United States ' Office of Air Quality
Environmental Protection Planning and Standards
Agency Research Triangle Park NC 27711
EPA-450/3-92-004
February 1992
Air
ฉEPA Summary of NOx
Control Technologies
and their Availability
and Extent of Application
-------
-------
EPA-450/3-92-004
Summary of NO
Control Technologies
and their Availability
and Extent of Application
Emission Standards Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
February 1992
-------
-------
DISCLAIMER
This report has been reviewed by the Emission Standards Division
of the Office of Air Quality Planning and Standards, EPA, and
approved for publication. Mention of trade names or commercial
products is not intended to constitute endorsement or
recommendation for use.
ii
-------
-------
TABLE OF CONTENTS
Page
1.0 INTRODUCTION 1-1
2.0 DESCRIPTION OF NOY CONTROL TECHNOLOGIES 2-1
J^
2.1 CONTROL TECHNOLOGIES FOR COMBUSTION SOURCES . 2-1
2.1.1 Theory of NOX Formation 2-1
2.1.2 Control of NOX by Modification of
Combustion Operating Conditions ... 2-3
2.1.3 Control of NOX by Modification of
Combustion Equipment 2-10
2.1.4 Control of NOX by Flue Gas Treatment . 2-16
2.1.5 Control of NOX by Fuel Modification . 2-17
2.2 CONTROL TECHNOLOGIES FOR NONCOMBUSTION
SOURCES . 2-20
2.2.1 Extended Absorption 2-20
2.2.2 Nonselective Catalytic Reduction (NSCR) 2-21
2.2.3 Selective Catalytic Reduction (SCR) . 2-21
2.2.4 Thermal Reduction 2-21-
2.3 REFERENCES FOR CHAPTER 2 2-22
3.0 AVAILABILITY AND EXTENT OF APPLICATION 3-1
ป
3.1 SUMMARY OF NOX EMISSIONS FROM STATIONARY
SOURCES 3-1
3.2 CONTROL TECHNOLOGIES FOR BOILERS 3-1
3.2.1 Utility Boilers 3-7
3.2.2 Industrial, Commercial, and Institutional
Boilers 3-25
3.3 CONTROL TECHNOLOGIES FOR COMMERCIAL AND
RESIDENTIAL SPACE HEATERS . . . 3-35
3.4 CONTROL TECHNOLOGIES FOR PRIME MOVERS ... 3-37
3.4.1 Internal Combustion Engines 3-37
3.4.2 Gas Turbines 3-44
3.5 CONTROL TECHNOLOGIES FOR MUNICIPAL WASTE
COMBUSTORS 3-50
3.5.1 Combustion Controls 3-50
3.5.2 Post-Combustion Controls 3-53
3.6 CONTROL TECHNOLOGIES FOR INDUSTRIAL PROCESSES
INVOLVING COMBUSTION 3-56
3.6.1 Petroleum Refining and Chemical
Manufacturing Process Heaters and
Boilers 3-56
iii
-------
TABLE OF CONTENTS
Page
1 i" i '
3.6.2 Petroleum Refining Catalytic Crackers
and Carbon Monoxide Boilers 3-63
3.6.3 Metallurgical Processes ....... 3-63
3.6.4 Glass Manufacturing 3-64
3.6.5 Cement Manufacturing 3-64
3.7 CONTROL TECHNOLOGIES FOR NONCOMBUSTION
INDUSTRIAL PROCESSES 3-65
3.7.1 Nitric Acid Plants 3-65
3.7.2 Adipic Acid Plants 3-67
3.7.3 Explosives Manufacturing Plants ... 3-67
3.8 REFERENCES FOR CHAPTER 3 . . . 3-68
iv
-------
LIST OF TABLES
TABLE 2-1.
TABLE 3-1.
TABLE 3-2.
TABLE 3-3.
TABLE 3-4.
TABLE- 3-5.
TABLE 3-6.
TABLE 3-7.
TABLE 3-8.
TABLE 3-9.
TABLE 3-10.
TABLE 3-11.
TABLE 3-12.
NOX FORMATION POTENTIAL OF SOME
ALTERNATIVE FUELS
NATIONAL ESTIMATES OF NITROGEN OXIDES
EMISSIONS IN 1985 . .
COMBUSTION CONTROLS FOR COAL-FIRED UTILITY
BOILERS
PARTIAL LIST OF COAL-FIRED LOW NOX BURNER
APPLICATIONS
COMBINED NO /SO CONTROL TECHNOLOGIES BEING
EVALUATED UNDER THE CLEAN COAL TECHNOLOGY
PROGRAM
COMBUSTION CONTROLS FOR OIL AND GAS-FIRED
UTILITY BOILERS .
PARTIAL LIST OF GAS AND OIL-FIRED NOX
BURNER APPLICATIONS .
Page
2-19
3-2
3-9
3-12
3-18
3-19
3-22
NOX RETROFIT CONTROLS APPLICABLE TO INDUSTRIAL,
COMMERICAL, AND INSTITUTIONAL BOILERS FIRED
WITH COAL . 3-27
NOX RETROFIT CONTROLS APPLICABLE TO INDUSTRIAL,
COMMERICAL, AND INSTITUTIONAL BOILERS FIRED
WITH DISTILLATE OIL
3-28
NO RETROFIT CONTROLS APPLICABLE TO INDUSTRIAL,
COMMERICAL, AND INSTITUTIONAL BOILERS FIRED
WITH RESIDUAL OIL
3-29
X RETROFIT CONTROLS APPLICABLE TO INDUSTRIAL,
COMMERICAL, AND INSTITUTIONAL BOILERS FIRED
WITH NATURAL GAS
3-30
PERFORMANCE SUMMARY OF LOW-NO,. CONTROL
EQUIPMENT FOR NATURAL GAS-FIRED
RESIDENTIAL HEATERS 3-36
PERFORMANCE SUMMARY OF LOW-NO-.. CONTROL
EQUIPMENT FOR DISTILLATE OIL-FIRED
RESIDENTIAL HEATERS 3-38
-------
TABLE 3-13,
TABLE 3-14.
LIST OF TABLES
PETROLEUM REFINERY PROCESSES FOR WHICH
LOW-NOX BURNER DATA ARE APPLICABLE . .
CHEMICAL INDUSTRY PROCESSES FOR WHICH
LOW-NO... BURNERS ARE REPORTED TO BE
IN USE . .
Page
3-59
3-60
vi
-------
LIST OF FIGURES
Page
Figure 2-1. Typical boos arrangement for opposed
fire unit 2-6
Figure 2-2. NOX reburning with gas . 2-9
Figure 2-3. Staged air burner 2-11
Figure 2-4. Staged fuel burner 2-13
vii
-------
-------
1.0 INTRODUCTION
Section 185B of the new Subpart 2 of the Clean Air Act
Amendments of 1990 directs the Environmental Protection Agency,
in conjunction with the National Academy of Sciences, to conduct
a study on the role of ozone precursors in tropospheric ozone
formation. The study is to include an examination of the
availability and extent of controls for sources of oxides of
nitrogen (NOX), which include nitric oxide (NO) and nitrogen
dioxide (NO2). As required by Section 185B, this report has been
prepared to summarize the extent and availability of NO,, controls
J^
for stationary air pollution sources.
Chapter 2 provides an overview of the types of NO,, controls
jฃ
that can be used to control NOX emissions from combustion and
noncdmbustion sources. Brief descriptions of each generic
technology alternative are presented to acquaint the reader: with
the fundamental principles of NO., control and with the
Ji
terminology used in Chapter 3.
Chapter 3 identifies the major categories of stationary NOX
sources and provides information on the applicability of control
alternatives for each type of source. For each source category,
information is provided on the current availability of control
alternatives and on the extent of its development and use.
Additionally, 'information is provided where available on the
performance of each control technology alternative in controlling
NOX emissions.
1-1
-------
-------
2.0 DESCRIPTION OF NOX CONTROL TECHNOLOGIES
This section describes the major technologies that can be
used to control NOX emissions from stationary sources. The
descriptions presented below are generic in that they are
intended to provide a broad perspective on the concepts of NO
J^
controls. For combustion sources, these concepts involve
controls that address the combustion process and those that
involve flue gas treatment. For noncombustion sources, control
concepts involve process modifications alone or in combination
with tail gas cleanup.
2.1 CONTROL TECHNOLOGIES FOR COMBUSTION SOURCES
In general, there are four approaches to controlling NOX
emissions from combustion sources:
Control of NOX formation by modification of combustion
operating conditions;
Control of NOX formation by modification of combustion
equipment;
Control of NOX formation by fuel switching; and
Postcombustion control of NOX by'flue gas treatment.
Because the first three approaches involve reducing
formation of NOX/ it is important to understand the basic
mechanisms by which NOX is formed during combustion.
Descriptions of these mechanisms are presented in Section 2.1.1.
The control approaches for reducing NOX emissions are described
in Sections 2.1.2 through 2.1.5.
2.1.1 Theory of NO.. Formation
jt ' '
During combustion, NOX formation occurs by three
fundamentally different mechanisms: thermal NO..., fuel NOV, and
ซ* jฃ
prompt NOX. Each of these mechanisms is described below.
2.1.1.1 Thermal NQ^. Thermal NOX results from the thermal
fixation of molecular nitrogen and oxygen in the combustion air.
Its rate of formation is extremely sensitive to local flame
temperature and, to a lesser extent, to local oxygen
concentrations. Virtually all thermal NO., is formed in the
Ji
2-1
-------
region of the flame at the highest temperature. Maximum thermal
NOX production occurs at a slightly lean fuel-to-air ratio due to
the excess availability of oxygen for reaction within the hot
flame zone. Control of local flame fuel-to-air ratio is critical
in achieving reductions in thermal NOX.
In general, the control mechanisms available! for reducing
the formation of thermal NOY are:
.A.
Reduction of local nitrogen concentrations at peak
temperature;
Reduction of local oxygen concentrations at peak
temperature;
Reduction of the residence time at peak temperature; and
Reduction of peak temperature.
Because'it is quite difficult to reduce nitrogen levels,
most control techniques have focused on the remaining three
mechanisms1.
2.1.1.2 Fuel NOX. Fuel NOX derives from the oxidation of
organically bound nitrogen in fuels such as coal and heavy oil.
Its formation rate is strongly affected by the ra.te of mixing of
the fuel and air in general and by the local oxyg'en concent ration-
in particular. Typically, the flue gas NOX concentration
resulting from the oxidation of fuel nitrogen is a fraction of
the level that would result from complete oxidation of all
nitrogen in the fuel. Although fuel NOX emissions tend to
increase with increasing fuel nitrogen content, the emissions
increase is not proportional. Thus, fuel NOX formation, like
thermal NOX formation, is dominated by the local combustion
conditions1.
Although fuel-bound nitrogen occurs in coal and petroleum
fuels, the nitrogen-containing compounds in petroleum tend to
concentrate in the heavy resin and asphalt fractions upon
distillation. Therefore, fuel NOX formation is of importance
primarily in residual oil and coal firing. Little or no fuel NOX
formation is observed when burning natural gas and distillate
oil1. In general, the control strategy for reducing fuel NOX
2-2
-------
formation for high nitrogen fuels involves introducing the fuel
with a sub-stoichiometric amount of air (i.e, a "rich" fuel-to-
air ratio). In this situation, fuel-bound nitrogen is released
in a reducing atmosphere as molecular nitrogen (N2) rather than
being oxidized to NOX. The balance of the combustion air enters
above or around the rich flame in order to complete combustion.
Here, as with thermal NOX, controlling excess oxygen is an
important part of controlling NOX formation1.
2.1.1.3 Prompt NO^. Prompt NOX is produced by the
formation first of intermediate hydrogen cyanide (HCN) via the
reaction of nitrogen radicals and hydrocarbons in the fuel,
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-NOY emitters2.
J^
2.1.2 Control of NOX by Modification of Combustion Operating
Condi t i ons
As discussed above, the rates of formation of both thermal
and fuel NOX are dominated by combustion conditions. Therefore,
modifications of combustion operating conditions can have a
substantial impact on the formation of NOY.
J^
Retrofit of NOX controls implemented by combustion
modification usually proceeds in several stages, depending on the
emission limits to be reached. These modifications can involve
one or more of the control strategies described below. First,
fine, tuning of combustion conditions by lowering excess air and
adjusting the burner settings and air distribution may be
employed. If NOX emission levels are still too high, minor
modifications, such as employing biased burner firing or burners
out of service, may be implemented. If further reductions of NOY
J*L
are necessary/ these modifications may be followed by other
retrofits, including installation of overfire air ports, flue gas
recirculation systems, and/or low-NOY burners.
J^
2.1.2.1 Low Excess Air (LEA)2. For all conventional
combustion processes, some excess air is required in order to
ensure that all fuel molecules are oxidized. In the LEA approach
2-3
-------
to NOX control, less excess air (oxygen) is supplied to the
combustor than normal. The lower oxygen concentration in the
burner zone reduces the fuel nitrogen conversion to NO...
J^
Additionally, in the flame zone, fuel-bound nitrogen is converted
to N2, thus reducing formation of fuel NOX. The limiting
criteria which define minimum acceptable excess air conditions
are increased emissions of carbon monoxide and smoke, and a
reduction in flame stability.
Adjustments of air registers, fuel injector positions, and
overfire air dampers are operational controls which can reduce
the minimum excess air level possible while maintaining adequate
air/fuel distribution. However, LEA controls require closer
operator attention to ensure safe operation. Continuous LEA
[ i
operations require the use of continuous oxygen (and preferably
carbon monoxide) monitoring, accurate and sensitive air and fuel
flow controls, and instrumentation for adjusting air flow at/
various loads.
LEA operation has an economic incentive since it results in
increased fuel efficiency. It may be used with all fossil fuels.
LEA operations may be used as the primary NCX, control method or
i J^
in combination with other NOX controls discussed below, such as
low-NOx burners, overfire air, or flue gas recirculation.
2.1.2.2 Off-Stoichiometric (OSC) or Staged Combustion1.
With off-stoichiometric or staged combustion methods, initial
combustion is conducted in a primary, fuel-rich combustion zone.
Combustion is then completed at lower temperatures in a second,
fuel lean zone. The sub-stoichiometric oxygen introduced with
the primary combustion air into the high temperature, fuel-rich
zone reduces fuel and thermal NOX formation. Combustion in the
secondary zone is conducted at lower temperature, thus reducing
thermal NOX formation. This approach can be used for combustion
of all fossil fuels. Operational modifications incorporating the
staged combustion concept include biased burner firing (BBF),
burners out of service (BOOS), and overfire air (OFA), discussed
below. In addition, low-NOx burners, discussed in
Section 2.1.3.1, incorporate the staged combustion concept.
2-4
-------
Biased Burner Firing consists of firing the low rows of
burners more fuel-rich than the upper rows of burners. This
modification may be accomplished by maintaining normal air
distribution to the burners while adjusting fuel flow so that a
greater amount of fuel enters the furnace through the lower rows
of burners than through the upper row. Additional air required
for complete combustion enters through the upper rows of burners,
which are fired fuel-lean.
Burners Out of Service combustion operations involve using
individual burners or rows of burners to admit air only (see
Figure 2-1). Correspondingly, the total fuel demand is supplied
through the remaining fuel-admitting or active burners.
Therefore, the active burners are firing more fuel-rich than
normal, with the remaining air required for combustion being
admitted through the inactive burners.
Overfire Air combustion involves firing the burners more -
fuel rich than normal while admitting the remaining combustion
air through overfire air ports or an idle top row of burners.
This modification is more attractive in original designs than in
retrofit applications because of cost considerations, including
costs of additional duct work, furnace penetrations, extra fan
capacity, and physical obstructions making retrofit difficult in
some installations. Also, OFA is usually more easily implemented
on large units than on small ones, because larger proportional
increases in furnace size and cost may be required to assure
complete fuel combustion. Overfire air is integral to retrofit
low-NOx combustion control technology for tangentially fired
boilers-all commercially available systems include some OFA with
redesigned low-NOx coal and air nozzles3'4.
2-5
-------
O Active burners
19C Burners admitting air only
Figure 2-1. Typical boos arrangement for opposed fire unit.
2-6
-------
2.1.2.3 Flue Gas Recirculation (FGR) or Exhaust Gas
Recirculation (EGR)*.The FGR approach to NOX control is based
on recycling a portion of flue gas back to the primary combustion
zone. This system reduces NOX formation by two mechanisms.
First, heating in the primary combustion zone of the inert
combustion products contained in the recycled flue gas lowers the
peak flame temperature, thereby reducing thermal NOY formation.
A,
Second, to a lesser extent FGR reduces thermal NOX formation by
lowering the oxygen concentration in the primary flame zone.
The recycled flue gas may be pre-mixed with the combustion
air or injected directly into the flame zone. Direct injection
allows more precise control of the amount and location of FGR.
In order for FGR to reduce NOX formation, recycled flue gas must
enter the flame zone.
The use of FGR has several limitations. The decrease in
flame temperature alters the distribution of heat and lowers fuel
efficiency. Because FGR reduces only thermal NOX, the technique
is applied primarily to natural gas or distillate oil combustion.
Additionally, FGR is more adaptable to new designs than as a
retrofit application.
2.1.2.4 Reduced Air Preheat (RAP)2. Reduced air preheat is
limited to equipment with combustion air preheaters, and can be
implemented by bypassing all or a fraction of the flue gas around
the preheater,- thereby reducing the combustion air temperature.
Reducing the amount of combustion air preheat lowers the primary
combustion zone peak temperature, thereby reducing thermal NOY
J^
formation. Because the beneficial effects are limited to the
reduction of thermal NOX/ this approach is economically
attractive for only natural gas and distillate fuel oil
combustion. 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.
2-7
-------
2.1.2.5 Reburn2. Reburn, also referred to as in-furnace
I "' III I ' . !' i ij1 , i,,,
NOX reduction or staged fuel injection, is the only NOX control
approach that is implemented in the furnace zone (i.e, the post-
combustion, preconvection section). Reburning involves passing
the burner zone products through a secondary flame or fuel-rich
combustion process (see Figure 2-2). This 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.
Reburning can be implemented either by redistributing the
fuel and air through the existing burner pattern or by installing
_ i" '"ll ' . . ;< ' '.' *" '. ' . "'. ' ..
additional fuel and air ports above the burner pattern, with the
latter approach likely to yield the best results. The burner
pattern plus overfire air ports provide an existing, potential
capability to implement the reburn control approach. In fact,
the BOOS approach implemented on some units to achieve fuel-rich
primary combustion (see Section 2.1.2.2) may also result in
partial reburning. The LEA (see Section 2.1.2.1) and FGR (see
Section 2.1.2.3) controls are combustion modification techniques
often combined with reburning.
2.1.2.6 Steam/Water Inj.ection1. Injection of steam or
water into the combustion zone can decrease flame temperature,
thereby reducing the formation of thermal NO... Because steam and
in i Jt
water injection reduce NOX by acting as a thermal ballast, it is
important that the ballast reach the primary flame zone. To
accomplish this, the ballast may be injected into the fuel,
combustion air, or directly into the combustion chamber.
Water injection may be preferred over steam in many cases,
due not only to its availability and lower cost, but also to its
potentially greater thermal effect. In gas- or coal-fired
boilers that are equipped for standby oil firing with steam
atomization, the atomizer offers a simple means for injection.
Other installations may require a developmental program to
determine the degree of atomization and mixing with the flame
2-8
-------
Burnout Zonซ
Figure 2-2. No reburning with gas,
2-9
-------
required, the optimum point of injection, and the quantities of
water or steam necessary to achieve the desired effect.
The use of water injection may entail some undesirable
operating conditions, such as decreased thermal efficiency and
increased equipment corrosion. This technique has the greatest
f i " ' : '> "' >. '. '.: < ; i
operating costs of all combustion modification schemes, with a
fuel and efficiency penalty typically about ten percent for
utility boilers and about one percent for gas turbines.
Therefore, it has not gained much acceptance as a NOX reduction
technique for stationary combustion equipment except for gas
turbines.
2.1.3 Control of NO., by Modification of Combustion Equipment
Ote "r ~~J " ~ L -1-
The NOX controls under this category include measures that
may require significant changes in combustion equipment, either
through substantial retrofitting or equipment replacement.
2.1.3.1 Low-NO^. Burners (LNB)2. The specific design and
configuration of a burner has an important bearing on the amount
of NOX formed during the combustion process. Certain design
types have been found to give greater emissions than others.
Specific low-NOx burner configurations that have been used or
tested in a variety of boiler and process heater applications are
described in Chapter 3. The most common approach, discussed
below, is to control NOX formation by carrying out the combustion
in stages.
Staged air burners are two-stage combustion burners which
are fired fuel-rich in the first stage (Figure 2-3). 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 primary combustion :zone inhibits
fuel NOX formation. Radiation of heat from the primary
combustion zone results in reduced temperature. The longer, less
intense flames resulting from the staged combustion lower flame
temperatures and reduce thermal NO... formation.
J^
Staged air burners generally lengthen the flame
configuration so that their applicability is limited to
installations large enough to avoid impingement. The
2-10
-------
STAGED AIR IS MIXED
WITH THE COMBUSTION
PRODUCTS FROM THE
PRIMARY ZONE. THIS
LOWERS THE PEAK FUME A
TEMPERATURE WHICH +A
UMITS THE FORMATION If
OF NO. ^. If
SyB-STOICHIOMETRlC
SrpS5?J5JN PRIMARY20NE
'NS?EASE THE AMOUNT OF
REDUCING AGENTS {H2 & CO).
STAGED AIR
SECONDARY AIR
PRIMARY AIR
Figure 2-3. Staged air burner.
2-11
-------
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, installing air flow baffles, or reshaping the
burner throat. Staged air burners can be used for all fuel
types.
Staged fuel burners also use two-stage combustion, but mix a
portion of the fuel and all of the air in the primary combustion
zone (Figure 2-4). The high level of excess air greatly lowers
the peak flame temperature achieved in the primary combustion
zone, thereby reducing thermal NOX formation. 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 gases simulate flue gas
recirculation. Heat is transferred from the first stage
combustion products prior to the second stage combustion and, as
a result, second stage combustion is achieved with lower partial
pressures of oxygen and temperatures than would normally be
encountered.
The staged fuel burner can be operated 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. Whereas in the first stage zone in the staged
air burner cooling of the combustion products is accomplished
primarily by radiation, in a staged fuel burner the entrained
products give additional cooling to the flame. This particular
characteristic permits more intense combustion with reduced
2-12
-------
SECONDARY COMBUSTION
HIGH AIR TO FUEL
RATIO IN PRIMARY ZONE
SECONDARY FUEL
COMBUSTION
AIRซ
SECONDARY FU&
CONNECTION
PRIMARY FUEL
CONNECTION
Figure 2-4. Staged fuel burner.
2-13
-------
levels. Unlike staged air burners/ staged fuel burners are only
designed for gas firing.
2.1.3.2 Burner Spacing. The interaction between closely
spaced burners, especially in the center of multiple-burner
installations, increases flame temperature at these locations..
Therefore, there is a tendency toward greater NOX emissions with
tighter spacing and a decreased ability to radiate to cooling
surfaces. Therefore, in most new utility boiler designs,
vertical and horizontal burner spacing has been widened to
provide more cooling of the burner zone area. In addition, the
furnace enclosures are built to allow sufficient time for
complete combustion with slower and more complete heat release
rates.' Also, furnace plan areas have been increeised to allow for
larger heat transfer to the cooling walls1.
Horizontal burner spacing is largest for tarigentially fired
boilers with the burners located at each corner of the furnace.
Flames in these units interact only at the center of the furnace
and, as a result, radiate widely to the surrounding cooling
surfaces before interacting with each other. In addition, the
tangential firing configuration results in slow mixing of fuel
with the combustion air. For these reasons, tangentially-fired '
boilers generally may have baseline, uncontrolled NOY emissions
< .
below those for other firing configurations. It is important to
note, however, that other types of boilers installed since the
new source performance standards were issued have uncontrolled
NOX emissions that compare favorably with tangentially-fired
boilers1'5.
2.1.3.3 Derating/Load Reduction2. Thermal NO., formation
111 , , Jt i*
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 enlarged fireboxes in new units. This
control option is applicable to all fuel types.
Reduced firing rates can lead to several operational
problems. The reduced mass flow can cause improper fuel-air
2-14
-------
mixing during combustion, creating carbon monoxide and soot
emissions. This situation can be alleviated by operating at
excess air levels higher than normally maintained at the original
design load. This increase in oxygen 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 NOY reduction similar to
Jlป
load reduction on existing units, without necessitating an
increase in excess air levels.
2.1.3.4 Catalytic Combustion. Catalytic combustion refers
to combustion occurring in close proximity to a solid surface
which has a special catalyst coating. A catalyst accelerates the
rate of a chemical reaction, so that substantial rates of burning
can be achieved at low temperatures, thereby reducing the
formation of NOX. Moreover, the catalyst itself serves to
sustain the overall- combustion process, minimizing stability
problems. Catalytic combustion can be effective in reducing NO...
*v
emissions, as well as emissions of carbon monoxide and unburned
hydrocarbons. However, at present this control option has very
limited applicability due to catalyst degradation at high
temperatures (above.1000ฐC (1830ฐF)). While it may be applicable
to gas turbines, its development for this purpose has been
limited to prototype combustors1'6.
2-1.3.5 Air-to-Fuel Adjustment2. In injection type engines
used as prime movers, including all diesel and many dual-fuel and
natural gas engines, the air-to-fuel ratio for each cylinder can
be adjusted by controlling the amount of fuel or air that enters
each cylinder. These engines are therefore operated lean, where
combustion is most efficient and fuel consumption is optimum.
Although the oxygen availability will increase, the capacity of
the air and combustion products to absorb heat will also
increase. Consequently, the peak temperature will fall,
resulting in lower NOX formation rates. The limiting factor for
2-15
-------
lean operation is the increased emissions of hydrocarbons at the
lower temperatures.
2.1.3.6 Ignition Timing Retard2. Ignition timing retard is
a NOX control technique that is applicable to internal combustion
(1C) engines. 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 IDC, the air or air-fuel mixture
is at maximum compression and power output and fuel consumption
are optimum. Retarding causes more of the combustion to occur
during the expansion stroke, thus lowering peak temperature,
'lip ' '' ' ' ,
pressure, and residence time. Typical retard values range from
2ฐ to 6ฐ, depending upon the engine. Beyond these levels, fuel
consumption increases rapidly, power drops, and misfiring occurs.
2.1.4 Control of NOX by Flue Gas Treatment
Flue gas treatment consists of technologies designed to
reduce NOX in the flue gas downstream of the combustion zone or
by treatment in the boiler unit. These technologies can be used
as the sole basis of control or in addition to the reductions
achieved upstream by combustion operation or equipment
modifications. Flue gas treatment systems are classified as
"selective" or "non-selective" depending on whether they
selectively reduce NOX or simultaneously reduce NOX, unburned
hydrocarbons, and carbon monoxide.
"' !'"',l|i: , ' "!
2.1.4.1 Selective Catalytic Reduction (SCR)2. The SCR
systems usually use ammonia to selectively reduce NOX to N2.
Ammonia, usually diluted with air or steam, is injected through a
grid system into the flue gas stream upstream of a catalyst bed
(e.g., vanadium, titanium, or platinum-based) enclosed in a
reactor. On the catalyst surface, the ammonia reacts with NOV to
J\,
form molecular nitrogen and water.
The reaction of ammonia and NOX is favored by the presence
of excess oxygen. The primary variable affecting NOX reduction
is temperature. A given catalyst exhibits optimum performance
within a temperature range of plus or minus 28ฐC (50ฐF) for
applications where flue gas oxygen concentrations are greater
than one percent. Below this optimum range, the catalyst
2-16
-------
activity is greatly reduced, allowing unreacted ammonia to slip
through. Above the range, ammonia begins to be oxidized to form
additional NOX. Further, excessive temperatures may damage the
catalyst.
2.1.4.2 Non-Selective Catalytic Reduction (NSCR)^. In NSCR
systems, NOX is reduced in the presence of a catalyst by carbon
monoxide in the flue gas, forming N2 and carbon dioxide. The
catalyst used to promote this reaction is usually a mixture of
platinum and rhodium. Use of certain oil additives (e.g.,
phosphorus, zinc) may result in catalyst poisoning.
2.1.4.3 Selective Non-Catalytic Reduction (SNCR)2. The
SNCR systems selectively reduce NOX without employing catalysts.
There are currently two commercially available SNCR systems. In
the Thermal DeNOxฎ system developed by Exxon, gaseous ammonia
(NH3) is injected into the air-rich flue gas to reduce NOX to N2.
In the NOXOUTฎ process, developed by the Electric Power Research.
Institute, a urea type (or amine salt) compound is injected into
the oxygen-rich and/or high temperature convection section of a
boiler to promote NOX reduction. The exact chemical mechanism is
not fully understood, but involves the decomposition of urea
(C(NH2)20) and the reduction' of NO by reaction with NH2.
Temperature is the primary variable for controlling the selective
reactions in both systems.
2.1.5 Control of NO., by Fuel Modification
^^"^^ Jt
While not necessarily considered as a NOX control technique,
modification of fuels can in some cases provide reductions in NO,,
' Jt
formation. Fuel modification techniques that are currently
available or potentially available are discussed below.
2.1.5.1 Fuel Switching1. Conversion to a.fuel with a lower
nitrogen content or one that burns at a lower temperature may
result in a reduction of NOX emissions. As discussed in
Section 2.1.1.2, combustion of natural gas or distillate oils
tends to result in lower NOX emissions than is the case for coal
or heavy fuel oils.
In addition to switching among conventional fossil fuels,
emerging alternative fuels may offer viable longer term fuel
2-17
-------
switching options. A summary of the NOX formation potential of
some alternative fuels is provided in Table 2-1.
. While fuel switching may be an attractive alternative from
the standpoint of NOX emission reductions/ technical constraints
and availability and costs of alternative fuels are major
considerations in determining the viability of fuel switching.
2.1.5.2 Fuel Additives. The use of fuel additives has been
considered for reducing the formation of NOX when the fuel is
burned. Tests were conducted in the early 1970's on 206 fuel
additives burned in an oil-fired experimental furnace. None of
the additives reduced NOX emissions, and some additives
containing nitrogen increased NOX formation7.
An investigation of fuel additives used in ci high-pressure
gas turbine cannular combustor indicated that transition metals
added to Jet A Fuel as organometallic compounds could reduce No..
jฃ
emissions by as much as 30 percent, with manganese, iron, cobalt,
and copper being most effective. However, the investigator
concluded that the resulting pollutants and operational problems
would probably not warrant the additional fuel costs8.
Investigations reported in the early 1970's indicated that
1.0 percent cobalt napthenate reduced NO... emissions in a
1 i " Jt
laboratory burner setup by 16 percent9.
2.1.5.3 Fuel Denitrification. Fuel denitrification of coal
or heavy oils could in principle be used to control fuel NO...
J^
formation. The most likely use of this concept would be to
supplement combustion modifications implemented for thermal NOV
Jฃ
control. Qurrent technology for denitrification is limited to
the side benefits of fuel pretreatment to remove other
pollutants, such as oil desulfurization and chemical cleaning or
solvent refining of coal for ash and sulfur removal. The low
denitrification efficiency and high costs of these processes do
not make them attractive solely on the basis of N'OV control, but
J^
they may prove cost effective on the basis of total environmental
impact.
2-18
-------
TABLE 2-1. NOV FORMATION POTENTIAL OF SOME ALTERNATIVE FUELS
Fuel
Shale Oil
Coal -Oil Mixture
Coal - Liquid
Mixturesa
Methanol
Water- oil emulsion
Hydrogen
Thermal NOY
Moderate
Moderate
Low
Low
Low
High
Fuel NOY
High
Moderate
Unchanged*5
Low
Unchanged
Low
alncludes coal-water, coal-oil-water, and coal-alcohol.
bFuel NOX is probably unchanged unless a significant amount of low
nitrogen oil or methanol replaces part of the coal on a heating
basis.
Source: Reference 1
2-19
-------
2.2 CONTROL TECHNOLOGIES FOR NONCOMBUSTION SOURCES
On a national basis, total emissions of NO,, from
' Jt
noncqmbustion stationary sources are small relative to those from
manmade stationary combustion sources. Noncombustion industrial
process sources accounted for about 8 percent of all stationary
source emissions in the U.S. in 198510. These sources include
various chemical processes, such as nitric acid eind explosives
manufacturing. Since emissions from nitric acid manufacturing
account for a significant amount of noncombustion stationary
source emissions, control techniques for nitric cicid plants are
addressed in this report. Further, since techniques for
controlling NOX emissions from adipic acid manufatcturing plants
are similar to those from nitric acid plants, they are also
included.
The absorption tower, common to all ammonia-oxidation nitric
acid production facilities and to adipic acid pla.nts using the
cyclohexane-oxidation process, is the main source of atmospheric
NOX emissions at these plants. For new plants, NOX emissions can
be well controlled by increasing absorption column pressure,
thereby increasing the efficiency of the absorber, or by
employing processes for producing more highly concentrated acid,
such as the Direct Nitric Acid process or SABAR (Strong Acid By
Azeotropic Reactivation) process. However, these production
alternatives are generally not feasible for existing plants.
Hence, the focus of .this report is on options for controlling
tailgas from absorption towers. The following technologies are
predominantly used.
2.2.1 Extended Absorption11
The final step for producing weak nitric acid involves the
absorption of N02 and N204 to form nitric acid. As N204 is
absorbed it releases gaseous NOX. Extended absorption reduces
NOX emissions by increasing absorption efficiency (i.e., acid
yield). This option can be implemented by installing a single
large absorption tower, extending the height of an existing
tower, or by adding a second tower in series with the existing
tower. The increase in the volume and the number of trays in the
2-20
-------
absorber results in more NOX recovered as nitric acid. This
option can also be implemented at adipic acid plants.
2.2.2 Nonselective Catalytic Reduction (NSCR) -11
In this process, absorber tailgas from nitric acid
production is heated to ignition temperature using ammonia
converter effluent gas in a heat exchanger, and fuel (usually
natural gas) is added. The gas/fuel mixture then passes through
the catalytic reduction unit where the fuel reacts in the
presence of a catalyst with NOX and oxygen to form elemental
nitrogen, water, and carbon dioxide when hydrocarbon fuels are
used. The process is called nonselective because the fuel first
depletes all the oxygen present in the tailgas and then removes
the NOX. Catalyst metals predominantly used are platinum or
mixtures of platinum and rhodium.
2.2.3 Selective Catalytic Reduction (SCR)^
The SCR technique has been described in Section 2.1.4.1. ...
When applied to nitric acid plants, the process is typically
applied downstream of the normal ammonia oxidation process.
Absorber tailgas is passed through a heat exchanger to ensure
that the temperature of the gas is within the operating
temperature range of SCR unit. The gas enters the SCR unitj
where it is mixed with ammonia and passed over a catalyst.
Titanium/vanadium catalysts are most commonly used in nitric acid
plants.
2.2.4 Thermal Reduction11
Thermal (or flame) reduction is used to control NO..
wC
emissions from adipic acid manufacturing by reacting the NO., in
J^
the absorber tailgas with excess fuel in a reducing atmosphere.
In a typical thermal reduction unit,'the NOX-laden stream and
excess fuel (usually natural gas) mixture passes through a burner
where the mixture is heated above its ignition temperature. The
hot gases then pass through one or more chambers to provide
sufficient residence time to ensure complete combustion. For
economic reasons, heat recovery is an integral part of thermal
reduction unit operations.
.2-21
-------
-------
2.3 REFERENCES FOR CHAPTER 2
1. Control Techniques for Nitrogen Oxides Emissions From
Stationary Sources - Revised Second Edition. U.S.
Environmental Protection Agency. Research Triangle Park,
NC. Publication No. EPA-450/3-83-002. January 1983. 428
pp.
2. Campbell, L.M., O.K. Stone and G.S. Shareef (Radian
Corporation). Sourcebook: NOX Control Technology Data.
Prepared for U.S. Environmental Protection Agency. Research
Triangle Park, NC. Publication No. EPA-600/2-91-029. July
1991. 168 pp.
3. Radian Corporation. Analysis of Short-Term Data for
Retrofit of Low NOx Combustion Controls. Paper prepared for
U.S. Environmental Protection Agency, presented to Acid Rain
Advisory Committee, NOX Subcommittee. Washington, DC.
August 27, 1991.
4. Kilkelly Environmental Associates (KEA). Low NOX Burner
.Vendor Summary Report. Draft prepared for U.S.
Environmental Protection Agency. Washington, DC. 1992.
5. Acurex Environmental. Evaluation and Costing of NOX
Controls for Existing Utility Boilers in the NESCAUM Region.
Draft prepared for U.S. Environmental Protection Agency.
Research Triangle Park, NC. September 1991.
6. Midwest Research Institute. Alternative Control Techniques
Document - Stationary Combustion Gas Turbines. Draft
prepared for U.S. Environmental Protection Agency. Research
Triangle Park, NC. July 1991.
7. Martin, G.B., D.W. Pershing and E.E. Berkau. Effects of
Fuel Additives on Air Pollutant Emissions from Distillate
Oil-Fired Furnaces. U.S. Environmental Protection Agency.
Research Triangle Park, NC. Publication No. AP-87. June
1971.
8. Shaw, H. Reduction of Nitrogen Oxide Emissions from a Gas
Turbine Combustor by Fuel Modifications. ASME Transactions.
Journal of Engineering for Power. Volume 95, No. 4, October
1973.
9. Altwicker, E.R., P.E. Fredette, and T. Shen. Pollutants
from Fuel Oil Combustion and the Effects of Additives.
Paper No. 71-14 presented at the 64th annual APCA Meeting.
Atlantic City, NJ. June 1971.
10. The 1985 NAPAP Emissions Inventory (Version 2): Development
of the Annual Data and Modelers' Tapes. U.S. Environmental
Protection Agency. Research Triangle Park, NC. Publication
No. EPA-600/7-89-012a. November 1989.
2-22
-------
;ป': i
11. Midwest Research Institute. Alternative Control Techniques
Document - Nitric and Adipic Acid Manufacturing Plants.
Prepared for U.S. Environmental Protection Agency. Research
Triangle Park, NC. Publication No. EPA-450/3-91-026.
December 1991. 112 pp.
2-23
-------
3.0 AVAILABILITY AND EXTENT OF APPLICATION
OF NOX CONTROL TECHNOLOGIES
This chapter provides a summary of the current state of
development and use of the NOX control technologies summarized in
Chapter 2, including available information on the performance of
each control alternative. The stationary air pollution sources
addressed in this chapter include:
Boilers, including electric utility and industrial/
commercial/institutional boilers;
Commercial and residential space heaters;
Prime movers, including stationary internal combustion
engines and gas turbines;
Municipal waste combustors;
Industrial combustion sources (in addition to industrial.
boilers); and
Noncombustion process sources.
The relative contribution of each of these source categories
to nationwide NOX emissions is discussed in Section 3.1.
Controls for each category are then discussed in Sections 3.2
through 3.6.
3.1 SUMMARY OF NOX EMISSIONS FROM STATIONARY SOURCES
The 1980 nationwide emissions of NOX from all air pollution
sources are. summarized in Table 3-1. Stationary sources
accounted for about 57 percent of total NOX emissions in 1985.
Of all stationary source categories, fuel combustion was by far
the largest source of NOX emissions, with about 90 percent of all
stationary source emissions. Industrial process sources not
involving fuel combustion accounted for about 8 percent of
nationwide stationary source emissions in 1985, with the
remaining 2 percent accounted for by municipal solid waste
combustion and open fires1.
3.2 CONTROL TECHNOLOGIES FOR BOILERS
As discussed in Section 3.1, in 1985 about 90 percent of all
stationary source NOX emissions, or 51 percent of NOX emissions
from all sources in the U.S., were from fuel combustion. Fossil
3-1
-------
TABLE 3-1. NATIONAL ESTIMATES OF NITROGEN OXIDES
EMISSIONS IN 1985
Source Category
Pud Combustion
External Combustion
Residential
Anthracite Coal
Bituminous Coal
Distillate Oil
Residual Oil
Natural Gas
Wood
Electric Generation
Anthracite Coal
Bituminous Coal
Lignite
Residual Oil
Distillate Oil
Natural Gas
Process Gas
Other
Area
Sources
2,035
2,035
406
1
2
75
0
248
81
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
ndustrial
Anthracite Coal
Bituminous Coal
Lignite
Residual Oil
Distillate Oil
Natural Gas
1,418
0
131
0
50
50
1,187
Point
Sources
8,529
7,804
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Total Emissions
(106 Tons)/Year
10,564
9,839
406
1
2
75
0
248
81
%of
All Sources
51
47.8
2.0
0.0
0.0
0.4
0.0
1.2
0.4
% of Stationary
Sources
90.2
84.0
3.5
0.0
0.0
0.6
0.0
2.1
0.7
6,614
12
5,604
381
169
20
419
4
6
6,614
12
5,604
381
169
20
419
4
6
1,127
6
434
27
136
37
274
2,545
6
565
27
186
87
1,461
32.0
0.0
27.2
1.9
.8
.1
2.0
0.0
0.0
12.4
0.0
3.2
.1
.9
.4
7.1
56.5
0.1
47.9
3.3
1.4
.2 ,
3.6
0.0
.1
21.7
:i
5.0
.2
1.6
.7
12.5
3-2
-------
TABLE 3-1. (continued)
Source Category
Process Gas
Coke
Wood
LPG
Bagesse
Other
Area
Sources
0
0
0
N/A
N/A
0
Point
Sources
102
7
85
1
2
18
Total Emissions
(106 Tons)/Year
102
7
85
1
2
18
%of
All Sources
.5
0.0
.4
0.0
0.0
.1
% of Stationary
Sources
.9
0.0
.7
0.0
0.0
.2
Commercial/Institution
Anthracite Coal
Bituminous Coal
Lignite.
Residual Oil
Distillate Oil
Natural Gas
Wood
LPG
Other
210
6
6
N/A
31
52
115
0
N/A
N/A
63
1
23
0
16
3
15
3
0
2
273
7
29
0
47
55
130
3
0
2
13
0.0
.1
0.0
.2
.2
.6
0.0
0.0
0.0
2.3
0.0
.3
0.0
.4
.5
1.1
0.0
0.0
0.0
internal Combustion
Electric Generation
Distillate Oil
Natural Gas
Other
ndustrial
Distillate Oil
Natural Gas
Gasoline
Diesel Fuel
Other
N/A
N/A
N/A
N/A
N/A
725
48
9
38
1
725
48
9
38
1
3.5
.2
0.0
.2
0.0
N/A
N/A
N/A
N/A
N/A
N/A
654
5
644
0
2
2
654
5
644
0
2
2
3.2
0.0
3.1
0.0
0.0
0.0
6.2
.4
0.0
.3
0.0
5.6
0.0
5.4
0.0
0.0
0.0
3-3
-------
TABLE 3-1. (continued)
Source Category
Commercial/Institution
Area
Sources
N/A
Point
Sources
18
Total Emissions
(106 Tons)/Year
18
56 of
All Sources
.1
% of Stationary
Sources
0.2
Engine Testing
N/A
6
6
0.0
.1
Industrial Process
Chemical Manufacturing
Food/Agriculture
Primary Metals
Secondary Metals
Mineral Products
Petroleum Industry
Wood Products
Organic Solvent Evap.
Petroleum Storage/Trans.
Metal/Fabrication
Textile Manufacture
Other/Not Classified
Solid Waste Disposal
Government
Municipal Incineration
Open Burning
Other Incineration
6
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
6
920
171
5
54
20
240
215
74
8
1
2
0
130
926
171
5
54
20
240
215
74
8
1
2
0
136
4.5
.8
0.0
.3
.1
1.2
1.0
.4
0.0
0.0
0.0
0.0
.7
7.9
1.5
0.0
.5
.2
2.0
1.8
.6
0.0
0.0
0.0
0.0
1.2
69
N/A
N/A
N/A
N/A
18
8
6
0
1
87
8
6
0
1
.4
0.0
0.0
0.0
0.0
.7
0.0
.1
0.0
0.0
Residential
On-Site Incineration
Open Burning
60
3
57
N/A
N/A
N/A
60
3
57
.3
0.0
.3
.5
0.0
.5
3-4
-------
TABLE 3-1. (continued)
Source Category
Commercial/Institution
On-Site Incineration
Open Burning
Outer
Area
Sources
7
7
0
0
Point
Sources
5
5
0
0
Total Emissions
(106 Tons)/Year
12
12
0
0
% of
All Sources
.1
.1
0.0
0.0
% of Stationary
Sources
.1
.1
0.0
0.0
Industrial
On-Site Incineration
Open Burning
Other
2
0
1
0
Transportation
Lend Vehicles
Gasoline
Light Duty Vehicles
Light Duty Trucks
Heavy Duty Vehicles
Off-Highway
8,835
8,549
5,139
3,368
1,320
297
153
5
4
0
1
7
4
1
1
0.0
0.0
0.0
0.0
N/A
N/A
N/A
N/A
N/A
N/A
N/A
8,835
8,549
5,139
3,368
1,320
297
153
43.0
41.6
25.0
16.4
6.4
1.5
.7
.1
0.0
0.0
0.0
75.5
73.0
43.9
28.8
11.3
2.5
1.3
Diesel Fuel
Heavy Duty Vehicles
Off-Highway
Rail
3,410
1,825
994
590
N/A
N/A
N/A
N/A
3,410
1,825
994
590
16.6
8.9
4.8
2.9
29.1
15.6
8.5
5.0
Aircraft
Military
Civil
Commercial
126
37
11
78
N/A
N/A
N/A
N/A
126
37
11
78
.6
.2
,1
.4
1.1
.3
.1
.7
3-5
-------
TABLE 3-1. (continued)
Source Category
Vessels
Bituminous Coal
Diesel
Residual 03
Gasoline
Area
Sources
160
0
118
22
19
Point
Sources
N/A
N/A
N/A
N/A
N/A
Total Emissions
(106 Tons)/Year
160
0
118
22
19
% of All
Souross
.8
0.0
.6
.1
.1
% of Stationary
Sources
1.4
0.0
1.0
.2
.2
Miscellaneous
Forest Fires
Forest Managed Fires
Agricultural Burning
Structural Fires
130
34
82
8
6
N/A
N/A
N/A
N/A
N/A
130
34
82
8
6
.6
.2
.4
0.0
0.0
1.1
.3
.7
.1
.1
Grand Total
11,074
9,467
20,541
N/A ป Not Applicable
Source: Reference 1
3-6
-------
fuel boilers used in the electric utility and industrial sectors
comprise the majority of fuel combustion emissions. The
applicability and extent of use of control technologies for
utility boilers are discussed in Section 3.2.1. Control
technologies for industrial, commercial, and institutional
boilers are discussed in Section 3.2.2.
3.2.1 Utility Boilers.
In the U.S., the control of NOX from utility coal-, oil-,
and gas-fired boilers has focused on the use of combustion
controls developed and implemented over the past two decades.
However, in Germany and Japan recent regulations have
necessitated the use of flue gas treatment processes in addition
to combustion controls to achieve some of the lowest NO..
ซ x
standards in the world"*. The following information summarizes
the experience of utilities in the U.S., Germany, and Japan with
both combustion and post-combustion NO., controls. The
J^
information was derived from Reference 3, unless otherwise
indicated. Sections 3.2.1.1 and 3.2.1.2 address NOY controls for
Jฑ
coal-fired utility boilers using combustion modifications and
flue gas treatment, respectively. For oil- and natural gas-fired
utility boilers, combustion modifications and flue gas treatment
techniques to control NOX emissions are discussed in
Sections 3.2.1.3 and 3.2.1.4, respectively.
3.2.1.1 .Coal-Fired Boilers; NO.. Controls bv Combustion
J\, ~ 1- r ~"~^^~ -i -.._._ i._
Modifications. The major combustion controls applicable to coal-
fired boilers include:
Low excess air;
Overfire air;
Low-NOx burners;
Low-NOx burners with overfire air and/or flue gas
recirculation;
Reburning; and
Fuel switching.
Low excess air firing (LEA.) is easy to install in most
utility boilers, both for new and existing units. The LEA
3-7
-------
technique was initially implemented by the utility industry to
increase thermal efficiency and to reduce stack gas opacity due
to acid mist, and it is now often considered more of an energy
conservation measure than a NOX control technique. New designs
and most existing combustion operations incorporate LEA firing as
standard practice2. Because LEA is so predominantly and
routinely used, the remainder of the combustion control
alternatives discussed in this section can be considered to
" i '" . !!!' I- ' '.'""'
supplement NOX reductions that are being achieved with LEA. A
summary of these combustion control techniques for coal-fired
utility boilers is provided in Table 3-2. The data on NOY
J^
reduction performance and controlled emission levels are based on
estimates developed for utilities in the Northeast States for
Coordinated Air Use Management (NESCAUM) region, as reported in
Reference 2. Due to limited data currently available, the actual
percentage reduction of NOX emissions for a given technology may
vary for a specific site from that shown in the table.
Overfire air, where applicable, generally offers a low-cost
approach to achieving NOX reductions. For pulverized coal units,
OFA is applicable to both corner-fired (tangential-fired) and
wall-fired (front and opposed) boilers. Many U.ฃ>. tangential
boilers put into service after the effective date of the federal
new source performance standards (NSPS) come equipped with OFA.
ports. Newer designs that increase the penetration of air into
the furnace for improved second stage performance under deeper
staging have separate ports located above the main burner windbox
(this design is often referred to as advanced overfire air, or
AGFA). However, OFA is not applicable to cyclone boilers and
other slagging furnaces because combustion staging will alter the
heat release profile, significantly changing the slagging rates
and properties of the slag2.
There are two principal design requirements for the retrofit
of OFA ports in existing coal-fired boiler furnaces. First,
there must be sufficient furnace volume above the; top row of
burners to provide adequate residence time to achieve optimum NO.,
J^
reduction performance. Second, the high OFA velocity needed for
good mixing requires installation of several ports, which can
3-8
-------
3-9
-------
affect the structural integrity of the furnace. Also,
penetration into the furnace with the installation of air ports
may result in structural weakness of the boiler tube panels.
There are a number of constraints to retrofitting OFA to a
number of existing utility boilers. At many existing units,
sufficient distance between the top burner and the furnace exit
is not available to achieve the optimum residence time. Further,
the high overfire air velocity needed for good mixing requires
installation of several ports, which can affect the structural
!!' il,, "
integrity of the furnace.
In addition, because OFA uses a large portion of the entire
firebox volume to obtain the needed separation between first and
second stage combustion, unburned carbon in the fly ash as well
as carbon monoxide emissions can be significant if excess OFA
(greater than 25 percent) is used, especially when burning high-
rank bituminous coals. Waterwall corrosion can also be a
significant concern in retrofitting OFA to existing high-sulfur
coal- and oil-fired boilers2.
The NOX control efficiency for OFA is estimated to range
between 15 and 30 percent for boilers installed prior to the
effective date of the NSPS. Post-retrofit NOX levels from these
boilers are anticipated to be in the range of 190 to 210
nanograms per Joule (ng/J), or 0,45 to 0.50 pounds per million
Btu (Ib/MMBtu)from an estimated baseline uncontrolled level of
250 ng/J (0.58 Ib/MMBtu) for tangential or corner-fired units
(14 to 22 percent reduction), and 230 to 280 ng/J (0.55 to
0.65 Ib/MMBtu) from an uncontrolled level of 330 :ng/J
(0.77 Ib/MMBtu) for wall/opposed-fired units2 (16 to 29 percent
reduction).
Because of recent advances in LNB technologies, all major
utility boiler manufacturers, here and abroad, have developed
low-NOx burners that can be used in new and retrofit
applications. Estimates by the Electric Power Research Institute
(EPRI) indicate that the retrofit applicability for LNB is about
50 to 80 percent, depending on firing configuration and boiler
manufacturer2. The performance of low-NOY burners varies
Jป
substantially from one boiler application to another, and from
3-10
-------
one LNB model to another4. Low-N0x burner technology often
includes OFA.
Combined with OFA, the use of low-NOx burners can reduce NO
emissions from coal-fired utility boilers to levels approaching
89 ng/J (0.21 Ib/MMBtu), although full-scale experience at such
low NOX levels is limited. For example, at Allegheny Power
Company's Pleasant Station Unit 2, NOX emissions were reduced
from uncontrolled levels of 410 to 510 ng/J (0.96 to
1.20 Ib/MMBtu) to a controlled level of 170 ng/J (0.40 Ib/MMBtu)
without OFA, and to 140 ng/J (0.33 Ib/MMBtu) with OFA,
representing emission reductions of 58 to 67 percent without OFA
and of 66 to 72 percent with OFA. LOW-NO., burner retrofits
Jt
without OFA have shown NOX reduction potential to levels as low
as 150 to 210 ng/J (0.35 to 0.50 Ib/MMBtu). Table 3-3 lists the
known, commercial coal-fired low-NOx burners, including some
recent domestic and foreign applications2.
In the U.S., wall- and opposed-fired utility boilers
retrofitted with a combination of low-NO_. burners and OFA or AOFA
. " O
include :
Allegheny Power, Pleasant Station Unit No. 2: 650
Megawatt (MWe) unit burning eastern bituminous coal;
San Juan Station Unit No. l: 360 MWe unit burning sub-
bituminous coal; and
Campbell Station Unit No. 3: 778 MWe unit burning eastern
subbituminous coal.
Domestic tangential boilers retrofitted with low-NOx burners
and OFA include2:
Kansas Power and Light, Lawrence Station Unit No. 5: 400
MWe unit;
Public Service of Colorado, Valmont Station Unit No. 5
(165 MWe) and Cherokee Unit No. 4 (350 MWe);
Utah Power and Light, Hunter Unit No. 2; and
Southern Company Services, Smith Unit No. 2 (180 Mwe).
Some low-NOx burners, such as the Separate Gas Recirculation
(SGR) and the Pollution Minimum (PM) burners developed by
Mitsubishi Heavy Industries (see Table 3-3), incorporate FGR in
3-11
-------
TABLE 3-3. PARTIAL LIST OF COAL-FIRED LOW
NOY BURNER APPLICATIONS
Burner Type
LNCFS
CCTFS
SGR
PM
CF/SF
IPS
CCV
HT-NR
BWE-Type
4AF
XCL
LNCB
Manufacturer
ABE-CE
ABB-CE
MHI
Mm-ABB-CE
FWEC
FWEC
Riley Stoker
BHK
BWE
B&W
B&W
Retrofit Applications
Comer-fired Boilers:
U.S.: Utah P&L Hunter Unit 2, PSCC Valmont 165
MWe Unit 5 and Cherokee 350 MWe Unit 4
UK: Fiddler Ferry Unit 1
(Typically used with OFA)
ENEL: Fusina Unit 2 160 MWe
Japan: EPDC Matsushima Thermal Power Station
Unit 1 & 2 (500 MWe each)
US: DP&L Lawrence Unit 5 (recent demo)
Japan: Several new and modified units
Italy: Fiume Santo 320 MWe
A total of 10 utility and large industrial units
retrofitted to date with over 5000 MWe capacity in
US. Installed with or without AGFA
Recently introduced as easy upgrade of CF/SF.
Only pilot-scale data available to date
Central Illinois P&L Duck Creek single wall 400
MWe and two Carolina P&L Roxboro units at 360
MWe each
Wall-Fired Boilers:
Japan: EPDC Matsuura 1000 MWe Unit 1
The Netherlands: Mais Unit 5, Njimegen Unit 13
Finland: 265 MWe Inkoo Unit 4
Wall-Fired Boilers:
Denmark: Asnaes 270 MWe Unit 4, additional
retrofit planned
U.S.: Ohio Edison Edgewater
Italy: Biindisi Sud Unit 2
Demonstration at DP&L Stuart 605 MWe Unit 4 and
some applications in Italy
Reported Performance
25-32 percisnt NOX reduction w/o OFA; 33-
50 percent w/OFA to about 0.28 to 0.31
Ib/MMBtu minimum
10-15 percent NOX reduction without OFA
and up to 49 percent reduction with 30
percent OFA to about 0.27 Ib/MMBtu
30-50 percent NOX reduction with OFA to
0.27 to 0.4D Ib/MMBtu levels
30-50 percwnt NOX reduction at KP&L (.25
to .45 Ib/MMBtu). Capability for 0.2 to
0.25 Ib/MMBtu reported for U.S. coals
50-60 percent reduction from pre-NSPS
boilers to 0.4 Ib/MMBtu;
70-80 percent reduction with AOFA to 0.2
Ib/MMBtu
Reported 7:5 percent reduction from pre-
NSPS boilers without AOFA to levels of 0.2
Ib/MMBtu
50 percent NOX reduction measured on U.S.
retrofits wilh underfire air to levels of 0.43
to 0.53 Ib/lJMBtu
25-50 percent NOX reduction to levels in the
range of 0.32 to 0.40 Ib/MMBtu with
several coal types
50 percent .NOX reduction to about 400 ppm
(0.53 Ib/MIVtBtu)
NOX reduction capability to 0.5 to 0.55
Ib/MMBtu
Anticipated 50 percent NOX reduction to
about 0.50 to 0.60 Ib/MMBtu
(Note: This list includes full-scale as well as pilot-scale demonstrations under controlled combustion conditions in the U.S. and abroad.
Data were obtained from a variety of coal ranks (i.e., low/high volatile coal)).
LNCFS: Low NOX Concentric Firing System
SGR: Separated Gas Recirculation
PM: Pollution Minimum MHI:
CCV: Control Combustion Venturi B&W:
LNCB: Low NOX Cell Burner
HT-NR; Hitachi NOX Reduction
CF/SF: Controlled Flow/Split Flame BWE:
CCTFS: Concentric Clustered Tangential Firing IPS:
System
Source: Reference 2
ABB: Asea Brown Boveri
CE: Combustion Engineering
Mitsubishi Heavy Industries
Babcock & Wilcox
BHK: Babcock Hitachi K.K.
FWEC: Foster Wheeler Energy Corp.
Burmeister & Wain Energy
Internal Fuel Staging
3-12
-------
tangentially-fired boilers to provide a more distinct separation
between the fuel-rich and fuel-lean zones of the burner, thereby
enhancing the degree of NOX control. However, low-NOx burners
designed for wall-fired boilers rarely use FGR2.
Reburning is another technique that can be used for reducing
NOX emissions from coal-fired utility boilers. Although
applicable to most boiler designs, reburning is expected to be
primarily applied to cyclone and wet-bottom boilers, which are
generally difficult to control by other combustion methods. The
technology has been used in Japan on at least one large (600 MWe)
boiler and several oil/gas-fired units in connection with LNB.
Commercialization of this technology in the U.S. awaits the
results of ongoing demonstration projects being conducted at five
utility plants to evaluate the retrofit potential and control
performance. These projects are2:
Illinois Power, Hennepin Station Unit No. 1: 71 MWe unit
employing tangential boiler;
City Water, Light and Power, Lakeside Station Unit No. 7-
33 MWe unit employing cyclone boiler;
Ohio Edison, Miles Unit No. 1: 108 Mwe unit employinq
cyclone boiler;
Public Service of Colorado, Cherokee Station Unit No 3-
158 MWe unit employing wall-fired boiler; and
Wisconsin Power and Light, Nelson Dewey Station Unit No
2: 100 MWe unit employing cyclone boiler.
The reburn technology used in the first two demonstrations
is combined with dry sorbent injection for simultaneous NO /SO
control. The first four demonstrations use natural gas for the
reburning fuel, while the fifth uses pulverized coal. Because of
its clean burning properties, natural gas holds better promise
for a more efficient reburning fuel. One full-scale
demonstration on a tangential boiler has shown NOX reduction from
an uncontrolled level of about 400 ppm to a range of 120 to
150 ppm with a reburn zone stoichiometry of 0.9, for emission
reductions ranging from 62 to 70 percent. Thermal efficiency
reduction for reburning is anticipated to be in the range of
0.1 percent2.
3-13
-------
In addition to the combustion modifications discussed above,
fuel switching is another potential alternative for achieving NOX
emission reductions from coal-fired boilers. As discussed in
Chapter 2, the combustion of oil and gas results in lower NOX
emissions than the combustion of coal. Therefore, for some coal-
1 ปl!,' ' u' , ' i''> ' ,n'
fired utility boilers, conversion to oil or gas may be a
technically feasible means of reducing NOX emissions3.
3.2.1.2 Coal-Fired Boilers; NOX Controls bv Flue Gas
Treatment. Postcombustion controls applicable to coal-fired
utility boilers include the following flue gas treatment .
techniques:
Selective catalytic reduction;
Selective non-catalytic reduction; and
Combined NOX/SOX controls.
Selective catalytic reduction systems have been widely used
on utility boilers in Japan, and more recently in Germany and
Austria. However, in the U.S. SCR application to power plants
has been very limited. The first SCR units to be used on coal-
fired boilers in the U.S. are under construction on two 140 MWe
units at Carney's Point, New Jersey. These units, which will use
low-NOx burners" combined with SCR, have permitted NOX emission
limits of 70 ng/J (0.17 lb/MMBtu)5. In addition, Southern
Company Services, Inc. will soon undertake a test program where
ten different SCR catalysts will be evaluated at a Florida
utility plant2. The Electric Power Research Institute is
sponsoring research at a level of about $15 million over a four-
year period to assess SCR process design, catalyst life,
instrumentation and controls, and plant design on boilers
combusting medium and high sulfur coal at 14 specific locations6.
Japan has about 20 years of full-scale utility experience
with SCR, with recent experience reported to have significant
success, initially, there were concerns about ammonia slip
(i.e., unreacted ammonia leaving the catalyst body), the
formation of ammonia sulfate and bisulfate, and catalyst
poisoning and subsequent deactivation. However, recent reports
indicate that ammonia slip control to levels below 5 ppm of
3-14
-------
ammonia are routine. Ammonium sulfates have been reduced with
the use of different catalyst formulations that minimize the
amount of SO2 to SO3 conversion in the reactor2. It is reported
that SCR systems are still operating without any catalyst
replacement for four to five years for coal-fired boilers in
Japan7.
Today, SCR is used on more than 100 utility boilers in
Japan, of which 40 burn coal2. Through 1990, total SCR-
controlled coal-fired capacity in Japan is 10,900 MWe7. While
most of these plants burn low sulfur coal, some SCR systems are
operated on high sulfur (2.5 percent) coal. For example, the
250 MWe Takehara plant is burning 2.3 to 2.5 percent sulfur coal,
and the SCR system is achieving a NOX removal efficiency of more
than 80 percent7. In Germany, 129 SCR systems have been
installed on over 30,000 megawatts of utility service. Most
utility applications have been retrofits on coal-burning plants.
The sulfur content of 'coal burned in these plants generally
ranges from 0.7 to 1.2 percent. Some wet bottom boilers in
Germany have been retrofitted with SCR, but significant catalyst
degradation due to arsenic oxide poisoning has been reported2.
Reductions of NOX emissions of 70 to 90 percent have been
reported in applications of SCR to utility boilers in Germany and
Japan. Slightly lower NOX reduction efficiencies are generally
found when the initial concentration of NOX entering the reactor
is low because of combustion controls. In applying these foreign
SCR technologies to U.S. utilities, it is likely that application
can be more easily accomplished when the coal burned has low-
sulfur and low-ash2.
The retrofit of SCR on existing power plants can be costly
and complex since, for example, modifications to the boiler
convective ducts are necessary. The SCR reactor must be placed
in the existing flue gas path where the temperature is
sufficiently high for efficient NOX control. Modifications of
the building structure and sootblower relocations are often
necessary to accommodate the equipment installation. Further,
regardless of the configuration and reactor location, the
retrofit of SCR requires boiler modifications and control system
3-15
-------
upgrade. Upgrade of the combustion air fans is always necessary
', '"[i , i ' <"
to accommodate the increase in pressure drop, and an ammonia
monitoring and feedrate control system is necessary to maintain
consistently high NO,., reductions and low ammonia slip at varying
1 ' '".iiSiSi, "!!! ' ' JL
boiler loads2.
Compared to SCR, there is very little experience with
application of SNCR to coal-fired utility boilers. The State of
New Jersey has recently approved an air quality permit for the
225 MWe Keystone plant. The plant, which will use low-NOx
burners combined with SNCR, has a permitted emission limit of
70 ng/J (0.17 lb/MMBtu)5. In the only coal-fired utility
demonstration of urea injection in the United States, the NOXOUTฎ
process was tested on a tangentially-fired boiler. The NOX
emissions were reduced from 225 ppm to 155 ppm, a reduction of
31 percent, after application of combustion modifications2. In
Sweden, the NOXOUTฎ process applied to a 50 MWe front wall-fired
boiler has achieved NO,, emission reductions of 6ฃ> to 75 percent;
!lnป ,i||i , . ' " ! ' " , ,
with ammonia slip less than or equal to 5 ppm8. A 75 MWe
tangentially fired boiler in Germany has achieved NOX reductions
of 35 percent, from 150 ppm to less than 100 ppm-'.
One limitation of SNCR is that it haslimited ability to
follow load changes while maintaining minimal ammonia slip.
Therefore, its application is generally limited to base loaded
boilers. Another limitation of this technology is the formation
of ammonium sulfate and bisulfate when applied to boilers burning
high-sulfur fuels. Therefore, the technology is currently
limited to utility plants fired with low-sulfur fuels. For coal-
fired plants, ammonia contamination of the flyash can be a
significant concern because of landfill restrictions and loss of
revenue from the sale of flyash to cement manufacturers2.
Recent regulatory and technological developments have
resulted in an increased interest in the demonstration of low
cost combined NOX/SOX control technologies as alternatives to
separate SCR or SNCR and flue gas desulfurizatioii systems. The
Clean Air Act Amendments of 1990, with mandates for acid rain
control and attainment of ozone standards, will require many
coal-fired power plants to control both NO.,,, and SO,
3-16
-------
In general, combined NOX/SOX control technologies are not
commercially available. However, many are undergoing
demonstration programs in the U.S., Canada, and Europe.
Table 3-4 lists combined NOX/SOX control technologies that are
currently being demonstrated under the Clean Coal Technology
program sponsored by the U.S. Department of Energy. In addition
to these technologies, a number of existing NO., controls such as
J^
low-NOx burners and urea injection are also being introduced with
other SOX reduction processes and marketed as combined NO /SO
controls2.
3.2.1.3 Oil- and Gas-Fired Boilers: NO.. Controls bv
Ji " -^^^^~ "" M"
Combustion Modifications. Combustion modification controls for
reducing NOX emissions from oil- and gas-fired utility boilers
have been implemented in the U.S. since the early 19707s,
especially in California. As is the case for coal-fired utility
boilers, the use of LEA is standard practice for oil- and gas-
fired boilers. This section provides a summary of experience
with NOX controls that are used in conjunction with LEA, which
are:
Off-stoichiometric combustion, including biased burner
firing and burners-out-of-service;
Flue gas recirculation;
Overfire air;
Low-N0x burners; and
Reburning.
A summary of these controls is provided in Table 3-5.
The off-stoichiometric NOX control methods of biased burner
firing (BBF) and burners-out-of-service (BOOS) are a common low-
cost operational modification applied to oil- and gas-fired
boilers. These techniques are attractive first level NO
controls for existing boilers because few, if any, equipment
modifications are required. The NOX reductions using BOOS on
oil-fired boilers have been reported in the range of 35 to
45 percent. For gas-fired boilers, the reported range is 35 to
55 percent. A reasonable average for this technique is
3-17
-------
a
o
8
g*
3
s
5?
1
t
II
,1
!!
I
X
8
I
I
X
8
1
60
1
BO
" ง*
II
33
l
ง
**3
2
o 35 35
iiซpi,
ง
I
o
I
13
o
1
CQ
CO
o*
i
CO
o
I
3-18
-------
o ฐ
/>
?S|
3-19
-------
40 percent from uncontrolled levels for gas- and oil-fired
boilers2.
Although large NOY reductions can be achieved with BOOS, the
"ป , ,
operational performance of the boiler is somewhat degraded
because of the need to increase excess air to keep carbon
monoxide, hydrocarbons, and smoke emissions in check. Some
limitations in the degree of staging may also result from
difficulty in steam temperature control. Because a flame
stability problem can also result, care must be taken in
selecting the appropriate burners to take out of service and the
degree of staging at each of the remaining burners in service2.
Flue gas recirculation is being used at a number of U.S.
utility plants to control NOX emissions. The FGR is an effective
NOX reduction technique for natural gas- and distillate oil-fired
units but is less effective when the nitrogen content of the fuel
is high, as is the case for residual oil. In California, FGR.
has been used effectively on utility oil- and gas-fired boilers
to achieve reductions in NOX on the order of 40 to 65 percent,
with the highest reductions achieved on the gas-fired boilers.
The NOX reduction levels at individual units are dependent upon
the amount of flue gas that is recirculated (typically 20 percent
or less of the total flue gas) and the initial NOY levels. In
n i ป J^
New York, the Niagara Mohawk Oswego Unit 6 and the Orange and
Rockland Utilities, Inc., Bowline Unit 2 are equipped with FGR,
with levels of controlled NOX emissions reported as 128 and
115 ng/J (0.3 and 0.27 Ib/MMBtu), respectively2.
Overfire air is another potential control alternative.
While OFA has been used to a limited extent in the U.S., it is
generally not a preferred retrofit control for existing oil- and
gas-fired boilers because BOOS can provide similar NO... reduction
. - .i . . A
efficiency at a fraction of the cost and with similar operational
performance losses. Also, high heat release furnaces, built from
the late 1950s to the early 1970s, are generally not suitable for
retrofit of OFA ports because the furnaces are small and there is
insufficient volume above the top burner zone to complete
combustion. However, some units in California have been
retrofitted with OFA ports, with NOX reduction efficiencies
3-20
-------
reported to average 24 percent for oil and nearly 60 percent for
gas. Generally, OFA is used in conjunction with other controls
such as FGR and BOOS2.
Low-NOx burners are another NOX control alternative for oil-
and gas-fired boilers. Low-N0x burners are often evaluated not
as a replacement for the other controls but as additional
combustion modifications needed to stabilize combustion, minimize
furnace vibration, and reduce particulate matter emissions when
higher FGR and OFA rates or additional BOOS are implemented to
attain NOX reductions2. Table 3-6 provides a partial list of
low-NOx burners for oil- and gas-fired applications and their
reported performance.
Reburning is another commercially available NOX control
alternative. However, reburning for NOX control of oil- and gas-
fired boilers has received little attention in the U.S., and no
retrofitting has been performed. A 1991 study investigated the
performance and retrofit potential for the In-Furnace NOV
ฎ x
Reduction (IFNR) reburn process, offered by Babcock & Wilcox and
Babcock Hitachi K.K., along with other combustion and flue gas
treatment controls for five utility boilers in California. In
that study, NOX reduction potential was reported in the range of
47 to 75 percent when IFNR was combined with derating (derating
was considered necessary to provide adequate gas residence time
in the furnace to complete combustion of the staged fuel). In
Japan, the application of the Mitsubishi Advanced Combustion
Technology process combined with low-NO,, burners has been
J^
reported as achieving NOX levels of less than 64 ng/J
(0.15 lb/MMBtu)2.
Combinations of control techniques using combustion
modifications can be used to achieve higher levels of NOV control
jฃ,
than can be achieved with a single technique. For example,
24 units in Southern California Edison's system are currently
controlled with a combination of BOOS, OFA, and FGR. Southern
California Edison's Scattergood Station Unit 3, a gas-fired unit,
has achieved a NOX emission level of 42 ppm from an uncontrolled
level of 1000 ppm, using a combination of FGR and derating, for a
NOX emission reduction of 95 percent. Flue gas recirculation is
3-21
-------
L APPLICATIONS
IX
p.
i
py
J-
1
H
O
o
rt
0]
1
fa
o
en
H
d
1
vo
1
m
M
m
EH
Reported Perfonnance
K
1
<
*J
K
u
|
1
2
J;
f
g
m
0.06 Ib/MMBtu for gas
O.2 Ib/MMBtu for heavy oil
g ง
1 i ซ
Pl^
'l|^ซ
w ^ to
S 5
S'o^ a
ilil
1^ co o
V3 ^ i-i yj
lall
^
I
m
o
1
Q
g
|^
^^
5
50 to 60 percent NOX reduction with
OFA; controlled levels reported were
0.14 Ib/MMBTu for oil and
0.06 Ib/MMBtu for gas
!
s
55
li
H O
o 5
is
w
9
ca
3
2
o
2
NOX reduced to below 0.23 Ib/MMBtu
with OFA and FGR
i
fl
$&
13
ซง
6 -a
9
if
||
5 o
*3 63
11
K g
a
CQ
1
m
1
9
t
25 to 50 percent NOX reduction
projected from controlled levels to 0.06
to 0.08 Ib/MMBtu natural gas and 0.12
to 0.17 Ib/MMBtu for oil
1
i
i
^
CO
&
.5
ง
1
s
i
1
1
9
n
3
ip
S
40 to 50 percent NOX reduction.
Controlled NO_ levels same as ROP<
1
I
!
03
&
1^
13
2 P
il
ฃ
1
ABB-CEt
o
SP
g
Up to 93 percent NOX reduction when
combined with BOOS and FGR to 0.03
to 0.04 Ib/MMBTU at partial load and
0.04 to 0.08 Ib/MMBtu at fall load
i
1
i
ฃ3
g
CQ
ง
O
1
H
1
m
ฃ
1
col
il
.*"!
u
"53 &
a "ป
5 &
to 2
fl
1
m
ป
8
s
a
CO
ซrt *Q)
3 04
1 1 I
b9 ;| jj
ฃH fcป O >
ฃ !'ง< N
s .g s o 8
CO (ฃ CU Z ง
o !|
05 ^
Sงs-< 1
gljf' g'^ &
3-22
-------
used in combination with many low-NOx burner designs to achieve
NOX reductions of 60 to 70 percent. For example, the Mitsubishi
Heavy Industries PMFS. burner uses FGR to achieve a separation
between the fuel jets and the secondary air, ensuring sufficient
time for NOX reduction during staging. Other tests with a
combination of FGR and OFA at reduced boiler load have shown NOX
reductions in the range of 60 to 85 percent2.
3.2.1.4 Oil- and Gas-Fired Boilers; NO^ Controls by Fine
Gas Treatment. As is the case for coal-fired utility boilers,
experience with flue gas treatment technologies for NOX controls
of oil- and gas-fired utility boilers is extremely limited in the
U.S. Therefore, much of the information on the applicability and
performance of these systems is based on the experience of use of
these systems in Europe and Japan, as described in
Section 3.2.1.2. The flue gas treatment systems applicable or
potentially applicable to oil- and gas-fired utility boilers are:
Selective catalytic reduction; and
Selective non-catalytic reduction.
In spite of its relatively easier application on oil- and
gas-fired utility boilers as compared to coal-fired applications,
SCR has not been retrofitted on U.S. utility boilers except for a
few demonstration projects. However, interest in using SCR has
recently increased as NOX emission limits have become more
stringent. This is illustrated by the fact that gas-fired
utilities in Southern California plan to retrofit several
thousand megawatts of capacity with SCR systems by the mid-1990's
to comply with stringent new air pollution requirements7.
The Southern California Edison Company is currently
conducting a demonstration project with an SCR system supplied by
KAH of Germany. In this demonstration, one half of the rotating
air heater serving 107 megawatts of the oil- and gas-fired boiler
has been replaced with a catalytic ceramic surface that will
perform as an SCR reactor while retaining the heat transfer
properties of the air heater. This arrangement is attractive
because it minimizes the space and boiler modification
requirements. A similar arrangement can also be used with the
3-23
-------
SNCR process, where any unreacted ammonia or urea below the
reducing temperature range will reduce NOX further when passing
through the air heater. However, performance and reliance of
this system remain to be demonstrated2.
Most of the comments regarding the applicability and
experience of SCR systems in Japan and Germany, discussed in
Section 3.2.1.2 for coal-fired utility boilers, are also relevant
to use of this technology for oil- and gas-fired boilers. Data
supplied by Mitsubishi Heavy Industries indicates that oil-fired
utility boilers retrofitted with SCR during the 1980'a have
achieved NOX control efficiencies in the range of 75 to
80 percent. In Japan, SCR systems are operating.that have not
had any catalyst additions or replacements for seven to ten years
for oil-fired boilers, and for more than ten years for gas-fired
boilers7.
As with SCR, there has been only limited experience with
SNCR systems on U.S. oil- and gas-fired utility boilers. In an
early 1980's demonstration of Exxon's Thermal DeNfox process, a
SNCR system installed on the Los Angeles Department of Water and
Power Haynes Unit 4 achieved only 35 to 45 percent NOX reduction
efficiency due to the inability of the process to follow boiler
load, difficulty in controlling the amount of ammonia injected as
the load changed, and inefficient mixing of the ammonia in the
gas stream. Since that time, significant improvements have been
made to the Thermal DeNO process such that process guarantees
' " Jt
are currently in the range of 40 to 60 percent NOX reduction.
However, no utility boiler retrofit has taken plaice in the U.S.
since this demonstration2.
Urea injection, using the NOXOUT process, lias recently been
installed on three California oil- and gas-fired boilers. On two
of these boilers, NO., reductions attributed to urea injection
,' ; Jt
were approximately 30 percent with ammonia slip of 20 ppm. On
, i'",!,| ., ' ,,, ป',iip , , I,,,,'" ,|, , ,ii i i| ,: ' ,
the third boiler, NOX reductions were limited to about 20 to
25 percent to minimize ammonia slip. The process* was found to be
very sensitive to temperature fluctuations that result from
routine load changes. In New York, the Long Island Lighting
Company is evaluating urea injection in a gas/oil.-fired utility
3-24
-------
boiler, although as of late summer 1991 no performance
information was available2.
Oil- and gas-fired boilers with flue gas NOX concentrations
of 100 ppm or less attained via combustion controls will likely
be limited to a maximum of 40 percent reduction using SNCR. For
boilers with uncontrolled NOX emissions, the performance of the
urea-based SNCR is estimated to range between 40 and 50 percent,
with less than 5 ppm ammonia slip2.
The same concerns mentioned in Section 3.2.1.2 for
coal-fired boilers regarding the difficulty of maintaining NO
Jt
reduction performance of SNCR systems over a wide range of boiler
loads, and problems associated with the formation of ammonium
sulfate and bisulfate when the technology is applied to boilers
burning high sulfur fuels, are also applicable to the use of SNCR
for oil- and gas-fired boilers. Because of these concerns, SNCR
applicability is principally limited to base-loaded plants
burning natural gas or low-sulfur oil2...
3.2.2 Industrial. Commercial. and Institutional Boilers
Industrial boilers are used in the manufacturing,
processing, mining, and refining industries to provide process
steam and/or hot water for space heating, process needs, and
other uses. Steam may also be produced to generate electricity
(cogeneration). Most industrial boilers range in size from 8.7
to 44 MW (30 to 150 MMBtu/hr), although they are as large as
250 MW (850 MMBtu/hr). Commercial and institutional boilers are
also used for space heating, hot water generation and electricity
generation. They are generally substantially smaller than
industrial boilers, ranging in size from 0.1 MW to 3.6 MW (0.4 to
12.5 MMBtu/hr), but may range up to 29 MW (100 MMBtu/hr)11.
Fuels burned by these boilers are primarily natural gas,
distillate oil, residual oil, and coal. The fuel feed mechanism
is an important characteristic affecting coal-fired boiler NO
emissions. Coal-fired boilers can be either pulverized coal,
stoker, or cyclone units. With pulverized coal units, coal
pulverized to the consistency of powder is pneumatically injected
into the furnace. Combustion begins at the burners and continues
into the furnace volume. The stoker is a conveying system that
3-25 .
-------
feeds coal into the furnace while providing a grate upon which
the coal is burned. The cyclone boiler uses a slagging
precombustor to produce highly turbulent combustion. The
populationof cyclone burners is small,''and"their production has
been terminated because of their high NOX forming potential11.
Nonfoisil fuels, such as wood, bark, agricultural wastes,
and industrial wastes, are also used to a much lesser extent.
Nonfossil fuel-fired boilers generally exhibit low NOX emissions
relative to fossil fuel-fired boilers11.
Tables 3-7 through 3-10 summarize the NOX reductions for
boilers burning coal, distillate oil, residual oil, and natural
gas, respectively, that have been reported for NOX controls based
on combustion modification and on flue gas treatment. Controls
using combustion modification are discussed in Section 3.2.2.1.
Flue gas treatment controls are discussed in Section 3.2.1.2.
3.2.2.1 Combustion Controls. The combustion modification..-
techniquessummarized in Tables 3-7 through 3-10 are not
universally applicable to all boiler types. The following
discussion describes the applicability of each technique and
limitations associated with their retrofit to existing units.
These techniques are:
Low excess air;
Off-stoichiometric combustion, including overfire air,..
burners-out-of-service, and biased burner firing;
Flue gas recirculation; and
Low-NO... burners.
' . i ^*
None of these techniquesare applicable to cyclone
coal-fired boilers. The design limitations of cyclone boilers
required to yield a melted slag are not compatible with the
requirements of the control of NOX emissions by combustion
modification.
Because LEA firing primarily reduces thermal NOX, it is most
effectively used with units burning natural gas eind distillates.
While it can be used for stoker coal-fired boilers, its use
presents potential problems with clinker formation. Low excess
air controls can be applied to all small boilers equipped with
3-26
-------
TABLE 3-7. NOX RETROFIT CONTROLS APPLICABLE TO INDUSTRIAL,
COMMERCIAL, AND INSTITUTIONAL BOILERS FIRED WITH COAL
NOx Control
Technique
LEA
OFA
FGR
SCR
SNCR (ammonia)
SNCR (urea)
Boiler Type
WT/PC
WT/S
WT/S
WT/S
wr/s
wr/s
WT/S
wr/s
wr/s
wr/s
wr/s
wr/s
wr/s
wr/s
wr/s
wr/s
wr/s
wr/s
wr/s
WT/PC
wr/c
wr/c
WT/PC
N/A
wr/c
WT/PC
NOx Emissions
to NOx / 1,000,000 Btu
uncontrolled controlled
a
0.635 0.452
0.634 0.491
0.540 0.412
0.572 0.401
0.468 0.443
0.454 0.312
0.506 0.405
0.483 0.418
0.400 0.283
0.229 0.211
0.353 0.316
0.324 0.310
0.277 0.209
a
%NOx
Reduction
15
29
23
24
30
5
31
20
13
29
8
10
4
25
15
10-20
5-10
40-45
20-30
80-90
60-70
60-70
60-70
60-70
80-90
50-85
Reference
3
12
12
12
12
12
12
12
12
12
12
12
12
12
3
13
13
13
14
13
13
13
13
13
13
15
Page
#
4-80
33
33
33
33
33
33
33
33
33
33
33
33
33
4-80
2-3
2-3
2-3
S.4
2-11
2-9
2-9
2-11
2-11
2-9
5
PC: Pulverized Coal
S: Stoker
C: Cyclone
WT: Watertube
a: Supporting emissions test data not provided
3-27
-------
TABLE 3-8. NOX RETROFIT CONTROLS APPLICABLE TO
INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL BOILERS
FIRED WITH DISTILLATE OIL
NOx Control
Technique
LEA
OFA
BOOS
BBF
FOR
CPPซ)
(ppm)
(ppm)
(ppm)
Low NOx, LEA
Low NOx, Staged Air
Low NOx, Staged Fuel
Low NOx, FOR
LowNOx&FGR
SCR
SNCR (ammonia)
SNCR (urea)
Boiler Type
FT
FT
FA"
WT/Pkg
WT/Pkg
WT/Pkg
WT/Pkg
WT/Pkg
WT/Pkg
N/A
WT/PC
N/A
N/A
FT
FT
WT/Pkg
WT/Pkg
WT/Pkg
WT/Pkg
WT/Pkg
FT
FT
WT
WT
N/A
FT
FT
WT/Pkg
WT/Pkg
FT
FT/WT
NOx Emissions
to NOx / 1,000,000 Btu
uncontrolled controlled
0221 0.197
0224 0.186
a
0.136 0.118
0.098 0.088
0.134 0.125
0.107 0.105
0.154 0.125
0.158 0.134
a
0.154 0.125
a
a
158 123
138 109
136 115
136 104
144 118
0.185 0.152
0.154 0.041
a
a
a
None Found
None Found
%NOx
Reduction
11
17
10-25
13
10
7
2
19
15
15-30
19
50
20
22
21
15
24
18
18
73
10-25
10
10
30-65
50-70
60+
60-70
60+
60-70
20-25
To 90%
Reference
12
12
16
12
12
12
12
12
12
14
12
14
14
17
17
17
17
17
12
12
16
3
3
16
16
18
19
18
19
20
16
Page
#
15
15
50
15
15
15
15
15
15
S.4
21
S3
S.4
A.12
A. 12
A.16
A.16
A.16
19
19
50
4-80
4-80
53
58
M3
2
M3
2
1
73
FT: FirปTubซ
WT: Water Tuba
Pkg Package
N/A Not Applicable
a: Supporting missions data not provktod
3-28
-------
TABLE 3-9. NOX RETROFIT CONTROLS APPLICABLE TO INDUSTRIAL,
COMMERCIAL, AND"INSTITUTIONAL BOILERS FIRED WITH RESIDUAL OIL
NOx Control
Technique
LEA
OFA
FGR
Low NOx, LEA
Low NOx & FGR
SCR
SNCR(ammonia)
SNCR(urea)
Boiler Type
FT
FT
rr
WT/Pkg
wr/pkg
WT/Pkg
WT/Pkg
WT/Pkg
wr/Pkg
wr/Pkg
wr/Pkg
wr/Pkg
WT/Pkg
WT/Pkg
Wl'/FH
WT/Pkg
WT/Pkg
WT/Pkg
WT/Pkg
WT/Pkg
WT/Pkg
WT/Pkg
WT/Pke
FT
WT/Pkg
WT/Pkg
FT
WT/Pkg
WT/Pkg
WT/Pkg
WT/Pkg
Emissions
to NOx / 1,000,000 Btu
uncontrolled controlled
0389 0328
0239 0.227
0213 0201
0256 0236
0278 0.193
0.4S9 0.438
0.436 0368
0217 0.159
0398 0356
02 0.145
0263 0231
0251 023
0386 0305
0.419 0312
0.641 0.572
0217 0.166
0217 0.141
0278 0.194
0.419 0222
0386 0245
0.161 0.157
0.161 0.112
0278 0.193
a
a
a
a
a
a
a
a
%NOx
Reduction
16
5
6
8
31
5
16
27
11
28
12
8
21
26
11
24
35
30
47
37
2
30
31
15
20
5-10
15
70-80
50
35-70
50
Reference
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
3
3
13
20
13
13
15
13
Page
#
25
25
25
25
25
25
25
25
25
25
25
25
25
25
25
31
31
31
31
31
29
29 .
29
4-80
4-80
2-16
1
2-16
2-16
7
2-16
FT: Fire Tube
WT Water Tube
Pkg Package
FE: Field Erected
a: Supporting emissions data not provided
3-29
-------
TABLE 3-10. NOX RETROFIT CONTROLS APPLICABLE TO INDUSTRIAL,
COMMERCIAL, AND INSTITUTIONAL BOILERS FIRED WITH NATURAL GAS
NOx Control
Technique
LEA
OFA
BOOS
BBF
FOR
(ppm)
(Kป0
(ppm)
'ppm)
LowNOx,LEA
Low NOx, Staged Air
Low NOx, Staged Fuel
Low NOx, FOR
Low NOx and FGR
"ppm)
SCR
SNCRf ammonia)
SNCR(urea)
Boiler Type
FT
FT.
FT
FT
FT
WT/Pkjt
WT/Pki
WT/Fka
WT/PkR
WT/Pkg
WT/Pkg
WT/PkK
WT/PkR
WT/Pkj?
N/A
WT/Pkg
WT/Pkg
N/A
N/A
FT
FT
FT
WT/Pkg
WT/PkR
WT/Pkj?
WT/Pkg
WT/PkR
WT/Pkg
FT
FT
WT
WT
WT
FT/WT
FT/WT
FT
FT
FT/WT
FT/WT
FT/WT
FT/WT
FT/WT
FT/WT
FT/WT
NOx Emissions
fcNOx / 1,000,000 Btu
uncontrolled controlled
0.122 0.080
0.132 0.111
0.076 0.072
0.071 0.093
0.105 0.072
0.101 0.079
0.101 0.095
0.117 0.094
0.097 0.079
0.127 0.132
0.075 0.066
0307 0.294
0.257 0.202
0.268 0.222
a
0.084 0.073
0.268 0.073
a
a
64.4 29.7
64.4 22.0
81.7 33.9
0.102 0.036
0.078 0.027
0.079 0.040
0.079 0.03
74 24
80 33
a
a
a
a
a
a
a
a
85 30
a
a
a
a
a
a
a
%NOx
Reduction
34
16
5
-31
31
22
6
20
19
4
12
4
21
17
15-30
13
73
50
20
54
66
59
65
65
49
62
68
59
10-25
5
5
30-65
50-70
60-70
60+
75
65
80-90
To90
50-60
70-80
70-75
50-60
35-70
Reference
12
12
12
12
12
12
12
12
12
12
12
12
12
12
14
12
12
14
14
17
17
17
12
12
12
12
17
17
16.
3
3
16
16
19
18
20
21,22
13
16
13
23
24
13
23
Page
#
4
4
4
4
4
4
4
4
4
4
4
4
4
4
S.4
11
11
S3
S.4
A-16
A-16
A-16
15
15
15
15
21
21
50
4-80
4-80
53
58
2
M3
1
2-13
1
2-13
129
2
2-13
129
FT: FirปTubซ
WT Wiisftub*
Fkf Package
K Supporting Sfnitsions tost data not provided
3-30
-------
forced-air burners. For boilers equipped with natural draft
burners, LEA cannot be used since excess air levels cannot be
controlled. However, some larger cast-iron boilers currently
equipped with natural draft burners can be equipped with forced
draft burners, thereby allowing the use of the LEA control
technique11'12.
Emission test data reported by EPA for 14 small natural gas-
fired boilers, ranging in size from 2.3 to 26 MW (8 to
88 MMBtu/hr) that controlled NOX emissions in the range of 28.4
to 126 ng/J (0.066 to 0.294 Ib/MMBtu) were achieved using LEA
from uncontrolled emissions in the range of 30 to 130 ng/J (0.071
to 0.307 Ib/MMBtu) for reductions ranging from 4 to 34 percent.
In two boilers, NOX emissions were found to increase after
application of LEA, by 4 and 31 percent, respectively. Test data
for six small distillate oil-fired boilers, ranging in size fronr
3.8 to 11 MW (13 to 38 MMBtu/hr), indicated LEA control levels
ranging from 37.8 to 84.7 ng/J (0.088 to 0.197 Ib/MMBtu) from
uncontrolled levels of 41.6 to 95.2 ng/J (0.098 to
0.224 Ib/MMBtu), with NOX emission reductions ranging from 2 to
19 percent. Test data for 14 boilers fired with residual oil,
ranging in size from 2.7 to 30 MW (9 to 100 MMBtu/hr), showed
control levels in the range of 62.4 to 246 ng/J (0.145 to
0.572 Ib/MMBtu) from uncontrolled levels ranging from 85 to
272 ng/J (0.200 to 0.641 Ib/MMBtu), with NOX emission reductions
in the 5 to 31 percent range. Finally, test data was collected
for 11 coal-fired boilers ranging in size from 16 to 29 MW (56 to
100 MMBtu/hr). A variety of boilers, including spreader,
underfeed, overfeed, and vibrating grate stokers are included in
the database. The data indicated that LEA resulted in controlled
NOX emissions ranging from 90 to 211 ng/J (0.209 to
0.491 Ib/MMBtu) from uncontrolled levels of 97.3 to 270 ng/J
(0.229 to 0.635 Ib/MMBtu), with emission reductions ranging from
4 to 30 percent. In all of these sets of data, wide variability
from unit to unit was observed in both controlled and
uncontrolled emissions levels12.
The OFA technique is another control alternative for many
boilers, but its applicability is limited. In general, the OFA
3-31
-------
technique is applicable only to boilers with burners (i.e., gas-,
oil-, and pulverized coal-fired boilers), although OFA ports can
be used in new stoker coal-fired boilers. It is not commercially
available for all.boiler design types, particularly firetube
boilers, and retrofit may not be feasible for most units,
especially package boilers. Further, the technique is generally
not available for boilers with capacities less than 7.5 MW
(25 MMBtu/hr)11.
In regard to the NOX removal efficiency of OFA, performance
test data reported by EPA for three small gas-fired boilers,
ranging in size from 6.5 to 16 MW (22 to 56 MMBtu/hr), showed
that controlled levels in the range of 31 to 61 ng/J (0.073 to
0.142 Ib/MMBtu) were achieved, with emission reductions of 13 to
73 percent reported. Data for a 6.5 MW (22 MMBtu/hr) boiler
burning distillate oil showed that emissions were reduced from an
uncontrolled level of 66.2 ng/J (0.154 Ib/MMBtu) to a controlled
level of 53.8 ng/J (0.125 Ib/MMBtu), an emission reduction of
19 percent. Test data for four small residual oil-fired boilers,
with capacities ranging from 6.5 to 16 MW (22 to 56MMBtu/hr),
showed that controlled NOX levels in the range of 60.6 to
105 ng/J (0.141 to 0.254 Ib/MMBtu) were achieved, with NCL.
, , i ' i >. , i | ' .< < , ' i !' I' .UII,, ' ' X,
reductions ranging from 24 to 47 percent12.
ill: ' i'"'' '' ,,'' ii '' ซi , ' ''I11!','1 i , v ,,'' i i 'i, ' '
Performance data on NOV emissions from small coal-fired
.i ' . ,.< "i1,i i .., ' ~v
boilers using OFA are limited. Overfire air applied to a coal-
fired fluidized-bed combustion boiler rated at 26.4 MW
(90 MMBtu/hr) resulted in an average NOX emission level of
258 ng/J (0.6 Ib/MMBtu) achieved over a two-day period. Compared
with a two-day average of 378 ng/J (0.88 Ib/MMBtu) without OFA, a
NOX emission reduction of 32 percent was achieved12.
In addition to OFA, BOOS and BBF are two other
off-stoichiometric techniques potentially available for NO...
IIILI ' ' , '.III 'I , Jt
control. However, these techniques are applicable only to
boilers that are fired with gas or oil and have multiple burners.
Further, in some cases, BOOS and BBF may require derating of the
boiler if the extra firing capacity of the remaining active
burners is very limited11.
3-32
-------
Flue gas recirculation systems are commercially available
for small boilers with capacities as low as 1.5 MW (5 MMBtu/hr),
although no FGR systems have been installed to date on cast-iron
boilers12. Although FGR systems have been retrofitted on gas-,
oil-, and stoker coal-fired boilers, the technique is not. as
effective for reducing NOX emissions from residual oil- and coal-
fired boilers as it is for gas- and distillate oil-fired units11.
The EPA has conducted emission tests on oil- and gas-fired
boilers using FGR. Tests were conducted over a variety of loads,
excess oxygen levels, and FGR levels. Test results for five
natural gas-fired boilers using FGR, with boiler sizes ranging
from 6.5 to 16 MW (22 to 56 MMBtu/hr), indicated attainment of
FGR-controlled levels ranging from 6.8 to 17 ng/J (0.016 to
0.040 Ib/MMBtu), for a NOX removal efficiency range of 49 to
75 percent. Test data for two distillate oil-fired boilers with
capacities of 6.6 and 17 MW (22 and 56 MMBtu/hr) indicated that
FGR-controlled NOX levels of 17.6 and 65.4 ng/J (0.041 and
0.152 Ib/MMBtu), respectively, were achieved, corresponding to
removal efficiencies of 73 and 18 percent. Test data for two
residual oil-fired boilers with capacities of 6.5 and 9.1 MW (22
and 31 MMBtu/hr) showed FGR-controlled emissions ranging from
47.6 to 82.0 ng/J (0.112 to 0.193 Ib/MMBtu), with a range of NO
J^
removal efficiencies of 3 to 31 percent12.
Low-NOx burners can be installed in many industrial,
commercial, and institutional boilers. Tangential- or wall-fired
pulverized coal boilers can use LNB technology with controlled
and uncontrolled fuel-air mixing. It should be noted, however,
that the majority of coal-fired boilers used in the industrial
and commercial sectors are stoker fed. The LNB system in
combination with LEA is also applicable for retrofit on boilers
fired with oil or gas, primarily on boilers with single
burners11. Not all boilers can be retrofitted with LNB. For
example, staged air and staged fuel LNB are applicable only to
watertube boilers, and are generally not available for boilers
with capacities less than 7.5 MW (25 MMBtu/hr). It should be
noted that one type of LNB, called the radiant or ceramic fiber
burner, is available for natural gas-fired boilers. Burners of
3-33
-------
fiber matrix design are available for single burners from less
than 5 MW (16 MMBtu/hr) and for multiple burners up to 60 MW
(200 MMBtu/hr)25. Retrofit of LNB systems may require derating
of equipment because of the potential for increased flame
lengths, which may result in flame impingement on the furnace
walls11'12.
Test data for three natural gas-fired boilers using low-NOx
burners, with sizes ranging from 18 to 31 MW (63 to
106 MMBtu/hr), indicated attainment of controlled NOX levels of
30 to 39 ng/J (0.07 to 0.09 Ib/MMBtu). Test data for a
distillate oil-fired boiler, rated at 22 MW (75 MMBtu/hr) and
using a low-NOx burner, indicated a controlled NO.K emission level
of 47.3 ng/J (0.110 Ib/MMBtu). Since test data for uncontrolled
NOX emissions were not available for either set of tests, the
reductions in NOX emissions could not be determined12.
3.2.2.2. Post-Combustion Controls. Flue gas treatment
applicable or potentially applicable to industrial, commercial,
or institutional boilers include:
Selective catalytic reduction; and
Selective non-catalytic reduction.
Experience with selective catalytic reduction on industrial,
commercial, and institutional boilers is extremely limited in the
U.S. However, in Japan, SCR has been applied to over 50
industrial boilers firing gas, oil, and coal. Sixty percent of
these boilers fire oil, followed by gas firing (25 percent) and
coal firing (15 percent). The boiler sizes range from 15 to
450 MW (50 to 1,500 MMBtu/hr), with start-up dates from 1977 to
1989. Typical oil-fired boiler NOX reductions range from 80 to
90 percent, with controlled emission levels of 25 to 50 ppm NOX.
In the coal-fired boiler applications, emission reductions range
from 40 to80 percent, with controlled emissions of 60 to 250 ppm
NOX. For the gas-fired boiler applications, typical NOX
reductions are 90 percent, with controlled emission levels of 15
to 30 ppm NOX26.
Selective non-catalytic reduction technology has been
applied to fluidized-bed combustion boilers and wood-fired
3-34
-------
boilers. Over 20 sites have been permitted based on the
application of SNCR. Almost all of the sites are coal or wood-
biomass-fired fluidized bed boilers and conventional wood-
biomass-fired boilers. For the wood and coal-fired SNCR
applications, about 70 percent have NOX permit levels of
0.1 Ib/MMBtu (about 25 ppm at 15 percent 02)26.
3.3 CONTROL TECHNOLOGIES FOR COMMERCIAL AND RESIDENTIAL SPACE
HEATERS
Commercial heating systems can be divided into three general
categories: space heaters, warm air furnaces, and hot water or
steam systems. Residential heating units are characterized by
thermostatipally controlled heating cycles. Natural gas-fired
residential space heating units generally employ single port
upshot or tubular multiport burners. Oil-fired units usually use
high pressure atomizing gun-type burners. Natural gas and
distillate oil are the primary fuels used for commercial and
residential space heating3.
Space heating equipment tuning has been considered as a
potential means of reducing NOX emissions. Tuning involves
normal equipment cleanup, nozzle replacement as required, and
simple scaling and adjustment with the use of field instruments.
However, while tuning can have significant beneficial affects on
reducing emissions of smoke, carbon monoxide, hydrocarbons, and
filterable particulate matter it has been shown to have little
effect on NOX emissions3.
Replacement of heating equipment with equipment designed to
produce lower emissions of NOX is the most viable approach for
achieving significant reductions in NOX emissions from space
heaters. A summary of the major types of residential space
heating equipment alternatives for gas-fired units is provided in
Table 3-11, including NOX, carbon monoxide, and unburned
hydrocarbon emissions, and steady state and cycle efficiencies
for each alternative. As indicated, use of equipment that is
currently commercially available can reduce NOX emissions by up
to 70 to 80 percent over conventional units. Further, equipment
presently under research may have the capability of achieving
3-35
-------
TABLE 3-11. PERFORMANCE SUMMARY OF LOW-NO.. CONTROL EQUIPMENT
FOR NATURAL GAS-FIRED RESIDENTIAL HEATERS
Control
Conventional
Units
Rjufiant
Screen*
Secondary Air
Baffle*
Surface
Combustion
Burner
Perforated
Burner
Modulating
Furnace
Pulse
Combustor
Catalytic
Combustor
Avenge
Operating
Excess Air
(percent)
40-120
40-120
60-80
10
NA
NA
NA
NA
Cyclic Pollutant Emissions, ng/J Heat Input
NOX*
28-45
15-18
22
7.5
7.7
25
10-20
<5
CO
8.6-25
6.4
14
5.5-9.6
26
NA
NA
NA
UHC*
33-33
NA
NA
NA
NA
NA
NA
NA
Steady State
Efficiency
(percent)
70
75
NA
NA
85
75
95
90
Cycle
Efficiency
(jwrcent)
60-65
70
NA
NA
80
70
95
85
Comments
Emissions of CO
and HC can
increase
siemficanflv if
screen is not
placed properly or
deforms.
Requires careful
installation.
Suited for single
port upshot
burners.
Not commercially
available. Still
under
development.
Commercially
available design.
Furnace is
essentially derated.
It requires longer
operation to
deliver a given
heat load.
Currently being
investigated by
AGAL.
Still at me R&D
stage.
* Sum of NO + NO2 reported as NO2.
b Unbumed hydrocarbons calculated as methane (CH^).
NA - Not Available.
Source: References
3-36
-------
even.greater reductions. The same types of information are
presented for oil-fired residential space heaters in Table 3-12.
Application of the control technologies shown in Tables 3-11
and 3-2 to commercial space heating uses has been very limited,
although the potential exists for applying some of them to
commercial units. Compared to residential gas-fired equipment, a
greater percentage of commercial warm air heaters or duct heaters
use power burners instead of naturally aspirated burners. Power
burners generally have more flexibility for excess air control
while maintaining low carbon monoxide and volatile hydrocarbon
emissions. Furthermore, theoretical considerations indicate that
the flame quenching and surface combustor concepts shown in
Table.3-11 could be implemented for commercial systems.
Application of control techniques similar to those for
residential oil burners may also be possible3.
3.4 CONTROL TECHNOLOGIES FOR PRIME MOVERS
Prime movers include stationary internal combustion (1C)
engines and gas turbines used for a wide variety of industrial,
commercial, and municipal uses. Control techniques for 1C
engines and gas turbines are presented in Section 3.4.1
and 3.4.2, respectively.
3.4.1 Internal Combustion Engines
Stationary 1C engines are widely used to generate electric
power, to pump gas and liquids, to compress air for pneumatic
machinery, and for other commercial/industrial uses. The
majority of 1C engines burn natural gas, oil, or are dual fuel
compatible, with about two-thirds using natural gas as the
primary fuel.
Two methods of igniting the fuel-air mixture are used in 1C
engines: compression ignition (CD and spark ignition (SI). All
diesel-fueled engines are CI engines, while all natural gas
engines are SI engines. From a NOX control viewpoint, the most
important distinction between different engine models and types
is whether they burn as fuel-rich or fuel-lean. Rich-burn
engines operate with an air-to-fuel ratio close to stoichiometric
levels, resulting in low excess oxygen levels and therefore low
exhaust oxygen concentrations. Conversely, lean-burn engines
3-37
-------
TABLE 3-12.
FOR
PERFORMANCE SUMMARY OF LOW-NOX CONTROL EQUIPMENT
DISTILLATE OIL-FIRED RESIDENTIAL HEATERS
Control
Conventional
Umu
Fkme Retention
Burner Htซd
CotfroUed
VfixSng BunMC
Hesd
Integrated
Fume* System
Bluซ Flame"
3umcr/Fumปcป
Syftem
nteratl
Recbculation
Average
Operating
Excess
Air
(percent)
50-85
20-40
10-50
20-30
20
10-15
Cyclic Pollutant Emissions,
ng/J Heat Input
NOXซ
37-85
26-88
34
19
10
10-25
CO
15-30
11-22
13
20
4.5-7.5
<30
UHC*
3.0-9.0
02-1.8
0.7-1.0
13.
1.5-2.5
NA
Smoke
Numb*e
32
2.0
<1.0
<1.0
zero
<1.0
Fktticulat*
7.6-30
NA
NA
NA
NA
NA
Steady State
Efficiency
(percent)
75
80-83 (alto
depends on
heat
xchtnger)
80(abo
depends on
he*t
exchanger)
84
84
85
Cyclf.
Efficiency
(percent)
65-70
NA
NA
74
74
NA
Range in NOX emissions is
for residential systems not
equipped with flame
retention burners.
Emissions for other
pollutants are avenges.
Combustible emissions are
relatively low because hot
firebox was used.
Uses optimized burner
head. For new furnace
only. Combustible
emissions are higher than
with burner head because
of quenching in air cooled
firebox.
Vew installation only.
Furnace is commercially
available.
3oth for retrofit or new
installations. Not yet
commercially available in
U.S.
* Sum of NO and NOj reported as NO2.
b Unburned hydrocarbons calculated aa methane.
NA - Not Available.
Source: Reference 3
3-38
-------
operate with significant excess oxygen, resulting in excess
oxygen levels in the exhaust gas stream. All naturally
aspirated, SI four-cycle engines and some turbocharged SI four-
cycle engines burn fuel-rich. All other engines, including all
two-cycle engines and all CI engines burn fuel-lean26'27.
3.4.1.1 Combustion Controls. The major types of combustion
controls currently or potentially applicable to 1C engines are:
Pre-ignition chamber combustion, or "clean burn" engines;
Ignition timing retardation;
Air-to-fuel adjustment (includes turbocharging);
Prestratified charge (PSC);
Exhaust gas recirculation;
Water or steam injection; and
Derating.
For natural gas-fired engines, engine design modifications
in general and clean burn or pre-ignition chamber combustion in
particular have been the most commonly applied NOX control
technologies in the past decade. For oil-fired engines, the most
common technique is injection timing retardation and clean
burn26.
In the pre-ignition chamber combustion NOX control approach,
cylinder heads are structured with small, separately fed,
combustion chambers where a rich mixture is ignited by a spark
plug, combusted, and then expanded into a very lean mixture in
the main combustion chamber. Some engine manufacturers have
developed retrofit kits using this approach. Systems employing
the pre-ignition chamber combustion approach are also referred to
as "clean burn" systems28.
Pre-ignition combustion chamber systems have been shown to
achieve NOX reductions in excess of 80 percent for natural gas-
fired lean-burn engines. Levels of NOV emissions have been
JL
reported in the range of 1.3 to 3.0 grams per horsepower-hour
(g/hp-hr)28.
3-39
-------
Applicability of pre-ignition combustion is currently
limited to constant load uses and to natural gas-fired 1C
engines. Conversion of direct injection diesel engines to pre-
ignition chamber combustion can increase fuel consumption by
10 percent or more. Precombustion chambers were implemented in
the 1980'aby one diesel engine manufacturer, but have been
discontinued due to marginal NOX reductions compared to fuel
efficiency losses. Currently no manufacturers have off-the-shelf
prechamber cylinder heads for diesel engines27'29.
Ignition timing retardation can reduce NOX emissions from
all types of diesel and dual-fuel engines and, in fact, is used
to some extent by virtually all manufacturers of these engines.
While this technique reduces NOY emissions, it also increases
ซ ' ';; ' , ^ป , , , , ,
fuel consumption. In general, a 4ฐ timing retard can result in
NOX reduction of 20 to 34 percent in diesel or dual-fuel engines
with a corresponding 1 to 4 percent fuel consumption penalty.
The amount of NOX reduction per degree of retard decreases with
increasing levels of retard29.
The control effectiveness of ignition timing retardation
varies considerably between direct and indirect injection diesel
engines. Application of this technique to direct injection
engines generally results in a significant reduction in NO..
1 . ' ' Jt
emission and a slight increase in fuel consumption. Conversely,
application to indirect diesel engines has less effect on NO-
', ' "' Ji
emission rates and a greater effect on fuel consumption29.
Adjusting the air-to-fuel mixture ratio is another technique
for reducing NOX emissions from 1C engines. By increasing the
airflow, rich-burn 1C engines can effectively be converted to
lean-burn operation. Engine manufacturers now offer lean-burn
conversion kits for some engines. These kits include a
turbocharger and intercooler for naturally-aspirated engines or
increased qapacity turbocharger and intercooler for turbocooler
engines, along with engine components (i.e., new carburetor and
intake manifolds, cylinder heads, pistons, and ignition system) .
The level of NOV emissions can be reduced to between 1.5 and
' '' "ij,i , ป
2.0 g/hp-hr. from pre-retrofit emission levels in the range of
roughly 9 to 20 g/hp-hr using these kits30. The applicability of
..!, ' :*..' 3-40 ' '
-------
air-to-fuel adjustment to existing engines is limited to those
engine models for which conversion packages are available from
the manufacturer27. .
Existing lean-burn SI engines can, in some cases, reduce
NOX emissions by increasing the air-to-fuel ratio. The
additional air required is accomplished by installing a
turbocharger on naturally aspirated engines, or by replacing an
existing turbocharger with a larger one. The NOX emissions can
be further reduced by adding an aftercooler (or intercooler) to
cool the air downstream of the turbocharger. For diesel engines,
the use of turbocharging as a NOX control measure is very limited
because most engines already use turbochargers. Further,
turbocharging alone will not reduce NOX emissions, but rather it
allows reoptimization of other parameters, such as ignition
timing, which will reduce NOV emissions27'29.
A.
The results of emissions tests conducted on engines
retrofitted with PSC systems indicate that NO- emission levels in
- J^
the range of 1.5 to 2.5 g/hp-hr. are commonly achieved for all
gaseous fuels. The NOX reduction efficiency for natural gas
ranges from approximately 80 to 90 percent. The NOX reduction
efficiency for low Btu fuels may be lower, corresponding to the
lower uncontrolled NOX emissions levels for these fuels, but the
1.5 to 2.5 g/hp-hr. achieved using natural gas is also achieved
using low Btu fuels27. The PSC systems have been successfully
applied to natural gas-fueled engines as well as engines fueled
by digester and landfill gas. The technology can also be used
with sulfur-bearing fuels. However, engines that operate in
cyclic or fluctuating load applications may not be candidates for
PSC technology. There currently is no proven control system that
can operate PSC on a cyclically loaded engine and achieve NOX
reduction levels above 50 percent without a significant increase
in hydrocarbon emissions or serious 'degradation to the
performance of the engine28.
Prestratified charge systems are applicable to naturally
aspirated and turbocharged four-stroke engines. The technology
cannot be applied to fuel injected and blower-scavenged engines.
Retrofit kits are currently available for virtually all candidate
3-41
-------
engines with a rated power output of 100 horsepower or more.
These engines represent more than 90 percent of the existing
candidate population, including engines built in the 1940's. In
addition, retrofit kits can be developed for any candidate
engine, and the development of tailored retrofit kits is
economically practical for engine populations as low as five or
six units27.
In addition to the combustion controls to reduce NO,.
1' ' ' ' " ' ' JW
emissions just discussed, others have been considered for 1C
engines. For example, exhaust gas recirculation (EGR) systems
may be applicable to rich-burn engines. However, data are
currently very limited and the available data indicate that NOV
JL
reductions are very marginal. Manufacturers are currently not
offering EGR for production SI and CI engines27.
Water or steam injection is another NOX emission control
technique that has been considered for 1C engines. However, this
technique does not appear to be a viable control alternative.
Unlike gas-fired turbines, where water/steam injection can be an
effective NOX control technique (see Section 3.4.2.1), 1C engines
have a lubricating oil film on the walls of the cylinders which
minimizes mechanical wearing of reciprocating parts. Water
injection adversely affects this oil film, accelerating engine
wear. This control technique is not available from any engine
manufacturer27.
Although engine derating (or reducing the power output) does
not appear to be a promising method to reduce NO,, emission rates
Jv
from diesel engines, it may be effective for dual-fueled engines.
When NOX emissions are expressed on a grams/hp-hr basis, they
appear to be fairly insensitive to load. Consequently, for a
given amount of work, engine derating is unlikely to reduce NO,,
* ซ*t
emissions from diesel engines. Derating also has minimal NOV
Jfc
reduction potential for natural gas-fueled engines for this same
reason2^.
Coal/water slurries and methanol have been fired in 1C
engines in limited testing to date. Test data foa: coal/water
slurries indicate reduced NOX emissions. Since methanol produces
lower combustion temperatures than natural gas and diesel,
3-42
-------
methanol firing should theoretically produce* lower NOX emissions.
However, data regarding the performance of methanol-fired 1C
engines are not currently available. Neither coal/water slurries
nor methanol is currently being used in any identified commercial
1C engine in the U.S27.
3.4.1.2 Post-Combustion Controls. Post-combustion controls
for 1C engines include:
Selective catalytic reduction (SCR); and
Non-selective catalytic reduction (NSCR).
Since SCR reaction mechanisms require the presence of
oxygen, SCR technology has been applied only to lean-burn
reciprocating and diesel engines where the exhaust gas oxygen
concentrations are high26. A further limit to applicability is
that SCR has only been demonstrated as applicable to engines with
non-cyclical loads28.
In the U.S., applications have largely been limited to
natural gas-fired engines in the past decade, with a recent
application in Massachusetts to a dual fuel-fired diesel engine.
This unit has been operating since September 1988 with apparently
no major problems. The manufacturer claims that this unit will
achieve a NOX reduction of 90 percent and guarantees the catalyst
for five years26'29.
A demonstration program conducted by the South Coast Air
Quality Management District in California on SCR applied to lean-
burn natural gas-fired 1C engines has shown the ability of SCR to
achieve an 80 percent NOX emission reduction level, while source
tests conducted in Ventura County, California, on 19 SCR systems
applied to these types of engines found an average NOX reduction
O Q
level of 87 percent^.
There is very limited experience with this technology for
diesel 1C engines. In Japan, SCR has been applied to natural
gas- and oil-fired engines. Two of these three units started
operation in the 1978-80 period, with another unit coming on-line
in 1989. Reported NOX removals for two of the units have been 85
and 90 percent, although significant daily maintenance is
required to keep the catalyst soot free. In West Germany, SCR
3-43
-------
has been applied to engines firing natural gas, dual fuel, oil,
and landfill gas26'29.
Non-selective catalytic reduction systems reqiiire fuel-rich
engine operation or the addition of a reducing agent in the flue
gas upstream of the catalyst. Therefore, application of this
technology has been limited to rich-burn engines. These systems
are applicable to all natural gas-fired engines with exhaust
oxygen content below 4 percent, and, for engines with exhaust
oxygen concentration of less than 1 percent, the systems can
^ C O Q
achieve reductions of at least 90 percent"so'^ฐ.
The NSCR systems are supplied by many manufacturers for non-
cyclic gas-fired 1C engines. A number of catalyst, manufacturers
guarantee their catalysts for two to three years. Tests of two
65 horsepower engines in Southern California equipped with NSCR
showed NOV reduction levels of 95 and 96 percent. Experience
J\*
with engines rated at less than 0.04 MW (50 hp) is lacking due to
the increasing costs on a per megawatt (horsepower) basis for
smaller engines. About 250 source tests have been conducted on
engines equipped with NSCR in Ventura County with only ten
failing to comply with permitted emission levels of 0.8 g/hp.hr
or 50 ppmv. Of those complying, the average reduction efficiency
op
was about 97 percent"50.
The ability of NSCR to control NOX emissions from cyclically
loaded rich-burn engines has only been demonstrated on a limited
basis. The major problem with the use of NSCR on cyclically
loaded engines is with the varying temperature, oxygen content,
and NOV levels in the exhaust. There are, however, several
J\,
approaches that can be taken to apply NSCR for gas-fired cycling
engines. For example, one manufacturer makes a Ceitalyst/muffler
combination that includes an oversized catalyst and exhaust pipe.
The manufacturer guarantees this system to achieve 90 percent NOX
"y ft
reductions for three years'60.
3.4.2 Gas Turbines
A gas turbine is an internal combustion engine that operates
with rotary rather than reciprocal motion. Gas turbines employ
three types of combustors: annular, can-annular, and silo. There
are four basic types of cycles in which gas turbines are
3-44
-------
operated: simple, regenerative, (regeneration, and combined cycle
operations.
3.4.2.1 Combustion Controls. The major types of combustion
control alternatives applicable or potentially applicable to gas
turbines include:
Water or steam injection;
Low-NOx burners, including lean premixed and rich/lean
combustors;
Catalytic combustors; and
Use of alternative fuels, such as coal-derived gas or
methanol.
The injection of water or steam into the flame area of a
turbine combustor provides a heat sink which lowers the flame
temperature and thereby reduces thermal NOX formation. Water or
steam injection, also referred to as "wet controls", have been
applied effectively to both aeroderivative and heavy duty gas
turbines, and to all configurations except regenerative cycle
applications. It is expected that wet controls can be used with
regenerative cycle turbines, but no such installations have been
identified by EPA. Water injection control systems are generally
available from turbine manufacturers, and most also offer steam
injection control systems31.
Water or steam injection can be added as a retrofit to most
gas turbine installations. One limitation with water or steam
injection is the possible unavailability of injection nozzles for
turbines operating in dual fuel applications. In this
application, the injection nozzle as designed by the manufacturer
may not physically accommodate an additional injection port
required for water or steam. An additional limitation for steam
injection is that it is not an available control option from some
gas turbine manufacturers31.
Reduction efficiencies of 70 to 85+ percent can be achieved
with properly controlled water or steam injection, with NO..
J\t
emissions generally higher for oil-fired turbines than for
natural gas-fired units. The most important factor affecting
reduction efficiency is the water-to-fuel ratio. In general, NO...
J^
3-45
-------
reduction increases as the water-to-fuel ratio increases;
however, increasing the ratio increases carbon monoxide and, to a
lesser extent, hydrocarbon emissions at water-to-fuel ratios less
than one. Further, energy efficiency of the turbine decreases
with increasing water-to-fuel ratio31.
Several types of low-NOx combustors are available for
application to gas turbines. In a lean premixed combustor, the
air and fuel are premixed prior to introduction into the
combustion zone. This.results in a mixture with a very lean and
uniform air-to-fuel ratio for delivery to the combustion zone,
and NOX formation is minimal. To stabilize the flame and to
assure complete combustion with minimum carbon monoxide
emissions, a pilot flame is incorporated in the combustor or
burner design.
Lean premixed combustors are applicable to can-annular,
annular, and silo combustors. They are effective in reducing
thermal NOX for both natural gas and distillate oil, but since
they are not effective on fuel NOX they are not as effective in
reducing NOX levels if high nitrogen fuels are fired. Further,
low NOX emissions when burning oil can only be achieved with
water or steam injection. Also, since low NOX levels are
achieved only at loads greater than approximately 40 to
75 percent, the use of lean premixed combustors is not an
effective control technique at reduced load conditions31.
Virtually all gas turbine manufacturers have initiated
programs to develop lean premixed combustors on a commercial
scale. At the present time, lean premixed combustors are
available for limited turbine models from at least three
manufacturers. Two additional manufacturers project an
availability date of 1994 for some models. All of these
manufacturers state that the lean premixed combustors will be
available for retrofit applications31.
The primary factors affecting the performance of lean
premixed combustors are the type of fuel and the air-to-fuel
ratio. Natural gas produces lower NOV levels than oil fuels. In
^W
fcerms ofthe air-to-ft|el ratio, it must be maintained in a narrow
range 'near'"the lean fiammabiiity limit of the mixture to achieve
- ' ' -..3-46
-------
low NOX emission levels. Lean premixed combust or s are designed
to maintain this ratio at the rated load. At reduced load
conditions the fuel requirement is decreased, the lean
flammability limit of the mixture will be exceeded, and carbon
monoxide emissions will rise dramatically. To avoid these
conditions, a_ll manufacturers' lean premixed combust or s switch to
a conventional combustion mode at reduced load conditions,
resulting in higher NOX emissions31.
Controlled emissions levels for natural gas, without
water/steam injection, range from 25 to 42 ppmv, referenced to
15 percent 02. This range, from uncontrolled levels of 105 to
430 ppmv, is a 60 to 94 percent reduction in NOX emissions. One
manufacturer has achieved levels of 9 ppmv for natural gas fuel,
a reduction of 98 percent. For operation on oil fuel,
water/steam injection is required to achieve reduced NO,.
Jv
emissions levels ranging from 42 to 60 ppmv, a reduction of 79 to
90 percent.31
Rich/lean combustors are another type of low-NO,. burner
Jw
using the staged air combustion concept. These combustors are
applicable to all types of gas turbines. They are particularly
well-suited for controlling NOX when burning fuels with high
nitrogen content. Emission reductions of 40 to 50 percent were
achieved in a test rig burning diesel fuel. Tests on other
rich/lean combustors indicate that NOX emission reductions of 50
to 80 percent can be achieved. At the present time, gas turbine
manufacturers do not have this design available for their
production models. This may be due to current lack of demand due
to the limited use of high nitrogen fuels in gas turbines31.
Catalytic combustors are another potential NO... control
* Jt
technique for gas turbines. Catalytic combustors are applicable
to all combustor types and are effective on both distillate oil
and natural gas fired units. Because of the limited operating
temperature range, catalytic combustors may not be easily applied
to gas turbines subject to rapid load changes (such as utility
peaking turbines). Presently, the development of catalytic
combustors has been limited to bench scale tests of prototype
combustors. The major problem is the development of a catalyst
3-47
-------
that will have an acceptable life in the high temperature and
pressure environment of gas turbine combustors. Additional
issues to be resolved are combustor ignition and the need to
design a catalyst to operate over a range of loads31.
Another control method for gas turbines is fuel
substitution. Use of fuels with flame temperatures lower than
those of natural gas or oil, such as coal-derived gas or
methanol, can result in lower thermal NOX emissions. Turbine
combustor rig tests have demonstrated that burning coal-derived
gas produces approximately 30 percent of the NOX emission levels
obtained from burning natural gas. A demonstration facility,
known as Cool Water, operated using coal gas for five years in
Southern California in the early 1980' s. The NOX emissions were
reported at 30 ng/J (0.07 lb/MMBtu)31.
In regard to methanol, the NOX emissions data for a
full-scale turbine firing methanol without water injection ranged
from 41 to 60 ppmv, and averaged.49 ppmv. Water injection
provided additional reductions. At water-to-fuel ratios from 0.11
to 0.24, NQX emissions when firing methanol ranged from 17 to 28
ppm, a reduction of 42 to 65 percent. The test a.lso indicated
that methanol increases turbine output due to the higher mass
flows resulting from methanol firing. Methanol firing also
increased carbon monoxide and hydrocarbon emissions slightly
compared to the same turbine firing distillate oil with water
injection. All other aspects of turbine performance were as good
as when firing natural gas or distillate oil, and, in addition,
turbine maintenance requirements were estimated to be lower and
turbine life longer than with distillate oil due to fewer
deposits in the combustor and power turbine31.
In terms of retrofitting performance, a 1984 study sponsored
by the California Energy Commission studied the performance of an
existing 3.2 MW gas turbine modified to burn methanol. A new
fuel delivery system was required, but the only major
modifications required for the turbine were new fuel manifolds
and nozzles. Tests showed emissions of NOX in the range of 22 to
38 ppm compared to emissions of 62 to 100 ppm for natural gas,
with NOX emission reductions as high as 65 percent, while no
3-48
-------
visible smoke emissions occurred and only minor increases in
carbon monoxide were experienced31.
3.4.2.2 Post-Combustion Controls. The major types of
postcombustion controls which are applicable or potentially
applicable to gas turbines include:
Selective catalytic reduction; and
Selective non-catalytic reduction.
Selective catalytic reduction is used on a total of 72 gas
turbine installations in the U.S. All of these applications use
SCR to supplement reductions from steam or water injection or
combustion modifications. Carefully designed SCR systems can
achieve NOX reduction efficiencies as high as 90 percent31.
Ammonia slip levels as low as 3 to 5 ppm have been reported, with
vendor guarantees of 10 ppm available32.
Due to its limited temperature operating window, SCR is most
applicable to new combined-cycle/cogeneration installations which
have heat recovery equipment with no flue gas bypass provision.
.Some combined-cycle/cogeneration bypass some of the gas turbine
exhaust to reduce steam flow during off-peak hours or route only
a portion of the turbine exhaust through the., heat recovery steam
generator and use the remainder for direct heating. For these
configurations, much of the exhaust will bypass the SCR reactor
and the turbine exhaust that does enter may be below the minimum
temperature31.
For simple-cycle configurations, the exhaust gas must be
lowered to the required SCR operating temperature, thereby making
SCR expensive for these configurations. Retrofit applications of
SCR involve high capital costs since retrofits require the
addition of a heat exchanger for simple cycle installations, and
replacement of the existing heat recovery steam generator in
combined cycle applications.
The formation of ammonium sulfate and bisulfate is a concern
when using SCR with sulfur-bearing fuels (i.e., distillate and
residual oil and some low-Btu fuels). Formation of ammonia salts
can be avoided only by limiting the sulfur content of the fuel
and/or limiting the ammonia slip. Limiting the ammonia slip to
3-49
-------
levels which inhibit the formation of ammonia salts is possible,
but higher catalyst volume may be needed to achieve the required
NOX efficiency32. Another concern is that SCR may not be readily
applicable to gas turbines firing fuels which produce high ash
loadings or high levels of contaminants because these elements
can lead to fouling and poisoning of the catalyst bed. However,
this may not be a significant impediment to SCR use with gas
turbines since fuels with high levels of ash or contaminants are
typically not used because of concern over damage to the
turbines.
The SNCR system has not been applied to gas turbines to
date. Its application is impeded by several technical issues.
For one thing, the operating temperature window for SNCR (870ฐ to
1200ฐC (1600ฐ to 2200ฐF) without hydrogen injection; 700ฐC
(1300ฐF) with hydrogen injection) is higher than gas turbine.
exhaust temperatures, which do not exceed 600ฐC (1100ฐF).
Additionally, the residence time required for the SNCR reaction
is relative slow for gas turbine operating flow velocities. It
may be feasible, however, to apply this technology within the gas
turbine itself, where operating temperatures fall within the
reaction window, if suitable turbine' modifications and injection
systems can be developed31.
3.5 CONTROL TECHNOLOGIES FOR MUNICIPAL WASTE COMBUSTORS
In general, the three types of. municipal waste combustors
predominantly used in the U.S. are: mass burn units (waterwall or
refractory)/ refuse-derived fuel (RDF) units, and modular units
(excess-air or starved-air). The relative contribution of
thermal Npx" and fuel NOX to the total NOX emitted from municipal
waste incinerators is dependent upon the design and operation of
the furnaceand the nitrogen content of the refuse burned.
Generally, 75 to 80 percent of the total NO., may be fuel NO26.
: -, * *
3.5.1 Combustion Controls-3-3
ป' ' ,|ljl ! , , ' i ' I ' ' I
The types of combustion control techniques that are
applicable to municipal waste combustors are:
Low excess air;
Staged combustion;
3-50
-------
Flue gas recirculation; and
Reburaing.
Low excess air (LEA) and staged combustion can be used
separately or together. With LEA, less air is supplied to the
combustor than normal, lowering the supply of oxygen available in
the flame zone. With staged combustion, the amount of underfire
air is reduced to generate a starved-air condition. Secondary
air to complete combustion is added as overfire air (OFA) . The
effects of LEA and overfire air rate were evaluated at a
municipal waste combustor in Marion County, Oregon, a mass burn/
waterwall unit. Compared to normal operating conditions
(75 percent excess air), LEA conditions (40 percent excess air)
reduced NOX emissions from an average baseline level of 286 ppm
to 203 ppm, a reduction of 29 percent. Under low load
conditions, NOX emissions were reduced from 257 ppm (at
70 percent excess air) to 195 ppm (at 58 percent excess air), a
reduction of 24 percent. During tests of this combustor with
only underfire air (low OFA) but at normal excess air conditions,
NOX emissions decreased by 27 percent at low load (188 ppm versus
257 ppm) and by 23 percent at normal load (220 ppm versus
286 ppm).
Tests at another mass burn/waterwall combustor at Quebec
City, Canada, indicated that use of low overfire air reduced NOX
emissions by about 24 percent compared to tests conducted at
similar load and at higher overfire air rates. For two sets of
test runs, average NOX emissions were reduced from 259 ppmv to
196 ppmv at 7 percent oxygen. A Japanese mass burn/refractory
combustor using automatic controls to obtain combined LEA and
staged combustion conditions demonstrated up to 35 percent
reduction in NOX emissions from emission levels obtained when
using manual controls. The average NOX emission level for this
combustor was 155.5 ppmv34.
The reason that a low overfire air rate generates less NOX
is not certain, but it may be at least partially caused by high
excess air at the grate reducing the peak flame temperature. At
the Marion County combustor, NOX measurements taken during
3-51
-------
testing with high overfire air and normal load (2176 ppm) and low
load (252 ppm) were roughly equal to NOX measurements taken
during tests conducted at similar load with normal air
distribution (286 ppm and 257 ppm, respectively). These data
suggest that use of high overfire air may be ineffective in
reducing NOX emissions from mass burn/waterwall combustors.
Flue gas recirculation (FGR) is another technique for
reducing NOX emissions from municipal waste combustors. At a
mass burn/waterwall unit in Long Beach, California, where FGR is
used to supply 10 percent of the underfire air, inductions in NOX
emissions have been observed, although no quantitative results
are available. At a mass burn/refractory combustor in Tokyo,
Japan, FGR is used to supply 20 percent of the combustion air,
with reported NOX emission reductions in the range of 10 to
25 percent. At higher FGR rates, little increase in NOX
reduction was observed. Two modular excess-air combustors in the
U.S. are using combustion units that have FGR bud.lt into the
system. In these units, FGR supplies approximately 35 percent of
the combustion air. Emissions of NOX from these units have been
measured in the range of 100 to 140 ppm at 7 percent excess
oxygen, although no data are available comparing NOX emissions
with and without FGR.
The METHANE DeNOx (reburning) approach involves the
injection of natural gas, together with recirculsited flue gases
(for mixing), above the grate to provide oxygen deficient
combustion conditions that promote the destruction of NOX, as
well as NOX precursors. A full scale METHANE DeNOx system was
designed and retrofitted to a 100-ton per day Riley/Takuma mass
burn system at the Olmsted County, Minnesota, Wasite-to-Energy
facility for field evaluation. The results of the field
evaluation demonstrated reductions of up to 60 percent in NOx
emissions and up to 50 percent in CO emissions. The average NOX
level was about 80 ppmv at an average CO level oil 35 ppmv.
Further benefits included a reduction of up to 50 percent in
excess air requirements and furnace efficiency improvement^.
3-52
-------
3.5.2 Post-Combust ion Controls-^
Post-combustion controls for municipal waste combustors
include:
Selective catalytic reduction; and
Selective non-catalytic reduction.
Currently there are no applications of SCR to municipal
waste combustors in the U.S. However, this technology has been
applied to municipal waste combustors in Europe and Japan. In
Japan, SCR has been applied to two mass burn municipal waste
combustors using special low temperature catalysts (V2O5 or
Ti02). At one of these sites, a 65 tpd unit in Iwatsuki, Japan,
an average NOX reduction of 77 percent was demonstrated at an
average stack temperature of 395ฐF. Average inlet NO.,
Jt
concentrations for the two units at this site were 215 and
211 ppm, respectively, with outlet concentrations of 43 and
51 ppm, respectively. At the Tokyo-Hikarigaoka 150 tpd municipal
waste combustor, the SCR system demonstrated.an average NCX,
jฃ
reduction of 44 percent at a stack temperature of 475ฐF. The
average inlet NOX concentration was 156 ppm, and the average
outlet concentration was 83 ppm. Ammonia slip averaged 8.5 ppm
and ranged from 0.5 to 14 ppm.
There are several operating considerations regarding the
applicability of SCR. First, the SCR operating temperatures at
both of the Japanese municipal waste combustors exceed the fabric
filter outlet temperature required to achieve maximum control of
dioxin/furans and acid gases. As a result, flue gas reheat may
be necessary to reach the desired catalyst operating temperature,
depending on the location of the catalyst bed. Flue gas reheat
can be a significant expense. Second, performance of SCR can be
detrimentally affected by catalyst poisoning by either metals or
acid gases. Third, ammonia slip can occur. In a properly
operated system, ammonia emissions are typically less than
10 ppm.
In regard to SNCR, long-term performance and reliability
data are limited. One municipal waste combustor, at Wilmington,
North Carolina, is known to use the NOxOutฎ process1.
3-53
-------
The Thermal DeNOxฎ system is being used at sieveral municipal
write,combustions in'the U.S. At a 380 tpd mass burn/waterwall
unit in Commerce, California, ten short-term optimization tests
conducted in conjunction with alternative ammonici injection
locations showed average NOX reduction of 49 percent. Maximum
one-hour NOX emission measurements made in 1989 were less than
150 ppm at 7 percent oxygen on all but six days of a total of
110 days. All of the 24-hour averages were less than 120 ppm at
7 percent oxygen. The estimated average NOX emisปsion reduction
was 44 percent
A mass burn facility in Long Beach, California, has three
waterwall combustors, each with a capacity of 460 tpd. Each
combustor has a Thermal DeNOxฎ system and FGR for NOX control,
with other pollutants controlled downstream by a spray
dryer/fabric filter system. When neither the FGR or Thermal.
DeNOxฎ are in operation, NOX emissions are typiccilly 190 to
230 ppm at 7 percent oxygen. With FGR only, NOX emissions are
typically 160 to 190 ppm. With both FGR and Thejrmal DeNOxฎ, NOX
emissions are reported to be consistently less than 120 ppm, and
frequently less than 50 ppm. These data indicate that the
Thermal DeNOxฎ system reduces NOX emissions at this facility by
30 to 70 percent.
At a mass burn facility in Crows Landing, California, two
400 tpd waterwall combustors are equipped with Thermal DeNOxฎ
systems. Tests performed on these units indicated NOX emissions
without ammonia injection of 297 ppm and 304 ppm,, respectively,
with emissions using ammonia injection of 93 ppm and 113 ppm,
respectively, at 12 percent carbon dioxide. This corresponds to
emission reductions of 69 and 63 percent, respectively.
if ' i , . , i ,,,,11,1, ,.': :i| i, .
There are several potential concerns associaited with
applying the Thermal DeNOx* system to municipal waste combustors.
First, ammonia or ammonium chloride emissions may result when the
ammonia isinjected outside the desired temperature window, at a
higher than normal rate, or when residual acid gas levels in the
stack exceed roughly 5 ppm. At the three facilities discussed
above, ammonium chloride plumes have been observed. Second,
;,,,,' i ' ,; : ii:1! 'I "i11 ' ,;, * i ป', ; , , " ' i 'i. ",'''", '"fii '.: ,,|i: . . . , ' , ' >. '' ' ' y
corrosion of the boiler tubes by ammonia salts has been
' ;;;:'; . . . , ,. . 3-54 ', '..'
-------
hypothesized as a potential problem. However, no boiler
corrosion problems attributed to ammonia salts have been observed
with the U.S. systems during their limited operating time.
Third, increased carbon monoxide emissions have been suggested as
a potential problem. However, at the Commerce, California,
facility, measurements of carbon monoxide emissions taken with
and without operation of the Thermal DeNoxฎ system were
essentially the same.
A recently identified concern with Thermal DeNox* is that
the ammonia injected into the flue gas may reduce control of
mercury emissions by a spray dryer/fabric filter. Compliance
tests at three municipal waste combustor facilities in California
with Thermal DeNOxฎ have shown relatively high mercury emissions
(180 to 900 jig/dscm at 7 percent oxygen) compared to four other
facilities without SNCR.
There are several theories to explain these observed
differences in mercury emissions. One possible explanation is
that mercury is normally in a combined ionic form (principally
HgCl2) that can absorb or condense onto particulate matter at the
low operating temperatures of fabric filters (300ฐF). By
injecting ammonia into the flue gas, pockets of reducing
atmosphere may form which reduce mercury to an elemental form
which is more volatile and difficult to collect. However, data
collected in 1988 at the Commerce, California facility
demonstrated mercury removals while the ammonia injection system
was operating of 91 percent while firing a mixture of 60 percent
commercial refuse and 40 percent residential refuse, and
74 percent while firing a mixture of 95 percent commercial and
5 percent residential refuse. These test results indicate that
ammonia injection may not be the reason for the observed low
mercury removals.
Another theory gaining acceptance is that carbon in the flue
gas enhances adsorption of mercury and that Thermal DeNO has no
J^
effect. This theory suggests that the poor removals of mercury
at the units with Thermal DeNOxฎ are the result of good
combustion leaving little carbon in the fly ash onto which the
mercury could adsorb. Little direct data are available on the
3-55
-------
carbon content of the fly ash at the seven MWC facilities where
mercury emissions have been evaluated. However, it is expected
that ODD/CDF concentrations at the combustor exit, are indicative
of good combustion, and thus provide a surrogate measure for the
carbon content of thefly ash. Data on mercury removal
efficiency and outlet concentrations versus CDD/CDF
,1'i'ir I1 "N i|1''' ซ |ปI 'ปMปi,,| ' , 'mi1 ' ' ; M ,, " i, ' !' , . i ' iip i .', ' ,''''
concentrations at the combustor exits for these facilities
support the theory that reduced carbon content in the fly ash
increases mercury emissions.
Because of the limited amount of mercury emissions data from
municipal waste combustors with Thermal DeNOxฎ and the apparent
strong relationship between fly ash carbon content and mercury
control, the hypothesized detrimental effect of Ihermal DeNOx* on
mercury control by spray dryer/fabric filters cannot be proven
with certainty.
3.6 CONTROL TECHNOLOGIES FOR INDUSTRIAL PROCESSES INVOLVING
COMBUSTION
Fossil fuel derived heat for industrial processes is
: '! '.'ill!:* i, L ,' t,. ; ii ' ' . '. . ,1 '',-">" 'I" '(".,"ป '','ปI'' ' , i*.. " ,': 'id " '','>'
supplied in two ways: (1) by heat transfer media, such as steam
" , 1" , ' '"r! , Mill! ' in .', i|" 1 ,1'Mil' ',,1" ,i i I'll', i! , "'',",, " , ,,' ' , > = . 'I! " '' I 4' "'.I f , , .
direct contact of the raw process material to flames or
combustion products in furnaces or specially-designed vessels.
The first type of equipment has been discussed in the preceding
sections. In this section process heating involving direct
contact is discussed.
3.6.1 Petroleum Ref inincr and Chemical Manufacturing' Process
Heaters and Boilers^
Process heaters are used extensively at petroleum refineries
in a range of refining processes, including distillation, thermal
cracking, coking, thermal cracking, hydroprocessing, and
hydroconversion. Large integrated refineries can have as many as
100 heaters, while small, topping refineries can have as few
as 4. The total number of processheaters in the petroleum
refining industry was estimated by the American Petroleum
Institute in 1980 to be about 3,200 of which 89.6 percent were
natural draft heaters, 8.0 percent were mechanical draft without
preheat, arid 2.4 percent were mechanical draft with preheat.
3-56
-------
Process heaters are also used in a wide variety of
applications in the chemical manufacturing industry. Uses
include fired reactors, feed preheaters for non-fired reactors,
reboilers for distillation, and heating for heat transfer oils.
More than 30 organic chemical and 7 inorganic chemical
manufacturing operations are reported to require process heaters.
3.6.1.1 Combustion Controls, Combustion controls to reduce
NOX emissions from process heaters include:
Low excess air; .
Low-N0x burners;
. Staged combustion air (air lances); and
Flue gas recirculation.
Low excess air using automatic controls has been applied to
more than 50 process heaters in the U.S. Available information
suggests that automatic LEA controls based on flue gas monitoring
are applicable to all new process heaters. Manual and automatic
damper control systems designed to reduce excess air can be used
with natural or mechanical draft heaters fired with oil, gas, or
oil/gas combinations. An assessment of the NO., removal
Jv
efficiencies of 12 process heaters, consisting of 11 natural
draft heaters and l mechanical draft heater, indicates that- an
average 9 percent reduction in NOX accompanies each 1 percent
reduction in excess oxygen level. -
Commercially packaged automatic damper control systems may
not be directly applicable to some specific heater applications.
For example, it may be difficult to equip multicell heaters with
common convection zones and one or more stacks when the cells are
not well balanced with respect to variations in product charge
and fuel firing rates. In these cases, the basic package may
require modification or compromise in achieving minimum low
excess air.
Low-NOx burners are another NOX emission control alternative
for process heaters. Many types of LNB are commercially
available, with most employing staged air, staged fuel, or FGR.
3-57
-------
Staged air, low-NOx burners are most commonly used with existing
process heaters.
In new heaters, low-NOx burners may be used instead of
conventional burners regardless of draft, fuel, or flame type.
Special low-NOX burner designs are available for firing low-Btu
fuels (high intensity low-NOx burners) and for providing uniform
radiant heat transfer from the furnace walls (radiant wall low-
NOV burners) . Burners of fiber matrix design are available for
nป
simple burners from 5 MW (16 MMBtu/hr) and for multiple burners
up to 60 MW (200 MMBtu/hr)25. The use of low-NOx burners for a
specific heater application may be limited if the application has
unusual process requirements. Also, in some retrofitted heaters
the longer burner flame associated with staged air, low-NOx
burners may cause flame impingement problems.
Table 3-13 lists the petroleum refinery process heater
applications known to be using low-NOx burners. The table is not
intended to be a comprehensive list of all refinery heater low-
NOV burnerapplications, but is representative of the heater
rt .
types that are compatible with the use of low-NOx burners. These
applications account for approximately 86 percent of the fired
heater energy used in typical refineries. Table 3-14 lists the
chemical industry process heater applications tha.t are currently
using low-NOx burners, as reported by members of the Chemical
Manufacturers Association.
Tests using a test furnace burning natural gas at 10 percent
excess air showed that at 200ฐF, NOX emissions were roughly
65 ppm compared to about 98 ppm for conventional burners, a
reduction of 34 percent. At 500ฐF, emissions were about 83 ppm
compared to roughly 153 ppm for conventional burners, for a NOX
reduction of 46 percent. For staged fuel low-NO^. burners, the
tests found that at 200ฐF NOX emissions were about 30 ppm, a
reduction of 69 percent compared to the emissions from
conventional burners (98 ppm). At 500ฐF NOX emissions were about
42 ppm, as compared to the emissions of 153 ppm for conventional
burners at this temperature, a reduction of 72 percent. The
tests also found that the effect of fuel type on NOX emissions
is roughly the same for both low-NO.. burners and conventional
Jt
3-58
-------
TABLE 3-13. PETROLEUM REFINERY PROCESSES FOR WHICH
LOW-NOY BURNER DATA ARE APPLICABLE
Heater
Crude heater
Naptha reformer
Vacuum column heater
Debutanizer bottoms reboiler
Hydrodesulfurization preheater
Coke heater
TOTAL
Estimated percent of total
fired heater capacity at
typical petroleum refinery
(energy basis)
26
20
15
2
10
13
86
Source: Reference 36
3-59
-------
TABLE 3-14. CHEMICAL INDUSTRY PROCESSES FOR WHICH LOW-NOX
BURNERS ARE REPORTED TO BE IN USI2
Agricultural chemical
Ammonia (steam hydrocarbon reformers)
Biphenyl
Butadiene
Chlorinated organics/oxides
Cumene
Ethylbenzene/styrene
Isocyanate
Olefins (ethylene pyrolysis furnaces)
PVC and polymers
PVC film
Silicones
Xylene
Source Reference 36
3-60
-------
burners. Emissions of NOX from burners firing oil with
0.3 percent by weight nitrogen were consistently twice as high as
those from comparable burners firing gas.
Staged combustion air, also referred to as air .lances, is an
off-stoichiometric combustion control technique that can be
applied alone or concurrently with LEA and/or low-NO.. burners.
Wk
To date, it has been used only in retrofit applications, but it
could also be used on new heaters. The applicability of this
technique to existing process heaters has been demonstrated in a
long term EPA test and on a commercial basis by at least one
refiner in California. The refinery has been successfully
operating three low temperature heaters retrofitted with natural
draft lances since 1983 with no problems.
Tests performed by EPA on a retrofitted full-scale, natural
gas-fired, vertical, crude heater have shown that natural draft
air lances reduce NOX emissions by 10 to 20 percent relative to
emissions without lances. Uncontrolled NO., emission levels at
Jฃ
5.5 and 3.0 percent oxygen were 67.1 and 54.0 ng/J (0.158 and
0.127 Ib/MMBtu), respectively, compared to emissions controlled
by natural draft air lances of 54.0 and 46.3 ng/J (0.127 and
0.109 Ib/MMBtu), respectively. For forced draft air lances, NO
Ji
reductions of 50 to 60 percent were found relative to emissions
without lances. Controlled emissions were found to be 34.0 and
34.0 ng/J (0.080.and 0.080 Ib/MMBtu) at 5.5 and 3.0 percent
oxygen, respectively.
The applicability of staged combustion air has several
limitations. First, in heaters where the process fluid flow may
be seriously affected by variations from the design heat flux
distribution, as is often the case with reforming heaters and
vacuum heaters, staged air lances may not be applicable. Another
limitation is that in some cases the use of staged combustion air
can lead to a corrosive environment, requiring frequent
replacement of air lances. Finally, the larger flame associated
with staged combustion air may require a larger flame zone in
some heaters.
Flue gas recirculation has been used on only a few process
heaters, and several inherent drawbacks will limit its use in the
3-61 -
-------
future. The most important of these is that the technology is
usually not cost effective because of the increasied energy costs
associated with transporting and reheating the recirculated flue
gas. Another drawback is that FOR requires a relatively large
capital investment because of the need for high temperature fans
and ductwork. In addition, FGR may not be applicable to all
types of heaters. Its low flame temperature and susceptibility
to flame instability limits the use of FGR in high temperature
applications. Furthermore, FGR can only be used on forced draft
process heaters because of the need to recirculate the flue gas.
3.6.1.2 Post^Combustion Controls. Post-combustion NOX
controls for process heaters include:
Selective catalytic reduction; and
Selective non-catalytic reduction.
1 '" ' ' ,, , , ' ,,- " ''. '' *' ' ', . . ' v ., . ;!
Selective catalytic reduction has been instsilled on at least
nine refinery process heaters in California. The refinery
systems were permitted in the early 1980s, with permit emission
levels for all of the units established in the rainge of 0.03 to
0.05 lb/B\MMBtu at about 10 to 15 percent oxygen. One of the
units has been "reported as achieving a NOX emissions reduction of
90 percent, with minimal operator attention required26'36.
Selective catalytic reduction systems are applicable to most
new mechanical draft process heaters, and it has wide
applicability to a variety of processes. For existing heaters,
retrofitting generally requires installation of at fan or ,
additional fan capacity and extensive ductwork. One potential
disadvantage 6f SCR systems is that they may not be applicable to
oil-fired heatersdue to problems with residual oil mist
carryover and catalyst plugging. Selective nonccitalytic
reduction has been installed on several refinery process heaters
in California. While the NOX reduction efficiency of individual
units depends on a number of factors, NOX emission reductions
have generally ranged from 35 to 70 percent.
Selective noncatalytic reduction is applicable to most new
process heaters and can be used in conjunction with combustion
modifications. However, since SNCR systems are very sensitive to
" " ' ii ' ',''' i.iiii ' " 'ij
3-62
-------
low load and variable load conditions, their applicability to
many processes is limited. Since SNCR performance is sensitive
to the residence time during reaction, significant load changes
can decrease NOX reduction capabilities considerably.
Furthermore, the ability of SNCR to reduce NOX emissions becomes
almost negligible when the heater load drops below 50 percent,
because the temperature window required for efficient operation
is not reached.
3.6.2 Petroleum Refining Catalytic Crackers and Carbon Monoxide
Boilers
Catalytic cracking regenerators and carbon monoxide boilers
can be large NOX emission sources at petroleum refineries.
Testing conducted on one carbon monoxide boiler in 1977 showed
that adjustment of staged air ports and use of BOOS had
negligible effects on NOX emissions, although carbon monoxide...
increased rapidly below about two percent excess oxygen. The
lack of response of NOX formation to combustion modifications was
attributed to NOX that is formed from ammonia in the carbon
monoxide gas feed3.
3.6.3 Metallurgical Processes
The iron and steel industry is the predominant source of NO
emissions from metallurgical processes. Other industries, such
as aluminum processing, extensively use electric melting furnaces
or operate process equipment at temperatures below the minimum
required for substantial NOX formation. The processes with the
largest potential NOX emissions at iron and steel plants include:
pelletizing, sintering, coke ovens, blast furnace stoves, open
hearth furnaces, soaking pits and reheat furnaces, and heat
treating and finishing3.
Tests conducted at iron and steel plants in the late 1970's
yielded the following information about the performance of NO
controls for some of these processes3:
An open hearth furnace was found to have wide variations
in NOX emissions, from 100 to 3500 ppm, due to large
changes in excess air as operators opened the hearth
doors. Following baseline tests, the furnace was
overhauled to repair refractory and to fix leaks
3-63
-------
A second test cycle showed that a NOX emission reduction
of about 40 percent was achieved after the overhaul.
'.! >: i i'i$" - ' - " ! ::- -" ; '. r.." , . .'.
. fr . ' ,, 'i " , . i , ,,. iji!,!' " . ,i,
One steel billet reheat furnace was tested while firing
natural gas. Lowering the excess air resulted in a
decrease in NOX emissions of 24 percent, and employing
BOOS produced a 43 percent NOX reduction.
One steel ingot soaking pit was tested while firing
natural gas through a single burner. Reduction of excess
air reduced NOX by 69 percent with no adverse effect on
the steel.
3.6.4 Glass Manufacturing
The flue gas from glass-melting furnaces is the major source
of NOX emissions in the glass industry. Certain process
modifications can reduce NOX emissions from these furnaces. For
example, preheating and agglomeration of raw batch materials
could reduce NOX emissions by 25 to 50,percent, at.some plants..
Augmentation of heat transfer in glass-melting furnaces (e.g., by
burner repositioning) could reduce NOX in proportion to the
energy saved, with potential NOX reductions in the range of 10 to
20 percent. Finally, development of a submerged combustion
process could substantially reduce NOX emissions3.
3.6.5 Cement 'Manufacturing
in : ' . , ', .1 ;:,.,'" ! , .
Combustion modifications to cement kilns can, reduce NOX
emissions to some extent. Emission tests conducted in the late
1970'& on a wet process cement kiln showed that reduction of
excess oxygen at the baseline air temperature reduced NOX by
36 percent. In addition, NOX emissions were found to be highly
dependent upon kiln temperature. Increasing the temperature from
700ฐF to 770ฐF increased NOY emissions by 15 percent. The
, , , . , ',.; : s <ฃ. . . , , . ,.,.
independent reductions of either excess air or air temperature
caused unacceptable reduction of kiln temperature that could lead
to process upset. It was found that simultaneous reduction of
excess air and an increase in air temperature could result in a
reduction in NOX emissions of about 14 percent while maintaining
the required kiln temperature3. Another means of emission
control in cement kiln operation is the choice of kiln type.
Some NOX reduction is achieved by using a vertical instead of a
rotary kiln. The mechanism of operation in vertical kilns is
3-64
-------
such that heat transfer to the load is very high, and peak
temperatures in the kiln are lower3.
Cement kilns have lower NOX emissions when using solid and
liquid fuels than when using gas, due to the highly adiabatic
nature of the process. An emissions test conducted on a dry
process kiln in the late 1970's showed that operation on oil
resulted in 60 percent less NOX emissions than operation on
natural gas. Operation on combined coke and natural gas produced
50 percent less emissions compared to use of natural gas alone3.
3.7 CONTROL TECHNOLOGIES FOR NONCOMBUSTION INDUSTRIAL PROCESSES
The NOX control technologies discussed in the preceding
sections involved controls for sources where NO., formation takes
Jv
place during combustion. This section addresses the control of
NOX from industrial process sources where NO... formation results
Jฃ
from noncombustion chemical processes. For these sources, NO
J^
control techniques involve flue gas treatment.
3.7.1 Nitric Acid Plants37
For new nitric acid plants, NOX emissions can be well
controlled by using advanced processes, such as high inlet
pressure absorption columns or strong acid processes. However,
NOX emission controls at existing plants must rely on flue gas
treatment techniques, including:
Extended absorption;
Selective catalytic reduction; and
Nonselective catalytic reduction.
Other techniques have been developed or demonstrated, including
wet chemical scrubbing, chilled absorption, and molecular sieve
absorption. However, poor NOX control performance or other
disadvantages have excluded these controls for common use.
Extended absorption is typically used in retrofit
applications by adding a second absorption tower in series with
the existing tower. Compliance tests for seven new (post-1979)
nitric acid plants using extended absorption showed NOV control
jฃ
efficiencies to range from 93.5 to 97 percent. Emission factors
for these plants range from 0.59 to 1.28 kilograms (Kg) of NO
per metric ton of acid (1.3 to 2.81 Ib/ton). Maximum NOV control
Jt
3-65
-------
efficiencies of extended absorption systems is achieved by
operating at low temperature, high pressure, low throughput, low
acid strength, and long residence time.
Selective catalytic reduction is used in many nitric acid
plants in Europe and Japan. However, only three U.S. plants are
currently using this technology. Reported NOX control
efficiencies for the European plants using Rhone-Poulenc SCR
technology range from 83.4 to 86.7 percent. Inlet NOX
concentrations range from 1,200 to 1,500 ppm, with outlet
concentrations at about 200.ppm. The European plants using BASF
SCR technology have NOX control efficiencies ranging from 41 to
83 percent. Inlet NOX concentrations range from as low as
200 ppm to as high as 3,000 ppm, and outlet concentrations range
from less than 110 ppm up to about 500 ppm. The SCR system on
one of the U.S. facilities, which is a new plant, is estimated-to
have a NOX control efficiency of 97.2 percent, based on an
uncontrolled emission factor of 10 Kg per metric ton (20 Ib/ton)
and a controlled emission factor of 0.29 Kgper metric ton
(0.57 Ib/ton). It should be noted that less stringent standards
' I'!"*:?: : ' ':: ' .',', i .:: ' ' .' ;.': ' . . I , ,.', ::.*i ' v ,
apply to the European plants as compared to U.S. standards. The
SCR technique is used on the European plants to bring NO,..
'if ,,: "" , : " !,;. ' i ' ' "" ,J Ill "':,: ' : , !,. ' . ; |ii- ' , .
emissions down to required levels only.
Several advantages of SCR make it an attractive control
technique. Since the SCR process can operate at any pressure, it
is a viable retrofit control alternative forexisting low-
pressure acid plants as well as for new plants. Another
technical advantage is that because the temperature rise through
the SCR reactor bed is small, energy recovery equipment (e.g.,
waste-heat boilers and high-temperature turboexpanders) is not
>'' . . Ji4! ', :! ' ' '.,'. , .'.,.( ':'.'' .; ', ; , i, ' ''',.; i'i . !'-:Jtr ' .*> : ' 'i
required, as is the case with the NSCR system, discussed below.
Nonselective catalytic reduction was widely used on new
nitric acid plants between 1971 and 1977. However, rapid fuel
cost escalation caused a decline in use of NSCR systems for new
plants, and many opted instead for extended absorption.
Despite the associated fuel costs, NSCR offers advantages
Vi , , j ,,"ป;, ,;;" ,' ป:" ', .,; , : a .; ;". " ,:.; si;,, i '.". '..>!"<' . ^.i w -v,* i .:i,t"'!: ,":'
that continue to make it a viable option for new and retrofit
applications. Flexibility is one advantage, especially for
3-66
-------
retrofit considerations. An NSCR unit generally can be used in
conjunction with other NOX control techniques. Furthermore, NSCR
can be operated at any pressure. Additionally, heat generated by
operating an NSCR unit can be recovered in a waste heat boiler
and a tailgas expander to supply the energy for process
compression with additional steam for export.
Test data for five nitric acid plants using NSCR shows that
controlled NOX emission factors ranged from 0.4 to 2.3 Ib/ton of
nitric acid produced. No trends were apparent relating the type
of NSCR unit (i.e., the number of stages, fuel type, and catalyst
support) to the observed emission factors. The NO., control
J^
efficiencies were found to range from 94.7 to 99.1 percent.
3.7.2 Adioic Acid Plants37
Adipic acid is produced at four plants in the U.S. The
following types of NOX control techniques are used at three of
these plants:
Extended absorption; and
Thermal reduction.
Extended absorption is used at one adipic acid plant in the
U.S. The estimated NOX emission factor for this plant ranges
from 0.41 to 1.23 Kg per metric ton (0.81 to 2.45 Ib/ton) of acid
produced.
The thermal reduction technique is used at two domestic
adipic acid plants. For these plants, estimated emission factors
for controlled NOX emissions are about 1.6 and 4.6 Kg per metric
ton (3.3 and 9.3 Ib/ton) of acid produced, respectively,
corresponding to estimated average NOX control efficiencies of 94
and 69 percent, respectively.
3.7.3 Explosives Manufacturing Plants
The major emissions from the manufacture of explosives are
nitrogen oxides and nitric acid mists. Emissions of nitrated
organic compounds may also occur from many of the trinitrotoluene
(TNT) process units. In the manufacture of TNT, vents from the
fume recovery system and nitric acid concentrators are the
principal sources of emissions. Emissions may also result from
the production of Sellite solution and the incineration of "red
3-67
-------
water. " The molecular sieve abatement system is used at the
Holston Army Ammunition Plant in Kingsport, Tennesssee, and at the
Radford Army Ammunition Plant in Radford, Virginia, to treat vent
gas streams from nitrocellulose operations3.
3.8 REFERENCES FOR CHAPTER 3
1. The 1985 NAPAP Emission Inventory (Version 2): Development
Of th@ Annual Data and Modelers' Tapes. U.S. Environmental
Protection Agency. Research Triangle Park, NC. Publication
No. EPA - 600/7-89-012a. November 1989. Pp. 3-32 - 3-34.
2. Acurex Environmental. Evaluation and Costing of
Controls for Existing Utility Boilers in the NESCAUM Region.
Draft prepared for U.S. Environmental Protection Agency.
Research Triangle Park, NC. September 1991.
3 . Control Techniques for Nitrogen Oxides Emissions From
Stationary Sources - Revised Second Edition. U.S.
Environmental Protection Agency. Research Triangle Park,
NC. Publication No. EPA-450/3-83-002. January 1983. 428
pp.
4. Radian Corporation. Combustion Modification: NOX Controls
for Wall Fired and Tangentially Fired Boilers. Prepared for
U.S. Environmental Protection Agency. Acid Rain Division.
Washington, DC. July 1991.
n
Washington Update", Power. November 1991.
6. Lowe, P.A., W. Ellison, and M. Perlswelg. Understanding the
German and Japanese Coal-Fired SCR Experience. Paper
presented at the 1991 Joint Symposium on Stationary
Combustion NO.^ Control. U.S. Environmental Protection
Agency/Electric Power Research Institute. March 25-28,
1991.
7. Industrial Gas Cleaning Institute, Inc., SCR Committee.
WhitePaper - Selective Catalytic Reduction (SCR) Controls
to Abate NOx Emissions. Washington, DC. November 1991.
8. Behrens, E.S. , B. Hakes, and M. MacGillivraiy. N6XOUT
Emission Reduction Program on SYDKRAFT Unit P-15 Boiler in
Malmo, Sweden. Final Report. September 3, 1987. .
9. Hoffman, J.E. , J. Bergman, and Dr. D. Bokeribrink. NOX
Control in a Brown Coal-Fired Utility Boiler. Paper
presented at U.S. Environmental Protection Agency/Electric
Power Research InstituteSymposium on Stationary Combustion
NOX Control. March 8, 1989.
10. Information provided in Reference 3, Page 4-46, and
information provided by Mr. William Neuffer, U.S.
p" ii ' nil ' " !, 'n ; . .'i, ' ' 'i' ,""''
!!!' " ii ,, " ' : " , , : ' ' 'i, ' , Ji.
",, ' >! ' "" ','.,'" " . . ', : '! ';:'",
i; .. ' ' "if ซ,ป ,, ' : / " i"" ' "' ' ;; ,;!"'
'' , : '.;': p ^ , ^ '_ ; ' ':'!"" .;-; 3-68 ' .' ^, . ' .. ' ' i ' "'"
JlJi I1 ;i 1 ; '" -1 !i:;1 t i.1 i ' ซ . Jail" -i >r' '' s"ซ-. ' ;'': ",L:' siL i-1. i, ;!':'<;/ i i '' ',i ' . '' ' :< i.,,:,,ซ'.,, J! : '. iiitii !. .' ',iii,,Sl"",', "i,:' ;,;;:' ."' d' .' < ' v .,t. , ;.'1.1, '/-.;k ! i JI i,
-------
Environmental Protection Agency, Office of Air Quality
Planning and Standards, Research Triangle Park, NC.
11. Midwest Research Institute. Retrofit Application for NOx
Controls for Five Source Categories. Draft prepared U.S.
Environmental Protection Agency. Research Triangle Park,
NC. August 1991.
12. Overview of the Regulatory Baseline, Technical Basis, and
Alternative Control Levels for Nitrogen Oxides (NOx)
Emission Standards for Small Steam Generating Units. U.S.
Environmental Protection Agency. Research Triangle Park,
NC. Publication No. EPA-450/3-89-13. May 1989. 40 pp.
13. Costs for NOx Emission Reduction for Industrial Sources.
Prepared by Acurex Corporation for State of Wisconsin.
Acurex Technical Report TR-8 8-121/ESD. January 15, 1990.
14. Makansi, J. Special Report. Reducing NOV Emissions.
Ppwer, September 1988. pp. s.l - s.7.
15. Epperly, W., R. Broderick, and J. Peter-Hoblyn, Control of
Nitrogen Oxides Emissions from Stationary Sources.
March 17, 1988.
.16. Technical Support Document for a Suggested Control Measure
for the Control of Emissions and Oxides of Nitrogen from
Industrial, Institutional, and Commercial Boilers, Steam
Generators, and Process Heaters. Prepared by the
(California) Air Resources Board and the South Coast Air
Quality Management District. Approved by the Technical
Review Group on April 29, 1987.. pp. 48 - 61.
17. Letter (with attachments) from Erickson, W., Erickson
Industrial Products, Inc., to Hamilton, R., Texas Air
Control Board. June 22, 1990. Product information and
performance test results.
18. Letter (with attachments) from Black, R., Industrial
Combustion, Division of Aqua-Chem, Inc., to Cassidy, M
Midwest Research Institute. May 20, 1991. Product
information and performance test results.
19. Telecon. Cassidy, M., Midwest. Research Institute, with
Black, R., Industrial Combustion, Division of Aqua-Chem,
Inc. General discussion of small boilers. May 17, 1991.
20. Telecon. Cassidy, M., Midwest Research Institute, to
Tompkins, G., Cleaver-Brooks. May 17, 1991. Discussion of
retrofit NOX emission controls.
21. South Coast Air Quality Management District. Application
No. 197793. Gardenia Foods Company, South Gate, California.
Control Device Cost Analyses. October 5, 1989.
3-69
-------
22. South Coast Air Quality Management District. Application
No. 191850-52. Great Western Malting Company. Control
Device Cost Analyses. February 1, 1990.
23. Rhoadi, T., J. Marks, and P. Siebert Overview of
Industrial Source Control for Nitrogen Oxides.
Environmental Progress. Volume 9, No. 2. Nay 1990.
pp. 126 - 130.
24. Bailey Network 90. NOX Removal by Post Combustion.
Application Guide. AG-4911-040-26. Undated.
25. information provided by Mr. William Neuffer, U.S.
Environmental Prptection Agency, Office of Air Quality
Planning and Standards,. Research Triangle Pa.rk, NC.
26. Campbell, L.M., O.K. Stone and G.S. Shareef (Radian
Corporation). Sourcebook: NOX Control Technology Data.
Prepared for U.S. Environmental Protection Agency. Research
Triangle Park, NC. Publication No. EPA-600/2-91-029. July
1991. 168 pp.
27. Midwest Research Institute. Material prepared in support
of preparation of Alternative Control Technology Document
for Internal Combustion Engines. Draft prepared for U.S.
Environmental Protection Agency. Research Triangle Park,
N.C. September27, 1991.
28. Arthur D. Little, Inc. Evaluation of NOx Control
Technologies for Gas-Fired Internal "Reciprocating"
Combustion Engines - Final Report. Prepared for County of
Santa Barbara Air Pollution Control District. March 6,
1989.
29. Electric Power Research Institute. Internal-Combustion
Engine NOx Control - Final Report. Publication No. EPRI GS-
7054. December 1990. 57 pp.
30. Letters (with attachments) from Stachowicz, R.W., Waukesha
Engine Division, Dresser Industries, Inc., t:o Snyder, R.,
Midwest Research Institute, September 16, 1SI91; from Miklos,
R.A., Cooper-Bessemer Reciprocating Products! Division,
Cooper Industries, to Jordan, B.C., U.S. Environmental
Protection Agency, January 21, 1992; and from locco, D.E.,
Engine Process Compressor Division, Dresser-Reed, to Snyder,
R., Midwest Research Institute, October 1, 1991. Product
intermation and performance test results.
31. Midwest Research Institute. Alternative Control Technology
Document - Stationary Combustion Gas Turbines. Draft
prepared for U.S. Environmental Protection Agency. Research
Triangle Park, NC. July 1991.
3-70
-------
32. Minutes of meeting of the Industrial Gas Cleaning Institute,
Inc., with.the U.S. Environmental Protection Agency,
December 18, 1991.
33. Municipal Waste Combustors - Background Information for
Proposed Standards: Control of NOx Emissions U.S.
Environmental Protection Agency. Research Triangle Park,
NC. Publication No. EPA-450/3-89-27d. August 1989. Ill pp.
34. Air Pollution Control at Resource Recovery Facilities.
California Air Resources Board. May 24, 1984.
35. Biljetina, R., H.A. Abbasi, M.E. Cousino, and R. Dunnette.
Field Evaluation of METHANE De-NOx at Olmsted Waste-to-
Energy Facility. Paper presented at the 7th Annual Waste-
to-Energy Symposium. Minneapolis, MN. January 28-30, 1992.
36. Radian Corporation. Fired Heaters: Nitrogen Oxides
Emissions and Controls - Final Report. U.S. Environmental
Protection Agency. Research Triangle Park, NC. June 29,
1988. 122 pp.
37. Alternative Control Techniques Document - Nitric and Adipic
Acid Manufacturing Plants. U.S. Environmental Protection
Agency. Research Triangle Park, NC. Publication No. EPA-
450/3-91-026. December 1991. 116 pp.
3-71
-------
-------
TECHNICAL REPORT DATA
(Please nod Instructions on the reverse be fort completing)
i. REPORT NO.
EPA-450/3-92-004
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Technical Report?*-* Summary of NOx Control Technologies
and their Availability and Extent of Application
Technical Air Pollution Study
5. REPORT DATE
February^ 1992
6. PERFORMING ORGANIZATION CODE
'. AUTHOR(S)
8. PERFORM
9. PERFORMING ORGANIZATION NAME AND AOORESS
Midwest Research Institute
401 Harrison Oaks Blvd, Suite 350
Gary, NC 27513-2412
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-D1-0115
12. SPONSORING AGENCY NAME AND AOORESS
U.S. Environmental Protection Agency
Emission Standards Division (MD-13)
Office of Air Quality Planning & Standards
Research Triangle Park, NC 27711
13. TYPE OF REPORT ANO PERIOD COVERED
14. SPONSORING AGENCY CODE
IS. SUPPLEMENTARY NOTES
EPA Work Assignment Manager: William J. Neuffer (919) 541-5435
1ซ. ABSTRACT
This Technical Report is a summary of previous documents dealing with NOx control
technologies. It provides a brief description of existing NOx control technologies.
The report also discusses the availability and .extent of application of these
technologies for several industrial categories that are the main stationary sources
of NOx emissions. Where available, achievable controlled NOx emission levels and
percent reduction for each control technology are presented.
17.
KEY WORDS ANO DOCUMENT ANALYSIS
DESCRIPTORS
J.IOENTIFIERS/OPEN ENDED TERMS
c. COSATi Field/Croup
NOx Emissions
Control Techniques for NOx Emissions
from various stationary sources
18. DISTRIBUTION STATEMENT
19. SECURITY CLASS (Till*Report)
105
20. SECURITY CLASS fTlliipagei
22. PRICE
EPA Fwป 2220-1 (ftซv. 4-77) PRCVIOUS COITION is oosoutTE
-------
1
,*"'*, !, ,; t.
------- |