EPRI
Electric Power
Research Institute
Keywords:
Nitrogen oxides
Combustion control
Denitrification
Flue gas treatment
Fossil fuel boilers
EPRI GS-7447
Volume 1
Project 2154
Proceedings
November 1991
Proceedings: 1991 Joint
Symposium on Stationary
Combustion NOX Control
Volume 1
-------
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
-------
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.
-------
DISCLAIMER OF WARRANTIES AND
LIMITATION OF LIABILITIES
THIS REPORT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN
ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER
RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY
COSPONSOR, THE ORGANIZATION(S) NAMED BELOW, NOR ANY PERSON ACTING
ON BEHALF OF ANY OF THEM:
(A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR
IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS,
METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS REPORT, INCLUDING
MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH
USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS,
INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS REPORT
IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR
(B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY
WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY
EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES)
RESULTING FROM YOUR SELECTION OR USE OF THIS REPORT OR ANY INFORMATION,
APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS REPORT
ORGANIZATION(S) THAT PREPARED THIS REPORT:
ELECTRIC POWER RESEARCH INSTITUTE
Printed on Recycled Paper
Proceedings: 1991 Joint
Symposium on Stationary
Combustion NOX Control
Volume 1
GS-7447, Volume 1
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
-------
Electric Power Research Institute and EPR1 are registered service marks of Electric Power Research Institute, Inc.
Copyright S1 1991 Electric Power Research Institute. Inc All rights reserved
ORDERING INFORMATION
Requests for copies of this report should be directed to Research Reports Center
(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.
-------
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.
-------
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
-------
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 1
• Session 7B: New Developments II
• Session 8: Oil/Gas Combustion Applications
An appendix listing the symposium attendees is included in both volumes.
VI
-------
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. Offen, 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-NOx Burners," T. Lu, R. Lungren, and A. Kokkinos 2-19
"Design and Application Results of a New European Low-NOy 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
-------
Paper
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. Macphail 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-NOx 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-NOx 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
-------
Paper Page
"S03 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
-------
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 68: 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
-------
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, Particulate, 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-N0x 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
-------
Session 1
BACKGROUND
Chair: I. Torrens, EPRI
-------
NOx EMISSIONS REDUCTION IN THE FORMER
GERMAN DEMOCRATIC REPUBLIC
B. Kassebohm
Stadtwerke Dusseldorf AG
LuisenstraGe 105
4000 Dusseldorf 1, Germany
S. Streng
Lentjes AG
Hansa-Allee 305
4000 Dusseldorf, Germany
-------
NOx EMISSIONS REDUCTION IN THE FORMER
GERMAN DEMOCRATIC REPUBLIC
ABSTRACT
Looking at a map of the European continent, we can see three areas of high NOx
emission concentration: the industrial regions of western and eastern Germany, and
the industrial area between Poland and Czechoslovakia. Unlike the SO,-, emission,
which, due to the prevalent wind currents in Europe, is concentrated and settles
on the southern part of Scandin3via, the NOx immission always comes from a nearby
source.
It is remarkable that these three equally-large environmental burdens are to be
found in such completely different political and economic systems. Using the
population figures and gross national product as a basis, we for example, discover
that three times as many people and a three times higher GNP cause the emission in
western Germany. The air pollution in East Europe, therefore, is mainly being
caused by inefficiency and energy wastage.
In order to effectively reduce the emission of pollutants in these countries,
therefore, it is not enough to make use of familiar primary and secondary techno-
logies, but especially efficiency must be increased and energy saved.
1-3
-------
NOx EMISSIONS REDUCTION IN THE FORMER
GERMAN DEMOCRATIC REPUBLIC
INTRODUCTION
In the former German Democratic Republic, as in all the other communist-governed
countries of the Eastern bloc, the economic development after the Second World War
was completely under state control. In place of the forces of a free market with
the flexible reactions of private initiative, the economic goals were determined in
long-term state plans. In these plans, not only requirements and demand, but also
the prices for raw materials and finished products, were regulated. This awkward
system was lacking any private initiative, not least because it was no advantage
for the individual. As a result, everybody only did what they had been told to do.
Now, after 40 years, we can see the serious damage this has done to the economic
system of the former GDR. Adequate profits, which could have been used to finance
the renovation or improvement of production facilities, or even measures for
environmental protection, were not allowed. The raw materials were mainly limited
to those found in their own country, or from communist neighbours. The prices for
raw materials and products did not cover their costs. The constant lack of products
for everyday life, and the effort for each individual to obtain them, also took
their minds off serious deficiencies such as adequate environmental protection.
ENERGY CONSUMPTION AND POLLUTANT EMISSIONS
Fig. 1 shows the relation between energy consumption and GNP for various countries.
Here we can see clearly that the former GDR is an energy waster compared to the
Federal Republic of Germany, due, as mentioned previously, to their antiquated
production equipment and methods, as well as low energy prices laid down by the
government. Fig. 2 shows this clearly using primary energy consumption. The
difference becomes particularly noticeable when we consider that the Federal
Republic of Germany has 60 million inhabitants, and the former GDR only 16 million.
The consumption of primary and final energy per capita is accordingly high; whereas
the old fashioned, antiquated production methods lead to lower electricity con-
sumption.
1-4
-------
It is characteristic of the communist systems that they endeavour to be economically
self-sufficient, and this is also true with regard to energy. In the former GDR,
since 1978, this has increasingly led to 85 % of the energy needs being met by
native brown coal. With this fuel 70 % of the electricity was produced, and more
than 65 % of heating needs met. At the same time, the brown coal met the need for
gas and largely also the need for fuel through hydrogenation. Incinerating the brown
coal, which here has a high proportion of water, salts, and sulphur, led to a high
emission of pollutants, as no money was spent on holding them back.
Fig. 3 shows a comparison of specific figures for the emission of the pollutants
NOx, S02 and dust per capita of population, and for NOx in the former GDR the
sectors involved, such as power plants, industry, dwelling heating and transport.
This picture was, and is, not just typical for the former GDR, but rather for the
entire Eastern bloc and especially for the industrial conurbation in the triangle
between the GDR, Poland and the CSFR which continues into Hungary, Romania and
Bulgaria. The damage afflicted upon the vegetation, and buildings, in these areas,
mainly due to SCU is well known, due to the ease with which S02 spreads, is not
limited to its place of origin. Southern Scandinavia is, due to the air currents,
the European collecting tank for transported S02, and as the region is rocky with
only a thin earth covering, with fir monocultures and lakes, it is unable to neu-
tralise these large amounts. As a result, the lakes are dead, and the forests'
rate of growth is reduced. The map of Europe in Fig. 4 shows the extensive dis-
tribution and concentration of SOV, in Scandinavia. With S02 especially, it is fairly
easy to follow up on imports and exports, and the result seen in Fig. 5, corres-
ponding to the seasonal air currents, is a familiar one. This shows an annual
average, whereas extreme conditions, which exist in Europe in winter with prevalent
eastern winds, have at times already led to disastrous smog conditions through im-
ported S02 and dust.
REGARDING THE EMISSION OF THE POLLUTANT NOx
The NOx which is measured recorded in the air of our population centres is, contrary
to the unchanging SO^SO^, not an import, but rather is produced on the spot. Pro-
vided it leaves the lower levels, NO changes to N02, and then through UV-influence
it may change to N20, or be a cause for the reduced formation of ozon, and then
elude identification. Fig. 6 shows a map of the European continent with regard to
NOx emission, and as typical points of interest the three industrial urban areas:
Rhein-Ruhr, southern former GDR and southern Poland, CSFR and Hungary. There is no
doubt that NOx has formed here due to the dense population, industrial work with
^-5
-------
various fossil fuels, and motor vehicle traffic. Fig. 7 shows the sources of heaviest
emission. The region displayed near the Polish border emits approximately the same
amount of NOx as Norway. In the Federal Republic of Germany, we can assume that, in
spite of the measures taken to decrease the emission of NOx in stationary industrial
furnaces, motor vehicles, and household fireplaces, which are already resulting in
decreases of 80 %, this heavy emission is the result of anthropogenic activity
from its roughly 60 million inhabitants. The situation is different regarding the
concentration of emission in the southern part of the former GDR and the CSFR. A
maximum of 16 million people live in this area, but their energy consumption,
specifically due to unefficient production methods and production plants, as well
as a certain energy wastage through subsidised prices, is substantially higher.
A PROGNOSIS FOR REDUCING THE EMISSION OF NOx
After dissolving the GDR and integrating it into the Federal Republic of Germany,
the region will as from July 1st, 1992 come under the environmental laws in the FRG.
The desolate condition of the eguipment alone though calls for a time limit for
conversion. These limits for various pollutants from stationary coalfired sources
are:
• sulphur dioxide (S02) from Jan. 1st, 1994 < 200 mg/mj
• nitrous oxide (NOx) from July 1st, 1996 < 200 mg/m3
• dust from July 1st, 1996 < 50 mg/m3 for new
< 80 mg/m3 for
existing plants.
The total emission of NOx in the GDR before unification was approximately
700 000 t/a, whereby 400 000 t were attributed to the stationary sources. The re-
maining 300 000 t came from a comparatively small amount of train, lorry, bus, and
car traffic. The latter will now align itself quickest to the west European level,
as the entire motor vehicle production in the former GDR has come to a standstill,
and a spontaneous exchange for western vehicle types with catalysts and minimum
pollution has begun. The substantial emission of hydrocarbons up to now, which
was a considerable burden for urban areas, and which was due to the common motor
vehicle types with two-stroke engines, will also be improved by this development.
As shown in Fig. 8, short-term relief from the pollutants from stationary fossil-
fired power plants, though, is possible, as about 50 % of the oldest plants, some
of which are up to 50 years old, can be closed down. This is feasible due to the
present economic recession, but also through savings due to the higher, market-
conforming prices for energy. This would leave the best power plants technically
1-6
-------
and economically-speaking, which could continue to use brown coal. For brown coal
mining it is planned to reduce the amount extracted by about a third from 300
million t per year at present to about 185 million t per year, in order to protect
the environment, but on the other hand not to increase unemployment. The remaining
power plant capacity of around 12 000 MW will then have to be retrofitted with flue-
gas cleaning equipment by the dates mentioned above. This especially concerns
improving the electrostatic dust filter and the installation of desulphurisation
systems. There is a good chance that using brown coal with a low calorific value
and high water content, it will be possible to decrease the NOx emission to below
100 ppm NOx just through so called primary methods in the furnace.
As regards the development of the economy in the former GDR it is valid to expect
to recover, and to reach the niveau in the FRG, very quickly. The associated
increase in energy requirements will be met by construction new power plants in
good time. These plants will be built using the latest concepts with hard coal as
a fuel, possibly with integrated gasification or natural gas, but in any case a
combined gas/steam power plant. Fig. 9 shows what pollutant decreases could be
achieved in the former GDR using power plants with new technology compared to the
existing brown coal plants.
The stationary dwelling heating systems must also be retrofitted to reduce the
amount of pollution through NOx emission, whereby approximately 23 % of dwelling
heating in the former GDR is already being provided by district heating from
central heating plants. The energy consumption here is also suspected of including
up to 50 % wastage, as neither the subsidized energy prices nor the antiquated
buildings are incentives to save energy. With fair market prices and improved
building insulation, capacity and fuel can be saved, and in addition, the pollution
level decreases. It is hoped that the unemployed capacity of the district heating
plants will then be used to switch new costumers from the individual heating systems
It is expected that the majority of these ecologically harmless fuel natural gas,
as soon as a pipework has been set up. A maximum of ten years has been set for
completing this measure.
All in all, the experts are optimistic enough to say that the pollution problem in
the former GDR will have been brought down to the level in the Federal Republic of
Germany in three or four years for traffic, in about five to six years for power
1-7
-------
plants, combined heat and power plants, and heating plants, and at ten years at the
latest for dwelling heating systems. The technology is available for this; it just
depends on whether the economy manages to recover in this set time to the niveau
in the Federal Republic of Germany.
REFERENCES
1. Ministerium fur Umweltschutz, Naturschutz, Energie und Reaktorsicherheit
der DDR, Berlin. Umweltbericht der DDR, Februar 1990
2. Ministerium fur Umweltschutz, Naturschutz, Energie und Reaktorsicherheit
der DDR, Berlin. Fristenplan zur Ubernahme der GroGfeuerungsanlagenverordnung
zum 1. Juli 1992
3. Volkskammer der DDR, Berlin. Umweltrahmengesetz der DDR, Juli 1990
1-8
-------
Energie Consumption
per Capita
100 -
Canada
)
50 -
Arg
n _
m
CSFR
Poland -*~s
Greece
entina Q
(J ^\raq
1
Great
P
Spam
Australia
O FRC
Britain „ ^^
U Q
Q(J France
Japan
Norway
: O"
Sweden
i 50
^ Brazil, Chile, Tunisia
China, India, Peru, Egypt
100
GNP per Capita
Fig 1: Gross Net Production arid
Energy Consumption per Capita (USA = 100)
Source: BWK 363.7 (1990)
FRG
GDR
Total
Fig 2: Energy Consumption
Source: Handelsblatt (1990)
K\\
K"
FRG GDR
Primary—
energy
kWh
6500
FRG GDR FRG GDR
Final-
energy
Electrical-
energy
Consumption per Capita
1-9
-------
41,9% Power Stations
'/S/S///SSS/////S/S//SS/S//S/S/S.
42,9% Traffic
Nitrogen- Sulfuroxide Dust
oxide
Fig 3: Emission per Capita in 1988
Source: Iiistitut fur Umweltschutz Berlin, DDR (1990)
1,7% Dwelling Heating
\ Nitrogenoxide
2 4
Fig 4: Measured S04 Immission
in Europe ( ^
Source: NATO/CCMS Studie 1979
1-10
-------
Great Britain
D aiimark
36 Ireland , — -^_ » 3
c-.-. _i \ rt
X~."-- <: T "A* ^P
Netherland'S \ /
13 „ — > r h
^~ V '-v / -C= Poland
) > 2fl
s7 \
Belgium / 7
25 LUX.—/ r_,
t~-- 1 s P GDR
; ^ %r 122
^ (
( '^J"\^
\ Vx .h^j CSFR
^~~7 • •-- 61
France ~~7 \
45 / /r
/ /
! \
( -f — •> i^5^^ 6
^ '~^^^yr"J'~' H> ' Austria
*"" ^ '""*
Switzerland (I Yugoslavia
3 Italy °
36
Great Britain ^ ,
T , 4 Danmtirk
12 Ireland .. . n
V -- ~\ /-.
X V-. ~^'--Jf
Netherland x j- ('
41^ ^-—i^ ^ Poland
"*^> \ ''' : ~*' 32
1 ^7
Belgium j )
20 Lux—- f
-*«, ) y ^- GDR
J 1 53
( ^
/ \
s) V*==^ CSFR
France ~7 J
57 /
/ ^'
1 \-^Au stria
^—-' \_^v r'-''"' \
/ | ^-' \
1 \
Switzerland 1 Yugoslavia
6 Italy 3
7
Fig 5: SO 4 Exchange in 1984 (Figures x lOOGt)
Source: Globus 6358
= 500 - 700 mg per m
= 1500 - 2000 mg per rn 2
= 2000 - 2500 mg per rn ^
Fig 6: Estimated Annual Deposition
of NOx in Europe
Source: Acid Magazine 1990
1-11
-------
IV)
Actual Situation *
- Existing Power Plant Capacity
(among these Nuclear
Availability ~ 86% i.e.
Peak load
Danmark
23.580 MW
2.200 MW)
19.800 MW
17.900 MW
Hypothesis for the Future:
- Saving Potential in Power Plant Capacity
~ 50% i.e. ~ 12.000 MW
Increase in Efficiency and/or
Emission Reduction by
- Renewal (till 2020)
Cost ~ 30 Bill DM
or
- legal Retrofitting by
Flue Gas Scrubbing (till 01.01.94)
Denitrogenisation (till 01.07.96)
Dust Precipitation (till 30.06.96)
Cost ~ 10 Bill DM
Fig 8: Power Generation of the GDK
in 1988
* Source: IZE
NetherlafidAJ' Q
GDR \
• - r 16,5 Mio \
Hamtmrs v Inhabitants \
.^.08.000 km2(
\ Poland
Berlin x
w_^ FRG
France ;> 62 Mio
/ Inhabitants
J- 249.000 km
. . I 3 Mill t NO x/a D
Switzerland
Austria
Fig 7: Points of Max NOx- Emission
Source: DIW (1985)
-------
a
o
•rH
03
03
-------
"TOP-DOWN" BACT ANALYSIS AND
RECENT PERMIT DETERMINATIONS
John R. Cochran
Morgen E. Pagan
Black & Veatch
-------
ABSTRACT
New EPA requirements for "top-down" best available control
technology (BACT) analyses have resulted in determinations that re-
quire more stringent control technologies. Accordingly, these per-
mit decisions include nitrogen oxide (NOX) emission limits significant-
ly lower than applicable New Source Performance Standards. However,
with careful consideration of acceptable site-specific impacts, obtain-
ing a reasonable BACT determination is still possible.
This paper presents a step-by-step approach for conducting a top-
down BACT analysis, and summarizes important considerations that
will lead to a more effective BACT analysis. In addition, recent per-
mit decisions regarding NOX emission rate and control technology
requirements for combined cycle combustion turbine and coal fueled
power plants are summarized and examined to ascertain the basis
for decisions. Guidance from this paper will help applicants in prepar-
ing an accurate and comprehensive BACT analysis for their proposed
projects.
1-17
-------
"TOP-DOWN" BACT ANALYSIS AND
RECENT PERMIT DETERMINATIONS
John R. Cochran
Morgen E. Fagan
Black & Veatch
INTRODUCTION
On December 1, 1987, the EPA Assistant Administrator
for Air and Radiation, J. Craig Potter, issued a memoran-
dum implementing a number of program initiatives
aimed at improving the effectiveness of the Clean Air
Act new source review program. Among these in-
itiatives was the implementation of a "top-down" ap-
proach to determine the best available control
technology (BACT) under the Prevention of Significant
Deterioration (PSD) program of the Clean Air Act.
Primarily, the top-down approach requires that the most
stringent feasible control technology available,
designed to achieve the lowest achie/able emission rate
(LAER) be evaluated first in a BACT analysis. This
technology would then represent BACT unless it could
be reasonably demonstrated on the basis of site-specific
energy, environmental, and economic impacts that this
level of control is not warranted. The next most stringent
level of control would then be evaluated. This process
would continue until a technology could not be
eliminated on the basis of energy, environmental, and
economic considerations, in which case this
technology is BACT for the project.
The EPA has indicated that the intent of the new top-
down BACT procedure is not to establish a national
BACT standard, but to avoid "bottom-up" evaluations
that do not consider LAER technologies and result in
the use of control technologies designed for com-
pliance with New Source Performance Standards
(NSPS). Accordingly, permit decisions since implemen-
tation of the guideline have resulted in NOX emission
limits significantly lower than applicable NSPS. Top-
down BACT analysis has made it increasingly difficult
for new sources to avoid a requirement for post-
combustion NOX control systems. However, with
careful consideration of site-specific impacts, it is still
possible to obtain a BAG" determination appropriate
for a proposed project.
NEW SOURCE PERFORMANCE STANDARDS
Baseline air emission performance requirements
(emission limits) for a number of new source types are
established by the United States Government in the
Code of Federal Regulations, Chapter 40, Part 60 (40
CFR 60). The emission requirements dictated by the
NSPS establish the minimum level of acceptable air
emission control. Table 1 provides a listing of NSPS
for coal fueled steam generators and combustion
turbines.
BACT PROGRAM OBJECTIVES
The definition of a BACT requirement is an emission
limitation based on the maximum reduction for a pollu-
tant regulated by the Clean Air Act, which, on a
case-by-case basis taking into account energy, en-
vironmental, and economic impacts, is determined
to be achievable through application of available
methods.
The primary objective of the BACT determination
process is to minimize consumption of PSD air quali-
ty increments, thereby enlarging the potential for future
economic growth without significantly degrading air
quality. To avoid setting national control technology re-
quirements, BACT guidelines dictate evaluating feasi-
ble control technology alternatives on a case-by-case
basis while considering site-specific impacts. The in-
tent is that this case-by-case approach will encourage
adoption of improvements in emission control
technology more rapidly than would occur through
uniform control technology requirements or New
Source Performance Standards.
Mr. Cochran and Mr. Fagan may be contacted at (913) 339-2000.
1-18
-------
Table 1
Nitrogen Oxide Emission NSPS for Selected Source Types
Steam Generating Units Larger than
250 MBtu/h (Subpart Da source)
Bituminous, Anthracite, and Lignite
Subbituminous Coal
Steam Generating Units With Heat Inputs Between
100 and 250 MBtu/h (Subpart Db source)
Spreader Stoker and Fluidized Bed Boilers
Pulverized Coal
Lignite
Stationary Gas Turbines*
Rated Load
Peak Load
"Corrected lo 15 percent oxygen minus corrections for heat rate and fuel bound nitrogen.
Emission Limit
0.60 Ib/MBtu
0.50 Ib/MBtu
0.60 Ib/MBtu
0.70 Ib/MBtu
0.60 Ib/MBtu
75 ppm
150 ppm
As previously discussed, NSPS provide the baseline re-
quirement establishing the minimum acceptable level
of control for a BACT determination. The BACT analysis
was required to evaluate alternatives between the NSPS
base line and the most stringent control technology
which provide the maximum emissions reduction.
In response to guidance documents issued by the EPA
in December 1978, new source permit applicants
prepared so-called "bottom-up" 8ACT analyses. These
analyses started with the NSPS base line and then com-
pared the feasibility of more stringent control
technologies to the NSPS base line. Because of either
regulatory procedures or inconsistencies in the process,
most of these bottom-up BACT analyses resulted in per-
mit determinations at or near NSPS limits. Since the
EPA interprets that the intent of Congress for implemen-
ting the BACT process was to drive technology, emis-
sion limits near NSPS were an unacceptable result of
the process.
With the adoption of a requirement for top-down BACT
analysis in December 1987, the EPA recognized
that the original BACT analysis guidance did not
adequately focus the BACT process and attain the
objective of adequately addressing the most stringent
level of control (LAER technology). Draft EPA top-down
guidance documents indicate that the burden of proof
for a top-down analysis is to disprove LAER. However,
the EPA maintains that the fundamental purpose
of the top-down approach is to arrive at consistent
determinations that adequately consider LAER
technology.
Theoretically, either the top-down or bottom-up BACT
procedure should result in the same permit determina-
tion. The same principles apply in both cases. However,
the real result of top-down guidance is a shifting of the
"burden of proof." In bottom-up BACT analyses, the
presumption lies in favor of an NSPS determination.
Therefore, a more stringent control technology must
be proven to be warranted. In top-down BACT analyses,
the presumption is to install LAER based technology.
Since EPA's interpretation of the BACT process is to drive
technology, this presumption has led to more stringent
determinations.
1-19
-------
TOP-DOWN BACT ANALYSIS PROCEDURE
A BACT analysis must be perrormed for each new,
modified, or reconstructed emissions source. The
applicability criteria requiring a BACT analysis vary
among states and EPA regional jurisdiction. In general,
BACT is required for pollutants whose potential emis-
sions exceed significant emission rates established by
the EPA.
The EPA has recommended that a BACT analysis follow
the general requirements of EPA's draft "Top-Down" Best
Available Control Technology Guidance Document,
March 15, 1990. The following discussion describes a
step-by-step approach to performing a BAG" analysis
that meets EPA requirements. Figure 1 graphically
depicts this step-by-step approach.
STEP 1—DETERMINE SOURCE AND EVALUATION
CRITERIA
One of the most important steps in a BACT analysis is
to accurately define source technical and economic
characteristics. Evaluation criteria typically used in a
BACT analysis are listed belcw:
• Technical Evaluation Criteria.
— Type of Combustor.
— Fuel Burn Rate.
— Fuel Analysis
— Emission Rates (Controlled and
Uncontrolled).
— Flue Gas Flow Rates.
— Site-Specific Constraints.
• Economic Evaluation Criteria.
— Commercial Operation Date
— Economic Recovery Period.
— Capital Cost Contingency Factor.
— Escalation Rate (Capital and O&M).
— Fixed Charge Rate.
— Present Worth Discount Rate.
— Indirects Cost Factor.
— Interest During Construction.
— Capacity Factor.
— Fuel Cost.
— Incremental Capacity Charge.
— Energy Cost.
— Additive Cost.
— Waste Disposal Cost.
These technical and economic criteria should be
accurately determined before any substantial efforts
are made on the BACT analysis. Subsequent evalu-
ation of alternative control technologies is greatly
dependent on these evaluation criteria.
Technical criteria are primarily used to determine
potential emissions, air quality control equipment
effectiveness, and equipment sizes. The two primary
criteria that have a major impact on pollutant
emission rates and equipment type and size are the
fuel quality and the maximum anticipated fuel
burn rate. For a coal fueled application, a specific
fuel source or at least a potential range of fuel
properties needs to be determined early in the
analysis process. For any type of source, a maximum
fuel burn rate should also be established early in the
analysis process. Since this fuel burn rate directly
affects the amounts of pollutants emitted and the
subsequent mass emission limits, it is critical that
this parameter be established with some margin to
account for uncertainties inherent in conceptual
design. Since costs are closely dependent on fuel
quality and fuel burn rates, economic portions of
the BACT analysis will have to be recalculated
whenever these parameters change. This recalculation
could delay the submittal of a PSD permit application.
Economic evaluation criteria are also important to the
BACT analysis since varying certain criteria can
significantly affect the final conclusions. It is important
that the economic criteria be project-specific If project-
specific criteria are not available, typical values can be
used that are representative of the current economic
trends. Since economics is not an exact science, some
variation in the evaluation criteria could be considered
in the analysis to provide a range of cost impacts (sen-
sitivity analysis).
Until recently, economic evaluation criteria have not
received close scrutiny. However, the economic analysis
has become a focal point of BACT analyses. Therefore.
it is very important that an applicant be capable of
defending economic evaluation criteria. Like fuel quali-
ty and fuel burn rate, economic criteria should also be
carefully selected to ensure the accuracy of the evalua-
tion and to prevent delays associated with changing
criteria.
1-20
-------
Step 1
Determine Services and
Evaluation Criteria
• Fuel Data
• Economic Data
• Site-Specific Information
Step 2
Review Recent Permit Decisions
• BACT/LAER Clearinghouse
Documents
• Other Projects
Step 3
Identify Alternatives
• Technically Feasible
• Technology Transfer
• Similar Applications
Step 4
Economic/Energy Evaluation
• Rank Alternatives
• Engineering Economics
• "Top Down"
• Incremental Cost
Step 5
Environmental Consideration
Other Pollutant Emissions
Waste Disposal
Contamination of Other Waste
Products
Comparison of Air Quality Impacts
Public Health and Safety
Considerations
Step 6
Recommend BACT Alternatives
• Technical
• Energy
• Environmental
• Economic
Figure 1
Top-Down BACT Analysis Technique
1-21
-------
STEP 2—REVIEW RECENT PERMIT DECISIONS
The next step m the analysis is to review recent permit
decisions to determine the LAER control alternative.
The 8ACT/LAER Clearinghouse documents provide a
good reference for this activity. These documents (1985
and 1990 editions) contain a comprehensive listing of
permit decisions and the associated control effec-
tiveness. Clearinghouse documents can be obtained
from the EPA. These documents are also helpful as an
indicator of what level of control (emission limit)
might represent BACT or, at least, provide a range of
control effectivness that should be considered in the
analysis.
Typically, EPA's position is that if a permit has been
previously issued requiring a specified emission limit
or technology, then this is sufficient justification to
assume that the control technology or emission limit
is feasible or achievable. However, it should be
remembered that some of the more stringent BACT
determinations were arrived at for various reasons.
Because of project schedule requirements and fiscal
health, a number of applicants may have conceded to
a regulatory agency proposed BACT determination to
expedite the permitting process. Other applicants may
have accepted the use of a technology or emission rate
to get below significance levels or to meet increment
consumption or ambient air quality standards. In ad-
dition, a number of so
-------
Engineering economics are the generally accepted
method of evaluation. Capital and annual operating (in-
cluding maintenance) costs are presented, as well as
total annual costs (levelized fixed charges on capital
plus levelized annual operating costs) of the various
alternatives. Costs presented should be comprehensive,
reflecting fully integrated systems. Operating costs
should reflect expenditures for maintenance, additive,
energy, demand, waste disposal, and operating person-
nel. In addition, if a control alternative negates the
potential for sale of waste products, the cost analysis
should reflect this impact. For control alternatives that
affect unit reliabilities, cost estimates for replacement
power should also be included. Total annual costs are
used to determine incremental cost-effectiveness (in-
cremental total levelized annual cost divided by in-
cremental annual emissions) of the various control
levels and technologies being considered. Incremen-
tal costs, not total removal costs, are the true indicator
of cost-effectiveness of a particular control alternative
as compared to the next less effective control
alternative.
STEP 5—ENVIRONMENTAL EVALUATION OF
CONTROL ALTERNATIVES
Environmental impacts of the various alternatives
should also be included. Environmental impacts that
should be considered for inclusion in the BACT analysis
include the following:
• Increased emission of other pollutants
resulting from use of a control alternative.
• Handling and storage of hazardous materials.
• Hazardous waste disposal of spent catalysts.
• Contamination of waste products that could
be sold for reuse
• Comparison of proposed BACT air quality im-
pacts with impacts resulting from use of a
more stringent control technology.
STEP fr-RECOMMEND tt^CT ALTERNATIVE
This step basically summarizes Steps 4 and 5. The most
effective emission control technology capability not
previously eliminated for technical, energy, en-
vironmental, and economic reasons is then pro-
posed as BACT. Generally, the 8ACT analysis and
recommendation are documented in the PSD
application.
IMPORTANT BACT ANALYSIS CONSIDERATIONS
Several important considerations should be incor-
porated into planning an effective BACT analysis.
The economic analysis should be based on a total
levelized annual cost, including capital and operating
costs. Levelized costs reflect the effect of escalation and
present worth discounting of future annual expen-
ditures, resulting in an equivalent of constant dollars
over the evaluation period. Levelized costs more ac-
curately represent financial impacts over the life of the
project than do first year costs only. Therefore, it is im-
portant to have good representative economic evalua-
tion criteria, since these criteria significantly affect the
results of the analysis. The economic evaluation of
alternate technologies capable of various degrees of
effectiveness should also be compared on an incremen-
tal basis. Incremental costs accurately reflect the true
economic effectiveness of a technology.
Various control technologies require additive or
catalyst. Special consideration must be given to any
technology that requires an additive or catalyst that
might have hazardous or deleterious environmental ef-
fects, for instance, ammonia generally can be used with
relatively little risk. However, an accidental spill could
have catastrophic consequences on the safety of per-
sonnel and surrounding communities. For instance, in
densely populated areas, emissions of unreacted am-
monia (ammonia slip) could be a significant en-
vironmental disadvantage Accordingly, such considera-
tions should be included in the environmental and
economic portions of the BACT analysis.
During the top-down BACT analysis the selection of a
particular technology or emission level may result in
an increase in other pollutants. A good example of this
is carbon monoxide (CO) and volatile organic com-
pounds (VOO which are inversely related to combus
tion control of NOX emissions. Combustion controls
1-23
-------
that are effective in lowering NOX emissions, such as
staged combustion and water injection in combustion
turbines, result in increased emissions of CO and VOC.
The environmental importance of these other pollutants
must be evaluated as compared to NOX emissions
reductions.
The results from ambient air quality impact modeling
should also be included in the BACT analysis to deter-
mine if the project will emit pollutants at a rate that
exceeds PSD significance levels or ambient air quality
limits. If the proposed emissions from the facility are
below, ambient air quality modeling significance values,
there would be no quantifiable benefit from using a
more effective control technology. Demonstrating that
emissions from the facility will be below ambient air
quality significant impact criteria will provide a good
argument against the imposition of a LAER technology
in a BACT situation.
Depending on the nature of the project and the type
of combustion technology being considered,
sometimes there is a potential net environmental
benefit from implementation of a project. For instance
a cogeneration plant providing steam supply to an in-
dustrial user may result in the retirement of process
steam boilers. These process steam boilers probably
have higher emission rates than the cogeneration plant
and are likely to discharge pollutants at relatively low
elevations, resulting in reduced dispersion. Despite the
cogeneration plants use of significantly larger boilers,
ambient air quality impacts may be reduced as a result
of relatively lower emission rates and increased disper-
sion. This would be an extremely important site-specific
consideration that should be included in the analysis.
It is not unusual for the BACT process to exceed a year
to resolve a contested BACT. Therefore, it is recom-
mended that a conservative BACT schedule be assumed
if a project plans to propose and defend BACT at some
level less than a LAER technology.
RECENT BACT DETERMINATIONS
To evaluate the effect of the top-down process, it is
beneficial to review recent BACT determinations. The
following discussion are summaries of BACT analyses
and determinations for NOX emissions reduction at
several coal fueled and combustion turbine combined
cycle projects.
COMBINED CYCLE COMBUSTION TURBINE
PROIECTS
Over the years, combustion turbine manufacturers have
improved their product by substantially lowering NOX
emissions. However, the requirement to use selective
catalytic reduction (SCR) systems on combined cycle
units in some cases is mandated by state and federal
regulatory agencies.
A recent combined cycle project in Florida obtained
a draft permit from the state that did not require an SCR
system so long as the capacity factor for the facility re-
mained below 60 percent. This determination was
based on excessive control technology costs (as com-
pared to other similar applications) for use at capacity
factors less than 60 percent. Subsequently, the Florida
governor and cabinet approved the draft permit.
However, under pressure from the EPA, the Florida
Department of Environmental Regulation issued the
final permit allowing the use of combustion controls
only if the capacity factor is limited to 25 percent or
less. Alternatively, at higher capacity factors the per-
mit dictates the installation and operation of a SCR
system. This determination was made despite the fact
that the incremental costs of an SCR system on the plant
with a 25-percent capacity factor limitation are much
higher than generally accepted incremental cost
thresholds. Currently, the applicant is contesting this
determination.
This does not appear to be an isolated incident. There
is some indication from other projects that the high cost
of an SCR system on a combined cycle plant (as com-
pared to the cost of control alternatives for other types
of plants) is not a significant factor in regulatory agen-
cy BACT determinations.
COAL FUELED HAWAIIAN COGENERATION PLANT
This project consists of two 90 MW bituminous coal
fueled circulating fluidized bed (CFB) boilers
scheduled or commercial operation in 1992. The
project will sell electrical power to a Hawaiian utility
and process steam to a local refinery. The Hawaiian
1-24
-------
Department of Health worked closely with EPA
Region IX during the PSD permitting of this
facility.
A SCR system was identified as the most stringent
method of NOX control, with selective non-catalytic
reduction (SNCR) and combustion controls also
evaluated as available control technologies. The BACT
analysis recommended that SCR and SNCR be
eliminated because of technical, economic, en-
vironmental, and energy considerations. The NOX
BACT recommended by the applicant for the project
was CFB combustion controls to meet an emission limit
of 0.36 Ib/MBtu.
EPA Region IX contested this proposed determination
on the basis of reasonable SNCR economics and as not
being representative of BACT, considering the number
of SNCR installations on CFB boilers in California. EPA
Region IX strongly suggested, and the project accepted,
the use of a SNCR system designed to meet a NOX
emission Iimitationof0.il Ib/MBtu.
COAL FUELED MICHIGAN POWER PLANT
This 45 MW project consists of one CFB boiler burn-
ing bituminous coal. The original BACT analysis com-
pared SCR, SNCR, and combustion control options for
NOX emission control. Based on economic, energy,
and environmental considerations, combustion controls
designed to limit NOX emissions to 0.35 Ib/MBtu were
recommended as BACT. The Michigan Department of
Natural Resources (DNR) accepted the proposed BACT
and issued a draft permit for public comment.
During the public comment period, EPA Region V
issued an official protest rejecting the DNR's determina-
tion of no post-combustion controls. The EPA recom-
mended that a SNCR system designed for maximum
NOX reduction efficiency be required as representative
of BACT. The EPA referenced numerous California per-
mits requiring SNCR to limit NOX emissions to 0.039
Ib/MBtu.
In response, the applicant prepared a BACT analysis ac-
cepting the use of SNCR, but contesting a requirement
for maximum control efficiency. The revised BACT
countered that the California plants burned extremely
low-sulfur (less than 0.50 percent) bituminous coals not
available in the Midwest. According to information pro-
vided by the SNCR manufacturer, burning low-sulfur
coals limited the technical effectiveness of SNCR
systems to approximately 0.12 Ib/M8tu. However, the
revised BACT also indicated that with the chlorine con-
tents of Midwestern coals, use of SNCR to meet a 0.12
Ib/MBtu emission limit would result in an ammonia
chloride plume (resulting from ammonia slip emis-
sions). To avoid the potential for an ammonia chloride
plume, SNCR effectiveness must be decreased to result
in a NOX emission of 0.16 Ib/MBtu. The revised BACT
analysis compared the relative economics and en-
vironmental effects of these two alternate emission
limits and recommended a 0.16 Ib/MBtu emission limit.
As a result of this analysis, the DNR (with agreement
by the EPA) issued a final permit at the 0.16 Ib/MBtu
emission limit.
COAL FUELED POWER PLANT
This project will consist of a bituminous coal fueled
CFB boiler. Once again an SCR system was identified
as the most stringent method of NOX control with
SNCR and combustion controls also being evaluated
as available control technologies. The BACT analysis
recommended that SCR and SNCR be eliminated
because of technical, economic, environmental, and
energy considerations. The applicant recommended
that BACT for the project was combustion controls.
The state regulatory agency and the regional EPA
disputed the validity of this BACT selection. In response,
the applicant provided substantial financial data sup-
porting that an SNCR determination would result in
cancellation of the project. In addition, the applicant
demonstrated that if the project was implemented as
recommended, other aspects of the project would lead
to ambient air quality improvements. This information
convinced both the state agency and the EPA that the
project-proposed BACT determination was valid
when overall environmental benefits and relative
project economics were taken into consideration.
Therefore, BACT for control of NOX emissions from this
project was determined to be combustion controls.
This determination is a good example of site-
specific considerations controlling a BACT
determination.
1-25
-------
CONCLUSION
The primary objective of the EPA in issuing guidelines
requiring top-down BACT analysis was to gain con-
sistency in the process, and to drive plants away from
NSPS determinations towards permit requirements
more representative of the current state of air quality
control technology. However, the EPA also maintains
that it is still an objective of the BACT program not to
dictate national BACT standards, but to evaluate the site
specifics of a given project.
At this time, it appears that the EPA has been successful
at achieving the objective of permit determinations
more stringent than NSPS. This is especially evident
on recent permit decisions for combustion turbine com-
bined cycle facilities. In this situation, EPA and state
regulatory agencies are mandating the use of selective
catalytic reduction systems capable of achieving NOX
emissions 80 percent below NSPS. An additional il-
lustration of this success has been the requirement for
SNCR systems at a number of coal fueled power plants.
Should these trends continue, the BACT process will
essentially accomplish emission requirements reflec-
tive of a de facto NSPS.
For an applicant to effectively dispute regulatory
agency-proposed BACT requirements, the BACT
analysis must be pertormed in a careful, objective man-
ner. This will first require an adequate schedule to
prepare and defend a non-LAER BACT proposal. In ad-
dition, the applicant must carefully research the
background and status of comparison permit deter-
minations. Economic and environmental considerations
must be fully developed to provide adequate arguments
disputing regulatory agency control technology man-
dates. Finally, the applicant must carefully establish and
represent project site specifics.
It is becoming a concern that environmental regulators
are intent on maximizing pollutant reductions from
new plants without regard for site-specific considera-
tions. Therefore, it appears that the BACT process is
becoming more closely related to the LAER process.
However, as illustrated by some of the examples, it is
still possible to use well developed site-specific
arguments to convince the regulatory agencies that the
proposed BACT is a reasonable control technology re-
quirement.
1-26
-------
RETROFIT COSTS AND PERFORMANCE OF NOX CONTROLS AT
200 U.S. COAL-FIRED POWER PLANTS
T. E. Emmel
M. Maibodi
Radian Corporation
3200 E. Chapel Hill Road
Research Triangle Park, North Carolina 27709
-------
RETROFIT COSTS AND PERFORMANCE OF NOX CONTROLS AT
200 U.S. COAL-FIRED POWER PLANTS
ABSTRACT
This paper presents the results of a study conducted under the National Acid Precipitation
Assessment Program by the U.S. Environmental Protection Agency's Air and Energy
Engineering Research Laboratory. The objective of this research program was to significantly
improve engineering cost estimates currently being used to evaluate the economic effects of
applying sulfur dioxide (SO2) and nitrogen oxide (NOX) controls at 200 large SO2-emitting
coal-fired utility plants. To accomplish the objective, procedures were developed and used
that account for site-specific retrofit factors. The site-specific information was obtained from
aerial photographs, publicly available data bases, and input from utility companies. Cost
results are presented for the following control technologies: low NOX combustion or natural
gas reburn, and selective catalytic reduction. Although the cost estimates provide useful site-
specific cost information on retrofitting NOX controls, the costs are estimated for a specific
time period and do not reflect future changes in boiler and coal characteristics (e.g., capacity
factors and fuel prices) or significant developments in control technologies that would change
the cost and performance estimates.
1-29
-------
RETROFIT COSTS AND PERFORMANCE OF NOX CONTROLS AT
200 U.S. COAL-FIRED PLANTS
INTRODUCTION
The objective of the National Acid Precipitation Assessment Program (NAPAP) study of 200
U.S. coal-fired power plants was to improve cost estimates being used to evaluate the
economic effect of retrofitting sulfur dioxide (SO2) and nitrogen oxide (NOX) controls at coal-
fired utility plants. Although study resources were primarily focused on the retrofit cost of
SO2 controls, cost estimates were developed for low NOX combustion controls [low NOX
burners (LNB), overfire air (OFA), or natural gas reburning (NGR)] and selective catalytic
reduction (SCR) for the boilers at each plant.
Figure 1 shows the phases in which the NAPAP study of 200 plants was conducted. In
Phase I, detailed site-specific procedures were developed with input from a technical advisory
committee. In Phase II, these procedures were used to evaluate retrofit costs at 12 plants
using data collected from site visits (1). Based on the results of this effort, simplified
procedures were developed to estimate site-specific costs without conducting site visits. For
LNB and OFA, performance-estimating procedures for NOX reduction were developed with
input from a consultant (2). SCR procedures were tested and revised based on the results of
a parallel program effort in which five coal-fired power plants in Germany were evaluated (3).
In Phase III, the simplified procedures were used to estimate NOX control cost and
performance for 188 plants. The results of this effort were sent to each utility company for
review and comment. In Phase IV, the review comments from the utility companies and the
NAPAP advisory committee were incorporated into the final 200-plant study report (4).
PERFORMANCE AND COST-ESTIMATING PROCEDURES
Figure 2 presents the cost-estimating methodology used to develop inputs to the Integrated
Air Pollution Control System (IAPCS) cost model (5). For each plant, a boiler profile was
1-30
-------
developed based primarily on public information from Energy Information Administration
Form 767, Powerplants Database (boiler design) (6), and aerial photographs obtained from
state and federal agencies.
Low NOX combustion (LNC) was evaluated for all dry-bottom boilers, with application of LNB
on wall-fired units and OFA on tangential-fired units. NGR was evaluated for wet-bottom
boilers and unconventional firing types because applying LNB was considered infeasible and
OFA would not reduce emission rates sufficiently. Performance estimates were developed to
account for non-ideal situations that will occur when retrofitting LNB and OFA. As discussed
below, the NOX reduction estimates are based on the boiler volumetric heat release rate. No
cost adjustments were made to reflect site-specific situations. For NGR, a NOX reduction of
60% was assumed for all boilers.
SCR was evaluated for all boilers with two types of SCR systems considered: hot-side and
cold-side. Both configurations have wide commercial application in Japan and Germany.
During the course of this study, very limited data were available on the long-term
performance of hot-side systems on coal-fired applications, and no commercial or recent pilot
scale data were available for hot-side systems using U.S. coal. Therefore, cold-side SCR
systems were selected for most boilers.
Cold-side SCR systems are located downstream of particulate and SO2 control systems,
thereby reducing or eliminating the catalyst poisoning effects of sulfur (SO3), chlorides,
arsenic, and alkali metals, which are found to a higher degree in U.S. coals than in coals
used overseas. The cold-side system configuration also minimizes unit downtime and
replacement power costs, and facilitates combining smaller units into one system, thereby
allowing economy-of-scale benefits. A disadvantage of cold-side systems is that the catalytic
reactor is located after the air heater, so that the flue gas must be reheated to 650-700°F
However, the capital and energy costs associated with flue gas reheat are somewhat offset
by lower catalyst costs.
Hot-side SCR systems require that the catalyst reactor be located in the flue gas path
between the economizer and the air heater to take advantage of the high flue gas
1-31
-------
temperature (650-700°F), but because of the lack of data mentioned above, hot-side systems
were applied only to boilers with hot ESPs or where space constraints prohibited the use of a
cold-side system.
Low NOX Burners and Overfire Air
When applying combustion controls, many boiler and coal parameters affect uncontrolled
NOX emissions and achievable NOX reductions. However, accurate data for most of these
parameters are not available. Additionally, well documented data on the performance of LNC
retrofits on U.S. boilers are limited. After a review of the detailed procedures used to
estimate NOX reduction performance at 12 plants where site visits were conducted, boiler
volumetric heat release rate was chosen to estimate NOX reduction performance. For most
boilers, furnace volume information was found in Powerplants Database. Based on data from
four LNB retrofits, the following correlation was developed expressing NOX emission reduction
as a function of boiler furnace volume and unit power generation (2):
NOXEFF = 68.8 * (V/MW) (A)
where: NOXEFF = NOX removal efficiency (percent)
V = Furnace volume (1000 ft3)
MW = Boiler rating (megawatts)
Although this equation can yield NOX reduction values lower than 25% and greater than 55%,
25 and 55% were used as lower and upper limits in this study.
If the furnace volume was not known, the following equations relating furnace volume to
boiler rating were used for boilers constructed before (Equation B) and after (Equation C) the
1971 New Source Performance Standards (NSPS) (2):
For boilers constructed before the 1971 NSPS, V = 0.596 * MW (B)
For boilers constructed after the 1971 NSPS, V = 0.844 * MW (C)
Therefore, substituting either Equation B or C into Equation A for furnace volume gives
roughly 40% NOX removal efficiency for wall-fired boilers constructed before the NSPS was
promulgated and roughly 55% NOX removal efficiency for wall-fired boilers constructed after
the NSPS promulgation.
1-32
-------
Even less data were available on NOX reductions that can be achieved when retrofitting OFA
on tangential-fired boilers. A review of furnace volume data for tangential-fired boilers
showed that the furnace volumes for pre-NSPS boilers are 40% smaller than the post-NSPS
boilers. OFA is generally capable of achieving a 15 to 35% NOX reduction (7). It was
assumed that OFA can reduce uncontrolled NOX emissions by 35% for tangential boilers that
were in service after 1974 or that had furnace volumes similar to post-NSPS boilers. For
boilers in service before 1974, a NOX emission reduction of 25% was assumed. For boilers
firing coals with high slagging tendencies, NOX emission reductions were reduced by 5%
(i.e., 25 - 5 = 20).
Natural Gas Reburninq
NGR is included in this analysis, although it is not as commercially developed as the other
NOX control technologies. Including NGR in the study provides a moderate NOX control level
(relative to SCR) where LNBs are inapplicable (cyclone furnaces, slagging wall-fired units,
unusual firing types. The NOX reduction performance of NGR would be affected by some of
the same factors discussed previously for LNC.
The Gas Research Institute is hoping to achieve NOX reductions as high as 75% on high-
NOx-emitting boiler types. However, because of the lack of commercial demonstration
performance data, a single estimate of 60% NOX reduction was used in this study. To
achieve 60% NOX reduction, it was assumed that 15% of the boiler heat input would be
injected into the upper furnace as natural gas. Capital costs include the installation of natural
gas and OFA injection ports into the upper furnace, reburn gas supply piping, and controls.
Selective Catalytic Reduction
The major equipment items for an SCR system include the catalyst, ammonia system,
controls, air preheater modifications or flue gas reheater, ductwork, and fan. The catalyst
volume is based on the flue gas flow rate and an 80% NOX reduction. The SCR equipment
cost estimates were developed from EPRI (8) and EPA (9) studies.
The IAPCS cost algorithms are based on new unit installation. In order to adjust these costs
for specific retrofit situations, scope adders (additional equipment costs) and retrofit factors
(difficulty multipliers) were used to adjust the costs. Scope adder costs considered were:
1-33
-------
duct and building demolition,
new duct work,
new roads and replacement and demolished facilities, and
new air heater (hot-side) or flue gas reheater (cold-side).
The EPRI flue gas desulfurization (FGD) retrofit guidelines (10) were used to develop costs
for the first three items. New roads and replacement of facilities were handled as increases
in general facilities. New air heater and flue gas reheater costs are based on a vendor quote
for a 500-MW plant and scaled by a 0.6 factor (9).
Access/congestion and underground obstruction factors were applied to the catalytic reactor
area. The EPRI FGD retrofit guideline factors for the SO2 and flue gas handling area were
used. The scope adjustments and retrofit difficulty factor were input to the IAPCS model to
generate the site-specific retrofit cost estimates.
IAPCS COST MODEL RESULTS
The site-specific model inputs developed for each NOX control technology were input to the
IAPCS cost model, along with other boiler and coal characteristics. The model generated
capital, operating and maintenance, and levelized annual costs of control and emission
reductions. Table 1 summarizes the economic bases used to develop the cost estimates.
Economic assumptions such as inflation rate, cost of money, cost of consumables, and
expected plant life are from the 1986 EPRI Technical Assessment Guide (1J) escalated to
1988 dollars.
For each control technology, cost per ton of NOX removed (Figures 3 and 5) and annual cost
(Figures 4 and 6) are plotted versus the sum of controlled megawatts. In each figure, the x-
axis (sum of megawatts) is the cumulative sum of the boiler size sorted in order from the
lowest to the highest cost to control. Also identified on each curve are the 25, 50, and 75
sum of megawatt percent points for the boilers included in the figures. Each point on the
curves represents a specific boiler cost result. The first point represents the boiler that had
1-34
-------
the lowest cost. The last point represents the boiler that had the highest cost. The curves
turn up sharply because each curve was developed starting with the boiler having the lowest
control cost and ended with the boiler have the highest control cost. The cost results .do not
represent the average or cumulative cost of control.
Costs developed in this report are based on economic assumptions that may not represent a
particular utility company's economic guidelines. The cost results are static (not dynamic)
and represent a single year (1985 base year or another year specified by the individual utility
company) with regard to capacity factor, coal sulfur, and pollution control characteristics.
Low NO^ Combustion Cost Results
Figures 3 and 4 summarize the unit cost and the annual cost, respectively, of retrofitting LNB
at 228 boilers, OFA at 214 boilers, and NGR at 81 boilers. In general, boilers having low unit
costs and annual costs are large, and have high capacity factors and high NOX reduction
efficiencies. Boilers having high unit costs and annual costs are small and have low capacity
factors and low NOX reduction efficiencies.
LNB were applied to wall-fired dry-bottom boilers. The boiler characteristics of the low, mid,
and high unit cost are:
Low $/ton Mid $/ton High $/ton
NOX Unit Cost $/ton 50 150 1315
Boiler size MW 1000 640 45
NOX Reduction % 53 43 40
Capacity Factor % 83 48 28
NOX Removed - tons/yr 15828 4586 183
Of the 228 boilers, 16% were estimated to have high (45 to 55%) NOX reduction efficiencies;
61% were estimated to have moderate (35 to 45%) NOX reduction efficiencies; and 23% were
estimated to have low (25 to 35%) NOX reduction efficiencies.
1-35
-------
OFA controls were applied to tangential-fired boilers. The boiler characteristics of the low,
mid, and high unit cost are:
Low $/ton Mid $/ton High $/ton
NOX Unit Cost - $/ton 27 100 1248
Boiler size MW 865 350 29
NOX Reduction % 35 25 25
Capacity Factor % 79 56 18
NOX Removed - tons/yr 6895 1271 39
Of the 214 boilers, 4% were estimated to have high (26 to 35%) NOX reduction efficiencies;
73% were estimated to have moderate (25%) NOX reduction efficiencies; and 23% were
estimated to have low (15 to 24%) NOX reduction efficiencies.
NGR controls were applied to wet-bottom boilers and boilers having unusual firing types
(e.g., roof-fired). The cost of NGR is much greater than LNB and OFA because of the fuel
price differential between natural gas and coal. The cost results presented here are based
on a fuel price differential of $2 per million Btu and 15% natural gas substitutes. Reducing
the fuel price to $1 per million Btu reduces the unit cost by -50%. Not included in the unit
cost is the benefit of the 15% reduction in SO2 due to the 15% fuel substitution. If the SO2
reduction were included in the unit costs, the unit cost of NGR would be reduced by 15 to
45 percent.
Selective Catalytic Reduction Cost Results
In this study, cost estimates for SCR were developed for 624 boilers: 577 boilers with cold-
side systems and 47 boilers with hot-side systems. Figures 5 and 6 summarize the cost
estimates for application of SCR. For cold-side systems, a significant energy penalty occurs
with flue gas reheating, (equivalent to 120°F reheat). This cost was not included in this study
because the earlier version of the IAPCS model did not estimate this cost. Reheat costs
estimated by the most recent version of IAPCS (12) increase the annual cost of control by 20
to 30% for cold-side systems.
1-36
-------
Costs presented here are for a 3-year catalyst life. However, clean gas applications of SCR
may have much longer catalyst life. Annual and unit costs estimated for a 7-year catalyst life
are 10 to 20% less than those with 3-year catalyst life.
For SCR, the boiler characteristics of the low, mid, and high unit cost are:
Low $/ton Mid $/ton High $/ton
NOX Unit Cost - $/ton 710 1810 6091
Boiler size MW 217 543 45
NOX Reduction - % 80 80 80
Capacity Factor % 94 49 28
NOX Removed - tons/yr 10,546 8331 366
CONCLUSION
There is a high degree of uncertainty regarding the cost and performance of retrofitting NOX
controls on U.S. boilers because of the very limited commercial application experience.
Passage of the Clean Air Act Amendments of 1990 require that NOX emissions from wall- and
tangential-fired boilers meet NOX emission limits of 0.5 and 0.45 pounds per million Btu by
applying LNB. These emission limits do not apply to cell-fired and wet-bottom boilers. The
results of this study show that the application of LNB and OFA are likely to have a wide
range of effectiveness for retrofit applications. As result, it can be expected that many units
may have difficulty achieving emission limits of 0.5 and 0.45 pounds per million Btu through
the application of LNB and OFA. The study results and study database can provide
guidance in evaluating the effectiveness of retrofitting LNC controls, but because of the
complexities of combustion modification controls the results of this study could vary widely
from the NOX reductions that can be achieved in practice.
1-37
-------
REFERENCES
1 Emmel T E., S. D. Piccot, and B. A. Laseke. Ohio/Kentucky/TVA Coal-Fired Utility
S02 and NOX Control Retrofit Study. EPA-600/7-88/014 (NTIS PB88-244447/AS), U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina, 1988.
2. Smith, L. L, Energy Technology Consultants, Inc. Evaluation of Radian/EPA NOX
Reduction Estimation Procedures. Radian Corporation, Research Triangle Park,
North Carolina, 27709. February 1988.
3. Emmel, T.E., et al. Comparison of West German and U.S. Flue Gas Desulfurization and
Selective Catalytic Reduction Costs. EPA-600/7-90-009, U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina 27711. April 1990.
4. Emmel, T. E., and M. Maibodi. Retrofit Costs for SO2 and NOX Control Options at 200
Coal-Fired Plants. EPA-600/7-90-021a, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina 27711. November 1990.
5. Palmisano, P. J., and B. A. Laseke. User's Manual for the Integrated Air Pollution
Control System Design and Cost Estimating Mode, Version II, Volume I. EPA-600/8-
86/031 a (NTIS PB87-127767), U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, 1986.
6. Elliot, T. C., ed. Powerplants Database, Details of the Equipment and Systems in Utility
and Industrial Powerplants, 1950-1984. McGraw-Hill, Inc., New York, New York, 1985.
7. Thompson, R. E., and M. W. McElroy. Guidelines for Retrofit Low NOX Combustion
Control. In Proceedings: 1985 Symposium on Stationary Combustion NOX Control,
Volume 1, EPA-600/9-86-021a (NTIS PB86-225042), July 1986.
8. Bauer, T. K., and P G. Spendle. Selective Catalytic Reduction for Coal-Fired Power
Plants: Feasibility and Economics. EPRI CS-3603, Electric Power Research Institute,
Palo Alto, California, 1984.
9. Burke, J. M., and K. L. Johnson. Ammonium Sulfate and Bisulfate Formation in Air
Preheaters. EPA-600/7-82-025a (NTIS PB82-237025), U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, 1982.
10. Shattuck, D. M., et al. Retrofit FGD Cost Estimating Guidelines. EPRI Report CS-3696,
Electric Power Research Institute, Palo Alto, California, 1984.
11. Electric Power Research Institute. Technical Assessment Guide (TAG), Volume 1.
Electricity Supply-1986. EPRI Report P-4463-SR, Palo Alto, California,'1986.
12. Maibodi. M, et al. Integrated Air Pollution Control System, Version 4.0, Volume 2:
Technical Documentation Manual. EPA-600/7-900-022b, U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina 27711. December 1990.
1-38
-------
Table 1.
ECONOMIC BASES USED TO DEVELOP THE COST ESTIMATES
Item Value
Operating labor 19.7 $/person-hour
Natural gas to coal fuel price difference $2/million Btu
Electric Power 0.05 $/kWh
Catalyst cost 20,290 $/ton
1988 constant dollar levelization factors
Operating and maintenance 1.0
Capital carrying charges3 0.105
aBook life - 30 years; Tax life 20 years; Depreciation Method Straight Line; and Discount
Rate 6.1%.
1-39
-------
Phase I
Develop Detailed Procedures
Phase II
Select 12 Plants and Develop Cost
& Performance Estimates
Revise Procedures Based on Utility
and Advisory Committee Input
Develop Simplified Procedures
Low NOx Burner and Over Fire
Air NOx Reduction Procedure
Recommendations by ETEC
Results of Site Visits and
Review of Cost of Selective
Catalytic Reduction at 5
German Coal-fired Plants
Phase III
Develop Cost & Performance Estimates
For Boilers at 200 U.S.
Coal-fired Power Plants
Phase IV
Incorporate Utility and NAPAP Review
Comments into 200 Plant
Study Final Report
FIGURE 1. 200 PLANT STUDY TECHNICAL APPROACH.
1-40
-------
Site Specific Information Sources
Aerial
Photographs
SCR
Retrofit Factors
and Scope
Adder Costs
Energy Information Administration
- 767 Form
Boiler/Coal Characteristics
Estimated NOx Reduction
Cost Model Inputs
Utility Comments and
Other Data Sources
Integrated Air Pollution Control System
Cost Model Outputs
Boiler/Coal Parameters
1
Capital Costs O & M Costs Annualized Costs Emission Reduction
FIGURE 2. SITE-SPECIFIC COST ESTIMATION METHODOLOGY.
-------
Q
LU
o
2
01
DC
o
o
o
NGR
LNB
X OFA
1988 CONSTANT DOLLARS
75% of Boilers
50% of Boilers
25% of Boilers
400
200
20,000
40,000
60,000
SUM OF MW
FIGURE 3. SUMMARY OF COST PER TON OF NOx REMOVED RESULTS FOR LOW
NOx COMBUSTION.
-------
GO
.c
X
s^
I-
o
O
6
5 -
0
A LNB
X OFA
• NGR
1988 CONSTANT DOLLARS
75% of Total MW
V
50% of Total MW
25% of Total MW
40.000
SUM OF MW
60.000
FIGURE 4. SUMMARY OF ANNUAL COST RESULTS FOR LOW NOx COMBUSTION
-------
Q
LU
o
5
LU
DC
X
O
z
c
o
O
O
7,000
6,000
5,000
4,000
3,000
2,000
1,000
1988 CONSTANT DOLLARS
25% of Boilers
\
3 YEAR CATALYST LIFE
\ i i i i i i i r t i i \ i i i i i i
20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000
SUM OF MW
FIGURE 5. SUMMARY OF ANNUAL COST RESULTS FOR SELECTIVE CATALYTIC
REDUCTION.
-------
en
j»
^-»
I-
o
o
Z
z
24
20
16
12
8
0
1988 CONSTANT DOLLARS
3 YEAR CATALYST LJFE
i i r
0 20.000
i r
60.000
100.000
i i
140.000
180.000
SUM OF MW
FIGURE 6. SUMMARY OF COST PER TON OF NOx REMOVED RESULTS FOR
SELECTIVE CATALYTIC REDUCTION.
-------
NITROGEN OXIDES EMISSION REDUCTION PROJECT
Larry Johnson, Project Manager
Case Overduin, Supervising Engineer
Southern California Edison
2244 Walnut Grove Avenue
Rosemead, California 91770
-------
NITROGEN OXIDES EMISSION REDUCTION PROJECT
ABSTRACT
Utilities in the Southern California South Coast Air Basin are subject to regula-
tions requiring over a 77% reduction in NOx from their oil/gas fired units and over
50% reduction from stationary gas turbines. This paper describes Edison's efforts
in developing a strategy to meet these new requirements and in parallel pursuing
new technologies which potentially will save Edison and our ratepayers significant
costs while still meeting the requirements of the South Coast Air Quality Management
District.
1-49
-------
NITROGEN OXIDES EMISSION REDUCTION PROGRAM
INTRODUCTION
On August 4, 1989 the South Coast Air Quality Management District in Southern
California adopted Rules 1134 and 1135 which require significant NOx reductions on
the utilities in the air basin. In order to comply with the new requirements
Southern California Edison has assembled the Nitrogen Oxides Emission Reduction
Project which has two main objectives.
Comply with Rules 1134 and 1135
• Reduce the costs of complying with the Rules
The analysis and planning involved in an effort to meet these two objectives is
discussed below as well as the results to date in both cost and performance.
BACKGROUND
Although Rules 1134 and 1135 were adopted in August 1989, studies and alternatives
for meeting various levels and timetables for NOx reduction were under evaluation
over a year prior to final adoption. Also, studies and alternatives continue to
be evaluated due to a number of factors as follows:
Rule 1135 was revised on December 21, 1990
Further revisions are expected May this year
Results of new technologies will be forthcoming
• Results of unit retrofits vary with technology
The basics of Rules 1135 and 1134 are shown in Figure 1. Because the majority of
the impact and cost of complying is associated with Rule 1135, the balance of this
paper will deal with this aspect.
1-50
-------
ANALYSIS OF CONTROL OPTIONS
Control Technologies
Following an evaluation of applicable NOx reduction control systems, three mature
technologies were chosen for potential application on 29 SCE steam generators.
These technologies are:
Combustion Modifications. Combustion modifications involve the replacement or
upgrading of existing burners with Low NOx Burners which employ various methods of
staged combustion to mitigate thermal NOx formation. Low NOx burners can be
combined with flue gas recirculation to the windbox where such a system does not
exist already.
Urea Injection. This technology involves the injection of Urea (Nh^CON^)
into the furnace exit and/or boiler convection pass. If the temperature in these
boiler locations is between 1650 and 1850°F, the Urea reacts with the NOx in the
combustion flue gases to form nitrogen, water, and carbon dioxide. If the flue
gas temperature is too high (>2000°F) NHj radicals formed from the
di sassoci ation of the urea will oxidize to form additional NOx. Should the
temperature be too cold (<1500°F) the NH^ radials will recombined to form
ammonia which will "slip" through unreacted diminishing the effectiveness of the
Urea system. Because of this temperature sensitivity system performance is very
dependent on boiler type and geometry.
Selective Catalytic Reduction. Selective Catalytic Reduction or SCR involves the
injection of NH3 in the flue gas to convert the NOx to innocuous nitrogen and
water. The reaction is effective at gas temperatures between 600 to 750°F in
the presence of a catalyst. This temperature typically exists at the boilers
economizer outlet and just upstream of the air-preheater. Catalyst volume
requirements are such that typically a major retrofit of the boiler backend is
required to accommodate the reactor containing the catalyst and associated ducting.
Removal Performance
The removal performance is dependent on the boiler being treated and in particular
with urea injection, substantial temperature and flow testing is needed to predict
NOx removal efficiencies as a function of load. For analysis and initial
selection of NOx controls required to meet the new NOx limits the following
average removal efficiencies have been assumed:
Technology Removal Efficiency
Combustion Modifications
without Flue Gas Recirculation 10%
Combustion Modifications
with Flue Gas Recirculation 30%
Urea Injection 35%
Selective Catalytic Reduction 90%
1-51
-------
Technology Costs
Capital costs for NOx removal technologies vary in particular for SCR systems
which are highly dependent on the amount of boiler retrofit required to
accommodate the SCR reactor and ducting. When expressed as capital requirements
per unit capacity the following averages were estimated for SCE generating units.
Urea injection
Combustion Modifications w/FGR
Combustion Modifications w/o FGR
Selective Catalytic Reduction
$3/kW
$28/kW
$9.30/kW
$100 to $120/kW
Generating Units Subject to NOx Reduction
The generation system subject to NOx reduction regulation consists of 28 units
with a total capacity of 6626 MW. All units are conventional oil and gas fired
steam generators and vary in size from 480 MW supercritical units built in the mid
sixties to 33.5 MW drum type generators constructed in the early fifties. The
units are located throughout the South Coast Air Basin at seven generating
stations as indicated in Table 1.
NOx Control Selection Methodology
With three basic control technologies and seven control technology combinations
available for possible application on 30 units, a myriad of control-unit
combinations can be applied to meet the new lower NOx emission limit of
Rule 1135. Considerable savings can be achieved by applying controls selectively
rather than across the board.
To find the lowest cost control solution the technique of linear programming (LP)
was used which is a mathematical technique for solving complex allocation and
planning problems. LP selected which controls were to be applied to what units to
attain the lowest theoretical Rule compliance cost. This mathematical selection,
adjusted for operational and construction considerations and constraints, formed
the basis for SCE's compliance plan.
SUMMARY OF COMPLIANCE PLAN AND COST
SCE submitted a Compliance Plan to fulfill the requirements of the SCAQMD to
identify the type and location of NOx controls planned to be installed to meet or
exceed the emission limitations and compliance schedule. The plan identifies the
installation of urea injection of 20 units, the implementation of combustion
retrofit of 9 units with SCR systems. An
Figure 2 and was designed to meet the interim
.25 Ib/MWHR system emission level required by
modifications of 9 units, and the
implementation schedule is shown in
emission levels as well the ultimate
the end of 1999 as illustrated in Figure 3.
The compliance cost has been estimated at $673 million installed cost.
Demonstration Technologies
The second major objective of the project is to reduce the overall cost of
compliance. The methodology used in arriving at a compliance plan as described
above does produce the most cost effective scenario for meeting the rule using
1-52
-------
proven technologies. However, additional cost savings may be realized by using
more advanced NOx control technologies which are ready for demonstration level
testing. Many new technologies were reviewed and four were selected for
demonstration on the Edison system.
• Advanced Low NOx Burners
• High Energy Urea Injection
Selective Catalytic Reduction Air Preheater
• Economizer (In-Duct) SCR
Figures 4-7 show schematically the basics of each technology. The Low NOx Burner
(LNB) was installed on 1-row of Alamitos Generating Station Unit 5 (480 MW). By
installing just 1-row (replacing onewhich is out of service) the operability of the
unit is not affected and yet the stability and potential NOx reduction capability
of the new burner can be tested. The high energy urea injection demonstration was
installed on Huntington Beach Unit 2 (215 MW). The primary purpose was to assess
the ability to inject urea into a narrow cavity and achieve a high level of NOx
reduction (50-60%). The 'basic difference between this type of urea injection
and the previously discussed system is the use of large blowers/compressors to
enhanced the injection and mixing. The selective catalytic reduction air
preheater utilizes replacement SCR baskets in place of the existing plate baskets
used in Lungstrum type air preheaters. At least two previous installations were
tried in Germany on coal fired units. One half or 1-wheel of Mandalay Unit 2
(215 MW) is being modified with this system. The last demonstration is the
economizer or in-duct SCR which will be installed on Redondo Unit 8 (480 MW).
This system utilizes advanced catalyst design and basically attempts to install as
much catalyst as possible between the economizer and the air preheater without
having an appreciable affect on unit performance.
The installation of these demonstrations is projected to cost over $20 million.
However, the potential savings assuming some of these technologies are successful
and can be retrofitted on units compatible with a given technology is projected to
be between $100-200 million. The reasons for this large potential is apparent
when you compare the average capital costs for conventional SCR at $100-$120/kW
versus the demonstration costs shown on Figure 8. By combining technologies as
shown in Figure 9 a reduction sufficient to meet the requirements of the rule can
be met at theoretically much less cost.
Status of Project
Compliance with Rule 1135 is proceeding per the compliance scenario as shown in
Figure 3. To date, this has been accomplished for the most part with optimization
of the existing units. Installation has been completed on two 320 MW urea
injection systems for a reduction of 357,, over the load range. Eight additional
urea systems are in various stages of construction with installation by July of
this year.
Two of the four demonstrations, LNB and High Energy Urea Injection have been
completed and initial testing concluded. The LNB installation should provide in
excess of 15% reduction if utilized on a complete boiler. The high energy urea
system as tested in a narrow cavity has not provided significant NOx reduction.
Reduction typically ranged between 20-25%. It does not appear at this time to be
a viable option for narrow cavity injection where downstream tubes cool the flue
gases immediately after the urea injection occurs.
1-53
-------
The installation of the SCR air preheater system is complete with startup and
testing to begin shortly. The economizer SCR project construction has been
deferred to the fall of this year due to permitting problems.
Conclusions
Each system, boiler, and the specific NOx reduction requirements have to be
analyzed very carefully to match technologies with individual units and their
associated costs in order to achieve a cost effective program for NOx reduction.
For Edison's case no one technology is the solution for cost effective NOx
reduction. Although a solution can be found utilizing existing technologies,
variations in performance of these technologies as well as potential advancement
in NOx technologies make it imperative that planning remain flexible within the
constraints of time and schedule. The project must integrate these elements as
well as operating constraints, permitting requirements and budgeting constraints.
In essence the project team needs to be well-rounded within the company as well as
outside in order to successfully complete any major systemwide pollution reduction
program.
1-54
-------
SUMMARY - RULE 1135
Requires .25 Ib. NOx/MWh by December 31, 1999
Averaging time is calendar day
Systemwide averaging
Incremental compliance schedule starting in 1990 through 1999
Edison to install and operate an SCR unit on a 480 MW steam generator by
December 31, 1993
SUMMARY - RULE 1134
Requires 15 ppm NOx by December 31, 1995 for combined cycle units >60 MW
Requires certified continuous in-stack monitoring
Exempts peaking units operating less than 200 hours/year
FIGURE 1. SUMMARY - RULES 1135,1134
1-55
-------
Table 1
BOILERS SUBJECT TO RULE 1135
Station
Alami tos
Alami tos
Alami tos
Alami tos
Al ami tos
Alami tos
El Segundo
El Segundo
El Segundo
El Segundo
Etiwanda
Etiwanda
Etiwanda
Eti wanda
Hi ghgrove
Hi ghgrove
Hi ghgrove
Hi ghgrove
Huntington Beach
Huntington Beach
Huntington Beach
Huntington Beach
Redondo
Redondo
Redondo
Redondo
Redondo
San Bernardino
San Bernardino
Unit
1
2
3
4
5
6
1
2
3
4
1
2
3
4
1
2
3
4
1
2
3
4
1-4
5
6
7
8
1
2
Maximum Rated
Capacity, MN
175
175
320
320
480
480
175
175
335
335
132
132
320
320
32.5
32.
44.
44.
215
215
215
225
292
175
175
480
480
63
63
Total
6626
1-56
-------
Compliance Schedule
Technology/
Activity Descriptions
Rule 1135
Urea Injection (5,600 MW)
Combustion Mods (1,900 MW)
SCR (3,200 MW)
Repower (1,000 MW)
1989
HIS
1990
1991
SSilS
;;Elflf
1992
SfHH
!x\X>vW:X\}»
^XXlvSXl;
1993
^
1994
ilSSSS
1995
1996
11
1997
•OV:;:;.^'.^
S;->"':>>S".;xv
1998
SSiS
1999
S;S:WS
1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
FIGURE 2
-------
NOx Lb./MWh
1.50
NOx Emissions Compliance Schedule
(Rule 1135)
1.10
1.00
.75
.50
.25
Proposed Rule 1135
Compliance Illustration
I I I I
I I I I
1989 90 91 92 93 94 95 96 97 98 99 2000
FIGURE 3
-------
Low NOx Burner
Typical Installation
en
CD
Flue
Gas
To stack
Air
Preheater
Forced Draft
Fan
FIGURE 4
-------
High Energy Urea Injection
Demonstration Project
Super Heater
Urea
Injection
Ports
Reheater
Super Heater
Economizer
To Air Heater
High Pressure
Urea Injection
Pump Ok
Urea Day Tank
Air Compressor
FIGURE 5
-------
CD
Burners
SCR/Air Preheater
Typical Installation
Economizer
Air preheater
SCR modules
To
injection grid
To stack vaporizer
FD Fan
CD
Liquid ammonia
storage tank
Air
blower
FIGURE 6
-------
Economizer SCR
Typical Installation
Rue
Gas
Boiler
Burners ^' •
HI Catalyst
Modules
Economizer
To ammonia
injection grid
To stack
Ammonia
vaporizer
Air Forced Draft
Preheater Fan
Liquid ammonia
storage tank
Air
blower
FIGURE 7
-------
Proposed Demonstration Technologies
NOx Controls $/kW % Reduction
High energy urea 25 50-60
Economizer SCR 34 50-80
SCR air preheater 23 40
Burners 10 15
FIGURE 8
-------
Suggested Scenarios for NOx Reduction
NOx (ppm)
120
100
75
50
25
Baseline
New limit
SCR
Economizer
I I I I
25 50 75 100%
Load (percent)
FIGURE 9
-------
THE GLOBAL ATMOSPHERIC BUDGET OF NITROUS OXIDE
Joel S. Levine
Atmospheric Sciences Division
NASA Langley Research Center
Hampton, Virginia 23665
-------
THE GLOBAL ATMOSPHERIC BUDGET OF NITROUS OXIDE
ABSTRACT
While only a trace constituent in the atmosphere at a concentration of about 0.31 parts
per million by volume, nitrous oxide is very important. Nitrous oxide is a greenhouse gas
that impacts global climate and also leads to the chemical destruction of stratospheric
ozone, which shields the Earth from biologically lethal solar ultraviolet radiation (200-
300 nm). Nitrous oxide is increasing in the atmosphere at a rate of 0.2-0.3% per year.
Fundamental uncertainties exist in our understanding of global sources of nitrous oxide.
Recent measurements have downgraded the global production of nitrous oxide by two
sources once believed important—fossil fuel combustion and biomass burning. Suggestions
for new sources of nitrous oxide include the "fertilization" of natural soils by nitrate formed
from atmospheric nitric oxide which enhances biogenic soil emissions of nitrous oxide and
enhanced biogenic soil emissions of nitrous oxide following surface burning.
1-67
-------
THE GLOBAL ATMOSPHERIC BUDGET OF NITROUS OXIDE
INTRODUCTION
Nitrous oxide (N2) with a concentration of only about 0.31 parts per million by volume is the
most abundant atmospheric nitrogen species after molecular nitrogen (N2). Nitrous oxide is
a very long-lived gas with an atmospheric lifetime of about 150 years (1). Nitrous oxide is an
important atmospheric constituent for two reasons—it is a greenhouse gas that traps Earth-
emitted infrared or heat energy (2) and it leads to the chemical destruction of stratospheric
ozone (1). A single nitrous oxide molecule has the greenhouse warming potential of about
250 carbon dioxide molecules (3) with strong absorption bands at 520-660 cirr1, 1200-
1350 cm-1, and 2120-2270 cm-1 (4). Nitrous oxide is chemically inert in the troposphere
and is only destroyed once it diffuses into the stratosphere. The atmospheric destruction of
nitrous oxide is due to photolysis and reaction with excited atomic oxygen (O(1D)) (1):
(1) N2O + hi/ -> N2 + O(1D), A < 341 nm
(2) N2O + O(:D) -* NO + NO
(3) N2O + O^D) -> N2 + O2
The photolysis of nitrous oxide (reaction (1)) is responsible for about 90% of its destruction
with reactions (2) and (3) each accounting for about 5% of its destruction (1). Reaction (2)
leads to the production of nitric oxide (NO) which leads to the chemical destruction of
stratospheric ozone (O3) through the nitrogen oxide catalytic cycle (1):
(4) NO + O3 - NO2 + O2
(5) NO2 + O -+ NO + O2
The net reaction of reactions (4) and (5) is: O3 + O -> 2O2. The nitrogen oxide catalytic cycle
is responsible for about 70% of the global chemical destruction of stratospheric ozone (5).
Stratospheric ozone absorbs solar ultraviolet radiation (200-300 nm) and shields the Earth's
surface from this biologically lethal radiation. Measurements indicate that atmospheric
concentrations of nitrous oxide are increasing at a rate of about 0.2 to 0.3% per year (6).
GLOBAL SOURCES OF NITROUS OXIDE
The major uncertainty in our understanding of nitrous oxide concerns its global sources. The
magnitude of its global sources must balance its rate of global destruction plus its rate of
1-68
-------
atmospheric accumulation. Photolysis (reaction (1)) and reaction with excited atomic oxygen
(reactions (2) and (3)) destroy about 10.5 ± 3.0 Teragram of N in the form of N2O per year
(1 Teragram of or 1 Tg = 106 metric tons = 1012 grams) (7). The atmospheric accumulation
of nitrous oxide requires an additional 3.5 ± 0.5 Tg N per year (7). Hence, the total global
production of nitrous oxide must be about 14 ± 3.5 Tg N per year.
Estimates of global sources of nitrous oxide are summarized in Table 1. Inspection of
Table 1 indicates that soils, either natural or unfertilized, and fertilized agricultural fields are
important global sources of nitrous oxide. Nitrous oxide is a free intermediate in microbial
denitrification in anaerobic environments. Denitrification involves the reduction of soil nitrate
(NO3~) to nitrate (NO2~) and then to nitrous oxide. However, almost all of the nitrous oxide
produced by denitrification in anaerobic environments is consumed by microorganisms which
use nitrous oxide as an oxidant. Significant quantities of nitrous oxide are also produced in a
variety of aerobic or partially aerobic soil environments via nitrification. Nitrification involves
the oxidation of reduced soil nitrogen, such as a ammonium (NH4+), to nitrous oxide. In the
oceans it is unclear whether nitrous oxide is primarily produced from nitrification in the oxygen-
rich surface waters or from denitrification in the oxygen-deficient deep waters. In fertilized
agricultural fields the use of nitrate and ammonium fertilizers enhances the production of
nitrous oxide via denitrification and nitrification, respectively. The conversion percentage of
fertilizer nitrogen to nitrous oxide ranges from 0.01 to about 2% (15). The annual global
production of nitrogen fertilizer in 1990 was estimated at about 55 Tg N and is increasing
with time (15). The leaching of nitrogen fertilizers from agricultural fields into ground water
may result in additional emissions of nitrous oxide (16).
The total global production of nitrous oxide of 11.2-16.1 Tg N per year (Table 1) is consistent
with the amount needed to balance the rate of global destruction of nitrous oxide and its rate
of accumulation in the atmosphere (10.5-17.5 Tg N per year). However, that was before
measurements of nitrous oxide from combustion sources collected and stored in sampling
bottles prior to analysis using a gas chromatograph/electron capture detector were found
to be questionable due to the presence of an artifact which caused nitrous oxide in the
sampling bottles to increase with time (17). In the sampling bottles, fossil fuel combustion
products, nitric oxide, sulfur dioxide, and water vapor formed nitrous oxide at a level of several
hundred parts per million only several days after collection (17). Since all determinations of
combustion-produced nitrous oxide were based on the chemical analysis of samples collected
and stored in such bottles, all such measurements are questionable. Real time, in situ
continuous analyzers for nitrous oxide measurements in fossil fuel burners recorded nitrous
oxide concentrations of only 5 parts per million or less (17,18,19). These significantly lower
nitrous oxide concentrations correspond to a fossil fuel combustion source of nitrous oxide of
1-69
-------
only between 0.1-0.3 Tg N per year(2Q), rather than the earlier estimates of about 3.2 Tg N
per year (12).
The question arose whether the nitrous oxide artifact discovered in fossil fuel combustion
sampling bottles also affected biomass burn samples which are collected in identical sampling
bottles. Measurements did indeed confirm that on occasion, concentrations of nitrous oxide
increased in sampling bottles several days after collection (21). To assess the concentration
of nitrous oxide produced in biomass burning without the artifact effect, a real time, in situ
measurement technique was developed which consisted of a gas chromatograph/electron
capture detector flown in a helicopter directly over a 300-hectare fire (22). This new
measurement technique yielded a mean emission ratio of nitrous oxide to carbon dioxide
production in biomass burning of 0.015% (22). To arrive at the global nitrous oxide production
per year due to biomass burning, this emission ratio is multiplied by the global carbon dioxide
production per year due to biomass burning. For a value of 2850 Tg carbon in the form of
carbon dioxide produced per year by biomass burning, the corresponding annual production
of nitrous oxide is about 1 Tg N (22). For 1425 Tg carbon in the form of carbon dioxide, the
corresponding annual production of nitrous oxide is about 0.5 Tg N.
Using the new artifact-free estimates for nitrous oxide production due to fossil fuel combustion
and biomass burning, the global production of nitrous oxide is reduced from 11-16 Tg N per
year (see Table 1) to 7.5-12.6 Tg N, and the global budget of nitrous oxide is no longer in
balance.
The missing nitrous oxide needed to balance the global destruction and the atmospheric
accumulation of nitrous oxide may be due either to an underestimate of the strength of
known sources or it may be that there are as yet unknown global sources of nitrous oxide.
Two new sources of nitrous oxide have recently been suggested. Measurements of biogenic
emissions of both nitrous oxide and nitric oxide from temperate soils following burning indicate
a significant enhancement in the emission of both of these gases (23, 24). Prior to surface
burning, the biogenic emissions of nitrous oxide were not detected, which indicates a nitrous
oxide emission of below 2 ng N rrr2 s~l, the minimum detectable emission of the gas
chromatograph, to more than 20 ng N rrr2 s"1 following burning (24). Measurements
indicated that the enhanced post-burn nitrous oxide emission persisted for at least 6 months
after the burn (23). The post-burn enhancement of nitrous oxide is believed to be related
to the measured post-burn enhancement of soil ammonium (NH4+) (24). Measurements
indicate that soil ammonium increased by more than a factor of 3, while the soil nitrate
(NO3-) decreased after burning (24). Soil ammonium is the substrate utilized by nitrifying
microorganisms in the production of both nitrous oxide and nitric oxide (24,25,26,27). Recent
1-70
-------
measurements indicate that on a global basis, biomass burning is much more widespread
than previously believed and that it appears to be increasing with time (28,29,30). More
information is needed before the impact of enhanced post-fire nitrous oxide emissions on the
global production of nitrous oxide may be accurately assessed.
Another source not previously evaluated is enhanced emission of nitrous oxide resulting
from "fertilization" of atmospheric nitrate on natural soils (31). The atmospheric nitrate
that stimglates microbial production of nitrous oxide results from nitric oxide chemically
transformed to nitrate in the atmosphere. Hence, it may be that nitric oxide may enhance the
biogenic emission of nitrous oxide in natural soils (31). The impact of nitric oxide-produced
nitrate on the global production of nitrous oxide has not yet been assessed. It is ironic that
nitric oxide emissions produced in part to reduce nitrous oxide emissions in various fossil
fuel combustion schemes may eventually lead to enhanced emissions of nitrous oxide from
the soil.
The buildup of atmospheric greenhouse gases, carbon dioxide, nitrous oxide, methane,
and chlorofluorocarbon 11 and 12 will lead to global warming (20). A global temperature
increase will have a positive feedback on soil emissions of nitrous oxide. The production of
nitrous oxide in soil via denitrification and nitrification increases with soil temperature (27).
Furthermore, global warming may result in increased drought conditions (20). Both higher
temperatures and drought conditions are conducive to an increased frequency of burning.
Increased burning will lead to enhanced production of nitrous oxide both as a direct
combustion product of burning and as post-burn enhanced biogenic soil emissions of nitrous
oxide. Hence, global warming may very well lead to enhanced emissions of nitrous oxide
due to biogenic production in soil and by biomass burning combustion.
REFERENCES
1. R. P Turco. "The Photochemistry of the Stratosphere." The Photochemistry of
Atmospheres (J. S. Levine, editor). Orlando: Academic Press, Inc., 1985, pp. 77-128.
2. W. R. Kuhn. "Photochemistry, Composition, and Climate." The Photochemistry of
Atmospheres (J. S. Levine, editor). Orlando: Academic Press, Inc., 1985, pp. 129-163.
3. C. S. Silver and R. S. DeFries. One Earth One Future: Our Changing Global Environ-
ment. Washington, D.C.: National Academy Press, 1990, pp. 64-67.
4. J. F. B. Mitchell. "The Greenhouse Effect and Climate Change." Reviews of Geophysics,
27, 1988, pp. 115-125.
1-71
-------
5. R. P. Wayne. Chemistry of Atmospheres. London: Oxford University Press, 1985,
pp. 113-173.
6. R. Prinn, D. Cunnold, R. Rasmussen, P. Simmonds, F. Alyea, A. Crawford, and R. Rosen.
"Atmospheric Trends and Emissions of Nitrous Oxide Deduced from Ten Years of
ALE/GAGE Data." Journal of Geophysical Research, 1990.
7. Word Meteorological Organization. Global Ozone Research and Monitoring Project
Report No. 16: Atmospheric Ozone 1985, 1985, Volume I, pp. 77-84.
8. P A. Matson and P. M. Vitousek. "Cross-System Comparisons of Soil Nitrogen Transfor-
mations and Nitrous Oxide Flux in Tropical Forest Ecosystems." Global Biogeochemical
Cycles, 1, 1987, pp. 163-170.
9. F. Luizao, P. Matson, G. Livingston, R. Luizao, and P. Vitousek. "Nitrous Oxide Flux
Following Tropical Land Clearing." Global Biogeochemical Cycles, 3, 1989, pp. 281-285.
10. J. Schmidt, W. Seiler, and R. Conrad. "Emission of Nitrous Oxide from Temperature
Forest Soils into the Atmosphere." Journal of Atmospheric Chemistry, 6, 1988, pp. 95-
115.
11. R. D. Bowden, P. A. Steudler, J. M. Melillo, and J. D. Aber. "Annual Nitrous Oxide Fluxes
from Temperate Forest Soils in Northeastern United States." Journal of Geophysical
Research. 1990.
12. W. M. Hao, S. C. Wofsy, M. B. McElroy, J. M. Beer, and M. A. Togan. "Sources of
Atmospheric Nitrous Oxide from Combustion." Journal of Geophysical Research, 92,
1987, pp. 3098-3104.
13. J. H. Butler, J. W. Elkins, T. M. Thompson, and K. B. Egan. "Tropospheric and Dissolved
N2O in the West Pacific and East Indian Oceans During the El Nino-Southern Oscillation
Event of 1987." Journal of Geophysical Research, 1990.
14. P. J. Crutzen, A. C. Delany, J. Greenberg, P. Haagenson, L. Heidt, R. Lueb, W. Pollock,
W. Seiler, A. Wartburg, and P Zimmerman. "Tropospheric Chemical Composition
Measurements in Brazil During the Dry Season." Journal of Atmospheric Chemistry, 2,
1985, pp. 233-256.
15. R. Conrad, W. Seiler, and G. Bunse. "Factors Influencing the Loss of Fertilizer Nitrogen
into the Atmosphere As N2O." Journal of Geophysical Research, 88, 1983, pp. 6709-
6718.
1-72
-------
16. D. Ronen, M. Mordeckai, and E. Almon. "Contaminated Aquifers Are A Forgotten
Component of the Global N2O Budget." Nature. 355, 1988, pp. 57-59.
17. L. J. Muzio and J. C. Kramlich. "An Artifact in the Measurement of N2O from Combustion
Sources." Geophysical Research Letters, 15, 1988, pp. 1369-1372.
18. L. J. Muzio, M. E. league, J. C. Kramlich, J. A. Cole, J. M. McCarthy, and R. K.
Lyon. "Errors in Grab Sample Measurements of N2O from Combustion Sources."
Journal Air Pollution Control Association. 39, 1989, pp. 287-293.
19. T. A. Montgomery, G. S. Samuelson, and L. J. Muzio. "Continuous Infrared Analysis
of N2O in Combustion Products." Journal Air Pollution Control Association. 39, 1989,
pp. 721-726.
20. J. T. Houghton, G. J. Jenkins, and J. J. Ephraums. Climate Change: The IPCC Scientific
Assessment. Cambridge: Cambridge University Press, 1990.
21. W. R. Gofer III, J. S. Levine, E. L. Winstead, and B. J. Stocks. "Gaseous Emissions from
Canadian Boreal Forest Fires." Atmospheric Environment, 24A, 1990, pp. 1653-1659.
22. W. R. Gofer III, J. S. Levine, E. L. Winstead, and B. J. Stocks. "New Estimates of Nitrous
Oxide Emissions from Biomass Burning." Nature, 349, Feb. 21, 1991.
23. I. C. Anderson, J. S. Levine, M. A. Poth, and P. J. Riggan. "Enhanced Biogenic
Emissions of Nitric Oxide and Nitrous Oxide Following Surface Biomass Burning.
Journal of Geophysical Research, 93, 1988, pp. 3893-3898.
24. J. S. Levine, W. R. Gofer III, D. I. Sebacher, E. L. Winstead, S. Sebacher, and P. J.
Boston. "The Effects of Fire on Biogenic Soil Emissions of Nitric Oxide and Nitrous
Oxide." Global Biogeochemical Cycles, 2, 1988, pp. 445-449.
25. J. S. Levine, T. R. Augustsson, I. C. Anderson, J. M. Hoell, and D. A. Brewer. "Tropo-
spheric Sources of NO^: Lightning and Biology." Atmospheric Environment, 18, 1984,
pp. 1797-1804.
26. I. C. Anderson and J. S. Levine. "Relative Rates of Nitric Oxide and Nitrous Oxide Produc-
tion by Nitrifiers, Denitrifiers, and Nitrate Respirers." Applied and Environmental Micro-
biology, 51, 1986, pp. 938-945.
27. I. C. Anderson and J. S. Levine. "Simultaneous Field Measurements of Biogenic
Emissions of Nitric Oxide and Nitrous Oxide." Journal of Geophysical Research, 92,
1987. pp. 965-976.
1-73
-------
28. J. S. Levine. "Global Biomass Burning: Atmospheric, Climatic, and Biospheric Impli-
cations." EOS, Transactions of the American Geophysical Union, 71, 1990, pp. 1075-
1077.
29. J. S. Levine. "Atmospheric Trace Gases: Burning Trees and Bridges." Nature. 346,
1990, pp. 511-512.
30. J. S. Levine. Global Biomass Burning. Cambridge, Massachusetts: MIT Press, Inc.,
1991.
31. J. W. Ekins. Presented at NASA/NOAA/EPA Workshop on Scientific Basis of Global
Warming Potential Indices, Boulder, Colorado, November 14-16, 1990.
1-74
-------
Table 1
Estimates of Global Sources of Nitrous Oxide
Units: Tg N per year
Natural soil emissions:
Tropical forests (8) 3.7
Tropical forests transformed 0.8-1.3
to pastures (9)
Temperate forests (10,11) 0.01-1.5
Combustion of fossil fuels (12) 3.2
Ocean (13) 1.4-2.6
Biomass burning (14) 1.6
Fertilized agricultural fields (15.) 0.01-1.1
Fertilizer leaching into groundwater (16) 0.5-1.1
Total 11.22-16.10
1-75
-------
Session 2
LARGE SCALE COAL COMBUSTION
Chair: B. Martin, EPA and G. Off en, EPRI
-------
DEVELOPMENT AND EVOLUTION OF THE ABB COMBUSTION ENGINEERING
LOW NOX CONCENTRIC FIRING SYSTEM
John Grusha, Manager of Firing Systems Engineering
Michael S. McCartney. Director, Fuel Systems and Controls Engineering
ABB Combustion Engineering Services, Inc.
-------
Development and Evolution of the
ABB Combustion Engineering Low NOx Concentric Firing System
John Grusha, Manager of Firing Systems Engineering
Michael S. McCartney, Director, Fuel Systems and Controls Engineering
ABB Combustion Engineering Services, Inc.
In the 1989 EPA EPRI Symposium in San Francisco, Combustion Engineering and Ferco
reported on the CE/Mitsubishi Heavy Industries (MHI) Pollution Minimum (PM) coal
retrofit at Kansas P&L Lawrence #5. Those reports documented MCR NOx levels of
less than .3 Ibs/mmBtu which has been recently improved by the plant personnel to
less than .25 Ibs/mmBtu over the top 50% of the load range (Figure 1). Clearly
the Lawrence demonstration met and in some aspects, exceeded the expectation of
the project sponsors. Many of the program participants were also duly impressed
with the complexity of the P.M. retrofit. In virtually all cases, the coal PM
burner requires a replacement of the original windbox enclosure which is a major
task. In the case of Lawrence #5, windbox replacement was probably easier than
can be anticipated with most other units, due to the accessibility around the
unit.
During the same time period, ENEL, the Italian national utility, installed a coal
PM burner on the 320 MW Fiume Santo. This unit was under construction at the time
the PM was substituted for the standard windbox. Faced also with the need to
retrofit existing tangentially fired, multi-fuel units, ENEL was receptive to
demonstrating an alternative to the PM technology that was more tailored for
retrofit. With the obvious market in the U.S. generated by the pending Clean Air
legislation, together with a committed host site in Italy, ABB/CE committed to an
accelerated R&D program to develop an advanced low NOx multi-fuel firing system
specifically for retrofit to existing tangentially fired units.
The intent of this paper is to report on the development, demonstration and
subsequent evolution of this low NOx technology for tangential, multi-fuel fired
boilers from the original concept called Clustered Concentric Tangential Firing
System (CCTFS) to the incorporation of its clustering feature into the
commercially established LNCFS product line.
2-3
-------
CCTFS Concept
Classic NOx theory as is generally accepted in the industry identifies three NOx
formation mechanisms called prompt, thermal and fuel bound NOx. At the risk of
oversimplification of these very complex kinetics, one can reasonably state that
time, temperature and the availability of elemental nitrogen and 02 are the
primary variables for all three mechanisms. Within the constraints of existing
units, time and temperature are not practical methods of control. Time for
example, is fixed by the volume flow rate of the products of combustion and the
volume of the existing furnace. Temperature is also a function of the degree of
air preheat, net fuel heat input and the amount of heat absorbing surface in the
furnace. Since the air preheat temperature, net heat fired and heat absorbing
surface are fixed, temperature also is eliminated as a practical method of NOx
control. Thus the control of elemental nitrogen and oxygen is, by default, the
most cost-effective means of controlling NOx. The practice of temporarily
withholding oxygen from the combustion process is generally referred to as
staging. The use of staging is the common denominator of virtually all low NOx
burner designs for both wall and tangential systems and was the basis of the
original CCTFS concept.
CCTFS stands for Concentric Clustered Tangential Firing System. The concept
behind CCTFS is to stage the combustion process at three points throughout the
history of the fuel in the furnace.
1. Early Staging: A concept called clustering is used to produce
early staging by the coal nozzles being grouped together without
intermediate air (Figure 2). The clustered fuel nozzles are
separated by large distances and large intermediate air
compartments. The theory is that fuel nozzles when placed next to
each other will entrain less air as the fuel enters the furnace
which will result in a more fuel rich environment during ignition
and the early devolatilization process. This temporary surplus of
ignited fuel depletes the available oxygen and in turn, forces the
kinetic path of the fuel bound nitrogen to N2. It is essential
with this concept to have early coal ignition producing
devolatilization and fuel bound nitrogen release within the time the
fuel jets can stay air-lean within the furnace. The fuel nozzles
are designed with a flame attachment feature borrowed from existing
LNCFS technology to encourage stable flame propagation from the
furnace back to a point close, near the fuel nozzle tip.
2. Intermediate Staging: No early staging technique can effectively
control fuel NOx from coal to any high degree, primarily because
large quantities of nitrogen can evolve from the fuel well after
complete devolatilization and well after the point in time that
fuel and air nozzles can maintain local fuel/air ratios. To
achieve intermediate staging a "close coupled" overfire air
compartment is incorporated into the top of the tangential
2-4
-------
windboxes. This portion of the CCTFS is a copy of the original
overfire air first used on tangential designs since the early
1970s. Because intermediate and late stage techniques drive
overall stoichiometry below 1.0, the intermediate air nozzles are
designed to direct combustion air away from the center of the
furnace and toward the waterwalls. This technique called
concentric firing is well established as a method to keep oxygen on
the waterwalls and increase lower furnace heat absorption. In and
by itself, it does not reduce NOx, but it plays a crucial role in
that it offsets the tendency of high quantities of overfire air to
slag the lower furnace and increase furnace outlet temperature. It
too was borrowed from existing LNCFS technology.
3. Late Staging: In theory, the most effective location for
introducing the air required to stage and then complete combustion
is as close to the furnace outlet as possible. This maximizes the
time the fuel is staged and minimizes the time in an excess air
condition. Since the fuel must be burned to completion at some
point before the furnace outlet, this late staging device must be
the most effective mixing system in the furnace. With CCTFS, this
is done with "separated overfire" (SOFA) windboxes located higher
in the furnace. Each is equipped with multiple air nozzles with
the ability to tilt in both the vertical plane (Pitch) as well as
the horizontal plane (Yaw). The air to the separated overfire air
is of sufficient quantity to keep the mid furnace around 1.0
stoichiometry and was boosted in the laboratory development, to
approximately 20 in w.g.
Laboratory Development of CCTFS
The CCTFS was developed in ABB/CE's Kreisinger Development Laboratory (KDL) in
Windsor, CT. The test facility is a 50 mmBtu/hr (15 mwt) facility sized to
simulate large boiler residence times. The temperatures are replicated by
selective refractory lining (Figure 3). One of the program's main objectives was
to test and evaluate the various candidate designs from the standpoint of a
variety of different coals. It was felt that many problems in the past were
caused by reaching conclusions on the basis of one fuel, only to find that it was
not repeatable on another fuel. In addition, the host utility, ENEL, had a fuel
policy that required a very wide range of potential fuels, ranging from South
African to U.S. high volatile bituminous fuels. The fuels tested are summarized
below:
Source HHV FC/VM %N %S %Ash
Ashland, KY 13430 2.0 1.4 .8 9.3
Virginia 14150 2.0 1.7 .8 6.6
Utah 11740 2.7 1.5 .6 16.1
W. Virginia 13310 5.0 1.4 2.3 13.3
2-5
-------
The program was built on prior work on concentric firing and close coupled OFA,
with the primary interests of the program centered on the development of a optimum
separated OFA system and clustering arrangement. In the interest of time and the
ABB-CE "proprietary" interest, a complete description of the test matrix and
results are beyond the intent of this paper. However, some of the KDL conclusions
and supporting data is presented to understand the evolution of CCTFS. These
conclusions are as follows:
1. Splitting the overfire air distribution between the close coupled
and the separated OFA positions produced the same or lower NOx than
placing all the OFA in the separated positions. This is shown in
Figure 4. The optimum OFA distribution was fuel specific.
2. The ability to vary the yaw (angular motion in horizontal plane)
had a clear impact on combustion efficiency. Figure 5 shows one
example of the effect of yaw angle on carbon in ash values.
3. Moderate levels of OFA had the effect of slightly reducing furnace
outlet temperatures; however, larger quantities had the reverse
effect of raising them significantly. The CFS nozzles reduced
furnace outlet temperature resulting in a zero degree net change in
furnace outlet temperatures when CFS and high quantities of OFA
were used together (Figure 6).
4. The clustering techniques reduced NOx approximately 15% under
conditions with low quantities of OFA. At 30% OFA, there was no
significant difference in NOx or combustion efficiency between
clustered and non-clustered configurations.
The CCTFS configuration was capable of achieving approximately 200 ppm NOx
corrected to 3% 0~ (60% reduction) while operating at 3.1% 02 on an Eastern high
volatile bituminous coal. The test clearly showed the dominance of overfire air
flow on NOx levels. All other features of the KDL demonstrated CCTFS were
successful in maintaining furnace outlet temperatures, surplus 0? on the
waterwalls and minimizing unburned carbon, but the quantity of OFA determined NOx
levels. The lesson learned was that NOx reduction from clustering was not
multiplicative or even additive to the OFA contributions. Larger quantities of
OFA appear to not only prevent the formation of NOx, but reduce NOx formed in the
burner area.
Fusina #2 Description
ENEL's Fusina #2 unit is a balanced draft, radiant-reheat, tangentially fired,
boiler designed and manufactured by Franco Tosi Legano, Italy under license from
ABB-CE. It is a multi-fueled unit capable of full load operation on either coal,
oil or natural gas. Four CE 623 RS exhauster-type pulverizers are used to supply
four levels of tilting coal nozzles which are located in the four corner
windboxes. In addition, four elevations of oil and natural gas firing equipment
2-6
-------
also exist. A side elevation view of Fusina #2 is shown in Figure #7. A brief
summary of unit design conditions are as follows:
Megawatt rating - 160 MW
Main steam flow - 1,119,800 Ibs/hr
Throttle pressure 2,100 PSIG
SH/RH temperatures - 1,005/1,005°F
Contract year - 1967
The unit was designed to fire low sulphur bituminous type coal, moderate sulfur #6
oil and natural gas.
The original firing system windbox arrangement consisted of four elevations of 12"
coal nozzles equally spaced throughout the height. Each windbox is 16" wide and
approximately 21' 7-3/4" high. Located between the lower three coal elevations
and above the uppermost elevation is the oil and gas firing equipment.
In order to incorporate the Clustered Concentric Tangential Firing System (CCTFS),
the original windbox arrangement had to be reconfigured. These changes to the
original windbox are shown in Figure #8. The most significant change was in
clustering or close arrangement of both the upper two and lower two coal
elevations. Additional design requirements of the reconfigured CCTFS windboxes
included a close-coupled overfire air system, "flame attachment" coal nozzle tips
and offset concentric air nozzle tips similar to the KDL CCTFS arrangement. In
order to incorporate all of these changes, oil and natural gas firing equipment
levels had to be relocated.
Equally important as the windbox modification, was the addition of a separated
overfire air system (SOFA) for late staging and completion of the combustion
process. This consisted of four smaller windboxes located approximately 15'
directly above the main windbox. Each SOFA windbox included three tilting air
nozzle tips, with the capability of tilting vertically + 30° independent of the
main windbox. Also incorporated into the separated overfire air system is the
unique feature of being able to horizontally adjust each nozzle tip either toward
or against the main fireball rotation see Figure #9.
The sizing criteria for both the close-coupled and separated overfire air system
at Fusina was based on the results of the CCTFS development program in KDL. The
close-coupled overfire air was designed to deliver 10% of the combustion air,
2-7
-------
while the separated overfire air was sized for 20% of the total combustion air.
Also as a result of the KDL program, high pressure boost fans capable of 25 in.
w.g. pressure were installed on the separated overfire air system in order to
optimize the discharge velocity of the separated overfire air independent of the
main windboxes. Its intended benefit was to allow utilization of higher
percentages of staged combustion air while maximizing upper furnace fuel/air
mixing and minimizing CO and unburned carbon in the flyash.
In addition to the overfire air, each coal elevation had flame attachment type
coal nozzle tips to help promote the early initiation of coal ignition under
oxygen deficient conditions, an established low NOx requirement.
To direct combustion air down along the waterwall, offset air nozzle tips were
located within the CCTFS windbox, to minimize reducing atmospheres and control
F.O.T. under staged coal firing conditions.
During the evaluation of the CCTFS performance, four different coals were
evaluated. These ranged from two South African medium volatile coals to two U.S.
eastern bituminous high volatile coals. A tabulation of their analyses are listed
in Figure #10. (Also listed for later comparison is the analysis of the western
bituminous coal fired with a LNCFS system at PSCC, Valmont.)
Fusina #2 Test Results - Coal
Approximately 150 tests were conducted with the CCTFS at Fusina #2. Four
different coals were evaluated. Throughout the parametric testing, all the
features of the CCTFS were evaluated against NOx, CO, carbon loss and other boiler
performance. As expected, each coal exhibited distinct characteristics.
Figure #11 presents the effect of firing zone stoichiometry on NOx for the
different types of coal with the CCTFS. For clarification, firing zone
stoichiometry is that percentage of total combustion air introduced at or below
the uppermost fuel elevation. Combustion air introduced above this upper
elevation is considered overfire air.
The results show that with approximately 90% firing zone stoichiometry, the CCTFS
produced nearly 50% NOx reduction. The results further show that the South
African coals (TCOA, AM coal), produced overall higher NOx emissions than the U.S.
eastern bituminous coals.
2-8
-------
Besides the NOx reduction capability of the CCTFS, the effect of firing zone
stoichiometry on unburned carbon was investigated. This is a common concern among
many boiler operators. As the percentage of total air to the main firing zone was
decreased for NOx reduction, the unburned carbon increased for the same coal
fineness, see Figure #12.
The first series of tests conducted with the South African coals (TCOA, AM Coal),
using a coal fineness of 85% through 200 mesh (3.8% on 100 mesh), resulted in an
increase of unburned carbon from 9% to 12% when the firing zone stoichiometry was
reduced from approximately 124% down to 94%. This same trend was demonstrated
with the U.S. coals which had a coal fineness on the first series of tests of 87%
through 200 mesh (3.6% on 100 mesh). With these U.S. coals, the unburned carbon
again increased, but to a lesser degree. This unit, however, had the pulverizer
capability to increase coal fineness. Referring again to Figure #12, improving
the coal fineness from 87% to 93% through the 200 mesh (1% on 100 mesh) on the
U.S. coals reduced the unburned carbon under staged firing conditions to below the
unstaged baseline values. This same trend was demonstrated with the South African
coal s as well .
Figure #13 shows the effect of increasing the separated overfire velocity for
three of the coals. The TCOA coal was further evaluated under both normal and
higher coal fineness. The results showed that increasing the pressure behind the
staged combustion air had little effect on improving the percent unburned carbon
in the flyash. Further it showed no improvement in NOx emissions and CO emissions
never exceeded 40 pptn throughout the test program.
Fusina Test Results - Oil and Natural Gas
In addition to evaluating the low NOx capability of the CCTFS system when firing
coal, the effectiveness of its separated and close coupled overfire air system was
tested on reducing NOx emissions when firing either No. 6 oil or natural gas.
As with coal firing on tangentially fired units, the use of an overfire air system
is very effective in reducing NOx emissions. Diverting a percentage of the total
combustion air away from the primary combustion zone, reduces both the thermal and
fuel NOx conversion by way of the staging process. Figure #14 illustrates the
effectiveness of staged combustion when firing heavy oil. With heavy oil, 50% of
the NOx formed can be a result of the fuel nitrogen in the oil. It therefore, has
an important effect on final NOx emissions. This graph presents the effect of two
fuel nitrogen levels on NOx emissions as a function of firing zone stoichiometry.
Still higher nitrogen values would expectedly produce higher NOx levels.
2-9
-------
In addition to fuel nitrogen, operating 02 levels were evaluated. Figure #15
compares the effects of varying CL on NOx and CO, during staged and unstaged
firing conditions. Varying the CL between 2% and 3% without OFA had a minimal
effect on NOx production. At the same 02 levels, CO emissions remain relatively
unchanged.
Utilizing overfire air to stage the oil combustion process, again did not appear
to demonstrate a significant sensitivity of NOx production to operating 02 levels.
However, under deep staged conditions at low Op levels, CO emissions increased.
It should be noted such increases are sensitive to such parameters as atomization,
oil quality, viscosity, and the mixing efficiency of air and fuel during the early
stages of the combustion process. Throughout the low NOx oil firing tests
reported particulate levels never exceeded .1 Ibs/mmBtu prior to the precipitator.
Unlike coal and oil, natural gas has no fuel nitrogen. All of its NOx production
is therefore thermal NOx which is solely dependent on 0? availability and
temperature. The results from Fusina demonstrate that as the firing zone
stoichiometry is reduced by the utilization of staged combustion, NOx emissions
decreased significantly. Figure #16 illustrates the results of staged combustion
on natural gas firing at Fusina. NOx reduction efficiencies of 70% were achieved.
CO increased, but never exceeded 200 ppm (corr. 3% 0?).
Low NOx Concentric Firing System (LNCFS) Results at Public Service of Colorado
Co., Valmont #5
Similar goals of NOx reduction were targeted for a coal fired unit at PSCC,
Valmont #5. To meet this objective an LNCFS was proposed and installed. Valmont
#5 being somewhat similar in size to Fusina #2 made for a good comparison of the
two low NOx firing systems.
Unit Description
PSCC Valmont #5 is a tangentially fired boiler manufactured by ABB-CE, and capable
of full load operation when firing either pulverized coal or natural gas. Side
elevation views of Valmont #5 is shown on Figure #17. The unit design conditions
are as follows:
MW rating - 165
Steam flow 1,230,000 Ibs/hr
Throttle pressure - 1,800 PSIG
SH/RH temperatures - 1,005/1005°F
Contract year 1961
2-10
-------
Valmont #5 fires low sulfur, western bituminous coal, a typical analysis is listed
in Figure #10.
The original windbox arrangement at Valmont #5 shows very little contrast from the
initial Fusina arrangement. Similarly four elevations of 18" coal nozzles are
supplied by four CE 743 RS exhauster-type pulverizers. Each windbox is 22" wide
and approximately 21' - 3-1/4" high. Between the four coal elevations exist three
levels of gas firing equipment which are capable of full load. The LNCFS similar
in concept to CCTFS, combines the NOx reducing capabilities of furnace combustion
air staging with early fuel devolatilization and offset air nozzles to control CL
availability; thereby, reducing total NOx emissions. The major components of the
LNCFS at Valmont #5 are:
Separated overfire air system
Offset concentric auxiliary nozzle tips
Flame attachment coal nozzle tips
Figure #18 comparatively illustrates the modifications made to the original
Valmont windbox to incorporate the LNCFS.
The major differences between the CCTFS and the LNCFS are seen primarily in the
fact that the coal nozzles are not clustered together. Similar to the CCTFS was
the utilization of flame attachment coal nozzles, but only a separated overfire
air system without boost was incorporated. Both systems' separated overfire air
arrangements had horizontal and vertical adjustment features proven to provide
optimal fuel air mixing during staged combustion operation to minimize CO
increases and 02 imbalance.
Valmont #5 Test Results
The effect of firing zone stoichiometry (FZS) on NOx with CCTFS and LNCFS are
compared in Figure #19. With the units being similar in size, but firing notably
different coals, the overall percent reduction efficiencies of both systems are
shown to be comparable in performance capabilities. For the same firing zone
stoichiometry due to staged combustion, percent NOx reductions of 50% with the
LNCFS closely approximated the CCTFS performance.
The unburned carbon results from Valmont #5 were superimposed on the CCTFS data
results and are shown in Figure #20. The unburned carbon with the LNCFS did not
increase with firing zone stoichiometry changes even with poorer overall coal
2-11
-------
fineness. This is attributed primarily to the fact that western bituminous coals
are highly reactive and do not tend to exhibit unburned carbon easily even under
aggressively staged firing conditions. This demonstrates the point that unburned
carbon levels under staged conditions are very dependent on coal type. The less
reactive coals such as the South African coals and Eastern U.S. bituminous coals
used at Fusina were more inclined to an increase in unburned carbon under staged
low NOx firing conditions. Further the sub-bituminous and lignitic coals which
are highly reactive should exhibit very little if any change in unburned carbon.
No opportunities to test the low NOx gas firing capabilities at Valmont were
avai1 able.
Summary and Conclusions
By comparing the CCTFS configuration results from both the lab and the field
demonstration at Fusina with the LNCFS results from Valmont, it is clear that the
firing zone stoichiometry overshadowed all other variables, except for final CL,
in determining the outlet NOx levels. This is not to say that OFA in and by
itself constitutes a low NOx firing system. High quantities of OFA by itself will
increase furnace outlet temperatures and depending on the specific fuel properties
may increase lower furnace slagging and increase unburned carbon loss. Moreover,
if an OFA system is a poor mixing system, carbon monoxide, 0? unbalance and a
whole host of other potential consequences are possible.
Thus the design approach for low NOx retrofit systems on a tangentially fired unit
is focused on first achieving the best mixing from the OFA systems and secondly,
manipulating the method of fuel and air introduction to counterbalance the
potentially adverse effects of staging. In general, we find that a tangential
system can, if designed properly, accommodate large quantities of OFA without
realizing these negative side effects, with one notable exception. The increase
in unburned carbon reported in this paper at Fusina under high overfire air flow
modes is the inevitable consequence of aggressive furnace staging on the less
reactive, agglomerating bituminous-type coals. As evidenced by the Valmont data,
this phenomena is less apparent with weakly agglomerating western bituminous or
sub-bituminous fuels. Where no deterioration in unburned carbon is acceptable,
modification to the pulverizer system will be required to reduce the particle size
of fuel to the furnace. Modification to pulverizers such as ABB/CE's dynamic
classifier is designed to reduce the mass fraction of the largest sized fuel
particles without having to reduce the size of all size fractions. With devices
such as the dynamic classifier, it is actually possible to reduce unburned carbon
in ash levels to a point lower than those measured prior to the low NOx retrofit.
2-12
-------
The retrofit system that will be offered by ABB-CE for coal fired units affected
by the Phase I of the Clean Air Act will be a blend of the Fusina CCTFS advanced
OFA as well as the fuel and offset concentric air nozzle configurations
demonstrated on both Fusina and Valmont. Because clustering will be dropped as a
NOx control technique, the CCTFS name will also be dropped. The LNCFS name will
be used for all coal fired retrofits. This is logical since LNCFS has always
combined OFA, flame attachment coal nozzle tips and offset concentric air nozzle
configurations.
Clearly not all units will require the same percent reduction to meet the .45
Ibs/mmBtu required by the Clean Air Act for tangentially-fired units. Where the
percent reduction does not require maximum quantities of OFA, a single level of
separated OFA will be utilized as in Valmont or integrated in the main windbox as
close coupled OFA. The higher levels of OFA within the LNCFS configuration are
shown in Figure #21 as Level 1, 2 and 3 LNCFS. In Level 1 and 3, the top two
elevations continue to be clustered which sounds like a contradiction with what
was stated before. The use of clustering in these situations is simply to make
room within the existing windbox enclosure for close coupled OFA.
All configurations of LNCFS can utilize the existing main windbox which greatly
simplifies and reduces the cost as compared to the PM which was discussed briefly
in the beginning of this paper. There will always be a few situations where the
original windboxes cannot be salvaged because they have deteriorated beyond repair
with age. However, in most cases, the box can be reused. The cost advantage can
be seen in Figure #22 which shows the approximate D&E cost of three levels of
LNCFS versus the PM, which always requires a windbox replacement. The cost
assumes a 200 MW, 4 corner unit and does not include dynamic classifiers.
As a final note, it should be stated that ABB-CE believes that LNCFS can meet the
Clean Air requirements for virtually all of the Phase I affected units. In
addition, the overfire air technology successfully demonstrated at Fusina #2 is
available for those oil and gas fired units also requiring NOx reductions. On new
boiler construction where the constraints of existing windboxes are obviously not
an issue, ABB-CE plans to continue utilizing the PM technology.
2-13
-------
E
CL
D.
o"
KP&L Lawrence #5
400 MW CCRR Unit
Subbit A Coal
BASELINE
BOILER LOAD (MW)
Figure 1. NOx vs. Boiler Load with 'PM' Firing
System
ORIGINAL
WINDBOX
CCTFS
ARRANGEMENT
Figure 3. Boiler Simulation Facility
PRE RETROFIT
- SEPARATED OFA WITH
ADJUSTABLE YAW
-COUPLED OFA
^COAL NOZZLE CLUSTER
i-OFFSET AIR NOZZLES
POST RETROFIT
305 -
300 —
<0^,
^
Figure 4. NOx vs. OFA Quantity & Elevation
Figure 2. Clustering
2-14
-------
FIREBALL
ROTATION
ADJUSTABLE
YAW -
FURNACE
PLAN VIEW
0 YAW -15 YAW -15 YAW
30% SEPARATED OFA, 3.1% O2KENTUCKY H! VOL. BIT.
Figure 5. Separated OFA YAW vs. % Carbon in Ash
SEPARATED
OFA
20
20
30
CFS ANGLE
DEG. FROM FUEL q_
*22
AVG. F.O.T.
1276 C
1255 C
1235 C
1275 C
Figure 6. Effect of Separated OFA and CFS on
Furnace Outlet Temperature
Figure 7. Fusina #2 Side Elevation
2-15
-------
ESS
EEEB
Separated
Dverfire
Close
CoupLecl
Overfire
(As Received]
HHV
HOIST
VM
FC
ASH
(DAF)
C
H
N
S
°2
FC/VH
TCOA
1091
a. 6
21.7
55-0
14.5
83.29
4.42
2.03
0 63
9 63
2.53
AM COAL
11844
7.50
24.54
52 76
15.10
71.10
3 82
1 63
0 40
7.74
2-14
MC CALL
14170
1.3
27.8
64 5
6.4
87.1
5.2
1.5
0.9
5.3
2.32
ARCH MINERAL
12731
7.53
34.43
50.38
7.66
76.60
5.16
1 51
0 85
7 5
1.69
W BIT
10957
9 26
34.78
43 86
12.10
79.52
5.80
1.74
0.52
12.33
1.26
Figure 10. Coal Analysis, CCTFS
400 I-
E 300
95 105 115
Firing Zone Stoichiometry
160 MW COAL/OIL/GAS UNIT
Figure 11. Effect of Firing Zone Stoichiometry on
NOx for Different Types of Coal with CCTFS
PREVIOUS ARRANGEMENT
MODIFIED ARRANGEMENT
Figure 8. Changes to Original Windbox, ENEL,
Fusina #2
CE Separated Overfire Air Assembly
Patent Pendinq
Figure 9. CE Separated Overfire Air Assembly
(Coal Fineness thru 200 Mesh)
95 100 105 110 115 120 125
Firing Zone Stoichiometry
160 MW COAL/OIL/GAS UNIT
Coal
* TCOA
° AMCoal
'-> MoCall
a Arch Mineral
NOTE.
BASELINE CARBON
VALUES AVERAGED
BETWEEN 7-9%
Figure 12. Effect of Coal Fineness on Unburned
Carbon vs. Firing Zone Stoichiometry with CCTFS
2-16
-------
100-
COAL
TCOA .3
-=- TCOA (High Fineness) o 50 "
2
^— MoCall
— Arch Mineral
100 150 200 250 300 350 400 450 500
VELOCITY (FT/SEC)
160 MW COAL/OIL/GAS UNIT
0.7 0.8 0.9 1
Firing Zone Stoichiometry
160 MW COAL/OIL/GAS UNIT
Figure 13. Effect of SOFA Air Velocity on Unhurried F'9ure 16^fect of Firin9 Zone Stoichiometry on
'•' •* K r\ij- nnf-1 f*ri iui4-l~t I K DCTC?
Carbon in Flyash with CCTFS
NOxandCOwithLNBFS
Fuel - Heavy Oil; 02-2.5%
O 100 "
Particulates < 0.1
0.7 0.8
0.9 1 1.1
Firing Zone Stoichiometry
160 MW COAL/OIL/GAS UNIT
12 13
Figure 14. Effect of Fuel Nitrogen on NOx vs. Firing
Zone Stoichiometry with LNBFS
- - — — — - . 350
Fuel - Heavy Oil (N-0.34%. S-0 81%)
m 250
150
O 100
50
,100 §
- 50
1.5 2 2.5
Percent O2
160 MW COAL/OIL/GAS UNIT
Figure 17. Valmont #5 Side Elevation
Figure 15. Effect of O2 on NOx and CO Levels
2-17
-------
12 - — -— — —
(Coal Fineness thru 200 Mesh)
Separated
Over-fire
EuB
ORIGINAL ARRANGEMENT
FOB
Gas
Offset A,r
Coal
Offset A,r
Offset ,
Gns
an
Gas
Offset ,
MODIFIED ARRANGEMENT
Figure 18. Windbox Modifications
—=— WBit (Valmont)
CCTFS
— " Arch Mmeral(Fusina)
--- McCall (Fusma)
30 85 90 95 100 105 110 115 120 125
Firing Zone Stoichiometry
Figure 19. Effect of Firing Zone Stoichiometry on
NOx for Different Types of Coal
—^- WBit (Valmont)
CCTFS
Arch Mmeral(Fusina)
McCall (Fusina)
80 85 90 95 100 105 110 115 120 125 130
Firing Zone Stoichiometry
Figure 20. Effect of Coal Fineness on Unburned
Carbon vs. Firing Zone Stoichiometry (200 Mesh)
Standard
Windbox
AIR
COAL
AIR
COAL
AIR
COAL
AIR
COAL
OIL
COAL
AIR
% Reductions'
LNCFS
Level 1
OFA
OFA
COAL
COAL
CFS
COAL
CFS
COAL
OIL
COAL
AIR
25-32
Level 2
OFA
OFA
AIR
COAL
CFS
COAL
CFS
COAL
CFS
COAL
OIL
COAL
AIR
33-40
Level 3
OFA
OFA
OFA
OFA
COAL
COAL
CFS
COAL
CFS
COAL
OIL
COAL
AIR
41 -50
Figure 21. Low NOx Retrofit Options
S/KW INSTALLED
n o m o 01 O o i
J
H
LNCFS LNCFS LNCFS PM
Level 1 Level 2 Level 3
Figure 22. NOx Reduction Systems, Retrofit Cost
Comparison
2-18
-------
PERFORMANCE OF A LARGE CELL-BURNER UTILITY
BOILER RETROFITTED WITH FOSTER WHEELER LOW-NOX BURNERS
T. L. Lu
R. L. Lungren
Arizona Public Service Company
Phoenix, Arizona
A. Kokkinos
Electric Power Research Institute
Palo Alto, California
-------
ABSTRACT
A comprehensive boiler testing program was performed on Units 4 and 5 of the
Four Corners Steam Electric Station to compare the NOX emissions and thermal
performance of a unit retrofitted with low-NOx burners (Unit 4) with a
"sister" unit still equipped with its original turbulent burners (Unit 5).
Built in the late 1960s, Units 4 and 5 are 800-MW Babcock & Wilcox
supercritical, once-through boilers designed for firing of a western
subbituminous coal. In 1989, Unit 4 was retrofitted with low-NOx circular
burners designed by Foster Wheeler Energy Corporation; Unit 5 was left
unmodified while awaiting its scheduled retrofit in 1991. Major objectives of
the comparative testing program were to establish the NOX emissions levels and
to assess any changes in the performance and operability of Unit 4 due to the
installation of low-NOx burners.
Testing included measurement of NOX, CO, and S02 emissions, unburned carbon,
gas temperature leaving the economizer, and heat absorption in various boiler
circuits at different levels of unit load and excess air, and with different
burner air register adjustments. Test results indicate that the low-NOx
burners reduced NOX emissions from Unit 4 by 55% compared with the unmodified
Unit 5, without any detrimental effect on boiler performance, efficiency, or
operability.
This paper should be of interest to any utility evaluating potential NOX
reductions and boiler performance effects that could be anticipated by
retrofitting these low-NOx burners to pulverized-coal-fired utility boilers
with "cell" burners or conventional circular turbulent burners.
2-21
-------
INTRODUCTION
The Arizona Public Service Company (APS) operates five coal-fired units at the
Four Corners Steam Electric Station located near Farmington, New Mexico. The
units operate under a state environmental regulation which limits emissions of
nitrogen oxide (NOX) to 0.70 Ib/MBtu from coal-fired utility boilers. This
regulation was promulgated in 1972, several years after the two units that
produce the highest NOX emissions--Units 4 and 5--went into commercial
operation.
Babcock & Wilcox (B&W) boilers manufactured during the late 1960s, like Units
4 and 5, were equipped with closely spaced, two- or three-nozzle "cell"
burners specially designed to maximize combustion intensity and produce
extremely high heat releases in a compact burner zone. These combustion
features result in very high flame temperatures, heavy slagging in the
furnace, and NOX emissions around 1.20 Ib/MBtu at full load.
Between 1972 and 1984, APS conducted several testing programs and NOX control
technology studies on Units 4 and 5 in an attempt to achieve compliance with
the state regulation. None of these efforts were successful or even
promising. In 1985, APS identified the Foster Wheeler Energy Corporation
(FWEC) Controlled-Flow/Split-Flame (CF/SF) low-NOx burner as a promising NOX
control technology for possible application to the Four Corners boilers.
Subsequent pilot-scale burner testing programs and design engineering studies
supported a retrofit of CF/SF low-NOx burners on Units 4 and 5.1 In 1987, the
retrofit was approved for major overhauls of Units 4 and 5 scheduled for 1989
and 1991, respectively.
BOILER PLANT DESCRIPTION
Units 4 and 5 are identical B&W opposed-fired, supercritical, once-through,
pressurized boilers. Each is capable of a maximum continuous rated output of
5,445,000 Ib/h main sueam flow at 1000/1000'F. The units fire a western, low-
sulfur, high-ash, subbituminous coal with the characteristics shown in
Table 1. Units 4 and 5 were originally designed by BSW with nine pulverizers
serving 18 three-nozzle cell burners. The closely spaced cell burners
2-22
-------
illustrated in Figure 1 were arranged in a nonuniform firing pattern in the
furnace.
Retrofit of the FWEC CF/SF low-NOx burners (Figure 2) required major design
modifications to the Unit 4 boiler including
• Conversion to eight pulverizers and 48 low-NOx burners, arranged in
four rows of six burners on each firing wall
• New lower furnace waterwall panels designed for a conventional,
widened burner spacing
• Replacement of most of the burner piping
• Installation of a new pulverizer/burner control system
These construction modifications were completed during a major two-month
overhaul of Unit 4 in the spring of 1989.
TEST PROGRAM DESCRIPTION
Following installation of the low-NOx burners, APS and the Electric Power
Research Institute (EPRI) entered into a cooperative agreement to test and
compare the modified boiler's performance and emissions with the performance
and emissions of unmodified Unit 5.
Specific objectives of the testing program were
• To assess any changes in Unit 4 boiler performance and operability
with the new low-NOx burners
• To investigate the effects of inner and outer air register positions
and burner inner nozzle adjustments on flame shape and stability, NOX
emissions, and boiler absorption rates, particularly in the secondary
superheater and pendant reheater sections
• To evaluate the effects of different unit loads and furnace excess
oxygen (02) levels on NOX emissions
Tenerx Corporation was hired to collect emissions data on NOX, excess 02,
carbon monoxide (CO), and sulfur dioxide (S02), to measure gas temperatures
leaving the economizer, and to collect and analyze coal and ash samples. APS
2-23
-------
engineers collected all flow, pressure, and temperature data needed to
evaluate boiler absorption performance. APS and Tenerx conducted a site
inspection of the boilers prior to the testing program to establish acceptable
sampling locations and testing procedures. Coal fineness and fuel/air balance
testing were performed on the fuel supply systems of both units prior to the
main testing program to ensure acceptable boiler test conditions. All
permanent plant instrumentation used in the testing was checked for
calibration and recalibrated where necessary.
Gaseous emissions and flue gas temperatures were measured in the flue gas
ducts between the economizer outlet and the air preheater inlets. Gaseous
emissions were collected from an 18-point grid in Unit 4 and an 8-point grid
in Unit 5. Gas temperatures were measured from a 27-point thermocouple grid
in Unit 4 and a 24-point thermocouple grid in Unit 5. A computer-based data
acquisition system was used to collect all thermocouple readings.
TESTING PROCEDURE
The comparative testing program followed the test matrix shown in Table 2 to
evaluate the units' emissions and thermal performance over a range of
operating conditions. The test plan consisted of a series of 15 parallel
tests on Units 4 and 5, along with six tests conducted only on Unit 4. Test
variables included unit load, furnace excess 02 level, burner tip position,
and inner/outer air register position. The following tests were conducted:
• Four full-load parallel tests were run on both units at standard
burner tip position of +3 inches at low (1.8-2.4%), normal (2.7-
2.9%), and high (3.4-3.6%) excess 02 levels.
• Four full-load, parallel tests were run on both units with burner tip
positions moved to zero and -3 inches at low (1.8-2.4%) and high
(3.4-3.6%) excess 02 levels.
• Four full-load tests were run on Unit 4 only while varying inner and
outer air register positions. These tests were performed at normal
excess 02 levels (2.7-3.0%). Optimum inner and outer air register
positions were identified based on NOX emission levels. Two
additional full-load tests were then run on Unit 4 with both air
registers at optimized positions at low (2.0%) and normal (2.7%)
excess 02 levels.
2-24
-------
• Four 75% load, parallel tests were run on both units under standard
burner operating conditions with all mills in service (AMIS) and with
top mill out of service (MOOS) at normal excess 02 levels (3.2-3.7%);
and with AMIS at high excess 02 levels (4.4-4.5%).
• Three 50% load, parallel tests were run on both units under standard
burner operating conditions with two top MOOS at normal excess 02
levels (4.7-5.0%), and then with two top MOOS 02 (5.4-5.5%).
Each test lasted about 4-5 hours —1.5 hours of process stabilization, and 3-4
hours of actual testing. Emissions were monitored and recorded as single-
point samples and as composite samples. Emissions testing equipment consisted
of a chemiluminescent NOX analyzer, infrared analyzers for CO and C02, a
zirconia cell analyzer for 02, and a DuPont S02 analyzer.
Two fuel analyses were performed during each test. Coal samples were
collected immediately downstream of the coal silos before the coal entered
each mill feeder. These samples were riffled together to produce an "average"
coal sample, and higher heating value (HHV), proximate, and ultimate analyses
were performed. Mineral analyses were also conducted on selected coal
samples.
Bottom ash samples were collected once per test from a selected bottom ash
hopper. Fly ash samples were collected from two selected baghouse hoppers and
one economizer hopper for each unit. Samples were analyzed for mineral
constituents, fusion temperature, and carbon carryover (loss on ignition,
LOI). Size, quantity, and elemental analyses were performed on selected
bottom ash and baghouse fly ash samples.
At the end of Test No. 1 a severe leak in the first point high-pressure
feedwater heater of Unit 5 occurred, and the heater had to be valved out of
service. Testing revealed that NOX emissions from Unit 4 were approximately
the same with this first point heater in or out of service. Based on this,
the Unit 4 first point heater was also valved out of set/ice for the remaining
parallel tests to allow a fair performance comparison between Units 4 and 5.
During the six tests on only Unit 4, both first point heaters were in service.
2-25
-------
EMISSION TEST RESULTS
Because the secondary air supply to the burners out of service on Unit 5 could
not be shut off, a staging effect was present that could explain the lower NOX
emissions from Unit 5 under low-load conditions. Figure 3 illustrates NOX
emissions versus stoichiometric air ratio to correct for the staging effect.
The FWEC low-NOx burners installed on Unit 4 achieved an average 50% reduction
in NOX emissions versus those from the unmodified Unit 5 when operating at
full load. Under 75% load and normal (3.4-3.7%) excess 02 levels, the
reduction in NOX emissions was 47% with AMIS, and 40% with the top MOOS. With
the two top MOOS at 50% load conditions, the staging effect on Unit 5 NOX
emission reduction was so obvious that only an average 17% NOX reduction was
observed on Unit 4.
Figure 4 illustrates NOX emissions versus unit load at various operating
excess 02 levels. A correlation analysis indicated a definite correlation
between NOX emissions and unit load for Unit 5, while the Unit 4 data did not
show significant correlation. Reducing unit load can only reduce thermal NOX,
which is a small portion of total NOX emissions. Because the turbulent
burners on Unit 5 were operated at higher peak flame temperatures than the
low-NOx burners on Unit 4, Unit 5 produced more thermal NOX than Unit 4, and
was more sensitive to unit load changes.
Figure 5 indicates that changing the burner tip position had little effect on
NOX emissions. When the burner tip position is adjusted, the primary air
velocity is changed because primary airflow is constant. Adjustments are used
to optimize the primary air/secondary air ratio to minimize shear-induced
turbulence. They may also cause major changes in flame shape. APS had
previously identified the optimum burner tip position as +3 inches.
The effects of inner and outev air register position on the performance of the
low-NOx burners in Unit 4 are illustrated in Figure 6. Inner air registers
regulate the amount of swirl in the secondary air near the burner tip and
control the point of flame ignition. Outer air registers impart initial swirl
2-26
-------
to the secondary air and control the overall flame shape and size/strength of
the internal recirculation zone. Minimum NOX emissions levels occurred at an
inner air register position of 10' open and an outer air register position of
35-40* open. With both inner and outer air registers in their optimum
positions, NOX emission levels were 0.44 Ib/MBtu at normal excess 02 level and
0.42 Ib/MBtu at low excess 02 level.
Figure 7 illustrates the NOX emissions versus burner zone liberation rate.
The effect of staging on Unit 5 NOX emissions fs obvious.
S02 flue gas values ranged from 605 to 914 ppm for Unit 4, and 546 ppm to 761
ppm for Unit 5. CO emissions on Unit 5 ranged from 32 to 75 ppm, while Unit 4
CO emissions ranged from 32 to 75 ppm except on one test with low excess 02,
where average CO emissions were 185 ppm.
Analyses of coal and ash samples taken during the testing program revealed the
consistency of the coal fired in Units 4 and 5. The coal is fairly reactive,
so there was little difference in the unburned carbon levels between Units 4
and 5.
BOILER PERFORMANCE TEST RESULTS
Based on preliminary analyses of boiler performance data, it appears that
there was no detrimental effect on boiler performance, efficiency, or
operability as a result of the installation of low-NOx burners on Unit 4.
Table 3 presents the results of a typical, full-load, boiler performance test.
Further analysis is required to explain the substantial differences between
some of the comparative data. APS plans to conduct boiler performance and
emissions testing on Unit 5 after the installation of low-NOx burners. This
will provide additional data for a better comparison of the boiler performance
before and after the burner retrofit.
Furnace Exit Gas Temperature (FEGT)
The FEGTs at full-load operations calculated using the back-calculation method
ranged from 2541 to 2680'F for Unit 4, and 2647 to 2850'F for Unit 5. The
2-27
-------
difference in FEGT for Unit 4, which ranges from 100 to 209'F lower than Unit
5 FEGT, is due to increased furnace heat absorption as a result of reduced
levels of slagging in the furnace. The low-NOx burners control high-
temperature flame regions which promote slagging.
Heat Absorption Rates in Boiler Circuits
Changes in the burner firing arrangement and the retrofit of low-NOx burners
have created a new furnace heat absorption pattern. Figure 8 illustrates a
typical comparison of heat absorption rates in the boiler circuits for Units 4
and 5.
Only enthalpies for the boiler circuits are shown in the figure because the
water/steam rates for Units 4 and 5 are almost identical. Unit 4 data shows
an increase of 31-66% in the upper furnace heat absorption rate compared with
Unit 5. This is due to reduced levels of slagging in the furnace. A decrease
of 33-43% in the primary superheater heat absorption rate is also indicated in
the Unit 4 data. The heat absorption rates for the upper furnace and primary
superheater are being investigated further to find out why there are
substantial differences between the units. The much higher upper furnace heat
absorption rate increases the primary superheater outlet steam temperature
such that the superheater spray flow requirement for Unit 4 is increased by
148-180% when compared with Unit 5. Units 4 and 5 data show insignificant
changes in the heat absorption rates in other boiler circuits such as the
lower furnace, secondary superheater, superheater enclosure, reheater, and
economizer
Main Steam and Hot Reheat Temperatures
Data indicate a slight increase in the main steam temperature for Unit 4.
Main steam temperatures are in the range of 990-1004'F for Unit 4 versus 983-
992'F for Unit 5. However, there is a substantial decrease in the hot reheat
temperature for Unit 4. Hot reheat temperatures are in the range of 947-
977'F for Unit 4 and 975-101TF for Unit 5. This is due to the pendant
reheater inlet gas temperature for Unit 4, which is 124-177'F lower than the
temperature for Unit 5. The effect of lower hot reheat temperature for Unit 4
on turbine cycle efficiency is being investigated.
2-28
-------
Boiler Efficiencies
Boiler efficiency increased slightly, in the range of 0.72-1.52%, for Unit 4.
This is due to lower air preheater inlet gas temperatures as a result of lower
economizer inlet water temperatures. During the only test that Units 4 and 5
had with both first point high-pressure feedwater heaters in service (Test
No. 1), the air preheater outlet gas temperatures were almost the same.
Therefore, it can be concluded that the boiler thermal efficiencies remained
the same after the retrofit.
CONCLUSION
The boiler emissions and thermal performance testing program comparing the
performance of Units 4 and 5 at the Four Corners Steam Electric Station
revealed that the retrofit of low-NOx burners to Unit 4 reduced NOX emissions
by about 50% at normal, full-load operating conditions without any detrimental
effect on boiler performance, efficiency, or operability.
The average level of NOX emissions from Unit 4 was 0.53 Ib/MBtu, well under
the applicable state of New Mexico air-quality standard of 0.70 Ib/MBtu.
ACKNOWLEDGMENTS
Special thanks to Four Corners operations, maintenance, and engineering
personnel for their assistance in conducting the testing, to Charles Allen for
his technical assistance, and to Paul Thompson of Tenerx for conducting the
testing.
REFERENCE
1. Vatsky, Joel, and Allen, Charles, "Predicting Boiler and Emissions
Performance by Comparative Turbulent/Low-N0x Burner Testing on a Large
Testing Facility." Proc. 1989 Joint Symposium on Stationary Combustion
NOv Control. 2, 23 (1989).
2-29
-------
WINOBOX
NORMAL FIRING POSITION
- COAL AND
PRIMARY AIR
COAL NOZZLE
Figure 1
FWEC Three - Nozzle Cell Burner
MOVABLE SLEEVE
DAMPER
SPLIT FLAME COAL NOZZLE
Figure 2
FWEC Controlled - Flow/Split - Flame Low - NO Burner
2-30
-------
NOx, LB/MBTU
1.3
Figure 3
EFFECT OF STOICHIOMETRY ON
NOX EMISSIONS
1.2
1.1
1
0.9
0.8
0.7
0.6
0.5
0.4
0.9
1.1 1.2 1.3
STOICHIOMETRIC AIR RATIO
1.4
1.5
Figure 4
EFFECT OF BOILER LOAD ON
NOx EMISSIONS
NOX
1.4
1.2
1
0.8
0.6
0.4
0.2
n
, LB/MBTU n
__- •
a
¥
— —
+ __
-f '
A
M
O
__ > —
—
+d
— •
m
,
H3
k*
•
O
-e- UNIT*
-f UNIT 5
N UNIT 4-HIGH O2
D UNIT 5-HIGH 02
X UNIT *-LOW 02
• UNIT 5-LOW O2
A UNIT 5-STAOINQ
400 450 500 550 600 650
LOAD, MW (N.tl
700 750
800
2-31
-------
Figure 5
EFFECT OF BURNER NOZZLE POSITION ON
NOX EMISSIONS
FULL LOAD NO*, LB/MBTU
1.4
1.3
1.2
1.1
1
0.9
0.8
0.7
0.6
0.5
0.4
n •>
-e- LOWER EXCESS 02
-i- HIGHER EXCESS 02
n NORMAL EXCESS 02
; C
}
t
t
-4 -3-2-10 1 2
BURNER TIP POSITION, INCHES
Figure 6
EFFECT OF AIR REGISTER POSITION ON
NOX EMISSIONS
FULL LOAD NO*, LB/MBTU
1.3-
1.1 -
•)
0.9-
0.8-
0.7 -
0 6
0.5 -
0.4 -
0 3 -
-e- INNER AIR REGISTER
-t- OUTER AIR REGISTER
* INNER REG w/LOWER O2
n OUTER REG w/LOWER O2
1
(
'^— -E
L ^^
1 ""
f-iccrrTTTTr'
fi
> -o
-,_-^
, — -^ — -^-t
r^
10 20 30 40 50 80
AIR REGISTER POSITION, % OPEN
70
80
2-32
-------
Figure 7
EFFECT OF BURNER ZONE LIBERATION
RATE ON NOX EMISSIONS
NOx, LB/MBTU
1.2-
1 -
0.8-
0 6
0.4-
0.2-
0 -
o UNIT 4
+ UNIT 5
« UNITS-STAGING
>
a
o
+
n
o
o
+
o
ef>
e
S>
o
50 100 150 200 250 300 350
BURNER ZONE UBERATION RATE, KBTU/HR-FT2
400
ENTHALPY (BTU/LB)
1500
Figure 8
COMPARISON OF SECTIONAL
HEAT ABSORPTION
2-33
-------
Table 1
COAL ANALYSES SUMMARY
Test
Proximate Analysis
% Moisture
% Ash
% Volatiles
% Fixed Carbon
Energy Content, Btu/lb
% Sulfur
MAP, Btu/lb
% Air Dry Loss
Condition
As Received
Dry Basis
As Received
Dry Basis
As Received
Dry Basis
As Received
Dry Basis
As Received
Dry Basis
Unit 4
14.67
16.33
19.14
26.47
31.02
42.53
49.84
9561
11205
0.85
1.00
13857
9.03
Unit 5
14.34
16.32
19.05
31.32
36.88
37.75
44.07
9602
11210
0.72
0.84
13848
7.57
Ultimate Analysis
% Moisture
% Carbon
% Hydrogen
% Nitrogen
% Sulfur
% Ash
% Oxygen
As Received
Dry Basis
As Received
Dry Basis
As Received
Dry Basis
As Received
Dry Basis
As Received
Dry Basis
As Received
Dry Basis
14.67
53.87
63.13
3.86
4.52
10
29
0.85
1.00
16.33
19.14
9.32
10.92
14.34
54.55
63.68
96
62
15
34
0.72
0.84
16.32
19.05
8.96
10.47
2-34
-------
Table 2
TEST MATRIX
Test Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Load
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
75%
75%
75%
75%
50%
50%
50%
50%
50%
Units
4&5
4&5
4&5
4&5
4
4
4
4
4&5
4&5
4&5
4&5
4&5
4&5
4&5
4&5
4&5
4&5
4&5
4&5
4&5
Excess Air
Normal
Normal
Low
Normal
Normal
Normal
Normal
Normal
Low
High
Low
High
Normal
High
Normal
Normal
Normal
High
Normal
Normal
Normal
Test Condition
Std. Nozzle & Register Positions
Std. Nozzle & Register Positions
Std. Nozzle & Register Positions
Repeat Std.
Outer Register Open
Outer Register Closed
Inner Register Open
Inner Register Closed
Burner Nozzle In (0)
Burner Nozzle In (0)
Burner Nozzle In (-3)
Burner Nozzle In (-3)
Std., All Mills In Service
Std., All Mills In Service
Std., 1 Mill Out of Service
Std.
Std., 2 Mills Out of Service
Std., 2 Mills Out of Service
Repeat Std.
Optimal Nozzle Register Positions
Optimal Nozzle Register Positions
2-35
-------
Table 3
TYPICAL COMPARATIVE BOILER PERFORMANCE DATA
Parameter Unit Unit
Load, MW 760 752
Excess 02, % Wet 2.82 2.74
Feedwater Flow, 1000 Ib/h 5478 5493
Superheater Spray Flow, 1000 Ib/h 433 286
Main Steam Temp., "F 1004 992
Hot Reheat Temp., 'F 965 999
Furnace Exit Gas Temp.,'F 2593 2775
NOX, Ib/MBtu 0.49 1.15
2-36
-------
DESIGN AND APPLICATION RESULTS OF A NEW EUROPEAN LOW-NOX BURNER
J. Pedersen
Burmeister & Wain Energy
23 Teknikerbyen
DK-2830 Virum, Denmark
M. Berg
ELKRAFT Power Company
5 Lautruphoej
DK-2750 Ballerup, Denmark
-------
DESIGN AND APPLICATION RESULTS
OF A NEW EUROPEAN LOW-NOX BURNER
J. Pedersen
Burmeister & Wain Energy
23 Teknikerbyen
DK-2830 Virum, Denmark
M. Berg
ELKRAFT Power Company
5 Lautruphoej
DK-2750 Ballerup, Denmark
ABSTRACT
To meet the new NOX regulations in Denmark, the ELKRAFT Power Company decided in
1987 to retrofit existing coal-fired units with low-NOx burners. In cooperation with the boiler
company Burmeister & Wain Energy, a new burner was developed to meet the specifications
of the first boiler to be retrofitted, and was tested at full scale in 1988 in an experimental
facility in the USA. In 1989 the front wall-fired Asnaes Unit 4 (285 MWe) was retrofitted with
24 coal/oil low-NOx burners of the new design, each with individual control of the combustion-
air flows. Daily operating experience, and specific testing with a range of world coals, has
demonstrated greater than 50% reduction in NOX emissions, whilst maintaining carbon in fly-
ash levels below 5%. Due to the stable and well-attached nature of the flames, the control
range on coal-firing has also been considerably extended. Evidence of flame impingement
on furnace walls, slag deposition or corrosion has not been observed. Following this
successful program several additional boilers will be retrofitted with the new low-NOx burners
in the near future.
2-39
-------
DESIGN AND APPLICATION RESULTS
OF A NEW EUROPEAN LOW-NOX BURNER
INTRODUCTION
In Denmark, more than 90% of the power is generated from coal, and having no domestic
coal resources, the coals are imported from all over the world.
To meet the NOx-regulations, the existing power stations in Denmark have to reduce the total
amount of nitrogen oxide emission per year gradually until the year 2005 in which a 50%
reduction, in relation to the 1980-level, will be demanded. New units will be further restricted
in their NOx-emission.
The ELKRAFT Power Company, covering the eastern part of Denmark and generating about
half of the Danish power supply, decided in 1987 to retrofit a number of units with low-NOx
burners. The Asnaes Power Station Unit 4 was the first unit to be retrofitted in 1989.
In the light of the low-NOx burner technology existing at that time, it was decided to develop
a new low-NOx burner for Asnaes Unit 4. The development program was sponsored by the
ELKRAFT Power Company and carried out in cooperation with the boiler and burner
manufacturer Burmeister & Wain Energy and the Asnaes Power Station.
ASNAES UNIT 4
Asnaes Unit 4, with a capacity of 270 MWe net, was commissioned as an oil-fired unit in
1968 and was converted to coal/oil-firing in 1978.
The boiler is of the Benson type and is front wall-fired. It is a two-pass system with reheater
and dry bottom furnace. The boiler has no flue gas recirculation system, and is designed for
full load when firing heavy fuel oil or bituminous coal. The coals used are imported from
countries around the world. The design coal is high volatile Polish coal. Due to the fly ash
2-40
-------
utilization in the cement industry, the unburnt carbon is limited to a maximum of 5%. Boiler
dimensions are shown on Figure 1, and performance data are listed in Table 1.
The 24 burners are located on the front wall in 4 levels of 6 burners each. Each burner level
is supplied with pulverized coal from its respective coal mill of the ball-ring type. During
normal operation, three coal mills, 18 burners, will maintain full load of the unit. Combustion
air is controlled and supplied separately to each individual burner.
LOW-NOX BURNER DESIGN CRITERIA
In the design of the new low-NOx burners, a number of design criteria were taken into
account. For application to Asnaes Unit 4, the number of burners and their location were to
be maintained. However, since the existing burner openings were designed for the original
unit operating on oil-firing only, it was decided that larger openings would be installed on the
boiler front wall. The size of the new burner openings was, however, restricted by the
presence of vertical support tubes. Also, the fact that future boiler retrofits would need to be
accomplished without modifications to the firing wall was taken into consideration in sizing
the new burners.
The restrictions caused by the vertical support tubes were also one reason for the new
burners being developed to achieve optimum NOX control at full boiler load with all 24
burners in service. This corresponds to a nominal fuel input of 28.8 MW per burner. It was
required, however, that full load should still be attainable on 18 burners only, corresponding
to a fuel input of 38.3 MW per burner, but without necessarily maintaining optimum NOX
performance.
When firing coal, the low-NOx burner should have a load range from 38.3 MW down to 16
MW fuel input and should have a reliable flame scanner signal over the full load range.
The layout of the new burner was also influenced by the decision not to change the coal mill
system. Furthermore, the burners should also be able to obtain full boiler load on heavy fuel
oil.
The goal for the burner development program was to achieve a NOx-emission at Asnaes with
full boiler load and 3% excess O2 at the economizer outlet, of less than 440 ppm (3% O2,
dry) with less than 5% unburned carbon in the fly ash. The pre-retrofit full load baseline NOX-
emission for Asnaes Unit 4 was 740 ppm (3% O2, dry).
Only low-NOx burners were taken into consideration for NOX reduction on Asnaes 4. Because
of limited residence time in upper furnace and the possibility of low mixing efficiency, the use
of overfire air was out of the question.
2-41
-------
BURNER DEVELOPMENT PROGRAM
In order to retrofit the Asnaes boiler with an optimum burner, a full-scale test burner of the
internal staging type was optimized in a "Coal Burner Test Facility" in USA in 1988,
simulating the same conditions as in Asnaes 4.
The test burner was designed with a high degree of flexibility and provided for a wide range
of variables in the configuration of combustion-air registers and in the design of the coal
injector. The test burner design was based upon common design features employed in
existing Burmeister & Wain coal burners, such as the axial movable turbolator for swirl
control.
The optimized low-NOx burner is based upon staged combustion with the flame attached to
a flame holder, mounted at the exit of the coal pipe. Typically, NOx-emissions will be reduced
when a detached flame (with flame stand-off) is changed to an attached flame, anchored by
the flame holder. The flame holder establishes local recirculation zones and promotes mixing
between coal and secondary air. Secondary air swirl ensures a well-attached flame. Sample
data from the burner test, shown on Figure 2, shows more than 50% NOx-reduction, when
changing burner settings.
The burner design is such that the tertiary air turbolator setting controls the flame shape.
With a flame length well below the firing depth of the Asnaes 4 furnace, the performance of
the optimized test burner at nominal load was 260 ppm NOX (3% O2, dry) with less than 5%
carbon in the fly ash. The burner was also tested at high load, corresponding to three-mill
operation at Asnaes 4, and at low load corresponding to minimum load on the coal mills.
Burner testing was conducted primarily with U.S. (Pennsylvania) coal and Polish coal with
limited tests on heavy fuel oil (no. 6). The development program was terminated with
operation of the optimized test burner to determine such parameters as secondary air/tertiary
air-flowsplit and turbolator settings. Good flame scanning signals were demonstrated over
the full load range.
BOILER RETROFITTING
At the end of 1989 Asnaes Unit 4 was brought back into operation with 24 of the low-NOx
burners installed in new boiler wall openings.
The new burner design is based on the recommendations developed in the burner test
program, and has been designated as the "BWE Type 4 AF" low-NOx burner. The burner
design is illustrated schematically in Figure 3, and shows the division of the combustion air
into secondary air and tertiary air streams, each with an axial movable turbulator for swirl
control.
In forward position, the axial turbolator creates a maximum swirl of the airflow. While
retracted, a certain part of the airflow bypasses the turbolator vanes and thus weakens the
swirl of the total flow. Both turbolators in the burner are provided with drives and are,
independently of each other, adjusted automatically or from the control room.
2-42
-------
A "LAND" flame monitor of the cross-correlation type is mounted on each burner for detection
of both coal flames and fuel oil flames.
The burners are provided with oil lances with steam atomization and high voltage ignition
lances.
The 24 combustion air ducts were modified during the burner retrofitting. The duct section
after each combustion air venturi was changed to include secondary and tertiary air ducts,
each with a control damper.
The secondary and tertiary air flow to each burner is measured by the common venturi. The
secondary air flow is measured downstream and separately by an annubar probe;
subsequently, the tertiary air flow is calculated. The secondary and tertiary airflow, as well
as the so-called SA/TA-flowsplit, is controlled automatically by the two dampers. The coal
and air supply to a given burner level is illustated on Figure 4.
A small part of the secondary air is supplied to the core air pipe as cooling and sealing air
around the oil lance. The core airflow to each burner was adjusted during the commissioning
by a manually operated damper and a pitot tube.
Due to the high degree of automation on Asnaes Unit 4, and because of the knowledge of
optimum burner settings obtained in the test program, the new burners were commissioned
in a very short period of time. In fact, only one half day was required to set and to verify
satisfactory operation of all 24 burners.
With coal-firing, the ideal secondary air tubolator position is forward for generation of high
swirl. At high burner loads, the tertiary airturbolator position is retracted in order to reduce
swirl, whilst at low burner loads, the tertiary air turbolator position is forward. For fuel oil-
firing, both turbolator settings are retracted for swirl reduction.
During boiler operation on coal, the six burners in one burner level are operated with identical
burner settings. All burner levels in service are operated similarly. During daily operation, the
burners are operated automatically over the full load range for coal-firing, as well as for fuel
oil and combined coal/oil-firing.
FIELD TESTS
During the first three months of 1990, the burners were tested with a range of different coal
types, i.e. Polish, U.S., W. Canadian and Colombian coals representing a volatile content
from 20.2% to 32.9% (as received) and an ash content from 6.8% to 18.6%. Typical coal
analyses are presented in Table 2.
2-43
-------
For the field test program at Asnaes 4, additional measurement and sampling equipment was
used. NO, SO2, O2, CO, CO2 and H2O in-situ instruments were installed at the two induced
draught fan outlets. Pulverized coal was sampled from each of the coal pipes with a rotary
multiprobe sampler. Coal samples were taken from the coal feeders during operation. Fly ash
was sampled from the two vertical flue gas ducts before the ESP, which is located on the
boiler house ceiling. Suction pyrometers were also installed for measurement of gas
temperature and O2% in upper furnace.
All gas emission data, the most important boiler data, firing system data and burner data
were sampled and averaged with an on-line data logging processor.
During the burner test program, the NOx-emission dependence on excess O2 and unit load
was recorded for 4 and 3 mill operation respectively. Also the dependence on turbolator
settings and SA/TA flowsplit was tested.
RESULTS
The main field test was carried out on Polish coal, since this coal type was the design coal
for Asnaes 4 and was used during the burner development program.
The following results summarize the tests with Polish coal, at full boiler load and are shown
in Figure 5:
0 4-mill operation: NOX = 370 ppm (3% O2, dry) and < 5% carbon in
fly ash at 3.0% O2 (dry), at the economizer outlet.
• 3-mill operation: NOX = 410 ppm (3% O2, dry) and < 5% carbon in
fly ash at 3.5% O2 (dry), at the economizer outlet.
These actual NOx-emissions on Asnaes 4 are close to the NOx-emissions estimated from the
testburner data, considering differences in the burner zone heat release rate.
With 3 mill operation, a cooling air flow through the burners out of service amounts to an
airflow at full boiler load, corresponding to 0.5% excess O2, at economizer outlet.
The distribution of pulverized coal to the burners, at full boiler load was measured to a
deviation from the average of 10-15%. For individual burners, however, the deviation could
be up to 25%.
The average fineness of the coal at full boiler load for Polish coal was found to be:
• 4-mill operation: 20% > 90 microns (170 mesh) and
0.9% > 250 microns (60 mesh)
• 3-mill operation: 26% > 90 microns (170 mesh) and
0.5% > 250 microns (60 mesh)
2-44
-------
Load was found to have only a moderate influence on the NOx-emission as shown in Figure
6. These results represent data with all burners in service and constant excess air at the
economizer outlet.
The secondary/tertiary air split was also tested over a nominal control range for full boiler
load and 3 and 4 coal mills in operation. As shown in Figure 7, this parameter has only a
small impact, indicating a satisfactory selection of optimum design parameters.
The tertiary airturbolator position has also a negligible effect on the NOx-formation, as shown
in Figure 8, but has a marked impact on flame shape.
Burner testing with the other coal types (U.S., W. Canada, Colombia) shows similar trends
as for Polish coal, but with minor variations in the absolute NOX levels, as shown in Figure
9.
OPERATING EXPERIENCE
Reliable ignition of the heavy fuel oil flames with the high voltage igniter has been proven
with the new low-NOx burner. Also, when firing coals within the normal range of control,
stable ignition characteristics have been demonstrated with attached and well-defined flames.
With normal burner settings, flame lengths are less than 9 meters, and are easily
accommodated into the furnace without impingement on the rear wall.
Acceptable performance on Polish, US, Canadian, and Colombian coals, in addition to a
number of mixed coals types, has been demonstrated since the initial commissioning of the
burners.
The NOX reduction level achieved on this unit is demonstrated by a comparison of daily
averages of NOX emissions during routine operation for periods before and after the burner
retrofit. This comparison is shown in Figure 10. For the period January to March 1989, which
was prior to the retrofit, the NOX emissions averaged 740 ppm (3% O2, dry). With the new
low-NOx burners, and over the same period in 1990, NOx emissions averaged 345 ppm (3%
O2, dry). This corresponds to an average NOX reduction of greater than 50%.
Daily average NOX emissions before and after the retrofit are further compared in Figure 11.
One further important consequence of installing the new low-NOx burners has been the ability
to reduce the minimum unit load with coal-firing from 180 MWe net, to 130 MWe net. The
control range of the unit before and after the burner retrofit is compared in Figure 12, where
the extended range is a direct result of improved flame stability with the new burner design.
This represents a potential for considerable savings in heavy fuel oil consumption during
start-up and low load operation. Minimum coal load on the unit is now obtained with two coal
mills in operation, and is limited only by the available primary air temperature for the coal
drying process.
2-45
-------
Since the commissioning of the new low-NOx burners, the boiler has been operated with
individual flame monitoring with no problems and maintaining strong scanner signals.
For the types of coals used, no slag deposition has been found on the furnace walls or in the
burnerthroats. Soot blowing once every 24 hours has been sufficient. On one occasion when
firing U.S. coals, the boiler was operated for 60 h without soot blowing, with no problems at
all. The consistency of the bottom ash is very porous compared with the pre-retrofitting
bottom ash.
The boiler operation has therefore been significantly improved by retrofitting the low-NOx
burners. Boiler efficiency and capacity have, however, not been reduced compared with
conditions before the burner retrofit.
CONCLUSION
The results of more than 1 year of operation with the new low-NOx burner at Asnaes Unit 4
can be summarized as follows:
• NOx-emission reduced by 50%
• Unburned carbon in ash less than 5%
• Stable flames at all boiler loads
• No flame impingement on furnace walls
• No slag deposition in the furnace
• Increased control range on coal-firing
• Excellent flame scanner signals
• Good correlation between test-burner and field-burner results
2-46
-------
FURTHER RETROFITTING PROGRAMS
Following the positive experience with Asnaes Unit 4 in 1989, further ELKRAFT units will be
retrofitted with the Burmeister & Wain, type 4AF Low-NOx burners:
1991: Amager Unit 1, 140 MWe, 12 burners, front wall fired drum boiler
1991: Asnaes Unit 2, 155 MWe, 12 burners, opposed fired drum boiler
1992: Amager Unit 2, 140 MWe, 12 burners, front wall fired drum boiler
1992: Asnaes Unit 5, 725 MWe, 48 burners, opposed fired Benson boiler.
These retrofit programs will be based on the burner designs and experience developed in
Asnaes Unit 4, and will be achieved without changes to the existing burner openings, or
major modifications to the existing firing systems.
ACKNOWLEDGEMENTS
The authors wish to thank the following organizations for generously providing equipment and
services. The authors also wish to thank the personnel for all its efforts and services
rendered to make this project possible:
Energy and Environmental Research Corporation
Riley Research Center
Land Combustion
2-47
-------
41.75
Figure 1. Asnaes 4 boiler dimensions.
TEST BURNER
NOx
ppm
400
300
200
100
"5
<
-c
u
-i
I
-i
i!
$f •
- \ ™
•-]•-
:'^
— £
•--!
r
*
si
i-
r
-
.
t:
-
r^
-
7
-
I
-T*
-
_"
^1
_ f
-t'
4'
-I
^-^
~4
-t -
:-L
-r
t
- i
^
J1
L
\
:
_
^-
_
^
.
-
""
t
-
A-
—
—
-
-,-
—
-
--
^-,
U-
•r.
;
•v
.
::
-
-
-_
-
f
-__
-
r
/
-
r
n
- _
-
-
-
-
-
s
—
-
"_
-
-
-
^
"
fW
-
--
A
1
--
-_
-
^
-
v/
-
-
\-
w
V
'-
-
r
-
A
-
-"-
U
r*
-
-
--
-"
-
V
[_*
-
t
-:-
-
1
pt.
n
•^
L-
_
-
—
v
>«.
*•
^
•
-
H-
i
-
•v
w^
;-_
—
-
^-
-;
-
--
T
v»
L
A.
—
•s.
v
--
-
^
77
I/
/
T
:
5
ATTACHED FlArtE
DIRECTION OF CHART SPEED
ml n .
Figure 2. NOX reduction by flame attachment.
2-48
-------
TERTIARY
AIR
IGNITER
FOR SUIRL CONTROL
L-FLAME HOLDER
PRIMARY AIR
+
PULVERIZED COAL
Figure 3. "BWE type 4 AF" attached flame low-NOx burner.
ASNAES POWER STATION UNIT NO. 4
COAL AND AIR SUPPLY TO BURNERS
ii
TERTIARY
AIR
65X
PRIMARY AIR
+
PULVERIZED COAL
COAL MILL
Figure 4. Coal and combustion air supply to a burner level.
2-49
-------
ASNAES POWER STATION UNIT NO. 4
FULL LOAD. POLISH COAL
NOX ppm
(37. 02 .DRY)
500 -
400 -
300
?00
100
2.5
NOX ppm
(3% Oj .DRY)
500
400
300
200 -
100 •
oH
CARBON IN ASH
• 4 MILLS
A 3 MILLS
-7
-6
-5
-4
-3
-2
- t
0
3.0
3.5
4.0 X 0, (DRY)
Figure 5. Relation between NOx-emission and excess O2%.
ASNAES POWER STATION UNIT NO. 4
POLISH COAL. 4 MILLS IN SERVICE
CARBON IN ASH
-10
-9
-6
-7
-6
-5
-4
-3
-2
- 1
160 160 200 220 240 250
MU
e .net
Figure 6. Relation between NO -emission and unit load.
2-50
-------
ASNAES POWER STATION UNIT NO. 4
FULL LOAD. POLISH COAL
NOx ppm
C3X 02 .DRY)
500 -
400 •
300 •
200 •
100 -
• 4 HILLS
A 3 MILLS
SECONDARY A!R / TERTIARY AIR FLOUSPLIT
Figure 7. Relation between NO-emission and SA/TA-flowsplit.
ASNAES POWER STATION UNIT NO. 4
FULL LOAD. POLISH COAL
NOX ppm
C3X 02 .DRY)
500 -
400 -
300 -
200 -
100 -
0 -
A-=- * L
•- • A
• 4 MILLS
A 3 MILLS
60 70 80 90 100 %
Figure 8. Relation between NOx-emission and TA-turbolator positi
2-51
-------
ASNAES POUER STATION UNIT NO. 4
FULL LOAD. 4 MILLS IN SERVICE
NOX pp
500 -
400
300 -
200 -
100 -
O CANADIAN COAL
O COLUMBIAN COAL
D U.S. COAL
• POLISH COAL
2.5
3.0
3,5
4.0 % 02 [DRY)
ECONOMIZER OUTLET
Figure 9. Relation between NOx-emission and
excess O2% for different coal types.
ASNAES POUER STATION UNIT NO. 4
COMPARISON OF DAILY AVERAGE NOx EMISSIONS
mg/MJ (LHV)
500
NOx EHISSION
500
400
300
200
too
Ib/mmBtu (HHV)
I,
_ fy. * i y • •
•rt • ••_>*• •
• * ," . V • «*L ^
OLD BURNERS
JANUARY-MARCH 1989
NEU BURNERS
JANUARY-MARCH 1990
-- 0.5
-"- 0
EACH DOT REPRESENTS DAILY AVERAGE
Figure 10. Comparison of NO -emission with new and old burners.
2-52
-------
N0y ppm
(3% 02 .DRY)
1000
900 -
600
700 -
600
500 -
400
300 -
200
100 -
ASNAES POWER STATION UNIT NO. 4
COMPARISON OF NOX EMISSIONS
N0» EMISSION
PRE
POST
RETROFITTING ASNAES 4
EC-DIRECTIVE U.S. CLEAN AIR ACT
NEW COAL-FIRED DRY-BOTTOn. UALL-FIRED
BOILERS >50 MU (0.5 Ib/mmBtu)
Figure 11. Pre- and post-retrofitting data.
ASNAES POWER STATION UNIT NO. 4
COMPARISON OF CONTROL RANGES ON COAL FIRING
MWe.nel
300
200
250
240
220
PLANT LOAD
200 •
180
150 -
140
120 •
100
PRE
POST
RETROFITTING ASNAES 4
Figure 12. Unit control range.
2-53
-------
Table 1
PERFORMANCE DATA
Generator output
Net output
High-pressure steam, outlet
Reheat steam, outlet
285 MWe
270 MWD
c
235 kg/sec
190 bar
545°C
40.5 bar
545°C
Coal Type
Ultimate, as received
Table 2
COAL ANALYSES
Polish
U.S.
Canadian Colombian
Proximate, as
Moisture
Ash
Volatiles
Fixed carbon
received
o/
/o
-------
APPLICATION OF GAS REBURNING-SORBENT INJECTION TECHNOLOGY
FOR CONTROL OF NOX AND S02 EMISSIONS
W. Bartok
B.A. Folsom
T.M. Sommer
J.C. Opatrny
E. Mecchia
R.T. Keen
Energy and Environmental Research Corporation
18 Mason
Irvine, California 92718
T.J. May
M.S. Krueger
Illinois Power Company
500 South 27th Street
Decatur. Illinois 62521
-------
APPLICATION OF GAS REBURNING-SORBENT INJECTION TECHNOLOGY
FOR CONTROL OF NOX AND S02 EMISSIONS
ABSTRACT
A Clean Coal Technology project is being carried out by Energy and Environmental
Research Corporation (EER) to demonstrate Gas Reburning-Sorbent Injection (GR-SI)
technology for NOX and SO? emission control from coal fired utility boilers. Phase
I, Design and Permitting, was completed in 1989 for three coal fired utility boiler
host sites in II1inois--tangential , wall, and cyclone fired units. The overall
objectives of the program are to reduce NOX emission by 60% and SOz emission by 50%
while maintaining or improving operability and not causing adverse environmental
impacts. In view of the Clean Air Act Amendments of 1990, the niche for this
technology appears to be relatively small, older, low capacity factor units firing
coals of medium to high sulfur content.
This paper describes the design and installation of the GR-SI and ancillary
equipment for a 71 MWe (net) tangentially fired boiler (Illinois Power Hennepin Unit
No. 1), which burns 3.0 wt% sulfur Illinois coal. The detailed design of the GR-SI
system was based on process specifications obtained through mixing, heat transfer
and kinetic modeling. Four sets of four tangential natural gas injectors with
recirculated flue gas as carrier have been installed above the existing coal
burners for gas reburning, followed by four reburn air ports in the upper furnace.
Hydrated lime sorbent will be injected with transport air through six injectors at
the elevation of the boiler nose, four on the front wall and two on side walls (at
low load the reburn air ports will be used for sorbent injection). Flue gas duct
humidification has been installed to upgrade the performance of the electrostatic
precipitator (ESP) with sorbent injection. The spent sorbent/fly ash mixture will
be sluiced to an existing ash pond after neutralization by CO?.
This paper compares predicted results with data collected during initial
operations.
2-57
-------
APPLICATION OF GAS REBURNING-SORBENT INJECTION TECHNOLOGY
FOR CONTROL OF NOX AND S02 EMISSIONS
INTRODUCTION
Gas Reburning-Sorbent Injection (GR-SI) n-12) is the combination of two developmental
technologies being tested by Energy and Environmental Research (EER) at Illinois
Power Company's Hennepin Power Station Unit 1. This project is part of the U.S.
Department of Energy's Clean Coal Technology program. Co-funding the project with
DOE are the Gas Research Institute and the Illinois Department of Energy and
Natural Resources.
The basis of the GR-SI technique (shown schematically in Figure 1) is the
introduction of a calcium-based sorbent and natural gas into the boiler to reduce
both sulfur dioxide ($02) and nitrogen oxide (NOX) emissions. The specific goal of
the project is to demonstrate that S02 reductions of 50% and NOX reductions of 60%
are attainable on an economically feasible basis. Among the advantages of this
technology is that many coal fired boi 1 er--especial ly small, older ones — can be
retrofitted to use it at a reasonable cost.
Illinois Power's Hennepin Unit 1 is a tangentially fired pul verized-coal boiler
utilizing 3 wt% sulfur Illinois bituminous coal. As part of the same project. GR-
SI technology will be tested on a cyclone-fired boiler at City Water. Light, and
Power's Lakeside Unit 7 in Springfield. Illinois.
The GR-SI process has two distinct steps. The first step, gas reburning, modifies
boiler combustion by firing only 80-85 percent of the coal fuel in the lower
furnace. The remaining fuel requirement is provided by injecting natural gas above
the primary combustion zone. This gas creates a slightly fuel-rich "reburning
zone" above the main coal flame zone. The gas reacts with NOX to form molecular
nitrogen. Finally, overfire air is injected into the upper furnace to complete the
combustion process without generating additional NOX.
The second step occurs above the reburning zone when a calcium-based sorbent
(hydrated lime in this project) is injected into the upper furnace. The SO? in the
furnace gases reacts with the sorbent to form calcium sulfate, which passes through
2-58
-------
the convective pass of the boiler with coal fly ash and unreacted sorbent, to be
collected by the electrostatic precipitator.
Preliminary tests indicate that the most important factors controlling the
effectiveness of the GR-SI process are:
1. The ratio of air to fuel in the reburning zone. Overall NOX reduc-
tions are highest when that ratio in that zone is 0.9. The test
program will verify the optimum quantity of reburning gas for NOX
reduction.
2. Residence time distribution of the. reactants in the reburning zone.
Mean gas-phase residence time in the zone is 0.3 to 0.5 seconds. By
operating the system under varying load conditions, the influence of
residence time on reburning effectiveness will be quantified.
3. Temperature of the furnace. Sulfur capture (sulfation) occurs at
temperatures between 1600°and 2200°F. Temperatures in excess of
2300°F significantly reduce the sulfation rates because of
"deadburning." Tests conducted at varying load conditions will
quantify the influence of furnace temperature on sulfur removal.
GAS REBURNING DESIGN
Another critical factor to the success of both processes is the rapid and complete
mixing of the injected reactants with the furnace gases. To ensure this, a 1/12
scale isotherma"! flow model of the Hennepin boiler was built to test the
effectiveness of the proposed injector designs. The model was based on furnace gas
velocity measurements made during the field evaluation tests. Smoke and soap
bubbles were used in the model to make the jets visible, and quantitative
dispersion measurements were made using methane as the tracer. The physical models
were verified using computer models of the heat transfer characteristics of the
boiler.
SORBENT INJECTION DESIGN
Sorbent Injection is used to reduce S02 emissions from the combustion of sulfur-
containing fuels. At Hennepin Unit 1, the SI system consists of the following
steps:
1. Hydrated lime is injected into the upper furnace.
2. The flue gases are humidified prior to solids collection in the
electrostatic precipitator (ESP) to enhance the performance of the
ESP by increasing the conductivity of the solids and decreasing the
temperature of the gases.
2-59
-------
3. An acid is injected into the ash sluice line to control the pH of
the effluent water to a value between 6 and 9.
The process design for sorbent injection involved the selection of the appropriate
temperatures, furnace injection points and proper velocities for good dispersal.
mixing and contact of sorbent particles and SO? gases.
Sorbent is used in excess quantities because sorbent utilization is incomplete.
The collected mixture of fly ash and sorbent is alkaline. Uhen the fly ash is
hydraulically conveyed to an ash pond, the resulting pH is above 9.0. Acidity
control can be accomplished by the addition of an acid such as sulfuric,
hydrochloric, acetic or C02- The choice of the acid depends upon existing and
anticipated ground water quality vs. regulatory levels, corrosiveness vs. system
materials, and cost. For the Hennepin installation, pH control by liquid CO?
injection was selected.
The GR-SI injector specifications are shown in Figure 2. They include four sets of
four tangential natural gas injectors with recirculated flue gas as carrier
installed above the existing coal burners for gas reburning. followed by four
reburn air ports in the upper furnace. Hydrated lime sorbent will be injected with
transport air through six injectors at the elevation of the boiler nose, four on
the front wall and two on side walls (at low load injectors located in the reburn
air ports will be used for sorbent injection). Flue gas duct humidification has
been installed to upgrade the performance of the ESP with sorbent injection.
GR-SI ENGINEERING DESIGN
Based on detailed process design studies completed for the Hennepin boiler, GR-SI
system performance requirements were identified. Detailed engineering followed to
identify new equipment and modifications to existing equipment necessary to achieve
those performance requirements. The GR-SI installation is shown in the schematic
di agram of Fi gure 3.
The Gas Reburning-Sorbent Injection and auxiliary system design included detailed
engineering work in the following areas:
Sorbent injection system
Gas reburning system
Flue gas humidification system
Ash handling system modifications
Power distribution system modifications
Control system modifications
Sootblowing system modifications
2-60
-------
To meet performance requirements for the sorbent injection system, subsystems were
designed to store, meter, convey, and inject sorbent into the Hennepin boiler upper
furnace. A new bolted, skirted sorbent storage silo was erected to provide
approximately 3 days supply at the nominal operating condition (Ca:S-2.0). Sorbent
will be delivered by truck to the site, pre-pulverized, and pneumatically conveyed
into the storage silo. The metering and dilute-phase conveying subsystem will
deliver 2,300-11,200 Ib/hr of sorbent to be distributed evenly to the injection
nozzles. Additional injection air is introduced with the sorbent/transport air
stream at the injection nozzles located on the front and side walls of the boiler
upper furnace.
The performance requirements for the gas reburning subsystems were designed to
meter, convey, and inject natural gas, recirculated flue gas, and overfire air into
the Hennepin boiler furnace. The GR system is designed to supply 2244 SCFM or
approximately 20% of the boiler fuel requirements at full load. Recirculated flue
gas is mixed with the natural gas at the point of injection into the boiler. The
flue gas stream provides the jet momentum necessary to insure that adequate mixing
of the natural gas and the combustion products occurs in the boiler furnace. A
total of 3-5 percent of the flue gas is recirculated in the Hennepin Unit. The
overfire air system provides heated combustion air to four ports located on three
of the four furnace walls. This air stream provides the oxygen necessary to
complete burnout of the remaining combustibles in the furnace.
To maintain particulate emissions below the allowable limit, the performance of the
existing ESP must be enhanced during sorbent injection. This is accomplished by
using a single pass multi-spray humidification system. The system is designed to
deliver approximately 60 gpm of filtered river water to cool the flue gases to 70°F
above saturation. The test program will identify the optimum requirement of
cooling water. Compressed air is used to atomize the water. The existing flue gas
breeching was modified to provide 2.0 seconds of retention time in the
humidification spray chamber prior to entering the ESP. The installation of the
spray chamber required that the ID fans be relocated as well as the replacement of
the majority of the ESP inlet and outlet ductwork.
The flue gases contain a mixture of solid particulates as they exit the boiler
during GR-SI operation. The particulate is a mixture of normal coal ash and
partially sulfated sorbent. Analysis of ash handling alternatives available to the
Hennepin site determined that wet handling to an on-site pond was the most cost
effective approach. Modifications to the existing sluice system included a new
hydroveyor with a built-in ram for cleaning, sluice line replacement and a new
microprocessor based controller.
A power distribution system was designed to provide power to all the GR-SI system
equipment. The power is fed from the plant's existing 2300 V switchgear. A new
2-61
-------
1000 KVA transformer reduces the voltage to 480 V for distribution. That supply is
distributed to the GR-SI equipment through various overload and fault protection
equipment. All motors rated from 1 HP to 200 HP are supplied 480 V. and smaller
motors are supplied 110 V. The maximum peak demand expected during GR-SI operation
is 750 kW.
The control of the GR-SI systems was studied extensively during the design
engineering effort. Control logic was determined to provide system operation in a
safe and efficient manner. Necessary control system hardware and software
modifications were identified and equipment selected. A Westinghouse WDPF
microprocessor system was selected in order to allow for future expansion and
interaction with any future controls upgrade.
After reviewing the cleaning capability of the existing 16 sootblowers, it was
determined that several areas of the boiler may be subject to heat transfer surface
fouling due to the increased ash loading in the flue gas during sorbent injection
operation. The areas of concern are all in the downflow convective section of the
boiler. Eight sootblower locations were identified for the installation of the new
sootblowers, which are supplied by a new sootblower air compressor.
PERFORMANCE TESTING
To determine performance of the process, a continuous emissions monitoring system
(CEMS) is needed. The CEMS is capable of monitoring from the economizer or from
the stack breeching. At the economizer, eight 4-in. sampling ports are utilized.
Each contains two phase discrimination probes designed to reduce particles in the
gas stream. Eight of the probes are inserted 1/3 of the way into the duct, and the
other eight 2/3 of the way. to provide a sampling grid representative of the
economizer duct flow.
The phase discrimination probe design is shown schematically in Figure 4. The
design of the probe is such that heavy dust particles in the gas are unable to make
the two 90° bends required to enter the annular space and flow to the monitoring
system. A ratio of approximately 10:1 by-pass gas to sample system gas is
maintained. The relatively clean gas from each probe passes through a filter and
rotameter system, and is then pumped to the test trailer via a heated Teflon sample
line. The CEMS analyzers used in the test trailer are shown in Figure 5. All
components outside the sample duct are heated to at least 250°F to prevent
condensation in the sampling system.
is
Phase discrimination probes are not required at the stack breeching. This
because of the very low dust content and good mixing from the ID fan just upstream.
Thus, only a single probe is used for sampling.
2-62
-------
The test trailer is equipped with a computerized data acquisition system which is
tied to all of the monitors. Every 3 seconds the computer takes a reading from
each instrument. The computer logs the average of the readings each minute. The
computer displays the raw signals and calculated emission data. Two hour trends of
average data are also available. All data are downloaded to tape from the hard
disk daily for later reduction and analysis.
BASELINE MEASUREMENTS
Baseline data measurements began on October 1. 1990. Over the period October 1,
1990 through January 23, 1991, economizer sampling was performed on 49 days for a
total of 406 hours, with stack breeching data collected on 19 days for a total of
166 hours. Hennepin Unit 1 is a cycling unit and is generally under dispatch
control . Thus, the load varies widely from day to day and the unit is frequently
off-line from 10 P.M. to 6 A.M. during the week and more often than not is off
during weekends. Thus, it provides a changing environment for NOX formation due to
the lack of steady state during its normal mode of operation. The distribution of
economizer sampling hours versus load is shown below:
MWe(gross) hr MUe(gross) hr
30-34 3 55-59 89
35-39 12 60-64 71
40-44 19 65-69 80
45-49 29 70-75 53
50-54 50
Figure 6 shows a plot of NOX concentration versus load under baseline conditions.
The data points represent average values of NOX versus boiler load grouped in 5 MW
increments. The solid line represents the linear regression trend line with the
dashed lines indicating ±1 standard deviation.
GAS REBURNING RESULTS
Only short term GR runs have been made to date (February 1991) to initiate the
optimization of the operation, which will be followed by optimization of SI
operating conditions and long term tests of the combined technology. Six-hour runs
were performed on a number of occasions. Parameters that were varied include:
natural gas, flue gas recirculation, overfire air (OFA) flow rates, and reburning
zone stoichiometry at different boiler loads. Figure 7 shows a plot of NOX and 0?
versus time during a typical GR run. It can be seen that at a reburning zone
stoichiometry of 0.9, the NOX emission level drops from the baseline condition of
2-63
-------
about 400 ppm to between 125 and 150 ppm ( all values corrected to 3% Oz dry basis).
Thus, reductions of NOX on the order of 65% are indicated by these prel iminary
tests. The degree of reduction slightly exceeds the stated target of 60% NOX
reduction by GR. For comparison, the predicted reductions in NOX calculated using
EER's kinetic models are shown in Figure 8. Figure 7 clearly indicates the strong
correlation between decreases in NOX emission and lowering the reburn stoichiometric
ratio or the overall level of excess air, respectively. The results also suggest
that increasing the rate of overfire air flow tends to decrease NOX emissions. This
effect will be investigated further.
The variation of NOX emissions with reburning zone stoichiometry is shown in Figure
9 at a unit load of 69 MWe. A linear relationship is exhibited, ranging from about
400 ppm NOX at a reburning zone stoichiometric ratio of 1.20 to a range of 125-225
ppm at 0.90 in line with the NOX reduction levels indicated in Figures 7 and 8.
There is another effect worth noting. The OFA ports were added to the boiler for
gas reburning. Under baseline (non-GR) operating conditions, about 6000-8000 SCFM
cooling air passes through them to prevent thermal damage. In one test cooling air
was shut off for a few minutes and it was found that the measured NOX increased
about 9-10%. When cooling air flow was restored, the NOX level decreased to its
former value of 400 ppm.
This observation suggests that evaluation of gas reburning performance must take
into account the effect of this cooling air on baseline NOX levels (i.e.. the true
baseline may be about 10% higher than the level measured with cooling, air passing
through the OFA ports).
FUTURE PLANS
A statistically designed matrix of tests is being completed to evaluate the effects
of 02. load, flue gas reci rcul ati on. coal burner and gas injector tilts, and
stoichiometric ratio on the reburning process. This optimization of operating
conditions will be followed by a similar set of sorbent injection tests aimed at
optimizing the overall GR-SI process for the Hennepin unit.
Once optimization of conditions is achieved, a long term (12-month) test will be
conducted at Hennepin. which will evaluate the emission and thermal performances of
the GR-SI control technology, in addition to potential boiler impacts such as
slagging, fouling, and tube wastage. Other discharges will also be monitored
2-64
-------
A similar GR-SI test program will be conducted on the cyclone fired boiler at
Lakeside, where construction is in progress.
SUMMARY
A full scale Gas Reburning-Sorbent Injection NOX-S02 emission control system has
been installed on a 71 MWe(net) tangential boiler fired with 3 wt% sulfur Illinois
bituminous coal. Preliminary GR test results indicate that the predicted level of
60% reduction in NOX should be attainable. Startup and preliminary testing of the
SI component of the system will be completed in early 1991. Current economic
projections indicate that the combined technology may have broad applicability to
older, relatively small boiler units requiring emission reduction as a result of
the Clean Air Act Amendment of 1990. The projected capital cost of this type of
installation (about $90/kW for GR-SI. $30/kW for GR) is lower than that of
scrubbers, while operating costs of 6-9 mills/kWhr may be kept within reasonable
bounds for units operating at low capacity factor.
ACKNOWLEDGEMENTS
This paper is based on work funded by the U.S. Department of Energy. Pittsburgh
Energy Technology Center, through Cooperative Agreement No. DE-FC-22-87PC79796; the
Gas Research Institute through Contract No. 5087-254-1494; and the State of
Illinois. Department of Energy and Natural Resources through Coal and Energy
Development Agreement EERC-2.
REFERENCES
1. Reed, R.D., "Process for Disposal of Nitrogen Oxide." John Zink Company. U.S.
Patent 1.274,637. 1979.
2. Sternling. C.V., et al.. 14th Symposium (International) on Combustion, p. 897.
The Combustion Institute, 1973.
3. Takahashi, Y., et al., "Development of Mitsubishi MACT In-Furnace NOX Removal
Process," Paper presented at U.S.-Japan NOX Information Exchange, Tokyo,
Japan, May 25-30, 1981.
4. Ogikami, N., et al., "Multistage Combustion Method for Inhibiting Formation of
Nitrogen Oxides," U.S. Patent 4.395.223, 1983.
5. Greene, S.B., et al., "Bench-Scale Process Evaluation of Reburning and Sorbent
Injection for In-Furnace NOX/SOX Reduction." EPA-600/7-85-012, March, 1985.
6. Greene, S.B., et al., "Bench-Scale Process Evaluation of Reburning and Sorbent
Injection for In-Furnace NOX Reduction." ASME Paper No. 84-JPGC-APC-9. 1984.
2-65
-------
8.
9.
10.
11.
Seeker, W.R., et al., "Controlling Pollutant Emissions from Coal and Oil
Combustors Through the Supplemental Use of Natural Gas," Final Report, GRI
5083-251-0905. 1985.
England, G.C., et al., "Field Evaluation Humidi f i cati on for Precipitator
Performance Enhancement," presented at the 7th Symp. on the Transfer and
Utilization of Particulate Control Technology, Nashville, TN, March 22-25,
1988.
Bartok. W. and B.A. Folsom, "Control of NOX and SOz Emissions by Gas Reburning-
Sorbent Injection," American Institute of Chemical Engineering Annual
Meeting, New York, November 1987.
.
Folsom, B.A.. et al . , "Field Evaluation of Gas Reburni ng-Sorbent Injection
Technology for NOX and SOX Emission Control for Coal Fired Utility Boilers,"
Conference and Exposition, Washington, D.C., February
X
15th Energy Technology
17-19, 1988.
Bartok, W., et al . , "Gas Reburning-Sorbent Injection for Controlling SOX
NOX in Utility Boilers," Env. Progress SCI). 18. 1990.
and
12. Bartok, W., et al., "Design Modeling of a Nitrogen Oxide-Sulfur Dioxide
Emission Control Process," Toxic and Hazardous Substance Control, in press.
2-66
-------
SORBENT
(HIGH LOAD)
OVERFIRE AIR + ,
SORBENT (LOW LOAD)
GAS 20%+FGR •
COAL 80%-
COAL 80%'
SORBENT
OVERFIRE AIR
GAS20%+FGR
TANGENTIAL
CYCLONE
Figure 1. GR-SI Configurations for Two Types of Boilers
SORBENT*
EL 553' 0"
SIX 3" INJECTORS
240 FT/S
4 ON FRONT WALL
2 ON SIDE WALLS
TRANSPORT AIR IS 3% OF
TOTAL COMBUSTION AIR
REBURN GAS
EL 520' 6"
FOUR INJECTOR ASSEMBLIES
TANGENTIAL/TILTING
EACH HAS FOUR
45/s" x 1" NOZZLES
ON 11" CENTERS
NG + FGR
415 FT/S
FGR IS 3% OF TOTAL FLUE
GAS FLOW
REBURN AIR
EL 530' 9"
FOUR 15" x 30" PORTS
110 FT/S
575" F
ADJUSTABLE VANES
EXISTING
COAL
BURNERS
* LOW LOAD SI THROUGH REBURN AIR INJECTORS
Figure 2. Summary of Injector Specifications for Tangentially Fired Boiler
2-67
-------
ro
en
oo
TRUCK
UNLOADING
TRANSPORT AIR
BLOWER
ASH LINE
PH CONTROL
HENNEPIN UNIT 1 TANGENTIALLY EIRED BOILER
Figure 3. GR-SI Process Schematic
-------
BY PASS GAS
(VIA WATER SEAL
VACUUM PUMP)
GAS SAMPLE TO
CEMS
(VIA THOMAS PUMP)
A
Figure 4. EER Phase Discrimination Gas Sample Probe
From
Plant "
Sources
i i—i i
Heafed " Perma-
Enclosure Pure
Drier
INSTRUMENT AIR
Figure 5. Continuous Emission Monitoring System
2-69
-------
ro
->i
o
n
it
a
H
•o
dP
n
OB
B
O
55
500
475
450
425
400
375
350
325
300
30-34
35-39
40-44
45-49
50-54
55-59
60-64
65-69
70-75
Boiler Load, MW (Gross)
AVERAGE VALVES
LINEAR REGRESSION TREND .......... STD . DEV.
Figure 6. Baseline NOX Emissions
-------
ro
500
450
— 400
a
a
350
O 300
I
x
o
250
200
150
100
8:27
W
M
o
9:27
10:27
11:27
12:27
13:27
14:27
15:27
16:27
RS = Reburn Stoichiometry
— NOX
— 02
All flowrateg expressed in SCFM
1/10/91 8 08:30 hrs.
Figure 7. Hennepin Unit 1 Gas Reburning Test
-------
1000
200
CYCLONE
•QVERRRE AIRI
L_
TANGENTIAL
OVERFIRE AIR
0.2
0.4
0.6
0.8
1.0
RESIDENCE TIME (SECONDS)
Figure 8. Predicted NOX Control
2-72
-------
550
Boiler Load = 69 MW (Gross)
500
O
450
400
O
O
350
ro
-^
OJ
I
a.
X
o
300
250
200
150
100
0.85
0.90
0.95
O
O
1.00
1.05
1.10
1.15
1.20
1.25
1.30
Reburning Zone Stoichiometric Ratio
Figure 9. Effect of Reburning Zone Stoichiometry on NOX Emissions
-------
RETROFITTING OF THE ITALIAN ELECTRICITY BOARD'S
THERMAL POWER BOILERS
R. Tarll, A. Benantl, G. De MIchele
Ente Nazionale Energia Elettrica
Italy
A. Piantanida
F.T.C.
Italy
A. Zennaro
ANSALDO ABB
Italy
-------
ABSTRACT
ENEL is carrying out research to improve the environmental impact of thermal
power stations. Particularly, as regards NOx emissions, ENEL is about to adopt
mainly combustion modification technique and low-NOx burners and to install SCR-
type abatement systems.
The paper presents the first results of the demonstration program started in 89
and presently in progress.
1. FOREWORD
In 1990 over 877. of the overall electricity demand (235 TWh) in Italy was met by
ENEL power stations fired with fossil fuels (oil, coal and natural gas) Coal-
fired stations supplied 28,5 TWh, thus covering 12% of the demand.
To meet the requirements concerning NOx emissions, ENEL, as announced in a
previous paper /!/ intended to first attain maximum reduction through combustion
modifications on all planned and operating plants, and then add high-dust SCR
systems to plants fired with low-sulphur oil. A comprehensive demonstrative
program and a number of preliminary results were presented.
This paper illustrates the more important data and conclusions of the tests
performed so far by ENEL, jointly with the national steam-generator
manufacturers (Ansaldo and F.T.C.), to reduce nitric oxide emissions through
modification of the combustion system. It should be remembered that the boilers
being modified are mainly of two types, that is, the wall-firing type made by
Ansaldo under licence from Babcock and Wilcox, USA, and the tangential-firing
type made by F. Tosi under licence from Combustion Engineering.
Table 1 shows the configuration of the burners of the operating boilers that
will be modified. The modifications will involve an overall installed capacity
of 23,815 MW, including 29% from coal.
The units can be divided into nine different groups, depending on the combustion
system configuration (five for oil-fired units and four for coal-fired units).
In the meantime the Italian Government issued new and more restrictive emission
limits that, in the case of NOx, are 200 mg/Nm^ for new and existing power
stations with a capacity greater than 500 MWth. For the sake of clarity, the
results of the above-mentioned demonstrative program are described separately
for the two different types of boiler (wall-firing and tangential-firing)
2-77
-------
2. ACTIVITIES UNDER WAY ON WALL-FIRING BOILERS
2.1 Oil and Gas Firing
In the above mentioned paper, ENEL announced that tests were being run,
concerning the BOOS technique, on oil- and gas-firing unit; certain data were
presented for cell burners in gas firing units (ROSSANO #4) and for cell burners
in oil firing units (CASELLA #3) . A short communication was given for the tests
that ENEL was running, at that time, on SERMIDE #1 (gas firing, axial burners
unit); this test is now complete.
ANSALDO installed 6 new NOx ports on CASELLA #3 (the 6 upper burners were
eliminated).
A test is now under way on SERMIDE #2 concerning the BOOS technique on axial
burners In oil firing units.
Another test is under way in PIOMBINO //4 concerning the BOOS technique for oil
firing in coal designed units. More details about the results of these tests are
given further on.
2.1.1 Low NOx Combustion Tests with Oil Units. In April 1990, ANSALDO installed
6 new NOx ports on boiler #3 at the CASELLA power station, eliminating the 6 old
upper burners, previously used as NOx ports; after this modification the NOx
dropped from 950 mg/Nm3 of the 18 burner configuration. (02 about 0,9%, GR
regulating) to 550 mg/Nm3 with 02 1.4% and gas recirculation (GR) dampers
opened at 20%.
The new NOx ports, in comparison with the old burner air register, slightly
improved NOx reduction: but an 0.2% reduction in 02 was possible (at the same
NOx value) as compared to the 12 burner configuration.
The unit has been operating in the 12 burner mode, waterwall gas analysis showed
a reducing atmosphere; anyway, up to now, we have no evidence of corrosion on
the waterwalls. The same thing can be said for two units of the same power
station that, for many months, have been operating with the BOOS 12 burner
configuration.
During April 1989, ENEL performed a test to verify the application of the BOOS
technique to ROSSANO #4; this is an oil and gas-firing cell burner unit; the
test was performed firing oil.
NOx emissions are reduced from 775 mg/Nm3 (18 burners) to 540 mg/Nm3 (12
burners) with 02 = 1,6% and GR dampers opened 70% with CO = 84 mg/Nm3 (fig. 1,
2) The opening of the GR dampers has a smaller effect on NOx reduction as
compared to the reduction achieved on the same unit during the gas-firing test.
2-78
-------
The poor quality of the oil burnt during the test required a small increase of
02 to keep CO and particulate at acceptable values.
ENEL is now running a test on the PIOMBINO #4 oil-firing, coal-designed unit, to
verify the application of the BOOS technique on this type of plant. This unit
has 30 burners, divided into 15 cells of 2 burners each. The upper burner of
each cell is used as a NOx port, while the oil flowrate has been doubled in the
lower one; in another low NOx mode, all the cells in the upper row act as NOx
ports, while the fuel flow rate of the lower one has been increased.
Preliminary data show a NOx emission reduction of about 20% from an original
value of about 430 mg/Nm3 with 02 = 2%.
2.1.2 Low NOx Combustion Tests for Boilers Equipped with Axial Burners. Since
the end of November 1990, ENEL has been running a test on SERMIDE # 2; this unit
is an axial burner, with an oil- and gas-fir ing boiler. This is another
application of the BOOS technique (the fuel used for the test is oil) .
Preliminary data show NOx is reduced from 950 mg/Nm3 (02"!%) to about 520 mg/Nm3
with 02 1,1%. Waterwall gas analysis is being performed on this unit and
further and more complete details will be ready at the end of the test period
(March 1991).
As part of the demonstrative program for low NOx burners, ANSALDO installed a
burner named TEA (designed jointly by ENEL and ANSALDO) on the MONFALCONE unit #
4 (oil-firing with axial burners before modification). Preliminary data show a
reduction of about 40% (fig. 3). The test program has not been completed yet
and the installation of NOx ports for the application of post combustion
technique on low NOx burner combustion system is scheduled for next year.
The second part of the demonstration program involves the installation of the
Babcock and Wilcox low NOx burner, XCL type, on SERMIDE # 1; the installation
has been completed. A test phase is under way and will last at least two months.
The test program has not been completed yet and the installation of NOx ports
for the application of post combustion technique on low NOx burner combustion
system is scheduled for next year.
The second part of the demonstration program involves the installation of the
Babcock and Wilcox low NOx burner, XCL type, on SERMIDE # 1; the installation
has been completed. A test phase is under way and will last at least two months.
2.1.3 Low NOx Combustion Tests with Gas-Fired Axial Burners. The test unit used
to verify the application of the BOOS technique to gas-fired, axial burner
boilers, is SERMIDE # 3 (320 MW) .
Operation with 12 burners and addition of air through the upper burners leads to
a considerable reduction of NOx emissions as compared to the 18-burner operating
2-79
-------
mode (fig. 4). At 320 MW, with 02 = 1.07 % and GR dampers opened 65%, the NOx
emissions decreased from 685 mg/Nm3 to 170 mg/Nm3 (75% reduction), while CO was
40 mg/Nm3 Without GR (dampers closed) the NOx emissions were 300 mg/Nm3 (02
0.8%)
2.2 Low NOx Combustion Tests with Coal
During 1990 ANSALDO modified the combustion system of Unit # 4 at the VADO
LIGURE power station; this unit was originally equipped with 30 burners arranged
in 15 two-register cells. According to the technology developed by B & W,the
lower burner of each cell is still firing coal, while the other one is used to
introduce the over-fire air. The coal pipes of the lower burners are enlarged
to accomodate the increased coal flow, and the upper air registers have been
modified internally
The first test program was completed in 1990, firing American bituminous coal;
the data were compared to the data we obtained in 1988, firing the same coal.
As far as emissions are concerned, NOx at 330 MW after modification are 876
mg/Nm3 (02 4%) and carbon in flying ashes is about 8%; (5 mills in service);
with the original burners in the same operating condition, NOx emissions were
1200 mg/Nm3 and carbon in flying ashes was 6%. Operating in the same way, but
with higher 02 (" 5%), NOx can be reduced from 1440 mg/Nm3 to 970 mg/Nm3, while
carbon in flying ashes increases from 5,5 (original burner configuration) to
7,7% (new burner configuration) (see fig. 5, 6)
3. ACTIVITIES UNDER WAY ON TANGENTIAL FIRED BOILERS
For this type of boilers ENEL adopted the Combustion Engineering low NOx
combustion system; this system was tested at the FUSINA power station.
3 .1 FUSINA Project
Unit # 2 of the FUSINA power station has a 160 MW, multi-fuel tangential boiler,
usually firing coal. During 1989 the unit was modified to reduce NOx emissions;
a new combustion system /3/ was installed by F.T.C. (the Italian licensee of
COMBUSTION ENG.) During the test period (February-July 1990), low-volatile
South African and high volatile U.S. bituminous coal, oil and gas were burned.
While firing a S.A. coal (TCOA), a decrease in NOx emission from 930 mg/Nm3 to
500 mg/Nm3 was achieved (02 was about 4.1% in both cases) An increase in mill
2-80
-------
fineness (from 85% to 90% on 200 mesh) was necessary to limit the carbon loss in
flying ashes to about 7% in the low NOx configuration (fig. 6)
The NOx reduction obtained by firing an American coal (MC CALL) was 47% (from
740 mg/Nm3 to about 390 mg/Nm-') with 02 4% and unburned coal in flying ashes
was about 6% with the low NOx system (fig. 7). In both cases we found that NOx
emissions are not affected by coal fineness and that high NOx reduction can be
achieved only by a high over-fire air flow rate (~ 140 t/h).
We noted that U.S. coals produce less NOx than S.A. coals (" 200 mg/Nm3 less in
the high NOx without OFA configuration and 100 mg/Nm3 in the low NOx
high OFA configuration) Increasing the mill fineness was the only way to
reduce carbon loss in the flying ashes to acceptable values (6-8%), for all the
coals we tested (S.A. and American)
During the oil firing test, while maintaining the temperature of the convective
parts of the boiler, the appropriate value was the most important problem
(FUSINA # 2 has no GR system); so excess air had to be high in order to increase
these temperatures. NOx emissions are reduced from 500 mg/Nm3 (without the
OFA mode) to 220 mg/Nm3 (high OFA mode) ; C>2 was about 2,4% and CO was low
in both cases (~ 30 ppm)
As far as emissions in gas-firing are concerned, NOx emissions in the base
configuration (without OFA) were about 360 mg/Nm3 (with 02 1,5% and CO = 40
ppm); in the best operating low-NOx condition, NOx emissions were about 95
mg/Nm3 with 02 1,65 and CO = 60 ppm; NOx emission reduction was 74% (fig. 8)
4. REBURNING
The aim of ENEL's program is to evaluate the application of reburning technology
both on standard oil and coal units.
Three phases have been planned:
a) Bench-scale tests on a 50 kW furnace
b) Experiments on a 15 MW Combustion Engineering Boiler Simulator
c) Demonstration on the 35 MWe Santa Gilla # 2 unit.
The bench-scale experiments were concluded and new, interesting results were
obtained. The modification of Santa Gilla // 2 was completed and tests are
scheduled for next April.
The first part of the experiments on the CE simulator was completed and
concerned the application of gas reburning to an oil-designed boiler; the
results were promising (fig. 10).
2-81
-------
5. CONCLUSIONS
ENEL's efforts in the field of NOx reduction are producing their first results.
The application of the BOOS technology is giving good results in oil/gas-
designed boilers whatever burner is installed (axial or circular). In terms of
NOx reduction, the application of BOOS in the case of coal-designed boilers
firing oil and coal is less effective.
Good performances are obtained by using an oil-low-NOx burner and further
improvements are expected thanks to the installation of NOx ports.
Application of OFA on tangentially fired boilers gave a very good NOx reduction
with gas, good performances were obtained with oil and coal.
Reburn tests on a 15 MW oil-firing boiler simulator confirmed the data obtained
using a bench-scale apparatus and indicated a strong decrease of NOx production.
ENEL's demonstrative program on the application of low NOx combustion technique
is going on and will be completed in two years, at the same time, on the basis
of the results being obtained, the first applications are being made and will
involve, over the next ten years, all units of ENEL's power stations.
ACKNOWLEDGMENTS
The Authors wish to thank Dr. G. Bianchi for his contribution to the present
paper.
REFERENCES
/!/ B. Billi, E. Marches!, R. Tarli
Retrofitting of existing thermoelectric plants
GEN-UPGRADE 90 Symposium, March 1990, Washington DC, USA.
/2/ A. Benanti, G. De Michele, A. Piantanida, R. Tarli, A. Zennaro
Retrofitting of the Italian Electricity Board's Thermal Power Plant
Boilers. GEN-UPGRADE 90 Symposium, March 1990, Washington DC, USA.
/3/ Towle D.P et al.
An update on NOx Emission Control Technologies for Utility Coal, Oil and
Gas Fired Tangential Boilers. AFRC Meeting, March '91, Hartford, CT, USA.
2-82
-------
OIL FIRED BOILER
CH1VASSO Unit 6 [•]
PIACENZA Units 3,4
LA CASELLA Units 1,2,3,4
OSTIGLIA Units l.S.3,4
TURBIGO LEV. Unit 1 f«J
Unit 2
Units 3,4
SERMIDE Units 1,2,3,4
TAVAZZANO Units 5,6
nONFALCONE Units 3,4
PORTO TOLLE Units 1,2,3,4
TORREV. SUD Units 2,3,4
TORREV. NORD Units 1,2,3,4
ROSSANO Units 1,2,3,4
TERMINI I. Units 4,5
PRIOLO G. Units J.2
TOML CAPACITY OTyj
CO^L^f_IRED_ BOILEFl
LA SPEZIA Units 1,2,4
Unit 3
VADO LIGURE Units 1,2,3
Unit 1
PIOMBINO Units 1,2,3,4
FUSINA Units 3,4
BRINDISI NORD Units 1,2
Units 3,4
S.FILIPPO Unit 5
Unit 6
SULCIS Units 1,2,3 (•)
TOT^L owMcirr mw
FRONT-REAR BURNERS
TW
REGISTER
CELLS
O
33O
/ .260
640
32O
2.57O
THREE
REGISTER
CELLS
1 .260
320
/ .280
640
3.520
60O
99O
640
320
2.550
PARALLEL
FLOW
1 .280
64O
640
2.640
5.200
O
TANGENTIAL
FIRING
BURNERS
66O
1 .3SO
660
2.64O
960
640
6.880
/ .235
640
1 .875
f»3 UNITS EQUIPPED WITH CIRCULAR BURNERS ON THE
FRONT UALL (TOTAL CAPACITY (.220 MW
fob./. BURNER CONFIGURATION OF ENEL's EXISTING BOILERS (CAPACITY >200
2-83
-------
900
eoo-
700-
600-
\ 500-
Cn
e
^ 400-
300-
200-
100-
D IB BURNERS
O IS BURNERS (DAI1PERS CLOSED]
+ 12 BURNERS (DAHPERS OPENED 25X1
\
\
0
100 300 300
LOAD. (HU)
Fig.] - ROSSANO #4 - OIL FIRING
NOx C3% 021 AS A FUNCTION OF THE OPENING
OF THE DAMPERS OF THE UPPER BURNERS
900
900-
700-
| 600-
\ 500-
cn
E
^ 400-
O 300-
100-
a 18 BURNERS
+ 12 BURNERS (DMPERS OPENED 25X1
1 1 \ 1 \
!00 POO JOO
LOAD, CHU)
400
Fig.2 - ROSSANO #4 - OIL FIRING
H1NIMUH NOx [3% 0?J VALUES IN
ACCEPTABLE OPERATING CONDITIONS
2-84
-------
\
CD
1200-
1000-
600-
600-
2 400-
200-
& AXIAL BURNER
o TEA BURNER
NOx
-250
-200
-150
- 100
-50
o
e
en
e
0 0.5 1.0 1.5 2'.0
0S,
Fig. 3 - MONFALCONE POUER STATION
COHPARISON BETWEEN NOx AND CO
C3% 02J OF AXIAL AND TEA BURNER
Id BURNERS
12 BURNERS
100
150
200 280
LOAD, (HU1
320
Fig. 4 - SERtllDE #3 (320 HU) GAS FIRING
NOx (3% 021 EMISSIONS VERSUS LOAD
2-85
-------
1000
900-
800-
\
Dl
vS 700-
0 600-
2;
500-
CARBON LOSS
CO
100
•80 'j
<.
-60 "I
-20
o
^ to
. ;2 £JLU
- to
to -=c
• /O to
O CJ5
-j 2:
•6 ^ x
O -j
OQU.
-4
CO •
Fig. 5 - \/>ADO LIGURE #4 (330 MU- 5 MILLS]
NOx (3% 02; EMISSIONS VERSUS 0?
NOx PORTS OPENING=50mm COAL ASHLAND
GR=50% DAMPERS OPENING
' — ,
0
e
2:
\
O^
e
^
X.
Q
2:
/ uuu -
900-
800-
700-
600-
500-
NU X
--^
^^^ CARBON LOSS
~^^
** >^^^ ^ — — - '
•-
CO •
- too
-
-80 'S
6
2;
-60 ^
V ,
i- 40 v
O
u
-20
-
^~ 1 c ^
_ V
to
- 10 to
o
1
~s 2:
o
CD
-6 Q:
5
-4
I I I I I
240 250 260 270 280 290 300 310 320 330
LOAD, (HU)
Fig.6 - VADO LIGURE #4- LOU NOx BURNERS
NOx (3% 0?) EMISSIONS VERSUS LOAD
NOx PORTS OPENING=50mm COAL ASHLAND
GR=50% DAMPERS OPENING
2-86
-------
500
6 450
S:
\
O)
6
O 400
350
FINESS:90X ON 200 HESH
OFA i. 155 t/h
CO
16 LU
3:
CO
- 10
-8
o
OD
CC
-^
O
Op, (XJ
Fig.7 - FUSINA #2 (170 HU - COAL TCOAJ
INFLUENCE OF EXCESS AIR ON NOx (3%
AND CARBON IN FLYING ASHES-HIGH OFA
HODES-HIGH FINESS
450
S 400-
\
en
e
O 350-
300
FINESS:B7X ON 200 HESH
OFA i IdS t/h
- ie
- 16
- 12
- 10
- 8
6
*•<
LU
U.
Q
CQ
Op, CXJ
Fig.6 - FUSINA Jt2 [170 M - COAL McCALLl
INFLUENCE OF EXCESS AIR ON NOx (3% 0?J
AND CARBON IN FLYING ASHES-HIGH OFA
HODES-LOU FINESS
2-87
-------
300
200-
\
o>
e
o too
350
NO* NO OFA
NO* HIGH OFA CiHO I/hi
I \ I I I 1
0.6 I 1.2 /.4 t.6 1.8 2 2.2
Fig. 9 - FUSINA #2 - GAS FIRING
INFLUENCE OF EXCESS AIR ON NOx
Otf -HIGH AND LOU OFA MODES
60-
40-
20-
REBURNING
1.0
T
0.9 0.6
sr. f-j
0.7
Fig. JO - DEPENDENCE OF NOx REDUCTION
FROM REBURN OR MAIN BURNER
ZONE STOICHIOMETRY OBTAINED
ON CE-15MU-BSF
2-88
-------
RETROFIT EXPERIENCE USING LNCFS ON 350 MW AND 165 MW
COA1 FIRED TANGENTIAL BOILERS
T.G. Hunt and R.R. Hawley
Public Service Company of Colorado
Denver, Colorado
R.C. Booth and B.P. Breen
Energy Systems Associates
Pittsburgh, Pennsylvania
-------
Retrofit Experience Using LNCFS
on 350MW and 165MW Coal Fired Tangential Boilers
T. G. Hunt and R. R. Hawley
Public Service Company of Colorado
Denver, Colorado
R. C. Booth and B. P. Breen
Energy Systems Associates
Pittsburgh, Pennsylvania
Abstract
Public Service Company of Colorado has installed ABB Combustion
Engineering's Low NOx Concentric Firing System (LNCFS) on both 165MW
and 350MW coal fired tangential boilers. The modifications were
completed in 1990 as part of a voluntary program to reduce nitrogen
oxide (NOx) emissions. The LNCFS included new burners, control
modifications, and separated overfire air ports.
Energy System Associates (ESA) completed an extensive test program
on each unit both before and after the retrofits. The test data from
the 165MW unit has shown that NOx was reduced by 52% from 0.664 to
0.316 Ib/MMBtu at optimum full load conditions with minimal impact to
carbon monoxide or unburned carbon. Testing was completed at many
different conditions so that the LNCFS could be optimized for low NOx
operation with minimal operator supervision. Baseline NOx testing on
the 350MW unit has been completed and preliminary post-installation
testing has shown a NOx reduction of 47% from a baseline of 0.533 to
approximately 0.28 Ib/MMBtu at full load. Acceptance testing has not
been completed due to operational problems with the unit.
Introduction
Denver Colorado is a beautiful city at the base of the majestic
Rocky Mountains but as rapid growth occurred in the 70's and 80's the
city has also become known for occasional visible pollution problems.
Local politicians foresaw the importance of clean air not only to local
residents but also as a requirement to maintaining a healthy growing
economy. With cooperation and financing from Public Service Company of
2-91
-------
Colorado (PSCC) and other private and public entities, a comprehensive
study of Denver's brown cloud was accomplished in the late 1980's. This
study concluded that the major contributors to the brown cloud were
automobiles and fireplaces. Coal fired power plants were responsible
for only 1% of the direct particulate that interfered with visibility.
The study did find that secondary particulate of ammonium sulfate and
nitrates contributed up to 43% of the brown cloud, but the study could
not attribute these secondary pollutants to any source.
All PSCC's Denver metropolitan power plants were installed before
NOx regulations were implemented. In September 1988 PSCC announced that
it would take a voluntary pro-active position to this study. The
Company announced that it would retrofit major coal fired metropolitan
power plants with NOx controls to allow a minimum 20% NOx reduction by
the end of 1991 in addition to significant SO2 removal modifications.
PSCC has a mix of boiler types in the metro area including top, wall,
and tangentially fired units. The goal of this program was to retrofit
combustion modifications that would allow the highest removal that was
economically feasible. The equipment was to be installed as soon as
possible but within the existing scheduled unit outages. The first two
units to be modified were the 165MW Valmont 5 and 350MW Cherokee 4
tangentially fired units. Modifications were completed in May 1990 on
Valmont 5 and in November 1990 on Cherokee 4. The remaining wall and
one top fired unit will be modified by December of 1991.
Original Investigation
Public Service Company of Colorado organized in the late 1980's
a three step program to determine the best method for obtaining NOx
reductions. The first step was a complete NOx assessment of all major
metropolitan units to determine current emissions and secondarily to
find operational means to reduce NOx emissions. The second step was to
perform an in-depth analysis of the data, investigate the cost and
availability of NOx control modifications, and finally to recommend NOx
control measures for the metropolitan coal fired units. The final step
was implementation of the NOx control plan through installation of the
recommended modifications.
PSCC personnel completed a comprehensive study of all the units
to find the most economical method to implement NOx reductions. All
known options were considered for the tangential units including
operational modifications, overfire air, Low NOx Concentric Fire System
(LNCFS), Pollution Minimum (PM) system, gas co-firing, selective
catalytic reduction (SCR), and selective non-catalytic reduction
(SNCR). The original NOx assessment testing found that operational
modifications could be effective but NOx reductions were minimal at
high loads and were dependent upon close operator attention. It was
determined that operational modification would not meet PSCC's
requirements. As combustion modifications would be required before
2-92
-------
strongly considering SCR or SNCR and neither technology has been proven
on large US coal fired boilers, these technologies were not seriously
considered.
The effect of each applicable method for NOx reduction was
compared and a cost per ton of NOx removed was calculated. As PSCC was
not striving to meet any specific regulatory requirements, the analysis
was used to select the technology that would provide the highest level
of economical NOx reduction. LNCFS met PSCC's requirments for Cherokee
4 and Valmont 5 and was recommended for installation
Before proceeding with the recommended modifications, Energy
System Associates (ESA) reviewed the NOx reduction study and concurred
with the recommendation.
Low NOx Concentric Firing System Description
ABB Combustion Engineering (ABB-CE) developed the Low NOx
Concentric Firing System (LNCFS) in the early 1980's to increase NOx
removal to higher levels than achievable with overfire air alone. The
system is composed of three main features:
1. Separated Overfire Air
2. Offset Concentric Air Nozzle Tips
3. New Coal Nozzle Tips
The separated overfire air allows diversion of up to 30% of the
combustion air above the main burner area. This allows combustion to
occur at lower stoichiometric ratios in the main burner area and thus
reduces both the thermal and fuel NOx.
The auxiliary air nozzles used as part of LNCFS are modified to
offset a portion of the secondary air approximately 22 degrees from the
furnace diagonal. This accomplishes two functions. The first is by
directing a portion of the secondary air away from the main flame,
excess air during the first stages of combustion is lower and thus NOx
generation is lower. The second is that the offset auxiliary air
blankets the walls with a high O2 stream and thus can lessen the
affects of substoichiometric combustion on tube corrosion. The velocity
of air across the tube wall also reduces wall slagging.
The coal nozzle tips are modified to bring the flame front closer
to the nozzle. Some NOx is formed in a standard burner as the coal is
injected into the furnace before combustion is initiated. The coal
devolitizes in this hot high O2 zone and NOx is formed. By initiating
combustion sooner, less oxygen is available to combine with the
volatile nitrogen.
2-93
-------
Unit Description
Valmont 5 and Cherokee 4 are tangentially-fired boilers installed
in 1964 and 1968 respectively. Low sulfur western bituminous coal is
normally fired in both units but any combination of natural gas or coal
may be fired. Valmont 5 uses a Bailey pneumatic control system and has
manual control of the secondary air dampers. Manual loading stations
to operate the overfire air dampers, overfire air tilt, and concentric
fire air were added. A new Distributed Control System is planned in
1991 and automated controls will be added. Cherokee 4 uses a Bailey 721
electronic analog control system and has automatic control of the
secondary air dampers. A Westinghouse WDPF system was installed
recently for data acquisition. The new controls required to control all
dampers and tilts were added to the WPDF on Cherokee as an additional
drop on the system. The table below lists major features of the units.
Electrical Generation
Steam Flow
Steam Pressure
Superheat /Reheat
Valmont 5
165MW
1,230,000 Ib/hr
1800 psig
1005°F/1005°F
Cherokee 4
350MW
2,587,000 Ib/hr
2400 psig
1005°F/1005°F
Combustion Engineering Services, Inc submitted a proposal for the
LNCFS for both units in September 1989 and was authorized to begin
design in November 1989. The Valmont proposal included replacement of
several sections of tube panels in an area above the burners due to
excessive tube leaks caused by hydrogen embrittlement. The LNCFS was
installed at Valmont during a planned six week outage and was placed
in-service in May 1990. The work was accomplished using double shifts
due to the short schedule. The approximate installed cost of the
Valmont system including all PSCC overheads was 2.5 million or $15/KW.
The LNCFS was installed at Cherokee during a planned ten week outage
and was placed in-service in November 1990. One shift per day was used
at Cherokee due to the extended schedule. The approximate installed
cost of the Cherokee system including all PSCC overheads was 4.0
million or $11.5/KW. In addition to the LNCFS retrofit, the economizer
was replaced by another supplier on the Cherokee unit.
Figures 1 and 2 compare the windbox arrangement of the Valmont and
Cherokee units before and after the LNCFS modifications were completed.
The major modification in the windbox arrangement, other than the
addition of separated overfire air, is that the original single
auxiliary air and gas fuel compartments were split into three separate
compartments to allow for two concentric fire air nozzles in the new
2-94
-------
ORIC
I
n
C3
cr
a.
m
•d
EL
a
[E1
EEE
VALMONX #5
3 1 HAL LNCFS
TOP AUXILIARY AIR
COAL
COAL,
COAL
2 GAS •* AUXILIARY AIR
COAL
LOWER AUXILIARY AIR
m
III!!
TUTU
1
^ILJJ
-j— i
ii
rffff
ffl
TffT
ffl
1 1 .
m
m
H
OV^RKIRED AIR
TOP AUXILIARY AIR
COAL
CF AIR
CF AIR
COAL
CF AIR
CF AIR
COAL
CK AIR
2 GAS + AUXILIARY AIR
CF AIR
COAL
LOWER AUXILIARY AIR
DRI
L~~l
1 — I
"dJ-"
-JT1
nzzr
1
CHEROKEE #-4
SINAI, LNCFS
TO P AUXIL IARY AI R
COAL
COAL
A QAS - AUXILIARY AIR
COAL
COAL
4 GAS -i- AUXILIARY AIR
COAL
WT
im\
TTTTTI
Jltm
n
2
-LLLL
frff
nn.
HE
ffi
ffff
rm
LiiJ
TOP AUXILIARY AIR
COAL
CF AIR
CF AIR
COAL
CF AIR
3 OAS + AUXILIARY ATR
COAL
CF AIR
CF- AIR
COAL
CF AIR
3 GAS ^ A1JX1 LIAKY Al R
CF- ATR
COAL
Figure 1
Figure 2
installation. This limited the space available for the gas spuds on the
Cherokee unit so the original four gas spuds were reduced in number to
three per gas compartment. A new ignitor system was also purchased for
the Cherokee 4 unit as the original igniters operations had not been
meeting expectations.
Guarantees
As part of the contract for the design and installation of the
LNCFS, substantial performance guarantees were implemented. The
guarantee for NOx removal was based on a sliding scale of percent NOx
removal dependent upon baseline values that were to be obtained before
the shutdown. In addition to NOx removal, boiler efficiency and
unburned carbon levels were guaranteed. Small allowances for decreased
boiler efficiency and increased unburned carbon levels were allowed for
variances in the testing accuracy. All guarantees were applicable only
at the full load conditions and were based on a series of tests
completed shortly before and after the modifications.
Testing
Energy Systems Associates (ESA) of Pittsburgh, Pennsylvania was
selected to perform emission testing as they had performed other NOx
testing for PSCC and demonstrated a thorough knowledge of NOx formation
and NOx reduction methods. Although both PSCC and ABB Combustion
2-95
-------
Engineering Services have very capable emission testing groups
qualified for this type of work, an independent contractor was required
to ensure impartiality. In addition to conducting the acceptance
testing at full load, ESA performed sufficient testing to define an
operating procedure across the load range that would minimize NOx
emissions. ESA provided all equipment required for the measurements of
nitrogen oxides, oxygen, carbon monoxide, and carbon dioxide. They also
provided the necessary equipment to collect EPA method 17 particulate
samples from the outlet duct. These samples were used to determine
unburned carbon loss. Plant personnel conducted boiler efficiency
testing by the standard short form ASME method.
Valmont 5 Results
In general the design, installation, and testing on Valmont 5 was
completed on schedule and without significant problems. During the
installation of the system it was discovered that four of the existing
coal nozzles were damaged beyond repair. The delivery of new nozzles
was expedited and were installed as part of the outage. Soon after
startup it was discovered that the new coal nozzle tips were binding
in one corner of the boiler. The unit was brought off-line and a
portion of the nozzle tip side material was removed to eliminate the
binding. Increased slagging occasionally occurred during some testing
but the slagging was usually associated with "unusual" damper positions
or tilts. After the correct operating procedures were determined no
further slagging problems have developed. Heat transfer in the boiler
appeared to be unaffected by the modification and there was no
significant change in economizer exit gas temperatures.
Sampling Locations
Two different sampling locations were used for the emissions
testing on Valmont. Baseline and guarantee testing were performed after
the air heater using a fourteen sample point matrix. It was later
determined that testing before the air heater would be more
advantageous as the data can be directly related the combustion
process. A nine point matrix was established at the economizer outlet.
Baseline Testing
The original NOx baseline testing was conducted over a period of
two weeks immediately before the outage. Waiting until the final weeks
to perform the testing was done to ensure the data would be as
comparable as possible to post-installation values. The lower coal mill
was taken off-line for major repairs at the outset of the testing.
Using the three available mills, testing was completed at 80, 120, and
150MW. When operating with three mills the lower auxiliary air and fuel
dampers were approximately 25% open and the remaining fuel/air dampers
were equal at 40 to 60% open. Previous testing has shown that a lower
2-96
-------
baseline could have been achieved with the top mill out of service. The
coal mill repairs were rushed by working multiple shifts and the mill
was placed in service two days before the outage began. This short
period allowed baseline testing at full load; however, there was
insufficient time for four mill testing at the other loads. This proved
very important as the normal operation of the plant is four mills at
loads above 120MW and some very important baseline data was not
obtained.
A series of ten tests were completed over a two week period to
define the NOx emissions across the load range. Three tests were
conducted at reduced oxygen concentrations but the testing did not show
a strong O2 correlation. The baseline data will be further discussed
in comparison to the LNCFS data presented below.
LNCFS Testing
ESA conducted a series of 90 tests after the installation of the
LNCFS in order to document fully the changes in boiler operations.
ABB-CE testing personnel organized and supervised the original
optimization testing and the guarantee performance testing while ESA
collected and organized data. After the guarantees were met, ESA
conducted all testing although ABB-CE advised and assisted throughout
the test program.
Overfire Air
The use of separated
overfire air as a part of
the LNCFS can provide
substantial NOx reduction.
Figure 3 documents the full
load testing. The amount of
overfire air is presented as
a damper position value and
not as an absolute air flow
value. The unit lacks flow
measurement devices to
measure actual air flow. All
concentric fire dampers were
closed and the boiler was
operated with the auxiliary
air dampers at approximately
60% open and normal O2 of Figure 3
3.1%. Note that with all
overfire air dampers closed the NOx emissions were reduced by 16% from
the baseline. This reduction is due to air leakage from the overfire
air ports and the new flame holding burners. NOx emissions were
gradually reduced as the dampers were opened until at full opening, NOx
was reduced by 36% from the original baseline.
Volmont 5 Overfire Air (§> Full Load
Aux 60%;CF 0%;02 3.1 %
1
CD 0-5
S
2
o °-4
z
"\-\.
"^^•^^i
\ ~ ~~i
^\.^J
i
I
0 10 20 30 40 50 60 70 80 90 100
Overfire Air Damper Position
I • Fuel 60% A Fuel 30%
2-97
-------
Overfire air's effectiveness was substantially increased by
closing the fuel air dampers to 30% at overfire air damper positions
greater than 70%. Closing the fuel air dampers increase the windbox
pressure and thus increase the air flow through the overfire air ports.
This technique increased the
the original baseline.
At lower load the
overfire air is generally
less effective as the
windbox pressure reduction
decreases the amount of
overfire air. This can be
compensated by closing both
the auxiliary air and fuel
air dampers as load is
decreased. Figure 4 shows
the NOx reduction at a 150MW
load. A NOx reduction from
baseline of 38% was obtained
by opening the overfire air
dampers to 70%. As the
dampers continue to open
only a slight reduction is
achieved.
NOx reduction of overfire air to 47% from
Valmont 5 Overfire Air @ Medium Load
0.6 >
i
0.55-
? 0.5-
5
2
\0.45-
° 0.4-
0.35-
0.3 H
C
Aux 30%; Fuel 10%; CF 0%; 02 3.4%
\
X^
^
\
\^_
™
i
10 20 30 40 50 60 70 80 90 100
Overlire Air Damper Posilion
Figure 4
Overfire Air Tilt
Overfire air tilt was
originally held at positive
tilts. Testing personnel
suspected that keeping the
tilts positive would allow
for increased time for
combustion at lower
stoichiometric ratios thus
providing for lower NOx
emissions. Testing was
completed at both 100% and
66% overfire air damper
positions over a tilt range
of -16 to 14 to determine
the affect tilt had on NOx
emissions. Figure 5 shows
that there is minimal NOx Figure 5
effect for various tilts
although it does show that minor reductions occurred in -5 to -10
range. The outlet sample matrix showed that neutral OFA tilts increased
NOx emission uniformity. This could explain the minor NOx reductions.
Valmont 5 OFA Tilt @ Full Load
Fue
5
.D
0 0.4-
, Aux 60%, CF 0%, 02 3%
^-~^^"'~
-20 -15
-10-5 0 5
Overfire Air Tilt
• 100% OFA + 66% OFA
10 15
2-98
-------
Overfire air tilt also affected superheat steam attemperation. The
amount of attemperation decreased at positive tilts. This is likely due
to the decreased mixing of the furnace gas that created isolated
streams of cooler gas. The cooler gas streams would decrease superheat
heat transfer and thus lower required attemperation. During the more
positive tilt testing, one or two of the nine sample probes would
experience significant carbon monoxide excursions though average CO was
not significantly increased. This again verifies less mixing of the
flue gas.
Oxygen Concentration
Figure 6 shows a series
of tests that indicate the
variance of NOx emissions as
a function of boiler oxygen
concentration. Sufficient
data for accurate comparison
was only available for two
conditions in which all
overfire air dampers were
fully open. In one case
there is a good correlation
with oxygen of approximately
78 ppm NOx per percent
oxygen change. However, in
the second test with the
fuel air dampers 30% open,
there is no correlation with
oxygen .
D
2
5
_D
o035
2
-•- Fuel
Valmont 5 Oxygen @ Full Load
CF 0%, Aux 60%
,
*-" '"^^ ^—
^~r-^^
^^__^— + +
>-- •
6 2.8 3 32 3.4 3.6 3 S i
Percent Oxygen
307., OFA 67% •*• Fuel 30%, OFA 1007. * Fuel 0%. OFA 1007
60%, OFA 33% -A- Fuel 60%, OFA 83% !
i
Figure 6
Concentric Fire Air
In much of the original
optimization testing for
overfire air, the concentric
fire (CF) dampers remained
closed. After a better
understanding of the correct
procedures for operating the
overfire air were obtained,
testing began at different
levels of concentric fire
air. Figure 7 shows the
affect on NOx emissions for
different levels of
concentric fire air when
operating at full load and
100% overfire air. The top
0
c
Valmont 5 Concentric Fire © Full Load
OFA 1 00%, Aux 60%
^^
• ~t— '^
^m ^^n^^^- •
10 20 30 40 50 60 70
Percent Conccnlric Fire Air
• 02 3%, Fuel 0% + 02 3.6%, Fuel 30%
Figure 7
2-99
-------
curve is at 3.6% oxygen with the fuel air dampers open 30% while the
lower curve is at slightly reduced oxygen with less fuel air. Opening
the concentric fire dampers slightly reduced NOx emissions in both
cases. However, NOx increased as the dampers are opened more than 20%.
The increase in NOx at high concentric fire damper opening is
likely due to two reasons. The first is that as more air is added to
the main combustion zone the amount of overfire air is decreased. This
testing shows that "vertical" overfire air above the combustion zone
is more effective than the "horizontal" overfire air closer to the
combustion zone. The second reason is that furnace mixing was reduced
by the use of concentric fire dampers. Figure 8 shows the uneven NOx
distribution at the boiler outlet while using 66% concentric fire air.
Conversely, Figure 9 shows the distribution while using 22% concentric
fire air. In this case the NOx is more evenly distributed across the
economizer outlet.
Valmont 5 NOx Distribution
Srtcrt [HE Modimujn BID L
Figure 8
Valmont 5 NOx Distribution
Cone
Figure 9
The use of concentric fire air with a high yaw angle does provide
two advantages. The concentric fire air provides a stream of high O2
gas next to the boiler wall tubes. Substoichiometric combustion of a
high sulfur coal can cause significant tube corrosion due to the
formation of hydrogen sulfide gas. A second advantage of concentric
fire air is the use of the high velocity air to reduce slagging of the
wall tubes. During one test at the Valmont site, significant wall
slagging occurred due to operation at substoichiometric conditions. The
slagging was successfully removed by closing the overfire air ports,
directing air to the concentric fire air ports.
Carbon Carryover and Carbon Monoxide
Many methods can be used to modify combustion to minimize NOx but
a penalty of increased carbon carryover and carbon monoxide emissions
often exists. PSCC was very concerned about increased carbon monoxide
and fly ash carbon carryover. Guarantees were obtained to ensure that
the NOx reduction would be obtained at minimum operation penalty
possible.
2-100
-------
Valmont 5 Carbon Carryover
£
o
_Q
5 1 5-
T>
E 1 •
3 '
JD
c
D
.^^ •--.
--"^ Xj^
^^
80 90 100
110 120 130 HO 150 160 170 ISO
Nel Load (MW)
• LNCF •*• Baseline
Fly ash is sampled at
the FFDC hoppers to perform
weekly boiler efficiency
testing and the Valmont unit
has a history of carbon
content below 2%. To
increase confidence in the
carbon carryover values, it
was decided that an
isokinetic sample would be
obtained from several points
in the duct to obtain a
representative sample for
this testing. Figure 10
shows the carbon carryover
at various loads. In all but
the minimum load testing,
carbon carryover is the same or lower after the LNCFS modification.
Similar positive results occurred with carbon monoxide emissions.
Throughout the testing CO emissions were below 30 ppm and showed no
increase over pre-retrofit values. At conditions of high overfire air
tilt or a high concentric fire air damper openings, CO excursions in
a single sample point up to 1000 ppm did occur.
Baseline' Comparison
The guarantee test was completed early in the test schedule before
significant optimization testing had occurred. A summary of the test
results and conditions are shown in the table below. Also shown is an
optimized test that provided significant NOx reduction at better
operating conditions.
Figure 10
NOx (Ib/MMBtu)
NOx Reduction
Boiler Efficiency
Unburned Carbon
Carbon Monoxide
Oxygen Concentration
OFA #3 Damper
OFA #2 Damper
OFA #1 Damper
OFA Tilt
Top Auxiliary Air
Fuel Air
Auxiliary Air
Concentric Fire Air
Lower Auxiliary Air
Baseline
0.664
86. 63
1. 6
<30
3.6%
NA
NA
NA
NA
50%
50%
50%
NA
50%
Guarantee
LNCFS
0.294
55.7%
86. 35
1.6
<30
3 . 6%
100%
100%
100%
+ 15°
100%
0%
50%
30%
100%
Optimized
LNCFS
0. 31
52.0%
NA
NA
< 0
3.6%
100%
100%
100%
-8°
50%
30%
50%
18%
0%
2-101
-------
1
c
Valmont 5 Baseline LNCFS Comparison
3
E
]
D
£
^\
^\
"^\ "\J-__ _^A
~-^g^ B^^^--— *
"^a ^^^-^v
80 90 100 110 120 130 140 150 160 170 180
Nel Load (MVV)
• Orig 3 Mills •*• Orig 4 Mills a LNCF 3 Mills B LNCF 4 Mills
Figure 11
A comparison of
baseline and optimized LNCFS
NOx emissions across the
normal load range is shown
in Figure 11. Data is shown
for both three and four mill
operation. The post retrofit
values show that a
significant NOx reduction
was obtained at the 120MW
load by removing one mill
from service. This is due to
the increased windbox
pressure and associated
increase in overfire air
flow that occurs by removing
a mill from service and
closing the associated air register. Normal operating procedures at
Valmont are to remove one mill from service between 120 and 130MW. Due
to the previously discussed problems with the lower coal mill, baseline
data was only obtained with four mill operation at full load. It is
believed that the four mill NOx baseline at the 120 and 150MW loads
would be higher than the three mill operation shown. Using the data
presented and the operating history of the unit, it is projected that
NOx emissions were reduced by the installations of the LNCFS by 43%
across the load range.
Cherokee 4 Results
The design and installation of the Cherokee 4 LNCFS conversion was
completed on schedule and without major incident. Due to the knowledge
gained from the Valmont installation, it was decided to replace all
coal nozzles. An outside engineering firm was also retained to redesign
some coal piping hangers to lessen pre-loadings on the coal nozzles.
During initial operation several tilt shear pins were broken. The pins
likely broke due to either mechanical interferences with grating or due
to a possible slag buildup around the nozzles. Maintenance personnel
removed the interferences and ABB Combustion Engineering Services, Inc
modified the external drive arms to reduce torque on the shear pins.
The modifications appear to have corrected the problem.
Unfortunately, startup and testing of the unit did not occur as
planned. Several startup problems not relating to the burners limited
generation and operation of the unit while firing coal. Three tube
leaks in a short period resulted in unit outages to repair. Due to
generation requirements the unit could not be brought down immediately
for repair and was operated on gas.
When the unit was operated on coal, a significant slag build up
occurred in the reheat section of the boiler within a few days. It was
2-102
-------
discovered that economizer exit temperatures had increased by
approximately 100°F from the pre-installation values. A new economizer
was installed by a supplier other than ABB-CE during the outage. Coal
sampling revealed that the ash fusion temperature of the coal had been
reduced by approximately 100°F from the pre-installation testing.
During the period of slag buildup the unit was operated at full load
for long periods to accomplish emissions testing. It was also
discovered that a third of the wall soot blowers were not operating.
Most blowers had been out of service for some time as they were not
required to control slagging before the LNCFS was installed.
Significant wall slagging was not occurring but it is possible that
slag characteristics had changed enough to affect heat transfer to the
waterwalls. The unit was taken off-line and the slag was removed by
manual means. Maintenance efforts were also completed to get all the
wall blowers operational.
The slag buildup continued to occur after startup and the unit was
operated on gas until it could be brought down for repairs. A dynamite
crew removed the slag. During this outage ABB-CE personnel installed
several thermocouples throughout the convection section of the boiler
to define the reasons for temperature increases. It was decided to
limit unit generation to 90% and increase the oxygen to approximately
4.5% to minimize flue gas temperatures in the reheat section. This
appears to have temporarily solved the slag buildup problem. The unit
is currently operating without restriction or significant slagging;
however, the unit is on load regulation and is not operated at full
load for long periods.
It is currently unknown if the increased economizer exit
temperatures and the slagging problem are related to the burner
modification, the new economizer, the change in ash fusion
temperatures, or some operating condition. Testing will continue until
this problem is resolved.
Sampling Locations
Sample matrix grids were installed at the economizer and air
heater outlet. Eight sample probes were installed at the outlet of the
air heater and twenty sample probes were installed at the economizer
exit. The baseline testing showed minimal differences in emission
values between the two locations. It was decided to use the economizer
sample location for all testing.
Baseline Testing
ESA conducted the original NOx baseline testing over a ten day
period three weeks before the scheduled outage. Testing was completed
to determine the effect of reductions in oxygen concentration and
removing a mill from service. The average NOx reduction from a 1%
decrease in O2 was 56 ppm (corrected to 3% O2). The removal of an in-
service mill had a greater effect as shown in the table below. Mills
2-103
-------
are identified by the letters A through E with mill A being routed to
the lowest burner elevation. The mill(s) removed from service is
indicated in parenthesis.
Load
350
250
157
Mill Reduction
5->4 (C)
5->4 (A)
4(E)->3 (E,A)
NOx Reduction
15%
0%
33%
A reasonable NOx reduction is achieved by removing a mill from service
in all but the midload test. Testing at Valmont and previous testing
on the Cherokee unit have shown significant reductions in NOx at
midload by removing the top mill (E) verses the lower mill (A).
LNCFS Testing
Emission testing was not a high priority after startup due to the
mentioned slagging problem. ESA was on site for approximately two weeks
and did collect data but the guarantee performance test was not
completed. Due to the higher economizer exit temperature, the boiler
efficiency of the unit has been notably decreased. The slagging caused
unusual gas flow and carbon monoxide emissions were higher than pre-
installation values with significant excursions. ESA is currently
scheduled to begin testing in February and will perform optimization
testing at lower loads. The guarantee performance testing and full load
testing will be postponed until the slagging and temperature problems
are better understood.
Over/ire Air
The use of separated
overfire air has also proved
very effective in combating
NOx on the Cherokee unit.
Figure 12 presents data from
testing at 350MW with the
auxiliary dampers at 60% and
the fuel dampers at 80%. On
the Cherokee unit the
concentric fire air dampers
are automatically controlled
to the same opening as the
other auxiliary air dampers.
With all overfire air
dampers closed, minimal
reduction from the original
baseline occurred. A fairly Figure 12
steep drop in NOx occurred
Cherokee 4 Overfire Air <5> Full Load
0.55-
0 Si
?CU5-
m
\ 0 4 •
_a
| 0.35-
0.3-
0 25-
C
Fuel 80%
N*
\
X^
10 20 30 40 50 60 70 SO 90 100
Overfire Air Damper Position
2-104
-------
until the overfire air dampers were opened 50%. With all overfire air
dampers open, a 47% reduction from the original baseline was obtained.
Oxygen Concentration
Figure 13 shows an
approximate 38 ppm reduction
in NOx for a 1% reduction in
02. This testing was
completed with overfire air
dampers fully open and at
350MW. This data compares
favorable with the baseline
testing that showed a
similar correlation with
oxygen. While it is
important to maintain low
excess oxygen, small
variances do not greatly
affect NOx emissions.
This data also shows
the effect of closing the fuel air dampers on NOx emissions. In nearly
every case closing the fuel air dampers increases the NOx reduction.
This is likely due to an increase furnace to windbox pressure that
increases the overfire air flow.
Baseline Comparison
The guarantee test has yet to be completed on Cherokee 4 due to
the slagging and economizer exit temperature problems. All current
indications show that the LNCFS can meet all guarantees other than
boiler efficiency. The baseline values are compared below to a
preliminary test of the LNCFS system below.
m
2
2
> 0.275'
~Z-
Cherokee 4 Oxygen @ Full Load
OFA 100%; Aux & CF 60%
•tt ^
*___4— — -— * """"" __^
A.
2.8 2.
9 3 3 1 3.2 3.3 3./I
Oxygen Concentration (%)
A Fuel 40% • fuel 60% ' Fuel 80%
3.5 3.6
Figure 13
Preliminary
NOx (Ib/MMBtu)
NOx Reduction
Boiler Efficiency
Unburned Carbon
Carbon Monoxide
Oxygen Concentration
OFA #3 Damper
OFA #2 Damper
OFA #1 Damper
OFA Tilt
Top Auxiliary Air
Fuel Air
Auxiliary Air
Concentric Fire Air
Lower Auxiliary Air
Baseline
0.533
88.87
2.2
<30
3.6%
NA
NA
NA
NA
78%
75%
75%
NA
100%
LNCFS
0.275
48.4%
NA
NA
<30
3.3%
100%
100%
100%
-10°
50%
80%
50%
50%
100%
2-105
-------
3
CO
_D
0
1.
D
Cherokee 4- Baseline LNCFS Comparison
i
j
""\___ _^^^
*
i
\
i
c
0 200 250 300 !>-
Load (NMW)
Orig 3 Mills •* Orig 4 Mills • Orig 5 Mills s |_fCF 5 Mills
i
[
^
0
Figure 14
Figure 14 presents a
comparison of the original
baseline NOx emissions by
load compared to the data
that is available for the
LNCFS modification. Data
obtained with one mill
removed from services is
also shown for the baseline
condition. As all LNCFS
testing to date has occurred
at full load, no LNCFS data
is available for comparison
at the lower loads. The
approximate reduction from
the original baseline was
48%. Further testing is
planned in February at lower loads and with various overfire air damper
openings.
Summary
Public Service Company of Colorado installed ABB Combustion
Engineering System's Low NOx Concentric Firing System to a 165 and a
350MW unit located in the Denver metropolitan area. The retrofits were
accomplished as part of a voluntary program to reduce the NOx emissions
of major metropolitan area coal fired boilers by a minimum of 20%.
The installation and testing of LNCFS was completed on schedule
and without major difficulty on Valmont 5, the 165MW unit. NOx
reductions are greatest at full load when the separated overfire air
ports are most effective. As load is decreased, the overfire becomes
less effective until a mill is removed from service. The increase in
windbox pressure then restores effectiveness of the overfire air ports.
Additional NOx reductions also can be obtained by partially closing the
fuel air dampers that decrease the stoichiometric ratio of combustion
and thus reduce NOx. Overfire air tilt did not greatly affect NOx
emissions but did affect furnace mixing. The use of concentric fire air
did not significantly influence NOx emissions but did provide some help
in reducing wall slagging. NOx reductions of over 50% are possible at
full load and an annual NOx reduction of over 40% is expected due to
the LNCFS modification. No major changes in boiler operation, unburned
carbon, carbon monoxide, or boiler slagging have occurred.
The installation of LNCFS on Cherokee 4, the 350MW unit, was
completed without major difficulty but problems with slagging and high
economizer exit temperatures have limited testing. It is currently
unknown what has caused the increase in slagging and the higher boiler
exit temperature. Although the coal source for this unit has not
2-106
-------
changed, a decrease in the ash fusion temperature of 150°F and an
increase in the ash content has occurred over the last few months.
Economizer outlet temperature comparisons are also more difficult as
the economizer was replaced in the same outage as the LNCFS. It is also
possible that the wall slagging pattern has changed enough that
currently operating soot blowers are not performing effectively.
Although testing has been limited, NOx reductions at full load are
about 48%. Additional testing is planned on Cherokee 4 to solve the
slagging problems and gather more emission data.
Acknowledgements
The authors would like to thank Mr. Oliver Kruse, Valmont Station
Manager, and Mr. Jim Stevens, Cherokee Station Manager, and their
operating and engineering staff for the assistance and patience
exhibited during the installation and testing of these modifications.
Their assistance and flexibility in difficult situations were very much
appreciated.
We would also like to thank the personnel from ABB-CE who have
reviewed this paper and contributed to its content. The testing
personnel who spent long hours collecting and summarizing the data
presented, often at very inconvenient times, are also gratefully
acknowledged.
References
Hawley R.R., Collette R. J. and Grusha J. Public Service Co. of
Colorado's NOx Reduction Program for Pulverized Coal Tangentially Fired
165 and 370MW Utility Boilers. Presented to Power-Gen 1990, Orlando,
Florida
2-107
-------
UPDATE 91 ON DESIGN AND APPLICATION OF LOW NOX COMBUSTION
TECHNOLOGIES FOR COAL FIRED UTILITY BOILERS
T. Uemura
S. Morita
T. Jimbo
K. Hodozuka
H. Kuroda
Kure Works of Babcock-Hltachi K.K.
Kure, Hiroshima, 737, Japan
-------
UPDATE 91 ON DESIGN AND APPLICATION OF
LOW NOx COMBUSTION TECHNOLOGIES FOR COAL FIRED UTILITY BOILERS
T. Uemura
S. Morita
T. Jimbo
K. Hodozuka
H. Kuroda
Kure Works of Babcock-Hitachi K.K.
Kure, Hiroshima, 737, Japan
ABSTRACT
Babcock-Hitachi K.K. (BHK) has been using the Hitachi-NR burner (HT-NR), which was
honored by the Japan Mechanical Engineering Society Award in 1986, to solve prob-
lems of low-NOx emissions in coal fired boilers.
The results in Japan have been favorable. Moreover, BHK has contributed to
European projects which modified existing coal fired boilers to overcome future
stringent regulations by granting licenses to European boiler manufacturers. These
results were also successful.
Furthermore, RHK plans to convert the HT-NR into it's second generation type (HT-NR2)
as an extremely low-NOx boiler for the future.
In this paper the following topics will be introduced.
1) HT-NR for the newest 1000 MUe boiler
-- Hatsuura power station unit-1 for the Electric Power Development
Co., Ltd. (Japan)
2) HT-NR for the retrofits of existing boilers
-- Plem Buggenum Maascentrale power station unit-5 for EPZ (The
Netherlands)
-- PGEM Njimegen power station unit-13 for EPON (The Netherlands)
-- Inkoo power station unit-4 for Imatran Voima Oy (Finland)
3) Development test results of the HT-NR2 using a BHK 90 - 100 million
Btu single burner testing furnace.
2-111
-------
INTRODUCTION
Recently, Japan's low-NOx combustion technologies have achieved remarkable progress
in the field of utility boilers based on stringent environmental protection regula-
tions made by the government.
The main counter-measures are the combination of the low-NOx burners and Two Stage
Combustion (TSC) as shown in Figure 1. In the case of most conventional low-NOx
burners which simply lengthen the flame by means of delayed combustion, however,
the combustion efficiency slows down and it becomes extremely difficult to recover
the "trade-off" defect between NOx reduction and increasing unburned carbon in ash
(UBC).
Two Stage Combustion (TSC), increasing the residence time of combustion gas between
the sub-stoichiometric burner zone and After-Air injection point, can accelerate
the post flame NOx decay and consequently augment NOx reduction. In general,
however, UBC tends to increase and/or scatter, if the residence time of the combus-
tion gas between After-Air injection point and furnace exit is too short. In other
words, if TSC is applied to an existing boiler and UBC is required to be kept as it
is, reliable NOx control cannot be obtained as shown in Figure ?..
Therefore, the above techniques may be useful only for newly designed boilers with
larger furnace volumes and with high capacities (good pulverizing fineness) in the
coal mills.
flethodol ogy
In early 1981 Babcock-Hitachi K.K. (BHK) started further development work on NOx
reduction burners to minimize the risks of NOx-UBC "trade-off" caused by the con-
ventional technologies, mainly focusing on the In-Flame NOx Reduction based on the
principle of High Temperature NOx Reduction, HT-NR.
Figure 3 shows the flame structure of the new low-NOx pulverized coal burner, the
HT-NR burner, based on this concept.
The volatile NOx, which is produced via volatile-N, has extremely large chemical
reaction rates on the flame front. However, under fuel rich conditions, in line
with the rapid progress of 02 consumption, excessive (overshooted) hydrocarbon
intermediates (hydrocarbon radicals, etc.) come into play and contribute to the
decomposition of ingredients. It has been confirmed, during the development work,
that a rapid ignition and higher temperature reducing flame can accelerate the
reactions of the NOx decomposition. The HT-NR Burner has the following features
which can achieve such conditions.
• Rapid ignition by the flame stabilizing ring with ceramic parts
• Separation of external air by the guide sleeve
• Promotion of the air-chars mixing in the post flame zone due to
higher swirling of external air
APPLICATION
The low NOx combustion technology of HT-NR burner is now widely employed to only in
Japan but also in Europe and other nations.
New Boiler Unit with HT-NR Burners
flatuura P.S. lu 1000 Mile for Electric Power Development Co., Ltd. the newest and
largest capacity unit in Japan, started its' commercial operation in June of 1990.
(See Figure 4)
2-112
-------
This boiler, manufactured by BHK, is equipped with a low-NOx combustion system
(HT-NR burners + TSC). (See Table 2)
NOx emission from the stack is minimized by the DeNOx equipped after the Air Heater
Planning coals have a wide range of properties as shown in Table 2.
In general, the higher the Nitrogen content (N) in coal and the higher the Fuel
Ratio (= Fixed Carbon/Volatile flatter), the more difficult it is to achieve low-NOx
combustion. (See Figure 5)
Though this unit uses coal with the highest Nitrogen content and highest Fuel Ratio
among all imported coals usually used in power plants in Japan, excellent low-NOx/
NOx-UBC combustion performance has been continuously maintained since its commis-
sioning. (See Figure 6)
Operation techniques of combustion control are also important for achieving and
maintaining stable low-NOx combustion performance.
In this unit, an operating-assistance system, the computer aided combustion moni-
toring system, is installed to support plant supervisors.
For example, the data from multi-eye flame detectors and automatic traverse exhaust
gas analyzer installed in the economizer outlet are very useful for achieving opti-
mum fuel/air distribution in the furnace which prevents NOx-UBC from scattering.
Figure 7 shows a CO profile leaving economizer obtained by the automatic "grid"
sampli ng.
Fig. 8 is a picture of the flames in a 1000 MUe boiler operating at the guaranteed
minimum load condition. Stable combustion flames were confirmed.
Generally, in the minimum-load operation of the boiler, it becomes more difficult
to get stable combustion because the amount of heat radiation to the cloud of pul
verized coal particles is reduced. Moreover, in the burner's low load zone, reduced
C/A ratio (coal/primary air) causes unstable combustion. Since the HT-NR Burner is
equipped with a "flame-stabilizing ring" at the tip of the fuel nozzle, we can
reduce the exclusive coal firing minimum load without adding extra equipments.
Low-NOx Retrofit Using HT-NR Burners
There are several cases of low-NOx retrofits for existing boilers using HT-NR
burners as shown in Figure 9.
The low NOx combustion systems of existing boilers may be classified into the fol-
lowing three types.
• Non "Low-NOx"
• Conventional Low-NOx Burner
• Conventional Low-NOx Burner with TSC
In Japan, most existing P.C. fired units already operate with both conventional
low-NOx burners and TSC systems.
From 1984 to 1987, BHK has replaced existing low-NOx burners with Hitachi-NR burn-
ers in several units.
In Europe, on the other hand, most of the existing coal-fired combustion units were
not the "low-NOx" type.
From 1988 to 1989, Stork and Tampellar, Dutch and Finnish boiler manufacturers
respectively, modified their three existing non-low-NOx burners into HT-NR burners.
Two of these units also incorporated two-stage combustion. Results of these
modifications are shown in Table 3. In this record, the results of plants A and B
in Japan are the same as introduced at the symposium in 1987 and 1988.
Of the three modified units in Europe, the Inkoo PS boiler No. 4 of Imatran Voima
Oy (IVO) Power Company of Finland is shown below.
2-113
-------
A low-NOx modification of an Inkoo PS boiler No. 4
• This is a Benson type boiler with an output of 265 MUe ; a two-stage
combustion system of the HT-NR burner and overfire air were employed
in 1989 for the low-NOx combustion system.
• A total of 16 HT-NR burners were arrayed in four stages and four
rows in the furnace rear wall and eight after-air ports were placed
in the front wall and rear wall, four pieces each.
• The two-stage combustion system was designed to feed 0 to 25 % of
the air into the after-air ports. Therefore, the excess air factor of
the burner unit could be varied in the range of 0.95 to 1.25.
In August 1989, two months after the start of operation, the performance was tested
by using two types of coal, and the NOx level and unburnt content in ash were as
shown in Fig. 10. As compared with the operation before modification, there was a
reduction of about 50 %. The slagging was unchanged.
Design and Estimation
To achieve extremely low-NOx combustion, the combination of TSC and HT-NR burners
is most effective and useful.
The basic equation in Figure 11, which is used for design and estimation, explains
that the Total Fixed Nitrogen (= No + HCN + NH3 + N in char) should be minimized
before After-Air injection.
• Higher Heat Release Rate in burner zone (BHR) raises thermal NOx
formation.
• Extremely low stoichiometric ratio of the burner zone (SRg) could
produce slagging and/or corrosion especially with fusible and high
sulfur coal/ash.
• Higher In-Flame NOx Reduction efficiency (TINR) ^s obtained by using
higher volatile coals, and rapid ignition flame conditions are pro-
moted by finer pulverizing.
• TSC effect is advanced by lengthening the residence time of the
reducing gas between burner zone and after-air injection.
Development of Hitachi-NR2 Burner
At BHK, we are now developing a super low-NOx burner (HT-NR2 burner) aimed at even
lower NOx to cope with the needs of the coal fired thermal power of the next gene-
ration. The new burner based on the principles of the HT-NR burner, intensifies
the ignition and expands the reducing flame. A structural diagram of HT-NR2 burner
is shown in Fig. 12.
Features
• The basic principles are the same as in HT-NR burner
• The following mechanisms 1. and 2. have been added.
1. Intensification of ignition
2-114
-------
Formation of stable combustion and elevation of temperature by
primary air velocity control shell (pulverized coal concentration
regulator). The pulverized coal around the velocity control
shell is supplied into the flame stabilizing ring by inertia,
while primary air flow is diffused at the front of the velocity
control shell. Therefore, a flow of pulverized coal of high con-
concentration is led to the flame stabilizing ring, intensifying
the ignition.
2. Expansion of reducing region
Expansion of the reducing region by tertiary air separator
By widening the aparture of the tertiary air feed port and
separating of the secondary and tertiary air feed ports, the
reducing region in the flame is expanded.
Figure 13 shows the results of measurement of behavior of gas concentration near
the burner, using HT-NR burner and NR2 burner, in a combustion furnace with a coal
corn-combustion capacity of 500 kg/h. Uhile maintaining high combustion efficiency
by promotion of ignition, the NOx decomposition reaction in the flame is promoted
also. Figure 14 shows the combustion test records of a full-scale burner (coal
combustion capacity 4000 kg/h) using a large-sized combustion test furnace. The
NOx and unburnt carbon characteristics of the HT-NR2 burner have been proved to be
more outstanding than those of the NR burner.
CONCLUSION S RECOMMENDATIONS
Babcock-Hitachi K.K. has developed and installed extremely low-NOx burners, HT-NR
Burners, with successful results.
This burner concept of "In-Flame NOx Reduction" is highly effective both for exist-
ing boilers and future boilers.
Use of In-flame NOx reduction technology will play a major role in successful
retrofitting of existing old furnaces.
On the other hand, it will be applied to new boilers suitable for present and
future needs.
Furthermore, in order to meet the potential needs of the next-generation of coal-
fired power plants, BHK is working toward further NOx reduction and is developing a
burner with extremely low NOx emissions (HT-NR2 Burner). Advanced performance of
the HT-NR2 Burner has been confirmed by using a large scale combustion test
faci1ity.
REFERENCES
1. S. Morita et al., "Update on Coal Combustion Technologies", the Hitachi Hyoron,
vol. 72 - No. 6, 1990.
2. S. Morita et al ., "Design Methods for Low-NOx Retrofits of Pulverized Coal
Fired Utility Boilers", EPA/EPRI Joint Symposium on Stationary Combustion NOx
Control, 1989.
3. S. Morita, "Low-NOx Combustion Technology of Pulverized Coal Fired Utility
Boilers", Journal of the Japan Boiler Association, No. 231-10, 1988.
4. I. Eknan et al ., "Desul phurization by Limestone Injection combined with
Low-NOx Combustion", GEN-UPGRADE 90.
2-115
-------
UBC NOx
Combust i on
Completion
Zone
Technical Point
•Mixing of After-Ai r
Longer Res idence Time
ig.1 Concept of low-NOx Furnace
Design Condition
• The Same Coal Property
•The Same Pulverrizing
•The Same UBC Requi rement
New Technology
Dual/2rows
After-Air Port
Advanced TSC
In-Flame NOx Reduction Hitachi-NR Burner
UBC
NOx
^
^
SRBNR
150ppm
V
200ppm
•^
N0x = 300ppm
RT1- NOx
fig.2 NOx-UBC "Trade-Off"
2-116
-------
iic j n High Swirl Re;
Wind Box ^
Guide Sleeve
Fl ame
Stabilizing
Ring
Vo I at i I e
+ 0;
NO
Axial Distance from Burner
Fig.3 Hitachi-NR Burner
2-117
-------
SECONDARY „
SUPER HEATER
\
REHEATER
PRIMARY
SUPER HEATER
ECONOMIZER
PR I MARY l| 11 SECONDARY
ir—AIR HEATER lAIR HEATER
"^
Turbine Output 1, 000 MWe
Evaporat ion 3, 170 t/h
Super Heater Out let Press. 25 MPa
Super Heater Outlet Temp. 543/5691)
Fuel Coal
Fig.4 Matsuura P.S.T (Electric Power Development Co.,Ltd)
*) FN(Relative NOx Emission Facter)
FN=1.2 Higher NOx
FN = 1.
*)
^k \ C-Coal
PIanning coaI
Lower NOx
NOx ^ 200ppm
UBC ^ 5%
FR
2
Fixed Carbon
Volatile Matter
Fiy.5 A Relative NOx Emission (Matsuura 1", lOOOMWe)
2-118
-------
Eco 02 = 3 — 3. 5 (%. dry)
C-Coal /
FR = 1. 9. N = 0. n
Ash=9S
D-Coal
A-Coa I
FR = 2. 6. N = 2.
Ash=15X
0
FR=I. 0. N=1. 5%
Ash=8°/o FR = 2. 2. N = l. 8%
LA^- _ Ash=]X
100
150
iler Out I et NOx (ppm. 6%02)
'Guaranteed Point
FR - Fixed Carbon ,_,
Volati le Matter [~'
N : dry a sh f re e
Ash : dry base
Eco 02 : 02 Leaving
Economizer
200
Fig.5 Operation Results of Guaranteed Coals (Matsuura r. IDOOWtVe)
05A-5
90/02/27 19:30 «»MU
tJ.'tl It (MCtt H UI1U 90/02/08 19:04:00 1001MU
90/02/08 17:53-18:45
1001 tlW
9 0 \~ff.t. | ->9'>J h-f,
Cl C2 C3 C4 C5 C6 C7 C8 C9 C[0
CO
Fig.7 A Graphic CRT of "Grid-Measurement" Leaving Econimizer
2-119
-------
Flame Condition at Minimum Load
Operat ion in the 1000 MWe Boiler
2-120
-------
—I Cond it ion }
Same Furnace Volume
No Derat i ng
-t —
Ci rcular Register Burner
(Non-"Low-NOx")
Dual Register Burner
(Conventional "Low-NOx")
Hitachi-NR Burner
After-Air (OFA) Port
<
< >
< >
< >-
\x
600 MWe (1989)
.
\ 180 MWe (1988)
<
* jj
i 3-
{ 1-
V
80 t/h (1984)
80 t/h (1985)
200 MWe (1985)
200 MWe (1986)
350 MWe (1987)
265 MWe (1989)
Fig.9 Menu of Retrofits with Hitachi-NR Burners
100% boiler load
three upper burner levels in service
tota I air factor 1. 22
__^ Col umbi an coal
o A before retrofit
«=> A af ter retrofit
e
o.
—' Amerlean coal
5 • before retrofit
z O after retrof it
0.9 1.0 1.1 1.2
Stoichiometric ratio on burnur level
Fig.10 Example of Results of NOx/UBC Performance
2-121
-------
= k-exp(BHR)-f(SRB)-Ndaf-(1- 7NR)-exp(-RTi)
Total Fixed Nitrogen Heat release j Fuel-N
(Before Injection After-Air) R3te i
Sto i ch i ometry
-- AAPs
-• BNRs '-
Gas Residence
T i me
NOx.Fi nal
Re-formation ?NR = rj (VM)-(TRF)
RT1
T
I n-F I ame
Re due t ion
by
HT-NR
Temperature
of
Reducing Flame
TFN
Volatile Matter
Fig.11 Key Equation for Low-NOx Combustion System
Wi nd Box
VeIoc i ty Control
Space Creator
FIame Stab i
Oil Atomizer
Pry Air+P. C.
Space Creator
Ve loc i ty Control She I I
Fig.12 Features of Hitachi-NR2 Burner
2-122
-------
CD
,uuu
900
800
700
600
500
400
300
200
100
0
•— • — '"^
-Hilddii-NR2 XT |mprovement of
,*/* combustion efficiency
I // — -— --1 n <^— ->
- \.¥^ ^R
- , A A- <> •—
\/ M IMK promotion of
^ / \^^ NOx reduction"
i » i i
D 1 2 3 4
j»» m —
sduct ion of Char-NOx
S3
Reduction of
boi ler outlet NOx
,/r—^l
6
-
Furnace f
IUU
90 5
80 X
o
70 g
60 o
50 £
40 c
o
30 -M
00
20 _g
10 S
0
;xi t
Distance from burner
Fig.13 Behavior of NOx Combustion Efficiency in the Furnace
by Using a Post-Period Super Low-NOx Burner
10
to
ro
c
O
T3
E 2
D
C
60
Coal:Newlands
(FR=2.3)
Hitachi-NR
Hitachi-NR2
100 120 140 160 180
NOx (ppm,6%02)
Fig.14 NOx and Onburned Carbon Performance of Hitachi-NR2 Burner
2-123
-------
Table 1 Specifications of P. C. Combustion Equipment
(Matsuura 1U. lOOOMWe)
Mil 1
Burner
AAP
Type
Quant i ty
Capac ity
Loading Pressure
Classifier
Type
Quant ity
Heat Input
Arrangement
Type
Arrangeme nt
MPS-118 (B&W Type)
7 (1 for Stand-By)
95.3 t/h.Mill (HGI=50)
12. 4 MPa (Oil Press.)
F i xed Stationary Type
Hitachi-NR
70
152. 8 x 10
10 bnrs x
5 bnrs x
Dual Type
10 AAPs x
Burner
(10 for
6 kJ/h
3 rows, Opposed
1 row, Opposed
1 row, Opposed
Stand-By)
(Top Row)
Table 2 Planning Coal (Matsuura P. S. 1U. lOOOMWe)
1 ten
GCV
Proximate IM
VM
FC
Ash
S(Total)
F R
N
IDT
Base Unit
A. D J/kg
A. D %
A. D %
A. D %
A. D %
A. D %
d. a. f %
Oxi. °C
Desi gn Coa 1
> 25. 1
< 20
< 1. 0
< 2. 4
< 2. 1
> 1200
PI anni
Min
24.2
1. 5
23. 9
38. 5
3. 5
0.2
1. 1
0.8
1210
ng Coal
Max
29.0
9.6
40. 6
59. 1
26.0
1. 3
2.4
2. 1
> 1500
Table 3 Low-NOx Retrofit of Existing Coal Fired Boilers
Plant
A
B
C
0
E
Capac ity
200MWe
350MWe
180MWe
265MWe
600MWe
Volati le
Content (%, daf)
34-
30-
23-
35-
30-
56
40
40
40
40
NOx Reduct ion
(Commerc i a 1
35-
25-
40-
40-
30-
Efficiency (%)
Operat ion Base)
45
30
50
50
45
Remarks
1985-86
Japan
1987
Japan
1988
Europe
1989
Europe
1989
Europe
2-124
-------
Session 3
LARGE SCALE COAL COMBUSTION
Chair: D. Eskinazi, EPRi and R. Mali, EPA
-------
DEMONSTRATION OF LOW NOX COMBUSTION CONTROL TECHNOLOGIES
ON A 500 MWe COAL-FIRED UTILITY BOILER
Steve M. Wilson
John N. Sorge
Southern Company Services
Lowell L. Smith
Larry L. Larsen
Energy Technology Consultants, Inc.
-------
Demonstration of Low NOx Combustion Control Technologies
on a 500 MWe Coal-Fired Utility Boiler
Steve M. Wilson
John N. Sorge
Southern Company Services
Lowell L. Smith
Larry L. Larsen
Energy Technology Consultants, Inc.
A DOE Innovative Clean Coal Project (ICCT) Project was awarded in 1989 to demonstrate retrofit
technologies to control NOx emissions on a 500 MWe wall-fired boiler. The primary objective of the
project is to demonstrate the control effectiveness of Advanced Overfire Air (AOFA), Low NOx Burners
(LNB) and the combination of these technologies under short-term controlled and long-term load dispatch
conditions. The project involves four test evaluation phases Baseline, AOFA, LNB and LNB with
AOFA. Each phase will evaluate NOx control effectiveness and the impact of the technologies on boiler
operation and backend cleanup equipment.
This paper provides an overview of the program test plan and instrumentation for the four phase program.
The test results from the Baseline and Overfire Air Port retrofit phases of the program are presented.
Comparisons are made between the short-term controlled test results and the long-term load control test
results for these phases. Comparisons are also made between the Baseline and AOFA long-term retrofit
results to establish the NOx control effectiveness for this technology.
3-3
-------
INTRODUCTION
This paper describes the technical progress of a U.S. Department of Energy (DOE) Innovative Clean Coal
Technology (ICCT) Project demonstrating advanced wall-fired combustion techniques for the reduction
of nitrogen oxide (NOx) emissions from coal-fired boilers. The project is being conducted at Georgia
Power Company's Plant Hammond Unit 4 near Rome, Georgia.
The project is being managed by Southern Company Services, Inc. (SCS) on behalf of the project co-
funders: The Southern electric system, the U.S. Department of Energy (DOE), and the Electric Power
Research Institute. In addition to SCS, The Southern electric system includes five electric operating
companies: Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric and
Power. SCS provides engineering and research services to the Southern electric system.
The Innovative Clean Coal Technology Program is a jointly funded effort between government and
industry to move the most promising advanced coal-based technologies from the research and
development stage to the commercial marketplace. The clean coal effort sponsors projects which are
different from traditional research and development programs sponsored by the DOE. The traditional
projects focused on long range, high risk, high payoff technologies with the DOE providing the majority
of the funding. In contrast, the Clean Coal project objective is to demonstrate commercially feasible
advanced coal-based technologies which have already reached the "proof-of-concept" stage. As a result,
the clean coal projects are jointly funded endeavors between the government and the private sector which
are conducted as Cooperative Agreements in which the industrial participant contributes at least fifty
percent of the total project cost.
The primary objective of the Plant Hammond demonstration is to determine the long- term effects of
commercially available wall-fired low NOx combustion technologies on NOx emissions and boiler
performance. Short-term tests of each technology are also being performed to provide engineering
information about emissions and performance tends. A target of achieving fifty percent NOx reduction
using combustion modifications has been established for the project. The project seeks to address the
following objectives:
1) Demonstrate in a logical stepwise fashion the short-term NOx reduction capabilities of the
following advanced low NOx combustion technologies:
a) Advanced Overfire Air (AOFA),
b) Low NOx Burners (LNB),
3-4
-------
c) LNB with AGFA.
2) Determine the dynamic long-term emissions characteristics of each of these combustion
NOx reduction methods using sophisticated statistical techniques.
3) Evaluate the progressive cost effectiveness (i.e., dollars per ton NOx removed) of the low
NOx combustion techniques tested.
4) Determine the effects on other combustion parameters (e.g., CO production, carbon
carryover, paniculate emission characteristics) of applying the NOx reduction methods listed
above.
PROJECT DESCRIPTION
The stepwise approach to evaluating the NOx control technologies requires that two plant outages be used
to successively install (1) the advanced overfire air ports and ducting and (2) the Foster Wheeler
Controlled Flow/Split Flame (CF/SF) low NOx Burners. These outages were scheduled to coincide with
existing plant outages in the spring of 1990 and the spring of 1991. The final LNB retrofit outage will be
completed by late April 1991.
Following each major retrofit outage, a series of four groups of tests are performed (1) diagnostic, (2)
performance, (3) long-term and (4) verification. The diagnostic, performance and verification tests
consist of short-term data collection under carefully established steady-state operating conditions. The
diagnostic tests are designed to map the effects of changes in boiler operation on NOx emissions and
establish NOx trends. The performance tests are used to evaluate a more comprehensive set of boiler and
combustion performance indicators including paniculate characteristics, boiler efficiency, and boiler
outlet emissions. Mill performance and air flow distribution are also established during the performance
testing. The verification tests are used to establish whether any changes in NOx emission trends might
have occurred during the long-term test phase.
One of the major objectives of this demonstration project is to collect long-term, statistically significant
quantities of data under normal operating conditions with and without the various NOx reduction
technologies. Earlier demonstrations of combustion emission control technologies have relied solely on
data from a matrix of carefully established short-term (one to four hour) steady-state tests. Utility boilers
seldom operate in this steady-state manner considering the dynamic nature of the plant equipment
operation needs and economic dispatch strategies employed. Due to this dynamic mode of operation,
3-5
-------
statistical methods have been developed for use with long-term emission and operational data that allow
determination of the achievable emissions limit (Ref. 1) or emission tonnage of a control technology (Ref.
2). These analytic methods have been developed over the past fifteen years by the Utility Air Regulatory
Group (UARG) - Control Technology Committee. Data collection criteria used in these methodologies
are now accepted as benchmarks for establishing the achievable SC>2 and NOx emission limits. These
criteria along with other criteria established by EPA will be used to determine the achievable NOx
emission level in each of the four operating conditions for Hammond Unit 4 - Baseline, AGFA, LNB and
LNB with AGFA.
The major emphasis of this paper is on description of the NOx Characteristics resulting from the Baseline
and AGFA retrofit short-term and long-term test efforts. Both short-term and long-term testing and
analysis have been completed for the Baseline configuration and have been thoroughly documented in
Reference 3. The short-term and long-term test efforts in the retrofit AGFA configuration have been
completed, however, detailed analysis of the data is still in progress as of the date of publication of this
paper. Consequently, information provided in this paper relative to the AGFA retrofit is preliminary and
may be revised upon publication of the final DOE Interim Test Report.
BOILER AND AGFA DESCRIPTION
Boiler Description. Hammond Unit 4 is a balanced draft Foster Wheeler Energy Corporation (FWEC)
opposed wall-fired boiler rated at 500 gross MWe with design steam conditions of 2500 psig and
1000/1000 °F superheat/reheat temperatures, respectively. Six FWEC Planetary Roller and Table type
MB-21.5 mills provide pulverized eastern bituminous coal (12,900 BTU/lb, 33% VM, 53% FC, 1.7% S,
1.4% N) to 24 Intervane burners. The burners are arranged in a matrix of 12 burners (4W x 3H) on
opposing walls with each mill supplying coal to four burners in an elevation. The unit is equipped with a
coldside ESP and utilizes two Ljungstrom air preheaters.
AGFA Description. Figure 1 schematically illustrates the AOFA retrofit on Hammond Unit 4. The
AGFA system consists of ductwork on each side of the boiler extending from immediately downstream of
each secondary air venturi to a separate overfire air windbox located above the burner windbox. Eight
FWEC can-in-can overfire air ports supply preheated air directly above each burner column on opposing
walls. The ductwork and OFA ports were designed to provide improved overfire air penetration across
the furnace. In addition, numerous dampers were provided to optimize the flow distribution of the
system. The AOFA system incorporates four sets of OFA flow control devices, 1) windbox/AOFA flow
proportioning dampers, 2) AOFA guillotine shutoff dampers, 3) AOFA flow control dampers and 4) can-
in-can distribution dampers. The windbox/AOFA proportioning dampers are set in one fixed position at
3-6
-------
commissioning. The guillotine shutoff dampers are used only for isolating the AGFA system from the
secondary air supply. The AOFA flow control dampers and the can-in-can dampers are used to modulate
the OFA flow and the distribution of the air across the furnace. In addition to these control dampers,
curtain air was supplied to protect the furnace walls.
TEST INSTRUMENTATION DESCRIPTION
A complete data acquisition system (DAS) was installed during the fall of 1989. This custom designed
micro-computer based system is used to collect, format, calculate, store, and transmit data derived from
power plant mechanical, thermal, and fluid processes. The extensive process data selected for input to the
DAS has in common a relationship with either boiler performance or boiler exhaust gas properties.
The DAS includes a continuous emissions monitoring system (NOx, SC>2, C>2, THC, CO) with a multi-
point flue gas sampling and conditioning system, an acoustic pyrometry and thermal mapping system,
furnace tube heat flux transducers, and boiler efficiency instrumentation. The instrumentation system is
designed to provide data collection flexibility to meet the schedule and needs of the various testing efforts
throughout the demonstration program. A discussion of the various instrumentation follows.
Extractive Continuous Emissions Monitor fECEMI. An underlying objective of the ICCT project is to
evaluate the long term effectiveness of retrofit NOx control technologies. The Extractive Continuous
Emission Monitor (ECEM) provides the means of extracting gas samples for automatic chemical analysis
from sample points at strategic locations in the boiler exhaust ducts. The system quantitatively analyzes
gas samples for NOx, SO2, CO, O2, and total hydrocarbons (THC). The results from the five analyses,
along with the status of the ECEM, are continuously transmitted to the DAS computer where the data is
processed and stored. The ECEM comprises sample probes and lines, a sample control system consisting
of valves and distribution manifolds, pumps, sample conditioners (filters, condenser/dryer, pressure
regulation and a moisture detector), flowmeters, gas analyzers and an automatic calibration system.
Automatic or manual calibration is achieved by sequentially introducing certified gases of known zero
and span value for each analyzer.
Acoustic pyrometer. The acoustic pyrometer is a micro-computer controlled system that transmits and
receives sonic signals through the hot furnace gas above the fireball from multiple locations around the
girth of the boiler. The acoustic pyrometer provides average temperature data for straight line paths
between any two transceivers not located on the same furnace wall. The acoustic pyrometer provides a
means of analyzing the variations in the combustion process. The velocity of the sonic pulses is used to
compute an average path temperature between two transceivers which, when combined with the other
3-7
-------
path temperatures, allows computation of isotherms at the plane of acoustic pyrometer transceivers. At
Plant Hammond Unit 4, the horizontal plane of the transceivers is approximately 15 feet above the
uppermost elevation of burners.
Fluxdome Heat Flux Sensors. The DAS instrumentation includes heat flux sensors that detect the heat
absorption into the boiler's furnace wall tubes at strategic locations in the furnace. These flux
measurements are intended to provide an indication of both the furnace combustion gas temperature and
the condition of the wall ash deposits in the near-burner zone. Comparisons of the flux measurements
during the various phases of retrofit may indicate whether any beneficial or undesirable effects on the
furnace wall tubing is associated with the low-NOx technologies.
The heat flux sensors consist of small metal cylinders welded to the fire side surface of a boiler tube. The
shape, size, and weld specifications of the cylinder are carefully controlled to assure exact dimensions in
order to provide a specific heat path from the furnace/tube interface into the boiler tube. Two type K
thermocouples are embedded in each cylinder at prescribed depths. The temperature gradient (typically
0-70 °C) detected by the thermocouples is proportional to the heat flux at the point of measurement.
Flue Gas Ch Instrumentation. A flue gas oxygen analyzing system is installed in the boiler exhaust ducts
at the economizer and air heater outlets. This system provides an accurate reading of C>2 in the flue gas
and allows for detection of air leakage at the air heater seals. The measurement system uses in-situ
zirconium oxide measuring cells located in the flue gas paths. This method eliminates many of the
repetitive maintenance problems found in extractive systems. Zirconium oxide probes are commonly
used in power plant applications and provide an accuracy of ± 0.25 percent. This system undergoes an
automatic calibration at frequent intervals.
Hammond Unit 4 has two probes located in each of the two economizer outlet ducts and two probes in
each of the two air heater outlet ducts. These probes are approximately positioned in each duct to obtain
a representative flow weighted average. Outputs from the probes are continuously transmitted to the
DAS.
3-8
-------
BASELINE NOx CHARACTERIZATION
During the Baseline series of test, the unit operated, for the most part, as a base loaded unit which only
reduced load at night to shed slag or accommodate system load requirements. As a consequence, most of
the short-term and long-term testing was performed at loads in the range of 400 to 480 MWe. A total of
62 short-term tests were completed in the baseline phase and continuous long-term data was gathered at
five minute averages from December 1989 through early April 1990.
Short-Term NQx Characteristics. The objective of the short-term testing was to establish the NOx trends
for the major parameters that influence emissions on this unit, i.e., excess oxygen, mill pattern and load.
The major premise behind the short-term data collection effort was that due to the potentially high
variability of the data, relatively representative trends could be established during short-term testing;
however, an accurate estimate of the absolute NOx level could be best determined through use of long-
term data. Testing was performed in such a manner as to eliminate some of the variability by establishing
trends at one boiler configuration (same test day). The following NOx characterizations reflect this test
philosophy.
At the high load condition of 480 MWe, characterization of the NOx over the excess oxygen range was
complicated by design constraints which limited the range to ± 0.75 percent about the nominal 2.7
percent O2 operating point. Figure 2 illustrates the trends over this excess oxygen range (solid lines
represent data collected on the same day under the same configuration). The data show significant
variability in not only the NOx levels at a given O2 set point but also with respect to the slope of NOx
versus O2- In general the slope of NOx versus O2 averaged approximately 110 ppm/%O2 with a
variability in measured NOx of ± 6 percent ( - 120 ppm band).
Figure 3 illustrates the NOx characteristics at a slightly reduced load of 400 MWe where mills can be
taken out of service. The nominal operating excess oxygen level at this load is 3.2 percent. These data
show the same general trends as those for the 480 MWe condition for the two mill patterns tested. The
average NOx versus O2 slope of 60 ppm/%O2 was considerably lower than for the 480 MWe condition.
It is evident from Figure 3 that the "B" mill out of service pattern yields higher absolute NOx emission
levels. For these mill patterns the variability in absolute NOx was in the order of ± 9 percent (160 ppm
band). This influence of mill pattern was evident for other patterns at this load and complicates the
ability to ascertain the representative NOx emissions at loads where various mill patterns are possible.
The load range NOx characteristics in the Baseline configuration are shown in Figure 4 for the tests
performed over the excess oxygen excursions. Based upon the average conditions tested, the slope of
3-9
-------
NOx versus load was determined to be approximately 1.2 ppm/MW. As can be seen, however, the NOx
can vary by as much as ± 25 percent about the mean for the normal operating excess oxygen level.
The type of data collected is adequate for characterizing trends in NOx, however, as can be seen by the
relatively large variability, is would be difficult to establish precise characteristics (absolute NOx levels)
without significantly more short-term data. The long-term data collection portion of this demonstration
project had as its goal the establishment of the mean NOx characteristics with estimates of the
uncertainties. These characterizations can be used to statistically establish the achievable NOx emission
level according to EPA criteria.
Long-Term NOx Characteristics. The long-term data collected in the Baseline testing allowed
determination of the statistical characteristics of the data such as the mean emission level, the 95 percent
confidence interval and the autocorrelation coefficient (Ref. 1). These statistical characteristics are
necessary for establishing the achievable emission level as well as the true dynamic load-following NOx
characteristics. Figure 5 illustrates the differences between the short- and long-term data results at 480
MWe. The long-term data demonstrates a mean NOx level of 870 ppm at the nominal 2.7 percent excess
oxygen operating condition while the short-term test results show a mean level of 970 ppm (12 percent
difference). The short-term data generally fits within the 95 percent confidence band, however, all of the
data is above the mean level that would normally be experienced during uncontrolled operation. The
explanation for this disparity most likely is a result of such variables as coal variability, minor unit
operating changes (air register settings, etc.) and possibly weather conditions affecting the coal grinding
(wet coal) as well as the fact that long-term data includes transients in operating ©2 level which may be
greater than the steady load excursions. The important point is that these normal excursions can influence
the short-term data taken at one point in time but are essentially averaged out during normal long-term
operation.
Figure 6 shows a comparison of the short-term to long-term data which illustrates that, in this case, that
the long-term mean is less than the short-term mean NOx level. The trend for the short- and long-term
test results was consistent over the normal operating load range. The short-term mean NOx level
consistendy falls within the 95 percent confidence interval for the long-term data. This indicates that the
short-term data is a subset of the long-term data and is therefore representative of the operating
characteristics.
Using the long-term data, statistical procedures were employed to estimate the NOx emission levels that
could be achieved based upon EPA criteria for 30-day rolling average compliance. The achievable
emission level is dependent upon the degree of autocorrelation, the mean emission level and the relative
3-10
-------
standard deviation or variability of the daily average data. Based upon 52 days of long-term data that
satisfies an underlying data collection criteria, for the load scenario experienced during the period
between December 1989 and April 1990, the achievable emission level was determined to be 1.24
Ib/MMBtu (Mean = 1.16, p = 0.54, a = 0.11).
ADVANCED OVERFIRE AIR NOx CHARACTERIZATION
Short-Term NOx Characteristics. Early in the commissioning of the AGFA system, the can-in-can OFA
port dampers overheated in the closed position requiring an outage to permanently fix them in the full
open position. This prevented obtaining any information on the influence of the retrofit on the Baseline
NOx emissions at the 0 percent OFA port opening due to the requirement for leakage cooling air for the
ports. The minimum OFA port setting was approximately 5 percent open. Control of the air flow to the
AOFA ports was accomplished using the flow control dampers.
An acceptable setting for the windbox/AOFA proportioning dampers was first established based upon the
minimum design windbox to furnace pressure differential. Subsequent to this, exploratory tests were
performed to assess the effectiveness of the AOFA ports with respect to the relative opening position of
the flow control damper. Figure 7 provides a summary of a number of high load tests performed prior to
establishing a final operating configuration for the AOFA system. These data illustrate the same level of
variability that was experienced during the Baseline test series which necessitated establishing the trends
on the same day, rather than at random, to eliminate the influence of unidentified biasing parameters. The
data at 480 MWe indicated that the NOx reduction at full load averaged 160 ppm or 20 to 25 percent
overall reduction between the 5 and 50 percent AOFA port open position. Further, indications were that
the reduction diminished significantly above the 50 percent open position. For this and other operational
considerations, the 50 percent AOFA flow control damper open position was chosen as the nominal
setting. Testing at reduced load proved this to be satisfactory down to a load of 300 MWe. At this setting,
the measured AOFA flow at full-load was determined to be approximately 20 percent of the total
combustion air flow. Below this load the AOFA flow control damper was closed to the indicated 25
percent open position.
A series of tests was performed at high load with the AOFA ports set at the 50 percent open setting to
determine the NOx characteristics with respect to excess oxygen excursions. Figures 8 and 9 show the
results of these characterizations at the 480 and 400 MWe load points. These data show somewhat less
variability than that for the Baseline test series. A potential reason for this is the fact that a long standing
practice of secondary air register modulation for steam temperature and flame appearance control was
eliminated after Baseline testing when it was discovered that this contributed to the NOx variability. At
3-11
-------
the full load condition the NOx was 67 ppm/%O2 compared to 110 pm/%C>2 in the baseline
configuration, or considerably less sensitive. The mean short-term NOx level at 2.7 percent C>2 was
approximately 550 ppm compared to 970 ppm in the baseline configuration (indicated 40+ % reduction).
As will be explained below, the operating excess oxygen level had to be raised above the Baseline levels
due to relatively high CO emissions on one side of the boiler.
The short-term NOx characteristics over the load range are shown in Figure 10 for all of the excess
oxygen levels tested. The short-term data indicated a minimum NOx at 400 MWe due possibly to the
higher operating excess oxygen levels used at the 300 MWe load point (nominally 4.5 percent).
Long-Term NQx Characteristics. Long-term testing is to be completed in early March 1991. As a result,
at the date of publishing of this paper only a limited amount of long-term data was available for analysis.
These limited data are used only to illustrate the differences between short- and long-term data results.
At the end of the short-term testing it was determined that significant CO emissions were emanating from
one side of the boiler during AGFA operation. As a result of this undesirable operating condition, the
recommended operating excess oxygen levels were increased at loads between 300 and 480 MWe as
shown in Figure 11. This was not an unexpected finding based upon the characteristics of previous OFA
retrofits.
Based upon the one week of long-term data available, a comparison is made between the short- and long-
term data for the AOFA retrofit. Figure 12 shows that the short-term mean NOx emissions are at least 100
ppm below the long-term mean. With only one week of long-term data it is difficult to establish if this is
the long term trend for all of the long-term data (in excess of 9 weeks). One observation is that the NOx
versus load trends for both data sets are consistent.
3-12
-------
COMPARISON OF SHORT-TERM AND LONG-TERM NOx CHARACTERISTICS
If the long-term trend illustrated in Figure 12 holds for the entire 9 weeks of long-term data, the
characteristics shown in Figure 13 will establish the true characteristics of the AGFA retrofit
effectiveness. As can be seen from this figure, the short-term data demonstrates a 40 percent reduction at
full load while the long-term data indicates a reduction of only 20 percent. However, increases in
combustibles loss-on-ignition (LOI) values were experienced. As shown in Figure 14, post AGFA
retrofit LOI values are approximately twice the pre-retrofit levels. The near-isokinetic CEGRTT samples
are obtained continuously from two, single point, sampling probes located in the gas path immediately
following the economizer. The mass train samples are obtained isokinetically at a grid located at the
electrostatic precipitator inlet. The balance of the AGFA results will be reported in a Phase II Interim
Test Report that will be issued late in 1991.
FUTURE PROJECT ACTIVITIES
Retrofit of the Foster Wheeler CF/SF Low NOx Burners will be completed in early May 1991.
Subsequent to shakedown tests, a series of tests will be performed to establish the effectiveness of the
burners with the AGFA ports closed. These tests are expected to be complete in early October 1991.
These tests will be followed by testing of the boiler with the AGFA ports open to the nominal position.
This testing is scheduled to be completed in late March 1992. Interim test reports for each of these phases
will be issued shortly after completion of the analysis of the data.
ACKNOWLEDGEMENTS
The authors wish to gratefully acknowledge the support and dedication of the following personnel for
their work at the wall-fired site: Mr Ernie Padgett, Georgia Power Company and Mike Nelson, Southern
Company Services, for their coordination of the design and retrofit efforts and Mr. Jose Perez, full-time
Instrumentation Specialist from Spectrum Systems, Inc. We also thank Messrs Jim Witt and Jimmy
Horton of Southern Company Services for their work coordinating the procurement and installation of the
instrumentation. We would like to recognize the following companies for their outstanding testing and
data analysis efforts at Plant Hammond: Flame Refractories, Inc., Southern Research Institute, W. S. Pitts
Consulting and Radian Corporation. Finally, the support from Mr. Art Baldwin, DOE ICCT Project
Manager and Mr David Eskinazi, EPR1 Project Manager, is greatly appreciated.
3-13
-------
REFERENCES
1. R. E. Rush and L. L. Smith, "Long-Term Versus Short-Term Data Analysis Methodologies -
Impact on the Prediction of NOx Emission Compliance'1 EPA/EPRI Joint Symposium on
Stationary Combustion NOx Control, New Orleans, Louisiana, March 1987.
2. W. S. Pitts and L. L. Smith, "Analysis of NOx Emissions Data for Prediction of Compliance with
NOx Emissions Standards". AWMA Combustion in the Environment Conference, Seattle,
Washington, March 1989.
3. Advanced-Wall-Fired Low NOx Combustion Demonstration - Phase 1 Baseline Tests. U.S. DOE
ICCT n Demonstration Project, Interim Report (Draft Report), Southern Company Services,
November 1990.
3-14
-------
CombuMkxi Mr
Flu* Gai to
Air PrBheater
Boundary Air Ports
Automated Data Collection Systerr
o Continuous Emission Monitor
o Acoustic PyromatBf
o Haat Flux TransOuccm
o Control Room Data
FIGURE 1 Modifications of the Plant Hammond Unit 4 Boiler
1200
1100
52.
E
1000
O
o5 900
en
LU
X
§ 800
700
480 MWe NOMINAL LOAD
ALL. BURNERS-IN-SERVICE:
2.5 3 3.5
EXCESS OXYGEN , %
4.0
FIGURE 2 Baseline Short-Term NOx Characterization at 480 MWe
3-15
-------
1100
CM
O
1000
g- 900
co
LLJ
x
O 700
600
400 MWe NOMINAL LOAD
•— E-MILLOUT OF SERVICE
fr-- B-MILL OUT OF SERVICE
3 4
EXCESS OXYGEN , %
FIGURE 3 Baseline Short-Term NOx Characterization at 400 MWe
1100
c7 100°
O
Q.
Q.
CO
O
CO
CO
5
LU
x
O
900
800
700
600
Average
I
150 200 250 300 350 400 450 500 550
LOAD , MWe
FIGURE 4 Baseline Short-Term Load Range NOx Characteristics
3-16
-------
1100
Q.
a 900
CO
o
CO
co
Lu 800
x
O
700
650
4SO MWe NOMINAL LOAD
ALL MILLS IN SERVICE
SHORT-TERM DATA
UPPER 98% a
MEAN
LOWER 5% Cl
LONG-TERM DATA
1.5 2 2.5 3
EXCESS OXYGEN , Percent
3.5
FIGURE 5 Comparison of Baseline Short- and Long-Term O2 Trends
1200
1100
O 1000
S?
n
900
Q.
Q.
g 800
O
co
CO 700
LU
600
500
400
SHORT-TERM DATA
UPPER 95% Cl m
MEAN "'
. LOWER 5% Cl
LONG-TERM DATA
250 300 350 400 450
GROSS LOAD, MWe
500
550
FIGURE 6 Comparison of Baseline Short- and Long-Term Load Range Trends
3-17
-------
1100
1000
eg
O
5?
O.
E
Q.
Q.
CO
g
co
co
HI
x
O
900
800
y 700
600
500
400
Each Symbol Type
Represents Different
Test Day
10 20 30 40 50
NOMINAL OFA POSITION
60
70
80
FIGURE 7 AOFA Port Opening Characterization at 480 MWe
OIAJ
c\T
O 700
CO
a
a.
CO 600
O
CO
CO
LU
O 500
Z
400
480 MWe NOMINAL LOAD
ALL MILLS IN SERVICE
50 % AOFA PORT OPENING
" 28
DAY 28
43
2 ^f
38
s^**
43
^
3 4
EXCESS OXYGEN , Percent
FIGURE 8 AOFA Short-Term NOx Characterization at 480 MWe
3-18
-------
NOx EMISSIONS . ppm (3% O2)
400 MWe NOMINAL LOAD
50 % AOFA PORT OPENING
^J
>-^a
DAY 47 » _j
"-^""If
M *° 39
/ —
s
^^
V
-(All Mills in Service j
"E" Mill Out of Service!
23456
EXCESS OXYGEN , Percent
FIGURE 9 AOFA Short-Term NOx Characterization at 400 MWe
ouu
OTnn
/ uu
Q.
E
a
a.
W ft/in
DUU
o
co
co
55
m
X enn
Q OUU
z
^.nn
1
o
a
c
A
O
o
0
*•»,
O *"~ -
(
c
(
c
t
— — . _ —
o
c
o
k ^ . -*"
--J
^tl
o
8
0 °
o
A
-^ &
o
0
9
0
0
250 300 350 400 450 500 55
GROSS LOAD , MWe
FIGURE 10 AOFA Short-Term Load Range NOx Characteristics
3-19
-------
5
Percent
.&.
z
LU
O
o
EXCESS
CO
2
2
"• x
RECOI
RECOMMEh
\
-. ^^^^
-. ^x
MENOEO MINIMUM C
DED MINIMUM O2 U
/
7
— L_
•«,s
4 ""-,
/
ULEVELFORSASEl
VELFOHAOFAOPEF
" .
""--._
NE OPERATION
AT1ON
50 300 350 400 450 500 55
GROSS LOAD , MWe
FIGURE 11 Baseline and AOFA Operating Excess Oxygen Curves
OJ
O
3?
CO
Q.
Q.
1100
1000
900
BOO
g
CO
52 700
O 600
500
400
LONG-TERM DATA FOR WEEK 2/10 TO 2/16/91
LONG-TERM DATA
LOWER 5% Cl oo
SHORT-TERM DATA
250 300 350 400 450
GROSS LOAD, MWe
500
550
FIGURE 12 Comparison of AOFA Short- and Long-Term Load Range Trends
3-20
-------
1000
900
CO
O
5?
o.
E eoo
Q.
Q.
C/3
O
W 700
c/2
LU
X
Z 600
500
LONG-TERM AGFA
__ SHORT-TERM AGFA __
250
300
20 % I
40%
500
350 400 450
GROSS LOAD, MWe
FIGURE 13 Comparison of Baseline and AGFA Operation
550
Oio
vO
^9
O
c
o
n
1*
"E 3
o
O
2
Mass Train Samples
CEGRIT Samples
Baseline
250
300
350
400
450
500
Unit Load (MWe)
FIGURE 14 Comparison of Baseline and AGFA LOI Values
3-21
-------
REBURN TECHNOLOGY FOR NO
CONTROL ON A CYCLONE-FIRED BOILER
R.W. Borio, R.D. Lewis, M.B. Keough
ABB Combustion Engineering
R. C. Booth
R. E. Hall
R. A. Lott
A. Kokkinos
D. F. Gyorke
S. Durrani
Energy System Associates
U.S. EPA
GRI
EPRI
DOE-PETC
Ohio Edison
H. J. Johnson OCDO
J. J. Kienle East Ohio Gas
-------
ABSTRACT
Cyclone-fired boilers have typically produced higher NO than other
types of coal-fired utility boilers. Cyclone-fired bolters are
generally not amenable to in-furnace NO reduction technologies;
reburning represents an in-furnace NO reduction technology that is
well suited to cyclone boilers. The Environmental Protection
Agency, Gas Research Institute, Electric Power Research Institute,
Department of Energy, and Ohio Coal Development Office have
cosponsored a program conducted by ABB Combustion Engineering to
demonstrate natural gas reburning on a cyclone-fired boiler at Ohio
Edison's Niles Station. Ohio Edison and East Ohio Gas have both
provided in-kind financial contributions to the program.
The paper provides a preliminary summary of results from recent
parametric testing of the reburn system which was installed and
commissioned during the third quarter of 1990. Key variables
evaluated during reburn testing included excess air, natural gas
flow rates, recirculated flue gas flow rates, and additional air
flow rates. Nitrogen oxide reductions were shown to be strongly
influenced by reburn zone stoichiometry. The effect of reburning on
boiler thermal performance was evaluated; changes in waterwall heat
absorption and convective pass heat absorption are presented along
with changes in boiler efficiency. Electrostatic precipitator
performance is compared for base case coal firing and the reburning.
Finally, mention is made of thicker ash deposits on the back wall of
the secondary furnace since installation of the reburn system.
INTRODUCTION
Recent passage of the 1990 Clean Air Act Amendments has underscored
the need for establishing commercially acceptable technologies for
reducing power plant emissions, especially sulfur dioxide (SO ) and
nitrogen oxides (NO ). NO and sulfur oxides (SO ) lead to formation
of acid rain by comoining with moisture in the atmosphere to produce
nitric and sulfuric acids (1,2,3). NO also contributes to the
formation of "ground level" ozone. Ozone is a factor in the creation
of smog, leads to forest damage, and contributes to poor visibility.
x
Electric utility power plants account for about one-third of the NO
and two-thirds of the SO emissions in the U.S. Cyclone-fired
boilers, while representing about 9% of the U.S. coal-fired generating
capacity, emit about 14% of the NO that utility boilers produce.
Given this backgroud, the Environmental Protection Agency (EPA), the
Gas Research Institute (GRI), the Electric Power Research Institute
(EPRI), the Department of Energy Pittsburgh Energy Technology Center
(DOE-PETC), and the Ohio Coal Development Office (OCDO) have sponsored
a program led by ABB Combustion Engineering (ABB-CE), to demonstrate
reburning on a cyclone-fired boiler. Ohio Edison is providing Unit
No. 1 at their Niles Station for the reburn demonstration along with
3-25
-------
financial assistance. The Consolidated Natural Gas Company (CNG),
specifically East Ohio Gas, has financially shared in the program.
Ohio Edison and East Ohio Gas are both sharing a portion of the
differential cost of natural gas.
Unit No. 1 went into commercial operation in 1955 and is a 108 MWe
(net) natural circulation reheat boiler operating with a pressurized
furnace. Steam conditions are 1485/374 psig* and 1000/1000°F.
Working with ABB-CE are Energy Systems Associates (ESA), Physical
Sciences Inc. Technology (PSIT), and Mitsubishi Heavy Industries
(MHI).
Reburn technology involves creating a second combustion or "reburn"
zone downstream from the main burners in a boiler. Combustion gases
that result from burning a fossil fuel in the main combustion zone,
move to the "reburn" zone where additional fuel, in this case natural
gas, is injected. The injection of additional fuel creates a
fuel-rich zone in which the NO formed in the main combustion zone are
converted to molecular nitrogen and water vapor which occur naturally
in the atmosphere. Any unburned fuel leaving the reburn zone is
subsequently burned to completion in a downstream burnout zone where
additional air is injected. Further details of the reburning process
can be found in the literature (4,5,6,7). Reburning is especially
attractive for cyclone-fired boilers and other wet-bottom boilers
since low NO burners and most other low NO combustion technologies
used on conventional boilers are not applicable to cyclone-fired and
wet-bottom boilers. The overall goal of the program is to
successfully demonstrate a 50% reduction in NO emissions from a
cyclone-fired boiler employing reburning technology. Figure 1 shows
the overall project scope and schedule.
The engineering design of the reburn system has been completed and
reported previously (8). This paper presents results of the
parametric testing of the reburn system installed during the summer of
1990.
REBURN SYSTEM
DESCRIPTION
Viewed in terms of its components, the reburn system is composed of
equipment/materials which are familiar to operators of utility power
plants. The reburn system is relatively compact, requiring a small
amount of space when compared with tail-end treatment systems; this
could be an advantage for utilities where indoor and/or outdoor space
is limited.
Readers more familiar with metric units may use the conversion
table at the end of this paper.
3-26
-------
The reburn system can be described in terms of equipment necessary for
the creation of the reburn zone and for the burnout zone. Key
components for the reburn zone are the flue gas recirculation (FGR)
fan, ductwork/associated control dampers, natural gas
pipeline/associated control valves, and the windboxes and nozzle
assemblies where the natural gas and flue gas are mixed shortly before
injection into the lower part of the secondary furnace of the boiler.
A mixture of flue gas and natural gas is injected through five windbox
nozzle assemblies, referred to as Upper Fuel Injectors (UFIs)
(Figure 2), along the back wall of the secondary furnace.
Key components for the burnout zone are the ductwork/associated
control dampers, and the windboxes and nozzle assemblies where
combustion air, referred to as Additional Air (AA), is injected into
the upper part of the secondary furnace. Greater detail on the design
and operation of the UFIs and AA nozzles was provided in an earlier
paper (8).
The reburn control system uses an Allen Bradley programmable
controller to operate the reburn system in an automatic,
load-following mode. Natural gas flow, at a predetermined percentage
of unit heat input, and recirculated flue gas flows are based on coal
flow demand input. The additional air flow is based on natural gas
flow with the final excess oxygen designed to be slightly lower than
the normal cyclone excess oxygen level.
The reburn system has been tied into the main boiler control system
for safety and control purposes. The natural gas reburn fuel controls
have been set up in a last-in-service/first-out-of-service logic. The
FGR system remains in service independent of the reburn natural gas,
except for loss of control power. All system dampers/valves fail shut
except for the natural gas vent valves which fail open. Flame
scanners are not used in conjunction with the UFIs since there is no
visible flame in the reburn zone.
The use of combustible gas measurement as a system safety input will
be evaluated with data that have been collected during parametric
testing. Operation of the reburn system has not required an increase
in operating personnel, an advantage from the utility's point of view.
INSTALLATION
The reburn system was installed with minimal disruption to normal
power plant operation. The four key phases of reburn system
installation involved: (1) procurement of material and delivery on
site, (2) pre-outage activities, (3) outage activities, and (4) post-
outage activities. A key consideration was the installation of all
direct boiler-related equipment/materials during the utility's normal
4-week boiler outage.
3-27
-------
Major items obtained during the procurement period included the UFI
and AA windboxes, their waterwall tube panel inserts, FGR fan,
recirculated flue gas and AA ductwork, and the control system. The
FGR fan and the control system represented those items requiring the
longest lead time at about 26 weeks.
Pre-outage work included demolition of the old FGR fan and associated
ductwork along with required asbestos abatement. The natural gas
pipeline was installed up to the point where it would connect to the
windboxes. Structural steel was reinforced in those areas where the
recirculated flue gas ductwork would be installed and some minor
revamping of access stairs and platforms was done to accommodate
installation of the new ductwork.
At the commencement of the boiler outage on May 21, 1990, boiler
casing and refractory, at the locations for the UFI and AA windboxes,
were removed exposing the straight sections of waterwall tubes which
would be cut out. Dimensions of waterwall sections removed to
accommodate the prefabricated UFI and AA tube panels were about 3 ft
wide by 15 ft. After welding in the tube panels, the windboxes were
welded to flanges provided as part of the tube panel structure, and
seal boxes were built around each windbox and tube panel to prevent
any furnace leakage (this is a pressurized furnace). Windboxes were
tied into the previously installed ductwork by the installation of
expansion joints which allowed for growth of the boiler versus the
stationary ductwork. The boiler was hydrostatically tested, followed
by the installation of refractory in the seal boxes and seal-welding
of all outer casing. Following an air pressure test to locate and
seal-weld any remaining furnace casing leaks, the boiler was fired up
(to allow for chemical cleaning and curing the refractory) and
returned to service on June 25, 1990.
CHECKOUT/START-UP
A key activity during the post-outage time frame was checkout and
start-up of the reburn system, the objective being to verify that all
components worked as designed. During the outage all mechanical and
electrical subsystems were verified to be operational. During system
start-up the various subsystem interactions and sequencing were
verified. Minor changes to the control system programming and
adjusting of the time delays based on actual device responses were
also completed. The gas reburn system was designed to operate in
either a reburn mode (natural gas being injected) or a non-reburn mode
(no natural gas being injected). In the non-reburn mode some minimal
amount of cooling FGR or air is needed to maintain the integrity of
the UFI and AA nozzles; minimal amounts of cooling FGR or air were
determined during the post-outage time frame.
Reburn system operation was initially simulated without the use of
natural gas to verify operation of the comprehensive control system
safety related permissives. Natural gas was injected in small
quantities for the first time on August 29, 1990. Full-load automatic
operation with 19% natural gas was achieved on September 21, 1990.
3-28
-------
PARAMETRIC TEST PROGRAM
OBJECTIVES AND SCOPE
The reburn system, as installed at Ohio Edison Niles Unit No. 1, by
design, incorporated a large amount of operational flexibility to be
able to examine and optimize reburning and boiler operations. The
primary objective of the parametric testing program was to determine
an operational mode which would result in low NO (not necessarily
lowest NO ) while minimizing other potentially detrimental effects on
boiler performance. These other effects included:
1. Minimizing other gaseous combustible and particulate emissions;
2. Minimizing fuel and auxiliary power costs;
3. Minimizing degradations in boiler performance (e.g., decreases in
boiler efficiency, use of reheat attemperator spray, or
excessive superheater or reheat steam or tube metal
temperatures).
A secondary objective of the parametric testing was to establish a
reburning data base which could be used to evaluate reburning for
other boilers.
During the parametric testing, approximately 150 test points were
completed to examine 13 existing boiler and reburn system operational
variables. The operational variables examined included:
Baseline Test Variables
t Cyclone Excess Air
• Cyclones in Service
t Boiler Load
Reburn Test Variables
• Reburn Zone
Natural Gas Flow
Flue Gas Recirculation Flow/Compartment Bias
UFI Tilt/Yaw
UFI Horizontal Bias
• Burnout Zone
Air Flow
AA Tilt/Yaw
AA and UFI Tilt Combination
Because of the large number of independent test variables, it was not
possible to examine every permutation and combination. The parametric
testing was set up and conducted to "step-through" the variables in a
decreasing priority sequence for each of the three key boiler "zones"
3-29
-------
(cyclones, reburn zone, and burnout zone). Initially, nominal
operating conditions were selected for each variable, then, once a
variable had been examined, it was reset to a "near optimum" condition
for subsequent tests. "Near optimum" conditions were selected based
on the test strategy previously described.
In addition, to ensure comparability of the results, many tests were
repeated as well as conducting tests examining a single variable on
the same day. This was necessary because, even though significant
effort was expended, it was difficult to replicate cyclone operating
conditions on a day-to-day basis. This difficulty and its
implications are further discussed in "Test Results."
During the parametric testing, a limited number of more comprehensive
tests were completed and were referred to as "maxi" tests. Maxi tests
were run at generator loads of 108 and 86 MWe (net) at baseline (100%
coal firing) and 18% natural gas reburn conditions utilizing the
reburn configuration found to represent an optimum during the
parametric investigations. Purposes of the "maxi" tests were to:
• Determine the effect of reburn system operation on the furnace
temperature entering the reburn zone and the convective pass.
• Assess the effect of reburning on the flue gas conditions entering
the electrostatic precipitator (ESP).
• Measure the size distribution and mass loading of the
particulates entering the ESP.
t Evaluate the effect of reburn on the collection efficiency of
the ESP.
BOILER PERFORMANCE AND EMISSIONS MONITORING SYSTEMS
During the parametric testing, in addition to normal control room
board data, most important boiler performance operational variables
were electronically recorded in a personal computer. These data
included flows, temperatures, and pressures for boiler water, steam,
air, and fuel .
Oxygen (02) concentrations of the flue gas leaving the four cyclones
were measured using the four existing water-cooled probes and
instrumentation. These probes are located on the rear wall near the
bottom of the secondary furnace with each of the probes
approximately lined up with one of the cyclone exhaust streams.
Gaseous emissions of NO , (L, CO, C0?, S0?, and THC (total
hydrocarbon) were measured at the bofler 5xit/air heater inlet via 10
sampling probes spaced across the boiler outlet duct. (See Figure 3.)
During testing samples were sequentially drawn from each of the 10
probes to be able to assess gaseous emissions profiles.
3-30
-------
ESP performance was assessed by particulate loading measurements
before and after; and particle size distribution and moisture content
were determined using EPA Method 5 isokinetic traverses of the ducting
using a cascade impactor. Flyash resistivity and dewpoint
measurements were made at the ESP inlet using a Wahlco resistivity
probe and a Land dewpoint probe, respectively. Flyash samples were
also taken at the ESP inlet duct test point using high volume sampling
techniques to ascertain carbon content. Boiler bottom ash was sampled
from the slag tanks below the wet-bottom slag taps.
Temperatures and velocities in the boiler were sampled with in-furnace
traverses using a water-cooled probe. Temperatures were measured
using a shielded high velocity suction pyrometer and velocities were
measured using a five-hole pitot tube. (Furnace velocity data have
not currently been analyzed and will be reported later.) The
in-furnace sampling on this pressurized furnace was limited to two
planes in the secondary furnace. Traverses of the first plane,
representing the inlet to the secondary furnace, were made using three
of the four ports that the plant has for measuring cyclone oxygen
levels. (The fourth port was not accessible.) Measurements made in
the second plane, at the secondary furnace outlet immediately below
the superheater surface, were carried out using an aspirated test port
located in one of the furnace sidewalls.
TEST RESULTS
General
Previous testing by others has shown that one of the key variables
affecting NO emissions was reburn zone stoichiometry (5,6,7,8,9,10).
Stoichiometry is defined as the ratio of actual air supplied compared
to the theoretical amount of air required to completely combust the
available fuel. It is important to understand the methodology used in
establishing this value. First, the oxygen content of the flue gas
effluent from each of the cyclones was measured to ascertain cyclone
stoichiometry. Second, the accurately measured reburn natural gas
flow rate was compared to a corrected boiler coal flow (corrected coal
flow was based on indicated coal flow, boiler efficiency, and plant
heat rate) to determine natural gas and coal fuel fractions on a heat
input basis. Third, the reburn zone stoichiometry was computed by
summing the mathematical products of the stoichiometry and fuel (heat
input) fractions for the cyclones and the reburn fuel flows.
While variations to cyclone excess oxygen level were evaluated and
documented, relative to its impact on NO , it is not a variable which
can be used to optimize NO emissions at this unit. Altering the
cyclone excess oxygen from the normal 2.0-2.5% 02 (10-13% excess air)
level for an extended period may have detrimental effects on cyclone
tube life or slag tapping if the oxygen level is lowered or raised,
respectively, beyond the normal range.
3-31
-------
The Ohio Edison Miles No. 1 unit was originally designed as a 125 MWe
(net) unit; however, except for short periods, it has operated at 108
MWe (net) for the past 30 years. There are several causes for this
derating including fan limitations early in the boiler history and
other more recent operational problems (principally, primary furnace
and cyclone tube wastage). Since the employment of reburning
essentially decreases the firing rate in the cyclones, and because
slag tapping is eventually affected as cyclone loading decreases, it
is important that the history of a unit be known if an application of
reburning is contemplated. Boiler derating, as is the case on the
subject boiler, and cyclone-firing configuration are two factors that
can affect the application of reburning technology.
NO emissions for the subject cyclone-fired boiler at 108 MWe (net)
averaged approximately 705 ppm (all NO emissions reported have been
corrected to a 3% excess 02 basis). Tnis emissions level was
representative of normal operation with a mean cyclone excess oxygen
level of 2.0-2.5% 02 (10.6-13.6% excess air). Slight variations in
individual cyclone operation resulted in day-to-day data scatter of
approximately +25 ppm.
Changing the cyclone excess oxygen level changed the NO emissions
slightly. For example, a 1% decrease in cyclone excess oxygen, from 3
to 2% 0-, decreased NO emissions by approximately 15 ppm.
Reducing the cyclone-firing rate also reduced NO emissions. At
86 MWe (net), a 20% decrease in boiler load, NO emissions under
normal operating conditions were approximately 630 ppm, a 75 ppm or
10% decrease in emissions from normal full load operation. At reduced
boiler load a similar trend of decreasing NO for decreasing cyclone
excess oxygen was seen. Baseline NO emissions results showing the
effects of boiler load and 0? are shown in Figure 4.
Carbon monoxide (CO) emissions in the baseline mode of operation were
typically very low, under 30 ppm. Baseline SO emissions varied
between 2400 and 2700 ppm due to slight variations in coal sulfur
content. Negligible THC gaseous emissions were observed during
baseline and reburn testing.
Coal Variability
The Eastern bituminous coal fired at the Niles plant arrives by truck
from approximately 15 supply mines located in the Ohio, Pennsylvania,
and West Virginia area. No one mine supplies more than about 10% of
the total coal supply used. Initially there was some concern that
coal variability at the Niles plant could add uncertainty to the
results and conclusions drawn from those results.
However, frequent samples and subsequent analysis of the coal have
shown the fuel composition to be very consistent. Table 1 presents a
composite coal analysis based on analysis of 21 coal samples. Some
statistical data showing the good consistency of the analyses are also
shown.
3-32
-------
TABLE 1
OHIO EDISON MILES UNIT NO. 1
Composite Coal Analysis As Received Basis
Proximate Analysis
Deviation
Average
Maximum
Value
Minimum
Value
Standard
31.
45.
11.
% Moisture (Total) 7.8 9.3 6.6
% Volatile Matter 32.2 33.7
% Fixed Carbon (By Difference) 47.3 49.3
% Ash 12.6 13.6
HHV Btu/lb 11576 11870 11277
Ib Ash/10 Btu 10.9 12.0 9.6
Ultimate Analysis
% Moisture 7.8 9.3 6.6
% Hydrogen 4.4 4.5 4.3
% Carbon 63.4 65.3 61.8
% Sulfur 3.3 4.1 3.0
% Nitrogen 1.4 1.5 1.3
% Oxygen (By Difference) 7.1 8.4 5.5
% Ash 12.6 13.6 11.4
Total 100.0
0.76
0.62
0.94
0.62
176
0.63
0.76
0.06
1.11
0.31
0.05
0.73
0.62
Based upon the consistency of the coal composition, coal variability
should have negligible effect on the test program results.
NO Emissions as Function of Key Variables
Reburn Zone Stoichiometry
As expected, it was found that some of the test variables had a
pronounced effect on NO emissions and other variables had little or
no effect on NO . Reburn zone stoichiometry was found to be the key
parameter affecting NO emissions. Figure 5 shows the relationship of
reburn zone stoichiometry with NO emissions. The reburn zone
stoichiometry was varied by adjusting either the reburn natural gas
flow rate or the cyclone excess air level. For the full-load tests
the reburn zone stoichiometry was varied from 0.88 to 1.06.
NO emissions were shown to be linearly related to reburn zone
stoichiometry (for the test range) and decreased by approximately 180
ppm per 0.10 (or 10%) decrease in reburn zone stoichiometry. For a
constant cyclone excess oxygen level an approximate 10% decrease in
reburn zone stoichiometry would result from a 9% increase in reburn
natural gas fuel fraction. For example, with the normal cyclone
excess oxygen level of 2.5% 0, (13.6% excess air), increasing the
reburn natural gas fuel fraction from 9 to 18% would result in a
decrease to the reburn zone stoichiometry from approximately 1.03 to
0.93 and decrease the NO emissions from approximately 480 to 300 ppm
(+25 ppm). X
3-33
-------
Reburn natural gas flow (Figure 6) presents the NO emissions data
versus the amount of reburn natural gas fired. Two interesting
results shown include: (1) the linearity of the NO reduction with
increasing natural gas flow for a given cyclone excess oxygen level;
and (2) for a given reburn zone stoichiometry, the NO emissions
results were similar regardless of whether the stoichTometry was
achieved by changing the reburn natural gas flow rate or by changing
the cyclone excess oxygen level.
Recirculated Flue Gas Flow
The purpose of flue gas recirculation (FGR) in the reburn system is to
assist in the penetration of the reburn fuel and promote mixing of the
reburn fuel with the bulk furnace gases without significantly
increasing the oxygen content or stoichiometry in the reburn zone as
would happen if air were used instead of FGR. Pilot scale research
(10) has also shown a small incremental NO reduction with increasing
levels of FGR. Figure 7 presents the results of tests where the FGR
flow rate was varied from approximately 3 to 11% of the total flue gas
flow. Both baseline (no natural gas) and 18% natural gas reburn test
series are shown. FGR had no effect on NO emissions with or without
reburning.
The lack of any effect of FGR on NO during the baseline tests was
likely due to: (1) coal combustion s being essentially completed (no
further nitrogen release); and (2) changes in thermal NO 's being not
measurably affected because of the relatively low thermaT dilution
created by introducing FGR (previously measured temperatures showed
approximately 2300-2400°F for the reburn zone inlet). For the reburn
tests, varying FGR had no effect on NO ; this was likely due to the
good mixing that occurred regardless of the FGR flow rate. Earlier
flow modelling (8) had shown that cyclone effluent gases tend to hug
the rear wall where the reburn jets were placed. The importance of
FGR flow is likely to be very unit specific; e.g., a large open
furnace where reburn fuel penetration is required.
After determining the sensitivity of NO reduction to FGR flow rate,
it was decided to operate at a reduced level (about 5%) with the FGR
fan inlet dampers nearly closed. This was advantageous since lower
levels of FGR minimized changes in boiler steam-side performance
(discussed later) and decreased auxiliary power usage. At the Niles
unit, safety requires the use of FGR.
Other Reburn System Variables
Somewhat surprisingly, NO emissions were essentially not affected by
the other reburn system operating variables including upper fuel
injector (UFI) tilt, yaw, or flow bias or additional air (AA) injector
tilt, yaw, or flow bias. It is interesting that burnout air (AA) did
not change NO emissions; and that NO has not reformed in the burnout
zone. This mSy be due to the cool furnace gas temperatures which do
not promote thermal NO formation or due to the lack of fuel bound
nitrogen in the reburn fuel.
3-34
-------
Boiler Load
Testing to establish the effect of boiler load on NO emissions was
completed during the parametric test. The partial load testing was
conducted at 86 MWe (net) since it represents the approximate load at
which the fourth cyclone is removed from (or placed into) service as
boiler load is decreased (increased) to ensure adequate slag liquidity
for removal from the furnace bottom. Also, the cyclone loading is
nearly equivalent for the 86 MWe (net) baseline non-reburn tests and
the 108 MWe (net) 18% natural gas reburn tests. Figure 8 compares the
NO emissions at these two loads as a function of reburn zone
stoichiometry. At the reduced load the NO values were lower for all
conditions. The decrease in NO emissions for a 10% change in reburn
stoichiometry at 86 MWe (net) was approximately 130 ppm compared to
the 180 ppm reduction rate observed for an equivalent change at full
load. However, because of lower baseline non-reburn NO levels the
percent NO reduction was nearly equivalent for the two test boiler
loads. x
Other Gaseous Emissions
NO emissions reduction was essentially linear with increasing natural
gas flow and did not significantly change with other reburn system
variables. The selection of an "optimum" natural gas flow to be used
during the forthcoming long-term tests will be based more on
minimizing other gaseous pollutants and changes in boiler performance.
During the shakedown period high levels of CO emissions were observed,
especially during high reburn fuel flow. These CO emissions were
subsequently decreased to typically below 100 ppm as the reburn system
operating variables were optimized. It was found that the vertical
tilt position of the UFIs and AAs were principal factors when high CO
emissions were observed. CO was minimized by downward tilting of both
the DPI and AA nozzles. A -17° (from horizontal) was selected as best
for the UFI nozzles and -10° for the AA nozzles (Figure 9). In
addition to lowering the average CO emission level a more uniform CO
and Op profile was generated across the boiler exit duct. This trend
can be seen by comparing Figures 10 and 11.
Higher CO emissions in the center of the duct were frequently observed
during the early testing and were probably due to unoptimized
additional air (AA) injector adjustments leading to insufficient
penetration and mixing. Variability in cyclone 0^ concentrations was
also a contributing factor. It was also observed that creation of a
tangential swirl in the furnace, by yawing the nozzles on one wall in
one direction and those on the other wall in the opposite direction,
further reduced CO emissions. The minimum exit CO resulted with the
UFI tilts at -17°, the AA tilts at -10°, and the AA yaw set up to
impart a clockwise swirl (viewed from above).
Emission of S02 decreased with increasing natural gas flow as
expected. On average the SO,, decrease was inversely proportional to
the reburn fuel flow; however, there was a significant amount of
scatter (+ 10%) due to coal sulfur variations. Gaseous THC emissions
were negligible for all tests.
3-35
-------
Boiler Thermal Performance
The main impact that reburning had on boiler thermal performance was a
shift in the heat absorption from the waterwalls to the convective
pass sections. The Miles unit does not have an economizer; therefore,
the increase in convective pass absorption was observed in the
superheater and reheater with slight increases to temperatures and
attemperator spray flows. The changes in boiler thermal performance
were due to:
1. Decreased cyclone loading with natural gas reburning in the
secondary furnace; and
2. FGR used with reburning to inject the natural gas.
Table 2 presents selected boiler thermal performance data for a
baseline (coal only) test and a nominal reburn test. These two tests
had equivalent boiler load and excess air at 115 MWe gross (108 MWe
net) and 15%, respectively. The reburn test had 17.2% natural gas
reburn fuel, on a heat input basis. For the boiler superheater, it
can be seen that the attemperator spray flow increased from 1.3 to
4.5% of main steam flow due to reburning. The primary superheater,
which is located prior to the attemperator, had a 20°F increase in
steam temperature at its outlet. The secondary superheater inlet,
which is just after the attemperator, was 15°F lower for reburning
(showing the higher spray flow). The final superheat steam
temperature was slightly higher for reburning.
The reheat steam section showed an attemperator spray flow of
approximately 3% of total reheat steam flow for reburning. This spray
flow represents leakage by the closed control valve when the block
valves were open. The final reheat steam temperature was also 12°F
higher with reburning which raised it to the design point of 1000°F-
The control dampers in the split boiler rear pass were set differently
for the baseline and reburn tests. For the baseline test the
superheat dampers were closed and the reheat dampers were open to
increase the flue gas flow and hence reheat steam temperature. For
the reburn test, the superheat dampers were open and the reheat
dampers were closed to limit the reheat absorption and attemperator
spray requirements. Note that the "closed" damper positions are still
approximately 20° open and still have a significant amount of flue gas
flow passing through them.
With reburning, boiler heat absorption in the waterwall decreased by
approximately 5% and convective section heat absorption increased by
approximately 5%. The decrease in waterwall absorption is due to
decreased cyclone loading. The increase in convective pass absorption
is due to increased gas temperatures (calculated to be 30°F at the
furnace outlet plane) and increased flue gas weight (due to FGR) with
reburning.
3-36
-------
Reheater absorption increased by only 4% while superheater absorption
increased by 6% due to the adjustment of the backpass flow control
dampers. Steam temperature profiles were also monitored during this
program. Thermocouples were installed on approximately every fourth
tube element at the primary and secondary superheater outlet headers.
Negligible changes were observed in primary or secondary superheat
profiles between baseline and reburn tests.
The boiler efficiency with natural gas reburning decreased by 0.7%.
Table 3 presents a breakdown of the efficiency and a comparison
between baseline and reburn. The primary reason was a 1% higher loss
due to a higher moisture in the flue gas in the reburn test due to the
higher hydrogen content of the natural gas versus the hydrogen content
in the coal. This loss was somewhat offset by a lower ash pit loss
and a lower carbon heat loss due to less coal being fired when
reburning.
Overall, the boiler performance did not change appreciably with
natural gas reburning. It was observed that, because of the lower
cyclone loading with reburning, it was necessary to monitor cyclone
excess oxygen levels more closely at reduced load to maintain slag
temperatures and viscosity for effective molten slag removal.
Carbon in Ash
Carbon loss in flyash was not significantly affected by reburning.
Flyash samples were taken and analyzed for approximately two-thirds of
the tests completed. Bottom ash samples were taken once per day.
Full-load flyash carbon levels of approximately 30-35% have typically
been shown with a range of 25-45% carbon in the flyash. The flyash
carbon level has been compared to reburn natural gas flow and cyclone
excess air, variables which may normally have correlated to flyash
carbon level, and no relationship was found. The bottom ash carbon
levels have typically been less than 1%. Thus for a 12.6% ash coal
and a baseline flyash/bottom ash ratio of 30:70, the baseline carbon
heat loss was approximately 1.2 to 1.4% and for reburning, with a
reduced coal flow and hence flyash loading, the carbon heat loss was
approximately 1.0 to 1.2%.
Reasons for the high unburned carbon under baseline and reburn
conditions are unclear. Possible causes include coal properties, coal
particle size distribution and cyclone aerodynamics (greater expulsion
of coal fines). During reduced load operation the average flyash
carbon content decreased to approximately 20% carbon in flyash. This
would be expected with more residence time, decreased cyclone loading,
and decreased expulsion of particulate from the cyclones.
Furnace Gas Temperatures
Reburn Zone Inlet Gas Temperature
Figures 12 and 13 show the results of the flue gas temperature
traverses that were made at the inlet to the reburn zone. The furnace
depth at the traverse locations was 13 ft and the maximum traverse
depth was physically limited to about 10 ft. At 108 MWe (net) the
3-37
-------
baseline average gas temperature was 120°F higher than with 18%
reburn. The tests at 86 MWe (net) showed a similar trend: the
baseline gas temperature averaged approximately 100°F higher than with
reburning. For both the baseline and reburn tests there was a 200 to
300°F decrease in flue gas temperature from the rear wall to the
division wall. The temperature profiles for baseline and reburn at 86
MWe paralleled one another while the baseline and reburn temperatures
at 108 MWe showed that they were considerably different near the back
wall but began to approach the same value as the probe was moved
towards its maximum insertion depth. Comparison of the average
temperatures and profiles measured during the 108 MWe reburn test with
the 86 MWe baseline test show very similar results. Note that with
18% reburn at 108 MWe, the coal loading to the cyclones is only
slightly higher than at 86 MWe with 100% coal. Therefore, it would
not be unusual for the average reburn zone inlet temperatures from
these two configurations to be the same.
Furnace Outlet
Figure 14 shows the results of the temperature traverses at the
furnace outlet plane. The traverse depth represents approximately one
third of the boiler width. The furnace outlet temperature with reburn
averaged 130°F higher at 108 MWe than the base case; i.e., 100% coal.
At 86 MWe the average temperature with 18% reburn was about 65°F lower
than the baseline temperature. This difference, though generally
corroborated by the boiler thermal performance evaluation, is not
fully understood and will be examined along with other data that have
not currently been analyzed.
Electrostatic Precipitator Performance
Electrostatic precipitators (ESPs) replaced mechanical collectors in
the early 1980s to improve particulate collection efficiency. The ESP
was si^ed quite liberally with a specific collection area (SCA) of
278 ft /ACFM; it is normally operated with only three of its five
fields energized, and operated in this mode an opacity of 2.5% was
routinely achieved during parametric testing involving both baseline
and reburn testing.
ESP collection efficiency was determined by sampling at the inlet to
the ESP and in the stack using EPA Method 5. Ammonia injection is
used to control acid smut emissions at the unit; the ammonia injection
point is upstream of the ESP inlet sampling port. No attempt was made
to optimize the ammonia injection operation to account for changes in
flue gas composition (such as S03) during reburn system operation.
Results of particulate sampling the stack showed that particulate
loading increased with reburn compared to baseline for both full load
and partial load cases primarily as a result of the flue gas
conditioning ammonia injection. At 108 MWe the particulate loading
was 0.032 lb/10 Btu for 100% coal firing and 0.043 lb/106Btu for the
reburn case where 18% natural gas was used, on a total heat input
basis. The trend was the same for the partial load test (86 MWe),
where6100% coal firing gave 0.022 lb/10 Btu compared with 0.027
lb/10 Btu
3-38
-------
when 18% natural gas was used in the reburn test. Despite the small
increase in particulate loading in the reburnfitests the actual
particul'ate loadings of 0.043 and 0.027 lb/10 Btu for the full load
and partial load reburn casesg respectively, are well below the
regulating limit of 0.1 lb/10 Btu. Duplicating the 100% coal firing
particulate loading levels leaving the stack should be feasible by
optimizing the flue gas conditioning system (ammonia injection).
Flyash resistivity ranged,from approximately 10 to 10 ohm-cm for
reburning and 10 to 10 ohm-cm for 100% coal firing over a load
range from 86 to 108 MWe. This change was due to less than optimal
SO, levels with reburning due to ammonia conditioning. The net
effect of a lower inlet loading with the higher flyash resistivity
resulted in a reduction in ESP efficiency. ESP efficiency at full
load was 99.3% with 100% coal and 98.0% with 18% reburning. This
trend was similar at partial load.
At the inlet to the ESP particle size distribution (PSD) tests were
conducted and it was found that PSD was a function of cyclone loading.
Full load PSD test results are shown in Figure 15. The bulk of the
particulate is above 10 micrometer diameter in size. There is a
significant decrease in the amount of particulate above 8 micrometer
diameter when reburning was used during full load tests. The size
distribution results shown in Figure 15 reflect the impact that
reducing the cyclone coal-loading has on lowering the amount of
particulate carryover.
The testing at 86 MWe (Figure 16) shows that between the 5 to 10
micrometer particle diameter size range there was an increase of
particulates as a result of reburn. Above 10 micrometer there was
virtually no change in particulates. The coal loading to the cyclones
is sufficiently low that further reductions in cyclone loading (i.e.,
reburning at partial load) do not impact particle carryover and PSD.
Note that the 108 MWe reburn test and the 86 MWe baseline tests have
nearly identical cyclone firing conditions (coal flow and excess Op)
and very similar particle size distributions.
ASH DEPOSITION IN THE SECONDARY FURNACE
Observations of the secondary furnace, particularly the back wall,
during the 6 months following installation of the reburn system
indicated a greater buildup of ash deposits than had previously been
seen. Following shutdown of the boiler during the planned year-end
outage in December 1990, the presence of thicker ash deposits on the
back wall of the secondary furnace was verified.
The presence of the thicker deposits did not affect operation of the
reburn system insofar as NO reduction is concerned and did not appear
to affect boiler thermal performance. However, due to the short
duration of boiler operation with the reburn system in place, the
effect of deposition on boiler thermal performance is not conclusive.
3-39
-------
It has been estimated that the reburn system was operated with natural
gas only about 20% of the time from June 25 to the late December 1990
outage. Boiler deslagging was completed during the year-end 1990
outage; one month later it was observed that thicker ash deposits
again resulted with absolutely no natural gas having been injected.
Given that the sister unit at Miles Station (Unit No. 2) burns the
same coal under the same conditions of load and excess air as No. 1,
it can be reasonably concluded that heavier ash is depositing under
the non-operational mode of the reburn system; i.e., with nozzle
cooling flue gas only. This is not to say that heavier ash would not
have also deposited if the reburn system was in operation, although
some arguments can be made to suggest that deposits in the reburn zone
might well be thinner during reburn system operation.
Although the root cause of the heavier ash deposition has not been
firmly established at this time, it has been hypothesized that the
heavier ash deposition on the back wall of the secondary furnace is
being caused primarily by the recirculated flue gas forming a cooler
boundary layer along the back wall; other contributing factors could
also be the particulate in the recirculated flue gas and the new studs
that have been installed on each of the five new panels on the back
wall. A plan is being formulated to confirm or refute the hypothesis
after which a solution will be determined.
SUMMARY
A reburn system was installed by the end of June 1990 on Unit No. 1 at
Ohio Edison's Miles Station. Following system shakedown, parametric
testing was carried out during the last 2\ months of 1990. Key
findings from a preliminary review of the data collected are as
follows:
• NO reductions ranged from 30 to 70% during parametric
testing.
i NO reductions in the 50 to 60% range are possible with
acceptable boiler operation and CO emissions.
0 Waterwall heat absorption decreased by approximately 5% and
convective pass heat absorption increased by 5% with 18%
natural gas reburning.
• Boiler efficiency decreased by 0.6% with 18% natural gas
reburning due principally to higher latent heat of vaporization
losses because of fuel moisture formation.
• Furnace outlet gas temperature increased slightly with reburning
(0°F change to 130°F) increase at various boiler loads and
conditions.
c ESP collection efficiency was lowered slightly with the reburn
system in operation due to lower ESP inlet loading with similar
outlet loading and a non-optimized flue gas conditioning system.
3-40
-------
• Thicker ash deposits have formed on the secondary furnace back
wall since reburn system installation.
The unit is currently being operated in a baseline mode, the primary
purpose of which is to collect tube wastage data. Following a planned
mid-year outage the unit will be operated continuously in a reburn
mode for 6 months, nominally ending in February 1992.
3-41
-------
ACKNOWLEDGEMENTS
The Natural Gas Cyclone-Fired Reburn Demonstration program is
sponsored by a number of organizations with significant contributions
by many participating organizations. The authors would like to
gratefully acknowledge the high levels of cooperation, excellent
technical advice, and support in a number of specific areas from the
following people.
Ohio Edison:
J. Dulovich
S. Brown
R. Bolli
R. Rook
Plant Operators
EPA:
J. Ford
Energy Systems Associates:
B. Breen
G. Dusatko
J. Bionda
R. Glickert
Physical Sciences Inc., Technology:
S. Johnson
Research Triangle Institute:
G. Tatsch
North Carolina State University:
L. Stefanski
University of North Carolina:
R. Ledbetter
ABB Combustion Engineering:
A. Kwasnik
R. LaFlesh
P. Jennings
A. Ingui
3-42
-------
REFERENCES
1. R. I. Bruck, (1987), "Decline of Boreal Montane Forest Ecosystems
in Central Europe and the Eastern North America Links to Air
Pollution and the Deposition of Nitrogen Compounds," Proceedings:
1987 Joint Symposium on Stationary Source Combustion NO Control,
Volume 1, EPA-600/9-88-026a (NTIS PB89-139695). x
2. C. Hakkarinen, (1987), "An Overview of Environmental Issues
Related to Nitrogen Oxides in the Atmosphere," Proceedings: 1987
Joint Symposium on Stationary Source Combustion NO Control,
Volume 1, EPA-600/9-88-026a (NTIS PB89-139695). x
3. A. H. Johnson, T. G. Siccama, (1983), "Acid Deposition and Forest
Decline," Environmental Science Technology, 17:294a-305a.
4. J. Kramlich, T. Lester, J. Wendt, (1987), "Mechanisms of Fixed
Nitrogen Reduction in Pulverized Coal Flames," Proceedings: 1987
Joint Symposium on Stationary Combustion NO Control, Volume 2,
EPA-600/9-88-026b (NTIS PB89-139703). x
5. C. Kruger, G. Haussmann, S. Krewson, (1987), "The Interplay
Between Chemistry and Fluid Mechanics in the Oxidation of Fuel
Nitrogen from Pulverized Coal," Proceedings: 1987 Joint Symposium
on Stationary Source Combustion NO Control, Volume 2,
EPA-600/9-88-026b (NTIS PB89-139703).
6. M. Toqan, et al., (1987), "Reduction of NO by Fuel Staging,"
Proceedings: 1987 Joint Symposium on
Stationary Source Combustion NO Control, Volume 2,
EPA-600/9-88-026b (NTIS PB89-139703).
7. J. Freihaut, W. Proscia, D. Seery, (1987), "Fuel Bound Nitrogen
Evolution During the Devolatilization and Pyrolysis of Coals of
Varying Rank," Proceedings: 1987 Joint Symposium on Stationary
Source Combustion NO Control, Volume 2, EPA-600/9-88-026b (NTIS
PB89-139703). X
8. R. W. Borio, et al., (1989), "Application of Reburning to a
Cyclone Fired Boiler," Proceedings: 1989 Joint Symposium on
Stationary Combustion NO Control, San Francisco, CA, Volume 1,
EPA-600/9-89-062a (NTIS PB89-220529).
9. Y. Takahashi, et al., (1982). "Development of 'MACT' In-Furnace
NO Removal Process for Steam Generators," Proceedings of the
19&2 Joint Symposium on Stationary Combustion NO Control, Volume
1, EPA-600/9-85-022a (NTIS PB85-235604). x
10. H. Farzan, et al., (1989), "Pilot Evaluation of Reburning for
Cyclone Boiler NO Control," Proceedings: 1989 Joint Symposium on
Stationary Combustion NO Control," San Francisco, CA, Volume 1,
EPA-600/9-89-062a (NTIS PB89-220529).
3-43
-------
UNIT CONVERSION TABLE
To Convert From
British Thermal Units
British Thermal Units/
Hour/Square Feet
British Thermal Units/Pound
Degrees Fahrenheit
Feet
Inches
Pounds/Square Inch
Pounds/100 British
Thermal Units
PPM at 3% 0,,
PPM at 3% 0,
Square Feet/(Actual
Cubic Feet/Minute)
To
Joules
Watts/Square Meter
Joules/Kilogram
Degrees Celsius
Meters
Centimeters
Kilograms/Square
Centimeter
Kilograms/Joule
Milligrams/Cubic Meter
at 6% 02
Pounds/106 British
Thermal Units *
Multiply By
9.478xlO"4
0.3171
2.326xl03
(T-32J/1.8
0.3048
2.54
14.223
2.326xl03
1.70
1.306x10
-3
Square Meter/ 0.305
(Actual Cubic Meter/Minute)
* This conversion factor is based on composite fuel analysis with 18%, natural
gas reburn fuel and 82% coal. For different fuel fractions different conversion
factors would be required.
3-44
-------
Table 2: Ohio Edison Miles Unit No. 1,
Boiler Performance Data
Net Load (MWe)
Fuel Type (%)
Coal
Natural Gas
Excess Oxygen (Air) (%)
Flue Gas Recirculation (%)
Flows (Ib/hr)
Main Steam
Superheat Spray
Reheat Spray
Temperatures (°F)
Feedwater
Primary Superheater Outlet
Secondary Superheater Inlet
Secondary Superheater Outlet
Reheat Inlet
Reheat Outlet
Flue Gas-Air Heater Inlet
Flue Gas-Air Heater Outlet
Air-Air Heater Inlet
Air-Air Heater Outlet
Heal Absorption (106 Btu/hr)
Primary Superheater
Secondary Superheater
Reheater
Waterwalls
Baseline
108
100
0
2.8(15.0)
,) 1.3
845,200
10,260
0
483
et 736
ilet 718
)utlet 997
682
988
680
5t 251
120
575
u/hr)
124.5
160.7
123.2
590.3
Reburn
108
82.8
17.2
2.7(14.2)
4.5
843,700
37,760
2,320
484
758
703
1000
685
1000
685
250
118
581
132.6
170.7
127.9
563.0
Table 3: Ohio Edison Niles Unit No. 1,
Boiler Efficiency
PERCENT COAL
PERCENT NATURAL GAS
HEAT LOSSES (PERCENT)
DRY GAS LOSS
MOISTURE IN FUEL LOSS
MOISTURE IN AIR LOSS
RADIATION LOSS
ASH PIT LOSS
HEAT IN FLYASH LOSS
PYRITE REJECTION LOSS
CARBON LOSS
TOTAL LOSSES %
EFFICIENCY %
BASELINE
100
0
REBURN
82.8
17.2
2.70
4.35
0.06
0.24
0.54
0.01
0.00
1.39
9.29
90.71
2.66
5.34
0.06
0.24
0.44
0.01
0.00
1.15
9.90
90 10
3-45
-------
1987 1988
1989 1990 1991 1992
TASK NO. TASK TITLE || |
1 TECHNOLOGY REVIEW BBBHi
2 BASELINE CHARACTERIZATION TESTS
3 REBURN SYSTEM DESIGN ••••
4 SYSTEM FABRICATION / INSTALLATION / STARTUP
5 PARAMETRIC GAS REBURN AND BASELINE TEST
6 LONG TERM PERFORMANCE TEST
7 PERFORMANCE ANALYSIS ,' TECHNOLOGY TRANSFER
8 SITE RESTORATION (OPTIONAL)
I I
•
...
A
••1
m
I I I I I I
™
mmm
I I I I I I I
••«
B
BB
c
III III I
..^
D
•••
••••••••
M I II
•
E
•
—
SIGNIFICANT EVENT KEV
A HWnt datn for rctxjrn system design tesl program @ Miles (2/24/88-3/11/88)
R Outage to install rebum system / UT mapping (5/20/90-6/19/90)
C Outaue twUT mapping (12/P6/90 1/3/91)
D Outage tor UT mapping (Date to coincide with planned annual outage)
E Oulagefar UTmappIng (12/26/91-1/5/92)
Figure 1: Overall Project Scope and Schedule of Gas
Reburn Project at Ohio Edison Miles Unit 1
Figure 2: Upper Fuel Injector Windboxes
3-46
-------
SUPERHEAT/REHEAT
CONVECTIVE PASSES
CBS '
RECIRCULflTIOH
FHH
Figure 3: Boiler Exit Gaseous Emissions Sample Matrix
•O MO
I
*
8
A 86 MWe Net
a 108 MWe Net
CYCLONE 02,%
o No Natural Gas
a 10% Natural Gas
a 14% Natural Gas
+ 18% Natural Gas
O.DO 0.65 0.90 0.95 1.00 1.05 1.10 1.16 1.20
REBURN ZONE STOICHIOMETRY
Figure 4: Baseline NOx Versus Cyclone O2
108 MWe and 86 MWe Net
Figure 5: NOx Versus Reburn Zone Stoichiometry at
Various Gas Flow Rates
108 MWe, 10%FGR
3-47
-------
a1.5-2.0CydoneO2
02.0-2.5 Cyclone Oz
& 2.5-3.0 Cyclone Oz
NATURAL GAS FLOW,%
Figure 6: NOx Versus Cyclone O2 at Various
Gas Fbw Rales
108MWe, 10% FOR
800-
TOQ-
£ »-
o.
<•> 400-
1 «-
200-
100-
a Baseline
n 18% Natural Gas
|
4 6 8 10 12 14
FLUE GAS RECIRCULATION FLOW,%
Figure 7: NOx Versus Percent Flue Gas Recirculation
(FGR)
IDS MW» Met
o No Natural Gas
a 10% Natural Gas
+ 14% Natural Gas
a 18% Natural Gas
86 MW« Net
• No Natural Gas
• 9 4% Natural Gas
• 183% Natural Gas
o.e i.o 1.1 1.2
REBURN ZONE STOICHIOMETRY
Figure 8: NOx Versus Reburn Zone Stochiometry at
Various Gas Flow Rates
108 MWe and 86 MWe Loads
1000O-
1000-
0.
0
o
100-
-3
° UFITilt@-17°
0 UFITilt@0°
A UFITilt@-25°
^^_ —•*-
^-~_ _D____^^-^^<^
^-^___ __^-—~-^~^
D
0 -20 -10 0 10 20 30
ADDITIONAL AIR VERTICAL TILT,degree8 from horizontal
Figure 9: CO Versus Additional Air Tilt at Several Upper
Fuel Injector Tilts
108 MWe Net, 5% FGR, 17.5% Natural Gas
o
o
CO, ppm
Flgur* 3 «how*
0 mtmple location
DISTANCE FROM DUCT RIGHT SIDEWALL.ft
Figure 10: 02 and CO Versus Boiler Exit Duct Sample
Location
Non-Optimized Operation
17.1 % Natural CM
2.B* Cyolon* 07
-17" UFl Tilt
-10° AA TIH
Clockwtaa AA Yaw
- CO, ppm
Ffgur« 3 ahowt
o •ampla location
I 3 « 9 12 1$ 18 21 24 27 30 33 38
DISTANCE FROM DUCT RIGHT SIDEWALL.ft
Figure 11: O2 and CO Versus Boiler Exit Duct Sample
Location
Optimized Operation
3-48
-------
3000
2800
°o 2600
1
E 2400
CD
1-
2200
2000
CYCLONE A CYCLONE C CYCLONE D
\
\ "^~\ Baseline
... \ . \ \ 0
'" \ ^
Baseline
Reburn
246810 246810 246810
Distance from Rear Wall, ft
2600
u_
°v 2400
13
E 2200
1—
2000
1800
CYCLONE A CYCLONE C CYCLONE D
. \ x\ TT\
'"~~-- ~Xv-- x\
\
Reburn
246810 2468 10 246810
Distance from Rear Wall, ft
Figure 12: Flue Gas Temperatures
Reburn Zone Inlet (108 MWe Net)
Figure 13: Flue Gas Temperatures
Reburn Zone Inlet (86 MWe Net)
opnn,
C.C.\)\J
2100
2000
,, 1900
5-
8" 1800
3
$
1 1600
1500
1400
1300
1 200
108 MWe Net 86 MWe Net
/ ""•"'
,/ ^
' / ~~ / ^
,' / s — / '
/ 1
/ I . •'
f
1
Baseline
Reburn
,
2 4 6 8 10 12 2 4 6 8 10 12
Distance from Left Side Wall, ft
E 15
3 14
? 13
° 12
f- 11
a 10
0)
E 9
D 8
o _
i e
1 5
1 3
% 2
« ,
"E 1
•
r\
\
A
i \\
o 1 00% Coal I i VA
& 18% Reburn 1 I \
I i \
/\< \
^0, ^Ck •
1
0)
3j
g
to
1
LLJ
15
14
13
12
11
10
9
8
7
5
4
3
2
1
Q
f\
o1 00% Coal I \
\
a 18% Reburn A \
/ i \
t^'' / \M,,
0.01 0.10 1.00 10.00 100.00
Aerodynamic Diameter, IJ/TI
Figure 16: Particle Size Distribution
(86 MWe Net)
3-49
-------
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. L. King
Babcock Energy Limited
Porterfield Road
Renfrew, PA4 8DJ, Scotland
J. Macphail Babcock Energy Limited
Technology Centre
High Street
Renfrew PA4 8UW, Scotland
-------
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.L. King
Babcock Energy Limited
Porterfield Road
Renfrew, PA4 8DJ, Scotland.
J. Macphail
Babcock Energy Limited
Technology Centre
High Street
Renfrew, PA4 8UW, Scotland.
ABSTRACT
In June 1987 after two years of development, sixty 37 MW(t) Mark I Low NOx Axial
Swirl Burners were retrofitted to Drax Unit 6. This is a highly rated opposed
wall pulverised fuel fired boiler, firing a typical UK bituminous coal. Baseline
preconversion NOx levels were 830 ppm at 3% 0 . Subsequent to the retrofit, NOx
reductions of 25 to 30% were achieved, but could not be maintained due to ash
deposits local to the burner quarl interfering with the desired near burner
aerodynamic flow pattern. A detailed investigation on the plant, using on line in
furnace video probing led to modification of the throat refractory arrangement, a
modification which resulted in deposit elimination.
After testing and demonstration at full scale in the Babcock Energy Large Scale
Test Facility an improved burner design was retrofitted to Drax Unit 6. NOx
levels in the range 350 to 390 ppm at 3% 0 have been achieved, a reduction of
over 50%, with no significant change in the overall boiler efficiency. Quarl
slagging has been eliminated on Unit 6 and plans are in hand to retrofit further
burners at Drax in 1991/92.
In addition to describing the results and experience obtained on Drax Unit 6,
results are also presented for a 48 MW(t) Low NOx Axial Swirl Burner fired in the
Babcock Energy Large Scale Test Facility with a range of coals which represent the
extremes of NOx related bituminous coal properties traded on a world wide basis
for utility boilers.
3-53
-------
INTRODUCTION
In the mid 1980's the then CEGB initiated a series of three year trials on
operating boilers to establish the NOx reduction that could be achieved by
combustion modification, the effect on boiler operation of these modifications and
any increased operating costs that might result. Drax with 6 off 660 MW opposed
wall fired boilers of similar design represented both a major proportion of the
coal fired generation capacity and had a size of burner (37 MW(t)) which had
application to other boilers. In June 1987, during a planned outage, Drax Unit 6
was retrofitted with 60 off Babcock Energy Mark I Low NOx Axial Swirl Burners,
which had been developed by Babcock Energy during 1985 and 1986. Prior to the
retrofit in March 1987, the performance and NOx output of the unmodified plant was
determined in a 'preconversion' test, the condition of the unmodified plant being
judged to be similar to that of a boiler returned to service after overhaul as
less than 6000 hours of operation had been accumulated. Subsequent to the
retrofit, a further series of characterisation trials were to be performed to
determine the efficiency of the conversion.
PLANT DESCRIPTION
There are six 660 MW(e) units at Drax Power Station. The boilers are of Babcock
Energy design, Units 1 to 3 being ordered in 1966, with Units 4 to 6, which are
essentially of similar design, being ordered in 1978. Operational experience with
all six units now covers over 400,000 hours service. The boilers operate at a
superheater outlet pressure of 165.5 bar, and 568 C steam temperature. The
furnace design is very highly rated, being designed for maximum combustion
efficiency, having a burner belt heat release rate of 1.6 MW/m The furnace
chamber of each boiler is divided by a partial central division wall, which cannot
be sootblown. Thirty standard Babcock Energy circular turbulent burners, supplied
by five mill groups are arranged in five horizontal rows on the furnace front
wall, and thirty on the furnace rear wall. Each burner row is fed from one mill,
there being 10 Babcock Energy 10E vertical spindle mills in total. The full
specified range of coals can be covered at MCR with nine mills; for the typical
design coal MCR can be achieved with 7 or 8 mills in service. (See Table 1 for
the original plant fuel specification).
Air supply to each mill group of burners is controlled by individual dampers to
each windbox/mill group. Each burner has a central oil lightup burner, of Spectus
tip shut off design on Units 4, 5 and 6, and of Babcock Energy Y-jet design on
Units 1, 2 and 3. An integral core air fan to provide stoichiometric combustion
air for the oil burners is installed on Units 4, 5 and 6. The oil burner is rated
at 0.25 kg/sec of Class 'G' residual fuel oil, (equivalent to 20% of the total
boiler heat input) and is used for boiler warm up and coal ignition/stabilisation
duties.
Preconversion NOx levels at 100% boiler load are summarised in Figure 1. In all
cases, NOx is stated corrected to 3% 0 dry at the ID fan outlet. At 3% 0 at the
economiser outlet, total NOx emission levels were 832 ppm with the eight top mills
firing, and 747 ppm with the eight bottom mills firing. Combustion efficiency
loss was typically 0.3 to 0.4% GCV, which corresponds to approximately 1% carbon
in ash. Fuel characteristics associated with the preconversion test, which are
typical of the fuel normally fired at Drax, are presented in Table 2.
3-54
-------
LOW NOx BURNER DESIGN
Initial Development
The initial development of the Low NOx Axial Swirl Burner has been presented
elsewhere (1) but in summary the programme involved development at 12 MW scale,
followed by the installation of two 37 MW(t) burners in a 500 MW front wall fired
plant. The process performance of these burners was assessed by using inflame
probing technigues, and the burner mechanical integrity was also demonstrated.
Mark I Low NOx Axial Swirl Burner Design Features
In the Low NOx Axial Swirl Burner, the combustion is staged within the burner, all
the combustion air being passed through the burner throat opening, and the mixing
of the combustion air with the fuel being controlled by burner aerodynamics. The
Mark I burner has the following features, Figure 2:-
i) A light up oil burner with an integral combustion air (referred to
as core air) supply. The light up burner, which is used for
furnace heating up and low load support for the coal flame, has a
heat input of 20% of the main coal burner. The air supply for the
oil light up burner is supplied from a core air fan mounted on the
windbox end of the core air tube, sufficient air being supplied
for near stoichiometric combustion of the oil. This approach
ensures excellent oil light up capability and improved control of
the oil flame under cold furnace conditions. Under coal firing
conditions, there is no reguirement for the core air fan to be in
operation.
ii) Pulverised fuel enters the burner through an elbow and then
passes through an annular pulverised fuel pipe, surrounding the
core air tube. The elbow is designed so as to decelerate the flow
entering it, the deceleration resulting in a redistribution of the
pulverised fuel. Subsequently, as it exits the elbow, the
pulverised fuel is re-entrained uniformly into the pulverised fuel
pipe. The fuel elbow is lined with a wear resistant chromium iron.
iii) The combustion air is subdivided into two streams, referred to as
secondary and tertiary air, the secondary air flow being controlled
by a secondary air damper. A swirling motion is applied to the
secondary air stream by an axial swirl generator, Figure 3. This
is a more efficient swirl generation process than the conventional
radial swirl generator, and mechanically less complex. The level
of swirl imparted to the secondary air stream is controlled by the
axial position of the swirl generator in the conical section of the
secondary air barrel.
Minimum swirl is obtained with the secondary air swirl generator
retracted out of the conical section, a proportion of the air
bypassing the swirl generator. Maximum swirl is obtained with the
swirl generator fully inserted into the conical section, thereby
allowing no air bypass.
3-55
-------
The tertiary air stream is subdivided into four distinct streams
by the use of 'splitters' in the tertiary air annulus. No
swirling motion is applied to the tertiary air.
iv) Due to the high incident heat fluxes on the burner (greater
than 500 kW/m ), burner components nearest the furnace are
manufactured from heat resisting material.
v) Two flame monitors are fitted, one for the oil light up burner
flame and one for the coal flame. Both monitors are of the
Babcock dual signal type.
Retrofit Requirements
The Mark I burner was installed in Drax Unit 6 with the minimum of retrofit
modifications. No modifications were made to the windbox or pf pipework
positions, and the existing flame monitors were reused, as was the oil light up
burner assembly. Modifications were necessary to the burner throat profile to
allow the slightly larger throat diameter of the Low NOx burner to be
accommodated. These modifications did not involve any tube alterations, the
refractory tiles which are used to form the throat opening being reduced in
thickness. The burners were supplied from the Babcock Renfrew Manufacturing
facility fully assembled, Figure 4, to enable ready insertion into the appropriate
windbox, and were retrofitted to the boiler during a 35 day outage in June 1987.
MARK I LOW NOx AXIAL SWIRL BURNER PLANT RESULTS
NOx Emission Levels
Following installation of the Mark I burners during a period of routine operation
set aside to allow the burners to be optimised, overall NOx reduction levels of
some 25 to 30% were recorded. However these readings were not maintained and with
time NOx levels gradually rose and stabilised at a level some 10 to 15% below the
preconversion value. Alteration of burner settings had no significant effect on
the NOx levels being obtained. A rapid boiler shutdown led to significant ash
deposits being shed from the furnace chamber, as judged by the amount of bottom
ash to be cleared. On return to load, a NOx reduction of some 25 to 30% was
achieved, but then subsequently stabilised over a period of days to a level 10 to
15% below the preconversion level.
Relationship between NOx Levels and Burner/Ash Deposit Accumulation
The foregoing observations indicated that a reasonable level of NOx reduction was
achieved when the boiler was free of deposit accumulation, and that the burner NOx
reduction apparently fell away after a period of boiler operation. It was not
clear at this stage as to whether the increase in NOx levels was due to an
increase in thermal NOx as the furnace chamber became progressively dirtier, or
due to the effect of deposits on burner operation and in particular interference
with the desired near burner aerodynamic flow patterns.
3-56
-------
Figure 5 is a photograph of a typical deposit pattern in the burner belt area
immediately after the unit came off load. Whilst the deposits are probably of no
greater magnitude than those associated with the standard circular burner, the
topographic structure of the deposit is different. The structure associated with
the low NOx burner illustrates a clover leaf type pattern, as compared to the more
conical frustum pattern associated with the standard circular burner. Closer
examination shows that the indentations in the clover leaf pattern associated with
the low NOx burner correspond to the location of the tertiary air splitters.
Simulation of these deposits on a 12 MW test burner indicated that the extent of
the deposit was sufficient to interfere with the near burner aerodynamics, and
significantly to increase NOx levels.
Quarl Deposit Mechanisms
In order to provide a better understanding of the mechanism of quarl deposition, a
water cooled video probe developed by the CEGB was used (2). The probe was
extremely useful in being able to identify the various mechanisms involved in
quarl slagging as they occurred. These mechanisms can be summarised as follows:-
i) Partially sintered ash particles, up to 25 mm in size, which had
initially been deposited on the upper furnace walls, roll slowly
down the furnace wall, the aggregates maintaining their basic
shape and form as they roll down the wall.
ii) When the aggregate encounters a refractory region (e.g. the
front face of a refractory throat tile) its motion is arrested
and the aggregate adheres to the refractory surface.
iii) Deposit build up continues in all directions with successive
aggregates adhering both to the refractory surface and to other
already adhered aggregates.
iv) As the deposit build up increases in size then the deposit
surface becomes progressively more molten and fused, and in
addition to attracting aggregates the deposit grows further due
to the collection of airborne ash from the furnace chamber.
Build up of deposit generally occurred more rapidly on out of
service burners.
v) The aerodynamic effects of the tertiary air splitters
result in ash being drawn back into the divergent section
of the burner, producing the typical clover leaf pattern.
To overcome the deposition on the tile face, the quarl tube assembly on 4 burners
was modified to replace the tile face with a furnace tube, so that there was
minimal refractory surface available for ash adhesion. Subsequent operation
showed that the modified quarls remained free from deposits, with major reductions
in the extent of 'eyebrow' deposition.
3-57
-------
There was however a tendency for ash to build up downstream of the tertiary air
splitters, even after additional ventilation of the splitters was introduced. It
was therefore concluded that:-
i) Quarl deposit formation could be virtually eliminated by
attention to the detail of quarl design.
ii) Whilst the principle of the tertiary air splitter design was
satisfactory, their application in a high temperature coal ash
situation was unacceptable and an alternative approach was
necessary.
Consequently an alternative burner design was developed and tested on the Babcock
Energy Large Scale Test Facility at Renfrew, prior to modification of the Mark I
burners in Drax Unit 6.
MARK III LOW NOx AXIAL SWIRL BURNER
Burner Development
The development of the Mark III burner design has been fully described elsewhere
(1), the final Mark III design, Figure 6, evolving through an intermediate Mark II
design. The Mark II design differed from the Mark I design in that:-
i) Tertiary air swirl was introduced to provide improved
aerodynamic characteristics compared to the aerodynamic effect
of the tertiary air splitters.
ii) Controlled fuel distribution within the burner was introduced,
as a result of further development testing at 12 MW (1).
Concern over the scaling criteria of several processes simultaneously from the
12 MW test burner to the 40 MW plant burner led Babcock Energy to invest in a
Large Scale Test Facility in Renfrew (Figures 7 and 8). Prior to demonstrating
the Mark II burner in the Test Facility, the facility was calibrated using a
standard circular turbulent burner. The coal quality and fineness was similar to
that used in the Drax Unit 6 preconversion tests. The results from the circular
turbulent burner are presented in Figure 9, together with the results from the
Mark II design and an improved Mark III design. The Mark III design differed from
the Mark II design in that the position of the ends of the burner tubes were
optimised, and means were introduced to improve the fuel ignition characteristics.
At 3% operating 0 , NOx emissions are reduced from 722 ppm to 300 ppm, an overall
reduction of 58%. The Mark III burner NOx emission levels correspond to a 60%
reduction in fuel NOx levels, a figure considered to be close to the maximum
reduction that can be achieved with an internally staged low NOx pulverised fuel
burner.
Following the demonstration of the full scale Mark III burners in the Large Scale
Test Facility, 60 Mark III burners were installed in Drax Unit in August 1989.
Prior to the installation of the Mark III burners, all sixty burner quarls had
been modified to the design developed during the Mark I burner investigation, and
3-58
-------
the Mark I burners modified to Mark II design. The satisfactory operating
experience with the Mark II design has been presented elsewhere (1), the enhanced
NOx reduction capability of the Mark III design (Figure 9) making it an attractive
retrofit to the Mark II design.
Mark III Plant Burner Optimisation
Experience from the Mark III burner development tests had shown that the NOx/
unburned carbon characteristics of the burner could be 'optimised1 by adjustment
of the secondary air swirl level (via the axial movement of the secondary air
swirler) and the secondary air flow rate (controlled by the secondary damper).
The results of the series of burner optimisation trials with the Mark III burner
on Drax Unit 6 are summarised in Figure 10. The figure clearly demonstrates how
NOx and unburned carbon can be optimised for the Drax situation by adjustment of
the burner settings, the results obtained on the plant reproducing the
characteristics of the burner in the test facility. Accordingly for the
demonstration of the Mark III burner in Unit 6 the burner settings were those
corresponding to Test 3, i.e. the minimum carbon in ash settings.
Burner Demonstration
The results of the demonstration tests performed with the Mark III burner design
in September 1989, approximately three weeks after installation, are presented in
Figure 11, whilst Table 3 summarises the overall boiler performance for both the
preconversion case and with the Mark III burners installed. Essentially:-
i) Overall NOx levels are reduced from 832 to 381 ppm, a reduction
greater than 50%, the figure obtained with eight top mills in
service being lower than the current EC directive for new boiler
plant.
ii) Carbon in ash levels have increased from 1 to 1.5% preconversion
to around 2.5% with the Mark III design. However, greater furnace
heat absorption and a consequent reduction in gas temperature
leaving the airheaters offset this efficiency loss.
Other Effects of the Low NOx Modification
Furnace Performance. A significant result of the installation of the Mark III
burners has been the reduction of arch level flue gas temperatures by 50 to 100 C
compared to the preconversion situation. This reduction in exit gas temperatures
has not posed any problems in operation of the plant, or in maintenance of the
required steam conditions, there now being less attemperator spray water flow than
preconversion. The reduction is attributed to the furnace water walls being
significantly cleaner with the Mark III burner design compared to the standard
circular turbulent burner, as a direct result of the improved control of fuel and
air flow within the burner required for efficient low NOx combustion. Flame light
off, burner stability and turndown is excellent.
3-59
-------
Side Wall Wastage. The improved furnace performance would suggest that local wall
reducing conditions are not present, and this has been corroborated by subsequent
furnace tube thickness measurement which showed very low wastage rates.
Quarl Slagging. The modifications carried out on the burner quarls have resulted
in the quarls remaining free of significant ash deposition during service, with
any deposition in out of service burners being rapidly cleared away on the burners
return to service (Figure 12).
Long Term Performance
Performance tests have been performed on Unit 6 at roughly six monthly intervals
since the Mark III retrofit in August 1989. These tests show that the low NOx
characteristics of Unit 6 have been maintained, with no problems associated with
quarl or furnace deposition. Inspection of the burner flameholder after 6 months
service showed some limited damage to the ceramic segments of the flameholder,
mainly associated with the fixing method. Wear on the pulverised fuel side of the
burner, the components having seen over 18 months service, is very low, and no
significant problems are anticipated with those or any other components meeting
the specified burner component life of 38 months (= 25,000 hours).
Plans are in hand to retrofit more Mark III Low Nox Axial Swirl burners at Drax in
1991/92, and further orders have been received from both the UK and the Far East
for Mark III burner retrofits.
THE EFFECT OF COAL QUALITY ON LOW NOx BURNER PERFORMANCE
Introduction
As noted in the previous section, the performance of the Mark III Low NOx Axial
Swirl Burner has been proven in a highly rated opposed wall fired boiler
environment, firing a typical UK bituminous coal of sensibly constant fuel
properties. In order to demonstrate the performance of the burner firing
bituminous coals whose NOx related properties differ significantly, a series of
tests were performed on a 48 MW(t) Low NOx Axial Swirl Burner installed in the
Babcock Energy Large Scale Test Facility in Renfrew.
Coal Properties
Three coals were selected, Table 4, whose properties represent virtually the
extreme, from a NOx emission point of view, of bituminous coals fired on utility
boilers and traded on the world market. The essential coal properties can be
summarised as follows:-
i) Indonesian coal, with a high volatile matter content and a high
inherent moisture level and nitrogen content.
ii) A UK coal, similar to that fired on Drax, and chosen to provide
a link between the 37 MW and the 48 MW burner data in the
Test Facility.
3-60
-------
ill) A South African coal, with a low volatile matter content and a
high nitrogen content.
The properties listed in Table 4 are on an as fired basis i.e. after the coal had
been pulverised off site and delivered to the test facility.
Results Obtained
Figure 13 shows the variation of NOx emissions with operating oxygen for the three
coals with the burner firing at 45 MW. At 3% operating oxygen, NOx emissions
range from 250 ppm with the Indonesian (low fuel ratio) coal, to 435 ppm with the
South African (high fuel ratio) coal. A value of 380 ppm is obtained with the UK
coal. This is higher than that obtained with the 37 MW burner design due to two
factors i.e. different burner settings and increased thermal NOx in the test
facility. For all three coals, CO levels and carbon in ash levels are typical of
those obtained in the Test Facility, being at 3% operating oxygen, typically 400
ppm and 4 to 6%. Carbon in ash levels with the South African low volatile coal
tend to be slightly higher than those for the high volatile coal, as might perhaps
be expected.
CONCLUSIONS
The Mark III Babcock Energy Low NOx Axial Swirl burner has been in operation on
Drax Unit 6 since 1989, and has been producing a consistent reduction in NOx
levels of 50 to 55%. This is an excellent achievement for a highly rated plant
such as Drax, which is now capable of operating below the EC directives.
Operationally advantageous changes in the heat transfer pattern in the boiler have
been measured, with the furnace chamber running significantly cleaner and guarl
slagging virtually eliminated. Further burner testing in the Babcock Energy Large
Scale Test Facility has demonstrated the effect of coal quality on NOx emissions
and that a wide range of coals can be burned in an efficient and stable manner.
The Babcock Energy Low NOx Axial Swirl burner can therefore be considered as a
proven combustion technique for the clean efficient combustion of pulverised
coals. In parallel with two stage combustion techniques and appropriate furnace
design, NOx levels commensurate with those specified in most worldwide
legislation can be achieved. In the retrofit situation, dependent on coal quality
and furnace design, NOx levels lower than 0.5 Ib/mBtu can generally be achieved.
ACKNOWLEDGEMENTS
The authors wish to express their gratitude to the Station Management and Staff at
Drax Power Station for their assistance in all stages of the execution of this
project.
This paper is published with the permission of Babcock Energy Limited.
3-61
-------
REFERENCES
A.R. Jones, G.S. Riley and B.M. Downer "The Development and Use of Special
Probes for Investigating the Effects of Ash on Furnace Operation." 2nd
Conference on the Effects of Coal Quality on Power Plants . St. Louis
Missouri, 19 21 September 1990.
R.M. Clapp, J.L. King and J. Macphail "Development and Application of an
Advanced Pulverised Fuel Low NOx Burner." 1990 International Joint Power
Generation Conference. Boston, 21 - 25 October 1990.
3-62
-------
900
800
700
600
NOx
P.P.M.
AT
3% 02
x 8 TOP MILLS
o 8 BOTTOM MILLS
I .0
0.5
GCV
LOSS
12345
ECONOMISER OUTLET OXYGEN (% DRY)
Figure 1. Preconversion Test Results
Source: Drax Unit 6.
IBdlARY AR-i
8ECONCARY MR ,— 6ECONQART DAMPER
3WBLER
-lERTMRT
aPUTTH) MMPER
Figure 2. Mark I Low NOx Axial Swirl Burner
3-63
-------
Figure 3. Axial Swirl Generator
Figure 4. Mark I Low NOx Axial Swirl Burner
3-64
-------
Figure 5. Typical Deposit Pattern
MAFK HI
Figure 6. Mark III Low NOx Axial Swirl Burner
3-65
-------
AIR BLOWER
FURNACE
GAS PROBE
TO WASTE HEAT BOILERS
OR ATMOSPHERE
LOSS IN
WEIGHT FEEDER
WATER
COOLING
TANK
FEEDER/
EJECTOR
FURNACE WITH
STEAM HOOD
SECONDARY AIR
PF BURNER
OIL BURNER
KEROSINE
TANK
STEAM
SUPPLY
FLOW CONTROL DAMPER
PUMP
MAKE UP
WATER
TANK
Figure 7. Schematic of Large Scale Burner Test Facility
Figure 8. Babcock Large Scale Burner Test Facility
3-66
-------
cr
Q
C\J
o
0.
Q.
X
o
900
800
700
600
500
400
300
200
100
STANDARD BURNER
MK II LNASB
MK III LNASB
12345
% 02 (DRY)
Figure 9. Test Facility Results
MEAN
CARBON 4
IN ASH
2
x TEST I
o TEST 2
TEST 3
TEST 4
I I I | L
320 350 400 430
NOx P.P.M. AT 3% 02
Figure 10. Summary of Optimisation Test Results
3-67
-------
500
NOx
P.P.M.
AT 400
3% 02
300
200
o 8 TOP MILLS
° 8 BOTTOM MILLS
I 2 3 4. 5
ECONOMISER OUTLET OXYGEN (% DRY)
Figure 11. Demonstration Test Results
Figure 12. Quarl In Service
3-68
-------
500
400
300
NOx
P.P.M.
DRY 200
AT
3% 02
100
SOUTH
AFRICAN
COAL
U.K. COAL
INDONESIAN
COAL
12345
OUTLET OXYGEN (% DRY)
Figure 13. Effect of Coal Quality on NOx Emissions
3-69
-------
TABLE 1
DRAX COAL ANALYSIS SPECIFICATION
Properties
Higher Heating Value KJ/Kg
Moisture %
Ash %
Volatile %
Sulphur %
Chlorine %
Ash Initial °C
Deformation Temperature
Design
Basic
24 400
8
20
28
2.0
0.4
1200
Coals
Range
17 680-27 910
4-24
3-40
20-32
0.5-4.0
0.03-1.0
1000-1345
Coals Burned
to Date
17 840-29 120
3.8-16.0
5.5-33.7
1.0-2.38
0.06-0.44
1060-1350
TABLE 2
TYPICAL COAL PROPERTIES FOR THE PRECONVERSION TEST
Coal Analysis
Ash Analysis
Moisture
Volatile Matter
Fixed Carbon
Ash
Nitrogen
FC/VM
Nitrogen (daf)
GCV (MJ/kg)
Pf Fineness
% < 75 micron
% < 150 micron
% < 300 micron
11.0
28.8
44.2
16.0
1.18
1.59
1.64
24.96
66.2 - 69.3
92.5 93.8
99.6 99.8
Silica
Alumina
Iron Oxide
Calcium Oxide
Magnesium Oxide
Titanium Oxide
Potassium Oxide
Phosphorus
Sulphur
57.8
24.1
8.9
1.4
1.8
0.92
3.09
0.25
0.56
3-70
-------
TABLE 3
COMPARISON OF PRECONVERSION AND MARK III BURNER BOILER DATA
^reconversion Post Conversion
TEST NO:
DATE:
TIMES:
Unit Load (MWe)
Mills in Service
Economiser Outlet
02 (% dry)
Arch Level Temperature
FEGT
NOx corrected to 3%
02 (dry)
1
18.03.87
09.30
11.30
662
8 Top
3.75
°C 1492
°C 1130
ppm
2
18.03.87
13.00
15.00
660
8 Top
2.76
1508
1129
823
3
18.03.87
16.30
18.30
661
8 Top
2.42
1529
1141
783
Al
20.09.89
09.30
11.45
660
8 Top
4.65
1402
1075
479
A2 A3 A4
20.09.89 20.09.89 20.09.89
12.30 16.00 19.00
14.30 18.00 21.00
655 652 654
8 Top 8 Top 8 Top
3.59 2.85 3.68
1413 1447 1430
1066 1081 1088
TABLE 4
ANALYSIS OF COALS TESTED
Indonesian United Kingdom South African
GCV MJ/kg 26.55 27.13 27.12
H20 % 10.5 3.4 3.1
VM % 40.6 31.6 25.3
FC % 44.7 46.8 56.4
Ash % 4.2 18.2 15.2
3-71
-------
UPDATE ON COAL REBURNING TECHNOLOGY FOR REDUCING NOX IN CYCLONE BOILERS
A.S. Yagiela
Cyclone Reburn Project Manager
Babcock & Wilcox
Barberton, Ohio
G.J. Maringo
Combustion Systems Development Engineer
Babcock & Wilcox
Barberton, Ohio
R.J. Newell
Supervisor Plant Performance
Wisconsin Power & Light Co.
Cassville, Wisconsin
H. Farzan
Alliance Research Division
Senior Research Engineer
Babcock & Wilcox
Alliance, Ohio
-------
UPDATE ON COAL REBURNING TECHNOLOGY
FOR REDUCING NOx IN CYCLONE BOILERS
A. S. YAGIELA
Cyclone Reburn Project Manager
Babcock & Wilcox
Barberton, Ohio
G. J. MARINGO
Combustion Systems Development Engineer
Babcock & Wilcox
Barberton, Ohio
R. J. NEWELL
Supervisor Plant Performance
Wisconsin Power & Light Company
Cassville, Wisconsin
H. FARZAN
Alliance Research Division
Senior Research Engineer
Babcock & Wilcox
Alliance, Ohio
ABSTRACT
Encouraging results have been obtained from engineering feasibility and
pilot-scale proof-of-concept studies of coal reburning for cyclone
boiler NOx control. Accordingly, Babcock & Wilcox (B&W) completed
negotiations for a Clean Coal cooperative agreement with the Department
of Energy (DOE) to demonstrate coal reburning technology for cyclone
boilers. The host site for the demonstration is the Wisconsin Power &
Light (WP&L) Company's 100 MWe Nelson Dewey Station.
Reburning involves the injection of a supplemental fuel (natural gas,
oil, or coal) into the main furnace to produce locally reduced
stoichiometric conditions which convert the NOx to molecular nitrogen,
thereby reducing overall NOx emissions. Currently, no commercially-
demonstrated combustion modification technigues exist for cyclone
boilers to reduce NOx emissions. The emerging reburning technology
should offer cyclone boiler operators a promising alternative to
expensive flue gas cleanup technigues for NOx emission reduction.
This paper reviews baseline testing results at the Nelson Dewey Station
and pilot-scale results simulating Nelson Dewey operation using
pulverized coal (PC) as the reburning fuel. Outcomes of the model
studies as well as the full-scale demonstration design are discussed.
INTRODUCTION
The Department of Energy (DOE) under its Clean Coal II solicitation is
sponsoring B&W and WP&L to perform a full-scale demonstration of the
reburning technology for cyclone boiler NOx emissions control. This
3-75
-------
full-scale evaluation is justified via a previous Electric Power
Research Institute-sponsored (Project RP-1402-30) engineering
feasibility study and EPRI/GRI (EPRI RP-2154-11; GRI:5087-254-1471)
pilot-scale evaluation of reburning for cyclone boilers performed by B&W
(1)(2). The feasibility study revealed that the majority of cyclone-
equipped boilers could successfully apply this technology to reduce
their NOx emission levels by approximately 50%-70%(1). The pilot tests
evaluated the potential of natural gas, oil, and coal as the reburning
fuel in reducing NOx emissions. The data obtained from the pilot-scale
project substantiated the results predicted by the feasibility study.
Though oil/gas reburning could play a role in reducing NOx emissions
from cyclone boilers, B&W coal reburning research has also shown that
coal performs nearly as well as gas/oil without deleterious effects on
combustion efficiency. This means that boilers using reburning for NOx
control can maintain 100% coal usage instead of switching to 20% gas/oil
for reburning. As a result of the coal reburning research performed to
date, the technology has advanced to the point where demonstration on a
commercial scale is imminent.
Currently, 105 operating, cyclone-equipped utility boilers exist,
representing approximately 15% of pre-New Source Performance Standards
(NSPS) coal-fired generating capacity (over 26,000 MW). However, these
units contribute approximately 21% of the NOx emitted since their
inherent turbulent, high-temperature combustion process is conducive to
NOx formation. Although the majority of the cyclone units are 20 to 30
years old, utilities plan to operate many of these units for at least an
additional 10 to 20 years. These units (located primarily in the
Midwest) have been targeted for Phase II Federal Acid Rain NOx emission
limitations.
The coal reburning demonstration project for cyclone boiler NOx control
will be carried out at WP&L's Nelson Dewey Station, Unit No. 2, in
Cassville, Wisconsin. The unit is a B&W RB-type boiler with three
cyclone furnaces. Unit No. 2 is small (nominal 100 MWe) to limit
project costs, but large enough to assure that the reburning technology
can be successfully applied to the cyclone-fired utility boiler
population. As part of the project, B&W's six-million Btu/hr Small
Boiler Simulator (SBS) pilot facility was utilized to duplicate the
operating practices of WP&L's Nelson Dewey Unit No. 2. The coal that is
fired at Nelson Dewey was fired in the SBS cyclone and also was utilized
as the reburn fuel. During the field test phase at Nelson Dewey
Station, emission and performance data was acquired and analyzed before
the coal reburn conversion to determine the NOx reduction and impact on
boiler performance. Combining these combustion test results with
physical and numerical modeling of the technology as applied to Dewey
Unit No. 2 provides a comprehensive test program not only for successful
application of WP&L's unit, but for the cyclone population as a whole.
From WP&L's perspective, involvement in this project was undertaken for
several reasons. The State of Wisconsin enacted acid rain legislation
in 1986, which will be fully implemented in 1993. Federal acid rain
legislation will require NOx reductions from cyclone fired boilers
beginning in 1995. The state law requires significant reduction of SO2
emissions and the study of potential reduction of NOx emissions.
Approximately 50% of WP&L's coal-fired capacity is generated from
cyclone boilers installed between 1952 and 1969. These boilers are
vital to meeting the electricity needs of WP&L's customers. However, of
concern to WP&L is that these cyclone boilers produce about 75% of the
NOx emitted within the WP&L system. Environmental concerns have been
3-76
-------
complicated by the fact that no commercial combustion technologies exist
for controlling NOx emissions from cyclone boilers. Based upon WP&L's
internal analyses of several advanced technologies, coal reburning
surfaced as the least-cost retrofit alternative. With these reasons and
a desire to promote cost-effective emission reduction technologies, WP&L
accepted B&W's offer to participate and host this project.
BACKGROUND/REBURNING PROCESS DESCRIPTION
The cyclone furnace consists of a cyclone burner connected to a
horizontal water-cooled cylinder, commonly referred to as the cyclone
barrel. Air and crushed coal are introduced through the cyclone burner
into the cyclone barrel. The larger coal particles are thrust out to
the barrel walls where they are captured and burned in the molten slag
layer which is formed; the finer particles burn in suspension. The
mineral matter melts, exits the cyclone furnace from a tap at the
cyclone throat, and is dropped into a water-filled slag tank. The flue
gases and remaining ash leave the cyclone and enter the main furnace.
No commercially-demonstrated combustion modifications have significantly
reduced NOx emissions without adversely affecting cyclone operation.
Past tests with combustion air staging achieved 15 to 30% reductions.
Cyclone tube corrosion concerns due to the resulting reducing conditions
were not fully addressed because of the short duration of these tests.
Further investigation of staging for cyclone NOx control was halted due
to utility corrosion concern. Additionally, since no mandatory
federal/state NOx emission regulation was enforced, no alternative
technologies were pursued.
The use of selective catalytic reduction (SCR) technology offers promise
of controlling NOx emissions from these units, but at high capital and
operating costs. Reburning is therefore a promising alternative NOx-
reduction approach for cyclone-eguipped units with more reasonable
capital and operating costs.
Reburning is a process by which NOx produced in the cyclone is reduced
(decomposed to molecular nitrogen) in the main furnace by injection of
a secondary fuel. The secondary (or reburning) fuel creates an oxygen-
deficient (reducing) region which accomplishes decomposition of the NOx.
Since reburning can be applied while the cyclone operates under its
normal oxidizing condition, its effects on cyclone performance can be
minimized.
The reburning process employs multiple combustion zones in the furnace,
defined as the main combustion, reburn, and burnout zones, as shown in
Figure 1. The main combustion zone is operated at a reduced
stoichiometry and has the majority of the fuel input (70 to 80% heat
input). Most past investigations on natural gas-/oil-/coal-fired units
have shown that the main combustion zone of the furnace should be
operated at a stoichiometry of less than 1.0. This operating criteria
is impractical for cyclone units due to the potential for highly
corrosive conditions, since many cyclones burn high-sulfur, high-iron
content bituminous coals. To avoid this situation and its potential
consequences, the cyclone main combustion zone was determined to be
operated at a stoichiometry of no less than 1.1 (2% excess 02) .
The balance of fuel (20 to 30%) is introduced above the main combustion
zone (cyclones) in the reburn zone through reburning burners. To
protect the tubes around the reburning burners in the reburning zone
3-77
-------
from fireside corrosion, air is introduced through these burners. The
burners are operated in a similar fashion to a standard wall-fired
burner except that they are fired at extremely low stoichiometries (less
than 0.6). The furnace reburning zone is operated at stoichiometries in
the range of 0.85 to 0.95 in order to achieve maximum NOx reduction
based on laboratory/actual boiler application results. A sufficient
furnace residence time within the reburn zone is required for flue gas
mixing and NOx reduction kinetics to occur.
The balance of the required combustion air—totaling 15 to 20% excess
air at the economizer outlet—is introduced through over-fire air (OFA)
ports. As with the reburn zone, a satisfactory residence time within
this burnout zone is required for complete combustion. These ports
should be designed with adjustable air velocity controls to enable
optimization of mixing for complete fuel burnout prior to exiting the
furnace.
PROJECT DESCRIPTION
The objective of the cyclone demonstration is to evaluate the
applicability of the coal reburning technology for reducing NOx
emissions in full-scale cyclone-equipped boilers. The performance goals
are:
1) Provide a technically and economically feasible low-NOx
alternative for cyclone boilers to achieve a greater than 50%
NOx reduction where one currently does not exist.
2) Show significant reductions in emission levels of oxides of
nitrogen achieved at a low capital and very low operating cost
(compared to the SCR technology).
3) Show that there is no need for a supplemental fuel. Reburn
will be carried out using the present boiler fuel which is
coal.
4) Provide a system that will maintain boiler reliability,
operability, and steam production performance after retrofit.
To meet the above stated goals, the coal reburn project consists of
three separate phases:
PHASE I - Design and Permitting
The coal reburn system will be designed based upon B&W's
pilot-scale combustion tests, physical and numerical flow
modeling tests, past experience, and knowledge of full-scale
burner/OFA port/control system retrofits. Baseline emissions
and performance data will be collected on WP&L's Nelson Dewey
Unit No. 2.
PHASE II - Procurement, Construction, and Start-up
A. Long Lead-Time Item Procurement
For schedule purposes, long lead-time equipment
will be ordered during the design and permitting
phase.
3-78
-------
B. Construction and Start-up
The coal reburn system will be fabricated and
installed at Nelson Dewey No. 2 and started up.
PHASE III - Operation and Disposition
Parametric/optimization and performance tests will assess
emission reductions and boiler performance capability of the
technology at both full-load and reduced-load operation.
Readiness for commercialization will be determined from both
a technical and economic viewpoint.
The overall project duration is 43 months and was initiated on October
1, 1989, with construction to start in June 1991 for a November 1991
operation. Figure 2 shows the overall program schedule.
A summary of the overall project organization of participants is as
follows:
Project Organization
Department of Energy - 50% funding co-sponsor
B&W - Prime contractor and project manager
WP&L - Host site utility and funding co-sponsor
State of Illinois - funding co-sponsor
Utility funding co-sponsors
Acurex Corporation - testing subcontractor
Sargent & Lundy - architect engineer subcontractor
The utility funding co-sponsors are:
1) Allegheny Power System
2) Atlantic Electric
3) Associated Electric Co-op, Inc.
4) Baltimore Gas & Electric
5) Iowa Electric Light & Power Co.
6) Iowa Public Service
7) Missouri Public Service
8) Kansas City Power & Light
9) Northern Indiana Public Service Company
10) Tampa Electric Company
SBS PILOT-SCALE SIMULATION TESTS
Technical Objectives
The technical objectives of the pilot-scale combustion tests were to
demonstrate NOx reductions of nominally 50 to 60% while maintaining
acceptable cyclone/boiler operating conditions. B&W's six-million
Btu/hr Small Boiler Simulator (SBS) pilot facility (see Figure 3) was
utilized to duplicate the operating practices of WP&L's Nelson Dewey No.
2. Baseline and coal reburning pilot tests were performed to evaluate
the potential applicability of this technology. The majority of these
tests were done while firing the project's demonstration coal (Lamar -
a medium sulfur, 1.87%, bituminous coal from Indiana). The numerous
parameters which are varied to help determine the technology's potential
are as follows: main cyclone/reburning burner fuel splits, reburn coal
3-79
-------
type, furnace zone stoichiometries and furnace zone residence times. In
addition to determining NOx reduction potential, other variables such as
mixing, corrosion, fireside deposition, combustion efficiency and
precipitator performance are evaluated.
Research Facility
B&W's six-million Btu/hr SBS utilized to perform the pilot-scale cyclone
coal reburning tests has been described elsewhere (1)(2).
Baseline Test Results
The baseline tests are performed under normal cyclone operating
conditions and identify the benchmark data to which the subsequent
reburning test results are compared. The key parameters measured during
the baseline tests included NOx emissions, Furnace Exit Gas Temperature
(FEGT), unburned carbon, CO, H2S, fly ash resistivity, and particulate
loading/deposition.
Figure 4 illustrates the NOx emission levels obtained during the
baseline tests. Operating the cyclone at six-million Btu/hr resulted in
baseline NOx levels of 950 to 1070 ppm (corrected to 3% O2) while varying
excess O2% from 2 to 3.75%, respectively. Since operating at 3% excess
O2 is considered typical, the baseline NOx level utilized to compare with
reburning conditions is 1025 ppm. Reducing the SBS load to 75% of rated
capacity (4.5 million Btu/hr) resulted in NOx emissions of 915 to 1000
ppm (corrected 3% O2) when varying excess O2 from 2.4 to 4.3%,
respectively. The NOx emission level while operating at a typical 3%
excess O2 was 950 ppm.
Baseline FEGT's at full and 75% loads were 2175°F and 1975°F,
respectively, at an excess O2%, of 3%. Fly ash samples collected
throughout the long-term deposition test phase resulted in an unburned
carbon (UBC) level of 3.5% or an associated combustion efficiency of
99.99%. During short-term tests a discrepancy in UBC results, which
will be discussed later, was observed with UBC levels of less than 1%
corresponding to an associated combustion efficiency of essentially
100%. Stack CO emission levels and measured H2S concentrations in the
lower furnace were low. CO (ppm) levels throughout the baseline tests
were less than 50 ppm and no H2S was detected. Fly ash resistivity
measurements were collected at the simulated precipitator inlet. The
measured resistivity was 4.5 x 1010 ohm-cm.
Reburning Test Results
Lamar coal was fired in the cyclone as it was operated at 65 to 80% of
total load under excess air conditions. Reburning coal firing provided
the remaining 20 to 35% heat input. In order to obtain various in-
furnace reburning zone stoichiometries (0.85 to 0.95), the reburning
burners were operated at substoichiometric conditions. The balance of
air was then introduced through two OFA ports located in the upper
furnace rear wall.
Major comparisons between the SBS baseline/reburning tests given below
include the following: NOx reduction, Furnace Exit Gas Temperature
(FEGT), combustion efficiency, fireside corrosion, and precipitator
performance.
3-80
-------
NOx Emissions
A 43 to 75% NOx reduction (from the baseline NOx level) was achieved
during coal reburning under various test conditions. These results are
reported as overall reductions and consist of basically two components:
NOx reduction via lower heat input at the cyclone burner
NOx destruction via the reburning process
The following results are based upon the overall NOx reductions while
varying reburning zone stoichiometries and burner flue gas recirculation
addition.
Reburning Zone Stoichiometries. Incorporating coal reburning operation
during full load and 0% Flue Gas Recirculation (FGR) conditions revealed
NOx reductions on the order of 49 to 73% from baseline when varying the
reburn zone stoichiometry from 0.95 to 0.85, respectively. Maintaining
the cyclone stoichiometry at 1.1 throughout the test sequence is
critical due to the potential corrosion/operating concerns of the
cyclone. Thus, while maintaining the cyclone stoichiometry, the
reburning zone stoichiometry is varied by increasing the amount of heat
input diverted to the reburn burners (while also maintaining a constant
reburn burner stoichiometry). To obtain the 0.95 to 0.85 reburn zone
stoichiometries, the corresponding cyclone/reburn burner coal splits are
80/20 and 66/34, respectively. Figure 5 shows NOx emissions (at 3% 02)
versus reburning zone stoichiometry at six million Btu/hr. This figure
also shows the NOx emission consequences while varying the reburning
coal fraction (standard, medium, and fine grind corresponds to 63, 78,
and 90% through 200 mesh, respectively) . The data show a good
correlation between all tested grind sizes versus NOx.
Reducing load to 75% of rated boiler capacity (0% FGR) and utilizing the
fine grind coal size revealed NOx reductions on the order of 43 to 63%
when varying reburn zone stoichiometry from 0.95 to 0.86.
Flue Gas Recirculation. Adding FGR to the reburning burners secondary
air zone increases the mass flow rate through the burner and thus
results in higher burner velocities with increased pressure drop and
turbulence. Comparing the NOx reduction capability during FGR addition
with the baseline 0% FGR case reveals that NOx reductions of 53 to 75%
were achieved while varying the reburn zone stoichiometry from 0.95 to
0.85. Thus, a slight improvement in NOx reduction was observed when FGR
was utilized.
Furnace Exit Gas Temperature
Furnace exit gas temperature did not change significantly between
baseline and reburning operation. Baseline FEGTs at full load and 75%
load (0% FGR) were 2175"F and 1975"F, respectively, at a stack O2 of 3%.
Incorporating reburning at full load revealed minimal FEGT effects
within a range of about ±40"F. The addition of FGR actually caused a
temperature quenching/tempering phenomenon to occur. Lower load
operation showed a potential FEGT increase up to about 100°F. This
increase at lower loads would not be a problem. Thus, based upon this
data (in conjunction with past pilot test/engineering studies), no
significant reburning impacts on FEGT would be predicted. Additional
investigations incorporated higher FEGT values within the boiler
performance models for the Nelson Dewey No. 2 demonstration site to
determine performance changes (superheat and reheat attemperator spray
quantities) with higher FEGTs.
3-81
-------
Combustion Efficiency
Reviewing unburned carbon data showed that the pilot-scale testing
predicts an increase in unburned carbon when operating under reburning
conditions. Reducing the reburn coal grind size does reduce the
magnitude of this increase. Thus, the full-scale reburn retrofit design
will incorporate the capability to change the coal particle size
distribution.
Since the total ash content to the furnace is low in cyclone boilers
(due to the slag tapping capability), increases in unburned carbon
levels in the fly ash should also be evaluated based upon changes in
combustion efficiency. Fly ash samples were collected throughout the
long-term deposition test phase (48 hour continuous runs) for both
baseline and reburning cases. The unburned carbon (UBC)/combustion
efficiency results are as follows:
Baseline - 3.5% UBC/99.99%
Combustion Efficiency
Reburning - 5.1% UBC/99.94%
Combustion Efficiency
Short-term baseline unburned carbon levels were also measured and they
were found to be low (less than 1%). Also during the short-term
testing, operation in the reburn mode at about a 0.9 (approximately 27%
reburn fuel) reburn zone stoichiometry, a fly ash carbon content of
approximately 5-6% was observed when utilizing the fine grind (90%
through 200 mesh) coal size.
Two items of interest become apparent. The first is that over a longer
period of time, the baseline UBC increased to about 3.5% versus the less
than 1% reported during the short-term tests. The second item pertains
to the small change in combustion efficiency observed (0.05% decrease
during reburning). Thus, although the pilot scale tests have
highlighted unburned carbon as a potential issue, minimal impact on
combustion efficiency should result.
Corrosion Potential
H2S measurements within the reburning zone were taken in order to help
assess potential corrosiveness when applying reburn technology. While
firing Lamar coal (Indiana - 1.87% sulfur), baseline and reburning cases
showed H2S concentrations of 0 ppm and 0-200 ppm, respectively. During
reburning operation, H2S levels measured near the boiler side walls were
low. The maximum H2S levels were found between the flames of the reburn
burners. Thus, minimum H2S contact with the boiler walls was observed,
which is a desired effect.
Precipitator Performance
No change in measured fly ash resistivity was observed between baseline
and reburning conditions. Via this parameter, no loss in precipitator
efficiency would be predicted. However, higher particulate mass
loadings were observed due to the injection of pulverized coal into the
furnace. This predicts possible increases in precipitator outlet grain
loading.
3-82
-------
WP&L BASELINE TEST RESULTS
Baseline tests were performed at Nelson Dewey Unit No. 2 prior to
installation of the coal reburning system in order to provide the
benchmark data to which subsequent reburning results will be compared.
The test sequence included collecting data at three load conditions—
100%, 75%, and 50%—and at different excess air and flue gas
recirculation levels. Thus, the baseline characterization not only
identified normal or typical conditions for boiler
operations/performance, emissions characteristics, and electrostatic
precipitator performance, but the test matrix was structured to identify
changes in these parameters when excess air and flue gas recirculation
rates are varied. This will provide future background data for coal
reburning operation.
NOx and Percent Loss on Ignition (unburned carbon) Emission Levels
Figures 6 and 7 show the full load (110 MW) baseline stack NOx emission
levels (ppm corrected to 3% O2) and percent loss on ignition (LOI),
respectively, as measured by the Acurex Testing Company versus various
excess oxygen contents as measured at the economizer. Figure 6 reveals
NOx levels ranging from approximately 640 ppm to 700 ppm (corrected to
3% 02) when economizer outlet O2% was varied between about 2 and 4%,
respectively. Since operating at 3% economizer outlet O2 is considered
typical, the normal baseline NOx level is 662 ppm at 3% O2. Figure 7
shows percent LOI varied from approximately 18% down to 9% while
increasing excess O2% from 2 to 4%, respectively.
Additionally, Figures 8 and 9 show the relationship between NOx (ppm at
3% 02) and percent LOI versus boiler load (MW) during typical boiler
operation (3% economizer outlet O2) . As shown in Figure 8, varying the
load from 55 MW to 110 MW resulted in NOx levels of approximately 550
ppm to 662 ppm (at 3% O2), respectively. Figure 9 reveals that percent
LOI remained fairly constant over the load range (approximately 16 to
17% LOI).
REBURN SYSTEM DESIGN CONSIDERATIONS
The demonstration boiler host site at WP&L's Nelson Dewey Unit No. 2 is
shown in Figure 10 and pertinent boiler information is summarized in
Table 1.
The reburning system design considerations included utilizing physical
and numerical modeling activities along with B&W low NOx burner/over-
fire air port design experience. The size, number, and location of
reburn burners and OFA ports were determined. The goal—to obtain good
mixing at the reburn burner elevation and OFA ports—is essential for
NOx reduction and combustible burn-out, respectively. In addition,
penetration of the reburn burners fuel streams into the cyclone hot flue
gas is of concern since over-penetration or under-penetration would
cause tube wastage in the boiler, along with potential burner flame
instability problems.
Simultaneous modeling of the cyclone, reburn burners and OFA ports
within one system is a new and unique procedure. Development of a
modeling methodology to assess mixing and penetration results was
required. The following plan was developed to meet the above stated
goals:
3-83
-------
Develop a procedure to simulate cyclone boiler flue gas flow
in cold flow and numerical models. Compare (validate) these
results with actual baseline flow measurements obtained at
Nelson Dewey.
Utilize validated cold flow model to simulate the reburn
system conditions using fundamental laws of aerodynamic
similarity.
Utilize validated numerical model to simulate the reburn
system conditions using B&W's FORCE and CYCLONE model computer
codes.
Physical Flow Modeling. Table 2 shows a summary of the test matrix for
the physical flow modeling of WP&L's baseline and mixing (reburning)
tests. In addition, it shows the actual field test flow measurement
conditions which were performed at Nelson Dewey during the baseline
field tests.
For the Nelson Dewey field test baseline condition, flow profile
measurements were obtained during cold (C) air flow conditions near the
proposed reburn burner elevation of 666 ft. Also, hot flow (50% oil
firing) velocity profiles were obtained at the cyclone exit and at the
above stated 666 ft. elevation. Baseline testing in the l/12th scale
model was performed using cold air and measurements were obtained at
three elevations:
1) 666 ft (near the proposed reburn burner elevation);
2) 681 ft (within the reburn zone just prior to the OFA ports);
and
3) 700 ft (furnace exit).
Comparing the field and the l/12th model measurements from elevation
666ft.showed good gualitative agreement between the collected data.This
agreement showed that high gas flow was concentrated at the boiler rear
wall with some negative (recirculation)/low turbulent flow near the
front (target) wall.
The mixing (reburning) tests were performed in the l/12th scale model by
utilizing a different temperature air stream at the various inlet
locations and then evaluating mixing potential by measuring the
resultant temperature downstream. For example, to evaluate reburn
burner mixing effectiveness, ambient air was introduced through the
cyclones and heated (H) air introduced through the reburn burners and
the resulting mixing temperature measured at the OFA inlet elevation of
681 ft. Figure 11 shows a comparison between various operating
conditions for this particular case. The example compares: four reburn
burners; 25% reburn fuel split and 5% flue gas recirculation (FGR) to
the burners at full load versus four reburn burners; 30% reburn fuel
split; and 7.5% FGR. The resulting normalized temperature profiles
(where 1.0 is equal to an ideal mix) show that improved mixing is seen
with the latter set of conditions. Thus, flexibility exists with the
reburn system-mixing potential since the latter case conditions are
being incorporated into the Nelson Dewey design.
Numerical Flow Modeling. Based upon an initial disparity between the
numerical and physical flow models, reburn burner penetration
capabilities, the numerical model was used to actually model the
3-84
-------
physical flow model. Since the physical model set-up criteria was
conservative, the numerical model needed to predict those physical model
results prior to having confidence in the numerical model. A detailed
1/12th scale numerical flow prediction was completed for the four reburn
burners, 25% reburn fuel split, and 5% FGR cases. The predictions
showed good agreement with observed physical flow model smoke patterns
and measured mixing performance at the 681 ft elevation. Thus, these
predictions benchmarked the numerical model for scale-up of the
reburning system design.
Table 3 shows a portion of the numerical flow modeling test matrix which
has been performed. The conditions which were varied included load
(MW) , fuel split, FGR rate, reburn burner parameters (number, size, and
side spacing) and OFA port parameters (number, size, and side spacing).
Summarizing all the various cases which were reviewed revealed that case
"4a" (4 reburn burners, 5% FGR, and 25% reburn fuel split) provided
comparable results to the predicted SBS mixing test conditions which
showed approximately 80% mass flow with stoichiometric ratio (SR) less
than 1.0, (which was our target level) within the reburn zone.
Obtaining the percent mass flow with SR less than 1.0, which was
predicted during the pilot SBS test phase, provided NOx reduction
prediction confidence for the Nelson Dewey retrofit. In addition, since
none of the cases using three-reburn burners approached this level, the
decision to proceed with the four-reburn burner design was made.
Figure 12 compares the results of the three- versus the four-reburn
burner cases with and without FGR. The figure shows mean stoichiometric
ratio versus furnace elevation as well as percent mass flow with SR less
than 1.0 versus furnace elevation. Minimum differences between the
three- and four-burner cases are observed in the no-FGR conditions, but
the percent mass flow with SR less than 1.0 does not approach the 80%
target level. Utilizing FGR distinguishes that four burners should be
used to provide maximum flexibility such that the 80% SR less than 1.0
could be obtained.
SUMMARY
The conclusions/recommendations of the physical and numerical model
activities are as follows:
Qualitative agreement between physical flow and numerical flow
results.
Baseline configuration
Reburning configuration
Numerical model can be used for qualitative evaluation and
scale-up of reburning system.
Four reburners and OFA ports provide the best mixing
performance.
Include the capability to add 5 to 10% flue gas recirculation
to the reburn burners.
Maintain the 25 to 30% fuel split capability-
Detail Design Considerations. Utilizing the conclusions/recommendations
from the physical/numerical modeling along with B&W's low NOx system
3-85
-------
design experience, the following reburn system design was determined.
An isometric view of the overall system design is shown in Figure 13.
The reburn system includes the following list of major components:
Four B&W S-type coal firing burners.
Four B&W dual air zone over-fire air (OFA) ports.
Furnace wall panels to accommodate the burners and OFA ports.
One B&W MPS 67 pulverizer with associated components including
coal piping.
One hot primary air fan and motor.
One gravimetric feeder.
One coal silo, 150 ton capacity.
Numerous flues and ducts to transport air/flue gas to various
system components.
A new enclosure to house the pulverizer and its associated
components.
A new motor control center and transformer to power the reburn
system.
Numerous dampers and drives to control flows to the various
system components.
One seal air fan and motor to provide seal air to the
pulverizer/feeder/hot PA fan.
New reburn system microprocessor control system.
Figure 13 shows a general overview of the reburning system and how it
compares to the existing boiler arrangement. The pulverizer (and
associated equipment) will be located in a new building enclosure
between column rows "12" (existing building) to "14" and "C" to "G" -
The hot primary air (PA) is taken off the left side of the air heater
and ducted to the PA fan inlet. Tempering air is fed to the PA prior to
the PA fan inlet in order to control pulverizer air inlet temperatures.
Automatic dampers will be available in each of these ducts. In
addition, an isolation damper (automatic) will be located just prior to
the PA fan inlet to allow maintenance on the fan/pulverizer when the
boiler is operating. An air monitor will also be located just prior to
the PA fan inlet to measure total air flow to the pulverizer.
Secondary air to the reburning burners will also be supplied from an air
heater outlet takeoff point located at the center bottom point of the
air heater. An automatic damper and air monitor will be located within
this line in order to control and measure total secondary air flow to
the burners. Gas recirculation can be introduced into this system (if
necessary) such that the total mass flow through the burners can be
varied. The gas recirculation (GR) takeoff is located after the
existing system's GR fans and is tied into the secondary air duct prior
to the burner splits. An automatic damper (tight shut-off) and monitor
are available in this flue to control and measure flow. Finally, this
3-86
-------
air/gas to the burner subsystem contains four manually adjustable
dampers in each of the lines leading to the individual burners. These
dampers will be utilized during system commissioning to balance flows to
each burner in case an imbalance exists.
The OFA system obtains its feed from the existing boiler's hot air
recirculation system. The hot air recirculation system is available to
take air from the air heater outlet to the FD fan discharge (basically
an air preheat system originally designed to help protect against cold
end air heater corrosion) . The OFA takeoff is prior to a booster fan in
this system. The duct work which leads to the four OFA ports includes
an automatic damper/air monitor to control and measure total air flow to
the OFA system.
The basis of the reburning technology is the range of in-furnace
operating stoichiometries along with reaction times. In order to
accurately control the process, additions to the existing control system
have to be made in order to control the fuel and air splits between the
cyclones, reburning burners, and OFA ports. The existing control system
at Nelson Dewey is the Bailey Network 90™, a state-of-the-art
microprocessor system. Additions to the microprocessor are possible due
to the existing system's flexibility.
FUTURE WORK/CONCLUSION
The focus of this demonstration project will be to determine maximum NOx
reduction capabilities without adversely impacting plant performance,
operation, and maintenance. In particular,- the prototype evaluations
will confirm and expand the results of the pilot-cyclone test programs.
Both steady-state and transient operation will be evaluated. The
following summarizes the specific items to be evaluated:
1) Major reburn process parameters on NOx reduction capability;
2) Combustion efficiency (based on unburned carbon and CO
emissions);
3) Boiler thermal efficiency;
4) Furnace temperature and heat absorption profiles;
5) Slaging and fouling;
6) Corrosion potential;
7) Gaseous and particulate emissions; and
8) Electrostatic precipitator operation.
In addition to completing the detail design of the reburn system, future
work includes investigating local heat transfer with boiler performance
models to help predict changes in furnace heat flux distributions.
Unburned carbon models will also be utilized to help predict changes in
UBC levels during reburning.
Another initial concern of the coal reburning is the amount and control
of the additional ash loading to the boiler and electrostatic
precipitator. Based upon a preliminary study by B&W and EPRI, the
existing precipitator has sufficient margin to adequately control the
increased fly ash added by the coal reburn process. In addition, the
ash mean particle size is expected to increase and aid in the
precipitator collection efficiency.
Finally, to investigate fireside corrosion—a potential side effect in
retrofit low NOx technologies—tube sections in the reburn zone will be
3-87
-------
replaced with new tubes during the installation phase. The new tube
samples will be taken out after the long-term performance tests, and
analyzed for potential corrosion effects. Ultrasonic measurements will
also be taken before and after the long-term performance tests to
evaluate furnace tube wastage. In addition, in-furnace H2S measurements
will be taken and corresponding corrosion rates will be predicted. This
information will be used to investigate potential problems and provide
recommendations for preventing such phenomena if necessary.
In conclusion, the modifications discussed in this paper constitute the
retrofit of a feasible coal reburning system to the selected host unit.
Thorough testing of this system along with obtaining information on the
boiler's baseline operating performance will provide a complete
evaluation of the usefulness of coal reburning as a NOx reduction
technology for cyclone-fired boilers. All the work to date has
substantiated that the goals of this project are attainable.
ACKNOWLEDGEMENTS
The authors extend their appreciation to the following B&W personnel for
their help in the performance of the SBS testing and the
numerical/physical flow modeling activities: Hamid Sarv, Rick Wessel,
Vince Belovich, Ray Kim, and George Watson.
REFERENCES
1. Maringo, et al., "Feasibility of Reburning for Cyclone Boiler NOx
Control", 1987 EPA/EPRI Joint Symposium on Stationary Combustion
NOx Control, New Orleans, Louisiana, March 23-27, 1987.
2. Farzan, et al., "Pilot Evaluation of Reburning for Cyclone Boiler
NOx Control", 1989 EPA/EPRI Joint Symposium on Stationary
Combustion NOx Control, San Francisco, California, March 6-9, 1989.
Legal Notice:
The Babcock & Wilcox Company pursuant to a cooperative agreement
partially funded by the U.S. Department of Energy (DOE) and a grant
agreement with IDENR for the DOE and IDENR and neither the Babcock &
Wilcox Company, DOE, IDENR, nor Southern Illinois University at
Carbondale, nor any person acting on their behalf:
a. Makes any warranty or representation, express or implied, with
respect to the accuracy, completeness, or usefulness of the
information contained in this report, or that the use of any
information, apparatus, method, or process disclosed in this report
may not infringe privately-owned rights; or
b. Assumes any liabilities with respect to the use of, or for damages
resulting from the use of, any information, apparatus, method or
process disclosed in this report.
Reference herein to any specific commercial product, process, or service
by trade name, trademark, manufacturer, or otherwise, does not
necessarily constitute or imply its endorsement, recommendation, or
favoring by the U.S. Department of Energy. The views and opinions of
authors expressed herein do not necessarily state or reflect those of
the U.S. Department of Energy.
3-E
-------
Table 1
Boiler Information
Nelson Dewey, Unit 2
Name Plate Rate:
Type:
Primary Fuel:
Operation Date:
Boiler ID:
Boiler Capacity:
Boiler General Condition:
Boiler Manufacturer:
Boiler Type:
Reburning Demonstration
Fuel:
Burners:
Particulate Control:
Boiler Availability:
100 MWe
Steam Turbine
Bituminous and Sub-Bituminous Coal
October 1962 - Unit No. 2
B&W RB-369
Nominal 11 MWe
Good
Babcock & Wilcox
Cyclone Fired RB Boiler, Pressurized
Indiana (Lamar) Bituminous Coal,
Medium Sulfur (1.87%)
Three B&W Vortex-Type Burners,
Single-Wall Fired
Research Cottrell ESP
90% Availability
Table 2
Matrix of WP&L Baseline and Mixing Tests
Test
Type
Baseline
Test
Mixing Test
Test
Facility
WP&L Boiler
1/12 Model
1/12 Model
Gas Temperature
Cycl
C
H
C
C
C
Rbm
C
H
C
OFA
C
H
Measurement Plane
Cycl Exit
X
666
X
X
X
X
681
X
700
X
X
700' —
681' —
666'-
Cyclones
Burnout
Zone
I OFA
Reburn
\ Zone
Reburner
3-89
-------
Case
No.
1
2
3
3a
4
4a
4b
5
5a
Load
100
100
110
110
110
110
110
110
110
MWe
MWe
MWe
MWe
MWe
MWe
MWe
MWe
MWe
Numerical Fl<
Fuel Reburne
Split FGR
30%
30%
25%
25%
25%
25%
25%
25%
25%
0%
0%
0%
8.7%
0%
5%
8.7%
0%
8.7%
Table 3
>w Modeling Test Matrix
r Reburneis
No.
3
4
3
3
4
4
4
3
3
Size
20"
18"
20"
20"
18"
18"
18"
20"
20"
Spacing
117.5"
7'9"
10'
10'
6'8"
6'8"
6'8"
10'
10'
No.
3
4
4
4
4
4
4
3
3
OFA Ports
Size
28"
24"
22"
22"
22"
22"
22"
26"
26"
Spacing
117.5"
7'9"
6'8"
6'8"
6'8"
6'8"
6'8"
10'
10'
In furnace
0.85 - 0.95
Stoichiometry
Coal
Bunker
Cyclone
Furnace
70%-80% Heat Input
Crushed Coal I v^
1.1 Stoichiometry | JN
Main Combustion O
Zone B&W Boiler
RB-369
100 MW capacity
Sec.
Air
Heater
Primary
Air Heater
Overfire Air Ports
Balance of Air
1.15-1.20 Overall
Stoichiometry
^ Reburning Pulverized
x Coal Burners
20% - 30% Heat Input
Pulverized Coal
0.4 - 0.5 Stoichiometry
Precipitator
J
Stack
Flyash Handling
and Disposal
Figure l--Coal reburn project - system layout, cyclone firing.
3-90
-------
Phase I: Design & Permitting
• Modeling & Pilot Scale
Testing
• Baseline Characterization
• System Design
Phase HA: Equipment Procurement
B: Construction & Start-Up
• Fabrication
• Installation
Phase III: Operation & Disposition
• Optimization
• Long-Term Performance
• Reporting & Disposition
1989
1990
12 Mo.
10 Mo.
H
9 Mo.
5 Mo
2.5 Mo.
1991
7 Mo.
-i
5 Mo.
1992
9 Mo.
11 Mo.
993
Figure 2--Coal reburning for cyclone boiler NOX control project schedule.
STACK
STEAM
SUPERHEATER
FOULING TUBE
DEPOSITION PROBE
FURNACE ARCH
PRIMARY AIR
AND COAL
TERTIARY AIR
SECONDARY AIR
FLUE GAS
RECIRCULATION
SLAG TAP
MOLTEN SLAG
SLAG COLLECTOR
AND FURNACE
WATER SEAL
Figure 3--Small boiler simulator (SBS).
3-91
-------
1100
1000-
900-
NOX
Corrected to 3% 02,
(ppm)
800-
700-
600-
500-
D Lamar Coal @ 6 x 106 Btu/hr.
+ Lamar Coal @ 4.5 x 106 Btu/hr.
Excess Oxygen, (%)
Figure 4--SBS baseline NO* emission levels.
1000-
800-
Stack NOX
corrected to
3% 02 600 -|
(ppm)
400-
200
Legend
Baseline conditions,
no reburning
Reburning Conditions
A Standard grind coal
• Medium grind coal
* Fine grind coal
Boiler Conditions
• Cyclone @ 10% excess air
• 0% Flue gas recirculation
• 6 x 106 Btu/hr load
0.9 1.0 1.1
Reburning Zone Stoichiometry
1.2
Figure 5--SBS NOX emissions with coal reburning.
3-92
-------
800
700-
Stack NOX,
Corrected to
3% 02l
(ppm)
600-
500
Boiler Load - 110 MW (Full Load)
Test Procedure - EPA Method 7E
234
Economizer Outlet Excess 02, (%)
Figure 6--Baseline NOX emission levels vs. excess 02. Nelson Dewey Unit 2.
19.0
17.0
o 15.0
13.0
11.0
9.0
0.0
Boiler Load - 110 MW (Full Load)
1.0 2.0 3.0
Economizer Outlet
Excess 02%
4.0
5.00
Figure 7--Baseline %LOI emission levels vs. excess 02 %. Nelson Dewey - Unit 2.
3-93
-------
700 i
600-
Stack NOX
corrected to
3% 02
(ppm) 500 -
400
30
50
Excess 02% at
Economizer Outlet - 3% 02 (Typical)
Test Procedure - EPA Method 7E
70 90
Load (MW's)
110
130
Figure 8--Baseline NOX emission levels vs. load. Nelson Dewey - Unit 2.
20.0
18.0
_op
8
12.0
10.0
50 60 70 80 90 100 110 120
Load (MW)
Figure 9--Baseline %LOI emission levels vs. load. Nelson Dewey - Unit 2.
3-94
-------
Figure 10-Wisconsin Power & Light Company, Nelson Dewey - Unit 2 (RB-369): cyclone reburn
project.
Rear Wall
700'-
681'-
Cold,—
Air—*
1_
Cyclone
To Fan
Burnout
Zone
IOFA
Reburn
. Zone
4 Reburners
25% Reburner
5% FGR Flow
Momentum Ratio Base
T Tc
TR-T,
Front Wai I
WP&L Mixing Test 31 - Elev. 681'
Rear Wall
Heated
Reburner
4 Reburners
30% Reburner
7.5% FGR Flow
Momentum Ratio Base
Front Wall
WP&L Mixing Test 33 - Elev. 681'
Figure ll--Examples of mixing test results.
3-95
-------
700
690
o 680
670
660
With FGR
700
690
680
§
OJ
670
660
3 Rbnrs, 3 OFA Ports
4 Rbnrs, 4 OFA Ports
0.9 1 1.1 1.2
Mean Stoichiometric Ratio
0 20 40 60 80 100
% Mass Flow with SR <1
Figure 12--Effect of number of reburners and OFA ports on reburning system mixing performance.
3-96
-------
Arrangement of Equipment for the Cyclone Reburn
Project at Wisconsin Power & Light Company's
Nelson Dewey Station, Unit No. 2
Partial Section
of Air Heater
Overfire Air Port
Figure 13--Equipment arrangement for the coal reburn project.
3-97
-------
DEMONSTRATION OF LOW NOX COMBUSTION TECHNIQUES AT
THE COAL/GAS-FIRED MAAS POWER STATION UNIT 5
J. Van der Kooij
Sep, Dutch Elecricity Generating Board
Ulrechtseweg 310, 6812 AR Arnhem, Netherlands
H.K. Hwee
A. Spaans
Stork Boilers
Industriestraat 1, 7553 CK Hengelo, Netherlands
J.J. Puts
N.V. Epz
Begijnenhof 1, 5611 EK Eindhoven, Netherlands
J.G. Witkamp
N.V. Kema
Utrechtseweg 310, 6812 AR Arnhem, Netherlands
-------
DEMONSTRATION OF LOW NOx COMBUSTION TECHNIQUES
AT THE COAL/GAS-FIRED MAAS POWER STATION UNIT 5
J. van der Kooij
Sep, Dutch Electricity Generating Board
Utrechtseweg 310, 6812 AR Arnhem, Netherlands
H.K. Kwee
A. Spaans
Stork Boilers
Industriestraat 1, 7553 CK Hengelo, Netherlands
J.J. Puts
N.V. EPZ
Begijnenhof 1, 5611 EK Eindhoven, Netherlands
J.G. Witkamp
N.V. KEMA
Utrechtseweg 310, 6812 AR Arnhem, Netherlands
ABSTRACT
Unit 5 of the Maas Power Station is a coal/gas-fired boiler
with horizontally opposed firing burners. In this boiler HTNR
low-NOx burners and after air ports have been installed to
demonstrate the viability of low-NOx combustion techniques. The
aim was to prove that in new installations NOX concentrations
of less than 400 mg/mj are feasible for a large variety of
coals, as well as to determine the impact of MO^ control
technology on boiler operation, performance and maintenance.
Prior to the retrofit of the boiler the HTNR burner was
modified to accomodate both coal and gas-firing.
Results are presented on:
* NOX emission with natural gas firing
* a parameter research on NOX emission and burnout: this
programme included burner setting, stoichiometry at the
burners, boiler load and excess air for three coal types;
* corrosion tests with reference materials;
* slagging tests with special probes;
* fly ash quality.
3-101
-------
INTRODUCTION
Since 1974 diversification of the fuel package for generation
of electricity has been one of the main objectives in the Dutch
energy policy. The reasons for preventing excessive dependence
on a few fuel types are to maintain the reliability of
electricity supply and to stabilize electricity tariffs. As the
decision on extending the use of nuclear energy was postponed
and natural gas was reserved for high-quality applications
only, a temporary switch to fuel oil was made in 1978. For the
longer term it was decided to make increasing use of coal, thus
reducing the role of fuel oil to a minimum. This process was
carried out in various phases. First, the existing power
stations, which used to be coal-fired, were once again made
suitable for coal-firing. Subsequently, two new coal-fired
power stations were built and four existing gas-fired power
stations were converted into coal-fired ones. In 1988 a coal
capacity of 3900 MW thus became available.
Approximately 40% of electricity production is now based on
coal-firing. This percentage will be maintained during the
nineties. Old power stations will be closed down, while new
coal-fired power stations will be commissioned. Three 600 MW
coal-fired units will be built at Amer, Hemweg and the
Maasvlakte. They are scheduled for completion by the middle of
the years 1993, 1994 and 1997 respectively.
As can be seen from Table 1, the standards for coal-fired
stations are tightened gradually. An important development was
the formulation of national standards in the Decree on Emission
Standards for Large Combustion Installations (1987). It
specifies maximum emission concentrations for SO,, NOX and
particulates for coal-, gas-, and oil-fired plants. The
combustion installations in question range from steam boilers
to process furnaces, stationary engines and gas turbines.
For coal-fired plants for which a license was or would be
granted after August 1, 1988, the national NO. standard is
400 mg/mj (STP, dry at 6% 02 ) . For installations with
horizontally opposed and front-wall firing the experience in
the Netherlands with modern combustion modifications was
considered to be insufficient in relation to the standard.
Therefore the decision was taken to carry out a demonstration
project at the Maas Power Station unit 5.
The project is performed in the framework of the Concerted NO -
Abatement Programme of the Dutch electricity generating
companies. In the programme low-NOx techniques are applied in
new and existing installations, while new technologies are
demonstrated to assess their applicability. Full-scale
demonstration is regarded as an essential step in confirming
the viability of the low-NO technology. The main thrust of the
demonstration is not only to quantify potential NO reductions
in actual boilers, but also to determine the exact nature and
the impact of NOX controls on boiler operation, performance and
maintenance.
3-102
-------
The demonstration of advanced low-NCL combustion techniques at
the coal/gas-fired Maas Power Station unit 5 is a joint
activity of many organizations.
EPZ, the electricity generating company in the Southern part of
the Netherlands placed the power station at the disposal of the
demonstration project. They commissioned Stork Boilers to
convert the power station and operated it in the low-NOx mode.
Sep, the Dutch Electricity Generating Board funded the project
and was responsible for coordination of the activities within
the Concerted NOX Abatement Programme. The Dutch Government
expressed its interest in the project and participated in the
project via NOVEM, the Dutch Association for Energy and
Environment, in the framework of the National Coal Research
Programme. Also, the Commission of the European Communites
subsidized the project in the framework of their Energy
Demonstration Programme: Gasification, Liquefaction and use of
solid fuels. The total amount of national and European
subsidies add up to approximately 10 million Dfl, i.e. 45% of
the project costs. After conversion of the power station EPZ,
Sep, Stork Boilers and NOVEM jointly performed a research
programme, together with KEMA, the research institute of the
Dutch utilities. REMA participated as a consultant in the
project and was responsible for a number of special
measurements and the scientific survey.
OBJECTIVES OF THE DEMONSTRATION PROJECT
The aim of the project is to prove that for new coal-fired
power plants a NO^ emission level of 400 mg/rr^ can be attained
without adverse side effects. In the retrofit situation, the
goal of 400 mg/rr^ is considered to be reached for given coal
types when NOX emission is below 470 mg/rn^ and the carbon in ash
content is below 2.6%. The relaxation of the standard by
70 rng/m^ compensates for the thermal load and the dimensions of
the furnace in the retrofit situation in comparison with a new
coal-fired boiler.
This goal was verified during guarantee measurements. For
Drayton coal 430 mg N0x/m3 was measured at 6% Oj and 1.4%
unburnt carbon in ash.
The scope of the demonstration programme was wider.
In order to investigate the impact of N0x-control technology on
boiler operation, performance and maintenance the operating
experience was evaluated and several possible side effects were
studied in a research programme.
With respect to the operating performance of the unit the
emphasis was on:
* safe and reliable operation of the boiler
* rapid response to load changes
* continuation of unit efficiency.
In the course of the research programme the impact of the coal
quality was studied. Three coal types were tested. These coal
types are different with respect to combustibility, NO
formation and burnout, but are well within the range of coal
types that are fired at the Maas power station. For each coal
3-103
-------
emission measurements were performed and the fly ash quality
and slagging tendency was investigated.
Moreover, a research project was carried out to investigate
whether the combustion modifications give rise to increased
fireside corrosion.
DESIGN OF THE LOW-NOx COMBUSTION SYSTEM
To achieve the NOX and UBC performance specified in the
objective of the demonstration project, low-NOx burners (HTNR)
were applied in combination with two-stage combustion. The
boiler and the combustion system are shown scematically in
Figure 1.
Low-N0x Burners (HTNR)
The original HTNR burner was developed by Babcock Hitachi for
firing pulverized coal with fuel oil as a supporting fuel.
For the specific conditions in the Netherlands, where natural
gas is used as a secondary fuel up to full load, modification
of the original HTNR burners was necessary.
The existing mill system at the Maas power station, unit 5 with
a relative high coal/air ratio in excess of 0.7 also led to a
minor modification of the internals of the original HTNR
burners which were designed for a coal/air ratio of 0.5.
The above-mentioned modification implied the following:
* implementation of a number of gas spuds surrounding the
pulverized coal nozzle;
* implementation of a gas igniter at the centre of the
burner;
* modification of the design of the flame stabilizing ring
for a coal/air ratio of 0.7.
The modified HTNR burner for coal- and gas-firing is shown in
Figure 2.
Low-NO,, Combustion System
A
To enhance NOX reduction, a two-stage combustion technique is
applied. One row of after air ports (AAP) was added at both
sides of the boiler. In order to optimize the mixing between
the after air and the combustion gases of the main combustion
zone, both the momentum and the swirl of the after air could be
adjusted (Figure 3).
Test Programme
Prior to the retrofit of the boiler, the burner and the lay out
of the furnace were tested by two trials:
* combustion test with a scaled down version of the
modified HTNR burner (1:7) in the 4 MWth test furnace of
Babcock Hitachi;
* water flow simulation of the gas/air mixing in the
furnace. Scale based on geometry 1:30.
3-104
-------
Combustion Test The combustion test was carried out in two
steps:
* coal/gas combustion test with the following objectives:
- assessment of flame stability and NOX performance;
verification of burner design;
assessment of the ignition behaviour of the gas and
coal flame;
* confirmation of the coal combustion test with the
following objectives:
evaluation of NO. and UBC performance;
- prediction of NOX and UBC performance for Maas power
station, unit 5.
During the combustion tests Blair Athol and Wambo coal were
used and a parameter study was carried out to evaluate the
influence of burner setting, stoichiometric ratio, primary/
secondary/tertiary air ratios and position of the gas spuds.
Some data from the combustion test are presented in Figure 4
for Wambo coal.
From these results a 15% higher NOX emission was estimated for
the modified burner in comparison with the original HTNR
burner. The outlook for UBC performance was unchanged.
It is not known whether this phenomenon is caused by the
increased space between the secondary and tertiary air and/or
by the higher coal/air ratio of the modified burner.
Water Flow Simulation One of the conditions for achieving good
combustion performance for two-stage combustion is intimate
mixing in the furnace of the AAP combustion air and the
combustion gas coming from the burner zones. Special attention
is paid to the design of the AAP' s due to the limited furnace
height available and the staggered arrangement of the burners
of Maas Power Station, unit 5.
The design of the AAPs was verified by means of a test with a
three-dimensional water flow simulation (Figure 5).
The flow analysis is performed using the Image Processing
Technique. The flow is visualized using polystyrene as a tracer
in combination with the tomography technique (slit light
illumination).
Figure 6 presents a typical result.
MODIFICATION OF THE BOILER
Maas Power Station unit 5 is a coal- and gas-fired unit rated
at 177 MWe and it was commissioned mid-1966. The boiler
manufactured by Stork Boilers is a Benson type with divided
second pass for steam temperature control. The technical
specification of the boiler and the combustion system is given
in Table 2.
In the summer of 1988 the boiler was modified to a low-NOx
combustion system.
3-105
-------
The modification involved the following main elements:
* Replacement of the 16 single register burners by 16
advanced low-NC^ HTNR burners.
* Replacement of the burner throats while maintaining the
same staggered arrangement of the horizontally opposed
burners as before the retrofit.
* For two-stage combustion 8 after air ports (AAP) were
placed above the upper rows of the burners.
* Modification of the combustion air ducts in order to
accomodate for two-stage combustion.
* Upgrading of the control system of the boiler and the
flame monitoring system.
* Extension of the flue gas analysing equipment.
As mentioned previously, the HTNR burner shown schematically in
Figure 2 is a modified HTNR burner, suitable for coal and gas
firing. Due to the limited available furnace height and
limitation of space surrounding the furnace a special after air
port as shown schematically in Figure 3 was designed.
The total modification took less than three months and the
boiler with advanced low-NOx combustion was commissioned in
August 1988.
DEMONSTRATION PROGRAMME
To establish the results of the combustion modifications, a
comprehensive measuring programme was set up.
The measuring programme consisted of a pre-retrofit baseline
test and a post-retrofit test series.
A brief summary of the test series is given below.
Pre-Retrofit Baseline Tests
The objective of these baseline tests was to establish the
basis for evaluation of the boiler and emission performance
before and after the modification of the combustion system.
Data for coal and gas firing were collected for
characterization of:
* NO. emission and unburned carbon (UBC) as a function of
boiler load and excess air;
* fly ash quality and slagging behaviour;
* boiler efficiency.
These tests were carried out in March and May 1988.
Post-Retrofit Tests
The post-retrofit tests that followed the commissioning of the
boiler with the new low-NOx combustion system involved an
extensive and systematic variation of the boiler and combustion
system operating parameters.
The post-retrofit tests consisted of two test series, i.e. test
series for gas firing and coal firing respectively.
3-106
-------
Gas Firing The post-retrofit tests for gas firing were carried
out for two weeks in November/December 1988.
Similar to the baseline test series, data were compiled for the
characterization of NOX and CO as a function of boiler load and
excess air.
To identify the capability of the combustion system, several
combustion operating modes were tested:
* conventional combustion. In this case the windbox dampers
of the after air ports were closed. An appropriate flow
of purging air is necessary to protect the after air
ports against excessive temperatures;
* two-stage combustion mode with variation of the burner
stoichiometric ratio.
Coal Firing A comprehensive post-retrofit test programme for
coal firing was set up to compile data for evaluation. This
programme involved the following:
* Parameter study to develop data for NOX emissions and UBC
as a function of coal properties, boiler load, combustion
mode, excess air, burner and AAP adjustment and burner
stoichiometry.
* Corrosion test by means of test tubes in the furnace wall
and gas analysis near the furnace wall.
* Study of the slagging conditions at the furnace wall.
* Characterization of the industrial applicability of the
fly ash.
* Recording the boiler operation under normal combustion
conditions.
Extensive tests were carried out in the period from January
1989 to June 1990. During this test period the demonstration
programme was interrupted due to the following problems:
* Slagging at the burner and AAP throat
Soon after the beginning of coal firing in the
conventional combustion mode heavy slagging was observed
at the AAP throat. This was attributed to the excessive
refractory of the throat.
This problem was solved by removing some of the throat
refractory. A few months later the same problem occurred
at the burner throat. It was solved in a similar way.
* Damage to the flame stability ring
After one year's service, damage to the flame stabilizing
ring was observed. This damage was more serious than
expected. Inspection of the ring showed that this was
caused by extremely high temperatures. These conditions
occurred during gas firing and when the burner was out of
service.
To avoid high temperatures of the flame stabilizing ring,
the burners were modified. This modification involved
lengthening of the gas spuds and providing the pulverized
coal nozzle with purging air.
3-107
-------
In spite of the above-mentioned problems, comprehensive data
have been developed for three coal types.
For each coal type a continuous test period varying from one to
two months has been taken.
RESULTS OF THE COMBUSTION TESTS
Gas Firing
The post-retrofit tests showed that a remarkable NO reduction
was achieved after the boiler modification.
A summary of the test results is illustrated in Figure 7.
Before retrofit NO concentration was slightly higher than
500 mg/mL After the modification NO concentrations were
between 150 and 250 mg/rn^, dependent on the burner setting. For
two-stage combustion the influence of burner setting was small
and a NO concentration of 100 mg/mj was measured, corresponding
to 80% reduction in comparison with before retrofit.
During the post retrofit test a larger excess air flow (2% 02
at air heater inlet) is necessary to achieve low carbon
monoxide concentrations.
Optimization of combustion to achieve CO-free combustion at
lower excess air was not an objective in the demonstration
project.
Coal Firing
In this section a brief overview is presented of the data
obtained after modification and a comparison is made with the
performance before retrofit. A summary of the coal properties
is given in Table 3.
Effect of Boiler Load Typical NO emissions as a function of
boiler load selected from the post-retrofit tests are
illustrated in Figure 8.
In general it is apparent that NO increases with load. A
similar trend is observed for the pre-retrofit results.
Concerning the UBC analysis of the fly ash UBC appeared to be
almost boiler-load-independent. The effect of excess air on NOX
emission is also shown in this figure.
Effect of Combustion Mode and excess Air A comparison of the
NO and UBC performance under pre- and post-retrofit conditions
was made for the coal types investigated.
NO and UBC as a function of the excess air are illustrated in
Figures 9, 10 and 11 for three coal types.
These figures also show the effect of the combustion mode, i.e.
conventional and two-stage combustion.
For both combustion modes a similar trend is apparent for the
effect of excess air on NO and UBC performance.
A comparison between the post-retrofit tests and the pre-
retrofit baseline tests gives the following results:
3-108
-------
* For the conventional combustion mode approximately 30%
NO. reduction is achieved after modification of the
boiler.
At low excess air a higher UBC is measured after
modification of the boiler. This can be explained as the
amount of excess air is effectively lower, because 2-4%
of the combustion air is supplied through the AAPs as
cooling air. Moreover, the burners are designed for two
stage combustion. The design is not optimized for
conventional combustion.
* In two-stage combustion mode, approximately 50% NO
reduction is achieved after modification.
Concerning UBC performance no significant difference in
UBC performance is measured for 02-concentrations at the
air heater inlet higher than 4%. The measured UBC is
within the limit of 5%.
Off-stoichiometric Combustion Tests were performed to
investigate the combined effect of two-stage combustion and
off-stoichiometric combustion. In this way the burner
stoichiometry is different for the upper and the lower burner
levels. Off-stoichiometric combustion can be implemented in
several ways:
* by controlling the pulverized coal flow to each burner
level (mill operation) and/or
* by controlling the combustion air flow to each burner
level (windbox damper operation).
Due to the limitations of the mill system only one test with
biased fuel distribution was carried out. As shown in Figure
12, the effect on NOX was small.
Windbox damper operation offered more potential to control the
burner stoichiometry of each burner level. The results of these
tests are illustrated in Figure 12.
By reducing the combustion air flow to the lower burner levels
by 20% and feeding this to the upper burners more than 20%
extra NOX reduction was obtained, while UBC was kept constant.
Effect of After Air Adjustment As mentioned before, the mixing
of the after air with the combustion products of the main
combustion zone is of paramount importance. Experiments were
performed to optimize the settings of the after air ports,
including the rotation and the momentum of the after air.
The results of these tests are illustrated in Figure 13.
As shown in this figure, it is apparent that particularly the
secondary air register adjustment, which defines a certain
swirl level, has an important influence on NOX emission and UBC
performance.
Less swirl of the after air led to lower UBC and higher NOX
emission. For high swirl levels NOX also increases. The reason
is that for high swirl levels of the after air ports the
distribution of the combustion air between burners and after
air ports could not be maintained. These data therefore
represent a higher burner stoichiometry.
3-109
-------
SIDE EFFECTS OF COMBUSTION MODIFICATIONS
In the framework of the demonstration project KEMA investigated
the possible consequences of the combustion modifications on
fireside corrosion, slagging and fly ash quality. Before and
after the retrofit samples were taken and measurements were
performed. The results and conclusions are reported below.
Fireside Corrosion
When two-stage combustion is applied, reducing atmospheres will
occur in the furnace locally. When such atmospheres exist at
the surface of boiler tubes, fireside corrosion might be
accelerated. In order to establish the risk of increased
fireside corrosion for the evaporation tubes, eleven test tubes
were welded in the furnace. Eight test tubes are 5 metres long
and consist of three different materials: 13CrMo44, 15 Mo3 and
310. To measure wall thickness accurately 30 test surfaces were
marked. By means of ultrasonic measurement the thickness of all
test surfaces was determined.
The test tubes were welded in the front and side walls of the
furnace in positions ranging from below burner level row to
above the after air ports.
After exposure during 17 months the test tubes were removed and
examined. It appeared that the thickness of only eight out of
273 test surfaces had changed by more than 0.05 mm, which is
the accuracy of the measurement method. Four of these samples
were not reliable. As for the remaining four samples a decrease
was measured in two samples and an increase in the other two.
The general conclusion was drawn that after 17 months of
exposure no decrease of wall thickness was established greater
than 0.05 mm. This means that the decrease of wall thickness
over a period of twenty years under comparable conditions will
be less than 1 mm. It should be mentioned that the conditions
near the furnace walls are not extremely reducing. Measurements
of the gas composition showed that some Oj was available and
that the concentrations of CO and H2S were not extremely high.
Slagging Tests
Slagging is considered to occur in two stages. In the first
stage deposition occurs in the liquid state. These components
may adhere to the evaporation tubes. The most important
components that are in the liquid state at ± 450 °C are
alkali/iron sulphates and partly oxidized pyrite.
After the formation of a liquid layer other materials can be
deposited due to the sticky nature of the material. The
deposited materials insulate the surface from the evaporation
tubes, so that the temperature increases and gradually higher
melting materials can be deposited.
The first stage of slagging was investigated with an air-cooled
metal probe at 425°C. For the second stage a ceramic probe was
used at the local furnace temperature.
3-110
-------
The results of the slagging tests with the metal probe are
summarized in Table 4. They showed that the deposition rate
before retrofit varied between 0.60-0.78 mg/cm ,h. After
retrofit the values differ over a wide range (0.04-10.24
mg/cm2,h) .
Compared with the composition of the coal ash the deposition is
enriched in Fe and to some extent also in Na, K and S. The low
iron content in the deposition before retrofit was remarkable
(2.2%). After retrofit values higher than 30% were measured for
the same coal type. Comparable concentrations were found for
other coal types. This indicates that after the retrofit partly
oxidized pyrite has a better chance to start the slagging
process.
In the same way examination of the test tubes i.e. the surface
of material 13CrMo44 with SEM/EDS indicated the presence of
alkali iron sulphates and possibly also sulphides.
In agreement with the above-mentioned theory on staged slag
formation, there was no relationship between the melting point
of the coal ash and the deposition of materials on the metal
surface. Also, the influence of the additive copper oxychloride
was negligible.
The composition of the deposits on the ceramic probe, however,
is comparable to that of the coal ash.
In the deposits sampled when.Cerrejon coal was fired the effect
of the additive CuOCl is clearly visible in the structure of
the slag. SEM graphs show larger pores in comparison with the
situation without additive. For Illawara and ANR coal this
effect is not visible. The structure of these samples is more
brittle than the Cerrejon sample, which was heavily melted
through.
Fly Ash Quality
Lab tests were carried out in order to assess the applicability
of the fly ash for use in concrete or cement. The experiments
included amongst other things the determination of particle
size distribution, compression strength and surface area. All
the investigated fly ashes met the standards for industrial
application.
OPERATIONAL EXPERIENCE
During the day the boiler is operated at full load. Two-stage
combustion is applied as the normal firing mode. For the start-
up procedure and at night, when the boiler is operated at low
load, the after air ports are closed and conventional firing is
applied. Although from visual observation combustion
performance is still good at low load with two-stage
combustion, the flame signals decrease for some burners. It was
shown that the problem can be solved by adjusting of the flame
scanners.
In general the operational experience is positive after two
years of low-NOx operation. There were no adverse effects on
boiler efficiency. In general the low-NO, combustion system did
3-111
-------
not effect the dynamic behaviour of the boiler, except for the
mentioned change in firing mode at low loads. The problems with
slagging on the burners and after air ports were solved. There
is no significant difference in furnace wall and superheater
slagging behaviour before and after retrofit.
Bottom-ash Hopper Explosions
In September 1989, about one year after commissioning, an
explosion in the bottom-ash hopper occurred during combustion
trials with ANR coal and two doors of the hopper were damaged.
The bottom-ash hopper is filled with water and consists of
four, partly connected, compartments from which the ash is
removed at regular intervals through de-ashing doors. After the
first time a series of explosions, some more violent than
others, followed. At first the explosions occurred during two-
stage combustion but later on also during conventional
combustion. It was concluded that the nature of the phenomenon
was a steam explosion and not a gas explosion:
* CO-measurements just above the bottom-ash hopper showed
only traces (maximum 300 ppm);
* the increase in furnace pressure during an explosion was
small and no damage was found in the boiler itself; the
damaged doors indicate a shock-wave inside the water
pool.
Before the boiler modifications no problems of this kind were
experienced, although in the past small pressure waves in the
boiler were measured when big lumps of slag fell into the
hopper. Therefore, before retrofit measures were taken to
reduce the slagging propensity by adding copper oxychloride to
the coal in order to obtain a more crushable slag. Although
regular observations did not show an increase in slagging
propensity after the retrofit, a possible explanation for the
explosions was the formation of much more porous and crushable
slag than in the past, which disintegrates rather
instantaneously on impact with the water filled hopper. This
would lead to a very fast heat exchange and subsequent steam
formation. The following measures were taken:
* a change in the burner settings in order to obtain a more
slender flame with less impingement on the side walls of
the boiler;
* no more addition of copper oxychloride;
* as it was experienced that sometimes an explosion
occurred after the refilling of the hopper with water,
more gradual refilling was applied;
* safety valves were applied on the doors to avoid damage
in case of an explosion.
Some bottom ashes were analyzed to get an impression of the
porosity by measuring the density. Comparison with the data
before retrofit did not show great differences. Also no clear
relation was found between coal type and the occurrence of
explosions. Until now no satisfying solution has been found and
small explosions continue to occur, but they do not cause
serious damage and the problem is manageable.
3-112
-------
Emission from Day to Day
It is interesting to compare emission levels day by day during
normal operation of the boiler with the results of the
demonstration tests. Therefore, each day during stable
conditions, the NO concentration is measured in combination
with several important parameters. In Figure 14 the NO emission
in mg/rn^ at 6% Oj and the amount of unburnt carbon in the fly
ash is presented for the month September 1990. In this period
the boiler was operated near full load. All data represent two-
stage combustion. Steam production and 02 concentration before
the air heater are also plotted in the figure. Three coal types
were fired in this month: Mingo Logan, Hobet and Anker Blend.
For three days coal blends were fired. The composition of the
coal is given in Table 5.
The average values for one month were: steam production
550 t/h; NO concentration 540 mg/mj at 6% Oj and unburnt carbon
1.7%. Further evaluation of the emission data during normal
operation of the boiler is still in progress, but these data
indicate that the NO figures for normal operation are close to
those obtained in the tests; the fly ash quality was good.
CONCLUSIONS
The HTNR burner developed by Babcock Hitachi for pulverized
coal firing was modified to accomodate both coal and gas
firing. The dual fuel burners and after air ports were
installed in the Maas Power Station unit 5 to demonstrate the
viability of low-NO. combustion techniques.
In the framework or the demonstration programme the combustion
system was optimized and extensive tests were conducted for
three coal types and natural gas.
For natural gas the NOX reduction amounts to values between 50
and 70% in the conventional combustion mode and 80% for two-
stage combustion. For coal firing typical reduction percentages
are 30% and 50% respectively. Adjustment of the burners was
generally effective for NOjj and UBC. Adjustment of the after
air ports appeared to be critical for UBC.
Typical results obtained for Cerrejon coal are 480 mg NO/m^ (6%
02 ) at 95% load and 25% excess air. For ANR coal the NO
concentration was 500 mg/mj at 6% Oj. Combination of two- stage
and off-stoichiometric combustion resulted in 15% more
reduction without impairment of UBC. For Illawara coal, which
is characterized by a high fuel ratio, the NO concentration
amounts to 600 mg/m^ at 6% Oj.
In the framework of the demonstration programme the impact of
combustion modifications on fireside corrosion was
investigated. It appears that under the conditions prevailing
in the furnace of Maas Power Station Unit 5 there is no risk of
increased fireside corrosion.
During the programme severe slagging problems have occurred on
the burners and after air ports. These problems were solved.
Measurements with a slagging probe indicate that there is an
increased tendency to form a liquid deposition layer in
comparison with the situation before the retrofit. In
3-113
-------
contradistinction to these slagging tests, it appears that
there is no significant difference in furnace wall and
superheater slagging behaviour before and after retrofit.
In general the operational experience is positive after two
years of low-NOx operation. There were no adverse effects on
boiler efficiency. In general the low-NOx combustion did not
effect the dynamic behaviour of the boiler, with the exception
of the change in firing more at low loads. Until now no
satisfying solution has been found to prevent bottom-ash hopper
explosions, but they do not cause serious damage and the
problem is manageable.
3-114
-------
Air
Air
-0-
AAF
BURNER
BURNEI
Air
Air
I
1 .
MILL 1
-0--
-0"
-0-
MILL 2
FIGURE 1. SCHEMATIC PRESENTATION OF THE FURNACE
AND COMBUSTION SYSTEM
laniter
FIGURE 2. MODIFIED HTNR-BURNER FOR COAL AND GAS FIRING
3-115
-------
Primary Air
FIGURE 3. AFTER AIR PORT (AAP)
300 400 t 500 600
-Checkpoint for NOx
Coal Feed Rate (Kg/h)
FIGURE 4i RESULTS OF COMBUSTION TEST 4 MW TEST BURNER
COAL TYPE: WAMBO
3-116
-------
ilLj_
FIGURE 5. WATER MODEL FOR FLOW SIMULATION
Sf = Sr
Ff = Fr Sf
-------
1
Q
? --.-.
S
Q
5
^
i»-i
»-i
0 6
-^
•^"
^--'
O 7
^--
^-"
^--^
o a
o L Le r
^^
r-^
0 9
.oad ("
0
y
O i
• 3* 02
4 4.3» O2
DO
2H 02
FIGURE B. EFFECT OF BOILER LOAD ON NO-EMISSION
COAL TYPE: CERREJON
3-118
-------
14OO
eg
O
S! 100O
if
1
en 800
£ 600
§
40O
/
/ ^
<^-
X
^-
»
CONV.
A PostRelrofit
CCXJV
O PostRolrofit
TSC
O BOO
O2 Inlet Alf Heater <%)
O2 njet Au Hetatwr (-/J
b 8
1
\
Pre-Relrofit
CONV
PoslRctrofit
CONV
PostR«trofil
TSC
\
PoilHk,
rsc
O2 Inlet Ar Heater 1%)
O2 inlbt Au Heotej ("A,)
FIGURE 9. EFFECT OF EXCESS AIR
CERREJON AT 951 MCR
FIGURE 10. EFFECT OF EXCESS AIR
ANR AT 1001 MCR
O 800
#
246
O2 lnle( Aif Healer 1%)
Post Heiio-
fit CONV.
Post Reuo-
fit TSC
Post Reuo -
fit CCTJV.
Post Reuo-
ht TSC
2468
O2 irilet Aw Hea itif IW
FIGURE 11. EFFECT OF EXCESS AIR
ILLAWARA AT 95Z MCR
3 O
0,ee-1.O4 076-1.14 1.04-O.67 1.O4-O.9
Sfl txjner Bottom - U|»«-
FIGURE 12. EFFECT OF BURNER OFP-STOICHIOMETRY
OH TWO STAGE COMBOSTIOH
3-119
-------
0 500
(0
1
1
E;
Q 400
A
9 ^
O
~. _
-
x
/:
/ I
/
_ " ^
'' .
3
-
A prim air
k O prim air
damper 30%
V prim air
- damper 50%
L D prim air
1 damper 75%
O prirn air
damper 1OO%
0 20 4O 60 8O 10O
Secondary Air Register AAP (%)
o
7
A- -
I
N
X
s
ss!
s
N
",
S
^ prim air
damper 1O%
O prim air
damper 3O%
7 prim air
damper 5O%
D prim air
damper 75%
° prim air
damper 1OO%
0 2O 4O 6O 80 1OO
Secondary Air Reaister AAP (%)
FIGURE 13. EFFECT OF AAP ADJUSTMENT CERREJON AT 95% MCR
steamprod. —- O2-conc bef NO—cone in — • unbunt
t/hr airheater rng/hin3 carbon
ouu
-------
TABLE 1
NOX EMISSION STANDARDS FOR COAL-FIRED POWER STATIONS
Power station
Commissioning Standard
Remarks
Maas no . 6
Maasvlakte no. 2,
Borssele no. 12
Maasvlakte no. 1
Amer no. 9
Hemweg no . 8
Maasvlakte no. 3
1986
1987
1987
1988
1993
1994
1997
270 g/GJ
* 750 mg/m3
400 mg/mj
300 mg/rn^
200 mg/m]
test value
190 g/GJ * 530 mg/m^
as a criterion for
low-NO. burners
&
commitment to pursue
200 mg/rn^
TABLE 2
MAAS POWER STATION UNIT 5
Unit capacity
Boiler type
Boiler manufacturer
Commercial operation
Steam production
Steam pressure/temperature
at superheater outlet
Number of burners
Burner heat capacity
Number of mills
Mill type
Coal consumption
Coal/air ratio
177 MWe
Benson
Stork Boilers
1966
580 t/h
188 bar / 540°C
16 (2x2x4, opposed)
30 MW
2
tube mill
64.5 t/h
0.725
TABLE 3
COAL PROPERTIES
LCV/GCV
Moisture
Ash
Volatile
HGI
Fuel ratio
Ndaf
MJ/kg
Cerrejon
26.3/27.5
12.4
5.4
33.0
48
1.49
1.60
Illawara
26.9/27.8
5.0
16.6
19.1
78
3.12
1.55
ANR
28.5/29.6
6.6
7.7
31.8
50
1.69
1.70
3-121
-------
TABLE 4
DEPOSITION ON METAL SLAGGING PROBE
Coal type Additive Deposition rate
CuOCl (mg/cm2.h)
ANR* + 0.60-0.78
Cerrejon + 0.06-0.57
Cerrejon - 0.04-0.30
Illawara + 0.30-1.26
Illawara - 2.02-3.13
ANR + 0.40-5.45
ANR - 0.40 - 10.25
pre-retrofit
TABLE 5
COAL COMPOSITION IN SEPTEMBER 1990
Mingo Logan Hobet Anker Blend
"A B C
Moisture (%) 7.5 6.9 9.3
Ash (%) 10.5 11.2 11.6
Volatile (%) 28.0 30.7 28.9
LCV (MJ/kg) 27.6 27.4 26.5
N-daf (%) 1.5 1.6 1.6
3-122
-------
Three-Stage Combustion (Reburning)
on a Full Scale Operating
Boiler in the U.S.S.R.
By
R.C. LaFlesh, R.D. Lewis, and O.K. Anderson
Combustion Engineering, Inc.
1000 Prospect Hill Road, Windsor, CT 06095
Robert E. Hall
U.S. Environmental Protection Agency
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
V.R. Kotler
All Union Heat Engineering Institute (VTI)
Moscow, U.S.S.R.
-------
ABSTRACT
This paper presents the results of a program to complete the preliminary
design of a three-stage combustion (reburn) system for nitrogen oxides (NO )
emissions control on an operating 300 MWe coal fired boiler in the U.S.S.R.
This project was sponsored by the U.S. Environmental Protection Agency (EPA)
in support of the protocol of the Eleventh Meeting of the Stationary Source
Air Pollution Control Technology Working Group, Moscow, U.S.S.R., November
1988.
The program to design the reburn system was composed of five major tasks: 1)
visiting the host site in the Ukraine to exchange design and operating
information; 2) translating Soviet design documents into English; 3)
performing process calculations; 4) conducting physical flow modeling; and 5)
developing a preliminary system design which included general arrangement
drawings and furnace performance analyses.
The overall preliminary reburn system design was completed and was presented
to and accepted by Soviet representatives during a June 1989 meeting at the
EPA's Air and Energy Engineering Research Laboratory (AEERL)in Research
Triangle Park, NC. The Soviets are currently completing the final detail
design and are targeting completion of hardware fabrication and installation
by the fourth quarter of 1991. All indications to date are that reburning
will be a viable NO reduction technology for the type of boiler (opposed-
wall-fired, wet bottom) that the host steam generating unit represents.
BACKGROUND
A joint U.S./U.S.S.R. committee for cooperation in the field of environmental
protection has sponsored meetings of a working group on stationary source air
pollution control technology over the past 13 years. The U.S. Environmental
Protection Agency's Air and Energy Engineering Research Laboratory has been
responsible for technical information exchange activities under this program
and, as of the Eleventh Working Group meeting in Moscow, November 1988, has
sponsored the first major joint U.S./U.S.S.R. air pollution control research
project with the objective of implementing NO control technology on a large
coal fired boiler in the Soviet Union.
The Soviet Union has substantial interest in controlling air pollution and is
currently developing a program for legislating NO emission levels from
electrical utility boilers. The current plan calls for the following NO
emission rules to be implemented for all new boilers having greater than 463
tons/hr (420 metric tons/hr) steam flow:
Natural Gas 0.08 lb/106 Btu (125 mg/Nm @ 3% 0 )
Fuel Oil 0.12 lb/10 Btu (185 mg/Nm @ 3% 0 )
Coal 0.18 lb/10 Btu (225 mg/Nm @ 6% Q^)
NO emissions from existing utility boilers are also to be regulated under
the proposed legislation. Again, the current plan calls for the following
NO emission rules:
x
3-125
-------
Natural Gas 0.15 lb/10 Btu (250 mg/Nm @ 3% 0 )
Fuel Oil 0.19 lb/10 Btu (290 mg/Nm @ 3% 0 )
Coal (brown) 0.28 lb/10 Btu (340 mg/Nm @ 6% 0 )
Coal (bituminous) 0.33 lb/10 Btu (400 mg/Nm @ 6% 0 )
The joint U.S./U.S.S.R. program called for the U.S. side (Combustion
Engineering, Inc. under contract to U.S. EPA) to provide the Soviet side with
a preliminary design for an in-furnace NO control system for a specific
Soviet boiler in anticipation of meeting impending NO legislation. The
Soviet side's participation in the project includes final detail design,
fabrication, installation, and testing of the system. The U.S. side is
assisting in an evaluation of the system's effectiveness in controlling NO
by providing NO monitoring instrumentation and technical support during
testing.
Both sides focused on the use of reburning as the technology of choice for
this project. Reburning (referred to by the Soviets as "three-stage
combustion") is an attractive alternative for in-furnace NO control where
either physical or operational modifications to the existing fuel firing
system (as required with most low NO retrofits) would be problematic from a
boiler operating standpoint. Application of reburn technology does not
require any configuration operational changes to a boiler's existing firing
system. The Soviet side selected a wet bottom (slagging) unit as the design
case; any change in the existing firing system to reduce NO could negatively
impact on slag management in the boiler. As a result, reburning technology
was chosen for implementation on the Soviet boiler. The boiler chosen to
represent the design case is located at the Ladyzhinskaya Power Station in
the Ukrainian city of Vinnitsa. (Figure 1.) The power station consists of
six 300 MWe coal fired boilers of the Soviet type Tnn-312. These
supercritical (3625 psig or 255 kg/cm ) steam pressure units employ
swirl-stabilized opposed-wall-fired coal burners (16 per boiler) which burn
locally available high volatile bituminous coals of relatively high (35%) ash
content. The boilers operate under slagging conditions; that is, a portion
(-30% by weight) of the ash is retrieved as wet slag at the furnace bottom,
and the remaining 70% by weight of ash input into the boiler is collected at
the furnace outlet by electrostatic precipitators.
According to Soviet data, baseline NO emissions from these units typically
range between 0.5 and 1.0 lb/10 BtuX (650 and 1300 mg/Nm @ 6% 0 ). The
objective of the project described herein is to demonstrate that reburn
technology can reduce NO emissions to a level consistent with the
aforementioned proposed NO rules on a Soviet type TTTTr-312 boiler. If the
demonstration is successful, the Soviets may extend the use of the technology
to the other units at Ladyzhinskaya as well as 300 other units of this class
located elsewhere in the Soviet Union.
REBURN PROCESS OVERVIEW
The concept of reburning or three-stage combustion and the postulated
chemical reactions which account for the reduction of NO in the reburn zone
have been addressed elsewhere in the literature and will 'not be reiterated in
detail here (1,2,3,4). Briefly, reburning is an in-furnace technique for
reducing NO by creating a slightly reducing (substoichiometric) zone
downstream of the primary combustor as shown schematically in Figure 2. The
3-126
-------
reducing zone is created by introducing fuel into a zone with insufficient
oxygen available to fully combust the fuel. The presence of a reducing zone
creates intermediate nitrogen-containing species (e.g., NH., HCN) which
subsequently react with previously formed NO to form the desired product,
molecular nitrogen. Any unburned fuel leaving the reburn zone is
subsequently burned to completion in the burnout zone when additional
combustion air is added. Reburning can be used on all types of fossil fuel
fired boiler configurations using coal, oil, or gas as primary fuels and, in
fact, has been successfully employed on a number of large utility oil fired
boilers in Japan where oil has been used as the reburn fuel (5) . The
technology is particularly adaptable to slagging furnaces employing cyclone
combustors (6) or swirl stabilized burners similar to those used in the
Ladyzhinskaya units. Since these combustors may not be able to tolerate
significant changes to their operation, such as lower excess air or staged
air injection, without the possibility of creating other problems (such as
slag tapping: the removal of coal-ash slag through the furnace bottom while
still in its molten state), they are limited to an in-furnace NO reduction
technology that does not depend on significant changes to its present mode of
operation. Reburning does not require that any significant operational
changes be made to the primary combustor or burners. The key requirement is
that the fuel feed rate be reduced in the primary combustor with an
equivalent amount (on a Btu basis) of fuel being injected into the reburn
zone, usually not more than 20% of the total fuel input. The excess air
(hence the air/fuel stoichiometry within the main burner zone) can be held
constant, thereby avoiding the potential for operational problems.
SYSTEM PROCESS DESIGN
The project was initiated by an exchange of boiler design information between
the U.S. and Soviet sides. Meetings were held both in the U.S. and at
Ladyzhinskaya in order to facilitate the transfer of information. Reburn
system process design was then initiated based on the following overall
process objectives:
1) Meet key design criteria for effective NO reduction while
minimizing any impact on normal boiler operation.
2) Incorporate operational flexibility within the design to permit
optimized host unit performance.
Key design criteria commensurate with the overall design objectives for the
reburn system were initially established. The criteria consist of
theoretical criteria for effective NO reduction, obtained through the open
literature, and practical, commercial considerations for reburn system
design, installation, and operation.
Key design criteria for the reburn zone were determined to be:
• Inject reburn fuel into as high a temperature zone as possible.
• Maintain average stoichiometry between 0.90 and 0.99.
• A small amount of 0. should be present to promote formation of OH and H
radicals.
• Maintain a minimum furnace gas residence time of 0.5 sec.
• Maximize entrainment, mixing, and dispersion of reburn fuel.
3-127
-------
• Avoid direct fuel impingement on boiler walls.
• Minimize the number of required boiler penetrations.
• Locate fuel injection nozzles to minimize boiler/structural steel
modifications.
• Provide for maximum flexibility of reburn fuel jet direction and flow
rates.
Key design criteria for the burnout zone were determined to be:
• Inject burnout air in as low a temperature zone as possible commensurate
with obtaining fuel burnout before entering the superheater surface.
• Provide for rapid mixing of air to minimize pockets of unburned fuel.
• Avoid direct air impingement on furnace walls.
• Minimize final excess oxygen commensurate with obtaining good fuel
burnout.
• Maintain a minimum furnace gas residence time of 0.6 sec.
• Minimize the number of required boiler penetrations commensurate with
obtaining good mixing.
• Locate burnout air injectors to minimize boiler structural modifications
while providing good mixing.
• Provide for maximum flexibility of air jet direction and flow.
With the above in mind, as well as the Soviet utility's requirements that the
reburn system not adversely affect slag tapping, not increase tube metal
temperatures beyond design limits, and not affect general slagging/fouling
characteristics, CE initiated the preliminary design by performing mass
balance and combustion calculations on the overall process. Existing process
flows were used in this calculation, along with the Soviet coal analysis, an
estimate of flue gas recirculation (FGR) mass flow necessary for the fuel
injectors (natural gas used as reburn fuel, FGR as a transport medium to
enhance mixing), furnace dimensions, and Soviet supplied furnace gas
temperature information. A proprietary CE computer code was employed to
calculate stolchiometric ratios and gas residence times in boiler zone 1 (the
furnace bottom to the reburn zone start or main burner zone) , zone 2 (the
reburn fuel injection position to the burnout air injection position or
reburn zone), and zone 3 (the burnout air injection position to the
horizontal furnace outlet plane, or burnout zone). Estimates for the reburn
fuel and burnout air injection position (elevation) were input into the code
and then iteratively adjusted to achieve reburn/burnout zone stoichiometries
and furnace gas residence times consistent with the key design criteria. An
example of output from the process design calculations for the final design
case for the reburn zone is shown in Table 1.
The above process calculations set the preliminary elevations for the reburn
fuel and burnout air injectors, based on calculated furnace gas residence
time of 1.59, 1.00, and 0.92 sec for zones 1, 2, and 3, respectively. The
preliminary reburn fuel elevation was set at 66.6 ft (20.3 m) and the burnout
air injector elevation at 95.8 ft (29.2 m) consistent with the above gas
residence time calculations.
PHYSICAL FLOW MODELING
Isothermal flow modeling studies were conducted as part of this program in
order to optimize the number, location, configuration, and operating
3-128
-------
parameters for the reburn fuel and burnout air injector system. Baseline
furnace aerodynamics were evaluated as well as the performance of a number of
candidate reburn system configurations.
Total mass flow rates for the reburn fuel, carrier gas recirculation, and
burnout air, as well as injection elevation in the furnace, were specified
from the process flow calculations described previously. Candidate reburn
fuel and burnout air injector configurations were identified based on
previous experience.
These configurations were then screened by calculating expected jet
trajectories for each configuration's reburn fuel and burner air nozzle
arrangement. Jet velocities investigated ranged from 146 to 275 ft/sec (45
to 84 m/sec) . It was assumed that all the reburn fuel and burnout air
injectors would be located on the boiler's front and rear walls. The
boiler's side walls were not considered for potential injector locations
because of equipment interferences on the actual unit.
The jet trajectory screening process indicated that reburn fuel and burnout
air jet velocities in the 146-229 ft/sec (45-72 m/sec) range were promising,
as were configurations which located six injectors on the front and/or rear
walls for both reburn fuel/burnout air cases. The trajectory calculations
also concluded that jet penetration and potential for mixing could be
enhanced if both the reburn fuel/burnout air injectors could be tilted down
as much as 30 from horizontal.
With consideration of the above, physical flow modeling was initiated. A
1/16 scale geometrically similar isothermal flow model of a Ladyzhinskaya
boiler was fabricated. This model, shown in Figure 3, encompasses the boiler
from the furnace bottom to the inlet of the economizer section.
Particular attention was paid to the design of the existing main burners,
reburn and burnout air nozzles, and existing gas recirculation nozzles (used
to control steam temperatures). The main burner "free" exit areas were
adjusted in accordance with Thring-Newby modeling criteria (7) in order to
account for the combustion process expanding those gases exiting the burner
and reducing jet momentum flux. Jet penetration and dispersion, as related
to the reburn fuel, FGR, and burnout air jets, are modeled by maintaining
equivalency between the inlet jet to bulk furnace gas mass ratio while
simulating jet trajectories. These modeling procedures have been
successfully applied in over 30 years of CE modeling experience. (7)
The first series of tests performed in the cold flow model was a baseline
evaluation of the Ladyzhinskaya furnace's aerodynamics with the model
simulating normal (non-reburn) operation. A qualitative evaluation of the
flow field was performed using smoke to trace jet penetration and mixing;
limited quantitative tests were also performed to establish three-dimensional
furnace gas velocity profiles under baseline conditions.
The baseline characterization highlighted the fact that the flow field
exiting the main burner zone was reasonably uniform in terms of direction and
velocity, suggesting that the reburn system injector/burnout air injector
system would not have to overcome major flow maldistributions in the existing
furnace aerodynamic flow field in order to provide for adequate gas mixing.
3-129
-------
Following the baseline tests, simulated reburn fuel and burnout air nozzles
were fabricated and installed on the furnace flow model. It was decided to
model two compartments at each reburn fuel/burnout air injector position.
Based on previous experience, this arrangement would both maximize
penetration and dispersion of the natural gas reburn fuel, recirculated flue
gas transport media, and burnout air streams, and provide for operational
flexibility. A "pant leg" nozzle configuration for the upper compartment
(Figure 4) enhances lateral jet dispersion; while the lower compartment
employed a conventional single nozzle arrangement. All compartments in the
model had the ability to tilt up or down to investigate the effect of tilt on
jet mixing.
The total number of injectors investigated in the model ranged from 12 to 32
(inclusive of both the reburn fuel injectors and burnout air injectors);
these injectors were assumed to be symmetrically located on the boiler's
front and rear walls.
Reburn system configurations were tested in two phases. Phase 1 evaluated
the performance of the reburn fuel injection system without a burnout air
system in operation. Phase 2 evaluated the performance of burnout air
injection systems with the best performing reburn fuel system from the Phase
1 efforts. Nozzle free areas and mass flow rates were the key variables
investigated.
REBURN FUEL SYSTEM FLOW TESTING
Figure 5 presents the jet trajectories of three reburn fuel injection jet
velocities for the configuration where 12 individual injection nozzles were
located on both the front and rear walls for a total of 24 injection nozzles.
Injection vertical tilt angle was 0 . The trajectory lines shown represent
the leading edge of the visualized jet. For the sake of clarity, only the
trajectories from the front wall have been shown. The trajectories from the
rear wall were symmetric to the front wall trajectories. It can be seen in
Figure 5 that 146 ft/sec (45 m/sec) injection velocity is sufficient to have
the reburn fuel jet penetrate slightly past the centerline of the unit.
Remembering that there is another set of injectors located on the rear wall
injecting at the same time, penetration of slightly past the centerline is
considered ideal in terms of providing a uniform fuel distribution. The
other injection velocities over-penetrated and impacted the opposite wall of
the furnace. The 183 ft/sec (56 m/sec) jet impacted at a point just slightly
below the burnout air injection elevation. The 229 ft/sec (70 m/sec) jets
Impacted the opposite wall just slightly above their point of injection.
Figure 6 shows the dispersion pattern (flow visualization using smoke tracer)
for the 146 ft/sec (45 m/sec) reburn fuel jet at 0° tilt. This jet
penetrates almost horizontally to the center of the unit before it turns up.
Dispersion was found to be very good in all but a small area located along
the wall just downstream of the injection point. This particular area was
devoid of injected material. The jets quickly dispersed in both the
side-to-side and front-to-back directions. As a result of the physical
modeling, the reburn injector jet velocity design target was established at a
nominal velocity of 146 ft/sec (45 m/sec).
3-130
-------
For all configurations and injection velocities, tilting the nozzles down
significantly increased the amount of dispersion but not the cross furnace
penetration. At an injection velocity of 146 ft/sec (45 m/sec), for example,
the penetration did not appear to increase more than a few percent. Angling
the injection nozzles down did, however, result in some of the reburn fuel's
being intermittently recirculated into the main burner zone of the furnace.
This observation is shown in Figure 7. Down-tilting did result in increased
downward penetration and thus increased the residence time of the injected
fuel. Tilting the injection nozzles down, therefore, was recommended as a
means of increasing the overall flexibility of the field installed injection
system. Downward injection may be useful as a method of optimizing the
reburn process if the furnace load should change and if the temperature
profile within the injection zone should change.
For all injection scenarios, the side-to-side dispersion of injected material
was found to be adequate, Figure 8. Material injected from the two nozzles
located adjacent to the side walls experienced strong jet attachment to these
walls. This phenomenon is detailed in Figure 9. Because this jet attachment
is unwanted, it is recommended that the side wall injection nozzles be given
yaw capability in order to direct flow away from the wall. Alternatively,
they should be designed at a fixed yaw angle to inject at least 18 away from
the walls.
BURNOUT AIR SYSTEM FLOW TESTING
The performance of the burnout air system was almost identical to that
observed for the reburn fuel system. The major difference in the injection
performance was in the penetration of the jets for a given velocity. Two
reasons for this have been identified. First, the mass flow rate of the
burnout air is 70% higher than that for the reburn fuel. This, in itself,
under identical cross flow conditions, would account for a 30% increase in
the penetration of the jet. Second, the aerodynamics in the burnout air
injection zone are more conducive to higher levels of penetration because of
the change in flow direction caused by the turn at the top of the unit.
Figure 10 presents the leading edge trajectories of three burnout air jets
simulating 146, 183, and 229 ft/sec (45, 56, and 70 m/sec) from flow
visualization tests. For this case, there were 6 windbox locations on both
the front and rear walls for a total of 12 burnout air locations. The
trajectories from the jets located on the rear wall were omitted on Figure 10
for the sake of clarity. Injection at 229 ft/sec (70 m/sec) resulted in the
jet's impacting the opposite wall of the unit almost directly across from the
point of injection. At 183 ft/sec (56 m/sec) the jets missed the rear wall
and exited the unit low above the arch. At 146 ft/sec (45 m/sec) the jets
quickly turned upward and did not provide sufficient penetration into the
center of the furnace. Rear wall jets did not penetrate as effectively as
front wall jets because they were injecting into a flow field that was
approaching counterflow.
It was recommended from the physical flow modeling phase that the design
injection velocity range of the burnout air system be between 183 and 229
ft/sec (56 and 70 m/sec). A burnout air injection system having velocity
capability in this range would enhance rapid burnout air's mixing into the
3-131
-------
bulk furnace gases issuing from the reburn zone, thus ensuring complete
burnout of combustible products.
PRELIMINARY REBURN SYSTEM DESIGN
The approach used to develop the preliminary reburn system design first
involved establishing initial locations and configurations for the reburn
fuel/FGR and burnout air subsystems, including shape, flow rate, and nozzle
velocities. These selections were based on the previously described reburn
system design criteria, mass flow balance/stoichiometric calculations,
physical flow modeling, a physical inspection of the boiler, and a review of
existing equipment arrangement drawings provided by the Soviet side.
As previously mentioned, reburn system modification analysis was limited to
the front and rear walls of the boiler; the side walls of the unit were
essentially inaccessible due to equipment interferences. The Ladyzhinskaya
boiler's waterwalls are made up of lower, midwall, and upper waterwall
sections. Distribution headers are located between each pair of sections.
For each section the waterwall tubes were arranged in a closely packed "S"
shaped configuration. To minimize the impact of a reburn system retrofit on
water circulation the proposed reburn fuel and burnout air windbox locations
were matched to coincide with these "S" shaped tube configurations. An
example of this is shown in Figure 11 for the reburn fuel injector system.
For the initial reburn fuel and burnout air injector locations, six locations
across the front and rear walls were selected, primarily to enhance mixing
processes and avoid extensive waterwall circuit modifications. This
arrangement is illustrated in Figure 12. The reburn injector would be
located at an elevation of 66.6 ft (20.3 m).
Based upon the flow modeling it is recommended that both the reburn fuel
injector and burnout air injector windboxes be multicompartmented with
individual control dampers on each compartment. This is because, consistent
with the physical flow model results, one large diameter jet and compartment
provided for better deep furnace penetration and dispersion while smaller
diameter angled jets and compartments provided for better near field jet
mixing and dispersion. The individual compartment control capability is
recommended for performance optimization during initial system start-up and
normal load-following boiler operation.
The reburn fuel injector windboxes were designed for 10% FGR for the reburn
fuel transport media, 20% natural gas (percent of total fuel heat input)
reburn fuel, and a nozzle exit jet velocity of 146 ft/sec (45 m/s) . The
general reburn windbox nozzle configuration is presented in Figure 13. Each
windbox is segmented into three vertical compartments. FGR can be introduced
Into all three compartments, natural gas is introduced through the upper and
lower compartments, with the center compartment designed for future
capability of using fuel oil or pulverized coal as reburn fuels. The reburn
fuel (natural gas) would be premixed with the FGR at the nozzle exit with a
natural gas spud located at the nozzle tilt axis centerline at the rear of
the nozzle. The pant-leg arrangement is clearly shown in Figure 13. Note
also that the bottom natural gas nozzle has a capability to yaw approximately
3-132
-------
The physical flow modeling suggested the desirability of vertical tilt
capability for the reburn injectors over a + 30 from horizontal range, so
this capability was recommended.
The burnout air windbox and compartment arrangement was similar. However,
only two compartments were required and yaw adjustment capability has been
added to the two smaller upper compartment nozzle tips. This configuration
is presented in Figure 14.
As in the case of the reburn fuel injectors, it is desirable to have 12
injectors, 6 on the front wall and 6 on the rear wall. The injectors would
be located at a boiler elevation of 95.8 ft (29.2 m) . For operational
flexibility, it was recommended that both the upper and lower nozzles have
independent yaw capability, as well as vertical tilt capability (+ or -30
from horizontal).
FURNACE THERMAL PERFORMANCE
The objective of this phase of the preliminary design study was to
investigate the potential impact of retrofitting a reburn NO reduction
system on furnace performance for the Ladyzhinskaya Power Station host
boiler. Objectives were to determine if changes would occur in: the furnace
exit gas temperature, the furnace hopper gas temperature, and the
distribution of and total heat absorption in the furnace with and without the
reburn NO reduction system.
x J
Other objectives in the analysis were to estimate any changes in combustion
efficiency and/or flyash carbon content when the reburn system was in
operation. No assessment was made of convective pass performance (superheat,
reheat, or economizer sections) with the reburn system due to any changes in
flue gas weights (mass flows), total boiler heat absorption (as compared to
furnace heat absorption), or changes in boiler exit gas temperature (as
compared to furnace exit gas temperatures) in this thermal performance
analysis.
The furnace thermal performance analysis was completed utilizing a
proprietary Combustion Engineering developed computer code (Figure 15). The
function of the program was to determine, through a series of heat balance
calculations, the heat transfer from the combustion products to the
waterwalls, the corresponding gas temperatures, and the furnace outlet
temperature of the combustion products. The combustion history and
combustion products were determined based on a fuel analysis, fuel and air
mass flow rates and injection locations, fuel particle size distribution, and
a set of fuel char combustion kinetics.
The computer program was first set up to emulate the current as-found or
baseline conditions using information provided by the Soviet side. The
program was then calibrated for the Ladyzhinskaya unit based on a furnace gas
temperature profile provided by the Soviets.
The furnace thermal performance with reburning was then determined using the
design locations and flow rates for the reburn fuel, recirculated flue gas,
and burnout air and the revised main burner fuel and air flows and the upper
furnace flue gas recirculation flow.
3-133
-------
Both furnace gas temperature profiles and furnace waterwall/heat absorption
profiles were generated as a result of the thermal analysis. These are shown
in Figures 16 and 17, respectively.
Unit performance predictions based on the thermal analysis can be summarized
as follows:
• Furnace heat absorption will be up to 4% lower when natural gas
reburning is employed
• Furnace exit gas temperature (FEGT) will be up to 60 F (35 C) higher
when natural gas reburning is employed
• Furnace bottom gas temperature will be up to 80 F (45 C) lower with the
reburn system in operation
• Overall furnace waterwall heat absorption profiles will not be
significantly altered with reburning
• Carbon heat loss will decrease with natural gas reburn, predicted
carbon-in-flyash: 2.3% baseline, 0.6% natural gas reburn fuel
• Overall boiler efficiency will be up to 1.0% less with natural gas
reburn due to moisture heat loss
Since reburn system operation (with natural gas) was projected to increase
FEGT by 60°F (35°C), the Soviets requested that additional furnace
performance analyses be conducted in an attempt to decrease or eliminate this
FEGT increase. It was also requested that an analysis be conducted on the
effect of the upper furnace FGR nozzles on FEGT with the goal of eliminating
these additional waterwall penetrations. The Soviet side stated that, for
this supplemental analysis and for the later detailed design, if it was
demonstrated advantageous, it may be possible to alter the burner (first
stage) zone excess air quantity For the preliminary reburn system design
the burner zone excess air level was maintained constant both with and
without reburning to minimize potential effects on ash slag tapping.
In support of the above, a sensitivity analysis (using the CE proprietary
code previously described) was conducted to assess changes in 1) FEGT, 2)
cumulative furnace heat absorption, and 3) flyash carbon content with
permutations in A) total FGR flow rate, B) upper furnace FGR flow rate, C)
main burner zone excess air (stoichiometry) , D) reburn nozzle/zone FGR, and
E) reburn fuel ratio.
Key parameters varied during the sensitivity study were main burner excess
air, total FGR rate, upper furnace FGR rate, FGR quantity introduced through
the reburn fuel injectors, and total quantity of natural gas as reburn fuel.
Table 2 summarizes the major conclusions reached from the sensitivity study.
It can be seen that decreasing the main burner excess air was predicted to be
beneficial in meeting the sensitivity study objectives of decreasing
(lowering) the furnace exit gas temperature and increasing (raising) the
waterwall absorption. A slight increase was predicted for the flyash-carbon
content. Thus, it is recommended that, for optimized reburning, the main
3-134
-------
burner excess air level be decreased to the extent possible while still
maintaining conditions appropriate for slag removal.
The two parameters analyzed pertaining to the objective of eliminating the
upper furnace FGR ports both showed that this elimination would not be
beneficial in regard to furnace performance. Eliminating the upper furnace
FGR ports by maintaining the FGR mass flow but changing its location to the
reburn elevation resulted in a predicted increase in FEGT of 13 F (7 C) and
lower waterwall absorption of 8x10 Btu/hr (2x10 kcal/hr). Eliminating the
upper furnace FGR ports by decreasing the FGR flow rate resulted in a
predicted increase in FEGT of 29 F (16 C). Therefore, it is recommended that
the upper furnace FGR ports not be eliminated as part of the reburn system
design; in fact, the sensitivity study showed that increasing the amount of
upper furnace FGR reduced the FEGT.
The sensitivity analyses also examined the possibility of decreasing the
amount of FGR used with the reburn fuel injectors by 2.5% from 10% to 7.5%.
For the sensitivity study, the reburn FGR was decreased with an equivalent
increase in upper furnace FGR. From a furnace performance standpoint this
change was predicted to be beneficial with a predicted decrease in FEGT and
an increase in waterwall absorption.
Finally, the sensitivity study examined the possibility of decreasing the
total reburn fuel flow rate. This was done with the assumption that the
previously recommended decrease in main burner excess air will be
incorporated into the optimized reburn system design. This assumption was
necessary to maintain the reburn zone stoichiometry in the desired range for
NO reduction.
x
Decreasing the reburn fuel ratio was beneficial with respect to both lowering
the FEGT and raising the waterwall absorption. Thus, it is recommended that
the reburn fuel flow rate be decreased for the optimized reburn system
design.
Table 3 summarizes the process flows and the predicted furnace performance
results for:
1. Baseline As Found Operation
2. Preliminary Reburn Operation
3. Optimized Preliminary Reburn Operation
As shown in Table 3, with the optimized preliminary reburn design conditions
the predicted furnace exit gas temperature was 18 F (10 C) lower than the
predicted current baseline as found during operation. Also the furnace total
waterwall heat absorption was essentially equal at 625 x 10 Btu/hr (157 x
10 kcal/hr). And finally, the flyash carbon content was predicted to remain
at a very low level.
FINAL SYSTEM DESIGN/PROJECT STATUS
Agreement has recently (November 1990) been reached on the final reburn
system design based on several technical meetings held over the past year
between the U.S. and Soviet sides. The Soviet side, responsible for final
detailed design, fabrication, installation, and operation of the system, has
3-135
-------
agreed to proceed with the project, basing the final design largely on the
preliminary design provided by the U.S. side.
The Soviets have recommended certain deviations from the preliminary design.
These deviations are highlighted in Figure 18. Most of the changes were
recommended by the Soviet side in order to minimize retrofit complexity and
cost. It has been jointly agreed that the majority of these deviations
between the preliminary design and final design will have an insignificant
impact on optimum system performance. There are, however, three significant
differences between the preliminary and final designs. First, the Soviets
had recently decided to retrofit an aerodynamic "nose" (Figure 18) into the
Ladyzhinskaya boiler; this modification will be implemented to improve heat
transfer in the boiler's convection section during the same outage scheduled
for the reburn system installation. The preliminary reburn design was
completed by the U.S. side prior to notification of the nose modification; it
is the joint opinion of both the U.S. and Soviet sides that the nose will
significantly affect upper furnace aerodynamics but will likely not have a
significant negative impact on reburn system effectiveness.
The Soviets also recommended combining each of the two innermost reburn and
burnout air windboxes into a single windbox, in order to facilitate retrofit.
Both sides agree that this configuration shouldn't negatively impact on
reburn system performance. As a result, there will be five reburn fuel
windboxes on both the front and rear walls and five burnout air windboxes on
both the front and rear walls, as opposed to six each in the preliminary
design.
The Soviets have also recommended that the variable yaw and tilt capability
defined in the preliminary design be eliminated; i.e., the nozzles would
operate with fixed tilt and yaw vertical and horizontal angles. This
decision was taken by the Soviet side to minimize system complexity and cost
as well as to maintain the project retrofit schedule. Variable tilt and yaw
in the U.S. side's experience enhances the field installed system's
flexibility in optimizing reburn fuel and burnout air mixing in the bulk
furnace gases, allowing the system to be tuned in the field in order to
optimize NO reduction. Discussions between the U.S. and Soviet sides have
been held to jointly agree on the fixed yaw and tilt angles; the decision has
been made to fix all horizontal yaw angles at 0 and the vertical tilt angles
at both the reburn fuel and burnout air locations at -15° from horizontal.
Both sides believe that these fixed angles offer the best opportunity for the
Ladyzhinskaya installation to meet its reburn system performance objectives
in lieu of the availability of a variable angle nozzle arrangement.
The current schedule calls for the Soviet side to complete detail design and
fabrication drawings by April 1991. The Soviets plan to install the reburn
system during a 120-day outage which is scheduled to start in May 1991. The
U.S. and Soviet sides will then jointly plan a test program for the
Ladyzhinskaya power station. The U.S. will then support the Soviets in
quantifying reburn system performance; these tests are to occur between the
fourth quarter 1991 and the second quarter 1992.
3-136
-------
REFERENCES
1. J. Kramlich, T. Lester, J. Wendt, (1987), "Mechanisms of Fixed
Nitrogen Reduction in Pulverized Coal Flames," Proceedings: 1987 Joint
Symposium on Stationary Source Combustion NO Control, Volume 2, EPA-
600/9-88-026b (NTIS PB89-139703). X
2. C. Kruger, G. Haussmann, S. Krewson, (1987), "The Interplay Between
Chemistry and Fluid Mechanics in the Oxidation of Fuel Nitrogen from
Pulverized Coal," Proceedings: 1987 Joint Symposium on Stationary
Source Combustion NO Control, Volume 2, EPA-600/9-88-026b (NTIS
PB89-139703). x
3. M. Toqan, J. Tears, J Beer, L. Radak, A. Weir, (1987), "Reduction of
NO by Fuel Staging," Proceedings: 1987 Joint Symposium on Stationary
Source Combustion NO Control, Volume 2, EPA-600/9-88-026b (NTIS
PB89-139703). X
4. J. Freihaut, W. Proscia, D. Seery, (1987), "Fuel Bound Nitrogen
Evolution During the Devolatilization and Pyrolysis of Coals of Varying
Rank," Proceedings: 1987 Joint Symposium on Stationary Source
Combustion NO Control, Volume 2, EPA-600/9-88-026b (NTIS PB89-139703).
5. Y. Takahashi, et al. (1982), "Development of 'MACT' In-Furnace NO
Removal Process for Steam Generators," Proceedings of the 1982 Joint
Symposium on Stationary Combustion NO Control, Volume I,
EPA-600/9-85-022a (NTIS PB85-235604). X
6. R. Borio, R. LaFlesh, R. Lewis, R. Hall, R. Lott, A. Kokkinos, S.
Durrani, "Reburn Technology for Boiler NO Control," Sixth Annual Coal
Preparation, Utilization, and Environmental Control Contractors
Conference, August 6-9, 1990, Pittsburgh, Pa.
7. D. Anderson, J. Bianca, J. McGowan, (1986), "Recent Developments in
Physical Flow Modeling of Utility Scale Furnace," Industrial Combustion
Technologies, American Society for Metals.
3-137
-------
Figure 1: Ladyzhmskaya Power Station
Diverting Portions of the Fuel and Combustion Air Streams from
the Main Burner(s) for Injection into the Post Flame Gases
Mechanistic Model for
NOx Destruction
NOx Formation Inhibited
Due to Fuel Rich Conditions in
Reburn Zone: NOx Destruction
is Promoted Due to Secondary
Flame Radical Attack on NO
Produced in Primary Zone to
Form Molecular Nitrogen
Staging Air-
Reburn Fuel-
Primary
Fuel-Air"
Hypothesized NOx Destruction Mechanism
CH
HCN
OH.H
OH,H
Figure 2: Basic Reburn Process Description
Figure 3: Ladyzhmskaya Flow Model
3-138
-------
I I
mm
TOP LEVEL OF NOZZLES
SECTION "AA"
BOTTOM LEVEL OF NOZZLES
SECTION "BB"
II II II II I I II
COMBINED REBURN NOZZLE
ASSEMBLY
FRONT ELEVATION
Figure 4: Schematics of Model Reburn Fuel/
Burnout Air Injector Bank
Gas Recirculation
Nozzles
Figure 5: Jet Penetration - Reburn Fuel Injectors
Gas Recirculation
Nozzles
Figure 6: Jet Penetration/Dispersion - Reburn Fuel
Injectors
Gas Recirculation
Nozzles
Figure 7: Effect of Injection Downtilt on Jet
Penetration/Dispersion
3-139
-------
Gas Recirculation
Nozzles
Burnoul Air
Injectors
Reburn Fuel
Injectors
•no a o-
Main Burner Zone
Figure 8: Lateral Jet Dispersion - Reburn Fuel
Injectors (Middle Nozzles)
Gas Reclrculatlon
Nozzles
Burnout Air
Injectors
Reburn Fuel
Injectors
E3 -BED E3 El--
Main Burner Zone
Figure 9: Lateral Jet Dispersion - Reburn Fuel
Injectors (Sidewall Nozzles)
Gas Recirculation
Nozzles
Figure 11: Example of Tube Modification for Reburn
Fuel Injector Installation
Figure 10: Jet Penetration - Burnout Air Injectors
3-140
-------
Burnout Air
/ Injectors
Reburn Fuel
Injectors
Figure 12: Preliminary Reburn System Design
Upper Compartment
[FGR » CH.)
Middle Compartment
(FGR)
(FUTURE OIL OR COAL)
Lower Compartment
(FGR + CH,)
Figure 13: Reburn Fuel Injector Windbox
Arrangement
Upper Compartment
Lower Compartment
Figure 14: Burnout Air Injector Windbox
Arrangement
3-141
-------
Inputs
Fuel Information
• Particle Size Distribution (R)
• Apparent Density (Pf)
« Chemical Characteristics
• Ash Characteristics
Drop Tube Furnace
System Information
• Char Activation Energy (E)
• Char Frequency Factor (A)
• Fuel Swelling Factor (a)
e Fuel Volatile Matter (VM DTFS)
Boiler Information
• Design Parameters
• Operating Conditions
l\
/lathematical
Model
Proprietary
Computer
Code
-
Outputs
• Temperature /Time
History
• Overall Fuel
Combustion Efficiency
• Percent Carbon in
Flyash
• Percent Carbon
Heat Loss
• Heat Release/Heat
Absorption Profile
Figure 15: Flow Diagram for Boiler Combustion Performance Model Simulation
Horizontal Furnace
Outlet Plane
Upper GR
Burnout Air
Reburn
Main Burner
Main Burner
Gas Reburn
Predicted
w/o Reburn
Soviet
Measurements
1500
2000 2500
Furnace Gas Temperature (F°)
Figure 16: Predicted Furnace Gas Temperature
Profile
(("F -32) x 5/9 = °C)
3000
Horizontal Furnace
Outlet Plane
Gas Reburn
Predicted
w/o Reburn
Main Burner —
Main Burner —
20000 30000 40000 50000 60000 70000
Waterwall Heat Absorbtion Rate (Btu/Hr/Ft2)
Figure 17: Waterwall Heat Absorption Profile
(Btu/hr/ft2 + 13273.0 = Cal/sec/cm2)
80000
3-142
-------
35.1m -
29.2m -
Tilt
0
20.3m — <3±25° £> --
Tilt
<£ Burner
<£ Burner
-FGR Nozzles (6)
Tertiary Air
• (Burnout) Nozzles
(6 Front, 6 Rear)
Reburn Fuel and
FGR Injectors
(6 Front, 6 Rear)
31.0m —
-15°.
26.8m • ••-15' Fixed
Fixed
20.3m
12.00m
8.75m
>Main Coal Burners
(8 Front, 8 Rear)
.-15° -15°.
Fixed Fixed
(£ Burner
Burner
FGR Nozzles (5)
i 27.5m
Burnout Air
Nozzles
(5 Front, 5 Rear)
-* 20.3m
Reburn Fuel and
FGR Injectors
(5 Front, 5 Rear)
12.00m
• 8.75m
>Maln Coal Burners
(8 Front, 8 Rear)
5.90m
5.90m
U.S. Side Preliminary Proposal Final Design Arrangement
Figure 18: Design Arrangements
Reburn Heat Input (20% of Total) (Ib/hr) 24314
Percent by Weight FGR (%) 14.7
Flue Gas Recirculation (Ib/hr) 410407
Gas Residence Time (Zone 2) (sec) 1.00
Volume Flow (ft3/sec) Wet
Gases Out of Reburn Zone
Reburn Zone Stoichiometry
Ash Flow Rate (Ib/hr)
Gas Compositions at Outlet
of Reburn Zone
(% by Volume Dry)
Gas Compositions at Outlet
of Reburn Zone
(% by Volume Dry)
CO, =
SOZ =
H20 =
CH,, =
CO, =
S02
H20
47084
0.97
102965
17.20
0.00
82.22
0.286
0.00
0.29
17.11
0.00
81.78
0.285
0.53
0.29
Table 1: Reburn Zone Process Calculations
3-143
-------
Parameter Changed
Decreasing Main Burner Excess
Air 20% to 5%
Changing Upper FGR Elevation
(35.1m) to Reburn Elevation (20.3m)
Decreasing Total FGR by 3.2%
by Eliminating Upper FGR
Decreasing Reburn FGR by 2.5%
by Increasing Upper Furnace FGR
Increasing Total FGR by 3% by
Increasing Upper FGR
Decreasing Total Reburn Fuel by 8%
with Main Burner Excess Air @ 5%
Furnace
Exit Gas
Temperature
(°F)
Lowered 20
Raised 13
Raised 29
Lowered 10
Lowered 20
Lowered 21
Furnace
Waterwall
Absorption
(10s BTU/hr)
Raised 6
Lowered 8
Raised 2
Raised 6
Lowered 2
Raised 9
Carbon
In
Flyash
(%)
Raises 0.4
Raises 0.1
No Effect
No Effect
No Effect
No Effect
Table 2: Furnace Performance Sensitivity Analyses
((°F -32) x 5/9 = °C)
(Btu/hr)/4 = kcal/hr
70
%
Performance Variables
Reburn Fuel Ratio
Total Excess Air
Burner Zone Excess Air %
Total FGR %
Reburn FGR %
Upper Furnace FGR %
Furnace Exit Gas °F(°C)
Temperature
Furnace Heat Absorption
x106 Btu/hr (x106 kcal/hr)
Flyash Carbon Content %
Baseline
as Found
N.A.
20
20
18
N.A.
13.2
1967(1075)
Preliminary
Reburn Case
20
20
20
18
10
3.2
2028(1109)
Optimum
Reburn Case
12
20
5
21
7.5
8.7
1949(1065)
626(158)
2.3
606(153)
0.6
625(157)
1.2
Table 3: Furnace Performance Summary
3-144
-------
Session 4A
COMBUSTION NOX DEVELOPMENTS I
Chair: W. Linak and D. Drehmel, EPA
-------
AN ADVANCED LOW-NOX COMBUSTION
SYSTEM FOR GAS AND OIL FIRING
R.A. Lisauskas
C.A. Penterson
Riley Stoker Corporation
Worcester, Massachusetts
-------
AN ADVANCED LOW-NOX COMBUSTION
SYSTEM FOR GAS AND OIL FIRING
R. A. Lisauskas
C. A. Penterson
Riley Stoker Corporation
Worcester, Massachusetts
ABSTRACT
A new low-NOx combustion system for gas and oil-fired industrial and utility
boilers is discussed. The system consists of an advanced Riley low-NOx STS burner
used in conjunction with overfire air and recirculated flue qas. One of the
distinctive features of the low-NOx STS burner is the use
to form a separation layer between the primary and secondary
gas.
of recirculated
f 1 ame
flue gas
zones.
This advanced
boilers in Western
low-NOx combustion
Europe.
results are summarized for two recent retrofit
are presented for both gas and oil-firing. NO.
have been demonstrated on a natural gas-fired <
tion of this advanced system to U. S. gas and
discussed.
system has been implemented on several power
Combustion system modifications and emission test
applications. Field emission data
emission levels of less than 50 ppm
20 MWe utility boiler. The applica-
oil wall-fired boilers is also
INTRODUCTION
Environmental concern over power plant stack emissions has grown steadily over the
past decade. In spite of this concern, the 1980's saw little change in U. S. NOX
regulations. However, recent passage of new federal Clean Air amendments and
proposed new state regulations make it likely that U. S. industry will soon be
required to meet revised emission standards on both new and existing boilers.
Unlike the United States, Europe and Japan did impose new emission regulations
during the 1980's. In 1984, German legislators recommended stringent NOX emissions
standards for new and existing boilers(l). These standards defined new emission
limits for all large combustion systems firing gas, oil and coal. As a result,
large numbers of industrial and utility boilers in Germany and other European
countries have been retrofitted with low-NOx systems. We believe this recent
European low-NOx retrofit experience is of particular interest to the U. S. power
industry. This paper focuses on some of this experience applied to gas and oil
fired systems.
4A-1
-------
Deutsche Babcock, the parent company of Riley Stoker Corporation, has had
considerable experience in supplying combustion systems to meet the demands of
German and European air pollution codes. Low-N0x combustion systems have been
implemented by Deutsche Babcock on a wide variety of industrial and utility
boilers. Since 1984, Deutsche Babcock has supplied low-NOx systems to over 110
liquid and gas-fired boilers. More than 520 low-NOx burners have been retrofitted
to a variety of boiler configurations. In order to meet stringent emission limits
many of these retrofit applications incorporate combustion modification
techniques, such as flue gas recirculation and overfire air, in combination with
new low-NOx burners(£). NCL reductions of over 80% have been demonstrated with
these new systems. New fuel injectors have also been developed in response to the
changing quality of heavy fuel oils. This technology and experience is now
available to the U. S. power industry through Riley Stoker.
One new burner system the Swirl Tertiary Separation (STS) burner is
particularly well suited to U. S. wall-fired boiler retrofit applications. This
new burner system is the subject of this paper. In addition to presenting
operating results from recent European retrofit installations, we will also discuss
the application of this new combustion system to U. S. boiler design
configurations.
DESCRIPTION OF LOW-NOX BURNER SYSTEM
New STS burner systems have been recently retrofitted on gas and oil wall-fired
boilers in both Germany and Sweden. In addition to reducing NOX, the burners were
designed to both minimize boiler pressure part changes and maintain acceptable
combustion conditions.
Figure 1 is an illustration of the STS burner equipped with swirl control. As is
typical in many European boiler designs, combustion air is controlled individually
to each burner. A spiral box, or scroll (shown in Figure 1) is used to supply the
combustion air to the burner. The scroll is divided between primary and secondary
air passages with control dampers and flow metering installed immediately upstream.
Total air flow to the burner is divided between the primary and secondary air
passages. The exact distribution of primary and secondary air can be adjusted
depending on the level of internal burner staging required for NOX control and
overall combustion performance.
The ability to independently control swirl imparted to the primary and secondary
air streams provides great flexibility in controlling flame length and shape. It
also ensures flame stability under low-NOx firing conditions. Adjustable air vanes
within the scroll are used to control the degree of swirl and subsequent fuel air
mixing. Between these two swirling air streams a separate recirculated flue gas
stream can be introduced forming a distinct separation layer between the primary
and secondary air.
The introduction of this separating layer of inert flue gas acts to delay the
combustion process and reduces NOX in the following manner:
• Peak flame temperatures, particularly on the surface of
the primary combustion zone, are reduced by a surrounding
blanket of inert flue gas.
• The rapid mixing of secondary air is prevented; thereby,
reducing the oxygen concentration in the primary combustion zone.
4A-2
-------
Unlike flue gas mixed with the primary or secondary air streams, the flue gas
separation stream is unswirled and concentrated. This serves to delay secondary
air mixing until after first stage oxygen has been consumed and the flame has
cooled. The intent of the separation layer, therefore, is to control both thermal
NOX formation and NOX produced from nitrogen contained in the fuel.
Additional NOX reduction is achieved through staged combustion. A portion of the
total combustion air can be introduced through overfire air ports above the burners
to provide external air staging. This overfire air is controlled and metered
independently of the combustion air to the burners. Low-N0x burners combined with
flue gas recirculation and overfire air offer an integrated approach for maximizing
the reduction of NOX emissions on gas as well as oil firing.
As shown in Figure 1, oil is burned using a centrally located steam or mechanically
atomized oil gun. Natural gas is burned using spuds or canes located within the
primary core of the burner.
FIELD RESULTS
Arzberg Power Station
Low-N0x STS burners have been installed at Arzberg Power Station Unit NO. 6 in
Arzberg, West Germany. The boiler, shown in Figure 2, is a once-through Benson
boiler rated at 1.58 million Ibs steam per hour and generates 220 MW of
electricity. The unit is currently equipped to fire natural gas or light NO. 2
oil. In 1988, the boiler was retrofitted with sixteen low-NOx burners, each rated
at 153 million Btu/hr heat input. Burners are arranged horizontally for opposed
firing on four levels. As stated earlier, the STS burner design was selected to
fit within existing burner openings.
NOX emission limits for this retrofit project were 50 ppm* for natural gas firing
and 75 ppm for light oil. The retrofit combustion system was designed with the
flexibility of introducing recirculated flue gas through either the burner zone
separation annulus or having it mixed directly with the combustion air to the
burners. One tertiary air port was also installed in close proximity to each
burner but was later found to be ineffective for NOX control. A level of overfire
air ports was added on both front and rear waterwalfs above the burner array for
staged or off-stoichiometric firing. As shown schematically in Figure 3, all flows
including primary, secondary, tertiary and recirculated flue gas were independently
controlled and metered.
Prior to the retrofit, NOX emissions from natural gas firing averaged 300
ppm. Testing was conducted following the retrofit to optimize the operation and to
commission the boiler. Figure 4 illustrates the effect of mixing flue gas
recirculation into the combustion air on NOX emissions for natural gas firing. NOX
is reduced with increasing amounts of flue gas recirculation (FGR) flow. With 20%
FGR and 10% OFA flow, NOX emissions were reduced to 75 ppm. By increasing the
amount of recirculated ffue gas to 30%, NOY decreased to 50 ppm.
All NOX and CO concentrations are dry and referenced to 3% 02-
4A-3
-------
Additional testing was then performed to evaluate the effect of introducing FGR
flow through the burner annul us for NCL control. The total amount of FGR flow
remained at 30% with 10% OFA. Figure 5 illustrates the effect of introducing
increasing percentages of FGR flow through the burner annulus or separation layer.
Uhen more than 50% of the total FGR flow was introduced through the separation
layer (the- remaining amount being mixed in with the combustion air) NOX decreased
significantly. The lowest measured NOX emission approached 25 ppm when nearly all
of the FGR flow was passing through the burner annulus. CO emissions remained less
than the 15 ppm throughout this testing and flame stability or scannability was not
a problem.
A limited amount of testing was performed on NO. 2 fuel oil. Data were collected
while operating at 15% FGR and 15% OFA flow rates. NOX emissions of 75 ppm were
achieved at full load and decreased to approximately 60 ppm at 50% boiler load. CO
emissions remained below 25 ppm for all test conditions.
Va'rtan Power Station
An advanced STS burner system has also been retrofitted at the Va'rtan Power Station
in Stockholm, Sweden. The Va'rtan unit, commissioned in 1976, is rated at 250 MW.
It is a once-through Benson style boiler designed for heavy oil firing. As shown
in Figure 6, the burners are mounted on a single wall in a 4 X 4 array. Each
burner is supplied individually with air and is equipped with a Deutsche Babcock
oil pressure/steam pressure atomizer. In addition to STS burners, the retrofit
combustion system includes both OFA and FGR. The existing FGR system was modified
to supply flue gas to each burner as well as the lower furnace.
The post-retrofit NOX guarantee limit for the Va'rtan unit is 0.27 lb/10^ Btu or
approximately 210 ppm. NOX emissions measured during recent commissioning tests
are shown in Figure 7. Emission levels (at high load) for the new system are 30 to
40% lower than the guarantee value. The data spread is due to differences in
operating conditions and varying fuel oil nitrogen content. Average fuel oil
nitrogen content is 0.3%. During the recent tests, high load excess oxygen
measured 1.3-1.4% upstream of the air heater corresponding to an excess air level
of less than 7%. CO emissions were less than 40 ppm. These results were achieved
with 10-11% OFA and 15% FGR. Approximately one third of the flue gas was
introduced through the burners. The remaining flue gas was introduced to the lower
furnace for steam temperature control.
APPLICATION TO U. S. BOILERS
The STS burner design has been adapted by Riley Stoker to U.S. wall-fired boiler
firing systems. Contrary to the European practice of individual burner air
supplies, 1). S. wall-fired boilers are equipped with common windbox/multiple burner
arrangements. Because of this, the burner inlet scroll, described in Figure 1, has
been replaced by primary and secondary air swirl vane registers surrounded by flow
control shrouds. All other burner components remain the same. As shown in Figure
8, the movable shrouds are operated by single actuators and can be automated with
boiler load. The shrouds control the primary/secondary air flow split
independently of swirl vane position. Flow measurement devices are positioned
between the burner barrels to provide a relative flow indication between the
burners.
4A-4
-------
A prototype 85 million Btu/hr STS burner designed for windbox applications (Figure
8) is currently being tested in Riley Stoker's large pilot combustion test facility
located at the Riley Research Center in Worcester, Massachusetts. This facility is
designed to simulate the near field combustion conditions of full scale
furnaces(3). Test variables include firing rate, flow biasing ratios, the amount
of flue gas recirculation and injection method, level of burner staging, swirl
setting, excess air and oil/gun positions. The test program has several
objectives: (1) to fully characterize the burner's low-NOx capability under U. S.
boiler operating conditions, and (2) to evaluate the sensitivity and trade-off of
various burner adjustments on NOX control and other combustion operating parameters
such as flame shape and particulate emissions. The prototype burner is being
tested on natural gas and NO. 6 fuel oil. The fuel oil selected for the test
program is a 2% sulfur oil with an asphaltene content of approximately 10%. Test
results will be available within the next several months.
SUMMARY
Advanced STS burners have been successfully retrofitted on several gas and oil
fired power boilers in Western Europe. These retrofits have been achieved within
existing burner openings. STS burners in combination with overfire air and flue
gas recirculation have exceeded their emission goals. NOX levels of less than 0.06
. X
Btu on natural gas and less than 0.2 lb/10^ Btu on heavy oil have been
demonstrated.
The introduction of a separate flue gas stream, or dividing layer through the
burner throat has been shown to be effective in reducing NOX on natural gas.
Additional testing is required to evaluate the effectiveness of this separation
layer during heavy oil combustion.
STS burner designs have been developed for U. S. wall -fired boiler burner/windbox
arrangements. Prototype burner tests are being carried out to ensure that European
experience is duplicated under U. S. boiler operating conditions.
REFERENCES
(1) P.W. Dacey, "An Overview of International NOX Control Regulations,"
Proceedings: 1985 Symposium on Stationary Combustion NOX Control, Vol. 1,
EPRI CS-4360, January 1986.
(2) R. Oppenberg, "Primary Measures Reducing NQX Levels on Oil- and Gas-Fired
Water Tube Boilers," Conference of the Association of German Engineers,
Duisberg, FGR, September 26, 1986.
(3) R. Lisauskas, et al_., "Experimental Investigation of Retrofit Low-N0x
Combustion Systems," Proceedings: 1985 Symposium on Stationary Combustion
NO Control, Vol. 1, EPRI CS-4060, January 1986.
4A-5
-------
Primary air Secondary air
Fu« I oil
a ~t o m i z e n
F u « L o I I
EL
Nat ura I
QQ9
FIue gas
Figure 1. Low-N0x STS Burner Equipped for Gas and Oil Firing and Individual Air Supply
-------
Figure 2. Arzberg Power Plant Unit NO. 6
4A-7
-------
CO
A Sta
ck
F.D.fan
Steam/air
preheater
FLue gas/air preheater
Furnace
Vort ex burner
FLue gas
fan
F.D.fan
FLue gas/air preheaier
a. Original System
b. Low-N0x Retrofit System
Figure 3. Low-N0x Combustion System at Arzberg Power Station
-------
80
Csl
o
40
-p..
>
CO
O-
CL
20
OverfireAir K)X
15 20 25
Flue Gas Recirculation
Rate into Combustion Air, %
30
80
60
CsJ
O
40
E
Q_
Q-
>T
O
20
Overfire Air
Flue Gas Red
culotion 30%
25
50
75
Flue Gas Percentage
in the Separation Flow, %
Figure 4. NOX as a Function of FGR into
the Combustion Air -
Natural Gas Operation
Figure 5. Nox as a Function of FGR into
the Annulus -
Natural Gas Operation
-------
Figure 6. Vartan Power Station
150
eg 100
o
50
0.8 1.0 1.2 1.4 1.6
Steam Flow, million Ib/hr
1.8
Figure 7. NOX Versus Boiler Load Post-Retrofit Heavy Oil Firing
4 A-10
-------
Shroud Actuators
Burner Front Plate
F.G.R. Inlet
Connection
Register Turning Vanes
Primary Air Shroud
Secondary Air Shroud
Furnace Woterwall
Oil Gun With Diffuser
Cos Cones
Figure 8. Riley Low-N0x STS Burner (Model 90) for Windbox Burner Arrangements
-------
NOX REDUCTION AND CONTROL
USING AN EXPERT SYSTEM ADVISOR
G. Michael Trivett
Monenco Consultants Ltd.
Calgary, Alberta
T2P 3W3
-------
NOx REDUCTION AND CONTROL USING AN EXPERT SYSTEM ADVISOR
ABSTRACT
In a continuing effort to reduce emissions of NOX from their coal fired power
units, TransAlta Utilities has undertaken a program of combustion optimization for
low-NOx operation. In addition to testing and tuning these units, Monenco is
developing an on-line Expert System to enable operators to continuously maintain
low-NOx emissions.
Characterization and optimization tests for low-NOx operation were conducted at the
Sundance Generating Station on the 375 MWe tangentially fired Unit #6. The tests
produced an extensive database which will be incorporated into the Expert System.
The tests confirmed that a reduction of NOX emission of 5 to 15% could be achieved
by improved control procedures.
The Expert System advisor will incorporate real-time input from sensors such as
oxygen analysers, temperature indicators, NOX analysers, CO analysers,
burner/pulverizer status, etc. A graphical computer interface will show current
readings and a message board will provide recommended corrective actions to
minimize NOX emissions.
4 A-15
-------
INTRODUCTION
NOX emissions are one of the precursors of acid rain for which coal fired power
plants are a significant contributor- During tests conducted by Monenco at
TransAHa Utilities Sundance Plant Unit #6, modest NOX reductions of between 5 and
15 percent from baseline levels were achieved. Reduction of NOX emissions on a
continuous basis requires considerable diligence by the operator in balancing the
competing requirements of steam temperature control, ash slagging conditions and
low-NOx operations. An expert system can be developed to review the available
operating data and by use of a knowledge base make recommendations to the operator
to minimize NOX emissions while maintaining optimum unit performance.
For a moderate NOX reduction of 10%, the expected development costs for the expert
system represent a NOX avoided cost of $60/tonne based on a 35 year operating life.
By comparison a Selective Catalytic Reactor (SCR) with an 80% NOX reduction
efficiency represents a cost of over $2000/tonne. Therefore the cost effectiveness
of developing the NOX control expert system (NOXPERT) which could be applied to all
of TransAlta's coal fired units, appears very attractive.
The potential benefit of the application of an expert system to Sundance Unit #6
would be a reduction in NOX emissions from existing levels at a reasonable cost.
On an annual basis this amounts to a reduction of between 210 to 630 tonnes
N0x/year from an estimated baseline rate of 4200 tonnes N0x/year. In addition to
the total NOX reduction, a proportional decrease in N0£ should result which may
reduce the contribution to the brown plume effect.
The general approach to be taken using an expert system would be to minimize NOX
formation by combustion modification or in-furnace techniques. Typical factors
that may be modified to reduce NOX emissions include reduced excess air operation,
increased fuel fineness, increased furnace wall sootblowing frequency and fuel/air
staging in the combustion zone.
4 A-16
-------
Each of the above factors can be optimized. However the interrelationship between
factors requires some degree of compromise to achieve a reasonable low-NOx emission
with acceptable unit performance. These interrelationships were developed as part
of the NOX testing program and the results of the tests form the majority of the
support data for the expert system development.
Expert systems have been developed as an extension of research in the field of
artificial intelligence (AI). An expert system is a computer program that combines
concepts, procedures and techniques derived from AI. These techniques allow the
design and development of computer systems that use knowledge and inference
techniques to analyze and solve problems in a way similar to human reasoning.
This specific application of an on-line or real-time expert system to control NOX
emissions is novel. The application of an expert system to real-time control is
becoming more advanced with chemical process companies applying systems to wider
and wider functions. However, the real-time aspect, particularly with future
closed loop control action, remains as leading edge technology. Expert system
"shells" or development tools are available from only a short list of potential
suppliers. Consequently the development of the NOX control expert system
represents leading edge development in both hardware/software and steam generator
control applications.
NOX EMISSION CHARACTERIZATION
TransAlta Utilities Sundance Plant has a total gross generating capacity of
2100 HWe. Units I and 2 are each 300 MWe and Units 3, 4, 5 and 6 are each 375 HWe.
All 6 units are Combustion Engineering design with forced circulation utilizing
tangential firing with a dual furnace arrangement. Units 3, 4, 5 and 6 are also
equipped with manual tilting overfire air nozzles. These units are supplied with a
low sulphur sub-bituminous "C" coal from the nearby Highvale Mine. Unit #6, in
particular, is equipped with 5 pulverizers, feeding coal to 5 elevations of
standard C-E tangentially fired coal nozzles on eight corners. The burner
arrangement is non-Low NOX except for the overfire air nozzles which are positioned
within the burner windbox setting.
The NOX tests were conducted on Unit #6 at Sundance and provided detailed
information on the relationships between NOX emissions and the control actions. A
4 A-17
-------
test matrix was arranged to evaluate the response on NOX emissions by the
following:
• Burner tilt position;
• Fuel-air settings;
0 Auxiliary air settings;
• Overfire air tilt position;
0 Increased coal fineness;
0 Reduced excess oxygen; and
0 Continuous operations.
The relationships between these control variables plus furnace cleanliness or
sootblowing frequency and unit load are depicted in Figure 1. Fuel NOX, which is
dependent on fuel nitrogen content, is shown with a dashed line since its control
requires primarily fuel switching to a lower nitrogen content coal or combustion at
sub-stoichiometric conditions. Thermal NOX can be reduced by adjusting the control
parameters, essentially reducing the flame temperature.
A change in one of these control parameters may reduce NOX, however, it may also
result in an unwanted change, for example, to performance. The objective then is
to strike an acceptable balance between NOX reduction and overall unit performance.
Some guidelines were set regarding acceptable performance for the NOX tests. These
included the requirements not to: jeopardize safety of operations; increase the fly
ash carbon content above 0.7% by weight; and increase the average carbon monoxide
emissions above 50 ppm by volume. Also normal steam outlet temperatures from the
superheater and reheater would be maintained within their acceptable ranges.
One of the major objectives of the NOX test program was to determine the baseline
or existing emissions on a continuous basis. An initial test series was conducted
on a twenty-four hour basis over four days. All operating conditions were set
as-is and in automatic mode where required. The data from these tests are
presented in Figure 2 and show the high, low and mean for each twenty-four hour
period. The descriptor on the x-axis represents both baseline and series G results
for days 1 to 4. The series G data, or optimized settings following the parametric
test matrix, are also shown for a direct before and after comparison.
The overall reduction in NOX emissions achieved was between 5 and 15 percent. In
addition the peak NOX emissions were reduced in the final test series as compared
to the baseline levels. The target settings for excess oxygen, burner tilts and
4 A-18
-------
furnace cleanliness were achieved on Day 3 of the final test series. Consequently,
this test day produced the lowest mean NOX emissions and the lowest peak values.
Excess oxygen (02) has an impact on NOX emissions as shown in Figure 2. Large
ranges of excess oxygen during the tests contributed to the large range in NOX
emissions, and the high oxygen peaks directly contributed to the high NOX peak
values. A reduction in excess oxygen during the optimized test series as seen in
Figure 2 aided in reducing the mean NOX emissions.
The effect of burner tilt position, either positive or negative degrees from
horizontal, has an effect on NOX emissions. Figure 3 shows the high and low range
for burner tilts for both the baseline data and series G data. The test days with
a large range in tilt position, had a corresponding large range in NOX emissions
and the highest peak levels.
As noted previously, changes to some control parameters may result in an
undesirable effect such as reduced performance. A decrease in performance is
typically indicated by two factors: the amount of unburned carbon in the fly ash
and the amount of carbon monoxide in the flue gas. Figure 4 shows the effect of
increased fineness and excess oxygen on NOX emission and the resulting carbon in
ash content. The data represented by test number A was conducted essentially with
baseline coal fineness and fixed burner tilts at the horizontal position. The
remaining data points, B, C, D and E were tested with an increased coal fineness
and for tests C, D and E decreasing excess 02. As shown, an increase in fineness
results in a reduction in the carbon in ash content. By increasing fineness with
normal excess oxygen, an expected increase in NOX resulted. However, the increased
fineness also allows the excess oxygen to be reduced, reducing NOX emissions. As
shown in Figure 4, as excess oxygen is reduced, carbon in ash increases. From this
information an optimum excess oxygen level, without degrading performance as
indicated by the carbon in ash level, was determined for these tests at a level of
2.5% 62- Reduced excess oxygen also has the benefit of increased thermal
efficiency due to reduced heat loss, reduced fan power and draft losses.
The changes made to pulverizer/classifier settings to achieve a finer coal grind
were minor and consequently had little effect on the stack opacity. Greater
changes in fineness, however, may impact the stack opacity and consequently opacity
data should be included for the expert system to review.
The overall effects on performance between the baseline data and the optimized
settings data as reflected in the carbon in fly ash levels and carbon monoxide
4 A-19
-------
emissions are shown in Figure 5. Since the fineness in the baseline or as-is
condition was considered to be out of specification, increased fineness was
expected to give an improvement in unburned carbon levels with lower CO emissions.
As noted the increased fineness, as reflected in the reduced carbon content, allows
the excess oxygen to be reduced without degrading performance.
Overfire air (OFA), which is considered to be a primary NOX control technology,
allows separation of the fuel and combustion air resulting 1n lower flame
temperatures and lower thermal NOX formation. The angle that the overfire air
enters the furnace, relative to the horizontal position, was tested and as the
angle approaches the horizontal position, or closer relative to the flame, the NOX
emissions increase. Consequently the greatest separation angle, or 30 degrees
above horizontal, results in the lowest NOX levels. In addition this OFA tilt
position should remain fixed regardless of the automatic positioning of the burner
tilts.
The combination of both controllable and uncontrollable parameters in coal fired
steam generator operation results in a dynamic, complex system for NOX control.
Changes in burner tilt position in response to steam temperature control demands,
furnace wall slagging, burner to burner coal flow imbalances and variations in
excess oxygen distribution from furnace to furnace result in fluctuations in NOX
emissions.
The amount of change or range in the control parameters noted gives a comparable
range in the resulting NOX emissions. Figures 2 and 3 show this effect for excess
oxygen and burner tilt position, respectively. In the optimized test series G the
movement of burner tilts was limited to within + or - 10 degrees with manual
adjustments and overall both the tilt range and excess oxygen ranges are smaller.
This resulted in a reduced peak for NOX emissions and an overall average reduction
between the baseline and series G emissions.
The NOX control expert system will review each of the noted parameters and based on
desired settings and expected relationships, should produce a reduction in
emissions similar to the difference between the baseline and optimized test data.
INPUT DATA FOR THE NOXPERT
The input data required for the NOX control expert system will be supplied from
three sources. The first source will be the flue gas analysis data. The second
4A-20
-------
will be panel board data with steam generator condition information, and the third
source will be the operator/user.
The input data for the flue gas analysis will include the following:
• Nitrogen Oxides (NOX);
• Carbon Monoxide (CO);
• Excess Oxygen (02); and
• Stack opacity.
The oxygen and carbon monoxide monitors, two in each of the two ducts leaving the
economizer, should provide sufficient data for averaging and fault diagnosis.
Suspect data could be detected if outside the normal expected range and
recalibration might be suggested by the expert advisor. Also, the opacity monitors
will be used to detect high excursions possibly caused by too fine a coal grind.
The units currently are not equipped with NOX analysers and separate monitors would
be required for each of the dual furnaces.
The panel board will provide input to determine what the steam generator current
operating conditions are corresponding to the flue gas analysis. These data will
include the following:
• Boiler/Turbine Load (MWe or steam flow);
• Burner tilt position (+ or - from horizontal);
• Superheater/Reheater outlet steam temperatures;
• Windbox to furnace pressure differential;
• Fuel Air damper position (% open for all 5 levels);
• Auxiliary Air damper position (% open for intermediate levels);
• Bottom air damper position (% open);
• Top air damper position (% open);
• Overfire air damper position (OFA % open); and
t Burner level status, mill coal feeder status (on/off).
The first two sources of data will be on-line or real-time at a specific recording
frequency. The third source of information will be input by the operator/user as
required by the expert system. This data will include information available only
at infrequent periods such as the following:
• overfire air tilt position (manual control, degrees from horizontal);
• carbon content of the fly ash;
4A-21
-------
• sootblower status and frequency;
• coal fineness for all 5 mills; and
• instrument calibration information.
In addition, the operator/user will respond to specific enquiries made by the
expert system for updates on the available data. For example time limits could be
set (time-stamping) for validity periods after which updates should be made.
The real-time data will also be recorded at a specified frequency so as to maintain
the latest information and status available. This frequency, however, is expected
to be in the order of minutes for updates due to the large dead times as a result
of the boiler system thermal inertia. As a result, the rules for low-NOx firing
can be reviewed and acted upon over a reasonably long time period.
The input data mentioned above is depicted as a schematic diagram showing
communication with the expert system in Figure 6. The input data plus the
recommended control action to minimize NOX emissions would be echoed on-screen as
shown in Figure 7.
LOW NOX RULES
The NOX control expert system is currently being developed by Monenco for TransAlta
for application on Unit #6 at the Sundance Plant. The development plan includes
various stages from prototype to a fully fielded and implemented advisory system 1n
a one year time frame. Once fielded, a closed loop control scheme will be reviewed
for operation within a distributed control system (DCS).
The following details some of the specific concerns in developing this system and
outlines some generic features of an expert system.
An expert system comprises three parts:
• facts;
• rules; and
• inference engine.
The facts describe aspects of the domain, for example, that the furnace excess
oxygen is at 3.2% by volume or that the top elevation of burners are out-of-
4A-22
-------
service. Rules describe what an expert might do with the facts to reach the
objective, for example reduce the oxygen to reduce the NOX emission. In the same
way in which a human operator infers a solution to a problem based on the available
facts and previous experience with a similar problem, the inference engine combines
rules and facts in the knowledge base to reach a conclusion.
By definition rules are English-like sentences used for defining the knowledge of
an expert. Rules can be grouped as subsets which can be activated or deactivated
independently. The intent is to control which rules are used (fired) when a new
fact is introduced (asserted) into the knowledge base.
The facts that describe the domain are determined on-line from the various input
sources such as the excess oxygen sensors. Once the facts are known by the expert
system, given constraints such as time validity, then the rules can be searched to
determine an appropriate decision or recommendation.
Rules are defined using an IF-THEN syntax that logically connects one or more
antecedent (or premise) clause with one or more consequent (or conclusion) clause.
A rule says that if the antecedents are true, then the consequents are also true.
The antecedents and consequents of rules refer to specific facts that describe the
state of the domain. Therefore each fact describes some particular aspect of the
domain's state. Together, the rules and facts make up the knowledge base.
The inference engine analyzes the rules and facts for any rule antecedents that
match existing facts. The process of matching is finding a rule clause with the
same pattern of words (in the same order) as a fact in the knowledge base. When
all of the antecedent clauses in a rule have a corresponding fact in the knowledge
base, the inference engine can assert the consequent of the corresponding rule into
the knowledge base as a new fact.
The inference engine consists of a generalized computer program that knows about
reasoning strategies and various ways to combine rules and facts, but knows nothing
about any particular application. The knowledge base of rules and facts is
nonprocedural, while the inference engine is highly procedural. In other words,
rules and facts represent what the knowledge is, but the inference engine
determines how that knowledge should be analyzed.
The following examples illustrate rules which would comprise the knowledge base.
The order or sequence of the rules is not important since the inference engine will
use or fire the rule that satisfies the current facts.
4A-23
-------
• If ppm NOX is greater than NOX Limit
ppm CO is less than CO Limit
Excess 02 is greater than 2.5%
Load is 100% MCR
Then reduce Excess 02 to 2.5%
• If ppm NOX is greater than NOX Limit
ppm CO is greater than CO Limit
C in Ash is greater than C Limit
Any Fineness less than 65% thru 200 mesh
Any Fineness greater than 1.5% on 50 mesh
Then Recommend Increase in that Fineness to 65% thru 200 mesh and less
than 1.5% on 50 mesh
• If ppm NOX is greater than NOX Limit
ppm CO is less than CO Limit
Excess 02 is 2.5%
C in Ash is less than C in Ash Limit
Burner tilt position less than 0 degree
Then Sequence wall sootblowers
Additional rules have been developed to set initial conditions, such as equipment
availability (i.e. Overfire Air), optimal excess oxygen as a function of steaming
rate required and hierarchical rules to dictate priorities such as steam
temperature control or carbon monoxide limit override. The rules for the NOX
control aspect of the NOX PERT are invoked only under steady load cases and during
transitional periods will be overridden in order to maintain safe operations.
The development of the rules, based on the example decision tree shown in Figure 8,
consists of logical If-Then clauses satisfying the various branches. Once the
complexity of the rules are fully defined, the expert system "Shell" will be
selected and a prototype NOX PERT will be assembled.
CONCLUSIONS AND RECOMMENDATIONS
There are three major techniques available for the reduction of nitrogen oxides
(N0x). They are classified as:
4A-24
-------
• operational control,
• combustion control, and
• post-combustion control.
In each case there is an associated economic cost with a corresponding increase in
equipment complexity. The least expensive cost is to alter operational control of
existing burner equipment by means of the subject expert system. The next least
expensive is a retrofit of the burner equipment to the low-NOx style of burners.
And finally, the most expensive control alternative is by post-combustion
techniques such as a selective catalytic reactor.
The costs associated with each technique and the level of NOX reduction offered
ranges from an estimated $60/tonne of NOX removed for an Expert System, $150/tonne
for low-NOx burners with overfire air and $2,000/tonne for an SCR. Utility
companies in Germany who have installed SCR's also recommend that NOX be reduced by
combustion first to minimize the cost of an SCR both in capital and annual
operating costs.
Based on the NOX test results from Sundance Unit #6, manipulating some key controls
can reduce NOX emissions by up to 15 percent from baseline emissions. By uniformly
applying rules for maintaining low-NOx operations, from operator shift to shift,
an overall reduction on both monthly and annual bases would be expected. Conse-
quently, an expert system that advises the operator using a consistent set of rules
could provide a NOX reduction up to and possibly surpassing the 15 percent from the
Sundance tests.
Based on these findings, an expert system to reduce NOX emissions from a utility
coal-fired steam generator represents a least cost approach with good probability
of success. Further, a successfully fielded expert system could be offered
commercially to other Utilities with similarly designed and equipped units.
ACKNOWLEDGEMENTS
The author would like to acknowledge the support offered by TransAlta Utilities
Corporation for funding the work reported here. Also special thanks to
Richard Bane, Malcolm McDonald and M1ke Blakely of TransAlta for technical guidance
through the various stages of this work.
4A-25
-------
Figure 1. NOx Emission Contributing Factors
ouu-
250-
CM~ 200-
0
5?
(3)
~ 150-
D.
CL.
X
0
z 100-
50-
0-
-
'.
_
^^
!.
^
r~
u
~^~- — ^_^^
^""~^
~
-^__
J
^^
NOX
n
\
LU LJ
J
O2
"^^^
-H
^^
n
y
T
^
^^
[
"
[
IU
-9
-8
-7
-6
-5
-4
-3
-2
-1
BS-1 BS-2 BS-3 BS-4 G-1 G-2 G-3 G-4
Baseline
Test Name Ootlmlzed
CM
O
c
0)
D)
S1
o
x
LU
Figure 2. NOx versus Excess Oxygen
4A-26
-------
300-
250-
200-
co
©
Q.
Q_
150-
100-
50-
NOX
Burner Tilt
BS-1
BS-2
Baseline
BS-3
BS-4 G-1
Test Name
G-2 G-3
Optimized
Figure 3. NOx versus Burner Tilt Position
Q.
_Q.
X
O
100
-80
60 2
£
D)
-------
500-
450-
400-
c\j
O
* 350-
E 300-
a
.g 250-
o 200-
c
o
_a
O
150-
100-
50---
617 ppm
BS-1
C in Ash
BS-2
Baseline
BS-3
BS-4 G-1
Test Name
-r
G-2 G-3
Optimized
G-4
-rO.9
-0.8
-0.7
-0.6
-0.5
-0.4
-0.3
-0.2
.-0.1
.c
O
Figure 5. Carbon Monoxide and %C in Ash
Figure 6. Input Data for NOxPERT
4A-28
-------
r
CD
NOx Control Expert System
Reheater T= Normal
Superheater T=Normal
OF A Tilt= + 30 Deg
Burner Tilt= -10 Deg
Coal Fineness
Most Recent Data:
Jan 17,1991
Burner Status
Level A= ON
Level B= ON
Level C= ON
Level D= ON
Level E= OFF
Fuel Air Pos'n
10098
10098
10098
10095
5098
co =
12 ppm
Message Board
Date: Jan 31, 1991
Time: 09 :45:33
Recommended Actions
NOX Level Higher Than 110 ng/j
* Suggest Reduce 02 by 0.6 98
* Verify Carbon in Ash= 0.698
* If NOX Doesn't Lower-
Then check coal fineness
Figure 7. Graphical Display for NOxPERT
-------
CO
o
Up Ex02
N. n«w |
'^' J
L.4 - 3<«4V
-
CinfiSH >
CinfiSH
1*4.4 =
jicady
-
PPM NOX >
NOX Limii
-
Ex02 >
Ex02 3<
-------
NOX PAPER FOR THE 1991 EPRI/EPA JOINT SYMPOSIUM ON A STATIONARY
COMBUSTION NOX CONTROL MARCH 25-28, 1991
THE CAPITAL HILTON
WASHINGTON D.C.
JANUARY 17, 1991
AN R&D EVALUATION OF LOW-NOX OIL/GAS BURNERS
FOR SALEM HARBOR AND BRAYTON POINT UNITS
Rui F. Afonso
Nino M. Molino
New England Power Service Company
Westboro, Massachusetts
John J. Marshall
Riley Stoker Corporation
Worchester, Massachusetts
-------
NOX Paper for the 1991 EPRI/EPA Joint Symposium
on Stationary Combustion NOX Control
March 25-28,1991
The Capital Hilton
Washington, D.C.
January 17,1991
AN R&D EVALUATION OF LOW-NOX OIL/GAS BURNERS
FOR SALEM HARBOR AND BRAYTON POINT UNITS
Rui F. Afonso
Nino M. Molino
New England Power Service Company
Westboro, Massachusetts
John J. Marshall
Riley Stoker Corporation
Worcester, Massachusetts
ABSTRACT
A thorough R&D program to evaluate low NOX, high efficiency oil/gas burners was
developed and conducted by New England Power Service Co. In anticipation of
retrofitting Brayton Point and Salem Harbor Units 4, the burner evaluation
project involved a series of evaluations designed to progressively identify
burner technologies most likely to meet New England Power performance
requirements. Detailed characterization of atomization quality using an
Aerometrics Phase/Doppler particle analyzer was performed for five of the
initial eight candidate burners. Pilot scale combustion tests at Riley Research
test facility, including oil, gas and dual (oil/gas) firing conditions, were
conducted for the baseline and final candidate burners. Retrofit and cost
impact studies were conducted for the selected burners to ensure the most
efficient/economic application. This paper focuses on combustion test results
at the Riley Research test facility.
4A-33
-------
INTRODUCTION
New England Power Service Company (NEPSCo) and Riley Stoker Corporation (Riley)
evaluated state of the art oil and gas burners for New England Power Company's
Salem Harbor, Unit 4 (Salem Harbor) and Brayton Point, Unit 4 (Brayton Point).
As originally designed by Riley for cycling/intermediate load operation, these
units typically operate with a capacity factor between 45% and 65%. Each of
these wall fired units produce 3,250,000 Ib/hr of steam at 955°F superheat and
reheat, generating about 440 MWe net. Figure 1 shows a cross sectional view of
the units. Twenty four rear wall mounted burners fire into a pressurized
furnace. Figure 2 illustrates the general windbox arrangement. Two half depth,
vertical platen walls divide the furnace into three cells. Horizontal,
drainable superheater and reheater surfaces allow for timely start up and
shutdown in cycling duty.
The existing Rodenhuis and Verloop TTL7 burners are nominally rated at 200
million BTU/hr. Designed before 1970, they represented burner technology prior
to the 1971 New Source Performance Standards (pre-NSPS). Currently, NOX control
regulations do not apply at Salem Harbor. Brayton Point, designed in 1969,
adheres to a 0.3 Ib/million BTU (~234ppm) NOX emission limit imposed by the
Massachusetts Department of Environmental Protection. Bias firing and Flue Gas
Recirculation (FGR) enable Brayton Point to achieve this level of control.
Particulate emission limits of 0.12 and 0.05 Ib/million BTU apply to Salem
Harbor and Brayton Point, respectively, and are achieved with the installed
electrostatic precipitators. Salem Harbor operates near 10% excess air with a
boiler efficiency of about 87%. Brayton Point uses up to 15% FGR with 10%
excess air.
Performance goals for the new burners include 0.3 Ib/MBTU and 0.2 Ib/MBTU of
NOX, respectively, for oil and gas firing at 5% excess air, while maintaining
carbon in the flyash (oil firing) to less than 20%. This will reduce total
particulate emissions and improve precipitator performance. Typically, both
units average 30-50% carbon in the flyash.
A Rodenhuis & Verloop TTL5 burner served as the baseline burner for testing in
the Combustion Burner Test Facility (CBTF) at the Riley Stoker Research Center.
This 80 million BTU/hr burner is similar to the 200 million BTU/hr burners
installed at both Salem Harbor and Brayton Point. Field data from Salem Harbor
4A-34
-------
was compared to the baseline burner test results in the CBTF. This analysis
provides guidelines for predicting the potential field performance for the
candidate burners tested in the CBTF.
Comparative data illustrates improvements achieved with the latest design.
Additionally, results are provided for natural gas firing and simultaneous
firing of both natural gas and residual fuel oil in various ratios.
THE R&D PROJECT
Previous papers (1) describe the background and technical approach to the
selection of the candidate burners for Brayton Point and Salem Harbor.
In summary, the program consisted of five primary tasks:
• Evaluation of vendor proposals
• Evaluation of atomization performance
• Baseline burner combustion tests
• Candidate burners combustion tests
• Engineering and economic evaluation of burner retrofits
The evaluation process started with the submittal of proposals by eight
participating manufacturers, and evolved through detailed atomization
performance testing (five candidates), to pilot scale combustion tests for the
baseline and two final candidates.
Atomization testing was performed using surrogate fluids, air/water and
air/water-glycol to simulate steam/oil at various viscosities and operating
conditions. Spray droplet size distributions (spatial and temporal),
mass/volume fluxes and atomization efficiency were compared for each burner.
Review of these results combined with the initial proposal evaluation, led to
the selection of the two burners for combustion testing.
This paper focuses on a comparison of the results of the baseline burner
(R&V TTL5) and a new generation Rodenhuis & Verloop TTL 22.5 burner capable of
residual fuel oil and natural gas firing.
4A-35
-------
PERFORMANCE CRITERIA
NEPSCo established the following full load performance goals and operational
characteristics for candidate burners:
Full Load Performance
NO., emissions less than 0.3 lb/106 Btu for 0.5% wt. nitrogen fuel;
0.2 Ib/Mbtu for natural gas
• Particulate emissions, less than 0.05 lb/106 Btu after the
precipitator (precipitator efficiency = 60%)
• CO emissions, less than 100 ppm
• Flue gas oxygen content, less than 1% by volume (5% excess air)
Operational Characteristics
• Turndown, 6:1 to 10:1
• Dual fluid atomizer using air or steam
• Fuel oil pressure, less than 300 psig at the gun inlet
• Fuel oil viscosity at the burner 100-150 SSL)
• Fuel flow: 21 gpm #6 oil, 220 KCFH natural gas
In addition to the performance criteria, the following concerns were considered
for the evaluation:
• Operability and reliability
• Mechanical design
• Materials of construction
• Cost
• Related experience of the various burner technologies
DESCRIPTION OF TEST BURNERS
Baseline Test Burner - TTL5: Over twenty years ago the Rodenhuis & Verloop B.V.
company of Holland developed the TTL5 burner. Compared to the typical utility
or industrial burners using pressure or steam assisted atomizers the TTL5 burner
was unique in that low pressure primary air, at a nominal 35"WG, atomizes tne
4A-36
-------
oil. No registers are available to control or shut off the secondary combustion
air flow to individual burners.
The TTL5, rated at 80 million BTU/hr, simulates the combustion aerodynamics of
the geometrically similar 200 million BTU/hr TTL7 installed at Salem Harbor and
Brayton Point. Figure 3 illustrates the TTL5 burner arrangement installed in
the CBTF test rig. Further details of the atomizing bullet assembly are shown
in Figure 4. The spiral atomizer head and the two stages (one adjustable) of
swirling primary air are indicated.
Primary air flow is about 7% of the total combustion air flow at full load.
During turndown the primary air flow stays essentially constant. In the case of
the Brayton Point and Salem Harbor installations primary air is taken from the
upstream side of the air heater. Booster fans distribute air to the burners.
The first stage of primary air supports and boosts the initial swirl of oil
issuing from the spiral atomizer to produce a conical shaped thin film sheet of
oil. The second stage primary air rotates in the opposite direction. The
interaction between these counter-rotating flow fields reduces the oil film to
fine droplets needed for combustion. An adjusting rod allows the second stage
primary air swirl to be changed. This is done by varying the second stage air
proportions through radial and tangential slots. Both extremes of 100% radial
to 100% tangential can be achieved. At full load oil pressures operate in a
range of 50 to 80 psig depending on oil type and viscosity.
The flame stabilizer is a conical annular diffuser ring mounted on the primary
air tube. Just upstream of the flame stabilizer an annular ring with a venturi
shape at the exit, helps to distribute the air uniformly to the diffuser. The
entire assembly penetrates just less than halfway into the venturi shaped
refractory throat.
Advanced Burner - TTL/MG22.5: Figure 5 depicts the new generation Rodenhuis &
Verloop TTL/MG22.5 selected for installation in the CBTF test rig. Rated at 80
million BTU/hr, the TTL/MG22.5 is similar in design and combustion aerodynamics
to the 200 million BTU/hr TTL/MG50 proposed for field retrofit.
The advanced burner incorporates many design changes over the baseline TTL5. A
sliding shroud register allows secondary combustion air flow control and
4A-37
-------
shutoff. No swirl of secondary air occurs at the register of this radial air
entry, axial flow burner.
The atomizer bullet assembly retains the operating parameters and design
philosophy of the TTL5 burner but new hardware designs enhance and improve
atomization. Two stages of primary air surround the spiral oil atomizer. The
assembly shown in Figure 5 illustrates the design without an adjustable slide
for changing the second stage swirl. The assembly is available with or without
this capability. In this program, testing included a temporary slide
arrangement to evaluate the impact of the additional hardware.
A multivane diffuser replaces the conical bluffbody flame stabilizer of the
TTL5. This changes the combustion aerodynamic patterns for mixing the primary
air/oil flows with secondary combustion air. The vaned diffuser provides a flow
that is counter in rotation to the second stage swirl of primary air. The
interaction of these flows increases the degree of mixing between streams.
Improved flame stability and turndown characteristics provide operational
advantages at low excess air operation.
The refractory throat area increases about 15% over the TTL5. Shape of the
throat changes to smaller entrance and exit angles with a longer axial section
(Figure 5). The combination of increased throat area and a 5% excess air
operating level reduces the secondary air velocity nearly 20%.
Natural gas enters the burner through an annul us created by a concentric tube
surrounding the primary air tube. A set of nozzles distributes the natural gas
at the inlet to the flame stabilizer. Pilot holes discharge a small amount of
fuel at the hub of the stabilizer directly to the primary flame zone.
TEST FUEL CHARACTERISTICS
To maintain a relatively consistent quality of residual fuel oil a storage tank
at Brayton Point was set aside to hold fuel throughout the test program. The
tank is rigid roof with heating but no mixing equipment. Though capable of
storing over two hundred thousand barrels, less than forty thousand barrels
(1,680,000 gallons) were in the tank at the start of the program. Over the
course of 18 months in the test program about 120,000 gallons were fired. Truck
4A-38
-------
shipments of 6000 to 8000 gallons were made from Brayton Point to the 10,000
gallon heated underground storage tank at Riley.
Each truck delivery was sampled as part of a quality plan. This assured that any
significant changes in fuel quality would not complicate the evaluation of test
results. Some minor variability was expected due to the design of the storage
tank, lack of mixing equipment, interrupted heating, the long period of testing
and the relatively small size of a delivery. Table 1 lists the typical fuel
analysis obtained from truck deliveries. This fuel is consistent with the
residual fuel oil fired at Salem Harbor and Brayton Point.
RESIDUAL OIL COMBUSTION TESTS
Baseline Burner And Performance Targets
The Combustion Burner Test Facility (CBTF) at Riley accommodated all burner
testing described here. Design details of this nominally rated 100 million
BTU/hr coal, oil and gas fired facility appear in other publications (1,2). The
results of the baseline Rodenhuis & Verloop TTL5 burner testing in January and
February of 1989 have already been presented (1). Additional baseline burner
testing in April 1990 expanded and verified the earlier results. One of the
objectives of the baseline test was to establish correlations to field data from
Salem Harbor (3,4,5).
Due to various burner adjustments, two stable flame characteristics were found
for the TTL5. A long narrow flame and a shorter wide flaring flame were
obtained by changing the location of the spiral oil atomizer along with
adjustments to the primary first and second stage air ratio. The long narrow
flame is not acceptable as representative of field operations due to potential
flame impingement. To establish the baseline correlation only the TTL5 wide
flame test results were used.
Currently, at full load oil firing and less than 5% excess air, Brayton Point
NOX levels must not exceed 0.3 Ib/million BTU (-234 ppm NOX at 3% Oxygen). This
is achieved in practice by utilizing flue gas recirculation (FGR) through the
TTL7 burners along with bias firing. Salem Harbor is not subject to NOV
A
regulatory limits.
4A-39
-------
The performance goal for carbon content in flyash is 20% or less. Full scale
field testing indicates a direct relationship between flyash carbon and
asphaltene content of the residual fuel oil (5). Currently at Salem Harbor, an
oil/water emulsification system helps control flyash carbon content.
Figures 6 and 7 respectively show the correlations for NOX and carbon content
reductions desired in the CBTF and field results. Burner area heat release
(BAHR) correlates the NOX data for the CBTF and the field. This technique has
been successfully applied in previous investigations for the Environmental
Protection Agency (6). Asphaltene levels in the residual fuel oil correlate the
carbon content results in the CBTF and the field.
Figure 6 illustrates the analysis used to develop potential NOX targets for new
burners applied in Salem Harbor or Brayton Point. The Salem Harbor field data
is scattered at about 350 ppm NOX at a BAHR of 350,000 to 363,000 BTU/hr-sqft.
Results from baseline burner tests in the CBTF range from 210 to 230 ppm NOX at
a nearly constant BAHR of 75,000 BTU/hr-sqft. Line LI connects the CBTF and
field data for similar burner operating and flame conditions and establishes the
methodology for projecting NOX emissions.
To determine the target NOX levels in the CBTF line L2 is drawn parallel to line
LI from the field requirement of 0.3 ID/million BTU (234 ppm NOX). The values
of line L2 represents a NOX reduction of about 35%. Accordingly, the NOX target
in the CBTF is 104 ppm NOX. Ideally the need for FGR, bias firing and
emulsification will be reduced or eliminated with the new burner, while meeting
the NOX emission goals.
Figure 7 shows the analysis to develop carbon loss reduction targets for new
burners applied in the field and firing neat oil. During the field test with
asphaltene levels in the oil at 6.1% and 14.7% the carbon content in the flyash
was 21.7% and 34% respectively (5). Considering carbon, ash and sulfate
contents in the flyash and the amount of carbon and ash in the as-fired fuel
oil, the carbon loss was 0.037% and 0.084% respectively. For the same amount of
ash and sulfates in the flyash, the flyash carbon goal of 20%, translates to
carbon loss values of 0.033% for the 6.1% asphaltene oil and 0.04% for the 14.1%
asphaltene oil. Figure 7 shows the actual field results and the equivalent
points needed to achieve 20% carbon content in the flyash.
4A-40
-------
This analysis indicates reduction requirements in carbon loss from 11% to 52%
for the range of oils tested in the field. The following description
exemplifies this procedure: during TTL5 burner tests the asphaltene content of
the as-fired fuel was 11.2%; from Figure 7 the target reduction in carbon loss
at this level of asphaltenes is about 40%; at full load conditions in the CBTF
the TTL5 burner produced a carbon loss value of 1.84%; therefore, 40% reduction
from this level equates to 1.10% carbon loss. The actual percent reduction for
new burners will depend on the as fired content of asphaltenes at the time of
the test.
TTL5 And TTL/MG 22.5 Performance
A number of independent parameters were varied during testing: burner hardware
settings, fuel oil viscosity, excess air, overfire air and load turndown. The
burner hardware adjustments included variations in the relative location and
settings of burner components. Items such as atomizer and diffuser position and
primary air staging ratios were varied from their design points.
In comparing the NOX performance of the TTL5 with the TTL/MG22.5, excess air and
overfire air provided greater impact than viscosity. Viscosity varied from 21.0
to 31.5 cStokes (100 to 150 SSU). The TTL5 NOX remained relatively constant at
220 ppm over this range. The TTL/MG22.5 NOX decreased about 14% to 174 ppm
while the viscosity increased but the appearance of the flame at the root and
the end did not support operating at the higher viscosity levels.
The ability of the TTL/MG22.5 to operate efficiently at low excess air provides
its greatest advantage over the TTL5. At 10% excess air (2.0% 02) the TTL5
produces about 220 ppm NOX. The TTL/MG22.5 produces slightly higher NOX (-230
ppm) at 10% excess air. For the 5% excess air design operating condition, the
TTL/MG22.5 produces 163 ppm NOX. This represents nearly a 25% reduction in the
level of NOX at design conditions. Figure 8 shows NOX versus exit oxygen.
Although the TTL5 burner operated stably at lower oxygen, the flame increasingly
contained dark areas and smoke. The TTL/MG22.5 produced good flame
characteristics down to 0.2% oxygen and perhaps lower but there was no practical
reason to pursue testing below this point. The level of CO was constant over
the range of 1.0% to 2.2% oxygen for each burner, with the TTL5 producing about
48 ppm while the TTL/MG22.5 yielded a lower 38 ppm. Down to 0.2% the TTL/MG22.5
4A-41
-------
CO level increased to about 43 ppm, still lower than the TTL5 at 1.0% oxygen.
CO is expected to be lower in the field due to tnulti burner interactions and
longer residence time.
After establishing the N0x/exit oxygen relation, most tests for the TTL5 were
conducted at about 2.2% oxygen which is typical of field operating conditions.
The TTL/MG22.5 tests stayed near 0.8% oxygen. Figure 9 shows the impact of OFA
on NOX emissions. The change in excess air accounts for most of the difference
between the two burners. At 25% OFA, the TTL5 NOX levels are lowered by 43%
while the TTL/MG22.5 levels dropped 37%. The TTL/MG22.5 achieves the target
level of NOY, 104 ppm, at 20% OFA. CO levels during OFA testing showed no
A
significant changes from the unstaged condition.
Figure 10 summarizes the NOX data in a comparison to the targets developed using
Figure 6. From this data the application of the new generation TTL/MG50 burner
is projected to decrease NOX about 17%, (see, L3 in Figure 10). Staging with
10% OFA would reduce NOX by 26% (L4). Using 20% OFA, (Figure 9) would achieve
the target NOX emission (L2).
The carbon loss reductions obtained with the TTL/MG22.5 reached the goal
established from the TTL5 burner and the guideline given in Figure 7. Three
sets of firing conditions were evaluated for the TTL/MG22.5 burner; low excess
air, low excess air with OFA and low excess air with a combination of OFA and
flue gas recirculation (FGR). The use of FGR had little impact on reducing NOV
A
during residual fuel oil firing. This is consistent with the findings of others
(8). As illustrated in Figure 11, the TTL/MG22.5 indicates a 47% to 57% carbon
loss reduction compared to the TTL5.
Natural Gas and Natural Gas/Residual Oil Dual-Firing
Brayton Point plans to add natural gas capability to in the future. Since the
unit has never fired natural gas, field data to develop a NOY correlation with
A
the CBTF are unavailable. The combustion testing of the TTL/MG22.5 with natural
gas in the CBTF provided information on the response of NOV emissions to various
A
hardware and operating parameter adjustments.
At design operating conditions of 1% 02, NOX emissions are about 60 ppm.
Variations in oxygen between 0.8% and 1.1% resulted in negligible changes in NOY
4A-42
-------
emission. CO did not vary for this range of excess air testing (12 ppm).
Staging from 0% to 15% reduced NOX from 61 ppm to 54 ppm indicating a very weak
response to staging. Again, the CO levels remained near 12 ppm.
Simultaneous firing of natural gas and residual oil in the TTL/MG22.5 burner was
tested in the CBTF. In the field Brayton Point wants the option to fire both
fuels simultaneously, either through the same burner, dual-firing, or through
separate burners, co-firing. As a single burner installation, the CBTF test rig
allows the evaluation of only dual-firing conditions. The state NOX emission
regulations for new sources are specific for gas or oil firing, but not stated
for simultaneous firing. For these conditions, a linear extrapolation may be
used as a first cut guideline by state environmental agencies.
Dual-firing tests were setup to evaluate NOX emissions at varying ratios of gas
and oil heat input. This was done with and without OFA. The results are
summarized in Figure 12. As natural gas is introduced into the burner a
significant increase in NOX emissions occurs, line 12. This trend stops near a
ratio of 80% oil/ 20% gas. Then the NOX decreases linearly to the level for 100%
gas. A similar situation occurs with 15% OFA but the effect is diminished at
these lower NOX levels. In this test program similar trends were found in a
more conventional steam atomized low-NOx burner except the initial rise in NOX
did not diminish with the use of 15% OFA.
SUMMARY
NEPSCo has supported a program that will assist in meeting commitments to
retrofit units at Salem Harbor and Brayton Point. The goals of the program aim
for improving unit efficiency, operation and fuel flexibility and simultaneously
reducing NOX emissions, carbon loss and particulate emissions. The program
evaluated several high efficiency, low-NOx burner technologies. Communications
with other users, burner proposal evaluations, atomizer tests, large scale
combustion tests, retrofit impact analysis and economic evaluations have all
played a roll in advancing the program. The selected technology, Rodenhuis and
Verloop TTL/MG50, is scheduled for installation at Brayton Point and Salem
Harbor in 1991, Full scale test results should be available in 1992.
4A-43
-------
REFERENCES
1.) R. F. Afonso, N. M. Molino, D. C. Itse, J. J. Marshall, J. F. Hurley and
S. Lindeman, Evaluation of Low-N0x, High Efficiency Oil and Gas Burners
for Retrofit to Utility Boilers. Presented at: American Flame Research
Committee 1989 International Symposium on Combustion in Industrial
Furnaces and Boilers, Short Hills, New Jersey September 25-27,1989 and the
EPRI Fuel Oil Utilization Workshop, Clearwater Beach, Florida November 1-
2, 1989, EPRI GS-6919, July 1990.
2.) R. A. Lisauskas, Experimental Investigation of Retrofit Low-No^ Combustion
Systems. Proceedings of the 1985 Symposium on Stationary Combustion NOX
Control, Vol. 1, EPRI CS-4360, January 1986.
3.) D. V. Giovanni and T. Sonnichsen, Gaseous and Particulate Emissions Tests
at Salem Harbor Unit 4. Report submitted to New England Power Service
Company by KVB, Inc., NY, December 1972.
4.) G. Dusatko, Salem Harbor Unit NOX Reduction Program. Report submitted to
New England Power Service Company by KVB, Inc., NY, September 1973 and
supplemental report in July 1974.
5.) N. M. Molino, G. Dusatko, Field Test of a Processed and Emulsified
Residual Oil at Salem Harbor Station Unit No. 4. Published by the
American Society of Mechanical Engineers, 345, East 47th ST., New York, NY
Ref. No. 87-JPGC-FACT-B.
6.) C. C. Masser, R. A. Lisauskas, D. C. Itse. Extrapolation of Burner
Performance From Single Burner Tests to Field Operations. Presented at:
1985 Joint EPRI/EPA Symposium on Stationary Combustion NOY Control,
Boston, MA, May 6-9, 1985.
7.) P. N. Garay. Add low-nitrogen, emulsified oils to list of emerging NO
controls. Power Magazine, October 1990.
K. M. Bentley, S. F. Jelinek, NOX control technology for boilers fired
with natural gas or oil. TAPPI Journal, April 1989.
4A-44
-------
Figure 1. Brayton Point Unit 4
©
©-
© © © ©
© ©
0 © © e-A
OMAT
OIL
IGfUTCII
CII-1
LILII1NCIIS
EL. 55'
BURNERS
FOHNEY
trrE
TTL
=n-
^Z>)
ID'-o I
Figure 2. General Burner Arrangement
4A-45
-------
FLAME STABILIZER
PRIMARY AIR BULLET
OIL GUN
REFRACTORY
THROAT
Figure 3. Rodenhuis and Verloop TTL5 Burner Arrangement
Figure ^. Rodenhuis and Verloop TTL5 Atomizing Bullet
4A-46
-------
Burner assembly
1/ Combustion air
21 Atomizing air
3/ Oil supply
4/ Gas supply
5/ Oil burner
6/ Ignitor
II Flame detector
8/ First stage atomizing air
9/ Second stage atomizing air
10/ Cylindrical air damper with drive
Oil and gas burner
Figure 5. Rodenhuis and Verloop TTL/MG Burner
and Atomizing Bullet Assembly
4A-47
-------
400:
o Salem Harbor
* CBTF TTL5
xLl
250-
200^
1501
5Q-.
0 50 100 150 200 250 300 350 400 450 500
Burner Area Heat Release, 103 Btu/hr-ftz
Figure 6. Correlation of CBTF NOx
Emission to Full Scale
oo
en
o
o
CD
o
u.iuu -
A f"\7 c '
0 A7H "
n np;^ :
n n^n :
n HSR "
n nsn "*
n OAR ~
n nin ~
n nis =
n nin ~
n nos "
n n9n
n ois
n run
n nns
0 QQO
0
0 1
0 2
0 3
.0 4
ill!
.0 5
| 1 I! i
0 6
I""
4 -1
0 7
s
: —
0 8
/
/
0 9
^
^
— —
.0 10
/
.
,111
.0 1
/s
^
.0 12
/
*~^*—
1 1 1 1 1
.0 i:
/*
Mil
.0 14
/*
1 1 1 1
.0 15
ASPHALTENES, %
• -ACTUAL X-GOAL
Figure 7. Salem Harbor Unit Performance
(Asphaltenes Versus Carbon
4A-48
-------
300
200 -
260 -
240 -
220 -
200 -
100 -
150 -
UO -
120 -
100 -
00 -
60 -
40 -
20 -
0 -
TTL5
TTL/HG 22.5
TARGET IN CBTF (101 ppm)
EXIT OXYGEN, %
Figure 8. Oil Firing Effect of Exity Oxygen on MOx
000
200 -
260 -
210 -
220 -
200 -
100 -
160 -
UO -
120 -
100 -
00 -
60 -
40 -
20 -
0 -
TARGET IN CBTF (104 ppm)
12
16
24
20
or A, i
Figure 9. Oil Firing Effect of OFA on NOx
4A-49
-------
to
o
o
QQ
Cd.
400
350 -I
300 -_
250 -;
= 200
100
LI Baseline
L2 Limit 0.3 Ib/HMBTU
L3 TTLMG/22.5 0%OFA
L4 TTLMG/22.5 10% OFA
0 50 100 150 200 250 JOO 350 400 450 500
BURNER AREA HEAT RELEASE, 103 BTU/HR FT2
Figure 10. Projected NOx Emissions to Full Scale
CUlF-PAimCIILAlG SiAMI'l INQ TEST CONDITIONS AND CAmiON LOSS
2.4 :
9 n -
1 fi
1.2 -.
n H
0.4 -;
0.0 :
FACIUTY
cnrF
CBTF
CUFF
CBTF
CBTF
BUnNETI
DESIGN
TTI 0
TADGirr
TTUMG22 5-GTU. BULLT
TTL/MG22.5-STD. EULLT
TTL/MG22 5-STD GUI.LT
TEST
NO.
^2~
-
91
90
101
OIL
ASPI 1ALT
11.2
11 2
O.D
0.0
9.0
I I I I
OIL
VISCOSITY
SBU
150
-
105
103
103
t
I I I I
38
34
loi
I I I I
EXIT
O2
2.2
00
0.7
0.8
0.7
II I I
SI
I I I
OFA
Va
0
-
0
11
9
Fen
0
-
0
0
9
I I
CARBON
LOSS
"Mi
1.01
1.09
0 92
0.9Q
079
I I I
I I I I
0 I 2
4567
9 10 II 12 13 14 15
ASPHALTENES, %
0-TTL5:*-GOAL:-|--R&VTTL/MG
Figure 11. Performance Comparison
Asphaltenes vs. Carbon Loss
4A-50
-------
300
220 -
ZSQ -
2W -
ro
-------
DEVELOPMENT OF AN ULTRA-LOW NOX PULVERIZED COAL BURNER
Joel Vatsky, Director
Timothy W. Sweeney, Supervisor
Combustion and Environmental Systems
Foster Wheeler Energy Corporation
Perryville Corporate Park
Clinton, New Jersey 08809-4000
-------
DEVELOPMENT OF AN ULTRA-LOW NOX PULVERIZED COAL BURNER
Joel Vatsky, Director
Timothy W. Sweeney, Supervisor
Combustion and Environmental Systems
Foster Wheeler Energy Corporation
Perryville Corporate Park
Clinton, New Jersey 08809-4000
ABSTRACT
Foster Wheeler has been utilizing the Controlled Flow/Split-Flame Low NOX burner for both new and
retrofit applications since 1979. This Internally Staged burner attains 50-60% NOX reduction, as
compared to pre-NSPS turbulent burners, without utilizing any staging ports. A new burner has been
developed which combines the internal staging concept with another patented Foster Wheeler
technology: fuel staging. This new design, which is defined as Internal Fuel Staging , is consistently
achieving NOX levels of 0.25 lb/10 Btu with bituminous coals containing 22-35% volatile matter and
fuel nitrogen of 1.8%. This represents at least 75% reduction from turbulent burner levels. This paper
discusses the results of comparative tests between the standard CF/SF Low NOX burner and the new
IPS design.
4A-55
-------
DEVELOPMENT OF AN ULTRA-LOW NOx PULVERIZED COAL BURNER
INTRODUCTION
An advanced low NOX burner has been developed which achieves NOX emission levels as low as 0.25
lb/106Btu; equivalent to reductions of up to 75% from turbulent burner levels. The Internal Fuel
Staged™ design is based upon concepts developed and patented by Foster Wheeler in the late 1970's.
Development of the IPS design was not undertaken at that time in favor of proceeding with the
Controlled Flow/Split-flame low NOX design. The latter is Foster Wheeler's standard low NOX burner
which as been in utility and industrial service, in both new unit and retrofit applications, since 1979.
The CF/SF burner was developed to achieve at least 50% NOX reduction in retrofit applications and
meet the 1979 New Source Performance Standard, of 0.5 lb/106 Btu for sub-bituminous and 0.6 lb/106
Btu for bituminous coals, without the simultaneous use of supplementary NOX controls such as overfire
air.
The IPS design, having a NOX control capability significantly greater than that of the CF/SF, was
delayed in development simply because there was no commercial market for a system with such low
NOX capabilities. By 1989 it became apparent that new source requirements were tending toward 0.3
lb/10 Btu and retrofit requirements toward 0.5 or lower.
Although the CF/SF design operates below the 0.5 level, in both new units and retrofits without
overfire air, and below 0.3 with overfire air, Foster Wheeler decided to advance the technological
capability by developing the IFS. Commenced in May 1990, the IPS development was completed in
September 1990 and has been offered commercially, with considerable success, since that time.
Development testing was done on Foster Wheeler's 80 million Btu/hr Combustion and Environment
Test Facility. Since substantial testing of the CF/SF burner had been performed on the CETF and
correlated with utility boiler data, and there are over 5,000 MW of retrofitted and over 7,000 MW of
new units with this design, all development testing of the IFS was comparative with CF/SF data.
Typical NOX emissions from the CF/SF burner, on theCETF, are about 0.4 lb/106 Btu. Typical IFS
emissions are 0.25-028 lb/106 Btu, at least one-third lower; both without overfire air.
It should be noted that the IFS design differs from the CF/SF in only a single component: the fuel injector's
nozzle. Consequently, it represents only a minor change in overall design since all other burner
components, and the operating method, are identical to the CF/SF design. The IFS coal nozzle is, therefore,
easily retrofittable to CF/SF burners currently in operation, thereby converting it to the EPS.
CONTROLLED FLOW/SPLIT-FLAME LOW NOX BURNER
The CF/SF design shown in Fig. 1 is based upon the principle of Internal Staging™ of the flame. This
principle was developed and defined by Foster Wheeler in the 1970's.
4A-56
-------
INTERNAL STAGING™ is defined as:
A low NOX burner design which two-stages the secondary air flow and stages the primary air/fuel
flows within the burner's throat while maintaining classical turbulent burner flame patterns and low
pressure drop: < 4.0" H20.
The Controlled Flow /Split-flame name is derived from the operating functions of the burner:
Controlled How for the dual register design which provides for the control of inner
and outer swirl zones along with a sleeve damper which allows independent control
of the quantity of secondary air flow to each burner.
Split-Flame for the coal injection nozzle which develops a split-flame pattern for
obtaining low NOX emissions.
Key criteria within the overall design philosophy are summarized as follows:
Mechanical reliability to be such that after long term operation movable components
would still operate.
Combustion air flow and swirl to each burner to be independently controllable.
Adjustable primary air/coal velocity to ensure optimum relation between primary
and secondary air streams.
No increase in primary or secondary air pressure drop so that existing PA and FD
fans can be used.
• Burner capacity to cover the complete range of industrial and utility use:
approximately 30 to 300 million Btu/hr.
Plug-in retrofitability, i.e., no pressure part changes, no burner piping
rearrangement and no major windbox modifications when installed on most
existing wall-fired boilers.
The CF/SF low NOX burner's components and their functions are described below:
Perforated Plate with Sleeve Damper: used to control secondary air flow on a per
burner basis. By measuring the pressure drop across the perforated plate an index of
air flow is obtained. The air distribution, vertically and horizontally, within the
windbox is thus optimized by adjusting the sleeve dampers to obtain equal burner
stoichiometries. This is a one time optimization after which the "open" position is
fixed. The sleeve damper has "closed", "ignite" and "open" positions and is used,
instead of the main radial vane register, to shut off the air flow when the burner is
out of service. It is controlled by an electrically operated linear drive, but is not
modulated with load.
Dual Series Registers: provide improved flame shape control by two-staging the
secondary air. A key mechanical reliability feature of this configuration is that the
blades and drive mechanisms, set back from the furnace wall, are well "shaded"
from direct flame radiation. Consequently, the registers operate at windbox
4A-57
-------
temperature and do not overheat, warp or bind. Additionally, once the flame is
optimized for proper shape, the registers are fixed. They remain in their optimum
position and are not modulated with load or closed when the burner is taken out of
service since the sleeve damper performs the latter function. The burner essentially
becomes a fixed register type with the option for adjusting the register if a major
fuel change occurs; the drive mechanisms being manual.
Split-Flame Nozzle: segregates coal into four concentrated steams. The result is that
the volatiles in the coal are driven out and are burned under more reducing
conditions than otherwise would occur without the split flame nozzles. Combustion
under these conditions converts the nitrogen species contained in the volatiles to N2,
substantially reducing NOX formation.
Adjustable Coal Nozzle: allows primary air/coal velocity to be optimized without
changing primary air flow. The proper relationship between primary and secondary
air is important for both good combustion and flame shaping. Once optimized no
further adjustment is required.
Succinctly, only the sleeve damper, used to shut off the secondary air flow, is moved when the burners
are taken in or out of service. Thus, after optimization, the burners become fixed register types.
Mechanical reliability of the design concepts, materials and operational methodology has been fully
confirmed by commercial experience.
ADVANCED OVERFIRE AIR SYSTEM
NOX emissions from the burning of pulverized coal have three (2) sources: Thermal NOx generated
from thermal fixation of atmospheric nitrogen (Nz) at high flame temperatures, conversion of bound
nitrogen in the coal's volatile fraction and conversion of bound nitrogen in the coal's char fraction. The
latter being the most difficult part of the emission to control.
Foster Wheeler's NOX control philosophy has been based upon using the CF/SF low NOx burner which
achieves a high degree of thermal and volatile-fraction fuel NOX reduction; with char-fraction fuel NOX
reduction to a lesser degree. This low NOX burner's effectiveness is uniformly consistent in reducing
NOX emissions by 50-60% from uncontrolled levels. When lower levels are required an advanced
overfire air system (AGFA) can be incorporated to increase NOX control to the 70-80% range. These
results are valid for both new steam generators and retrofittable existing units.
Figure 2 schematically illustrates a typical AOFA system. It is characterized by a set of overfire air ports
placed well above the top burner level to provide relatively long residence time between the top burner
level and the overfire air port level. One port is located above each burner column with an additional
port near each sidewall. This is illustrated in Figure 2 where a four-burner wide arrangement uses six
overfire air ports on each firing wall.
Older overfire air arrangements, which used fewer ports and shorter residence time, can achieve only
about 20-30% NOX reduction from the low NOX burner's level. This AOFA system increases the NOX
reduction capability to the 40-50% range. Foster Wheeler demonstrated this system's capability in the
early 1980's when two (2) new utility boilers, a 275 MW front-wall fired unit and a 550 MW
opposed-fired unit, were tested. The combination of the CF/SF low NOX burner and the above noted
AOFA principles enabled both units to operate at NOX levels of about 0.2 lb/106 Btu. During
subsequent commercial operation the overfire air ports were closed since the NOX regulations to be
4A-58
-------
attained were only those of the 1977 NSPS. Without overfire air both units operated at about 0.41b/106
Btu.
The AGFA System was not commercialized by Foster Wheeler until the late 1980's since there was no
regulatory need to achieve emission levels below 0.3 lb/10 Btu. This system is now being incorporated
on several new steam generators, ranging in size from 65MW to 550 MW. In early 1990 it was retrofitted
to a 500 MW unit, having the arrangement shown in Figure 2, where NOX emissions were reduced 78%
to about 0.26 lb/106 Btu.
FIELD EXPERIENCE: CF/SF AND AGFA
Since its introduction in 1979, when retrofitted to the 36Q MW San Juan No. 1 unit of Public Service
New Mexico, the CF/SF low NOX burner has been successfully retrofitted to a total of ten (10) utility
boilers. Table I summarizes this experience, which totals 5,135 MW. The average NOX reduction
attained on these units is nearly 60% without overfire air; and nearly 80% with AOFA.
Table II is a listing of the projects underway for 1991: eight (8) units totalling 3,635 MW. Options in
these projects add another 2,380 MW for a total of over 11,000 MW and over 600 burners.
The NOx control capability and results are summarized on Figure 3, which contains data from four of
the ten utility units, two industrial units and Foster Wheeler's Combustion and Environmental Test
Facility. Table in lists the range of fuel properties in these retrofit applications. The NOX control
capability is consistent.
Figure 3 graphically illustrates the NOX control effectiveness of the low NOX Controlled
Flow/Split-Flame burner. The plot is of total NOX emission against Burner zone Liberation Rate (a
measure of heat input to the burner zone; the higher this number the hotter the lower furnace), for
turbulent burners, CF/SF low NOX burner and CF/SF in combination with AOFA. The data show both
industrial and utility units with burner capacities ranging from 30 to 300 million Bru/hr. The curves are
not load curves but, rather, represent the full load NOX emission for each value of Burner Zone
Liberation Rate.
Conclusions drawn from the summary information contained in this figure are:
1. NOX control is independent of burner capacity: large burners and small burners
achieve the same degree of NOX reduction.
2. The low NOX burner (lower two curves) is much less sensitive in the thermal
environment than is the turbulent burner. There is a much smaller slope of the NOX
vs BZLR low NOX curves than for the turbulent burner curves indicating a very
small amount of thermal NOX is emitted by the low NOX burner (due to its lower
flame temperature).
3. NOX reduction in the higher temperature units is somewhat greater than in the
lower temperature (lower BZLR) units due to the substantial decrease in thermal
NOX in the former.
4. Uncontrolled NOX emissions from single wall-fired units is higher than from
opposed-fired units, yet this difference is eliminated by the CF/SF burner.
4A-59
-------
5. Foster Wheeler's Advanced Overfire Air System provides an additional NOX
reduction of 40-50% (to total reduction of 70-80%) below levels emitted by the low
NOX burner only.
Foster Wheeler has retrofitted wall-fired steam generators from all major domestic boiler
manufacturers, including an 800 MW opposed-fired unit originally equipped with three-nozzle "cell"
burners. The effectiveness of the CF/SF low NOX burner is the same regardless of the boiler in which it
is installed.
Of utmost importance to steam generator operation are its performance and efficiency. In none of the
low NOX burner retrofits performed by Foster Wheeler have either boiler performance of efficiency
been deteriorated from pre-retrofit conditions. Typically efficiency is improved due to:
Reduced excess air operation yielding lower stack losses and reduced forced draft
and induced draft fan power.
Lower burner pressure drop yielding further F.D. fan power savings.
Cleaner furnace walls (reduced slagging).
Unburned carbon levels equal to, or lower than, original equipment burners.
Succinctly, unit operations are equal to, or better than, pre-retrofit while NOx is reduced at least 50%
without overfire air.
Also shown on Figure 3 is the effectiveness of AOFA on three utility units and the CETF. All results,
without and with AOFA, are uniformly consistent in terms of NOx control.
Two projects are of particular interest: Units 1 and 7 on Figure 3. Unit 1 is an 800 MW boiler originally
equipped with 18-3 nozzle cell burners and was retrofitted with 48 CF/SF burners in early 1989. Unit 7
is a 500 MW boiler retrofitted with CF/SF burners and AOFA in early 1990. Since the results of these
two retrofits are typical of all others they will be briefly discussed below.
1. Four Corners Unit No. 4: Cell Burner Boiler - Arizona Public Service
This boiler is a Babcock & Wilcox opposed-fired, supercritical steam generator with
a maximum continuous rating (MCR) of 5,446,000 Ib/hr main steam flow at
1000/1000F and 3590 psig. The unit was fired by 18, 3 nozzle cell burners (54
throats). Turbine rating is 820 MWG (780 MW net). Unit 4, along with its sister Unit
5, was built in the late 1960's; and went into commercial operation in 1969 and 1970,
respectively. In 1971 the State of New Mexico instituted a retroactive NOX emission
limit of 0.7 lb/10 Btu for coal-fired units constructed prior to 1971. Over the years
Arizona Public Service conducted several test and evaluation programs to arrive at
an acceptable means of achieving the NOX limit without degrading boiler
operability, performance or efficiency. In 1988 Foster Wheeler was contracted with
to provide a low NOX conversion with a guarantee lower than the State limit (0.65 vs
0.7). The unit was experiencing severe slagging, wide spacial variation of Furnace
Exit Gas Temperature and resultant high superheater outlet metal temperatures.
Consequently, Arizona Public Service chose to proceed with a complete
revision of the lower furnace. This consisted of replacing both front and
4A-60
-------
rear firing walls with a new burner arrangement, six (6) burners wide and four (4)
burners high.
Foster Wheeler's scope of supply consisted of 48 CF/SF low NOX burners, twelve
burner wall panels (each containing four throats), new igniters and scanners and
miscellaneous equipment. Arizona Public Service had already contracted with B&W
to supply nine new MPS-89N pulverizers for each unit (Unit 5 mills were previously
installed and Unit 4 mills were installed during the low NOX conversion). Due to the
new firing configuration the total number of mills purchased for both units was
reduced from 18 to 16.
It should be emphasized that this conversion represents the most extensive
modification that can be performed on a cell-burner boiler's firing system. However,
the method chosen was designed not only to reduce NOX emissions but also to
improve boiler operability. In particular to produce a more uniform Furnace Exit
Gas Temperature (convert to one mill supplying a burner level) and reduce slagging
(vertically spreading the burners). Slag reduction also occurs because of the lower
flame temperature inherent in the CF/SF burner.
Other cell burner equipped boilers may not require modification as extensive as
Four Corners 4 & 5. In many units only a direct low NOx burner replacement may
be acceptable.
Also, of the total of 23 units either completed, underway or as contractual options,
the two Four Corners units are the only ones requiring panel replacement. The vast
majority of boilers, regardless of original equipment manufacturer, can be
retrofitted with Foster Wheeler low NOx burners without pressure part
modification.
The results of this retrofit are summarized on Table IV which compares pre and
post-conversion conditions.
Significantly, burner pressure drop has been reduced 2-2.5" BtzO which will yield
substantial forced draft fan power savings.
During the past nearly two years since start-up the unit has operated according to
system load requirements, almost continually at full load. The following results
have been observed:
- - There is no flame impingement on any heat transfer surface and no extension of
flames.
- - Slagging and clinkering have been nearly eliminated on Unit 4. The furnace walls
are now the cleanest they have been since initial unit start-up 20 years ago. In
contrast the unconverted Unit 5 continues to have the same level of slag
accumulation that Unit 4 had prior to conversion.
- - There has been no increase in FEGT, instead it appears to have decreased as a
result of increased furnace absorption caused by the clean walls.
4A-61
-------
- - Combustion efficiency has not been decreased, as indicated by CO and unburned
carbon levels.
In summary, NOX emissions, have been reduced about 60% with no degradation in
boiler performance or efficiency. Unit operability has been significantly improved
due to the near elimination of the slagging/clinkering problems and elimination of
excessive superheat tube metal temperatures.
Unit 5 is currently undergoing retrofit.
2. Hsin-Ta #1: Taiwan Power Corp: This is a 500 MW Foster Wheeler natural
circulation unit in commercial operation since 1978. Originally equipped with an
early non-split flame low NOX burner (FW Controlled How design) and a basic
1970's vintage overfire air system, it was designed to meet a NOX regulation of 0.7
lb/106 Btu. More recently, the NOX regulations in Taiwan have been reduced. As a
result TPC purchased 24 CF/SF low NOX burners and the AOFA system for both
Foster Wheeler units on that site.
Unit 1 was converted in early 1990, and has been operating for approximately ten
(10) months. Because of the simultaneous use of CF/SF burners and AOFA this
unit's operating data will be presented in more detail than Four Corners #4. The
firing system and geometrical arrangement are as shown schematically in Figure 2.
After start-up and low NOX optimization a series of performance tests were done
over a period of several weeks. Since Taiwan imports most of its coal, fuels from the
US, Australia and South Africa were fired as part of normal plant operations. Table
V lists the typical range of coals fired at this station. Fuels varied on a day-to-day
basis. As shown on the table volatile matter varied from 22.5% to 36.1% with fuel
nitrogen contents covering the relatively high range of 1.85% to 2.28%.
However, the low NOX systems effectiveness is such that there is no significant
affect of these fuel properties on NOX emissions. Boiler performance and efficiency
variations were only those normally expected due to fuel properties affecting gas
weights and moisture content.
Figure 4 compares NOX emissions as a function of load for the CF/SF burner with
AOFA closed and open. Load was reduced in the manner normal for that station
with pulverizers taken out of service at the same loads they were prior to the low
NOX retrofit. The unit achieved full load with all mills in service or any single mill
out of service. Consequently full load testing was performed with all mills in or one
top or bottom mill out of service.
NOX emissions decrease monotonically from full load values average 0.464 and
0.266 lb/10 Btu with AOFA ports closed and open, respectively. For simplicity of
graphical illustration only seven (7) data points are shown, out of a much larger set.
The temporal and fuel-property related variations in emissions cover a narrow
range: at not time did NOX emissions exceed 0.5 or 0.3 with AOFA closed or open,
respectively.
Figure 5 is a similar plot of windbox-to-furnace pressure drop as a function of load.
These results are also typical of the Foster Wheeler low NOX system. At full load
4A-62
-------
with AOFA closed and all mills in service AP does not exceed 3.0" H2O. When
AOFA ports are opened AP decreases to less than 1.5" HiO at full load. In both cases
AP decreases monotonically as load decreases.
Figure 6 illustrates the change in variability of the NOX emission as more
sophisticated NOX controls are used at full load. From a mean (X) emission of 1.23
lb/10 Btu and standard deviation (S) of 0.06 in the uncontrolled case, X and S are
decreased to 0.464 and 0.032 with CF/SF burner and no overfire air. When AOFA
ports are opened X = 0.266 and S = 0.012. The data includes all miH combinations
and the range of fuels listed in Table V.
The following summarizes the results of Figures 4,5 and 6.
- - NOX does not increase as load is decreased.
- - Full load pressure drop is no greater than for typical turbulent burner values, less
than 3.5" HiO at full load.
- - High burner pressure drop is not needed to attain high NOX reduction and low
absolute emission level.
- - NOX emission variability due to operating condition and fuel properties decreases
with the use of more'sophisticated NOX controls.
Although the above results and conclusions are presented for two specific
retrofitted units, they are typical of data obtained on all other retrofits as well as
from thousands of additional MW's of new steam generators utilizing the same
equipment.
INTERNAL FUEL STAGED™ LOW NOX BURNER DEVELOPMENT
The development of the IPS low NOX burner has been performed on the Combustion and
Environmental Test Facility (CETF) located at Foster Wheeler's manufacturing facility in Dansville, NY.
Among the types of test work being performed at the CETF are burner development, low NOx furnace
design evaluations, sulfur dioxide control by dry sorbent injection, fuels evaluations, integrated
combustion/emissions control testing and customer support and problem analysis.
The CETF's furnace (Fig. 7) is arranged to produce conditions which closely match those of commercial
equipment, for example:
Furnace residence time is limited to about 2 sec. max. between the burner centerline
and furnace exit.
Furnace Exit Gas Temperature (FEGT) is about 2200 °F and can be varied, by
adjusting total furnace absorption.
Bumer/fumace aerodynamics are similar to those of commercial equipment as are furnace
mixing patterns, due to both overall geometry and the two-burner-high arrangement.
4A-63
-------
The arch configuration, which is required to provide proper conditions for low volatile fuel
combustion, is also important to produce the desired velocities/residence times and FEGT with
horizontal firing. The reduced upper furnace cross-section is responsible for the increased
velocity and resultant decreased residence time. Decreased upper furnace heat transfer surface
reduces absorption above the burner zone, thereby increasing FEGT to levels normally achieved in
commercial equipment.
Although not currently equipped with a superheater, the unit has screen tubes at the furnace exit
followed by a water-cooled economizer which yield realistic gas quenching rates. In this way all flue
gas constituents, gaseous and particulate, are comparable to field equipment. Commercial practices,
used throughout the CETF system design, have been mated with research-oriented considerations
wherever practicable to maximize the usefulness and flexibility of the system.
The CETF utilizes a direct-fired system (i.e., hot-primary-air-swept ball mill) feeding either a single 75
million Btu per hour arch-fired twin-cycle burner assembly or two 40 million Btu per hour
horizontally-fired burners (shown) which fire into a refractory-lined water-jacketed furnace. The water
jacket operates under water-head pressure and utilizes natural circulation, producing steam which is
vented to the air through a steam drum above the furnace. Combustion gases leaving the furnace flow
over horizontal, convection tube surfaces (economizer) cooled by forced-water circulation. The gases
then pass through a two-stage air heater (a tubular air heater followed by a heat pipe air heater), a
baghouse dust collector, an induced-draft fan, and then the stack. The level of sulfur dioxide is
controlled by injecting a sodium-based sorbent into the gas stream prior to the baghouse. In addition to
back-end sulfur dioxide cleanup, the CETF has the capability of furnace injection of calcium-based
sorbents for evaluation of in-situ sulfur dioxide control.
IPS DESCRIPTION
The IFS concept, as noted in the introduction, was conceived in the 1970's but not developed at that
time. Internal Fuel Staging is defined as:
A low NOX burner which two-staged the secondary air flow and internally stages
the fuel flow and primary air flow such that co-axial flames are developed within
the burner's throat while maintaining classical turbulent burner flame patterns and
low pressure drop: < 4.0" H2O.
Figure 8 schematically illustrates the IFS design. The philosophy of this development was to utilize as
much of the commercially-proven hardware of the Controlled How /Split-Flame low NOX burner as
possible. As can be seen in Fig. 8, the IFS differs from the CF/SF in only one respect: the coal injector's
nozzle.
AH other mechanisms and functions are identical to those of the CF/SF, including operating method.
Externally, the two burners appear to be identical. However, internally the fuel injection's nozzle has
been redesigned to produce split-flames surrounding a co-axial internal flame. The result is NOX
emissions approximately one-third lower than those attained with the CF/SF design.
Table VI is a comparison of the key features of the CF/SF and the IFS. The similarity is so great that an operator
would note no difference between the two designs, other than the lower emission from the IFS.
The IFS burner is intended for use in both new and retrofit applications. Also, if units which are already equipped
with the CF/SF design require lower emissions all that is necessary is to replace the fuel injector.
4A-64
-------
IPS PERFORMANCE RESULTS
Due to extensive performance and emission data available for the CF/SF low burner, from the CETF
and new and retrofit field applications, IFS testing on the CETF is compared to CF/SF data.
Boiler performance results demonstrate no adverse difference in either furnace absorption or Furnace
Exit Gas Temperature on the CETF between the two low NOX burner designs. Since extensive field data
already exits which shows no change in boiler performance when the CF/SF is retrofitted to boilers
initially equipped with turbulent burners, it can be inferred the IPS design will, similarly, not adversely
affect boiler performance.
A wide range of fuels, sub-bituminous and bituminous have been tested on the CETF using the CF/SF
burner. For the EPS development testing two baseline bituminous coals have been used: a low volatile
and several high volatile coals.
Table VII compares NOX and CO data at full load for the two burner designs with the high and low
volatile coals. NOX is reduced 33-35% below CF/SF levels using the IFS. For all data, overfire air ports
are closed and excess C>2 is 3.4-3.6%. Note that for both fuels the variability in NOx emission decreases
significantly, to about the same standard deviation. Typical coal analyses are listed in Table VIE.
Figure 9 compares NOX and air-to-coal ratio (A/C) to load. Over a turndown ratio of nearly 3:1 NOX
decreases monotonically with load from about 0.27 to about 0.21 lb/10 Btu. A/C increases as load
decreases from about 2.1:1 to about 2.6:1, covering the range of typical vertical roller pulverizers. This is
a significant result in that reduced load operation does not deteriorate the IFS burner's performance:
NOX does not increase as load decreases.
It is also instructive to compare the CF/SF NOX data from the 500 MW boiler, without and with
overfire, to the CF/SF and IFS data from the CETF without overfire air. Figure 10 presents such a
comparison. The mean uncontrolled emissions for the 500 MW and the CETF are 1.23 and 1.04 lb/10
Btu for the fuel ranges listed in Tables V and Vin respectively. The 500 MW unit's emission in higher
than that of the CETF because it is a hotter unit and was firing higher nitrogen fuels than the CETF.
On each unit, NOX is reduced by over 60% with the CF/SF low NOX burner without overfire air. Note
that both the uncontrolled data and CF/SF data have nearly identical standard deviations
approximately 0.06 and 0.03, respectively. When overfire air ports are open on the 500 MW unit NOX is
further decreased to a mean value of 0.266 lb/10 Btu: a total reduction of over 78%.
On the CETF the IPS low NOX burner yields a mean NO>c emission of 0.269 lb/106 Btu without overfire
air: a total reduction of nearly 75%. Note that the standard deviations on the 500 MW unit with overfire
air ports open is about the same as that of the CETF when the IFS is used with overfire air ports closed.
Again illustrating that more sophisticated NOX controls become less sensitive to operating conditions
and fuel parameters.
A further comparison from this data is the NOX reduction from CF/SF levels due to AOFA or IFS. On
the 500 MW unit NOX reduced 42.7% when the OFA ports are open. On the CETF, the IFS burner
reduces NOX 33.6% below CF/SF levels. The IFS low NOx burner is achieving a NOX reduction
capability that is 80% of the additional reduction AOFA attains beyond CF/SF levels.
The relationship of the IFS results to field data are graphically illustrated on Figure 11, which is a simplified version
of Figure 3. Clearly, many commercial boilers will be able to operate at levels below 0.4 lb/10 Btu without AOFA
Where lower levels are required the IFS low burner can be supplemented with the AOFA System.
4A-65
-------
SUMMARY
Foster Wheeler's standard Controlled Flow/Split-flame NOX burner has been successfully retrofitted
to ten (10) utility steam generators ranging in size from 225 MW to 800 MW, with an additional 6000
MW either underway or as options to existing contracts. In 1991 3635 MW will be retrofitted. Of these
three units, two B&W and one Foster Wheeler, will be receiving the new Internal Fuel Staged low
NOX burner design.
The EPS burner development has been successfully completed and it has been offered commercially for
new steam generator and retrofit use. The full range of emissions and boiler performance guarantees
are offered. In addition to the above noted retrofits, the IPS will be installed on the following new steam
generators:
2 x 65 MW; NOX guarantee: 0.32
2 x 150 MW*;NOx guarantee: 0.27
1 x 550 MW; NOX guarantee: 0.32
*
These Units will also be equipped with Foster Wheeler's SCR system to achieve 0.1
lb/106Btuatthe Stack
The IPS design achieves NOX levels one-third lower than those attained by the standard CF/SF low
NOX burner, when tested on the Combustion and Environmental Test Facility. NOX levels below 0.27
lb/10 Bru without simultaneous use of overfire air, are routinely attained with a wide variety of
bituminous coals with NOX emissions showing little sensitivity to operating mode or fuel
characteristics. These performance results are obtained at low burner pressure drop and with short
flames which do not cause adverse changes to furnace absorption rates or Furnace Exit Gas
Temperature.
It is fully expected that these results will be duplicated in the new unit and retrofit applications
currently underway.
4A-66
-------
Year
1979
1980
1981
1986
1987
1989
1990
1990
1990
1990
Total
MW
360
525
275
650
500
800 (Cell)
800
500
500
225
5135 MW
0.95
*•
X-
1.0
1.15
1.25
1.10
1.23
1.15
1.15
Table I
Low NOX Burner
Retrofit Experience
NOX db/106 Btu)
Before After
0.42
0.40
0.40
0.41
0.55
0.50
0.45
0.27+
0.50
0.50
Reduction
OEM
56
—
—
59
52
60
59
78
56
56
FW
FW
FW
FW
FW-UK
B&W
FW
FW
FW UK
FW
New Boiler Converted during erection + With Advanced Overfire Air System
NOTE: Boiler ages range from 10 to 25 years
Unit Size (MW)
800 MW (Cell-Burner)
150 MW
200 MW (3 x 200)*
650 MW
500 MW
525 MW
650 MW (2 x 650)
160 MW (3x160)
Total 3635 MW
*
( ) = Contractual Options
Table II
Low NOX Burner
Retrofits Underway of 1991
No. of Burners
48
16
18(54)
24
24
24
24(48)
16(48)
194
Boiler OEM
B&W
B&W
B&W
FW
FW
FW
FW
FW
4A-67
-------
HHV
N2
Si
Ash
Average NOX Level
NOX Reduction
Table III
Range of Fuel Properties
8000
1.0
0.5
5.0
13.500 Btu/lb
2.3%
3.5%
2.5%
0.451b/10 Btu
55 - 60 % (No OFA))
Parameter
No. Mill in Service
Excess Air (%)
NOx(lb/106Btu)
CO (ppm)
Burner A P ("HzO)
Carbon Loss (% Eff.)
Results:
Performance and efficiency not degraded
Eliminated slagging and clinkering
Significant power savings
Table IV
Four Corners # 4 Data
800 MW Cell-Burner Unit
Pre-Conversion
All (9)
18
1.27
<40
5-6
Post-Conversion
All (8)
13-15
0.48 - 0.52
20-40
3-3.5
Table V
500 MW Advanced Low NOX Retrofit
Range of Fuels Fired
(As Received)
VM (%)
EC (%)
Ash (%)
H2O (%)
C
H
O
N
S
HHV (Btu/lb)
22.51
54.05
15.55
7.49
64.49
3.79
5.48
2.07
0.73
10,909
28.07
52.63
12.45
6.85
67.39
4.11
6.27
2.28
0.65
11,605
36.15
41.47
12.01
10.37
61.99
4.79
8.70
1.85
0.59
11,018
4A-68
-------
Desgn Parameter
Registers
Adjustments
Sec. Air Flow Control
Fuel Injector
Primary Air Velocity Control
NOX Reduction
NOX Level
Table VI
Low NOX Burner Comparison
CF/SF
Dual
Manual
Elec. Sleeve Damper
Split-Flame
Yes
55 - 60%
0.41b/106 Btu
IFS
Dual
Manual
Elec. Sleeve Damper
Split-Flame
Plus
Coaxial Internal Flame
Yes
70 - 75%
0.27 lb/106 Btu
Table VII
CETF Comparative Data
CF/SF vs IFS
Fuel V.M. (%)
N2 (%)
XS02(%)
Burner Type
NOX (lb/106 Btu): Avg.
Std. Dev.
CO
Avg.
Std. Dev.
0.41
0.033
54
13
IFS
0.273
0.014
59
11
33
1.59
3.5 - 3.6
CF/SF
0.40
0.035
70
15
ffS
0.260
0.011
75
17
NOX Reduction (%)
33.4
35.0
4A-69
-------
Table VIII
CETF Fuels: IPS Testing
VM 32.70 23.49
FC 48.16 59.41
ASH 9.11 4.34
H2O 10.03 7.86
C 67.34 77.37
H 4.50 4.68
O 5.60 3.19
N 1.59 1.87
S 1.85 0.79
HHV 11,935 13,877
NOX Reduction 79.5% 73%
NOX Level 0.266 0.273
No significant difference in NOX emissions due to coal characteristics
4A-70
-------
ELECTRIC SLEEVE
DMPER DRIVE
MANUAL OUTER
REGISTER DRIVE
PERFORATED PLATE AIR HOOD
MOVABLE SLEEVt
DAMPER
01 SUN
SPLIT FLAME
ICOAL NOZZLE
ADJUSTABLE
INNER SLEEVE
Fig 1. Controllled Flow Split Flame Burner
LOWER
FUBNACE
AIRPOBI!
IYPICAI
OVEBFIRi
AIRPORT
DANFEt!
SECONDARY
AIR DUCT
VEN1UB
AIR DJC1!
Fig 2. Typical Advanced Overfire Airport System
4A-71
-------
IV)
(1) 800 MW Four Corners #4
(2) 626 MW Pleasants #2
275 MW Front Wall Fired
(3) 360 MW Front Wall Fired
• 525 MW Opposed Fired
1.2
Lb/M Btu
0.8
0.6
0.4
0.2
Single Wall Fired Units
Pre-NSPS Burner
(4) 110,000 Lb/Hr 4 Burner
(5) 125,000 Lb/Hr. 4 Burner
(6) CETF
(7) 500 MW Opposed Fired
Opposed Fired Units
(5)
(4)
(6)
(3)
(7)
(2)
(1)
CF/SF Low NOx Burner
CF/SF H- Advanced OFA
50 100 150 200 250 300 350 400 450
BURNER ZONE LIBERATION RATE
(10 3Btu/Hr-Ft
Foster Wheeler Energy Corp.
Combustion & Environmental Systems
Fig. 3. NO^Reduction Summary
-------
NOX
lb/106Btu
KEY
O ALL MILLS IN SERVICE
ONE MILL OUT OF SERVICE
TWO MILLS OUT OF SERVICE
300 350 400
LOAD (MW)
450
500
Fig. 4. Advanced Low NOx Retrofit 500 MW Boiler NO^ vs Load
w - -.
X4 0
—T • W
'Z'CXJ*1
£L 3.5
w 3.0
O
< 2.5
Z
a: po
D^> w
n,
O 1-5
X 1-0
O
m 0.5
0 ALL MILLS IN SERVICE
ONE MILL OUT OF SERVICE
TWO MILLS OUT OF SERVICE
QVERFiREASR
300
350
400
450
OVERFIREAIR
OPEN
500
Fig. 5. Advanced Low NOx Retrofit 500 MW Unit Pressure Drop vs Load
4A-73
-------
NOx
lb/106Btu
1.4 -
1.3 -
1.2 -
1.1 -
1.0 -
0|*S
.9
0.8-
0.7-
0.6-
0.5-
0.4-
0.3-
0.2-
0.1 -
UNCONTROLLED
_ sggssssgg £ =1 ,.,3
~ wxsxsas S = 0.06
REDUCTION
62.5% 78.6%
w
— CF/SF JL™«
LNB ^^•••i* ^ = 0.464
^
ONLY *KMKWKW g 0032 ^f
LNB JL^
AOFA"""^^ '
o — U.Ul^i
CF/SF = Controlled Flow/Split-FIame
LNB = Low NOX Burner
AOFA - Advanced Overflre Air
LOAD = 500 MW; 02 = 3.5%
Fig. 6. 500 MW Boiler NOx Reduction
Fig. 7. Combustion and Enviornmental Test Facility
4A-74
-------
; 0.40
Stu) 0 35 -
0.30-
0.25-
0.20-
0.15-
0.10-
0.05-
0.00
ELECTRIC SLEEVE
DAMPER DRIVE
MANUAL OUTER
UGISTER DRIVE
Fig. 8. Internal Fuel Staged Low NO^ Burner7
10
20
30
40 50 60
70
SO
90 100
LOAD (% MCR)
For all test points: CO < 50 ppm ; O2 = 3.4 - 3.6%
AP = 1.5" H2O Maximum
No Overfire Air
Fig. 9. CETF Testing Internal Fuel Staged Burner
3.0 NG
2.9
2.8
2.7
2.6
-2.5
-2.4
-2.3
-2.2
2.0
4A-75
-------
NOx 1-4~
, c •! o
lb/10b Btu 1-3
1.2 -
1 1
i . i
1.0 -
.9
00
.0
0-7
. /
Or*
.O
Or-
.O
0.4"
0.3-
0.2 -
0.1 -
UNCONTROLLED
SS&89Kf&KK6
7 = 1 .23
S = 0.06
78.6% 62 5%
:>
CF/SF
NO OFA
»BS5«55e«BW^
flU
CF/SF
OFA -• OP
74.
S
— 0.464
S = 0.032
>
£ = 0.266 "
S = 0.012
EN
UNCONTROLLED
KMWWMQMOK ••
61%
6% 1
I CF/SF
^ NO OFA
^W 7 ri /i r\c
awOTMSBSKwaas W ~ U.fUO
v^^^^ S = 0.034
*= 7 =0.269
IPS S = °'015
NO OFA
500 MW 80 M Btu hr
Steam Generator Test Facility
Fig. 10. Low NOx Burner Comparative Data Controlled Flow/Split Flame vs Internal Fuel Staged
4A-76
-------
-si
KEY:
Uncontrolled Levels
CF/SF - with AGFA
O CF/SF - no OFA
. IFS - no OFA
CF/SF Low NOx Burner
CF/SF + Advanced OFA
50 100 150 200 250 300 350 400 450
BURNER ZONE LIBERATION RATE
(103 Btu/Hr-Ft2)
Foster Wheeler Energy Corp.
Combustion & Environmental Systems
Fig. 11. NO, Reduction Summary IFS vs. CF/SF
-------
REDUCTION OF NITROGEN OXIDES EMISSIONS BY COMBUSTION PROCESS
MODIFICATION IN NATURAL GAS AND FUEL OIL FLAMES:
FUNDAMENTALS OF LOW NOV BURNER DESIGN
A
M.A. Toqan, L. Berg, and J.M. Beer
Massachusetts Institute of Technology
Cambridge, MA 02139
A. Marotta, A. Beretta and A. Testa
Eniricerche
Italy
-------
Reduction of Nitrogen Oxides Emissions by
Combustion Process Modification in Natural Gas and Fuel Oil Rames:
Fundamentals of Low NOX Burner Design
M.A. Toqan, L. Berg, and J.M. Beer
Massachusetts Institute of Technology
Cambridge, MA 02139
A. Marotta, A. Beretta and A. Testa
Eniricerche
Italy
Abstract
Increasingly tight environmental regulations for NOT emission from coal-, oil- and gas-
fired utility boilers are forcing utility and industrial users of fossil fuels to pay greater
attention to control of NOX in oil, coal and even gas-fired units. Effective control of NOX
emissions requires the application of one or a combination of methods of combustion
process modification including staged air and staged fuel injection, the use of low-NOT
burners, and possibly even post-combustion clean-up such as NH3 injection into combustion
gases.
To date, the degree of NOX reduction achieved by these technologies has been
observed to vary widely and to depend on the combustion system in question. Primarily
this wide variation in performance of staged systems and of low NOX burners is due to lack
of understanding of the overlapping processes of the nitrogen-hydrocarbon chemistry and
the mixing/temperature histories of the fuel in the flame.
To address the variation of performance of low-NOx burners a theoretical and an
experimental investigation is being carried out at MIT which is focused on the
fundamentals of low-NO^ burner design, applied to natural gas and fuel oil combustion.
In the experimental investigation a multi-annular burner developed by Massachusetts
Institute of Technology is used. Flame studies are carried out in the 1.2 m x 1.2 m x 4.5 m
test section of the MIT Combustion Research Facility (CRF). The CRF is a pilot plant
scale combustion tunnel, having a 3 MW^ multi-fuel firing capability and designed to
facilitate detailed investigation of industrial type turbulent diffusion flames. The burner is
equipped with a fuel gun surrounded by primary, secondary and tertiary air supplies. Mass
flow rates for each of the three air supplies external to the fuel gun can be independently
controlled, and for each supply the swirl can be adjusted over a wide range by means of an
independent moveable block swirler. A shroud-diffuser is used to maintain physical
separation of the secondary and tertiary air jets entering the combustion chamber.
The results from this investigation are pertinent to the design principles of low-NOx
burners including scaling criteria.
4A-81
-------
INTRODUCTION
The most widely used design strategy for NOX reduction is staged combustion. The
creation of fuel-rich and -lean combustion zones in flames by means of staging the input
of either air or fuel is a successful method of NOX emission control. Nevertheless, the
degree of NOX reduction achieved by these technologies has been observed to vary widely
and to depend on the combustion system in question (1,2,3).
While the principles of staged combustion control of NOX emission are well
established (4,5,6), their practical realization is hampered by lack of information on the
overlapping processes of the nitrogen-hydrocarbon chemistry and the mixing-temperature
history of the fuel in the flame. The problems are especially difficult in the case of the so
called "internal staging" process, in which the fuel-rich and -lean combustion zones must
be produced by appropriate fuel-air mixing in a single low-NOx burner, rather than by
producing fuel- rich and -lean combustion zones in the combustion chamber using overfire
air.
This problem is addressed in an experimental research project at MIT focused on
the principles of low-NOx burner design as applied to natural gas and oil combustion. This
paper reports results obtained with both natural gas and No. 2 and No. 6 oil as fuels. The
experimental RSFC (Radially Stratified Flame Core) burner was developed at MIT based
on the patented design of a multiannular burner (7). The RSFC burner is attached to the
flame tunnel (3 MW^, 1.2 x 1.2 x 4.5 m) of the MIT Combustion Research Facility (CRF).
Parallel with the experiments a mathematical modeling study is carried out; the progress
of combustion along the flame is computed for the effects of design and operating variables
of the burner, using the "Fluent" fluid dynamics code. In this paper, the relationships
between burner input parameters and emissions of CO and NOX are reported.
EXPERIMENTAL
The MIT Combustion Research Facility was designed to permit detailed in-flame
measurements of the flow field and of spatial distributions of temperature and chemical
species concentrations to be made. Variable heat extraction along the flame - by the use
of completely and partially water cooled furnace sections - is used to closely simulate large
scale flame systems. Access to the flame for optical or probe measurements is provided by
a 1.0 m long slot at the burner and by instrument ports at every 30 cm length further
downstream along the flame tunnel.
The experimental RSFC burner the concept of radial flame stratification
The burner consists of three concentric annuli with each of the annular nozzles at
a larger radial position extending further in the axial direction (Fig. 1). Fuel is introduced
in the center through a fuel gun. The three sections of the burner can be axially adjusted
as may be required to maintain optimal geometry at turn down. Additional features of the
burner include independently variable swirl control in each annular air nozzle by means of
IFRF moveable block swirlers.
4A-82
-------
CO
00
TERTIARY AIR
SECONDARY AIR-
3?
11
r
BURNER QUARL
T
AIR
STEAM
FLUE GAS
PRIMARY AIR
MOVABLE SHROUD
^
BURNER QUARL
SWIRL GENERATOR
Figure 1. Schematic of Low-NOx Radially Stratified Flame Core Burner
-------
The operation of the burner is based on the principle that a combination of a
positive radial density gradient and rotating flow field has a stratifying effect on the flame
by virtue of the damping of turbulence at the interface of the central flame zone and the
colder air flow radially surrounding the flame (8). This feature was chosen to give the
name: Radially Stratified Flame Core (RSFC) Burner. The flame so produced would have
mixing zones in the opposite sequence to the Flame type 1. used in the EFRF terminology,
as it would start with a narrow fuel jet flame of low air entrapment followed by an
internally recirculating flame region in which combustion is completed (Fig. 2).
The flexible design of the experimental burner permitted the variation of input
parameters over wide ranges. The burner parameters were:
Fuel jet velocity and angle
Fuel gun position (relative to the face of the burner)
Air distribution to Primary, Secondary and Tertiary air flows
Radial distribution of the swirl velocity hi the air flow
Axial separation of the Primary, Secondary and Tertiary air flows
Experimental Matrix
Using natural gas and No. 2 and No. 6 oil and preheated combustion air (450°F)
parametric flame experiments were carried out with the RSFC burner. In the experiments,
burner input parameters were varied to determine their effect upon NOj and CO emissions.
The ranges of variables adopted were:
Fuel jet velocity: 50 - 600 ft/sec.
Fuel jet angle: 0° - 25°
Fuel gun position: -45 - 0 cm
Primary air flow rate: 0 - 100%
Secondary air flow rate: 0 - 100%
Tertiary air flow rate: 0 - 100%
Swirl number of primary air: 0 - 2.79
Swirl number of secondary air: 0 - 1.90
Swirl number of tertiary air: 0 - 1.39
Elemental analyses of the No. 2 and No. 6 fuel oils are listed in Table 1.
Measurements
Temperature, and gaseous concentrations of CO, CO2, NOX and O2 were measured
at the exit of the combustion tunnel.
4A-84
-------
TERTIARY AIR
FUEL GUN-:
PRIMARY AIR
SECONDARY AIR
EXTERNAL RECIRCULATION
ZONE
FLAME ENVELOPE
INTERNAL
RECIRCULATION
ZONE
Figure 2. Schematic of a Radially Stratified Low NOX Flame
4A-85
-------
Table 1
Ultimate
Analysis
C
H
N
Ash
H2O
Asphaltene
Content
Heating value,
(Btu/lb)
Weight %
No. 2
86.80
12.44
0.14
0.01
—
—
19,640
No. 6
86.46
9.67
.53
.08
.4
9.5
18,236
EXPERIMENTAL RESULTS
Natural Gas Combustion
In the N.G. tests, 98 flames were investigated for the effects of burner input
variables upon NO^ and CO emissions from the combustion tunnel. The input variables
found to have effect upon NOX and CO emissions are:
type of fuel nozzle
fuel gun position within burner
primary air fraction
radial displacement of swirl from flame axis
Type of Fuel Nozzle
Two parameters, the exit velocity of the fuel jet from the gun and the angle of the
jet relative to the flame axis, were considered in the design of the fuel nozzles. Several
nozzles were built to allow the velocity of the fuel to range from 50 ft/sec, to 600 ft/sec, and
the angle to vary from 0° to 25°. Results obtained from the combustion tests with these
nozzles are shown in Fgures 3 and 4. It is noteworthy that while CO emission levels were
very low for all cases, they increased slightly with increasing fuel jet velocity. On the other
hand, NOX emission levels were more influenced by the fuel jet angle: i.e., increasing the
fuel jet angle from 18 to 25° increased NO^ concentration at the exit by ~ 25 %.
4A-86
-------
NATURAL GAS
E
a.
a.
cc
i-
z
UJ
O
Z
o
o
o
o
1 UU"
90-
80-
70-
60-
50-
40-
HU
30-
20-
10-
n
m^_____ •*
-^^ NOX
» »
CO r — — —
% Swirl No.
Prim, air low high
Sec. air zero
Tert. air high high
- i uu
-90
-80
-70
-60
-50
-40
HU
-30
-20
-10
.n
Q.
•z.
o
h-
CC
1-
Z
UJ
o
z
o
o
X
20 30 40
50 60 70 80 90 100 110 120 130
FUEL JET VELOCITY (FT/SEC)
EFFECT OF FUEL JET VELOCITY ON NOx AND CO
EMISSIONS (O2 at exit = 1.5 %)
Figure 3.
4A-87
-------
100-
— 90-
a 80
z 70-
O
H 60
DC
f-
Z
LU
O
Z
o
o
o
o
50-
40-
30-
20-
10-
0
NATURAL GAS
% Swirl No.
Prim, air low high
Sec. air zero
Tert. air high high N ^)
y\
^ *" *
H — •
I i I
_1 1 P
CO
eL.\J\J
-180
-160
-140
-120
-100
-80
-60
-40
-20
n
E*
Q.
Q.
Z
g
j^
QC
K-
Z
01
O
O
X
O
z
0
15
FUEL JET ANGLE
25
EFFECT OF FUEL JET ANGLE ON NOx AND CO
EMISSIONS (O2 at exit = 1.5 %)
Figure 4.
4A-88
-------
Fuel Gun Position
The axial position at which the fuel is introduced within the burner is known to be
important in determining the flame structure. Fluid dynamically it affects the interaction
of the axial fuel jet and the swirling annular air flow. To investigate the effect of this
parameter upon NOX and CO emissions, several flames were investigated in which the
location of injection of fuel within the burner was varied. Figures 5 & 6 illustrate the
effect of this variable for the cases of strongly and weakly swirling primary air. The
negative values of the fuel gun positions shown in Figures 5 & 6 indicate the distance
between the end of the burner face and the fuel gun tip. A negative value implies that the
gun has been retracted into the burner throat It can be seen from Figures 5 and 6 that
the fuel gun position has little effect on NOX concentration. However, CO emissions were
observed to increase dramatically when the fuel gun was moved in the burner for certain
burner configurations.
Primary air fraction
The conditions represented in Fig. 5 with 51% of the air supplied as primary air give
high NOj values, ranging from 110 to 135 ppm, while CO concentrations are
understandably low because of the early aeration of the fuel. It is the case illustrated in
Fig. 6 that deserves further discussion. With the low primary fraction, NOX levels are La
the range of 75 to 85 ppm which shows that even at a low level of swirl in the primary air,
fuel/air mixing is damped in the near field. However, as the primary air fraction is raised
as illustrated in Figures 7 and 8, NOX emission levels increase due to the early mixing of
the fuel with the combustion air. It is noteworthy that for the cases which have low
primary air fraction, the lean stage mixing further downstream is inefficient without strong
swirl in the tertiary air. For the condition of high swirl degree of the primary air, NO
concentration is mainly dependent upon the primary air fraction. The CO emissions,
however, are more dependent upon the swirl degree of the secondary/tertiary air. For the
cases in Fig. 8 the CO concentration remains virtually constant over the full range of
primary air flow fraction as long as the tertiary air has a high degree of swirl. An optimum
flame was found in which the burner input conditions reflect the above trends: low primary
air fraction, with high swirl, high secondary mass flow fraction with over critical degree of
swirl, and low tertiary air flow with no swirl, ( NO emission at 3% O2: 70 ppm; CO: 56 ppm
and the O2 concentration in the exhaust 1.85%).
Similarly favorable conditions were obtained with low primary, low secondary and
high tertiary air flows as long as swirl was imparted both to the primary and the tertiary air
flows.
Radial displacement of swirl from flame axis
With the multi-annular burner it is possible to produce a wide range of different
types of swirling flows. The two extreme cases are the free and forced vortex flows.
Assuming a uniform axial velocity profile, free vortex flow is obtained by high swirl in the
primary air, low swirl in the secondary air and no swirl in the tertiary air. A forced vortex
4A-89
-------
NATURAL GAS
^uu-
-^ 350-
Q.
3 300-
Z
2 250-
|E 200-
z
0 150-
z
o
0 100-
o
0 50-
n-
% Swirl No.
Prim, air medium high
Sec. air zero
Tert. air medium high
H ~ ~~* —————4.
NOx
CO »_— _ »— — "
-------
E
Q.
Q.
O
DC
h-
UJ
O
Z
o
o
o
o
NATURAL GAS
1000
900-
800-
700-
600-
500-
400-
300-
200-
100-
%
Prim.air low
Sec. air low
Tert air high
Swirl No.
low
low
zero
0
-50
-45 -40 -35 -30 -25 -20
FUEL GUN POSITION (CM)
-15
100
-90
-80
-70
-60
-50
-40
-30
-20
-10
E
Q.
a
g
h-
QC
Z
01
O
O
O
o
0
-10
EFFECT OF FUEL GUN POSITION ON NOx AND CO
EMISSIONS (O2 at exit = 1.5 %)
Figure 6.
4A-91
-------
NATURAL GAS
E
Q.
_O.
Z
O
H
<
rr
i_
r^
z
01
o
0
o
iuu-
90-
80-
70-
60-
50-
40-
30-
20-
10-
o-
NOX
^ — """^
^
CO ^^-^^
^~"^\^^
% Swirl No.
Prim, air - high
Sec. air - high
Tert. air zero
i | | [- 1
-
-------
E
Q.
CL
Ol
O
-z.
O
O
O
O
100
80-
p 60-
40-
20-
0
0.0
NATURAL GAS
PRIM AIR
SEC AIR
TERT AIR
0.4 0.8
FRACTION OF PRIMARY AIR
Swirl No.
HIGH
HIGH
200
-180
-160
-140
-120
-100
-80
-60
40
20
0
1.2
E
Q.
a.
o
(J
x
O
EFFECT OF (PRIM./TERT.) AIR RATIO ON NOx AND
EMISSIONS (O2 at exit = 1.5%)
CO
Figure 8.
4A-93
-------
swirling flow is obtained by high swirl in the tertiary air, a lower swirl in the secondary air
and a no swirl in the primary air. In a Rankine type vortex a forced vortex in the core of
the rotating flow combines with a free vortex on the outside. A Rankine vortex can be also
produced by the appropriate adjustment of the radial distribution of the swirl velocity in
the RSFC burner. To investigate the effect of the radial displacement of the peak swirl
velocity (tangential velocity) component in the combustion air from the flame axis, several
flames were generated by imparting varying swirl degrees to the primary, secondary and
tertiary air jets. The effect of this parameter on NOX concentration is illustrated in
Figure 9. It can be seen that lowest NOX emission was obtained with a Rankine vortex type
swirl velocity distribution.
No. 2 and No. 6 Oil Combustion
Based on the experience gained from natural gas combustion, 41 flames were
investigated for the effect of burner input parameters upon NOX and CO emission levels.
The parameters varied included:
(1) Type of fuel nozzle
(2) Primary air fraction
(3) Radial displacement of swirl from flame axis
Type of fuel nozzle
Six hole "Y" jet twin fluid atomizers were used and the angle between the six fuel
jets and the axis was varied to range from axial (0°) to 25° half angle. NOX concentrations
obtained using these atomizers for several primary/secondary/tertiary air ratios and several
swirl numbers are shown in Figures 10 and 11. The experimental results show the
importance of the fuel jet angle upon NOX emission levels. For No. 2 oil, changing the fuel
jet angle from axial (0°) to 25° raises NOX emission levels from 54 to 90 ppm for the best
cases examined and from 90 to 250 for the worst cases. For No. 6 oil, using a 25° atomizer
instead of an axial (0°) nozzle has the effect of raising NOT concentration levels at the exit
of the combustion tunnel from 97 ppm to ~ 170 ppm for the best cases and from ~ 240
to ~ 300 ppm for the worst cases.
Primary Air Fraction
The effect of the primary fraction ratio upon NOT emissions is shown in Figure 12.
It is noteworthy that for both fuel nozzle types when the primary air fraction constitutes
~ 0.5 of the total combustion air or higher, NOX emissions are high i.e., ranging from 86
to 140 ppm for No. 2 oil and ranging from 235 to 330 for No. 6 oil. As the combustion air
is diverted towards the tertiary air port, je concentration of NOX measured at the exit for
the axial (0°) nozzle drops to 59 ppm and 105 ppm for No. 2 and No. 6 oils, respectively.
A similar trend is observed with the 25° fuel jet atomizers. However, the lowest emission
level achieved with the latter could not match that obtained with the narrow angle fuel
nozzle. These results are similar to those obtained with natural gas. It is concluded that
only a small fraction of the combustion air has to be supplied around the fuel spray to
4A-94
-------
130
0
NATURAL GAS
1 2
OVERALL SWIRL NUMBER
EFFECT OF TYPE OF VORTEX AT BURNER EXIT ON
NOx EMISSIONS
Figure 9.
4A-95
-------
No.2 OIL
250
2 3
CASE NUMBER
EFFECT OF FUEL JET ANGLE UPON NOx EMISSIONS
Figure 10.
4A-96
-------
N0.6OIL
350
1
CASE NUMBER
EFFECT OF FUEL JET ANGLE UPON NOx EMISSIONS
Figure 11.
4A-97
-------
NOx
CO
g
< 200H
UJ
o
z
O
O
Prim, air frac. Low High Low High Low High Low High
Fuel Jet Angle
25V
25°
EFFECT OF PRIMARY AIR FRACTION ON NOx AND CO EMISSIONS
FROM OIL COMBUSTION
Figure 12.
4A-98
-------
ignite the fuel and stratify the flame. The remaining fraction can then be introduced as
tertiary air.
Radial displacement of swirl from flame axis
Using narrow angle fuel sprays, combustion experiments were carried out with No.
2 fuel oil to investigate the effect of radial displacement of peak tangential velocity of the
air upon NOX emissions.
In Figures 13 and 14 the effects of the swirl degree, the radial distribution of the
swirl velocity of the combustion air and the angle of the fuel spray upon NOX emission are
illustrated. NOX emission is seen to decrease with increasing swirl number and "RanMne"
vortex is favored for the air flow and a narrow angle spray for the fuel oil. Minimum NOX
levels were 97 ppm for No. 6 fuel oil and 54 ppm for No. 2 fuel oil.
NOX emissions as a function of combustion air swirl vary differently in gas and oil
flames with the RSFC burner. In contrast to the gas flames in which NOX emissions were
increasing as the swirl degree was raised above its critical value for vortex breakdown
(S ~ 0.6), they continued to decrease in both No. 2 and No. 6 oil flames for much higher
values of the combustion air swirl. This difference is thought to be due to the lower
entrainment rate and higher penetration depth of the narrow angle fuel spray compared
to the gas jet. As a result of this, radial stratification of the flow can be maintained to a
higher value of the swirl number in the oil flames than in the gas flames.
The lowest levels of NOX and CO emissions obtained by purely combustion
aerodynamic means are shown in Fig. 15. In recent experiments in which gas recirculation
and steam injection were used, significant reductions were reached in NOX emission levels
while maintaining low CO concentration at the exit of the combustion tunnel. These
results will be reported in our paper prepared for the 1991 Fall Meeting of the American
Flame Research Committee.
CONCLUSIONS
An experimental investigation has been carried out with a flexible experimental
low-NOx burner of novel design. The burner is designed to achieve staged combustion by
a combination of radial flow stratification and axial air staging in the flame. Fuel/air mixing
is suppressed by radial flow stratification close to the burner but is then promoted by a
toroidal recirculating flow further downstream of the burner.
Parametric experimental studies carried out in the flame tunnel of the MIT
Combustion Research Facility (CRF) permitted optimization of the burner for low-NOx and
CO emissions by determining favorable conditions for the radial distributions of the air flow
and the swirl velocity at the exit from the burner and for the central fuel injection velocity
and angle. The results showed that for several operational modes of the burner input
variables, highly stable flames with low-NOx and CO emission levels were attainable.
Minimum values of NO. and CO emissions obtained by the optimization of the
4A-99
-------
No.2 OIL
100-
90-
o aoH
5?
70-
S
Q.
0.
o 6°H
z
50-
40
RANKINE VORTEX
0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8
SWIRL NUMBER
100-
90-
S 8o^
I ^
O 60-
50-
40
FORCED VORTEX
0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8
SWIRL NUMBER
EFFECT OF TYPE OF VORTEX ON NOx EMISSION
Figure 13.
4 A-100
-------
400
350
(7 300'
O
n 2501
Q.
t 200
s
z ISO-
100-
50
0.5
FREE VORTEX
10 degrees
1.5 2
SWIRL NUMBER
2.5
FORCED VORTEX
25 degrees
10 degrees
0 degrees
0 0.2 0.4 0.6 08 1 1.2 1.4 1.S 1.8
SWIRL NUMBER
400
350-
fj 3001
O
o 2501
a.
£. 200
O
z 150
100
50
0.5
RANKINE VORTEX
25 degrees
0 degrees
10 degrees
1 1.5 2
SWIRL NUMBER
2.5
Figure 14. Effect of Type of Vortex Upon NOX Emission
4A-101
-------
No. 6 Oil
NOx BB CO
E
Q_
Q.
O
cc
LU
O
•z.
O
O
120
100-
80-
60-
40-
20-
N.G. No.2 No.6
NOx AND CO EMISSIONS FOR AN OPTIMUM
BURNER CONFIGURATION
Figure 15.
4 A-102
-------
aerodynamic variables (staging by flame stratification) were 70 ppm NOX and 56 ppm CO
for natural gas, 54 ppm NOX and 23 ppm CO for No. 2 fuel oil and 97 ppm NO^ and
32 ppm CO for No. 6 fuel oil.
The data reported here are initial results only; recent experiments presently under
evaluation show that further significant reductions of NOX emission can be obtained with
the new radiaUy stratified flame core (RSFC) burner by means of the controlled admixing
of small amounts of recirculated flue gas and steam.
ACKNOWLEDGEMENTS
Financial support from a consortium of utility companies: Empire State Electric
Energy Research Corporation (ESEERCO), Eniricerche, Electric Power Research Institute
(EPRI), Ente Nazionale Per L'Energia Elettrica (ENEL), Florida Power and Light
Company and Southern California Edison Company is gratefully acknowledged. We thank
ABB-CE for their expression of readiness in producing a commercial burner should our
experiments be successful. The authors are indebted to Ms. Bonnie Caputo for the
production of the many drafts and the final form of the paper.
REFERENCES
1. Morita, S., Kiyama, K., limbo, T., Hodozuka, K_, and Mine, K, "Design Methods for
Low-NO,, Retrofits of Pulverized Coal Fired Utility Boilers", EPRI/EPA Joint
Symposium on Stationary Combustion NOX Control, Mar, 1989.
2. Lisauskas, R.A., Reicker, E.L., and Davis, T., "Status of NOX Control Technology at
Riley Stoker", EPRI/EPA Joint Symposium on Stationary Combustion NOX Control,
Mar, 1989.
3. Thompson, R.E., Shiomoto, G.H., Shore, D.E., McDannel, M.D., and Eskinazi, D., "
NOX Emissions Results for a Low-NOx PM Burner Retrofit" EPRI/EPA Joint
Symposium on Stationary Combustion NOX Control, Mar, 1989.
4. Sarofim, A.F., Pohl, and Taylor, B.R., "Strategies for Controlling Nitrogen Oxide
Emissions During Combustion of Nitrogen Bearing Fuels, "AIChE Symposium Series
No. 175. 74, 67, (1978).
5. Farmayan, W.F., M.Sc. Thesis, "The Control of Nitrogen Oxides Emission by Staged
Combustion," Department of Chemical Engineering, Massachusetts Institute of
Technology, Cambridge, MA, April 1980.
6. Beer, J.M., Jacques, M.T., Farmayan, W.F., Gupta, A.K., Hanson, S., Rovesti, W.C.,
"Reduction of NOX and Solid Emissions by Staged Combustion of Coal Liquid Fuels."
Nineteenth Symposium on Coal Liquid, Haifa, Israel, Aug. 1983.
4 A-103
-------
7. Beer, J.M. British Patent No. 1099 959. Jan. 17, 1968; U.S. Patent: "Low NO^ Rich-
Lean Combustor Especially Useful in Gas Turbines", Jul 11, 1989.
8. Beer, J.M., Chigier, N.A., Davies, T.N. and Bassindale, K.: "Laminarization of
Turbulent Flames in Rotating Flow Environments" Combustion and Flame, Vol. 16.
pp 39.45 (1971).
4 A-104
-------
DEVELOPMENT OF LOW NOX GAS BURNERS
Shyh-Ching Yang, John H. Pohl, Steven J. Bortz,
Robert J. Yang, Wen-Chen Chang
Energy & Resources Laboratories
Industrial Technology Research Institute
Hsin Chu, Taiwan, R.O.C.
W. J. Schafer Associates, Irvine, CA 92718
R-C Enviornmental Service & Technologies, Irvine CA 92718
-------
Development of Low NOx Gas Burners
Shyh-Ching Yang1, John H. Pohl2, Steven J. Bortz3,
Robert J. Yang1, Wen-Chen Chang1
Energy & Resources Laboratories
Industrial Technology Research Institute
Hsin Chu, Taiwan, R.O.C.
2W. J. Schafer Associates, Irvine, CA 92718
3R-C Environmental Service & Technologies, Irvine, CA 92718
ABSTRACT
The Energy Commission, Ministry of Economic Affair(EC, MOEA),
Republic of China, has a program to develop 2.5MW low NOx gas
burners. This paper reports the results on premixed and
nonpremixed swirl burners.
The versatile premixed and nonpremixed swirl burners were designed,
fabricated and tested in Energy and Resources Laboratories'(ERL) 10
xlO^ Btu/hr furnace. It is shows that the NOX can be controlled to
levels of less than 15ppm. The peak flame temperatures required to
maintain required NOX levels were achieved by mixing sufficient flue
gas, and/or other diluents and well control the mixing rate.
The ERL's test furnace is designed to simulate single burner industrial
boilers. The furnace is 1600mm square inside, and is lined with
500mm thick refractory for the first 2500mm. The last 3840mm of the
furnace is water cooled. The furnace is built of 250mm segments and
operated with residence time at 2-3 sec and 5-10 mm water positive.
The results showed that dilution of the premixed gas by air or flue gas
could reduce NOX emission to 12.5ppm(dry, 3% 02) and is relatively
temperature insensitive for premixed burner. The results of non-
premixed swirl burner showed that turndowns of 5/1, with CO
emissions less than 50ppm, O2 1 2.5%, NOX emissions about
10-12ppm were achieved with the conditions of flue gas recirculation
of 15%, and primary zone stoichiometry of 0.7.
4 A-107
-------
INTRODUCTION
Recently, international attention has increased to the role of nitrogen
oxides in lake acidification, oxidant formation and forest damage.
Stringent regulations to reduce the allowable emissions of nitrogen
oxides are being promulgated in many industrial area of the world.
Under the clean air regislations, the combustion industry is being faced
with the necessary of having to reduce nitrogen oxides from its existent
units. Combustion modifications(i.e. low-NOx burners, reburning or
staged combustion) generally afford the least capital for achieving
reductions(l).
This paper summerizes the results of a program funded by the Energy
Commission Ministry of Economic Affairs(EC,MOEA) Republic of China to
develope and to determine the ability of burner designs and operating
conditions to achieve the low levels required and expected for NOx
emissions.
To achieve this objectives, chemical reaction and aerodynamics control
of the flame were used for burner design (2,3,5,6,7). In this program,
four burner designs, premixed (1), partially premixed (4), nonpremixed
fuel jet and swirl burner (3), were tested in Energy and Resources
Laboratories' 10 x 106 Btu/hr furnace.
EXPERIMENTAL
The Energy and Resources Laboratories' test furnace is nominally rated
for lOxlO6 Btu/hr and is designed to simulate single burner industrial
boilers. A schematic of the furnace is shown in Figure 1. The furnace is
1600mm square inside, and is lined with 500 mm thick refractory for
the first 2500 mm. The last 3480 mm of the furnace is water cooled.
4 A-108
-------
The furnace is built of 250 segments. Each segment has a rectangular
port for veiwing and probing the flame. The furnace is operated with
force draft at 5 10 mm water positive.
The furnace is equipped with a rear port for flame photography and
measuring the exit concentration of the flue gas. The wall are
instrumented with thermocouples to monitor the change in wall
temperature and to measure the heat extraction in the wall-cooled
sections. The furnace is also equipped with a number of sheathed
thermocouples on axis to monitor the relative flame temperatures.
Flue gas is drawn by an induced draft fan from the stack. The flue gas
is cooled in a direct spray tower, monitored by an orifices plate and fed
to the burner. The direct spray tower cools the flue gas to!50°C
(300°F). Use of the direct spray will increase the water content of the
heat capacity, and to a limited extent heat which can be extracted from
the flame by the flue gas.
Gases are drawn from the furnace through a water-cooled probe for
continuous analysis. The gases are analyzed for CO and CO2 with non-
dispersive infrared analyzer, for NO and NO2 with chemiluminescence
analyzer, and for oxygen with an electrochemical analyzer. A suction
pyrometer was used to measure the temperatures in the flame and
sheathed thermocouples were used to continuously track changes in the
lower temperature regions of the furnace.
The versatile premixed, partially premixed, nonpremixed fuel jet and
swirl flow burners were designed, fabricated and tested in E&RL's
furnace. Those configurations are shown in Figures 2 and 3.
• Premixed Burner (Figures 2 and 3a)
In this configuration nature gas is introduced from the bottom, is mixed
4 A-109
-------
in a chamber with air. Flue gas, if used, is drawn by a fan from the exit
of the furnace, cooled to 150°C by a water spray, measured with an
orifice meter, and fed radially into the chamber. The rear nature gas
chamber is isolated from the air chamber by two layers of 1mm
opening screen to help prevent flash backs. The face of the burner is
covered with two layers of 1mm opening screens to prevent flash back
from the furnace. The burner is set within a cast refractory quarl. The
quarl is equipped with a pilot flame and a flame detector.
• Partially Premixed Burner (Figures 2 and 3c)
In this configuration, nature gas is introduced from the bottom, is mixed
in chamber I with air. The mixed air and flue gas is fed to the chamber
II through a perforated shroud.
• Nonpremixed Fuel Jet Burner (Figures 2 and 3b)
In this configuration, nature gas is introduced from the bottom. Flue
gas, if used, is mixed in chamber I with nature gas. The air is fed to the
chamber II through a perforated shroud.
• Swirl Burner (Figure 3d)
In this configuration, nature gas is introduced in the central gas gun.
The air is drawn through a swirl generator to generate a low pressure
drop, low turbulence swirling flow to achieve the desired ignition, flame
geometry and burnout characteristics for a given fuel. The flue gas
recirculation and air staging were used in this testing.
RESULTS
These versatile burners were tested in the E&RL's 10x10^ Btu/hr
4A-110
-------
furnace. Results from the tests are reported in this paper.
Measurements were made of gas composition (NOX, CO, CO2, and 02) and
flame temperature. The temperature at 37.5mm from the quarl was
measured using a suction pyrometer; other temperatures were
measured using sheathed termocouples. Data was taken under the
follow conditions:
• Premixed and Nonpremixed Fuel Jet Burners
premixed flame and diffusion flame.
load 3.9-6.6xl06 Btu/hr
flue gas O2 2.0-9.0%(dry)
flue gas recirculation 0-10%
mixing factor, M=l for premixed burner
mixing factor, M=0 for nonpremixed fuel jet burner
The results of NOX emissions and flame temperatures are shown in
Figure 4. The emissions of NOX decreased with increasing or decreasing
oxygen in case of without flue gas recirculation. Where ^ is the
percentage of the flue gas recirculation, ®r is the total stoichiometric
and M is the mixing factor. The mixing factor is defined as the ratio of
air mixed with fuel per total air introduced at a given ®r
M= air mixed with fuel/total air introduced at a given ®T
(1)
For premixed burner, M=l whereas for partially premixed burner,
The influence of a "flame temperature" is also shown in Figure 4. The
"flame temperature" used is the value measured by the suction
pyrometer at 375mm from the quarl. The NOx emissions decreased
with decreasing "flame temperature". For load of 3.9x10^ Btu/hr, the
4A-111
-------
NOx emissions of 0.02 Ib/MM Btu corresponds the flame temperature
of 1245°C. The NOx emissions increases to 0.07 Ib/MMBtu at "flame
temperature" increases to 1500°C. The track of the NOX emissions and
"flame temperature" are similar.
The relative "flame temperature", 9 = T/TBAS, and relative NOX
emissions, ^ = NOx/NOxBAS of % =1.10-1.45 and 5 =0-10%
for premixed and nonpremixed fuel jet burners are shown in Figure 5.
The emissions of NOX and "flame temperature" decreased with
increasing the amount of flue gas recirculation. The relations of ^ and
& versus ^ are
^ = 1- 0.075 5 (2)
and
6=1- 0.006 £ (3)
Where ^ is in percent. These results give the agreement of the 'H and
© approach to 1 as ^ equal to zero.
• Partially Premixed Burner
premixed flame
load 3.9-6.6xl06Btu/hr
flue gas O2 1.5-4%(dry)
flue gas recirculation 0-10%
mixing factor; 0
-------
concentrations of a given flue gas recirculation rate. These graphical
solutions can tell us the phenomena of NOx emissions of the partially
premixed burner and the design and operation methodology for this
type of burners. For example, the conditions of O2=2.1%, ^=4%;
O2=3.1%, 5 =6%; and O2=6%, 5 =6% will give the same NOX emissions of
0.03 Ib/MM Btu for the load of 3.9xlQ6 Btu/hr. Figures 8 and 9 give
the comparison between prediction and experiment results for those
various burners. The agreement of these values at various operation
conditions is very well.
It is shown that these burners have been developed to meet the strict
emissions regulations, NOX<0.03 Ib/MM Btu, mandated by the South
Coast Air Quality Management District(SCAQMD).
• Nonpremixed Swirl Flow burner
diffusion flame
load 5.9x106-10.0x106 Btu/hr
flue gas O2 1.0-5.0%(dry)
flue gas recirculation 0-20%
The NOX emissions of the swirl burner with the load of 10.0 x 106
Btu/hr and flue gas recirculation rate of 0-10% are shown in Figure 10.
The total stoichiometric, ®T is 1.05-1.2. The emissions of NOX decreased
with decreasing oxygen and/or increasing the amount of flue gas
recirculated. The NOX emission reduction can be defined as
(4)
RE(%) = (1 - XTX ) x 100%
S NOXBAS
After regression these data, which gives the reduction of NOX emissions
versus flue gas recirculation rate is
Rt(%) = £ (%)/( 133 0T- 1.15) (5)
4A-113
-------
The NOx emissions at the load of 5.9x10^ Btu/hr, without flue gas
recirculation , are shown in Figures 11 and 12. With extrapolation of
equation (5) at each recirculation rate, ^ 5-15%, it shows that the
agreement of prediction and experiment of NOX emissions is well. The
NOx emissions at the load of 6.6xl06 Btu/hr and 8.7xl06 Btu/hr with
air staging of primary stoichiometric 0.6-0.64 and with 4-5% flue gas
recirculation are shown in Figure 13. The total stoichiometric is 1.05-
1.3. The NOX emissions for unstaged are 0.03-0.048 Ib/MMBtu. The air
staging and flue gas recirculation can provide a significant further
reduction of the NOX emissions. The minimum level of NOx which could
be achieved was 10-12 ppm .
CONCLUSIONS
Four versatile premixed, partially premixed, nonpremixed fuel jet and
nonpremixed swirl burners were designed, fabricated and tested in
Energy and Resources Laboratories' lOxlO^Btu/hr furnace. Results
show that 12.5ppm(3% O2) can be achieved either by diluting the flame
with air or flue gas to lower the maximum flame temperature for the
premixed flame or delay the mixing and to lower the flame temperature
for the diffusion flame.
This paper has mentioned the minimum NOX levels for various
premixed and diffusion flame burners. Some results provide the
concept of NOX emissions reduction methodologies. The agreement
between the prediction and experiment of NOx emissions for various
burner and operation conditions are very well.
Use of excess air and/or flue gas recirculation to reduce NOX will depend
on individual circumstances of each boiler. Increased of excess air in a
premixed burner will reduce NOx emission, will not require installation
of ducts and high temperature fans but will reduce boiler efficiency.
Use of flue gas recirculation and air staging of a swirl burner will reduce
NOx will require ducts and high temperature fans, but will not
drastically influence the boiler efficiency.
4A-114
-------
REFERENCES
1. Pohl, J.H., S.-C. Yang, C.-H. Chen and R.Yang, "The Performance of Low
NOx Gas Burner Configurations: I. Premixed," October, 1990, American
Flame Research Committee International Symposium, NOx Control,
Waste Incinerators and Oxygen Enriched Combustion, San Francisco, CA,
U.S.A.
2. Pohl, J.H.,A.W. Bell, S.-C. Yang, C.-H. Chen, and R.Yang," Development of
a Full Sized Ultra Low NOx Industrial Burner," 1990,April presented at
the American Flame Research Committee Members Meeting, Tuscon,
Arizona U.S.A.
3. Bortz, S.J. and S.-C. Yang,"Development of a Generalized Burner Design
Procedure" October, 1990, American Flame Research Committee
International Symposium, NOx control, Waste Incinerators and Oxygen
Enriched Combustion, San Francisco, CA, U.S.A.
4. Pohl, J.H. S.-C. Yang, R. Chang and R. Yang, "The Influence of Burner
Geometry and Operation on NOx Emissions: II. Partially
Premixed",January, 1991,ASME Third Fossil Fuels Combustion
Symposium Houston, Texas, U.S.A.
5. Yang S.-C., R.-S. Juang, W.-C. Chang, and J.-S. Chen, "Velocity
Measurements and Energy Distribution for Isothermal, suddenly-
Expanding, Swirling Flow in an Industrial Burner with Bluff-body",
Energy, 1_5, NO.11, pp.1015-1021,1990.
6.R.-S. Juang, S.-C. Yang, W.-C. Chang, and J.-S.Chen, "Flow Characteristics
on Isothermal Sudden Expending Swirling Flow in an Industrial Burner
with Bluff Body,"(Accepted by J. of Chem. Eng. of Japan).
7. Yang S.-C., et al., "Isothermal Swirling Flow in the Expanding Quad of
Industrial Burner with a Bluff Body", November 1989,Proceeding of the
1989 International Gas Research Conference, Tokyo, Japan.
4A-115
-------
PREMIXED BURNER
>
CD
UJ
£
AIR
FLUE GAS , -1-
250 MM
Figure 1 Energy and Resources Laboratories
lOxlO6 Btu/hr Test Furnace.
Figure 2 Versatile Natural Gas Burner
-------
PREMIXED BURNER
FUEL'
FLUE GAS
AIR
Figure 3a Versatile Premixed Gas Burner
NONPREM/XED FUEL JET BURNER
FUEL
FLUE GAS
AIR
Figure 3b Versatile Nonpremixed Fuel Jet Burner
4A-117
-------
PARTIALLY PREMIXED BURNER
FUEL
AIR AIR FLUE GAS
Figure 3c Versatile Partially Premixed Burner
NONPREMIXED SWIRL BURNER
Figure 3d Versatile Nonpremixed Swirl Burner
4A-118
-------
0.08 -
0.07 -
0.06
DQ 0.05
CD
^0.03
00
0.02
0.01
1500
• O 3.9 X/06
A A 6.6 X/06
• El 3.9 XIO6
• O6.6X/06
(.05
(.15
1.25
1.35
0
1400
0
o
CO
I3OO
1200
1.45
T
Figure 4 NOx Emissions and "Flame Temperatures"
of the Premixed and Fuel Jet Burners.
4A-119
-------
1.0
0.9
oo
QQ 0.8
X
O
2
\
x
O
0.7
0.6
0.5
0.4
0.3
0
O
A
D
O
BTU/HR
3.9X I06
6.6X I06
3.9XIQ6
6.6XI06
M
0T = I./O-
1.45
0
0
= / -0.006
= 1-0.075
10
12
14
(6
( %)
Figure 5 Relative NOX Emissions and Relative
"Flame Temperatures" Versus Flue Gas
Recirculation Rate
1.0
0.98
096 ^
00
h-
0.94 \
h-
0.92 »
0.90
4 A-120
-------
0.07
0.06
Q05
m a04
X 0.03
O
0.02
0.01
3.9X/ObBTU/HR
0
I I
PREDICTION
M=0 —
I I
0
7 8
(0
02
Figure 6 Prediction of NOx Emissions for Partially
Premixed Burner
4A-121
-------
6.6 XI06BTU/HR
PREDICTION
0.07
0.06
0.05
QD
\ O04
QD
-J
x 0.03
O
2
0.02
0-01
0
0
I
456
02 (%)
8
10
Figure 7 Prediction of NOx Emissions for Partially
Premixed Burner
4A-122
-------
O
0.09 -
0.08 -
0.07 -
0.06 -
Q 0.05 -
0.
>< 0.04
0.03 -
0.02 -
0.01 -
0
3.9XIO°BTU/HR 02(%)
0.69
0.66
0.69
0.66
0.73
0.69
0.68
0.70
0.69
O.O/ 0.02 0.03 O.04 0.05 0.06 0.07 0.08
NOX (EXPERIMENT), (LB/MMBTU)
0.09
Figure 8 Comparison Between the Prediction and
Experimental Results of NOX Emissions
4 A-123
-------
0.09
0.08
0.06
§ Q°5
O
S 0.04
Ct
CL
Xo.03
0.02
001
6.6XI06BTU/HR
0.01 0.02 0.03 0.04 0.05 0.06 0.07
NOX (EXPERIMENT); (LB/MMBTU)
0.08 0.09
Figure 9 Comparison Between the Prediction and
Experimental Results of NOX Emissions
4 A-124
-------
003
0.02
.
X
o
o.o /
o
1.0
IO.OXI06 BTU/HR ;
O f = 0 %
D
10
NOX REDUCTION
I I
NOX,BAS
I I
-JX/00%= g /(I.33&T-U5)
1.05
1. 10
I./5
1.20
Figure 10 NOX Emissions of Swirl Burner
4 A-125
-------
0.04
0.03
te
\
QD
O
0.02
0.01
5.9 XI06 BTU/HR; fi =
O
NOX , , PREDICTION
= I-0.01 £ /n.330T-/./5)
0
J I
1.0
1.2
1.3
1.4
0T
Figure 11 NOX Emissions of Swirl Burner
4 A-126
-------
0.04 -
i
o
I-
o
a
0.02 -
X
Q 0.01
0
0.01
0.02
0.03
0.04
NOX | (EXPERIMENT); (LB/MMBTU)
Figure 12 Comparison Between Prediction and
Experimental Results of NOX Emissions
4 A-127
-------
0.05
0.04
6.6X106 BUT/HR
D UNSTAGED
•PRIMARY STOiCH=o,60-o.64
EPRIMARYSTOICH=0.60-0.64, 4-5% FGR
I —C0<20 PPM
8.7X/06 BTU/HRI
O UNSTAGED
0.01
0
1.05
1.15
1.2
1.25
1.3
0
T
Figure 13 NOX Emissions of Swirl Burner with Air
Staging and Flue Gas Recirculation
4 A-128
-------
Session 4B
LARGE SCALE SCR APPLICATIONS
Chair: E, Cichanowicz, EPRI
-------
UNDERSTANDING THE GERMAN AND JAPANESE COAL-FIRED SCR EXPERIENCE
Dr. Phillip A. Lowe
INTECH Inc.
11316 Rouen Dr.
Potomac, MD 20854-3126
Mr. William Ellison
Ellison Consultants
4966 Tall Oaks Dr.
Monrovia, MD 21770
Mr. Michael Perlsweig
U.S. Department of Energy
Office of Fossil Energy
Washington, DC 20854
-------
UNDERSTANDING THE GERMAN AND JAPANESE COAL-FIRED SCR EXPERIENCE
ABSTRACT
This paper examines the Japanese low sulfur and the German medium sulfur, coal-fired
selective catalytic reduction (SCR) costs and operating experiences. Their
implications for high sulfur, U.S. coal-fired applications is also presented. It has
been observed that the costs are more strongly related to the application size than
they are to the location of the SCR catalyst section. However, operating costs and
issues are more strongly related to the location of the SCR system. The German Tail
Gas configuration technology, in which the SCR system is located downstream of the
flue gas desulfurization system, should be more easily transferred to high sulfur,
U.S., coal-fired applications, and if newer low temperature catalysts or less
expensive flue gas reheat designs are developed, it could become the configuration
of choice. Otherwise, site specific conditions, such as retrofit difficulty, will
probably dominate the selection process for applying High Dust or Tail Gas SCR
designs. A new issue not addressed in the German and Japanese SCR experience will
be how the spent catalysts are controlled, since they may be classified as a hazardous
waste in the U.S..
INTRODUCTION & BACKGROUND
In 1970, the Japanese initiated the use of SCR technology for NOx control on large,
electric utility boilers, including coal, oil, and gas service. The Japanese locate
their SCR reactor before the particulate collection equipment (High Dust
configuration) , or when they have a high temperature particulate control system they
locate it after that equipment (Low Dust configuration) . There were some initial
problems, principally with the formation of deposits on the catalysts and down stream
equipment. Studies showed that sulfur bisulfates were forming, and they were
depositing on the equipment or mixing with ash particles and the mixture was
depositing on the equipment. Considerable additional product development was
undertaken, and they eventually developed a long life, reliable SCR system for
reducing NOx emissions. Their approach included: reformulating the catalyst to reduce
its potential to form sulfur trioxide; during operations reducing the amount of
ammonia used by about 10-15% from the design specification and further controlling
the ammonia injection, if required, to assure that the ammonia leakage past the SCR
reactor (e.g., ammonia slip) is less than 10 ppm and preferably less than 5 ppm; only
treating about one-third of the boiler's uncontrolled NOx with the SCR system by using
combustion modifications to control the other two-thirds of the uncontrolled NOx; only
operating the SCR during steady plant operations (it can, however, be operated during
slow transients but it is not operated during start up or shut down); and operating
with low sulfur, low ash content coals (less than 1% sulfur and 10% ash). Because
of continuing problems with instrumentation, control of the process has been based
upon using calculated values of NOx and ammonia, and the measured values are
principally used as a trim signal for the control setting. Through 1990 they have
installed 40 SCR systems on 10,852 MWe of coal-fired utility service.
In the early 1980s, the German utilities began an extensive pilot plant evaluation
of Japanese SCR designs for use at German electric utility power plants. Ultimately,
4B-3
-------
they conducted about 70 different pilot plant experimental studies. Since 1985, 129
SCR systems have been installed on 30,625 Me of coal-fired utility service. Their
coal quality is quite different from the Japanese: they use low to medium sulfur and
ash coals (0.7 to 1.2% sulfur with low ash coals but on occasion up to 1.5% sulfur
and 25-30% ash, although such ballast coal is usually blended with the cleaner coal);
and their plant operations include intermediate duty (e.g., daily cycling and usually
shut down during the weekends). Also, the Germans retrofit their SCR systems to
existing plants, whereas the Japanese have both retrofit and new plant applications.
The Germans have both wet bottom firing (e.g., slagging boilers) and dry bottom
firing, whereas the Japanese use dry bottom firing. The principal German SCR design
is either the High Dust system or a Tail Gas system where the SCR is located after
the flue gas desulfurization (FGD) equipment. Initially, the Tail Gas configuration
was specified for wet bottom firing when the fly ash was recirculated to the furnace
section to be slagged (recycling produced high arsenic levels in the flue gas which
poisoned the catalyst). It is important to note that the Germans also do not operate
the SCR during start up or shut down periods (ammonia injection is typically keyed
to having the catalyst temperature at 554 °F or greater).
TECHNICAL IMPACTS ON SYSTEM COSTS
Typically, the Japanese report SCR costs at $35-80/kW"", depending on the
application. The initial German experience"'2'11 indicated that costs of $60-189/kW
can be expected, depending on the boiler size and firing conditions, and the coal
used. U.S. cost estimates range from $80-100/kW for new plant installations"''1".
A key reason for the greater reported costs in the German literature is that they are
for retrofit applications at older, more congested plant sites, compared to the
Japanese and the new plant basis for the U.S. estimates. German studies prepared in
1985 and 1986 compared the expected costs for the High Dust and Tail Gas applications.
Figures 1 and 2 are typical of the German results reported"'31- Often the capital
costs reported exclude the cost of the initial catalyst charge.
These figures and the results from the initial SCR installations (from 1985 through
1987) appear to be used by many authors to identify that the High Dust configuration
is less expensive than the Tail Gas configuration. However, if the entire data base
of applications through 1990 are considered, it appears that the Tail Gas
configuration is no more costly and may even be less expensive. High Dust
applications require long plant shutdown periods (during which the lost power must
be purchased from other sources) to allow for the connection of the SCR system to the
plant. On the other hand, the Tail Gas system requires a flue gas reheat system which
can consume as much as 3-4% of the fuel costs. Of course, costs are controlled, to
a very large degree, by the local site conditions, and thus either configuration could
be the least expensive at any specific site. The High Dust system (in retrofit
applications) sometimes require penetrating the boiler primary pressure boundary to
remove or bypass part of the economizer so that the plant can continue to operate at
part power while maintaining the required SCR reactor inlet tempertures. This is an
expensive modification that is generally not identified in reported costs such as
provided in Figures 1 and 2. On the other hand, the Tail Gas systems requires a
second heat exchanger or auxiliary firing to bring the flue gas up to the SCR reactor
operating temperature (and to recover the excess heat before the flue gas is
discharged through the stack). The heat exchanger equipment can easily increase the
Tail Gas system's capital costs by 20%, which is significant.
In considering the capital costs, it should be recalled that Figures 1 and 2 are based
upon analysis assumptions and are not plots of data. The early capital cost estimates
were important for establishing budgets, and thus cost assumptions that increased the
estimated cost were often used to conservatively predict the expected costs. In 1988
Jung"1 examined the reported costs for 19 German plants and reported that the total
4B-4
-------
capital expenditure had an arithmetic mean of about DM 66.3/kW,. More importantly,
his analysis showed that there was no statistical difference between wet and dry
bottom firing (and hence High Dust and Tail Gas SCR configuration) , but that the data
is represented by:
C = 0.358 x MW,0-"1
where C is the total capital cost in millions of DM, expressed in January 1988
DM; and MW, is the power plant net thermal output in megawatts
The uncertainty factor needed to account for having a 90 percent confidence that all
of the actual cost data is represented by this expression can be expressed by applying
a multiplier on the coefficient 0.358:
C = 0.358 x (1.65 or 0.65) x MW/-"1
where the multiplier 1.65 is used to define the upper bound of the cost data,
and the multiplier 0.65 is used to define the lower bound of the cost data.
Since the uncertainty can be accounted for in the coefficient, the 0.775 exponent can
be thought of as the factor that accounts for the effects of size or scale. The range
in the coefficient 0.358 (+65% to -35%) indicates that there is considerable
variability in the cost data base. This suggests that more detailed analyses of the
reasons for the cost differences would be useful.
However, the equation is important since it explains the large difference in the
reported cost/kW for High Dust and Tail Gas SCR applications as being primarily
related to the size of the system being retrofit. It is also important to note that
the inflation in Germany between 1985 and 1990 has been small enough that this cost
expression can be used to account for the DM in any year of convenience. Others''1'1
have examined the reported capital costs and they report similar exponential
relationships between total costs and the size of the SCR application.
There is some distortion in the capital cost data that needs to be understood, and
it also needs to be recognized that the above expression does not account for those
distortions. First, the catalyst costs for the early SCR applications were 40,000-
60,000 DM/m3. By 1989 competition and the shrinking market for catalysts reduced the
costs to 20-25,000 DM/m], and in one case the catalyst cost was reported at 17,000
DM/ms. Thus, as time went on the total capital costs were being reduced significantly
because of the reduced charge for the catalyst. To obtain a more realistic estimate
of the present cost for an SCR system, the data that was used to generate the above
equation should be normalized to assume the same unit costs for the catalyst.
However, that is not easy to accomplish because the German utilities do not always
identify the catalyst component of the total costs, nor do they use a standard chart
of accounts. Thus, the reported capital costs can vary from plant to plant because
significantly different items are included in the total cost number. Also, regulatory
concern about the safety of anhydrous ammonia storage and preparation systems has
increased significantly during the application period. Now the regulators may require
remote location of the storage vessels, double wall vessels and piping, and increased
instrumentation and monitoring. These differences can increase the total plant costs
by an amount approximately equal to the changes accounted for in the cost decreases
that have occurred for the catalyst charge.
By 1987 the installed number of High Dust systems was about twice the number of Tail
Gas systems, suggesting that the market agreed with the interpretation that the High
Dust system was the least expensive. However, by the end of 1990 the number of Tail
Gas systems was slightly more than the number of High Dust systems""- This suggests
4B-5
-------
that price (and technical) considerations have shown that the Tail Gas is at least
competitive if not less expensive. However, just as the cost data is not always
clear, there is other evidence that High Dust systems are preferred. For example,
the company Steag has reported that in 1989 the High Dust systems accounted for 80%
of the dry bottom boiler applications and 16% of the wet bottom boiler applications
(for a total of 18,213 MW of capacity) , while the Tail Gas accounted for the remaining
units (for a total 9,997 MW of capacity). Thus, in 1989 and 1990, more smaller units
applied the Tail Gas system. Since the cost/kW is greater for smaller units, on the
surface the raw cost data would imply that the Tail Gas is more expensive. Jung's
analysis, shows that this is not the case.
The earlier cost estimates assumed the same catalyst design for both the High Dust
and the Tail Gas configurations. Actual experience*141 for honeycomb catalysts is that
the High Dust systems have used a catalyst pitch of 6-7.5 mm with a space velocity
of 2,000-3,000/hr. Tail Gas designs have used a 3.7-4.2 mm pitch with space
velocities of 4,000-6,500/hr., and they can also use a more reactive catalyst
formulation since the flue gas is cleaner than that which is treated by the High Dust
system. It has been observed in Germany and Japan that sticky, very small sized dust
particles can cause more serious catalyst deactivation problems than does arsenic (see
below for a further discussion about arsenic) . Also, the greater dust accumulation
on the equipment in High Dust systems has contributed to SCR fires in Japanese oil-
fired plants. The High Dust systems often employ a dummy leading edge to control
catalyst erosion. These physical conditions mean that a smaller catalyst and SCR
reactor can be specified for the Tail Gas system (it can be 50-60% smaller1111) ,
reducing its system costs. Some of this impact is mitigated by the fact that the flue
gas saturation at the Tail Gas location means that the SCR reactor must process up
to 20% more flue gas volume than would a High Dust system on that plant, causing its
costs to increase (assuming that both designs operate at the same catalyst
temperature).
Examination of the assumptions that were used to prepare Figure 2 also indicates that
some of them have biased the results to indicate that High Dust systems are less
expensive to operate. For example, the figure is based upon assuming the catalyst
life is 3 years for the High Dust system and 5 years for the Tail Gas system.
Experience indicates that 3-4 years (with occasional 5 years life) is consistent with
the High Dust catalyst design. However, some Tail Gas system operators report that
they are not experiencing catalyst degradation, and that they expect the catalyst to
last for up to 80,000 operating hours (more than ten years). The Japanese on clean
flue gas, but not in coal service, have had catalysts last more than 10 years.
Catalyst life is an important item, others1" have reported that catalyst lifetime can
dominate the estimate of the levelized cost for SCR systems. Figure 2 was also
prepared with the Tail Gas system being charged for the cost of the flue gas reheat
system when a good part of that cost would have been incurred whether or not the SCR
system were present because some reheat is needed to add buoyancy to the flue gas
after FGD treatment. In reality, only the incremental costs beyond those required
for the FGD reheat system should be charged to the Tail Gas system. The figure also
assumes that all the reheat energy costs must be charged to the Tail Gas system costs.
The High Dust system requires that an economizer by-pass be installed to allow the
SCR system to operate when the plant is at part power. In the assumed 4,000
hours/year duty cycle that was used to generate Figure 2, the plant will be at part
power for a significant fraction of the operating time. Under those conditions bypass
of the economizer would lower the overall power plant efficiency by 2-4%, but that
cost impact was not included in the analysis used to generate the figure. The higher
assumed initial capital costs for the Tail Gas configuration require a larger
levelized capital recovery factor for that design. All of these assumptions tend to
make the operating cost estimate for the High Dust system less expensive and the Tail
Gas system more expensive.
4B-6
-------
Another factor that can be very important to account for is the fact that the retrofit
of a High Dust system may be very difficult and more expensive due to the congested
available space, the need to reinforce the boiler building substructure and supports,
the requirement to penetrate the boiler wall and to remove heating surfaces, and the
need to relocate soot blowers. Those costs and the plant down time (and the resulting
costs for replacement power while the plant is shut down) should be charged to the
High Dust system initial costs. On the other hand, the Tail Gas system can be sited
where it is convenient and the final hook up to the main plant can be performed more
quickly (typically in a few weeks). However, the more remote and accessible the Tail
Gas site, the potentially longer the flue duct runs and the higher would be their
corresponding costs. The greater dust loadings, the potential for fires involving
the SCR system (several fires were reported in Japan in 1989), the risk during plant
upset conditions for ammonium bisulfate deposits to form on downstream equipment, and
the need for washing the downstream equipment to remove deposits and then to control
and treat the wash water so it can be released to the environment all suggest a
greater down-side risk is associated with the High Dust system during the lifetime
of the plant. This risk should be reflected as a cost, but it is normally not
considered in the analyses used to prepare figures such as Figure 2.
The levelized cost assumptions do not include costs for control and disposal of the
spent catalysts. The shorter the catalyst lifetime the greater this problem could
be over the life of the plant, and the greater the expense associated with the
problem. In Germany and Japan it is assumed that the catalyst supplier will be
responsible for the spent catalyst, and in Germany the typical contract requires the
supplier to receive the spent catalyst. The experience in Japan (there has not yet
been enough experience in Germany with spent catalysts) is that it is not economical
to recover the catalyst materials, and they are simply disposed of by the catalyst
supplier. Thus, the assumption that the disposal cost are negligible is reasonable
for German and Japanese applications. The assumption needs to be checked for its
validity at local U.S. power plant sites.
U.S. cost estimates for new plants can also be used to help calibrate the reported
costs from German and Japanese plants. In 1984m the costs for a new 500 MW plant
were estimated at $70-80/kW. In 1989(1) similar applications were estimated at
$101/kW. The 1989 costs actually represent about a 40% reduction in the SCR system
costs, compared to the 1984 estimates, as is indicated when the 1984 costs are
escalated to the same basis as the reported 1989 costs'61. However, the 1989 estimates
also include the 50% reduction in catalyst costs as reported in the German literature.
With retrofit cost factors added, the U.S. estimates compare favorably to the German
reported costs; they are, however, significantly greater than the reported Japanese
costs for new plants.
OPERATIONS AND MAINTENANCE
Another important lesson learned deals with the receipt, storage, use, and measurement
of ammonia. It has been established110'11'"1 that if the SCR design is to provide a high
level of NOx control, extensive flue gas flow modeling and flow straightening are
needed to guide the design of the ammonia injection system and to assure that the flue
gas NOx-ammonia mixture is uniformly distributed across the catalyst cross sectional
area. The ammonia injection designs in Germany typically employ 30-40 injection
points per square meter of flow area. Each injection nozzle may have an individual
flow control (or each flow tube may have the controls if several nozzles are installed
on a single flow tube) , so that the system can be optimized during the plant shakedown
period (optimization is the attempt to develop a uniform NH,/NOx ratio throughout the
entire inlet cross section of the SCR reactor). However, the use of many injection
points can lead to a false sense of security. It has been observed (see Figure 3)
in at least one design that used multiple injection nozzles that dust and other
4B-7
-------
deposits collected inside the ammonia flow tube, indicating that conditions occurred
which caused the flue gas to enter some of the nozzles rather than for ammonia to exit
those nozzles. Since the resulting flow maldistribution built up slowly during
operations, it was not detected by the available monitoring instrumentation. But,
the hoped for NOx control that was supposed to be achieved by having a large number
of "tuned" ammonia injection nozzles was not achieved.
Much of the plant shake down and acceptance period is spent qualifying the valving,
motors, and switches in the ammonia distribution system (and in assuring that the
desired flow injection pattern is achieved). Typically, full flue gas velocity, NOx,
and temperature profiles are taken and a less extensive ammonia distribution profile
is taken. A 10% variation in the NHs/NOx ratio would be an excellent optimization,
a 25-30% variation would not be unusual. Often two measurement instruments are used
so that a average value can be determined.
The Germans initially used, in their High Dust applications, the Japanese criteria
of designing for an ammonia slip of less than 5 ppm, but during operations they have
found that they must limit the slip to less than 1 to 3 ppm(11) in order to provide fly
ash that can be used in other commercial processes. This also requires that the
ammonia injection be such that the ratio of NH,/NOx be less than 0.85 or the slip will
exceed the limit after a short operating period'81. The amount of acceptable ammonia
slip introduces a significant uncertainty in the life expectancy of the catalyst.
That is, later in its lifetime the catalyst may be able to provide for the design NOx
reduction with a 5 ppm ammonia slip, but not the needed 1 to 3 ppm slip. This item
remains to be evaluated, based upon actual, long term, operating experience. In the
Tail Gas configuration, because of the very clean nature of the gas, the ammonia slip
can be set by air emissions criteria, and slips as large as 20-30 ppm should not lead
to operational problems (ammonia odor and plumes are troublesome at 50 ppm or greater
ammonia concentrations).
As the German regulators dealt with additional SCR installations, they have become
more concerned about the safety implications of anhydrous ammonia, and increasing
design restrictions reflect those concerns. In Germany, anhydrous ammonia is
primarily delivered by rail, truck transport is prohibited except for volumes less
than 500 liters. The Germans generally store on site a 15 to 30 day supply of
anhydrous ammonia. Often the ammonia is diluted to a mixture of 8% or less ammonia
before it is introduced into the flue gas. Normally, clean, cold, fresh air is the
diluent in order to help keep the ammonia nozzles clean. Two storage tanks are used
to allow for uninterrupted operation. They also increase the inherent safety margin
if a tank accident should occur. Many of the systems use double wall tanks and double
wall piping from the point of receipt to the exit from the ammonia vaporizer. Warm
water heating (compared to electrical heating used at some U.S. gas turbine
installations) is used to vaporize the ammonia. However, the safety requirements are
locally developed, and some installations use single wall systems, some facilities
bury their tanks, others were allowed to install above ground tanks. Increasingly
restrictive safety criteria have caused the ammonia system costs to increase almost
as much as the SCR catalyst costs have decreased"1. Figure 4 is a presentation of the
purity specifications used for the purchase of anhydrous ammonia. The water and
oxygen are controlled such that the delivered ammonia is in region A of the figure.
Equipment corrosion is possible in region B, and corrosion will occur if the oxygen
and water content are such that the ammonia is in region C. However, corrosion by
water alone is unknown, and the storage of hydrous ammonia with 25% or greater water
content is common.
Actual plant operations in Germany have shown that some of the catalysts can store
ammonia. The storage has no effect during steady state operation, but this ammonia
inventory is released from or added to the catalyst during transients such as load
4B-8
-------
changes or shut downs. This phenomenon must be recognized in the design of the
ammonia injection control system, as the desorption process has been found, in at
least one plant, to take up to eight hours. For example, if the ammonia injection
control does not account for desorption during shut down, excess ammonia will be in
the flue gas during low temperature operations, causing too high an ammonia slip and
possibly forming and depositing bisulfate salts. Since ammonia desorption/absorption
can produce a 30 minute lag in the NOx control1", the selection of the averaging time
for meeting the NOx emission control requirement is very important for establishing
if the plant operation can remain within the permitting requirements. Since bisulfate
formation is not controlled by the ammonia slip as much as it is by the SOS
concentration, the lack of a continuous ammonia monitor and control by ammonia slip
levels is not serious to the overall satisfactory operation of the SCR system.
Other design areas that were not addressed during the initial German installations
but which have been indicated by operating experience are: 1) sulfur trioxide and acid
attack of the duct liners downstream of the SCR has occurred in some cases, indicating
that the oxidation potential of the catalyst (for converting sulfur dioxide to
trioxide) will be an important consideration when high sulfur coal is fired. 2) the
gas to gas heat exchanger for reheating the flue gas for the Tail Gas system has been
required to be redesigned to make it less complicated and to produce less leakage of
the untreated gas into the treated gas. Leakages as high as 7% are reported, but 1.5-
3% appears to be more common. It is possible to design for zero leakage, and some
plants have such heat exchangers. This suggests that the use of rotary heat
exchangers should be replaced with the use of non fluid mixing heat exchangers for
reheating the flue gas to the Tail Gas system operating conditions. 3) control
problems under load swing conditions have indicated that the ammonia instrumentation
remains an issue as well as the impact of ammonia absorption/desorption from the
catalysts. This could be even a more pronounced problem in high sulfur coal service.
The initial reason for developing the Tail Gas configuration was to overcome the
catalyst poisoning that was experienced in a few pilot plants that serviced wet bottom
boilers that also recirculated the fly ash back to the boiler to slag the ash. That
operation was found to increase the arsenic concentration in the flue gas by 10 to
100 times from the level found when no fly ash recirculation was used. That
information was initially used to conclude that the Tail Gas design was required when
wet bottom firing with full flue gas recirculation was used at the power plant.
Gutberlet'111 has since examined the arsenic concentration in 14 wet bottom plants that
had varying amounts of fly ash recirculation. Figure 5(1" presents data from the 14
separate boilers. The upper plot presents the relative amount of arsenic in the flue
gas before the air preheater. The lower plot shows the relative amount of arsenic
in the coal being fired. The data was plotted so that the amount of arsenic in the
flue gas would increase as the data is viewed from left to right. The figure clearly
shows that arsenic content in the coal and operation with 100% fly ash recirculation
back to the boiler can cause both high or low arsenic concentrations in the flue gas
(Gutberlet did not identify the actual arsenic concentrations). Thus, fly ash
recirculation by itself is not a sufficient parameter to determine if arsenic
poisoning would be a problem for a High Dust SCR application. Gutberlet concluded
that the composition of the fly ash itself was a significant factor, and that the
greater the amount of calcium oxide in the fly ash the less arsenic would be found
in gaseous form in the flue gas. He recommended that the calcium oxide in the fly
ash be at least 3% and preferably greater than 5%; that fly ash recirculation be
restricted in general if possible and especially during boiler soot blowing; and that
coals with low arsenic content be used (most German coals have arsenic levels of 5-25
mg/kg, and the term "low arsenic content" was not defined or compared to those
levels). Separate Japanese'111 studies (the coal arsenic levels were not reported)
have shown that calcium content in the fly ash is a primary factor for causing
catalyst deactivation in High Dust SCR configurations. This further supports the
4B-9
-------
German data that fine dust can be a greater catalyst "poison" than is arsenic. The
Japanese data is for dry bottom firing. The Japanese experience is that if the
calcium oxide content is less than 1% the catalyst will not have to be replaced even
after 38,000 hours of operation. Five to eight percent calcium oxide in the fly ash
can cause a comparable catalyst deactivation in 20,000 hours, and catalyst replacement
will be required before 25,000 hours. They also found that high sulfur coals that
produce a higher ratio of gypsum in the calcium compounds in the fly ash are less
likely to cause rapid catalyst deterioration. Thus, it appears that if there is a
species such as arsenic in the flue gas, it can react with the calcium and is thus
removed as an active poison. However, if there is no species available to react with
the calcium, the calcium itself can blind the catalyst. The desirability of some
calcium content in the flue gas needs to be carefully studied for U.S. high sulfur
coal applications. Such a study will also have to evaluate the type of FGD design
used if Tail Gas SCR systems are being considered.
IMPLICATIONS FOR U.S. SCR OPERATIONS
Extensive overseas use of SCR has established design and cost criteria as well as
credibility for the use of this technology in low sulfur fuel applications, including
coal, oil, or gas. An important consideration in this commercial success for High
Dust applications has been the recognition that the ammonia:sulfur trioxide reaction
to form ammonium bisulfite and bisulfate can be controlled by limiting the ammonia
slip.
Low Sulfur Coal
The large U.S. population of low sulfur, coal-fired, electric utility boilers,
primarily those firing western subbituminous coals, should be able to readily utilize
the commercial design and operating retrofit experience from Japan and Germany to
achieve NOx emission levels, when and if required, as low as 100 ppm or 0.17 Ib
NOj/million Btu. The German operating experience is more important for such U.S.
applications because many of the U.S. installations are on peaking utility boilers,
whereas Japan coal-fired service has been essentially all in more simple, base load
boiler cases. An appropriate SCR system design strategy based on German practice on
low sulfur, coal-fired, dry bottom boilers would call for the retrofit of combustion
modifications including low NOx burners to reduce the gross emission to the range of
325 to 400 ppm(m- This greatly mitigates the overall cost and ammonia slip problems,
since the resulting SCR removal efficiency requirement is no more than 70 to 75% to
achieve a 100 ppm stack emission. Such an approach, if it achieved only half of the
four million annual ton of NOx emission inventory reduction in the U.S., which is
implicit in Title IV of the new Clean Air Act, would result in nearly 100,00 MW of
retrofit SCR system capacity. That would be more than the entire present worldwide
population of existing SCR facilities.
Key design premises for this coal-fired SCR service are tied to the use of a design
ammonia slip of 3-5 ppm. The suppliers and users in Japan'201 have identified them as:
• Vertical downward gas flow reactors to prevent ash accumulation.
• Linear gas velocities of 16-20 ft/sec (5-6 m/s) at maximum continuous
rating to prevent ash accumulation and erosion.
• Use of a grid-shaped catalyst with a channel spacing (pitch) of 0.275-0.3
inches (7-7.5 mm) to prevent ash accumulation and erosion.
• Catalyst layers formed without seams along the gas flow direction
4B-10
-------
(including optional use of a sacrificial initial stage) to prevent ash
accumulation and erosion.
• Ash deposition removal by intermittent vacuuming or soot blowing.
Technical literature issued by Japanese SCR system suppliers emphasizes the following
key elements for a successful SCR installation on peaking utility boilers:
• Reliable ammonia feed control.
• Adequate ammonia feed distribution across the cross section gas flow
area.
• Flue gas duct designs that ensure good mixing of flue gas and ammonia
feed.
• Provision for suitable control of ammonia feed at part load.
In Germany, important new SCR experience has been gained on slagging (wet bottom)
boilers, which produce different flue gas and fly ash characteristics that can impact
the SCR catalyst'21'. Full-scale experience since 1986 in the use of the High Dust SCR
designs for some wet bottom boilers has confirmed excessive impacts on the catalyst
life and has lead to their reworking approximately 3,000 MW of such retrofits to
convert them to Tail Gas designs. It is clear that such boilers are best served by
the Tail Gas design.
High Sulfur Coal
The potential impacts of the much higher sulfur dioxide and especially the higher
sulfur trioxide concentrations in the flue gas from U.S. high sulfur, coal-fired
plants will be an item of special concern. It may cause a new optimum of catalyst
reactivity, linear velocity, ammonia slip, and operating temperature window to be
established. Since much of the impacts of ammonia absorption/desorption, sulfate and
bisulfate formation, poisoning of the catalyst, and blockage or blinding of the
catalyst are surface effects, it is not possible to scale the existing German and
Japanese High Dust SCR results with confidence without the benefit of prior testing
at the expected operating conditions. Although the Tail Gas results can be scaled
with somewhat more confidence, questions about calcium poisoning or trace element
carry over from the FGD system indicates that these designs also need to be tested
prior to final design selection.
Patterning its work after the major pilot plant test program in Germany, EPRI is
carrying forward a $15 million collaborative bench and pilot-scale research program
to include definition of costs and technical feasibility for the use of SCR in
domestic medium and high sulfur coal service'"1- Testing will be conducted at as many
as 14 separate facilities over a four year period to assess SCR process design,
catalyst life, instrumentation and controls, and plant integration.
Application of the Tail Gas system design is an important and possibly vital approach
for using SCR technology in high sulfur coal service. Such process applications would
avoid the potentially excessive rate of air preheater fouling and catalyst degradation
from high sulfur service, High Dust SCR design, even with an ammonia slip value as
low as 1 ppm.
Cyclone-fired wet bottom boilers, for high sulfur service and with their typical NOx
emissions of 0.8 to 1.8 Ib N02 million Btu (500 to 1,100 ppm, represent a major market
4B-11
-------
for the Tail Gas SCR design. There are presently 105 operating cyclone units. They
represent about 14% of the pre-NSPS coal-fired generating capacity (over 26,000 MW).
However, these units contribute about 21% of the NOx emitted by pre-NSPS units because
their combustion design is conducive to NOx formation, and their firing design is not
conducive for low NOx burner technology. Furthermore, other conventional NOx
reduction techniques such as two-stage combustion cannot be applied to the full extent
due to associated operational concerns with corrosion. Although many of the units
are 20 to 30 years of age, many of the utility owners plan to operate them for an
additional 10 to 20 years. Since the majority of these units are located in the acid
rain emission control area (the Midwest) , cyclone boilers may be especially
appropriate for NOx control. With the well established use of Tail Gas SCR systems
on wet bottom boilers in Germany, this class of boilers appears to be a key target
market sector for Tail Gas SCR designs.
REFERENCES
1. NOx Task Force, Economic Commission for Europe, Technologies for Controlling
NOx Emissions from Stationary Sources. July 1986.
2. "Development & Application of NOx-Flue Gas Treatment in the Federal Republic
of Germany." NATO/CCMS Meeting, Control of Air Pollution From Combustion
Systems, Duesseldorf, October 1988.
3. B. Schaerer, N. Haug, and J-H. Oels. "Cost of Retrofitting Denitrification."
Proceedings of the Workshop on Emission Control Cost, Esslinger am Neckar, FGR,
1987.
4. "Selective Catalytic Reduction for Coal Fired Power Plants." EPRI CS-3603,
October 1984.
5. C. P. Robie, P. A. Ireland, and J. E. Cichanowicz. "Technical Feasibility and
Economics of SCR NOx Control In Utility Applications." Proceedings 1989
Symposium on Stationary Combustion Nitrogen Oxide Control. EPRI GS-6423, July
1989.
6. P. A. Lowe. Selective Catalytic Technology. Burns and Roe Service Corporation
report submitted to the U.S. Department of Energy, December 1989.
7. J. Jung. "Capital Expenditures in S02- and NOx Reduction in the German
Electricity Industry." VGB Kraftwerkstechnik, Vol. 68, No. 2, February 1988.
8. P. A. Lowe, and M. Perlsweig. "Recent Experiences for SCR Systems at Coal-Fired
Utility Boilers." Proceedings of the American Power Conference, March 1990.
9. J. E. Cichanowicz, and G. R. Offen, "Applicability of European SCR Experience
to U.S. Utility Operation," 1987 Symposium on Stationary Combustion Nitrogen
Oxide Control, EPRI CS-5361, August 1987.
10. P. Necker. "Operating Experience with the SCR DeNOx Plant in Unit 5 of
Altbach/Deizisau Power Station." 1987 Joint Symposium on Stationary Combustion
NOx Control, EPRI CS-5361, August 1987.
11. M. Novak, and H. G. Rych. "Design & Operation of the SCR-Type NOx-Reduction
Plants at the Duernohr Power Station in Austria." 1989 Symposium on Stationary
Combustion Nitrogen Oxide Control, EPRI GS-6423, July 1989.
4B-12
-------
12. J. Ando., "NOx Abatement for Stationary Sources in Japan," EPA-600/7-83-027
(PB83-207639), May 1983.
13. P. Necker. "Experience Gained by Neckarwerke From Operation of SCR DeNOx
Units." 1989 Symposium on Stationary Combustion NOx Control, EPRI GS-6423, July
1989.
14. K. Staebler, et. al.. "Secondary Measures for NOx Reduction Experience with
Pilot- and Commercial-Scale Plants." VGB Kraftwerkstechnik, 68, No. 7, July
1988.
15. H. Gutberlet. "Influence of Furnace Type on Poisoning of DENOX Catalysts by
Arsenic." VGB Kraftwerkstechnik, Vol 68, No 3, March 1988.
16. S. Nagayama, et. al.. "SCR Application for NOx Control in Coal Fired Utility
Boilers." Proceedings of the 7th Pittsburgh Coal Conference, September 1990.
17. A. Kinoshita. "Trends in Environmental Control Costs for Coal-Fired Power
Plants in Japan." Proceedings of the 7th Pittsburgh Coal Conference, September
1990.
18. M. Hildebrand. "Status of the Art of Flue-Gas Purification at E.S.C. Power
Stations S02/N0x-Reduction (in German)." Elektrizitaetswirtschaft, Jg. 89, Heft
9, 1990.
19. K. Leikert, H. Reidick, and H. Schuster. "Low NOx-Emission Combustion of Fossil
Fuels in the Federal Republic of Germany." Proceedings of the Fourth Seminar
on the Control of Sulphur and Nitrogen Oxides From Stationary Sources, Graz,
Austria, 1986.
20. P. A. Lowe. "Utility Operating Experience with Selective Catalytic Reduction
of Flue Gas NOx.", Proceedings of the Second International Conference on Acid
Rain, Washington, B.C., 1985.
21. G. R. Offen, et. al.. "Stationary Combustion NOx Control." Journal of the Air
Pollution Control Association, July 1987.
22. Electric Power Research Institute, "Selective Catalytic Reduction for NOx
Control, A Proposed Collaborative Bench- and Pilot-Scale Research Program,"
April 1988.
4B-13
-------
a:
ca
Uj
a:
Uj
100-
90-
80-
70-
60-
50-
40-
30-
20-
10-
0 VET BOTTOM BOILER CORL-FIRED
S QRT BOTTOM BOILER CORL-FIREO
[ID OIL- FIND GRS-FIRED BOILER
80'/ NO* REMOVffL
100 200 300 400 500
CflPPCITY [MV*1]
600
700
FIGURE 1. GERMAN SCR CAPITAL COSTS VERSUS CAPACITY
J.5-
s:
Q
o
o
*-J
-------
FIGURE 3. DUST DEPOSITS IN AN AMMONIA FLOW TUBE
FIGURE 4
-GERMAN OXYGEN AND WATER PURITY SPECIFICATION.
FOR ANRYROUS AMMONIA
O, [ppm]
48-15
-------
ARSENIC IN FLUE GAS
l.O
0.1
0.0 1
O.001
1.0
0 5
• 100% ash recirculation
® partial ash recirculation
° no ash recirculation
e
o
o
o
ARSENIC IN COAL (dry)
o
! 2 3 4 5 6 7 8 9 1011121314
TEST NUMBER
FIGURE 5. RELATIVE CONCENTRATION OF ARSENIC IN
THE FLUE GAS AND IN THE COAL
4B-16
-------
OPERATING EXPERIENCE WITH TAIL-END AND HIGH-DUST
DENOX-TECHNICS AT THE POWER PLANT OF HEILBRONN
Dr. H. Maier
Energie-Versorgung Schwaben AG
KriegsbergstraBe 32
7000 Stuttgart 10
Germany
P. Dahl
Energie-Versorgung Schwaben AG
KriegsbergstraBe 32
7000 Stuttgart 10
Germany
-------
OPERATING EXPERIENCE WITH TAIL-END AND HIGH-DUST
DENOX-TECHNICS AT THE POWER PLANT OF HEILBRONN
ABSTRACT
At the Heilbronn power station two different SCR-DENOX technics are installed.
The high dust SCR of the unit Heilbronn 7 has been started up in September 1986 and
operates till now appr. 25.000 hours.
It is a two line arrangement, each of it denitrificating 50 % of the total flue gas
amount.
The loss of catalysts activity and the ammonia slip have been measured in dependence
of operating hours and the results compared with expected or theoretical calcula-
tions.
Decrease of catalysts activity, fly ash plugging, irregular distributions in the SCR-
reactor (velocity, temperature, NH3/NOx-ratio) and side reactions (acid particles
formation and emission, ammonia sulfates) have been investigated in detail.
In the units Heilbronn 3 6 the tail-end configuration is installed.
The flue gases of 4 slag tap boilers are desulfurized downstream the electrostatic
precipitators in one FGD plant (wet limestone process yielding gypsum as byproduct)
with a capacity of approximately 1.800.000 m3/h. The tail-end SCR denitrificates the
flue gases, which are free of dust and desulfurized, with two lines, each of it
treating 50 % of the total flue gas amount.
The first line started up in the middle of 1988 and operates till now appr. 14.000
hours, the second one in October 1990. In contrast to high dust DENOX-plants, which
had been proofen in Japan for several years, there was no experience with tail-end
arrangements.
Therefore different start up times resulted from the demand, to research and optimize
such a configuration at the first line.
4B-19
-------
OPERATING EXPERIENCE WITH TAIL-END AND HIGH-DUST
DENOX-TECHNICS AT THE POWER PLANT OF HEILBRONN
(Dr.-Ing. Herwig Maier, Paul Dahl)
1. INTRODUCTION
At Heilbronn the EVS operates following combined heat and- power units:
• Unit 3-6, with four bituminous coal fired boilers and a slag tap
firing process.
Technical parameters as shown in fig. 1. (1st slide)
• Unit 7, with one bituminous coal fired boiler and dry firing
process.
Technical parameters can be seen in fig. 2 (2nd slide).
In the Federal Republic of Germany the N0x-emissions from bituminous coal fired
boilers with more than 300 MW thermal output are limited to less than 200 mg/m3.
This usually needs post combustion flue gas cleaning technics. A well known and
widely used technology is the selective catalytic reduction or SCR-process, where
ammonia reduces with the aid of catalysts nitrogen oxides to nitrogen and water at
temperatures between 300 °C and 400 °C. (Fig. 3, 3rd slide).
The SCR-process can be installed between boiler outlet and air preheater (the so
called high dust arrangement) or downstream of the electrostatic precipitator and
the flue gas desulphurization plant (the so called tail end configuration).
At Heilbronn power station both possibilities are realized.
2. THE HIGH DUST DENOX OF HEILBRONN 7
2.1 General Informations
During start of erection (1982) and trial run (end of 1985) environmental protec-
tion laws have been actualised several times, of course each time they changed to
lower limit values for SOX- and N0x-emissions. Until 1982 the N0x-reduction by post
4B-20
-------
combustion flue gas technics has not been a severely discussed, feasible solution.
But in January 1984 the N0x-emission limit for new coal fired plants was reduced
from 800 mg/m3 to 200 mg/m3. So, during the phase of erection of Heilbronn 7 we were
forced to realize a SCR-plant as soon as possible. The erection of the DENOX-plant
started in the last quarter of 1985. One year later, in September 1986 the SCR was
put into operation.
Fig. 4 (4th slide) shows the high dust arrangement of the SCR-plant at Heilbronn 7.
2.2 Operating Experience
Since beginning of operation the loss of catalysts activity and resulting ammonia
slip is measured periodically and compared with expected respectively theoretical
calculations.
Fig. 5 (5th slide) shows, that after 12.000 operating hours the status of the SCR-
plant was much better than expected (and guaranteed). But, as one can see in fig. 5
too, during the first months of 1990 (after appr. 18.000 operating hours) we
recognized increasing amounts of ammonia in the fly ash (up to 100 ppm) and
consequently we got problems with our waste water, where the ammonia concentration
is limited to 10 mg/1. Therefore we were forced to set measures immediately:
• ordering an access layer of catalysts
• manually cleaning of the DENOX plant
• measuring of catalysts activity
• measuring the ammonia slip before and after cleaning.
The results, that partially can be recognized again in fig. 5, were:
• The relative activity Kt/K0 of the catalysts was 0.77, after 18.500
operating hours a really sufficient result
• the cleaning of the plant decreased the ammonia slip from appr.
2 vpm to 0.5 vpm
• optically we estimated a loss of active surface of appr. 22 %,
caused by fly ash plugging (fig. 6, 6th slide).
These results caused (beside manual cleaning) further steps, to bring the plant
back to optimal operation conditions.
4B-21
-------
Fig. 7 (7th slide) shows, how the need of access catalyst volume or, at the other
hand, the loss of volume needed for good operation, is influenced by irregular
distributions of
• NH3/NOx-ratio
• temperature
• velocity
It can be seen clearly, that optimizing the NH3/NOx-distribution is most effective.
Therefore, measures to be done are:
• control of the NH3/NOx-distribution and, if necessary, optimize the
NH3-feeding
• we recommend generally and ordered for Heilbronn 7 sootblowers
between all catalyst layers, including the dummy, to keep the plant
free from surface losses caused by fly-ash plugging. The sootblowers
will be installed this summer
t to keep further troubles far from us during that time, we replaced
the first layer by a new one.
In fig. 8 (8th slide) we tried to estimate the consequences of replacing one
catalyst layer in dependence of fly-ash plugging. You can see clearly, how impor-
tant the sootblowers are regarding the life time.
2.3 Side Reactions
The most important and well known side reaction in high-dust plants is the cataly-
tic oxidation of S02 to S03 and, depending on flue gas humidity and temperature, the
formation of sulfuric acid. This can cause troubles in two ways:
The Formation of Ammonia Sulfates like (NHJ, SO, or NH^HSO,,. These compounds can
cause pluggings on the gas-gas-reheater, therefore needs washing of it and creates
ammonia-loaded waste water.
According to the very low ammonia slip, which we try to run at Heilbronn 7 because
of other reasons (saling of high-quality fly-ash), this is no problem till now. The
ammonia concentration behind SCR is not sufficient to form ammonia sulfates at
amounts, which could hurt.
4B-22
-------
Formation and Emission of Acid Particles. Sulfuric acid condensates at the cold
raw-gas side of the gas-gas-reheater and is transported to the clean-gas side.
There an acid film forms at the walls of the flue gas ducts and the stack and is
adsorbed by fly ash or gypsum particles. That means, particles are created with an
access of free sulfuric acid. Especially during starts after a few days stop the
acid particles are solved from the walls by thermal expansion, transported to the
stack and, after reaching full load and corresponding gas velocity, emitted within
a few minutes.
This phenomenon causes severe troubles if attacking the dope of cars nearby the
power plant.
To fight these emissions, we have the possibility
• to reduce the efficiency of the ESP and increase the amount of
neutralizing fly ash (this we are doing at the moment)
• to set constructive measures in the clean gas duct like especially
precipitators (we are testing this)
• in future, when catalysts have to be renewed, to use types with low
conversion efficiency.
2.4 Conclusions
After appr. 25.000 hours of operating the SCR-Plant at Heilbronn 7 we made follo-
wing experiences:
• The decrease of catalysts activity is far from expected values and
much better than assumed.
• Fly ash plugging can cause severe problems, so we recommend to
install sootblowers between each layer.
• Irregular distributions of velocity, temperature and NH3/NOx-ratio
can not be avoided. The most effective measure at relatively low
costs is to optimize the distribution of NH3/NOXI i. e. optimizing
NHj-injection under respect of not avoidable irregular distributi-
ons.
• Formation and emission of sulfuric acid and acid particles makes a
lot of troubles especially at plants with much starts and shutdowns.
Measures to solve this problem are possible and we try to realize
them at the moment.
4B-23
-------
t Formation of ammonia sulfates and consequences out of this is no
problem. This follows from the very good activity-slope and conse-
quently low NH3-sl ip.
3. THE TAIL-END DENOX OF HEILBRONN 3 - 6
3.1 General Informations
The start up of these elder units at Heilbronn was between 1958 and 1966. As
mentioned before, also for these plants the N0x-emissions were limited to 200 mg/m3
in the middle of the 1980's.
That means again, that additional to primary measures post combustion technics had
to be installed.
But in contrast to the situation at unit 7, the well proofen high dust technic is
often not feasible for slag tap boilers.
Problems arise due to interference with the compact design of elder plants and to
relatively high content of catalyst poisening gaseous trace elements (like arsenic)
in the flue gas.
These were the reasons, why we decided to erect a so called tail-end SCR plant
behind electrostatic precipitators and flue gas desulphurization. This configura-
tion is shown in figure 9 (9th slide).
Because of no experience with such an arrangement, we realized this project within
three steps. The first was a pilot plant, which is not in discussion here. Just let
me say, that the principal feasability could be proofed.
The second step was the commercial scale tail end plant for one half of the total
flue gas amount of the units 3-6, appr. 900.000 m3/h. This first line started up
in the middle of 1988 and operates till now more than 14.000 hours. An intensive
research project was running with this line from January until December 1990. The
first two steps have been partially sponsored by the EEC. The third step conse-
quently was DENOXing the second half of the flue gases of unit 3 6. This second
line started its operation in December 1990 with the trial run.
3.2 Operating Experience
Catalysts activity has been measured after 3.700 and 6.500 hours of operation with
the result of no activity loss. At the moment we expect the results after 13.000
hours. The ammonia slip measured at the DENOX-plant additionally after those times
was below 1 ppm.
4B-24
-------
Because of the very low dust- and S02-concentration with the tail-end configuration,
the design of the catalysts is different to that of the high dust arrangement, as
one can see in figure 10 (10th slide). Smaller pitches cause in spite of the low
dust concentrations some pluggings, so we are cleaning the plant from time to time
manually and we think about the installation of sootblowers.
In contrast, to the high dust plant the flue gas temperatures in front of the tail-
end reactor is appr. 50 °C (behind FGD). Therefore we have to operate a reheating
system (9th slide), which is a combination of regenerative gas/gas preheater (GAVO)
and gas burner. The last one we need to compensate the hot side temperature
approach of the GAVO, which is below 30 °C.
Up to now the GAVO operates very well. The total leakage is about 3.7 % at full
load, that means an increase of the NOX clean gas concentration of appr. 25 mg/m3
caused by the GAVO. To prevent an increase of differential pressure according to
GAVO plugging, we clean it once per shift using sootblowers, but we don't wash the
GAVO.
3.3 Side Reactions
In principal we have to discuss the same side reactions as before, but obviously it
is expected to cause less problems because
• the S02-concentration behind FGD is very low
• the conversion rate depends on the temperature (it decreases with
decreasing temperature rapidly) and we have significantly lower
temperatures with the tail-end configuration (290 °C 320 °C)
t also the ammonia slip is far from dangerous concentrations.
And indeed till now there are no problems with side reactions at the tail-end
plant.
3.4 Conclusions
After appr. 14.000 hours of operating the first line of the tail-end DENOX plant at
Heilbronn 3-6, and after three months with the second line we made the experi-
ence, that this configuration is a suitable one for slag tap fired boilers:
4B-25
-------
The operating characteristics are shown in figure 11 (11th slide).
Again the decrease of catalysts activity is far from expected
values.
Fly ash plugging can be handled by manual cleaning, but sootblowers
should be more effective.
The danger of formation and emission of acid particles is less than
at the high dust plant and we don't expect troubles from this side
in the future.
Catalyst poisening caused by gaseous trace elements can be avoided,
if using a tail-end arrangement.
4B-26
-------
Flue gas flow rate Nm3/h 1,8 x 106
Output MWnet 426
NOx-concentration
- inlet of SCR mg/m3 < 1.000
- outlet of SCR mg/m3 < 200
NOx-removal % > 80
SOx-concentration
- inlet FGD mg/m3 1.600 - 3.400
- outlet FGD mg/m3 < 160 - 340
SOx-removal % > 90
Dust concentration
- inlet electrostatic mg/m3 6.000
precipitator
- outlet electrostatic mg/m3 < 200
precipitator
- outlet FGD mg/m3 < 50
Operation time
DENOX 1 h 14.000
DENOX 2 h 2.000
Figure 1. Technical Parameters of Heilbronn 3-6
4B-27
-------
Flue gas flow rate Nm3/h 2,3 x 106
Output MWnet 700
NOx-concentration
- inlet of SCR mg/m3 < 800
- outlet of SCR mg/m3 < 200
NOx-removal % 75 - 80
SOx-concentration
- inlet FGD mg/m3 1.500 - 3.200
- outlet FGD mg/m3 < 200 - 400
Dust concentration
- inlet electrostatic mg/m3 7.000 - 12.000
precipitator
- outlet electrostatic mg/m3 < 50
precipitator
Start up of DENOX-system September 1986
Operation time h 25.000
Figure 2. Technical Parameters of Heilbronn 7
4B-28
-------
CD
ro
CD
catalyst
32CTC-40OX
m tf~?~\
4 +
\ catalyst r\ /<^\ **
.) 320.c_400.c -3 Qy + 6
Figure 3. Principals of the SCR-Process
-------
flue gas
duct
DO
CO
O
DENOX-
reactor
Figure 4. High dust SCR-arrangement at Heilbronn 7
-------
CD
CO
rel.
activity
K/K0
2500 4600 6300 8500 12000
operating hours [h]
18500
NH3-slip
[vpm]
5
4
3
2
1
Figure 5. Heilbronn power station unit 7; DENOX-plant. Loss of activity and ammonia slip
-------
00
CO
-.
• V.,. ' A • • V •
Figure 6. Fly-ash plugging in the DENOX-reactor of Heilbronn 7
-------
NH3/NOX
vP
0s
0
E
3
0
CO
0)
O
O
CO
50 -
45 -
40 -
35 -
30 -
25 -
20 -
15 -
10 —
5--
0 5 10 15 20 25 30
irregular distribution %
Figure 7. Heilbronn power station
unit 7; DENOX-plant. Need of access
volume vs irregular distributions of
temperature, velocity and NH3/NOX
4B-33
-------
CD
CO
o
CO
0)
'•?
JB
CO
to
JZ
CO
CO
I
o
o
£
Figure 8. Heilbronn power station unit 7; DENOX-plant. Loss of activity and NH;
in fly-ash in dependence of plugging; replacing of the 1st layer
-------
CD
CO
cn
NH?-
injection
T T
DENOX-
burner
\
G
A
V
O
regenerative
gas preheater
| stack
I bypass-burner
DENOX
Figure 9. Tail end arrangement of the DENOX plant at Heilbronn unit 3-6
-------
high-dust
system
tail end
system
CD
CO
7.4 - 7.0
430 - 470
1.0
320 - 400
100
pitch
surface
activity
temperature
pressure loss
mm
m2/m3
4.2
750
1.0-1.2
(270) 300 - 320
-180-250
Figure 10. SCR catalysts for slag-tap firing systems
-------
Temperature 290 °C - 320 °C
NOX5 behind SCR 150 mg/m3
NH3-slip < 1 ppm
Pressure drop
total plant 37 mbar
reactor 7,5 mbar
GAVO 14,0 mbar
Start up- / Shut down-times
heat up from 20 °C to 320 °C 51/2 hours
cool down from 320 °C to 20 °C 24 hours
Operational values
natural gas consumption 1.300 ms/h
NH3 consumption 170 kg/h
electrical power consumption 4 MW
Figure 11. Operating Characteristics of DENOX 3-6
4B-37
-------
SO3 GENERATION -
JEOPARDIZING CATALYST OPERATION?
R. Jaerschky
A. Merz
J. Mylonas
Isar-Amperwerke AG
Brienner StraBe 40
8000 Munchen 2, Germany
-------
S03 GENERATION -
JEOPARDIZING CATALYST OPERATION?
ABSTRACT
Isar-Amperwerke AG's modern, hard-coal-fired combined power and dis-
trict heating plant in Zolling went into operation at the end of 1985.
To ensure conformance with the applicable emission limits, the power
plant was initially equipped with primary NOx reduction measures, a
high-efficiency electrostatic precipitator and a desulfurization plant.
With the introduction of a more stringent limit for NOX emissions, it
became necessary to retrofit a DeNOx plant. This DeNOx plant, which
functions on the principle of selective catalytic reduction using
ammonia, went into operation at the beginning of 1988 and achieved the
required separation efficiency without difficulty.
After a brief period of operation, however, acidic particles started to
be emitted. Extensive investigations revealed that these emissions were
the result of the catalysts' having a very high SO2/SO3 conversion rate.
On the basis of the investigations results, steps were taken which
reduced the emission of acidic particles to an absolute minimum. It
became apparent, though, that a permanent solution to the problem would
require replacing the catalysts.
For this reason, the catalysts were replaced mid-1990 after approxi-
mately 12,000 hours of operation by a new type with a much lower con-
version rate.
This paper reports on the operating results obtained with the old
catalysts, the investigations carried out regarding SO2/SO3 conversion,
and first experiences gained with the new fill.
4B-41
-------
ZOLLING POWER PLANT
Zolling Power Plant - formerly known as Leiningerwerk Power Plant Unit
5 - benefits from a number of environmental protection features:
High efficiency thanks to supercritical steam conditions
Extraction of district heat
Highly efficient flue gas cleaning with DeNOx, dust removal
and desulfurization
A liquid waste processing system with ammonia stripper
A pleasant architectural design (Fig. 1)
Figure 1. Zolling Power Plant
4B-42
-------
The technical data of the Zolling Power Plant are listed in Table 1:
Table 1
TECHNICAL DATA
Max. thermal output of furnace 1,144 MW
Main steam mass flow 384 kg/s
Main steam temperature 540 °C
Main steam pressure 274 bar
Reheat temperature 540 °C
Reheat pressure 55 bar
Gross output at terminals 450 MW
Net output at terminals 420 MW
Max. district heat extraction 270 MW
(at a gross output at terminals of: 392 MW)
The power plant burns a mixture of German hard coals with a low ash and
sulfur content (see Table 2) . It operates primarily in the lower inter-
mediate load range and is frequently shut down at weekends and at night.
Table 2
COAL ANALYSIS (AVERAGE VALUES)
Water 8.51 %
Ash (free of water) 7.52 %
Volatile substances (free of water and ash) 28.44 %
C content 73.46 %
H content 4.32 %
N content 1.54 %
S content 0.96 %
Net calorific value 28.99 MJ/kg
FLUE GAS CLEANING FACILITIES
Table 3 correlates the applicalbe emission limits in Germany with the
flue gas values at the boiler outlet and at the stack of Zolling Power
Plant:
4B-43
-------
Table 3
Dimension Raw gas Limit Clean gas
mg/mN3 (6% O2) 650 200 190
mg/mN3 (6% 02) 1,900 400*' 200
Dust mg/mN3 (6% O2) 7,100 50 5
) but at least 85% SO2 separation
NO
SO
To ensure conformance with the applicable limits, the power plant is
equipped with a high-dust DeNOx plant, an electrostatic precipitator and
a flue gas desulfurization plant (FGD) , the arrangement of which is
shown in Fig. 2.
Figure 2. Flue Gas Flow Diagram
The following in-furnace N0x controls are also incorporated into the
boiler:
Dynamic classifier for finer pulverization
Low-NOx burners for quasi-stoichiometric combustion
Air staging with over fire air
4B-44
-------
These primary measures result in a flue gas N0x content of about 650 mg
NO2/mN3 (6% O2) at the boiler outlet, together with a low nonburned
residue content of the fly-ash (less then 3%) [1, 2].
DENOx PLANT
Zolling power plant initially went into operation without a DeNOx plant,
but a retrofit was rendered necessary by increasingly stringent NOx
limits.
With a view to linking the boiler outlet and the air preheaters, we
selected the high-dust configuration (see Fig. 2), which is more favor-
able from the energy point of view.
We decided on plate-type catalytic converters on account of their
superior corrosion resistance and lower pressure losses. The main design
data of the DeNOx plant are summarized in Table 4.
Table 4
DESIGN DATA OF DENOx PLANT
Flue gas volumetric flow (damp) 400 mN3/s
Flue gas temperature min./max. 300 °C/ 400 °C
NOX reduction 70 %
Max. NH3 slip after 12,000 hours of operation 5 ppm
Volume of catalytic material 522 m3
Specific surface area of catalytic material 330 m2/m3
OPERATING RESULTS
The objective of 70% NOx reduction was reached without difficulty throu-
ghout the service life of the catalysts (approximately 12,000 hours).
Activity checks carried out on the catalysts showed that deactivation
took place much more slowly than had been postulated in their design
(Fig. 3) . After 12,000 hours of operation, the remaining activity of the
catalysts was still 94% of the original value. This minimal drop in
catalyst activity resulted in only a small increase in the ammonia
content of the fly-ash from about 4 mg NH3/kg at the start to around 10
mg/kg prior to the catalyst replacement. Figure 4 shows the increase in
ammonia content of the fly-ash in the first quarter of 1990; these
values point to an NH3 slip of approximately 0.5 ppm.
4B-45
-------
110
100
.
CO
0)
CC
90
80
Actual activity deterioration
Designed activity deterioration
no
100
90
80
5 000
10 000
70
15 000
Hours of operation [h]
Figure 3. Activity Deterioration of Catalyst at Zolling Power Plant
30
20
E
Q.
a..
m'
15
o
10
Ammonia concentration
of fly-ash
Linear regression
30
25
20
15
10
" I I I I I""" I I
01.01. 15,01. 31.01. 15.02. 28.02. 15.03. 31.03. 15,04. 30.04.
Spot-check analyses 1990
Figure 4. Ammonia Concentration in Fly-Ash Prior to Catalyst Replacement
4B-46
-------
Throghout the entire duration of operation, no problems were encountered
with fly-ash deposits on the catalytic material; at the full-load duty
point the pressure loss across all the catalyst layers (htotal = 2m) re-
mained virtually constant at 3 mbar for the entire 12,000 hours of
operation.
After only a short period of operation all these positive aspects were,
however, overshadowed by the emission of acidic particles, which caused
damage to the paintwork of cars parked in the vicinity of the power
plant and jeopardized the good reputation of our power plant.
S03 GENERATION
After extensive investigations and measurements it became apparent that
the emission of acidic particles was the result of oxidation of SO2 to
S03 in the DeNOx catalytic converters. This sulfur trioxid subsequently
reacts with the steam, of which there is plenty in the flue gas, to form
gaseous sulfuric acid.
The S02 conversion rate K (S02) is applied to quantify the oxidation of
S02 to S03
K (S02) = - — — - - X 100%
2^
' a' downstream catalyst ' 3' upstream catalyst
upstream catalyst
with the C (SO2) and C (SO3) concentrations entered in ppm.
The following parameters have a significant effect on the conversion
rate (cf. [3]) :
The chemical composition of the catalytic substance -
particularly the vanadium pentoxide content
The ratio of the surface area of the catalytic material to
the flue gas volumetric flow
The flue gas conditions, particularly the temperature
Figure 5 shows, as a function of the flue gas temperature, the S03
concentration C (SO3) measured upstream and downstream of the catalytic
converters in the course of the investigations.
4B-47
-------
30
20 -
E
CL
Q.
1__
CO
O
05
O
15 -
10 -
5 -
upstream of catalyst
downstream of catalyst
O
30
- 25
- 20
- 15
- 10
- 5
A /-^
JO
' O O
300
320
340 360
Flue Gas Temperature [°C]
380
400
Figure 5. SO3 Concentration in the Flue Gas
It became apparent that the SO3 concentration in the flue gas was raised
considerably by the DeNOx catalytic converters, and that there was a
noticeable dependence on the flue gas temperature. At a flue gas SO2
content of 665 ppm, the SO2 conversion rate calculated for 375 °C was
1.2% and for 405 °C 3.3%.
At low load (120 MW) and temperatures of around 315 °C, the SO3 content
was lower downstream of the DeNOx plant than upstream, i.e. at this duty
point the catalyst stores S03.
S03 CONCENTRATION IN FLUE GAS PATH
In order to better understand the mechanisms involved in the formation
of acidic particles, several series of measurements were taken to deter-
mine the SO3 concentrations at a given time at various points along the
flue gas path downstream of the DeNOx plant. Figure 6 plots the SO3
concentration downstream of the catalytic converter, downstream of the
air preheater, and in the stack (i.e. downstream of the regenerative
gas reheater); this series of measurements begins at low load (110 MW;
flue gas temperature 315 °C) , with a rapid increase to full load between
6.00 and 7.00 a.m., causing the temperature to rise to 375 °C.
4B-48
-------
30
25 -
20 -
Q_
a.
O
CO,
o
10 -
5 -
downstream of catalyst
A
downstream of air preheater
e
in the stack
110MW
315°C
450 MW
375 °C
n r
6 8
Time
10
30
- 25
- 20
- 15
- 10
- 5
Figure 6. SO3 Concentration in the Flue Gas as a Function of Time
GU —
25 -
20 -
Q.
£;
co 15 -
O
CO,
O
10 -
5 -
0
downstream of catalyst
downstream of air preheater
9-
in the stack
B-
250 MW
345 °C
^ L
\ \
12 14
/
/
1
.
1
{
4
/
l
I
1
/
i
l
k"" X-X.
X
""A- — -
~~ — A
450 MW
390 °C
Activation of steam air preheater
I
1 .--.
* ,'
-+''''* V"
- 25
- 20
- 15
- 10
- 5
-
1 1 1 •- o
16 18 20
Time
Figure 7. SO3 Concentration in the Flue Gas as a Function of Time
4B-49
-------
A similar experiment is shown in Figure 7, but in this instance there
was no soot blowing, which meant that the flue gas temperatures were
higher. Starting from 250 MW and tFG = 345 °C, the plant was run up to
full load between 15.30 and 16.00, causing the flue gas temperature to
rise to 390 °C. At 18.00 the flue gas temperature downstream of the air
preheater was raised from 130 °C to 150 °C by activating the steam air
preheaters.
In both cases the SO3 concentration downsream of the DeNOx plant rose
sharply on load increase and stabilized after about 3 to 4 hours at a
somewhat lower level; this phenomenon is the result of thermal desorp-
tion of stored S03 (see Fig. 5) .
The SO3 concentrations downstream of the air preheater were considerably
lower, which can be accounted for by the fact that the temperatures in
the region of the air preheater are below the acid dew point. This
results in sulfuric acid precipitating on the fly-ash, of which there
are large quantities (sulfur content of the fly-ash 0.5%).
The amount of sulfuric acid which precipitates depends to a large
degree on the temperature in the air preheater, as is clearly illustra-
ted in Figure 7. Activating the steam air preheaters, thus causing the
flue gas temperature downstream of the air preheaters to rise from 130
°C to 150 °C, resulted in a decrease in the precipitation of SO3 from
24 ppm at 130 °C to 15 ppm at 150 °C.
The measurements also revealed that almost all of the SO3 still present
in the flue gas downstream of the air preheater precipitates in the
regenerative gas reheater; in all experiments the concentration of
gaseous SO3 in the stack was close to the minimum detectable level
(approximately 0.5 ppm). As there is virtually no fly-ash in the region
of regenerative gas reheater to absorb the precipitated acid fraction,
further investigations were carried out to determine what was happening
to the sulfuric acid.
After one week's operation, a plate was removed from the regenerative
gas reheater. On the cold side of the heat exchanger plate there was an
oily deposit of concentrated sulfuric acid which, extrapolated for the
entire heat transfer surface of the regenerative gas reheater, amounted
to a stored volume of 600 kg of sulfuric acid [3].
Solids such as residual dust, iron oxides and gypsum are deposited in
this acid film. The rotation of the heat transfer plates allows these
acid-soaked particles to pass to the treated gas side of the regenera-
tive gas reheater, where they can break away and, given a sufficient gas
velocity, be carried out of the stack.
Acidic particles were emitted primarily on rapid load increase, particu-
larly on plant run-up after weekend shutdown.
4B-50
-------
MEASURES TO PREVENT ACIDIC EMISSIONS
On the basis ot the investigations, the following steps were taken to
prevent the emission of acidic particles:
Soot blowing was stepped up to ensure that the flue gas
temperature at boiler outlet remains below 380 °C, even at
full load. As Figure 5 shows, this halves the SO3 concentra-
tion downstream of the air preheaters, i.e. it reduces the
SO2 conversion rate from 3.3 % at 400 °C to 1.2%. As Figures
6 and 7 show, most of this SO3 fraction can be seperated
out in the air preheater.
The flue gas temperature downstream of the air preheater
was lowered, but at temperatures of less than 130 °C the
pressure losses began to increase considerably, which was
apparently the result of ammonia bisulfate deposits. The
temperature was therefore raised again to 135 °C.
Baffles were fitted to the floor of the flue gas ducts
upstream and downstream of the regenerative air reheater
for separation of the large particles (see Figure 8).
Figure 8. Baffles for Separation of Large Particles
4B-51
-------
During each weekend shutdown the flue gas ducts in the
region of the regenerative gas reheater were freed of
particles.
The blowing procedure of the regenerative gas reheater was
modified; the hot and cold untreated gas sides are blown
simultaneously so that the loosened particles remain on the
untreated gas side.
The plastic heat exchanger plates were removed from the
regenerative gas reheater in order to reduce cooling and
reheating and to achieve a smaller separator surface.
The facility for drying the treated gas from the FGD plant
using hot, SO3-laden untreated gas was taken out of service.
During each weekend shutdown the regenerative gas reheater
was flushed out with large quantities of low-pressure water
(10 bar). After each flushing cycle (duration 3 hours,
volume of water around 150 m3) , the pH of the water dischar-
ged was measured; the flushing process was terminated as
soon as a virtually neutral pH (around 6) was reached.
As a result of applying these measures, no emmisions of acidic particles
have been detected since April 1989. However, the effort involved and
the damage done to the plant components by the sulfuric acid (corrosion,
shortening of service life, etc.) are tremendous. It was therefore
decided that, in the long term, the catalyst would have to be replaced
by a type with a lower conversion rate.
THE NEW CATALYST
Our Japanese suppliers, like all well-known manufacturers of catalytic
converters, invested a lot of effort in developing a low-conversion
catalyst.
Since the reduction of NO by NH3 takes place on the surface of the
catalyst, while the oxidation of SO2 to SO3 is a volumetric reaction,
i.e. it increases linearly with the volume of the catalytic material,
the plate thickness of the catalytic converters was reduced, thus
decreasing the volume while maintaining the surface area for the DeNO
process.
A further significant reduction in the conversion rate was achieved by
refraining from adding vanadium pentoxide to the catalytic material.
However, this heavy metal promotes DeNOx activity, particularly in the
300 - 370 °C temperature range, this measure resulted in a 10% increase
in the necessary catalyst volume to 574 m3.
4B-52
-------
We were assured that this new catalyst would, at the same NOx reduction
efficiency of 70%, have a maximum ammonia slip of 5 ppm after 16,000
hours of operation. An SO2 conversion rate of 0.9% at 400 °C was antici-
pated; inservice measurements under normal power plant conditions
yielded values of around 0.7%. Right from the start, however, a notice-
ably higher NH3 slip of about 1.5 ppm was registered.
FIRST OPERATING RESULTS WITH THE NEW CATALYST
The catalyst was replaced during the unit outage in June/July 1990.
Acceptance testing was performed in September 1990 with the following
results:
The catalyst achieves the required N0x reduction without the increased
NH3 slip anticipated on the basis of the experimental measurements. Spot
measurements showed the maximum to be 0.5 ppm NH3 and the average 0.3
ppm. These values were confirmed by the fact that the NH3 content of the
fly-ash after catalyst replacement (Figure 9) is similar to that prior
to replacement (Figure 4).
Figure 10 presents the results of the SO3 measurements upstream and
downstream of the catalytic converter.
30
25 -
20
E
Q.
a.
co"
Z^
o
15
10
Ammonia concentration
of fly—ash
Linear regression
15.08. 31.08. 15.09, 30.09. 15,10. 31.10. 15.11. 30.11. 15.12. 31.12. 15.01. 31.01.
Spot-check analyses 1990/1991
Figure 9. NH3 Concentration in the Fly-Ash after Catalyst Replacement
4B-53
-------
30
25 -
20 -
E
Q_
Q.
(FT
o
c/^
O
15 -
10 -
upstream of catalyst
downstream of catalyst
30
- 20
- 15
- 10
- 5
300
320
340
~
360
380
400
O-*>_> O'-'VJ
Flue Gas Temperature [°C]
Figure 10. SO3 Concentration in the Flue Gas
At a constant SO3 content upstream of the catalytic converter, the
values downstream of the DeNOx plant are considerably lower than those
shown in Figure 5. At 394 °C, only 7 ppm were measured (old catalyst >15
ppm) , thus confirming the SO2 conversion rate of 0.7% at 400 °C in actual
power plant operation.
As was the case with the old catalyst, storage of SO3 occured in the low
load range (tFG = 315 °C) . Figure 11 reveals the surprising fact that no
detectable release of the stored SO3 was observed on load increase from
200 to 450 MW.
Figure 11 also shows that the SO3 concentration downstream of the air
preheater is close to the minimum detectable level of about 0.3 ppm. It
should be added that, under all load conditions, the gaseous SO3 and
sulfuric acid aerosols detected in the flue gas ducts downstream of the
air preheater were always in the minimum detectable range.
As anticipated, the total S03 fraction can therefore be separated out
in the air preheater by reducing the temperatures to values below the
acid dew point. The fly-ash analyses confirm that the S03 content of the
flue gas upstream of the air preheater is now considerably lower; at
otherwise constant values, the sulfur content dropped from 0.5% to 0.3%.
4B-54
-------
Q.
CL
o
CO.
o
5 -
0 -
0 -
5 -
upstream of catalyst
A
downstream of catalyst
e —
downstream of air preheater
E
200 MW
310°C
450 MW
365 °C
__ _-e"''
i
2 4
- 25
- 20
- 15
- 10
- 5
III u
6 8 10 12
Time
Figure 11. SO3 Concentration in the Flue Gas Path as a Function of Time
Since catalyst replacement, there has apparently been no further preci-
pitation of sulfuric acid in the regenerative gas reheater. On flushing
the regenerative gas reheater with LP water, the first water discharged
was found to be approximately neutral (pH > 4.5), so it was decided to
extend the flushing intervals.
To summarize, the SO2 conversion rate is one of the most significant
criteria to be considered when selecting a high-dust catalytic con-
verter.
Our experience with a low-conversion catalyst has shown that a trouble-
free operation of the DeNOx plant is possible, without risk of the
emission of acidic particles.
REFERENCES
1. G. Musset, U. Schroder, E. Swoboda and D. Kiefer. "Operating Experi-
ence with the Low-NOx Firing Concept in Unit 5 of the Leiningerwerk
Power Plant of Isar-Amperwerke AG"-VGB-Kraftwerkstechnik. Vol. 69,
No. 4, April 1989.
2. R. Jaerschky and A. Merz. "NOx Reduction at Zolling Power Station
Pre-Combustion and In-Furnace Measures, SCR Catalyst Equipment".
ASME Paper 90-JPGC/FACT. October 1990.
4B-55
-------
H. Gutberlet, A. Dieckmann, A. Merz and L. Schreiber. "SO2 Konver-
sionsrate von DeNOx-Katalysatoren - Messung und Auswirkung auf nach-
geschaltete Anlagenteile"- Chemie im Kraftwerk 1989. pp. 86-96.
4B-56
-------
SCR OPERATING EXPERIENCE ON COAL-FIRED BOILERS
AND RECENT PROGRESS
Edward S. Behrens
Joy Environmental Equipment Company
Monrovia, California
Senichi Ikeda
Electric Power Development Company
Tokyo, Japan
Teruo Yamashita
Idemitsu Kosan KK.
Chita, Japan
Gunther Mittelbach, PhD
Deutsche Babcock Anlagen AG
Krefeld, Germany
Makoto Yanai, PhD
Kawasaki Heavy Industries, Ltd.
Kobe, Japan
-------
1.0 - INTRODUCTION
Selective Catalytic Reduction (SCR) technology development traces
its roots back to the early 1970's. Its use for NOX reduction in
oil- and gas-fired energy-conversion plants has long been widely
accepted as Best Available Control Technology (BACT) by many U.S.
regulatory bodies. Its acceptance on coal-fired plants overseas
has demonstrated its ability to reduce NOX from these fuels. But
its acceptance in the U.S. for coal-fired power generation has
lagged somewhat due, in part, to perceived problems revolving
around the typically hightr sulfur coals found here. Nevertheless
over 50 commercial coal-fired plants overseas are proving that with
proper physical and chemical catalyst designs and operation these
perceived problems can be overcome. This paper will detail the
operating experience of three coal-fired commercial power plants
using this technology to successfully control their NOX emissions
and present an up-to-date review of SCR technology.
2.0 - COAL-FIRED SCR OPERATING EXPERIENCE
Detailed below are the design specifications and operating results
of SCRs in thr^^ -oal-fired power plants in Japan and Germany
including other items of operational interest with respect to
experience with the SCRs installed.
2.1 - Takehara Power Station
Electric Power Development Company's Takehara Power Station, Unit
1, in Hiroshima, Japan is a 250-MW, coal-fired boiler burning 2.3-
to 2.5-percent sulfur coal. It uses hot-side low-dust SCR
arrangements in two parallel SCR reactors A+B, each handling 50
percent of the flue gas. The reactor B SCR was placed in service
in 1981, and the current catalyst charge has been in service since
1985 using Type 470 catalyst elements having a 7 mm pitch. The
SCRs are located downstream of the hot-side electrostatic
precipitator (ESP) and upstream of the air preheater. Flue-gas
temperature is 658'! (348'C) with a NOX removal efficiency of 80
percent at full load.
Figure 1 is a photo of the downflow reactor at Takehara, and Figure
2 is a sectional elevation of the SCR reactor showing three layers
of catalyst and the vertical vanes used to assure proper gas-flow
distribution. Figure 3 is a computer generated diagram of the SCR
gas-flow showing even gas distribution across the catalyst modules.
Catalyst modules are loaded from the side of the reactor by means
of a fork-lift track assembly.
4B-59
-------
The Takehara SCR unit 1-B
FIGURE #1
Sectional Elevation of The
Takehara SCR unit 1-B
FIGURE #2
Gass Flow Analysis of
Takehara Reactor Unit 1-B
I
;;;iiS%|£&nr Vv
FIGURE #3
4B-60
-------
Figure 4 shows fine dust deposition from the ESP on the top
catalyst module after 34,000 hours of operation using the current
large openings, Type 470, 7 mm catalyst type which is a thin-wall
catalyst. Flyash from the ESP is very fine and is highly adhesive,
and is one of the reasons a high opening type 470 catalyst was
selected. Despite the high SO2 levels (1800 ppm) entering the SCR
no plugging of the air preheater by ammonium salts has been
observed. No additional preheater washings have been necessary.
This is accomplished by maintaining low NH3 slip levels.
Typical ash deposit with no sool blowing
after 34,000 hr. operation at Takthara.
FIGURE #4
Table 1 details design data and Table 2 shows actual performance
results from annual performance tests of the SCR at the Takehara
Power Station.
Lo«d fMW« par SCR)
C*» Flow (Bcfat
T«*p«r«tur« (T)
NO, In (ppwvd)'
SO, In (ppmvd)
SOj conwrvion (%)
fly A*h (gr/icf) dry
D*HO, Efficiency (%)
HH, Slip Ippwvd)'
HO, Out ( ppWd )
CltalysC d«lt* P tin K,0)
Cacjiyvc contact ar«« |MJ/MJ)
125
253,435
659
300
1150
0.5
0. 04
80
Corr»ct»d to 6%
b»for« C»t»ly«t
4B-61
-------
TABLE 2
TAKEHARA UNIT 1-B SCR PERFORMANCE TEST RESULT
Cat vcliiM
G»« TeKMratur*
NO, 1=
NO, Out
D»NO, t'flciency
Slip ST
Slip KB.
x 1,
•r
pp»
PP«
*
ppa
PP»
000 SCFM
(«% Oj)
(6* Oj)
(6» Oj)
(design
basis)
DEC.
1985
246
649
306
61
80
0.1
0.1
MOV .
1986
256
669
283
60
79
0.1
0. 1
OCT.
1987
235
649
251
45
82
0.2
0.2
FEB.
1988
246
644
249
52
79
0.1
0.1
OCT.
1988
239
651
270
57
79
0. 1
0.1
OCT.
1989
246
653
315
64
90
0.2
0.2
JUNE
1990
235
660
279
51
82
0.2
0. 2
SO, Ir.
SO, 1=
SO, Out
so,
ppm
ppm
ppm
1,490 1,130
5.2 4.9
7.6 7.4
0.18 0.21
1,340
3.2
3.2
0.08
1,210
.8
4.6
0.15
956
2.2
2.9
0.08
1,040 1,170
2.1 1.8
3.3 2.8
0.12 0.09
Catalyse >u raplaod in th« periodic inspection becvwn Sept«m£«r and November, 1985.
2.2 - HKW Reuter West. Boiler E/D
The po^er station Reuter West of the Berliner Kraft- und Licht AG
in Berlin, Germany does include 2 x 284 MW coal-fired power plants
burning various coals with sulfur contents up to 1.2 percent. The
boilers D and E of those two plants went on the line in 1988 and
has operated about 15,000 hours till November 1990. It is an
example of the hot-side, high-dust SCR arrangement. The SCR reactor
is located between the economizer and the air preheater, upstream
of any particulate-removal or flue gas desulfurization (FGD)
equipment. The flue gas temperature entering the SCR depends upon
coal burned, firing rate, and the condition of the boiler
(dirty/clean); the normal average value is about 360" C. NOX
removal is more than 85% depending on removal requirements; the
average ammonia slip is about 1.5 ppmvd and the SO2 conversion to
SO3 about 0.5 percent.
Figure 5 is a photo of a model of the SCR unit at Reuter West, and
Figure 6 is a sectional elevation of one of the half-capacity SCR
reactors of one boiler. It shows space for three and one-half
layers of catalyst. Layer No. 1 uses only one module while layers
No. 2 and 3 use two modules stacked on top of each other; the
fourth layer is a spare and is currently not used. It is held
vacant for use in future catalyst replacement programs or, if
needed, additional NO removal. Stacking modules facilitates
4B-62
-------
interchangeability of the modules and reflects the fact that
catalyst elements can only be extruded up to about 1 m in length.
The typical level of potential catalyst poisons found in fly ash of
the Ruhr coal (K20 - 4 to 5%; CaO - 6.3%; MgO - 1.5%; P205 - 0.6%)
have not appeared to significantly accelerate catalyst
deterioration. Table 3 shows examples of measured operation dates
of the SCR of one of the boilers at HKW Reuter West.
The SCR at Reuter West
FIGURE #5
im_ ^ t-
Sectional
Elevation
of the SCR at
Rente- "'e_
FIGURE
4B-63
-------
TABLE 3
HVTK Reuter West
Boiler E
Dewag
EXAMPLES
OF MEASUBEB
OPERATION DATA
230
680
5.5
350
865
0.5
5.11
85
1. 1-2. 1
52
f/rf) 427
165
662
6.3
350
865
86
. 7-1.6
50
Load (MHe)
Temperature (F)
Avg. 02t
NO, In (ppmvd)
SO2 In (ppravd)
SO2 conversion (%)
Fly Ash (gr/scf) dry21
DeNO, Efficiency (%)
KH, Slip (ppravd)
NO, Out (ppmvd)
Catalyst contact area
" Corrected to 6* O2
!) Design Condition
31 Measured at 725 "F
The operation experiences are good. The activity losses of the
catalyst which were controlled after about 10,000 hours of
operation were much less than expected. Due to the relatively low
SO2-conversion rate and low NH3-slippage no plugging at the air
preheater has occurred and no washing of it was necessary since the
start up of the plant. The soot blowing of the catalyst layers is
done only one time per week.
2.3 - Aichi Refinery
Idemitsu Kosan KK's Aichi Refinery Boiler No. 4 power unit in
Aichi, Japan is a 40-MW, coal-fired boiler burning 0.4-percent
sulfur coal. It was placed in service in 1986 and uses a hot-side,
high-dust SCR arrangement. The SCR was designed for an efficiency
of about 59 percejit producing an outlet NOX consistently below 90
ppm. Inlet NOX generally ranges between 200 and 250 ppm and the
SCR sometimes operates at >60% NOX removal, maintaining outlet NO
below 90 ppm.
The air preheater is a Lungstron type with coirten elements. This
air preheater was designed to permit NH4SO4 deposition at the cold
side of the hot-side element. Since start-up, there has been no
need for washing between the scheduled annual outages, nor has any
element been replaced or repacked.
4B-64
-------
Aichi No. 4 power unit is the earliest SCR system equipped with a
baghouse downstream. In general, it has been predicted that
baghouses downstream of an SCR would experience increased pressure
drop due to NH3 leakage and SO3 increase by the SCR. However, the
baghouse at Aichi continues to operate without increased pressure
loss, because of the low NH3 slip and low S02 to SO3 conversion.
Figure 7 shows the Aichi boiler and SCR unit. Figure 8 is a
computer-generated gas-flow diagram for this SCR reactor which
utilizes a turning vane to improve distribution minimize gas eddies
and reduce pressure drop, across the catalyst module surface. Once
per day, soot blowers operate to clean the first catalyst layer
only. There has been no observation of catalyst plugging or
increased pressure drop. NH3 in the ash was 28 ppm after 5000
hours of operation.
The SCR at the Aichi Refinery
Gas Dow analysis of the Aichi Reactor
FIGURE #7
FIGURE #8
4B-65
-------
Activity of the catalyst has been tested annually and the activity
loss was very small compared with other high-dust systems (see
figure 10). The major cause of deterioration is deposition of Ca,
and Si on the surface of the catalyst.
As a test, KHI enclosed several catalyst elements of Type 555
geometry, among the usual Type 470 catalyst in the Aichi SCR. This
allows actual exposure of the test catalyst to the flue gas for
extended periods. Inspections of the Type 555 over a three-year
period showed very little plugging. Similar to Type 470 adjacent
to test elements.
Table 4 lists design conditions of the SCR installed at the Aichi
Refinery, Boiler 4.
TXBLE «
Aichi Refinery
Unit 4
Ideaitsu Kohsan Co.
Design Ccnditiona
Load (HW«) 40
Ga« Flow (scfn) 115,965
Temperature (F) 716
Avq. Oj* 3.56
HO, In (ppnvd)' 220
SO, In (ppmvd) 429
SO, conversion (%) 1.2
Fly Ash (gr/scf) dry 8.73 15.28
DeKO, Efficiency (t) 59
HH, Slip (ppavd), 3-5
HO, Out (ppwvd)' 90
Catalyst d«lta P (in H20) 3.1
Catalyst contact ar«« (H2/)*3) 470
1 corr«ct«d to 6% Oz
• Kaximua allowable bafor* Catalyst Replacement
4B-66
-------
2.4 - Present and Possible Future Catalyst Geometries.
Present and possible future catalyst element geometries are shown
in Table 5. The thin-wall elements contemplated for future
installation exhibit improved NOX reduction and reduce S02 to SO3
conversion (see 3.1). The thin-wall geometry is also less prone to
fly ash plugging. Since Type 555 has been successfully tested in
the Aichi reactor, and Type 572, which has a larger void/opening
ratio than Type 555, its future application looks promising.
TABLE 5
Examples of grid honeycomb geometry
Cells per Side
Slaius
Georr... .]
Identification
Wall
Thickness (mm,
Opening
rale (%)
Application
Gas Firing
Boiler / Turbine
Oil Firing Boiler
Diesel
Coal firing Boiler
Municipal Waste
Incinerator
20x20
Conventional
Type 427
1.35
64
21x21
High Opening
Type 470
1.00
71
25)
Conventional
Type 555
1.00
68
c25
Hxjtl Opening
Type 572
0.80
73
35 >
Conventional
Type 751
0.80
64
L35
High Opening
Type 816
0.55
76
4B-67
-------
2.5 - NH3 Injection.
Proper mixing of NOX and NH3 is important to insure required NOX
reduction. Figure 9 shows the NHj injection systems employed at
Takehara and Aichi which provides adjustability for gas
distribution through header regulation and individual orifice
replacement. During start-up of these NH3 injection systems, it is
necessary to fine tune the AIG to ensure performance. However in
smaller plants, like Aichi, it has been demonstrated that the
standard deviation of NH3 distribution is usually within allowable
limits. However, if fine tuning is needed to optimize NH3
distribution, it is easily accomplished.
Typical SCR Ammonia Injection Grid
to Reactor
Flow equalizer
(Pipe grid)
Detail of NH, injection nozzle
FIGURE #9
2.6 - Observed Catalyst Operation
At both Takehara and Aichi, catalyst physical and activity changes
over the life of the catalyst have been carefully monitored. This
is done as part of catalyst management program. Tests are made
annually. Since Takehara is a low-dust installation, erosion, of
course, has not been experienced. At Aichi, some slight erosion
has been noted in the top layer of catalyst, but it has not been
severe and will not compromise anticipated catalyst life.
Deterioration is relatively low for a high dust system. Primary
cause of deactivation is deposition of Ca^i on catalyst surface.
Figure 10 shows the relative catalyst activity reduction for the
three coal-fired plants discussed versus cumulative operating
hours. All three plants exhibit better than expected catalyst
4B-68
-------
activity after 20,000+ hours of operation. Figure 11 shows the KHI
catalyst activity measurement facility, and Figure 12 shows their
erosion simulation facility.
CATALYST ACTIVITY DETERIORATION
FIGURE #10
KHI Catalyst Activity
Test Facility
*— A ^Tcr*-. . ito'flE
KHI Catalyst Erosion
Test Facility
FIGURE #11
FIGURE #12
4B-69
-------
3.0- MODERN SCR TECHNOLOGY
The fundamental basis of SCR technology is based on the catalyzed
reduction of NOX (mixtures of NO2 and NO) with ammonia (NH,) into
innocuous water (H2O) and nitrogen N2) in two general reactions:
NO + NH3 + 1/402 -» N2 + 3/2H2O (main reaction)
NO + NH2 + 2NH3 -"• 2N2 + 3 H2O
NH3 (in the form of liquid anhydrous or aqueous ammonia), which has
been vaporized it is diluted with air. The mixture is injected
into the flue-gas stream. The NH3 is injected upstream of the
catalyst appropriate to NOX removal requirements through a
distribution grid.
3.1 - Catalyst Properties
Ceramic, homogeneous, honeycombed catalyst elements measuring
approximately 6-in. x 6-in. square are extruded up to 39-in. long
(150 mm x 150 mm x 1 m) . Titanium oxide (TiO3) as the base
material and is used to disperse and support the vanadium pentoside
(V2O5) . Tungstein oxide (WO3) provides thermal and mechanical
stability. This titanium-based catalyst has been proven to provide
the highest durability and excellent reactivity. By changing the
mixing ratio of th--> active components, the catalyst can be tailored
to meet specific flue-gas requirements.
The vanadium content controls the reactivity of the catalyst. But
it also catalyzes the oxidation of SO2 to SO3. Therefore in high-
sulfur applications, it is necessary to minimize the vanadium
content. Through homogenous distribution of V2O5 throughout
catalyst elements, activity reduction of possibly low V2O5 catalyst
is minimized.
Within the honeycombed catalyst elements, the incoming NOX/NH3
mixture enters micropores on the catalyst's surface and diffuses
back out after the chemical reactions have taken place within the
catalyst material itself. Therefore one of the goals in catalyst
development has been to attain a good mixture of macro-pores to
support gas diffusion and micro-pores to support the reaction
itself.
Honeycomb pitch (flue-gas passages) can also be varied to
accommodate a range of flue-gas dust loadings. The sectional
geometry of a few of the flue-gas-flow patterns used in these
catalyst elements are shown in Figure 13. Since the effective
depth of catalyst for NOX reduction occurs near the surface
(approximately 0.1 mm deep) it is possible to reduce the catalyst
4B-70
-------
volume if the catalyst surface area is increased by increasing the
number of cells. This produces a smaller cell pitch with thinner
walls. Alternatively, S02 oxidation occurs more slowly and takes
place deep inside the catalyst material. Therefore, the SO, to S03
conversion can be decreased by decreasing inner-wall thickness
without reducing NOx-removal activity.
Honeycomb Catalyst Elements
FIGURE #13
All of these catalyst optimization features must, however, be
tempered in coal-fired applications by the fact that large-passage
honeycomb patterns permit freer flow of the dirtier flue gasses
typically encountered, but they also present less catalytic surface
area for reduction of NOX. In general, erosion-proof catalysts
demonstrate lower activity compared to catalysts used in low-dust
environments such as gas/oil-fired applications. Erosion-proof
catalysts inevitably have a smaller volume of micro-pores, the
major cause of their lower activity. Recent developments have
succeeded in increasing the activity of these lower-activity
catalysts to near optimum levels.
3.2 - Catalyst Modules and Reactor Design
The honeycombed catalyst elements are assembled into steel-cased
modules of the required size, Figure 14, for ease of handling and
installation. Modules can be inserted into the SCR reactor on
rollers or by an overhead crane. Modules are then stacked
horizontally or vertically within the SCR reactor on engineered
support structures. In coal-fired power plants, flue-gas flow is
vertically downward. Figure 15, to facilitate the passage of fly
ash through the catalyst elements with minimum drop out.
Horizontal dimensions of the SCR unit are set to optimize gas
4B-71
-------
velocity pressure drop and distribution through the SCR catalyst
elements; the number of vertical layers of modules (usually 2 to 4)
is determined by the desired NOX removal efficiency and the
temperature of the flue gas. NH3 is introduced at the inlet of the
SCR reactor through an Ammonia Injection Grid (AIG) system which
mixes the NH3 thoroughly with the incoming flue gas before entering
catalyst-module array.
Catalyst Module
FIGURE #14
Typical Downflow SCR System
FIGURE #15
4B-72
-------
3.3 - SCR Catalyst Operating Conditions
Optimum flue-gas temperature for SCR reaction is between 500°F and
800°F (260°C to 427°C). Below this temperature range, chemical
reactivity is impaired, and above it, physical catalyst damage can
occur through sintering. Catalyst degradation can also result from
poisoning through chemical reactions which tend to neutralize the
catalyst's reactivity and masking caused by ammonium bisulfate
(NH4HSO4) , ammonium sulfate ((NH4)2SO4) and fly-ash deposition. Any
of these adverse effects can cause NH3 leakage to increase through
the SCR which is generally limited to <5 ppm for high-sulfur coals.
This occurs because the catalyst has become less reactive, thus
requiring more NH3 to achieve the same NOX removal. Figure 16 shows
NH3 slip increases with time with constant DeNOx. While design
criteria calls for slightly over two year's operation before NH3
slip increases to the 5-ppm level, a predicted mean operating life
of over three years is expected. On the other hand, measured
operating unit experience shows that catalyst life of well over
four years can be anticipated. This is an example of the catalyst
maintenance program used at Aichi.
Aichi SCR Catalyst
'De s igne d
Predicted Me an
. ;i-;^kr1^^---e "l-ioasured Hctual
B 12 IB 2B 24 JB
Cumulative Operation Hours (XI008 hour
InlBl N0«:220 ppm, Outlet N0«:90 ppm, lype-170,
FIGURE #16
Figure 17 shows that the mole relationship between NOX removed and
NH3 consumed is nearly linear except in the high efficiency range.
In order to achieve high removal efficiency with low ammonia slip,
the catalyst volume must be increased. This results in higher SO2
4B-73
-------
to S03 conversion. Increasing temperature also increases SO2 to S03
oxidation. This is, of course, undesirable and should be held to
<3 percent since SO3 promotes the formation of ammonium sulfate and
ammonium bisulfate which can plug downstream heat transfer and
emission-control equipment. For a given catalyst volume a typical
interrelationship of temperature,
reduction is shown in Figure 18.
SO2 to SO3 conversion and NOX
NO, reduction >nd Nil, slip vj. Nil, / NO, mole ratio
100
04 06 08 10
NH-,/NOx Mole Ratio
FIGURE #17
NO, mlucllon and [Mrcrnl SO, cnrnTnlon »!. SCR Icmprrlure
£ 90
u
£ 85
u
UJ
s 80
3
•o -_
o> 75
IT
X
o
Z 70
.
/
/
High sullur /
calalysl /
*
/
/ -**
Lr -.---:''' . '
—
s
to
a
§
U
20 o
1 5 ^
o
1 0 ~.
05 °
600 650 700 750 800
Temperalure (°F)
FIGURE #18
4B-74
-------
Location of the SCR unit within a coal-fired power plant's flue-gas
stream is critical. Three options are available here, Figure .19;
(1) a hot-side, high-dust system is located after the economizer
and upstream of the air preheater and any emission-control
equipment such as an electrostatic precipitator (ESP), baghouse, or
FGD; and (2) A hot-side, low-dust ESP unit; and (3) A cold-side,
low-dust system is located after the air preheater and emission-
control equipment.
BOILER . NH
Hot Side High Dust System
Hot Side Low Dust System
Cold Side Low Dust System
FIGURE #19
In a hot-side, high-dust reactor, a large-pitch catalyst must be
used to accommodate the heavy dust loading. Furthermore,
reactivity of the catalyst is reduced to minimize oxidation of S02
to SO3. Conversely, in a cold-side, low-dust system, most of the
particulates and SO2 have been removed from the flue gas.
Therefore, a small-pitch, high-surface area catalyst can be used.
Generally this requires less catalyst volume, and a more active
catalyst can be used s-nne there is little concern for oxidation of
S02. But the primary advantage of this system as well as the hot-
side low dust system is the reduced deterioration rate of the
catalyst. However, reduced operating temperatures can require
reheating the flue gas. In most operating coal-fired power plants
the costs associated with reheating the flue gas outweigh the
savings from reduced catalyst volume and maintenance of the cold-
side SCR.
4B-75
-------
3.4 - Catalyst Module Replacement Schedules
Fifty to 60 percent of the cost of an SCR system lies in the
catalyst. Therefore catalyst life and associated replacement
schedules have a significant impact on the economics of the SCR.
The life limiting factor for these catalyst elements is increasing
NH3 slip with time which should be held to <5 ppm, for coal-fired
hot-side SCRs.
Figure 20 is a typical SCR configuration, and Figure 21 shows two
possible catalyst module replacement programs that can be used.
Cathalyst Module Arrangement
in a typical SCR reactor
NH3 INJECTION CONTROL
SOOT BLOWS
CHTRLYST MODULE
FIGURE #20
In the first example shown, three layers of catalyst modules are
used initially with provision for a fourth layer. When the NH3
slip has reached 5 ppm after approximately 24,000 hours of
operation, a new layer of modules is added in the vacant bottom
position. Then after an additional 16,000 hour of operation or so
when the NH3 slip has again increased, a new top layer of moduler
is installed, replacing the original top layer. When the NH3 slip
again increases after another 16,000 hours of operation, a new
intermediate layer is installed, again replacing one of the
original module layers. In subsequent replacements, a new layer is
added, and the oldest layer is removed.
In the second example shown in Figure 21, the full catalyst charge
is replaced every 24,000 hours. This results in a 70 percent
4B-76
-------
increase in catalyst consumption over life of the plant. But, if
the additional spare layer module replacement program is chosen,
due consideration must be paid to the capability of the ID fan to
accommodate the resultant increased pressure loss caused by the
addition of another catalyst layer.
16 2432 40 49 56 64 7 80
CUHULRTIVE OPERRTION (1000 hour*)
Predicted Progr tm of Ctt•1y11 R«oI «c t ng In High-Dust SCR
FIGURE #21
3.5 - Catalyst Regeneration
During operation, fine dust partical deposit on the catalyst's
surface causing the micropores to plug and reducing activity.
Generally, these particles can be removed, so that the catalyst can
be reused. However, regeneration methods do not fully restore the
original catalytic activity because of such factors as sintering
due to heat, but they do approach it. Currently, it appears that
the best method of catalyst regeneration involves sandblasting,
using a sand grain size of O.lmm which is blown through the
deteriorated catalyst's passages. However, further development of
this technique is required before full commercial practice is
available.
4.0 - CONCLUSION
This operating data on coal-fired commercial power plants burning
medium sulfur coal indicates that SCR is an effective technology
for reducing NOX emission and are not presenting abnormal operating
difficulties due to fly ash or SO2/SO3 in the flue gas, excessive
NH3 slip, nor high SO2 to SO3 conversion.
4B-77
-------
TECHNICAL FEASIBILITY AND COST
OF SCR FOR
U.S. UTILITY APPLICATION
C.P. ROBIE
P.A. IRELAND
UNITED ENGINEERS & CONSTRUCTORS INC
WESTERN OPERATIONS
AND
J.E. CICHANOWICZ
ELECTRIC POWER RESEARCH INSTITUTE
-------
TECHNICAL FEASIBILITY AND COST
OF SCR FOR
U.S. UTILITY APPLICATION
C. P. ROBIE
P. A. IRELAND
UNITED ENGINEERS & CONSTRUCTORS INC.
WESTERN OPERATIONS
AND
J. E. CICHANOWICZ
ELECTRIC POWER RESEARCH INSTITUTE
ABSTRACT
The cost of utilizing Selective Catalytic Reduction (SCR) for NOX reduction in
both new and retrofit applications is presented. Retrofit cases include hot-side
SCR technology applied to both PC and cyclone-fired units and post-FGD SCR
technology applied to a PC-fired unit. Technology status is assessed based
primarily on recent European experience. The impact of operational effects and
resultaot modifications on downstream equipment are included in the analysis.
The hot-side capital costs (December 1989 dollars) range from $78 to $87/kW for
the new PC-fired case, $125 to $140/kW for the retrofit cyclone case, $96 to
$105/kW for the retrofit PC case. The single post-FGD SCR case evaluated is
estimated at $140/kW. The hot-side levelized costs range from 5.3 to 5.9
mills/kWh for the new case, 8.2 to 9.1 mills/kWh for the retrofit cyclone fired
case, and 5.9 to 6.5 mill/kWh for the retrofit PC-fired case. The levelized cost
for the single post-FGD SCR case presented is 6.8 mills/kWh.
INTRODUCTION
The feasibility and cost of applying ammonia-based selective catalytic reduction
(SCR) to control nitrogen oxide (NOJ emissions from power plants firing U.S.
coals is of considerable current interest. Although the NOX control requirements
of the 1990 Clean Air Act Amendments (CAAA) focus on low NOX burner technology
and other forms of combustion control, other factors such as the CAAA NOX
emissions averaging provision, and strict NOX control requirements considered by
various state and local regulatory agencies provide the prospect of SCR
application in the U.S. In fact, applications for several low sulfur coal-fired
facilities developed by independent power producers in selected northeastern
states either require SCR, or a detailed, factual accounting of the feasibility
of SCR for the site. The considerable extent of SCR application in Japan and
Europe for low sulfur fuels has been a significant factor in promoting the
application of this technology in the U.S.
This paper completes the presentation of data from an EPRI-funded activity to
evaluate the feasibility and cost for various potential applications of SCR.
4B-81
-------
This study addresses the following six applications, proposed as representing the
range of potential SCR applications:
1. New Plant low sulfur coal
2. New Plant high sulfur coal
3. Retrofit cyclone boiler, high sulfur coal
4. Retrofit conventional (wall or T-fired) boiler, high sulfur coal
5. Retrofit post-FGD (e.g. reactor following S02 scrubber)
6. Retrofit oil-fired boiler
Results for cases 4 and 6 were reported at the 1989 Symposium (8). This paper
summarizes results for cases 2, 3, and 5, with limited case 4 results repeated
for comparison.
DESIGN PREMISES
Key design Assumptions. SCR costs are significantly influenced by several key
design assumptions. The most important design variables used in this study are:
1. Catalyst life Several coal-fired European SCR installations have
operated for over two years without catalyst replacement and only
moderate measured loss in activity. A catalyst life of four years for
coal-fired hot-side SCR applications and four years for post-FGD SCR
applications has been used in this evaluation.
2. Catalyst cost Catalyst costs in Europe have decreased since 1985 by a
factor of approximately 2.5, primarily due to a very competitive supply
situation. Accordingly, this evaluation covers catalyst costs from
$330/ft3 to $660/ft3, covering the range seen in Europe.
3. Ammonia slip Ammonia slip in European SCR installations is typically
specified at 5 ppm, while some utilities recommend even lower levels (2
ppm). For several coal cases in this study, both 5 ppm and 2 ppm slips
have been evaluated.
4. Space Velocity Advances have been made in catalyst formulation to
minimize S02 to S03 conversion, to develop smaller pitches and to
provide resistance to fouling by trace elements. These various advances
are reflected in the space velocities used for the cases evaluated.
Case Definition. In order to develop representative costs for both the new and
retrofit SCR study cases, typical power plant layouts and design conditions were
selected. In the case of the retrofits, actual U.S. power plant layouts provided
the basis for design conditions selected. For the new plant application, design
conditions and layout were selected based on similar EPRI studies evaluating the
cost of flue gas desulfurization processes. Six study cases were evaluated in
this study, however, only Cases 2 to 5 are the subject of this paper and are
described in Table 1. General arrangement drawings for the study cases evaluated
in this paper are provided in Figures 1 to 4.
For the conventional hot-side SCR applications (reactor between economizer exit
and air heater inlet), the reactors were located above the particulate collection
device. In the post-FGD application, a wet FGD system precedes the reactors
which were placed above the heat recovery units (Gas-Gas-Heaters).
4B-82
-------
SCR Process Design. To obtain budgetary SCR system costs, a performance
specification for the catalyst and reactor was developed for each case. The
specifications were developed using fuel analyses, plant performance and
emissions data, and desired control of NOX, residual NH3, and byproduct S03.
Included in the specification was variation in certain process variables such as
NOX removal and ammonia slip for selected cases. Three SCR system suppliers
provided quotations to these specifications.
The design basis and vendor supplied design data for each of the cases evaluated
in this paper are shown in Table 2. Sensitivity analyses are provided for the
new plant, hot-side design (Case 2) and the cyclone-fired, hot-side retrofit
design (Case 3), to show the cost and performance impacts of reducing the ammonia
slip from 5 to 2 ppmvd. For retrofit of hot-side SCR to a conventional
pulverized coal-fired boiler (Case 4), the effect of reducing the uncontrolled
NOX emission rate (by adding combustion controls) while still meeting the same
NOX emission limit is evaluated; specifically, lowering uncontrolled NOX emission
rate from 0.60 to 0.40 Ib NOX/MM Btu reduces the SCR NOX removal from 80% to 70%.
Consistent with typical practice, one reactor per air heater was used as the
design basis; the cyclone-fired retrofit (Case 3) uses a single reactor (1 x 100%
tubular air neater), while the other hot-side SCR cases utilize two reactors (2 x
50% trisector air heaters). The post-FGD case utilizes twin reactors because two
(2 x 50%) Ljungstrom heat recovery units were utilized.
The hot-side applications utilize downflow reactors, with additional capacity to
add a spare catalyst layer. Also, steam sootblowers are employed in the design
along with ash hoppers and ash transfer equipment. In the post-FGD application
the reactor is also designed as a downflow unit with capacity to add a spare
layer. The post-FGD reactor design does not require sootblowers and ash
collection hoppers.
The hot-side cases employ a catalyst with a 7.07 mm pitch (20 x 20 grid) while
the post-FGD case employs a catalyst with a 4.2 MM pitch (35 x 35 grid). The
lower pitch (higher specific area) and higher activity (per unit volume) of the
post-FGD catalyst allows a space velocity considerably higher than required for
the hot-side cases.
The ammonia storage and supply systems were designed using a truck unloading
station and a storage island providing seven days storage at an MCR rating.
Steam vaporizers are utilized for ammonia vaporization and dilution air is
provided from the discharge of the primary air fans in the hot-side cases, while
the post-FGD case utilizes separate dilution air fans.
SCR PROCESS IMPACT
The hot-side SCR process, because of its location directly downstream of the
boiler and upstream of the air heater, impacts every component of the flue gas
train and the boiler itself through its effect on the air heater (and in some
cases the economizer). The degree of impact varies with power plant
configuration, environmental control components, type of fuel, and emission
control requirements. The post-FGD SCR process impact is much less severe
because of its location at the end of the flue gas train.
Hot-Side SCR (coal) Impact
The impacts of hot-side SCR in coal-fired applications are summarized on Figure
5. The principal impacts are on the boiler, air heater and ID fan. Other
4B-83
-------
impacts are on the particulate collection device (ESP), wet limestone flue gas
desulfurization (FGD) process, FGD reheat system, waste disposal system and water
treatment system.
Boiler. The principal effects of hot-side SCR on the boiler will be the loss of
overall thermal efficiency, and additional operations and control complexity,
particularly for cycling units. Also, auxiliary power consumed by the SCR
process will reduce the net generating capacity.
Loss of thermal efficiency results from air heater modifications and an
economizer bypass which will result in higher air heater flue gas exit
temperatures. The result will be loss in the net generating capacity for the
same quantity of fuel consumption.
Air Heater. The potential for formation of ammonium sulfates and bisulfates
coupled with the presence of fly ash necessitates air heater modifications in the
hot-side SCR cases. Modifications to the air heaters in the PC boiler cases
include adding high pressure steam soot blowers at both the cold and hot ends,
adding high pressure water wash capability, replacing 24 gage heat transfer
surface material with 18 gage, replacing intermediate and cold end double
undulating (DU) heat transfer surface with notched flat (NF) surface, and adding
bypasses and dampers for on-line washing capability.
In the cyclone-fired boiler case, to reduce the rate of ammonium compound
deposition and build-up, all the existing 2" diameter tubes in the cold end, and
25% of the tubes in the hot end were replaced with 3" diameter tubes. Also, a
steam soot blowing system utilizing medium pressure superheated steam at both the
hot and cold ends was added to reduce the rate of deposits.
In this case, it is expected that some residual ammonia may be captured by the
FGD system resulting in a build-up of ammonium species in the FGD liquor.
Although this may complicate scrubber sludge reuse or disposal, no cost impact
has been assigned.
Stack. The increase in the flue gas S03 concentration across the SCR could
result in increased opacity of the flue gas plume. Recent data from an EPRI
sponsored study with a member utility shows a direct correlation between stack
opacity and sulfuric acid concentration. To reduce opacity control measures may
be required to reduce the S03 concentration. A typical method of reducing S03 in
the flue gas would be to inject NH3 upstream of the ESP. The specific impacts or
costs associated with this effect have not been evaluated in this study, however.
ID Fan. To overcome additional pressure drop (up to 11" we) associated with the
hot-side SCR, the existing ID fans were modified. For the retrofit cases it was
assumed that new, larger diameter wheels could be placed into the existing fan
housing to overcome the additional static pressure drop. The modifications
included replacing the fan wheel, shaft, bearings and motor.
ESP. SCR effects on the ESP include higher volumetric flowrate, higher negative
operating pressure, higher S03 concentration, higher flue gas temperature and
precipitation of ammonium compounds on fly ash.
Higher flue gas volume (an increase of up to 9.4% in the PC-fired cases) results
from higher flue gas temperature (20°F), lower flue gas static pressure, and
increased mass flow (the latter due to increases air heater leakage and dilution
air), and will have a significant impact on ESP operation. The increase in flue
gas volume will effectively reduce the Specific Collecting Area (SCA) and the
4B-84
-------
concentration of particulate in the flue gas. The result will be that the ESP
may require additional power to deliver the same particulate removal efficiency.
Greater negative operating pressure could require re-enforcement of the ESP.
This effect was not considered in the capital cost analysis.
In the high sulfur coal applications, the S03 concentration in the flue gas is
estimated to increase by 18 ppm across the SCR. Typically, an increase in S03
would be expected to reduce the fly ash resistivity significantly. However, the
increase in the flue gas temperature in the PC-fired cases (to keep the flue gas
above the acid dew point) may counteract the effect of the S03 increase, possibly
producing little net change.
Ammonium compound precipitation on the fly ash typically has a beneficial impact
on ESP performance by helping the fly ash agglomerate, preventing reentrainment.
The cumulative effects of all the above could be significant on an ESP; a pilot
test program would be required to determine actual design and operations impacts.
In this study case it was assumed that the only net effect on the ESP operation
was an increase in power consumption by about 12%.
In the cyclone-fired boiler case the flue gas volume increase is expected to be
3.8%. This result is lower than the PC cases because of a negligible increase in
the leakage rate across the tubular air heater and only an 8°F flue gas
temperature increase at the air heater exit. Only a slight increase in the ESP
power consumption was assumed in this case.
Ash Disposal/Reuse. Ammonium compound content in the fly ash can have an impact
on waste disposal or marketing practices; for example, these compounds decompose
and release ammonia at elevated pH. While Eastern U.S. coals are not alkaline in
nature and ammonia would not be expected to gas off upon wetting, fixation with
alkaline species could result in an ammonia odor problem.
Similarly, reuse options for fly ash contaminated with ammonium compounds may be
limited. Direct use as an admixture in cement manufacturing may be jeopardized
if the ammonium compound content is too high.
FGD/Reheat. The chief effect on the FGD system is an increase in the water
evaporation rate and steam reheat requirement. The higher inlet temperature and
higher mass flow rate will result in an increase in water evaporation in the
absorber, as well as a significant increase in steam use by the FGD reheat system
(SOT reheat assumed).
A slight increase in power consumption could occur from having to increase the
FGD liquor recirculation rate in order to maintain the same S02 removal
efficiency. The higher liquor recirculation rate might be required as a result
of dilution of S02 in the flue gas, and higher flue gas volumetric flow rate
(saturated gas flowrate). This effect was not considered in this analysis.
FD Fan. In the PC-fired boiler cases (e.g. employing Ljungstrom air heaters) the
FD fan will consume slightly more power to account for a higher mass flow rate.
The mass flow increase results from an expected higher air heater leakage rate.
Water Treatment. Introduction of nitrogen species into the air heater wash water
requires additional water treatment equipment. Nitrogen species are introduced
into the wash water as ammonium bisulfate and sulfates. A biological treatment
4B-85
-------
process is utilized to convert the nitrogen species to free nitrogen. The
effluent is assumed to be discharged to the existing on-site water treatment
equipment.
Post-FGD SCR Process Impact
The impact of post-FGD SCR on power plant operations and equipment is less
significant than that expected with hot-side SCR, as the SCR reactor and
ancillary equipment follow all major process equipment. The impacts are shown by
Figure 6.
Boiler. The boiler is affected only insofar as auxiliary power consumption is
increased. The increase in the auxiliary power consumption (reduction in the net
generating capacity) will increase the Net Plant Heat Rate. Natural gas consumed
in elevating the SCR inlet gas temperature will also increase the NPHR.
ID Fan/Booster Fan. The increase in the flue gas pressure drop associated with
the post-FGD SCR process is estimated at 14.5 in w.c. The pressure losses are
principally across the inlet and outlet of the Gas-Gas-Heater (GGH) and the SCR
reactor. Addition of a booster fan into the flue gas train will increase the
complexity in flow and pressure control. In this case the booster fans are
located upstream of the stack; one booster fan is supplied for each SCR reactor
train.
Water Treatment. Nitrogen species will be introduced into the air heater wash
water as a result of ammonium bisulfate deposition on heat transfer surface.
With relatively little S03 capture expected within the FGD system, some
additional S03 generation across the catalyst, and the absence of fly ash, the
rate of chemical deposition on the GGH equipment is expected to be quite
significant. A biological treatment process was included to treat the
wastewater.
FGD. The SCR process affects the FGD system only indirectly. Because of the
location of the GGH, FGD system mist eliminator operation will be critical.
Excessive mist carryover could result in loss of heat recovery (resulting in
increased natural gas consumption) and an increase flue gas pressure drop,
possibly limiting generation capacity in addition to detracting from plant heat
rate.
Stack. Retrofit of the post-FGD SCR process will almost certainly have an impact
on the stack. If the original plant design included a wet stack, the 225°F GGH
exit gas temperature will require liner replacement. In this design case it was
assumed that the original design included steam reheat (50°F) and that the stack
was designed for approximately 180°F. The effect of the increase in the flue gas
temperature to 225°F was considered negligible.
Higher S03 concentration in the flue gas may result from oxidation of S02 across
the catalyst. While some of the S03 is likely to form ammonium/sulfur compounds
and deposit on the GGH surface, there may be a net increase in the SO,
concentration which could increase plume opacity.
COST DEVELOPMENT
To develop total process capital costs, physical layouts of the ductwork and SCR
reactors were developed. From these drawings, lengths of ductwork and structural
requirements were estimated. All costs are presented in December 1989 dollars
4B-86
J3
-------
The operating and capital cost impact of SCR on other plant components was also
estimated. For major pieces of equipment, such as the air heaters, ammonia
storage system and ID fans, vendors were consulted in developing the cost of the
modifications. For smaller equipment items and piping runs, UE&C utilized in-
house data to arrive at equipment costs.
EPRI's Technical Assessment Guide (TAG) provided the basis to estimate fixed
operating and maintenance costs. Variable operating costs were determined by
calculating utility and raw material consumption rates. Considered in the
variable operating costs were the following:
SCR catalyst replacement
Ammonia consumption
Ammonia vaporization steam
Incremental Sootblowing steam
Incremental ID/Booster fan horsepower consumption
Incremental FD fan horsepower consumption
Incremental ESP power consumption
Water treatment chemicals
Air heater efficiency loss
Incremental FGD reheat steam consumption
SCR catalyst disposal
Incremental fly ash disposal cost
Natural gas consumption
RESULTS
Selected results from this study are summarized in Figures 7 to 10, while
sensitivity of results to catalyst cost and life are provided in Figures 11 to
14. Highlights are discussed as follows:
Capital Costs. Total capital requirement (TCR) for each of the cases is
presented, indicating the contribution of the reactor/catalyst, structural
modifications and/or support equipment, air heater, ductwork, NH3 injection, flue
gas handling, and contingencies. Figure 7 shows capital cost is least for new
units, due to the absence of retrofit considerations, and reduced catalyst
quantity from lower boiler exit NOX emissions. These same factors, retrofit
considerations and boiler exit NOX emissions, are responsible for the cyclone
boiler having the highest cost for the hot-side application. Post-FGD capital
cost is high due to the GGH, which adds significantly more cost than is saved
through simplifying reactor design and reduced catalyst quantity.
Decreasing the ammonia slip from 5 to 2 ppm (shown for both cases 2 and 3) is
expected to increase the TCR by about 12% due to a larger catalyst volume
requirement.
The cost impact on the SCR of reducing the boiler NOX emission rate from 0.60 to
0.40 Ib NOX/MM Btu is shown by Case 4.0 and 4.1. Reduction of the boiler NOX
emission rate (through combustion modifications), while meeting the same emission
limit of 0.12 Ib NOX /MM Btu, reduces the SCR capital cost by $9.4/kW.
(Level ized costs reflecting both capital and operating costs must be compared to
judge the full benefit.)
The catalyst and reactor cost represents about 40-50% of the TCR in the hot-side
SCR cases. In the post-FGD SCR case, the catalyst cost represents only about 17%
of the TCR. The largest cost item in the post-FGD SCR case are the twin GGH's
used for heat recovery.
4B-87
-------
The contingency ranges from 14.4% to 18.2%. The highest contingency is assigned
to Case 3 due to uncertainties in high sulfur coal applications, coupled with
tubular air heaters and a very high boiler NOX emission rate.
Levelized Cost. Figure 8 presents levelized costs for the same design cases,
depicting generally the same trends between costs for new units, cyclone boilers,
conventional PC boiler, and post-FGD application. The data shows that variable
operating costs and fixed charges represent about 50% of total levelized cost for
the hot-side application. The most significant component of fixed charge is the
recovery of capital for the reactor and catalyst. Similarly, the most
significant component for variable O&M is catalyst replacement cost. Comparison
of cases 4.0 and 4.1 shows the benefit of adding combustion controls to reduce
the NOX reduction requirement of the SCR; the results indicate that the SCR cost
can be"reduced from 6.54 to 5.88 mills/kWh by reducing the boiler emission rate
from 0.60 to 0.40 Ib NOX/MM Btu. In the case of the post-FGD SCR process, fixed
charges represent about 65% of the total levelized cost. Note that the results
consider a 0.93 mills/kWh credit for a 50°F steam reheat system that is no longer
required upon retrofit of the post-FGD SCR process. This credit would, of
course, not apply for units that employ wet stack operation.
The levelized costs for Case 3.0, the cyclone boiler, are significantly higher
than the costs expected with retrofit to a PC-fired boiler. This is due both to
higher capital requirement and catalyst replacement cost due to the large volume
of catalyst required in this application.
Figure 9 shows levelized costs in terms of $/ton NOX removed. Primarily, the
data shows the impact of the boiler NOX emission rate on the cost to remove a ton
of NOX. The cyclone-fired boiler (Case 3.0) shows the lowest levelized cost
(about $l,100/ton NOX ). Although the cost of SCR for application to cyclone
boilers is significant, the high uncontrolled boiler NOX emissions reduce costs
on a per ton basis.
The highest levelized cost is shown by Case 4.1 where combustion controls were
added to reduce the SCR NOX reduction requirement from 80% to 70%. Lowering the
boiler exit NOX emission rate correspondingly increased costs on a per ton basis.
Figure 10 provides a more detailed cost comparison between a post-FGD and hot-
side SCR process in terms of levelized costs (mills/kWh). The power plant, fuel,
and NOX reduction performance is identical for both cases. The levelized costs
for the two process options are comparable, however, as described earlier, the
reheat credit of 0.93 mills/kWh for the post-FGD process may not be applicable to
specific sites if a wet stack is used. Also, note that a 4-year catalyst life
was used in the post-FGD cost development, six years is closer to the currently
expected life. Catalyst replacement is the most significant O&M cost item for
the hot-side process, while natural gas cost (and heat rate penalty) is the most
significant O&M cost item for the cold-side process.
Effect of Catalyst Life and Unit Costs. Sensitivities of the cost results to
both catalyst cost and life are provided by Figures 11 to 14. Base case
economics were developed assuming a four year catalyst life for both hot-side and
post-FGD SCR processes; a six year catalyst life for the post-FGD SCR is now
being predicted. Base case catalyst cost of $660/ft3 was utilized; this cost
reflected budgetary quotations from the primary U.S. SCR catalyst vendors with
coal-fired experience. It is possible that catalyst costs will approach those in
Europe ($400-450/ft ) due to world market competition.
4B-88
-------
The figures show that the SCR applications which require the largest quantity of
catalyst are most sensitive to both catalyst life and cost. The post-FGD process
(Case 5) is the least sensitive due to its relatively small catalyst charge.
CONCLUSIONS
Conclusions developed from this study are:
• The capital cost of SCR in 500 MW (nominal) size U.S. plants is expected
to be:
A. $96 $105/kW for hot-side retrofits to conventional (tangential or
wall) coal-fired power plants.
B. $125 $140/kW for hot-side retrofits to cyclone-fired boilers.
C. $78-87/kW in new plant hot-side applications.
D. $140/kW for post-FGD retrofits.
t The levelized cost of SCR in U.S. coal-fired power plants (500 MW size
range) is expected to be:
A. 5.3-5.9 mills/kWh for new hot-side power plant applications.
B. 5.9 to 6.5 mills/kWh for hot-side retrofits to conventional-fired
units.
C. 8.2 to 9.1 mills/kWh for hot-side retrofits to cyclone-fired units.
D. Approximately 6.8 mills/kWh for post-FGD retrofits to con-
ventional units assuming a credit for reheat (0.93 mills/kWh).
• The levelized cost of removing a ton of NOX utilizing SCR is expected to
range as follows:
A. $3,300 $3,800/ton NOX for new coal-fired plant hot-side
applications.
B. $1,100 $l,250/ton NOX for coal-fired cyclone boiler hot-side
retrofits.
C. $2,750 $4,250/ton NOX for coal-fired conventional boiler hot-side
retrofits.
D. $2,850/ton NOX for post-FGD SCR retrofit to a conventional boiler.
• The levelized cost of removing a ton of NOX is lowest with high NOX
emission rates. The levelized cost of removing a ton of NOX for a
cyclone-fired boiler with a 1.80 Ib NOX/MM Btu NOX emission rate is
estimated at $l,100/ton NOX.
• The SCR capital cost in a new power plant application is substantially
less than in a retrofit application. The cost of a new plant SCR is
expected to be about 34% lower than a retrofit, the lower cost is due
largely to new boilers having lower NOX emission rates and an attendant
reduced catalyst requirement, and the absence of costly existing
equipment modifications required in SCR retrofit applications.
• SCR capital costs are higher for cyclone-fired boilers because of their
high NOX emission rate. The SCR capital cost for cyclone-fired units is
expected to be about 45% higher than that expected for conventionally-
fired power plants.
• Catalyst life and catalyst unit cost significantly affect levelized
process costs. For most hot-side SCR applications, an increase in
catalyst life from 2 to 4 years reduces levelized cost by 30%. A
reduction in catalyst unit cost from $660/ft3 to $450/ft (for cases
assuming a four year catalyst life) reduces levelized costs by 15%.
4B-89
-------
s The levelized cost of NOX removal for both hot-side and post-FGD SCR
processes is similar, but the components of the cost vary significantly.
Compared to hot-side SCR, post-FGD applications requires 30% more
capital, but feature lower catalyst replacement costs.
REFERENCES
1. Bauer, T. K., Spendle, R. G., "Selective Catalytic Reduction for Coal-Fired
Power Plants: Feasibility and Economics," Stearns-Roger Inc., EPRI CS-3603,
October 1984.
2. Cichanowicz, J. E., Offen, G. P., "Applicability of European SCR Experience
to U.S. Utility Operation," Proceedings: 1987 Joint Symposium on Stationary
NO. Control, EPA/EPRI, New Orleans, 1987.
3. Cichanowicz, J. E. et. al., "Technical Feasibility and Economics of SCR NOX
Control in Utility Applications," Proceedings: 1989 Joint Symposium on
Stationary Combustion NOX Control, EPA/EPRI, March 1989.
4. Electric Power Research Institute (EPRI), TAG Technical Assessment Guide,
Volume I: Electricity Supply - 1986, EPRI P-4463-SR, December 1986.
5. Ellison, W., "Assessment of S02 and NOX Emission Control Technology in
Europe," EPA-600/2-88-013, February 1988.
6. Nakabayashi, Y., Abe, R., "Current Status of SCR in Japan," Proceedings: 1987
Joint Symposium on Stationary NQX Control, EPA/EPRI, New Orleans, 1987.
7. Necker, P., "Operating Experience with the SCR DeNOx Plant in Unit 5 of
Altbach/Deizisau Power Station," Proceedings: 1987 Joint Symposium on
Stationary NOX Control, EPA/EPRI, New Orleans, 1987.
8. Osborn, H. H., "The Effect of Ammonia SCR DeNOx Systems on Ljungstrom Air
Preheaters," C-E Air Preheater, EPRI RP 835-2, June 1979.
Table 1
Case Definition
PLANT DESCRIPTION
Case
Retrofit
Capacity, MW (gross)
Boiler Type
Air Heaters
Participate Control
S02 Control
Reheat
Gross Plant Heat Rate, Btu/kUh
Capacity Factor, %
Remaining Life, years
SITE CONDITIONS
Location
Seismic Zone
Urban Site
FUEL
Type
Area
Higher Heating Value, Btu/lb
Sulfur Content, wt. %
Ash Content, wt. %
2.0
No
546,600
PC
Ljungstrom
Baghouse
Wet FGD
yes
9,137
65
30
Kenosha, WI
I
No
Coal
III i no is No. 6
10,533
3.74
9.51
3.0
Yes
536,000
Cyclone
Tubular
ESP
None
No
9,974
65
20
Kenosha, WI
I
No
Coal
1 1 1 inois No. 6
10,533
3.74
9.51
4.0
Yes
536,000
PC
Ljungstrom
ESP
Wet FGD
Yes
9,197
65
20
Kenosha, WI
I
No
Coal
Appalachian
13,100
2.60
9.10
5.0
Yes
536,000
PC
Ljungstrom
ESP
Wet FGD
Yes
9,197
65
20
Kenosha, WI
j
No
Coal
Appalachian
13,100
2.60
9.10
4B-90
-------
Table 2
SCR Process Design
CD
CD
CASE NUMBER
DESCRIPTION
SCR DESIGN BASIS
Boi ler Type
Economizer Outlet Temp. 3HCR, °F
Economizer Excess Air, %
Boiler NOx Emission Rate, Ib/MM Btu
NOx Concentration, ppmv (actual)
NOx Emission Limit, Ib/MM Btu
NOx Reduction Rate, %
NH3 Slip Rate, ppmvd (3 3% 02)
Guaranteed Catalyst Life, years
Reactor Configuration
Ammonia Storage, days
SCR DESIGN
Space Velocity, SCF*/ft3-hr
Linear Velocity, actual fps
Operating Temperature, °F
S02 Oxidation rate, %
Catalyst Geometry
Surface Area, m2/m3
Pitch, mm
Catalyst Layers (active + spare)
Soot Blowers
Ammonia Consumption, Ib/hr
Gas-Gas-Heater (GGH)
-Number
-Untreated Gas In/Out, °F
-Treated Gas In/Out, °F
SCR COST DEVELOPMENT
Catalyst Cost, $/ft3
Expected Catalyst Life, years
Ammonia Cost, $/ton
Natural Gas Cost, $/MM Btu
Plant Life, years
Capacity Factor, %
2.0
New,
hot-side
PC
725
24
0.40
364
0.08
80
5
2
Twin,
Vertical
7
2,750
18.2
725
1.10
Grid
470
7.07
4 + 1
Yes
941.4
NA
NA
NA
660
4
145
NA
30
65
2.1
New,
hot-side
PC
725
24
0.40
364
0.08
80
2
2
Twin,
Vertical
7
2,300
18.2
725
1.20
Grid
470
7.07
4 + 1
Yes
932.3
NA
NA
NA
660
4
145
NA
30
65
3.0
Retrofit,
hot -side
Cyclone
682
20
1.80
1700
0.36
80
5
2
Single,
Vertical
7
1,800
18.2
682
1.10
Grid
470
7.07
6 + 1
Yes
4,478
NA
NA
NA
660
4
145
NA
20
65
3.1
Retrofit,
hot-side
Cyclone
682
20
1.80
1700
0.36
80
2
2
Single,
Vertical
7
1,500
18.2
682
1.10
Grid
470
7.07
6 + 1
Yes
4,468
NA
NA
NA
660
4
145
NA
20
65
4.0
Retrofit,
hot -side
PC
725
24
0.60
572
0.12
80
5
2
Twin,
Vertical
7
2,530
18.2
725
1.20
Grid
470
7.07
4 + 1
Yes
1,383
NA
NA
NA
660
4
145
NA
20
65
4.1
Retrofit,
hot -side
PC
725
24
0.40
381
0.12
70
5
2
Twin,
Vertical
7
2,960
18.2
725
1.20
Grid
470
7.07
4 + 1
Yes
807
NA
NA
NA
660
4
145
NA
20
65
5.0
Retrofit,
cold-side
PC
NA
24
0.60
428
0.12
80
5
2
Twin,
Vertical
7
6,000
22.0
625
0.39
Grid
795
4.2
2 + 1
No
1,383
2 X 50%
129/550
625/226
660
4
145
2.98
20
65
* SCF 3 32°F
-------
^BOILER
PLAN
TQS, EL22Q'-Q'
ELEVATION
rSS
Figure 1. Case 2 Plan and Elevation General Arrangements.
4B-92
-------
BOILER ROOM
UNIT NO I
BOILER ROOM
UNIT NO 2
: SCR
- REACTOR
60'-O
/IAN
PHECIPITATOR NO 1
\ /
PRECIPITATOR NO 2
.
STACK
A
ELEVATION LOOKING WEST
Figure 2. Case 3 Plan and Elevation General Arrangements.
4B-93
-------
ELEVATION
Figure 3. Case 4 Elevation General Arrangement.
Figure 4. Case 5 Plan General Arrangement,
4B-94
-------
03
CD
Oi
AIR HEATER
Ammonium Blsulfate •
Fouling ,
Higher Exit Gas Temp. ,
Higher Leakage
Higher AP
Higher Steam Sootblow Rate
Higher Water Wash Rate
Higher Steam pressure &
Superheat
Additional Dampers For
On-Llne Wash
BOILER
NPHR Increase
Temp. Bypass
Reduced KW
FD FAN
• Higher Mass Flow •
• Provide Dilution Air •
• Higher Hp Consumption •
AMMONIA STORAGE •
• Operator Training •
& safety
WATER TREATMENT •
• Treat AH Wash For •
Nitrogen .
ESP
Higher Inlet Gas Volume
Higher Gas Temp.
SO3 NH3 Conditioning
Higher AP
Resistivity Affected
FLY ASH
Marketability Impact
Odor Problems
Additional Equipment
For SCR
ID FAN
Higher Mass Flow •
Higher Volumetric Flow •
Higher AP
REHEAT
Higher Mass Flow
Increased Steam Usage
FGD
Volume Increase
Higher Inlet Temp.
Increase In H2O Evap.
SOj Concentration Dilution
FGD Wastewater Treatment
For NH3
STACK
Increased Opacity
Higher SO3
FD FANS
ChD
WATER TREATMENT
TO EXISTING
W & WM SYSTEM
ID FAN
J » WASTE TO
DEWATERING
Figure 5. Hot-side SCR Design/Operations Impact.
-------
PLANT
• NPHR Increase
• Reduced Kw
• Natural Gas Supply
Required
• Additional Plant
Complexity
WATER TREATMENT
• Treat GGH Water Wash
tor Nitrogen
Compounds
FGD
Mist Eliminator
Operation Critical
AMMONIA STORAGE
• Operator Training & Storage
STACK
• Higher SO3
• Increased Temperature
• Increased Opacity
• Increased Volume
CD
CD
PILUTIQN
AIR FAN
FD FAN
TO EXISTING
W & WM SYSTEM
WATER TREATMENT
Figure 6. Post-FGD SCR Design/Operations Impact.
-------
160
Total Capital Requirement, $/kW
10
Mllls/kWh
5.91
5.32
COST ITEMS
KUl CONTINGENCY
FACILITIES,ENG.,FEE
HZ] ID FAN.WiWM.REHEAT
dl AIR HEATER/GGH
^M STRUCTURAL
CU DUCTWORK
KS NH3 STORAGE
•• REACTOR/CATALYST
2.0 2.1 3.0 3.1 4.0 4.1
CASE
5.0
Figure 7. Total Capital Requirement.
9.08
8.17
6.54
6.76
5.88
COST ITEMS
HZ] FIXED CHARGES
•^ VARIABLE O&M
•I FIXED O&M
2.0 2.1 3.0 3.1 4.0 4.1 5.0
CASE
Figure 8. Levelized Cost (mills/kWh).
4B-97
-------
$/ton NOx Removed (Thousands)
4255
1227
2.0 2.1 3.0 3.1 4.0 4.1
CASE
COST ITEMS
I I FIXED CHARGES
•Jj VARIABLE O&M
•I FIXED O&M
Figure 9. Levelized Cost ($/ton NOx removed).
Mills/kWh
u
8
6
4
0
n
o
it
B
6.54
Hi
i
1
^
1
7 68
««f
-0.9C
H
M
1
3
COST ITEMS
EFFICIENCY LOSS/GAIN
1 i W&WM, STEAM
CD NATURAL GAS
POWER
1 1 CATALYST
,™™
CASE 4.0 CASE 5.0
Figure 10. Hot-Side vs Post-FGD SCR Cost Comparison.
4B-98
-------
10
$/ton NOx Removed (thousands)
23456
Catalyst Life, years
— Case 2
-*— Case 3
~*~ Case 4
-B- Case 5
Figure 11. Levelized $/ton NOx versus Catalyst Life.
20
15
10
Levelized Mills/kWh
23456
Catalyst Life, years
Case 2
Case 3
Case 4
Case 5
Figure 12. Levelized Mills/kWh versus Catalyst Life.
4B-99
-------
Levelized Mills/kWh
300
400 500 600
Catalyst Cost, $/ft3
700
Case 2
Case 3
Case 4
Case 5
Figure 13. Levelized Mills/kWh versus Catalyst Cost.
Total Capital Requirement, $/kW
300
400 500 600
Catalyst Cost, $/ft3
700
r
Case 2
Case 3
Case 4
Case 5
Figure 14. Total Capital Requirement versus Catalyst Cost.
4B-100
-------
APPLICATION OF COMPOSITE NOX SCR CATALYSTS IN
COMMERCIAL SYSTEMS
B.K. Speronello, J.M. Chen, M. Durilla, R.M. Heck
Engelhard Corporation
101 Wood Avenue South
Iselin, NJ 08830
-------
Application Of Composite NOx SCR Catalysts In Commercial Systems
B.K. Speronello, J.M. Chen, M. Durilla, R.M. Heck
Engelhard Corporation
101 Wood Avenue South
Iselin, NJ 08830
Abstract
Composite NOx SCR catalysts have been installed in a variety of
commercial NOx control systems, including coal fired power plants,
gas turbines, stationary engines, and chemical plants. This paper
reviews how such catalysts performed in these systems, and it relates
key features of the composite catalyst design to catalyst
performance. These data illustrate how composite SCR catalysts can
cut catalyst volume and reactor size by over 50% (relative to
conventional SCR catalysts), with no loss of NOx removal efficiency.
Background
The term composite honeycomb catalyst refers to a catalyst design
strategy where a layer of catalytic material is bonded to a strong,
thin-walled honeycomb support. This design has been used for years
to treat exhaust from a variety of sources, including: stationary
internal combustion engines1, gas turbines^, chemical
processes3, and, most notably, automobiles4- In 1984, Engelhard
developed a composite catalyst for the selective catalytic reduction
(SCR) of NOx by ammonia^. This catalyst contains a catalytic layer
of V205/Ti02 (V/Ti) supported on a cordierite ceramic honeycomb.
Recently, a composite zeolite SCR catalyst was developed to extend
the maximum operating temperature for the SCR reaction from nominally
450°C up to 600°C.
To date, composite catalysts have been demonstrated in 10 pilot tests
(see Table I) and 12 commercial installations (see Table II). In
addition, Table II lists another 12 commercial installations in
varying stages of design and construction. Overall, the treated
flows range from 3 Ib/sec for a small chemical process to 650 Ib/sec
for a 50 MW gas turbine. This paper discusses some of the reasons
why the composite catalyst design was chosen for SCR, and summarizes
some of the experience that has been developed with composite SCR
catalyst. In particular it focuses on factors pertinent to the
application of these catalyst to the exhaust from power generating
installations.
4B-103
-------
Discussion
Figure 1 illustrates the basic structure of a composite V/Ti SCR
catalyst, and compares it with a conventional SCR catalyst made by_
extruding catalytic material into the honeycomb shape. The composite
design is appropriate whenever mass transfer factors, such as
boundary layer diffusion or pore diffusion, limit the penetration of
reactant gases to a thin layer at the catalytic surface. This is the
case with NOx SCR.
The benefits of the composite design include:
1. High strength due to the strength of the underlying
structural ceramic;
2. Thin walls made possible by the support's high
strength;
3. High geometric surface area at constant pressure drop
due to the thin walls;
4. Excellent abrasion resistance due to the hardness of
the ceramic support;
5 . High activity due to high geometric surface area and
greater porosity within the catalytic layer;
6. Wider temperature range of operation due to better NOx
mass transfer characteristics;
7. Inherently low SC>2 oxidation activity, and
8. Contains 85% less heavy metals.
Composite SCR catalysts can be made with walls as thin as 12
thousandths of an inch (0.30 mm) compared to ca. 27 thousandths (0.65
mm) for conventional extruded SCR catalysts. Because they have
thinner walls, composite SCR catalysts can have much smaller openings
(and consequently higher geometric surface area) than conventional
catalysts. Figure 2 illustrates the benefits of thinner walls and
increased geometric surface area for increasing catalyst activity and
reducing catalyst volume and reactor size. Figure 2 compares the the
amount of SCR catalyst that would be needed to achieve either 80% or
90% NOx reduction using catalysts of different cell densities (ie.
channel opening sizes measured in cells per sguare inch, CPSI). For
example, in a design to achieve 80% NOx reduction at a pressure drop
below 3 inches water column, a conventional 40 CPSI catalyst would
require a relative catalyst volume of 3.3. In comparison, a 200 CPSI
composite catalyst provides the same performance with 65% less
catalyst (a relative catalyst volume of only 1.2).
Figure 3 illustrates another benefit of smaller channel openings,
wider range of operating temperature. It compares the curve of NOx
conversion vs. temperature for a 200 CPSI composite SCR catalyst
with a catalyst having a more conventional cell density, 25 CPSI.
The 200 CPSI composite catalyst was tested at much higher flow rate
than the 25 CPSI catalyst so that both provided similar NOx
conversion at temperatures below 350°C (660°F). As temperature was
increased, both catalysts exhibit the conversion peak and subsequent
drop off that is characteristic of the onset of excessive ammonia
oxidation in V/Ti SCR catalysts. However, the peak for the composite
catalyst is over 5 conversion points and 40°C higher than the 25 CPSI
4B-104
-------
catalyst. In addition, at 450°C (840°F), the normal maximum
continuous operating temperature for V/Ti, the 200 CPSI catalyst
still provided over 85% NOx conversion, while the 25 CPSI catalyst
had fallen to only 70%.
Figure 4 explains why composite catalysts demonstrate inherently low
SC>2 oxidation activity. It is a graph of SC>2 conversion vs.
relative catalyst loading (in gram catalyst/in^ of catalyst, relative
to a base loading). A medium cell density composite SCR catalyst has
a relative catalyst loading of IX, while a conventional extruded SCR
catalyst has a typical loading of 10X on this scale. Because of the
low S02 oxidation activity of composite SCR catalysts, this test was
run under exceptionally severe conditions to increase oxidation
sufficiently to allow for precise measurement. SC>2 oxidation in
commercial operation would be significantly lower than shown in
Figure 4.
At conversion levels of < ca. 20%, the rate of SC>2 conversion is
controlled by the number and potency of the active sites for S02
oxidation. Under this rate limiting condition the extent of 502
oxidation to SO^ increases in proportion to the amount of catalytic
material in the catalyst. As a result, composite catalysts have
inherently low S02 oxidation activity, because they contain only
about 10% as much V/Ti as extruded SCR catalysts. To compensate for
this deficiency, the SC>2 oxidation activity of extruded catalysts is
suppressed by incorporating SC>2 oxidation demoters into the catalyst
formulation. These additives, however, are also reported to suppress
NOx removal activity^.
The relative hardness of the ceramic honeycomb support results in
excellent erosion resistance for composite catalysts in high dust
environments. This characteristic, and catalytic performance in
several pilot and commercial installations are discussed in the
following sections.
Coal Fired Power Plants
High Dust, Hot Side:
The first experience with composite SCR catalyst for NOx control in a
high dust, hot side coal fired power plant environment began in 1988.
Small portions of the conventional SCR catalyst beds of two operating
coal fired power plants in Germany were replaced with composite
catalyst. One was on a dry bottom boiler, and the other a wet bottom
boiler. Pertinent operating characteristics are included in Table
III. Of particular interest were the dust loadings, which ranged up
to 15 g/Nm3 (ca. 7 grain/DSCF). Each SCR system contained 2 layers
of catalyst; each 1 meter deep. Several sleeves of composite SCR
catalyst (25 CPSI, 5.1 mm cell pitch) were mounted in each catalyst
layer.
A 6 inch long block of catalyst was mounted at the inlet of each
layer to test for possible erosion. These inlet blocks were removed
after 18 months and returned to Engelhard for erosion analysis. The
remaining catalyst is continuing in operation.
4B-105
-------
Two types of erosion were evaluated; axial (ie. length) erosion of
the catalyst block and wall erosion (ie. thinning of the catalytic
layer). Neither type was detected.
Axially, there was no change in the length of the catalyst blocks,
nor was there evidence of honeycomb wear to the sharp edges at the
inlet face of the catalyst. The hard ceramic support completely
resisted abrasion in this environment.
Wall erosion was measured by electron microscopy. Three samples were
cut from each aged catalyst block plus a fresh control. One sample
was taken from the center of the block, and the other two were taken
from spots located ca. 1 inch in from each end. These were mounted,
polished to reveal a cross section of each wall, and 5
photomicrographs were taken of each sample. These showed that there
was no evidence of erosion of the catalytic layer. There was no
difference in wall thickness between the aged and fresh catalysts,
and no correlation between depth of the catalytic layer and sample
location within a block. Figure 5 shows representative
photomicrographs comparing aged catalyst with the fresh control. The
lighter layer near the center of each photo is the catalytic V/Ti,
and the darker material beneath it is the ceramic support. The depth
of the catalytic layer was unaffected by aging.
These results are consistent with prior observations showing that
flow straighteners and hardening of the catalyst inlet face could
control erosion of the SCR catalyst, and there was no report of wall
thinning away from the inlet face7.
Analysis at Engelhard indicates that catalyst erosion is limited to a
transition zone from turbulent to laminar flow at the inlet to the
honeycomb channel. The depth of this transition zone can be affected
by factors such as gas velocity and angle of incidence of the gas
with respect to the catalyst channel, but once the flue gas develops
into full laminar flow (always within millimeters of the inlet face
of the catalyst) there is little interaction between abrasive
particles and the catalyst wall. Conseguently there is negligible
wall thinning within the block. With composite catalysts, the hard
ceramic substrate resists erosion at the inlet, so, in addition to no
wall thinning, there is also no axial erosion.
While the main purpose of this experiment was to study catalyst
erosion in the high dust environment, the SCR performance of these
aged inlet samples were also measured. The results are shown in
Figure 6. It is a graph of NOx conversion as a function of tem-
perature for aged catalyst taken from the SCR beds of both power
plants. Considering that the samples represent the most contaminated
and deactivated portion of the bed, the inlet 6 inches, it is notable
that both provide over 80% NOx reduction and little or no ammonia
slip at a typical commercial flow rate.
Medium Dust, Cold Side:
Composite SCR catalysts have been, and are continuing in pilot plant
tests on several coal fired power plants downstream of the flue gas
desulfurization systems. Figure 7 shows the results for a pilot
4B-106
-------
reactor system that used a 200 CPSI V/Ti composite catalyst to
determine if catalyst with a pitch of less than 2 mm could operate in
that environment without plugging. Table IV summarizes pertinent
operating conditions. The test included a total of 2500 on-stream
hours (including 40 pilot plant start-ups and shutdowns)8. At
20,000 1/hr VHSV and 350°C, NOx conversion averaged 92% with <5 ppm
ammonia slip. For this application, the particulate concentration
(primarily gypsum, CaCC>3 and SiC>2) averaged about 50 mg/Nm3 (0.02
grains/DSCF) with peaks of up to about 120 mg/Nm3 (0.05
grains/DSCF). The inlet NOx concentration varied between 350 and 420
ppm. No apparent decline of catalyst performance was seen throughout
the test period.
Since the channel size of the 200 CPSI catalyst was significantly
smaller than typically used for this dust level, provision was made
for soot blowers to prevent catalyst plugging. Initially the soot
blowing frequency was every 2 hours. Over the first 800 hours of
operation the soot blowing frequency was steadily reduced with no
increase in pressure drop across the catalyst. After 800 hours, soot
blowing was stopped completely. Pressure drop rose slightly and
stabilized at a 15% increase from the original level. While every
installation is different, these results indicate that it is possible
to operate high cell density SCR catalysts at moderate dust levels
without plugging.
Figure 8 shows on-line NOx reduction efficiency and ammonia slip
versus feed NH3/NOx ratio during this pilot test. It shows that by
using a 200 CPSI catalyst it was possible to achieve >92% NOx
conversion with <5 ppm NH3 slip at with relatively little catalyst
(20,000 1/hr VHSV).
Aging of these catalyst modules plus several others containing lower
cell density catalyst was continued in the SCR reactor downstream of
the FGD unit of another coal fired boiler. Dust levels averaged 10
mg/Nm3 (0.005 grains/DSCF), and inlet NOx ranged between 550 and 600
ppm. To date the catalysts have accumulated a total of 15,800 hours
of operation. Laboratory activity tests made at 60,000 1/hr VHSV on
core samples taken at 0, 2500 and 7540 hours showed no decline of
catalyst activity from the fresh level (see Figure 9). Testing after
nearly 16,000 hours shows what may be a slight decline in conversion,
but even these results are within the range of normal test
variability.
These data demonstrate that this composite SCR catalyst with a high
cell density can be applied successfully to boiler exhaust even where
the presence of particulates is significant. This can represent a
several fold reduction in catalyst volume for achieving the same high
NOx performance efficiency as conventional catalyst designs of lower
cell density.
Stationary Engines
Composite V/Ti based SCR catalyst technology has also been applied to
a wide range of stationary engine applications. Engine sizes have
ranged from 210 to 3900 horsepower. Fuels have been natural gas,
digester gas, and #2 diesel fuel. Ammonia control strategies have
4B-107
-------
ranged from manual adjustment to continuous monitoring with control
by an in-plant host computer. In each application, the required NOx
conversion and NH3 slip performance limits were achieved.
Of particular interest are the results from one application which
utilized #2 diesel fuel. This application was operated on 300 CPSI
(1.5 mm pitch) composite catalyst as a demonstration unit by the EPA
at their Air and Energy Research Laboratory at Research Triangle Park
in North Carolina9. The demonstration was run for 4000 hours in
approximately 100 hour increments. Particulate levels in the exhaust
ranged from 27 mg/Nm3 (0.013 grains/DSCF) during steady state
operation to up to 100 mg/Nm3 (0.05 grains/DSCF) during each start-
up. There was occasional evidence of increased pressure drop due to
accumulation of wet soot on the ultra-fine pitch catalyst during
periods of frequent repeated cold starts. As a result, the catalyst
was manually air lanced four times during the demonstration. After
each cleaning, 85% NOx conversion was maintained. There was no
evidence of particulate buildup during periods of continuous
operation.
This test demonstrated that ultra-fine pitch composite SCR catalyst
could provide continuous steady state NOx emission control on a
diesel engine operating on #2 fuel at a substantial reduction in
catalyst volume relative to conventional catalysts.
Conclusions
The composite catalyst design strategy using ceramic supports offers
several unique advantages for NOx selective catalytic reduction.
They include greater mechanical strength, exceptionally high
activity, excellent erosion resistance, and inherently low S02
oxidation activity. These benefits have been demonstrated in both
extensive pilot scale testing and commercial installations.
ACKNOWLEDGEMENT
The information included in this paper was generated in collaboration
with several Engelhard colleagues, including: Dr. J.W. Byrne, Mrs.
C.Hirt, Mr. J.Hansell, and Mr. M.Tiller.
4B-108
-------
K.Burns, M.Collins, R.M.Heck, Catalytic Control Of NOx
Emissions From Stationary Rich-Burning Natural Gas Engines,
ASME 83-DGP-12, 1983
J.M.Chen, R.M.Heck, K.R.Burns, M.F.Collins, Development Of
Oxidation Catalyst For Gas Turbine Cogeneration Applications,
82nd Annual Meeting And Exposition Of The Air Pollution
Control Association, June 1989, Anaheim, California
R.M.Heck, M.Durilla, A.G.Bouney, J.M.Chen, Ten Years
Operating Experience With Commercial Catalyst Regeneration,
81st Annual Meeting And Exposition Of The Air Pollution
Control Association, June 1988, Dallas, Texas
J.J.Mooney, C.E.Thompson, J.C.Dettling, Three Way Conversion
Catalyst - Part Of A New Emission Control System, SAE 77-
0365, 1977
R.M.Heck, J.C.Bonacci, J.M.Chen, Catalytic Air Pollution
Controls - Commercial Development Of A Catalyst For The
Selective Catalytic Reduction Of NOx, 80tn Annual Meeting And
Exposition Of The Air Pollution Control Association, June
1987, New York, New York
J.Ando, "NOx Abatement For Stationary Sources In Japan", EPA
600/7-83-027(1983)
L.Balling, D. Hein, DeNOx Catalytic Converters For Various
Types Of Furnaces And Fuels - Development, Testing,
Operation, 1989 EPA/EPRI Joint Symposium On Stationary
Combustion NOx Control, March 6-9, 1989, San Francisco,
California
D.Dreschler, presented at the German VGB Conference, Feb.
1986
J.H.Wasser, R.B.Perry, Diesel Engine NOx Control With SCR,
EPA/EPRI 1985 Joint Symposium On Stationary NOx Control, May
1985, Boston, Mass.
4B-109
-------
Figure 1:
Two Different NOx SCR Catalyst Designs
Composite
Extruded Vanadia/Titania
Strong, -
Thin Walled
Ceramic
Support
Catalytic
Layer Of
Vanadia/Titania
Figure 2:
Catalyst Volume Can Be Cut 50 - 65% By
Increasing Geometric Surface Area
Pressure Drop, Inches Water Column
100 CPSI
200 CPSI
;40 CPSI
111 "CPSI j
o-— -- - - -- -
1.0 10.0
Relative Catalyst Volume
350 deg. C, 20 ft/sec Velocity (@ T)
NOx SCR Efficiency
90% Conversion
80% Conversion
-- — ._ ._!_ J... . J_ I
100.0
4B-110
-------
CD
Figure 3:
Increasing SCR Catalyst Geometric Area
Widens The Operating Temperature Window
100
90
80
70
60
50
40
2£
NOx Conversion, %
D
D —
\ \
\ \
\
\
\
\
\
\
\
\
D 200CPSI, 60.000VHSV
+ 25CPSI, 12.000VHSV
; i
50 300 350 400 450 500 550
Temperature, deg C
Figure 4:
Composite SCR Catalysts Exhibit
Inherently Low SO2 Oxidation Activity
10
SO2 Conversion,
o
Extruded Catalyst
Equivalent To
5X - 15X
1/1 NH3/IMOX Ratio
O.OX 0.5X 1.0X 1.5X 2.OX 2.5X
Relative Catalyst Loading, (g/in3)/base
100 CPSI, 350 deg. C, 450 ppm SO2
-------
figure1 5
Composite SCR Catalyst Aged In High Dust, Coal Fired Boiler
Exhaust Shows No Evidence Of Wall Erosion
CD
r\j
Fresh Catalyst
Catalyst Aged In Dry Bottom Boiler Exhaust
Catalyst Aged In Wet Bottom Boiler Exhaust
-------
Figure 6:
Inlet 6" Of Composite SCR Catalysts From
High Dust SCR Beds Of Coal Boilers
NOx Conversion, %
100 i 7
80
60
40
20
Ammonia Slip, ppmv
100
—" Dry Bottom Boiler
-**- Wet Bottom Boiler
80
- 60
40
- 20
300
325 350 375 400
Temperature, degrees C
o
425
3000 hr-1 VHSV, 1/1 NH3/NO*
Figure 7:
200 CPSI Composite SCR Catalyst Did Not
Plug In A Moderate Dust Environment
100
80
60
40
20
0L
NOx Conversion, %
Change In Pressure Drop, %
-100
24
No Soot Blowing
Soot Blowing
Frequency, hours
80
60
40
20
0 400 800 1,200 1,600 2,000 2,400 2,800
On-Stream Time, hours
50-120n mg/Nm3 dust
4B-113
-------
Figure 8:
NOx Conversion And Ammonia Slip Over
Composite SCR Catalyst After Coal FGD
Figure 9:
Composite SCR Catalyst Unaffected By
2 Years In Coal Fired Utility Exhaust
CD
4^
NOx Conversion, %
100
95
90
85 -
NH3 Slip, ppm
0.70
0.80 0.90 1.00 1.10
Inlet NHS/NOx Ratio
425 ppm NOx, 20,000 1/hr VHSV,
200 CPSI, 50-120 mg/Nm3 Dust
100
NOx Conversion, %
NH3 Slip, ppm
80 F
60 |_ Catalyst Condition
I I n Aged 2500 Hrs
-I- Aged 7450 Hrs
''•> Aged 15800 Hrs
Fresh Catalyst
40
1.0 1.1 1.2
NHS/NOx Ratio
400 ppm NOx, 320 deg C
60,000 1/hr VHSV, 200 CPSI
1.3
100
-80
60
40
J20
1.4
-------
Table I:
Engelhard Composite SCR Catalyst Pilot Tests
Location
United States
Germany
Germany
Germany
Germany
Germany
United States
United States
United States
United States
Type
Diesel Engine
Cold Side, Coal Fired Heating Plant
Cold Side, Coal Fired Power Plant
Cold Side, Coal Fired Power Plant
Hot Side, Coal, Dry Bottom Boiler
Hot Side, Coal, Wet Bottom Boiler
Gas Turbine
Natural Gas Boiler
Gas Turbine - Simple Cycle (980 F)
Gas Turbine - Simple Cycle (1085 F
Table II:
Engelhard's 25 Composite SCR Catalyst Systems
Location
California
4 Natural
Alabama
California
California
California
California
California
California
Texas
New Jersey
California
New Jersey
Application -Catalyst*
6 Engines-VNX
Gas and 2 Digester Gas
Chemical Process-ZNX
Industrial Boiler-VNX
Refinery Heater-VNX
Refinery Heater-ZNX/VNX
50 MW Gas Turbine-VNX
1 MW Gas Turbine-ZNX
Annealing Furnace-VNX
5-Refinery Heaters-VNX
Chemical Plant-VNX
3-Dual Fuel Engine-ZNX
Refinery Heater-VNX
2-50MW Gas Turbines-VNX
Approx.
Startup
1984
8/90
10/90
10/90
10/90
11/90
2/91
3/91
3/91
5/91
6/91
10/92
Flow,#/sec
200 to
4000 HP
3
17
84
46
650
23
29
16-31
99
5
39
844
*VNX(tm) & ZNX(tm) are V/Ti and Zeolite SCR Cat.
4B-115
-------
Table
Operating Conditions Of Hot Side SCR Systems
Boiler Type
Coal Type
Ash Content, %
Sulfur Content, %
Dry Bottom
Wet Bottom
German/Foreign Ruhr/Saarland
6 - 12
< 1.5
Temperature, deg. C 360
Inlet NOx, mg/Nm3 800
Inlet SO2, ppmv 1000
Particulates, g/Nm3 10 - 15
Soot Blowing
Monthly
4-7
< 1.5
360
1300 - 1500
1000
2
Every 10 Days
Table IV:
Moderate Dust SCR Pilot Plant Conditions
Location
Flow Rate, scfm
Temperature, deg. C
Space Velocity, hr-1
Inlet NOx, ppmv
Inlet SO2, ppmv
Particulates, mg/Nm3
Coal Type
Sulfur Content, %
Ash Content, %
Slipstream Off FGD
2060
350
20,000
350 - 420
50
50 - 120
Bituminous
0.95 - 1.18
5.0 - 6.5
4B-116
-------
SCR CATALYST DEVELOPMENTS FOR THE U.S. MARKET
by T. R. Gouker
Research Division
W. R. Grace & Co.-Conn.
7379 Route 32
Columbia, MD 21044
C. P- Brundrett
Davison Chemical Division
W. R. Grace & Co.-Conn.
10 E. Baltimore Street
Baltimore, MD 21202
-------
SCR CATALYST DEVELOPMENTS FOR THE U.S. MARKET
ABSTRACT
This paper reviews SCR catalyst development from its invention in the U.S.
through power plant applications of the technology in Japan and West Germany.
Building on this experience, the requirements for adaption of the SCR process to
U.S. high-sulfur coal applications are discussed. Grace's SCR catalyst development,
SYNOX, is then reviewed for its application to U.S. boilers firing high sulfur coal.
JAPANESE SCR DEVELOPMENT
SCR was originally invented and patented by a U.S. company in 19591, but its
use was limited to a few industrial applications, such as pollution control from
nitric acid plants. It wasn't until the 1970's that SCR gained application to power
plant NOX emissions. The first utility applications took place in Japan. The
Japanese identified SCR as a suitable approach for controlling NOX and began a
stepwise application of the technology to all three types of fossil-fueled boilers:
gas, oil and coal. By 1985, there were more than 200 commercial installations
operating in Japan2.
Application of SCR to power plant exhaust was not a simple matter. A number
of problems were encountered during development. These included: (1) catalyst
poisoning by sulfur species in the fluegas; (2) ammonium bisulfate deposition in the
catalyst and on downstream equipment; and (3) equipment corrosion due to increased
S03 levels in the flue gas. The single most important contribution the Japanese
made to the development of SCR was to switch from noble metals to base metal oxides
for the catalyst3. The use of titanium dioxide supports with mixtures of vanadium
and tungsten oxides as catalysts, solved the major problems associated with oil and
gas-fired utility fluegas applications.
Additional developments were required, however, to address the issues of
flyash plugging and erosion for coal-fired service. In 1978, pellet catalysts were
given-up in favor of parallel-flow honeycomb or plate catalysts. The low conversion
targets (40-60%) coupled with the relatively low fly ash content of Japanese boilers
and the fact that most units were relatively new, allowed SCR application go
smoothly. Continued development led to ceramic honeycomb and plate-type catalyst
configurations which provided high geometric surface area with low tendency for
flyash plugging. In the early 1980's the focus of Japanese work on SCR was on
optimizing surface geometry and avoiding flyash plugging. This optimization reduced
the size (and cost) of SCR reactors by a factor of 2 and greatly improved the
economics of the SCR process. At this stage of development, ceramic honeycomb-
based catalysts had a pitch of 13 (wall thickness of 2 mm and channel opening of 11
mm) in 1978. By 1982, catalysts with a pitch of 7.5 (wall thickness of 1.4 mm and
channel opening of 6.1 mm) had been demonstrated. Since the mid-1980's, catalyst
research in Japan has principally focused on understanding the deactivation
mechanisms of SCR catalysts*. Mechanisms have been proposed for for the effects of
alkalis, alkaline earths, and heavy metals such as arsenic. Research on SCR
continues in Japan, but due to the more demanding commercial environment, the lead
role in SCR technology development shifted to West Germany in the mid-1980's.
WEST GERMAN SCR DEVELOPMENT
Driven by tough regulatory standards, West German utilities made rapid
4B-119
-------
progress, lowering their coal-fired power plant NOX emissions to below 0.16
Ibs/million Btu5, about half that of the Japanese national standard. To do this,
the SCR process could not run at the 40-60% conversion levels as in Japan, but
instead systems were designed for up to 90% NOx removal.
The first SCR facility to be retrofited in West Germany went into operation in
1985. By the end of 1990, more than 23 GWe of power plant capacity had SCR
installed to control NOX emissions5 (Figure 1). In support of this intensive
emission control program, about 60 pilot plants were constructed and operated. The
pilot plants were required to address the design issues which surfaced in the more
demanding environments of West German boilers. In addition to dry bottom units, as
in Japan, SCR was retrofitted on slagtap boilers. Since few German utilities has
low NOX burners, NOX concentrations were much higher than in Japan. Coal sulfur and
ash contents were also higher than in Japan, leading to higher SOX and flyash
concentrations in the fluegas. The SCR pilot program resolved several issues
involving SCR process technology. The effect of erosion, poisoning and fouling on
catalyst lifetime were quantified. The potential for ammonia slip was also
determined, along with the resulting effect of ammonium bisulfate deposition.
In general, the process experience with dry ash boilers in West Germany has
been similar to the results experienced by coal-fired utilities in Japan. The
majority of the loss in activity was due to interactions of the catalyst with the
flyash. The flyash had several types of effects on the monoliths: physical
fouling, poison transfer, and bulk plugging. Sub-micron ash particles accumulated
on the surfaces of the elements and blocked the pores of the catalyst. This
physical fouling prevents the NOX and ammonia from reaching the active sites of the
catalyst and leads to a reduction in catalytic performance. Figures 2 and 3 compare
the ESCA analysis of fresh and aged samples typical of dry ash boilers6. This data
demonstrates the buildup of the wide variety of flyash elements near the surface.
The reduction in the intensity of the titanium signal further demonstrates the
covering of the surface by flyash.
Flyash was also found to contribute poisons to the catalyst surface. The
transfer of alkali metals from the flyash lowered the activity of the catalyst.
This was found to occur primarily due to the leaching action of moisture on the
flyash during start-up and shutdown of the units7. Since these metal salts are
soluble in water, the presence of moisture can promote the redistribution of these
elements. In laboratory studies, alkali salts have been shown to be a catalyst
poison due to the formation of inactive complexes with the vanadium and tungsten.
In some cases, bulk plugging of the channels by accumulations of dust was
observed. Dust plugging occurred when flyash "flaked" off of upstream equipment.
Wire screens were installed on most units to break up these flakes as they
approached the catalyst. Soot blowers were also installed to blow the flakes back
and break them up during pilot plant start-up and shutdown.
In addition to occasional plugging problems, severe erosion problems due to
fluegas flow maldistributions have occurred. The use of flow straightening vanes
and/or "dummy" catalyst layers has reduced gas flow distribution problems and
associated erosion.
While the experience in installing SCR on dry ash boilers was generally
similar in both Japan and West Germany, there has been a significant shift in
expectation of average catalyst life between SCR on the two continents. Perhaps
because of improvements in catalyst technology or improvements in process
installations, SCR catalysts in West Germany are experiencing better activity
maintenance than the Japanese high-dust, coal-fired SCR catalysts experience
4B-120
-------
suggested. Figure 4 shows a graph of relative catalyst life versus operating time5.
This figure illustrates a 5-10% higher level of activity per year for a number of
West German installations when compared to the curve based on Japanese experience.
This has turned out to be a surprising development for the industry in that most
organizations expected SCR to experience higher rates of activity loss in West
Germany. In planning for potential activity problems, a number of new catalyst
formulations were investigated for the West German market but nor commercialized.
These developments put the United States in a position to reap the benefits of
recent SCR catalyst advances as the technology is introduced on U.S. boilers.
U. S. SCR ISSUES
As mentioned earlier, SCR technology was originally invented in the United
States. While extensively installed abroad, U.S. SCR application has expanded from
its beginnings on nitric acid plants. SCR is in service on an increasing number of
gas and oil-fired boilers, turbines, and industrial applications such as refinery
process heaters. Grace has been offering SCR systems into this growing market under
the trade name Camet for a number of years. Systems have been designed to provide
up to 90% NOX removal. Due to the low sulfur and low fly ash concentrations,
catalyst pitch for these applications can be greatly reduced. With conventional
ceramic plate type catalyst, pitch can only be reduced to 3.0 mm. Camet catalysts
are supported on a thin metal substrate (2.5 mils) and can be manufactured with
openings equivalent to a 0.2 pitch catalyst, greatly reducing the volume of an SCR
reactor. An example of a Camet SCR system is shown in Figure 5. The system is part
of the Santa Maria Cogeneration Project in California. It is owned and operated by
Bonneville Pacific Corporation of Salt Lake City, Utah.
Except for pilot testing by the EPA and EPRI8'9, SCR has not been implemented
on coal-fired boilers in the U.S. The boiler types in the U.S. are similar to those
in West Germany, therefore a great deal of information can be transferred from the
German experience. Several issues must be addressed, however, before SCR will gain
wide spread acceptance in coal service in the United States. An assessment must be
made of the impact of higher sulfur content of Eastern Bituminous coals on SCR life
and performance. The effects of differing fly ash constituents must be identified
and quantified. In addition, the possibility exists for some as yet unrecognized
boiler conditions or coal characteristics to impact SCR performance.
For SCR to be installed on U.S. facilities, especially those burning high-
sulfur U. S. coal, risks must be reduced to an acceptable level. To do this,
engineering companies and catalyst vendors will have to develop information on a
number of key areas including:
1. The proper space velocity, linear velocity and reaction
temperature to minimize ammonia slip at required NOX removal
levels.
2. The tolerable level of ammonia slip under high S02 and S03
conditions.
3. The performance of catalyst and its deactivation rate in
flue gas and fly ash from U. S. coals.
4. Performance of the air preheater when exposed to high S03
levels and subsequently high levels of NHi,S04.
5. Adhesion characteristics of fly ash from U. S. coals to SCR
catalyst. The effectiveness of soot blowing and the effects
4B-121
-------
of residual fly ash on catalyst activity.
The most efficient way for catalyst vendors to assist in the development and
demonstration of SCR technology on high-sulfur U. S. coals is through the design of
catalysts tailored to meet the above needs in a cost-efficient manner. High levels
of denox activity while minimizing ammonia slip can be met by catalysts designed to
have higher NOX conversion activity. The effects of NHAS04 deposition can be
minimized by designing catalysts to have a low S02 to S03 oxidation activity. The
detrimental effects of fly ash and deactivation can be counteracted by catalysts
designed to be more durable, and poison resistant.
U. S. SCR DEVELOPMENT
The design requirements and the recognition that a major portion of SCR
process costs are still associated with the catalyst has led researchers to
vigorously pursue improved catalyst designs. Grace's approach has been to focus on
increasing catalyst activity and life, thus reducing catalyst volume requirements
while extending the useful life and consequently reducing SCR process costs. To
determine the potential for major improvements, Grace undertook a fundamental study
of the limits of SCR catalyst performance, developing a mathematical model that
expressed catalyst performance (NOX conversion, ammonia conversion, S02 oxidation)
as a function of the properties of the catalyst.
The model accounts for the key design parameters of the catalyst, including
its composition, monolith channel shape and dimensions, monolith wall thickness,
pore structure, overall volume, and aspect ratio. The model has been found to
correlate well with Grace's commercial data base, adjusting only surface-kinetic
rate parameters. Modeling results indicated that a substantial reconfiguration of
the pore structure of the catalyst could increase NOX conversion by about 50%, while
simultaneously increasing resistance to poisoning and thereby extending catalyst
life. The model indicated that the NOX conversion improvement would be selective
with respect to S02 conversion. That is, the undesired S02 oxidation reaction would
not be enhanced by the pore structure reconfiguration. This is due to the fact that
the reduction of NO is diffusion limited whereas the rate of oxidation of S02 is
kinetically controlled.
The model showed that an optimum balance between surface catalytic activity
and diffusivity could be provided by a bimodal pore structure with a substantial
percentage of macropores (Figure 6) . However, such pore structures could not be
attained using titania as the catalyst support.
To solve this problem, Grace succeeded in engineering silica to provide the
necessary macropores for a new catalyst pore structure while maintaining the
necessary intrinsic denox activity. Grace researchers developed a preparative route
to deposit titania within the silica to produce a novel catalyst support (Figure 7).
When extruded and impregnated with vanadia, the new catalyst, trade named SYNOX™,
resulted in the anticipated 50% improvement in activity11. We have demonstrated
excellent hydrothermal stability through near 3000 hours in simulated fluegas with
no noticeable decrease in activity (Figure 8) in testing of laboratory-scale pieces.
Proposals have been made to expose these new monoliths to power plant stack gas side
streams. Such pilot plant tests have been planned by the Electric Power Research
Institute and Southern Company Services (for the U.S. Department of Energy).
Independent of the pilot plant tests, Grace has initiated a slipstream test of its
own.
A slipstream reactor has been set up at the TVA Shawnee Steam Plant in
Paducah, KY, to study the SYNOX catalyst in fluegas from a 100 MU boiler burning
4B-122
-------
high-sulfur coal. The effects of flyash, alkali salts, and other constituents will
be studied and compared to their effects on a conventional titania catalyst. The
boiler effluent contains about 300 ppm NOX, 3000 ppm S02, and a flyash loading of
about 3 grains per standard cubic foot, the Grace slipstream reactor is located
downstream from the mechanical separators and air preheater, as shown in Figure 9.
The fluegas temperature entering the unit is about 150°C and must be reheated to
about 350°C before passing over the catalyst.
The reactor contains 3 catalyst baskets stacked one on top of the other and a
dummy basket at the top. The dummy basket contains inactive catalyst support and is
used as a flow straightener. Each catalyst basket contains 16 pieces of 2.5 cm x
2.5 cm x 23 cm-long monoliths.
A large bypass stream is maintained from the TVA supply duct to the Grace
slipstream reactor and back to the TVA return duct. This minimizes heat losses in
the 20 m-long pipes and reduces the chances of flyash plugging. A purge valve on
the inlet sample line helps keep the bypass lines clean. The primary purpose of
this slipstream reactor is to expose catalyst to fluegas under typical SCR operating
conditions.
The slipstream test is configured to expose the SYNOX and commercial catalyst
pieces to fluegas at typical linear velocities in order to evaluate poison and
erosion resistance. The slipstream reactor length of 27 inches versus the 9-12 feet
used commercially results in very low NOX conversions at these exposure conditions
which reproduce commercial linear gas velocities. Conversion, however, is measured
from time to time by reducing the linear velocity and operating at space velocities
typical of commercial installations. Figure 10 shows the results of testing upon
initial start-up of the slip stream reactor.
Quantitative catalyst analysis for denox efficiency is performed in the
laboratory under carefully controlled conditions. Accurate activity measurements
are possible only when the NOX and NH3 concentrations are constant and the catalyst
is operating at steady state. Due to a wide range of difficulties with Unit #9 at
the Shawnee Steam plant, data on aged catalyst has not been obtained yet.
SCR PROCESS COSTS
Since its introduction in Japan in the 1970's, the cost of SCR has dropped
continually, primarily because of technological advances. In Japan, the levelized
busbar cost of SCR decreased over a six-year period by more than a factor of 3
because of increases in catalyst life and reductions in catalyst volume requirements
as a result of improved catalyst geometry and composition. In Germany the learning
curve continued, dropping costs by an additional factor of 2, again largely because
of technical developments: reduced catalyst installation cost; mechanized and
automated catalyst manufacture; and new catalyst replacement strategies that allowed
the extension of average catalyst lifetime guarantees to four years.
Additional progress on the learning curve toward reduced costs is expected
when SCR gains large-scale U.S. application. This can be best illustrated by
showing the cost sensitivity of the latest German SCR experience12, transposed to a
U.S.-equivalent basis, in 1988 dollars. Figure 11 shows, as mentioned previously,
that approximately half of the levelized busbar cost of SCR is still catalyst
related . This points to the possibility of further cost reductions as a result of
improvements in the catalyst.
Figure 12 quantifies this possibility by comparing costs for first- and
second-generation SCR control technologies. The first column in Figure 12, taken
4B-123
-------
from a 1989 United Engineers & Constructors study of first-generation SCR prepared
for EPRI", shows the costs associated with SCR for an 80% removal efficiency from
an uncontrolled emission level of 0.6 Ibs/mm Btu.
Costs for second-generation technology, such as Grace's SYNOX catalyst, are
illustrated in the second column. With the 50% higher activity of SYNOX, an SCR
unit will need only two-thirds of the conventional reactor volume. Capital
requirements will be reduced to $62 per KW. With a reduced catalyst volume and
increased catalyst life, the levelized busbar cost will drop from 5.2 mills/KWh to
2.1 mills/KWh and the cost expressed in $/ton of NOX removed will also decrease. At
the level of 80% N(X removal the per-tonnage cost of a clean NSPS boiler will drop
from $2170 to $870. Combining SYNOX SCR with low-NOx burners can reduce the cost
even further to $700/ton of NOX removed. On a cyclone unit, costs will be lowered
from the $600/ton range to $400/ton of NOX removed.
The work described in this paper was not funded by the U.S.
Environmental Protection Agency and therefore the contents
do not necessarily reflect the views of the Agency and no
official endorsement should be inferred.
1. Anderson, H. C., W. J. Green and D. R. Steele, "Catalytic Treatment of Nitric
Acid Plant Tail Gas," Ind. Eng. Chem., 53, 199 (1961).
2. Ando, J., "Recent Status of Acid Rain and SO;,/NOX Abatement Technology in
Japan," 10th Symposium on Flue Gas Desulfurization, EPRI/EPA, Atlanta, GA,
November 18-21 (1986).
3. Lowe, P. A., W. Ellison, L. Radak, "Assessment of Japanese SCR Technology
for Oil-Fired Boilers and its Applicability in the U.S.A.," Joint Symposium
on Stationary Combustion A/0X Control," EPRI/EPA, San Francisco, CA March
6-9 (1989).
4. Aoyagi, K., "Rapportuer's Report: Sessions on Environmental Control
Retrofit/Upgrade," GEN-UPGRADE 90, IEA/USDOE/EPRI, Washington, D.C., March
6-9 (1990).
5. Haug, N., Material presented at the NATO Meeting on Coal Combustion Systems,
Copenhagen, Denmark, May 13-15 (1990).
6. Gouker, T. R., J. P. Solar, J. C. Fu, C. P. Brundrett, "Evaluation of
Selective Catalytic Reduction Catalysts from West German Pilot Plant
Studies," 7th Annual International Pittsburgh Coal Conference, Univ of
Pittsburgh, Pittsburgh, PA, September 10-14 (1990).
7. Schallert, B., of VEBA Kraftwerke Ruhr AG, Private Communication (1987).
8. Maxwell, J. D., T. W. Tarkington, T. A. Burnett, "Technical Assessment of
NOx Removal Processes for Utility Application," EPA Report 600/7-77-127
March (1978). '
9. Shiomoto, G. H., L. J. Muzio, "Selectice Catalytic Reduction for Coal-fired
Power Plants-Pilot Plant Results," Final Report, EPRI Report CS-4386, April
(1986).
4B-124
-------
10. Beeckman, J. W., L. L. Hegedus, "Design of Monolith Catalysts for Power Plant
NOX Emission Control, paper 72e presented at the AIChE Annual Meeting,
Washington, D.C. (1988); Ind. Eng. Chem. Res., in press, 1991.
11. Solar, J. P., J. C. Fu., "Effect of Reaction Parameters on the Activity of
SYNOX Catalysts for the Selective Catalytic Reduction of NOX," 83rd Air and
Waste Management Annual Meeting, AWMA, Pittsburgh, PA, June 24-29 (1990).
12. Schonbucher, B., "Costs of a DeNOx Plant on the Basis of the SCR Process,"
Proceedings of the Workshop on Emission Control Costs, Eds. 0. Rentz, et.
al., Inst. for Ind. Prod., Univ. of Karlruhe, Karlsruhe, West Germany,
September 28 October 1 (1987).
13. Boer, F. P., L. L. Hegedus, T. R. Gouker, K. P. Zak, "Controlling Power
Plant NOX Emissions," CHEMTECH, 20, 312 (1990).
14. Robie, C. P., P. A. Ireland, J. E. Cichanowicz, "Technical Feasibility and
Economics of SCR NOX Control in Utility Applications," Joint Symposium on
Stationary Combustion NOX Control, EPRI/EPA, San Francisco, CA, March 6-9
(1989).
4B-125
-------
[103 MW,
35 —
30 -
25 -
20
15 -
10 -
el
o —-
1985
1986 1987 1988 1989 1990 1991 1992
Year
Figure 1.
Flue-Gas Treatment NOx Controls
in West German Power Stations
1993
p
e
a
k
1
n
t
e
n
s
i
t
y
i ii.
o
1 1 -
10 J
9 ^
'
8 ' -'. °
I
7 - ^ f j|
1 \ j v I \ h
6 - M i
I A
5 - <.—— - ' I
\
F r e s l"i
T
I
4 X^il
3 o
2 - -\ J VI j {
1 -
1888 988 888
788 688 588 488 388
Binding Energy, eV
288 188
Figure 2.
ESCA of Fresh Catalyst Surface
4B-126
-------
p
e
a
k
1
n
t
e
n
s
i
t
y
A
c
t
i
V
i
t
y
i ^ -, ,
0
1 1 H
10- rtyc°
9 -i ;
81
6 -
5 -
4 -
3 -
2 -
1 -
o -
I
''•A Ba Ce
~" I I Ti AS
l/fl ' I Oa N | ca K C S S Si
~^~'~V'/VV'V^— -JJi^ L || Sl A
J~^J —-^-v_
i i i i i i i i i
1884 983 883 783 682 582 482 381 281 181 1
Binding Energy, eV
Figure 3.
ESCA Showing Ash Constituents
on Aged Catalyst Surface
1-4 — . — ._
.1
1
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
x .. n • *+ .* ^
--^ ^ * a *a
x^ — - ^
/
Expected curve ace. to
Japanese experience
-
-
~
-
-
\ , i i i i i i i i i i i i '
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15-103h 1
Figure 4.
SCR Catalyst (High-Dust) Activity
Loss in a Dry-Bottom Boiler
4B-127
-------
Figure 5.
Camet SCR System located at the
Santa Maria Cogeneration Installation
4B-128
-------
Conventional
Catalyst
1.0
300
L o.e
0
G „ .
200
Por« Diameter,
Figure 6
Model Prediction of DeNOx Activity
Figure 7
Pore Size Distributions
4B-129
-------
A
c
t
i
V
i
t
y
oxeram CHDB Catalyst
250
300
350
400
Figure 8
Comparison of the Activity of SYNOX, a second-
generation catalyst under development by Grace, with
Noxeram, a first-generation catalyst produced in West
Germany by a joint venture between Grace and Feldmuehle.
STACK
AIR
MECHANICAL
SEPARATOR
WATER
BAGHOUSE
150 C
AIR
PREHEATER
STEAM
COAL
/ UNIT \
' # 9
BOILER
I'
PREHEATED AIR
Figure 9
Flue Gas System of TVA Boiler #9
Shawnee Steam Plant Paducah, KY
4B-130
-------
Conversion, %
100 ;
80 r
60 r /
/ Nominal Operating Conditions
/
„/ Flue gas flow = 1100 SCFH
4Q '_ •/ Temperature - 350°C
NOX 300 ppm
i SO2 3000 ppm
SOs - 25 ppm
20 r H2O 6%
i O2 4%
Flyash 3 grains/scf
QJ 1 1 1
0 0.5 1 1.5
NH3to NOX Ratio
Figure 10
SYNOX Catalyst Performance at Start-up
in Test Unit at Shawnee Steam Plant
Variable Operating Costs
Catalyst Replacement 34%
Ammonia 5%
Power 7%
Fixed Operating and Maintenance Costs
Maintenance Labor 11%
Administrative 8%
Capital Charges
Catalyst First fill 14%
Ancillary Equipment 21%
Figure 11
Levelized Busbar Breakdown of SCR in 1988
4B-131
'0
-------
Second-generation SYNOX
First-generation catalyst catalyst. Grace estimates
Boiler Type NSPS NSPS
Uncontrolled Emissions, Ib/mm Btu 0.6 0.6
Capital Cost, $/KW 100 62
Levelized Busbar Cost, mills/KWh 5.2 2.1
NQ Removal Cost, $/ton 2170 870
Figure 12
U.S. SCR Cost Projections in 1988 Dollars at 80% NOV Removal
A
4B-132
-------
POISONING MECHANISMS IN EXISTING SCR CATALYTIC CONVERTERS
AND DEVELOPMENT OF A NEW GENERATION FOR
IMPROVEMENT OF THE CATALYTIC PROPERTIES
L. Balling
R. Sigling
H. Schmeltz
E. Hums
G. Spitznagel
Siemens AG Power Generation Group (KWU)
Hammerbacherstrasse 12 + 14
8520 Erlangen, Germany
-------
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
Siemens AG Power Generation Group (KWU)
Hammerbacherstrasse 12+14
8520 Erlangen, Germany
ABSTRACT
For better understanding of the processes involved in catalytic NOx reduction using
titanium, tungsten, molybdenum and vanadium oxide catalysts, extensive investigations
have been carried out by Siemens/KWU in recent years, also focussing on explaining the
deactivation phenomena in greater detail.
On the basis of research carried out on wet-bottom furnaces, heavy oil combustion and
glass melting furnaces, this paper discusses the mechanisms of poisoning and the factors
which cause changes in the catalytic properties. The catalysts were analyzed by
appropriate methods such as XRD, XPS, XANES, EXAFS, etc.
Taking arsenic oxide as a well known catalyst poison, this paper explains its formation and
accumulation in the wet-bottom boiler type. Deactivation mechanisms and poisoning
models are considered.
Finally, the paper points out the way in which this knowledge has been incorporated into
further developments, resulting in a new generation of catalyst, which is currently being
prepared for introduction onto the market.
4B-135
-------
1. INTRODUCTION
Catalyst aging means "normal" loss of activity during operation as a result of irreversible
processes in the catalyst e.g. sintering. Catalyst poisoning by contrast is a much more
rapid deactivation caused by components of the flue gas.
At the beginning of SCR catalyst development in Germany, unusually high deactivation
rates were, however, measured in the high-dust region downstream of wet-bottom
furnaces, see Fig.1.
Relative activity
7— Dry bottom
, boilers
'4ii£
Slag tap
boilers
4 8 hx103 16
* Operating time
Status 1986
Figure 1. Relative activity of SCR catalysts in dry and wet-bottom boilers versus the service
time.
Extensive measurements in power plants showed that the rapid deactivation is caused by
gaseous arsenic oxide or very fine arsenic oxide covered dust particles. The
concentrations of arsenic oxide in wet-bottom boiler flue gases upstream of the air
preheater is about 100 times higher than in dry-bottom boiler flue gas.
One of the first basic questions was therefore, to find the reason for the much higher
arsenic oxide concentration and to find measures to reduce this influence of catalyst
poisoning.
4B-136
-------
2. WET-BOTTOM BOILERS
The ash recirculation and the very high combustion chamber temperature in wet-bottom
boilers are the main differences to the dry-bottom boiler type. In dry-bottom furnaces the
arsenic oxide concentration is mainly a function of the concentration in the fuel. In wet-
bottom boilers however, ash recirculation increases the concentration from a second
source, the melting of arsenic laden flyash in the combustion chamber see Fig.2.
SG
SCR AH
ESP
A A
Ash recirculation
Slag (CU)
Figure 2. Arsenic circulation in a wet-bottom boiler
Arsenic circulation step by step:
• vaporization of arsenic contained in the fuel
in the combustion chamber by the very high
process temperature
• condensation and absorption of gaseous arsenic
oxide on fly ash particles (especially fines)
• precipitation of the flyash in the electrostatic
precipitator
• recirculation of arsenic oxide laden flyash
from the ESP to the combustion chamber
the circulation continues while arsenic contained in the fuel steadily enters the combustion
process.
4B-137
-------
POSSIBILITIES OF PREVENTING ARSENIC OXIDE ENRICHMENT
Preventing enrichment by complete or partial dust removal
Measurements of arsenic oxide concentration in the individual sections of an electrostatic
precipitator have shown that about 30% of the total of arsenic oxide on the flyash was
bound to the fines fraction of flyash. By partial extraction of this fines fraction which
accounts for only 18% of the total amount of dust, the gaseous arsenic oxide
concentration can be reduced by a factor of 2 - 3, as shown in Fig.3. This potential solution
was not, however, pursued further, since the question of what to do with these fines is still
open for some power plants, rendering this concept financially unattractive for them.
sootblower operation
without duet removal
with IB* duet removal
0 10 20 30 40 50 BO 70 80 90 100
Operating period (hours)
Figure 3. Effect of partial dust removal on the gaseous arsenic concentration
Improvement of Adsorption of Gaseous Arsenic on Flyash or on Additives
Binding gaseous arsenic to a suitable fuel additive proved useful for two reasons. It is a
well-known fact that when the crystalline fraction contained in the ash is high, only very
low concentrations of gaseous arsenic will be present in the flue gas, even if the arsenic
content of the coal was high. In a wet-bottom furnace plant where limestone was added to
the coal to enhance slag flowability, it was also observed that the catalyst deactivation was
much lower. For this reason, systematic measurements have been performed to
4B-138
-------
investigate the effects of limestone dosing to bind arsenic and other volatile metals as
well. Results are given in Fig.4. It can clearly be seen that in this special case, admixture of
limestone to coal reduces the concentration of gaseous arsenic oxide in the flue gas from
700 ug/m3 to less then 100 ug/m3.
700
0.5
1.0 1.5 2.0 S.5 3.0
Metering of limestone (%)
3.5
4.0
Figure 4. Effect of limestone metering on the gaseous arsenic concentration
The reduction of the arsenic deposited on catalyst specimens is particularly striking proof
of the effectiveness of this measure. In Fig.5 the uptake of arsenic by a catalyst as a
function of gaseous arsenic concentration is shown.
300
400
500
600
700
800
Gaseous As-concentratlon (ug/m3N)
Figure 5. Arsenic concentration in the catalyst versus gaseous arsenic concentration
4B-139
-------
All results shown above where gathered (measured) by Siemens from a wet-bottom boiler
with the utilities kind assistance. In spite of these positive results, we do not consider
these measures alone sufficient, since the catalyst could suffer serious damage in matter
of hours in the event that limestone dosing is not available. For this reason it was
imperative to develop catalysts which:
• adsorb less poisoning matter, i.e. have lower
affinity for arsenic than conventional dry-
bottom furnace catalysts
• are less susceptible to arsenic poisoning
3. CATALYTIC MECHANISMS
After having explained the reasons for the high concentration of arsenic oxide in the flue
gas and measures to reduce it, we will now elucidate why this compound can act as a
poison for a DeNOx catalyst.
MODEL OF DENOX CATALYSIS
To thoroughly understand the poisoning mechanisms it is necessary to know about the
undisturbed catalytic mechanisms on the surface of a DeNOx catalyst. Fig.6 shows a more
general model of the SCR process, illustrating the pore system of a DeNOx catalyst
containing pebbles of titanium dioxide joined together by sintered bridges and covered
with an active catalytic layer comprising a mixture of oxides of vanadium and either
molybdenum or tungsten.
6H20
TiO2 with V:05 coating 1
Pore system =
cavity system of
a pebble bed
Catalytic converter
Figure 6. Modell of DeNOx Catalysis
4B-140
-------
We thus consider the catalyst to have the form of a pebble bed in which the surface
structures of the pebbles at the bottom of the bed are accessible via the cavity system of
the bed. Using this model as a basis, the SCR process can now be broken down into 5
steps (see also Fig.7).
1. The reactants first have to be drawn off from the flue gas, which pass the catalyst at a
rate of about 10 m/s, and conducted via the system of pores to the interior surfaces. Large
pores enable gases to be transported rapidly, but at the same time the pebbles should be
as small as possible in order to provide a large specific surface area. A compromise has to
be reached in this respect, because pore size and pebble diameter in any pebble bed are
normally correlated functions. For practical purposes, pebbles with a primary grain size of
about 20 nm, resp. 75 m2/g of specific surface area have proven to be useful.
2. The reactants NH3 and NO are adsorbed by the active sites.
3. The reaction occurs between NH3 and NO at the active sites.
4. The reaction products, N2 and H2O are desorbed.
5. The reaction products leave the pore system via the same route as the reactants were
admitted and become entrained in the flow of flue gases.
— •^~
OH
1
V V
u -H,0-N;-H,0
OH NO OH
1 NO
NHj
OH 0
-\ V
A
V V V V
V y y.s
Figure 7. DeNOx-reaction-path
4B-141
-------
DEACTIVATION CAUSED BY ARSENIC OXIDE
During exposure to flue gases the arsenic oxide is deposited on the surface of the
catalysts. In the event of condensation of the arsenic oxide, this occurs preferentially in
the smallest pores with the highest curvature, so that there may be a narrowing of small
pores, inhibiting the gas transport in steps 1 and 5.
Apart from such physisorptive coverage, a chemical attack of the surface structures by
arsenic has been observed. Both effects reduce the number of active sites necessary for
step 2.
Investigations by X-ray absorption spectroscopy show that the initially deposited As3+ in
arsenic is oxidized to As5 + , forming a structure of isolated orthoarsenate on the catalyst
surface. This implies a reduction of the catalyst and might lead, for instance, to a change
in its reoxidation ability necessary for step 3.
An irreversible selective blocking of NH3 adsorption sites by arsenic oxide is suggested by
infrared spectroscopy studies. These show, in the case of tungsten type catalyst,
pertubations of W = O (terminal oxo group) oscillations by orthoarsenate, analogous to the
reversible adsorption of Lewis bases, such as H20, NH3 or CO.
As a consequence of all these considerations, the pores of a wet-bottom boiler catalyst
should be somewhat larger than in a dry-bottom boiler in order to limit the blocking of
active sites. Furthermore, the chemical composition on the surface should be optimized to
account for arsenic loading. The investigations on this subject are in progress and focuss
especially on differences between tungsten and molybdenum, because catalyst types
based on these active components have shown different behaviour in service.
4B-142
-------
4. NEWLY-DEVELOPED CATALYTIC MATERIAL
Based on our experience with 45 DeNOx-plants in operation with Siemens catalytic
converters (wet and dry-bottom boiler, oil fired, up and downstream of FGD) we are in a
good position to further improve our catalysts. The long-term experience in pilot plants
and in large scale reactors downstream of wet-bottom boilers with arsenic oxide
concentrations greater than 1000 jig/Nm3 indicate how the catalytic material based on
TiC-2, WO3, MoC-3 and V205 was chemically and physically changed. Investigations in
arsenic-deactivated catalytic material show a chemical reduction of its active components
such as vanadium.
For the explanation of the above-mentioned phenomenon, arsenic poisoning tests with
V2O5/MoC>3 as well with TiO2/V2O5/MoO3 systems were performed and compared. TiO2-
free as well TiO2-based material containing MoO3 and a composite oxide of V and Mo. It
was found that this composite oxide is reduced by As2C>3, forming a certain ratio of V5 +
to V4+ by phase transformation without arsenic incorporation. The special feature of this
reduced phase is a portion of stable V5+ which can not be further reduced by arsenic.
Using this stabilized V/Mo precursor for the catalyst preparation, chemical and physical
properties can be achieved which differ from those of the Japanese-licensed catalytic
material.
5. COMPARISON TESTS IN A WET-BOTTOM BOILER
To demonstrate the behavior of different catalytic materials in a long-term test, we exposed
samples prepared as specimen plates to the flue gas of a wet-bottom boiler with a very
high gaseous arsenic oxide concentration of about 700-1200 jjg/Nm3. To accelerate the
deactivation, we exposed the material to a very high gas (resp. arsenic) mass flow in
relation to the surface area.
Catalyst A is a tungsten type material prepared with a coprecipitation method, catalyst B is
a molybdenum type Siemens innovation for wet-bottom boilers and type C is a new
catalyst also based on TiO2, prepared with this special arsenic oxide resistant V/Mo-
precursor.
4B-143
-------
Figure 8 compares the physical and chemical properties of the fresh material.
Properties
Activity fresh 350°C Nm3/m2h
SC>2 - conversion const Nm^/m^h
BET surface area m2/g
Porevolume mm^/g
e
Poremaximum A
Type A
34,5
83
79
272
70-100/40-50
TypeB
38,1
112
76
229
100-150/50-60
TypeC
46,5
221
73
292
900-1500/150
Figure 8. Comparison of different catalytic materials
Figure 9, 10 and 11 compare the properties of catalytic activity, inner surface and pore
volume before and after 1800 h operation in the above-mentioned flue gas.
Figure 9 clearly shows, that the newly-developed catalyst has the highest activity
combined with lowest deactivation which can be traced to the different pore size
distribution (see Fig. 12) and the highly stabilized precursor as regards poisoning.
50 -
30
measuring conditions:
T = 350°C
O2 4Vol%
H2O = 10 Vol%
NO = 400 vpm
NH3 = 400 vpm
LV =4 m/s (350°C)
before exposure
after exposure
Type
Figure 9. Comparison of the catalytic activity before and after exposure
4B-144
-------
Fig. 10 and 11 demonstrate the possibility of reducing the influence of the arsenic oxide
condensation to the inner structure.
90 -
80 -
*? 70 "
E 60
S 50 -
w
g 40 -
ffl
1 30 J
«
Hi 20-
m
10 -
| ] before exposure
{' i T;| after exposure 3SO
I
I
,,
,,>
N i
— -
; >
, ',
'
^ ',
V'--'
¥
i-
300-
-51
E
E
o, 200
3
O
£
o 100-
a.
| | before exposure
KtiSJj after exposure
-
— ,
Type
Figure 10. Comparison of the inner
surface before and after exposure
Type ABC
Figure 11. Comparison of the pore volume
before and after exposure
Figure 12 shows the pore size distribution of the catalyst type A and type C in comparison.
pore volume
ml/g
0,20
0,08 -
type A
MINI ! 1 I MUM I ! T
10' 10'
0,26
0,20
0,14 -
0.08
0,02
pore radius A
type C
—run i i i i—mm i ;—i—inn 11 i—i—inn 11 i—r
105 10s 103 102
pore radius A
Figure 12. Comparison of the pore size distribution of type A and C
4B-145
-------
To improve a catalytic material for applications in S02-laden gases, especially for fuels
with a very high sulfur content such as some American coals, it is necessary to reduce the
SO2 oxidation rate. The feature of the composite oxide and the pore size distribution (see
Fig. 12) leads to an increase in DeNOx catalytic activity without increasing the SO2
conversion rate. In other words, the SO2 conversion and the SO3 production rate can be
limited to very low levels.
The activity and S02 conversion rate of the newly-designed catalyst can be adjusted by
the amount and composition of the precursor. In Fig.13 the catalytic activity and the
reaction constant for SC>2 conversion are compared for different compositions of type A
(tungsten type) and type C (newly-developed type).
It can be clearly seen, that at fixed S02 reaction constant, the catalyst volume can be
reduced by about 15 %. The major advantage for high-dust applications however is the
reduction of the 803 production by a factor of about 2.6 ( 350°C), consequently minimizing
the corrosion problems in downstream facilities.
300 -
200 -
100
0 30
type A
Figure 13. Comparison of the
types
40 ..
KNOx
value versus
45
typeC
for two different catalyst
4B-146
-------
6. CONCLUSIONS
When retrofitting power plants in the US with SCR systems, the very different flue gas
compositions have to be considered on a case-to-case basis, tailoring the catalytic
converter to specify plant requirements. Improved catalysts feature durability against
poison laden gases and reduced S02 conversion rates.
Faced with this spectrum of requirements, Siemens AG Power Generation Group (KWU) is
in a position to offer an improved catalytic material with low SO2 oxidation and low
deactivation rates combined with the advantage of a plate type shape for high-dust
applications.
To demonstrate these combined advantages, we are ready to supply this type of catalytic
converter to pilot or demonstration plants in the US.
4B-147
-------
Appendix A
LIST OF ATTENDEES
-------
1991 Joint Symposium on Stationary Combustion NOx Control
03/25/91-03/28/91
The Capital Hilton
Washington DC
List of Attendees
Jan van der Kooij
Environmental Affairs Dept.
Sep/Dutch Elec.Generating Board
Utrechtseweg 310
6812 AR Arnhem
THE NETHERLANDS
+31/85 721473
Pierre van Grinsven
Senior Development Engineer
KSLA - Ron Shell Lab Amsterdam
Badhuisweg 3
1031 CM Amsterdam
THE NETHERLANDS
020/303818
Hamid Abbasi
Mgr., Applied Combustion Research
Institute of Gas Technology
4201 West 36th Street
Chicago, IL 60632
312/890-6431
Andris Abele
Program Supervisor
So.Coast Air Quality Mgmt.District
9150 Flair Drive
El Monte, CA 91731
818/572-6491
Alberto Abreu
Sr Air Pollution Ctrl Engr
San Diego Air Pollution Ctrl Dist
9150 Chesapeake Dr
San Diego, CA 92123
619-694-3310
Jerry Ackerman
Mgr., Contract Research Marketing
Babcock & Wilcox
1562 Beeson Street
Alliance, OH 44601
216/829-7403
Rau Acosta
Asst. Ops. Supt.
Florida Power & Light
P. 0. Box 13118
Ft. Lauderdale, FL 32316
305/527-3543
Michael Acme
Senior Proj. Engineer
Kilkelly Environmental
P. 0. Box 31265
Raleigh, NC 27622
919/781-3150
Ken Adams
Senior Scientist
Ontario Hydro
700 University Avenue
Toronto, Ontario
M5G 1X6 CANADA
416/592-4333
Rul Afonso
Senior Engineer
New England Power
Research 5- Development
25 Research Tlrjve
Westborough, MA 01582
N/A
Bhuban Agarwn!
Gen. Mgr., EA Division
Foster Wheeler Energy Corp.
8 Peach Tree Hill Road
Livingston NJ 07039
201/535-2372
Annette Ahart
Section Leader
EG&G WASC, Inc.
P. 0. Box 880
Morgantown, WV 26507-0880
304/291-4463
A-1
-------
Raymond Aichner
Supv.Plant Engineering
Southern California Edison
6635 S. Edison Drive
Oxnard, CA 93033
805/986-7244
Jeffrey Allen
Special Combustion Projects Manager
NEI-International Combustion Ltd.
Sinfin Lane
Derby DE2 99J
ENGLAND
332 271111
Maurice Alphandary
N/A
AEA Technology ETSU
B156 Harwell Laboratory
Oxfordshire 0X11 ORA 44
UNITED KINGDOM
N/A
Leonard Angello
Technical Manager
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94304
415/855-2873
Patrick Aubourg
Manager, R&D
Owens Corning Fiberglass
2790 Columbus Road, Rte.16
Granville, OH 43023
614/587-7604
Robert Badder
Power Production Manager
City of Independence Power & Light
21500 E. Truman Road
Independence, MO 64056
816/796-4400
P Baimbridge
First Engineer
PowerGen Pic.
Moat Lane, Solihull
West Midlands
ENGLAND
(ENG.)021-701-3873
Aldo Baldacci
Manager
ENEL-CRTN
Via A. Pisano, 12
Pisa 56100
ITALY
0039/50-535744
Lothar Balling
Manager, DeNOx
Siemens KWU/T123
Frauenauracherstr. 85
Erlangen, 8520 GERMANY
9131/186151
Maureen Barbeau
Conference Coordinator
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94304
415/855-2J27
Joe Barklcy
Chemical Engineer
Tennessee Valley Authority
P. 0. Box 150
West Paducah, KY 42086
502/444-4657
William Bartok
Senior Vice President
Energy & Environmental Research
P. 0. Box 189
Whitehouse, MJ 08888
908/534-5833
R. J. Batyko
Mgr., Environmental Projects
Babcock & Wilcox
20 S. Van Duren Ave.
Barberton, OH 44203
216/860-1654
Frank Bauer
Corporate Consultant
Stone & Webster
Three Executive Campus
Cherry Hill, NJ 08034
609/482-3284
A-2
-------
Nick Bayard de Volo
President
ETEC
One Technology, Suite 1-809
Irvine, CA 92718
714/753-9125
Peter Beal
Manager, Business Development
NEI-International Combustion Ltd.
Sinfew Lane
Derby
ENGLAND
332/27 11 11
Frank Beale
Mgr., Boiler Burner Systems
John Zink Company
4401 South Peoria Ave
Tulsa, OK 74170
918/748-5180
Robert Becker
President
Environex, Inc.
P. 0. Box 159
Wayne, PA 19087
215/975-9790
Janos Beer
Scientific Director
Massachusetts Instit. of Technology
MIT Combustion Research Facilities
Cambridge, MA 02139
617/253-6661
Edward Behrens
Product Manager, DeNOx
Joy Environmental Equipment Co.
404 E. Huntington Drive
Monrovia, CA 91016-3633
818/301-1215
F. Bennett
Sr. Systems Engineer
Potomac Electric Power
1900 Pennsylvania Ave., N.W.
Washington, DC 20068
202/872-2442
Mogens Berg
N/A
ELKRAFT Power Company Ltd.
Lautruphoj 5
DK-2750 Ballerup
DENMARK
+45 42 65 61 04
Elliot Berman
President
Project Sunrise, Inc.
6377 San Como Lane
Camarillo, CA 93012
805/388-0208
Leif Bernergard
Technical Officer
Swedish Environm.Protection Agency
S-171 85 Sotna
SWEDEN
+468 799 11 19
Naum Bers
N/A
Consultant
2111 Jefferson Davis Highway
Apt. 1219 North
Crystal City, VA 22202
N/A
Kamal Bhattacharyya
Head, Emissions Evaluation
Ministry of Environment
Air Management Branch
810 Blanshard Street
Victoria, BC V8V 1X5 CANADA
604/387-9946
Ramon Biarno.s
Managing Director
Land Combustion
2525-B Pearl Buck Rd
Bristol, PA 19007
215-781-0810
Richard Biljetina
Assistant Vice President
Institute of nas Technology
3424 S. State
Chicago, IL 60616
312/890-6418
A-3
-------
Gary Bisonett
Senior Steam Gen.Engineer
Pacific Gas & Electric Co.
245 Market Street, 434A
San Francisco, CA 94106
415/973-6950
John Bitler
President
Environmental Catalyst Consultants
P. 0. Box 247
Spring House, PA 19477
215/628-4447
Verle Bland
Emissions Control Supervisor
Stone & Webster
P. 0. Box 5406
Denver, CO 80217-5406
303/741-7684
Richard Boardman
Senior Engineer
Westinghouse Idaho Nuclear Co.
P. 0. Box 4000 MS 5218
Idaho Falls, ID 83402
208/526-3732
Danny Bolerjack
Maintenance Foreman
Alabama Power Co.
Miller Steam Plant
4250 Porter Road
Quinton, AL 35130
205/674-1207
Richard Borio
Executive Consulting Engineer
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-2229
Steven Bortz
Manager, Western Lab
Research-Cottrell Envir.Serv/Tech.
9351 B Jeronimo
Irvine, CA 92718
714/830-2255
Ernest Bouffard
Senior Air Pollution Control Engr.
State of Connecticut
165 Capitol Ave., Room 136
Hartford, CT 06106
203/566-8230
Richard Boyd
Program Manager
Radian Corporation
2455 Horsepen Road
Herndon, VA 22011
703/834-1500
Bernard Breen
President
Energy Systems Associates
1840 Gateway Three
Pittsburgh, PA 15222
412/392-2380
Fiorenzo Bregani
Senior Researcher
ENEL-CRTN
Milan, ITALY
N/A
John Brewster
Ass't. Plant Manager
Cajun Electric
112 Telly Street
New Roads, LA 70760
504/638-3773
Frank Briden
Chemist
U. S.Environmental Protection Agency
Air & Energy Eng'g Research Lab.
Research Triangle Park, NC 27711
919/541-7808
Das lav Brklc
Manager/Chemical & Envir. Catalysts
UOP
25 East Algonquin Road
Des Plains, TL 60017-51017
708/391-2677
A-4
-------
R. G. Broderick
Consultant
RJM Corporation
10 Roberts Lane
Ridgefield, CT 06877
203/438-6198
Bert Brown
Vice President, Technology
Joy Environmental Equipment Co.
404 E. Huntington Drive
Monrovia, CA 91016-3633
818/301-1172
William Browne
Environmental Engineer
U.S.Environmental Protection Agency
841 Chestnut Bldg.
Philadelphia, PA 19107
215/597-6551
C. P. Brundrett
Manager, Emission Control
W. R. Grace & Co. - Conn.
10 East Baltimore St.
Baltimore, MD 21202
301/659-9125
Hans Buening
Sen. Staff Engineer
Radian Corporation
7 Corporate Park
Irvine, CA 92714
714/261-8611
Galen Bullock
Project Engineer
Carolina Power & Light
P. 0. Box 1551
Raleigh, NC 27602
919/546-2768
Daniel Butler
Deputy Group Leader
Los Alamos National Laboratory
Group T-3, MS B216
Los Alamos, NM 87545
505/667-9099
Gary Camody
Product Mgr., Burner Systems
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-5039
E. J. Campobenedetto
Mgr.,NOx Control Systems
Babcock & Wilcox
P. 0. Box 351
Barberton, OH 44203
216/860-6762
Gene Capriotti
Vice President, Sales
Nalco Fuel Tech
2001 West Main St., Ste. 295
Stamford, CT 06902
203/323-8401
Ben Carmine
Supervising Engineer
Houston Lighting & Power Co.
P. 0. Box 1700
Houston, TX 77251
713/922-2191
Steven Carpenter
Market Analyst
Diamond Powor
P. 0. Box 415
Lancaster, OH 43130
614/687-4363
Doug Carter
General Engineer
U.S. Department of Energy
1000 Independence Ave., S.W.(FE-4)
Washington, DC 20585
202/586-1188
Carlo CastaJdini
Project Manager
Acurex Corporation
555 Clyde Avenue
P. 0. Box 7044
Mountain View, CA 94039
415/961-5700, X3219
A-5
-------
P. Cavelock
Sr. Project Engineer
Potomac Electric Power
1900 Pennsylvania Ave.,
Washington, DC 20068
202/872-2447
N.W.
Charles Chang
Mechanical Engrg.
L.A. Department of Water & Power
P. 0. Box 111
Los Angeles, CA 90051-0100
213/481-3235
Kwok-Ping Ching
Environmental Protection Officer
Environ.Protect.Dept.,Hong Kong Gov
28thfloor, Southern Centre
130 Hennessy Road
Wan Chai, HONG KONG
852-8351074
Roger Christman
Program Manager
Radian Corporation
2455 Horsepen Road
Herndon, VA 22071
703/834-1500
Landy Chung
President
Phoenix Combustion, Inc.
P. 0. Box 2257
Ashtabula, OH 44004
216/964-6396
Ed Cichanowicz
Project Manager
Electric Power Research Institute
1019 Nineteenth St, N.W.
Suite 1000
Washington, DC 20036
202/293-7515
David Clay
Manager
Kraftanlagen Heidelberg
c/o AUS, 1140 East Chestnut Ave.
Santa Ana, CA 92701
714/953-9922
John Cochran
Ass't.Group Leader,Air Qual.Control
Black & Veatch
8400 Ward Parkway
P.O. Box 8405
Kansas City, MO 64114
913/339-2190
Thomas Coerver
Engineer Supervisor
Louisiana Dept.of Environ.Quality
P. 0. Box 44096
Baton Rouge, LA 70804
504/342-8912
Mitch Cohen
Consultant
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-2482
William Coler
Senior Marketing Specialist
Babcock & Wilcox
1562 Beeson
Alliance, OH 44601
216/829-7317
Robert Collette
Project Mgr., Low NOx Projects
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-5687
Richard Col l.ins
Mechanical Engineer
Tennessee Valley Authority
1101 Market Street (MR 3B)
Chattanooga, TN 37402-2801
615/751-7935
Robert Combs
Corporate Research Specialist
Virginia Power
Innsbrook Technical Center
5000 Dominion Blvd.
Glen Allen, VA 23060
804/273-2975
A-6
-------
Joseph Comparato
Hgr., Process Development
Nalco Fuel Tech
P.O. Box 3031
1001 Frontenac Road
Naperville, IL 60566-7031
708/983-3247
Raymond Connor
Technical Director
Industrial Gas Cleaning Institute
1707 L Street, N.W., Ste. 570
Washington, DC 20036
202/457-0911
Thomas Cosgrove
Manager, Testing Services
Research-Cottrell Envir.Serv/Tech.
P. 0. Box 1500
Somerville, NJ 08876
908/685-4619
David Cowdrick
Senior Engineer
Tampa Electric Co.
P. 0. Box 111
Tampa, FL 33601
813/228-4111,X46269
H.Tom Creasy
Engineer
Virginia Dept.Air Pollution Control
P. 0. Box 10089
Richmond, VA 23240
804/786-0178
David Crow
Manager, Faber Div.
Tampella Keeler
2600 Reach Road
Williamsport, PA 17756
717/326-3361
D. P. Cummings
Associate Engineer
Ontario Hydro
700 University Avenue
Toronto, Ontario M5G 1X6
CANADA
416/592-4505
Donna Currie
Engineer ing-Generating
Potomac Electric Power
1900 Pennsylvania Ave., N.W.
Washington, DC 20068
202/331-6280
G. D'Anna
Ansaldo Component! Representative
Ansaldo Component!, B&W Interntl.
c/o Babcock & Wilcox International
20 South Van Buren Ave.
Barberton, OH 44203
216/860-6029
Manny Dahl
PEPS, Project Manager
Babcock & Wilcox
20 South Van Buren
Barberton, OH 44203
216/860-6634
Donna Dant
Environmental Engineer
Louisville Gas & Electric
P. 0. Box 32010
Louisville, KY 40332
502/627-2343
R. M. Davies
Manager, Engineering Science
British Gas Pic
Midlands Research Station
Solihull, West Midlands B91 2JW
ENGLAND
0/21-705-7581
Charles Davis
Sr. Staff Engineer
Virginia Power
5000 Dominion Blvd.
Glen Allen, VA 23060
804/273-2619
Michael Deland
Chairman
President's Council/Environ.Quality
Executive OFfice of the President
The White House
Washington, DC
N/A
A-7
-------
Mukesh Desai
Supervisor, Env. Technology
Bechtel
9801 Washington Blvd.
Gaithersburg, MD 20878
301/417-3158
Arun Deshpande
Abatement Engineer
Ministry of Environment
A.P.I.O.S. Office
135 St. Clair Ave.,W, StelOOO
Toronto, Ontario,M4V 1P5 CANADA
416/323-5055
Larry Devillier
Eng.Supervisor, Air Permits
Louisiana Dept.of Environ.Quality
P. 0. Box 44096
Baton Rouge, LA 70804
504/342-8926
J.G. DeAngelo
N/A
New York State Electric & Gas
4500 Vestal Parkway, E.
Binghamton, NY 13902
607/729-2551
N. N. Dharmarajan
Principal Engineer
Central & South West Services
1616 Woodall Rodgers Freeway
Dallas, TX 75202
214/754-1373
Richard Diehl
Dir.,Coal Tech.,Energy Tech Office
Textron Defense Systems
2385 Revere Beach Parkway
Everett, MA 02149
617/381-4282
Daniel Diep
Senior Research Engineer
Nalco Fuel Tech
One Nalco Center
Naperville, IL 60563-1198
708/305-2047
Joseph Diggins
Mgr. Pittsburgh District Sales
Foster Wheelor Energy Corp.
300 Corporate Center Dr. Ste.130
Coraopolis, PA 15108
412/264-0611
Roger Dodds
Air Quality Engineer
Wisconsin Electric Power
333 W. Everett St.
Milwaukee, WI 53201
414/221-2169
Patrick Doherty
Senior Engineer
Coastal Power Production Co.
310 First Street, 5th floor
Salem, VA 24153
703/983-4365
Stephen Doll
District Manager
Riley Stoker Corporation
4108 Park Road, #315
Charlotte, NC 28209
704/527-8877
Brandon Donahue
Client Manager
ABB Combustion Engineering
1200 Ashwood Parkway, NE
Suite 510
Atlanta, GA 30338
404/394-2616
Les Donaldson
Mgr., Emissions Control Research
Gas Research [nstitute
8600 W. Bryn Mawr Avenue
Chicago, II, 60631
312/399-8295
Dirk Doucet
N/A
Gulf States Utilities
P. 0. Box 2951
Beaumont, TX 77704
409/838-6631
A-8
-------
Barry Downer
Boiler Engineer
National Power PLC
Whitehil Way Swindon
Wilts, ENGLAND
(SWINDON) 892263
Brian Doyle
Principal
Brian Doyle Engineering
Six Sunset Road
Putnam Valley, NY 10579
914/528-0139
John Doyle
Sales Engineer
Babcock & Wilcox
7401 W. Mansfield Ave, Ste.410
Lakewood, CO 80235
303/988-8203
Dennis Drehmel
Dpty.Dir..Pollution Control Div.
U.S.Environmental Protection Agency
AEERL (MD-54)
Research Triangle Park, NC 27711
919/541-7505
H.C.W. Drop
N/A
Rodenhuis & Verloop
Oosterengweg 8
1221 JV Hilversum
THE NETHERLANDS
+31 35 88 1211
Richard Dube
Consultant
Stone & Webster
245 Summer Street
Boston, MA 02107
617/589-7831
J. D.M. Dumoulin
N/A
EPON
Dr. Stolteweg 92
8025 AZ Zwolle
HOLLAND
038/ 27 29 00
David Duncan
Air Permits Coordinator
Texas Utilities Electric
400 N. Olive St., LB 81
Dallas, TX 75201
214/812-8479
Hao Duong
Engineer
Dayton Power &. Light
P. 0. Box 468
Aberdeen, OH 45101
513/549-2641,X5832
Michael Durham
Vice President, R&D
ADA Technologies, Inc.
304 Inverness Way South
Suite 110
Englewood, CO 80112
303/792-5615
Michael Durilla
Sr. Tech. Service Engineer
Engelhard Corporation
101 Wood Avenue
Iselin, NJ 08830-0770
908/205-6644
Hans-Jurgen Ourselen
Engineer
RWE Energie AG
Lannerstr. 30
405D Monchenglodbach 4
Essen, GERMANY
02166/58943
George Dusatko
Vice President & Gen. Mgr.
Energy Systems Associates
1840 Gateway Three
Pittsburgh, PA 15222
412/392-2372
Richard Dye
General Engineer
U.S. Department of Energy
FE-4
Washington, DC 20585
202/586-6499
A-9
-------
Owen Dykema
President
Dykema Engineering, Inc.
23429 Welby Way
Canoga Park, CA 91307
818/348-3751
Ed Ecock
Steam Gen.Engineer
Consolidated Edison of N.Y.
Four Irving Place
New York, NY 10003
212/460-4830
Raj Edwards
President
EnviroTech International
335 Park St, NE
Vienna, VA 22180
703/938-5138
D. R. Eisenmann
V.P.,SCR Systems Div.
Peerless Mfg. Co.
2819 Walnut Hill Lane
Dallas, TX 75229
214/357-6181
John Eldridge
Prof.of Chemical Engineering
University of Massachusetts
39 Kendrick Place
Amherst, MA 01002
413/253-5991
William Ellison
Director
Ellison Consultants
4966 Tall Oaks Drive
Monrovia, MD 21770
301/865-5302
Thomas Emmel
Senior Staff Engineer
Radian Corporation
3200 East Chapel Hill Road
Research Triangle Park, NC 27709
919/541-9100
Michael Escarcega
Sr. Environmental Engineer
Southern California Edison
P. 0. Box 800
2244 Walnut Grove Ave.
Rosemead, CA 91770
818/302-4032
Art Escobar
Environmental Engineer
Virginia Dept.Air Pollution Control
9th Street Office Bldg.
Richmond, VA 23219
804/786-5783
David Eskinazi
Project Manager
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94304
415/855-2918
Lee Ewing
Engineer
U.S. Department of Energy
9141 Vendome Drive
Bethesda, MD 20817
301/353-5442
Nancy Exconde
Proposal Manager
Babcock & WiIcox
74 E. Robinson Avenue
Barberton, OH 44203
216/860-2320
Edward Farkas
Senior Engineer
Canadian Gns Research Institute
55 Scarsdaln Road
Don Mills, Ontario
M3B 2R3, CANADA
416/447-6465
Hamld Farzan
Sr. Research Engineer
Babcock & Wilcox
1562 Beeson St.
Alliance, OH 44601
216/829-7385
A-10
-------
Michael Fatigati
Liaison Engineer
Babcock & Wilcox
4332 Cerritos Ave. Ste.204
Los Alamitos, CA 90720
714/236-0432
George Feagins
Environmental Engineer Senior
Virginia Dept.Air Pollution Control
121 Russell Road
P. 0. Box 1190
Abingdon, VA 24210
703/676-5582
Paul Feldman
Director R&D
Research-Cottrell Envir.Serv/Tech.
P. 0. Box 1500
Somerville, NJ 08876
908/685-4880
W. K. Felts
Air Quality Regulatory Analyst
Potomac Electric Power
1900 Pennsylvania Ave., N.W.
Washington, DC 20068
202/331-6179
James Ferrigan
N/A
Wahlco, Inc.
4707 College Blvd.
Leawood, KS 66211
913/491-9292
Abe Finkelstein
Chief, Clean Air Technologies
Environment Canada
-Unit 100 Asticou Center
Hull, Quebec
CANADA
819/953-0226
Tom Fletcher
Combustion Research Facility
Sandia National Laboratories
P. 0. Box 969
Livermore, CA 95376-0969
415/294-2584
John Foote
Senior Engineer
University of Tennessee
Space Institute
B.H. Goethert Parkway
Tullahoma, TN 37388
615-455-0631
John GaitskiJI
Engineer
U. S.Environmental Protection Agency
230 South Dearborn
Chicago, IL 60604-1504
312/886-6705
Ivo Galliuberti
Professor
University of Padova
Via Gradenigo 6A
35131 Padovn
ITALY
33/49-828-7541
Michael Gamburg
V.P., Western States Op.
Todd Combustion, Inc.
61 Taylor Reed Place
Stamford, CT 06906
203/359-1320
Wayne Gensler
Combustion Engineer
Selas Corporation America
P. 0. Box 200
Dreslier, PA 19025
215/283-8338
Robert Giammar
Mgr.,Process Engineering Dept.
Battelle Memorial Institute
505 King Avenue
Columbus, OH 43201
614/424-7701
A. F. Gi1lespie
Engineering Manager
Foster Wheeler Ltd.
P. 0. Box 3007
St. Catharines, Ontario
CANADA
416/688-4434
A-11
-------
Dan Giovanni
President
Electric Power Technologies, Inc.
P. 0. Box 5560
Berkeley, CA 94705
415/653-6422
Philip Goldberg
Coal Utilization Division
Pittsburgh Energy Tech. Center
P. 0. Box 10940, MS 922H
Pittsburgh, PA 15326
412/892-5306
Toby Gouker
Mgr., Stationary Emission Control
W. R. Grace & Co. Conn.
7379 Rt. 32
Columbia, MD 21044
301/531-4131
Loic Gourichon
Engineer
CERCHAR
Rue Aime Dubost
62670 Mazingarbe
FRANCE
33/21 72 81 88
Mary A. Gozewski
Editor
Coal & Synfuels Technology
1401 Wilson Blvd., Suite 900
Arlington, VA 22209
703/528-1244
Martin Grant
Senior Engineer
AUS Combustion Systems, Inc.
1140 East Chestnut Ave.
Santa Ana, CA 92701
714/953-9922
Michael Grimsberg
Tekn. Lie.
University of Lund
Dept. of Chem. Eng.II.Box 124
S-221 00 Lund
SWEDEN
+46/46-108276
John Grusha
Mgr.,Firing Systems Engrg.
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-3497
Manoj Guha
Mgr., Technical Assessment
American Electric Power
One Riverside Plaza
Columbus, OH 43220
614/223-1285
James Guthrie
Assoc.Air Resources Engineer
State Air Resources Board
P. 0. Box 2815
Sacramento, CA 95812
916/327-1508
Steven Guzlnski
Mechanical Engineer
Naval Energy & Envir.Support Activ,
NEESA-11A
Port Hueneme, CA 93043-5014
805/982-5388
Greg Haas
Mechanical Engineer
Exxon Research and Engineering
2800 Decker Drive
Baytown, TX 77522
713/425-7892
Donald Hagar
President
Damper Design, Inc.
1150 Mauch Chunk Rd.
Bethlehem, PA 18018
215/861-0111
Leo Hakka
Project Development Mgr.
CANSOLV
Union Carbide Canada Ltd.
Box 700, Pofnte-Aux-Trembles
Quegec H1B 5K8 CANADA
514/4993-2617
A-12
-------
Robert Hall
Branch Chief
U.S.Environmental Protection Agency
Combustion Research Branch (MD-65)
Research Triangle Park, NC 27711
919/541-2477
M. Halpern
Proj.Licensing Coor.-Gen.Engrg.
Potomac Electric Power
1900 Pennsylvania Ave., N.W.
Washington, DC 20068
202/331-6489
David Ham
President
EnviroChem, Inc.
54 Bridge Street
Lexington, MA 02173
617/863-1334
Doug Hammontree
Project Manager
Burns & McDonnell
4800 East 63rd Street
Kansas City, MO 64141-6173
816/822-3115
Frank Harbison
Senior Analyst
Louisiana Power & Light
P. 0. Box 60340, Unit N-31
New Orleans, LA 70160
504/595-2308
Stan Harding
Vice President
RE I
317 Marion Drive
McMurray, PA 15317
412/941-9202
Robert Hardman
Research Engineer
Southern Company Services
P. 0. Box 2625
Birmingham, AL 35202
205/877-7772
Doug Hart
Prin.Engr., Firing Systems
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-2439
S. Hashemi
Sr. Project Engineer
Potomac Electric Power
1900 Pennsylvania Ave., N.W.
Washington, DC 20068
202/331-6495
Gary Hausman
Project Engineer
Pennsylvania Power & Light
Two North Ninth Street
Allentown, PA 18101
215/774-6562
Robert Hayes
Operations Specialist
Illinois Power Co.
500 S. 27th Street
Decatur, II, 62525
217/424-8101
John Healy
Mgr.,Generating Schedule/Cost
Potomac Electric Power
1900 Pennsylvania Ave., N.W.
Washington, DC 20068
202/872-3596
Dennis HelfrUch
Mgr., Technology Assessment
Research-Cottrell Envir.Serv/Tech
P. 0. Box 1500
Somerville, NJ 08876
908/685-4147
Todd He11ewe 11
Engineering Support Manager
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-4919
A-13
-------
R. Henry
Sr. Project Engineer
Potomac Electric Power
1900 Pennsylvania Ave., N.W.
Washington, DC 20036
202/872-2441
Mark Hereth
Senior Chemical Engineer
Radian Corporation
2455 Horsepen Road
Herndon, VA 22071
703/834-1500
Andrew Hetz
Environmental Engineer Senior
Virginia Dept.Air Pollution Control
7701 Timberlake Road
Lynchburg, VA 24502
804/947-6641
Steven Higgins
Engineer, R&D
Pennsylvania Electric Co.
1001 Broad Street
Johnstown, PA 15907
814/533-8883
Duane Hill
Mrg., Performance Admin.
Dairyland Power Coop
3200 East Ave. S
LaCrosse, WI 54602
608/787-1424
Richard Himes
Project Engineer
Fossil Energy Research Corp.
23342 C South Pointe
Laguna Hills, CA 92653
714/859-4466
Anna Hinderson
Process Engineer
ABB Carbon AB
612 82 Finspong
SWEDEN
+46-122 81000
John Hofmaim
Vice President, Engineering
Nalco Fuel Tech
1001 Frontenac Road
Naperville, II, 60563
708/983-3252
Gerald Hollinden
Sr. Program Manager
Radian Corporation
633 Chestnut Street
Chattanooga, TN 31450
615/755-0811
Kevin Hopkins
Senior Engineer
Carnot
15991 Red HilJ Road
Suite 110
Tustin, CA 92680-7388
714/259-9520
Richard Hobchkiss
N/A
National Power
Kelvin Ave., Leatherhead
Surrey KT22 7SE
ENGLAND
703-374488
Reagan Houston
President
Houston Consul |-.ing, Inc.
252 Foxhunt Lane
Hendersonvilie, NC 28739
704/642-3722
Vincent Huang
Program Manager
A. 0. Smith Corp.Technology
12100 W. Park Place
Milwaukee, WT 53224
414/359-4255
Alex Huhmann
Mgr.,Air Pollution Control Sys
Public Service Electric & Gas
80 Park Plaza
P. 0. Box 570, MC-19E
Newark, NJ 07101
201/430-6997
A-14
-------
Terry Hunt
Professional Engineer
Public Service Company of Colorado
5900 East 39th Avenue
Denver, CO 80207
303/329-1113
Peter Imm
Principal Engineer
Olin Corporation
P. 0. Box 2896
Lake Charles, LA 70602
318/491-3481
Ivan Insua
Senior Engineer
Salt River Project
P. 0. Box 52025
Phoenix, AZ 85072-2025
602/236-5240
Robin Irons
Team Leader, NOx Control Tech.
PowerGen
Ratcliffe Technology Centre
Ratcliffe-on-Soar
Nottinghamshire, NG11 OEE, ENGLAND
602/830591, X2437
Bruce Irwin
Engineering Manager
Hauck Manufacturing Co.
P. 0. Box 90
Lebanon, PA 17042
717/272-3051
Reda Iskandar
V.P., Sales & Marketing
Cormetech, Inc.
8 E. Denison Parkway
Corning, NY 14831
607/974-4313
Keijo Jaanu
Technology Development Mgr.
KEMIRA, Inc.
P. 0. Box 368
Savannah, GA 31402
912/236-6171,X149
Rudolf Jaerschky
Director, Power Plant Department
Isar-Amperwerke AG (IAW)
Brienner Strasse 40
Munchen 2, GERMANY 8000
089/5208-2621
James Jarvis
Senior Staff Engineer
Radian Corporation
8501 Mo-Pac Blvd.
Austin, TX 78720-1088
512/454-4797
Jeff Jensen
Civil/Mechanical Design Supervisor
Wisconsin Public Service Corp.
600 North Adams
Green Bay, WI 54307
414/433-1864
Ken Johnson
Environmental Affairs Manager
Duke Energy Corporation
400 S. Tryon St.
Wachovia Center
Charlotte, NC 28202
704/373-5089
Larry Johnson
Project Manager
Southern California Edison
2131 Walnut Grove Avenue
Rosemead, CA 91770
818/302-8542
Robert Johnson
Regional Sains Manager
Wahlco, Inc.
4707 College Blvd., Suite 201
Leawood, KS 66211
913/491-9292
Steve Johnson
Vice President
PSI Technology Co.
20 New England Business Center
Andover, MA 01810
508/689-0003
A-15
-------
Dale Jones
N/A
Noell, Inc.
1401 East Willow Street
P.O. Box 92318
Long Beach, CA 90800-2318
213/595-0405
Anda Kalvins
Environ.Studies Specialist
Ontario Hydro
700 University Avenue
Toronto, Ontario M5G 1X6
CANADA
416/592-3193
Bent Karll
Senior Manager
Nordic Gas Technology Centre
Dr. Neergaards Vej 5A
DK-2970 Horsholm
DENMARK
45/45 76 69 95
Anders Karlsson
Reporter
Technical Outlook
Swedish Off.of Science & Tech.
600 New Hampshire Ave., N.W.
Washington, DC 20037
202/337-5170
Hans Karlsson
Professor
University of Lund
Dept. of Chem.Eng. II, Box 124
S-221 00 Lund
SWEDEN
+46/46-108244
Wally Karrat
Advisory Engineer
IBM T.J.W. Research
Route 134
P. 0. Box 218
Yorktown Heights, NY 10598
914/945-35166
Borchert Kassebohm
Director
Stadtwerke Dusseldorf AG
Am Wiedenhof 7
D 4000 Dusseldorf, GERMANY
0211/821-2459
Randy Kaupang
Air Pollution Control Engineer
Burns & McDonnell
4800 East 63rd Street
Kansas City, MO 64141-6173
816/333-4375
Bruce Kautsky
Boiler Specialist
United Engineers & Constructors
460 E. Swedes ford Rd
Wayne, PA 19087
215-254-5155
Donald Kaweckl
Section Manager
Foster Wheeler Energy Corp.
Perryville Corporate Park
Clinton, NJ 08809
908/730-5466
Jim Kennedy
Service Rep
Foster Wheeler Energy Corp.
2001 Butter field Road
Downers Grovo, IL 60515-1050
708/241-2850
Stephen Kerho
Consulting Engineer
Electric Power Technologies, Inc.
24672 Venablo Lane
Mission Viejn, CA
714/380-7316
Tanveer Khan
R&D Engineer
Ahlstrom Pyropower, Inc.
8970 Crestmar Point
San Diego, CA 92121
619/552-2323
A-16
-------
Mark Khinkis
Asso.Dir.,Applied Combustion Res,
Institute of Gas Technology
4201 West 35th Street
Chicago, IL 60632
312/890-6452
J.Leslie King
Combustion Engineering Manager
Babcock Energy Ltd.
Porterfield Road
Renfrew, PA4 8DJ
SCOTLAND
41/886-4141
Allan Kissam
Senior Salesman
Joy Environmental Equipment Co.
404 E. Huntington Drive
Monrovia, CA 91016-3633
818/301-1100
Edward Kitchen
Senior Engineer
Fichtner USA, Inc.
Overlook 1, Suite 360
2849 Paces Ferry Rd., NW
Atlanta, GA 30339
404/432-6983
John Kitto
Program Manager
Dabcock & Wilcox
1562 Beeson St.
Alliance, OH 44720
216/829-7710
Peter Knapik
Manager, R&D
UOP
25 E. Algonquin Rd.
Des Plaines, IL 60017-5017
708/391-2554
Bernard Koch
Director, Project Development
Consolidation Coal Company
4000 Brownsville Road
Library, PA 15129
412/854-6612
Angelos Kokkinos
Project Manager
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94304
415/855-2494
Zofia Kosim
Environmental Engineer
U.S.Environmental Protection Agency
401 M Street, SW
Washington, DC 20460
202/475-9400
Gerrit Koster
Process Service Engineer
Stork Boilers
Postbus 20
7550 GB Hengelo
THE NETHERLANDS
074/401416
Vaclav Kovac
Design Engineer Specialist
Ontario Hydro
700 University Ave.
Toronto, Ontario
CANADA
416/592-5243
Toshio Koyanagi
Senior Engineer
Mitsubishi Ho.nvy Industries
2 Houston Contor, Suite 3800
Houston, TX 77010
713/654-4151
Ed Kramer
Sr. Product i.on Engineer
PSI Energy
P. 0. Box 40R
Owensvilie, IN 47665
812/386-421?.
Henry Krlgmont
Dir..Technical Dept.
Wahlco, Inc.
3600 W. Segnr^trom Ave.
Santa Ana, CA 92704
714/979-7300
A-17
-------
K.S. Kumar
Manager, Applications
Research-Cottrell Envir.Serv/Tech.
P. 0. Box 1500
Somerville, NJ 08876
908/685-4876
Naveen Kumar
Project Engineer
Sargent & Lundy
55 E. Monroe
Chicago, IL 60603
312/269-6706
Yul Kwan
Consulting Engineer
Applied Utility Systems, Inc.
1140 East Chestnut Avenue
Santa Ana,CA 92701
714/953-9922
H. K. Kwee
N/A
Stork Boilers B.V.
P. 0. Box 20
7550 GB Hengelo
THE NETHERLANDS
31/74 40 18 57
Richard La Flesh
Principal Consulting Engineer
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-2583
Yan Lachowicz
Product Mgr., Burner Systems
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-2581
Don Langley
Regional Service Manager
Babcock & Wilcox
7401 W. Mansfield Ave #410
Lakewood, CO 80235
303-988-8203
Ellen Lanum
Mgr.Conferenr.es & Exhibits
Electric Power Research Institute
3412 Hillvinw Avenue
Palo Alto, CA 94304
415/855-2193
Leonard Lapatnick
Environmental Research Engineer
Public Service Electric & Gas
80 Park Plaza, T16H
Newark, NJ 07101
201-430-8129
Dennis Laudal
Research Engineer
University of North Dakota
Energy & Environ.Research Center
P 0. Box 8213, University Station
Grand Forks, ND 58202
701/777-5138
Tom Laursen
Development Engineer
Babcock & Wilcox
20 S. Van Burrn Ave.
Barberton, OH 44203
216/860-6J42
Al LaRue
Advisory Engr/Combustion Systems
Babcock & Wl1 cox
20 S. Vfin BurrMi Avenue
Barberton, OH 44203
216/860-1.493
Steve Legp.dzn
Mgr., Industrial Process Tech.
Consumers G.i? Company Ltd.
P. 0. Box 650
Scarborough, Ontario
M1K 5E3 CANADA
416/495-5156
L. Leo
Technical Specialist
Potomac Electric Power
1900 Pennsy1vnnta Ave., N.W.
Washington, DC 20068
202/331-6491
A-18
-------
Joel S. Levine
Senior Research Scientist
NASA Langley Research Center
Atmospheric Sciences Division
Hampton, VA 23665
804/864-5692
Julian Levy
Dir., Atmospheric Science Div.
Versar, Inc.
9200 Rumsey Road
Columbia, MD 21045
301/964-9200
Robert Lewis
Consulting Engineer
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-5968
John Lewnard
Principal Process Engineer
Air Products and Chemicals, Inc.
7201 Hamilton Blvd.
Allentown, PA 18195-1501
215/481-6932
Sergio Ligasacchi
Thermal/Nuclear Research
ENEL-CRTN
Via A. Pisano, 120
Pisa 56100
ITALY
050/535622
William Linak
Project Officer
U.S.Environmental Protection Agency
AEERL (MD-65)
Research Triangle Park, NC 27711
919/541-5792
Robert Lisauskas
Director, R&D
Riley Stoker Corporation
45 McKeon Road
Worcester, MA 01610
508/792-4801
Mike Little
Chemical Engineer
Tennessee Valley Authority
P. 0. Box 150
West Paducah, KY 42086
502/444-4654
Jim Locher
Engineer, Production
Pennsylvania Electric Co.
1001 Broad Street
Johnstown, PA 15907
814/533-8547
Judith Lomax
N/A
Maryland Power Plant Research Prog,
301/974-226J
Robert Lott
Project Manager
Gas Research Institute
8600 West Bryn Mawr Ave.
Chicago, IL 60631
312/399-8228
Phillip Lowe
President
INTECH, Inc.
11316 Rouen Drive
Potomac, MD 20854-3126
301/983-9367
Tien-Lin Lu
Senior Mechanical Engineer
Arizona Public Service Company
P. 0. Box 53999
Phoenix, AZ 85072-3999
602/250-4731
Richard Lyon
Senior Scientist
Energy & Environmental Research
18 Mason
Irvine, CA 92718-2789
201/534-5833
A-19
-------
Denis Maftei
Sr.Process Engineer
Ministry of Environment
880 Bay Street, 4th floor
Toronto, Ontario M5S 1Z8
CANADA
416/326-1649
Herwig Maier
Dept. Mgr., Steam Gen & Envir.Tech.
Energie-Versorgung Schwaben AG(EVS)
Hauptverwaltung
Kriegsbergstrabe 32
7000 Stuttgart 1, GERMANY
0711/128-2849
Jason Makansi
Executive Editor
Power Magazine
11 West 19th St., 2nd floor
New York, NY 10011
212/337-4074
Rene Mangal
Engineer
Ontario Hydro
Research Division
800 Kipling Avenue
Toronto, Ont., M8Z 5S4 CANADA
416/231-4111,X6162
Mansour Mansour
President
Applied Utility Systems, Inc.
1040 East Chestnut Avenue
Santa Ana, CA 92701
714/953-9922
John Marion
Mgr.,Fuel Systems Development
ABB Combustion Engineering
Kreisinger Development Laboratory
1000 Prospect Hill Road
Windsor, CT 06095-0500
203/285-4539
B. L. Marker
N/A
New York State Electric & Gas
P. 0. Box 3607
Binghamton, NY 13902
607/729-2551
Eugene Marshall
Principal Engineer
Pacific Corp Electric Operations
14007 West North Temple
Salt Lake City, UT 84140
801/220-2235
Greg Marshall
District Sales Manager
Foster Wheeler Energy Corp.
2001 Butterfield Road, Ste. 206
Downers Grove, IL 60515-1050
708/241-2050
John Marshal 1
Manager
Riley Stoker Corporation
45 McKeon Road
Worcester, MA 01613
508/792-4826
G. B. Martin
Deputy Director
U. S.Environmental Protection Agency
Air & Energy Engrg.Research Lab
MD-60
Research Triangle Park, NC 27711
919/541-2821
Sadahira Marura
Mgr., Business Development
Nippon Shokubai America, Inc.
101 East 52nd Street
New York, NY 10022
212/759-7890
Doug Maxwe.l I
Principal Research Engineer
Southern Company Services
P. 0. Box 2625
Birmingham, AT, 35202
205/877-7614
A-20
-------
Michael Maxwell
Chief, Gas Clean.Tech.Branch
U.S.Environmental Protection Agency
AEERL (MD-04)
Research Triangle Park, NC 27711
919/541-3091
Phil May
N/A
Radian Corporation
P.O. Box 1300
Research Triangle Park, NC 27709
N/A
T. J. May
Planning Project Manager
Illinois Power Co.
500 S. 27th St.
Decatur, IL 67525
217/424-6706
Michael McCartney
Dir.,Fuel Systems Controls Engrg.
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095-0500
203/285-4677
John McCoy
Senior Consultant
Electricity Supply Board Internat'l
Stephen Court
18/21 St. Stephen's Green
Dublin 2, IRELAND
353/01 785-155
Mark McDannel
Vice President & General Manager
Carnot
15991 Red Hill Road
Suite 110
Tustin, CA 92680-7388
714/259-9520
Barry McDonald
President
Carnot
15991 Red Hill Road
Suite 110
Tustin, CA 92680-7388
714/259-9520
Michael McElroy
Project Manager
Electric Power Technologies, Inc.
695 Oak Grove Ave.
Menlo Park, CA
415/322-0843
Marilyn Mcllvnine
Managing Editor
Mcllvaine Company
2970 Maria Ave.
Northbrook, IL 60062
708/272-0010
Robert Mcllvaine
President
Mcllvaine Company
2970 Maria Ave.
Northbrook, IL 60062
708/272-0010
John McKie
Environmental Engineer, Senior
Virginia Dept.Air Pollution Control
6225 Brandon Ave., Suite 310
Sprinfield, VA 22150
703/644-0311
William McKinney
Vice Pres.,Ncw Business Develop.
United Catalysts, Inc.
P. 0. Box 32370
Louisville, KY 40232
502/634-7218
Robert McMurry
Design Engineer
Duke Power Company
500 S. Church Street
Charlotte, NC 28262
704/373-6346
Tom McNfiy
N/A
Cincinnati Gas & Electric
P. 0. Box 960
Cincinnati, OH 45201
513/632-2676
A-21
-------
Gunter Mechtersheimer
Mgr., Environmental Technologies
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-2853
David Meier
Sales Manager, Utilities
Beltran Associates, Inc.
1133 East 35th Street
Brooklyn, NY 11210
718/338-3311
James Meyers
Chemical Equipment Engineer
Detroit Edison Company
2000 Second Ave., H-128A WSC
Detroit, MI 48226
313/897-0806
Paolo Michelotti
Engineer
F.T.C. Legnano
Via Monumento, 12 Legnano
Legnano 20025
ITALY
0331/522 111
Charles A. Miller
Mechanical Engineer
U. S.Environmental Protection Agency
Air & Energy Engineering Res.Lab
MD-65
Research Triangle Park, NC 27711
919/541-2920
Katherine Miller
Environmental Engineer
Virginia Dept.Air Pollution Control
801 Ninth & Grace Streets
Richmond, VA 23219
804/786-1433
John Mincy
Market Development Manager
Nalco Fuel Tech
P. 0. Box 3031
Naperville, IL 60566-7031
708/983-3258
Tadahisa Miynsaka
Chief Representative
Electric Power Development Co.
1825 K St., N.W..Suite 1205
Washington, DC 20006
202/429-0670
Cal Mock
General Sales Manager
Babcock & WIlcox
3333 Vaca Valley #300
Vacaville, CA 95688
707/451-1100
Larry Monroe
Head, Combustor Research Group
Southern Research Institute
P. 0. Box 55305
Birmingham, AT, 35255-5305
205/581-2879
Ed Moore
R&D Manager
Hauck Manufacturing Co.
P. 0. Box 90
Lebanon, PA 17042
717/272-305J
Terry Moore
Environmental Engineer, Senior
Virginia Dept.Air Pollution Control
7701 TimberInke Road
Lynchburg, VA 24502
804/947-664)
Bruce Morgan
Environmental Staff Engineer
Rust International
100 Corporate Parkway
Birmingham, AL 35243
205/995-7112
Mark Morgan
Mgr., Engrg. & Services
PS I Technology Co.
20 New England Business Center
Andover, MA 01810
508/689-0003
A-22
-------
Dominick Mormile
Manager, Air Quality Control
Consolidated Edison of N.Y.
4 Irving Place
New York, NY 10003-3586
212/460-6275
Per Horsing
Mgr.DeNOx Technology
Haldor Topsoe A/S
Nymollevej 55
DK-2800 Lyngby
DENMARK
+45/45 27 2000
Herman Mueller-Odenwald
N/A
Kraftanlagen Heidelberg
c/o AUS 1140 East Chestnut Ave.
Santa Ana, CA 92701
714/953-9922
Paul Musser
Program Manager
U.S. Department of Energy
Fossil Energy, FE-232 GTN
Washington, DC 20585
301/353-4348
Lawrence Muzio
Vice President
Fossil Energy Research Corp.
23342-C South Pointe
Laguna Hills, CA 92653
714/859-4466
Ram Nayak
Principal Mechanical Engineer
Stone & Webster
Three Executive Campus
P. 0. Box 5200
Cherry Hill, NJ 08003
609/482-3582
Lewis Neal
President
NOXSO Corporation
P. 0. Box 469
Library, PA 15129
412/854-1200
Mike Nelson
Senior Engineer
Southern Company Services
P. 0. Box 2625
Birmingham, AL 35202
205/870-6518
Sumitra Ness
Research Engineer
University of North Dakota
Energy & Environ.Research Center
15 North 23rd Street
Grand Forks, ND 58202
701/777-5213
Richard Newby
Principal Engineer
Westinghouse STC
1310 Beulah Road
Pittsburgh, PA 15235
412/256-2210
Julie Nicholson
Principal Engineer
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-3745
Satashi Nonakn
Manager
Mitsubishi Heavy Industries America
1000 Prospect Hill Road
Windsor, CT 06095
203/285-2491
Dave Nott
Special Projects Supervisor
Central Illinois Light Co.
300 Liberty Street
Peoria, IL 61602
309/697-1412
Jim Nylfindp.r
Senior Engineer
San Diego Gns & Electric
4600 Carlsbad Dlvd.
Carlsbad, CA 12008
619/931-7294
A-23
-------
James O'Brien
Project Engineer
Pennsylvania Power & Light
Two North Ninth Street (N-5)
Allentown, PA 18101
215/774-4352
John O'Leary
N/A
Nalco Fuel Tech
2001 W. Main St., Suite 295
Stamford, CT 06902
203/323-8401
Raymond O'Sullivan
Manager, Power Engineering
Orange & Rockland Utilities, Inc.
One Blue Hill Plaza
Pearl River, NY 10965
914/577-2630
George Offen
Program Manager
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94304
4156/855-8942
Earl Oliver
President
Oliver Associates, Inc.
2049 Kent Drive
Los Altos, CA 94024
415/964-4838
Paul Orban
Engineer, Boilers
Pennsylvania Electric Co.
1001 Broad Street
Johnstown, PA 15907
814/533-8537
Robert Orchowski
Sr. Compliance Assurance Engr.
Duquesne Light Co.
One Oxford Centre
301 Grant Street
Pittsburgh, PA 15279
412/393-6099
Case Overduin
Supervising Engineer
Southern California Edison
2131 Walnut Grove Avenue
Rosemead, CA 91770
818/302/8323
Louis Paley
Compliance Monitoring Coordinator
U.S.Environmental Protection Agency
401 M Street, S.W.
Washington, DC 20460
703/308-8723
Y.S. Pan
Project Manager
U.S. DOE/PETC
P. 0. Box 10940
Pittsburgh, PA 15236
412/892-5727
Paul Paris!
Development Engineer
Union Carbide
P. 0. Box 700
Pointe-anx-Trembles
Quebec RIB 5A8 CANADA
514/640-7400,X1296
Reginald Parker
Environmental Engineer
NYSDEC
50 Wolf Road
Albany, NY 12233
518/457-2044
Ramesh PnteJ
Principal Engineer
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-2027
Roy Payne
Senior Vice President
Energy & Environmental Research
18 Mason
Irvine, CA 17.718
714/859-8851
A-24
-------
David Pearsall
Product Manager
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT
203/285-5127
Jarl Pedersen
Manager
Burmeister & Wain Energy
23, Teknikerbyen
DK-2830 Virum DENMARK
+45/4285 7100
Thomas Penn
Mgr., Generating Projects
Potomac Electric Power
1900 Pennsylvania Ave., N.W.
Washington, DC 20068
202/872-2446
Henry Pennline
Chemical Engineer
U.S. Department of Energy
PETC
P. 0. Box 10940
Pittsburgh, PA 15236
412/892-6013
Michael Perlsweig
Program Manager
U.S. Department of Energy
Fossil Energy, FE-232 GTN
Washington, DC 20585
301/353-4348
Mildred Perry
Group Leader, Flue Gas Chem
U.S. DOE/PETC
Box 10940
Pittsburgh, PA 15236
412-892-6015
Karin Persson
Chemical Engineer
Swedish Energy Development Corp.
Biblioteksgatan 11
S-11146 Stockholm
SWEDEN
+468 679 8610
Henry Phillips
N/A
Consultant
22 Beacon Hill Drive
Metuchen, NJ 08440
201/549-0332
Richard Phillips
Engineer
Union Electric Co.
1901 Chouteau Ave.
St. Louis, MO 63103
314/554-3485
Robert Phi]p
Research Coordinator
Energy, Mines & Resources Canada
555 Booth Street
Ottawa, Ontario K1A OG1
CANADA
613/996-2175
Matthew Piechocki
Contract Manager
Babcock & Wilcox
20 S. Van Buren Ave
Barberton, OH 44203-0351
216/860-1704
Bill Pierce
District Sales Manager
Babcock & Wilcox
3333 Vaca Valley Parkway
Suite 300
Vacavillo, CA 95688
707/451-1100
Larry Piorson
Project Manager
Babcock & Wilcox
20 S. Van Burp.n Ave.
Barberton, OH 44203
216/860-1103
Jack Pirkey
Principal Rosoarch Engineer
Consolidated F.dison of N.Y.
4 Irving Plnco.
New York, NY 10003
212/460-2504
A-25
-------
William Pitman
Environmental Engineer
Tennessee Valley Authority
400 W. Summit Hill Drive
Knoxville, TN 37902-1499
615/632-6699
E. L. Plyler
N/A
U. S.Environmental Protection Agency
AEERL (MD-54)
Research Triangle Park, NC 27711
N/A
John Pohl
Senior Scientist, Energy
W. J. Schafer
8001 Irvine Center Drive
Suite 1110
Irvine, CA 92718
714/753-1391
Terry Poles
Director, Market Development
Engelhard Corporation
101 Wood Ave
Iselin, NJ 08830
908-205-6633
Robert Porter
Ass't.Project Manager
TransCanada PipeLines
55 Yonge Street, Sthfloor
Toronto, Ontario M5E 1J4
CANADA
416/869-2161
John Pratapas
Senior Project Manager
Gas Research Institute
8600 W. Bryn Mawr Avenue
Chicago, IL 60631
312/399-8301
Edward Preast
Project Manager
Florida Power & Light
P. 0. Box 14000
Juno Beach, FL 33408-0420
407/694-3112
Shaik Qader
Project Manager
Ebasco Services, Inc.
3000 West MacArthur Blvd.
Santa Ana, CA 92704
714/662-4093
Greg Quartucy
Engineer
Fossil Energy Research Corp.
23342 C South Pointe
Laguna Hills, CA 92653
714/859-4466
Brian Quil
Mechanical Engineer
Naval Energy & Envir.Support Activ
NEESA-11A
Port Huenemp., CA 93043-5014
805/982-3512
Les Radak
Senior Research Engineer
Southern California Edison
2244 Walnut Grove Avenue
Rosemead, CA 91770
818/302-9746
G.P. Rajendran
Research Chemist
E. I. Du Pont de Nemours
P. 0. Box 80302
Wilmington, OF, 19880-0302
302/695-2784
Jay Ratafin-Brown
Dir.,Environmental Projects
SAIC
1710 GoodrJdgo. Dr.
Box 1303
McLean, VA 22102
703/448-6343
William Renmy
EnvironmentnI Engineer
Baltimore Gas & Electric Co.
1000 Brandon Shores Road
Baltimore, Mil 21226
301/787-5378
A-26
-------
James Reese
Manager
Applied Utility Systems, Inc.
1140 East Chestnut Avenue
Santa Ana, CA 92701
714/953-9922
Christopher Reilly
Sr. Engineer, R&D
New York State Electric & Gas
4500 Vestal Parkway, East
Binghamton, NY 13902-3607
607/729-2551,X4105
Anthony Renk
Supervising Engineer
Florida Power & Light
P. 0. Box 078768
West Palm Beach, FL 33410
407/640-2289
Diane Revay Madden
Project Manager
U.S. DOE/PETC
P. 0. Box 10940
Pittsburgh, PA 15236-0940
412/892-5931
Cathy Rhodes
Public Health Engineer
Colorado Dept. of Health
4210 East llth Ave.
Denver, CO 80220
303/331-8570
Michael Rini
Sr. Consulting Engineer
ABB Combustion Engineering
Kreisinger Development Lab
1000 Prospect Hill Road
Windsor, CT 06095-0500
203/285-2081
J. R. Rizza
President
Todd Combustion, Inc.
61 Taylor Reed Place
Stamford, CT 06906
203/359-1320
Rodney Robertson
Project Manager
Burns & McDonnell
P. 0. Box 419173
Kansas City, MO 64141
816/822-3062
Chris Robie
Consulting Engineer
United Engineers & Constructors
P. 0. Box 5888
Denver, CO 80217
303/843-2803
Farzan Roshdieh
Senior Engineer
Applied Utility Systems, Inc.
1140 East Chestnut Avenue
Santa Ana, CA 92701
714/953-9922
Geoff Ross
Senior Program Engineer
Environment Canada
Industrial Programs Branch
Ottowa, Ontario K1A OH3
CANADA
819/997-1222
Edward Rubin
Professor
Carnegie Mellon University
Schenley Park
Pittsburgh, PA 15213
412/268-5897
Dave Rundstrom
Research Scientist
Southern California Edison
2244 Walnut Grove Ave.
Rosemead, CA 91770
818/302-9561
Pia Rydh
Chemical Engineer
Vattenfall F.no.rgisystem AB
Box 528
16215 ValJInghy
SWEDEN
+46/8 739 55 68
A-27
-------
Joseph Saliga
Systems Engineer
Fluor Daniel, Inc.
200 W. Monroe St.
Chicago, IL 60606
312/368-3862
Pia Salokoski
Engineer
Imatran Voima OY
Rajatorpan tie 8 P. 0. Box 112
SF-01601 Vantaa
FINLAND
358/0 508 4837
N. C. Samish
Staff Research Engineer
Shell Development Co.
P 0. Box 1380
Houston, TX 77251
713/493-7944
Howard Sandier
Principal
Sandier & Associates
111 Pacifica, Ste. 250
Irvine, CA 92718
714/727-2676
Emelina Sandoval
Engineer
Pacific Gas & Electric Co.
One California St., F-836D
San Francisco, CA 94106
415/973-5422
Edmund Schindler
Project Manager
Todd Combustion, Inc.
61 Taylor Reed Place
Stamford, CT 06906
203/359-1320
Richard Schlager
Div.Head, Environmental Sciences
ADA Technologies, Inc.
304 Inverness Way South, Suite 110
Englewood, CO 80112
303/792-5615
Henry Schreiber
Project Manager
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94304
415/855-2505
David Schulz
Regional Power Expert
U.S.Environmental Protection Agency
Region 5
230 S. Dearborn 5AC-26
Chicago, IL 60604
312/886-6790
Herbert Schuster
N/A
Deutsche Dabcock Energie
Duisburgerstr 375
D-4200 Oberhaussen
FEDERAL REPUBLIC OF GERMANY
N/A
Blair Seckington
Supervising Engineer
Ontario Hydro
700 University Avenue
Toronto, Ontario M5G 1X6
CANADA
416/592-5191
Charles Sedmnn
Chemical Engineer
U. S .EnvJ ronmcnt-.al Protection Agency
AEERL (MD-04)
Research Trinngle Park, NC 27711
919/541-7700
James Seebold
Staff Engineer
Chevron Corporation
100 Chevron Wny
Richmond, CA 94802-0627
415/620-3313
Tim Seelaus
Mgr., Business Development
Pure Air
Two Windsor Plaza
Allentown, PA 18195
215/481-5373
A-28
-------
Daniel Seery
Sr. Program Manager
United Technologies Research Center
Silver Lane
East Hartford, CT 06108
203/727-7150
Dave Shilton
Senior Environmental Engineer
Pacific Power & Light
920 SW 6th Ave., Suite 1000
Portland, OR 97204
503/464-6479
Gary Shiomoto
Engineer
Fossil Energy Research Corp.
23342 C South Pointe
Laguna Hills, CA 92653
714/859-4466
Dale Shore
Program Manager
Radian Corporation
7 Corporate Park, Ste. 240
Irvine, CA 992714
714/261-8611
J. M. Shoults
Manager, Permitting
Texas Municipal Power Agency
Environmental Affairs
P. 0. Box 7000
Bryan, TX 77805
409/873-2013
William Siegfriedt
Director, Process Engineering
Fluor Daniel, Inc.
200 W. Monroe Street
Chicago, IL 60606
312/368-3828
Ralf Sigling
Engineer
Siemens/KWU
Hammerbacher Str. 12 + 14
Erlangen 8520 GERMANY
01149/9131-18-6169
Paul Singh
Sr. Vice President
Procedair Industries
625 President Kennedy
Montreal, Quebec H3A 1K2
CANADA
514/284-0341
Bill Smith
Combustion Specialist
Burns & McDonnell
P. 0. Box 419173
Kansas City, MO 64141
816/822-3074
Chris Smith
Proposal Mgr., Burner Systems
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-5573
David Smith
Senior Chemist, Environment
Saskpower Corporation
2025 Victoria Avenue
Regina, Sask. S4P OS1
CANADA
306/566-2290
J. W.R. Smith
Gen. Mgr., Sales & Marketing
Babcock Energy Ltd.
11 The Boulevard
Crawley, W. Sussex RH10 1UX
UNITED KINGDOM
0293/528755
Ken Smith
Engineer
Southern California Edison
2700 Edison Wny
Laughlin, NV
702/298-1197
Lowell Smith
Vice President
ETEC
One Technology, Suite 1-809
Irvine, CA 92718
714/753-91.26
A-29
-------
Martin Smith
Coal Research Establishment
British Coal Corporation
Stoke Orchard
Cheltenham, Glos
ENGLAND
0242 673361
Todd Sommer
Vice President, Engineering
EER Corp.
1645 N. Main St.
Orrville, OH 44667
216/682-4007,,
Robert Sommerlad
Mgr., Combustion Tech.
Research-Cottrell Envir.Serv/Tech.
P. 0. Box 1500
Somerville, NJ 08876
908/685-4776
John Sorge
Research Engineer
Southern Company Services
P. 0. Box 2625
Birmingham, AL 35202
205/877-7426
Arend Spaans
Engineer
Stork Boilers
Postbus 20
7550 GB Hengelo
THE NETHERLANDS
31/74-401328
David Speirs
Principal Engineer
ABB Combustion Engineering
99 Bank Street
Ottawa, Ontario KIP 6C5
CANADA
613/560-4458
Barry Speronello
Principal Development Scientist
Engelhard Corporation
Menlo Park CN40
Edison, NJ 08818
908/205-5155
Cindy Spittler
Marketing Manager
Radian Corporation
50 Century Blvd.
Nashville, TN 37214
615/885-4281
Hartmut Spliethoff
Scientific Assistant
University of Stuttgart
IVD Institute
Pfaffenwaldring 34
7000 Stuttgart 80 GERMANY
49/711-685-3396
Christopher Stale
Project Mgr.,Advanced Materials
Gas Research Institute
8600 W. Bryn Mawr Avenue
Chicago, IL 60631
312/399-8233
Susan Stamey-Hall
Staff Scientist
Radian Corporation
3200 E. Chapel Hill Rd
P. 0. Box 13000
Research Triangle Park,NC
919/541-9100
James Staudt
Mgr., NOx Control
PSI Technology Co.
20 New Englnnd Business Center
Andover, MA 01810
508/689-0003
Richard Storm
V.P., Technical Services
Flame Refractories, Inc.
Highway 742
P.O. Box 649
Oakboro, NC 28129
704-485-3371.
Richard P Storm
Senior Service Engineer
Flame Refractories, Inc.
P. 0. Box 649
Oakboro, NC 2R129
704/485-3371
A-30
-------
Joseph Strakey
Assoc.Dir..Clean Coal
Pittsburgh Energy Tech. Center
P. 0. Box 10940
Pittsburgh, PA 15236
412/892-6124
Peter Strangway
R&D Consultant
Niagara Mohawk Power Corp.
300 Erie Blvd., West, A-2
Syracuse, NY 13202
315/428-6532
Sabine Streng
N/A
Lentjes AG
Hansa-Allee 305
4000 Dusseldorf
GERMANY
N/A
Lamar Sumerlin
Principal Engineer
Southern Company Services
P.O. Box 2625
Birmingham, AL 35202
205-870-6519
Kohei Suyama
Project Manager
Mitsubishi Heavy Industries
2 Houston Center, Suite 3800
Houston, TX 77010
713/654-4151
Timothy Sweeney
Supervisor
Foster Wheeler Energy Corp.
Perryville Corporate Park
Clinton, NJ 08809
908/730-5436
Thomas Szymanski
Mgr., Product Research
Norton Company
P. 0. Box 350
Akron, OH 44309
216/673-5860
Masaki Takahashi
Visiting Researcher
MIT/EPDC
One Amherst Street
Cambridge, MA 02139
617/253-7828
Harry Tang
Sr. Research Engineer
Shell Development Co.
P. 0. Box 1380
Houston, TX 77251-1380
713/493-8424
Tai Tang
Associate Engineer
KBN Engineering & Applied Sciences
1034 NW 57th Street
Gainesville, FL 32605
904/331-9000
Roberto Tar11
Manager
ENEL
Production & Transmission Dept.
Via A. Pisano, 120
56100 Pisa, ITALY
0039/50-535754
Robert Teetz
Mgr.,Chem.Div.,Env.Engrg.Dept.
Long Island Lighting Co.
P. 0. Box 426
Glenwood Landing, NY 11547
516/671-6744
Donald Teixeira
Tech. Mgr., Fossil R&D
Pacific Gas & Electric Co.
3401 Crow Canyon Road
San Ramon, CA 94583
415/866-5531
Preston Temporo
Plant Managor
KPL Gas Service
Mile Post #30
P.O. Box 249
Lawrence, KS 66044
913-843-8118
A-31
-------
Angelo Testa
Visiting Researcher
Eniricerche (Italy)
c/o MIT - Chemical Engineering
60 Vassar St., Bldg. 31-261
Cambridge, MA 02139
617/253-1721
Paul Thompson
President
Tenerx Corporation
P. 0. Box 1444
303 Laurel
Friendswood, TX 77546
713/482-5801
Richard Thompson
President
Fossil Energy Research Corp.
23342 C South Pointe
Laguna Hills, CA 92653
714-859-4466
David Thornock
R&D Engineer
ABB Combustion Engineering
1000 Prospect Hill Road
Windsor, CT 06095
203/285-2931
Richard Tischer
Project Manger
U.S. Department of Energy
P. 0. Box 10940
Pittsburgh, PA 15102
412/892-4891
Majed Toqan
Prog.Mgr., Prin.Research Engineer
Massachusetts Instit. of Technology
Dept. of Chemical Engineering
60 Vassar St., Bldg. 31-261
Cambridge, MA 02139
617/253-1721
Ian Torrens
Department Director
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94304
415/855-2422
H.H.J. Tossaint
Mgr., Combustion Engrg.
Stork Boilers
P. 0. Box 20
7550 GB Hengelo (0)
THE NETHERLANDS
31/74 40 1015
Donald Toun
Advisory Engineer
Babcock & Wilcox
20 S. Van Vuren
Barberton, OH 44203
216/860-1986
Shiaw Tseng
Project Engineer
Acurex Corporation
P. 0. Box 13109
Research Triangle Park, NC 27709
919/541-3981
Lance Turcotte
Assoc. Consulting Engineer
Ebasco Services, Inc.
759 South Federal Highway
Stuart, FL 34994-2936
407/225-9476
Henry Turner
Utility Plant Manager
IBM
P. 0. Box 218
Yorktown lit, NY 10598
914/945-1720
Minoru Uchidn
Mgr., Nuclear Project Dept.
Chiyoda Corporation
12-1 TsurumJchuo 2-Chome, Tsurumi
Yokohama, JAPAN
045/506-7062
Toshio Uemura
Senior Engineer/Combustion Systems
Babcock-Hitnchi K.K.
No. 6-9 Takara-machi
Kure-city, Hiroshima-prefectur
JAPAN
0823/21-1163
A-32
-------
Andy Uenosono
Senior Project Coordinator
Hitachi America, Ltd.
2000 Serra Pt. Parkway
Brisbane, CA 94005-1835
415/244-7602
K. Ueshima
Ass't. Mgr.,Environ.Plant Engrg.
KHI/Joy Environmental Equipment
1-1, Higashi Kawasaki-cho 3-chome
Chuo-ku, Kobe
JAPAN
078/682-5230
David Underwood
Vice President, Sales
Aptec
RD 1, Box 583
Honey Brook, PA 19344
215/942-3651
James Vader
Project Manager
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94304
415/855-2316
Mohammad Vakili
Project Manager
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94304
415/855-2541
James Valentine
President
Energy & Environmental Partners
480 Hemlock Road
Fairfield, CT 06430
203/254-7166
Bauke Van Kalsbeek
Vice President
Sierra Environmental Engineering
3505 Cadillac Avenue, K-l
Costa Mesa, CA 92626
714/432-0330
Bill Van Nieuwenhuizen
N/A
Babcock & Wilcox
581 Coronation Blvd.
Cambridge, Ontario N1R 5V3
CANADA
519/621-2130
Michel Vandycke
Head, Chemical Engineering
Stein Industrie
19-21, Av. Morane Saulnier
78141 Velizy-Villacoublay
Cedex, FRANCE
34-65-46-02
Joel Vatsky
Dir., Combustion & Environ.Systems
Foster Wheeler Energy Corp.
Perryville Corporate Park
Clinton, NJ 08809-4000
9087/730-5450
Dahlgren Vaughan
EnvironmentsI Engineer
Virginia Dept.Air Pollution Control
300 Central Rd.,Suite B
Fredericksburg, VA 22401
703/899-4600
Gary Veerkamp
Sr. Mechanic?!] Engineer
Pacific Gas 8- Electric Co.
One Californi.fi, Room F827
San Francisco, CA 94106
415/973-1576
Denise Viola
Commercial Manager
Engelhard Corporation
101 Wood Avenue
Iselin, NJ ORfno
908/205-5039
Gary VonBargen
Project Engineer
Wisconsin Eloctric Power
P.O. Box 2046
Milwaukee, WI 53201
414-221-2310
A-33
-------
Peter Waanders
Contract Manager
Babcock & Wilcox
20 S. Van Buren Ave.
Barberton, OH 44203
216/860-1967
Frederick Wachtler
Project Manager
Foster Wheeler Energy Corp.
Perryville Corporate Park
Clinton, NJ 08809
908/730-5438
Paul Wagner
Project Engineer
Delmarva Power
195 & Route 273
P.O. Box 9239
Newark, DE 19714
302-454-4844
Peter Warne
Senior Instrumentation Engineer
Monenco Consultants Ltd.
Power Division
400 Monenco Place, 801 6 Ave., S.W.
Calgary, Alberta T2P 3W3 CANADA
403/298-4678
Kevin Washington
Power Resources Staff Specialist
Florida Power & Light
6001 Village Blvd.
West Palm Beach, FL 33407
407/640-2412
Richard Waterbury
Principal Engineer
Florida Power & Light
16423 79th Terrace, N.
Palm Beach Gardens, FL
407/747-7643
Robert Weimer
Chief Engineer
Air Products and Chemicals, Inc.
7201 Hamilton Blvd.
Allentown, PA 18195
215/481-7626
Steven Weiner
Program Manager
Air Products and Chemicals, Inc
7201 Hamilton Blvd.
Allentown, PA 18195
215/481-4372
M. Weiss
Mgr.generating Systems Engr.
Potomac Electric Power
1900 Pennsylvania Ave., N.W.
Washington, DC 20068
202/872-2431
Tom White
Project Engineer
Sargent & Lundy
55 E. Monroe
Chicago, IL 60603
312/269-6137
Kenneth Wildmnn
Development Engineer
Eastman Kodak Co.
Kodak Park Bldg 31
Rochester, NY 14652-3709
716-477-0666
Donald Wilhelm
Sr. Chemical Engineer
SFA Pacific, Inc.
444 Castro St., Suite 920
Mountain Vipw, CA 94041
415/969-8876
Ronald Wilkniss
N/A
Mobil Oil Corporation
3700 W. 190th Street
Torrance, CA 90509
213/212-4587
Steve Wilson
Principal Research Engineer
Southern Compnny Services
P.O. Box 2625
Birmingham, AT, 35202
205/877-7835
A-34
-------
Phil Winegar
Senior Engineer
New York Power Authority
Research & Development
1633 Broadway
New York, NY 10019
N/A
Larry Winger
Mgr., New Ventures
Engelhard Corporation
101 Wood Avenue
Iselin, NJ 08830
908/205-5266
Johan G. Witkamp
Project Manager
KEMA
Utrechtseweg 310
6900 ET Arnhem
THE NETHERLANDS
085/56 3625
James Wittmer
Supervisor, Project Mgmt.
Central Illinois Light Co.
300 Liberty Street
Peoria, IL 61602
309/693-4840
James Wolf
Senior Engineer
Virginia Power
5000 Dominion Blvd.
Glen Allen, VA 23060
804/273-2617
Brian Wolfe
District Manager
Babcock & Wilcox
7401 West Mansfield, #410
Lakewood, CO 80235
303/988-8203
Gregg Worley
Environmental Engineer
U.S.Environmental Protection Agency
345 Courtland St., N.E.
Atlanta, GA 30365
404/347-2904
H. B. Wylie
Senior Engineer
Baltimore Gas & Electric Co.
1000 Brandon Shores Road
Baltimore, MD 21226
301/787-5245
Anthony Yaglela
Cyclone Reburn Project Manager
Babcock & Wilcox
20 S. Van Buren Avenue
P. 0. Box 351
Barberton, OH 44203-0351
N/A
Misao Yamamura
Mgr., NO.2 Land Boiler
Mitsubishi Heavy Industries
1-1 Akunoura-Machi
Nagasaki 850-91
JAPAN
81/958-28-6400
Ralph T. Yang
Chair, Dept. of Chem. Engineering
State University of N.Y. at Buffalo
Buffalo, NY 14260
716/636-2909
Shyh-Ching Yang
Mgr.,Energy Resources Laboratories
Industrial Tech. Research Institute
Bldg.64,195 Rpo.4, Chung Hsing Rd.
Chutung Hsinohu, Taiwan
REPUBLIC OF CHINA 31015
886/35-916439
James Yeh
Chemical Engineer
U.S. Department of Energy
P.O. Box 10940
Pittsburgh, PA 15236
412-892-5737
Cherif Yousso.f
Research Project Engineer
Southern California Gas Co
Box 3249 Terminal Annex
ML 731D
Los Angeles, CA 90051
818-307-2695
A-35
-------
Kenneth Zak Jim Zhou
Development Associate N/A
W. R. Grace & Co. Conn. Babcock & Wi.lcox
7379 Route 32 581 Coronation Blvd.
Columbia, MD 21044 Cambridge, Ontario N1R 5V3
301-531-4383 CANADA
519/621-2130
Kent Zammit
Project Manager Qian Zhou
L.A. Department of Water & Power Research Engineer
111 N. Hope St.,Room 931 NOXSO Corporation
Los Angeles, CA 90012-2694 P. 0. Box 469
213/481-5019 Library, PA 15129
412/854-1200
Aldo Zennaro
Combustion Engrg.Manager
Ansaldo Component!
Via Sarca 336
Milan 20126
ITALY
010392/6445 2204
A-36
------- |