United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory _
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-82-025b August 1982
Project Summary
Impact of NOX Selective
Catalytic Reduction
Processes on Flue Gas
Cleaning Systems
G. D. Jones, R. L. Glover, G. P. Behrens, and T. E. Shirley
Nitrogen oxide (NOX) emissions
from electric utility boilers may be
reduced by 80-90% through the
application of pollution control tech-
nology based on the selective catalytic
reduction (SCR) of NO* with ammonia
(NHs); however, some unreacted NH3
may be emitted from the control
system. This study was performed to
investigate the impact of the NH3
leaving a IMOX SCR process on down-
stream flue gas cleaning processes.
These include electrostatic precipi-
tator (ESP), baghouse, and flue gas
desulfurization (FGD) systems. Under
normal operating conditions, most of
the NH3 leaving the SCR system will
be removed, either as particulate salts
by the particulate removal system or
as free NH3 by the FGO system. Very
little NH3 should be emitted at the
stack. The operation of ESP and FGD
systems, in most cases, will be
improved by the presence of NH3 in
the flue gas. The effects of NH3 and
NH3 salts on baghouse operation are
not known. At normally expected
emission levels, no adverse environ-
mental impacts are projected; how-
ever, at high NH3 emission levels, the
potential exists for problems with NH3
in the waste streams from fly ash and
SO? collection devices. Potential
adverse environmental impacts exist
in the ash and sludge ponds where
collected NH3 may be concentrated
and emitted as a gaseous pollutant.
This Project Summary was devel-
oped by EPA's Industrial Environ-
mental Research Laboratory. Re-
search Triangle Park. NC, to announce
key findings of the research project
that is fully documented in a separate
report of the same title (see Project
Report ordering information at back).
Introduction
Recent Japanese experience with
selective catalytic reduction (SCR) for
controlling nitrogen oxides (NOX) emis-
sions from gas- and oil-fired combus-
tion sources has shown that NOX reduc-
tions of 80-90 percent are achievable.1'2
Since this NOX reduction exceeds that of
combustion modifications alone, the
EPA is interested in demonstrating SCR
technology in the U.S. The EPA has
funded two pilot-scale demonstration
projects for evaluating SCR process
applicability to coal-fired combustion
sources.
For a utility application of SCR (see
Figure 1 for typical flue gas treatment
configuration), the catalytic reactor is
located between the economizer and air
preheater sections of the boiler. At this
point the flue gas temperature is 300-
400°C(570-750°F) which is suitable for
the NOX reduction reactions to occur
rapidly. Ammonia (NH3) is injected into
the flue gas upstream of catalyst and re-
acts with NOX on the catalyst surface to
form elemental nitrogen and water.
Steam is used as the carrier for the NH3
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Steam •
Boiler
300-
400°C
Catalytic
Reactor
200-250°C
J60°C
Stack
ESP - Electrostatic precipitator
BH - Baghouse
FGD - Flue gas desulfurization
Figure 1. Typical arrangement—NO* SCR unit with boiler and other flue gas
cleaning processes.
to aid in dispersion after injection. The
overall reactions can be represented by:
2~4N2+6H20 (1)
3N2 + 6H20 (2)
Although SCR systems have under-
gone extensive commercial develop-
ment in Japan, an unresolved issue is
that of NH3 emissions from the process
and the impact of these emissions on
equipment downstream of the catalytic
reactor. Such equipment can include air
preheaters, flue gas desulfurization
(FGD) systems, and paniculate removal
devices. EPA has conducted two studies
of the effects of excess NH3 on down-
stream equipment. This report gives
results of the study examining these
effects on baghouse, ESP, and FGD
systems. A separate investigation was
conducted to examine the impact of
excess NH3 on air preheaters. I3)
Problem Definition and
Project Objectives
Unreacted NH3 will exit the SCR
system in concentrations normally
expected to be about 10-20 ppm.
However, under transient operating
conditions, NHs levels may be higher.
Ammonium sulfate salts can form in
downstream equipment due to the
reaction of NH3, SO3, and H2O present in
the flue gas as illustrated by:
NH3(g)+H20(g) + SO3(g)32rNH4HS04(l,s)
(3)
2NH2(g) + H20(g)+ S03(g);s:(NH4)2S04(s)
(4)
NH3(g)+HC1(g)zMMH4C1 (s)
(5)
The direction in which these reac-
tions proceed depends on the flue gas
temperature and the concentrations of
the reactants. At a given flue gas con-
centration, the formation of solid sulfate
and liquid bisulfate will occuras the flue
gas is cooled. For typical concentrations
of NH3 and S03 downstream of an SCR
unit, the approximate formation tempera-
tures of (NH4)2S04 and NH4HS04 are
195°C-210°C and 165°C-180°C, re-
spectively. Typical air preheater opera-
ting temperatures for the flue gas are
from over 300°C at the inlet to about
150°C at the air preheater outlet.
Obviously, the thermodynamics of the
formation reactions indicate that some
(NH4)2SO4 and NH4HSO4 can form in the
air preheater. Some of these NH3 salts
will deposit on the preheater heat ex-
change surface, but most will pass
through and enter the downstream par-
ticulate control equipment. Most of the
particulates will be removed here, but
unreacted NH3 and traces of the NH3
salts will continue into the FGD system.
The formation and deposition of
ammonium sulfates in air preheaters
has been observed downstream of SCR
systems/31 Deposits have also formed
during tests of fly ash conditioning with
NH3 for improved ESP performance.
This study was performed to investi-
gate the impact of the NH3 leaving the
NOx SCR process on downstream flue
gas cleaning processes. Operational
effects on ESP, baghouse, and FGD
systems were investigated. In addition,
the ultimate fate of the NH3 was
investigated and a literature search was
performed on the health and environ-
mental effects of NH3 and NH3 salts.
Approach
The analyses given in this report are
based on the application of a SCR
system to coal-fired utility boilers. Both
low sulfur Western and high sulfur
Eastern coals are considered. Table 1
gives the typical coal analyses and flue
gas flows and compositions used in this
study. These data represent the flue gas
entering the SCR with the flue gas
treatment processing configuration
specified in Figure 1. Table 2 gives the
makeup water analysis used for the
FGD system investigations.
The first step in this study was to
conduct a literature search to obtain
information concerning the problems
and benefits which could result from the
presence of NHs in gases entering ESP
and FGD systems, and to gather data
concerning health effects of NH3 and
NH3 salts. Information was also collected
concerning the formation of NH3 salts by
the reaction of NH3 with gaseous acidic
species in the flue gas. Baghouse and
ESP data were sought to determine the
ability of these control devices to
remove NH3 particulates.
Since NH3 has been used to improve
ESP performance, the literature available
was used to determine the ultimate fate
of the NH3 in ESP systems. This
information was also used to identify
potential operating problems and al-
ternatives for avoiding the problems
which may result from NH3 upstream of
the ESP. Unlike ESP's, little information
is available on the effect of NH3
compounds on bag houses. NH3 panicu-
late removals were therefore based on
the ability of baghouses to remove fine
particulates.
The investigation of the effect of NH3
on FGD system operation was per-
formed by using the Radian Inorganic
Process Simulation (RIPS) computer
model. This model consists of a group of
subroutines which can be used to
simulate the unit processes and chemi-
cal phenomena in lime/limestone FGD
systems. The computer model considers
10 dissolved species: calcium, mag-
nesium, sodium, ammonia, phosphate,
chloride, carbonate, nitrate, sulfite, and
sulfate. The model calculates the
equilibrium partial pressure of CO2,
S02, and NH3 gases for a given aqueous
solution composition. A more detailed
discussion of the computer model is
presented in the appendix of the full
report.
The computer model was used to
determine NH3 removal efficiencies in
limestone scrubbing systems applied to
utility boilers firing the Eastern and
Western coals characterized in Table 1.
Simulations, performed for various
concentrations of NH3 entering the FGD
system (0-100 ppm), were used to
determine:
1. Expected NH3 removal efficiency.
2. Required liquid-to-gas ratio (L/G)
to achieve 90 percent S02 removal.
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Table 1. Coal Analyses and Flue Gas Parameters For Representative Eastern and
Western Coals
Eastern Western
Coal compositions (wt %)
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen
Moisture
HHV cal/g (Btu/lb)
Flue gas parameters*
SO2 (mole %)
SO3
H20
C02
Nz
02
HCI
NH3
Fly ash. g/m3 (gr/ft3)
Flow, b Nm3/sec (scfm)
57.7
3.7
0.9
0.1
4.0
16.0
5.8
12.0
5.606 (10.000)
0.2929
0.0030
8.190
11.95
73.73
5.824
0.00704
0.0100-0.0000
6.32 (2.771
553 (1.17= 106)
47.85
3.40
0.62
0.03
0.48
6.40
10.83
30.40
4,451 (8,020)
0.0398
0.0004
11.92
11.88
70.50
5.656
0.0100-0.0000
0.0100-0.0000
3.02 (1.32)
607 (1.29 = 106)
BAt exit from SCR system.
toBased on 500 MW net generating plant (550 MW gross generation}
Source: Ref. 4
Table 2. Representative FGD System
Makeup Water Analysis
7.3
Component (mg/l as ion)
Carbonate
Sulfate
Calcium
Magnesium
Sodium
Chloride
Nitrate
84.4
60.0
35.0
8.2
12.0
15.0
0.8
Source: Ref. 4
3. Required reaction tank volume to
prevent scale formation.
4. Sludge compositions.
Expected variations which might result
for other FGD processes were also
addressed. However, a more detailed
analysis of the limestone FGD process
was performed due to the large number
of commercial limestone systems in
operation in the U.S.
Results
SCR systems in Japan have achieved
80-90 percent IMOx reductions on
gas- and oil-fired utility boilers. Com-
mercial demonstrations of this technol-
ogy on a coal-fired boiler are underway
in Japan.'=¥=' It is expected that 80-90
percent NOx reductions will result in 10-
20 ppm of NH3 in the gas exiting the
SCR. The effect of this NH3 on down-
stream equipment is summarized below.
Ammonia Removal by
Downstream Equipment
The results of a comparison study on
the formation of NH3 salts indicate that
downstream of the air preheater, NH3
will react with SO3 and HCI to form
particulates. The reactions, in order of
occurrence, are:
NH3 + S03 + H2O^NH4HS04(I) (6)
NH3+ NH4HSO4=(NH4)2SO4(s) (7)
NH3 + HCI^NH4CI(s) (8)
A literature search concerning NH3
injection for improved ESP performance
indicated that, under normal operating
conditions, the ESP would remove
approximately 90 percent of these
particulate salts. NH3 removal by the
ESP will only occur to the extent that the
NH3 will remain in the gas phase and
pass through the ESP.
A baghouse is more efficient than an
ESP in collecting fine particles; conse-
quently, the predicted removal of NH3
salts by a baghouse is 99 percent. As
with the ESP, unreacted NH3will not be
collected by a baghouse.
The level of NH3 removal which will
occur in FGD systems depends on the
form of the NH3 in the flue gas, the pH of
the FGD system scrubbing liquor, and
the type of contactor used in the FGD.
Computer simulations were run at
steady state NH3 concentrations of the
scrubber inlet of 0, 10, 20, 50, and 100
ppm at the inlet of a limestone scrubber
for both Eastern and Western coal. The
NH3 removal in each case is shown in
Table 3. For limestone scrubbing
systems (with particulate removal
upstream), about 50 percent of the
gaseous NH3 will be removed in a
Western coal application (about 95
percent in an Eastern coal application)
for NH3 concentrations of 10-20 ppm
entering the FGD system. At the lower
NHs concentrations (1-3 ppm) normally
expected at the FGD inlet, higher
percentage removals are expected.
Removals for Western coaf are lower
since the coal has a lower sulfur
content. Low sulfur coals result in lower
blowdown rates and high liquid NH3
concentrations in the scrubbing liquor
thereby reducing the concentration
driving force for NH3(g) removal is
proportional to the difference inthegas-
and liquid-phase concentrations. Other
FGD systems which typically operate at
higher pH levels should not achieve
gaseous NH3 removals as high as
limestone FGD systems.
The amount of NH3 salts in the flue
gas which will be removed in an FGD
system will depend on the type of
contactor used. A low pressure drop
contactor such as a spray tower (com-
monly used in limestone FGD systems)
should not remove a significant portion
since these salts are typically submicron
in size. Higher pressure drop contactors,
such as packed or mobile bed types, may
achieve greater removal of the submicron
NH3 salt particulate from the flue gas.
However, for the typical configuration,
most of the NHs salts would be removed
in an upstream ESP or baghouse.
The NH3 removal by a dry FGD system
is now known. However, removal of NH3
salts formed as the flue gas cools will be
collected by the baghouse downstream
of the FGD system.
To summarize, NH3 exiting the SCR
reactor can be partially removed by
downstream equipment by two mech-
anisms: (1) reaction with SO3 or HCI to
form particulates which are partially
removed by the ESP or baghouse, and
(2) absorption of free NH3 into the FGD
scrubbing liquor. It is not possible to
make a general prediction of the
magnitude of NH3 removal by these
mechanisms since NH3 removal is
affected by the concentrations of
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several flue gas components, especially
SOz, S03 and HCI. Some hypothetical
examples of NH3 removal are illustrated
below.
Ultimate Fate of NH3
NH3 by flue gas treating equipment is
shown in Figures 2 through 4; three
cases are considered:
1. Eastern coal, wet FGD.
2. Western coal, wet FGD.
3. Western coal, dry FGD.
In each case three levels of NH3emis-
sions from the SCR system are shown.
A normal emission level is considered to
be 10 ppm; 50 ppm, a high level; and
100 ppm, significantly higher than
anticipated. The material balances
shown in the figures are calculated
values based on a number of assump-
tions.
In the first case, Eastern coal with wet
FGD, no NH3 is emitted at the stack due
to the large concentrations of SO3 and
HCI. The bulk of the NH3 is removed as
salts in the ESP or baghouse; small
quantities are removed in the scrubber.
This is not the case with Western coal
(Figure 3) since S03 and HCI concentra-
tions are substantially lower. With
Western coal, the NH3 reacts completely
with SO3 and to equilibrium with HCI.
Table 3. Removal by FGD Scrubber as a Function of Coal Type and NH3
Concentration
Case
1
2
3
4
5
NH3 in
Scrubber
Inlet
Gas, ppm
100
50
20
10
0
Eastern Coal
pH
6.0
5.9
5.9
5.9
5.9
NH3 removal. %
85
90
93
95
100
Western Coal
pH
6.2
6.0
5.9
5.9
5.8
NH3 removal. %
25
35
45
55
100
NH3
±
Some, but not much, of the remaining
free NH3 is removed by the scrubber.
Even with 50 ppm of NH3 in the SCR exit
gas, the stack concentration is only 15
ppm which is acceptably low. The stack
gas also contains the equivalent of 12
ppm of NH4CI as particulate. With Wes-
tern coal and a spray dryer the amount
of NH3 in the stack gas will not change,
but the amount of particulates will be
signif icantly reduced by the down-
stream baghouse.
These material balances indicate that
NH3 emissions will not be a problem,
even at SCR reactor outlet concentra-
tions of up to 50 ppm, when the SCR
system is followed by a particulate
collection device and an FGD system.
NH3 emissions will be significantly
reduced by this downstream equipment
when high sulfur Eastern coal is used.
The NH3 that is removed by downstream
equipment ultimately ends up in the
waste streams from these processes,
and it is these streams which have a
potential for environmental impact.
Impacts of NH3 on
Downstream Equipment
NH3 in the flue gas can impact
downstream equipment in two ways: by
Flue
Gas
350°C
SCR
1
350°C
APH
2
150°C
ESP
BH
3
150°C
Ffsn
4
50°
Stack
T
6
Sludge
NH3 in SCR Exit Gas
10 ppm
50 ppm
100 ppm
Stream
NH3
S03
HCI
NHtHCO*
(NH<)2SO<
NH4CI
1
10
30
70
0
0
0
2
1
21
70
9
0
0
3
1
21
70
1
0
0
4
0
21
7
1
0
0.2
5
0
0
0
8
0
0
6
0
0
68
0
0
1
1
50
30
70
0
0
0
2
4
0
70
30
7/5
1
3
4
0
70
2
1
1
4
0
0
7
2
1
2
5
0
0
0
28
6.5
0
6
0
0
59
0
0
4
1
100
30
70
0
0
0
2
8
0
38
0
30
32
3
8
0
38
0
2
2
4
2
0
4
0
2
4
5
0
0
0
0
28
30
6
0
0
25
0
0
6
Figure 2. FateofNHa. SOa. and HCI in flue gas cleaning system-Eastern coal, wet FGD. (All concentrations in ppmv equivalents.)
4
-------
Flue ,.rn 1 .„.. 2 ^ ESP 3 FGD 4 fc
350°C 350°C 750°C fi# 750°C ' ' 50°C
T T
Ash Sludge
NH3 in SCR Exit Gas Wppm 50 ppm WOppm
Stream 123456123456123456
NH3 10 2 2 2 0 0 50 28 28 15 00 100 71 71 64 00
SO3 400000400000 400000
HCI 25 25 25 3 0 20 25 11 11 1 0 8 25 4 4 0 0 1
».
NH4HS04 000000000000 000000
(NHthSO* 0 4 0.2 0.2 3.8 0 0 4 0.2 0.2 3.8 0 04 0.2 0.2 3.8 0
NH4CI 0 0 0 0 0 2 0 14 1 12 13 2 0 21 1 5 20 3
Figure 3. Fate ofNH*, SOs. and HCI in flue gas cleaning system- Western coal, wet FGD. (A II concentrations in ppmv equivalent.)
Flue _ 1 2 Spray 3 4
350°C 350°C 150°C v 50°C 50°C
Stack
T
NH3 in SCR Exit Gas Wppm 50 ppm WOppm
Stream 1234512345123
NH* 10 2 0 0 0 50 28 17 ? ? 100 71 67
S03 4000 04000 0 4 f 0 0
HCI 25 25 23 2 21 25 11 00 0 25 4 0
HN4HSO4 00 0000000000
(NH4)ZSO* 0440 40440 4 044
NHtCI 0020 2 0 14 25 0 25 0 21 25
4 5
? ?
0 0
0 0
0 0
0 4
0 25
Figure 4. Fate ofNHs. SOa, and HCI in flue gas cleaning system- Western coal, wet FGD. (A II concentrations in ppmv equivalent.)
5
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affecting the performance and/or the
waste stream. These impacts were
examined by both literature survey and
original analysis.
NHs injection upstream of ESPs is a
common practice at some plants and, in
the older units, NH3 levels (<50 ppm)
have caused excessive fly ash adhesion.
This operational problem may be
overcome by increasing rapping fre-
quency and/or intensity, or by periodic
washing of the ESP collector plates.
Baghouse operation may be impaired
due to the presence of NhUHSCU, which
is liquid at 147°C, and may cause
blinding of the filter bags. More frequent
cleaning and bag replacement may be
required; however, investigations are
needed to assess the severity of this
problem since no commercial experience
is available for study.
An alternate equipment configuration
is the use of a hot-side ESP. Since the
operating temperature upstream of the
air preheater is about 100°C higher than
the formation temperature of the NH3
salts, very little NHs salt would be
removed if the hot-side ESP were
downstream of the SCR. Obviously, no
NHs salt would be removed with the ESP
upstream of the SCR. This configuration
has been proposed for use in Japan to
prevent contamination of the ash with
the NHs salts. However, in this config-
uration, it is probable that control of the
submicron NH3 salts will be difficult.
Low-pressure-drop S02 scrubbers will
not remove these fine particulates, and
it is possible that this configuration
could result in a visible plume unless
additional paniculate control devices
are employed.
A fabric filter following a spray dryer
FGD system should remove most of the
NH3 salt particulates. Since NhUHSCu is
not liquid at these temperatures (—65-
95°C), the potential for filter media
blinding is reduced.
With respect to FGD systems, the
presence of NH3 in the scrubbing liquor
will be beneficial with respect to S02
removal. At expected FGD inlet NH3 lev-
els of 1-2 ppm, a slight rise in S02
removal efficiency may be observed. At
higher levels (10-20 ppm inlet to FGD),
the L/G ratio could be reduced while
maintaining a constant 90 percent SOz
removal. At very high levels (>50 ppm)
of gaseous NH3 entering the FGD
system, SC>2 removal would improve
substantially. However, NH3 may also
evolve over tanks, filters, and other open
vessels causing some operator com-
plaints.
Other types of wet FGD systems
should exhibit slightly increased S02
removal because of NH3 in the gas.
Spray dryers will probably not remove
significant amounts of gaseous NH3;
however, the baghouse should collect
essentially all of the NH3 salts. Regen-
erable FGD systems may require addi-
tional equipment to remove NH3 from
the by-product stream.
Handling of the fly ash containing
ammonium sulfate salts can potentially
cause NH3 emissions. The vapor pressure
of NHs over the solid salts is very low;
but, if the ash is wetted or sluiced,
gaseous NH3 will evolve. The phenom-
enon depends on the pH and NH3
concentration of the liquid. Sluicing of
the ash will dissolve the NH3 salts and
could lead to aqueous NHs discharges if
the sluice water is not recycled.
In the SCR exit gas, 10 ppm of NH3
could result in NH3 concentrations in
the ash pond overflow of 30 mg/l for
Eastern coal and 60 mg/l for Western
coal. The potential also exists for NH3to
leach into the ground water from the fly
ash pond. With proper pond lining,
however, the probability of this leaching
will by very low.
Aqueous NH3 concentrations of
200-1300 mg/l are possible in FGD
sludge liquors when SCR NHs emissions
are 30 ppm, depending on the coal type.
For this reason, leachate from FGD
sludge ponds could cause contamination
of groundwaters due to the NH3.
However, the amount of NH3 that would
reach groundwaters from FGD and ash
disposal ponds is unknown. Again,
proper pond lining would eliminate
these concerns. Depending on the pond
pH and aqueous NH3 concentration,
gaseous NH3 could evolve from the
sludge ponds. In some cases, biological
treatment or stripping of pond discharge
water may be necessary.
Gaseous NH3 or NHs salts could
theoretically result in visible plume
formation; however, most of the NH3
salts will be removed in a cold-side ESP
or baghouse, minimizing the chance of a
plume. Systems using a hot-side ESP
may have (NH^SO^NHaHSO* plume
formation problems. A high-pressure-
drop mist eliminator may be capable of
preventing visible plume formation by
removing the fine NH3 particulates
passing through the FGD system, but
would increase the FGD system capital
costs about 5 percent (based on lime-
stone). Another potential source of
visible plume formation is the reaction
of gaseous NHs with SOz(g) leaving the
stack gas. This phenomenon is not
expected to occur, except at high levels
of excess NH3 (>10 ppm) exiting the
FGD system. These levels of NH3
emissions can exist with Western coal-
fired-systems when the steady state
SCR NH3 emissions are >50 ppm. This
level of SCR emissions is higher than
the guaranteed levels and would only be
expected during upset conditions (which
are transient, short-term situations).
With Eastern coal, stack gas NHs
concentrations are expected always to
be «10 ppm. Japanese installations
utilizing either SCR or NH3 injection for
ash conditioning have indicated that
plume formation is not a problem.
Health Effects
The health and environmental effects
of a SCR will be minimal if standard
operating and safety procedures are
followed. Low levels of NH3 are neither
toxic nor carcinogenic. A major spill of
NH3, however, could result in a locally
toxic atmosphere for plant personnel.
Conclusions
Ultimate Fate of Ammonia
• Much of the NH3 will react with SO2
and HCI to form salts which will be
significantly reduced by downstream
paniculate removal equipment. 90-
95 percent of the NH3 should react to
form these salts for exit SCR levels of
10-20 ppm NH3, and 10-20 ppm
S03.
• The removal of gaseous NH3 by FGD
systems will depend heavily on the
scrubbing liquor pH. Removal effic-
iencies for limestone systems were
calculated to be about 50 percent
Western coal and about 94 percent
for Eastern coal (assuming FGD inlet
gaseous ammonia levels of 10-20
ppm). At the normally expected FGD
inlet NH3 concentrations of 1 -3 ppm,
higher removals would be realized.
Other FGD systems which operate at
higher pH levels than limestone
systems should experience lower
gaseous NHs removal efficiencies.
• The removal of (NH4)2S04 and NH4
HSO* particulates in an FGD system
will depend on the contactor type.
Open contactors such as spray
towers (used in many limestone
systems) should not achieve high
NH3 paniculate removals since they
are typically submicron particles.
Higher pressure drop contactors,
such as packed or mobile beds, could
potentially achieve higher removals.
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Equipment and Operational
Impacts
• The NH3 salts formed will most likely
improve ESP performance.
• Under high transient NH3 concentra-
tions, gaseous NH3 would pass
through the ESP. Some older plants
report difficulty in cleaning the
collection plates under these condi-
tions.
• The removal of the submicron NHs
salts by a baghouse should be as
efficient as for other small particu-
lates (>99 percent). However, the
presence of liquid NI-UHSO^ could
cause blinding of the filter media and
result in increased bag cleaning and
replacement for baghouses imme-
diately following the air preheater.
• NH3 absorbed by the FGD will be
beneficial with respect to SOZ re-
moval. At the expected NH3 concen-
tration of 1 -3 ppm into the FGD unit,
the SO2 removal may be slightly
increased. For higher NH3concentra-
tions, the increased absorbing ca-
pacity of the liquid could allow a
reduction in L/G while maintaining
constant S02 removal.
• Regenerable FGD systems may
require special equipment to separate
the by-product from NH3 compounds.
Waste Stream Impacts
• Under normal operating conditions,
NHa emissions at the stack will be
negligible. These low NHa emissions
should eliminate the potential for
plume formation at the stack.
• Wet handling of the collected fly ash
could generate aqueous and gaseous
NHa emissions, depending on the
slurry pH and process configuration.
• Under normally expected FGD inlet
concentration of NH3 (1-3 ppm) and
upstream collection of particulates
after the air preheater, no significant
environmental emissions are expec-
ted. Continuous high levels of NH3
(>50 ppm) in the SCR exit gas could
result in high NH3 concentrations in
the sludge pond water.
• Pond discharges could result in
significant aqueous NH3 emissions.
To avoid these emissions, the ash
sluice system could be operated in a
closed-loop mode with all ash pond
overflow recycled to sluice ash.
Another alternative is to reuse a
portion or all of the ash pond
overflow elsewhere in the plant,
such as for FGD system makeup.
Stripping and/or biological treatment
may be required for NH3 removal
from wastewater. Secondary gaseous
emissions from the pond could also
occur, depending on the liquid pH
and process configuration.
References
1. Jones, G.D. Selective Catalytic
Reduction and NOX Control in
Japan. EPA-600/7-80-030(NTIS
PB81-191116), March 1981.
2. Ando, Jumpei. NOX Abatement
for Stationary Sources in Japan.
EPA-600/7-79-205 (NTIS PB8Q-
113673), August 1979.
Burke, J.M. and K.L. Johnson.
Ammonium Sulfate and Bisulfate
Formation in Air Preheaters. EPA
Report IERL-RTP-1286. Radian
Corporation, Austin, TX. 1982.
Arnold, C.W., Jr., et al. An
Investigation of the Effects of
Increased S02 Removal Efficien-
cies on the Operation of Limestone
and Magnesium Oxide Flue Gas
Desulfurization Systems, draft
final report. DCN 78-200-258-02,
EPRI Contract No. TPS 78-760.
Radian Corporation, Austin, TX.
September 1978.
G. D. Jones, R. L Glover. G. P. Behrens, and T. E. Shirley are with Radian
Corporation, Austin, TX 78759.
J. David Mobley is the EPA Project Officer (see below).
The complete report, entitled "Impact of /VO« Selective Catalytic Reduction
Processes on Flue Gas Cleaning Systems," (Order No. PB 82-240 086; Cost:
$12.00, subject to change) 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
U. S. GOVERNMENT PRINTING OFFICE: I982/559 -092/0490
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Information
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