, is performed.
SCR Operating History
Since start-up in December 1987, the SCR unit has been in operation 9293 hours (as of
November 1989). Diesel fuel operation accounts for only around 1000 hours of the total operation.
Initially, four layers of catalyst were installed by Steuler in the reactor housing. However, the SCR
system could not achieve the 500 mg/m3 NQ, outlet guarantee with four catalyst layers. Therefore, a
fifth catalyst layer was added to meet the guarantee. This incident of under-sizing the catalyst bed was
claimed to be due to the discrepancy between design and actual flue gas flow rates.
No change in ammonia consumption or outlet NQ, concentration has been experienced since
the fifth layer of catalyst was added. The catalyst has not been replaced at the Peissenberg site since
start-up. The catalyst is claimed to be resistant to poisoning by impurities present in the diesel fuel
which are poisons to base metal catalysts. The only compound known to poison zeolite catalysts is
fluoride, which destroys ceramics.
Permit Conditions
The NQ, concentration limit required by the TA Luft is 1000 mg/m3 at 5 percent oxygen. This
limit is much less stringent than the 500 mg/m3 Steuler guarantee. The TA Luft requires hourly, daily,
and monthly NQ, emission averages to be recorded. Additionally, a stack test for compliance is
required every three years by the TA Luft. The initial compliance test was conducted about six months
after start-up, following addition of the fifth catalyst layer by Steuler.
Sulfur content of the No. 2 fuel oil fired at Peissenberg is 0.5 weight percent, maximum.
E-19
-------
SCR System Costs
The total installed capital Investment for the entire cogeneration plant was 11 million DM (current
exchange rate is about 1.5 DM to a dollar) in 1987. The SCR catalyst system accounted for 800,000 DM
of the total capital investment.
Cost of ammonia is 0.23 DM/kg supplied to Peissenberg.
E-20
-------
TRIP REPORT
I. PURPOSE
The U.S. Environmental Protection Agency (EPA) is gathering information to provide State and
local agencies with information on NOX control technologies for stationary industrial combustion
sources. The objective of the European field trips is to collect design, operating history, and cost
information from state-of-art NOX control sites.
II. PLACE AND DATE
Stadtwerke Dreieich
Dreieich, West Germany
November 16, 1989
III. SITE CONTACT
Herr Heinz-Dieter Karstens, Stadtwerke Dreieich
IV. DISCUSSION
The Stadtwerke Dreieich facility was visited by Radian Corporation to gather information on the
facility's SCR system for NOX control. Facility personnel provided SCR design and operating history
information, as well as a power plant tour within the facility.
Background
Stadtwerke Dreieich operates an approximately 2 MWe cogeneration plant consisting of five
natural gas 1C engines, and two standby boilers used for peaking service. Each of the 1C engines is
rated at 155 kWe each. NOX emissions are controlled by individual SCR (ceramic molecular sieve
catalysts) systems on each engine.
SCR System Design
The Steuler SCR catalyst for each 1C engine is installed upstream of the waste heat boiler. The
exhaust gas temperature for each unit normally operates between 450 and 507 C. The units operate on
natural gas fuel only.
The emission standards for oil and gas are 500 ppm; however, the local regulatory agency has
required these units to meet a 250 ppm limit at 12 percent ©2 (see Appendix H for unit conversion
factors).
E-21
-------
Each SCR catalyst system consists of 27 catalyst blocks per engine. There are 3 layers of
catalyst, each consisting of 9 blocks in a 3 x 3 arrangement. The overall dimensions of the catalyst
housing are approximately 0.7 m x 0.7 m x 0.7 m.
Operating History
The 1C engine/SCR units were started in 1986. There have been no catalyst additions or change
outs. The catalysts were cleaned once in 1987; they were inspected again in 1988 and showed no
visible signs of dirt.
The operating history for the engines is as follows:
Unit
1
2
3
4
5
Operating Hours
17,400
17,400
17,400
14,100
14.100
Number of Starts
13,000
8,000
12.390
11,000
12,200
At 155-160 kW, the NH3 consumption for Unit 1 is 2.2 liters/hr, Unit 2 is 2.0 liters/hr, and Units 3-5 are
1.8 liters/hr.
The units are tested by TA Luft once every two years. The last test conducted showed an outlet
NQ, emission level for this facility of 187 ppm.
E-22
-------
TRIP REPORT
I. PURPOSE
The U.S. Environmental Protection Agency (EPA) is gathering information to provide State and
local agencies with information on NOX control technologies for stationary industrial combustion
sources. The objective of the European field trips is to collect design, operating history, and cost
information from state-of-art NOX control sites.
II. PLACE AND DATE:
Stadtwerke Norderstedt
Heidbergstrasse 101-111
2000 Norderstedt, West Germany
November 7, 1989
III. SITE CONTACT
Herr Qroth, Stadtwerke Norderstedt
IV. DISCUSSION
The Stadtwerke Norderstedt facility was visited by Radian Corporation to gather information on
the facility's SCR system for NOX control. Facility personnel provided SCR design and operating history
Information, as well as a power plant tour within the facility.
Background
Stadtwerke Nordestadt operates a 2 MW cogeneration plant consisting of six natural gas-fired 2-
cyde 1C engines. The engines supply hot water for residential heating and electrical power servicing a
3 kilometer radius area. The six engines, manufactured by Jenbacher Werke A.G., are 500 kW each.
NOy emissions from the engines are controlled by individual SCR systems (six total SCR catalysts). The
SCR systems were retrofined to the existing engines in September 1985, before which time the engines
had been operating uncontrolled for about 6,000 hours. The SCR systems were in commercial operation
by the end of 1985. The Stadtwerke Nordestadt site was one of the first Steuler SCR sites.
SCR System Design
The SCR catalyst for each 1C engine is installed upstream of the waste heat boiler. The exhaust
gas temperature from each engine is between 430° C and 45CPC. The engine exhaust actual flow rate is
E-23
-------
4,500 m3/hr; however, the SCR system for each engine was designed for an exhaust rate of only
3,900 m3/hr. The original catalyst was an aluminum oxide formulation.
The NOX concentration in the exhaust gas from the engine is about 1,300 ppmv at 12.5 percent
oxygen, which is equivalent to 4,000 mg/m3 at 5 percent oxygen (see Appendix H for unit conversion
factors). The SCR system is designed to reduce NOX emissions to meet 800 mg/m3 at 5 percent
oxygen, which represents an 80 percent NOX reduction efficiency. The manufacturer's guarantee on
SCR performance is one year after commissioning.
Each SCR catalyst bed presently consists of 144 blocks which are 150 mm x 150 mm x 150 mm
each. Each catalyst bed presently has 4 layers of catalyst. The overall dimensions of the SCR catalyst
housing is 1.5 m x 1.5 m x 1.5 m, with ammonia injection occurring about 1 m upstream of the catalyst.
The pressure drop across the catalyst bed is 70 mm w.g.
SCR Operating History
Since the SCR system was retrofit into the existing power plant, space limitations dictated some
of the design aspects of the SCR system. The original SCR ducting design included two 90 degree
bends upstream of the catalyst, which caused poor flow distribution. The ducting was changed to two
45 degree bends to help improve the flow characteristics. Vibration from the engines caused initial
cracks in the catalyst housing and ductwork.
In the first two years of operation, the reliability of the SCR system was very poor, causing
repeated shutdowns for repairs. In November 1986, the catalyst was replaced with a titanium-based
formulation due to catalyst performance decline. At this time, the spent aluminum oxide catalyst had no
visible damage or coating. In addition, an extra catalyst layer was added during the catalyst
replacement (the original catalyst bed had only three layers). Three months following catalyst
replacement, the new catalyst performance began a gradual decline. The ammonia flow rate required to
achieve 800 mg/m3 outlet NOX (at 5 percent O2) had increased from 8 l/hr to 14 l/hr by six months
after replacement. Steuler cleaned the catalyst in mid-1987 via dipping the catalyst blocks in a liquid
cleaning solution. No further replacement or reactivation has occurred since that time. After cleaning,
the ammonia injection rate has been at the design 8-9 l/hr until around August 1989. Since August
1989, the ammonia injection rate has steadily increased ana is presently at 13 l/hr, as of
November 1989.
Other problems which have occurred include ammonia corrosion of copper instrumentation
fittings, seals, and gaskets and NOx monitors failing after 1,500 hours of operation. Steuier supplies the
NOX analyzer system which consists of two analyzers for the six SCR units (each analyzer monitors
three engines).
E-24
-------
The actual operation of each engine and the number of starts, as of November 1989, is as
follows:
Engine
1
2
3
4
5
6
Hours of Operation
16,423
15,375
15.741
15,803
15,698
15.813
Number of Starts
7,545
5,825
5,985
5,339
5,783
3,929
The SCR system was installed on each engine after about 6,000 hours operation and 2,500 starts.
Heir Groth speculated that ash and lubricating oil may potentially be the reason for catalyst
deactivity. However, the boiler tubes (entirely downstream of the SCR) are not fouled as rapidly since
SCR has been installed.
Permit Conditions
The NOX emission limit required by the TA Luft is 800 mg/m3 (about 425 ppmv) at 5 percent
oxygen. This NOx concentration is around 238 ppmv corrected for an actual concentration of
12 percent oxygen. In the future, the control of CO emissions via catalytic oxidation will be required.
CO emissions are presently 465 ppm at 12 percent Og.
SCR System Costs
The capital cost of the initial SCR system, including ammonia tanks, NOX monitors,
instrumentation, etc., was 1 million DM (current exchange rate is about 1.5 DM to a dollar) in 1985.
Replacement catalyst is 180 DM per 150 mm x 150 mm x 150 x mm block. The NOx monitors cost
1,000 DM per monitor to replace. The SCR system was procured by Energie Beratung Wolff, Munich
(089-785-3225).
E-25
-------
TRIP REPORT
I. PURPOSE
The U.S. Environmental Protection Agency (EPA) is gathering information to provide State and
local agencies with information on NOX control technologies for stationary industrial combustion
sources. The objective of the European field trips is to collect design, operating history, and cost
information from state-of-art NOX control sites.
II. PLACE AND DATE
Universitat Technique
Eisendorferstrasse 40
2100 Hamburg - Harburg 20, West Germany
November 6, 1989
III. SITE CONTACTS
Dr. Schiff, Universitat Technique
Herr Jungk, Universitat Technique
Herr Thramer, Universitat Technique
IV. DISCUSSION
The Universitat Technique facility was visited by Radian Corporation to gather information on the
facility's SCR system for NOy control. Facility personnel provided SCR design and operating history
information, as well as a power plant tour within the facility.
Background
The Universitat Technique in Hamburg - Harburg operates a cogeneration system consisting of
four natural gas-fired 2-cycle 1C engines. The engines supply hot water for heating the University
buildings in addition to providing the University's electrical needs, with the capability to purchase and
sell excess electricity to/from the grid. The engines are operated according to the heating demand and
peak electrical needs. Most or all of the engines are shutdown at night. The engines are all Jenbacher
Werke AG (Tirol, Austria) models, two of which are 8-cylinder 700 kW each, and the other two are
6-cylinder 500 kW engines. A zeolite catalyst SCR system manufactured by Steuler International for
controlling NOX emissions is employed.
E-26
-------
SCR System Design
The combined exhaust from the four engines is ducted directly to the single SCR catalyst system
without cooling. The maximum design exhaust temperature is 420° C. The minimum exhaust gas
temperature, below which ammonia injection is halted, is 350° C. During an engine cold start,
approximately 20 to 30 minutes is required to reach the minimum 35Cf C, before ammonia is injected.
The NOX concentration at the inlet of the SCR system ranges between 800 and 900 ppmv actual
concentration. Normally, the oxygen content of the flue gas stream is around 10 percent. The SCR
system is designed to reduce NOX to around 120 ppmv actual concentration, which represents 85-
87 percent NOy removal.
The SCR catalyst itself is a monolith type which is supplied in 200 mm x 200 mm x 200 mm
cubes. The present dimensions of the entire catalyst bed are 1.1 m x 2.2 m x 1.6 m. There are
presently six layers of catalyst.
SCR Operating History
Originally, Steuler International installed four layers of catalyst; however, an additional two layers
of catalyst were added because the performance guarantee was not met. The Steufer guarantee was
specified as 125 ppmv outlet NOX using a maximum ammonia flow of 10 l/hr (25 percent aqueous
ammonia). With the original four catalyst layers, the required ammonia injection rate was 20 l/hr to
achieve 125 ppmv outlet NOX, which did not meet the performance guarantee. The additional two
catalyst layers were added after six months of operation. During the six month initial period before
adding extra catalyst, the ammonia injection point was moved further upstream to enhance mixing,
however, the system performance did not improve significantly. After the catalyst addition, the ammonia
flow rates are around 10 l/hr for the 700 kW engines and 7 l/hr for the 500 kW engines. The ammonia
injection pressure is 2.5 bar.
The SCR system has been in commercial operation for about two years as of November 1989.
The system is operated at around 2,000 hours per year. The actual operation for each engine and the
number of starts, as of November 1989, is as follows:
Unit
1
2
3
4
Output, KW
700
500
700
500
Hours of Operation
2130
2100
2063
1946
Number of Starts
1919
982
1187
1960
E-27
-------
Permit Conditions
The NOX emission limit set by the TA Luft is 230 ppmv at 7 percent oxygen. This NOX level is
equivalent to 180 ppm at the typical 10 percent oxygen level. Once per year, the units are tested for
NOX, 02, CO, and CO2- Ammonia slip was only tested initially as part of the compliance tests by an
outside agency. The ammonia slip level tested initially was 5-7 ppmv, after the additional two catalyst
layers were installed. No repeat testing of ammonia slip Is required.
SCR System Costs
The power plant and SCR system were procured and constructed by the Civil Engineering
Services of Hamburg. A small, independent A/E firm in Hamburg, Goptert, Reimer und Partner (040-
69200-133, Herr Trust), has all the information concerning the SCR system capital costs.
E-28
-------
APPENDIX F
NOY CONTROL DATA
y^
JAPAN
Information Source: Environmental Catalyst Consultants, Inc.
P.O. Box 637
Spring House, PA 19477
215/628-4447
F-1
-------
TABLE F-1. SCR SITES FOR COMBUSTION TURBINES
NQ<
Site Size Fuel Start-up Inlet Outlet
Japan National Railway/ 141 MW Kerosene 1981 60-80 10
Kawasaki
Sumotono/Shirakawa 3 MW Kerosene 1984 100 25
TABLE F-2. SCR SITES FOR STATIONARY INTERNAL COMBUSTION ENGINES
NO, NO,
Site Size Fuel Start-up Inlet Outlet
Mitsubishi Petrochemical/ - Oil 1980 900 90
Yokkaichi
Unitika/Uji - Oil 1978 1000 150
Monshu Paper/Oita - Oil 1989
F-2
-------
TABLE F-3. INDUSTRIAL BOILERS FITTED WITH SCR FOR DIRTY FUELS
Site
Shindaikyowa Petrochemical/
Nippon Yakin
Nisshin Steel
Kansai Paint
Kansai Oil
Shindaikyow Petrochemical
Ube Industries
Daishowa Paper
Fuji Oil
Shinnihon Chemical Industry
Somitomo Chemical
Ube Industries
Takeda Medicine
Idemrtsu Kosan
Location
Yokkaichi
Kawasaki
Amagasaki
Amagasaki
Sakai
Yokkaichi
Sakai
Yoshinaga
Chiba
Onahama
Chiba
Ube
Nikari
Aichi
Fuel
Oil
Oil
Oil
Oil
Oil
Oil
Oil
OH
Pitch
Oil Coke
Oil Coke
Coal
Coal
Coal
Start-up
Year
1975*
1976*
1977
1978
1979
1985
1989
1989
1983
1984
1985
1982
1986
1986
NO,,
Inlet
250
300
300
250
250
250
500
600
500
400
400
260
ppm
Outlet
25
30
30
25
50
50
50
60
50
250
80
60
*Shut Down
F-3
-------
TABLE F-4. WASTE SLUDGE INCINERATORS FITTED WITH SCR
Plant Name
Sunamachi
Nanbu No. 1
Nanbu No. 2
Kasai
Hirano
Hoshutsu
Shingashi
Shingashi
Senda
Sunamachi
Kosuge
Tsumori
Konan
Hojin
City
Tokyo
Tokyo
Tokyo
Tokyo
Osaka
Osaka
Tokyo
Tokyo
Hiroshima
Tokyo
Tokyo
Osaka
Biwako
Nagoya
Inlet, ppm
NQ,
100
100
100
100
130
130
100
100
130
100
40tf
150
135
130
NQ,
Removal %
90
90
90
90
90
90
90
90
90
90
90
90
90
80
Start-up
Date
1979s
1983
1983
1983
1983
1983
1983
1983
1983
1984
1985
1985
1985
1986
a Catalyst was replaced in 1985, after 6 years operation.
b NQ is high because of the use of flukJized bed incinerator, while other incinerators are multi-stage type.
F-4
-------
APPENDIX G
PARTIAL VENDOR LISTING
Page
Selective Catalytic Reduction G-2
Non-Selective Catalytic Reduction G-4
Selective Non-Catalytic Reduction G-5
Combustion Turbines G-6
Engines G-7
Process Heaters G-8
Low-N0x Burners G-9
G-1
-------
SELECTIVE CATALYTIC REDUCTION
VENDOR LISTING
Company
Contact Name
Phone No.
B&W Hitachi America
20 S. Van Buren Avenue
P.O. Box 351
Barberton, OH 44203
Camet/WR Grace
12000 Winrock Rd.
Hiram, OH 44234
Cormetech. Inc. (Mitsubishi/Corning)
Environmental Technologies
8 East Denison Pkw.
Coming, NY 14831
Engelhard Corporation
Menlo Park, CN-28
Edison, NJ 08818
F W Energy Applications. Inc. (IHI)
(A Foster Wheeler Company)
8 Peach Tree Hill Rd.
Livingston, NJ 07039
Hitachi Zosen
150 E 52nd St.
New York, NY 10022
Johnson Matthey
Catalytic Systems Division
436 Devon Park Dr.
Wayne, PA 19807
Joy Technologies, Inc. (Kawasaki)
404 East Huntingdon Drive
Monrovia, CA 91016
MHI/Combustion Engineering
Houston, TX
Nippon Shokubai
101 East 52nd Street (14th floor)
New York, NY 10022
Ed Campobenedetto
Alan Thomas
Carmo Pereira
Ed Smith
Reda Iskandar
216-860-6762
301-659-9111
301-534-4335
215-887-0911
607-974-4313
Ken Burns
John Byrne
Jack Pdcer
Bhuban Agarwal
Andi Akita
John Kamerosky
Paul White
Bert Brown
Ted Behrens
Rick Martinez
Yojiro Takahashi
201-632-6640
201-321-5153
201-535-2271
201-535-2372
212-355-5650
215-341-8505
215-341-8544
818-301-1100
818-301-1215
713-652-9230
212-838-5258
(continued)
G-2
-------
(CONTINUED)
Company Contact Name Phone No.
Nitrogen Nergas Corp. Werner Henke 318-232-2142
P.O. Box 51932
Lafayette, LA 70505
Norton Chemical Process Products Steve Turner 216-673-5860
P.O. Box 350
Akron, OH 44309
Steuler International Corporation Manfred Grove 215-682-7171
Farmington Road
P.O. Box 38
Mertztown, PA 19539
G-3
-------
NON-SELECTIVE CATALYTIC REDUCTION
VENDOR LISTING
Company Contact Name Phone No.
Engelhard Corporation Ken Bums 201-632-6640
Menlo Park, CN-28
Edison, NJ 08818
Nitrogen Nergas Corp. Werner Henke 318-232-2142
P.O. Box 51932
Lafayette, LA 70505
G-4
-------
SELECTIVE NON-CATALYTIC REDUCTION
VENDOR LISTING
Company Contact Name Phone No.
Exxon Research and Engineering Donald E. Shaneberger 201-765-1307/2339
P.O. Box 101 Don Krider
Florham Park, NY 07932
Fuel Tech Bryan Luftglass 203-323-8401
61 Taylor Reed Place
Stanford, CT 06906
G-5
-------
COMBUSTION TURBINE MANUFACTURER USTING
Company
Contact Name
Phone No.
Allison Gas Turbine Division
P.O. Box 420
Indianapolis, IN 46206
Asea Brown Boveri
1460 Livingston Avenue
North Brunswick, NJ 08902
General Electric Company
1 River Road
Schenectady, NY 12345
General Electric Company
One Neumann Way MD N156
Cincinnati, OH 45215-6301
KWU/Siemens
Solar Turbines Incorporated
9250 Skypark Court
San Diego, CA 92123
United Technologies
Turbo Power
308 Farmington Avenue
Farmington, CT 06302
Peter J. Hart
Septimus Van der Linden
Marvin Schorr
Charles Steber
Douglas Todd
Ed D. Sailer
Jim Thompson
Gerald Napierala
Roger L Swingle
William H. Day
317-230-4106
201-932-6319
518-385-3036
518-385-9670
518-385-3791
512-552-5432
813-723-4350
619-694-6512
619-544-5778
203-677-3419
G-6
-------
ENGINE MANUFACTURER USTING
Company
Contact Name
Phone No.
Catepillar, Inc.
100 NE Adams St.
Peoria, IL 61629-6480
Cooper Bessemer
150 Lincoln Ave.
Grove Cfty, PA 16127
Cooper Ajax/Superior Division
Springfileld, OH
Cummins Engine Company, Inc.
P.O. Box 3005
Columbus, IN 47202
Fairbanks Morse Engine DM?
701 Lawton Ave.
Beloit, Wl 53511
Waukesha
1000-T St. Paul Ave.
Waukesha, Wl 53188
Don Dowdall
Joe Taucher
Bruce Chrismann
Hugh Daugherty
Paul Danyluk
Paul Cannestra
309-675-5362
412-458-8000
Ext. 4124
513-327-4200
812-377-3263
608-364-8228
414-547-3311
G-7
-------
PROCESS HEATER MANUFACTURER LISTING
Company Contact Name Phone No.
Foster Wheeler Corporation Larry Mac Evory 201-535-2297
Fired Heater Division
8 Peachtree Hill Rd.
Livingston, NJ 07039
JohnZink Bill Johnson 918-747-1371
4401 S. Peoria
Tulsa. OK 74105
Lummus Crest Tom Gronauer 201-893-2823
1515 Broad St.
Bloomfield, NJ 07003
G-8
-------
LOW-NO* BURNER MANUFACTURER LISTING
Company
Contact Name
Phone No.
ABB Combustion Engineering Systems
1000 Prospect Hill Road
Windsor, CT 06095
Alzeta Corporation
2343 Calle Del Mundo
Santa Clara, CA 95054
Babcock & Wilcox
20 S. Van Buren Avenue
Barberton, OH 44203
Cleaver-Brooks
Milwaukee, Wl
Coen Company, Inc.
1510 Rollins Road
Burtingame, CA 94010
Foster Wheeler Energy Corporation
Perryville Corporate Park
Clinton, NJ 08809
John Zink Company
P.O. Box 702220
Tulsa. OK 74170
Keeler Dorr-Oliver
77 Havemeyer Lange
Stamford, CT 06904
Process Combustion Corporation
P.O. Box 12866
Pittsburg, PA 15241
Riley Stoker Corporation
9 Neponset Street
Worchester, Massachusetts
Zum Industries
1422 East Avenue
Erie, PA 16503
Mike McCartney
Richard C. LaFiesh
John Marian
Wayne Krill
Paul Cioffi
Al Larue
Doug McDonald
Jim White
Jon Backland
Chet Binasik
Wayne Wieszczyk
Joel Vatsky
Richatd T. Waibel
Roger Moble
Richard A. Giberti
Robert Kelly
Peter B. Nutcher
John J. Marshall
Robert A. LJsauskas
David A. Harris
Roy Caldwell
Frank D. Vona
203-285-4677
203-285-2583
203-285-4539
408-727-8282
216-753-4511
414-962-0100
415-697-0440
201-730-5450
918-748-5105
918-747-1371
203-358-3500
717-326-3361
412-655-0955
508-792-4826
508-792-4802
508-852-7100
814-452-6421
G-9
-------
APPENDIX H
CONVERSION FACTORS
H-1
-------
CONVERSION FACTORS
[Standard conditions are 77°F (25°C) and 1 atm.;
NOX (ppm at
NOX (ppm at x% Oz) '
.9 — X
NOX (IblMMBtU) = NOX (ppm at x%
20.9 - x
FD x 1.17 x 10
'7
NOX (ppm at x% OJ = NOX (mglm3 at x% CX) f-L] x (22.4) x f
\46) \
'298
,273
A/0X (ppm at 15%
NOX (g/bhp-hff
16;6"3-2?
12-0 + z
where:
FD for natural gas
FQ for oil
FD for wood
F for coal
Z for natural gas =3.5
Zfordiesel
BSFC
BSFC average
= 8,740 dscf/MMBtu at standard conditions
= 9,220 dscf/MMBtu at standard conditions
= 9,280 dscf/MMBtu at standard conditions
= 9,820 - 10,140 dscf/MMBtu at standard conditions (depending on coal
type)
= hydrogen/carbon ratio of the fuel
=1.8
= brake specific fuel consumption, g/hp-hr
= 7,276 Btu/hp-hr which represents engine efficiency of 35 percent for all engines.
Use lower heating value (LHV) of fuel to convert to g/hp-hr: LHV (gas) = 20,000
Btu/lb; LHV (diesel) = 18,320 Btu/lb (see Reference 6 for details).
H-2
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO
EPA-600/2-91-029
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Sourcebook: NOx Control Technology Data
5. REPORT DATE
July 1991
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Lisa M. Campbell, Diana K. Stone, and
Gunseli S. Shareef
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
Radian Corporation
3200 E. Chapel Hill Road/Nelson Highway
Research Triangle Park, North Carolina 27709
11. CONTRACT/GRANT NO.
68-02-4286, Tasks 92, 102,
and 117
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final;
14. SPONSORING AGENCY CODE
EPA/600/13
15.SUPPLEMENTARY NOTES AEERL project officer is Charles B. Sedman, Mail Drop 4, 919/
541-7700.
16. ABSTRACT rj-^g repOrt ( a compilation of available information on the control of
nitrogen oxide (NOx) emissions from stationary sources, is provided to assist new
source permitting activities by regulatory agencies. The sources covered are com-
bustion turbines, internal combustion engines, non-utility boilers and heaters, and
waste incinerators. The report discusses the background of NOx formation in the
combustion process and major NOx sources, and describes processes for NOx con-
trol. The current status of NOx control technology is discussed, and applications
to meet permitting requirements are detailed. Permitted NOx emission levels are
summarized by combustion source, fuel type, and control technology. Documentation
includes references and contacts for further information.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COS AT I Field/Group
Pollution
Nitrogen Oxides
Combustion
Gas Turbines
Internal Combustion Engines
Boilers
Heating Equipment
Incinerators
Pollution Control
Stationary Sources
Waste Incinerators
13 B
07B
21B
13G
21K
13A
13B
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
168
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
H-3
------- |