EPRI
Electric Power
Research Institute
Keywords:
Nitrogen oxides
Combustion control
Denitrification
Flue gas treatment
Fossil fuel boilers
EPRI GS-7447
Volume 2
Project 2154
Proceedings
November 1991
Proceedings: 1991 Joint
Symposium on Stationary
Combustion NOX Control
Volume 2
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REPORT SUMMARY
Proceedings: 1991 Joint Symposium on Stationary
Combustion NOX Control
Volumes 1 and 2
Proceedings of this 1991 symposium, sixth in a biennial series on NOX
control, provide an overview of current NOX control activities. The 66
presentations in these two volumes contribute significantly to the
development of cost-effective and reliable control systems for fossil-
fuel-fired power plants.
INTEREST CATEGORY
Fossil plant air quality
control
KEYWORDS
Nitrogen oxides
Combustion control
Denitrification
Flue gas treatment
Fossil fuel boilers
OBJECTIVE To foster an international exchange of information on developments
in NOX control technologies for stationary combustion processes.
APPROACH EPA and EPRI cosponsored the sixth joint NOX control symposium,
held March 25-28, 1991, in Washington, D.C. Approximately 500 representatives of
electric utilities, equipment vendors, R&D groups, and government agencies heard
66 speakers report on control of NOX emissions from stationary combustion
processes. Reports focused on developments since the 1989 symposium that per-
tain to electric utility power plants and other stationary combustion sources. They
described progress in combustion technologies, selective catalytic reduction
(SCR), and selective noncatalytic reduction (SNCR).
KEY POINTS
• R&D in the United States to reduce NOX emissions from conventional pulverized-
coal-fired boilers is oriented mainly toward retrofit combustion modifications. Low
NOX burners (LNBs) with or without the addition of overfire air (OFA) continue to
be the preferred approach, both economically and technically, for tangentially fired
and wall-fired units. Reburning remains the only widely discussed option for
cyclone boilers.
• Demonstrations of full-scale retrofit LNB and LNB/OFA systems have increased
considerably in the past two years. The trend in these demonstrations is toward
increasing staging of air and fuel. With controls, emission levels (short-term mea-
surements) for tangentially fired boilers are commonly 0.30 to 0.50 Ib/MBtu, and
those for wall-fired boilers range from 0.45 to 0.60 Ib/MBtu. Continuously achiev-
able levels would be higher.
• Many presentations suggested that the maximum NOX reduction achievable with-
out significantly affecting boiler operations depends on fuel characteristics, specifi-
cally on reactivity, nitrogen content, and fineness. A number of speakers reported
increases in unburned carbon (UBC) in fly ash when using combustion modifica-
tion techniques to control NOX. The increase depends on the above properties and
the amount of staging. Except for high-reactivity coals, UBC increases ranged
from 2 to 5%.
• SNCR technologies using NH3 or aqueous urea are receiving increased attention
in the United States and Europe. Full-scale tests indicate that NOX emission reduc-
tions up to 50% are possible with NH3 slip below 5 to 10 ppm. Optimization of
EPRI GS-7447S Vols. 1 and 2
Electric Power Research Institute
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reagent mixing at 1700 to 1900°F and accurate temperature measure-
ments are critical in obtaining these results.
• Experience with SCR reported by one utility in Germany indicates no
significant catalyst activity decrease, attainment of design NOX reduction
levels (75 to 80%), and control over NH3 slip, usually to less than 1 ppm.
• Retrofit capital costs for SCR on a conventional coal-fired boiler in the
United States are estimated at approximately $100/kW. Operating costs
are estimated at 5 to 7 mills/kWh and are dominated by catalyst replace-
ment costs.
PROJECT
RP2154
Project Manager: Angelos Kokkinos
Generation and Storage Division
For further information on EPRI research programs, call
EPRI Technical Information Specialists (415) 855-2411.
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DISCLAIMER OF WARRANTIES AND
LIMITATION OF LIABILITIES
THIS REPORT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN
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ELECTRIC POWER RESEARCH INSTITUTE
Printed on Recycled Paper
Proceedings: 1991 Joint
Symposium on Stationary
Combustion NOX Control
Volume 2
GS-7447, Volume 2
Proceedings, November 1991
March 25-28, 1991
Washington, D.C.
Symposium Cochairpersons
A. Kokkinos
ELECTRIC POWER RESEARCH INSTITUTE
R. Hall
U.S. ENVIRONMENTAL PROTECTION AGENCY
Prepared for
U.S. Environmental Protection Agency
Air and Energy Research Laboratory
Combustion Research Branch
Research Triangle Park, North Carolina 27711
EPA Branch Chief
R. Hall
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, California 94304
EPRI Project Manager
A. Kokkinos
Air Quality Control Program
Generation and Storage Division
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Electric Power Research Institute and EPRI are registered service marks of Electric Power Research Institute, Inc
Copyright -" 1991 Electric Power Research Institute, Inc All rights reserved
ORDERING INFORMATION
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(RRC), Box 50490, Palo Alto, CA 94303, (415) 965-4081. There is no charge for reports
requested by EPRI member utilities and affiliates, U.S. utility associations, U.S. government
agencies (federal, state, and local), media, and foreign organizations with which EPRI has
an information exchange agreement On request, RRC will send a catalog of EPRI reports.
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ABSTRACT
The 1991 Joint Symposium on Stationary Combustion NOX Control was held in Washington, D.C.,
March 25-28, 1991. Jointly sponsored by EPRI and EPA, the symposium was the sixth in a biennial
series devoted to the international exchange of information on recent technological and regulatory
developments for stationary combustion NOX control. Topics covered included the significant
increase in active full-scale retrofit demonstrations of low-NOx combustion systems in the United
States and abroad over the past two years; full-scale operating experience in Europe with selective
catalytic reduction (SCR); pilot- and bench-scale SCR investigations in the United States; increased
attention on selective noncatalytic reduction in the United States; and NOX controls for oil- and gas-
fired boilers. The symposium proceedings are published in two volumes.
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PREFACE
The 1991 Joint Symposium on Stationary Combustion NOX Control was held March 25-28, 1991, in
Washington, D.C. Jointly sponsored by EPRI and EPA, the symposium was the sixth in a biennial
series devoted to the international exchange of information regarding recent technological and
regulatory developments pertaining to stationary combustion NOX control. Topics discussed
included the significant increase in active full-scale retrofit demonstrations of Iow-N0x combustion
systems in the United States and abroad over the past two years; full-scale operating experience in
Europe with selective catalytic reduction (SCR); pilot-and bench-scale SCR investigations in the
United States; increased attention on selective noncatalytic reduction in the United States; and NOX
controls for oil- and gas-fired boilers.
The four-day meeting was attended by approximately 500 individuals from 14 nations. Sixty-six
papers were presented by EPRI and EPA staff members, domestic and foreign utility companies,
federal and state government agencies, research and development organizations, equipment
vendors from the United States and abroad, and university representatives.
Angelos Kokkinos, project manager in EPRI's Generation & Storage Division, and Robert Hall,
branch chief, Air & Energy Engineering Research Laboratory, EPA, cochaired the symposium. Each
made brief introductory remarks. Michael R. Deland, Chairman of the President's Council on
Environmental Quality, was the keynote speaker. Written manuscripts were not prepared for the
introductory remarks or keynote address and are therefore not published herein.
The Proceedings of the 1991 Joint Symposium have been compiled in two volumes. Volume 1
contains papers from the following sessions:
• Session 1: Background
• Session 2: Large Scale Coal Combustion I
• Session 3: Large Scale Coal Combustion II
• Session 4A: Combustion NOX Developments I
• Session 4B: Large Scale SCR Applications
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Papers from the following sessions are contained in Volume 2:
• Session 5A: Post Combustion Developments I
• Session 5B: Industrial/Combustion Turbines on NOX Control
• Session 6A: Post Combustion Developments II
• Session 6B: Combustion NOX Developments II
• Session 7A: New Developments I
• Session 7B: New Developments II
• Session 8: Oil/Gas Combustion Applications
An appendix listing the symposium attendees is included in both volumes.
VI
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CONTENTS
Paper Page
SESSION 1: BACKGROUND
Chair: I. Torrens, EPRI
"NOX Emissions Reduction in the former German Democratic Republic," B. Kassebohm
and S. Streng 1 -1
"'Top-Down' BACT Analysis and Recent Permit Determinations," J. Cochran and M. Pagan 1-15
"Retrofit Costs and Performance of NOX Controls at 200 U.S. Coal-Fired Power Plants,"
T. Emmel and M. Maibodi 1 -27
"Nitrogen Oxides Emission Reduction Project," L. Johnson 1-47
"The Global Atmospheric Budget of Nitrous Oxide," J. Levine 1 -65
SESSION 2: LARGE SCALE COAL COMBUSTION I
Chair: B. Martin, EPA and G. Often, EPRI
"Development and Evolution of the ABB Combustion Engineering Low NOX Concentric
Firing System," J. Grusha and M. McCartney 2-1
"Performance of a Large Cell-Burner Utility Boiler Retrofitted with Foster Wheeler
Low-N0x Burners," T. Lu, R. Lungren, and A. Kokkinos 2-19
"Design and Application Results of a New European Low-N0x Burner," J. Pedersen and
M. Berg 2-37
"Application of Gas Reburning-Sorbent Injection Technology for Control of
NOX and SO2 Emissions," W. Bartok, B. Folsom, T. Sommer, J. Opatrny, E. Mecchia,
R. Keen, T. May, and M. Krueger 2-55
"Retrofitting of the Italian Electricity Board's Thermal Power Boilers," R. Tarli, A. Benanti,
G. De Michele, A. Piantanida, and A. Zennaro 2-75
"Retrofit Experience Using LNCFS on 350MW and 165MW Coal Fired Tangential Boilers,"
T. Hunt, R. Hawley, R. Booth, and B. Breen 2-89
"Update 91 on Design and Application of Low NOX Combustion Technologies for Coal
Fired Utility Boilers," T. Uemura, S. Morita, T. Jimbo, K. Hodozuka, and H. Kuroda 2-109
VII
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Paper Page
SESSION 3: LARGE SCALE COAL COMBUSTION II
Chair: D. Eskinazi, EPRI and R. Hall, EPA
"Demonstration of Low NOX Combustion Control Technologies on a 500 MWe Coal-Fired
Utility Boiler," S. Wilson, J. Sorge, L Smith, and L. Larsen 3-1
"Reburn Technology for NOX Control on a Cyclone-Fired Boiler," R. Borio, R. Lewis, and
M. Keough 3'23
"Full Scale Retrofit of a Low NOX Axial Swirl Burner to a 660 MW Utility Boiler, and the
Effect of Coal Quality on Low NOX Burner Performance," J. King and J. Macphai! 3-51
"Update on Coal Reburning Technology for Reducing NOX in Cyclone Boilers," A. Yagiela,
G. Maringo, R. Newell, and H. Farzan 3-74
"Demonstration of Low NOX Combustion Techniques at the Coal/Gas-Fired Maas Power
Station Unit 5," J. van der Kooij, H. Kwee, A. Spaans, J. Puts, and J. Witkamp 3-99
"Three-Stage Combustion (Reburning) on a Full Scale Operating Boiler in the U.S.S.R.,"
R. LaFlesh, R. Lewis, D. Anderson, R. Hall, and V. Kotler 3-123
SESSION 4A: COMBUSTION NOX DEVELOPMENTS I
Chair: W. Linak and D. Drehmel, EPA
"An Advanced Low-N0x Combustion System for Gas and Oil Firing," R. Lisauskas
and C. Penterson 4A-1
"NOX Reduction and Control Using an Expert System Advisor," G. Trivett 4A-13
"An R&D Evaluation of Low-N0x Oil/Gas Burners for Salem Harbor and Brayton Point
Units," R. Afonso, N. Molino, and J. Marshall 4A-31
"Development of an Ultra-Low NOX Pulverizer Coal Burner," J. Vatsky and T. Sweeney 4A-53
"Reduction of Nitrogen Oxides Emissions by Combustion Process Modification in
Natural Gas and Fuel Oil Flames: Fundamentals of Low NOX Burner Design," M. Toqan,
L. Berg, J. Beer, A. Marotta, A. Beretta, and A. Testa 4A-79
"Development of Low NOX Gas Burners," S. Yang, J. Pohl, S. Bortz, R. Yang, and W. Chang 4A-105
SESSION 4B: LARGE SCALE SCR APPLICATIONS
Chair: E. Cichanowicz, EPRI
"Understanding the German and Japanese Coal-Fired SCR Experience," P. Lowe,
W. Ellison, and M. Perlsweig 4B-1
"Operating Experience with Tail-End and High-Dust DENOX-Technics at the Power Plant
of Heilbronn," H. Maier and P. Dahl 4B-17
VIII
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Paper Page
"SO3 Generation-Jeopardizing Catalyst Operation?," R. Jaerschky, A. Merz, and J. Mylonas 4B-39
"SCR Operating Experience on Coal-Fired Boilers and Recent Progress," E. Behrens,
S. Ikeda, T. Yamashita, G. Mittelbach, and M. Yanai 4B-57
'Technical Feasibility and Cost of SCR for U.S. Utility Application," C. Robie, P Ireland,
and J. Cichanowicz 4B-79
"Application of Composite NOX SCR Catalysts in Commercial Systems," B. Speronello,
J. Chen, M. Durilla, and R. Heck 4B-101
"SCR Catalyst Developments for the U.S. Market," T. Gouker and C. Brundrett 4B-117
"Poisoning Mechanisms in Existing SCR Catalytic Converters and Development of a New
Generation for Improvement of the Catalytic Properties," L Balling, R. Sigling, H. Schmelz,
E. Hums, G. Spitznagel 4B-133
SESSION 5A: POST COMBUSTION DEVELOPMENTS I
Chair: C. Sedman, EPA
"Status of 1 MW SCR Pilot Plant Tests at Tennessee Valley Authority and New York State
Electric & Gas," H. Flora, J. Barkley, G. Janik, B. Marker, and J. Cichanowicz 5A-1
"Pilot Plant Investigation of the Technology of Selective Catalytic Reduction of Nitrogen
Oxides," S. Tseng and C. Sedman 5A-17
"Poisoning of SCR Catalysts," J. Chen, R. Yang, and J. Cichanowicz 5A-35
"Evaluation of SCR Air Heater for NOX Control on a Full-Scale Gas- and Oil-Fired Boiler,"
J. Reese, M. Mansour, H. Mueller-Odenwald, L. Johnson, L. Radak, and D. Rundstrom 5A-51
"N20 Formation in Selective Non-Catalytic NOX Reduction Processes," L. Muzio,
T. Montgomery, G. Quartucy, J. Cole, and J. Kramlich 5A-71
"Tailoring Ammonia-Based SNCR for Installation on Power Station Boilers," R. Irons,
H. Price, and R. Squires 5A-97
SESSION 5B: INDUSTRIAL/COMBUSTION TURBINES ON NOX CONTROL
Chair: S. Wilson, Southern Company Services
"Combustion Nox Controls for Combustion Turbines," H. Schreiber 5B-1
"Environmental and Economic Evaluation of Gas Turbine SCR NOX Control," P. May,
L. Campbell, and K. Johnson 5B-17
"NOX Reduction at the Argus Plant Using the NOxOUT* Process," J. Comparato, R. Buchs,
D. Arnold, and L Bailey 5B-37
IX
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Paper page
"Reburning Applied to Cogeneration NOX Control," C. Castaldini, C. Moyer, R. Brown,
J. Nicholson 5B-55
"Selective Non-Catalytic Reduction (SNCR) Performance on Three California Waste-to-
Energy Facilities," B. McDonald, G. Fields, and M. McDannel 5B-71
"Use of Natural Gas for NOX Control in Municipal Waste Combustion," H. Abbasi,
R. Biljetina, F. Zone, R. Lisauskas, R. Dunnette, K. Nakazato, P Duggan, and D. Linz 5B-89
SESSION 6A: POST COMBUSTION DEVELOPMENTS II
Chair: D. Drehmel, EPA
"Performance of Urea NOX Reduction Systems on Utility Boilers," A. Abele, Y. Kwan,
M. Mansour, N. Kertamus, L Radak, and J. Nylander 6A-1
"Widening the Urea Temperature Window," D. Teixeira, L. Muzio, T. Montgomery,
G. Quartucy, and T. Martz 6A-21
"Catalytic Fabric Filtration for Simultaneous NOX and Particulate Control," G. Weber,
D. Laudal, P. Aubourg, and M. Kalinowski 6A-43
SESSION 6B: COMBUSTION NOX DEVELOPMENTS II
Chair: R. Hall, EPA
"Heterogeneous Decomposition of Nitrous Oxide in the Operating Temperature Range of
Circulating Fluidized Bed Combustors," T. Khan, Y.Lee, and L Young 6B-1
"NOX Control in a Slagging Combustor for a Direct Coal-Fired Utility Gas Turbine,"
P. Loftus, R. Diehl, R. Bannister, and P. Pillsbury 6B-13
"Low NOX Coal Burner Development and Application," J. Allen 6B-31
SESSION 7A: NEW DEVELOPMENTS I
Chair: G. Veerkamp, Pacific Gas & Electric
"Preliminary Test Results: High Energy Urea Injection DeNOx on a 215 MW Utility Boiler,"
D. Jones, S. Negrea, B. Dutton, L. Johnson, J. Sutherland, J. Tormey, and R. Smith 7A-1
"Evaluation of the ADA Continuous Ammonia Slip Monitor," M. Durham, R. Schlager,
M. Burkhardt, F. Sagan, and G. Anderson 7A-15
"Ontario Hydro's SONOX Process for Controlling Acid Gas Emissions," R. Mangal,
M. Mozes, P. Feldman, and K. Kumar 7A-35
"Pilot Plant Test for the NOXSO Flue Gas Treatment System," L. Neal, W. Ma, and R. Bolli 7A-61
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Paper Page
'The Practical Application of Tunable Diode Laser Infrared Spectroscopy to the Monitoring
of Nitrous Oxide and Other Combustion Process Stream Gases," F. Briden, D. Natschke,
and R. Snoddy 7A-79
SESSION 7B: NEW DEVELOPMENTS II
Chair: C. Miller, EPA
"In-Furnace Low NOX Solutions for Wall Fired Boilers," R. LaFlesh, D. Hart, P. Jennings, and
M. Darroch 7B-1
"NOX Reduction on Natural Gas-Fired Boilers Using Fuel Injection Recirculation (FIR)
Laboratory Demonstration," K. Hopkins, D. Czerniak, L Radak, C. Youssef, and J. Nylander 7B-13
"Advanced Reburning for NOX Control in Coal Fired Boilers," S. Chen, W. Seeker, and
R.Payne 7B-33
"Large Scale Trials and Development of Fuel Staging in a 160 MW Coal Fired Boiler,"
H. Spliethoff and R. Dolezal 7B-43
"Computer Modeling of N2O Production by Combustion Systems," R. Lyon, J. Cole,
J. Kramlich, and Wm. Lanier 7B-63
SESSION 8: OIL/GAS COMBUSTION APPLICATIONS
Chair: A. Kokkinos, EPRI
"Low NOX Levels Achieved by Improved Combustion Modification on Two 480 MW Gas-
Fired Boilers," M. McDannel, S. Haythornthwaite, M. Escarcega, and B. Gilman 8-1
"NOX Reduction and Operational Performance of Two Full-Scale Utility Gas/Oil Burner
Retrofit Installations," N. Bayard de Volo, L. Larsen, L Radak, R. Aichner, and A. Kokkinos 8-21
"Comparative Assessment of NOX Reduction Techniques for Gas- and Oil-Fired Utility
Boilers," G. Bisonett and M. McElroy 8-43
"Analysis of Minimum Cost Control Approach to Achieve Varying Levels of NOX Emission
Reduction from the Consolidated Edison Co. of NY Power Generation Systems," D. Mormile,
J. Pirkey, N. Bayard de Volo, L. Larsen, B. Piper, and M. Hooper 8-63
"Reduced NOX, Paniculate, and Opacity on the Kahe Unit 6 Low-N0x Burner System,"
S. Kerho, D. Giovanni, J. Yee, and D. Eskinazi 8-85
"Demonstration of Advanced Low-NOx Combustion Techniques at the Gas/Oil-Fired Flevo
Power Station Unit 1," J. Witkamp, J. van der Kooij, G. Koster, and J. Sijbring 8-107
APPENDIX A: LIST OF ATTENDEES A-1
XI
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Session 5A
POST COMBUSTION DEVELOPMENTS I
Chair: C. Sedman, EPA
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STATUS OF 1 MW SCR PILOT PLANT TESTS AT
TENNESSEE VALLEY AUTHORITY AND
NEW YORK STATE ELECTRIC & GAS
H. Flora and J. Barkley
Tennessee Valley Authority
G. Janik and B. Marker
New York State Electric & Gas
J. E. Cichanowicz
Electric Power Research Institute
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STATUS OF 1 MW SCR PILOT PLANT TESTS AT
TENNESSEE VALLEY AUTHORITY AND
NEW YORK STATE ELECTRIC & GAS
H. Flora and J. Barkley
Tennessee Valley Authority
G. Janik and B. Marker
New York State Electric & Gas
J. E. Cichanowicz
Electric Power Research Institute
ABSTRACT
EPRI and member utilities are sponsoring a pilot plant test program to evaluate
SCR NOX control for potential application by the U.S. utility industry. This
program will employ up to six SCR pilot plants of nominally I MW capacity, and
focus on evaluating catalyst life and process performance for medium and high
sulfur coal application. The first pilot plant in operation is located at TVA's
Shawnee Test Facility, operating on high sulfur content (3-4%) coal. Initial results
from baseline tests show catalyst performance for NOX removal and control of
residual NH3 after 4 months operation meets the design values estimated by the
catalyst suppliers. A two year test program including periodic extraction and
analysis of catalyst samples is planned for all pilot plants to track any changes in
catalyst performance and activity. The results will provide a basis for estimating
catalyst life and process feasibility for U.S. conditions.
INTRODUCTION
In recent decades, environmental agencies in Japan and Europe have implemented
regulations to significantly reduce NOX emissions. Generally, these reductions
necessitate control of NOX to limits beyond the capabilities of combustion controls.
For example, since the 1970s, allowable NOX emissions for coal-fired power stations
in Japan have been as low as 150 ppm. Several western European nations in the
1980s implemented NOX regulations for coal-firing to approximately 100 ppm.
This international trend in NOX regulations raises the prospects for increasingly
stringent requirements in the U.S. Without major improvements in the NOx
control performance of combustion technology, postcombustion control may be
required to meet the most strict NOX regulations.
The most widely commercialized postcombustion technology to date is selective
catalytic reduction (SCR). Considerable experience with SCR exists in Europe with
low sulfur coal; and in Japan with low sulfur coal, oil, and natural gas. In contrast,
there is no meaningful experience with SCR for medium/high sulfur U.S. fuels in
combination with furnaces of heat release characteristics that typify U.S.
applications. Recent results from a fundamental investigation of SCR catalyst
poisoning (1) suggests that sulfur, in combination with certain trace elements in
5A-1
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coal (such as alkali) can contribute to catalyst poisoning. Accordingly, meaningful
pilot plant experience is desirable prior to full-scale SCR application.
To provide this experience, EPRI and member utilities plan to operate up to six
SCR pilot plants on medium and high sulfur fuels on U.S. power plants. The
proposed pilot plants will provide the basis for realistic estimates of catalyst life and
SCR process impacts. A companion paper at this Symposium (2) has identified the
significant impacts of SCR on balance of plant equipment, and documented the
influence of catalyst life on SCR levelized costs. Data from this pilot plant program
will be used by EPRI to refine engineering study results estimating the feasibility
and cost of SCR for the U.S. utility industry. This paper describes the pilot plant
design and test plans for the first two units scheduled for operation, at the TVA
Shawnee Steam Station, and the New York State Electric & Gas (NYSEG) Somerset
Station. Initial results from the TVA pilot plant are summarized.
PROGRAM SCOPE AND OBJECTIVE
This empirical test program will address both the conventional "hot-side" SCR
process (reactor located between the boiler economizer and air heater) and the
alternative "post-FGD" SCR application. The test objective is to provide realistic
information for key SCR design variables such as space velocity (e.g. catalyst
quantity), the level of residual ammonia that can be tolerated, byproduct SO3
formation, catalyst lifetime, and the formation of byproduct ammonium/sulfur
compounds. This information will reflect authentic U.S. utility operating
conditions, as defined by fuel properties and furnace design characteristics. A
generic pilot plant design was defined for all six planned sites, thus the only
changes between sites will be fuel properties, furnace design, and operating modes.
For the "hot-side" application, tests will focus on the quantity and lifetime of
catalyst necessary to maintain control of residual NH3 while delivering required
NOX removal, and generation of byproduct SO3- For the post-FGD process, tests
will similarly evaluate the catalyst quantity and lifetime necessary for control of
NOX and residual NH3, and generation of acidic compounds; but also evaluate the
thermal performance of the heat exchanger necessary to elevate flue gas
temperatures to reaction levels.
A fundamental premise of this program is that fuel composition and furnace
design uniquely determine catalyst life, by defining the conditions for transport of
trace species to the catalyst surface. Transport conditions are defined by both the
composition and concentration of trace species in flue gas, particularly the amount
of trace elements volatilized; thus both fuel composition and furnace
temperature/time history are important. A total of six pilot plants will be
employed to simulate the wide range of transport conditions typifying the U.S.
utility industry. Table 1 summarizes the fuel characteristics and furnace types at
four pilot plant sites that are either operating in a test mode, are in startup, or are
in a design/planning stage. High sulfur coal SCR testing on a pre-NSPS
conventional boiler (e.g. tangential- or wall-fired) is underway at TVA's Shawnee
Steam Station. The post-FGD SCR application on a medium sulfur coal is being
evaluated at the Somerset Station of NYSEG. SCR application to high sulfur
content (-1% sulfur) fuel oil will be conducted at Niagara Mohawk's Oswego
Station. Also planned is an SCR pilot reactor followed by an air heater on a high
5A-2
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sulfur coal-fired, cyclone type boiler, presently designated for the Coffeen Station of
Central Illinois Public Service. Two additional pilot plants are planned, although
specific utilities and fuel types have not yet been identified.
A unique feature of this program is a cooperative venture with catalyst suppliers to
assess deactivation mechanisms and estimate catalyst life based on the pilot plant
results. Each pilot plant will be capable of evaluating two catalysts, at identical
process conditions. Catalyst suppliers will extract samples at approximately 3 or 4
month intervals for analysis in their laboratories. Measurements will both
document catalyst activity (as inferred from NO removal) and the accumulation on
the catalyst surface of trace species suspected to be poisons. Results over a two year
period will provide a factual basis for estimating catalyst lifetime.
Data from these pilot plants will be supplemented by results from the evaluation of
SCR conducted by Southern Company Services (SCS) under the Department of
Energy's Clean Coal Technology program. The SCS program, which EPRI is
cofunding, will also be conducted for a nominal 3% sulfur coal, on a pre-NSPS
conventional boiler, similar to the fuel/furnace conditions reflected by the TV A
Shawnee Station. The objectives of these two activities are complementary—the
SCS program will evaluate a large number of different catalysts at relatively fixed
fuel composition and furnace design; in contrast the EPRI program will evaluate a
limited number of similar catalysts over a wide range of fuel composition and
furnace designs.
PROGRAM STATUS
The TVA 1 MW pilot plant at the Shawnee Steam Station has been operating for
almost four months; baseline tests are 60% complete. The TVA pilot plant is
evaluating catalysts supplied by Joy Environmental Equipment Company and
Norton Company. The NYSEG pilot plant, evaluating the post-FGD SCR
application, is initiating startup/shakedown tests at this writing. Catalysts will be
supplied by W.R. Grace Co. and Englehard Industries. The pilot plant at Niagara
Mohawk's Oswego Steam Station has been fabricated and is presently being
installed; a mid-1991 startup is planned. The SCR reactor/air heater pilot plant
planned for the Coffeen Station of Central Illinois Public Service is still in the
formative stages of planning and funding; no significant activities are anticipated
until late 1991/early 1992.
PILOT PLANT DESIGN
A generic 1 MW pilot plant was designed based on experience gathered from
numerous SCR pilot plants tested in Europe in the mid-1980's, and from the 3 MW
SCR pilot plant operated by EPRI on low sulfur coal from 1980 through 1982 at the
Arapahoe Test Facility. The key design premises based on this experience are:
• pilot plant flue gas should promote process conditions replicating a full-
scale reactor in terms of flue gas residence time, temperature, gas species
and trace element composition, etc.
• full-scale catalysts representative of commercial systems should be tested.
5A-3
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• pilot cross section should ensure at least one full-scale catalyst element is
not adjacent to a wall, and thus experiences erosion, mass transfer, and
heat transfer conditions typifying full-scale conditions.
• two catalysts should be evaluated at identical process conditions, with
samples capable of being extracted at nominally 3 or 4 month intervals.
The TVA and NYSEG pilot plants are described as follows:
Hot-side SCR: TVA Shawnee
The hot-side SCR high sulfur coal pilot plant is shown in Figure 1. Pilot process
conditions are selected to provide 80% NOX removal (from boiler exit
concentrations of 600 ppm) and maintain residual NH3 at the exit at 5 ppm. Four
catalyst layers are employed to meet the design conditions; a fifth layer exists to
evaluate the required catalyst quantity and pressure drop to reduce residual NH3 to
2 ppm or less. Pilot design and operating conditions are summarized in Table 2.
Flue gas composition measurements can be obtained at the exit of any of the five
layers.
Flue gas is extracted from the economizer exit of Unit #9 at the Shawnee Steam
Station (Paducah, KY) at approximately 710°F, and passes through an isolation
damper, a venturi to monitor flow rate, and a 40 kW heater to adjust process
temperature to desired values (680-700°F). Flue gas then enters an approximately 20
ft straight section in which ammonia reagent is injected and mixed. The flow is
then equally split into two reactors, each containing catalyst from a different
supplier. At the exit of each reactor are flow rate monitors and manual dampers
which insure flow rates are equal in each section. An induced draft fan followed by
a control damper is the last component prior to flue gas return.
Post-FGD: NYSEG
The post-side pilot plant is located at NYSEG's Somerset Station, approximately 40
miles northeast of Buffalo, New York. Figure 2 presents a simplified schematic of
the pilot plant, which employs a recuperative heat exchanger and electric auxiliary
heater to increase flue gas temperature to 625°F for acceptable NOX removal.
The NYSEG/post-FGD process conditions are selected to provide 80% NOX removal
(from boiler concentrations of 400 ppm) and control of residual NHs to 10 ppm and
5 ppm (at the exit of the second and third catalyst layer, respectively). A fourth
catalyst layer is included to evaluate the additional catalyst and pressure drop
required to reduce residual NHs to 2 ppm. Similar to the TVA pilot, two different
catalysts can be evaluated at identical process conditions. Pilot design and operating
conditions are presented in
Table 2.
Flue gas is extracted following the exit of the host station's wet limestone flue gas
desulfurization process at approximately 125 °F. The flue gas concentration typifies
that of FGD exit conditions, with low SC>2 and particulates (150 ppm and 0.006 gr/scf,
respectively). Design values for the concentration of NOX and O2 at this location are
400 ppm and 6%, respectively. After extraction with the isokinetic scoop flue gas
5A-4
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passes through an isolation damper, a venturi to monitor flow rate, and is heated to
550°F by a recuperative (heat pipe) heat exchanger. Two electric heaters provide a
total of 100 kW heating input to further increase flue gas temperature to 625°F. The
gas then enters the reactor tower, which is identical to the TVA design with the
exception that four catalyst layers are provided instead of five. After exiting the
reactor, flue gas is cooled by die recuperative heater, and exits the process at
approximately 225°F.
TEST PLAN
A test strategy has been developed based on a two year operating period. The test
plan will first establish baseline performance, then implement load-following
operation. Documented changes in catalyst activity over two years will allow
estimating the useful catalyst life. Additionally, a series of measurements will
determine if SCR contributes to or reduces the concentration of trace species and
particulates. For approximately 85% of the operating time, the pilot plant will
operate in a simple load-following mode, and allow for monitoring NOx removal,
residual NH3, and byproduct SC»3.
Figure 3 presents the anticipated form of one specific result that will be used to
characterize catalyst performance and lifetime. Figure 3 describes the relationship
exhibited between NOx removal and residual NH3 concentration, as a function of
NH3/NOX ratio. Residual NH3 concentration is relatively constant until an
NH3/NOx ratio of approximately 0.90; further increases in NH3/NOX ratio
significantly elevate residual NH3- Experience with SCR pilot plants and full-scale
applications in Europe, as well as the SCR pilot plant operated by EPRI at the
Arapahoe Test Facility, shows that residual NH3 is one of the most sensitive
indicators of catalyst activity. Accordingly, residual NH3 as a function of ammonia
injected will be periodically documented during the two year tests to characterize
any changes with time. This data, in addition to NOX removal and residual NH3
measured between catalyst layers at selected test conditions, will supplement the
analysis of catalyst samples for use in projecting catalyst life.
Figure 4 depicts the test schedule for the TVA pilot plant. The major components of
the test plan are described as follows:
Baseline. Selected baseline tests completed to date document NOX removal, residual
NH3, and byproduct SC»3 as a function of key design variables. Additional tests
scheduled for completion by late April will document the effect of flue gas
temperature, space velocity, and NH3/NOX ratio, among others. A second baseline
test period of 4 weeks is planned after two years.
Load-following. This activity will be fully implemented by June 1991, and will
employ a process control system to simulate actual load-following. The pilot will
operate at a fixed reactor design flow rate of 2000 scfrrt (1000 scfm per catalyst), but the
ammonia injection will be tailored to maintain a fixed NH3/NOX removal over the
daily variable conditions of inlet NOX, O2, temperature, etc.
Trace Species/Particulate. Over the two year period, two measurement campaigns
will be conducted to determine the fate of trace metals across the reactor, and if trace
5A-5
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byproducts (e.g., N20) are created or removed by the reactor or the NOX reduction
reactions.
Catalyst Activity. At three month intervals, the reactor will be removed from load-
following operation, and selected test conditions from the baseline series repeated.
The reactor will be removed from service and inspected, and catalyst samples
extracted for bench-scale testing by the supplier. The first samples were removed in
late March 1991.
Each catalyst supplier has modified the center catalyst so that samples can be
extracted for further testing and analysis in a bench-scale laboratory rig. Samples
will be tested under well-controlled operating conditions of gas composition and
temperature to define NO removal, allowing catalyst activity to be assessed. In
addition, catalyst suppliers will employ special-purpose diagnostic techniques to
monitor the surface composition. It is anticipated that changes in catalyst activity
will correlate with the surface concentration of trace species suspected to be poisons
for SCR catalysts. Samples will be extracted at approximately 3 or 4 month intervals,
allowing trends in activity and surface composition to be established that can be
used to estimate catalyst life.
RESULTS
As of late March 1991 testing with the TVA pilot plant had progressed
approximately 60% through baseline operation, accumulating almost 2000 hrs (one
fourth year) operation. The NYSEG unit had not yet started operation but was in
the final stages of construction and check-out. Selected results from the TVA unit
are summarized as follows.
TVA.
Two categories of results have been obtained to date with the TVA pilot plant: (a)
process performance data, and (b) operating experience that could minimize
operating problems and maintenance costs at full-scale.
Process Performance. Preliminary measurements defining NOX removal and
residual NH3 as a function of ammonia injection rate are shown in Figure 5. Data
analysis is not yet complete, thus data for each specific catalyst is not identified;
rather the general range of results is shown along with several points for illustrative
purposes. Figure 5 indicates that the catalyst in a new state (e.g. 3 months duty or
less) meets the design performance specifications. The measured residual NH3
concentration is two ppm or less for NH3/NOX ratios less than 0.85. We are
conducting additional diagnostic tests to insure all residual ammonia both in the
flue gas and adsorbed by participate is accounted for.
Initial measurements of SO3 show flue gas concentration entering the pilot plant is
generally 20-30 ppm, depending on boiler operating factors such as load, excess air,
etc. Measurements also show that depending on the specific catalyst and process
conditions up to 40 ppm SO3 can be added to the flue gas, producing concentrations
exiting the reactor in excess of 70 ppm. The high SOs content (from both inherent
levels associated with high sulfur coals and SO2 oxidation) compared to Japanese
5A-6
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and European applications could be responsible for the two operating experiences
described below.
Ash Deposition. Significant deposits of fly ash adhered to the wall of the SCR
reactor in the initial stages of operation. In general, most of the adhered fly ash was
hardened with a cementitious surface, or glazing. Analysis of surface deposits by
scanning electron micrograph show a high content of sulfate compounds -
specifically calcium sulfates - well above the content usually observed in fly ash. It
is theorized that sulfuric acid (from high SOs) condensed on the fly ash, leached out
calcium, and subsequently formed the sulfates. The condensation of sulfuric acid
was likely due to frequent startup/shutdown operation in the early phases of pilot
plant testing, exposing the catalyst to SC>3 and moisture at temperatures below the
condensation threshold. These hardened deposits blocked up to 10% of the catalyst
surface, and if allowed to further accumulate, would remove a significant portion of
the catalyst from operating duty.
As a result of this experience, a procedure for proper startup/shutdown was
developed that in principle could be adopted to full-scale. To avoid condensation
during startup the catalyst was preheated with ambient air to above both the flue gas
SOs and moisture dewpoints (~300 °F and 100 °F, respectively. During shutdown,
the reactor is purged with air as the catalyst cools from operating temperatures (-700
°F) to below the SO3 and moisture dewpoint. This is accomplished at the TVA pilot
plant by installing an inlet valve in the flue gas ductwork to allow ambient air to be
inducted. The ambient air was heated to above 350 °F by either an electric heater
(during startup operation) or the relatively hot duct walls (during shutdown
operation). This experience has been documented and will be used to develop
star tup/shutdown guidelines for full-scale.
Deposit Formation On NH^_ Injectors. Additional operating experience addressed
ammonia injection equipment. To date, no full-scale installations in Japan or
Europe have reported in the open literature problems with ammonia
sulfate/bisulfate formation on the injector nozzles. However, operation during the
first three months of startup documented the formation of ammonium
sulfates/bisulfates on the injectors in quantities sufficient to block ammonia
injection and/or cause maldistribution of ammonia and reduced NOx removal.
These injectors were of a special design to provide rapid mixing and a uniform
distribution of NH3 and NOX; however the solids deposition is believed possible on
conventional injectors.
The usually reported temperature for deposition of such compounds is
approximately 400°F, based on ammonia and SO3 concentrations of approximately
10 ppm. However, the thermodynamics of these reactions for high sulfur coal
conditions (up to 30 ppm SOs in flue gas, and ammonia concentration up to 50,000
ppm in the transport air) suggests that such compounds can form at temperatures
up to 625°F. These unique conditions, not previously reflected in full-scale or pilot
tests, could be responsible for persistent deposition at these relatively high
temperatures. As of mid-February this problem at the pilot scale had been remedied
with a special-purpose injection system. In this approach, two injectors are
alternately used, allowing ammonium compound deposits on the injector not in
5A-7
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service to decompose to ammonia and 803. We are presently evaluating concepts
that could be applied at full-scale.
NYSEG post-FGD.
Installation of this pilot plant was completed in mid March 1991, with check out
activities and startup tests scheduled to begin in late March. The test plan for the
NYSEG unit is similar to that for the TVA pilot plant, and is presented in Figure 6.
SUMMARY
Selective catalytic reduction has been applied extensively in Japan and more recently
in Europe to control NOX emissions to extremely low levels. Although no serious
problems have been reported to date for these low sulfur coal applications, several
critical concerns remain for high sulfur coal application in the U.S. For the
conventional hot-side application, these concerns address primarily catalyst life and
quantity to control residual ammonia, and the quantity and fate of residual SO3
generated by the catalyst. For post-FGD applications, the cost and materials of
construction required for a recuperative heat exchanger that can survive the
potentially corrosive, low temperature environment following conventional wet
FGD processes is critical.
EPRI and member utilities plan tests employing up to six pilot plants to empirically
evaluate these issues for U.S. application. The first pilot plant is addressing hot-side
SCR on high sulfur coal at the TVA/Shawnee Test Facility, with early results
confirming catalyst suppliers predictions for catalyst performance, but identifying
two operating issues that potentially relate to the high SOs content of flue gas.
A second pilot plant to evaluate post-FGD SCR at NYSEG's Somerset Station will be
operational in April 1991. Results from these pilots and two additional units
planned (at Niagara Mohawk Power Corp. and Central Illinois Public Service) will
be used with EPRI engineering studies to predict with confidence the feasibility and
cost of SCR for U.S. application.
REFERENCES
(1) "Poisoning of SCR Catalysts," presented at the 1991 Joint Symposium on
Stationary Combustion NOX Control, March 1991, Washington, D.C.
(2) "Technical Feasibility and Cost of SCR for U.S. Utility Applications", presented
at the 1991 Joint Symposium On Stationary Combustion NOX Control, March
1991, Washington, DC
(3) "Technical Feasibility and Cost of SCR NOX Control In Utility Applications,"
Draft Report for EPRI Project 1256-7, August 1990.
5A-8
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Table 1. Fuels. Furnace Designs Evaluated In The EPRI/Utility
Industry SCR Pilot Plant Program
NYSEG*
Niagara
Mohawk
CIPS
FUEL
3-4% S
2% S
1% S Oil
3-4% S
*Post-FGD
FURNACE DESIGN
Pre-NSPS
(Wall-fired)
'79 NSPS
(Wall-fired)
Pre-NSPS
(Wall-fired)
Cyclone
Table 2. Design Basis of Pilot Plants
PILOT FEATURE NYSEG
Flowrate (scfm)
Number of Catalyst Layers
Dummy Layer
Reactor Temperature (°F)
Inlet NOX (ppm)
Inlet SO2 (ppm)
Design Performance
- NOX(%)
- NH3 (ppm)
Catalyst Manufacturer
(all honeycomb-type)
Catalyst Pitch (mm)
2000
4
no
625
400
150
80
5
WR Grace
Englehard
4
TVA
2000
5
yes
700
600
2000
80
5
• Joy/KHI
• Norton
6/7
5A-9
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Figure 1. Installation Arrangement of 1MW SCR Pilot
Plant At TVA
DAMPER
OLD ELECTROSTATIC
PRECIPITATOR
(OEENERGIZED)
SAFETY SHOWER
-------
Figure 2. Schematic Of Post-FGD SCR
Pilot Plant at NYSEG's Somerset Station
From
Scrubber
Outlet
(125T)
Return
To Plant
(250°F)
Recuperative Heat
Exchanger
Gas out
550° F
Electric
Heater
T in : 625°F
NH3
SCR I
Reactor[
U\J
F.D. Fan
-------
Figure 3. Anticipated Relationship Between
NOx Removal and Residual NH3 vs. Time
en
~ 90%
NOx
Removal
3 months
(Baseline)
NH3,
ppm
y
X
-.90
Ammonia/NOx Ratio (moles)
-------
Figure 4. Test Schedule For
TVA High Sulfur Pilot Plant
Activity 6/9° 9/9° 12/9° 3/91 6/91 9/91 12/91 3/92 6/92 9/92 12/92 3/93
en
CO
1. Start-up
2. Sampling/Analytical Trials
3. Baseline
4. Load-Following
5. Catalyst Activity
6. Trace Species/Particulate
7. Second Baseline
-------
Figure 5. Relationship of NOx Removal,
Residual NH3 - Preliminary TVA Baseline Results
NOx
100
95 +
en
>
Removal on
9°
85 --
80
75
.80 .85 .90 .95 1.0 1.05
Ammonia/NOx Ratio (moles)
-------
Figure 6. Test Schedule For
NYSEG Post-FGD Pilot Plant
01
en
Activity
3/91 6/91 9/91 12/91 3/92 6/92 9/92 12/92 3/93 6/93
1. Start-up ^^
2. Sampling/Analytical Trials
3. Baseline
4. Load-Following
5. Catalyst Activity
6. Trace Species/Particulate
7. Second Baseline
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PILOT PLANT INVESTIGATION OF THE TECHNOLOGY OF SELECTIVE
CATALYTIC REDUCTION OF NITROGEN OXIDES
Shiaw C. Tseng, Wojciech Jozewicz
Acurex Coporation
P.O. Box 13109
Research Triangle Park, NC 27709
Charles B. Sedman
Gas Cleaning Technology Branch, MD-04
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
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PILOT PLANT INVESTIGATION OF THE TECHNOLOGY OF SELECTIVE
CATALYTIC REDUCTION OF NITROGEN OXIDES
Shiaw C. Tseng, Wojciech Jozewicz
Acurex Corporation
P.O. Box 13109
Research Triangle Park, NC 27709
Charles B. Sedman
Gas Cleaning Technology Branch, MD-04
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
ABSTRACT
The U.S. Environmental Protection Agency has built a bench scale
pilot plant to investigate the ammonia (NH3) based technology for
selective catalytic reduction (SCR) of nitrogen oxides (NOX). A
key objective of this task is to establish the performance of
commercially available SCR catalysts on U.S. fuels and combustion
sources.
One rudimentary catalyst produced in-house and two commercial
catalysts were tested over the temperature window of 327 to 440°C.
The space velocity (SV) ranged from 7,650 to 36,500 hr"1. The
combustion gas was doped with nitric oxide (NO) and NH3, and the
NH3/NO ratio ranged from about 0.6 to 2.2. Sulfur dioxide (S02)
was added to the combustion gas in some runs to investigate its
effect on NO conversion. The results obtained indicate that the SV
has a significant effect on the conversion of NO for the in-house
catalyst which was prepared primarily for start-up of this system
before the commercial catalysts arrived. For the two commercial
catalysts, the NO conversion was 90% and higher when the NH3/NO
ratio was near or above unity. For the same catalysts, the NO
conversion was approximately proportional to the NH3 concentration
at the inlet of the reactor, when the NH3/NO ratio was below unity.
For one commercial catalyst, the NO conversion was lower when 95
ppm of S02 was present in the flue gas. Over the same catalyst,
the amount of nitrous oxide (N20) formed was practically
negligible. The difference of activity between the in-house and
the commercial catalysts is attributed to the difference in
chemical composition.
5 A-19
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INTRODUCTION
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