United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-81 -126 August 1982
Project Summary
Industrial Boiler Combustion
Modification IMOx Controls
K. J. Lim, C. Castaldini, R. J. Milligan, H. I. Lips, R. S. Merrill, P. M. Goldberg,
E. B. Higginbotham, and L. R. Waterland
Volume I of the report gives results
of an environmental assessment of
combustion modification NO, control
techniques for coal-, oil-, and gas-
fired industrial boilers, with focus on
NO, control effectiveness, operational
impacts, thermal efficiency impacts,
capital and annualized operating
costs, and effects on emissions of
pollutants other than NO,. Major
industrial boiler design types are
characterized and equipment trends
are reviewed. Currently available con-
trol techniques can achieve 10-25
percent NO, reductions for coal- and
residual-oil-fired boilers and 40 - 70
percent reductions for distillate-oil-
and gas-fired units with minimal
adverse operating impacts. Controls
should increase steam costs by only 1
- 2 percent, but the initial investment
required could be significant; up to 20
percent of the boiler cost on a new
boiler and up to 40 percent of the
boiler cost for a retrofit. Volumes II
and III of the report give results of
detailed Level 1 tests on two stoker-
coal-fired boilers, indicating that
combustion modification reduces the
source potential environmental hazard
by lowering NO, emissions, leaving
the emissions of other pollutants
largely unaffected.
This Project Summary was devel-
oped by EPA's Industrial Environmen-
tal Research Laboratory, Research Tri-
angle Park, NC. to announce key find-
ings of the research project that is fully
documented in a separate report of the
same title (see Project Report ordering
information at back).
Introduction
With the increasing extent of NO,
control application in the field, and
expanded NO, control development
anticipated for the future, there is cur-
rently a need to: (1) ensure that the cur-
rent and emerging control techniques
are technically and environmentally
sound and compatible with efficient and
economical operations of systems to
which they are applied, and (2) ensure
that the scope and timing of new control
development programs are adequate to
allow stationary sources of NO, to
comply with potential air quality stand-
ards. With these needs as background,
EPA's IERL-RTP initiated an "Environ-
mental Assessment of Stationary
Source NO, Combustion Modification
Technologies Program" (NO, EA) in
1976. This program has two main ob-
jectives: (1) to identify the multimedia
environmental impact of stationary
combustion sources and NO, combus-
tion modification controls applied to
these sources, and (2) to identify the
most cost-effective, environmentally
sound NO, combustion modification
controls for attaining and maintaining
current and projected NO2 air quality
standards to the year 2000.
The NO, EA's assessment activities
have placed primary emphasis on major
stationary fuel combustion NO, sources -
utility boilers, industrial boilers, gas
turbines, internal combustion engines,
and commercial and residential warm
air furnaces; conventional gaseous, liq-
uid, and solid fuels burned in these
sources; and combustion modification
controls applicable to these sources
-------
with potential for implementation to the
year 2000.
Volume I of the report summarizes the
EA of combustion modification controls
for industrial boilers. It outlines the
environmental, economic, and opera-
tional impacts of applying combustion
modification controls to this source
category. Volumes II and III summarize
results of two field test programs aimed
at providing data to support the environ-
mental and operational impact evalu-
ation.
Conclusions
Source Characterization
Industrial boilers are defined here as
coal-, oil-, or natural-gas-fired steam
generators with heat input capacities of
2.9 - 73 MW (10 - 250 X 106 Btu/hr).
The boilers provide electrical or mechan-
ical power, process heat, or a combina-
tion of these in a wide variety of indus-
tries. This capacity range does not
encompass all steam and hot water gen-
erators used in industry. In fact boilers in
this size category represent about 60
percent of the installed capacity used in
the industrial sector. In addition, indus-
trial boilers fire fuel other than coal, oil,
or natural gas.
However, industrial boilers larger
than 73 MW (250 X 106 Btu/hr) heat
input are generally similar in design and
controllability to utility boilers. Boilers
smaller than 2.9 MW (10 X 106 Btu/hr),
generally used for hot water and space
heating, can be grouped with commer-
cial heating units. Both utility boilers
and commercial heating units are
treated in other NOX EA reports. 1~6
The industrial boiler category as
defined here represented the third larg-
est contributor to stationary source NOX
emissions in the U.S. in 1977, contribu-
ting about 14 percent, as shown in Fig-
ure 1. This share is expected to remain
high, given incentives to switch to coal
firing in the future. Thus, this same
category represents a priority category
for control evaluation in the NOX EA.
Coal-fired industrial boilers are gen-
erally of the watertube design. Two
major design categories are: pulverized-
coal-fired units and stokers. Pulverized-
coal-fired units accounted for only
about 8 percent of the installed coal-
fired population. But since these units
are almost entirely greater than 29 MW
(100 X 106 Btu/hr) capacity, they
account for almost 20 percent of the
coal-fired capacity. Characteristic de-
signs are similar to those in the utility
Noncombustion 1.9%
Warm Air Furnaces 2.0%
Gas Turbines 2.0%
Others 4.1%
Industrial Process
Heaters 4.1%
— Incineration 0.4%
Industrial
Boilers 14.4%
14.4%
Reciprocating
1C Engines
18.9%
Figure 1.
Total: 10.5 Tg/yr (11.6 x 106 tons/yr)
Distribution of stationary anthropogenic NO* emissions for the yeai
1977 (controlled NO, levels).
sector; tangential and single- and oppos-
ed-wall designs predominate.
Stoker-fired boilers account for nearly
all the remaining coal-fired installa-
tions. These boilers are classified by the
method of introducing fuel to the fur-
nace: spreader, underfeed, and over-
feed. Spreader stokers are most popular
in newer installations.
Oil- and gas-fired boilers can be clas-
sified as either watertube or firetube.
Both shop-assembled, or packaged, and
field-erected watertube boilers exist;
however virtually all firetube boilers are
packaged units since firetube boilers
are generally limited in size to about 8.7
MW(30X 106Btu/hf).
There are two major types of pack-
aged watertube boilers: horizontal
straight-tube and bent-tube. Newer
boilers are exclusively bent-tube, further
classified by tube configuration. A-, D-,
and O-tube configurations are most
common.
Industrial firetube boilers can be clas-
sified as horizontal return tube (HRT),
scotch, or firebox. The HRT is a two-pass
boiler and was the most popular into the
1960s. Scotch boilers, in two, three, or
four passes, have since become the
most popular. Firebox boilers are shod
and compact, employing three passes a!
most, finding use in installations where
floor space is limited.
Control Alternatives
NOX is the primary flue gas pollutam
from industrial boilers amenable to con-
trol by combustion modification. The
major combustion modification tech-
niques which have been shown to be
effective in reducing NOX emissions
from industrial boilers are: low excess
air firing, staged combustion usinc
overfire air ports or burners-out-of
service, low NOX burner designs, flue
gas recirculation, reduced air preheat
load reduction or reduced combustior
intensity, and homogeneous reductior
of NO* using ammonia injection.
Typical baseline (uncontrolled) NO
emission factors for industrial boiler;
-------
are given in Table 1. Note that these are
average values; NOX emissions from
individual units can vary significantly
within a design/fuel category. Sim-
ilarly, the effectiveness of the above NOx
control techniques varies with boiler
design and fuel fired, as well as within a
given design/fuel category. Thus, the
following discussion is organized by
design and fuel.
Pulverized Coal-Fired Boilers
Combustion modification NOx con-
trols have been successfully applied to
only a limited number of coal-fired
industrial boilers. Those considered
most promising on pulverized coal-fired
units are low excess air, staged com-
bustion, low NOx burners, and ammonia
injection.
Low excess air (LEA) operation is rela-
tively simple to implement. It applies to
all boilers and requires only reducing
airf low to the burner windbox. However,
in a multiburner unit, the windbox may
have to be modified to improve air distri-
bution to individual burners during LEA
operation. Lowering excess air can
reduce the safety margin for complete
combustion. Hence, an oxygen trim sys-
tem may have to be added, in addition to
the normal airflow controllers. Never-
theless, boiler efficiency gains with LEA
should offset any additional hardware
costs, making LEA the most attractive
NOx control technique for first imple-
mentation (5 - 25 percent NOX reduc-
tion). Figure 2 shows results of LEA
tests on representative coal-fired indus-
trial boilers. The slopes of the data
bands indicate the relative effective-
ness of LEA on each equipment cate-
gory. LEA is about equally effective for
each.
Staged combustion with overfire air
(OFA) and LEA is the best demonstrated,
available control option for pulverized
coal-fired industrial boilers, potentially
reducing NO« emissions by up to 30 per-
cent. The LEA and OFA control system
has an advantage over other control
systems because of its commercial
availability and effectiveness. The cost
of the system is not prohibitive when
OFA ports are designed as part of new
boilers. In addition, careful operation of
staged air injection is not expected to
affect emissions of other criteria pollu-
tants seriously. Burner stoichiometries
of 100 - 110 percent would achieve a
20-percent NOx reduction. At these stoi-
chiometry levels, oxidizing atmospheres
would prevail in the furnace, thus min-
imizing concern over possible furnace
slagging and boiler tube wastage. How-
ever, achieving more stringent NOX con-
trol with combined LEA and OFA may
require burner stoichiometries below
100 percent in some cases. This low
burner stoichiometry level would cause
reducing atmospheres in parts of the
furnace, creating the potential for corro-
sion of water tubes, especially when fir-
ing high-sulfur coal. Generally, boiler
manufacturers do not recommend
burner operation with stoichiometry
below 100 percent, primarily because of
increased corrosion potential. Another
potential adverse impact is that addi-
tional excess air may be required to
ensure complete combustion, resulting
in a decrease in boiler efficiency. How-
ever, experience with utility boilers indi-
cates that these potential problems can
be overcome with proper design and
implementation. Indeed, 30-day, con-
tinuous monitoring tests of staged com-
bustion with LEA, at varying reduced
boiler loads, demonstrated a 30-percent
NOx reduction with no adverse opera-
tional impacts.
Burners-out-of-service (BOOS), the
other technique that can be used for
staged combustion, is primarily consi-
dered for retrofits. However, it is not
favored for several reasons:
• Extensive engineering and testing
on an individual boiler basis is
required to determine the optimal
BOOS pattern.
• An effective BOOS pattern is some-
times not possible because pulver-
Table 1. Representative Industrial Boilers and Typical Baseline /V0X Emission Levels
Fuel
Pulverized Coal
Stoker Coal
Residual Oil*
Distillate Oil
Boiler Type
Single Wall and Tangential
Spreader
Underfeed
Chain Grate
Firetube
Watertube
Firetube
Watertube
Without air preheater
With air preheater
Typical Size
(Heat Input Capacity)
MW
(10s Btu/hr)
59
44
9
22
4.4
44
4.4
29
(200)
(150)
( 30)
( 74)
( 15)
(150)
( 15)
(100)
Average
/VOx Baseline
Emission Level
ng NOz/J
(lb/WsBtu)
285
265
150
140
115
160
70
55
90
(0.663)
(0.616)
(0.349)
(0.0326)
(0.267)
(0.372)
(0.163)
(0.128)
(0.208)
Natural Gas
Firetube
Watertube
Without air preheater
With air preheater
4.4 ( 15)
29 (100)
40 (0.093)
45 (0.105)
110 (0.255)
'Includes No. 5 and No. 6 fuel oils.
-------
400—
\
I
i
300—
200 —
;oo-
'Cyclone
Pulverized Coal Boilers
'Spreader
Stokers
Underfeed and
Traveling
Grate Stokers
I I
2 3
I I I I I I
456789
Excess Oxygen, percent
I I I I
10 11 12 13
Figure 2. Effect of excess oxygen on N0t emissions from coal-fired boilers.
\zeis may serve burners on two
levels. The most effective BOOS
pattern often involves the top level
of burners on air only.
Burners/pulverizers that operate
during BOOS often cannot handle
increased coal flow, necessitating a
significant reduction in the boiler
steam rating (e.g., 20-percent).
• Potential increased slagging and
corrosion.
Several low NOX burner (LNB) designs
are under development by commercial
firms, with 40 - 60 percent NOX control
projected. In addition, an advanced
design under study by EPA is the distrib-
uted fuel/air mixing concept. Field test-
ing and application is scheduled for late
1982, with a target NOX level of 86 ng/J
(0.2 lb/106 Btu).
In some applications, LNBs may have
several advantages over other combus-
tion modifications such as OFA and
BOOS. For example, one utility boiler
manufacturer claims that LNBs will
maintain the furnace in an oxidizing
environment, minimizing slagging and
reducing the potential for furnace corro-
sion when firing high-sulfur coal. Also,
more complete carbon utilization maybe
achieved due to better coal/air mixing
in the furnace. Finally, lower oxygen
levels may be obtained with all the com-
bustion air admitted through the burners.
Since the burners generally alter the
flame configuration, care must be taken
when applying the burners to existing
boilers. For instance, some LNBs have
longer flames. Such burners can be
installed only in boilers large enough tc
avoid cold-wall impingement. Once
developed, however, low NOX, coal-firec
burners for industrial boilers coulc
become the best control system because
of the expected lower cost, higher NO,
reduction capability, and other opera-
tional advantages.
If additional control, over and above
boiler/burner modifications, is needec
(e.g., to meet stringent local regula-
tions), ammonia injection is offeree
commercially. The technique has yettc
be demonstrated on coal-fired boiler;
and is several times more costly thar
conventional combustion modifica
tions. In addition, as a developing tech
nology, several potential implementa
tion and operational problems need t(
be resolved:
• Optimal effectiveness for noncata-
lytic reduction of NO by NH3 occurs
over a very narrow temperature
range; hence, the precise locatior
of NH3 injection ports.
• Since the temperature profile in t
boiler changes with load, NOX con-
trol with NHs may restrict load.
• Emissions of NH3 and by-products
• Possible boiler equipment foulinc
by ammonium sulfates.
However, the major strengths of ammo
nia injection are its potential for moder
ate NOX removal (40 - 60 percent), anc
its applicability as an additional contro
that can be combined with conventiona
combustion techniques for mcreasec
NOX reductions.
Stoker-Coal-Fired Boilers
NOX emissions from stokers are gen
erally lower than those from pulverize!
coal. These lower emissions can bi
-------
attributed to the lower combustion
intensity and to the partial staged com-
bustion that naturally occurs during
combustion on fuel beds.
As shown in Figure 2, NO* emissions
from spreader stokers tend to be higher
than those from other stokers. The coal
in a spreader stoker boiler burns partly
in a suspended state and partly on a
moving or vibrating grate. The combus-
tion of coal in the suspended state
apparently causes generally higher NOX
emissions than for other stokers that
feed and combust coal directly on a
moving grate. In addition, the higher
heat release rates of spreader stokers
probably contribute to high NOX emis-
sions.
Four methods have been used to mod-
ify stoker coal combustion to reduce NOX
emissions: reduced undergrate air or
LEA, OFA, reduced heat input, and
reduced air preheat (RAP). Of these
methods, only LEA firing has been dem-
onstrated to be widely effective.
EPA field tests of 17 stokers indicate
that the excess oxygen levels at base-
line operating conditions averaged
about 9 percent. During LEA tests, the
average excess oxygen level was
reduced to 6.4 percent by reducing the
undergrate airflow while maintaining
the OFA flow close to normal operation.
Such reduction lowered NOX emission
levels approximately 10 percent for
each 1 percent reduction in excess oxy-
gen. Additional data from an EPA-DOE-
ABMA field test program, involving 11
relatively new design stokers operating
near the lower excess air level, support
this conclusion.
The minimum achievable excess air is
limited by several factors. Except for the
water-cooled vibrating grate, the grate
is cooled only by airflow. If this air is cut
back too much, the grate can overheat.
There is also the danger of creating local
reducing zones and of forming harmful
corrosion products as the air is cut back.
Another problem during field tests was
the formation of clinkers and increased
CO emissions as the excess oxygen was
reduced. However, test results indicate
that, if excess oxygen levels are main-
tained above 5 percent, CO emissions
will stay below 150 ppm.
Fuel combustion with lowest possible
levels of excess air ensures maximum
boiler efficiency unless the air is
decreased to the point where unburned
carbon losses are greatly increased.
Limited available data indicate that, if
airflow is maintained for an excess oxy-
gen level above about 6 percent, no seri-
ous operational or emission problems
should result. NOX emission reductions
of about 5-25 percent and increases in
boiler efficiency of 1 percent can be ex-
pected with LEA. if fuel burnout does
not change during the process.
Residual-Oil-Fired Boilers
As with coal-fired boilers, combustion
modification NOX controls have been
applied only to a limited number of oil-
fired boilers.
This experience indicates that low
excess air firing is the only demon-
strated universally applicable control
technique for all oil-fired boilers. Figure
3 shows excess air test results.
Baseline NOX emissions from residual-
oil-fired firetube boilers are relatively
low, averaging 115 ng/J, as noted in
Table 1. Low excess air operation
should lower emissions by about 20
percent and also increase boiler effi-
ciency. The same possibility of increased
300—
200—
.o
£
i
700-
PS 300 (High Nitrogen
No. 5 Oil)
\
3
I I I
56789
Excess Oxygen, percent
I
JO
I
//
T
12
Figure 3.
Effect of excess oxygen /VOX emissions from distil/ate and residual
oil-fired boilers.
-------
CO and hydrocarbon emissions dis-
cussed for coal firing under low excess
air applies here also. Low NOx burners
and staged combustion are the pre-
ferred alternatives for additional con-
trol. However, neither has been demon-
strated for firetube boilers. Developing
low NOx burners may become the first
control choice after LEA because of
their potential for high NOx reduction
with the lowest boiler operational
impact.
The generally larger watertube boil-
ers with higher NOX emissions(160 ng/J
average) can also benefit from the same
controls: low excess air, low NOx
burners, and staged combustion. Staged
combustion has been demonstrated for
large multiburner watertube boilers.
However, if developing low NOX burners
are successful and achieve 40 - 60 per-
cent reduction, down to 86 ng/J (0.2
lb/106 Btu), they should prove more
cost effective. The only other alternative
for stringent control is ammonia injec-
tion. Although demonstrated and in
limited commercial operation for oil and
gas firing in Japan, this system is a
severalfold more costly alternative for
NOx reduction than the other two. In
addition, operational problems and
potential emissions of NH3 and by-
products are of environmental concern.
Distillate-Oil- and Gas-Fired
Boilers
NOx emissions from distillate oil and
natural gas combustion are primarily
from thermal NOX formation. The rela-
tively low uncontrolled baseline NOx
emissions of these boilers (see Table 1)
should permit very low controlled NOx
levels. These control levels can be met
in most cases with commercially avail-
able combustion modification tech-
niques. The preferred control systems
are low excess air, reduced air preheat,
flue gas recirculation, and low NO*
burners (under development), in that
order, lowering NOX down to about 65
ng/J (0.15 lb/106 Btu). Distillate oil-
and natural-gas-fired boilers not equip-
ped with air preheaters (all firetubes,
some watertubes) generally exhibit
significantly lower average NOx emis-
sions than those with air preheaters, re-
gardless of boiler heat input capacity, as
shown in Figure 4. Figure 4 shows that
bypassing an existing preheater sub-
stantially reduces NOx (shown for nat-
ural gas, though similar behavior is ex-
pected for distillate oil). Those boilers
without air preheat should be able to
175
(0.41)
^ /50
125
>
100
50
0.72,
Uj
^.Distillate Oil
D Natural Gas
P Boiler With Preater
NP Preheater Bypassed
a
1 1 1 1 t-1 1 1
1
1 1
1(3.4)
10(34)
Boiler Capacity, MW(106 Btu/hr)
100(3<
Figure 4. Effect of combustion air preheat and boiler capacity of /VOX emissions
from distillate-oil- and gas-fired industrial boilers.
reach 43 ng/J (0.1 lb/106 Btu) with just
flue gas recirculation; air-preheater-
equipped boilers may require combined
reduced air preheat and flue gas recir-
culation. Figure 5 shows the high effec-
tiveness (40 - 75 percent NOX reduc-
tion) of flue gas recirculation for distil-
late oil and natural gas firing.
Cost of Controls
The primary contributions of combus-
tion modification controls to steam cost
changes are the equipment modifica-
tion costs and changes in thermal effi-
ciency and fan power demand. In
general, combustion modification con-
trols should be cost-effective for indus-
trial boilers, raising steam costs only 1 -
2 percent in most cases. However, the
initial investment, especially for smaller
boilers, may be a large fraction of the
cost of the boiler itself, up to 25 percent
when controls are installed on a new
boiler. Retrofit control costs, highly site
specific, could be two to three times
higher.
Table 2 summarizes costs and cost
effectiveness of controls to attain var-
ious control levels for the various boiler
design and fuel categories. Costs in
Table 2 reflect annualizing capital costs
and adding these to annual operating
costs.
LEA, in many cases, will actually lowei
steam costs due to the increase in ther-
mal efficiency. In general, LEAisrecom
mended with other control technique:
to lessen their cost impact and to give
higher NOX reductions. Staged combus
tion causes an estimated small increase
in steam cost; but, with careful desigr
and operation, this estimated cost car
probably be reduced. Flue gas recircula
tion, although costly, is the most effec
tive technique for the clean fuels
distillate oil and natural gas. Again
optimal design and operation will proba
bly lower the cost. Low NOX burners
promise to be the most cost-effective
However, they are still under develop
ment.
Post-combustion control, because o
higher capital equipment, raw material
and energy requirements, is signifi
cantly more costly. Ammonia injectioi
is several times more costly than con
ventional combustion modifications
Flue gas treatment costs are about ai
order of magnitude higher than com
bustion modifications.
Incremental Emissions Due to
Controls
Combustion modifications, used t
control NOx emissions from Industrie
-------
70
2
QQ
-------
OFA ports. The reinjection air is sup-
plied by the OFA fan.
During this program, two furnace
operating conditions were tested: (1)
under normal operating conditions, and
(2) with increased OFA (at constant
overall excess air) to determine the
effect on NOX as well as paniculate and
trace element emissions.
Increased OFA caused apparent oper-
ating efficiency to increase from 77.8 to
80.8 percent. The largest contributing
factor to this increase was a decrease in
the combustible content of the flyash.
Table 3 summarizes flue gas emis-
sions at the ESP outlet for all compo-
nents analyzed. The table shows that
NOx emissions were reduced 18 percent
under OFA firing; however, emission
levels of CO, SO2, and SO3 increased. The
increases in sulfur species emissions
were probably due to measurement dif-
ficulties or nonhomogeneities in coal
composition, rather than changes in fir-
ing mode. Particulate load increased at
the ESP outlet, as did flue gas organic
species OC7) emissions under low NOX
firing. Infrared analyses of flue gas sam-
ple extracts indicated the presence of
carboxylic acids and some aromatics in
the baseline extract, and aromatics and
possibly an amide in the low N0«extract.
Emission levels of the trace element
species remained unchanged, within
analytical accuracy, with firing mode.
The bottom ash, mechanical hopper
ash, and ESP hopper ash were also ana-
lyzed for trace elements, ionic species,
and Level 1 organic content.
Results indicated that concentrations
of the trace elements and most ionic
species were unchanged with firing
mode. Interestingly, however, bottom
ash nitrate content (oxidized nitrogen)
apparently decreased while ammonium
content (reduced nitrogen) apparently
increased for the low NOx test. For the
organic species, levels were higher in
the low NOx bottom ash than in the
baseline bottom ash, although the base-
line mechanical hopper ash had higher
organic content than the low NOX me-
chanical hopper ash.
Infrared spectrometry analyses of
ash sample extracts showed that car-
boxylic acids, esters, and ethers were
present in both bottom ash samples,
and that only aliphatic hydrocarbons
were present in ESP hopper ash
samples.
Site B
The unit tested at Site B was a Riley
single-pass boiler with a Riley spreader
Table 3. Flue Gas Composition at the ESP Outlet (ug/dscm): Site A
Baseline
Low /VOX
/VO,
SOZ
SO3
CO
Particulate
6.3 x 10s
8.2 x 10s
5.8 x 103
2.5 x 10s
4.0 x 10"
5.2 x 10s
1.1 x 706
3.5x10*
4.8 x 10s
6.3 x 10*
Antimony
Arsenic
Barium
Beryllium
Bismuth
Boron
Cadmium
Chromium
Cobalt
Copper
Iron
Lead
Manganese
Mercury
Molybdenum
Nickel
Selenium
Tellurium
Thallium
Tin
Titanium
Vanadium
Zinc
Organics OCj)
Methane
<19
3.2
420
3.8
<24
910
6.1
17
9.2
29
1. 1 x 103
<57
32
<0.037
10
34
32
1.1
<34
8.4
1.2
8.7
63
1.0x W3
4.9 x 1O*
<3.2
<7.0
70
<0.097
<6.7
350
<17
150
<48
<98
1.9x 103
<180
<77
<0.016
<8.0
<140
45
<5.5
<37
<220
580
<17
35
1.8x 103
stoker. The unit had a continuous rating
of 25 kg/s steam (200,000 Ib/hr) with a
2 hour maximum capacity of 28 kg/s.
The steam is produced at a pressure of
1.38 MPa (185 psig) and temperature of
260°C (500°F). This boiler also had a
flyash reinjection system. All the ash
from the boiler hopper is reinjected and
part of the ash from the mechanical col-
lector is also reinjected. An ESP is used
for final flyash control. The boiler was
also equipped with an economizer.
The NO, EA field tests at Site B con-
sisted of a baseline (normal operation)
test and a test with low excess air. Low
NOx operation reduced NOx by 37 per-
cent at the economizer outlet.
Table 4 summarizes the flue gas
emissions at the economizer outlet for
all species analyzed in the test. As
shown, CO levels remained relatively
unchanged while particulate emissions
increased slightly under low NOx firing.
Results of sulfur species analyses were
inconclusive; errors are suspected in the
values obtained by the Shell-Emeryville
method used. Flue gas organic emis-
sions increased with low NOX firing.
Infrared spectrometry indicated the
presence of aliphatic hydrocarbons,
ethers, esters, and carboxylic acids in
the extracts from both tests. Trace ele-
ment emissions were not affected by
firing mode, within analytical accuracy.
The bottom ash, mechanical hopper-
ash, and ESP hopper ash were analyzed
for trace elements, ionic species, and
Level 1 organic content.
Concentrations of these did not vary
significantly with firing mode. Infrared
-------
Table 4. flue Gas Composition at ESP Outlet f/jg/dscm): Site B
Baseline
Low /VOx
A/0,
SO2
S03
CO
CO2
Paniculate
4.7x10*
5.2 x 10s
2.4 xW3
5.4 x 10*
2.1 x 10*
1.9x JO4
3.4 x 10*
3.3x10*
2.2 xlO3
3.5 x 10*
2.4x10e
2.9 x 10*
Antimony
Arsenic
Barium
Beryllium
Bismuth
Boron
Cadmium
Chromium
Cobalt
Copper
Iron
Lead
Manganese
Mercury
Molybdenum
Nickel
Selenium
Tellurium
Thallium
Tin
Titanium
Vanadium
Zinc
Organics OCj)
Methane
3.5
35
170
1.2
2.6
<6.8 x 103
<1.2
61
23
64
280
<1.2
12
2.4
320
2.6 x 103
13
2.2
2.0
9.5
<55
130
9.7
920
1.27 x 10*
3.5
39
2.7
0.25
3.2
7.8 x 103
5.2
20
5.8
0.050
<71.2
<0.50
11
1.3
210
2.4 x JO3
13
<3.0
<2.2
<8.8
<49
18
<0.058
1.37 xW3
5.72x10*
spectrometry of ash sample extracts
indicated the presence of aliphatic and
aromatic hydrocarbons, esters, and car-
boxylic acids in bottom ash samples; ali-
phatic hydrocarbons in mechanical
hopper ash samples; and possibly an
ester or carboxylic acid in ESP hopper
ash samples.
Environmental Impact
Evaluation
The data obtained in the field test pro-
gram discussed above were evaluated by
a Source Analysis Model (SAM), specifi-
cally SAM/IA,8 to give quantified mea-
sures of the potential hazard posed by
emissions from stoker-fired' industrial
boilers and to evaluate how low NOX fir-
ing affects the potential hazard. SAM/IA
was developed by IERL-RTP for use in
EA projects to estimate the potential
hazards of source discharge streams.
The SAM/IA model defines two in-
dices of potential hazard: Discharge
Severity (DS) and Weighted Discharge
Severity (WDS). DS is the ratio of the
pollutant discharge concentration to its
Discharge Multimedia Environmental
Goal (DMEG). (DMEGs, within IERL-
RTP's EA program for a large number of
species, represent maximum pollutant
concentrations desirable in discharge
streams to preclude adverse effects on
human health or ecological systems.) A
DS exceeding unity flags the existence
of a potential hazard. A stream's Total
Discharge Severity (TDS) is the sum of
the DSs calculated for the discharge
stream.
WDS is the product of DS times the
discharge stream mass flowrate. Total
Weighted Discharge Severity (TWOS) is
the sum of WDSs calculated for the dis-
charge stream. Thus WDS and TWOS
indicate the magnitude of a potential
hazard and can be used to rank the rela-
tive hazard posed by different discharge
streams.
Table 5 gives results of the SAM/IA
evaluation of the flue gas composition
data from Site A, for uncontrolled (base-
line) and controlled operation (low NO,).
The table shows MEG category DS for
each firing condition for components
with DS greater than 1 in either test. DS
values shown were calculated from
air/health-based DMEGs. Table 5
shows that NOX and SOz are potentially
the most hazardous flue species. The
sum of theDS values for these two spe-
cies comprises over 70 percent of the
stream TDS. The DS for S02 fluctuates
with day-to-day fuel sulfur content,
masking the effects of the reduction of
the NOX DS with the application of NOX
control, so that stream TDS remains rel-
atively constant with NOX control appli-
cation. Other species of potential
concern include CO, SOs (vapor), and
several trace elements. In this test the
S03 increased sixfold with NOX control.
However, this increase may be within
the accuracy of the analytical technique
used to measure SOs. Carboxylic acids
are flagged here also.
Table 6 shows stream TWOS for each
stream under each firing mode tested.
The table shows that thef lue gas stream
dominates the potential hazard of the
source, with a WDS over two orders of
magnitude larger than any other stream.
In addition, the TWDSs for the ash
streams remain relatively constant with
firing mode. Thus, changes in flue gas
TWOS will elicit corresponding changes
in total source TWOS. It is concluded
that the NOX control tested does not, of
itself, increase total source potential
hazard.
Table 7 gives results of the SAM/IA
evaluation of the flue gas from the Site B
unit, for the two modes of operation
(baseline and low NOX). MEG category
DS values for compounds with DS
greater than 1 in either test are given.
Again, these values were calculated
with air/health DMEGs.
Conclusions from Table 7 are analo-
gous to those discussed for Table 5. NOX
and SOa remain the potentially most
hazardous species, accounting for over
half the flue gas stream TDS. Here,
though, the DS for SO2 (which varies
exclusively with fuel sulfur content)
drops in the low NOX mode, so that
-------
Table 5. Flue Gas Discharge Severity: Site A
Discharge Severity
Component
/vo,
SOZ
CO
SOa {vapor)
Beryllium
Arsenic
Iron
Carboxylic acids
Titanium
Cadmium
Lead
/wco
Category
47
53
42
53
32
49
72
8
41
82
46
Baseline
70
63
6.3
5.8
1.9
1.6
1.1
1.0
0.34
0.61
0.38
Low /VOX
58
85
12
35
0.049
3.5
1.9
1.8
3.7
1.7
1.2
Total Stream
154
206
Table 6. Total Weighted Discharge
Severity: Site B
Total Weighted
Discharge Severity
(kg/s)
Stream
Baseline Low N0t
Flue gas 6,600 7,900
Bottom ash 15 16
Mechanical
collector hopper ash 1.7 1.8
ESP hopper ash 5.3 2.6
Table 7.
Flue Gas Discharge Sever-
ity: Site B
Discharge
Severity
MEG
Component Category Baseline Low /VOx
/vo,
SOz
COi
Arsenic
Boron
SOa (vapor)
CO
47
53
42
49
68
53
42
68
39
35
18
2.2
2.4
1.4
38
23
27
20
2.5
1.6
0.88
Total stream
168 114
stream TDS decreases with NOx control
application.
Other flue gas species with DS
greater than 1 include COz, CO, S03
(vapor), and the trace elements arsenic
and boron. The DS for SOa shows
essentially no change with firing mode.
In addition, no organic category had a DS
value greater than 1.
Table 8 shows stream TWOS values
for each stream at Site B, under both
firing modes tested. The Site A conclu-
sions hold here as well. Specifically, the
flue gas stream dominates the potential
source hazard, and NOX control reduces
total source potential hazard in the
absence of 562 considerations which
depend on the fuel sulfur content and
not on the NOx control.
Bioassays of the bottom ash and ESP
hopper ash from the Site B low NOx test
indicated negative mutagenicity and
nondetectable toxicity. Only the ESP
hopper ash elicited a positive response,
giving a low toxicity result in the RAM
cytotoxicity assay.
Recommendations
NOx controls have been applied to
industrial boilers only to a limited
extent. An exception is low excess air,
which is often used to increase boiler
efficiency. Thus, there is a general need
for data on the effectiveness, costs, and
operational impacts of NOx combustion
modification control applied to indus-
trial steam raising equipment. The gen-
eral trends highlighted in this report are
meant to be only guidelines; there will
certainly be exceptions, and much
research and development work remains
to be done before NOx control technol-
ogy is well characterized for the wide
diversity of industrial boiler design and
equipment types.
However, it can be generally con-
cluded that currently available combus-
Table 8. Total Weighted Discharge
Severity: Site B
Total Weighted
Discharge Severity
fkg/s)
Stream Baseline Low NO,
Flue gas
Bottom ash
Mechanical
collector hopper
ash
ESP hopper ash
7.160
a
50
1.9
3,640
7.7
5.5
3.7
^Bottom ash sample not taken.
tion modification technology is capable
of moderate reductions (10 - 25 percent)
for coal- and residual-oil-fired boilers,
while major reductions (40 - 70 percent)
are possible for distillate-oil- and gas-
fired units with minimal adverse opera-
tional or environmental impacts. Ad-
vanced techniques under development,
such as low NOx burners and ammonia
injection, are potentially capable of
more efficient operation and/or addi-
tional reductions, and the development
of these techniques should continue.
EPA is currently sponsoring several
field test programs demonstrating com-
bustion modification NOX controls for
industrial boilers. Results from these
studies should help fill some of the data
gaps identified in this study. In addition,
several other field tests of these and
other combustion controls are under-
way, including 30-day continuous
monitoring programs. The results of
these and other test programs should
be monitored and incorporated in future
updates of the assessment of combus-
tion modification NOX controls.
References
1. Lim. K. J., et al., "Environmental
Assessment of Utility Boiler Com-
bustion Modification NOX Controls:
Volume 1. Technical Results, and
Volume 2.-Appendices," EPA-
600/7-80-075a,b (NTIS PB80-
220957 and 80-212939), Industrial
Environmental Research Laboratory,
Research Triangle Park, NC, April
1980.
2. Higginbotham, E. B., and P. M.
Goldberg, "Combustion Modifica-
tion NOx Controls for Utility Boilers:
Volume I. Tangential Coal-Fired
10
-------
Unit Field Test," EPA-600/7-81 -
124a, Industrial Environmental
Research Laboratory, Research Tri-
angle Park, NC, July 1981.
3. Sawyer, J. W., and E. B. Higginbo-
tham, "Combustion Modification
NOx Controls for Utility Boilers:
Volume II. Pulverized-Coal Wall-
Fired Unit Field Test," EPA-600/7-
81-124b, Industrial Environmental
Research Laboratory, Research Tri-
angle Park, NC, July 1981.
4. Sawyer, J. W., and E. B. Higginbo-
tham, "Combustion Modification
NOx Controls for Utility Boilers:
Volume III. Residual Oil Wall-Fired
Unit Field Test," EPA-600/7-81 -
1 24c, Industrial Environmental
Research Laboratory, Research Tri-
angle Park, NC, July 1981.
5. Castaldini, C., et al., "Combustion
Modification Controls for Residen-
tial and Commercial Heating Sys-
tems: Volume I. Environmental
Assessment," EPA-600/7-81 -123a,
Industrial Environmental Research
Laboratory, Research Triangle Park,
NC, July 1981.
6. Castaldini, C., et al., "Combustion
Modification Controls for Residen-
tial and Commercial Heating Sys-
tems: Volume II. Oil-Fired Residen-
tial Furnace Field Test," EPA-600/
7-81-123b, Industrial Environ-
mental Research Laboratory, Re-
search Triangle Park, NC, July
1981.
7. Lentzen, D. E., et al., "IERL-RTP
Procedures Manual: Level 1 Envi-
ronmental Assessment (Second Ed-
ition)," EPA-600/7-78-201 (NTIS
PB293795), Industrial Environ-
mental Research Laboratory, Re-
search Triangle Park, NC, October
1978.
8. Schalit, L. M. and K. J. Wolfe,
"SAM/IA: A Rapid Screening Meth-
od for Environmental Assessment
of Fossil Energy Process Effluents,"
EPA-600/7-78-015 (NTIS PB
277088), Industrial Environmental
Research Laboratory Research Tri-
angle Park, NC, February 1978.
K. J. Urn, C. Castaldini, R. J. Milligan, H. I. Lips, R. S. Merrill, P. M. Goldberg, E.
B. Higginbotham, and L. R. Water/and are with Acurex Corporation, Energy
and Environmental Division, Mountain View, CA 94042.
Joshua S. Bowen is the EPA Project Officer (see below).
The complete report consists of three volumes, entitled "Industrial Boiler Com-
bustion Modification /VOX Controls,"
"Volume I. Environmental Assessment," (Order No. PB 82-231 077; Cost:
$28.50, subject to change)
"Volume II. Stoker-Coal-Fired Boiler Field Test—Site A," (Order No. PB
82-231 085; Cost $16.50, subject to change)
"Volume III. Stoker-Coal-Fired Boiler Field Test—Site B," (Order No. PB
82-231 093; Cost: $18.00, subject to change)
The above reports will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
11
U. S. GOVERNMENT PRINTING OFFICE: I982/559-092/0484
-------
o •
o
5'
I.
O
01
O)
00
CO
3D fr
c
fr
2T
o
m > TJ m
fill
CO O O O
W< A 3
w 03
------- |