United States EPA-600/R-92"093a
Environmental Protection
Agency July 1992
svEPA Research and
Development
PROCEEDINGS: 1991 JOINT SYMPOSIUM ON
STATIONARY COMBUSTION NOx CONTROL
WASHINGTON, D. C. , MARCH 25-28, 1991
Volume 1. Sessions.1-3
Prepared for
Office of Air Quality Planning and Standards
Prepared by
Air and Energy Engineering Research
Laboratory
Research Triangle Park NC 27711
-------
TECHNICAL REPORT DATA .
(Please read Instructions on the reverse before compieti | |||| || ||||| ||| 11 III ||| 11 III
1, REPORT NO. 2.
EPA-600/R-92-093 a
3. i i mi ii inn in mi ii iii i mi
PB93-212843
4, TITLE AND SUBTITLE
Proceedings; 1991 Joint Symposium on Stationary
Combustion NOx Control, Washington, D. C,, March
25-28, 1991, Volume 1. Sessions 1-3
8. REPORT DATE
July 1992
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Carolee DeWitt, Compiler
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
William Nesbit and Associates
1221 Farmers Lane
Santa Rosa, California 95405
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
NA (EPRI Funded)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Proceedings; 3/89 - 3/91
14. SPONSORING AGENCY CODE
EPA/600/13
16.supplementary notes ^EERL project officer is Robert E. Hall, Mail Drop 65, 919/541-
2477. Volume 2 includes Sessions 4 and 5, and Volume 3 includes Sessions 6~8.
16. abstract proceedings document the 1991 Joint Symposium on Stationary Combus-
tion NOx Control, held in Washington, DC, 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 develop-
ments for stationary combustion nitrogen oxides (NOx) control. Topics covered inclu-
ded the significant increase in active full-scale retrofit demonstrations of low-NOx
combustion systems in the U, S. and abroad over the past 2 years; full-scale oper-
ating experience in Europe with selective catalytic reduction (SCR); pilot- and bench-
scale SCR investigations in the U. S.; increased attention to selective noncatalytic
reduction (SNCR) in the U. S. ; and NOx controls for oil- and gas-fired boilers. The
proceedings are published in three volumes.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Nitrogen Oxides
Combustion
Catalysis
Fossil Fuels
Pollution Control
Stationary Sources
Catalytic Reduction
Noncatalytic Reduction
13 B
07B
21B
07D
21D
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (ThisReport/
Unclassified
21. NO. OF PAGES
328
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73) g_
-------
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the contents necessarily
reflect the views and policy of the Agency, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161,
NTiS Is authorised to reproduce and sell this
report. Permission lor further reproduction
must be obtained tram the copyright owner.
Copyright (e) 1991, EPEI GS-7447, Proceedings:
1991 Joint Symposium on Stationary Combustion
NOx Control, Volumes 1, 2, and 3. Since this
work was, in part, funded by the U, S. Government,
the Government is vested with a royalty-free, non-
exclusive, and irrevocable license to publish, trans-
late, reproduce, and deliver that information and
to authorize others to do so.
-------
EPA-6G0/R-92-093a
July 1992
PROCEEDINGS:
1991 JOINT SYMPOSIUM ON STATIONARY COMBUSTION NOx CONTROL
Washington, D.C., March 25-28, 1991
Volume 1. Sessions 1-3
Compiled by
Carolee DeWitt
William Nesbit and Associates
1221 Farmers Lane
Santa Rosa, CA 95405
EPA Project Officer:
Robert E. Hall
U.S. Environmental Protection Agency
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
EPRI Project Manager:
Angelos Kokkinos
Electric Power Research Institute
3412 Hill view Avenue
Palo Alto, CA 93404
Prepared for:
U.S. Environmental Protection Agency
Office of Research and Development
Washington, DC 20460
Electric Power Research Institute
3412 Hill view Avenue
Palo Alto, CA 93404
-------
ABSTRACT
The 1991 Joint Symposium on Stationary Combustion NQX 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 three 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 NO„ control. Topics discussed
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 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 three volumes. Volume l
contains papers from the following sessions:
Session 1:
Session 2:
Session 3:
Background
Large Scale Coal
Large Scale Coal
Combustion
Combustion
I
II
iii
-------
Papers from the following sessions are contained in Volume 2:
Combustion NOx Developments I
Large Scale SCR Applications
Post Combustion Developments 1
Industrial/Combustion Turbines on NOx Control
Papers from the following sessions are contained in Volume 3;
¦
Session 6A:
Post Combustion Developments 11
¦
Session 6B:
Combustion NOx Developments II
¦
Session 7A;
New Developments 1
¦
Session 7B:
New Developments 11
¦
Session 8:
Oil/Gas Combustion Applications
An appendix listing the symposium attendees is included at the end of Volume 3.
¦ Session 4A:
¦ Session 4B:
¦ Session 5A:
¦ Session 5B;
iv
-------
CONTENTS
Paper VOLUME 1 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. Fagan 1-15
"Analysis of 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: URGE 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-NOx Burner," J. Pedersen and
M, Berg 2-37
"Application of Gas Reburning-Sorbent Injection Technology for Control of
NOx and S02 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 BoHers," 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
v
-------
Paper Page
SESSION 3: LARGE SCALE COAL COMBUSTION II
Chair: D. Eskinazi, EPRI arid 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 (Rebuming) 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
VOLUME 2
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. Be&r, 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
vi
-------
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
"NgO Formation in Selective Non-Catalytic NOx Reduction Processes," L Muzic,
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
Vll
-------
Paper
Page
"Rebuming 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. Usauskas, R. Dunnette, K. Nakazato, P. Duggan, and D. Unz 5B-89
VOLUME 3
SESSION 6A: POST COMBUSTION DEVELOPMENTS II
Chair: D. Drehmel, EPA
"Performance of Urea NOx Reduction Systems on Utility Boilers," A. Abele, Y. Kwan,
M. Mansour, N. Kertamus, L. Radak, and J. Nylander 6A-1
"Widening the Urea Temperature Window," D. Teixeira, L. Muzio, T. Montgomery,
G. Quartucy, and T. Martz 6A-21
"Catalytic Fabric Filtration for Simultaneous NOx and Particulate Control," G. Weber,
D. Laudal, P. Aubourg, and M. Kalinowski 6A-43
SESSION 6B: COMBUSTION NOx DEVELOPMENTS II
Chair: R. Hall, EPA
"Heterogeneous Decomposition of Nitrous Oxide in the Operating Temperature Range of
Circulating Fluidized Bed Combustors," T. Khan, Y.Lee, and L. Young 6B-1
"NOx Control in a Slagging Combustor for a Direct Coal-Fired Utility Gas Turbine,"
P. Loftus, R. Dlehl, 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 k 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
viii
-------
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 li
Chair: C. Miller, EPA
"In-Fumace 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 N0X 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. Doleial 7B-43
"Computer Modeling of NjO 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. Haythomthwaite, 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-NOx Burner System,"
S. Kerho, D. Giovanni, J. Yee, and D. Eskinazi 8-85
"Demonstration of Advanced Low-NOx Combustion Techniques at the Gas/OII-Flred 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
IX
-------
NOx EMISSIONS REDUCTION IN THE FORMER
GERMAN DEMOCRATIC REPUBLIC
B. Kassebohm
Stadtwerke Dusseldorf AG
LuisenstraSe 105
4000 Dusseldorf 1, Germany
S. Strenc
Lentjes AG
Hansa-Aliee 305
4000 Dusseldorf, Germany
1-1
Preceding page blank
-------
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 SOj emission,
which, due to the prevalent wind currents in Europe, is concentrated and settles
on the southern part of Scandinavia, 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
Preceding page blunt
-------
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 fox
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, SCL 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 S02 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 S02 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 NjO, 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
1-5
-------
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 equipment 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/m3
• nitrous oxide (NOx) from July 1st, 1996 < 200 mg/m3
« dust from July 1st, 1996 < 50 mg/m5 for new
< 80 mg/m5 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 NQx 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 Umweltsehutz, Naturschutz, Energie und Reaktorsicherheit
der DOR, Berlin. Umweltbericht der DOR, Februar 1990
2. Ministerium fur Umweltsehutz, Naturschutz, Energie und Reaktorsicherheit
der DDR, Berlin. Fristenplan zur Ubernahme der GroBfeuerungsanlagenverordnung
zurn 1. Juli 1992
3. Volkskammer der DDR, Berlin. Umweltrahmengesetz der DDR, Juli 1990
1-8
-------
Energie Consumption
per Capita
100
C n d
n l
.USA
Austi i
C
Great Britain
O
FRG
/— o
Jreece ^ (J France
© © U Japan
Spain
raq
50
'Brazil, Chile, Tunisia
'China, India, Peru, Egypt
100
Norway
O
G
Sweden
GNP per Capita
Fig 1: Gross Net Produktion and
Energy Consumption per Capita (USA = 100)
Source: BWK 363.7 (1990)
.1.219 PJ
Hydro etc.
FRG
GDR
kWh
6500
5800
FRG GDR
FRG GDR
Total
Fig 2: Energy Consumption
Source: Haudelsblatt (1990)
FRG GDR
Primary- Final- Electrical-
energy energy energy
Consumption per Capita
1-9
-------
Nitrog
oxide
41,9% Power Stations
42,9% Traffic
13,5% Industry
Fig 3: Emission per Capita in 1988
Source: Institut fQr Umweltschutz Berlin, DDR (1990)
1,7% Dwelling Heating
Nitrogenoxide
C\n>.
Fig 4: Measured S04 Immission
in Europe ( ng/in3)
Source: KATO/CCMS Studie 1979
1-10
-------
Source: Globus 6358
Fig 6: Estimated Annual Deposition
of NOx in Europe
Source: Acid Magazine 1990
1-11
-------
Actual Situation *
- Existing Power Plant Capacity ~ 23.580 MW
(among these Nuclear ~ 2.200 MW)
Availability ~ 86% i.e. ~ 19.800 MW
Peak load ~ 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 GDR
in 1988
* Source: IZE
Danmark
Switzerland
Fig 7: Points of Max NOx— Emission
Source: DIW (1985)
-------
Today GDR-Teehriology
g/KWh
New Technologies
Lignite
Konv. Power Station ¦
Hard-
coal
Comb. Cycle-
Power Stat.
Fig 9: Reduction of Power Station
Emission by New Technologies
Source: BWK 363,8 (1990) *
1-13
-------
"TOP-DOWN" BACT ANALYSIS AND
RECENT PERMIT DETERMINATIONS
John R. Cochran
Morgen E. Fagan
Black & Veatch
1-15
Preceding page blrntJ
-------
ABSTRACT
New EPA requirements for "top-down" best available control
technology (BACD 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 conducing 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
Preceding page blank
-------
INTRODUCTION
On December 1, 1987, the EPA Assistant Administrator
for Air and Radiation, J. Craig Rotten 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 (BACD 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 achievable 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-
dew n 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
SNSPS). 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
Mr. Cochran and Mr. Figin may be contacted it <913) 339-2000.
possible to obtain a BACT 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.
1-18
-------
Table 1
Nitrogen Oxide Emission NSPS for Selected Source Types
Emission Limit
Steam Generating Units Larger than
250 MBtu/h (Subpart Da source)
Bituminous, Anthracite, and Lignite
0.60 lb/M8tu
Subbituminous Coal
0.50 Ib/MBtu
Steam Generating Units With Heat Inputs Between
100 and 250 MBtu/h (Subpart Db source)
Spreader Stoker and Fluidized Bed Boilers
0.60 Ib/MBtu
Pulverized Coal
0.70 Ib/MBtu
Lignite
0.60 Ib/MBtu
Stationary Gas Turbines*
Rated Load
75 ppm
Peak Load
150 ppm
•Corrected to IS percent oxvsen minus corrections for heat rate and fuel bound nitrogen.
As previously discussed, NSPS provide the baseline re-
quirement establishing the minimum acceptable level
-------
TOP-DOWN BACT ANALYSIS PROCEDURE
A 3ACT analysis must be performed 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 CPA'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 BACT 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 below:
* Technical Evaluation Criteria.
— Type of Combustor.
— Fuel Bum 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 Rata
— 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 sines 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 present delays associated with changing
criteria.
1-20
-------
Figure 1
Top-Down BACT Analysis Technique
1-21
-------
STEP 2—REVIEW RECENT PERMIT DECISIONS
The next step in the analysis is to review recent permit
decisions to determine the LAER control alternative.
The BACT/LAER Clearinghouse documents provide a
good reference for this activity. These documents (198S
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 far 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 scxaHed BACT determinations in
California were arrived at within a state BACT defini-
tion that more closely resembles LAER program re-
quirements.
The projects with more stringent control and emission
determinations listed in the BACT/LAER Clearinghouse
documents are in various stages of development.
Research should be performed to confirm if it is an-
ticipated that the plant will still be constructed. If a
source is operating, research should also be performed
to confirm compliance status with all permit limitations.
Information regarding a project cancellation or trouble
with maintaining compliance would be helpful in
disputing a LAER technology or a LAER level of con-
trol requirement.
STEP 3— IDENTIFY POTENTIALLY FEASIBLE
ALTERNATIVES
The third step in a BACT analysis is to identify all poten-
tially feasible control technologies tor the source and
pollutant under consideration. A potentially feasible
alternative is a technology that can be reasonably ap-
plied to the source to reduce the emissions of a pollu-
tant These control technologies can include control
processes that are applicable to similar emission source
types or gas streams. Technologies required as a result
of a LAER determination must be carefully considered
(Step 2) in the BACT analysis. A LAER technology would
typically represent the first alternative analyzed in the
top-down approach.
Also included in this step of the BACT analysis is a
technical feasibility evaluation of potential
technologies. A technology could be considered in-
feasible because of physical, chemical, and engineer-
ing impacts, if the application of the technology would
not result in successful compliance with an emission
limitation. However, the reasons for technical infeasibili-
ty should be clearly documented in the analysis. An
emission limit (not a technology! can be eliminated on
a technical basis if it can be shown that other operating
sources with the same control technology have not
been able to achieve compliance with the emission
limit or that site-specific considerations would preclude
meeting the emission limition.
It is not necessary to evaluate technologies that offer
a level of control that is less than the proposed BACT
limit.
STEP 4—ECONOMIC AND ENERGY EVALUATION
OF CONTROL ALTERNATIVES
Once the technically feasible alternatives have been
identified, they are ranked according to control effec-
tiveness, starting with the most stringent control
alternative. The technologies are then evaluated on the
basis of economic impacts. Energy consumption is an
integral part of the economic analysis. Therefore,
energy impacts are evaluated as part of the economic
analysis.
1-22
-------
Engineering economics are the generally accepted
method of evaluation. Capital and annual operating ^in-
cluding maintenance) costs are presented, as well as
total annua) 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 BAG" 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 6~ RECOMMEND BACT 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 BACT 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 ecpen-
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 require an additive or catalyst that
might have hazardous ex- 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-dewn 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 (VOG 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 e/aluated 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 preside a good
argument against the imposition of a IAER 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 vwuld 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 Co 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
PROJECTS
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 COGENERATtON PUNT
This project consists of two 90 MW bituminous coal
fueled circulating fluidized bed (CFBJ boilers
scheduled tor 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 (5NCR) and combustion controls also
evaluated as available control technologies. The BAG"
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 036 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 limitation of 0.11 Ib/MBtu.
COAL FUELED MICHIGAN POWER PUNT
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 035 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/MBtu. 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 woufd 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 BAG" 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 performed 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 prwide adequate arguments
disputing regulatory agency control technology man-
dates, Finally, the applicant must carefully establish and
represent project site specifics.
It is becoming 3 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
-------
ANALYSIS OF 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
1-27
-------
ABSTRACT
This paper presents an analysis of combustion and selective catalytic reduction NOx control cost and
performance estimates from the report "Retrofit Costs for S02 and NOx Control Options at 200 Coal-Fired
Plants". Although the information used for the analysis was developed under a National Acid Precipitation
Assessment Program Study, the results and conclusions of the analysis are those of the Radian analyst
The analysis indicates that the application of low NOx burners (LNB) on wall-fired boilers and close-coupled
overfire air (OFA) on tangential-fired boilers is likely to have a wide range of effectiveness (15 to 55%) for retrofit
applications. And, it can be expected that many wall-fired boilers applying LNB and tangential-fired boilers
applying close-coupled OFA may have difficulty in achieving emission limits of 0.5 and 0.45 pounds per million
Btu (650 and 585 mg/Nm3 @ 6% 02), respectively. The unit cost of control using these technologies ranged
from less than $100/ton to greater than $1300/ton of NOx removed. By comparison, the analysis shows that the
application of cold-side selective catalytic reduction has a unit cost of control ranging from $700/ton to greater
than $6000/ton of NOx based on 80% NOx reduction and 3 year catalyst life.
1-29
Preceding page blank
-------
INTRODUCTION
This paper presents an analysis of the combustion and selective catalytic reduction NOx control cost and
performance estimates from the report "Retrofit Costs for S02 and NOx Control Options at 200 Coal-Fired Plants"
(1). The information contained in this report was developed under a National Acid Precipitation Assessment
Program study. 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 (S02) and nitrogen oxide (NOx) controls at coal-fired utility plants. Although the NAPAP study
resources were primarily focused on the retrofit cost of S02 controls, cost estimates were developed for iow
NOx combustion controls [low NOx burners (LNB), close-coupled 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 (2). 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 (3). 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 (4). 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 (1). The cost and
1-30
-------
performance estimates that provided the basis for the analysis are estimates for a specific time period (primarily
1985) and do not reflect future changes in boBer and coal characteristics (e.g., capacity factors and fuel prices)
or the significant developments In control technologies since 1988.
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 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 close-coupied 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 coid-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 S02 control systems, thereby reducing or
eliminating the catalyst poisoning effects of sulfur (S03), chlorides, arsenic, and alkali metais, 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
1-31
-------
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 (329-357°C). 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 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 NQX 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 (6). 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 (3):
NOxEFF = 68.8 * (V/MW) (A)
where: NOxEFF = NOx removal efficiency (percent)
V = Furnace volume (1000 cubic feet)
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.
1-32
-------
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) (3):
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.
Even less data were available on NOx reductions that can be achieved when retrofitting close-coupled 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. Close-coupled 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 Reburnina
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.
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
1-33
-------
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:
• 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 S02 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.
1-34
-------
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 (11) escalated to 1988 dollars.
For each control technology, cost per ton of NOx removed (Figures 3 and 4) and annual cost (Figures 5 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
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 5 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 iow 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 N0X reduction efficiencies.
1-35
-------
LNB controls were applied to wall-flred dry-bottom boilers. Example characteristics of boilers having low, mid,
and high unit costs are:
Low $/ton
Mid $/ton
Hiah $/ton
NOx Unit Cost - $/ton
50
150
1315
($/metric ton)
(55)
(165)
(1450)
Boiler Size - MW
1000
640
45
NOx Reduction - %
53
43
40
Capacity Factor - %
83
48
28
NOx Removed - tons/yr
15828
4586
183
(metric tons/yr)
(14359)
(4160)
(166)
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%) N0X reduction efficiencies; and 23% were estimated to have low (25 to 35%) NOx
reduction efficiencies.
Close-coupled OFA controls were applied to tangential-fired boilers. Example characteristics of boilers having
low, mid, and high unit costs are:
Low $/ton Mid $/ton Hioh $/ton
NOx Unit Cost - $/ton
27
100
1248
($/metric ton)
(30)
(110)
(1376)
Boiler Size - MW
865
350
29
NOx Reduction - %
35
25
25
Capacity Factor - %
79
56
18
NOx Removed - tons/yr
6895
1271
39
(metric tons/yr)
(3534)
(1153)
(35)
1-36
-------
Of the 214 boilers, 4% were estimated to have high (26 to 35%) NOx reduction efficiencies; 73% were estimated
to have moderate (25%) N0X 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 substitution. 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 S02 due to the 15% fuel substitution. If the S02 reduction
were included in the unit costs, the unit cost of NGR would be reduced by 15 to 45%.
Selective Catalytic Reduction Cost Results
In this study, cost estimates for SCR were developed for 624 boilers: 577 toilers with cold- side systems and 47
boilers with hot-side systems. Figures 4 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 (35°C) 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.
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.
1-37
-------
For SCR, example characteristics of boilers having low, mid, and high unit costs are:
Low $/ton
Mid $/ton
High $/ton
6091
(6714)
NOx Unit Cost - S/ton
($/metric ton)
Boiler Size - MW
NOx Reduction - %
Capacity Factor - %
NOx Removed - tons/yr
(metric tons/yr)
10,546
(9567)
710
(783)
217
80
94
1810
(1995)
543
80
49
8331
(7558)
45
80
28
366
(332)
CONCLUSION
Radian derived the following conclusions from an analysis of the combustion and selective catalytic reduction
NOx control cost and performance estimates presented in the report "Retrofit Costs for S02 and NOx Control
Options at 200 Coal-Fired Plants" (1). These conclusions are those of the Radian analyst, and do not reflect the
views of the U.S. Environmental Protection Agency. The analysis shows that the application of LNB on wall-fired
boilers and close-coupled OFA on tangential-fired boilers is likely to have a wide range of effectiveness for
retrofit applications due to the complexities of combustion modification controls. And, it can be expected that
many units may have difficulty achieving emission limits of 0.5 pounds per million Btu (650 mg/Nm3 @ 6% 02)
for wall-fired boilers and 0.45 pounds per million Btu (585 mg/Nm3 @ 6% 02) for tangential-fired boilers with the
application of LNB and close-coupled OFA, respectively. On a unit cost basis ($/ton), SCR control costs were
estimated to be more than an order-of-magnitude greater than LNB and OFA control costs. 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 retrofit application experience. Therefore, the NOx control performance and cost estimates and
NOx emission level estimates presented in the NAPAP 200 plant study could vary widely from what can be
achieved In practice.
1-38
-------
REFERENCES
1. Emmel, T. E., and M. Maibodi. Retrofit Costs for S02 and N0X Control Options at 200 Coal-Fired Plants,
Volume I. EPA-600/7-90-021 a (NTIS PB91-133322), U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina 27711. November 1990.
2. Emmel, T. E., S. D. Piccot, and B. A. Laseke. Ohio/Kentucky/TV A 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, August 1988.
3. 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.
4. Emmel, T.E., M. Maibodi, and J.A. Martinez. Comparison of West German and U.S. Flue Gas
Desulfurization and Selective Catalytic Reduction Costs. EPA-600/7-90-G09 (NTIS PB90-206319), U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina 27711. April 1990.
5. Palmisano, P. J., and B. A. Laseke. User's Manual for the Integrated Air Pollution Control System Design
and Cost-Estimating Model, Version II, Volume I. EPA-600/8-86-03la (NTIS PB87-127767), U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina, September 1986.
6. Eliiot, 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-600/9-86-021 a
(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, April 1982.
10. Shattuck, D. M., et at. 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, A.L Blackard, and R.J. Page. Integrated Air Pollution Control System, Version 4.0, Volume 2.
Technical Documentation Manual. EPA-600/7-90-022b (NTIS PB91-133520), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina 27711. December 1990.
1-39
-------
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 ($7.9/KCal)
Electric power
0.05 $/kWh
Catalyst cost
20,290 $/ton
(22,477 $/metric 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%.
1-40
-------
FIGURE 1. 200 PLANT STUDY TECHNICAL APPROACH
1-41
-------
Capital Costs O & M Costs Annualized Costs Emission Reduction
FIGURE 2. SITE-SPECIFIC COST ESTIMATION METHODOLOGY.
-------
V
I
CO
Q
Ui
>
O
s
UJ
DC
X
o
z
o
c
o
&s
o
o
z
3
1,600
1,400
1,200
1,000
800
600
400
200
¦ NGR
A LNB
X OFA
1988 CONSTANT DOLLARS
75% of Boilers
50% of Boilers
20,000
40,000
60,000
SUM OF MW
FIGURE 3. SUMMARY OF COST PER TON OF NOx REMOVED RESULTS FOR LOW
NOx COMBUSTION.
-------
V
SUM OF MW
FIGURE 4.
SUMMARY OF COST PER TON OF NOx REMOVED RESULTS FOR
SELECTIVE CATALYTIC REDUCTION
-------
r
i
Ul
£
.*
\
0)
H
0)
o
o
z
z
<
20,000
40.000
60.000
SUM OF MW
FIGURE 5. SUMMARY OF ANNUAL COST RESULTS FOR LOW NOx COMBUSTION
-------
1988 CONSTANT DOLLARS
I
}
70% of Total MW
80% of Total MW X.
25% of Total MW X
3 YEAR CATALYST UFE
i i i i I i l I I I I I I I I I i i i
0 20,000 60,000 100.000 140.000 180,000
SUM OF MW
FIGURE 6. SUMMARY OF ANNUAL COST 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
Rosenead, California 91770
1-47
-------
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
Preceding page blank
-------
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 NOk 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 wlndbox where such a system does not
exist already.
Urea Injection. This technology involves the injection of Urea (N^CON^)
into the furnace exit and/or boiler convection pass. If the temperature in these
boiler locations is between 1650 and 1B50°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) NH^ radicals formed from the
disassociation of the urea will oxidize to form additional NOx. Should the
temperature be too cold (<1500°F) the NHj 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 357.
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.
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.
i
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
modifications of 9 units, and the retrofit of 9 units with SCR systems. An
implementation schedule is shown In Figure 2 and was designed to meet the interim
emission levels as well the ultimate .25 lb/MWHR system emission level required by
the end of 1999 as i1lustrated 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
Urea injection
Combustion Modifications w/FGR
Combustion Modifications w/o FGR
Selective Catalytic Reduction
$100 to $120/kW
$3/kW
$28/kW
$9.30/kW
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 Alain tos Generating Station Unit 5 (480 MW). By
installing just 1-row (replacing one which is out of service) the operabi1i ty 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 1 evel of NOx
reduction (50-60%). The basic difference between this type of urea injection
and the previously di scussed 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 1 s 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 351 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 1n 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 lb. NOx/MWh by December 31, 1999
Averaging time Is calendar day
Systemwide averaging
Incremental compliance schedule starting In 1990 through 1999
Ed 1 son to Install and operate an SCR unit on a 480 MW steam generator by
December 31, 1993
SUMMARY - RULE 1134
Requires 15 ppm NQx 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
Maximum Rated
Station Unit Capacity, MH
Alamitos 1 175
Alamitos 2 175
Alamitos 3 320
Alamitos 4 320
Alamitos 5 480
Alamitos 6 480
El Segundo 1 175
El Segundo 2 175
E1 Segundo 3 335
El Segundo 4 335
Etiwanda 1 132
Etiwanda 2 132
Etiwanda 3 320
Etiwanda 4 320
Hi ghgrove 1 32.5
Highgrove 2 32.5
HIghgrove 3 44.5
Highgrove 4 44.5
Huntington Beach 1 215
Huntington Beach 2 215
Huntington Beach 3 215
Huntington Beach 4 225
Redondo 1-4 292
Redondo 5 175
Redondo 6 175
Redondo 7 480
Redondo 8 480
San Bernardino 1 63
San Bernardino 2 63
Total 6626 MN
1-56
-------
Compliance Schedule
Technology/
Activity Descriptions
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Rule 1135
Urea Injection (5,600 MW)
Combustion Mods (1,900 MW)
SCR (3,200 MW)
Repower (1,000 MW)
1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
FIGURE 2
-------
NOx Lb./MWh
NOx Emissions Compliance Schedule
(Rule 1135)
1.50
1.10
1.00
.75
.50
.25
Proposed Rule 1135
Compliance Illustration
I I
J L
1989 90 91 92 93 94 95 96 97 98 99 2000
FIGURE 3
-------
Low NOx Burner
Typical Installation
Flue
Gas
I
Boiler
Burners
•^To stack
Air
Preheater
Forced Draft
Fan
FIGURE 4
-------
High Energy Urea Injection
Demonstration Project
FIGURE 5
-------
SCR/Air Preheater
Typical Installation
storage tank
FIGURE 6
-------
r
Economizer SCR
Typical Installation
CT>
ro
\"4
Boffer
Burners
Flue
Gas
\
cB.
WBm
Catalyst
Modules
mm.
II1P
Economizer
rTo ammonia
injection grid
To stack
Ajr Forced Draft
Preheater
Fan
m
Ammonia w a
vaporizer
Air
blower
Liquid ammonia
storage tank
FIGURE 7
-------
r
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
-
/ Baseline
100
/
75
Combustion
—1 / improvements "
i
50
- "1 j, Urea
SCR
Economizer
25
——^"^New limit
t
... uun ncnvass
1 1 1 1
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
1-65
-------
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
Preceding page blanl
-------
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 (I). A single nitrous oxide molecule has the greenhouse warming potential of about
250 carbon dioxide molecules (3) with strong absorption bands at 520-660 cm-1, 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^D)) (1):
(1) n2o + hf -~ N2 + 0(1D), X < 341 nm
(2) N20 + 0(lD) -+ NO + NO
(3) N20 + O^D) - N2 + 02
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 (03) through the nitrogen oxide catalytic cycle (1):
(4) NO + 03 N02 + 02
(5) N02 + O -» NO + 02
The net reaction of reactions (4) and (5) is: 03 + O -»202. 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 N20 per year
(1 Teragram of or 1 Tg = 10® metric tons = 1012 grams) (Z). 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
(NO»-) to nitrate (N02~) 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 wrth 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 (17,18,11). 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(20). 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 m-2 s-1, the minimum detectable emission of the gas
chromatograph, to more than 20 ng N m-2 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 stimulates 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 (2Q). 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 Tropica! 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
N20 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 N20." 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 N20 Budget." Nature. 355, 1988, pp. 57-59.
17. L. J. Muzio and J, C. Kramlich. "An Artifact in the Measurement of N20 from Combustion
Sources." Geophysical Research Letters, 15, 1988, pp. 1369-1372.
18. L. J. Muzio, M. E. Teague, J. C. Kramlich, J. A. Cole, J. M. McCarthy, and R. K.
Lyon. "Errors in Grab Sample Measurements of N20 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 N20 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. Cofer 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. Cofer 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. Cofer 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 (Mil) 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 (IS) 0.5-1.1
Total 11.22-16.10
1-75
-------
DEVELOPMENT AND EVOLUTION OF THE ABB COMBUSTION ENGINEERING
LOW NOx CONCENTRIC FIRING SYSTEM
John Srusha, Manager of Firing Systems Engineering
Michael S. McCartney, Director, Fuel Systems and Controls Engineering
ABB Combustion Engineering Services, Inc.
2-1
Preceding page
-------
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 ICR 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
Preceding page blank
-------
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 al 1 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 wi11 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 waterwal1s. This technique called
concentric firing is well established as a method to keep oxygen on
the waterwal1s 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
siag 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
Ashland, KY
Virginia
Utah
W. Virginia
HHV
FC/VM
%N
XS
%Ash
13430
2.0
1.4
.8
9.3
14150
2.0
1.7
.8
6.6
11740
2.7
1.5
.6
16.1
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% Og (60% reduction) while operating at 3.1% 0^ 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 lbs/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 waterwal1, 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
coals 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 ppm 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 Og levels were evaluated. Figure #15
compares the effects of varying Og on NOx and CO, during staged and unstaged
firing conditions. Varying the 0^ between 2% and 3% without OFA had a minimal
effect on NOx production. At the same Og 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 0^ levels.
However, under deep staged conditions at low 0^ 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 1bs/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. 2% 0^).
Low NOx Concentric Firing System (LNCF5) 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 LMCFS 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 0^
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 1ignitic 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
available.
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 0.,,
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, 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
1bs/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
-------
CO
E
CL
a
d
z
200
KP&L Lawrence #5
400 MW CCRR Unit
Subbit. A Coal
PM
December
Testing
BASELINE
PM
Early Data
BOILER LOAD (MW)
Figure 1. NOx vs. Boiler Load with 'PM' Firing
System
ORIGINAL
WINDBQX
PRE RETROFIT
CCTFS
ARRANGEMENT
-SEPARATED OFA WITH
ADJUSTABLE YAW
-COUPLED OFA
-COAL NOZZLE CLUSTER
~¦OFFSET AIR NOZZLES
POST RETROFIT
Figure 2. Clustering
Figure 3. Boiler Simulation Facility
305
300
> :
k
ft,:
«°=>
0#O
-------
FIREBALL
ROTATION "/
ADJUSTABLE
YAW
FURNAGE
PLAN VISW
0°YMl -1S°Y8
-------
m
Crd A;r
Gos
-ejo-
_L
Gos
Coal
4-
Cos
-e|e-
31
-.aLr-,
Gas
|IXI
Coal
4- ¦
Gas
-W1
an
Li.
Gas
Cool
Gas
rvon
Gas
Coo.'.
CO
EtiW Air
FFffl
Separ*a*tee»
Dverfire
n
CD
XT
Close
Coupteci
~verf ire
lias
m
Gqs
Bl
Gas
Offset Air
Dffifei Air
Cos
Oil
Das
Gos
~ii
Cos
LNCFS
ICO ft
AH COAL
K CALL
ARCH NiNtftAL
W. BIT
(M Received)
30911
11844
14170
12'3;
10957
M0ES1
3 63
7.50
i .3
7.53
9.26
VH
21.75
24.64
27.8
34.43
14.78
fC
5S.S5
52.76
64.5
50.38
43.86
ASH
M.5*
15.10
$.4
7M
12.10
(om
c
83.29
n.ie
87.1
76.60
79.52
H
4,42
i.gz
5.2
5.16
5.80
H
2.C3
i 63
i.5
1.51
1.74
S
0.65
0.«0
0.3
0.85
0.52
02
M3
7.74
5.3
7.5
12.33
Km
2.53
2.14
2,32
i.m
1.26
Figure 10. Coat Analysis, CCTFS
i
/f :
j
E BBS9lln« 1
i ~
TCOA ;
2T
-"&¦ AMCoaf i
-fr- MeCall i
-«*- Arch Mineral |
§5 105 US
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
C€ Separated Ovcrflr* Air Assembly
Patent Pending
Coal
+ TCOA
° AMCoal
McCalE
--- Arch Mineral
MOTE:
BASELINE CARBON
VALUES AVERAGED
BETWEEN 7-9%
O
05 100 ICS 110 115 120 125
Firing Zone Stoichiometry
160 MW COAL/OIL/GAS UNIT
Figure 12. Effect of Coal Fineness on Unburned
Carbon vs. Firing Zone Stoichiometry with CCTFS
Figure 9. CE Separated Overfire Air Assembly
2-16
-------
Fuel - Natural Gas
TCOA
TCGA (High Fineness)
McCail
Arch Miners]
£ 1
% lO&r
e !
S I
A so
too ISO 200 250 300 350 400 450 500
VELOCITY (FT/SEC)
160 MW COAL/OlL/GAS UNIT
j NOx
Figure 13. Effect of SOFA Air Velocity on Unburned
Carbon in Flyash with CCTFS
0.7 0.8 0.9 1 11 1,2
Firing 2one Stoichiometry
160 MW COAL/OIL/SAS UNIT
Figure 16. Effect of Firing Zone Stoichiometry on
NOx and CO with LNBFS
Fuel - Heavy Oil; OZ»2.5%
6 ioo r
Particulates < 0,1
0.7 0.8
0.8 1 1.1
Firing Zone Stoichiometry
160 MW COAUOIL/GAS UNI!
1.2 1.3
Figure 14. Effect of Fuel Nitrogen on NOx vs. Firing
Zone Stoichiometry with LNBFS
350 - 350
I Fuel - Heavy Oil (N-C.34%, S-0.81%)
- 2S0
200
1S0
O 100
z
50
H 200 £
150
100 s
¦f 50
1.5 2 2.5
Percent 02
160 MW COAL/OIL/GAS UNIT
Figure 17. Valmont#5 Side Elevation
Figure 15. Effect of Os on NOx and CO Levels
2-17
-------
A
(Coal Fineness thru 200 Mesh)
EEE0
rrrn
t t I I
] 1)11
BP
u Itnri
m
Cos
Cos
Cos
Cas
CH
f'l j jl
il ill
S^pora-tsd
Overfire
Afr
Mini
rf t M I
1 1 ..I., i '
lit If
£rd A r
Co©(
11/ S 1 1
Bx-S
Offset Air
Gas
Go. 5
LirH-li
Offset Air
M
Cool
rpmi
1 1 11 ?*T
l+LJ
Offset Air
Gas
Gas-
Offset Air
|=|
Co&l
UzESI
ffgB
Offset A.r-
Gas
Oft
Gas
Offset Air
H
Coal
End Air
Xf7
WBit (Vainer,1}
CCTFS
Arch Mineral(Fusina)
McCbII {Fusina)
80 85 90 95 100 106 110 115 120 125 130
Firing Zone Stoichiometry
Figure 20. Effect of Coal Fineness on Unburned
Carbon vs. Firing Zone Stoichiometry (200 Mesh)
Standard
Windbox
AIR
COAL
AIR
COAL
A!R
COAL
AIR
COAL
OIL
COAL
AIR
% Reduction$:
LNCFS
Level 1
OFA
OFA
COAL
COAL
CFS
COAL
CFS
COAL
OIL
COAL
AIR
Level 2
Level 3
OFA
OFA
AIR
COAL
CFS
COAL
CFS
COAL
CFS
COAL
OIL
COAL
AIR
25-32
OFA
OFA
OFA
OFA
COAL
COAL
CFS
COAL
CFS
COAL
OIL
COAL
AIR
41-50
ORIGINAL ARRANGEMENT
MODIFIED ARRANGEMENT
Figure 21. Low NOx Retrofit Options
Figure 18. Windbox Modifications
£ 400 ••
LNCFS
WBit (Valmont)
CCTFS
Arch Mlfieral(Fusina)
McCall (Fusina)
60 86 90 95 100 105 110 116 120 125
Firing Zone Stoictiiometry
150
100
50
25
20
15
10
5
-Er
LNCFS
Level i
LNCFS
Level 2
LNCFS
Level 3
Figure 22. NOx Reduction Systems, Retrofit Cost
Comparison
Figure 19. Effect of Firing Zone Stoichiometry on
NOx for Different Types of Coal
2-18
-------
PERFORMANCE OF A LARGE CELL-BURNER UTILITY
BOILER RETROFITTED WITH FOSTER WHEELER LOW-NO* BURNERS
T. L. Lu
R. L, Lungren
Arizona Public Service Company
Phoenix, Arizona
A. Kokkinos
Electric Power Research Institute
Palo Alto, California
2-19
-------
ABSTRACT
A comprehensive boiler testing program was performed on Units 4 and 5 of the
Four Corners Steam Electric Station to compare the N0X 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 1ow-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 N0X emissions levels and
to assess any changes in the performance and operabi1ity of Unit 4 due to the
installation of low-NOx burners.
resting included measurement of N0X, CO, and S02 emissions, unburned carbon,
gas temperature leaving the economizer, and heat absorption in various boiler
circuits at d1fferent levels of unit load and excess air, and with different
burner air register adjustments. Test results indicate that the low-NOx
burners reduced N0X emissions from Unit 4 by 55% compared with the unmodified
Unit 5, without any detrimental effect on boiler performance, efficiency, or
operabi Hty.
This paper should be of interest to any utility evaluating potential N0X
reductions and boiler performance effects that could be anticipated by
retrofitting these 1ow-NOx burners to pulverized-coal-fired utility boilers
with "cell" burners or conventional circular turbulent burners.
2-21
Preceding page blank
-------
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 (N0X) 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 1n very high flame temperatures, heavy slagging in the
furnace, and N0X 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) 1ow-N0x 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-N0x burners on Units 4 and 5.' 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 lb/h main steam 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 B&W 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 FWEG CF/SF low-NOx burners (Figure 2) required major design
modifications to the Unit 4 boiler including
¦ Conversion to eight pulverizers and 48 1ow-NOx burners, arranged in
four rows of six burners on each firing wall
¦ Hew lower furnace waterwal! 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 S.
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, N0X
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 N0X emissions
Tenerx Corporation was hired to collect emissions data on N0X, 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 N0X 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 wil'l 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 NO* 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 N0X 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 sewice 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 N0X
emissions from Unit 5 under low-load conditions. Figure 3 illustrates N0X
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 N0X 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 N0X emissions was 47% with AMIS, and 40% with the top MOOS. With
the two top HOOS at 50% load conditions, the staging effect on Unit 5 N0X
emission reduction was so obvious that only an average 17% NOx reduction was
observed on Unit 4.
Figure 4 illustrates N0X emissions versus unit load at various operating
excess 02 levels. A correlation analysis indicated a definite correlation
between N0X emissions and unit load for Unit 5, while the Unit 4 data did not
show significant correlation. Reducing unit load can only reduce thermal N0X,
which is a small portion of total N0X emissions. Because the turbulent
burners on Unit 5 were operated at higher peak flame temperatures than the
1ow-NOx burners on Unit 4, Unit 5 produced more thermal N0X than Unit 4, and
was more sensitive to unit load changes.
Figure 5 indicates that changing the burner tip position had little effect on
N0X 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 a1r/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 N0X 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, N0X emission levels were 0.44 Ib/HBtu at normal excess 02 level and
0.42 Ib/HBtu at low excess 0a level.
Figure 7 illustrates the N0X emissions versus burner zone liberation rate.
The effect of staging on Unit 5 NQX emissions Is 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 1ow-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 fFEGT)
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-N0x 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-N0x 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 steal 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 975-1011"F 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-N0x burners to Unit 4 reduced N0X emissions
by about 50% at normal, full-load operating conditions without any detrimental
effect on boiler performance, efficiency, or operability.
The average level of N0X emissions from Unit 4 was 0,53 lb/MBtu, well under
the applicable state of New Mexico air-quality standard of 0.70 lb/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-NOjj Burner Testing on a Large
Testing Facility." Proc. 1989 Joint Svmoosmm on Stationary Combustion
NO* Control. 2, 23 (1989).
2-29
-------
WiNDBOX
wvf; ¦¦
j t* TO 3*
w NORMAL FIRfNO POSITION
• COAL AND
PRIMARY Am
COAL NOZZLE
Figure 1
FWEC Three - Nozzle Cell Burner
:/!,:¦ :
if If
;
3-^1 f:
¦'
•
fife'
¦
- ¦¦
S
MOVABLE SLEEVE "*N«
OAMPER
SPLIT FUME COAL NOZZLE
iimiiiiiiiinwiin
Figure 2
FWEC Controlled - Flow/Split - Flame Low - NOx Burner
2-30
-------
Figure 3
EFFECT OF STOfCHIOMETRY ON
NOx EMISSIONS
NO* IB/MBTU A
STOICHIOMETRIC AIR RATIO
Figure 4
EFFECT OF BOILER LOAD ON
NOx EMISSIONS
NO*, LB/MBTU A
LOAD, MW (Nat)
2-31
-------
Figure 5
EFFECT OF BURNER NOZZLE POSITION ON
NOx EMISSIONS
FULL LOAD NOx, LB/MBTU
1.4
; i i
• ; ;
-e- LOWER EXCESS 02
-t- HIGHER EXCESS 02
o NORMAL EXCESS 02
* » J
1 \ i
! i I i j j
4 1 j j— j [ «
Y j a : : "9
1 i 1 i i 1 i
-2-10 1 2
BURNER TIP POSITION, INCHES
Figure 6
EFFECT OF AIR REGISTER POSITION ON
NOx EMISSIONS
FULL LOAD NO*, LB/MBTU
1.4
1.3
1.2
1.1
1
0.9
0.8
0.7
i
-i
\
INNER AIR REGISTER
-+- OUTER AIR REGISTER
* INNER REG w/LOWER 02
\
•i
\
!
I
\
u U(
JlcH Hcu W/LOWER UZ
\
: 1
^ * 1
t
f
¦ ¦ ¦ • 1 "i - ¦1 "¦ ¦ 1 '
' ¦ M> ¦ 1 *' i
«¦¦¦ "i— *
0.5
0.4
0.3
AIR REGISTER POSITION, % OPEN
2-32
-------
Figure 7
EFFECT OF BURNER ZONE LIBERATION
RATE ON NOx EMISSIONS
NOx, LB/MBTU
o UNIT 4
+ UNITS
* UNITS-STAGING
1 s
: :
} x w
\ i
: } + : +
; i
: : :
1 5 9k {
?
—
*
O
! ° '
! ; O
\a ""~1
-------
Table 1
COAL ANALYSES SUMMARY
Test
Proximate Analysis
% Moisture
% Ash
% Volatiles
% Fixed Carbon
Energy Content, Btu/lb
% Sulfur
MAF, Btu/lb
% Air Dry Loss
Ultimate Analysis
% Moisture
% Carbon
% Hydrogen
% Nitrogen
% Sulfur
% Ash
% Oxygen
Condition Unit 4 Unit 5
14.67 14.34
As Received 16.33 16.32
Dry Basis 19.14 19.05
As Received 26.47 31.32
Dry Basis 31.02 36.88
As Received 42.53 37.75
Dry Basis 49.84 44.07
As Received 9561 9602
Dry Basis 11205 11210
As Received 0.85 0.72
Dry Basis 1.00 0.84
13857 13848
9.03 7.57
14.67 14.34
As Received 53.87 54.55
Dry Basis 63.13 63.68
As Received 3.86 3.96
Dry Basis 4.52 4.62
As Received 1.10 1.15
Dry Basis 1.29 1.34
As Received 0.85 0.72
Dry Basis 1.00 0.84
As Received 16.33 16.32
Dry Basis 19.14 19.05
As Received 9.32 8.96
Dry Basis 10.92 10.47
2-34
-------
Table 2
TEST MATRIX
Test Number
Load
Units
Excess Air
Test Condition
1
100%
4&5
Normal
Std. Nozzle 4 Register Positions
2
100%
445
Normal
Std. Nozzle 4 Register Positions
3
100%
445
Low
Std. Nozzle 4 Register Positions
4
100%
445
Normal
Repeat Std.
5
100%
4
Normal
Outer Register Open
6
100%
4
Normal
Outer Register Closed
7
100%
4
Norma!
Inner Register Open
8
100%
4
Normal
Inner Register Closed
9
100%
445
Low
Burner Nozzle In (0)
10
100%
445
High
Burner Nozzle In (0)
11
100%
445
Low
Burner Nozzle In (-3)
12
100%
445
High
Burner Nozzle In (-3)
13
75%
485
Normal
Std., All Mills In Service
14
75%
445
High
Std., All Hills In Service
15
75%
445
Normal
Std., 1 Mill Out of Service
16
75%
445
Normal
Std.
17
50%
445
Normal
Std., 2 Mills Out of Service
18
50%
445
High
Std., 2 Mills Out of Service
19
50%
445
Normal
Repeat Std.
20
50%
445
Normal
Optimal Nozzle Register Positions
21
50%
445
Normal
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 lb/h 5478 5493
Superheater Spray Flow, 1000 1b/h 433 286
Main Steam Temp., *F 1004 992
Hot Reheat Temp., *F 965 999
Furnace Exit Gas Temp.,'F 2593 2775
N0X, Ib/MBtu 0.49 1.15
2-36
-------
DESIGN AND APPLICATION RESULTS OF A NEW EUROPEAN LOW-NO, BURNER
J. Pedersen
Burmelster & Wain Energy
23 Teknikerbyen
DK-2830 Virum, Denmark
M. Berg
ELKRAFT Power Company
5 Lautruphoej
DK-2750 Ballerup, Denmark
2-37
-------
ABSTRACT
To meet the new NOx regulations in Denmark, the ELKRAFT Power Company decided in
1987 to retrofit existing coal-fired units with Iow-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 Iow-NOx burners
in the near future.
2-39
Preceding page blank
-------
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 bailer load and 3% excess 02 at the economizer outlet, of less than 440 ppm (3% 02,
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% 02, 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% 02, 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 air turbolator 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
-------
Forthe field test program at Asnaes 4, additional measurement and sampling equipment was
used, NO, S02, 02, CO, C02 and H20 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 02% 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 02 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:
• 4-mill operation: NOx « 370 ppm (3% 02, dry) and < 5% carbon in
fly ash at 3.0% 02 (dry), at the economizer outlet.
t 3-mill operation: NOx = 410 ppm (3% 02, dry) and < 5% carbon in
fly ash at 3.5% 02 (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 02, 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:
t 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 simitar 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% 02, dry). With the new
low-NOx burners, and over the same period in 1990, NOx emissions averaged 345 ppm (3%
02, 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,
Forthe types of coals used, no slag deposition has been found on the furnace walls or in the
burner throats. 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
t 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
Figure 2. NOx reduction by flame attachment.
2-48
-------
TERTIARY SECONDARY
AIR AIR
IGNITER
fcE9-
go-*-'
t
FUEL OIL
PRIMARY AIR
FOR SWIRL CONTROL ,
•FLAME HOLDER PULVERIZED COAL
Figure 3. "BWE type 4 AF" attached flame low-NOy burner.
ASNAES POWER STATION UNIT NO. 4
COAL AND AIR SUPPLY TO BURNERS
2-49
-------
ASNAES POWER STATION UNIT NO, 4
FULL LOAD. POLISH COAL
NOjj ppm
13% 02 .DRY3
500
¦ 4 MILLS
A 3 HILLS
CARBON IN ASH
400
300 ¦
200
} 00
0
2.5
Figure 5.
3.0
3.5
4.0 % 03
-e
-7
j-6
-5
-4
-3
-2
-t
-0
(DRY)
Relation between NOx-emission and excess 02%.
NO,, ppm
C3% 02 .DRY!
500
400
300
200
100 -
o-hV
ASNAES POWER STATION UNIT NO. 4
POLISH COAL, 4 HILLS IN SERVICE
t r
160 160 200 220 240 260 «We,nel
Figure 6. Relation between NO -emission and unit load.
2-50
-------
N0X ppm
(3% 02 .DRY)
500
400 ¦
300
200 ¦
too
-V
ASNAES POWER STATION UNIT NO, 4
FULL LOAD. POLISH COAL
¦ 4 MILLS
~ 3 MILLS
1 1 1 ! 1 5
SECONDARY A¦R / TERTIARY AIR - FLOUSPLlT
Figure 7. Relation between NO -emission and SA/TA-flowsplit.
N0X ppm
(3S Og .DRY]
500
400 ¦
30D •
200 ¦
0 4-Vr—
60
Figure 8.
ASNAES POWER STATION UNIT NO, 4
FULL LOAD. POLISH COAL
¦ 4 HILLS
A 3 MILLS
-r
70 80 90 100 X
Relation between NO -emission and TA-turboIator position
2-51
-------
NO, pptn
C3% Og .DRY)
500
400 •
300 ¦
200 ¦
100
ASNAES POWER STATION UNIT NO. 4
FULL LOAD, 4 HILLS IN SERVICE
2,5
o Canadian coal
O COLUMBIAN COAL
~ U.S. COAL
¦ POLISH COAL
3,0
—r—
3.5
ECONOMIZER OUTLET
1.0 X 02 DRY)
Figure 9. Relation between NOx-emission and
excess 02% for different coal types.
ASNAES POWER STATION UNIT NO. 4
COMPARISON OF DAILY AVERAGE NO* EMISSIONS
mg/hj
600 -
CLHV)
NO* EMISSION
]b/mmBtu (HHV)
500
400
300
200
100
V
-\ V/ ¦"" •,
¦ / • « * ¦ "
OLD BURNERS
JANUARY-MARCH 1909
%
'¦¦tipivysj -ijS.
a %'^a
— CTP • jP "
¦ ¦
¦ ¦ ¦
'wv ¦
NEW BURNERS
JANUARY-MARCH 1990
1.0
0.5
EACH DOT REPRESENTS DAILY AVERAGE
Figure 10. Comparison of NOx-emission with new and old burners.
2-52
-------
N0X ppin
t3% 02 .DRY)
1000
900
800
700 ¦
BOO ¦
500 •
400 •
300 H
200
too
0
ASNAES POWER STATION UNIT NO. 4
COMPARISON OF NO, EMISSIONS
PRE
1
tl
W/.
It
POST
EC-DIRECTIVE U.S. CLEAN AIR ACT
NEW COAL-FIRED DRY-BOTTOM, UALL-FIRED
BOILERS >50 flW [0.5 Ib/mmBuO
RETROFITTING ASNAES 4
Figure 11. Pre- and post-retrofitting data.
ASNAES POWER STATION UNIT NO. 4
COMPARISON OF CONTROL RANGES ON COAL FIRING
HUe
300
260
260
240
220
200
180
160
140
120
100
net
PLANT LOAD
-
•W/
V//
a
-
8
/y/t
-
PRE
POST
RETROFITTING ASNAES 4
Figure 12. Unit control range.
2-53
-------
Table 1
PERFORMANCE DATA
Generator output 285 MWe
Net output 270 MWe
High-pressure steam, outlet 235 kg/sec
190 bar
545°C
Reheat steam, outlet 40.5 bar
545°C
Table 2
COAL ANALYSES
Coal Type
Polish
U.S.
Canadian Colombian
Proximate, as received
Moisture
Ash
Volatiles
Fixed carbon %
%
%
%
9.8
16.0
24.9
49.3
13,1
14.6
24.8
47.5
12.3
14.3
20.8
52.6
12.5
9.1
31.5
46.9
Ultimate, as received
Moisture
Ash
Carbon
Hydrogen
Sulphur
Nitrogen
Oxyggen
%
%
%
%
%
%
%
9.8
16.0
62.5
3.6
0.6
1.0
6.5
13.1
14.6
60.2
3.4
1.2
0.9
6.6
12.3
14.3
62.7
3.3
0.4
0.9
6.1
12.5
9.1
65.4
4.0
0.8
1.3
7.0
LHV
HHV
MJ/kg
MJ/kg
24.50
25.50
23.74
24.76
24.32
25.32
25.50
26.64
2-54
-------
APPLICATION OF GAS REBURNING-SORBENT INJECTION TECHNOLOGY
FOR CONTROL OF NOx AND S02 EMISSIONS
W. Bartok
8.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
2-55
-------
ABSTRACT
A Clean Coal Technology project 1s being carried out by Energy and Environmental
Research Corporation (EER) to demonstrate Gas Reburning-Sorbent Injection (GR-SI)
technology for N0X and SO2 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 NO* emission by 60% and SO2 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 SR-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 CO2.
This paper compares predicted results with data collected during initial
operations.
2-57
Preceding poge blanl
-------
INTRODUCTION
Gas Reburning-Sorbent Injection (GR-S1)n-m ,s 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 (SO2) and nitrogen oxide (NOx) emissions. The specific goal of
the project is to demonstrate that SO? reductions of 50% and NO* reductions of 60%
are attainable on an economically feasible basis. Among the advantages of this
technology is that many coal fired boiler — especially 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 N0X.
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 SO2 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 NQX 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 N0X
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 isothermal 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
bof1er.
SORBENT INJECTION DESIGN
Sorbent Injection is used to reduce SO2 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 SO2 gases.
Sorbent is used in excess quantities because sorbent utilization is incomplete.
The collected mixture of fly ash and sorbent is alkaline. When the fly ash is
hydraul ically 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 CO2. 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 CQ2
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, 6R-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
diagram of Figure 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 handl1ng 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 returning 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
overfi re 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 1ncluded 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 OEMS 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 1s
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.
Phase discrimination probes are not required at the stack breeching. This is
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 N0X 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
MWc(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 fol1 owed 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 stolchiometry at different boiler loads. Figure 7 shows a plot of N0X and O2
versus time during a typical 6R run. It can be seen that at a reburnlng zone
stoichiometry of 0.9, the N0X emission level drops from the baseline condition of
2-63
-------
about 400 ppm to between 125 and 150 ppm ( all values corrected to 3% O2 dry basis).
Thus, reductions of N0X on the order of 65% are indicated by these preliminary
tests. The degree of reduction slightly exceeds the stated target of 60% NO*
reduction by GR. For comparison, the predicted reductions in NO* calculated using
EER's kinetic models are shown in Figure 8. Figure 7 clearly indicates the strong
correlation between decreases in NQX 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 NQX emissions. This
effect will be investigated further.
The variation of N0X 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 N0X at a reburning zone stoichiometric ratio of 1.20 to a range of 125-225
ppm at 0.90 in line with the N0X 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 N0X 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 NO* 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 recirculation, 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 Reburni r.g-Sorbent Injection NQX-S02 emission control system has
been installed on a 71 HWe(net) tangential boiler fired with 3 wt% sulfur Illinois
bituminous coal. Preliminary GR test results indicate that the predicted level of
60% reduction in NQX 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 mi 11s/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. Stern!ing, 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 NO* Removal
Process," Paper presented at U.S.-Japan NO* Information Exchange, Tokyo,
Japan, May 25-30, 1981.
4. Qgikatni, 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 N0x/S0x 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 N0X Reduction," ASME Paper No. 84-JPGC-APC-9, 1984.
2-65
-------
7. Seeker, W.R., et al., "Control ling Pollutant Emissions from Coal and Oil
Combustors Through the Supplemental Use of Natural Gas," Final Report, GRI
5083-251-0905, 1985.
8. England, G.C., et al., "Field Evaluation Humidification for Precipitator
Performance Enhancement." presented at the 7th Symp. on the Transfer and
Utilization of Particulate Control Technology, Nashville, TN. March 22-25,
1988.
9. Bartok, W. and B.A. Folsom, "Control of N0X and SO2 Emissions by Gas Reburning-
Sorbent Injection," American Institute of Chemical Engineering Annual
Meeting, New York, November 1987.
10. Folsom, B.A., et al., "Field Evaluation of Gas Reburning-Sorbent Injection
Technology for NO* and S0X Emission Control for Coal Fired Utility Boilers,"
15th Energy Technology Conference and Exposition, Washington, D.C., February
17-19, 1988.
11. Bartok, W., et al., "Gas Reburni ng-Sorbent Injection for Controlling SO* and
N0X in Utility Boilers," Env. Progress £(1), 18, 1990.
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
SORBENT
OVERFIRE AIR
GAS 20% + FGR
TANGENTIAL
CYCLONE
Figure 1. GR-SI Configurations for Two Types of Boilers
* LOW LOAD SI THROUGH REBURN AIR INJECTORS
Figure 2. Summary of Injector Specifications for Tangentially Fired Boiler
2-67
-------
V
ro
O)
oo
TRUCK
UNLOADING
TRANSPORT AIR
BLOWER
ASH UNE
PH CONTROL
HENNEPIN UNIT 1 TANGENTIALLY FIRED BOILER
Figure 3. GR-SI Process Schematic
-------
GAS SAMPLE TO
CEMS
(VIA THOMAS PUMP)
if
V
jjjp^
/ 1
Figure 4. EER Phase Discrimination Gas Sample Probe
Figure 5. Continuous Emission Monitoring System
2-69
-------
r
ro
¦nJ
o
M
JQ
8>i
to
•a
«*>
0.
x
o
S!
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, MM (Gross}
~ AVERAGE VALVES
LINEAR REGRESSION TREND S3®. DEV.
Figure 6. Baseline N0X Emissions
-------
V
ro
m
«
A
>1
M
•a
8.
o.
o
S5
8:27
-- 5
9:27
10:27
11:27
12:27
13:27
14:27
15:27
16:27
RS = Reburn Stoichiometry
— NOX — 02
All flowrates expressed In SCFM
1/10/91 S 08:30 hrs.
Figure 7.
Hennepin Unit 1 Gas Reburning Test
-------
RESIDENCE TIME (SECONDS)
Figure 8. Predicted N0X Control
2-72
-------
Boiler Load « 69 MW (Gross)
Reburning Zone Stoichiometric Ratio
Figure 9. Effect of Reburning Zone Stoichiometry on N0X Emissions
-------
RETROFITTING OF THE ITALIAN ELECTRICITY BOARD'S
THERMAL POWER BOILERS
R, Tarll, A. Benanti, G. De Michele
Ents National© Kti£ i* ^ i s Elsttirics.
Italy
A, Piantanida
F.T.C.
Italy
A. Zennaro
ANSALDO ABB
Italy
2-75
-------
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 87% 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 /I/ 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).
Preceding page blank
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 //I (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/Nm^ of the 18 burner configuration. (0£ about 0,9%, GR
regulating) to 550 mg/Nm^ with 0£ ~ 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 O2 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/Nm^ (18 burners) to 540 mg/Nni^ (12
burners) with O2 = 1,6% and GR dampers opened 70% with CO = 84 mg/Nm^ (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
O2 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/Nm^ with O2 - 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-firing 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/Nm^ (02~1%) to about 520 mg/Nm-^
with 0£ " 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 O2 - 1.07 % and GR dampers opened 65%, the NOx
emissions decreased from 685 rag/Nm^ to 170 mg/Nm^ (75% reduction), while CO was
40 mg/Nm'. Without GR (dampers closed) the NOx emissions were ~ 300 mg/Nm^ (O2
" 0.8%).
2.2 Low NOx Combustion Tests with Coal
During 1990 ANSALDO modified the combustion system of Unit # 4 at the VAD0
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
rag/Nm^ (O2 " 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/Nm^ and carbon in flying ashes was 6%. Operating in the same way, but
with higher O2 (~ 5%), NOx can be reduced from 1440 mg/Nm^ to 970 mg/Nm^, while
carbon in flying ashes increases from 5,5 (original burner configuration) to
7,7t (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/Nm^ to
500 mg/Nm^ was achieved (O2 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/Nm^ to about 390 mg/Nm^) with O2 ~ 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/Nni^ less in
the high NOx - without OFA - configuration and * 100 mg/Nm^ 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 (6-81), 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/Nm^ (without the
OFA mode) to " 220 mg/Nm^ (high OFA mode) ,* O2 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/Nm^ (with O2 " 1,5% and CO — 40
ppm); in the best operating low-NOx condition, NOx emissions were about 95
mg/Nm^ with O2 " 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 mdxcated 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
/l/ B. Billi, E. MarchesI, R. Tarli
Retrofitting of existing thermoelectric plants .
GEN-UPGRADE 90 Symposium, March 1990, Washington DC, USA,
/%/ 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
VHtVASSO
Uni (
5 C«2
PIACENZA
Uni (•
3,4
LA CASELLA
Unl 1>
),2,3,4
OSTIGLIA
Untie
J.2,3.4
Tim WO LEV.
Unit
f f»J
Unit
2
Unit*
3.4
SERKIOE
Units
1,2.3.4
TAMZZANO
Unl tm
5,6
HONFALCONE
Uni (•
3,4
PORTO TOLLE
Uni l»
1.2,3.4
TORREV. SUD
Units
2,3.4
rum*)/, mm
Uni !«
1,2.3,4
R066AN0
Uni i*
(,2,3.4
Tmmm i.
Uni t#
4,5
PRIOLO e.
Unit*
I.S
TOTAL CAPACITY
(WW
COAL FIRED BOILER
LA SPEZIA
Uni t«
1.S.4
Unl t
3
VADO LIGURE
(Mi ttf
1,2.3
Uni t
4
PWHBINO
Uni ta
f,2,3,4
FUSINA
Unl iff
3,4
brindisi nord
Uni iff
1.2
Unit*
3,4
S.FILIPPO
Unit
S
Unit
6
SULCJS
Unl fcs
1,2,3 (•}
TOTAL CAPACITY
(WW
FRONT-REAR BURNERS
tuo
mmsTEx
CELLS
33 O
I. £60
640
320
S.S70
THREE
meism
SELLS
i .seo
320
! .280
640
3.520
600
990
640
320
2.550
fiNMLLE.
FLOU
1.280
e 4o
640
3.640
6,200
TANGENTIAL
FIRING
BURNERS
660
1.320
660
2.640
960
640
6.880
1.235
640
J .675
f»3 Wire EQUIPPED WITH CIRCULAR BURNERS ON THE
FRONT WALL (TOTAL CAPACITY 1.220 MW1
Tab.J. BURNER CONFIGURATION OF ENEL's EXISTING BOILERS (CAPACITY >200 We),
2-83
-------
900-
aoo-
700-
O
£
600-
500-
£
400-
X
O
300-
2:
200 -
100-
0-
0 IS BURNERS
O IS BURNERS IDA,IPERS CLOSED)
4- IS BURNERS IDAdPERS OPENED SSX)
100 200 300 400
load, my]
Fig. I - ROSSANO M4 - OIL FIRING
NOx (3X 02J AS A FUNCTION OF THE OPENING
OF THE DAMPERS OF THE UPPER BURNERS
900-
800-
700-
i—,
u
6
600-
a:
\
500-
D)
6
W
400-
X
O
300-
z
200-
100-
0-
t
a 18 BURNERS
+ 18 BURNERS tDAHPERS OPENED SBX1
1 r
too
1 1 1 r
200 300
400
load, my]
Fig.2 - ROSSANO M4 - OIL FIRING
MINIMUM NOx C3X 0g) VALUES IN
ACCEPTABLE OPERATING CONDITIONS
2-84
-------
1200-
1000-
o
e boo-
\
05
6 600-
O 400-
200-
0-
A AXIAL BURNER
O TEA BURNER
NOx
CO
•A-e—A
0.5
1.0
02 - (XJ
T
1.5
¦250
¦200
150
•100
•50
o
6
X
o»
6
O
u
2.0
Fig. 3 - tlONFALCONE POUER STATION
COMPARISON BETWEEN NOx AND CO
CSX OgJ OF AXIAL AND TEA BURNER
\
en
x
o
a:
BOO
700
600
BOO
400
300
200
100
Id BURNERS
f 0 12 BURNERS
3.
777
A
ISO
200 260
LOAD, WW
77
6L
£4c
m
//,
320
Fig. 4 - SERtllDE #3 (350 Ml GAS FIRING
NOx (3X 0g] EMISSIONS VERSUS LOAD
2*85
-------
woo
900-
o
£
2:
800-
%
Oi
S
700-
*
o
600-
500-
Fig. 5 - VADO LIGURE ff4 C330 tlV- 5 HILLSJ
NOx (3% 0SJ EMISSIONS VERSUS 02
NOx PORTS OPENING*50mm COAL ASHLAND
GR=50X DAMPERS OPENING
1 I 1 1 r
240 250 250 270 260 290 300 310 320
LOAD, CM)
330
Fig,6 - VADO LIGURE #4- LOU NOx BURNERS
NOx C3X 0g) EMISSIONS VERSUS LOAD
NOx PORTS OPENING=50mm COAL ASHLAND
GR-50Z DAMPERS OPENING
2-86
-------
0B, (X)
Fig.7 - FUSINA U2 (170 HU - COAL TCOAJ
INFLUENCE OF EXCESS AIR ON NOx C3X OgJ
AND CARBON IN FLYING ASHES-HIGH OFA
MODES-HIGH FI NESS
450-
| 400-
FINESS.-87X ON 200 HESH
OFA i 105 l/b
O 350-
2;
300-
4 5
os. m
8 W
lu
p ^
Fig. 8 - FUSINA JfS C170 HU - COAL flcCALL)
INFLUENCE OF EXCESS AIR ON NOx (3X Og)
AND CARBON IN FLYING ASHES-HIGH OFA
MODES-LOU FINESS
2-87
-------
300-
| BOO ¦
\
Oi
o too-
350
NQx NO OFA
NO* HIGH OF A ft HO l/k)
j , j j 1—
0.6 I 1.2 1.4 1.6 1.6 2 2.2
02 - (X]
FUSINA tf2 - GAS FIRING
INFLUENCE OF EXCESS AIR ON NOx
C3X Op) -HIGH AND LOU OF A flODES
ST, f-}
10 - DEPENDENCE OF NOx REDUCTION
FROM REBURN OR MAIN BURNER
ZONE STOICHIOMETRY OBTAINED
ON CE-I5HU-BSF
2-88
-------
RETROFIT EXPERIENCE USING LNCFS ON 350 MW AND 165 MW
CQA1 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
2-89
-------
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 lb/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 lb/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 801s 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
Preceding page blanl
-------
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 S02 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 PSCC1s
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 PSCe 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 (ISA) 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 02 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 02 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.
Valmont 5
Cherokee 4
Electrical Generation
165MW
350MW
Steam Flow
1,230,000 lb/hr
2,587,000 lb/hr
Steam Pressure
1800 psig
2400 psig
Superheat jReheat
1005°F/1005°F
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
-------
VAJLMOKT #5
QR2QIHAL XJMCFS
TOP AUXILrARV AIR
COAL
2 OAS ~ AUXILIARY Alft j
2 GAS ~ AUX21ZARV AIR |
2 OAS + AUXILIARY AIR |
COAL
LOWER AUXILIARY AIR
OVERFIRED AIR
TOP AUXILIARY ATS
COAL
CP AIR
2 OA3 » AUXILIARY AIR
CF AIR
COAL
CF AIR
2. SAS -~ AUXILIARY AIR.
cr AIR
COAL
CF AIR
a GAS - AUXILIARY AIR
CF AIR
COAL
LOWER AUXILIARY AIR
CHEROKEE #4
OR3QXHU. UJCFS
TOP AUXILIARY AIR
COAL
•4 CAS - AUXILIARY AIR
OAS • AUXILIARY AIR
4 OAS - AUXILIARY AIR.
4 OAS ~ AUXILIARY AIR
COAL
LOWER AUXILIARY AXR
mm
OVBRPIRED AIR
TOP AUXILIARY AIR
COAL
cr ATR
3 GAS ~ AUXILIARY ATH
CF AIR
COAL
CP AIR
3 OAS - AUXILIARY AT ft
CF AIR
COAL
Cf AIR
3 OAS * AUXILIARY AIR
cr AIR
COAL
CF AIR
3 GAS AUXILIARY AIR
cr AIR
COAL
LOWiSK. AUXILIARY AiK
"igure 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 ignitors 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
15QMW. 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 mi11
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 12QMW 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 02 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 02 of
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.
Valmoni 5 Overfire Air @ Full Lood
Aux SG%;CF 0%;02 3.1%
¦ fuel 60% A Fuel 3C%
Figure 3
2-97
-------
Volrnon) 5 Overfire Air © Medium Load
Aux 30%; Fuel 10%; CF 0%; 02 3,4%
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 NOx reduction of overfire air to 47% from
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.
0,6
0.56
>.0.45
§ 0,4
0.35
10 20 30 40 50 60 70
Overfire Air Damper Position
SO 90 ICO
Figure 4
Volmonl 5 0FA Tilt @ Full Lead
Fuel, Aux 60%, CF 0%, 02 3%
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
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.
0.5
0.475
I 0.45
J 0.425
j 0.4
0.375
0.35
-5 0
Overfjrs Air Tilt
100% or a
6S% OfA
Figure 5
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.
Valmont 5 Oxygen @ Full Load
CF 0%, Aux 60%
- ruel 30%, OfA 67%
- fu«l 60%, QFA 33%
Fuel JOS, OfA 100%
- Fuel 607., OfA 83%
fuel OS, OfA 100*;
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
Volmorit 5 Concentric Fire @ Full Load
OFA 100%, Aux 60%
0.5 -| — — — — — —
0,45
0.25 -t . . r . 1
0 10 20 30 40 50 60 70
Percent Concenlnc Fire ASr
¦ 02 1%, 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
concerttzic Fire Air 66%
WO*.
Pose i P©rt :
I Sheet Clill Uili Lcng
Figure 8
Valmont 5 NOx Distribution
Concentric Ti re Air 29,\
l»« tppn • 02;
t GID Mod»mum liiijl Long
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 02
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
-------
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.
Guarantee
Optimized
Baseline
LNCFS
LNCFS
NOX (lb/MMBtu)
0. 664
0. 294
0.31
NOx Reduction
55.7%
52.0%
Boiler Efficiency
86.63
86.35
NA
Unburned Carbon
1.6
1.6
NA
Carbon Monoxide
<30
<30
< 0
Oxygen Concentration
3.6%
3.6%
3.6%
OFA #3 Damper
NA
100%
100%
OFA #2 Damper
NA
100%
100%
OFA #1 Damper
NA
100%
100%
OFA Tilt
NA
+15°
-go
Top Auxiliary Air
50%
100%
50%
Fuel Air
50%
0%
30%
Auxiliary Air
50%
50%
50%
Concentric Fire Air
NA
30%
18%
Lower Auxiliary Air
50%
100%
0%
Valmon! 5 Carbon Carryover
3,
2,5
&
1
SO 90 1C0 110 120 130 140 150 16G 170 180
Net toad (MW)
¦ LNCF Baseline j
Figure 10
2-101
-------
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'temove 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 4 3%
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
Vglmorrt 5 Baseline LNCFS Comparison
¦ Orlg 3 Mis A Orig 4 Mills a LNCF 3 Mills s> lncf 4 Midi j
Figure 11
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 02 was 56 ppm (corrected to 3% 02). 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
Mill Reduction
NOx Reduction
350
5->4 (C)
15%
250
5->4 (A)
0%
157
4(E)->3 (E, A)
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.
Overfire 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 €0% 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
steep drop in NOx occurred
Cherokee 4 Overfire Air © Full Load
Fuel 80%
0.55
0.5 it
3 0,45
£
9 0.35
0.5
0,25
0 10 20 30 40 50 60 70 SO 90 100
Overfire Air Dampsr PoslHon
Figure 12
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.
Preliminary
LNCFS
0.275
48.4%
NA
NA
<30
3.3%
100%
100%
100%
-10°
50%
80%
50%
50%
100%
0.35
0.325
0,3
•v 0.275
0,225
0,2
2.8
Cherokee 4 Oxygen @ Full Load
Of a 1 00%; Aux & CF 60%
2.9
3 3.1 5.2 3.3 3.4
Oxygen Cerseenfration (%)
FjbI 40%
3.5
Fuel 60% * Fud 80%
3-6
Figure 13
Baseline
NOx (lb/MMBtu)
0.533
NOx Reduction
Boiler Efficiency
88.87
Unburned Carbon
2.2
Carbon Monoxide
<30
Oxygen Concentration
3.6%
OFA #3 Damper
NA
OFA #2 Damper
NA
OFA #1 Damper
NA
OFA Tilt
NA
Top Auxiliary Air
78%
Fuel Air
75%
Auxiliary Air
75%
Concentric Fire Air
NA
Lower Auxiliary Air
100%
2-105
-------
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
4 8%. 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
Cherokee 4 Baseline LNCFS Comparison
load (NMW)
° Orig 3 Wilis A O'ig * Mils « Orig 5 Mills LNCf 5 Mills
Figure 14
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 Tanqentiallv 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
Kure Works
Kure. ^
T, Uemura
S. Morita
T. Jimfao
K. Hodozuka
H. Kuroda
of Babcock-Hitachi K.K.
Iroshlma, 737, Japan
2-109
Preceding page blank
-------
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, BHK 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 Mile boiler
-- Hatsuura power station um't-1 for the Electric Power Development
Co., Ltd. (Japan)
2) HT-NR for the retrofits of existing boilers
-- PI em Buggenum Maascentrale power station unit-5 for EPZ (The
Nether!ands)
— PGEH 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
Preceding page blanl
-------
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 countermeasures 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 NQx 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 2.
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.
Methodology
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 volati1e-N, has extremely large chemical
reaction rates on the flame front. However, under fuel rich conditions, in line
with the rapid progress of 0j> consumption, excessive (overshooted} hydrocarbon
intermediates (hydrocarbon radicals, etc.) come into pi ay 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
Matuura P.S. lu 1000 MWe for Electric Power Development Co., Ltd. the newest and
largest capacity unit in Japan, started its1 commercial operation in June of 1990.
(See Figure 4)
2-112
-------
This boiler, manufactured by BHK, is equipped with a low-NOx combustion system
(BT-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-lJBC 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 pi ant 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"
samp!i ng.
Fig. 8 is a picture of the flames in a 1000 MWe 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 MWe ; 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
formati on.
• 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 (t^r) is 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 ai r 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
com-combustion capacity of 500 kg/h. While maintaining high combustion efficiency
by promotion of ignition, the NOx decomposition reaction in the flame is promoted
al so. Fig ure 14 shows the combustion test records of a ful 1 -seale 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 X RECOMMENDATIONS
Rabcock-Hitachi K.K. has developed and installed extremely low-NOx burners, HT-NR
Burners, with successful results.
This burner concept of "In-Flane NOx Reduction" is highly effective both for exist-
ing boilers and future boilers.
Use of In-flane 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, 19B9.
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. Ekman et al., "Desulphurization by Limestone Injection combined with
Low-NOx Combustion", GEN-UPGRADE 90.
2-115
-------
Technical Point
Mixing of After-Air
Residence Time
New TechftoIofly
Dual/2rows
Attei—Air Port
Advanced TSC
In-Flame HOx Reduction Hitachi-NR Burner
Fig,1 Concept of Low-NOx Furnace
Design Condit ion
•The Same Coal Property
Fig.2 NO x - LIB C "Trade-Off
2-116
-------
Fig,3 Hitachi-NR Burner
2-117
-------
SECONDARY ,
SUPER HEATER
Turbine Output 1,00D MWe
Evaporat ion 3, 170 t/h
Super He a t e r Outlet Press. 25 MPa
Super Heater Outlet Temp. 543/669"0
Fuel Coal
Fig.4 Matsuura P. S. Iu {Electric Power Development Co., Ltd)
*S Fn(RelatIve NOx Emission Facter)
Fn-1.2 Higher NOx
FN=1,0
*)
Planning coal
Lower NOx
4f 1
NOx <; 200pprn
UBC sS b%
x
FR
2
Fixed Carbon
Volatile Matter
(-)
Fig.5 A Relative NOx Emission {Matsuura 1U. lOOOVWe)
2-118
-------
Eco 02 = 3 —• 3. 5 (X, dry}
C-Coal X""1
FR = 1. I, N-0. i%
Ash«9X
D-Coal
FR-1.0. IM.8X
]¦
A-Caa I
FR=2. 6, N = 2. IS
Ash=158
B-Coal /
0
Ash=3«i FR = 2. ?. N = 1.8X
Ash= ? X
* > ¦ ¦ ¦ » > ¦
100 150
Boiler Outlet NOx (ppn. 5H0?)
\
Guaranteed Point
FR
(-)
fixed Carbon
Volatile Matter
N : dry ash free
Ash : dry base
Eco 02 : 02 Leaving
£cor.om i ze r
200
Fig.6 Operation Results of Guaranteed Coals (Matsuura 1". ICOOMWe)
V.
0 5 A-5 Eco&aWtiSx&v&le
COgSMB^ft
SMlBil 90/02/08 17:53-18:45
, 1801 M«
90/02/27 19:38 MMIW
U.'M/tt mm 90/02/08 19:04:00 1801MW
UMI
-km®
Oi
CO
3,7 %
10PPI
n
il
CI C 2 C 3 C 4 C 5 C 6 C? C8 C 9 €10
CO 23 ppi
ft/J\ CO [ppi
mmm> I
561 : :
}
! ! !
! •
co
¦
m>ii | \"«> ' '
1 t ¦¦¦-»
: ; ;
!
! : !
Wl
CO
NOx
& NOx
12
120 pel
138 ppi
Fig.? A Graphic CRT of "firid-Measurement" Leaving Econimi zer
2-119
-------
Flame Condition at Minimum toad
Operation in the 1000 MWe Boiler
2-120
-------
C o n di t i on
Same Furnace Volume
No Derat ing
Circular Register Burner
(Non-"Low-NOx")
Dual Register Burner
(Conventional "Low-NOx")
Hitachi-NR Burner
After-Air (OFA) Port
80
t/h
(1984)
80
t/h
(1985)
200
MWe
(1985)
200
MWe
(1985)
350
MWe
(1987)
265 MWe (1989)
Fig.9 Menu of Retrofits with Hitachi-NR Burners
1O0K boi ler load
three upper burner levels in service
totaI air factor 1, 22
Columbian coal
A before retrofit
A after retrofit
2§
e
American coal
• before retrofit
O after retrofit
Stoichiometric ratio on burnur level
Fig.10 Example of Results of NOx/UBC Performance
2-121
-------
TFN=k«exp(BHR) • f (SRb) • Ndaf • n~ 7nr)-exp (-RTi)
Total Fix«d Nitrogen Heat r«lease j Fuel-N
(Befcr# Injection A'ter-Air) Rgte I
Stoichiometry
<
-- AAPs -
"• BNRs "
m mmmm. - .
" " "
Gas Residence
Time
NOx.F i na 1
Re-format ion yNR •- /-/"(VM) • (TRF)
1n-FI erne
Reduction
by
HT-NR
Temperature
of
Reducing Flame
TFIM
Vol at 11# Matter
Fig,11 Key Equation for Low HCx Combustion System
Wind Box
Fig,12 features of Hitachi-NR2 Burner
2-122
-------
K
O
o 700
lo 600
f 500
tL
400
300
200
100
0
w
mprovement of
combustion efficiency
Reduction of Char-NOx
W— ~~
Promotion of
NOx reduction
Reduction of
boiler outlet NOx
\
~
y-i-
2Lt
2 3 4
Distance from burner
-tV-
100
90
s
80
>»
o
Hi
c
c 2
3
XI
c
Coal:New lands
(FR=2- 3)
Hi tachi-NR2
j u
60 80 100 120 140 160 180
NOx (ppm, 6%Oz)
Fig,14 NOx and Onburned Carbon Performance of Hitachi-NR2 Burner
2-123
-------
Tabl e
1 Specifications of
P. C. Combustion Equipment
(Matsuura 1u. lOOOMWe)
Mi 11
Type
Quant ity
Capacity
Loading Pressure
Classifier
MPS-118 (B&W Type)
I (1 for Stand-ay)
95.3 t/h.Miii (HO 1 = 50)
12.4 MPs (Oil Press.)
Fixed Stationary Type
Burner
Type
Quant ity
Heat Input
Arrangement
Hitachi-NR Burner
70 (10 for Stand-By)
152.8 x 10' kJ/h
10 bnrs x 3 rows. Opposed
5 bnrs x 1 row. Opposed (Top Row)
AAP
Type
Arrangement
Dual Type
10 AAPs x 1 row, Opposed
Table
2 Planning Coal (Matsuura P. S. iu. 1000MWe)
Item
Base Unit
Planning Coal
Design Coal
Mi n Max
GCV
A. O J/kg
> 25. 1 24.2
29.0
Proxi mate
IM A, D %
1.5
9.6
m A. D %
23. S
40.8
FC A. D %
38. 5
59. 1
Ash A. O %
< 20 3.5
28.0
S {Total)
A. D X
<1.0 0,2
1,3
f R
-
<2.4 1. 1
2.4
N
d. a, f %
< 2. 1 0. 8
2. 1
IDT
Oxi. Xj
> 1200 1210
> 1500
Table
3 low-NQx Retrofit of Existing Coal Fired Boiiers
Plant
Capacity Volatile
Content (X, daf)
NOx Reduction Efficiency {%)
(Commercial Operation Base)
Remarks
A
20 OMWe
34-56
35-45
1985-86
Japan
1
3 5 OMWe
30—40
25-30
198?
Japan
C
18 OMWe
23-40
40-50
1988
Europe
0
26 5MWC
35-40
40-50
1989
Europe
E
60OMWe
30-40
30-45
1989
Europe
2-124
-------
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.
3-1
-------
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 Overflre 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 Overflre Air Port retrofit phases of the program arc 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
Preceding page blank
-------
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 AOFA,
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 die effects on other combustion parameters (e.g., CO production, carbon
carryover, particulate 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
oudet 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 SO2 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, AOFA, LNB and
LNB with AOFA.
The major emphasis of this paper is on description of the NOx Characteristics resulting from the Baseline
and AOFA 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 AOFA 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 AOFA retrofit is preliminary and
may be revised upon publication of the final DOE Interim Test Report.
BOILER AND AOFA 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.
AOFA Description. Figure 1 schematically illustrates the AOFA retrofit on Hammond Unit 4. The
AOFA system consists of ductwork on each side of the boiler extending from immediately downstream of
each secondary air venturi to a separate overftre air wind box located above the burner windbox. Eight
FWEC can-in-can overftre 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 AOFA 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 iriput 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, SO2, O2, 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 (ECEM). 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 Cb 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 O2 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 oudet 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 pan, 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 NOx 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 Oj averaged approximately 110 ppm/%02 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/%02 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 O2 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
consistently 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,
-------
the full load condition the NOx was 67 ppm/%02 compared to 110 pm/%02 in the baseline
configuration, or considerably less sensitive. The mean short-term NOx level at 2.7 percent O2 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 NOx 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 AOFA 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 AOFA 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 AOFA
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 AOFA 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 AOFA 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 AOFA 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, EPRI 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". 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
-------
\ a a J
Low NO* Surrwrt
9oanfl«v Air Pom
CaalFwdPtpM
AutemstKl Dtts CeirtKatan Syn#r
0 Contmuoi* Emutien Mooter
o Aoomjcc Pyrsmtwr
Q HMt Flux TrarWOuCff*
oGorttty Room Oat*
FIGURE 1 Modifications of the Plant Hammond Unit 4 Boiler
1200
1100
1000
eoo
700
3 3.5
EXCESS OXYGEN. %
FIGURE 2 Baseline Short-Term NOx Characterization at 480 MWe
3-15
-------
EXCESS OXYGEN , %
FIGURE 3 Baseline Short-Term NOx Characterization at 400 MWe
1100
1000
900
soo
700
•
•
•
Ave
age ——
\
•
•
\
•
• /
\ j/
i
•
r
i
600
150 200 250 300 350 400 450 500 550
LOAD, MWe
FIGURE 4 Baseline Short-Term Load Range NOx Characteristics
3-16
-------
1100
sr 1000
0
1
i
°» 900
cn
1
300 350 400 450 500 550
GROSS LOAD, MWe
FIGURE 6 Comparison of Baseline Short- and Long-Term Load Range Trends
3-17
-------
1100
1000
400
0 10 20 30 40 50 60 70 SO
NOMINAL OFA POSITION
FIGURE 7 AOFA Port Opening Characterization at 480 MWe
800
Si
O TOO
a?
©•
E
o.
o.
» 600
O
55
m
u
5
z
500
400
460 MWe NOMINAL LOAD
ALL MILLS IN SERVICE
50 % AOFA PORT OPENING
43
* a#
-------
800
E
i
TOO
eoo
500
400
3 4 5
EXCESS OXYGEN, Percent
FIGURE 9 AO FA Short-Term NOx Characterization at 400 MWe
0
<3
D
»
<
f
o
8
0 °
o
n A
<
o
«
(O — -
. i
0
<
o
* 2.
^ <9
0 °o
O
r\
o
250 300 350 400 450
GROSS LOAD, MWe
500
5S0
FIGURE 10 AOFA Short-Term Load Range NOx Characteristics
3-19
-------
RECOMMEfn
OEO MINIMUM 02 LE
VGL FOR AOFA OPEF
5
I
>N
neco»
M6NQS& MINIMUM <
/
>2 LfvaFOFIBASa
NE OPERATION
250 300 350 400 450 500 550
GROSS LOAD, MWa
FIGURE 11 Baseline and AOFA Operating Excess Oxygen Curves
1200
LONG-TERM DATA FOR WEEK 2/10 TO 2/16/91
sr
0
q,
E
a
a
05
Z
S
m
CO
1
UJ
LONG-TERM DATA
T
' /
/
/
I
7-.-.V ¦
— "T
V:
SHORT-TERM DATA
400
250 300 350 400 450
GROSS LOAD, MWa
500
550
FIGURE 12 Comparison of AOFA Short- and Long-Term Load Range Trends
3-20
-------
20 %
21 *
LQNO-TEHMAOFA
«%
— ^ SHORT-TERM AQFA
250
300
500
350 400 450
GROSS LOAD. MWe
FIGURE 13 Comparison of Baseline and AOFA Operation
550
Mass Train Samples
CEQRIT Samples
80% AOFA Da/rper
Baaaffns
250
300
500
350 400 450
Unit Load (MWe)
FIGURE 14 Comparison of Baseline and AOFA LOI Values
550
3-21
-------
REBURN TECHNOLOGY FOR NOx
CONTROL ON A CYCLONE-FIRED BOILER
R.W. Borio, R.D. Lewis, M.B. Keough
ABB Combustion Engineering
R.
C, Booth
- Energy System Associates
R.
E. Hall
- U.S. EPA
R.
A. Lott
- GRI
A.
Kokkinos
- EPRI
0.
F. Gyorke
- DOE-PETC
S.
Durrani
- Ohio Edison
H.
J. Johnson
- OCDO
J.
J. Kienle
- East Ohio Gas
This paper has been reviewed in accordance with the U.S. Environmental
Protection Agency's peer and administrative review policies and approved lor
presentation and publication.
3-23
Preceding page blanl
-------
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 Miles 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 comfiining ftith 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.
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 N0x 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
Preceding page blanl
-------
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-foilowing 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 siightly 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 pi ant 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 1t 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 del ays 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
• Cyclone Excess Air
• Cyclones in Service
• Boiler Load
Reburn Test Variables
a 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).
t 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 (0-) 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 , 0?, CO, C02, S0?, and THC (total
hydrocarbon) were measured at the bofler exit/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 1n 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 pi tot tube. (Furnace velocity data have
not currently been analyzed and will be reported later.) The
in-furnace sampling on this pressurized furnace was 1imited 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 1owered or raised,
respectively, beyond the normal range.
3-31
-------
The Ohio Edison Niles 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 0« basis). Tnis emissions level was
representative of normal operation with a mean cyclone excess oxygen
level of 2.0-2.5% 0- (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% 02, decreased N0X 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 §30 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 NILES UNIT NO. 1
Composite Coal Analysis - As Received Basis
Proximate Analysis
Deviation
Maximum Minimum Standard
Average Value Value
% Moisture (Total)
% Volatile Matter
% Fixed Carbon (By Difference)
% Ash
7.8
32.2
47.3
12.6
9.3
33.7
49.3
13.6
6.6
31.1
45.3
11.4
0.76
0.62
0.94
0.62
HHV Btu/lb
lb Ash/10 Btu
11576 11870 11277
10.9 12.0 9.6
176
0.63
Ultimate Analysis
% Moisture
% Hydrogen
% Carbon
% Sulfur
% Nitrogen
% Oxygen (By Difference)
% Ash
7.8
4.4
63.4
3.3
1.4
7.1
12.6
100.0
9.3 6.6 0.76
4.5 4.3 0.06
65.3 61.8 1.11
4.1 3.0 0.31
1.5 1.3 0.05
8.4 5.5 0.73
13.6 11.4 0.62
Total
Based upon the consistency of the coal composition, coal variability
should have negligible effect on the test program results.
NQX 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).
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 stoichiometry 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 thermal 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 or 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 1ikely 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 may 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.
Other Gaseous Emissions
NO emissions reduction was essentially linear with increasing natural
gal 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 UFI and AA nozzles. A -17s (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 S02 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 Niles 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 lOOCF.
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 21-45% 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 sized 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/10 Btu 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),
whereK100% 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 reburnKtests the actual
particulate loadings of 0.043 and 0.027 lb/10 Btu for the full load
and partial load reburn cases, 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).
12 14
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 0,)
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 Niles 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 Niles Station. Following system shakedown, parametric
testing was carried out during the last 2J months of 1990. Key
findings from a preliminary review of the data collected are as
fol1ows:
• NO reductions ranged from 30 to 70% during parametric
testing.
• NO reductions in the 50 to 60% range are possible with
acceptable boiler operation and CO emissions.
• 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.
• 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, 0. 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 NQV Control, Volume 2, EPA-600/9-88-026b (NTIS
PB89-139703). x
8. R. H. 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. Takahashl, et al., (1982), "Development of 'MAC!' In-Furnace
NO Removal Process for Steam Generators," Proceedings of the
1982 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 ?B89-220529).
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/10 British
Thermal Units
PPM at 3% 0„
PPM at 3% 0,
Square Feet/(Actual
Cubic Feet/Minute)
IS Multiply B,y
Joules 9.478xl0"4
Watts/Square Meter 0.3171
Joules/Kilogram 2.326xl03
Degrees Celsius (T-32)/l.8
Meters 0.3048
Centimeters 2.54
Kilograms/Square 14.223
Centimeter
Kilograms/Joule 2.326x10"*
Milligrams/Cubic Meter 1.70
at 6% 02
Pounds/106 British 1.306x10"
Thermal Units *
Square Meter/ 0.305
(Actual Cubic Meter/Minute)
* This conversion factor is based on composite fuel analysis with 18%s natural
gas reburn fuel and 82% coal. For different fuel fractions different conversion
factors would be required.
3-44
-------
Table 2: Ohio Edison Niles Unit No. 1,
Boiler Performance Data
Baseline
Reburn
Net Load (MWe)
108
10B
Fuel Type (%)
Coal
100
82.8
Natural Gas
0
17.2
Excess Oxygen (Air) (%) :
2.8 (15.0)
2.7(14.2)
Rue Gas Recirculation (%)
1.3
4.5
Flows (Ib/hr)
Main Steam
845,200
843,700
Superheat Spray
Reheat Spray
10,260
0
37,760
2,320
Temperatures (°F)
Feedwater
483
404
Primary Superheater Outlet
736
758
Secondary Superheater Inlet
718
703
Secondary Superheater Outlet
Reheat Inlet
997
682
1000
685
Reheat Outlet
938
1000
Flue Gas-Air Heater Inlet
680
685
Flue Gas-Air Heater Outlet
251
250
Air-Air Heater Inlet
120
118
Air-Air Heater Outlet
575
581
Heal Absorption (10* Btu/hr)
Primary Superheater
124.5
132.6
Secondary Superheater
160.7
170.7
Reheater
123.2
127.9
Watarwalls
590.3
563.0
Table 3: Ohio Edison Niles Unit No. 1,
Boiler Efficiency
BASELINE REBURN
PERCENT COAL
100
82.8
PERCENT NATURAL GAS
0
17.2
HEAT LOSSES (PERCENT)
DRY GAS LOSS
2.70
2,66
MOISTURE IN FUEL LOSS
4.35
5.34
MOISTURE IN AIR LOSS
0.06
0.06
RADIATION LOSS
0.24
0.24
ASH PIT LOSS
0.54
0.44
HEAT IN FLYASH LOSS
0,01
0.01
PYRITE REJECTION LOSS
0.00
0.00
CARBON LOSS
1.39
1.15
TOTAL LOSSES %
9.29
9.90
EFFICIENCY %
90,71
90.10
3-45
-------
TASK NO.
TASK TITLE
1987 1988 1989 1990 1991
lllllllllllllllllll Illllllllll
1992
1 TECHNOLOGY REVIEW
2 BASELINE CHARACTERIZATION TESTS
3 RE BURN SYSTEM DESIGN
4 SYSTEM FABRICATION / INSTALLATION / START-UP
5 PARAMETRIC GAS REBURN AND BASELINE TEST
6 U3NQ TERM PERFORMANCE TEST
7 PERFORMANCE ANALYSIS / TECHNOLOGY TRANSFER
8 arc RESTORATION (OPTIONAL)
9 PROJECT MANAGEMENT/ REPORTING
SIGNIFICANT EVENT KEY
A: Plant dalafor return system design test program @ Niies W24/BB3/11/88!
B: Outsgato bsfall rabum aymtmf UT mapping (5/20^-6/19/90)
Outage fa UT mapping (12S&90-1/3/91)
Outage for UT msppng {Date to coincide with planned annua! outage;
Outage far UT mapping {12/2B/&1-1/5/92)
Figure 1: Overall Project Scope and Schedule of Gas
Reburn Project at Ohio Edison Niles Unit 1
3-46
-------
Figure 3; Boiler Exit Gaseous Emissions Sample Matrix
8
£
*
A 86 MWb Net
O 108 MWe Net
CYCLONE Og,%
o No Natural Gas
& 10% Natural Gas
~ 14% Natural Gas
+ 18% Natural Gas
o.is ».»« o.»s i.oo ».«» t.10 i.n
REBURN ZONE STOICHIOMETRY
Figure 4: Baseline NOx Versus Cyclone Ck
108 MWe and 86 MWe Net
Figure 5: NOx Versus Rebum Zone Stoichiometry at
Various Gas Flow Rates
108 MWe, 10% FGR
3-47
-------
Figure 6: NOx Versus Cyclone 02 at Various
Gas Flow Rales
108 MWe, 10% FGR
Figure 8: NOx Versus Reburrt Zone Stochiometry at
Various Gas Flow Rates
108 MWe and 86 MWe Loads
Figure 10:0? arid CO Versus Boiler Exit Duct Sample
Location
Non-Optimized Operation
Figure 7: NOx Versus Percent Flue Gas Recirculation
(FGR)
D UFlTilt® -17®
0 UFITilr® 0°
UFITilt@ -25*
1600'
E
a.
n.
o
j-j
-------
3000
2800
2600
2400
2200
2000
CYCLONE A
\
CYCLONEC
CYCLONE D
¦ \
v \
\u
r\
\\
Baseline
\ ©
*
*
Bassline
Reburn
2468 10 2466 10 2468 10
Distance trom Rear Wall, ft
Figure 12: Flue Gas Temperatures
Reburn Zone Inlet (108 MWe Net)
2800
2600
2400
2200
2000
1800
CYCLONE A CYCLONE C
CYCLONED
• X
- V
X
\
\
Baseline
Reburn
2468 10 246810 24B8 10
Distance from Rear Wall, It
Figure 13: Flue Gas Temperatures
Reburn Zone Inlet (86 MWe Net)
2200
2100
2000
1900
1600
1700
1600
1500
1400
1300
1200
108 MWe Net
86 MWe Net
. ™
/ /
/
r /
t
Baseline
1
----Reburn
¦ I .X— J ..-J— ^ L
2 4 6 6 10 12 2 4 6 8 10 12
Distance from Left Side Wail, ft
Figure 14: Flue Gas Temperatures
Furnace Outlet
| 15
i 14
? 13
? 12
a t1
I 10
1 9
£ 8
| 6
t 6
"a 3'
° 100% Coal
a 18% Reburn
0.01
0,10
Aerodynamic Diameter, |»n
Figure 15: Particle Size Distribution
(108 MWe Net)
1.00 10.00 100.00
o 100% Coal
a 16% Hebum
0.10
1.00 10.00
Aerodynamic Diameter, |im
100.00
Figure 16: Particle Size Distribution
(86 MWe Net)
3-49
-------
FULL SCAM! RETROFIT OF A LOW NOx AXIAL SWIRL BURNER TO A §60 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
Preceding page blank
3-51
-------
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, h 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% 0have 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.
Preceding page blank
-------
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 maximuoj 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 101 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 techniques, 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 requirement 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.
Ouarl 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 Babeock
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 'optimised' 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
-------
iii) 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 111 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 quarl
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 lb/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.
3-61
-------
REFERENCES
1, 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.
2. 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
x-
I o GCV
' LOSS
0.5
ECONOMISER OUTLET OXYGEN (% DRY)
Figure 1. Preconversion Test Results
Source: Drax Unit 6.
TBR1WW AR-
teooKMif m j—mxmm mam
WUflBt DAMPER
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
Figure 6. Mark III Low NOx Axial Swirl Burner
3-65
-------
Figure 7. Schematic of Large Scale Burner Test Facility
Figure 8. Babcock Large Scale Burner Test Facility
3-66
-------
>-
QC
a
m
o
KS
<
5"
Q_
Cl
X
o
900
800
700
600
500
4-00
300
200
100'
STANDARD BURNER
MK II LNASB
MK III LNASB
, , , j ,—
12 3 4 5
% 02 (DRY)
Figure 9. Test Facility Results
MEAN
CARBON 4
IN ASH
%
x TEST I
320 350 400
NOx P.P.M. AT 3% 02
Figure 10, Summary of Optimisation Teat Results
430
3-67
-------
500
NOx
P-P.M.
AT 400
3% 02
300
200
o 8 TOP MILLS
° 8 BOTTOM MILLS
12 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
2 3 4
OUTLET OXYGEN (% DRY)
Figure 13. Effect of Coal Quality on NOx Emissions
3-69
-------
TABLE 1
DRAX COM. ANALYSIS SPECIFICATION
Properties
Higher Heating Value KJ/Kg
Moisture %
Ash %
Volatile %
.Sulphur %
Chlorine %
Ash Initial °C
Deformation Temperature
Design Coals
Basic
24 400
8
20
28
2,0
0.4
1200
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
Pf Fineness
% < 75 micron
% < 150 micron
% < 300 micron
Ash Analysis
Moisture
%
11.0
Silica
%
57,8
Volatile Matter
%
28.8
Alumina
%
24.1
Fixed Carbon
%
44.2
Iron Oxide
%
8.9
Ash
%
16.0
Calcium Oxide
%
1.4
Nitrogen
%
1.18
Magnesium Oxide
%
1.8
FC/VM
%
1.59
Titanium Oxide
%
0.92
Nitrogen (daf)
%
1.64
Potassium Oxide
%
3.09
GCV (MJ/kg)
%
24.96
Phosphorus
%
0.25
Sulphur
%
0.56
66.2 - 69.3
92.5 - 93.8
99.6 - 99.8
3-70
-------
TABLE 3
COMPARISON OF PRECOKVERSIOH MID HARK III BUHNER BOILER
TEST HO:
DATE:
TIMES:
A1
Post Conversion
A2 A3
M
18.03.87 18.03.87 18.03.87 20.09.89 20.09.89 20.09.89 20.09.89
09.30
11.30
13.00
15.00
16.30
18.30
09.30
11.45
12.30
14.30
16.00
18.00
19.00
21.00
Unit Load (MWe)
Mills in Service
Economiser Outlet
02 (% dry)
o
Arch Level Temperature C
FEGT °C
NOx corrected to 3%
02 {dry} ppoi
662
8 Top
3.75
1492
1130
862
660
8 Top
2.76
1508
1129
823
661
8 Top
2.42
1529
1141
783
660
8 Top
4.65
1402
1075
479
655
8 fop
3.59
1413
1066
413
652
8 Top
2.85
1447
1081
370
654
8 Top
3.68
1430
1088
410
TABLE 4
ANALYSIS OF COALS TESTED
Indonesian
United Kingdom
South African
GCV MJ/kg
26.55
27.13
27.12
h2o %
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 COM. REBURNING TECHNOLOGY TOR 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
Barbe rton, 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
3-73
Preceding page blank
-------
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 techniques 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 techniques 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
Preceding page blank
-------
full-scale evaluation is justified via a previous Electric Power
Research Institute-sponsored (Project RP-1402-30) engineering
feasibility study and EPRI/GRI (1PRI RP-2154-11; GRI:5087-254-1471)
pilot-scale evaluation of returning 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%(l). 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 bailers 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 S02
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-equipped 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 stoichiometrics (less
than 0,6). The furnace reburning zone is operated at stoichiometrics 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 stoichiometrics 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% 02) while varying
excess 02% from 2 to 3.75%, respectively. Since operating at 3% excess
Oj, 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% 02) when varying excess Oa from 2.4 to 4.3%,
respectively. The NOx emission level while operating at a typical 3%
excess 02 was 950 ppm.
Baseline FEGT's at full and 75% loads were 2175°F and 1975°F,
respectively, at an excess 02%, 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 10io 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 stoichiometrics (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.
Refrwning E
-------
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-terra 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 HaS 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 (unbumed carbon) Emission Levels
Figures 6 and 7 show the full load (110 MW) baseline stack NOx emission
levels (ppm corrected to 3% 02) 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 02% was varied between about 2 and 4%,
respectively. Since operating at 3% economizer outlet 0a is considered
typical, the normal baseline NOx level is 662 ppm at 3% 02. Figure 7
shows percent LOI varied from approximately 18% down to 9% while
increasing excess 02% from 2 to 4%, respectively.
Additionally, Figures 8 and 9 show the relationship between NOx (ppm at
3% 0a) and percent LOI versus boiler load (MW) during typical boiler
operation (3% economizer outlet 02). 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% 02), 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 WF&L's Nelson Dewey Unit No. 2 is
shown in Figure 10 and pertinent boiler information is summarized in
Table l.
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 1/12th 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 1/12th model measurements from elevation
666ft.showed good qualitative 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
i/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 kstjt im © s 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 l.o
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 ,,14W 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 stoichiometrics 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 Reburnmg 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 Babcoek S 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 4
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
nay 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 cosunerciel 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.
3-88
-------
Table 1
Boiler Information
Nelson Dewey, Unit 2
Name Plate Rate:
100 MWe
Type:
Steam Turbine
Primary Fuel:
Bituminous and Sub-Bituminous Coal
Operation Date:
October 1962 - Unit No. 2
Boiler ID:
B&W RB-369
Boiler Capacity:
Nominal 11 MWe
Boiler General Condition:
Good
Boiler Manufacturer:
Babcock & Wilcox
Boiler Type:
Cyclone Fired RB Boiler, Pressurized
Reburning Demonstration
Fuel:
Indiana (Lamar) Bituminous Coal,
Medium Sulfur (1.87%)
Burners:
Three B&W Vortex-Type Burners,
Single-Wall Fired
Particulate Control:
Research Cottrelf ESP
Boiler Availability:
90% Availability
Table 2
Matrix of WP&L Baseline and Mixing Tests
Test
Type
Test
Facility
Gas Temperature
Measurement Plane
Cycl
Rbrn
OFA
Cycl Exit
666
681
700
Baseline
Test
WP&L Boiler
C
X
H
X
X
1/12 Model
C
C
C
X
X
X
C
H
X
Mixing Test
1/12 Model
c
C
H
X
3-89
-------
Table 3
Numerical Flow Modeling Test Matrix
Case
Fuel
Reburner
Rebumers
OFA Ports
No.
Load
Split
FGR
No.
Size
Spacing
No.
Size
Spacing
1
100 MWe
30%
0%
3
20"
117.5"
3
28"
11*7.5"
2
100 MWe
30%
0%
4
18"
7'9"
4
24"
7'9"
3
110 MWe
25%
0%
3
20"
10'
4
22"
6*8"
3a
110 MWe
25%
8.7%
3
20"
10'
4
22
6'8"
4
110 MWe
25%
0%
4
18"
6'8"
4
22"
6*8"
4a
110 MWe
25%
5%
4
18"
6*8"
4
22"
6*8"
4b
110 MWe
25%
8.7%
4
18"
6"8"
4
22"
6*8"
5
110 MWe
25%
0%
3
20"
10'
3
26"
10'
5a
110 MWe
25%
8.7%
3
20"
10'
3
26"
10"
In furnace
0.85 - 0.95
Stoichiometry
Coal
Bunker
Cyclone
Furnace ~~v
70%-80% Heat Input
Crushed Coal
1.1 Stoichiometry
Main Combustion O
Zone B&W Boiler
RB-369
100 MW capacity
Flyash Handling
and Disposal
Reburning Pulverized
' Coal Burners
20% - 30% Heat Input
Pulverized Coal
0.4 - 0.5 Stoichiometry
Figure 1-Coal reburn project - system layout, cyclone firing.
3-90
-------
Phase I: Design & Permitting
• Modeling & Pilot Scale
Testing
• Baseline Characterization
• System Design
Phase I1A: Equipment Procurement
B; Construction & Start-Up
• Fabrication
• Installation
Phase III: Operation & Disposition
• Optimization
• Long-Term Performance
• Reporting & Disposition
Figure 2--Coal reburning for cyclone boiler NO, control project schedule.
1989
1990
1991
1992
1993
s(c(nd
jj^s^a
c.
#
i
jf^aMjaa
spMc
jjf^
12 Mo.
10 Mo.
9 Mo.
5 Mo
2.5 Mo.
i—
7 Mo.
5 Mo.
4 !
to.
9 Mo.
> i
11 Mo.
STACK
STEAM
SUPERHEATER
FOULING TUBE
DEPOSITION PROBE
REHEATER
DEPOSITION
PROBE
FURNACE ARCH
PRIMARY AIR
AND COAL
TERTIARY AIR
SECONDARY AIR
FLUE CAS
RECIRCULATION
/
SLAG TAP
MOLTEN SLAG
SLAG COLLECTOR
AND FURNACE
WATER SEAL
Figure 3--Small boiler simulator (SBS).
3-91
-------
1100-
1000-
900 H
N0X
Corrected to 3% 02,
(ppm)
800-
700-
600-
~ Lamar Coal @ 6 x 106 Btu/hr.
+ Lamar Coal @ 4.5 x 106 Btu/hr,
500-
Excess Oxygen, (%)
Figure 4--SBS baseline NO* emission levels.
1000
Stack NO,
corrected to
3% Oz
(PPm)
800
600
400-
200
Legend
Baseline conditions,
no reburning
Reburning Conditions
a Standard grind coa!
¦ Medium grind coal
~ Fine grind coal
..•fc
Boiler Conditions
• Cyclone @ 10% excess air
• 0% Flue gas recirculation
• 6 x 106 Btu/hr load
0.8
0.9 1.0 1.1
Reburning Zone Stoichiometry
1.2
Figure 5--SBS NO, emissions with coal reburning.
3-92
-------
800
700-
Stack NOx,
Corrected to
3%02i
(ppm)
600
500+
1
Boiler Load -110 MW (Full Load)
Test Procedure - EPA Method 7E
2 3 i
Economizer Outlet Excess O2, (%)
Figure 6-Baseline NO, emission levels vs. excess 02. Nelson Dewey - Unit 2.
Economizer Outlet
Excess 02%
Figure 7--Baseline %LOI emission levels vs. excess 02 %. Nelson Dewey - Unit 2.
3-93
-------
700
600-
Stack NO,
corrected to
3%02
(ppm) 500'
Excess 02% at
Economizer Outlet - 3% 02 (Typical)
Test Procedure - EPA Method 7E
400-
30
50
70 90
Load (MW's)
110
130
Figure 8--BaseIine NO, emission levels vs. load. Nelson Dewey - Unit 2.
20.0
18.0
.1 16-0
*E
M
g 14.0
yj
c/i
3
12.0
10.0
50 60 70 80 90 100 110 120
Load mm
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 Wal!
To Fan
4 Reburners
25% Reburner
5% FGR Flow
Momentum Ratio Base
T-Tc
Tb-Tc
Front Waif
WP&L Mixing Test 31 - Elev. 681'
Rear Wall
fOFA
Heated
Air
Reburner
Cyclone
4 Reburners
30% Reburner
7,5% FGR Flow
Momentum Ratio Base
Front Wall
WP&L Mixing Test 33 - Elev, 681'
Figure 11-Examples of mixing test results.
3-95
-------
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
Figure 13-Equipment arrangement for the coal reburn project.
3-97
-------
DEMONSTRATION OF LOW NQX 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 l, 5611 EK Eindhoven, Netherlands
J.G. Witkamp
N.V. Kema
Utrechtseweg 310, 6812 AR Arnhem, Netherlands
3-99
Preceding page blanl
-------
ABSTRACT
Unit 5 of the Maas Power Station is a coal/gas-fired boiler
with horizontally opposed firing burners. In this boiler HTN1
low-NO. burners and after air ports have been installed to
demonstrate the viability of low-NOj combustion techniques. The
aim was to prove that in new installations N0X concentrations
of less than 400 mg/mj are feasible for a large variety of
coals, as well as to determine the impact of NO^ control
technology on boiler operation, performance and maintenance.
Prior to the retrofit of the boiler the HTN1 burner was
modified to accomodate both coal and gas-firing.
Results are presented on;
* NOj emission with natural gas firing
* a parameter research on N0X 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
Preceding page blank
-------
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 401 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,, N0X 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/n^ (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 NOj-
Abatement Programme of the Dutch electricity generating
companies. In the programme low-NOj 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-NQ, technology. The main thrust of the
demonstration is not only to quantify potential NOj reductions
in actual boilers, but also to determine the exact nature and
the impact of N0S controls on boiler operation, performance and
maintenance.
3-102
-------
The demonstration of advanced low-NO, 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-NOs mode.
Sep, the Dutch Electricity Generating Board funded the project
and was responsible for coordination of the activities within
the Concerted N0X 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 Df 1, 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/n^ is considered to be reached for given coal
types when NOj emission is below 470 mg/n^ and the carbon in ash
content is below 2.6%. The relaxation of the standard by
70 mg/n^ 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 NOx/ny 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 coax
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 N0X and UBC performance specified in the
objective of the demonstration project, low-NOj burners (HTNR)
were applied in combination with two-stage combustion. The
boiler and the combustion system are shown scematically in
Figure 1.
LQWr_NOx Burners_lHTNR1
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-NOjj Combustion System
To enhance NOs 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 N0Z 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 Nus and UBC performance for Haas 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 NOj 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 MP'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-NOt
combustion system.
3-105
-------
The modification involved the following main elements:
* Seplacement of the 16 single register burners by 16
advanced low-NO^ 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-NO 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-NOj 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 N0S 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 N0S 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/it^. After the modification NO concentrations were
between 150 and 250 mg/it^, dependent on the burner setting. For
two-stage combustion the influence of burner setting was small
and a NO concentration of 100 mg/n^ 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 N0E
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, fhis 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. Of f-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 N0X 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 N0X 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 N0X emission and UBC
performance.
Less swirl of the after air led to lower UBC and higher NOj
emission. For high swirl levels N02 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 HjS 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/cnr,h. After
retrofit the values differ over a wide range (0.04-10,24
mg/cm ,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. SIM 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.
Flv 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-NOj operation. There were no adverse effects on
boiler efficiency. In general the low-NOx 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/n^- 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 0^ 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/ir^ at 6% 0* 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 of the demonstration programme the combustion
system was optimized and extensive tests were conducted for
three coal types and natural gas.
For natural gas the N0£ reduction amounts to values between 50
and 70% in the conventional combustion mode and 801 for two-
stage combustion. For coal firing typical reduction percentages
are 30% and 50% respectively. Adjustment of the burners was
generally effective for NO^ and UBC. Adjustment of the after
air ports appeared to be critical for UBC.
Typical results obtained for Cerrejon coal are 480 mg N0/n|3 (6%
02) at 95% load and 25% excess air. For AN! coal the NO
concentration was 500 mg/naj at 61 O2. 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/ity at 6% 02.
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-NO^ 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
-------
FIGURE l. SCHEMATIC PRESENTATION 0? THE FURNACE
AHD COMBUSTION SYSTEM
FIGURE 2. MODIFIED HTNR-BURNER FOR COAL AND GAS FIRING
3-115
-------
FIGURE 3. AFTER AIR PORT (AAP)
350
SR - l.Z
Modified HTHR-
/
/
#
**
/
. /
V
2 SO
200
1
2O0P8Q / /
v/_
//
* 2
/
00*90 ~
/
*»» ^
x
Ji_d
J1 i
~
^ 2QQPB0-
~
-Original HTNR
15
fe-J
1
30D 400 | SOO 000
«— Checkpoint (or NO*
Coal Feed Race (Kg/h)
FIGURE 4s RESULTS OP COMBUSTION TEST - 4 Mtf TESf BURNER
COAL TYPEi WAMSO
3-116
-------
*»t¦«
TTTT
# £ #
* k ~ ~
m m /ft A,
*|r v ~ ~
r r *tf
FIGURE S. WATER MODEL FOR FLOW SIMULATION
Ff = Fr Sf = Sr Ff = Fr Sf
-------
600
500
400
30O
200
100
rami
Pc#-Retrofit
CONV. 02s" 1%
CONV ngh
swirl
mm
CONV low
swirl
TSC
<1? = 2%
FIGURE 7. SUMMARY Or OAS FIRING AT 1001 MCI
EFFECT OF COMBUSTION MODE
Sailer Load {")
70 SO 90
Boiler Load (Zs
FIGURE 8. EFFECT OF BOILER LOaD QH N0-EHIS5I0N
COAL TYPE; CER&EJGN
3-118
-------
1400
1200
8
g 10Q0
©
I
800
B
/
~
9 Pre-f?«rbpf PostR«troM
TSC
02 Wet Ai Hfcatet l%»
20
o 12
1
e a
%
\x
\
V
e \
V
B
2 4 6
02 lni»i Air Mnat&f
0 2 4 6
02 (rtdi Air Htwstw (%)
Pit-- KcUufji
COlW
CiJfW
FuslMfctrOli!
ISC
U 6
I «
\
9
\
\|
Y
V
\.
V Pre-ftelf&M
CONV
A PuStHtl/Ofil
caw
O PcsStKsflfoTJl
rsc
02 inle< A* Hewter <%}
FIOUEE 10. EFPECT OF EXCESS Alt
AtfR AT XOOI MCR
O BOO
O 2 4 &
Q2 inlet At Heater l%>
0.2 4 6
02 irtfM Air Hester (%>
Post R&t/o-
fit CONV.
Post fteuo-
fit TSC
9 P05jt ftfrlJQ
fit CONV.
O Peal Retro-
fit TSC
530
380 fr~™"nt r—""«> 1 "" r—roi r """ » O
0,96-0,9? 088-1,04 0,?&-t,»4 IjM-O.97 J.04-0.&1
5R how Bottom — Uppar
FIGURE 12. EFPECT OF BUSKER OFF-STOICHIQHZTIY
OR WO STASt COMBUSTIQH
FIOORE 11. EFFECT Of EXCESS AIR
ILLAWARA AT 951 HCS
3-119
-------
g 500
w
350
O 20 40 60 SO 100
Secondary Air Poster AAP m
& prim air
camper 10%
O prim ar
damper 30%
? prim air
damper 50%
~ prim air
damper 75%
O prsrn a'
damper 100%
1S
A prim air
damper 10%
O prim ar
damper 30%
V prm ar
damper 50%
O prim 9 v
damper 75%
$ prim ar
damper 100%
0 20 40 60 80 1QO
Secondary Air Register AAP (%)
FIGTOE 13. EFFECT OF AAP ADJUSTMENT CERREJON AT 95% MCR
§ «
steamprod 02-conc bef NO-ccnc in — • irtjurnt
Mr antwater rr>
-------
TABLE 1
N0X EMISSION STANDARDS FOR COAL-FIRED POWER STATIONS
Power station
Commissioning Standard
Remarks
Maas no. 6
1986
Maasvlakte no. 2,
1987
Borssele no. 12
1987
Maasvlakte no. 1
1988
Amer no. 9
1993
Hemweg no. 8
1994
Maasvlakte no. 3
1997
270 g/GJ
* 750 mg/ir^
400 mg/n|
300 mg/w$
200 mg/i^
test value
190 g/GJ » 530 rag/n^
as a criterion for
low-NOj burners
commitment to pursue
200 mg/mj
TABLE 2
MAAS POWER STATION UNIT
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 /
16 (2 x 2
30 MW
2
tube mill
64.5 t/h
0.725
540 * C
x 4, opposed)
LCV/GCV
Moisture
Ash
Volatile
HGI
Fuel ratio
Ndaf
MJ/kg
%
I
%
TABLE 3
COAL PROPERTIES
Cerreion
26.3/27.5
12,
5
33.
48
1,
1.
4
4
0
49
60
Illawara
26.9/27.8
16
19
78
3
1
.0
,6
.1
,12
. 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 D.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.
This paper has been reviewed in accordance with the U.S. Environmental
Protection Agency's peer and administrative review policies and approved for
presentation and publication.
3-123
-------
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 coml fired boiler in the U.S.S.I.
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 46$
tons/hr (420 metric tons/hr) steam flow:
Natural Gas - 0.08 lb/106 Btu (125 mg/Nm3 @ 3% 0 )
Fuel Oil - 0.12 lb/10 Btu (185 mg/Nrn 8 3% 0,)
Coal - 0.18 lb/10 Btu (225 mg/Nm @ 6* 02>
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
Preceding page blank
-------
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 ffnal. 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, returning 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 tjp Soviet type Tinr-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 Tnn-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 (substoichiometrie) zone
downstream of the primary eombustor 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^, HON) 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. Reburnlng 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
eombustors (6) or swirl stabilized burners similar to those used in the
Ladyzhinskaya units. Since these eombustors 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 stoichiometric 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, FGE, 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 ra/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
10°.
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 wlndbox 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.
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 reburnlng 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°€) 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 t^e furnace total
wagerwall 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 apposed 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 HO 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, Teare, 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
ft. J. Freihaut, ¥. 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 Join!
Symposium on Stationary Combustion NO Control, Volume I,
EPA-600/9-85-022a (NTIS PB85-235604). *
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: Ladyzhinskaya Power Station
Diverting Portions of tha 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 Staging Alr-
Due to Fuel Rich Conditions In
Reburn Zone; NO* Destruction
Is Promoted Due to Secondary Reburn Fuel-
Flame Radical Attack on NO Primary
Produced In Primary Zone to Fuel-Air"
Form Molecular Nitrogen
Burnout
Zone
Reburn
Zone
Primary
\*w"/
Hypothesized NOx Destruction Mechanism:
CH OH,H
NO +- HCN NH
-------
" ~
i 'flow-1r
IT
mil
TOP IIVII OF NOZZLES
SECTION "A*"
BOTTOM LEVEL OF NOZZLES
SECTION "BS"
A
II I I I I II I I II
~1
COMBINED RE3UPN NOZZLE
ASSEMBLE
FRONT ELEVATION
Figure 4: Schematics of Model Rebum Fuel/
Burnout Air Injector Bank
Gss Recirculation
Nozzles
Figure 5: Jet Penetration - Rebum Fuel Injectors
Gas Recirculation
Nozzles rj«
Burnout Air
injectors
Gas Recirculation
Nozzles
Figure 6: Jet Penetration/Dispersion - Reburn Fuel
Injectors
Figure 7: Effect of Injection Downtiit on Jet
Penetration/Dispersion
3-139
-------
G(* Recirculation
Nozzles
Burnout Air
Injectors
Reburn Fuel „„„
Injector*
Gss Recirculation
Nomas
Burnout Air
Injectors
Raburn F uel
Injectors
Figure 8; Lateral Jet Dispersion - Reburn Fuel
Injectors (Middle Nozzles)
Figure 9: Lateral Jet Dispersion - Rebum Fuel
Injectors (Sidewall Nozzles)
Gas Recirculation
Nozzles
Burnout Air
Injectors
Reburn Fuel
Injectors
ir—fl
r
jL-Ji r{'—:-'|i d
: r —^ i | ^ ^ :j-—
- 't3 —y -f-i it—'L br~)
"i: hriT
' ' " fp-
LJi
Figure 11: Example of Tube Modification for Reburn
Fuel Injector Installation
Figure 10: Jet Penetration - Burnout Air Injectors
3-140
-------
Fluegas
Recirculation ¦
Nozzles
,'Hi ii
tfft
Burnout Air
y/ Injectors
Reburn Fuel
Injectors
Auxllary
Burners
Main Coal
/ Burners
Upper Compartment
(FOR + CH4)
Middle Compartment
(PGR)
(FUTURE OtL OR CCAU
Lower Compartment
(FGR * CHJ
Figure 13: Reburn Fuel Injector Windbox
Arrangement
Figure 12: Preliminary Reburn System Design
Figure 14: Burnout Air Injector Windbox
Arrangement
3-141
-------
Mathematical
Inputs Model Outputs
Figure 15: Flow Diagram for Boiler Combustion Performance Model Simulation
Furnace Gas Temperature (°F)
Figure 16: Predicted Furnace Gas Temperature
Profile
ft°F - 32) x 5/9 = °C]
Horizontal Furnace
t «•» Gas Reburn
Outlet Plane
_\\ ««• Predicted
W w/o Reburn
Upper GR
\v
Burnout Air
-
Reburn
Main Burner
J
Main Burner
- ,
20000 30000 40000 50000 60000 70000 80000
Waterwall Heat Absorption Rate (Btu / hr / fl2)
Figure 17: Waterwall Heat Absorption Profile
(Btu/hr/ft2 + 13273.0 = Cal/sec/cm2)
3-142
-------
35.1m —
29.2m
- "
Burner
<£ Bumar
¦FGR Nozzles (6)
Tertiary Air
•(Burnout) Nozzles
(6 Front, 6 Hear)
Reburn Fuel and
FGR Injectors
(6 Front, 6 Rear)
31,0m«
26.8m
20.3m
I2"00"1 VMain Coal Burners
-8.75m ^ Fr0n,> 8 Rear)
. -15'.
¦-15 Fixed
Fixed
.-15° -15°.
Fixed Fixed
£ Burner
<£ Burner
5.90m
5.90m
FGR Nozzles (5)
• 27.5m
Burnout Air
Nozzles
(5 Front, 5 Hear)
-20.3m
Reburn Fuel and
FGR Injectors
(5 Front, 5 Rear)
12.00m
8.75m
>Maln Coal Burners
(8 Front, 8 Hear)
U.S. Side Preliminary Proposal Final Design Arrangement
Figure 18: Design Arrangements
Reburn Heat Input (20% of Total) (lb/hr) 24314
Percent by Weight FGR (%)
Flue Gas Recirculation (lb/hr)
Gas Residence Time (Zone 2) (sec)
14.7
410407
1.00
Volume Flow (ft3/sec) Wet
Gases Out of Reburn Zone
47084
Reburn" Zone Stoichiometry
Ash Flow Rate (lb/hr)
Gas Compositions at Outlet
of Reburn Zone
(% by Volume Dry)
Gas Compositions at Outlet
of Reburn Zone
(% by Volume Dry)
0.97
102965
C02
=
17
20
°2
-
0
00
Nz
-
82
22
so2
=
0
286
H20
=
0
00
CH*
0
29
co2
=
17
11
o2
0
00
N2
-
81
78
so2
0
285
H20
0
53
CH<
=
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 = kca!/hr
Performance Variables
Reburn Fuel Ratio %
Total Excess Air %
Burner Zone Excess Air %
%
%
Baseline
as Found
N.A.
20
20
18
N.A.
13.2
Total FGR
Reburn FGR -/o
Upper Furnace FGR %
Furnace Exit Gas °F(°C)
Temperature
Furnace Heat Absorption
x106 Btu/hr (x106 kcal/hr) 626(158)
Flyash Carbon Content % 2.3
Preliminary Optimum
Reburn Case Reburn Case
20
20
20
18
10
3.2
12
20
5
21
7.5
8.7
1967(1075) 2028(1109) 1949(1065)
606(153)
0.6
625(157)
1.2
Table 3: Furnace Performance Summary
3-144
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO. 2.
EPA- 600 /R- 92-093a
3. RECIPIENT'S ACCESSION'NO.
4. TITLE AND SUBTITLE
Proceedings: 1991 Joint Symposium on Stationary
Combustion NOx Control, Washington, D, C. , March
25-28, 1991, Volume 1. Sessions 1-3
5. REPORT DATE
July 1992
6. PERFORMING ORGANIZATION CODE
7. AUTHOFMS!
Carolee DeWitt, Compiler
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
William Nesbit and Associates
1221 Farmers Lane
Santa Rosa, California 95405
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
NA (EPRI Funded)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Proceedings; 3/89 - 3/91
14, SPONSORING AGENCY CODE
EPA/600/13
t5. supplementary notes AEERL project officer is Robert E. Hall, Mail Drop 65, 919/541-
2477. Volume 2 includes Sessions 4 and 5, and Volume 3 includes Sessions 6-8.
16. abstract 'pbg proceedings document the 1991 Joint Symposium on Stationary Combus-
tion NOx Control, held in Washington, DC, 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 develop-
ments for stationary combustion nitrogen oxides (NOx) control. Topics covered inclu-
ded the significant increase in active full-scale retrofit demonstrations of low-NOx
combustion systems in the U.S. and abroad over the past 2 years; full-scale oper-
ating experience in Europe with selective catalytic reduction (SCR); pilot- and bench-
scale SCR investigations in the U. S.; increased attention to selective noncatalytic
reduction (SNCR) in the U. S.; and NOx controls for oil- and gas-fired boilers. The
proceedings are published in three volumes.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. descriptors
b.identifiers/open ended terms
c. COSATI Field/Group
Pollution
Nitrogen Oxides
Combustion
Catalysis
Fossil Fuels
Pollution Control
Stationary Sources
Catalytic Reduction
Noncatalytic Reduction
13 B
07B
21B
07D
21D
18, distribution statement
Release to Public
19. SECURITY CLASS (ThisReport/
Unclassified
21. NO. OF PAGES
328
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
3-145
------- |