SWEPCO-MU-Ex. 68
Reducing Acid Mist Emissions
from Coal-fired Power Plants
Presented at COAL-GEN
August 17-19, 2005
San Antonio, Texas
Paul S. Farber
Environmental Specialist, Environmental Consulting Group
Sargent & Lundy LLC
312-269-2261
[email protected]
David G. Sloat
Project Manager, Environmental Consulting Group
312-269-2784
[email protected]
55 East Monroe Street • Chicago, IL 60603-5780 USA • 312-269-2000
SL511-363.
Copyright 2005. www.SargentLundy.com
SWEPCO-MU-Ex. 68
SWEPCO-MU-Ex. 68
Reducing Acid Mist Emissions from Coal-fired Power Plants
Abstract
Coal-fired power plants produce emissions that must be controlled for compliance with State and
Federal regulations. One of these emissions, particulate matter (PM), actually has two forms filterable PM and condensible PM. Although Federal regulations (NSPS - New Source
Performance Standards) only addresses the control of filterable PM emissions, many State
agencies are now including condensible PM limits in their construction permits for new coal-fired
power plants. Additionally, problems with the opacity of exhaust plumes have been traced to the
presence of these condensible PM emissions. Consequently, there is a growing need for utilities
to understand the extent of condensible particulate emissions and the potential control methods
available.
Condensible particulate emissions are currently measured using US EPA Method 202. A great
deal of controversy exists around the accuracy of the sampling method, especially where it has
been shown that a portion of the SO2 in the gas stream may convert to a "pseudoparticulate" in
the impingers. Furthermore, the ammonia (NH4) used to control NOx in SCR and SNCR systems
can also react in the impingers form salts that are falsely measured as condensible PM in the
impingers. New power plants with condensible PM emission limits in their permit may have a
difficult time obtaining vendor performance guarantees based on the limited data and the
potential for a false positive bias from SO2 and NH4 in the flue gas.
Sargent & Lundy has reviewed PM emissions data from several coal-fired plants. Compliance
testing reports were analyzed to determine the fraction of condensible PM among the total PM
and the testing methodology employed at each facility. In some cases the condensible PM
fraction was further divided into organic and inorganic constituents.
This paper will summarize available information on total (filterable and condensible) PM
emissions from coal-fired power plants, review techniques to minimize and account for false
condensible PM measurements, and discuss the role that condensible emissions may play in
plume opacity. This paper will also discuss potential emissions control methods for condensible
PM and sulfuric acid mist.
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INTRODUCTION
The issues of condensible particulate matter and acid mist emissions are becoming
increasingly important for both new and existing coal-fired power plants. Such plants
traditionally have had particulate matter (PM) emission limits that only applied to
filterable particulates. Recently, air construction permits for proposed power plants have
called for measuring emissions of both filterable and condensible PM, as well as sulfuric
acid mist. The upcoming designation of PM2.5 non-attainment areas may necessitate that
some existing power plants begin to monitor and control their condensible PM emissions.
Therefore it is important to understand the various processes which result in the
formation of condensible PM in a coal-fired boiler and the methods available to reduce
these emissions. The type of coal burned and the post-combustion pollution control
equipment all have an effect on condensible PM emissions. Furthermore, the EPA test
methods for measuring both condensible PM and sulfuric acid mist may result in a falsepositive measurement biases, indicating higher than actual emissions. With a more
complete understanding of this issue, utilities can better plan for future power plant
development.
Forms of Particulate Matter
The measurement of total PM includes both the filterable (“front-half catch”) and
condensible (“back-half catch”) particulates. Filterable particulate matter (FPM) are
those compounds which exist as a solid in the flue gas stream and do not change in
physical state when exiting to the atmosphere. When measuring FPM using U.S. EPA
Methods 5, 17, or 201a, a portion of the flue gas passes through a glass fiber filter, where
the FPM is collected. Method 5 places the filter in an oven heated to 250oF, located
outside of the stack; Method 17 and 201a place the filter inside of the stack where it
comes into equilibrium with the stack temperature.
Condensible particulate matter (CPM) are those compounds which exist as a vapor in the
flue gas stream, and condense out as liquids (excepting for water) or aerosol solids upon
exit to the cooler atmosphere. U.S. EPA Method 202 measures CPM by passing the postfiltered flue-gas sample through a series of de-ionized water-filled impingers, chilled to
32oF. The impinger water is evaporated and the residue is extracted and gravimetrically
analyzed for both organic and inorganic forms of CPM.
Sulfuric acid mist is usually measured by U.S. EPA Method 8. Method 8 measures
sulfuric acid by passing the post-filtered flue-gas sample through a series of impingers
filled with isopropanol, and hydrogen peroxide solution. The sulfuric acid is measured
by titrating the isopropanol solution with a barium solution and a thorin indicator.
Organic CPM from coal fired boilers comes mainly from the incomplete combustion of
the organic constituents in the coal. Inorganic CPM from coal fired boilers includes salts,
acid mists, and trace metals. As an example, sulfur trioxide (SO3) in the flue gas can
react with water or ammonia to produce CPM in the following reactions:
1)
2)
SO3 (gas) + H2O (gas) → H2SO4 (gas) → H2SO4 (liquid)
SO3 (gas) + H2O (gas) + 2NH3 (gas) → (NH4)2SO4 (solid)
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The FPM and CPM emissions are added together to give total PM emissions. FPM
emissions are rarely a problem for a coal-fired power plant with a properly functioning
baghouse or electrostatic precipitator (ESP). CPM emissions, however, can be vexing for
even the most modern coal-fired power plant, as the sources are numerous and the
processes of formation are complex. The false positive bias inherent in U.S. EPA
Methods 8 and 202 can result in difficulty with meeting PM and sulfuric acid emission
limits in an otherwise well-designed power plant.
METHODS 8, 202 AND FALSE POSITIVE BIAS
There are a few reactions that take place in the impinger solutions that do not normally
occur as the flue gas exits the stack into the atmosphere. Such reactions can form
“pseudoparticulates” which are measured as CPM by Method 202 and as sulfuric acid by
Method 8, but are not truly reflective of actual emissions. Sulfur dioxide (SO2) in the
flue gas, which would normally exit the stack unaffected, can undergo the following
pseudoparticulate reaction in the impinger solutions:
3)
SO2 (gas) + H2O (liquid) → SO2 (dissolved gas) + time, O2 → SO4¯ (liquid) ↔ H2SO4 (liquid)
During a flue gas emissions test, a portion of the SO2 in the flue gas dissolves in the
impinger water. Throughout the test run, some of the dissolved SO2 will oxidize to
sulfate ions (SO4¯) and sulfuric acid (H2SO4). Unlike the formation of SO3 into H2SO4
(equation 1), the formation of SO2 into H2SO4 (equation 3) does not reflect what actually
happens at the stack exit. The contribution of SO2 gas toward a false positive bias in
these test methods is widely recognized by the U.S. EPA, state environmental agencies,
and independent researchers.i The text of Method 202 acknowledges the
pseudoparticulate nature of SO2, and recommends a 1-hour nitrogen purge (at 20
liters/min) to remove the dissolved gas.ii
Staff from the EPA’s Environmental Measurements Branch conducted simultaneous
testing of two Method 5/202 trains at a coal-fired boiler (1.5% sulfur content) in order to
determine the adequacy of the nitrogen purge under field conditions. The total CPM
measured in the purged impingers averaged 4.7 mg, while the CPM measured in the
unpurged impingers averaged 51.4 mg. The 10 fold difference between the two suggests
that the 1-hour nitrogen purge is effective in removing a good portion of the dissolved
SO2. Comparison of the purged and unpurged trains also indicates that the nitrogen
purge has little affect on organic condensibles, as the two measurements had a 95%
confidence level. Based on these pair-trained tests, the EPA concluded that the 1-hour
nitrogen purge was appropriate for Method 202.
However, other researches still question whether the 1-hour nitrogen purge can
adequately correct the inherent false positive bias in Method 202. Once the SO2 ionizes
into SO4¯, it remains a liquid and will not be removed by the nitrogen purge. Even if
most of the dissolved SO2 is removed during the purge and only a small fraction of the
SO2/H2SO4 remains in the solution, the resultant addition to the particulate weight can be
still be significant. Filadelfia and McDannel conducted a series of lab tests which
showed that if only 1% of flue gas SO2 remains dissolved in the impinger after the purge,
the ensuing pseudoparticulate formation can reach levels of 0.015 to 0.060 lb/mmBtu
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(based on 0.5% to 2.0% sulfur in coal).iii These levels are at or above the PM emission
limits from some recent air construction permits. It is expected that the formation of
pseudoparticulates in a Method 8 sampling train will be the same as in the Method 202
train due to the presence of water in the flue gas and the isopropanol solution.
The Electric Power Research Institute conducted Method 5/202 tests at the Black Dog
Generating Station in November of 1997. They found that SO2/H2SO4 pseudoparticulates
comprised 83% of the total measured CPM and 58% of the total PM.iv The New Jersey
Department of Environmental Protection also witnessed emission tests on coal-fired
power plants that emitted undetectable levels of SO3 (a true CPM precursor), yet had
measurable levels of H2SO4 in the impingers after purging.v
Another potential pseudoparticulate reaction in the Method 202 impingers occurs when
ammonia slip from a selective catalytic reduction (SCR) system or selective non-catalytic
reduction (SNCR) system reacts with SO2 to form ammonium sulfate and ammonium
bisulfate:
4)
2NH3 (gas) + SO2 (gas) + H2O (liq) → 2NH4+ (liq) + SO3¯ (liq) + time, O2 ↔ (NH4+)2 SO4¯
(liq)
5)
NH3 (gas) + SO2 (gas) + H2O (liq) → NH4+ (liq) + HSO3¯ (liq) + time, O2 ↔ (NH4+) HSO4¯
(liq)
or
Even with the small amounts of ammonia slip found at modern coal-fired power plants (2
to 10 ppm), the production of ammonium salts can be significant. The reactions in
equations 4 and 5 are dependent on dissolution in water and the 32o F temperature of the
impingers; they would not normally take place anywhere in or beyond the stack exit. A
nitrogen purge will have no effect in removing the ammonia salts. The only way to
account for these pseudoparticulates is to measure the ammonia salts in the impinger
catch using ion chromatography or selective ion electrodes.
Coupled with the false positives due to the formation of pseudoparticulates is the inherent
inaccuracy of Method 202 and Method 8. During the development of Method 202 the
EPA ran tests on 2 coal-fired boilers. The results of the testing showed standard
deviations of 3.5±1.1 mg/m3 from the first boiler test and 39.5±9 mg/m3.ii The deviations
of 23%-31% in test results clearly indicate inaccuracies in the methods that should
invalidate their use for compliance testing. Method 8 was originally developed to
measure SO3 emissions from sulfuric acid manufacturing plants, a relatively clean and
dry source gas stream. The EPA Emission Measurement Center (EMC) understands that
there are limitations to the usefulness of Method 8 in measuring SO3 emissions from
other sources and has stated;
“Because Method 8 is the only method that EPA has published for measuring sulfuric
acid/sulfur trioxide emission, it has been applied to many source categories other than
the one for which it was developed. It may not work very well for some source categories
and may not be appropriate for measuring sulfur oxide emissions from them. It should
not be used to measure sulfuric acid/sulfur trioxide from the following kinds of sources:
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1. Those sources that have significant emissions of solid sulfates that are water
soluble. Solid sulfates are compounds like sodium sulfate.
2. Those sources that have significant emissions of sulfur dioxide and ammonia.”
Similarly, the imprecision in Method 202 has been noted by the EPA EMC and they have
stated;
“When conducted consistently and carefully, EPA Method 202 does provide acceptable
precision for most emission sources. However, several options are allowed by the method
to accommodate State/local test methods that existed at the time the method was
proposed and promulgated in the Federal Register. Each of these options may change the
mass that would be counted as condensable particulate matter. As a result, when the
same source is tested using different options allowed by the method there may appear to
be a large variation of the condensable particulate emissions. In addition, the flue gas
characteristics may exacerbate the perception of the amount of variation that is
introduced by the optional procedure. For example, under specified conditions, EPA
Method 202 allows the one hour nitrogen purge to be replaced with air or not conducted
when specified conditions exist. Each of these options results in more SO2 remaining
dissolved in the impinger water. The dissolved SO2 slowly converts to SO3 and then to
H2SO4. While the SO2 should not be counted as condensable particulate matter, both
SO3 and H2SO4 form particulate matter. As a result, EPA Method 202 should not be
considered to be a single standardized test method, but should be considered to be a
collection of test methods. Therefore, when EPA Method 202 is specified as the
applicable test method, any optional procedures should also be specified in order to
achieve results that are more in agreement with the basis of the specified emission
limitation.”
IMPACTS OF COAL TYPE AND POLLUTION CONTROL
EQUIPMENT ON CPM FORMATION
Sargent & Lundy LLC has reviewed emission test reports from 8 power plants that
utilized Method 202 to measure CPM. These plants utilize a range of coal types and
pollution control configurations. Since few power plants are currently required to utilize
Method 202, the existing data is too limited to correlate coal-type and pollution control
equipment to CPM emissions. The available data for Bituminous Coal is shown in Table
1, Sub-Bituminous coal is shown in Table 2, and Lignite coal is shown in Table 3.
Table 1. PM Emissions from Select Bituminous Coal-Fired Power Plantsvi
Plant
NOx
control
SO2
control
PM
control
A - 1994
A - 2003
B
SCR
SCR
SNCR
SDA
SDA
--
B
SNCR
--
C
LNB
WFGD
Inorganic
CPM
(lb/mmBt
u)
0.021
0.036
0.0085
Organic
CPM
(lb/mmBt
u)
-0.003
0.0039
Total
CPM
(lb/mmBt
u)
0.021
0.039
0.0124
Total PM
(lb/mmBt
u)
CPM %
of Total
PM
FF
FF
C-ESP
Filterable
PM
(lb/mmBt
u)
0.047
0.015
0.0128
0.068
0.054
0.0252
30.9 %
72.2%
49.6 %
C-ESP
0.0085
0.0505
0.0059
0.0564
0.0649
86.9 %
FF
0.0067
0.0097
--
0.0097
0.0164
59.1 %
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Table 2. PM Emissions from Select Sub-Bituminous Coal-Fired Power Plants
Plant
NOx
control
SO2
control
PM
control
C-ESP
FF
FF
C-ESP
Filterable
PM
(lb/mmBt
u)
0.0222
0.0118
0.0108
0.0197
Inorganic
CPM
(lb/mmBt
u)
0.0490
0.0052
0.0025
0.0300
D
D - 2001
D - 2002
E
-SCR
SCR
SNCR
-SDA
SDA
--
E
LNB
SDA
C-ESP
0.0158
0.0302
Organic
CPM
(lb/mmBt
u)
0.0035
-----
Total
CPM
(lb/mmBt
u)
0.0525
0.0052
0.0025
0.0300
Total PM
(lb/mmBt
u)
CPM %
of Total
PM
0.0747
0.0170
0.0133
0.0497
70.3 %
30.5 %
18.8 %
60.3 %
0.0302
0.0460
65.6 %
Total PM
(lb/mmBt
u)
CPM %
of Total
PM
0.1227
0.0507
73.0 %
71.0 %
Table 3. PM Emissions from Select Lignite Coal-Fired Power Plants
Plant
F - 1999
F - 2003
NOx
control
---
SO2
control
PM
control
SDA
SDA
FF
FF
Filterable
PM
(lb/mmBt
u)
0.0331
0.0147
Inorganic
CPM
(lb/mmBt
u)
0.0896
0.0360
Organic
CPM
(lb/mmBt
u)
---
Total
CPM
(lb/mmBt
u)
0.0896
0.0360
The data in Tables 1-3 show a range of CPM emissions. For bituminous coal, the percent
contribution of CPM to the total PM ranged from 31% to 87%. For sub-bituminous coal,
the percent contribution of CPM to the total PM ranged from 19% to 70%. For lignite
coal, the percent contribution of CPM to the total PM was about 72%.
It is difficult to draw firm conclusions from this data. Nor is it possible, at this point in
time, to correlate CPM emissions with the pollution control equipment configurations.
The emission test reports for many of the plants in Tables 1-3 did not indicate whether a
1-hour nitrogen purge was performed. In most cases, the back-half catch was analyzed
for inorganic CPM only; in just a few cases was the back-half catch analyzed for both
inorganic and organic CPM. It is unknown what percentage of the CPM is true and what
is pseudoparticulate.
It is conceptually understood how the pollution control equipment could contribute to the
formation of CPM. As described above, ammonia slip from an SCR or SNCR could
combine with SO2 to form ammonium sulfate and ammonium bisulfate, both
pseudoparticulates. The catalyst in an SCR could also contribute to the oxidation of SO2
to SO3, creating sulfuric acid mists, a true CPM species.
The data in Table 1-3 does indicate the significance of CPM emissions from all coal-fired
power plants. As more plants will be required to perform Method 202 tests in the future,
meeting total PM emission limits will prove to be challenging.
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Other Available Data on CPM from Coal-Fired Power Plants
The U.S. EPA’s Air Pollution Emission Factors (AP-42) for bituminous and subbituminous coal combustion has limited information on condensible particulate
emissions. For a pulverized coal-fired boiler, equipped with a particulate control system
and flue gas desulfurization (FGD) system, AP-42 reports a total condensible particulate
emission rate of 0.02 lb/mmBtu (AP-42, Table 1.1-5) with an emission factor rating of
“E”, the lowest confidence rating that the U.S. EPA gives for an emission factor. This
number falls within the range of values shown in Tables 1-3 above.
POTENTIAL TECHNOLOGIES FOR REDUCING CPM EMISSIONS
There are several operating approaches and technologies that may allow CPM emissions
to be further controlled. Most of the research and demonstration has been directed
towards the reduction of sulfur trioxide (SO3) as this compound has received the most
attention from regulators and industry. The control techniques and approaches for
reducing condensible particulates include:
•
•
•
•
•
In-furnace injection of alkaline materials
Low SO2 to SO3 conversion SCR catalyst
Control of ammonia slip
Post-SCR sorbent injection for SO3 removal
Wet ESP for CPM reduction
In-furnace Injection of Alkaline Materials
Research and field demonstrations have shown that the injection of alkaline materials into
a coal-fired furnace can effectively reduce SO3 emissions. Carmeuse North America and
URS, working under a DOE Cooperative Agreement, tested by-product Mg(OH)2
injection into the boilers at Bruce Mansfield Plant Unit 3 (BMP3) and at the Gavin
Plant.vii The results of the tests, shown in Figure 1, indicate that up to 90% SO3 removal
was possible with Mg(OH)2 injection. At BMP3, the removal was limited by a need to
maintain acceptable performance in the existing electrostatic precipitator (ESP). At Gavin
Plant, the report stated that the overall sulfuric acid removal was limited because the
furnace injected sorbent was less effective at removing SO3 formed across the SCR
system than at removing the SO3 formed in the furnace. The testing also indicated that
the effect on operational related items such as furnace gas exit temperature, slagging, and
furnace pressure drop were negligible, although the injection did have an adverse affect
on the downstream ESP performance.
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Figure 1 – SO3 Removal From In-Furnace Injection Of Mg(OH)2 at BMP3
Low SO2 to SO3 Conversion SCR Catalyst
Some condensable particulates are the result of additional conversion of sulfur dioxide to
sulfur trioxide when flue gas passes through an SCR catalyst. Many SCR catalyst
manufacturers offer catalyst with a low SO2 oxidation rate. Use of this low conversion
catalyst should be a serious consideration when planning a new SCR installation or
ordering replacement catalyst for an existing SCR.
Control of Ammonia Slip
Ammonia slip from SCRs or SNCRs can react with SO3 in the flue gas to form
ammonium bisulfate as the gas stream cools. The slip expected from an SCR, at the end
of its guaranteed catalyst life, can be 2 ppmv. Similarly, the slip from an SNCR, under
normal operation, can be 5-10 ppmv depending upon the degree of NOx removal
achieved.
The ammonia slip from a SCR, when reacted to form ammonium bisulfate, could result in
un-controlled condensible emissions of 0.026 lbs/mmBtu. The slip from an SNCR could
produce uncontrolled condensible emissions ranging from 0.066 to 0.132 lbs/mmBtu.
Because ammonium bisulfate is a "sticky" particle it is reasonable to assume that
approximately 90% of it would be deposited, along with fly ash, in the air heater. This
reduction results in potential condensible emissions from ammonia slip ranging from
0.003 to 0.013 lb/mmBtu. Considering the particulate emissions limits which are
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appearing in new coal-fired power plant permits, the particulates created by ammonia slip
could potentially be a significant fraction of the permitted limits.
Control of ammonia slip can be accomplished through process controls as well as good
operating practices. Periodic testing the stack flue gas for ammonia slip or the flyash for
residual ammonia can give an indication of the catalyst degradation. A continuous
emissions monitor for ammonia can also be installed in the ductwork following the SCR,
which can be used as a maintenance monitoring tool for minimizing emissions of SO3.
Post SCR Sorbent Injection for SO3 Removal
Sodium Bisulfite (SBS) can be injected as a 10% solution (by weight) into a flue gas
upstream or downstream of the air heater, or upstream of an FGD system. The SBS
reacts with the SO3 in the flue gas to form sodium salts which are then collected by the
existing particulate collection equipment or FGD system. SBS is currently being used at
two commercial installations, First Energy’s Bruce Mansfield Station and Tennessee
Valley Authority’s (TVA) Widows Creek Unit 7, as well as in full-scale testing at
Vectren Corporation’s A. B. Brown and AEP’s Gavin Unit 1. The full-scale testing
indicates SO3/H2SO4 removal capability up to 90% with SO3 levels reduced to
approximately 2 ppm to 10 ppm with reagent stoichiometries of 1.5:1 to 2.0:1. Air heater
fouling and dust dropout in the ductwork have been reported by the operating facilities.
The SBS is shipped to the site as a 30 wt% solution and would be diluted, when used, to
provide a 10 wt% solution that is then pumped to the ductwork and sprayed into the flue
gas stream. SBS could also be shipped as a dry powder or a commercial grade of sodium
bisulfite could be purchased for use. One source of for the SBS is a byproduct of the
double alkali scrubber at Vectren’s A. B. Brown Station. The use of SBS also incurs a
process royalty fee.
Hydrated lime (Ca(OH)2), injected into the flue gas ductwork upstream of an existing
baghouse or cold ESP, will react with SO3 vapor and condensed sulfuric acid to form
calcium sulfate salts. These salts will be removed by the downstream particulate control
equipment. This option has certain drawbacks in that it increases fly ash resistivity,
requires a high stoichiometric ratio for effective removal, and needs a sufficient length of
duct to ensure adequate mixing of the lime with the flue gas. The injected hydrated lime
can form salts that exhibit high resistivity which can reduce ESP performance. Injection
rates vary between 1 lb/hr per 1,000 acfm with humidification to 2 lb/hr per 1,000 acfm
without humidification to achieve 80%-85% reduction of SO3; injection rates can be as
much as 5.6 lb/hr per 1,000 acfm for 95% reduction. This option was used at AEP
Gavin, but the maximum lime injection quantities (~2.5 tph) were limited by ESP
performance.
Trona (Na2CO3• NaHCO •2H2O).) injection downstream of the air heater for SO3 and
sulfuric acid mist control has been successfully demonstrated, by AEP, at the General J.
M. Gavin plant.viii Trona was selected, by AEP, as a candidate for testing based on its
acid neutralizing abilities coupled with its sodium content that would be utilized for
conditioning the precipitators at Gavin. Trona was expected to be useful for maintaining
low fly ash resistivity even as SO3 was removed from the gas stream. Trona is the least
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expensive sodium-based sorbent available. This made it more attractive to test compared
to sodium bicarbonate. Trona injection was tested for SO3 control at Gavin Unit 2 via an
existing hydrated lime injection system. Two sets of tests were conducted: the first set
lasted 11 days, the second 4 days. Testing was conducted first with the SCR’s out of
service. After these test proved to be successful, the #2 SCR reactor was placed in service
Finally all three reactors were placed in service.
AEP’s testing found SO3 removal rates ranging from a low of 63% at about 1 ton per
hour injection rate to a high of 86% at a rate of about 5.8 tons per hour. The figure below
presents the data AEP acquired in the testing in the units of moles of trona injected per
mole SO3. A comparison to SO3 removals achieved with lime injection (using the same
injection equipment and injection locations) showed SO3 removals up to 60% but at
much higher stoichiometries than were required for trona at the same removal.
Wet ESP for Condensible Particulate Matter Reduction
A wet ESP is typically installed between a wet FGD absorber and the stack, removing the
remaining flyash as well as the condensed sulfuric acid. The wet ESP may be located at
grade for horizontal gas flow or mounted on the top of the absorber for vertical gas flow.
The deciding factor on whether to use a horizontal or vertical flow lies in the tradeoff
between the extra ductwork and footprint needed to install the wet ESP at grade and the
structural and foundation alterations necessary to put the wet ESP on top of the FGD
tower. In either arrangement the wet ESP can very effectively capture sulfuric acid
aerosols (90%+). Wet ESPs have been used for many years in the metallurgical
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industry. Utility applications include the AES Deepwater cogeneration plant in Houston
since 1986 and at Xcel Energy’s Sherbourne County Station. A wet ESP was installed on
top of an FGD absorber at New Brunswick Power’s Coleson Cove plant in 2002 and
Wisconsin Energy recently selected wet ESPs for their 1,000 MW Elm Road project.
Wet ESPs operate in a three-step process that includes charging the entering particles,
collection of the particles on oppositely charged plates, and cleaning the collection
surfaces. While a dry ESP uses mechanical cleaning of the collecting plates, a wet ESP
uses either an intermittent or continuous water wash. The advantages of a wet ESP
include an increased power level (2 W/acfm as opposed to 0.1 to 0.5 W/acfm with a dry
ESP) and reduced particle re-entrainment after rapping of the collecting plates. In
addition, the wet ESP uses clean water for washing the plates and may use MgO to
neutralize the wash water for reuse or consume some of the FGD reagent if drained to the
FGD system. The wet ESP also has potential co-benefits in the collection of fine fly ash
particles and possibly some mercury. Wet ESPs require the use of acid-resistant materials
of construction for ductwork and ESP internals that are relatively costly.
CONCLUSION
CPM emission limits are becoming more common in permits for new coal-fired power
plants. Although there are questions about the accuracy of EPA Method 202 for
measuring CPM, at present there does not appear to be a better method acceptable to the
regulatory community. Utilities should be sensitive to potential for pseudoparticulate to
form in the Method 202 impingers, and have alternative means to account for them.
Similarly, the CPM formation should be addressed in the bidding specifications when
purchasing pollution control equipment.
The bulk of the CPM emissions appear to be related to SO3. Several control technologies
exist to reduce the emission of condensible particulates. The selection of a method to
reduce condensible particulate emissions at a coal-fired power plant will be site specific
and will depend upon economic as well as technical factors.
i
DeWees, F.G.; Stelnsberger, S.C., et.al. Laboratory and Field Evaluation of the EPA Method 5 Impinger
Catch for Measuring Condensible Matter from Stationary Sources, U.S. Environmental Protection Agency:
Research Triangle Park, NC. 1989.
ii
Method Development and Evaluation of Draft Protocol for Measurement of Condensible Particulate
Emissions. EPA 450/4-90-112, U.S. Environmental Protection Agency; Research Triangle Park, NC. 1990
iii
Filadelfia, E.J.; McDannel, M.D. “Evaluation of False Positive Interferences Associated with the Use of
EPA Method 202.” In Proceedings of the 89th Annual A&WMA Meeting. Air & Waste Management
Associate: Pittsburgh, PA, 1996: Paper No. 96-RA109.04.
iv
Measurement of Condensible Particulate Matter: A review of Alternatives to EPA Method 202, Electric
Power Research Institute, Palo Alto, CA: 1998. Report TR-111327.
v
Corio, Louis A. and John Sherwell. “In-Stack Condensible Particulate Matter Measurements and Issues.”
in the Journal of the Air & Waste Management Association, volume 50, February 2000.
vi
Emissions data in Tables 1-3 were taken from the Emissions Testing Reports for various power plants,
obtained from the State Regulatory Agencies under the Freedom of Information Act (FOIA).
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vii
Blythe, G. M. and McMillan, R. "Sulfuric Acid Removal Process Evaluation: Long-term Results," DOE
Topical Report, July 2002.
viii
Ritzenthaler, Douglas P. and Maziuk, John, “Successful Mitigation of SO3 Emissions While
Simultaneously Enhancing ESP Operation at the General James M. Gavin Plant in Cheshire, Ohio by
Employing Dry Sorbent Injection of Trona Upstream of the ESP” , EPA/EPRI/DOE/AWMA
Megasymposium, Washington D.C., August 2004
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