United States
Environmental Protection
Agency
Off ice Of
The Administrator
(A-101F6)
171-R-92-003
February 1992
>,EPA
The Use Of SNCR As
BACT For NOx Control
In Boilers And Municipal
Solid Waste Incinerators
Printed on Recycled Paper
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The Use of SNCR as BACT for NOx Control in
Boilers and Municipal Solid Waste Incinerators
Prepared for the U. S. EPA Region H
Air Compliance Branch
August, 1991
by
Michele Kaplan
Protection
West
Chicago,
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o
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DISCLAIMER
This report was furnished to the U.S. Environmental Protection
Agency by the student identified on the cover page, under a National
Network for Environmental Management Studies fellowship.
The contents are essentially as received from the author. The
opinions, findings, and conclusions expressed are those of the author
and not necessarily those of the U.S. Environmental Protection
Agency. Mention, if any, of company, process, or product names is
not to be considered as an endorsement by the U.S. Environmental
Protection Agency.
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Table of Contents
Page
Abstract 2
NOx Formation 3
SNCR Technology ~ . 4
Facility Descriptions 7
Field Data 11
Conclusions 15
References 16
Contacts 18
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Abstract
This report presents an investigation into the present
operational use of selective non-catalytic reduction (SNCR) as a
method of NOx control in boilers and incinerators. Two patented
forms of SNCR were researched; Exxon's Thermal DeNOx, which uses
ammonia injection, and Fuel Tech's NOxOUT, which uses urea
injection. A questionnaire was faxed to fifteen facilities in
the United States that use ammonia injection systems, most of
which are located in the Stockton, Delano and San Diego areas of
EPA Region IX. No facilities were found in the United States
that currently operate with NOxOUT or any other type of urea
injection system. Frc-m the responses that were received, it can
be concluded that SNCR is an effective and relatively inexpensive
method of NOx control, achieving up to an 85% reduction
efficiency with a capital cost ranging from $100,000 to $500,000
and a monthly cost of about $4,000 for ammonia and maintenance.
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Acknowledgements
The research performed for this paper was assigned as a
project for the National Network for Environmental Management
Studies (NNEMS), a program that began four years ago to develop a
relationship between the EPA and various universities. I am
presently a senior at the Cooper Union, studying Mechanical
Engineering. My ten weeks at the EPA was a great summer
experience. I had the opportunity to speak to environmental
engineers and plant managers working in the field of power
generation, as well as visit a few cogeneration facilities in New
Jersey. I also had the opportunity to prepare a presentation of
my work for the employees of the Air Compliance Branch. In my
free time it was interesting to speak to people at different
branches of the EPA, to learn about the various projects they
were working on. I was surprised at the diversity of education
and experience of everyone, and received a lot of support and
advice about graduate schools and careers in Mechanical and •
Environmental Engineering.
Michele Kaplan
August 16, 1991
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NOx Formation
There are two main causes of NOx formation, thermal
chemistry and fuel bound nitrogen, where NOx is a combination of
about 90% NO and 10% N02.
Thermal NOx
Thermal NOx is caused by the dissociation of N2 and 02 at
high temperatures, resulting in the following reactions:
N2 + O > NO + N (1)
N + 02 > NO + O (2)
Maximum thermal NOx production occurs at a slightly lean
fuel mixture ratio due to the excess oxygen available for the
nitrogen to react with. Also, since almost all thermal NOx is
generated in the combustion flame core, there is higher NOx
production at higher flame temperatures [1].
Fuel NOx
Fuel NOx is generated when fuel bound nitrogen compounds
react with oxygen when the fuel is burned. The written reaction
is much more complicated than the equations above because of the
complexity of the nitrogen compounds, and the compounds vary with
the different types of fuel used. Among fossil fuels, coal
generates higher NOx emissions per unit of energy input than fuel
oil, with natural gas generating the least NOx [1]. Fuel NOx also
can be reduced by controlling the amount of oxygen in contact
with the fuel.
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SNCR Technology
There are three patented SNCR technologies currently
available; Thermal DeNOx from Exxon, a DeNOx system from
PYROPOWER and NOxOUT from Fuel Tech. Thermal DeNOx and PYROPOWER
use ammonia injection and NOxOUT uses urea injection.
Thermal DeNOx
Thermal DeNOx is a method of non - catalytic NOx reduction
patented by Exxon. The Thermal DeNOx process injects gaseous
ammonia into flue gas to react with NOx by the following
reactions [2]:
2NO + 4NH3 + 202 > 3N2 + 6H2O (3)
4NH3 + 502 > 4NO + 6H2O (4)
The first reaction dominates in the temperature range of
1600 to 2200 degrees Fahrenheit, causing a decrease in NOx.
Above 2200°F, the second reaction dominates, causing an increase
in NOx production. Below 1600°F, there is an insufficient amount
of activity to either increase or decrease the amount of NOx.
The optimum temperature for NOx reduction using the Thermal DeNOx
system has been empirically determined by Exxon to be 1750°F. [2]
For a substantial amount of NOx reduction to occur, there
must be adequate residence time and mixing of the ammonia and the
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flue gas in the required temperature range, without any drastic
temperature variations occurring during the reaction. The initial
ammonia to NOx ratio also affects the reduction process; NOx
reduction of 40 to 60 percent require 1.5 to 2.0 NH3/NOx
injection ratios [2].
PYROPOWER
PYROPOWER has recently patented an ammonia injection system
similar to Thermal DeNOx. The chemical reactions between the
ammonia and NOx are the same as in the Exxon system; however, the
SNCR design is customized for the PYROPOWER boiler systems.
•NOxOUT
The NOxOUT process of non - catalytic NOx reduction was
patented by Fuel Tech. The process injects a urea solution into
the upper furnace or high temperature section of a boiler or
incinerator to reduce NOx by the following reaction:
NH2 + NO --- > N2 + H2O (5)
This reaction takes place at temperatures between 1700°F and
3000°F. However, Fuel Tech has also patented additives that
change this temperature range for NOx reduction to 800°F to
2100°F [2]. The NOxOUT process also needs adequate mixing and
residence time of the urea solution and the flue gas for
substantial NOx reduction to occur.
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Capital costs for urea injection are less than that of
ammonia injection as the safety hazards of ammonia storage are
avoided. Anhydrous ammonia is stored as a liquid in a
pressurized vessel, which usually is sized for biweekly or
monthly refilling. There is the possibility of vessel or piping
failure, resulting in the release of a large ammonia gas cloud,
which is an extreme health hazard [3]. Urea, on the other hand,
can be stored in granular form, then mixed with water prior to
injection. However, urea injection has a higher operating cost
than ammonia injection as urea is more expensive than ammonia.
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Facility Descriptions
In a boiler, fuel is either injected through a nozzle and
burned while suspended in the boiler combustion chamber, or solid
fuel such as coal, wood or municipal waste is burned on a grate
at the bottom of the combustion chamber. A fluidized bed boiler
is one in which the cfombustion of solid waste occurs in a hot,
suspended bed of sand or other media. The combustion
temperatures in a boiler vary from 1600°F to 1800°F [2]. This
temperature range supports the use of SNCR as NOx control. After
the gas exits the combustion chamber in a boiler, it travels
through a cyclone that recycles char and bed material back into
the fluidized bed. The cyclones provide ideal mixing chambers
for ammonia or urea solutions and the flue gas.
The PYROPOWER DeNOx system injects ammonia either into the
cyclones or the combustion chamber, depending on the gas
temperatures. If the temperature entering the cyclones is 1500°F
or above, the ammonia is injected to the cyclones, otherwise it
is injected into the combustion chamber [9].
Another method of decreasing NOx in boilers is the use of
staged combustion. In staged combustion, there are two air
injection sections in the boiler. Air is injected in the primary
section at substoichiometric conditions to decrease the amount of
thermal NOx generated, then secondary air is injected downstream
to complete the fuel combustion. The distribution between the
primary and secondary injection nozzles can be adjusted to
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increase the flame length, which decreases the peak flame
temperature and thus decreases the amount of thermal NOx
generated as well. In a fluidized bed boiler, the distribution
of the underfire and overfire combustion air influences NOx
production. For municipal solid waste incinerators, the fuel
nitrogen content is extremely important as 75 to 80 percent of
the total NOx formed "may be fuel NOx [2].
NOx control tests were performed on a 40 MW coal-fired
circulating fluidized bed boiler for the Department of Energy
Conversion at Chalmers University of Technology in Sweden. The
boiler under investigation used the Fuel Tech NOxOUT system for
NOx reduction. Using this system, it was discovered that NOx
formation increased with increasing bed temperatures, which is
expected since high temperatures support the production of
thermal NOx. There also were higher NOx emissions at lower loads
than at higher loads. This was due to an increase in excess air,
which increased the amount of oxygen available to form NOx. It
was also discovered that when the urea solution was injected
before the cyclones the ammonia slip was much smaller than when
injected at the cyclone outlet, which makes sense since the
cyclones provide excellent mixing conditions for the urea and
flue gas [4].
The boiler system achieved a NOx reduction of 90% with a
urea injection ratio corresponding to an ammonia molar ratio of
3.5, and a bed temperature of 1650°F. The ammonia slip was about
3 to 4 mg/nm3. However, with this high percent NOx reduction,
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the CO emissions increased by 60%, which is due to incomplete
combustion of the coal. In the report's conclusions, it vas
claimed that the optimum bed temperature for NOx reduction using
the NOxOUT system is about 1540°F, which takes into account the
increase in CO emissions with the increase in percent NOx
reduction [4].
Other tests on NOx reduction using urea injection were
performed on a West German 325 MW electric utility coal-fired
boiler and a Swiss 330 TPD municipal solid waste incineration
plant. For these facilities, there were no chemicals or
additives used with the urea.
To reduce NOx emissions, the coal-fired boiler used a multi-
level burner system and urea injection through steam driven
nozzles located in the furnace at 165 ft and 205 ft elevations.
Depending on the flame size, urea would be injected at either of
the two elevations. The large furnace size of 54 X 54 X 250 feet
also reduced NOx formation as it increased the amount of time
available for the urea-water solution droplets to dry, which
improved the mixing of the solution and the flue gas before the
DeNOx reactions began to occur. The municipal solid waste
incinerator used air-carried high energy urea injection nozzles,
also located at two elevations [5].
The ammonia slip for both facilities was determined using
two methods; continuous gas analyzers and sample extraction for
wet chemistry methods. Although much more labor intensive, the
second method provided more consistent results, possibly because
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ammonia was lost in gas sampling lines upstream from the gas
analyzer cells in the first method [5].
.The coal fired boiler used a urea/NOx molar ratio of 0.5,
achieving 60% NOx reduction. The MSW incinerator achieved 42%
NOx reduction using the same molar ratio of 0.5. The highest
efficiency of NOx reduction in the coal fired boiler occurred
between 1600°F and 19OO°F and in the incinerator occurred between
1550°F and 1850°F. It is believed that the width of the
temperature window is due to the following factors: the ability
of the injection system to mix and distribute small amounts of
urea into large volumes of flue gas; the ability of the control
system to adjust the location where the urea was injected from
one of the two levels to the other; the allowed drying time for
the urea - water solution droplets. As the temperature decreased
during the testing, the ammonia slip increased. It was concluded
that as the temperature of the reaction drops below 1600°F,
ammonia slip is expected to increase to levels above 10% of the
concentration of urea being injected [5], This conclusion is
consistent with the given optimum operating temperature range for
NOxOUT of 1700°F to 3000°F.
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Field Data
Ten facilities that have installed SNCR in EPA Region IX
were sent questionnaires requesting information on emission
reduction, ammonia storage, maintenance requirements and costs of
their ammonia injection systems. Table 1 lists the name, size,
permit date, approximate percent efficiency and type of fuel used
for each of the facilities.
Table 1: List of Facilities Contacted
Facility
Cogeneration National Corp, Stockton, Ca.
Stockton Cooeneration, Stockton, Ca.
Delano Energy Co., Delano, Ca.
Valley Power Associates, Delano, Ca.
Mt Poso Cogeneration, Mt. Poso, Ca.
Argus ACE, Trona, Ca.
Corn Products Co., Stocklon, Ca.
GWF Power Systems, Stockton, Ca.
Westinghouse Electric Corp, Sunnyvale, Ca.
Commerce Refuse to Eneroy, Commerce, Ca.
Fuel
Coal Fired Boiler
Coal Fired Boiler
Coal Fired Boiler
Coal Fired Boiler -
Coal Fired Boiler
Coal Fired Boiler
Coal Fired Boiler
Coal Fired Boiler
Gas Fired Boiler
MSW Incinerator
Permit Date
12/85
na
na
na
1/87
11/85
12/85
2/85
8/88
5/84
% Efficiency
75%
80%
75%
na
70%
75%
85%
na
85%
40%
Size
49 MW
49.9 MW
31 MW
61 MW
49.5 MW
96 MW
49.5 MW
202 MMBtu/hr
380 MMBtu/hr
11.5 MW
As can be seen in Table 1, most SNCR systems operate between
70% and 85% NOx reduction efficiency, with Commerce Refuse to
Energy as the exception. One explanation of this could be that
Commerce burns municipal solid waste, which may produce more NOx
than the coal fired boilers. Size could also contribute to the
lower efficiency as the facility is only 11.5 MW, where most of
the other facilities are between 31 and 61 MW. However, these
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are only speculations since Commerce is the only facility of that
size in this study.
Table 2 lists emissions data received from the facilities
that responded to the questionnaire, where the ppm is calculated
at 3% 02. The facilities that burn solid fuels reported the
occurrence of ammonium chloride pluming and an ammonia slip
exceeding 10 ppm when- attempting to reduce NOx below 25 to 30 ppm
using SNCR [6]. Excess ammonia can form ammonium sulfates and
can produce more NOx by oxidizing itself. Even though ammonia
consumption depends on the type of fuel used and the uniformity
of temperature and oxygen level in the fluid beds, plant
engineers at Cogen National claim that there does not appear to
be a correlation between the nitrogen content of the coal they
use and the ammonia consumption. They also claim that the
frequency of ammonium chloride pluming is not directly related to
the chloride content of the coal [10].
Table 2: Facility Emissions Data
Facility
Mt. Peso Cogen
Argus Cogen
Corn Products
Commerce Refuse
Degeneration National
Stockton Cogen
Uncontrolled
NOx
Emissions
not available
not available
not available
47 Ib/hr
70-120 ppm
180-190 ppm
Permitted NOx
Emissions
70 ppm
70 ppm
40 ppm
40 Ib/hr
30 ppm
50 ppm
Actual NOx
Emissions
50 ppm
50 ppm
30-35 ppm
28 Ib/hr
25 ppm
25-30 ppm
Measured
Ammonia Slip
1-2 ppm
2 ppm
5-10 ppm
not measured
not measured
not measured
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At most facilities, the ammonia is stored as a liquid in a
horizontal•cylindrical pressurized storage tank that has a
capacity of 10,000 to 20,000 gallons. The ammonia is then
vaporized before injection into the boiler. The safety features
of the ammonia storage system generally consists of the
following: 100% pressure relief valves, high flow check valves
and solenoid valves i-n the piping, ammonia detectors with alarms
situated around the storage tank, a manual and computer operated
water deluge that will convert ammonia vapor to liquid if any
vapor escapes, safety showers and eye baths. At many of the
facilities, the storage tank is contained within a concrete dike.
All the facilities contacted claimed that the plants were
never shut down solely to repair the SNCR system. General
'maintenance is needed for two parts of the SNCR system during the
year: the ammonia storage and distribution system and the
continuous emissions monitoring system. During facility
shutdown, maintenance for the ammonia storage and distribution
system includes the following: mending or replacing leaking
pipes, replacing control valves, adjusting the control system,
replacing injection nozzles, calibrating the instrumentation,
painting the ammonia storage tank, -and testing the ammonia
storage safety system. The continuous emissions monitoring
systems require daily electrical and optical checks as well as
weekly gas calibrations. At most facilities the system is
constantly adjusted and modified, however, it seems that fewer
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adjustments are needed after the system is in operation for a
year or two.
Many facilities could not determine the capital cost of
their SNCR system as the cost was included in the fixed price
contract for the boiler. However, Commerce Refuse to Energy
claimed the capital cost of their SNCR system to be approximately
$100,000 for their 11-.5 MW system [8] and Delano Energy Co.
claimed the capital cost to be $500,000 for their 31 MW system
[11]. The maintenance costs for the facilities are approximately
$10,000 to $13,000 per year. The ammonia costs range from $150
to $250 per ton.
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Conclusions
1 SNCR can achieve 70% to 85% NOx reduction in coal fired
boilers. When operated at a higher percent NOx reduction, excess
ammonia is produced, which causes ammonium chloride pluming
and/or the production of corrosive ammonium sulfates.
2 Permit limits for .NOx emissions are set at about 10 ppm higher
than the lowest emissions achievable as a safety factor because
of possible fluctuations in the ammonia injection system.
Perhaps future permit limits can be lower than they are now, with
an allowable number of exceedances per year of up to 10 ppm
higher than the given permit limit.
3 The capital and maintenance costs of an SNCR system are
reasonable, and with the NOx reduction data support the use of
SNCR as a best available control technology for NOx reduction in
boilers and municipal solid waste incinerators. It is also
easier and less expensive to retrofit an ammonia injection system
than it is to retrofit a catalyst into an existing facility, so
SNCR may be considered BACT for a facility if SCR is not
feasible.
4 Aqueous ammonia can be stored without any problems if the
storage system is maintained on a weekly basis, and if there are
sufficient safety features supporting the system.
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References
1 Neuffer, W. J. NOx Control Technologies for Small Boiler
Applications. Prepared for the U. S. Environmental Protection
Agency, Research Triangle Park, N. C. July 24, 1985.
2 The Radian Corporation. Sourcebook for NOx Control Technology
Data. Prepared for the U. S. Environmental Protection Agency,
Research Triangle Park, N. C. July, 1991.
3 Cobb, David, et aJL. "Application of Selective Catalytic
Reduction (SCR) Technology for NOx Reduction From Refinery
Combustion Sources." Fluor Daniel, Inc., Irvine, Ca.
Environmental Progress, Vol 10, No 1. Feb, 1991.
4 Mjornell, Margareta, et al. "Emissions From a Circulating
Fluidized Bed Boiler." Department of Energy Conversion, Chalmers
University of Technology, Sweden. Report A 89 - 180, August,
1989.
5 Jones, D. G. , et a_l. "Urea Injection NOx Removal in European
Coal Fired Boilers and Municipal Solid Waste Incineration
Plants." Noell - KRC. 83 rd AWMA Annual Meeting and Exhibition,
Pittsburgh, Pa. Paper No. 90 - 32.3, June 24 - 29, 1990.
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6 Phone conversation with Bruce Furbish, Plant Engineer for Pyro
Power at Mount Poso Cogeneration Co., July 10, 1991.
7 EXXON; The Thermal DeNOx Process. The Exxon Research and
Engineering Company, Technology Licensing Division, 1989.
8 Facsimile sent from. Joe Smisko at the Commerce Refuse To Energy
Facility, July 24, 1991.
9 Facsimile sent from Sharon Ferrier at PYROPOWER, August 9,
1991.
10 Facsimile sent from Nigel Guest at Avalon Engineers, August
12, 1991.
11 Facsimile sent from Paul Dolan at Thermo Electron Energy
Systems, August 13, 1991.
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Contacts
Source: Cogeneration National Corp
Contact: Rich Recor, General Plant Manager
Phone: 209 462 2723
Source: Stockton Cogeneration
Contact: Allen Anderson, Environmental Consultant
Phone: 209 983 0391
Source: Westinghouse Electric Corp
Contact: Tom Froman, Plant Engineer
Phone: 408 735 4400 .
Source: Commerce Refuse to Energy
Contact: Joe Smisko, Plant Engineer
Phone: 213 721 1278
Sources: Mount Poso Cogeneration Corp
Argus ACE Cogeneration
Corn Products
Contact: Bruce Furbish, Engineer for Pyro Power
Phone: 619 458 3161
Source: GWF Power Systems Co. Inc.
Contact: Kevin Kolnowski, Plant Engineer
Phone: 415 938 5117
Sources: Delano Energy Co.
Valley Power Associates
Contact: Paul Dolan, Plant Engineer
Phone: 617 622 1146
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