950R80041
U.S. Environmental Electric Power IERL-RTP-1084
Protection Agency Research Institute October 1980
Proceedings of the Joint
Symposium on Stationary
Combustion NOx Control
Volume II
Utility Boiler NOx Control
by Flue Gas Treatment
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the MISCELLANEOUS
REPORTS series. This series is reserved for reports whose
content does not fit into one of the other specific series.
Conference proceedings, annual reports, and bibliographies
are examples of miscellaneous reports.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policy of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
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IERL-RTP-1084
October 1980
Proceedings of the Joint
Symposium on Stationary
Combustion NOx Control
Volume II
Fun Utility Boiler NOx Control
by Flue Gas Treatment
Symposium Cochairmen
Robert E. Hall, EPA
and
J. Edward Cichanowicz, EPRI
Program Element No. N130
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
and
ELECTRIC POWER RESEARCH INSTITUTE
3412 Hillview Avenue
Palo Alto, California 94303
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PREFACE
These proceedings document more than 50 presentations given at the
Joint Symposium on Stationary Combustion NOx Control held October 6-9,
1980 at the Stouffer's Denver Inn in Denver, Colorado. The symposium was
sponsored by the Combustion Research Branch of the Environmental
Protection Agency's (EPA) Industrial Environmental Research
Laboratory-Research Triangle Park and the Electric Power Research
institute (EPRI). The presentations emphasized recent developments in
N0X control technology. Cochairaen of the symposium were Robert E.
Hall, EPA, and J. Edward Cichanowicz, EPRI. Introductory remarks were
made by Kurt E. Yeager, Director, Coal Combustion Systems Division, EPRI,
and the welcoming address was given by Roger L. Williams, Regional
Administrator, EPA Region VIII. Stephen J. Gage, Assistant Administrator
for Research and Development, EPA, was-the keynote speaker. The symposium
had 11 sessions:
I: N0X Emissions Issues
Michael J. Miller, EPRI, Session Chairman
II: Manufacturers Update of Commercially Available Combustion
Technology
Joshua S. Bowen, EPA, Session Chairman
III: N0X Emissions Characterization of Full Scale Utility
Powerplants
David G. Lachapelle, EPA, Session Chairman
IV: Low NOx Combustion Development
Michael W. McElroy, EPRI, Session Chairman
Va: Postcombustion N0X Control
George P. Green, Public Service Company of Colorado,
Session Chairman
Vb: Fundamental Combustion Research
Tom W. Lester, EPA, Session Chairman
VI: Status of Flue Gas Treatment for Coal-Fired Boilers
Dan V. Giovanni, EPRI, Session Chairman
VII: Small Industrial, Commercial, and Residential Systems
Robert E. Hall, EPA, Session Chairman
VIII: Large Industrial Boilers
J. David Mobley, EPA, Session Chairman
IX: Environmental Assessment
Robert P. Hangebrauck, EPA, Session Chairman
X: Stationary Engines and Industrial Process Combustion Systems
John H. Wasser, EPA, Session Chairman
XI: Advanced Processes
G. Blair Martin, EPA, Session Chairman
ii
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VOLUME II
TABLE OF CONTENTS
Session Va: Postcombustion N0X Control
Page
Session Va: Postcombustion N0X Control
"Empirical Evaluation of Postcombustion Control,"
J. E. Cichanowicz *
"Assessment of N0X Flue Gas Treatment Technology,"
J. D. Mobley 1
"Development of Flue Gas Treatment in Japan,"
Y. Nakabayashi ..... *
"Status of SCR Retrofit at Southern California Edison
Huntington Beach Generating Station Unit 2,"
L. W. Johnson, C. L. W. Overduin, and D. A. Fellows 24
Session VI: Status of Flue Gas Treatment for Coal-Fired Boilers
"Countemeasure8 for Problems in N0X Removal Process
for Coal-Fired Boilers," H. Itoh and Y. Kajibata 47
"Treating Flue Gas from Coal-Fired Boilers for N0X
Reduction with the Shell Flue Gas Treating Process,"
J. B. Pohlenz, A. 0. Braun, and R. A. Persak *
"The Hitachi Zosen N0X Removal Process Applied to
Coal-Fired Boilers," R. Wiener, P. Winkler,
and S. Tanaka 70
"Babcock-Hitachi N0X Removal Process for Flue Gases
from Coal-Fired Boilers," T. Narita, H. Kuroda,
Y. Arikawa, and F. Nakajima 106
"Test Summary of an Integrated Flue Gas Treatment System —
Utilizing the Selective Catalytic Reduction Process for a
Coal-Fired Boiler," N. Aoki and J. S. Cvicker 129
"The Development of a Catalytic N0X Reduction
System for Coal-Fired Boilers," T. Sengoku, Y. Todo,
N. Yokoyama, and B. M. Howell *
*See Volume V, Addendum.
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ASSESSMENT OF N0X FLUE GAS TREATMENT TECHNOLOGY
By:
J. David Mobley
Industrial Environmental Research Laboratory
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
1
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ABSTRACT
The Environmental Protection Agency has maintained a program to
further the advancement of N0X control by flue gas treatment technology
since the early 1970's. The program consists of technology assessment
studies in conjunction with small scale experimental projects. These
activities have shown that 80-90% reduction of N0X emissions by selective
catalytic reduction with ammonia has been commercially demonstrated on
gas- and oil-fired sources in Japan, and that such processes are ready
for test application on coal-fired sources. The Japanese experience,
combined with experimental projects in the U.S., should establish the
technology as a viable control technique for use in tackling N0X
environmental problems in the U.S. However, some significant technical
concerns need to be addressed in demonstration projects before wide-
spread application of the technology can be recommended.
2
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INTRODUCTION
The U.S. Environmental Protection Agency (EPA) has maintained a
research and development program since the early 1970's to advance flue
gas treatment technology for the control of nitrogen oxide (NO^)' emissions
from stationary combustion sources. The objective of this program has
been to demonstrate the technical feasibility of a 90% reduction of
N0X emissions in a cost effective, energy efficient, and environmentally
sound manner. Emphasis of the program has been on control of N0X emis-
sions from coal-fired boilers.
This program has been maintained since technology for highly
efficient N0X reduction may be required as a control strategy for some
of the environmental problems in the United States. Specifically,
application of the technology may be required by regulations which
address Prevention of Significant Deterioration, Visibility Protection,
Acid Rain, or Nonattainment of National Ambient Air Quality Standards
(NAAQS). The promulgation of a short term nitrogen dioxide (NO2) NAAQS
may increase the number of nonattainment areas for NO2 and may increase
the need for application of flue gas treatment technology (1).
To ameliorate their environmental problems, the Japanese have
developed and applied N0X flue gas treatment technology to gas- and oil-
fired sources and are planning applications on coal-fired sources. They
have also conducted extensive research on dry and wet processes for
simultaneous control of N0X and sulfur oxide (SOx) emissions. Thus, a
major portion of EPA's program has been to investigate Japanese tech-
nology for potential applications to coal-fired boilers in the U.S.
Accordingly, this paper will include:
3
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"Assessment of Technology in Japan
-Dry N0X Processes
-Dry Simultaneous NOx/SOx Processes
-Wet N0X and N0X/S0X Processes
"Assessment of Technology for Application in the U.S.
-Cost Estimates
-Energy and Environmental Impacts
-Experimental Projects
Finally, conclusions that can be drawn from these assessment
activities will be presented.
4
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ASSESSMENT OF TECHNOLOGY IN JAPAN
Japanese technology for control of N0X and simultaneous control of
N0X and S0X by flue gas treatment techniques Is more advanced than any
other country's. EPA has sponsored the publication of periodic reports
and papers to facilitate the transfer of Information from Japan to the
United States. These documents have been mainly prepared by Jumpel Ando
of Chuo University, Tokyo, Japan (2,3). Since most of the development
and application of N0X flue gas treatment technology has been in Japan,
it is appropriate for any assessment to begin with the status of the
technology In Japan.
DRY N0X PROCESSES
Selective catalytic reduction (SCR) of N0X with ammonia (NH3) is
the only process that has achieved notable success in treating combustion
flue gas for 90% removal of N0X and has progressed to the point of commer-
cial application. SCR processes are based on the preferential reaction
of NH3 with N0X rather than with other flue gas constituents. Since
oxygen (O2) enhances the reduction, the reactions can best be expressed
as:
Equation 1 represents the predominate reaction since approximately
95% of the NOx In combustion flue gas Is in the form of nitric oxide (NO).
Therefore, under ideal conditions, a stoichiometric amount of NH3 can be
used to reduce N0X to harmless molecular nitrogen (N2) and water vapor (H2O).
4NH3 + 4N0 + 02
•> 4N2 + 6H2O (1)
4NH3 + 2N02 + 02
•> 3N2 + 6H20 (2)
5
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In practice, an NH3 5NO mole ratio of about 1:1 has typically reduced
N0X emissions by 90% with a residual NH3 concentration of less than
20 ppm.
The SCR processes require a reactor, a catalyst, and an ammonia
storage and injection system. Due to increased pressure drop across the
SCR reactor, some increase in boiler fan capacity, or possibly an addi-
tional fan, may be necessary.
The optimum temperature for the N0X reduction reaction without a
catalyst is about 1000°C (1830°F). However, the catalyst effectively
reduces the optimum reaction temperature to the 300° to 450°C (570° to
845°F) range. To obtain flue gas temperatures in this range and to
avoid the requirement for large amounts of reheat, the reactor is
usually located between the boiler economizer and the air preheater. A
typical flow diagram is shown in Figure 1. Obviously, the reactor and
catalyst are the critical elements of the process and warrant further
discussion.
Catalysts with vanadium compounds were found to promote the
reduction of N0X with NH3 and to be unaffected by the presence of S0X.
Titanium dioxide (Ti02) was found to be an acceptable carrier, since it
is resistant to attack from SO3. Therefore, many S0X resistant catalysts
are based on Ti02 and V2O5; however, constituents and concentrations of .
most catalysts are proprietary.
Reactor and catalyst configurations also vary with the application,
primarily to accommodate the different particulate concentrations.
Natural-gas-fired boilers employ SCR catalysts (as spherical pellets,
cylinders, or rings) and reactor vessels (as fixed packed beds).
6
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However, designs for use with oil- and coal-fired boilers have to
be capable of tolerating particulates (fly ash) in the flue gas stream.
For these applications, a parallel flow catalyst is preferred. Parallel
flow means that the gas flows straight through the open channels parallel
to the catalyst surface. The particulates in the gas remain entrained
while N0X reaches the catalyst surface by turbulent convection and
diffusion. An alternative to the parallel flow catalysts is the parallel
passage reactor. In this design, the catalyst material is arranged in
channels and held in place by a metal screen. The operating principle
is similar to that of the parallel flow catalyst.
The various parallel flow catalyst shapes are shown in Figure 2.
The catalyst may be a homogeneous material or may be composed of an
active material coated on the walls of a metallic or ceramic carrier.
The parallel flow catalysts are normally manufactured In a unit cell
configuration about 1 m^ as shown in Figure 3. The cells are stacked in
banks in the reactor as shown in Figure 4.
Even though much progress has been made In catalysts and reactor
design, some problems still remain* The catalysts may not be resistant
to all contaminants in flue gas or be able to tolerate high particulate
loadings. In addition, fine particulates, smaller than about 1 ym, may
blind the catalyst surface. Long term operation without catalyst
plugging or catalyst erosion needs to be demonstrated for coal-fired
applications. Catalyst life also needs to be extended from the current
guarantees of 1 to 2 years for applications with S0X and particulates in
the gas stream.
One of the major concerns with SCR processes Is the formation of
solid ammonium sulfate [(Nlty^SO^] and liquid ammonium bisulfate
(NH4HSO4) downstream of the reactor. The formation conditions are
7
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difficult to avoid since some unreacted NH3 from a SCR system and some
SO3 from combustion of sulfur-containing fuels is expected. The biggest
problem seems to be deposition of (NH4)2S04 and NH4HSO4 on the air
preheater. These compounds are corrosive and can form deposits which
plug the air preheater. Air preheater problems were found to be most
severe on high-sulfur oil-fired applications and coal-fired units which
employ a hot electrostatic precipitator (ESP) ahead of the N0X reactor
and the air preheater. Systems which accept full particulate charge of
a coal-fired boiler through the air preheater should have less difficulty
with pluggage of the air preheater. In these systems, the fly ash
apparently scours the surface of the air preheater to remove any deposits,
or the ammonium compounds deposit on the fly ash and are carried through
the air preheater by the fly ash. However, increased soot blowing, from
both the hot and cold sides, and water washing of the air preheaters
appear necessary for most applications. The wash water from cleaning
air preheaters as well as purge streams from a flue gas desulfurization
(FGD) unit may require treatment to remove NH3 before being discharged.
Modifications to the conventional air preheater design are also being
developed to address the ammonium sulfate problem; however, these units
have not been applied on full scale systems as yet.
Other concerns and potential problems include: emission of NH3 and
NH3 compounds; causing or increasing the emission of undesirable compounds
such as SO3; affecting the performance of downstream pollution control
equipment such as FGD processes, ESPs, and baghouses; lack of proven
NH3 analytical control systems; sensitivity of the process to temperature
changes due to boiler load swings; disposal or reclamation of spent
catalysts in an environmentally acceptable manner; and reliability of
the process and its effect on the boiler system's availability.
8
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Despite these potential problem areas and uncertainties, the
processes have been successfully installed and operated in Japan on gas-
and oil-fired boilers, and coal-fired units are being constructed. The
companies listed in Table I were visited by a team of EPA, Tennessee
Valley Authority, and Radian Corporation personnel in March 1980 to
survey the status of the technology in Japan. The gas- and oil-fired
operating units reported very high reliability and the capability to
overcome operational difficulties. In general, no labor was added to
operate a SCR system on retrofit applications, and new systems do not
plan additional personnel for the N0X system. Generally, no maintenance
was reported other than cleaning the air preheater during annual shut-
downs. The control systems are usually fairly simple and employ a feed-
forward control system based on inlet N0X concentration with fine tuning
supplied by feedback of the outlet N0X concentration. Most gas- and
oil-fired applications also utilized an outlet NH3 emissions monitor;
however, an NH3 emissions monitor has not been perfected for coal-fired
applications. NH3 emissions were reported to be very low (0-5 ppm) in
most cases. NH3 emission limitations are not prescribed by governmental
agencies, but low NH3 emissions are deemed essential to minimizing
problems with downstream equipment. No problems were noted with NH3
fuming or emissions of cyanide, nitrates, nitrosoamines, or other
harmful species.
The N0X emission rates were very low when SCR units were employed.
As shown in Table I, gas-fired units were controlled to about 10 ppm of
N0X and oil-fired units to 15-35 ppm. Further, coal-fired units are
being constructed which will demonstrate control to 40-80 ppm of N0X.
It is important to note that the Japanese seem to prefer 80% N0X removal
as the optimum control level since it minimizes capital and operating
costs as well as energy and environmental Impacts while maximizing
operabillty, reliability, and system life.
9
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The coal-fired applications of SCR technology in Japan are of
particular interest to U.S. personnel since coal-fired sources represent
a major N0X control problem in the U.S. Four SCR systems for coal-fired
boilers were under construction in Japan and are shown in Table I.
Further, construction of additional coal-fired boilers are being planned
and SCR units are expected to be installed on most of these units.
Therefore, the Japanese experience should provide valuable information
for many years for U.S. personnel interested in N0X control.
The SCR units were installed to meet local governmental N0X
emission limitations and are not necessary to comply with the Japanese
national standard. Compliance with local and national environmental
agreements is achieved through a sincere cooperative spirit that exists
between industry and government to solve the country's pollution
problems. Local governments maintain a very comprehensive and extensive
instrumentation system to monitor ambient pollutant concentrations and
emission rates from major emitters* Although the local governments have
no enforcement authority, violations are rarely, if ever, detected since
the companies do not want to jeopardize the "good will" that exists
between the industrial, governmental, and public sectors.
In summary, it should be emphasized that SCR technology is being
successfully operated in Japan on large scale gas- and oil-fired sources
and that large scale applications to coal-fired sources are under con-
struction with equal success anticipated.
DRY SIMULTANEOUS NOx/SOx PROCESSES
The Shell Flue Gas Treating process is a unique variation of SCR
technology that can simultaneously remove both N0X and S0X from combustion
10
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flue gas. The process uses copper oxide (CuO) supported on stabilized
alumina placed in two or more parallel-passage reactors. The reactions,
which characterize process operation, can be expressed as:
Acceptance
CuO + 1/2 O2 + S02 —
¦> CUSO4
(3)
4N0 + 4NH3 + 02
CuSO&
•> 4N2 + 6H20
(4)
Regenerat ion
CuSO^, + 2H2
¦> Cu + S02 + 2H20 (5)
Cu + 1/2 02
> CuO
(6)
Flue gas is introduced at 385*C (725°F) into one of the reactors
where the S02 reacts with CuO to form copper sulfate (CUSO4). The
CuSO^ and, to a lesser extent, the CuO act'as catalysts in the reduction
of N0X with NH3. When the reactor is saturated with CuSO^, flue gas is
switched to a fresh reactor for acceptance of the flue gas, and the
spent reactor is regenerated. In the regeneration cycle, hydrogen
(H2) is used to reduce the CuSO^ to copper (Cu), yielding a S02 stream
of sufficient concentration for conversion to sulfur or sulfuric acid.
The Cu in the reactor is oxidized, preparing the reactor for acceptance
of the flue gas again. Between acceptance and regeneration, steam is
injected into the reactor to purge the remaining flue gas or H2 to
eliminate any possibility of combustion. The process can also be
operated in the NOx-only mode by eliminating the regeneration cycle, or
in the SOx-only mode by eliminating the NH3 injection.
11
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The process has been Installed In Japan on a heavy-oil-fired boiler
treating 120,000 Nm^/hr of flue gas. The unit has demonstrated 90%
SO2 removal and 70% N0X removal. UOP Process Division is the licensor
of the process in the United States.
WET N0X AND N0x/S0x PROCESSES
The wet N0X and simultaneous N0x/S0x processes developed to date
cannot compete economically with dry processes for removal of N0X from
combustion flue gas. This is primarily due to the complexity, limited
applicability, and water pollution problems associated with the wet
processes.
12
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ASSESSMENT OF TECHNOLOGY FOR APPLICATION IN THE U.S.
Since NOx SCR systems have been successfully installed and operated
in Japan on gas- and oil-fired sources, it is expected that equal success
could be obtained in the U.S. However, coal-fired boilers in the U.S.
are the primary concern for control of N0X from stationary combustion
sources. Therefore, EPA has focused on technology assessment studies to
determine cost estimates, energy requirements, and environmental impacts
of applying the technology on coal-fired boilers in the U.S. In parallel
with the technology assessment studies, small scale experimental projects
have been undertaken to demonstrate the performance of the technology.
COST ESTIMATES
Preliminary cost estimates for application of SCR processes to a coal-
fired utility boiler were made by the Tennessee Valley Authority through an
interagency agreement with EPA. (This study was cosponsored by the Electric
Power Research Institute.) The basis for this estimate was a new, 500 MW
boiler firing Eastern bituminous coal with a heating value of 24.4 MJ/kg
(10,500 Btu/lb), a sulfur content of 3.5%, and an ash content of 16%. The
study assumed operation of the boiler for 7000 hr/yr and the SCR process
for 90% reduction of NOx. The estimates were based on a capital investment
in m.ld-1979 and an annual revenue requirement in mid-1980. Results of that
study, summarized in Table II, indicate that the capital costs of SCR
processes will be about $42/kW or $9.8/acfm and that annual revenue require-
ments will be about 2.7 mills/kWh. (Since the volume of gas treated is the
dominating parameter in determining the cost of installing an SCR system,
the $/acfm factor may be the most meaningful in determining representative
costs of firing various coals in various sized plants.) The study also
indicated that the dry simultaneous N0x/S0x process would be competitive
with these costs if the cost of a FGD process for S0£ control were added to
the cost of the N0X SCR process, but that the cost of wet simultaneous
N0x/S0x processes would be significantly higher.
13
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The cost of applying N0X SCR technology to industrial boilers was
estimated in a study for EPA by Radian Corporation (5). It was found
effects on the system cost. The results of this study are summarized in
Table III.
ENERGY AND ENVIRONMENTAL IMPACTS
The SCR processes are projected to require about 0.2% of the boiler
capacity. This assumes that flue gas reheat will not be required and
does not include an energy requirement represented by raw materials (4).
The major concerns from an environmental impact viewpoint appear to
be emissions and discharge of NH3 and NH3 compounds and disposal of
spent catalysts. Operational techniques to limit NH3 emissions and
methods for regenerating or reclaiming the catalysts are under develop-
ment to minimize problems in this regard (5).
EXPERIMENTAL PROJECTS
To determine the actual performance and cost of applying SCR
processes in the U.S., several demonstration projects have been planned
as summarized in Table IV. Relative to the EPA pilot plant projects,
the basic objective is to demonstrate the feasibility of the processes
for 90% control of N0X or N0x/S0x emissions from a coal-fired source.
The projects were divided into four phases:
that the fuel fired, boiler size, and design N0X removal had significant
I
Design
Procurement and erection
Startup, debugging, and optimization
Long term operation and assessment.
II
III
IV
14
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Phase IV began in June 1980 for both projects. Therefore, it is
not possible to provide results of the projects in this paper. However,
it should be noted that numerous problems have been encountered in
operating the pilot plants. One major problem area has been sampling
and analytical techniques for NO, NO2, N0X, SO2, SO3, and NH3.
Successes and failures of the pilot plants will be reported in full in
the final project reports. Since papers on each project or process
listed in Table IV will be presented at this Symposium, further details
will not be presented in this paper.
If the coal-fired pilot plants and oil-fired demonstration scale
plants are successful, then a coal-fired prototype or demonstration
scale plant (10-100 MW) will be desirable. It is conceivable that such
a plant could be built in conjunction with a new or expanding facility
in an area with nonattainment, prevention of significant deterioration,
visibility, or other environmental constraints. In this manner, the
environmental impact of the facility could be minimized, and SCR
technology for N0X control could be commercially demonstrated.
15
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CONCLUSIONS
The following conclusions can be drawn from this assessment of
flue gas treatment technology.
1. N0X flue gas treatment processes, based on selective catalytic
reduction (SCR) of N0X with NH3( have been successfully
demonstrated on commercial-scale gas- and oil-fired sources in
Japan for >80% N0X removal.
2. SCR systems are being installed on commercial-scale coal-fired
sources in Japan which will demonstrate the viability of the
technology for coal-fired sources.
3. SCR systems are being evaluated on pilot-scale coal-fired
sources and on a demonstration-scale oil-fired source in the
U.S. for 90% N0X control. One of the pilot plants is
evaluating dry simultaneous N0x/S0x control. If these applica-
tions are successful, evaluation on a prototype-scale coal-
fired facility will be desirable.
4. Although significant progress has been made in developing and
applying the technology, several problem areas remain to be
resolved (i.e., impact on downstream equipment, long term
performance, and reliability).
5. Experimental projects, in conjunction with technology
asssessment studies, will enable a determination of the
feasibility of applying NOx SCR processes in the U.S.
16
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REFERENCES
1. Blanks,„J.P., E.P. Hamilton, III, B.R. Eppright, and N.A. Nielsen.
Investigation of N09/N0V Ratios' in Point Source Plumes* Radian
Corporation, EPA-600/7-80-036 (NTIS PB 80-169550), February 1980,
U.S. Environmental Protection Agency, Research Triangle Park, NC.
2. Ando, Jumpei, SO? Abatement for Stationary Sources in Japan* EPA-
600/7-78-210 (NTIS PB 290198), November 1978, ' U.S. Environmental
Protection Agency, Research Triangle Park, NC.
3. Ando, Jumpei, NOY Abafcepqnt for Stationary Sources in Japan. EPA-
600/7-79-205 (NTIS PB 80-113673), August 1979, U.S. Environmental
Protection Agency, Research Triangle Park, NC.
4. Maxwell, J.D., T.A. Burnett, and H.L. Faucett. Preliminary Economic
Analyst of N0V Flue Gas Treatment Processes. Tennessee Valley
Authority* EEA-600/7-80-021 (NTIS PB 80-176456), February i,9<80,
U.S. Environmental Protect$*ft , ^Re search Triangle. Park, NC.
5. JonesrG.D.randK. Johnson. JEechnology Assessment Report for
Industrial Boiler Applicatafctma^Hfly 3Flug Gag Treatment* Radian
Corporation, EPA-600/7-79-178g (NTIS PB 80-173636), December 1979,
U.S. Environmental Protection Agency, Research Triangle Park, NC.
17
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Coal
H Air H»
Air
Ammonia
Storag* Tank
Rail
or
Truck
Hook-up
NH,
Vaporizer
Flu* go*
dMul-
lurization
unit
Figure 1. Typical flowsheet for NOx selective catalytic reduction processes (4).
Metal Honeycomb
1
Tubular
ooo
12 mm
-I I-
t)OOC
Parallel Plate
10 mm
30
7 mm
_1
10 mm 10mm
1 "I F-Ht-
C#ramic HomyoMib
10
-i »—)t-n r
JUUUUU I I I I I I
CCCCCC > 1111 i
300000 mini
Figure 2. Types of parallel flow catalyst shapes for NOx selective catalytic reduction
processes (3).
18
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>
Tubular configuration Metallic honeycomb configuration
Figure 3. Unit cells of parallel flow catalysts for NO* selective catalytic
reduction processes (3).
Catalyst Layer
Figure 4. Parallel flow reactor for NOx selective catalytic reduction processes (3).
19
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TABLE I. SELECTED INSTALLATIONS WITH NOx SELECTIVE CATALYTIC REDUCTION SYSTEMS IN JAPAN3
Boiler NOv SCR System
Company
Station
No.
Fuel
Size
(MW)
Size
(MW)
N0V Removal
(%)
Outlet N0X
(ppm)
Vendor'5
Startup
Chubu Electric
Chita
5
Gas
700
700
80
8-10
B-H
Mar. 1978
6
Gas
700
700
80
8-10
B-H
Apr. 1978
4
Oil
700
700
80
20
MHI
Mar. 1980
Chugoku Electric
Kudamatsu
2
Oil
375
375
80
32
IHI
Apr. 1979
3
Oil
700
700
80
26
IHI
Sep. 1979
Fuji Oil
Sodegara
7
Oil
40
40
87
15
MHI
Jan. 1978
—
CO & Oil
10
10
92
15
JGC
Jul. 1976
Chugoku Electric
Shimonosekl
1
Coal
175
175
50
250
MHI
Apr. 1980
Hokkaido Electric
Tomakonai
1
Coal
350
90
>80
<40
B-H
Oct. 1980
Electric Power
Takehara
1
Coal
250
125
80
80
B-H
Jun. 1981
Development Co.
1
Coal
250
125
80
80
KHI
Jun. 1981
a) These Installations were visited by a team of EPA, TVA, and Radian personnel In March 1980.
b) B-H Babcock-Hitachi
MHI Mitsubishi Heavy Industries
IHI Ishlkawajima-Harina Heavy Industries
JGC JGC Corporation
KHI Kawasaki Heavy Industries
-------
TABLE II. ESTIMATED COSTS FOR EMISSION CONTROL SYSTEMS FOR UTILITY BOILERS
Process Types
SCR, FGD, ESP
Dry Simultaneous NOx/SOx
Wet Simultaneous NOx/SOx/PM
Capital Costs ($/kW)
N0X S02 PM Total
42
101
22
165
<—134
>
29
163
<
-200—
>
200
Annualized Costs (mills/kWh)
N0X S02 PM Total
2.7 4.2 0.7 7.6
< 6.4 > 0.9 7.3
< 11.3 > 11.3
Basis for the Estimate:
NOx Control System
SO2 Control System
Particulate Matter (PM) Control System
NOx Removal Efficiency
SO2 Removal Efficiency
PM Removal Efficiency
Boiler Size
Fuel
Heating value
Sulfur content
Ash content
Operation
Capital Investment
Annual Revenue Requirement
SCR Processes
Dry Simultaneous N0x/S0x
Wet Simultaneous N0x/S0x/PM
Source: Maxwell, Burnett, and Faucett (4).
Selective Catalytic Reduction (SCR) with NH3
Limestone Flue Gas Desulfurization (FGD)
Electrostatic Precipitator (ESP) for dry systems
wet scrubber for wet simultaneous systems
90%
90%
99.5%
500 MW, new
Coal
24.4 MJ/kg (10,500 Btu/lb)
3.5%
16%
7000 hr/yr
mid-1979
mid-1980
Average of UOP-Shell, Hitachi Zosen,
Kurabo process costs
UOP-Shell
Average of Moretana Calcium and
Asahi CIO2 process costs
-------
TABLE III. ESTIMATED COST OF NOx SELECTIVE CATALYTIC REDUCTION SYSTEMS FOR INDUSTRIAL BOILERS
Rating Capital Costs $ Annual Costs $
Fuel
(MJ/s)
(MBtu/hr)
70% Control
80% Control
90% Control
70% Control
80% Control
90% Control
Coal
8.8
30
181,900
213,100
249,600
104,200
117,500
133,900
(Parallel Flow)
22.0
75
298,900
349,500
413,300
157,600
170,700
196,500
44.0
150
451,500
534,600
633,000
216,600
251,600
292,300
58.6
200
531,900
632,600
752,400
254,200
298,800
351,300
Residual Oil
8.8
30
158,100
179,100
202,900
96,100
102,000
108,200
(Parallel Flow)
44.0
150
378,200
436,200
503,100
181,180
200,900
222,860
Residual Oil
8.8
30
144,600
154,700
166,700
120,400
125,100
129,900
(Moving Bed)
44.0
150
259,700
300,200
347,000
167,700
184,800
203,600
Distillate Oil
4.4
15
88,200
93,600
99,400
63,600
65,500
67,400
(Fixed Packed Bed)
44.0
150
223,800
261,500
305,600
137,200
155,300
175,900
Natural Gas
4.4
15
92,800
96,600
100,500
64,400
66,000
67,600
(Fixed Packed Bed)
44.0
150
223,700
262,000
306,800
129,400
150,400
174,700
Basis for Estimate:
Cost Basis Mid-1978
Load Factors
Coal 0.60
Residual Oil 0.55
Distillate Oil 0.45
Natural Gas 0.45
Coal Low Sulfur Western
Source: Jones and Johnson (5).
-------
TABLE IV. PLANNED DEMONSTRATION PROJECTS OF NOx SELECTIVE CATALYTIC
REDUCTION TECHNOLOGY IN THE U.S.
Sponsor
Contractor
Location
Size
(MWe)
Fuel
Planned
N0X
Reduction
Startup
Environmental Protection
Agency
Environmental Protection
Agency
Electric Power Research
Institute
Southern California
Edison^)
Hitachi Zosen
Georgia Power Company
0.5
Coal
90%
Fall 1979
UOP Process Division Tampa Electric Company
Kawasaki Heavy
Industries
Kawasaki Heavy
Industries
Public Service Company
of Colorado
Arapahoe Station
Southern California
Edison
Huntington Beach Station
a) 90% Reduction of SO2 also planned by the dry, simultaneous N0x/S0x process.
b) Required to meet regulations of the California Air Resources Board.
0.5 Coal
2.5
100
Coal
Oil
90%(a) Fall 1979
90%
90%
Winter 1980
Fall 1981
-------
STATUS OF SCR RETROFIT AT SOUTHERN CALIFORNIA EDISON
HUNTINGTON BEACH GENERATING STATION UNIT 2
By:
L. U. Johnson, C. L. W. Overduin, D. A. Fellows
Souther California Edison Company
P. 0. Box 800
2244 Walnut Grove Avenue
Rosemead, California 91770
24
-------
ABSTRACT
Utilities in the Southern California South Coast Air Basin are subject
to a regulation (Rule 1135.1) requiring 90 percent NOx reduction. Rule
1135.1 is comprised of four basic compliance options of which the first two
options require two stages with an intermediate milestone reduction and a
demonstration unit of a 90 percent NOx reduction system.
This.paper describes the Selective Catalytic Reduction (SCR) 107.5 MW
Demonstration Facility SCE plans to install on one-half of Southern California
Edison's Huntington Beach Unit 2, 215 MW boiler. The physical size, operation
and maintenance, and controls for achieving 90 percent NOx reduction through
normal load variations as well as the status of the project are discussed.
The system retrofit requirements are discussed with specific reference
to the differences between the demonstration unit and other larger units and
the site constraints for retrofit on the larger units. The operational and
maintenance requirements for a systemwide retrofit and potential problem areas
will also be reviewed.
The paper will present cost estimates for the Huntington Beach demons-
tration facility as well as SCE's projection of cost for adding SCR on the major-
ity of its oil-fired units in the South Coast Air Basin. These costs will
include capital as well as O&M. All costs will be presented in 1981 dollars.
25
-------
I. INTRODUCTION
Utilities in the Southern California South Coast Air Basin are subject to a
regulation (Rule 1135.1) requiring 90% NOx reduction. Over the past two
years, many workshops and hearings have been held regarding the requirements
of the rule. The latest version, adopted earlier this year, is comprised of
four basic compliance options of which the first two options require two
stages with an intermediate milestone reduction and a demonstration unit of a
90% NOx reduction system.
The demonstration unit requires the 90% NOx reduction on a unit of at least
100 megawatts in the Los Angeles basin by January 1, 1982. Depending on the
options selected, a 90% NOx reduction basin wide must be achieved by 1988 or
1990. Considerable work is underway by the Southern California Edison Company
to comply with the demonstration unit and muqh effort has gone into
determining the impact of complying with the balance of the rule. This report
describes the work performed to date.
26
-------
II. HUNTINGTON BEACH SCR DEMONSTRATION PROJECT
FACILITY DESCRIPTION
The Huntington Beach Demonstration Facility employs a Selective Catalytic
Reduction (SCR) process, in which nitrogen oxides in the boiler flue gas are
reduced, using ammonia as a reducing agent. This facility will be capable of
treating one half of the flue gas generated by Southern California Edison's
Huntington Beach Unit 2, which is rated at 215 MW.
The SCR NOx removal process is depicted in Figure 1, and consists of the
following five principle systems:
o A reactor system consisting of a reactor to contain and support the
catalyst modules, a ducting/damper system to divert flue gas through or
past the reactor, and a reactor booster fan with bypass duct to draw
the flue gas through the reactor.
o An ammonia supply system consisting of a liquid ammonia storage tank,
ammonia vaporizer and associated piping and controls to forward the
ammonia vapor to the ammonia dilution skid.
o An ammonia dilution and injection system consisting of a blower for
diluting the ammonia with combustion air from the air preheater, and an
ammonia flue gas mixer to inject the diluted ammonia vapor uniformly
into the flue gas stream.
27
-------
o A control system consisting of ammonia injection controls, reactor
booster fan control systems, a system to protect the boiler against
negative pressure excursions and an emission monitoring systera.
o An electrical system utilizing the existing Unit 5 gas turbine
auxiliary transformer which includes a 4160 V switchgear, 480 V
switchgear, lighting facilities, communication system, grounding
systera, DC power system and all associated raceways and cable.
EQUIPMENT
Reactor
The reactor is designed for vertical flue gas flow and has a fixed
catalyst bed. The catalyst bed is built from individual catalyst
modules which can easily be removed from the reactor through a large
access door utilizing a permanently installed hoist system.
Reactor Booster Fan
The reactor booster fan is a centrifugal fan with air foil blading and
is located downstream of the air preheater. The fan is directly
coupled to a one speed electric motor and equipped with inlet vanes for
flow control. A fan bypass duct and damper are provided to allow
isolation of the fan from the existing boiler draft system.
Ammonia Tank.
The ammonia tank is a horizontal vessel designed for storage of liquid
anhydrous ammonia. The tank is sized to satisfy maximum ammonia demand
for approximately 14 days of continuous operation. The tank is
equipped with an external electric vaporizer to insure adequate ammonia
vaporization at high demand/low ambient temperature conditions.
28
-------
Equipment Data
Pertinent data for the above Apparatus as well as Huntington Beach
Unit 2 are presented in Tables I and II.
ARRANGEMENT
Refer to Figures 2 and 3 for plan and elevation views of the NOx removal
system. The arrangement takes advantage of an existing duct elbow between the
economizer outlet and inlet to the hot side of the vertical shaft air
preheater. This duct will be replaced with new ducting including branches for
reactor inlet and outlet, and a reactor bypass. The bypass will allow boiler
operation during reactor inspection and service.
A portion of the stack breaching will be removed to accommodate the reactor
booster fan and fan bypass duct. The fan can discharge either to the existing
stack or, through damper manipulation, to its own new stub stack.
The latter discharge mode will allow visual monitoring of the treated flue gas
opacity.
The reactor is located in a vertical position directly south of the unit and
does allow for system expansion to treat all flue gas flow from Unit 2.
CONTROLS AND INSTRUMENTATION
Ammonia Injection
A control system will be installed at Huntington Beach to inject
ammonia according to unit load and flue gas NOx content at a rate to
maintain a preset 90% removal ratio and a NH^ slip within 0 to
10 ppm. To set the NOx removal at 902, NOx will be monitored before
and after the reactor for calculation of the removal ratio. The
differential signal between the calculated ratio and the setpoint will
be fed back to the NH^ injection controls for correction of the
injection rate.
29
-------
Reactor Flue Gas Flow
A reactor booster fan is used to control the flue gas flow through the
reactor and balance the flow between the east and west air
preheaters. Air flow is controlled by inlet vanes which respond to
boiler load and reactor differential pressure. The latter signal
represents the actual flow through the reactor.
Boiler Protection
The addition of the reactor booster fan has increased the occurrence of
boiler negative pressure excursions with an associated increased risk
of boiler implosion. Hence, a protective control system will be added
to mitigate this increased risk. This control system will take the
reactor booster fan out of the flue gas loop in response to boiler
trips, low furnace pressure, FD fan trips and low reactor outlet
pressure. The booster fan draft is eliminated by the opening of fast
acting dampers in the booster fan by-pass duct and the fast closing of
the fan isolation damper.
Emission Instrumentation
Emission of NOx, NH^, SO2 as well as 0£ levels will be monitored
downstream of the air preheater. In addition, opacity of the flue gas
subjected to the SCR process will be visually monitored at the new stub
stack.
TEST PROGRAM
The test program to be conducted at the Huntington Beach NOx removal facility
will be designed primarily to determine the following process and operating
parameters:
o NOx removal efficiency as a function of operating hours, ammonia
injection rate, and NH3 slip. A removal rate of 90% for 7,000 hours
with an NH3 slip of less than 10 ppm will be attempted.
30
-------
o Assessment of catalyst operating life. This is a most important
parameter with a dominating impact on system operating cost.
o Reactor and air preheater plugging as a result of deposits such as
ammonia bisulfate.
o Operating factors such as reactor draft loss and ammonia consumption.
o Evaluation of ammonia injection controls, draft system controls, boiler
protection controls and emission monitors and analyzers.
PROJECT STATUS
As indicated by the basic project schedule shown in Figure 4, all engineering
has been completed and the construction contract awarded. All major equipment
has been procured and will be delivered to the site during the last quarter of
1980. One exception is the reactor itself, which is being fabricated in Japan
at this time, and is scheduled for delivery in April, 1981. The system will
be ready for testing on October 1, 1981. Testing for performance and
compliance with the ARB Rule 1135.1 will be complete in January, 1982.
Further testing will continue thereafter, to evaluate catalyst life and long-
term operating effects.
31
-------
III. SYSTEM RETROFIT
RETROFIT REQUIREMENTS
The retrofit requirements as previously illustrated in Figures 2 and 3 for the
Huntington Beach Generating Station are not at all typical for SCE generating
facilities in the Los Angeles basin. Most of the larger units have horizontal
shaft air preheaters which are located closely behind the boiler economizer
outlet. As Illustrated in Figure 5, this means that for most units all
equipment and ducting downstream of the economizer outlet, including the
stack, will nave to be relocated to make room for the reactor and the ammonia
flue gas mixer. In many cases existing structures, equipment and other site
restraints interfere with the required expansion of the backend of the boiler,
and consequently dictate major site rearrangements.
OPERATING AND MAINTENANCE REQUIREMENTS
Table III tabulates the O&M requirements for all Los Angeles basin units
involved, including major items such as electrical power consumption, system
NH3 consumption and the yearly new catalyst and used catalyst disposal
requirements. Maintenance items such as the washing and cleaning of reactor,
air preheater and reactor booster fan is not known and not included at this
time.
32
-------
PROBLEM AREAS
Since most Steam Generators require a major modification to the back-end of
the unit in order to provide room for the installation of the reactor,
retrofitting these units will require a long construction period and extended
unit outages. In addition, the existing plants are already congested, which
will add to this problem and create many construction restraints. Because of
these problem areas and the existing unit overhaul schedule to work with,
considerable risks will be encountered in meeting these schedules and
supplying power to the consumers.
Some unknowns which may create further problems are catalyst availability and
catalyst disposal after use. At present there are insufficient manufacturing
facilities available for the new honeycomb DeNQx catalyst. The type of
disposal required is not yet known nor the potential for reconditioning and
reuse.
Perhaps the greatest risk to the system reliability waits at the completion of
construction when startup and operation begin. Because of the booster fan
required to overcome the pressure drop in the system, the larger units will be
converted from forced draft units to a balanced draft operation. Controls to
operate in this mode will be included and complete boiler implosion studies
will be made to assess the need for boiler reinforcement* Mitigation of this
risk is possible, elimination is not.
33
-------
IV. COST
HUNTINGTON BEACH DEMONSTRATION UNIT
Capital Cost
Capital cost estimates have been prepared for the 107.5 MW Demonstra-
tion Project at Edison's Huntington Beach Generating Station. This
estimate is provided for information, and caution should be exercised
in using the figures for other applications. Since this Is a
demonstration project, some shortcuts have been assumed which would not
be used in a commercial installation. In addition, due to the small
scale of the demonstration, many of the modifications required to
backfit an entire unit were not required.
The cost for this facility is estimated to be $13,500,000 including all
corporate overheads and AFUDC, but excluding testing cost. This is
based on a late 1981 operating date and the costs are consistent with
1981 dollars.
O&M Cost
Estimates for operating labor and material for this project were
obtained from Edison's Power Supply Department. The Engineering
Department provided data for ammonia, energy and catalyst consumption
which became the remaining components of O&M. Catalyst replacement was
calculated based on the bids received for the project. These costs are
shown In Table IV.
34
-------
SYSTEM RETROFIT COST
Capital
Capital cost estimates for Catalytic DeNOx were prepared in May,
1978. The basis for these estimates follows:
Conceptual engineering was performed for providing catalytic DeNOx
equipment at the following units:
Units Unit Size (Each)
Alamitos 1 & 2 175 MW
Alamitos 3 & 4 320 MW
Alamitos 5 & 6 480 MW
The engineering consisted of the development of plot plans, flow
diagrams, one-line diagrams and arrangement sketches. At the
completion of this effort, a list of major equipment was prepared,
along with engineering take-offs of bulk material quantities such as
piping, cable, structural steel, and the equipment relocations and site
modifications required. Using this information, cost estimates were
prepared for the above units. This information was then used to
estimate the cost for all other stations using $/kW figures from the
base estimates multiplied by a site factor to account for specific
conditions at each station.
Consideration was given to the following criteria in arriving at the
site factor for the units listed in Table II.
Space Availability
Unit Configuration
Size of Unit
35
-------
The estimates were reviewed in December, 1979, to determine if there
were any inconsistencies with information collected on the catalyst and
the balance of plant for the Catalytic DeNQx Demonstrations Project-
It was determined that no modifications to the total costs were
required. The estimates wei'e then escalated from 1978 to 1981. These
capital costs are shown in Table V-
O&M Cost
The system O&M cost was based on $/MW/year from the Catalytic DeNOx
Demonstration Project modified for the unit capacity factor.
For catalyst replacement, the cost per cubic foot of catalyst of the
demonstration unit was used with the assumption that the catalytic
reactor volume would be proportional to the flue gas flow to be
treated.
The O&M as well as catalyst replacement costs are shown in Table V.
CO:df
36
-------
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-------
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-------
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UNIT NO
0 AT C
Huntington Beach
2
7-29^80
MAJOR ACTIVITIES FOR CATALYTIC DeNOx PROJECT
Activities
MONTHS.
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-------
Stack
(exist-
ing)
Stack
(New)
ftp
Air Preheater
(Relocated)
/ /i>i
( Preheate
I I (existing) ' I
/
- m-c.
I.D. Fan
F.D. Fan
(relocated)
an
(existing)
SOUTHERN CALIFORNIA EDISON COHPANY
AUMITOS STEAM STATION - UNITS NO. 5 i 6
LOS ALAHITOS, CALIFORNIA
SHOWN RETROFITTED WITH SCR NO* REMOVAL REACTOR
FIGURE 5
-------
TABLE I
HUNTINGTON BEACH UNIT 2 DATA
Electrical Output:
Flue Gas Flow Rate:
Flue Gas Temperature:
NOx Concentration:
SC>2 Concentration:
Particulate Concentration:
SOg Concentration:
215 MW (107.5 MW for West
half of unit)
100,000 to 500,000 ACFM
at 750°F (half of total
unit flow)
550° to 800°F
(economizer outlet)
180-280 vpptn at 3% O2 dry
70-140 vppm at 11% and 4% 02
.005 - .02 gr/SCF
1-5 vppm
42
-------
TABLE II
MAJOR EQUIPMENT DATA
Catalytic Reactor:
- Size 16' (W) x 18' (L) x 23' (H)
- Space Velocity: 6655 hr~*
- Design Pressure: -17 to +15" WG
- Assembled Weight: 184,300 lbs
- Catalyst Shape: Square Honeycomb
Booster Fan:
- Type: centrifugal, air foil blading
- Operating characteristics: 371,800 CFM @ 17" WG SP.
- Flow control: inlet vanes
- Drive: 2000 HP Electric Motor
Ammonia Tank:
- Nominal Capacity: 12,000 gallon
Electrical Equipment:
- 4160 V Switchgear
- 480 V Circuit Breaker
- 480 V Motor Control Center
CO:df
43
-------
TABLE III
OPERATING AND MAINTENANCE DATA
Huntington Beach SCR Demonstration Unit (107.5 MW)
o
o
o
o
Power Requirement
Power Consumption
NH3 Consumption
Catalyst Consumption*
and Disposal
1500 kW
7.5 x 10^ kWhr/yr
320 tons/yr
20 tons/yr
SCR NOx Removal Systems on all 175 MW and larger L.A. Basin Units (7720 MW)
o
o
Power Requirements
Power Consumption
NH3 Consumption
Catalyst Consumption*
and Disposal
83 MW
386 x 10^ kWhr/yr
21,500 tons/yr
1,860 tons/yr
*Based on two-year catalyst operating life
CO:df
44
-------
TABLE IV
107.5 MW
CATALYTIC DeNOx - DEMONSTRATION UNIT
O&M COST (1981 $)
Derate $ 59,880
Energy 207,600
Chemicals 62,570
Labor and Supplies 134,250
Catalyst Replacement 986.740
Total O&M $1,362,860
SAY $1,363,000
45
-------
TABLE V
COST SUMMARY FOR CATALYTIC DeNOx REDUCTION TECHNIQUES
($ X 106 all in 1981)
Total
Capacity
Average
Capacity
Factor
(1)
Catalytic DeNOx^
(3)
Capital
0 & M Catalyst Replacement
(1-Year) (1-Year Life) (2-Year Life)
(MW)
<%)
($)
($)
($)
($)
Oraond 1 & 2
1500
55
220.0
7.2
10.1
5.1
Redondo 7 & 8
960
59
190.0
4.9
6.4
3.3
Alamitos 5 & 6
960
59
130.0
4.9
6.4
3.3
Alamitos 3 & 4
640
53
80.0
3.0
4.1
2.1
El Segundo 3 & 4
670
53
120.0
3.2
4.5
2.3
Etiwanda 3 & 4
640
53
100.0
3.0
4.1
2.1
Huntington 3 & 4
440
47
60.0
2.0
2.8
1.4
Huntington 1 & 2
430
47
60.0
1.8
2.7
1.4
Mandalay 1 & 2
430
47
60.0
1.8
2.7
1.4
Alamitos 1 & 2
350
40
50.0
1.4
2.4
1.2
El Segundo 1 & 2
350
40
50.0
1.4
2.4
1.2
Redondo 5 & 6
350
40
60.0
1.4
2.4
1.2
Total
7720
1180.0
36.0
51.0
26.0
NOTE: (1) Average capacity factor - Based on the latest information from System Planning - November 1979. These
factors were used in the calculation of O&M.
(2) Catalytic DeNOx - Hie capital cost was based on the original estimate of May 1978. The O&M cost was
based on the latest information available from the demonstration unit in Huntington Beach Station and
also using the latest capacity factors available.
(3) Catalyst Replacement - Cost shown is an average cost for a 2-year life catalyst.
CO; df
-------
COUNTEBMEASURES FOR PROBLEMS IN NOx REMOVAL PROCESS
FOR COAL-FIRED BOILERS
By:
H. Itoh and Y. Kajibata
Kawasaki Heavy Industries, Ltd.
Japan
47
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ABSTRACT
The construction of many coal-fired power plants is being planned as a
result of the recent petroleum shortage , and so the need for -the De—NOx
process for coal-fired boilers is increasing. However, there are many problems
to be solved in the practical application of the De-NOx process for coal-fired
boilers, because high concentrations of dust particles and SOx are contained
in the flue gas. The major problems are t (1) catalyst bed pluggage and
catalyst erosion by dust particles (2) the influence of unreacted NR3 and SO3
from the De-NOx reactor to the downstream equipment (3) deactivation of the
catalyst by dust particles and SOx.
KHI has been working to solve these problems and to put the De-NOx
process into practical use for coal-fired boilers with the co-operation of
EPDC for many years. We have developed superior catalysts having several
characteristics, which include long life, SOx resisting properties, dust
resisting properties and low conversion of SO2 to SO3. Further, we have solved
the above problems and have developed the most economical and stable De-NOx
process.
This paper describes the problems involved in the practical application
of the De-NOx process for coal-fired boilers and the countermeasures under-
taken in KHI's De-NOx process.
48
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INTRODUCTION
It was since 1973 that the regulation on NOx emission from fixed source
was enforced in Japan. Many enterprises have been involeved in research and
development of NOx removal technology. Kawasaki Heavy Industries Co., Ltd.
( hereinafter referred to as " KHI " ) has been endeavoring to the NOx removal
technology for many years, and has in particular engaged in the research and
development with respect to the Selective Catalytic Reduction of NOx with NH3
since 1970. Finally, we have succeeded in the practical application of the
DeNOx process for LNG-fired and heavy oil-fired boilers.
On the other hand, the practical application of the DeNOx process for
coal-fired boilers is more difficult than for oil-fired boilers, because the
flue gas of coal-fired boilers contains more dust particles and SOx as
compared to that of oil-fired boilers. Since 1975, KHI has been cooperating
with Electric Power Development Co., Ltd. ( hereinafter referred to as EPDC )
in the research of DeNOx process for coal-fired boilers. We have developed
superior catalysts having several characteristics, which feature long life,
SOx resisting properties, dust resisting properties and low conversion of SO2
to SO3. Furthermore, we have obtained the economical and stable DeNOx process.
Consequently,KHI received an order for demonstration DeNOx plant for Takehara
No.l boiler of EPDC and are now doing our best to manufacture it. Furthermore,
KHI received an order for the DeNOx pilot plant from Electric Power Research
Institute in the U.S.A. and are now engaged in its operation.
In this paper , we describe the various problems involved in practical
application of the DeNOx process for coal-fired boilers and countermeasures
undertaken in KHl's DeNOx process.
VARIOUS PROBLEMS IN DeNOx PROCESS FOR COAL-FIRED BOILERS
Because of high concentration of dust, SOx and NOx in the flue gas out of
the coal-fired boiler, the total system is required for flue gas treatment in
order to resolve th$ environmental problems. The total flue gas treatment
system is composed of dust collection, DeNOx and DeSOx. In order to improve
the performance, reliability and economics of the total system, we must
consider not only the performance and reliability of each component technic
but also the most suitable combination of these components. Accordingly, the
49
-------
performance and reliability of the DeNOx process have to be pursued
considering its influence on the other process.
There are two kinds of DeNOx processes for coal-fired boilers, viz. low
dust DeNOx process and high dust DeNOx process ( cf. Figure 1 ). We have
solved two problems in developing these DeNOx processes. The first problem
is the influence of the unreacted NH3 and the generated SO3 from the DeNOx
reactor on the downstream equipment, and the second one is the influence of
the high concentration of dust and SOx in the flue gas on the performance and
stability of the DeNOx plant.
Influence of the unreacted NH3 and the generated SO3 from the DeNOx reactor
on downstream equipment
Influence of the unreacted NHi. In the low dust DeNOx process, the unreacted
NH3 reacts with SO3 and forms ammonium bisulfate with the fall of the flue gas
temperature at the air preheater. As the ammonium bisulfate is strongly
corrosive and adhesive , it causes the corrosion or plugging of the air
preheater. And as the unreacted NH3 is collected in the wet DeSOx process and
accumulated in the absorbing liquid, there arises a need for removing NH3 in
the waste water of the wet DeSOx process.
In the high dust DeSOx process, the unreacted NH3 is fixed to the fly ash
which is collected by the electrostatic precipitator. Figure 2 shows the
relationship between the concentration of the unreacted NH3 and the adsorbed
ammonia on fly ash. The dotted line in the figure shows the calculated value
assuming that all the unreacted NH3 is adsorbed on the fly ash. According to
the test results, most of the unreacted NH3 less than 20ppm is proved to be
adsorbed on the fly ash. Accordingly, the influence of the unreacted NH3 on
the air preheater and the wet DeSOx process in the high dust DeNOx process is
less than in the low dust DeNOx process. But there are several problems such
as leaching of NH3 and offensive odor in utilizing the fly ash for cement
admixing material or using it for reclamation.
As the unreacted NH3 will cause various sorts of troubles.it is necessary
to decrease to the unreacted NH3 at least as low as lOppm and preferrably
below 5ppm (1).
Influence of SO3. The DeNOx catalyst generally works as shown in the formulas
50
-------
(1) and (2). In addition to these NOx removal reactions, it works as SO2
oxidation catalyst as in the formula (3).
(1)
(2)
(3)
In the low dust DeNOx process, SO3 forms ammonium bisulfate through the
reaction with the unreacted NH3 and forms the sulfulic acid at low
temperatures.
In the high dust DeNOx process, there is no influence of SO3 to the air
preheater, because most of SO3 is adsorbed on the fly ash. But SO3 adsorbed on
the fly ash accelerates the adsorption of NH^.
As SO3 from the DeNOx reactor will cause the above mentioned troubles, it
is desirable to keep the oxidation of S02 as low as possible. It is necessary
to decrease SO3 below lOppm in order to control influence of SO3 to the
minimum.
Influences on the performance and stability of DeNOx process
Influence of dust. Problems of the plugging of the catalyst bed and the
erosion of the catalyst are perceived as the influence of the dust. The
plugging of the catalyst bed will cause the increase of the pressure drop of
the catalyst bed and the decrease of the NOx removal efficiency, whereas the
erosion of the catalyst will cause the decrease of the NOx removal efficiency
and the secondary environmental pollution by scattering the catalyst
components. Accordingly, sufficient countermeasures are required against the
plugging and the erosion caused by dust, especially in the high dust DeNOx
process.
Influence caused by the particular properties of coal-fired flue gas.
Influences of SOx, halogen (HC1,HF), and alkali metals in dust, especially
pottassium, on the catalytic performances may be anticipated. The decrease of
the catalytic performance must be especially avoid, because it causes not only
the lack of stability of the system but also the increase of running cost.
Accordingly, it is necessary to develop catalysts which can resist against the
particular properties of coal-fired flue gas.
NO + NH3 + 1/4 02 N2 + 3/2 H2O
N02 + 4/3 NH3 7/6 N2 + 2 H20
S02 + 1/2 02 ^ S03
51
-------
Influence of the long-term low load operation and the repeat of star-up/shut-
down . The long-term low load operation of boilers may result in the
deactivation of the catalyst and the plugging of the catalyst bed due to the
deposit of NH3 , SOx and dust in accordance with the decrease of the gas
temperature and the gas flow rate.
Repeat of start-up/shut-down of boilers may result in the catalytic
deactivation due to the condensation of SOx and H2O on the catalyst surface
and due to masking of the catalyst surface with dust.
It is necessary to perform the simulation tests of the long-term low load
operation and the repeat of start-up/shut-down.
COUNTERMEASURES ADOPTED IN KHI's DeNOx PROCESS
Control of the unreacted NH-^ and the oxidation of S02
Control of the unreacted NH3. The NH3/NOX mole ratio should be controlled
less than 1 in order to control the unreacted NH^ emission. For example, it is
necessary to control the NH3 injection whithin the region of NH3/NOX mole
ratio between 0.83 and 0.93 in order to obtain the NOx removal efficiency more
than 80% and to decrease unreacted NH3 less than 5ppm ( cf. Figure 3. ).
For this purpose, it is required to control the NH3 injection in
accordance with the change of the volume of the treatment gas and that of the
inlet NOx concentration. KHI developed an unique control system by combining
the following two methods. One is a feed-forward control of the NH3 injection,
of which the amount is calculated by the boiler load and the inlet NOx
concentration. The other is a feed-back control, in which the amount of NH3
injection is corrected by the outlet NOx concentration or the NOx removal
efficiency. The follow-up test results of our control system for boiler load
variation was satisfactory. As shown in Figure U, the unreacted NH3 is
controlled within 5ppm in spite of the change of the gas volume, the gas
temperature as well as the inlet NOx concentration.
In large DeNOx plants, the mixing and dispersing of injected NH3 are
very important in order to decrease the unreacted NH3. We carried out cold-
model tests as to the mixing and dispersing, and have found the most efficient
52
-------
configulation . The length of the duct from the nozzle to the reactor is short
and the pressure drop of the duct is quite small in this configulation.
Control of SO2 oxidation. Characteristic of a conventional catalyst are shown
in Figure 5. The Oxidation rate of SO2 will increase as the NH3/NOX mole
ratio and the space velocity decrease. Therefore, the development of catalysts
with low oxidation rate of SO2 is indispensable for the simultaneous control
of the unreacted NH3 and the generated SO3 emission. KHI has endeavored to
improve the catalysts in cooperation with the catalyst manufacturer.
We started with the V205-TiC>2 basis catalyst, which has various
features such as high NOx reduction activity and long life, etc..
Our points of the improvement are as follows :
1. Decrease of the amount of the active element ( V2O5 )
2. Addition of an active element as promoter
3. Improvement of the dispersion of the active elements
We succeeded in developing the catalysts with low oxidation rate of SO2 and
high NOx reduction activity. Figure 6 shows the performance of the two
improved catalysts. KHI has several catalyst with low oxidation rate of SO2
avilable , and select the most suitable catalyst for practical use in
accordance with gas temperature and SOx concentration. Figure 7 shows the
performance of the improved catalyst ( K-110 ) for coal-fired boiler load
conditions. Thus it is possible to control SO3 emission from the DeNOx
reactor below lOppm by employing the improved catalysts with low oxidation
rate of SO2.
Treatment of the ash containing NH3. As already mentioned, NH3 is contained
in the fly ash collected by the electrostatic precipitator in the high dust
DeNOx process. The ash containing NH3 being dumped for reclamation,there might
arise problems of NH3 odor and leaching of NH3. We carried out odor tests and
leaching tests, and confirmed that it is necessary to make the amount of NH3
on the fly ash below 20ppm ( mg/kg ) for reclamation. We have been developing
the NH3 removal technology out of the fly ash in cooperation with EPDC. Our
NH3 removal process is a pyrolysis process by utilizing a part of flue gas of
the boiler. We have carried out the bench scale tests and have confidence in
the practical application of this process.
53
-------
Means of stabilizing the catalystic performance
Countermeasures against dust. As already mentioned, there are two problems
due to the dust, viz. the plugging of the catalyst bed and the erosion of the
catalyst. Against the plugging of the catalyst bed, we have been employing
fixed bed reactor with dust free type catalysts for many years. Through the
pilot tests for the dust free type catalysts in high dust and low dust flue
gases, we have found the most suitable catalyst shape, catalyst dimensions and
gas flow rate for respective flue gas. As for the shape of the catalyst, pipe
or honeycomb shape is most preferable, but for the high dust gas wider opening
is required than for the low dust gas.
The erosion of the catalyst usually starts at the inlet part of the
catalyst and gradually progresses (2) . The countermeasure we adopted is
hardening the inlet part of the catalyst as long as 1/100 to 1/50 of its
length by the impregnant, of which effectiveness was confirmed by endurance
tests. Our catalysts are made so as to contain in the active elements evenly
into the inside, and so the performance of the catalysts will be maintained
in spite of the progress of the erosion. Figure 8 shows the change of the
catalyst erosion rate with time for a conventional catalyst and our improved
catalyst. The inlet hardening could decrease the amount of erosion of about
6% per year to less than 1%.
Long-term stability of the catalytic performence. KHl's catalysts have
various features such as high activity and long life. In our previous report,
we had confirmed that the lifetime of the catalyst for the flue gas of the
heavy oil-fired boilers was more than two years (2) . For coal-fired boilers,
we carried out the durability test at the pilot plants adopted to Takehara
No.1 boiler of EPDC and could confirm that the lifetime of the catalyst was
more than 8,000 hours. As shown in Figure 9, no change was noticed of NOx
removal efficiency as well as the pressure drop due to the catalyst bed.
For the improved catalyst with low oxidation rate of SO2, the durability test
has been continued for more than 3,000 hours. According to Figure 10,
no change is noticed of the NOx removal efficiency and of the oxidation rate
of SO2. As a result, it was confirmed that our catalyst has a stable
performance against SOx, halogen ( HC1, HF ) in the flue gas and potassium in
54
-------
the dust.
In order to investigate the influence of the long-term low load operation
and the repeat of start-up/shut-down of the boiler, we conducted simulation
tests. As for the long-term low load operation, we conducted cyclic
operations between a quarter and a half of the full load for about one month.
It was found that the catalytic activity could be recovered by the full load
operation at 350°C, although it was temporarily lowered by the low load
operation at 270°C ( cf. Figure 11 ). This temporary deactivation phenomenon
is consider to be caused by the increase of So|" and Nh£ in the catalyst.
But the catalyst will not reach the permanent poisoning by such a degree of
— -f1
increase of S0£ and NH^ . NH^ is removed from the catalyst with the
recovery of reaction temperature, and the catalytic activity is recovered.
On the other hand, we repeated emergency stop and start-up five times.
No deactivation of the catalyst was caused by such operations like as
emergency stop and start-up ( cf. Figure 11 ) .
KHl's DeNOx PROCESS FOR COAL-FIRED BOILERS
The KHI's newly developed DeNOx process for coal-fired boilers has the
following features :
1. It is possible to suppress the unreacted NH3 below 5ppm by means of
our highly active catalysts, pertinent control of NH3 injection and
uniform dispersion of NH3 . '
2. It is possible to control the SO^ from the DeNOx reactor below lOppm
by employing the catalysts of low oxidation rate of SO2 .
3. No plugging of the catalyst bed occurs by employing such dust free
type catalyst as pipe-shaped or honeycomb-shaped.
4. The erosion of the catalyst will hardly occur even in the high dust
DeNOx process by employing the hardening treatment of the inlet part.
5. Our catalysts are hardly subject to the influence of SOx, halogen in
the flue gas and potassium in the dust .
In addition to thi6 DeNOx process, KHI has the established technology of dust
collection and wet DeSOx , and has been proceeding with the development of the
comprehensive flue gas treatment system for coal-fired boilers. The flow
55
-------
diagram of the toatl flue gas treatment systems and an example of material
balance for a 500 MW coal-fired boiler are shown in Figures 12 and 13.
As shown in these figures, it can be seen that the unreacted NH^ is suppressed
to 5ppm and the generated SO3 is to 8ppm with the NOx removal efficiency as
high as 90% . And it can be seen that unreacted NH3 and generated SO^ are all
collected by the electrostatic precipitator in the high dust DeNOx process,
and are partially collected by the wet DeSOx process in the low dust DeNOx
process.
SUMMARY
Hereto described is the progress to date of the KHI's DeNOx process with
many outstanding features for coal-fired boilers. KH1 has almost accomplished
the total system for flue gas treatment utiliziling this process.
However, further study tasks are continuing for improvement of reliability
and economics of the total systems.
Finally, we wish to express our sincere appreciation to Mr. Nakabayashi,
Mr. Shimizu and Mr. Mohri of Electric Power Development Co., Ltd..
REFERENCES
1. Y. Nakabayashi, " Research and Development on NOx Removal in Japan and
Results of EPDC's Research and Development of the DeNOx Process
EPRI FP-1109-SR Seminar Proceedings Special Report, ppl8-l — 18-25, July
1979
2. Y. Nakabayashi and S. Niwa, " Characteristics of Cylindrical De-NOx
Catalysts for a Coal-fired Boiler EPRI FP-1109-SR Seminar Proceedings
Special Report, pp21-l — 21-13, July 1979
56
-------
IDF
BUF
Boiler
FDF
Air
Preheater
H.ESP
DeNOx
Wet-DeSOx
GGH
Low Dust DeNOx Process
IDF
BUF
Boiler
L. ESP
Air
Preheater
FDF
DeNOx
GGH Wet-DeSOx
High Dust DeNOx Process
Figure 1. Total Flue Gas Treatment Process for Coal-Fired Boilers
-------
u I
I
I
/>
I
I
I o
—— : Calculated
20
40
60
80
100
Unreacted NH3 (ppm)
Figure 2. Adsorption of Unreacted NHj on Fly Ash
58
-------
Gas Temperature : 350°C
Inlet NOx Concentration : ca. 350ppm
100
90
u
S 80
O : Low Space Velocity
~ : High Space Velocity
70
60
— 40
30
20
10
0.6 0.7 0.8 0.9 1.0
NH3/N0x Mole Ratio (-)
1.1
Figure 3. Control Region of NH3/NOX Mole Ratio
59
-------
MCR
ECR
75
50
25
370
350
330
300
200
100
50
30
10
90
70
50
8
4
vy
\s
%
•••
• •••••••••••a*,***.
• •
A A ®
•••••••••
•••••
••
!»• *••*•••••••«••••••••••
^ • • g I «• ••
ft*
20 22 0 2 4 6 8 10 12 14 16 18 20
Time (h)
Figure 4. Follow-up Test for Boiler-Load Variation
60
-------
100
80
60
—
40
20 —
Gas Temp. : 350°C
NHg/NOx Mole Ratio
1.03
0.86
0.70
4.0
2.0
2000
4000 6000
Space Velocity (l/h)
Figure 5. Characteristic of a Conventional Catalyst
61
-------
100
90
80
Catalyst
o : K-109
~ : K-110
¦H
•H
O
400
380
340
360
320
300
Reaction Temperature (°C)
Figure 6. Performance of Improved Catalysts
62
-------
•H
•H
90
80
u a
o e^s
•M
4) O
U 4J
380
360
&oU 340
H 320
300
50
75
25
ECR
MCR
Boiler Load (%)
Figure 7. Performance of Improved Catalyst (K-110)
for Boiler Load Conditions
63
-------
>-3
Dust Concentration
20g/Nn
2.0 —
0)
% 1.5
c*S
0.5
Conventional Catalyst
Improved Catalyst
1
1
1
2000 4000 6000
Time (h)
8000
10000
Figure 8. Change of Catalyst Erosion Rate with Time
64
-------
100
o o o o u o o o Q ^ Po o Qo n qo jop o ^ Q Q oo
o-a
90
1.0
350°C
70
30
a.
n n op n
20
10
0
8000
7000
6000
5000
2000
3000
4000
0
1000
Time (h)
Figure 9. Durability Test of Pipe-Shaped Catalyst for the Economizer Outlet Gas of the Coal-Fired Boiler
-------
>1
100
90
U-l
H-l
80
350°C
70
(V
6
4
•H
2
0
4000
3000
2000
1000
0
Time (h)
Figure 10. Durability Test of Improved Catalyst for the Economizer
Outlet Gas of the Coal-Fired Boiler
66
-------
100
80
60
40
xl0~4
3 io
0)
r-i
o
E
>s
u
c
o
E
<11
0£
X
O
z
te
TO
U
CM J-
o
•>
+ J"
X
2
at 350°C
at 300°C
-o—
MM
2-
S0£
°"-o o
—
NH^
A
— A
—
500 Time (h)
1000
1 A l
1
J D | E |
A
B
C
D
E
Operation at 350°C
Cyclic Operation at 3008C and 270°C
Without NH3 at 270°C
Cyclic Operation at 300°C and 270°C
Operation at 350°C
Cyclic Operation of Start-up and Shut-down
+ 2—
Figure 11. Change of Catalitic Activity and NH^.SO^ in Catalyst
with Low Load Operation and Start-up/Shut-down Operation
67
-------
NH:
~i j-04 ^
IDF BUF
V*
Boiler
H.ESP
DeNOx
Air
Preheater
FDF
C
-O-
rll
Stack
GGH
-<$>-
Wet-DeSOx
s
———_____
<§>
<3>
Gas Volume
Nm3/h
(Wet Basis)
1700000
1714000
1723600
1861500
1913600
1967400
1915300
Gas Temperature
°C
380
380
380
150
86
45
106
Cone, of Fly Ash
mg/Nm3
(Dry Basis)
20000
30
30
30
30
20
20
Cone, of SOx
ppm
(Dry Basis)
1000
990
985
910
889
50
50
Cone, of NOx
ppm
(Dry Basis)
300
300
30
30
30
30
30
Cone, of NH3
ppm
(Dry Basis)
5
*
5
*
5
4
*
4
Cone, of SO3
ppm
(Dry Basis)
7
7
15
5*
10
5"
10
4"
8
4"
8
* : Reduced Value of NHi4HS0i+ to NH3 or S03
Figure 12. Flow Diagram of Total Flue Gas Treatment Process and Example of Material Balance
for a 500 MW Coal-Fired Boiler (Low Dust DeNOx Process)
-------
IDF
BUF
L.ESP
( Pulsed
Energization
System )
Stack
Boiler
FDF
Air
Preheater
DeNOx
Wet-DeNOx
GGH
~
O
O
<2>
O
Gas Volume
Nm3/h
(Uet Basis)
1700000
1709600
1846400
1849700
1901500
1953600
1901800
Gas Temperature
°C
380
380
150
150
86
45
106
Cone, of Fly Ash
mg/Nm3
(Dry Basis)
20000
19900
18400
10
10
10
10
Cone. of SOx
ppm
(Dry Basis)
1000
990
920
920
895
50
50
Cone. of NOx
ppm
(Dry Basis)
300
300
30
30
30
30
30
Cone, of NH3
ppm
(Dry Basis)
5
*
5
Trace
Trace
Trace
Trace
Cone, of SO3
ppm
(Dry Basis)
7
15
5*
10
Trace
Trace
Trace
Trace
* : Reduced Value of NH^HSO^to NH3 or SO3
Figure 13. Flow Diagram of Total Flue Gas Treatment Process and Example of Material Balance
for a 500 MW Coal-Fired Boiler (High Dust DeNOx Process)
-------
THE HITACHI ZOSEN NOx REMOVAL PROCESS
APPLIED TO COAL-FIRED BOILERS
By:
R. Wiener and P. Winkler
Chemico Air Pollution Control Corporation
One Penn Plaza
New York, New York 10001
S. Tanaka
Hitachi Zosen
Palaceside Building
1-1, Hitotsubashi, 1-Chome
Chiyoda-ku, Tokyo, Japan
70
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ABSTRACT
Hitachi Zosen is a leading supplier of flue gas treatment
systems for the removal of nitrogen oxides. They have nine com-
merical plants in operation. Early in 1978 Chemico Air Pollu-
tion Control Corp. whollyowned subsidiary of Envirotech Corporat
acquired the North American license for the Hitachi Zosen
technology, a dry process with selective' catalytic reduction
using ammonia. Because many sources of flue gas which require
nitrogen oxide removal also contain a high level of dust,
Hitachi Zosen has expended a considerable effort in developing
a catalyst bed which can operate without plugging even though
the gas contains particulates. Pilot plant tests using a
specially designed metallic catalyst have been successfully
operated on very dirty gases from steel sinter operations, and
coal-fired boilers. An extensive pilot plant program has been
in operation for over a year at Georgia Power Company's Plant
Mitchell in Albany, Georgia. This is a 0.5 MW equivalent demo-
stration plant for coal-fired denitrification which is sponsored
by U.S. EPA. Hitachi Zosen and Envirotech/Chemico believe that
this testing has shown the effectiveness of the process over
extended operating periods and the soundness of the control
system and basic design.
71
-------
Eventually a workable system will be evolved which can
supply a continuous record of ammonia slippage.
STARTUPS AND SHUTDOWNS
Hitachi Zosen experience indicates that no special precau-
tions are needed during starting up and shutting down of the
Hitachi Zosen NO removal system in coal-fired units except for
the avoidance of fly ash accumulations. Ammonia injection should
of course be stopped whenever the temperature drops below about
300°C to prevent ammonium sulfate/bisulfate formation on the
catalyst. The reactor can follow the normal tem-
perature changes along with the boiler with no difficulties. The
catalyst has been tested through hundreds of temperature cycles
without deterioration. If SO^ condenses on the catalyst during
shutdowns or startups, this produces no adverse effects and the
SO^ will evaporate when the temperature is raised to normal
levels. The SO^ condensate will not corrode the catalyst or re-
duce its activity.
Fly ash accumulations on the catalyst can be avoided by
careful design of the ductwork to ensure that proper flow dis-
tribution is maintained at most flow rates. Soot blowing is an
additional measure to avoid fly ash deposits.
72
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INTRODUCTION
Hitachi Zosen began the development of selective catalysts
for NOx removal in late 196 9 with basic research and laboratory
testing. These were carrier-supported catalysts. By 1974,
after extensive pilot plant studies, the catalysts were
considered to be commercial. The Green Chemical Company, a
wholly-owned subsidiary company, was then formed in June 1974 to
manufacture these catalysts and started operation in 1975.
In early 1974 a contract was signed between the Idemitsu
Kosan Company, LTD, one of the world's leading petroleum re-
fineries in Japan, and Hitachi Zosen for the construction of an
N0X removal plant with a capacity of treating 350,000 NM /H
(218,000 SCFM) of flue gases. The plant was the first of its
kind and size in the world. Construction work commenced at the
Chiba Refinery in May, 1975 with test operation in November the
same year. NO removal efficiencies of 95% were demonstrated.
Following the successful start-up of the Idemitsu-Kosan
system, other plants soon went into operation including a
)
274,000 SCFM unit at a petrochemical plant, and two plants at
steel manufacturing facilities. All of these have operated suc-
cessfully. (See Table 1 for a listing of commercial plants built
by Hitachi Zosen).
A particularly effective physical design of the catalyst
structure has been developed by Hitachi Zosen. This structure
is of a metallic corrugated shape. Figure 1 illustrates this
design. The key features of the catalyst are:
73
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(1) All-alloy thin metal plate or wire mesh
corrugated structure.
(2) Due to substantially reduced pressure drop
across the catalyst layer, operating power
costs are much lower than with conventional
catalysts.
(3) A straight gas flow path prevents dust clog-
ging.
(4) It is applicable for gases with high S0X con-
centrations and high dust loadings.
One of the primary applications for Hitachi-Zosen*s corru-
gated NOXHON catalyst is the treatment of high temperature
gases with high S0X and high dust concentration such as coal
fired boiler flue gases. Due to the catalyst's non-clogging
feature, the N0X removal system reactor"can be 'installed
directly behind the economizer. Thus, expensive flue gas pre-
treatment for dufet removal is not required.
Development work by Hitachi Zosen has been conducted at
various bench-scale and prototype pilot plants to ensure the suc-
cessful application of N0„ removal process technology for the
treatment of dirty gases exhausted from power plants (coal-fired
and high sulfur-containing heavy oil or residual oil fired), iron
ore sintering plants, cement kilns, and other similar sources.
One of the most important of the pilot plant operations con-
tinues at the Electric Power Development Corporation (EPDC) power
plant at the Isogo Station in Yokohama, Japan. This is a colla-
borative effort between EPDC and Hitachi Zosen under subsidy of
the Japanese government. The excellent cooperation and contri-
butions of the personnel of EPDC have resulted in the collection
of a great deal of valuable data. Important developments, par-
ticularly in methods of gas distribution, have been achieved.
There are three reactors installed, each treating about
200 NM^/Hr of gas, plus several smaller reactors for abrasion
74
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testing. These reactors have operated essentially continually
for several years.
NOXNON 600 catalyst was tested at this facility and some of
the runs were over 6000 hours and were halted only because of the shut-
down of the boiler for scheduled maintenance. As an example,
one test was run for about 6300 hours at the end of which the
targeted removal of 80% was still being attained. Ammonia slip-
page was very low as was the conversion of SO2 to SO3. These
tests have established the effectiveness of NOXNON 600 catalyst,
•its resistance to abrasion, its long-term reactivity, and the
low tendency to convert SO2 to SO3.
In addition to the wo^rk at EPDC, the pilot plant test faci-
lity for EPA, located in Albany, Georgia, has been operated for
over a year. The results to date of this test program form the
basis for this paper.
75
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PROCESS DESCRIPTION
The Hitachi Zosen NO Removal Process is a selective cataly-
tic reduction process in which nitrogen oxides in the boiler flue
gas are reduced using ammonia as the reducing agent. The reduc-
tion reaction occurs in the presence of a proprietary catalyst.
Flue gas leaves the boiler economizer (Figure 2) at a
temperature of 665°-745° (normal temperature range), depending on
the boiler load, and is diverted from the air preheater by means
of dampers into the ductwork leading to the reactor.
Ammonia vapor, diluted with air or steam, is injected into
the flue gas in this ductwork in approximately equimolar ratio
to the desired N0„ removal requirements. A pictorial representa-
tion of the ammonia injection system is shown in Figure 3. Care-
ful attention is given to the design of the ammonia injection
system to produce uniform mixing throughout the bulk of the flue
gas.
The flue gas, containing the ammonia, enters the top of the
N0X reactor where it passes through a grid system which insures
uniform gas distribution through the fixed catalyst bed, located
below the grids. No dust removal is necessary prior to catalyst
contact because of the non clogging design of the catalyst geo-
metry. Nitrogen oxides are reduced by ammonia to ordinary nit-
rogen and water vapor over the catalyst surface. The treated gas
then resumes the flow through the present boiler exit train, i.e.,
air preheater, and stack. Soot blowers are provided in the re-
actor for high dust laden gases to periodically clean the cata-
lyst bed of any dust accumulation (Figure 41.
76
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CATALYST CHARACTERISTICS
The gases to be treated flow in parallel to the plates of
active catalyst material in Hitachi Zosen's corrugated catalysts,
(see Figure 1). The catalyst bed consists of alternate rows of
corrugated and flat plates. The distance between the flat plates
is termed the pitch and this is typically between 6 and 16 milli-
meters. The pitch selection will depend upon the application
and in particular the concentration of particulates in the gas
to be treated. A larger pitch will have less tendency to retain
accumulations of particulates but the larger pitch increases the
required volume of catalyst.
CATALYST PREPARATION
The catalyst plates are arranged in a steel frame box sup-
ported by retainers. A standard module is 1.0 meter long, 1.0
meter wide, and 0.5 meter deep.
The activation of the catalyst follows after the corrugated
catalyst assembly is made. In the NOXNON 500 catalyst, thin
stainless steel plates are used. The surface is first converted
to an aluminum alloy which is then treated with an aluminum dis-
solving solution rendering the surface layer porous. The steel
surface may then be immersed in a solution containing active com-
ponents which adhere to the porous surface layer. A permanent
bond is obtained by further proprietary treatment.
A newer development is NOXNON 600 oatalyst which,instead of
plates, uses a metallic mesh material which is then coated with
a porous carrier in which the active components are supported.
The NOXNON 600 is considerably lighter in weight and contains
more active material for a given volume of catalyst.
77
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The active components of the catalyst consist of vanadium
and titanium compounds. Other components are added to increase
resistance to fly ash abrasion.
CATALYST ACTIVITY MEASURE
Catalyst activity is calculated by the following equation
and is independent of N0X concentration, and SC>2 or SO^ concen-
trations.
- In (1-X) = K (A/F)
where X = fraction removal of NO
A = surface area of catalyst
F = flue gas volumetric flow rate
K = apparent reaction rate coefficient
MEASURE OF GAS VELOCITY
The concept of space velocity is normally applied to cata-
lysts which are granular, cylindrical, ring, extrudate, and so
on. However, the concept of space velocity is not useful in de-
signing for the use of corrugated catalysts because of this unique
structure. Instead of space velocity, Hitachi Zosen uses area
velocity (A.V.), which is defined as flue gas volume flow rate
per unit of apparent catalyst surface:
(M3/M2-Hr.)
The particular A.V. used in the Hitachi Zosen design depends
upon the percent removal of N0X required, the gas temperature,
and other factors. However, the velocities are relatively high.
ABRASION
The catalyst can be abraded by the action of fly ash. Over
a period of time the continuous abrasive blasting of the catalyst
surface by the high velocity, dust laden flue gas will wear away
the active catalyst material. The degree of abrasion or ash-cut
has been studied by Hitachi Zosen and is estimated by the follow-
ing equation:
78
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A = a (c) (v2) (t)
where A = decrease of catalytic activated layer by ash-cut
a = constant
c = concentration of fly ash
v = superficial linear velocity of gas across catalyst
surface
t = elapsed operating time
A great deal of effort has gone into increasing the time
that the catalyst can be used in contact with particulate laden
flue gas. Special additives have been developed which are incor-
porated into the catalyst to increase its abrasive resistance.
Precautions are taken to ensure good gas distribution so as to
reduce areas of high gas velocity. These steps have been suc-
cessful in allowing operations of a year or more at pilot opera-
tions in Japan where dust laden flue gases have been tested,
Hitachi Zosen catalyst life of two years or more with typical
coal-fired boiler conditions are obtainable.
CATALYST REGENERATION
The catalyst life is expected to be at least two years.
Regeneration of the catalyst is not needed during the planned
catalyst life period. At the end of this period the old catalyst
would be scrapped and new catalyst installed.
79
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CHEMISTRY OF PROCESS
The following reactions are postulated:
4
NO + 4NH3 + 02
=
4
n2
+
6H20
(1)
6
NO + 4NH3
=
5
"2
+
6H20
(2)
2
N02 + 4NH3 + 02
=
3
»2
+
6H20
(3)
6
N02 + 8NH3
=
7
n2
+
12H20
(4)
4
NH3 + 302
=
2
"2
+
6H20
(5)
The first two reactions are probably those that occur within
the reactor. As we have experienced only very low levels of
NO2, the reactions (3) and (4) are not of significance. Reaction
(5) will only begin to occur at very high temperatures of 850°F
or higher.
The reaction of NH^ and NO is probably a combination of the
equations (1) and (2). It has been found by many investigators
that one mole of ammonia will react with more than one mole of
NO. At the Georgia Pilot Plant it appears that the ratio is
around 8:9. That is, eight moles of ammonia will react with
about nine moles of NO. This ratio holds up to about 80-85% re-
moval of NO.
The efficiency will drop off as increased removals are
sought and at a 90% removal the ratio is close to 1.0.
80
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IMPORTANT VARIABLES
The most critical variables which affect the degree of N0X
removal are the mole ratio of ammonia to NO - the flue gas flow
rate, and the reactor temperature.
MOLE RATIO
This variable is defined as the ratio of moles of ammonia
fed into the reactor to the moles of N0„ in the flue gas to be
treated. Typically a ratio of 0.9 to 1.0 is required for a NO
removal of 90% or higher. Figure 5 shows the mole ratio curve
prepared from data collected at the Georgia Power pilot plant
with NOXNON 600. It illustrates that the ammonia will,remove
somewhat more than one mole of NOx per mole of ammonia feed up
to a mole ratio of 0.7. Above this the removal becomes less ef-
ficient and the removal of more than 90% NO requires a lot more
ammonia for the final quantities of NO to be reacted.
This figure also shows the slippage of ammonia which becomes
appreciable at high mole ratios. At a 90% removal of NOx the
slippage is still relatively low, below 10 PPM.
FLUE GAS FLOW RATE
Increased flow rates provide decreased contact time with
the catalyst and consequent lower removal efficiencies. However,
at the normal range of operations the changes in removal are not
too obvious at varying flow rates. Figure 7 shows results of
tests at the Georgia pilot plant over a range of velocities which
indicate a general tendency toward lower removals at the higher
flow rates but the data is mostly scattered in a narrow band.
Figure 5 shows Mole Ratio vs. Removal data for two flow rates and
the results are very close.
81
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Tests at a wider range of flows performed in Japan (Figure 8)
indicate a definite drop off of efficiency at very high flow
rates. Very high flow rates are not recommended because of in-
creased pressure drops. Figure 6 shows the pressure drops
found at the Georgia pilot plant over the test conditions. These
flows would probably be typical of commercial operations.
TEMPERATURE
The flue gas temperature in the reactor is an important
variable. The effects are shown in Figures 8, 9 and 10. Nor-
mally the reactor temperature is held above 330°C (620°F) to
avoid the possibility of ammonium sulfate/bisulfate formation and
the reactivity of the catalyst is very high at this level. At
area velocities of about 10 (Figure 8) temperatures above 300°C
have little effect on the percent NO conversion. In effect, the
normal expected operating tejrperature ranges (above 300°C) have
essentially no influence over the removal efficiency.
82
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EFFECTS OF SULFUR OXIDES
The NOXNON 500 and 600 catalysts have been de-
veloped to be able to withstand high levels of sulfur oxides.
They have been run for several thousand continuous hours of test-
ing in contact with flue gases containing 400 to 500 PPM S02 with
no measureable decrease in activity due to the sulfur oxides.
Data from Japan provides indication of the fact that there
is no effect of SO2 concentrations on the removal of NOx. These
tests were run with NOXNON 600 catalyst at 10 M^/M^-Hr. , with a
gas composition of 500 PPM NOx and a mole ratio of 1.0.
S02 02 _ % NO Conversion
(PPM) (%) 20 0°C 250°C 300°C 350°C
0 10 55 73 86 94
250 10 54 73 85 93
For SO^, promoted catalyst life tests with concentrated SO^
have been used to obtain data. Even with contact with SO2 con-
centrations of 30,000 PPM over several hours the reaction rate of
NOXNON 500 and 600 showed no decrease after several such exposures.
83
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EPA FLUE GAS DENITRIFICATION DEMONSTRATION PLANT
In May of 1978 Hitachi Zosen received an order from the
United States Environmental Protection Agency (E.P.A.) for a
1,700 NmVh (0.5 MW equivalent) capacity demonstration plant for
its coal-fired power plant flue gas denitrification process.
As part of its energy strategy, the United States Government
plans to establish regulations which will require newly installed
power plants to use coal as their energy source instead of heavy
fuel oil or natural gas. But most U.S. coals have high SOv
(sulfur oxides) and ash concentrations, and no commercial techno-
logy has been introduced to remove NOx (nitrogen oxides) from
flue gases from power stations using these coals.
Therefore, the E.P.A. decided to construct a flue gas deni-
trification demonstration plant to carry out technological and
economical assessments on high SO and dust-containing coal-fired
power station flue gas.
The objective of the pilot plant program is to demonstrate
Hitachi Zosen's catalytic reduction process for the treatment of
flue gas with ammonia for the removal of 90% of NOx. The
program will evaluate the performance of the NOXNON 500 and
6 00 catalysts, which have been developed by Hitachi Zosen
for flue gas of high sulfur oxide and high dust content which is
exhausted from coal-fired boilers.
The original planned duration of the test program included
a three-month start-up and test operation period plus three
months of continuous operation. Varying levels of nitrogen oxide
and sulfur oxide concentrations were tested along with varying
84
-------
temperatures and gas flow rates. This program has been extended
and the test operation will be run for over a year.
Through the generosity and support of Georgia Power Company
the pilot plant host site is the Plant Mitchell of GPC at
Albany, Georgia. The flue gas is obtained from Unit #3. This
unit was built in 1964 and consists of a coal-fired C-E Boiler
and a Westinghouse Turbine-Generator with a capacity of 165 MW.
Steam temperature is 1000°F and the pressure 1800 PSI.
Flue gas for the pilot plant is obtained by connecting a
14" duct into the power plant duct after the economizer. The
slipstream of flue gas is first passed through an electric heater
to control the gas temperature, ammonia is injected into the gas,
and the gas then passes through the reactor vessel where the
nitrogen oxide is converted to nitrogen. The cleaned gas is re-
pressurized in a blower and returned to the power plant duct.
Additional quantities of nitrogen oxide and sulfur trioxide are
generated, as required, to vary the concentration in the flue
gas.
Construction and operation of the pilot plant was carried
out by Chemico Air Pollution Control Corporation (CAPCC), Hitachi
Zosen's North American licensee. Fabrication and procurement
v;as done within the United States as far as possible.
In implementing the contract with E.P.A., Hitachi Zosen pro-
vided the basic design, proprietary catalysts, and fabrication
of the NO , SO., generating unit needed for the system. CAPCC,
A J
as major subcontractor, provided the detailed engineering and de-
sign, procurement, erection and operation of the pilot plant.
The initial NOXNON 500 catalyst charge provided excellent
results for about 2000 hours of operation. Based on experience
in Japan the sootblower was not operated because the pressure
drop remained constant. After this period of time however,
there occurred a drop in removal efficiency and an increase in
85
-------
pressure drop. Removals decreased from the normal 90% level to
the 80% level. Intensive efforts were made to check and re-
check the analytical and control equipment to make certain that
it was the catalyst at fault. It became obvious that the
catalyst activity had definitely decreased below the acceptable
level.
A spare batch of NOXNON 500, which was at the site, was
installed to replace the initial batch. The replacement
material was exactly the same shape and composition as the
original.
Samples of the original batch were flown back to Japan for
intensive investigations. The results of these indicated that
there was no loss of catalyst activity. The material was as
chemically sound as originally provided. It appeared that the
loss of activity was due to a masking of a portion of the
catalyst surface due to a buildup of fly ash within the catalyst
bed. This phenomenon was not exhibited in Japan during long-run
tests at a coal-fired station. Analyses were made of the fly
ash from Georgia as compared to that in Japan. One possible
significant difference was that the Georgia material contained
a relatively high level of unburned coal or carbon. Physical
tests were performed on the fly ash and it showed that the
Georgia material had a greater tendency to agglomerate at high
temperatures.
One of the contributing factors to the fly ash build-up on
the catalyst was the design of the ductwork. When the ducts
were disassembled for an inspection of the system it was found
that the design allowed a large accumulation of fly ash in a
horizontal run above the reactor. Some of this fly ash un-
doubtedly loosened and fell onto the catalyst bed, thus block-
ing a portion of the flow through the reactor. This probably
contributed tc the lower than expected performance of the pro-
86
-------
cess. The ductwork was changed soon after the inspection was
made and such problems were not encountered later.
The replacement NOXNON 500 also gave excellent results
for some months of operation. However, again after some 2000
hours of operation it began to exhibit a loss of activity. This
happened despite daily operation of the sootblower. This cata-
lyst was taken out of the reactor, cleaned with compressed air,
and was replaced. The pressure drop, which had increased at
the same time the removal decreased, returned to a normal level
but the activity did not recover.
The loss of activity of the second batch of catalyst was
found to be due to a physical blinding of the surface of the
catalyst by fly ash. The degree of fly ash accumulation was
surprising. Investigations into the causes continue. One clue
is the tendency to an increased pressure drop when the system
is shutdown and restarted. One theory is that deposits on the
elements of the flue gas heater are released when the system is
cooled down. They are then carried with the flue gas during
restarts, into the reactor. The extreme temperatures on the
heater elements over long periods of time probably cause physical
or chemical changes in the deposited fly ash which might make
it more adhesive. This altered fly ash could stick to the
catalyst surface. This situation was not encountered during
many months of operation in Japan probably because of the dif-
ference in the heater design and the difference in the fly ash
composition. If this did actually occur in the pilot plant,
it would not be expected to happen in commercial systems where
flue gas heaters are not required.
The third batch of catalyst was then installed. This
catalyst was of Hitachi Zosen's latest design: NOXNON 600.
This is made from a metallic mesh instead of from sheets of steel
and is consequently much lighter in weight. Of more signifi-
cance is the fact that the pitch of this catalyst was larger:
87
-------
14 mm vs. 8 mm. The openings are much wider and the tendency
to clog is greatly reduced.
Because of the wider pitch, the reactor had to be
lengthened to accept the new catalyst which required more volume.
This NOXNON 600 catalyst has been in service since April 1980
and, as of this writing at the end of July, is providing ex-
cellent results. It is planned to test this catalyst at least
until October.
88
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PROCESS DESIGN CONSIDERATIONS
AMMONIUM SULFATE/BISULFATE FORMATION
The formation of ammonium sulfate (or ammonium bisulfate)
produced by the reaction between ammonia and sulfur trioxide can
cause difficulties in the process. Deposits can result in a
decrease of catalyst activity due to adhesion on the catalyst-
activated surface and/or blockage of the catalyst layer.
There is an increased tendency towards ammonium sulfate
formation at higher levels of ammonia and sulfur trioxide and at
lower temperatures. The best means of prevention is to maintain
a temperature so high that this compound cannot form. This is
normally around 330°C (620°F). If the reactor temperature, for
some reason, begins to drop and approaches this temperature it
would be best to stop the ammonia flow until the required mini-
mum temperature is reattained. If deposits are formed on the
catalyst by a process upset the sootblower can be effective in
removing these.
Deposits on downstream equipment such as air preheaters are
best avoided by maintaining a low level of ammonia slippage.
AMMONIA CONTROL SYSTEM
The pilot plant at Georgia was designed to simulate as
closely as possible the control system for a full-sized commer-
cial plant. The ammonia feed system is completely automatic and
requires only that the operator select the desired mole ratio.
From that point on the ammonia feed will be delivered as required
to satisfy the selected ratio of ammonia to incoming nitrogen
oxide.
89
-------
In this control system, the flue gas flow rate and the in-
coming nitrogen oxide concentration are measured and the signals
are multiplied to provide the mass flow of NO entering the re-
A
actor. This quantity is then multiplied by the set mole ratio
to determine the amount of ammonia required. This signal, in
turn, is relayed to the ammonia flow meter to set the ammonia
flow.
This system has worked exceptionally well. This ammonia
control system can probably be applied to a full-scale unit along
with some refinements, such as using the outlet NO or outlet
X
ammonia concentration to provide a signal to fine tune the
ammonia feed rate.
One potential drawback to this control system is the mea-
surement of the flue gas flow rate. This is difficult to do on
a large boiler system because usually there are no straight runs
of duct in which a flow element could be installed. Most of the
flue gas passes through headers without any significant ducting.
If there were a straight run, either before or after the reactor,
a flow element could be installed to provide a pressure drop
signal as a measure of gas flow. Such a system is used at the
Georgia pilot plant and might be practical even for larger
boilers.
In the absence of a flue gas flow meter other signals are
available. One of these is the steam flow rate to the turbine.
This is a measure of the fuel burned and indirectly a measure of
the combustion gases produced. Combining this signal with the
inlet NO level will provide a fairly accurate measure of the NO
X X
mass loading. This control can then be fine tuned using the
outlet NO level or the percent removal of NO .
X X
90
-------
REACTOR INSTRUMENTATION
Both temperature and pressure drop are required measurements
for the reactor. The temperature of the flue gas has an effect
on the removal efficiency. Normally, the temperature would not
be controlled and the reactor would accept whatever the gas tem-
perature would be at the economizer exit. At the Georgia pilot
plant an electric heater is supplied to control the temperature
because of the high heat loss from the ductwork, typical of pilot
plants.
A low temperature at the reactor inlet is of concern because
of the risk of ammonium bisulfate formation. At low temperatures
an interlock is provided to shut down the ammonia supply by over-
riding the ammonia flow controller.
The pressure drop across the reactor is an important mea-
surement. This will indicate whether there is any tendency to
plugging by fly ash or by other deposits within the catalyst bed.
At an increased pressure drop the sootblower is actuated to clean
the catalyst.
SOOTBLOWER CONTROL SYSTEM
Soot blowers are installed to periodically clean the cata-
lyst bed. They can use steam or air. The system can be com-
pletely automated and initiated manually by a push button. At
the Georgia pilot plant the system is set up the same as would be
provided for a commercial system. Upon initiation steam or air
is admitted into the electric heater which raises the temperature
of the gas to 650°F. The gas is released to atmosphere until
the temperature is sufficiently high. When the temperature is
high enough a valve opens permitting the gas to flow into the
sootblower and at the same time the sootblower moves forward
across the top of the reactor blasting the hot gas down through
the catalyst. After one cycle, forward and back, the system
automatically stops, the remaining gas is released to the atmos-
91
-------
phere, and the system shuts off. There are interlocks provided
to ensure proper gas pressure and to ensure that the sootblower
moves properly. The air or steam pressure and temperature are
monitored. At the Georgia pilot plant the sootblower has been
run once per shift since the NOXNON 600 catalyst was installed.
Both air and steam are being testfed.
AMMONIA SLIPPAGE
A certain amount of ammonia can be lost from the process
without reacting. This can happen particularly at high NOx re-
movals when there would have to be an excess of ammonia available
to approach complete reactions with the NO . Experience has
shown that slippage of ammonia is negligible below about 80% N0x
removal. At 90% removal or above the slippage can amount to
10-20 PPM or higher.
The control of ammonia slippage is important mainly because
of the risk of accumulations of ammonium sulfate/bisulfate on
downstream equipment. In Japan some clients have requested
targets as low as 10 PPM. The need for a continuous measurement
of ammonia slippage is very obvious.
At the Georgia pilot plant ammonia slippage has been essen-
tially nil below a mole ratio of 0.9. As the ammonia feed is
increased, however, the slippage rapidly increases as can be
seen in Figure 5.
The pilot plant in Albany, Georgia was originally designed
to provide a continuous read out of ammonia levels in the flue
gas leaving the reactor. The design used a chemiluminescent
analyzer with two converters. The sample of flue gas drawn
through the sample line was split. Half was sent through a high
temperature converter to convert all of the ammonia and NO2 to
NO. The other half of the sample stream was passed through a
low temperature converter which converted only the N02 to NO and
did not affect the ammonia. The analyzer was designed to deter-
92
-------
mine the NO level in each of the two streams in the two chambers
and by difference provide the ammonia concentration. In prin-
ciple this system should work but the problem was to ensure that
the ammonia reached the converter.
Ammonia can be easily lost from the flue gas sample before
it reaches the analyzer. It can react with SO2 or SO-j or it can
be absorbed by condensed moisture or by deposits of solid
material. We have even experienced the absorption of ammonia by
certain gas filters.
Despite heroic efforts at the pilot plant it was not possi-
ble to make the ammonia analytical system operable. A good sam-
ple to the analyzer could not be ensured. Eventually they went
to wet sampling methods using impingers to absorb ammonia from
gas samples and a Hach colorometric method to determine the con-
centration of ammonia in the absorbent. This system has provided
the necessary data but would not be a practical system for a
commercial plant.
Further efforts continue in the design and testing of a
continuous ammonia slippage monitoring system. A gas condition-
ing system has been designed by GCA and Charlton Associates to
treat a sample of flue gas at the sample point in the duct before
the sample can cool down. A sample of flue gas is filtered and
then passed through an absorbent to remove sulfur trioxide. The
gas is either passed through a stainless steel converter to con-
vert the ammonia to NO or is bypassed around the converter. The
gas sample is then dried and sent by the sample line to the ana-
lyzer at the control rooms. By comparing the NO level of the
sample passed through the converter and the sample bypassing the
converter, the ammonia analysis can be determined. This system
avoids the problem of the reaction of ammonia with sulfur tri-
oxide by absorbing the sulfur trioxide and avoids the problem of
the reaction with sulfur dioxide by maintaining a minimum tem-
perature above which the reaction cannot take place.
93
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FIGURE 1
NOXNON 600 CATALYST CONFIGURATION
94
-------
FIGURE 2
TYPICAL FLOW SHEET COMMERCIAL SYSTEM
BOILER
vo
in
AIR
HEATER
FLUE
GAS
CLEANING
I.D.
FAN
STACK
FUEL
AIR
FLUE GAS
HEATER
BOOSTER
FAN
REACTOR
AMMONIA
STORAGE
TANK
VAPORIZER
-------
FIGURE 3
AMMONIA INJECTION SYSTEM
AMMONIA
DISTRIBUTOR
MIXING
FINE CONTROL
ADJUSTMENT
ADDER
RELAY
AIT
102
FC
123
NOx
OUTLET
FFIK
FE
123
FIT
121
FY
MULTIPLIER = TOTAL NOx INLET
AIT
101
FR
NOx
INLET
FLUE GAS
FLOW
AIR SUPPLY
NHaFEED
96
-------
FIGURE 4
SOOT BLOWER
RETRACTABLE ARM
vO
SOOT BLOWER
CATALYST BED
-------
FIGURE 5
N0X REMOVAL vs. MOLE RATIO
100
80
O
z
U.
o
-J
o
2
LU
CC
60
40
20
m
(•
rrv.
(7
/b
•
(*Jr
] ~
'
r
0.2
0.4
0.6
0.8
1.0
120
100
80
60
40
20
1.2
a.
CL
LLI
(D
£
Q-
—1
CO
CJ
X
MOLE RATIO NhyNO*
Catalyst: NOXNON 600
Temp.: 700-710°F
How Rate: o 1500 SCFM
~ 1300 SCFM
Inlet NOx: 400-500 PPM
98
-------
FIGURE 6
PRESSURE DROP vs. VELOCITY
SUPERFICIAL VELOCITY Ft/Sec
NOXNON 600
Bed Depth: 2.0 Meters
Temperature: 715°F
99
-------
FIGURE 7
% N0X REMOVAL vs. AREA VELOCITY
9
10
11
12
a
AREA VELOCITY M3/M2-Hr
Mole Ratio: 1.0
Reactor Temp.: 720°F
Inlet NOx Cone.: 400-450 PPM
100
-------
FIGURE 8
AREA VELOCITY vs. NO CONVERSION
150°C
AREA VELOCITY: M3/M2-Hr.
Catalyst: NOXNON 600
Gas Composition: 500 PPM NO
500 PPM NH3
250 PPM S02
6% Oa, 10% H20, 10% C02
101
-------
FIGURE 9
REACTION TEMPERATURE vs. NO CONVERSION
2
O
CO
2
O
O
o
2
9s
REACTION TEMPERATURE
Catalyst: NOXNON 600
Area Velocity: 20.4 M3/M2-Hr.
Gas Composition: 250 PPM S02
6% 02
10% H20
10% C02
-------
FIGURE 10
MOLE RATIO vs. NO CONVERSION
350°C
300°C
250°C
• _
200°C
150°C —
0.2
0.4
0.6
0.8
1.0
1.2
1.4
MOLE RATIO NhyNO
Catalyst: NOXNON 600
Area Velocity: 20.4 M3/M8-Hr.
Gas Composition: 500 PPM NO
250 PPM S02
6% Oa, 10% HjO, 10% C02
103
-------
FIGURE 11
OXYGEN LEVEL vs. NO CONVERSION
100
350°C
300 C
200 C
4 6
% OXYGEN
Catalyst: NOXNON 600
Area Velocity: 20.4 M3/M2-Hr.
Gas Composition: 500 PPM NO
500 PPM NH3
250 PPM S02
10% HaO, 10% C02
104
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TABLE 1
HITACHI ZOSEN
LIST OF COMMERCIAL PLANTS
Customer
Osaka Gas Co.,
' Sakai
_ Daiki Engineering,
2 Chiba
- Idemitsu Kosan,
3 Chiba
Shin-Daikyowa Petro-
4 chemical, Yokkaichi
Hitachi Zosen,
5 Osaka
Toshin Steel Mill,
6 Himeji
_ Kawasaki Steel,
7 Chiba
Nippon Satetsu,
8 Himeji
. Kansai Oil Co.
9 Sakai
Treating
Capacity,
Nrn^/hr.
53,000
5,000
350,000
440,000
6,000
70,900
762,000
10,000
150,000
Rue Gas Source Process
LNG or naphtha-fired Ammonia
furnace Reduction
LPG-fired furnace rSESS.
CO boiler and gas- Ammonia
fired heater Reduction
Fuel oil-fired boiler with Ammonia
wet-type desulfurization Reduction
Gas-fired annealing Ammonia
furnace Reduction
Kerosene-fired steel Ammonia
heating furnace Reduction
Iron ore sintering plant with Ammonia
wet-type desulfurization Reduction
Fuel oil-fired steel Ammonia
heating furnace Reduction
Fuel oil fired Ammonia
boiler Reduction
Completion
1975
1975
1975
1975
1975
1976
1976
1977
1979
105
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BABCOCK-HITACHI NOx REMOVAL PROCESS FOR
FLUE GASES FROM COAL-FIRED BOILERS
By:
T. Narita and H. Kuroda
Kure Works of Babcock-Hitachi
Dr. Y. Arikawa
Kure Research Laboratory of Babcock-Hitachi
Dr. F. Nakajima
Hitachi Research Laboratory of Hitachi Ltd.
106
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ABSTRACT
In the previous symposium in 1978 we presented a paper titled "SOME
EXPERIENCES OF NOx REMOVAL IN PILOT PLANTS AND UTILITY BOILERS". In that
paper we stated the history of developments of oar process, catalyst charac-
teristics and several operating experiences. This tine we intend to intro-
duce some of the improvements And developments which we have achieved since
then.
As far as coal-fired applications are concerned, there are two systems
required. The first one is DeNOx with low dust loading where the DeNOx
reactor is located downstream of the hot electrostatic precipitator (EP),
and the second is DeNOx with higfr dust loading where the DeNOx reactor is
located upstream of the cold EP. Although the selection of EP system should
be determined mainly from the standpoint of performance of collecting fly
ash through the boiler, our DeNOx process is applicable in either case.
As for the two commercial DeNOx plants with low dust loading from coal-
fired boilers, we have already completed the design and manufacture, and
they will go into commercial operation in November of 1980 and in July of
1981, respectively. Concerning the DeNOx with high dust loading, we will
introduce in this paper the results of abrasion and performance tests under
dust concentration of 15 to 20 g/Nm^, through which we have confirmed the
reliability of the catalyst.
Furthermore, another important thing in the Selective Catalytic Reduc-
tion (SCR) process is to reduce the conversion of SOg to SOj in order to
minimise the influence on the downstream equipment. Ve have developed a
catalyst with the lowest conversion rate less than 0.5 % without decreasing
the NOx conversion activity at the rated load.
107
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INTRODUCTION
Recently the use of coal as a substitute fuel for fossil oil has become
of world wide importance. Since the characteristics of coal vary according
to the location of mining, those of the coal-fired flue gas also vary.
Generally, it contains not only more dust (15 — 25 g/Nm^) than heavy oil-fired
flue gas (0.05~0.2 g/Nm'), but also higher NOx (Nitrogen Oxides) and higher
SOx (Sulfur Oxides) concentration. This means that the DeNOx system, which
is one of the environmental protection systems for coal-fired flue gas,
demands more sophisticated technology than for heavy oil-, or gas-fired flue
gas.
It was introduced at the previous symposium that Babcock-Hitachi had
produced a high activity catalyst through extensive B&D, and has succeeded
in developing it into a thin plate catalyst (a parallel flow type) for dirty
gas. The plate type catalyst has been adopted for 20 plants out of 23 plants
which have been ordered or are intended to be ordered soon. 10 of these
plants are already operating satisfactorily or are under preoperation stage.
Recently, demand for a DeNOx system for coal-fired flue gas has been increas-
ing rapidly. Our first new DeNOx plant for low dust coal-fired flue gas
(Hokkaido Electric Power Co., Tomato Atsuma P.S. Unit 1), the first in Japan
to be installed in a new coal-fired P.S., will be in commercial operation this
coming November, while the second plant (Electric Power Development Co. (EPDC)
Ghkehara P.S. Unit 1) will also be in commercial operation next July. In
addition to these, several plants including those for high dust flue gas are
now being designed.
Ibis paper describes the features of the DeNOx system for coal-fired
flue gas in comparison with that for the oil-fired flue gas and includes an
example of a DeNOx system for a coal-fired 500 MW boiler.
Furthermore, a pilot plant test using the plate type catalyst for a
coal-fired flue gas has been conducted at Tfekehara P.S. on a co-study basis
with EPDC.
108
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ITEMS CONSIDERED IN THE DESIGN 07 THE DeNOx SYSTEM FOB COAL-FIRED FLUE OAS
As the characteristics of coal-fired flue gas differ much from those of
the heavy oil-fired flue gas, the peculiarities of the coal-fired flue gas
have to be taken into consideration when designing the DeNOx system. Fig. 1
is a summary of the items considered and the measures taken in each item.
Our company has been producing the catalyst, which is a key point in
the DeNOx technology, in accordance with our policy of manufacturing in our
own works, from mixing of material to final product, under strict quality
control since the start of development. Our success in developing a catalyst
with high performance in practical use, is the result of a long program of
catalyst improvement based on severe tests conducted in our research labora-
tory, factory, and in the field.
The catalyst, is composed of many thin plate elements, and its shape
resembles the N.F elements of an air heater, so it is free from dust accumu-
lation and has a low pressure drop. Additionally it has high erosion re-
sistance and rigidity because it contains inner layer metal plate. It was
confirmed that the performance of the catalyst had not decreased against the
influence of SOx, halogen compounds (HC1, HF), and alkaline metals (K, Na)
in the dust, even after 10,000 hours test with an actual coal-fired flue gas.
Especially, the conversion ratio of SO2 to SO} which is apt to cause problem
in the downstream equipment is small enough to say that our DeNOx catalyst
for coal-fired flue gas has a great advantage. Moreover, based on the
results of model testing, improvements have been made to the reactor struc-
ture to prevent dust accumulation and non-uniform gas flow, and to simplify
the loading and removal of catalyst.
SYSTEM FOB DeNOx
The flue gas treatment system for coal-fired boiler consists of three
major systems, namely DeNOx, DeSOx and Dust Collection. Each system, in
addition to fulfilling its own particular function, should, as part of the
109
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general boiler system, contribute to the total reliability and stability
of the system over a long period of tine, and be economical. Taking the
above into consideration, we put two treatment systems for coal-fired flue
gas into practical use. Kiose are shown in Fig. 2.
One is called a low dust DeNOx system, in which the boiler flue gas is
first treated through a hot EP, and then the low dust flue gas is treated in
the DeNOx reactor. The other is called a high dust DeNOx system, in which
the boiler flue gas is treated in the DeNOx reactor without any pre-treatment
after the economizer and followed by a cold EP.
The selection of the DeNOx system depends on the EP type which should be
determined mainly from the standpoint of performance of collecting fly ash of
which properties vary widely according to the location where fuel coal is
mined. As far as DeNOx system is concerned, tests using actual flue gas have
been conducted sufficiently for both systems, and it has been confirmed that
both are practical as DeNOx system. Die construction or the design of actual
plants for each system is being carried out at present.
DeNOx SYSTEM WIJH LOW DUST LOADING
We introduced some results of a low dust loading test for practical use
at the previous symposium. We had performed a pilot plant test, in which we
carried out long duration operation of more than 10,000 hours and confirmed
various characteristics of the low dust loading. For instance, no change is
found in DeNOx efficiency and reactor pressure drop, see Fig. 3» which shows
that the DeNOx system can be operated quite stably. As shown in Fig. 3,
DeNOx inlet dust concentration of 20, 100, 200 mg/Nm^ were used and in ad-
dition 12 g/Nm^ was experienced at hot EP trip, but there was no change in
DeNOx efficiency nor reactor pressure drop. During this test the annual
maintainance inspection, lasting days, for the boiler unit was carried out
and during this shutdown the DeNOx plant was exposed to the atmosphere,
however this had no influence on the catalyst.
110
-------
Summarizing the above, ve can come to the conclusion that our DeNOx
system has high reliability for practical use at low dust loading. The
result of actual operation of the DeNOx system at Hokkaido Electric Power
Co., and at plant of Electric Power Development Go. are expected to be
excellent.
DeNOx WITH HIGH DUST LOADING
A high dust DeNOx system treats the flue gas from a boiler without any
pretreatment. Therefore, the main aim in developing this system is to
obtain an erosion resistant catalyst, which can withstand large amounts of,
coarse, and hard dust composed of mainly silica and aluminum. For the pur-
pose of overcoming this problem, an accelerated erosion test for the plate
type catalyst was conducted with actual fly ash in Hitachi research laborato-
ry. Fig. k shows the test equipment and Fig. 5 shows the evaluation of the
test results.
According to our investigation of abrasion phenomenum, the erosion
caused by abrasion with dust on the plate catalyst starts almost at the front
edge of the plate, and then gradually proceeds downward. The catalyst
material is integrally coated to stainless steel support plate which works
as a protector against the abrasion by particulates. It was confirmed that
our catalyst has extraordinary high erosion resistance. Summarizing the
test results, the weight loss of the catalyst caused by abrasion can be
estimated using the equation in Fig. 5*
Moreover, in order to conduct an abrasion test on the oatalyst in an
actual gas, the abrasion test catalyst was installed upstream of a hot E.P.
in the same pilot plant as used for the low dust test mentioned in proceeding
section. The test with high dust loading was conducted at a velocities of
k, 6, 8 m/s for about 3«000 hours. 3fee result showed little or no erosion
nor deactivity of the catalyst employed in the test. The result of this ac-
celerated test with a gas velocity of 6 to 8 m/e was converted to the actual
operating basis where the gas flows at a velocity of k to 5 m/s, and the
111
-------
result of this evaluation was that the operating duration would be equiva-
lent to as much as 17,000 to 23,000 hours. Accordingly it is apparent that
the catalyst can be used for commercial plant.
Fig. 6 ahows the result of a high dust performance test, using the
catalyst that bad been used for the abrasion test mentioned above.
Up to now approximately ^,000 hours of performance testing, and as far
as abrasion is concerned, a total of 7,000 hours of testing has been com-
pleted satisfactorily. It can be seen from Fig. 6 that little or no deacti-
vity of the catalyst nor increase in pressure drop across the reactor has
occured over the test duration, as was expected.
Several inquiries have been received regarding commercial DeNOx systems
for high dust loading and some of them are at present under design.
LOW CONVERSION OF S02 TO SOj
Ae illustrated in Fig. 1 when designing a DeNOx system for coal-fired
flue gas, such points as "minimum effect on the downstream equipment" should
be taken into consideration. To achieve this, the following conditions are
essential.
1) A low conversion rate of SO2 to SOj
2) Minimized slip from the DeNOx system
SO^, mainly converted from SO2, and NHj in the flue gas react to form
NH^HSO^, as in the following reaction formula (1).
NHj(g) + SOj(g) + H20(g) NH^HSO^(liq.) (1)
Fig. 7 shows the relation between the precipitation temperature of NH^HSO^
and SO-j concentration with the parameter of NH^ concentration. From Fig. 7,
under the ordinary SOtj and slip NHr, concentration at reactor outlet, it is
112
-------
understandable that NH^HSO^ is formed at around 230~ 250 °C, which usually
coincides with the temperature range in the intermediate section of the air
heater downstream.
NHj^HSO^ becomes such a sticky liquid over 130 °C that it is likely to
adhere to the elements of the air heater and cause some dust to accumulate on
the elements! ultimately resulting in problems, such as increase in pressure
drop and plugging. In order to prevent this, it is preferable to slightly
modify the air heater with regard to element shape, section deviding, and
soot blowing procedure.
Most important is to minimize the formation of NH^HSO^, which causes
trouble downstream. In order to prevent SOj and NHj from forming NH^HSO^,
the SOj and NHj concentrations in the flue gas have to be kept as low as
possible. To minimize slip NHj, the reactor should be designed under an
appropriate Space Velocity (SV), which is the gas quantity (Nm3/h) divided
by the catalyst volume (m'), and operated with low (NHj)/(N0x) mole ratio,
then the reaction between NHj and NOx should be maximum. lhe slip NHj can
be kept at less than 5 ppm.
Regarding SOj which forms NH^HSO^, in addition to the SOj originated in
the combustion flue gas, SOj is converted from S02 under the presence of the
DeNOx catalyst. In the case of coal-fired gas, S02 is contained at the inlet
of DeNOx reactor in such quantity, about 1000-2000 ppm, that large quantitis
of SO^ will be formed if we use an ordinary catalyst. It means 20-40 ppm
of SO^ will be formed newly with a catalyst which has a conversion ratio of
S02 to 80j of 2 for instance. Needless to say the lowest conversion of
S02 to SOj should be required for DeNOx catalyst for coal-fired flue gas.
Generally speaking, the catalyst which has high activity for NOx decom-
position presented by formula (2) has also high conversion activity of S02
to SO3 expressed in formula (3).
^NO + *fNHj + Og ^ 4N2 + 6H20 (2)
S02 «¦ 1/2 02 =r SOj (3)
113
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In other words if SO2 oxidation activity is restrained, the NOx decomposing
activity will also be greatly reduced. However, we succeeded in achieving
low SC>2 oxidation activity without decreasing the NOx decomposing activity at
boiler rated load by the selection of the proper catalyst component.
Fig. 8 shows the pilot plant test results using actual flue gas.
During about 6,000 hrs operation conversion of SO2 to SO^ has been kept at
less then 0.5 % without any tendency to increase.
DESIGN EXAMPLE FOR A 500 MV COAL-FIRED UTILITY BOILER
For reference, we would like to present an example of a design of a
reactor for a 5O0 MW coal-fired utility boiler.
Design conditions are as follows.
Gas flow rate
No. of reactors
Gas temperature
NOx at inlet
SOx at inlet
Dust concentration
DeNOx efficiency
Slip NH3
1,500,000 Nm^/h at MCR
2/boiler
370 °C
500 ppm
0£, dry basis)
1,000 ppm
20 g/Nm3
Case-1 80 %
Case-2 90 %
10 ppm
(5% O2, dry basis)
The outline of the reactor designed, the shape of the catalyst and the
catalyst loading procedure are illustrated in Fig. 9 and 10.
Hie basic dimensions of the catalyst element are about 1 mm thickness
and 10 mm pitch. Gas from the economizer comes down, parallel to each
catalyst plate, to avoid dust accumulation and two stages of catalyst bed
are contained in the reactor. Generally soot blowers to clean the catalyst
114
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would be installed, however in the case of our plate type catalyst, which
consists of thin catalyst plates arranged in parallel, very little dust
accumulation on the catalyst was experienced, since there are very few
corners in the flow path and the flow velocity is evenly distributed. In
our design usually soot blowers for the catalyst are not necessary.
Jig. 11 shows the expected performance of the DeNOx for the boiler load
at a DeNOx efficiency of 90 % (case-2). Generally, the DeNOx efficiency
has a tendency to increase a little with lower load, which is caused by the
relation of both the decreased gas flow rate and the decreased gas tempera-
ture. The pressure drop of a reactor can be designed to be as low as about
50 mmH20 and the SOg oxidation ratio, to be as low as 0.J~0,5 %• Our study
is based on a NOx concentration of 500 ppm at the DeNOx reactor inlet (boiler
outlet), however, in Japan boiler combustion technology has improved so much
that the NOx emitted by a new boiler can be less than 200 ppm.
SV is influenced by the reactor inlet NOx concentration, so that under
the condition of constant DeNOx efficiency and slip NH^, SV could be increased
in proportion to lower NOx. The relation between SV and NOx concentration is
shown in Fig. 12. Incidentally, if the NOx concentration at the DeNOx re-
actor inlet decreased from 500 ppm to 200 ppm, SV would increase by about
25 % «nd the quantity of catalyst required would decrease by about 20 £.
DeNOx efficiency is related to the quantity of catalyst, as shown in
Fig. 13. It can be seen from Fig. 13 that the quantity of catalyst would
decrease by about y0 %y in case the DeNOx efficiency lowered from 90 % to
80 %.
SUMMARY
In this paper we have related some of our recent studies with the
Babcock-Hitachi dry catalytic NOx removal process. Regarding the DeNOx
efficiency, we can obtain as high a value as we wish, by increasing the
catalyst quantity, but the most important points for the DeNOx system in
115
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coal-fired plant are the catalyst characteristics of erosion resistance,
anti-plugging and low conversion of 80% to SO^. We believe that our plate
type catalyst, which we manufacture in our own works under strict control,
should satisfy all of those requirements. Hitachi Ltd., including Babcock-
Hitachi, as not only a utility boiler manufacturer but also as an integrated
machine manufacturer, highly experienced in the field, will continue to
strive to improve this technology with all its technological resources.
116
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Characteristics of coal-
fired flue gas
,in contrast with heavy n
oil-fired flue gas
\ Catalyst requirements"] | Design features of actual system
High activity
High NOx
High SOx
Unaffected by gas or
dust components
High halogen
^soluble acid gas
such as HC1, HF, etc.
High dust including
alkaline metal (K, Na)
Low conversion of SOg
to 8O5
Minisrum effect on down-
stream equipment
Besistant to plugging
High erosion resistance
Catalyst
Ti-base catalyst - special components for
low oxidation
Plate type
1) each element has inner layer plate
- high structural strength and
erosion resistance
2) elements made into units
- for optimum element pitch
3) units made into blocks
- easy handling* easy loading
Seactor
7
Down flow type
1) optimized shape of structural compo-
nents
- minimum surface area perpendicu-
lar to gas flow, thus minimum
dust accumulation
Installation of guide vanes
1) even distribution of gas
2) prevention of dust accumulation
Operation
Operation at low (NHx)/(NOx) mole ratio
Selection of appropriate SV
Remarks : NOx (Nitrogen Oxides), SOx (Sulfur Oxides), SV (Space Velocity)
Fig. 1 Consideration on DeNOx System for Coal-Fired Flue Gas
-------
Item
DeNOx with Low Duat Loading
DeNOx with High Duat Loading
Syatea
to Stack
Boiler Hot | "
1 EP DeNOx A/H d/d H DeSOx
to Stack
Boiler Cold 1
DeNOx A/H EP Q/Q E DeSOx
GRF
GRF
Renarka : GRF (Gaa Recirculation Fan)
-------
Catalyst Plate fype
Gae Teoperature 350 °C
(NH3)/(N0x) 0.83
(Pretreated by Hot EP)
VO
12 g/m*
not EP Trip
100 -
Q W
4000
6000
8000
'
10000
Time (h)
Fig. 3 Pilot Plant Teat of Parallel Flow Reactor Treating Flue Gas from Coal-Fired Utility Boiler
-------
N»
O
Test Section
15 ¦/»
(Oas Velocity)
10 m/e
LX
5
Mesh for
Uniform Gas Flow
%
S
Dust Inlet
=f=^
Blower
Flow Meter
20 m/e
25 •/•
Fig• ^ Equipment for Catalyst Abrasion Test
-------
Experimental Equation W«: Weight Lode of Catalyst (wt%)
u _ r . »2.9 r1.7 . «P.E *: Constant
W-K ¥" . C T" v : Oas Velocity (m/m)
C; Dust Concentration (g/Na)
T : Operating Tiae (h)
2.0
1.0
Oust : Fly Ash
Gas Velocity : k a/a
Dust Concentration
50 g/Na3
30 g/Na3
10 g/H«3
0.1 g/Nn3
5,000 10,000 15,000
Operating Tiae (h)
20,000
Tig. 5 Anticipated Weight Loss of Plate type Catalyst vs Operating Tiae
-------
Test Purpose
Abrasion Test
Performance Test
Gas Temperature
346-360 °C
348-353 °C
NO*
244 ~ 3^5 PDB
285- 472 ppa
SOx
1100-1700 ppa
(1100-1700) dm
Dust Concentration
16.1-19.0 g/Nm^
17.3-20.2 g/Na3
LV
-
k m/b
(NHn)/(N0x)
0
O.83
© ~ 50
h °
2
• a § 25
2 2 J
£ Q
i?
a
•H
S-S
St:
o w
0
100 r
90
80
70
60
JL
(2780)
. I i
JL
1000 2000 JOOO 4000 5000
Total Tiae froa the Abrasion Taat (h)
» i I '
6000
7000
1000 2000 3000
Performance Test Tiae (h)
4000
Fig. 6 Operation Chart of the Parallel flow Type DeNOx Pilot Plant
for Coal-Fired Boiler Flue Gas
-------
Foraula : SOj ~ NHj + I^O — NH^HSO^
350
200
1000
10 100
SOj (pp«)
***• 7 Precipitation Te«per*tur« of Aaaoniua Bianlfate (NH4HSO4)
-------
Catalyst
Gas Temperature
(NH3)/(NOx)
Plate T^pe
350 °C
O.83
KJ
¦t-
a
o
f*
a
h
•
~ ^
s ^ s
CO
f\J
S 2
o
2
! £ •
£ a
1.5
1.0
0.5
0
100
50
0
e
<5 3
Q W
100
90
80
70
2000
J»000
6000
Tiae (h)
Fig. 8
Pilot Plant Test of a Parallel Flow Reactor Treating
Flue Qae froa a Coal-Fired Utility Boiler
-------
Catalyst
r / v Block
Fig. 9
Outline of Reactor for 500 MW Coal-Fired Boiler
-------
f-J
On
Catalyst Element
Catalyst Unit
Catalyst Block
Transportation
Crane
v=o—o-rm
<>
X
X
X
X
X
X
Fig. 10 Assembling and Loading Procedure of Catalyst
Loading
-------
100
8o
6o
600
500
*~00
50
25
0
1500
1000
500
Efficiency
(NHj)/(N0jc)
Inlet NOx
Slip NHj
Pressure Crop
SO2 Conversion to SOj
Oas Flow Bate
Oas temperature
1 I
g
1.0
z
/—¦
> J.
KN
0.5
H
as
10
5
0
K\
iti
Z B
P.
O. P.
1.0 S
a
0
5 ~
§
-------
DeNOx Efficiency : constant
Slip NHj : constant
(Base)
5 100
75
50
•H
400
100
500
200
Inlet NOz Concentration (ppa)
Fig. 12 NOx Concentration re Catalyst Quantity
Inlet NOx Concentration : constant
: constant
S 150
(Base)
S 100
+>
60
8o
70
100
90
DeNOx Efficiency (%)
Fig. 13 DeNOx Efficiency vs Catalyst Quantity
128
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TEST SUMMARY OF AN INTEGRATED FLUE GAS TREATMENT SYSTEM
Utilizing the Selective Catalytic Reduction Process
for a Coal-Fired Boiler
By:
N. Aoki
Ishikawajima-Harima Heavy Industries Co., Ltd.
Tokyo, 135, Japan
J. S. Cvicker
Foster Wheeler Energy Corporation
Livingston, New Jersey 07039
129
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ABSTRACT
This research program was initiated to investigate whether denitrification
of flue gases from a coal-fired boiler can be effectively accomplished by using
the selective catalytic reduction process in combination with desulfurization
and dust control as an integrated system.
An experimental system was designed to handle between 1000 and 2000 NM^/
hr of. flue gas and measure such parameters as catalyst life, catalyst plugging,
catalyst abrasion rate due to ash", air heater plugging, hot ESP, wet ESP, and
bag filter efficiencies, along with the efficiency of a limestone desulfuriza-
tion system.
The results of this testing have shown that this integrated approach to
flue gas cleanup is feasible and may be incorporated into a full-scale, coal-
fired boiler flue gas design. This testing will be continued to develop a more
reliable integrated flue gas treatment system prior to commercialization.
130
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SECTION 1
INTRODUCTION
Recent attempts to substitute coal for oil as an energy source for power
plants have created a decrease in the overall air quality. To correct this
trend, the need for an integrated flue gas treatment system has become appar-
ent. This new integrated system must reduce the concentrations of dust, S0X,
and N0X in the flue gases below those created by the former use of heavy oil.
To meet these needs, IHI started a joint research and development proj-
ect for an integrated coal flue gas treatment system with Electric Power
Development Co., Ltd. To prepare for this project, IHI started denitrifica-
tion testing in January 1978 on flue gas from a coal-fired boiler at Isogo
Power*Station of Electric Power Development Co., Ltd. In December 1978 a
desulfurizing system was installed on the downstream side of the denitrifica-
tion system. Various tests were conducted concerning denitrification, desul-
furization, and dust collecting functions of this integrated flue gas treat-
ment system. These tests have provided the opportunity to analyze the
problems and possible solutions concerning the eventual commercialization of
this integrated flue gas treatment system.
Foster Wheeler is presently marketing the IHI Selective Catalytic Reduc-
tion Process in the United States.
131
-------
SECTION 2
TEST OBJECTIVE
The individual techniques to treat air pollution emissions from coal-
fired boilers, such as NOx, S0X, and dust, have been well established. How-
ever, these tests were aimed at integrating these techniques into a total
system, including waste water treatment. The following discussion is con-
cerned with various problems aji(i their solutions regarding such an inte-
grated flue gas treatment system.
The major test objectives were as follows:
1. Determining DeNC^ catalyst life
2. Preventing the catalyst layer from plugging with ash
3. Preventing the abrasive wear on the catalyst due to ash
4. Detecting ways to prevent plugging of the gas air heater (GAH)
5. Developing of a low SO3 conversion ratio catalyst
6. Determining dust collecting efficiencies of a high temperature
electrostatic precipitator, bag filter, and a wet type electro-
static precipitator
7. Measuring characteristics of the desulfurization system, such as
efficiency of removal, effect of dust, quality of gypsum, method
of waste water treatment, and ways to prevent plugging of the
reheat system.
132
-------
SECTION 3
TEST SYSTEM
Two DeNOx systems were selected as the best available for this testing.
The first was chosen to handle the high dust condition directly from the
boiler and located ahead of the air heater and cold ESP. The other DeNOx
system was installed between the hot ESP and the air heater to handle the
low dust condition. (Reference Figure 1 on the following page.) In this
test, the flue gas reheater was a standard design, and the FGD system used a
common wet limestone process.
133
-------
High Dust Denitrifying Process
Boiler
DeNOx
GAH
Cold ESP
or Bag
filter
w
GGH
Low Dust Denitrifying Process
Hot ESP
GAH
FIGURE 1
134
Waste water
treatment
FGD
Wet ESP
-------
SECTION 4
SPECIFICATIONS OF TEST EQUIPMENT
The specifications of the major test equipment used for this program are
shown in Table I below, and Figure 2 on following page shows the Schematic Flow
Diagram.
TABLE I
Test
Equipment
Specifications
Denitrifi-
cation
device
Denitrifying
method
Type of
reactor
Selective catalytic reduction process using NH3
Vertical downward flow type fixed bed
Shape of
catalyst
Square honeycomb type catalyst
Capacity
; 1000 NM3/h x 2 for high dust
1000 NM^/h x 2 for low dust
1 I
High Dust Low Dust
Air heater
(GAH)
Type
. |
(Regenerative (Generative type) i
type) ;
¦ 1
j
High temperature j NF-Single layer
' element: DU
; Medium and low >
temperature
' element: NF
j
Capacity
2000 NM3/h x 1 2,000 NM3/h x 1
1
135
-------
TABLE I (cont'd.)
1
Test
1 Equipment
Specif ications
1
1
1
i ¦
! High temper-
ature electro-
i static precipi-
tator
f — - " ¦" 1
I
Bag
filter
Wet electro-
static precipi-
tator
jDust
icollector
i
i
Type
Dry horizontal
gas flow type
Reverse
washing
bottom
inlet
type
Wet type flat
plate
1
Capacity
2000 NM3/h
2000 NM3/h
1000 NM3/h
Reheater
(GGH)
Type
Capacity
(Generative type)
1000 NM3/h x 1
Desulfuri-
zation
device
_
Type
Capacity
Limestone wet process FGD system
(Both separation and mixing of ash are possible)!
1000 NM3/h x 1
Dust removing tower, absorption tower, mist '
eliminator, gypsum recovery process, waste
water treatment equipment
136
-------
-n--
typeL
V"-/ ' | DeSOx |
FIm3
Bed R
cror
.000
Irm-T/KM
(tilth Dust)
(2,000 Na->/h)
*2.000 |^/b)
, Pet twej [ Mi«r
(Low Dust)
llmlnafor
HOT EP
J
BUF
(1,000 Itai3/h)
Met type
DeSOx
(2,000 1ta3/h)
(1,000 Nm3/h)
Fig. 2 Schematic Test flow diagram of integrated flue gas
treatnent systems.
-------
SECTION 5
TEST SCHEDULE
This test and research project was initiated as a result of early DeNOx
testing that started January 1968. It soon became apparent that there was a
need to combine N0X, S0X, and dust removal in one integrated system and that
this combined system looked viable based on the early individual testing.
Table II shows the schedule of the testing from 1977 through 1980.
138
-------
TABLE XI
1977
1
1978 j 1979
T~ —
1980 '
Installa-
Denitrifica-
^™Desulfuri- Bag™""""^ j
tion work j tion device
! High Temperature
I ESP, GAH
DeNOx i
test
zation
device
filter
Integrated]
flue gas ;
treatment ;
test
DeHOx test (High/Low dust)
• Test to check the construc-
tion of the reactor
• Performance test
• Test to check pitch of honey-
comb mesh
• Development of low SO3
conversion ratio catalyst
• Measures to prevent plugging
of GAH
• Measures to prevent plugging
and wear of catalyst
Integrated flue gas
treatment test
• Life test of catalyst
(Low dust system, High
dust system)
I
• Desulfurizing test
I
Measures to prevent plug-
ging of GAH and GGH
• Long-term test to check
plugging of GAH and GGH
• Life test of bag filter
139
-------
SECTION 6
DISCUSSION OF TEST RESULTS
The results of this integrated flue gas treatment test can be sum-
marized as follows:
DENITRIFICATION EQUIPMENT
Life Test of Catalysts
Tests to determine the life of the catalyst are now in progress. Some
catalysts have passed 9,000 hours during low dust conditions and 7,000 hours
for high dust conditions. No significant deterioration was observed under
either of these conditions, and the catalysts have shown that a stable DeN0x
efficiency of greater than 80% is possible. These tests will be continued in
order to test their performance over a longer period.
Figures 3 and 4 on the following pages show the life test results of cata-
lyst at low and high dust conditions.
Plugging of Catalyst Layer
At the high dust conditions, no deposits or ash accumulation were
observed on the catalyst. While at the low dust conditions, the ash has a
smaller grain size and is more prone to sticking to the catalyst without the
benefit of having the larger particles perform a self-cleaning action.
As a result of this non-self-cleaning action, partial deposits or accumu-
lations of ash were observed in this case. It was shown, however, that the
plugging of the catalyst layer can be prevented by considering such factors
as the flue gas flowrate, mesh size of honeycomb catalysts, catalyst support
construction, and adoption of a catalyst layer using seamless catalyst in the
flow direction.
140
-------
Fig. 3 Results of test for the concentration of high dust
Place of test
Isogo Power Plant \
Catalyst
Square wesh honeycoab type catalyst
<*-111 typei
Concentration of duat
9/Hm3
12 ^ 20
c
Concentration of SOx
300 % 900
-H
fraction temperature
*C
JS0
•a
c
0
CJ
MH3/NOX
Mol ratio
0.9
SV value
h-1
3,300
(BO01 900pp« k(Ur Feb. 14, 1980)
Concentration of high SOx
(SO2, SO3 injected)
19B0
Month
of NH3
Work for
resodelling of bag
Installation of
|b«9
Overhauling inspection
ar.d •<
ra
ir vacation
60
Yeai-end and
new year vacations
50
4110H
-------
Fig. 4 Result* of test for the concentration of low dust
Place of test
Catalyst
;lsogo Power Plant
Square nesh honeycopto catalyst
(A-II type)
1
Condition ,
Concentration of dust
qy>J*3
0.1*0.2
Concentration of SO*
300 900
Reaction temperature
•c
350 -C
HHj/NOx
Mol ratio
0.9
SV value | h~*
2,eoo
(800 "V ?OOpp* *fter Feb . 14, 1980}
Concentration of high SO*
(SOj injected)
1980
197B
1979
Month
100
90
»-o-c
Installing
new bag
system
re node 1 ling
work
•0-
28 periodic
inspections
Year-end and i
year vacation
70
21 stop
60
SO
60
S 8, 40*
8340H
6400H
1960H
Change of catalyst
-------
Erosion of Catalyst
The most significant factor which affects the life of the catalyst in
coal-fired applications is the abrasive wear caused by the ash in the combus-
tion gas. However, these tests have shown that this wear can be effectively
controlled by designing for the following conditions: selecting an appropri-
ate flowrate for gas, choosing a catalyst having a high resistance to wear,
and eliminating the seams in the catalyst in the direction of gas flow. The
results of the test for the 7,000 hr catalyst life test showed no significant
wear during inspection when the above design considerations were taken.
During this series of testing, an accelerated wear test was conducted
over a relatively short period of time, where the flowrate of gas and the con-
centration of dust were extremely high when compared with those at normal
conditions.
The result of this test showed the abrasive wear of the catalyst to be
calculated as O.lmm/year, indicating that the catalyst can be used effectively
for several years at normal conditions. At low dust conditions, the concen-
tration is 1/100 of that under high dust conditions and the grain size is
smaller, thereby eliminating the concern about abrasive wear of the catalyst.
Development of Low SO3 Conversion Ratio Catalyst
The rate of conversion at which parts of SO2 contained in the gas are con-
verted into SO3 in the catalyst layer affects the equipment on the downstream
side through corrosion or plugging. However, it has been shown through
research that a catalyst having an extremely low conversion rate of SO2 to
SO3 of less than 1% can be manufactured.
PLUGGING OF GAS AIR HEATER (GAH) ELEMENTS
This plugging, caused by an NH3/SO3 based product consisting of
unreacted NH3 from the DeNOx process and SO3 contained in the flue gas, is
one of the problems that emanate from the operation of the DeNOx process.
However, this problem can be solved by considering the design of the heater
element, soot blowing design, and frequency of soot blowing.
143
-------
Where there is a high dust concentration in the flue gas, a large clean-
ing effect from the dust can be expected so that the GAH can be normally
operated by using the soot blower several times a day.
In the case of a low dust concentration flue gas, a cleaning effect from
the dust cannot be expected, thus creating a greater possibility for the
heater elements plugging. However, even for this low dust condition, plugging
of the elements can be prevented by designing the element shape to produce an
improved overall soot blowing effect. For example, according to the results
of a test conducted for over 3,000 hours, close inspection showed no signifi-
cant plugging of heater elements. This test is still in progress in order to
check whether it is possible to operate continuously over a long period of
time using these design improvements.
Additional test results showed no significant corrosion or decrease in
the wall thickness of the heater element for either the low or high dust
conditions.
Figure 5 shows the results of pressure loss testing for the GAH for both
high and low dust conditions.
DUST COLLECTOR
High Temperature Electrostatic Precipitator (Hot ESP)
Currently there are various opinions as to the efficiency of the hot ESP.
According to the results of these tests, the collection efficiency of a hot
ESP proved highly effective on dust in the flue gas from coal containing 0.6%
sulfur.
Wet Type Electrostatic Precipitator (Wet ESP)
At present, the concentration of dust at the outlet of a desulfurization
system has to be about 20 mg/NM^ in Japan. However, in order to meet more
strict requirements in the future, a wet ESP was installed on the outlet side
of the desulfurization device used for this testing. The next test series
showed the dust collection efficiency of wet ESP to be about 93%. These
results show that the concentration of dust at the outlet of the FGD unit can
be maintained under 10 mg/NM^ when this wet ESP is used, even if the scale
effect is taken into consideration.
144
-------
Pi9« 5 |Pressure loss in GAH
<0
A : M for high dust
O t M for low dust
Onlt stopped
Dec.24 - Jan.18
ContMiiution of «l«Mnt,
Inspected on Feb. 13, 1980
CI ass.
f tea
AN for high dust
AH for low dust
Consturction
of AH
High-te«f>erature ele-
ments DU
t - llSQrm
Lov-teaperature side
element: NF
I « liSOn
JNF-S ingle
High/low — [layer
1 - 1140m
Gas condition
IGas inlet:
280 * 300*C
tGas outlet:
MS*1SS*C
300 *320*C
145 % 1S5-C
S.B. catalyst
i^7,5K saturated
steaa
6^7,5* saturated
stea*
i A1 1
S.B. condition
iMt «u myiiika on Mm. >9. 1M0
A— A- ¦ A 'A A A A A A AA . a a
<«. for high dmO | ^
2B periodic
Hf wl>>i"
-A—
Mar 28 '80
A ^
U«il |
• tlM/iir ¦ ltal».A«lM( •( Ua
ilfk-u^paiKm aiflti
k«-tnftriUn illn «lw mm m it toft
U>-tMT«r«(«r« il«ii ) llM*/4*y i Wi./m
Iw-tMfaratun (14*t 4 tim/Or ¦ lM*./w*n •( Um
Hfh-tffv*(«t«ra aldii 4 tlMi/dtf e > ia./Hfen «( tim
• timm/4« ¦ hl«.^a*«r •( tlw
ii4ii ) tini/d*y i IMa./nurbtt »f tlm
sl4ti I tlHi/dtr i Wa./erter of (1m*
a periodic Uifietiw
T»at iMfuhlt « Iter. 19, 19*9
| Hay 28 '80
¦o—o
< Ml for low du*t >
* tmt thw ii*t I UBi/l*r ¦ •' «l«M
. »Idai « tir*»/4iy « SelB./wwteer »f tl*«
Stop »f S.B. «m
* ld#-tnir«t»rt tldt'
4 tlm/lajr i lMi./wrttr of tl«n
tldii |
« ¦ "—
• tlM/Mf ¦ ¦
Itm Qt W-./nij-tin of tlat* I •**•» • tlr»i/«ay « lOrj V/*u.-&«r «r tia
.1. o«" ¦ Soi of tia
fcifh-tMp*r«t«r4 lid* ' —"—
SOx: 300-v 400PPH
SOx: 800 -w 900PPM
1,000
1,500 2,000
Operating hours
3,000
-------
Bag Filter
A Sumitomo bag filter is used with the high dust DeNOx process as the
low temperature dust collector. This same bag filter was used successfully
in a joint development project by Electric Power Development Co., Ltd.,
Sumitomo Heavy Industry Co., Ltd., and IHI. The results of this test con-
firmed the expected efficiency of the bag filter, as it succeeded in main-
taining the concentration of dust below 10 mg/NM^ with a pressure drop of
150 mm W.G. for the case where the flue gas had passed through the DeN0x
process. A long-term test to determine the life span of the bag filter
material is now in progress.
FGD PROCESS
Desulfurization Efficiency
When a boiler is fired with several kinds of coal, the SO2 concentration
of the flue gas may vary over a wide range.
In this test it was shown that a satisfactory desulfurization effici-
ciency of over 96% can be obtained for SO2 concentrations ranging from 300
to 1,000 ppm at the inlet.
Dust Removing Efficiency
When an FGD unit is installed as shown in Figure 1, the dust at the
inlet is affected by the unreacted ammonium from the DeN0x process, dust
contained in the flue gas, and other various gases such as fluorine, chlor-
ine, etc.
According to the results of this series of tests, the effects of such
dust and gases are relatively small. For instance, the concentration of
3
dust at the outlet of the FGD system is less than 20/NM , thus showing that
this FGD system has sufficient dust removing capability.
Quality of Gypsum from the FGD Process
In the case of coal-fired boilers, traces of various impurities con-
tained in the coal accumulate in the circulating scrubbing liquid of the FGD
system after a period of time. This test showed that some of these impuri-
ties affect the gypsum crystallization and also control of pH in the scrub-
bing liquid. However, it was also shown that such problems can be solved
146
-------
and that gypsum of the desired quality can be obtained by taking appropriate
measures such as injection of an additive. Furthermore, it was confirmed
that an NH3/SO3 based product coming from the upstream side of the desul-
furizing system does not significantly affect the quality of gypsum and that
to obtain gypsum of high quality, the ash-separation method is more effective
than the ash-mixed method.
Plugging of GGH Element
The GGH element is subject to plugging by mist deposits from the FGD
process; but by operating the soot blower more frequently, this problem is
not severe. During these tests, no significant corrosion or decrease in the
thickness of the element wall was noticed.
FGD Booster Fan
SUS material is used for the blades, and a rubber lined casing.is used
for corrosion protection. The booster fan has provided adequate and stable
performance during these tests.
Waste Water Treatment System
Traces of various substances such as heavy metals, fluorine, chlorine,
etc., contained in the coal and unreacted ammonium from the DeNOx process
will accumulate in the circulating scrubbing liquid of the FGD system.
Normally this liquid is blown down to protect the materials of construction
from corrosion. This waste water stream is normally sent to an integrated
waste water treatment system. A research program is now being conducted to
develop a more economical waste water treatment system for FGD applications.
147
-------
SECTION 7
EVALUATION OF TEST RESULTS AND CONSIDERATIONS FOR COMMERCIAL PLANTS
Evaluation
Item
Evaluation of Test Results
High Dust Denitrifying Process
Low Dust Denitrifying Process
Considerations for
Conmerclal Plants
Process
Boiler
DeN^
GAH [
DeSOx
Boiler
Hot ESP
DeNO*
GAH
DeSOx
»
P
filter
—»
i
*
In setting up the planning for
actual plants, It 1s an important
point to determine the process
arrangement which depends on
whether a low temperature or a
high temperature dust collecting
method is selected. The selec-
tion of the method largely
affects the economy and general
arrangement of the system and
can be determined by considering
the kind of coal used.
Denltriflcation
J ! Function
¦P-
oo
This process will not cause any serious plug-
ging of the catalyst layer or the GAD and is
useful from the viewpoint of the denltriflca-
tion function.
As for wear, partial erosion was observed
where there was a drift in the gas flow, but
such phenomenon can be prevented by correct-
ing the gas flow on the upstream side of the
catalyst layer.
In this process, the catalyst layer,
especially the element of the GAH, Is sub-
ject to more plugging conpared with the
high dust process, but this process has
proved its effect in the DeNOx function if
proper consideration is given to the con-
struction of the catalyst layer and the
form of the GAH element and if soot blow-
Is used appropriately.
When applied to the actual sys-
tem, unlike the case of the test
plant, considerable changes will
be expected in the gas flow,
causing partial erosion of the
| catalyst at the upstream side.
To minimize the erosion
effect, the method of regulat-
the gas flow oust be considered
carefully.
To solve the plugging problem
that occurred in the low dust AH,
It is necessary not only to
select an appropriate value for
the space velocity but also to
follow the instructions given in
the column at the left. Also, it
is desirable to apply a close
control on the NH3/H0X mol ratio
to restrict unreacted NH3 for
partial load and to adopt a
low conversion ratio for SO3
for the catalyst.
-------
SECTION 7 (cont'd.)
EVALUATION OF TEST RESULTS AND CONSIDERATIONS FOR COMMERCIAL PLANTS (cont'd.)
loci
Evaluation of Test Results
Considerations for
Item
High Dust Denitrifying Process
Low Dust Denitrifying Process
Comnerclal Plants
Adaptability
r
1 Dust Collecting
Function
• Unlike the low dust denltrlflcatlon
method, the Nl^-SOj-based products from
the GAH and ash containing NH3 are col-
lected almost completely by the dust
collector installed on the downstream
side. Therefore, the method of treating
NH3 ash becomes one of the problems to be
considered. Thus, IHI Is now conducting
research on this problem In parallel with
research on the effective use of NH3 ash.
• A high temperature electrostatic precipi-
tator is installed on the upatream side
of the denltrlflcatlon equipment, thereby
freeing it from the effect of NH3. This
hot ESP Is designed according to princi-
ples of conventional hot ESP design and
performs well for a wide variety of coal
and will not adversely affect the down-
stream side of the system. Since it does
not contain NH3, ash treatment Is conven-
tional.
• When using an ESP as the low temp-
erature dust collector, its effi-
ciency should be considered with
the integrated system's dust col-
lecting efficiency, including the
dust removing efficiency of the
wet type desulfurization equipment.
Desulfurization
Function
• Tests on the desulfurization function in
conjunction with the high dust denltrlfi-
cation process have not been conducted
yet; however, the NH3-S03~based product
and mist produced in GAH are collected
almost completely by the dust collector
on the downstream side of this process.
Therefore, this process is more advantag-
eous than the low dust denltrlflcatlon
process as far as the treatment of waste
water and the removal of dust are con-
cerned. Future testing will check treat-
ment of waste water, integrated dust col-
lecting efficiency, the requirement for a
wet ESP, and the effect on the bag filter
caused by the NH3-S03-based product.
• When comparing the Integrated flue gas
treatment system with a conventional
desulfurlzing system without a DeNOx sec-
tion, the problem of an NH3-S03~based
product arises from unreacted NH3 enter-
ing the desulfurlzing system and accumu-
lating in the circulating liquid. This
problem Is solved by removing the amonium
through the waste water teatment system.
Testing has shown that this process has
an excellent desulfurlzing efficiency and
dust removing capability.
• The desulfurization process is con-
ventional, but it is necessary to
develop more economical techniques
to treat chemical oxygen demand
and to eliminate formation nitro-
gen from unreacted NH3.
-------
SECTION 8
CONCLUSION
This paper is a summary of the results of testing an integrated flue
gas treatment system for a coal-fired boiler. Through these tests and associ-
ated research, it has been shown that the denitrification, dust collecting,
and desulfurizing processes which have been tested are effective and that
they can be incorporated into a full-scale integrated flue gas treatment
system. These tests have provided the confidence that both the high and
low dust DeNOx systems tested will be put into commercial use in the near
future.
This test and research program will be continued in order to develop a
more reliable integrated flue gas treatment system.
150
-------
SECTION 9
APPENDIX
The Appendix Figures A-l, A-2, A-3, and A-4 show photographs of the
denitrification, bag filter, and desulfurization test equipment, respectively.
151
-------
Figure A-l Denitrification Test Equipment
FUJICOLOR CO 00
Figure A-2 Bag Filter
152
-------
Figure A-3 Desulfurization Test Equipment
Figure A-4 Desulfurization Test Equipment
153
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing/
1. REPORT MO. 2
3. RECIPIENT'S ACCESSIONNO.
4 TITLE AND SUBTITLE
Proceedings of the Joint Symposium on Stationary
Combustion NOx Control. Vol. 2. Utility Boiler NOx
Control by Flue Gas Treatment
5. REPORT DATE
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(S)
Symposium Cochairmen: Robert E. Hall (EPA) and
J.E. Cichanowicz (EPRI)
8. PERFORMING ORGANIZATION REPORT NO.
IERL-RTP-1084
9 PERFORMING ORGANIZATION NAME AND ADDRESS
See Block 12.
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
NA (Inhouse)
12 SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Proceedings; 10/6-9/80
14. SPONSORING AGENCY CODE
EPA/600/13
16. supplementary notes EPA-600/7-79-050a through -050e describe the previous sympo-
sium.
is abstract procee(jings document the approximately 50 presentations made during
the symposium, October 6-9, 1980, in Denver, CO. The symposium was sponsored
by the Combustion Research Branch of EPA's Industrial Environmental Research
Laboratory, Research Triangle Park, NC, and the Electric Power Research Institute
(EPRI), Palo Alto, CA. Main topics included utility boiler field tests; NOx flue gas
treatment; advanced combustion processes; environmental assessments; industrial,
commercial, and residential combustion sources; and fundamental combustion re-
search. This volume relates to the treatment of flue gases from utility boilers to
control NOx emissions.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATi Field/Group
Pollution Flue Gases
Combustion Engines
Nitrogen Oxides
Boilers
Tests
Assessments
Pollution Control
Stationary Sources
Environmental Assess-
ment
13B
2IB 2 IK
07B
13A
14B
IS DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
157
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (»-73) }54
------- |