Jone 1976
{•viroMiiiital Prttecttofl
 EPA
6002/2
  76
 1*i2C

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               RESEARCH REPORTING
                                          SERIES
Research reports of the Office of Research and Development. U.S. Environmental
Protection Agency, have been grouped into fivj» seizes. These five broad
categories were established to facilitate furtfwr development and application of
environmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a rnaximiim interface in related fields.
The five series are:                         j    i
    1.
    2.
    3.
    4.
    5.
          Environmental Health Effects Research!
                                      iv I
          Environmental Protection technology
          Ecological Research       :
          Environmental. Monitoring
          Socioeconomic EnvironrnentaJ Sludies
: This report has been assigned to the ENVIftONhteNTAL PROTECTION
 TECHNOLOGY series. This se«es describes resea 'ch p formed to develop and
 demonstrate instrumentation, equipment,;and met wxlotooy to repair or prevent
 environmental degradation from point af^ rioft^intJijurces of pollution. This
 wtinX provides the new or Improved technology  re^fred for tti» control and
 treatment of pollution sourcass to meet 6fwn?nmef tai quality standards.   .
                    EPA REVIEW
This report has been reviewed by thi >
Protection Agency, and approved for
dees not signify that the contente
views and policy of the Agency, nor
names or commercial products cons1
recommendation for tse.
                                         publication.  Approval
                                                  reflect the;
                                        i loefl mention of trade
                                        itute endorsement or
This document is available to the public through (the National Technical Informa-
tion Service. Springfield, Virginia 22161,      i

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                                                            EPA-600/2~76-152c

                                                            June 1976
                             PROCEEDINGS OF THE

              STATIONARY SOURCE COMBUSTION SYMPOSIUM

                       VOLUME HI—FIELD TESTING AND SURVEYS
                              JoshuaS. Bowen, Chairman
                            Robert E.  Hall, Vice-Chair man


                      Industrial Environmental Research Laboratory
                        Office of Energy, Minerals, and Industry
                          Research Triangle Park, NC  27711
s.
     ROAPNo. 21BCC
Program Element No.  1AB014
                                    Prepared for

                     U.S. ENVIRONMENTAL PROTECTION AGENCY
                          Office of Research and Development
                                Washington, DC 20460

                                                   AGENflC

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r

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                               PREFACE
     The Stationary Source Combustion Symposium was held on September




24-26, 1975, at the Fairmont Colony Square Hotel in Atlanta, Georgia.




The symposium was sponsored by the Combustion Research Branch of E.P.A.fs




Industrial Environmental Research Laboratory (IERL).  The Combustion




Research Branch has been involved in developing improved combustion




technology for the reduction of air pollutant emissions from stationary




sources, and improving equipment efficiency.








     Dr. Joshua S. Bowen, Chief, Combustion Research Branch, was Symposium




Chairman; Robert E. Hall, Research Mechanical Engineer, Combustion Research




Branch, was Symposium Vice Chairman and Project Officer.  The Welcome




Address was delivered by Dr. John K. Burchard, Director of the Industrial




Environmental Research Laboratory.  Frank Princiotta, Acting Director of




the Energy Processes Division of E.P.A.'s Office of Energy, Minerals,




and Industry, was the Keynote Speaker.









     The Symposium consisted of four Sessions:




     Session I:  Fundamental Research




     Co-chairmen:  Dr. Joshua A. Bowen




                   W. Steven Lanier, Research Mechanical Engineer, E.P.A.,




                       IERL, Combustion Research Branch
                                 iii

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     Session II;  Fuels Research and Development




     Chairman:  G. Blair Martin, Chemical Engineer, E.P.A., IERL,




                   Combustion Research Branch








     Session III;  Process Research and Development




     Chairman:  David G. Lachapelle, Research Chemical Engineer,




                  E.P.A., IERL, Combustion Research Branch








     Session IV:  Field Testing and Surveys




     Co-chairmen:  Robert E. Hall



                   John H. Wasser, Research Chemical Engineer, E.P.A.,




                      Combustion Research Branch








     These Session Chairmen have reviewed the transcriptions of the




question and answer sessions, and, in addition, have worked with authors



to clarify and revise presentations, where appropriate, and to make them




clear and meaningful for these printed proceedings.








     We are grateful for the cooperation of Marjorie Maws, Project Leader;




Anita Lord, Symposium Administrator; and Margaret Kilburn, Program Director,




of Arthur D. Little, Inc., who coordinated the symposium for E.P.A.
                                  IV

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                                  CONTENTS
Preface ....

Welcome Address

Keynote Address
                                                                        ill
                  J.K. Burchard	1-1

                  F.T. Princiotta	1-3


                      SESSION I - FUNDAMENTAL RESEARCH

Formation of Soot and Polycyclic Aromatic Hydrocarbons (PCAH)
in Combustion Systems 	  1-18

     J.D. Bittner, G.P.  Prado, J.B.  Howard, R.A. Hites

Questions and Answers	1-32


Effects of Fuel Sulfur on Nitrogen Oxide Emissions	1-35

     J.O.L. Wendt, J.M.  Ekmann
            Si
Questions and Answers	1-88


Two-Dimensional Combustor Modeling  	  1-91

     R.C. Buggeln, H. McDonald

Questions and Answers 	  .....  (n/a)


Effects of Interaction Between Fluid Dynamics and Chemistry on
Pollutant Formation in Combustion 	  1-109

     C.T. Bowman, L.S. Cohen, L.J. Spadaccini, F.K.  Owen

Questions and Answers 	  1-119


Fate of Coal Nitrogen During Pyrolysis and Oxidation  	  1-125

     J.H. Pohl, A.F. Sarofim

Questions and Answers	1-147

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A Detailed Approach to the Chemistry of Methane/Air Combustion:
Critical Survey of Rates and Applications 	  1-153

     V.S. Engleman

Questions and Answers	  1-182


Chemical Reactions in the Conversion of Fuel Nitrogen to NOx	1-185

     A.E. Axworthy, G.R. Schneider, V.H. Dayan

Questions and Answers 	  1-211


Prediction of Premixed Laminar Flat Flame Kinetics, Including
the Effects of Diffusion	1-217

     R.M. Kendall, J.T. Kelly, W.S. Lanier

Questions and Answers	  1-266


Estimation of Rate Constants	1-267

     S.W. Benson, R. Shaw, R.W. Woolfolk

Questions and Answers	  .  (n/a)


Production of Oxides of Nitrogen in Interacting Flames  	  1-291

     C. England

Questions and Answers	1-316


Concurrent Panel Discussions:

1.  Combustion Chemistry and Modeling:  An Overview

   A.F. Sarofim - Combustion Chemistry and Modeling 	  1-325

   Questions and Answers	  I- 345


   T.J. Tyson - The Mathematical Modeling of Combustion Devices ....  1-347

   Questions and Answers  	  ......  1-410
                                    vi

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2. Federal, Regional, State, and Local Air Pollution
   Regulations: An Overview

   S. Cuffe - Federal	1-413
   G.T. Helms - Regional	1-429
   R.H. Collum - State	1-443
   H.W. Poston - Local	I- 447



               SESSION II - FUELS RESEARCH AND DEVELOPMENT


Assessment of Combustion and Emission Characteristics of
Methanol and Other Alternate Fuels  	 II-3

     G.B. Martin

Questions and Answers	 . 11-30


Burner Design Criteria for Control of Pollutant Emissions
from Natural Gas Flames	11-31

     D.F. Shoffstall

Questions and Answers 	 (n/a)


Integrated Low Emission Residential Furnace 	 . 	 11-81

     L.P. Combs, W.H. Nurick, A.S. Okuda

Questions and Answers 	 11-101


The Control of Pollutant Emissions from Oil Fired
Package Boilers 	 11-109

     M.P. Heap, T.J. Tyson,  E. Cichanowicz, R.E. McMillan, F.D.  Zoldak

Questions and Answers 	 11-160


Pilot Scale Investigation of Catalytic Combustion Concepts for
Industrial and Residential Applications 	 . 	 11-163

     J.P. Kesselring, R.M. Kendall, C.B. Moyer, G.B.  Martin

Questions and Answers 	 II-196
                                       vii

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The Optimization  of  Burner Design Parameters to Reduce NOx
Formation  in Pulverized Coal and Heavy Oil Flames 	 II-197

     M.P.  Heap, T.J. Tyson, G.P. Carver, G.B. Martin, T.M. Lowes

Questions  and Answers	11-239


Pilot Scale Investigation of Combustion Modification Techniques
for NOx Control in Industrial and Utility Boilers 	 11-241

     R.E.  Brown,  C.B. Moyer, H.B. Mason, D.G. Lachapelle

Questions  and Answers  . . 	 11-267
             SESSION III - PROCESS RESEARCH AND DEVELOPMENT


Overfire Air as an NOx Control Technique for Tangential
Coal-Fired Boilers 	 III-3

     A.P. Selker

Questions and Answers 	 ... Ill-26


Control of NOx Formation in Wall Coal-Fired Boilers 	 Ill-31

     G.A. Hollinden, J.R. Crooks, N.D. Moore, R.L. Zielke,
     C. Gottschalk

Questions and Answers 	 111-77


The Effect of Additives in Reducing Particulate Emissions
from Residual Oil Combustion  	 111-83

     R.D. Giammar, H.H. Krause, A.E. Weller, D.W.  Locklin

Questions and Answers 	 Ill-115


System Design for Power Generation from Low Btu Gas Boilers 	 Ill-119

     M.P. Heap, T.J. Tyson, N.D.  Brown

Questions and Answers	(n/a)
                                      viii

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                  SESSION IV - FIELD TESTING AND SURVEYS


The Effect of Combustion Modification on Pollutants and
Equipment Performance of Power Generation Equipment . 	 .... IV-3

     A.R. Crawford, E.H. Manny, M.W. Gregory, W. Bartok

Questions and Answers	 IV-109


Analysis of Gas-, Oil-, and Coal-Fired Utility Boiler
Test Data	IV-115

     O.W. Dykema, R.E. Hall

Questions and Answers	IV-161


Influence of Combustion Modifications on Pollutant Emissions
from Industrial Boilers 	 IV-163

     G.A. Cato, L.J. Muzio, R.E. Hall

Questions and Answers 	 . . IV-219


Emission Characteristics of Small Gas Turbine Engines 	 IV-227

     J.H. Wasser

Questions and Answers	IV-252
Systems Evaluation of the Use of Low-Sulfur Western Coal in
Existing Small- and Intermediate-Sized Boilers  	
     K.L. Maloney

Questions and Answers
IV-2 55
IV-316
A Survey of Emissions Control and Combustion Equipment Data in
Industrial Process Heating  	 IV-321

     P.A. Ketels, J.D. Nesbitt, D.R. Shoffstall, M.E. Fejer

Questions and Answers	(ti/a)
                                      ix

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POM and Particulate Emissions from Small Commercial
Stoker-Fired Boilers 	  IV-411

     R.D. Giammar, R.B. Engdahl, R.E. Barrett

Questions and Answers	IV-439



Concluding Remarks - J.S. Bowen	IV-441
Appendix
      List of Speakers	A-l
      List of Participants
              Alphabetically by Name	A-2
              Alphabetically by Organization 	 A-6

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        SESSION IV

FIELD TESTING AND SURVEYS
  R. E.  Hall;  J.  H. Wasser
       Co-Chairmen
           IV-1

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IV-2

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      THE EFFECT OF COMBUSTION MODIFICATION
     ON POLLUTANTS AND EQUIPMENT PERFORMANCE
          OF POWER GENERATION EQUIPMENT

by A. R. Crawford, E. H. Manny, M. W. Gregory and W. Bartok

      Exxon Research and Engineering Company
             Prepared for a Symposium
                        on
           STATIONARY SOURCE. COMBUSTION
                   Sponsored by

            Combustion Research Branch
   Industrial Environmental Research Laboratory
       U.S. Environmental Protection Agency
           Fairmont Colony Square Hotel
                 Atlanta, Georgia
              September 24-26, 1975
                      IV- 3

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This report has been reviewed by the Environmental Protection Agency
and approved for publication.  Approval does not signify that the
contents necessarily reflect the views and policies of the Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
                             IV-

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                          TABLE OF CONTENTS
    SUMMARY ............................   IV-9
1.  INTRODUCTION .........................   IV-11
2.  FIELD STUDY PLANNING AND PROCEDURES ..............   IV-13
    2.1  Selection of Power Generation Combustion Equipment. ...   IV-13
    2.2  Test Program Strategy ..................   IV-15
    2.3  Gaseous Sampling and Analysis ..............   IV-17
    2.4  Particulate Sampling ...................   IV-21
    2.5  Furnace Corrosion Probe Testing .............   IV-23
    2.6  Boiler Performance ..................... IV-24
3.  FIELD TEST RESULTS AND DISCUSSION ...............   IV-27
    3.1  Gaseous Emission Results for Individual
         Power Generation Units ................ ..   IV-27
         3.1.1  Widows Creek, Boiler No. 5 ............   IV-28
         3.1.2  Ernest C. Gaston, Boiler No. 1 ..........   IV-35
         3.1.3  Navajo, Boiler No. 2 ...............   IV-42
         3.1.4  Comanche, Boiler No. 1 ..............   IV-51
         3.1.5  Barry, Boiler No. 2 ................   IV-57
         3.1.6  Morgantown, Boiler No. 1.... .........   IV-67
         3.1.7  Morgantown, G.E. Gas Turbine No. 3 ........   IV-75
    3.2  Particulate Emission Results ...............   IV-77
    3.3  Corrosion Probing Results ................   IV-83
    3.4  Boiler Performance Results ............. .... IV-88
4.  CONCLUSIONS ..........................   IV-9 3
    4.1  Gaseous Emission Measurements ..............   IV-93
    4.2  Side Effects of Combustion Modifications .........   IV-99
5.  REFERENCES . .........................   IV-100
    ACKNOWLEDGMENTS ........................   IV-101
    APPENDIX A - Cross Section Drawings of
                 Typical Utility Boilers .............   IV-102
    APPENDIX B - Conversion Factors. . . , , , ..........   IV-106
                                IV-5

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                            LIST OF TABLES
Number
          Summary of Coal and Mixed Fuel Fired Boilers Tested.  .  .

          Continuous Analytical Instruments in Exxon Van 	
Page

IV-16

IV-19
2-1

2-2

3-1      Summary of Operating and Emission Data -
         Widows Creek. Boiler No. 5	   IV-29

3-2      Test Program Experimental Design - PPM NO  and % 0.
         Widows Creek, Boiler No. 5 	 ? .......   IV-30

3-3      Summary of Operating and Emission Data -
         Ernest C. Gaston, Boiler No.  1	   IV-38

3-4      Test Program Experimental Design -
         (Ernest C. Gaston, Boiler No. 1)	„ . .  , .   IV-39

3-5      Summary of Operating and Emission Data -
         Navajo Station - Boiler No. 2	 .   IV-43

3-6      Reduced Load Test Data - Navajo No. 2 Unit	   IV-47

3-7      Test Program Experimental Design - Run No., % Oo, PPM NO
         (Navajo No. 2 Unit - Full Load (795-808 MW)	   IV-49

3-8      Summary of Operating and Emission Data
         (Comanche No. 1 Boiler)	   IV-53

3-9      Summary of Operating and Emission Data
         (Barry No. 2 Boiler)	   IV-60

3-10     Test Program Experimental Design - Run No., % 0 , PPM NO
         (Barry No. 2 Boiler)	7 . .  . .x Iv~62

3-11     Summary of Operating and Emission Data
         (Morgantown No. 1 Boiler). .  „	   IV-68

3-12     Test Program Experimental Design -
         Morgantown Boiler No. 1	   IV-69

3-13     Summary of Operating and Emission Data -
         Morgantown Station, G.E. Gas  Turbine No. 3	   IV-75

3-14     Particulate Emission Test Results	   IV-78
                                    1V-6

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                      LIST OF TABLES (Continued)
Number

 3-15


 3-16

 3-17


 3-18

 3-19


 3-20

 3-21

 3-22

 3-23

 4-1
                                                           Pace
Public Service Company of Colorado -
Comanche Station, Boiler No. 1	   IV-79
Salt River Project - Navajo Station, Boiler No.  2,
IV-80
Southern Electric Generating Company -
E. C. Gaston Station	   IV-81
Tennessee Valley Authority - Widows Creek Station.  .
IV-84
Southern Electric Generating Company -
E. C. Gaston Station	   IV-85

Salt River Project - Navajo Station	   IV-86

ASME Test Form for Abbreviated Efficiency Test	   IV-89

ASME Test Form for Abbreviated Efficiency Test	   IV-90

Summary of Boiler Performance Calculations	   IV-91

Summary of NO  Emissions from Coal Fired Boilers  ....   IV-94
                                IV-?

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LIST OF FIGURES
Number
2-1

2-2

2-3

3-1

3-2

3-3

3-4

3-5

3-6

3-7

3-8

3-9

3-10

3-11

3-12


Exxon Research Transportable Sampling and

Corrosion Probe - Detail of 2-%" IPS Extension

Corrosion Probe - Detail of Corrosion Coupon Assembly

PPM NOX (3% 02, Dry) vs % Stoichiometric Air to

NOX Emission vs Staged Firing Patterns
(Widows Creek No. 5 Unit) 	
Bab cock and Wilcox Dual Register

Mill-Burner Configuration

PPM NOX (3% 02, Dry) vs % Stoichiometric Air to

PPM NOX (3% 02, Dry Basis) vs % Oxygen
(Navajo No. 2 Boiler - Full Load, Normal Firing) ....
PPM NOX (3% 02, Dry Basis) vs % Oxygen
(Navajo No. 2 Boiler - 87, Overfire Air Dampers 100% Open)
PPM NOX (3% 02, Dry basis) vs % Oxygen

PPM NOX vs Overfire Air Dampers - % Open
(Navajo No. 2 Boiler - Full Load) 	
PPM NOX (3% 02, Dry Basis) vs Burner Tilt

PPM NOx (3% 02, Dry Basis) vs Overfire Air - % Open
(Comanche No. 1 Unit 	 15° to -20° Burner Tilt) ....
PPM NOX (3% 02 Basis) vs % Oxygen
(Comanche No. 1 Unit - S/ - 50% Open OFA Ports) 	
Page

IV-18

IV-25

IV-26

IV-31

IV-33

IV-36

IV-37

IV-41

IV-45

IV-46

IV-48

IV-50

IV-54

IV-55

IV-56
    IV-8

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                     LIST OF FIGURES (Continued)
Number

 3-13

 3-14


 3-15
Unit Side Elevation, Alabama Power Co., Barry No. 2. . ,

PPM NOX (3% 02, Dry) vs % 02 in Flue Gas
(100% Coal Fired Test Runs - Barry No. 2 Unit) 	
PPM NOX (3% 02, Dry) vs % Coal in Coal-Gas Mixed
Fuel Firing (Barry No. 2 Unit - Full Load Test Runs) . .
Page

IV-58


IV-63


IV-65
3-16
3-17
3-18
3-19
4-1
4-2
4-3
PPM NOX (3% 02, Dry Basis) vs % Coal in Coal/Oil Mixed
PPM NOX (3% 02, Dry Basis) vs Coal in Coal/Oil Mixed
Fuel Firing (Full Load, Staged Firing Operation) ....
PPM NOX (3% 02, Dry Basis) vs % Coal in Coal/Oil Mixed
Fuel Firing (Reduced Load - Normal and Staged Firing)- •
PPM NOX (3% and 15% 02, Dry Basis) vs Gross Load MW
PPM NOX vs % Oxygen in Flue Gas
Effect of Excess Air Level on NOX Emissions Under
Effect of Excess Air on NOX Emissions Under Modified
IV-70
IV-71
IV-72
IV-76
IV-96
tV-97
IV-98
                                IV-9

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IV-10

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               THE EFFECT OF COMBUSTION MODIFICATION
              ON POLLUTANTS AND EQUIPMENT PERFORMANCE
                   OF POWER GENERATION EQUIPMENT

    by A. R. Crawford, E. H. Manny, M. W. Gregory and W. Bartok
                   Government Research Laboratory
               Exxon Research and Engineering Company
                         Linden, New Jersey

                     Prepared for a Symposium on
                    "Stationary Source Combustion"
             Sponsored by the Combustion Research Branch,
             Industrial Environmental Research Laboratory
                 U.S. Environmental Protection Agency
               Held at Fairmont Colony Square Hotel in
              Atlanta, Georgia on September 24-26, 1975
SUMMARY

          Exxon Research and Engineering Company has completed the
first year of a continuing field test research program on power
generation combustion pollution sources.  This program, jointly
sponsored by EPA (Contract No. 68-02-1415) and EPRI (Project No. 200),
has been conducted with the cooperation of equipment manufacturers and
equipment operators.  Measurements of gaseous emissions, particulate
mass, particulate size distribution, accelerated corrosion, boiler
efficiency and slagging tendency have been made using Exxon's mobile
sampling/analytical van.

          The major emphasis of this program has been placed upon
combustion modification of coal fired boilers.  However, field testing
of mixed fuel firing boilers, waste fuel fired boilers, gas turbines
and stationary, power generating, internal combustion engines are also
included within the scope of this program.

          Six coal fired boilers, including two with mixed fuel firing
(coal-oil, coal-gas) capabilities and a gas turbine have been tested to date.
We have been fortunate in obtaining the excellent cooperation of the
operators of four boilers, selected at the suggestion of boiler
manufacturers, that are equipped with special NOX emission reduction
equipment.  Three Combustion Engineering designed boilers have overfire
air ports and a Babcock and Wilcox designed boiler has been retrofitted
with their new, limited turbulence, controlled diffusion flame burners.
The three-phase test programs conducted on most of these units consisted
of, first, a statistically designed short period test run to determine
baseline and minimum NOX emission capability of the unit, second, a
one or two day sustained run under "low NOX" operation to determine
if potential operating problems arise and third, a 300-hour sustained
run under baseline and "low NOX" conditions to check on other potential
side effects such as corrosion, loss in boiler efficiency, particulate
emissions, slagging, etc.
                                  IV-11

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          Several key findings have been determined from an analysis
of the gaseous emission data.  The new B&W burner equipped boiler
emitted 35% less NOX under normal firing and over 50% less NOX under
full load, modified firing operation than was emitted from an identical
boiler with normally equipped burners.  Tangentially fired boilers
equipped with overfire air ports emitted about 20% less NOX than
similar boilers when tested under normal firing operation.  Modified
firing using overfire air ports and low excess air resulted in an
average of over 40% additional reduction in NOX emissions at full load,
for a reduction of over 50 percent over boilers not equipped with
overfire air ports.  Mixed fuel fired boiler NOX emission levels
increased as the % of coal in the coal-oil or coal gas mixture increased,
but not linearly.  NOX emissions from a 50 MW (MCR) gas turbine on a
3% 02 basis were about 375 PPM at full load, 400 PPM at peak load, with
reductions to about 325 and 250 PPM at 50% and 20% of full load respectively.
All PPM values given in this report are corrected to a 3£ 02, dry basis.

          Only relatively minor differences have been observed in
particulate mass loadings under "low NOX" firing conditions.  Unbumed
carbon in the fly-ash, which was observed to Increase in previous
studies, especially on front wall and horizontally opposed fired boilers,
was found to decrease on most of the boilers tested in this program.
Particle size distribution, which could affect electrostatic precipitator
collection efficiency, was found to be the same for "low NOx" operation
as for baseline conditions.

          In 300-hour sustained runs, no major differences in corrosion
rates have been observed for low NO^ firing compared to normal operation.
Long term tests measuring actual furnace wall tube wastage are needed to
confirm this finding.  As in previous studies, no significant changes in
boiler efficiency have been observed due to "low NO " mode of operation.
          In the continuation of this program we will add sampling and
analytical capabilities for measuring sulfates, nitrates, HCL, HCn and
hazardous and toxic materials.  This will include POM as well as
metallic elements.  Also, further testing will be carried out to relate
slagging tendency to furnace temperatures, to explore the potential use
of antislagging additives, and to define the potential of combustion
control for wet-bottom and waste fuel fired boilers.
                            IV-12

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                        1.  INTRODUCTION
          Exxon Research and Engineering Company has been conducting
field studies under EPA sponsorship on the application of combustion
modification techniques to control pollutant emissions from utility
boilers.  The emphasis in these studies has been on controlling NOX
emissions without adverse side-effects.  These cooperative field
studies have been conducted using a mobile sampling analytical system
supplied by Exxon.

          Under EPA Contract No. CPA 70-90 (1), significant reductions of
were achieved for gas and oil-fired boilers using combustion modification
techniques in limited field testing, without attempting to optimize the
technology.  The principal modifications investigated consisted of minimizing
excess air, staged air/fuel introduction, flue gas recirculation, varying
boiler load, and varying air preheat temperature.  Also, as part of this
study, it was possible to achieve significant reductions in NOX emissions
for two of the seven coal-fired boilers tested, through the combination of
low excess air with staged firing.

          Because of the difficulty of controlling NOX emissions from coal
fired boilers, in the subsequent EPA-sponsored Exxon study (Contract No.
68-02-0227) (2) the emphasis shifted to a more detailed investigation of
emission control for coal-fired utility boilers, again in cooperation with
boiler owner-operators and manufacturers.  These field studies on twelve
coal-fired units representative of the current design practices of the
major U0S. boiler manufacturers (Babcock and Wilcox, Combustion Engineering,
Foster Wheeler, and Riley-Stoker)  have produced very promising results.  It
was possible to achieve reductions in NOX emissions ranging between about
30% and 50%, without apparent adverse side-effects.  In addition to gaseous
emissions measurements the studies included partlculate mass loading and
unburned combustible measurements, accelerated furnace corrosion probing,
determination of boiler efficiency, and observations of changes in boiler
operability, in particular slagging, fouling, and flame problems.

          Based on the successful results of the above work, the Environmental
Protection Agency and the Electric Power Research Institute decided to
jointly fund the present Exxon field study.  The scope of the work has been
broadened to determine the effects of combustion modification techniques on
the control of pollutant emissions and on the performance of fossil fuel
fired power generation equipment.   In this field program, coal-fired,
mixed-fuel fired and waste fuel-fired boilers are studied, in addition
to short-term tests on stationary gas turbine and I.C. engine equipment.
There remains continuing emphasis in this work on coal fired utility
boilers.
                                IV- 13

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          The objective of the present study is to develop improved
pollutant control techniques for coal fired utility boilers, and explore
the application of such techniques to emissions control from mixed and
waste-fuel fired combustion equipment, as well as to obtain preliminary
field data on other power generation combustion equipment.  Boilers
selected for the program are being tested in cooperation with electric
utilities and boiler manufacturers.  Approaches aimed at improved NQ^
control, such as coal fired boilers constructed with overfire air ports,
and improved burner design are being explored.  Potential adverse side-
effects of combustion modifications are being studied in more detail than
previously.  Thus, in addition to the usual emission measurements (including
pollutants, stable combustion products and unburned combustibles), both
particulate mass and size distribution measurements are being made under
normal and low NOX modes of boiler operation.  The effect of combustion
modifications on the collectability of particulates will be evaluated by
making precipitators of one or two units to be tested, and the SC^/SOo
ratio is being determined under normal and low NOX operating conditions.

          As previously, the effect of combustion modifications on boiler
efficiency and operability is being determined.  Special attention is
being paid to the determination of potential furnace water wall corrosion
resulting from staged firing.  For this purpose, the results of 300-hour
sustained corrosion runs will be compared with actual tube wastage
measurements on at least one coal-fired utility boiler operated under low
NOx conditions for a six-month period.
                                IV-14

-------
              2.  FIELD STUDY PLANNING AND PROCEDU1ES
          This section discusses the major steps involved in field
study planning and the testing methods used to obtain emission,
corrosion and performance measurements.  Field study planning steps
included selection of representative power generation equipment (with
participation of EPA, EPRI, equipment manufacturers and equipment
operators) and designing an effective test program strategy.  Methods
of gaseous emission testing were quite similar to those used in Exxon's
"Systematic Field Study" (1).  Particulate sampling, corrosion probing
and performance measurements were an expanded version of those used
in Exxon's previous field studies (2),  Boilers firing coal, coal-oil
and coal-gas mixed fuel were tested as was an oil fired, utility sized,
gas turbine.  In addition, particulate size distribution samples were
taken and S02/S03 measurements were made using standard wet chemical
methodology.

2.1  Selection of Power Generation Combustion Equipment

          This program provides for the testing of utility boilers
(coal fired, mixed fossil fuel fired and waste fuel fired) utility
sized gas turbines and a large, stationary 1C engine.  To date,
testing has been completed on four coal fired boilers, two mixed
fuel (coal-oil and coal-gas) fired boilers and a oil fired gas turbine.

          The successful selection of boilers representing current
design practices was the result of a cooperative planning effort by
Exxon Research,  EPA, EPRI and boiler manufacturers (Combustion
Engineering, Babcock and Wilcox,  Riley Stoker and Foster Wheeler).
The process of developing boiler selection criteria, reviewing boiler
manufacturers list of boilers meeting the criteria, selecting a
tentative list of boilers for detailed field meetings and final
selection and scheduling of test programs has been described
previously (2).

          Design factors were the prime consideration in selecting
boilers in the current field test program after other criteria such
as size, operating flexibility, boiler measurement and control
capability, etc. had been met.  Boilers representing the current
design practices of all four utility boiler manufacturers were desired.
However, coal fired boilers designed with overfire air ports or
specially designed burners for NOx emission control were particularly
desired.  We were fortunate to obtain the cooperation of the boiler
operators of three tangentially fired (2 coal, 1 coal-gas mixed fuel)
                             IV- 15

-------
boilers with overflre air ports and a wall fired boiler retrofitted
with special low NOX burners.  We were not successful in obtaining
the cooperation of the utility company which operates the only
front-wall, coal fired boiler in the United States equipped with
overfire air ports.

          The design and operating features of the six coal or mixed
fuel fired boilers tested to date in the current program are summarized
in Table 2-1.  Four boilers are tangentially fired (ranging in size
from 130 Mtf to 800 MW) and two are wall fired (a rear-wall fired
125 MW unit, and a horizontally opposed firing 270 MW capacity unit).
These boilers have been selected for field studies at the recommendation
of their respective manufacturers as representative of current design
practices and/or because of special designed NOX reduction capabilities
or programs.
                               IV-16

-------
I
                         2.2  Test Program Strategy

                                   The up-to-date, comprehensive information obtained in field
                         meetings provided the necessary data for Exxon to develop detailed,
                         run-by-run proposed test program plans for review by all interested
                         parties.  Each test program, tailored to take full advantage of the
                         particular combustion control flexibility of each boiler, was comprised
                         of three phases:  (1) short test-period runs, (2) a 1-3 day sustained
                         "low NOX" run and (3) 300-hour sustained "low NOX" and normal operation
                         runs.  Thus the strategy used for field testing coal-fired boilers
                         consisted first  of defining the optimum operating conditions for NOX
                         emission control, without apparent unfavorable side effects in
                         short-term statistically designed test programs.  Second, the boiler
                         was operated for 1-3 days under the "low NOX" conditions determined
                         during the optimization phase, for assessing boiler operability
                         problems.  Finally, where possible, sustained 300-hour runs were made
                         under both baseline and modified ("low NOX") operating conditions.
                         During this period, air-cooled carbon steel coupons were exposed on
                         corrosion probes in the vicinity of furnace water tubes, to determine
                         through accelerated corrosion tests whether operating the boiler under
                         the reducing conditions associated with staged firing results in
                         increased furnace water tube corrosion rates.  Particulate samples
                         were obtained under both baseline and "low NOjc" conditions.  Engineering
                         information on boiler operability, e.g., on slagging problems, and data
                         related to boiler performance were also obtained.
                         «
                                   Statistical principles (as discussed in more detail in our
                         "Systematic Field Study" (1)) provided practical guidance in planning
                         the Phase 1 test programs;  i.e., how many, and which test runs to
                         conduct, as well as the proper order in which they should be run.
                         These procedures allow valid conclusions to be drawn from analysis
                         of data on only a small fraction of the total possible number of
                         different test runs that could have been made.  Our subsequent studies
                         (2) illustrate these principles applied to a field test program
                         conducted on a wall fired boiler.
                                                       IV- 17

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                IV- 18

-------
2.3  Gaseous Sampling and Analysis

          The sampling and analytical system used in this program to
obtain reliable gaseous emission data in field tests has been described
in detail (_1,.2).  A schematic drawing of the sampling system is provided
in Figure 2-1.  The gaseous species analyzed are also indicated on this
diagram.  Table 2-2 tabulates the instruments contained in the Exxon
Analytical Van according to manufacturer, operating technique employed,
and measurement range capabilities.  This system has been used for over
five years to obtain reliable field test data with a minimum of operating
difficulties.

          A major consideration in obtaining reliable gaseous emission
data is to insure that the sample gas is virtually moisture free.
Moisture in the sample gas can influence the readings obtained by certain
instrumentation.  This problem has been avoided effectively in the
Exxon sampling system by passing the sample gases through a refrigerated
water knock-out coil.  Recently, permeation-type drying tubes* (Permatubes)
have become available for removing moisture in gas sampling systems
without changing the concentrations of other gases.  For the present
study, therefore, permatube driers were added to the Exxon sampling train
as an addition to the refrigerated knock-outs to insure the maximum
drying capabilities for the gaseous emission sampling system.  This
system has proven to be very effective in obtaining dry sample gases.

          Concurrent with the present program, Exxon Research and
Engineering Company conducted an investigation under contract to EPA
(Contract No. 68-02-1722) to "Determine the Magnitude of the Strati-
fication of Gases in the Ducts of Fossil Fuel Fired Power Plants."
The results of this investigation showed that stratification of the
gases in the ducts does indeed exist and that meaningful "average"
emission values can be obtained only by multiple probe sampling of
the inner 50% of the duct.  Also, average emission data obtained in
this manner would be within plus or minus 10 percent of values prevailing
in adjacent ducts on the same boiler, perhaps with the exception of
oxygen (02) the concentration of which may be influenced by leaks.
   Manufactured by Perma Pure, Inc., Oceanport, N.J.
                              IV- 19

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                   LLJ
IV- 20

-------
                                TABLE 2-2

                          CONTINUOUS ANALYTICAL
                        INSTRUMENTS IN EXXON VAN
    Beckman
  Instruments

NO
         Technique
CO,,
CO
so.
Hydrocarbons
Thermo Electron
NO/NO
Non-dispersive Infrared


Non-dispersive ultraviolet


Polarographic


Non-dispersive infrared

Non-dispersive infrared



Non-dispersive infrared


Flame ionization detection
Chemiluminescent
  Measuring
    Range	

0-400 ppm
0-2000 ppm

0-100 ppm
0-400 ppm

0-5Z
0-252

0-20Z

0-200 ppm
0-1000 ppm
0-23,600 ppm

0-600 ppm
0-3000 ppm

0-10 ppm
0-100 ppm
0-1000 ppm
0-2.5 ppm
0-10.0 ppm
0-25 ppm
0-100 ppm
0-250 ppm
0-1000 ppm
0-2500 ppm
0-10,000 ppm
                                   IV- 21

-------
          The findings of this stratification study verify the design
principles utilized by the Exxon sampling system for obtaining
representative gaseous emission data.  In the Exxon system, samples
are taken from zones of "equal areas" in the flue gas ducts.  At
least two probes are installed in each flue gas duct, or a minimum
of four are used when there is only one large flue duct on the boiler.
Each of the probes is comprised of three stainless steel sampling tubes
(short, medium and long) reaching to the mid-point of zones of equal
area in the depth of the duct.  Thus, a minimum of six sampling points
per duct or 12 per boiler are provided, assuring representative gas
samples.

          A complete range of calibration gas cylinders in appropriate
concentrations with N2 purge and zeroing gas for each analyzer is
installed in the system.  Instruments are calibrated daily before each
test and in-between tests if necessary, assuring reliable, accurate
results.
                           IV-22

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2.4  Particulate  Sampling

          Combustion of fuel in utility boilers normally is accom-
plished in multiple burner arrays of several different firing patterns,
such as, front wall, horizontally opposed, tangential, cyclone, etc.
Air for combustion is supplied by forced draft fans in pressurized
boilers or by both forced and induced draft fans in balanced draft boilers,
On the average, excess combustion air in the utility industry varies
between 15 to 25% and the air is admitted to the burners in a highly
turbulent fashion and in sufficient quantities (as above) to assure
complete combustion of the fuels,  Combustion air and flame tempera-
ture are also maintained as high as possible to improve combustion
efficiency.

          Recently, with the advent of NOX emission regulations, com-
bustion processes have been modified to promote less intense combustion
conditions so that operation at lower MOX emission levels is possible.
This has been accomplished by lowering and optimizing excess air
levels, staging the combustion process and re-adjustment of burner
dampers to decrease turbulence.  Lowering excess air increases flame
temperatures, aiding combustion, but tends to limit the amount of
oxygen available for the combustion process.  Potentially, this fac-
tor directionally increases the probability of burnout problems.
Staging the combustion pattern, where the majority of the burners
are operated at sub-stoichiometric conditions and the remaining air
is introduced either through inactive burners or "overfire air ports"
to complete the combustion process, can have similar, major effects.
In the latter, available oxygen is limited in the initial combustion
phase, flames are lengthened, and there is less turbulence due to the
slower, diffusive mixing of air and fuel.  Thus, staging the combus-
tion pattern potentially can increase unburned combustibles.  Modi-
fications to the combustion process for NOX emission control may also
affect the amount and character of the particulate matter emitted
from the boiler.

          Accordingly, this field test program included investigations
of potentially increased particulate emissions and changes in flyash
particle size distribution in pulverized coal fired utility boilers.
Measurements were made of particulate mass loading and flyash particle
size distribution in tests both at "base" and optimized "low NOX"
operating conditions.  The objective of this effort was to determine
the extent of potential adverse side effects of "low NOX" combustion
modifications on particulate emissions by comparing total quantities,
percent unburned carbon, and changes in particle size distribution
with comparable data obtained under normal or baseline operating con-
ditions.  Data of this type is  needed for an evaluation of potential
adverse affects on electrostatic precipitator performance.
                              IV- 23

-------
Measurements of flyash resistivity, which are also needed for
assessing affects on precipitator performance, were beyond the scope
of the present program.

          Two Joy Manufacturing Company, and two Aerotherm Accurex
High Volume, EPA type particulate sampling trains complying with EPA
Method 5 requirements (3) were used to obtain particulate mass loading
data.  These trains have been modified to incorporate a Brink, multi-
stage cascade impactor in the heated sampling box for the determination
of particle size distribution.  This arrangement permits particle size
distribution determinations outside of the boiler under isokinetic
sampling conditions.
                              IV-24

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2.5  Furnace Corrosion Probe Testing

          Under certain conditions, pulverized coal fired boilers are
subject to wastage of the furnace wall tubes.  Normally, this type of
corrosion is experienced in areas where a localized reducing environment
might exist adjacent to the midpoint of furnace sidewalls near burner
elevations where flame impingement could occur.  To counteract such
effects, normal practice is to increase the excess air level so that
an oxidizing atmosphere prevails at these locations, and to increase
the fineness of pulverization, so that the oxidation of the pyrites
in the coal is completed before these species can come into contact
with the furnace wall tubes.  For new boilers, a design improvement
consists of increasing the separation between the burners and the
sidewalls, thus minimizing potential impingement problems.  Several
mechanisms have been postulated for this type of corrosion which
appears to be associated with the formation of pyrosulfates from the
coal ash (at 600-900°F), and iron sulfide, or 863 from the pyrites.

          Combustion modifications for NOx emission control are
generally most effective at low excess air or substoichiometric air
supply conditions in the flame zone, i.e., under conditions that are
potentially conducive to furnace tube wall corrosion.  The need for
investigating the effects of modified firing operations on furnace
tube wall corrosion has been recognized and preliminary investigations
have already been conducted by Exxon Research and Engineering Company
under EPA Contract No. 68-02-0227.  Details and results of these
investigations have been reported previously (_2).

          In the above program, the approach used for obtaining cor-
rosion rate data was to expose corrosion coupons installed on the end
of probes inserted into available openings located near "vulnerable"
areas of the furnace under both baseline and "low NOX" firing condi-
tions.  Coupons were fabricated of SA 192 carbon steel, the same
material used for furnace wall tubes.  Exposure for 300 hours at
elevated coupon temperatures of 875°F (above normal furnace tube
metal temperature of about 600°F) was chosen in order to deliberately
accelerate corrosion so that "measurable" values could be obtained.
Coupons were also mild acid pickled to remove any existing oxide
coating prior to exposure to eliminate any potential differences due
to surface conditions.  The major conclusion of these investigations
was that no major differences in corrosion rates were found for cou-
pons exposed to "low NOX" firing conditions compared to similar cou-
pons subjected to normal operation.  Corrosion rates on the coupons,
however, were considerably higher than would be expected in a furnace
wall tube due to the severe exposure conditions employed to obtain
"measurable" values.
                                IV- 25

-------
          The approach used in obtaining corrosion rate data in the
current program was similar to that of the prior program, but with
several significant differences.  First, corrosion coupons, which
are all fabricated and machined in the same manner, are no longer
mild acid pickled but, instead, are merely dipped in acetone and air
dried prior to weighing to remove any existing oil used in machining.
Second, and most important, coupon temperatures have been reduced to
approximately the metal temperatures of the existing furnace wall
tube in which they are exposed in an effort to more closely approxi-
mate actual furnace conditions.  Third, in the current program,
three coupons are installed on each probe in an effort to increase
the amount of available data compared with only two in the prior pro-
gram.  Although this does not materially affect test conditions,
more information is obtained from each probe.  Time of exposure (300
hours) was held the same as for the prior program in order to elimi-
nate potential differences in corrosion rates due to this factor.

          Figures 2-2 and 2-3 show details of the corrosion probes used
in this and the prior study.  Our probes are based on a design supplied by
Combustion Engineering.  Essentially, the design consists of a "pipe
within a pipe," where the cooling air from the plant air supply is
admitted to the ring-shaped coupons exposed to furnace atmospheres
at one end of the probe, through a 3/4-inch stainless steel tube
roughly centered inside of the coupons.  The amount of cooling air
is automatically controlled to maintain the desired set-point tem-
perature of 875°F for the coupons.  The cooling air supply tube is
axially adjustable with respect to the corrosion coupons, so that
temperatures of both coupons may be balanced.  To simplify the pres-
entation, thermocouples mounted in each coupon are not shown in
Figures 2-2 and 2-3.  Normally, one thermocouple is used for con-
trolling and the other one for recording temperatures.  Also, as
noted above, a third coupon is used on the end of the probe which is
not shown in Figure 2-3.  The cooling air travels backwards along the
2-1/2-inch extension pipe and discharges outside of the furnace.
Thus, the cooling air and the furnace atmosphere do not mix at the
coupon location.

2.6  Boiler Performance

          Low NOX modification techniques result in less intense
combustion conditions which tend to increase burnout problems.
Potentially this mode of operation increases the amount of unburned
combustibles which could have an adverse effect on boiler efficiency.
Particulate dust loading tests therefore were run for each major test
at baseline and "low NOX" operation and the samples were analyzed for
unburned carbon.  Boiler efficiency was then calculated, using the ASME
Abbreviated Efficiency Test heat loss method, and the results compared
to evaluate the side effects of low NOX firing.  The results are
discussed in section 3.4.
                                IV-26

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                                w
IV-27

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      LU:
«M

LU

§
CD
      O i
                                         IV- 28

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              3.  FIELD TEST RESULTS AND DISCUSSION


          The field test results obtained on individual coal fired
boilers under a variety of operating conditions, are presented in four
parts,  These parts consist of gaseous emission measurements, flue gas
particulate loadings measured upstream of particulate collector equip-
ment, corrosion probing data obtained in accelerated furnace fire-side
water-tube corrosion tests, and estimated boiler performance.  Gaseous
emission data and most of the particulate emission data were obtained
tinder normal, as well as modified firing operation.  As discussed be-
fore, particulate loadings of the flue gas were determined only under
conditions corresponding to baseline and "low NOX" operation, for
purposes of comparison on the relative effect of modified combustion
operation on flue gas particulate loadings in coal combustion.  Simi-
lar considerations apply to the sustained, 300-hour corrosion tests,
which had as their objective the determination of whether staged fir-
ing of coal accelerates furnace water tube corrosion rates.

          The gaseous emission data obtained under baseline and modified
firing conditions at various load levels are presented first.  Through-
out this report, NOX concentrations are expressed as ppm, adjusted to
three percent 02 in the flue gas, on a dry basis.

          In addition to the results obtained in testing coal fired
boilers, this section also presents the gaseous emission data on two
mixed fuels (coal-gas and coal-oil) fired units, and an oil fired
gas turbine.

3.1  Gaseous Emission Results for Individual
     Power Generation Combustion Units	

          Test programs were conducted on 6 coal fired boilers
consisting of a rear-wall fired, an opposed-wall fired and four
tangentially fired boilers.  Two of the tangentially fired boilers
were equipped to fire mixed fuel, one on coal and gas and the other on
coal and oil.  Typical cross-sectional diagrams for these types of
boilers are shown in Appendix A.  Table 2-1 lists each boiler by
station and number, boiler manufacturer, type of firing, fuels burned,
full load MW rating, and number of burners.  In addition, the number
of operating test variables included in each test program and the
number of completed test runs are shown.

          In presenting the results and discussion for each of these
combustion units, we will first briefly describe the unit and the
reason for its selection; second, summarize the key operating variables
tested (load,  excess air level, staged firing patterns, etc.) and
resulting % 02 and PPM NOX emission data for each test run according
to the program experimental plan; and third, present figures to aid
in discussing analysis of test results.  Major conclusions and overall
findings will be presented in Section 4.
                              IV-29

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      3.1.1   Field  Test  Results -
             Widows Creek, Boiler No. 5

          Tennessee Valley Authority's Boiler No. 5 at the Widows
Creek Station was  the first boiler to be tested in our current field
test program.  A major reason for including this boiler in the test
program was  to obtain short-term (300 hour) corrosion data using Exxon
corrosion probes which will be correlated with six month corrosion
data based both on tube wall thickness measurements and coupon weight
measurements provided by TVA.  In addition, it provided TVA with an oppor-
tunity to compare  their newly acquired test van with our sampling and
analytical system.  It also gave us the first opportunity to test our
improved gaseous sampling conditioning system, our S02/S03 wet chemi-
cal analytical system and our new stratification probes.

          Widows Creek Unit No. 5 is a 125 MW, 16-burner, rear-wall,
pulverized coal fired Babcock and Wilcox boiler.  Although the boiler
was originally rated at 140 MW, full load is currently considered to
be 125 MW.   It has a single, dry-bottom furnace with a division wall.
The 16 burners are arranged with four burners in each of four rows.
Each row is  fed with coal from a separate pulverizer, designated "A"
for the top  row through "D" for the bottom row.  The burners are
numbered 1 through 4 on each row from left to right when facing the
rear wall (see Figure 3-2).

          Table 3-1 contains a summary of the key operating and
emission data from the 27 short-period test runs conducted on this
boiler.  Table 3-2 presents these results according to the test pro-
gram experimental design.  The four operating variables included in
the test program were gross load (125 and 100 MW), excess air level
(normal and  low), secondary air register setting (60% and 20% open)
and burner firing pattern (S± through 89).  The emission data shown
on Tables 3-1 and 3-2 are average % oxygen and ppm NOX (3% 62, dry
basis).  Four probes, each containing short, medium and long sampling
tubes were positioned at the centers of 12 equal areas in the flue
gas ducts upstream of the air prcheaters and downstream of the pri-
mary superheater.  Composite gas samples from each probe were analyzed
in turn over four complete cycles,  resulting in 16 measurements of
each gaseous component on each test run.

          Figure 3-1 contains a plot of ppm NOX (3% 02, dry basis) vs.
average % stoichiometric air to active burners.  Least squares lines
have been fitted to the data points for normal firing at 125 MW, nor-
mal firing at 100 MW and staged firing at 125 MW.  Test run numbers
are shown within the symbols which indicate different operating con-
ditions.  The test runs for the firing patterns that produced the
                           IV- 30

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                  Table  3-1

 Summary of  Operating and Emission Data -
 	Widows  Creek, Boiler No. 5	
(125 MW, Front  Wall, Pulverized Coal Fired)
Date
and
Run
No.
9/25-1
2
3
4
9/26-1A j
5 :
6 i
7
8 :
9/27-9
10
11
12
10/2-13
14
15
16
10/3-17
18
19
20
10/*.-21
22
23
24
10/7-1B
10/8-1C
Operating Conditions
Gross
Load
(MW)
105
118
120
121
121
121
117
119
120
115
110
112
120
102
98
98
97
99
100
99
100
99
100
100
101
125
125
Firing Pattern
(Burners on
Air Only)
S -None
S -None
S -None
S.-None
S -None
S2-(A1A4)
S3~(C1C4}
V(BlV
V(DlV
S5-(DlV
o/^vJj-iiJ. /
ft j^ fi
S3~(C1C4)
S2-(AlV
S1 -None
S -None
S1-None
S -None
S6-(A1A4D1D4)
S?-(A1A4B2B3)
Sg-(A1A4B1B4)
S9-(AlA2A3A4)
S9-(A1A4A3A2)
V(AlA4BlV
V(WlV
S?-(A1A4B2B3)
S.-None
3.,-None
Sec. Air
Registers
(% Open)
60
60
20
20
60
60
60
20
20
60
60
20
20
60
60
20
20
60
60
20
20
60
60
20
20
60
60
Excess
Air
Level
Normal
Low
Normal
Low
Normal
Low
Low
Low
Low
Low
Low
Low
Low
Normal
Low
Normal
Low
Low
Low
Low
Low
Low
Low
Low
Low
Low
Low
Flue Gas Measurements
%o2
5.4
3.2
3.5
3.2
4.0
3.0
4.8
3.6
3.6
3.4
4.0
4.1
3.2
5.5
3.0
5.4
2.1
3.2
3.0
3.3
5.3
4.5
4.4
4.3
3.3
2.4
2.5
PPM
NOx
(3% °2)
603
502
574
548
597
486
639
517
580
598
521
474
468
660
462
667
381
365
374
316
305
329
368
421
302
409
441
% Stoich. Air
to Active
Burners
134
117
119
117
123
101
113
105
105
104
108
108
102
135
116
134
110
88
87
88
100
94
94
93
88
112
113
                    IV- 31

-------
IV-

-------
                                        FIGURE  3-1

                          PPM NOX (3% 02. DRY)  VS % STOICHIOMETRIC
                          	AIR TO ACTIVE BURNERS	
                                (WIDOWS CREEK,  BOILER NO,  5)
700
   600
   500
   400
                                                  S2_5-125 MW
                                                               8^125 MW
fl
   :>oo
   200
   LOO -
             S6_9-100_MW
Firing Pattern
Symbol (Active /A£r)
O S1 (16/0)
C
J Sx (16/0)
A S2 (14/2)
A S3_5 (14/2)
D S6_g (12/4)

Sg (12/4)
Gross
Load
125
100
125
125
100
100
      80
               90
100
110
120
130
140
                       AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
                                          IV-33

-------
 lowest NOX emission levels among staging patterns with two burners on
 air only,  82,  and  four burners on air only, 89, are indicated by the
 larger traingles and larger squares, respectively.

           Baseline NO  emissions calculated from the least squares re-
 gression lines  for 120% stoichiometric air were 567 ppm and 506 ppm
 at  125 and 100 MW,  respectively.  These results are about 100 ppm
 lower  than the  results obtained in our previous field test program on
 "sister" boiler No.  6.  This difference is probably due to the differ-
 ent coals  fired and the fact that the inside walls of No. 5 furnace
 were much  cleaner  (less ash deposit) than the furnace walls of No. 6
 boiler when it  was  previously tested.

           Operation under low excess air conditions reduced NOX emis-
 sions  as shown by  the least squares line plotted on Figure 3-1.  A
 reduction  of 10% in % stoichiometric air to active burners (i.e., 120%
 to  110%) reduced NOX emissions by 21% under both full load (567 to
 447 ppm) and 100 MW load (493 to 388 ppm) under normal, 16 burner
 firing operation.

           Reducing  gross load from 125 to 100 MW (20% reduction) with
 normal excess air,  16 burner firing resulted in lowering calculated
 NOX emissions from  567 ppm to 493 ppm (13% reduction) at 120% stoich-
 iometric air.   Since the actual excess air level was increased during
 reduced load operation, actual NOX emissions were higher during re-
 duced  load, "normal" air operation than under normal air, full load
 operation.

           Staged firing test runs were conducted only at low excess
 air levels.  This procedure was used to allow us to test additional
 staged firing patterns within the same test period, and to concen-
 trate  on low excess air operation that produces minimum NOX emission
 rates.   The minimum level of excess air was determined by acceptable
 CO  emissions (less  than 200 ppm) and normal stack appearance.

           Four  staged firing patterns were tested at 125 MW load with
 two burners on  air only (14 active burners).  The lowest average NOX
 emissions were  measured with top row outer burners on air only (477
 ppm using  $2)•  The next lowest average NOX emissions were measured
with next  to top row wing burners on air only (519 ppm using SA)
while  83 and 85 staged firing patterns with next to bottom and bottom
 row wing burners on air only produced an average of 557 and 589 ppm
NOX emissions,  respectively.  Thus, there was a consistent pattern of
decreased NOx emissions as the "air only" burners were shifted from
"underfire" air on the bottom row to "overfire" air on the top row
of burners as shown by the top line of Figure 3-2.   Reducing secondary
air register settings from 60% open to 20% open on the active burners
                                 IV- 34

-------
                                   FIGURE 3-2
                     NOY EMISSIONS VS,  STAGED FIRING PATTERNS
                      . x    	,___________^^_—-———.—._^——

                           (WIDOWS CREEK NO,  5 UNIT)
vt
O
5-;
     600
     500
£   400
.X  300
                  A

                  B
                  C
                  D
1
0
0
0
0
2
o
O
O
o
3
O
0
O
O
4
O
O
O
O
                       BURNER
                    CONFIGURATION
FULL
LOAD
(125 MW)
©REDUCED
LOAD
(100
                             STAGED FIRING  PATTERNS
                                       IV-35

-------
consistently resulted In lowered NOx emissions on all 4 firing patterns
with an average reduction of 9%.  The best operating combination of
register setting and staged firing  (test run No. 12) produced an
average NOX emission level of 468 ppm which was 22% lower than the
597 ppm under actual base level operation (test run 1A).

          Four staged firing patterns were also tested at 100 MW load
with 4 burners on air only  (12 active burners).  The lowest average
NOX emission level  (317 ppm) was measured with the top row of burners
 (fed from A mill) on air only (S9).  The next to best NOX level (338 ppm)
was measured when operating with A^, ~&2> %, and A^ burners on air only,
(Sy).  Staged firing pattern Sg  (A-^, A^, B^ and 84 burners on air
only) produced NOX  emissions slightly higher than firing pattern 87,
while firing pattern Sg (A^, A^, Dj and D£ burners on air only) pro-
duced the highest average ppm NOX emission level of 393 ppm among the
4 burners off firing patterns.  Reducing secondary air register set-
tings from 60% open to 20% open on active burners reduced NO  emis-
sions by an average of 6% over these 4 firing patterns.  The best
combination of staged firing pattern (89) and air register setting
 (test run No. 20) produced a 305 ppm NOX emission level or about 49%
below full load, baseline operation.  The average NOX emission levels
for staged firing patterns 6-9 are plotted on Figure 3-2.

          Two factors appear to be responsible for lower NOX when
operating with secondary air register settings of 20% open on the
active burners.  The first one is that the overall level of excess
air can be lowered, and the second is that operating in this way
allows lower substoichiometric air supply to the active burners.

          The test  results obtained from boiler No. 5 were about as
expected based on the results obtained on the previously tested No.
6 unit and other front-wall fired boilers.  Each of the 4 operating
variables, load, excess air level, secondary air register setting
and firing pattern  has a significant effect on NOX emission levels.
From a full load, base level NOX emission level of 567 ppm (120%
stoichiometric air), low excess air operation reduced NOX emissions
by about 12% to 502 ppm.   Reducing load by 20% to 100 MW reduced NOX
emissions by 13%.   Low excess air, staged firing at full load reduced
NOX emissions to as low as 468 ppm when secondary air registers were
closed to 20% open.  Low excess air, staged firing at reduced load
(100 MW) reduced NO  emissions to as low as 305 ppm with A mill burn-
ers on air only and closed down secondary air registers.   The most
effective staged firing patterns are those that maximize the amount
of "overfire" air across the burner area.
                                  TV- 36

-------
     3.1.2  Ernest C. Gaston, Boiler No. 1
            (Southern Electric Genera/tine Company)

          Southern Electric Generating Company's Boiler No. 1 at the
Ernest C. Gaston Station, was the second boiler to be tested in our
current field test program.  The major reason for selecting this
boiler is that it has been retro-fitted with newly designed, low NOx
emission burners.  These burners, designed by Babcock and Wilcox,
produce a limited turbulence, controlled diffusion flame.  They are
designed to minimize the amount of fuel and air mixed at the burner
to that required to obtain Ignition and to sustain combustion of the
fuel.  Figure 3-3 presents a line diagram of the dual register
pulverized coal burners installed in Boiler No. 1.

          Gaston Units No. 1 and 2 are 270 MW, 18-burner, horizontally
opposed, pulverized coal fired Babcock and Wilcox boilers.  Two
division walls divide each furnace into 3 equal compartments, each
having six burners arranged 3 high in both the front and rear walls
of the furnace.  The furnace is 60 feet wide, with a volume of
139,500 cubic feet and a total wall area of 25,732 square feet.  Six
pulverizers (each with 36,000 pounds capacity) feed coal to 3 burners
each as shown in Figure 3-4.  The maximum continuous rating of each
boiler is 1,700,000 pounds of steam per hour.  Steam design pressure
at superheat outlet is 2,075 PSIG at 1000°F.  Steam design pressure
at reheater outlet is 495 PSIG at 1000°F.  Steam temperature controls
includes flue gas recirculation into the furnace and spray attemperators
for primary superheat and reheater.

          Table 3-3 contains a summary of the key operating and
emissions data.  Table 3-4 presents these results according to the
test program experimental design.  The five operating variables (and
experimental levels tested) included in the test program were:

          1.  Gross load (full load (270 MW), 250 MW and 190 MW to 205 MW)

          2.  Excess air level (high, normal and low).

          3.  Secondary air register setting (30, 50, 70 and 100% open).

          4.  Tertiary air register setting (50 and 100% open).

          5.  Firing pattern (all burners firing, 1 top mill off, 2 top
              mills off).

The emission data shown in Tables 3-3 and 3-4 are average % oxygen and
PPM NOX (3% 02, dry basis).  Four probes, each containing short, medium
and long sampling tubes were positioned near the centers of 12 equal
areas in the flue gas ducts between the economizer and the air preheaters.
                                IV-37

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                     FIGURE 3-4




             MILL-BURNER CONFIGURATION




         (E.G. Gas ton Boilers No. 1 and 2)
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                      IV-39

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 Composite  gas samples from each probe were analyzed and recorded in
 turn over  four complete cycles, resulting in 16 measurements of each
 gaseous component in each test run.  "Hie level of excess air on "low"
 excess air test runs was established as the minimum excess air level
 operation  that would not produce over 200 PPM CO emissions.

           Figure 3-5 is a plot of PPM NOX (3% 02, dry basis) vs.
 average %  stoichiometric air to active burners.  The numbers within
 the plotted symbols identify the run number from which the data were
 obtained.  Least squares, linear regression lines were calculated from
 the data points representing normal firing (Si) at 270 MW, normal firing
 at 205 MW, staged firing (S2 - top mill burners on air only on front or
 rear wall) at 250 MW and staged firing operation (83 - top mill burners
 of front and rear wall on air only) at 190 MW.

           Base-line NOx emissions calculated from the least squares
 regression lines shown on Figure 3-5 for 120% stoichiometric air were
 363 PPM and 279 PPM at 270 and 205 MW, respectively on Boiler No. 1 using
 the new low NOX burners.  Thus, a load reduction of 24% resulted in a 23%
 reduction  in NOX emissions.  From a full load, base level NOX emission
 level of 389 PPM (125% stoichiometric air), low excess air operating
 reduced NOX emissions by about 29% to 278 PPM.  Three staged firing
 patterns were tested:  E mill burners on air only (83)< E and B mill
burners on air only (83) and B mill burners on air only (84).  Low
 excess air, staged firing at 250 MW reduced NOX emissions to as low as
 240 PPM with B mill burners on air only (84).  Low excess air, staged
 firing at  a lower load of 190 MW reduced NOx emissions to as low as
 182 PPM with both E and B mill burners on air only (83).  Analysis of
 secondary  air register setting vs. NOX shows that the lowest NOX level
was reached when the register setting is approximately 70% open with
 lower and  higher settings give higher NOX levels.

          NOx measurements on Boiler No. 2 when operated at full load
 of 270 MW, averaged 595 PPM at 24% excess air.  Boiler No. 1 when operated
at full load of 270 MW, averaged 387 PPM at 24% excess air.  Therefore,
 the new dual register burners used in Boiler No. 1 reduced NOX emission
 levels (35% reduction) significantly, compared to conventional Babcock
 and Wilcox burners.

          A short term set of experimental runs were conducted to determine
 the effect of reduced pulverizer air temperature on NOX emissions.  At
 the normal operating temperature of 170°F, average NOX emission measured
 361 PPM (3.0% 02) while at a reduced temperature of 140°F, average NOX
 emissions measured 313 PPM (2.9% 02).  Thus, a 12% reduction in NOx
emissions  resulted from the use of lowered pulverizer air temperature.
Further experimentation would be necessary to determine if the reduced
 temperature operation would result in mill operating problems and to
validate these results over a longer time period with a variety of coals
and pulverizer settings.
                                    IV-42

-------
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                                   IV-43

-------
      3.1.3  Navajo Station,  Boiler No.  2
            SALT RIVER PROJECT	

          Navajo Unit  No. 2  is  a  twin furnace, 800 MW, Combustion
Engineering Boiler.  The two cell furnace has a volume of 465,500 cu. ft.,
width of 83 ft. 6-3/4  in. and front to  rear length of 40 ft. 10-1/4 in.
Maximum continuous rated primary  steam  flow is 5,400,000 lb./hr., at
1005 F, with a reheat  steam  flow  of 4,850,000 lb./hr. at 1003°F.  The
normal fuel fired is Black Mesa Sub-Bituminous coal with a higher heating
value of 10,725 BTU/lb., 10.4% ash, 10.3% moisture, 38% volatile material
and 41.4% carbon content.  At maximum continuous rating, 652,000 lb./hr.
coal if fired and a furnace  efficiency  of 88.77% is expected.  7 pulverizers
feed 56 burners arranged to  fire  at 7 different levels.  Overfire tilting
air ports are located above  the top row of burners.  Main steam pressure
is 3590 Ibs./sq. in.  at the  superheater outlet.

          Table 3-5 contains a summary of the major operating variables
and flue gas measurements for each of the 36 test runs completed on
Navajo No. 2 Unit.  Operating variables included in the experimental
program were gross load, excess air level, burner tilt, and firing
pattern.  Average % oxygen and ppm NOx  (3% 02, dry basis) are shown for
each test run.  Table 3-6 presents a summary of emission data (run no.,
% 02, ppm NOX) arranged according to the experimental design.  Figures 3-6
through 3-9 have been constructed to aid in the analysis of these data.

          Figure 3-6  is a plot of ppm NOx (3% 02, dry basis) vs. average
% oxygen measured in the flue gas for all test runs conducted at full
load with normal firing (Si).  Lines have been drawn to show the effect
of excess air level on NOx emission levels for +25°, +10 to +15°, 0°
and -10 to -15° burner tilts.  The effect of overfire cooling air
(about 10% open) has  no beneficial NOX reduction effect when the burners
are tilted up 25°.  However, as the burners are tilted towards horizontal
levels, the separation distance between the overfire cooling air and bulk
flames increases and improved NOx reductions are apparent.  Operating
with burner tilts at  -10 to  -15° produced higher NOx emission levels
than 0° tilt operation.  The least squares, regression line calculated
from the 7 test runs conducted at +10 to +15° burner tilt, (ppm NOX =
118 + 51% 02) showed an average reduction of 51 ppm NOX for each
reduction in flue gas oxygen content„

          Figure 3-7 is a plot of ppm NOX (3% 02, dry basis) vs. % oxygen
for the test runs conducted  at full load with overfire air dampers 100%
open  (87).  The least squares, regression line calculated from the 8 test
runs conducted with +10 to +15° burner  tilt (ppm NOx = 90 + 54% 02)
showed an average reduction  of 54 ppm NOx for each 1% reduction in
flue gas oxygen content,,  The average ppm NOx emission level for the 5
87 test runs conducted at the lowest excess air level (3.5 to 3.8% 02)
was 282 ppm or 17% below the 341  ppm NOX level for comparable excess air
S  test runs.
                                  IV-44

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-------
                                       Figure 3-6
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                          -• ~ "  X      £



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    350
cn
^x



o



S
    300
    250
                 -10  to -15

            Burner Tilt
                                                       +25   Burner Tilt
                                                                     +10 to +15°

                                                                       Burner Tilt
                                                         0° Burner Tilt
      3.0
                  3.5         4.0         4.5         5.0



                        Average % Oxygen Measured in Flue Gas
5.5
6.0
                                          IV-  47

-------
                                       Figure3-7


                        PPM NO^ (3% 02» Dry Basis)  va.  % Oxygen


               (Navajo No.  2 Boiler - S ,  Overfire  Air  Dampers 100% Open)
     500,.
     400-
 co
 *  300
I
    250
      3.0
                                              +10  to +15   Burner Tilt
                    I
                          I
                                                                     -10 to -15

                                                                     Burner Til
                                                              0   Burner Tilt
I
              3.5        4.0         4.5         5.0         5.5


                     Average % Oxygen Measured in Flue Gas
                       6.0
                                           IV-48

-------
          Figure 3-8 is a plot of ppm NOX vs. % oxygen for the $2, 84, 85
and Sg staged firing test runs.  The least squares line labeled Sj from
Figure 3-7 has been drawn on Figure 3-8 for comparison purposes.  Short lines
parallel to the 87 line have been drawn through the average data for 84,
85 and Sg test runs.  The lowest NOX emissions resulted from test runs
No. 7 and No. 8 conducted with the top tier of burners on air only ($2)
and cooling air through the overfire air registers.  The beneficial effect
of increasing overfire air register openings from 25% (84), 50% (85) to
75% (Sg) is apparent from examination of Figure 3-8.  However, Figure 3-9
has been constructed to present the effect of changing overfire air
register settings more directly.  Only test runs conducted with approximately
equal excess air levels (3.6 to 40% 02) and burner tilts (+10° to +15°)
are shown on Figure 3-9 so that the effect of overfire air settings on NOX
emission rates can be easily seen.  Average ppm NOX levels (and overfire
air register openings) decrease from 330 (25% OFA) to 318 (50% OFA) to
290 (75% OFA) to 283 (100% OFA).

          Table 3-6 below has been developed so that the effect of boiler
load on NOX emission levels can be estimated.  The first 5 columns provide
data pn the 3 test runs conducted at reduced loads of 565 to 305 MW.  The
fifth column lists NOX levels for full load operation at comparable excess
air levels and burner tilts from Figure 3-6.   The last column indicates the
% reduction in NOX levels obtained at the reduced loads.

                              TABLE 3-6

                         REDUCED LOAD TEST DATA
Run
No.

23
24
18D
  Gross
Load (MM)

   565
   565
   305
Burner
 Tilt

 +10°
 +30°
 +25°
5.3%
5.0%
4.6%
ppm
NO

350
404
349
Full Load
   NO
	x	
   388
   506
   474
Reduction

   10
   20
   26
in NO,
   Thus, a 29% reduction in load resulted in a 10 to 20% reduction
emission levels and a 52% reduction in load resulted in a 26%
reduction in NOx emission level.
                                  IV-49

-------
                           Figure 3-8



           PPM NO  (3% Oot Dry  Basis) vs. % Oxygen
                 '3C"""~     
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-------
                   PPM NO  vs^ Overfire Air  Dampers - Z Open
                   ^^™~ .  . --J£ I  II--III II   ILILILILILILILILlmlLILIBILIlm—UP J11UL JLILILILILILI • •  •,^_^^«^_^^^^_^^^ _  ^ (-._ _ -_

                      (Navajo No. 2 Boiler - Full Load)
    350
CO
S
CO
    250
                     I
I
                    20           40          60
                       Overfire Air Dampers - %  Open
            80
                         17J3.6% Oxygen
                         18)3.6% Oxygejn
                          18^3.7%
            Oxygen
100
                                        IV- 52

-------
3.1.4  Comanche Station, Boiler No. 1
       Public Service Co. of Colorado, Pueblo, Colorado

          Comanche Unit No. 1 is a single furnace, tangentially fired,
Combustion Engineering Boiler.  It was selected for this program because
it conforms to modern design practices and has overfire air ports  (OFA)
over the top level of burners for NOX emissions control.  The furnace
has a volume of 238,000 cu. ft., width of 45 ft. 4 in. and front to rear
length of 40 ft.  Maximum continuous rated primary steam flow at 2500
lb./in2 is 2,534,000 Ib./hr. at 1005°F with a reheat steam flow of
2,155,000 Ib./hr. at 1005°.  A Wyoming sub-bituminous coal is fired
with nominal values of 8,250 BTU/lb., 5.2% ash, 0,57% sulfur, 29% moisture,
32.4% fixed carbon and 33.4% volatile matter, and an ash fusion temperature
of 2150°F.  At maximum continuous rating (350 MW), 428,000 Ib./hr. coal
is fired and a furnace efficiency of 84.65% is predicted.  Five pulverizer
feed 20 burners firing at 5 levels (designated "A" for the top and "E"
at the bottom).

          This unit was the first pulverized coal fired boiler designed by
Combustion Engineering to have overfire air ports (through extended wind-
boxes) for reduced nitrogen oxides emission levels.  It also has a hot electro-
static precipitation for particulate collection.

          Table 3-8 contains a summary of the major operatimg variables
and flue gas measurements for each of the 30 test runs completed
on Comanche No. 1.  Operating variables included in the experimental
program were overfire air damper settings (closed to 100% open and horizontal
to -15° tilt), burner nozzle tilt (horizontal to -26°), secondary air reg-
ister settings (22-40% open auxiliary and 100% open coal registers) and boiler
load (316 to 340 MW).

          Several operating limitations were experienced due to load, weather
and boiler conditions.  July and August are peak load demand months and thus
only normal load variations were treated.  Only normal excess air operation
was used due to maximum ID fan capacity (economizer section blockage) and plant
operating management's desire to avoid possible slagging problems  (previously
encountered) that might be caused by low excess air operations.  Burner tilts
are normally operated at -20° from the horizontal to avoid high steam outlet tem-
perature and to reduce excess air level variations between flue gas economizer
outlet ducts to a minimum.  Thus, the burners were not tilted above horizontal.
Secondary air register settings at full load are varied automatically to
maintain a 4.5 to 5.0 in. H20 furnace to windbox differential by varying
auxiliary register settings, while the coal air registers are maintained
100% open.  Thus, if the overfire air registers are opened from 5%  (closed)
to 50% open, the auxiliary air registers automatically close to 22 to 26%
open from about 50% open.  Maximum gross load during our test period was
320 to 340 MW due to limited ID fan capacity mentioned above and poorer
than normal coal (up to 7% ash instead of 5%, ash content).  However,  in spite
                                   IV-53

-------
of these limitations most of the objectives of the test program have
been accomplished satisfactorly due to the excellent cooperation and
assistance of plant personnel.
          Table 3-8 contains average flue gas measurements of percent 02 and ppm
NOX  (3% 0£, dry basis) for each test run.  Flue gas samples were taken from
the centers of 6 equal areas from each of the two ducts ("A" and "B") between
the economizer and the hot-side precipitator.  Sixteen measurements were
made of each gaseous component during each 32 minute "steady state" test
run.

          Figure 3-10 is a plot of ppm NOX (3% 02, dry basis) vs. burner nozzle
tilt (degrees from horizontal).  The number within the symbols indicate the
test run.  Straight lines have been drawn through the data points obtained
from similar firing patterns to indicate the relationship between NO* emission
levels and burner tilts.  Baseline operations (normal firing pattern with
OFA ports closed) resulted in 410 PPM NOX when operating normally at -15° to
-20° burner tilts.  Horizontal burner operation reduced NOX emissions by
187. to 336 PPM, (Run 5) while lowering burner nozzle tilts to -26° increased
NOX emissions to 448 PPM (Run 3), or 9% above baseline operation.

          Operation of the overfire air registers, as expected, had a large
effect on NOX emission levels.  The three lines on Figure 3-10 drawn through
data from Si operation (closed OFA ports), 83 (257, open OFA ports) and S.
(50% open OFA ports), respectively, indicate the  reduction of NOX emission
levels as OFA port registers are opened.  Figure  3-11 is a plot of PPM KOx
emissions vs % open OFA registers for the data from test runs conducted at
the normal operating range of -15 to -20° burner nozzle tilts.  The solid
line drawn through these data points indicates that NOX emissions are reduced
sharply from 407 PPM with overfire air ports closed (5% open for cooling)
to 358 PPM with OFA ports 257. open to 289 PPM with 507. open OFA ports to a
level of 264 PPM NOX emissions when operating with 75 or 1007. open OFA ports.
Thus a 36% reduction in NOX emissions levels from baseline operations was
obtained through the use of overfire air ports.  Additional improvements
would be expected with low excess air operation and raised burner nozzle tilts
closer to a horizontal position.

          Excess air levels were maintained within "normal" levels during
the entire test period at Public Service Company's request to avoid possible
slagging problems.  Consequently,  test run average flue gas 02 measurements
varied within the narrow range of 3.5% to 4.4% making meaningful NOX vs 02
correlations difficult.  However,  as commonly found in tangentially fired
boilers,  average 02 measurements (and NOX measurements) from one duct (A)
were consistently lower than average 02 measurements (and NOX measurements)
from the other duct (B) on each test run.  This situation provided a means
for correlating NOX levels with 02 levels within test runs.  Figure 3-12 is a
plot of ppm NOX vs 02 data by flue gas duct for test runs 22 through 31.
02 measurements in Duct B averaged 2.2% higher than in Duct A, while NOX
measurements in Duct B were 27 PPM higher than in Duct A.  Although these
lines cannot represent the full NOX reduction potential of low excess air
operation, they indicate directionally the improvements that should be
obtainable.
                                IV- 54

-------
                                 PHASE I  EXPERIMENTAL TEST
 Date
  And
  Run
  No.

7/14/75

   1
   3
   5
   7

7/15/75

   9
  11
  13
  IS

7/16/75

   2
   4
  17
  18

7/17/75

   6

7/18/75

  20
   8
  21
  19

7/21/75

  22
  23
  24

7/22/75

  25
  26

7/23/7S

  27

1Z24/7S

  28

7/25/7S

  2*

7/2J/7S

  30
  31
                     Firing Pattern
Ho. of B
Firing
Coal
S.-20
s[-zo
s:-2o
Sj-20
S,-20
54-20
Ss-20
S6-20
S,-20
S}-20
83-20
S3-20
unmrm
Air
Only
None
Rone
None
None
None
None
None
None
None
None
None
None
Over Fire
I
Open^
Cloied
Cloied
Cloied
10%
25%
30%
751
100%
Cloied
Cloied
25%
25%
Air

Tilt
Horli.
Horlz.
Horiz.
Horlz.
-15°
-15°
-15°
-15°
-15°
-15'
-15°
-15°
          Sj-20
          8&-20
          S4-20
          84-20
                     None
                              ClOMd
                                          -15°
           None
           None
                               501
                     501
                     50t
su
84-20
SA-M
•t-20
                               501
                               SOX
                               501
                              Cloeed
                                         Hori*.
                               Horic.
                               Horlz.
                               Horli.
                               Horil.
Boric.
Horiz.
Horlz.

Burner
NoziU
Tilt
-14°
-26°
Horlz.
-16°
-17°
-17°
-17°
-18°
-16*
-18°
-26°
Horlz.

Excels
Air
Level
Nonel
Nonel
Normal
Normal
Honel
Normal
Sormal
Honel
Normal
Normal
Normal
Sormal
Secondary
Air Reg.
Aux/Coel
(% Open)
40/100
40/100
40/100
37/100
35/100
30/100
27.5/100
26.5/100
38/100
40/100
36/100
36/100

Groat
Load
OflO
340
334
340
340
335
335
333
332
332
331
331
332

N0r
C3J 02,
Dry Baiii)
391
448
336
373
355
306
261
266
404
417
383
308
                                                     -16°
                                                     -20°
                                           -21°
            -19°
            -20*
            -20°
-15°
-15'
-15*
                                                               Normal
S,-20
Sj-20
83-20
83-20
84-20
S.-20
S4-20
84-20
S4-20
None
None
None
None
None
None
None
None
None
251
Cloeed
251
251
501
501
SOI
sot
sn
Hori*.
Horiz.
Horiz.
Horiz.
Horlz.
Horlz.
Horli .
Horiz.
Horli.
-17°
-20°
-23°
-4°
Horii.
-13°
-25°
-15°
-18*
Nonel
Nonel
Nonel
Normal
Normal
Normal
Nonel
Nonal
Normal
                                                     Nonel
                                                     Normal
                                                     •onaal
                                                              •onwl
    al
Normel
                                                                  38/100
                                                                            29/100
                                                                            36/100
                                                                            33/100
                                                                            32/100
                                                                            26/100
                                                                            22/100
                                                                            22/100
                                                                            22/100
                                                                            24/100
                                                                  23/100
                                   22/100
                                   24/100
                       37/100
                       27/100
26/100
26/100
37/100
                                                                                        335
                                                                              323
                                                                              323
                                                                              321
                                                                              322
                                                                              322
                                                                              321
                                                                              316
                                                                              322
                                                                              321
                                                                             321
                                                                             322
                                                                             321
                         325
                         322
323
324
324
                                                                                         405
                                                           362
                                                           428
                                                           364
                                                           332
                                                           280
                                                           316
                                                           326
                                                           268
                                                           284
                                                                                         24S
                                                                                         259
                                                                                         289
                        380
                        271
                                                                                                     273
                                                                                                     275
                                                                                                     389
                                                                                                               Avg.
                                                                                                                3.9
                                                                                                                4.0
                                                                                                                3.7
                                                                                                                3.8
                                                                                                                4.1
                                                                                                                4.2
                                                                                                                3.7
                                                                                                                3.5
                                                                                                                3.8
                                                                                                                4.0
                                                                                                                4.0
                                                                                                                4.0
                                                                                                                3.7
                                                            3.9
                                                            3.8
                                                            3.9
                                                            4.0
                                                            4.0
                                                            4.2
                                                            4.4
                                                            4.2
                                                            4.1
                                                                                                      3.8
                                                                                                      3.8
                                                                                                      4.4
                         3.7
                         3.9
1.1
3.9
                                                     IV-55

-------
                                        FIGURE 3-10
                         PPM NOX  (3% 02 BASIS) VS BURNER TILT



                                (COMANCHE NO, 1 UNIT)
    450
    400
    350
    300
c



on
v_/


 X
Q.

D_
    250
                                                       Sj_ - NORMAL  FIRING  - OFA PORTS CLOSEI
    200
            S]



            s.
                                           S5 - OFA 75% OPEN
                       S6  - OFA 100%OPEN



             (NUMBERS  IN SYMBOLS INDICATE RUN NO,)



O CLOSED (5%  OPEN)



*_S 10% OPEN
    150 _
                    25% OPEN



               \f   50% OPEN



               ^J  75% OPEN
                   100%  OPEN
    lOOL

    -30C
                -25°         -20°         -15°         -10°           5e




                       BURNER  NOZZLE  TILTS  -  DEGREES FROM HORIZONTAL
                                              IV-56

-------
                                         FIGURE  3-11
    450
                           PPM NOX  (3% 02 BASIS) VS OFA  -  %  OPEN
                       (COMANCHE NO,  1  UNIT  -  -15  TO  -20  BURNER TILT)
    400
    350
CO
CO
    300
 x 250
    200
    150	
                         (NUMBERS WITHIN SYNBOLS  INDICATE RUN NO,)
    100
                                I
                I
1
                   20
  40           60         80

OVERFIRE AIR REGISTERS - % OPEN
           100
                                              IV-57

-------
                                       FIGURE  3-12
                         PPM NOX  (3% Q2 BASIS) VS  % OXYGEN
                        (COWNCHE NO, 1 UNIT-S4~50% OFA TORTS)
    400
    350
    300
 ™  250
o

?^
    200
    150
    100
            DUCT  B
                             DUCT "A"
                          (NUMBERS  IN CIRCLES  INDICATE RUN NO,)
                                I
I
                                                  1
                               345


                             AVERAGE % OXYGEN IN FLUE GAS
                                            IV-58

-------
     3.1.5  Barry Station, No. 2 Unit
            (Alabama Power Company)

          Alabama Power Company's Boiler No. 2 at the Barry Station was
the third boiler to be tested in our current field test program.  There
were two major reasons for selecting this boiler.  First, it is one of
very few boilers that has been retrofitted with overfire air ports for
NOx emission control.  The second reason for selecting this boiler was
that it is capable of firing gas (up to 40% of full load), coal and
mixed fuel firing.  To the best of our knowledge this is the only
United States boiler with these combined capabilities.  Figure 3-13 is a
side elevation view of the unit.

          Barry Station, Unit No. 2 is a natural circulation, balanced
draft boiler which fires coal through four elevations of tilting tangential
fuel nozzles.  Each elevation of burners is fired by a pulverizer.
The steam capacity at maximum continuous rating is 900,000 Ibs/hour
main stream flow with a superheat outlet temperature and pressure of
1000°F and 1875 PSIG, respectively.  Superheat and reheat temperatures
are controlled by burner tilt and water spray desuperheating.  The
furnace is 38 feet 2 inches wide and 28 feet lif inches in depth.  Two
wind boxes (upper and lower) feed secondary air through 10 compartments
(4 coal and 6 auxiliary) located at the four corners of the furnace.
Vertical burner spacing is 4* 11" from center line to center line between
elevations 1 to 2 and 3 to 4 with 7' 6" spacing between elevations 2 and 3.
Overfire air ports were designed to supply about 20% of total air through
new ducts located at each corner at 8 feet above the upper fuel zone as
well as through the top two compartments of the upper windbox.

          The experimental program was planned to produce required
emission and operating information on this unusually flexible boiler
from a minimum number of test runs.  The program was divided logically
into three experimental blocks, one at full load and two at reduced loads.
The prime objectives of the full load (130 MW) block were to obtain
baseline and modified combustion NOX emission levels while firing 100%
coal (Alabama and Illinois) as well as mixtures of gas and coal up to
the maximum gas firing capability of the boiler under both normal and
overfire air operation.  Test runs to evaluate the effect of excess air
level, burner nozzle tilt and secondary air register settings were also
included in the full load block.  The major objective of the reduced
load block at 95 MW was to compare the NOX reduction effectiveness of
overfire air port operation with modified staged operation (top row
of burners on air only).  95 MW is the maximum load capability of the
boiler with the top mill off.  To obtain information on NOX emissions
while firing 100% gas, test runs were conducted at the maximum load
possible (55 MW) while firing gas only.
                                  IV-59

-------
         Figure 3-13

     UNIT SIDE ELEVATION
ALABAMA POWER CO., BARRY NO. 2
                 1 V- 60

-------
          Table 3-9 contains a summary of the key operating and emission
data for the 37 short-period test runs completed on this unit.   Table 3-10
presents the average ppm NOX emissions (3% C>2, dry basis) and % oxygen
measurements for each test run according to the test program experimental
design.  The six operating variables (and experimental levels tested)
included in the test program were:

          1.  Gross load  (130 MW-full load), 95 MW and 55 MW)

          2.  Fuel fired  (Alabama coal, Illinois coal, mixed fuel and
              natural gas)

          3.  Excess air  level (normal and low)

          4.  Firing patterns (all coal levels firing with NO ports
              closed, 50% open and 100% open; top row coal off with
              NO ports closed and 50% open)

          5.  Burner tilt (horizontal, 20° up and 20° down)

          6.  Secondary air register setting  (coal/auxiliary air
              at 30/100 and 100/50 % opening)

Full Load Test Data Results - Barry No.  2 Unit

          Analysis of the NOX emission data from the full load test
block reveals several significant findings:
1.
    Full load, baseline operation (normal firing of all 16 burners,
    down or horizontal burner nozzle tilt and normal secondary air
    register settings) produced an average NOX emission level of
    341 ppm (3% 02, dry basis) while firing 100% coal.
2.
3.
4.
    Staged firing using the special overfire air ports reduced
    emissions by 10 to 20% from baseline operation at equal excess
    air levels.  100% open overfire air ports produced lower NOx emissions
    than 50% open operation.

    Excess air level was the most significant single operating variable
    affecting NOx emission levels.  NOx emissions were reduced through
    low excess air operation by 43% to 196 ppm under normal (S^)
    firing operation, by 39% under staged firing operation, S2 (50%
    open overfire air ports) and by 29% under staged firing operation
    S3 (100% open overfire air ports) .  The solid regression lines on
    Figure 2 indicate the relationship between ppm NOx and average %
    oxygen in the flue gas for these three firing patterns while
    firing 100% coal and operating with horizontal or down burner tilts
    and normal secondary air register settings.

    Normal secondary air operation (30% open coal air and 100% open
    auxiliary air registers) produced an average of about 10% lower
    NOx emissions than reversed secondary air operation (100% coal air
    and 50% open auxiliary air registers) when firing 100% coal.
                                   IV-61

-------
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                                        FIGURE 3-14
                        PPM MOX (3%  02,  DRY)  VS % 02 IN FLUE GAS


                      (100% COAL FIRED TEST RUNS - BARRY MO,  2 UNIT)
    ADO -
C/3
    300 —
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     200
                                                                            31

                                                                             s.
FULL LOAD  /
TEST RUNS/
AT 130 M/
                                                                           w
                                                                                  REDUCED
                                                                                   LOAD
                                                                                 TEST RUNS
                                                                                 AT 95 m
                       RUNS
                                                                       OFA CLOSED

                                                                       OFA  50% OPEN

                                                                       OFA 100% OPEN
                                                                       V AIR ONLY
                                                                       "A" AIR ONLY
                                                                       OFA  50% OPEN
     100
                                1
J_
                                456

                                AVERAGE % OXYGEN  IN  FLUE GAS
                                             t V-65

-------
     Burner nozzle tilt  over  the  range  of  -20°  to  horizontal produced
     no consistent change  in  NOX  emission  levels.  However,  raising
     burner nozzle tilts to +20°  resulted  in  significantly higher NOx
     emission levels.  This effect  can  be  explained by  the fact  that
     the overfire  air  directional dampers  were  fired at -11° and thus
     the effectiveness of  staged  combustion was reduced with raised
     burner tilts  due  to reduced  separation of  overfire air  from the
     main combustion mixture.

     Mixed fuel  tiring at  full  load reduced NOx emissions significantly.
     Figure 3-15 is a  plot of ppm NOX (3%  02, dry) vs % coal in fuel for
     comparable  full load  test  runs under  normal firing, Si, and staged
     firing (S2  and S3)  operations.  Firing with 80% of the  heat release
     from coal firing  reduced NOx emissions by  an  average of 30% while
     firing with 60% coal  resulted  in an average of 32% NOx  reduction
     from 100% coal firing over the three  firing patterns.   Thus, within
     the range of  full load,  mixed  fuel firing  capability of this boiler,
     the data indicates  that  replacing  coal with gas fuel lowers NOx in
     the direction of  full gas  firing but  the relationship is not linear.
     As discussed  below  at reduced  load (55 MW), firing with 100% gas,
     reduced NOX emissions from 269 to  110 ppm  (60%) compared to 100%
     coal firing.   A comparable linear  relationship at full  load would
     thus be a 12% reduction  in NOx emissions when firing 80% coal-20%
     mixture and a 24% reduction  when firing  a  mixture of 60% coal-40% gas,
Reduced Load Tests

          Earlier, we discussed the necessity for conducting
two test program blocks at reduced load.  The first block (comprising
7 100% coal fired test runs) was conducted in order to obtain
information on the NOX emission reduction effectiveness of staged combustion
using overfire air ducts compared to modified staged combustion operation
where the top tier of burners are on air only.  Since the maximum capacity
of the boiler with the top mill inactive is 95 MW, all of these runs were
made at this load for comparative reasons.  The second block (4 test runs)
was conducted at the maximum load capacity of this boiler (55 MW)  when
firing with gas alone.

          Reduced load test runs at 95 MW were conducted under normal,
all burners firing operation and at three different staged firing operations:
82, overfire air port dampers set at 50% open and all four levels of burners
firing; 84, overfire air port dampers closed (cooling air only) with top
tier of burners on air only; and 85, overfire air dampers 50% open and top
tier of burners on air only.

          The dashed lines on Figure 3-14,  labeled 82,  84 and 85 Join the
normal excess air and low excess air NOX emission data points for each
of these staged firing operations for visual comparison with the full load
test results discussed above.  These results cam be summarized as  follows:
                                   IV-66

-------
    400
    300
o

en
Q.
CL
    200
                                       FIGURE  3-15
                PPM NOX  (3% Q2> DRY) VS  % COAL IN  COAL-GAS MIXED FUEL FIRING


                           (BARRY NO,  2  UNIT-FULL  LOAD TEST RUNS)
                                                                    26)-5.4%
    100
                                                            O  NORMAL FIRING - S][
                                                                 50%  OPEN OFA PORTS - S0
                                                                100% OPEN OFA PORTS - S.
                                I
                         I
                           I
       0
20
  40          60          80


COAL IN COAL-GAS MIXED FUEL FIRING



                IV- 67
100

-------
1.  Baseline NOX emissions were 452 ppm at the higher excess level required
    under reduced load operation.

2.  Low excess air operation reduced NOX emissions sharply in all three
    staged firing configurations compared to normal excess air levels as
    shown by the dashed lines in Figure 3-14.

3.  As expected all three staged firing operations resulted in significantly
    lowered NOX emission levels with the combined use of overfire air and
    top row of burners on air only producing the best results.  Compared
    to the 95 MW, baseline NOX emission level of 452 ppm, low excess air,
    $2 operation (overfire air ports % open) reduced NOX emissions by 44%
    (to 253 ppm); low excess air, 84 (top burners on air only) operation
    reduced NOX emissions by 53% (to 212 ppm) and low excess air, 85 operation
    (50% open overfire air ports plus top row of burners on air only) reduced
    NOX emissions by 58% to 192 ppm.

          The second set of reduced load test runs (numbered 13 through 16)
were designed to supply information on 100% gaseous fuel firing
compared to 100% coal firing under both normal and low excess air operation.
Under normal operation at 55 MW load, coal was fired through the bottom
two rows of burners with relatively high excess air levels.  Baseline NOX
emissions of 284 ppm were reduced to 254 ppm with low excess air operation.
100% gas firing operation produced 122 ppm NOX under normal excess air
levels and 97 ppm when using low excess air operation.  Thus, at this low
load, gas firing resulted in a 57% NOX emission reduction under normal air
operation and a 62% NOX emission reduction under low excess air operation
compared to 100% coal firing.
                                 IV-68

-------
     3.1.6  Morgantown, Boiler No. 1
            (Potomac Electric Power Company)

          Potomac Electric Power Company's, Boiler No. 1 at Morgantown, Md.
was the fourth boiler to be tested in our current field test program.
This boiler was selected, with the assistance of Combustion Engineering
Company, because it represents modern design practices and has the
capability of firing oil, pulverized coal or mixtures of the two fuels.

          Morgantown Boiler No. 1 is a 575 MW, Combustion Engineering,
tangentially fired, twin furnace boiler.  Five pulverizers feed 40 burners
arranged at 5 levels (A feeding top 8 burners to E feeding the bottom 8
burners).  32 oil burners are positioned at the four levels (8 per level)
between the five pulverized coal burner levels, i.e., between A and B,
B and C, C and D and D and E.  The furnace has a volume of 292,600 cubic
feet, a width of 63.15 feet and a length of 34.45 feet.  Full load steam
rate is 4,250,000 pounds/hour at 1005 F superheat temperature and 3810
PSIG pressure.

          Table 3-11 contains a summary of the operating and emission data
from the 27 test runs completed on the boiler,,  Table 3-12 presents these
results arranged according to the test program experimental design.  The
five operating variables (and experimental levels) included in the test
program were:

          1.  Gross load (full load - 575 MW, and reduced load - 300 MW)

          2.  Excess air level (normal, low and high)

          3.  Fuel mixture fired (100% coal to 100% oil)

          4.  Burner tilt (horizontal, +15°, -15°)

          5.  Firing pattern (normal firing - S1, and staged firing - S_)

Flue gas measurements of average % 02 and ppm NOjj (3% 02, dry) are
included in Table 3-11 as well as the calculated % stoichiometric air to the
active burners.  The flue gas sampling system consisted of four probes,
each containing short, medium and long sampling tubes positioned at the
centers of 12 equal areas in the ducts between the economizer and the air
heaters.  Composite gas samples from each probe were analyzed and recorded
in turn over four complete cycles, resulting in 16 measurements of each
gaseous component in each test run.

          Three figures have been constructed using identical coordinate
scales to aid in visual analysis of the data.  Figure 3-16 is a plot of ppm
NO  (3% 02, dry basis) vs % coal (heat release basis) in the coal-oil
mixed fuel firing for test runs conducted at full load under normal firing
conditions (no overfire air).  Figure 3-17 is a plot of test runs conducted
under full load, staged firing (air only at top pulverized coal burner
level) operation.  Figure 3-18 is a plot of test runs conducted at reduced
load (about 300 MW) under both normal and staged firing operation.  The
                                    IV-69

-------
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                     PPM NO^ vs % Coal in Coal/Oil Mixed Fuel Firing


                            (Full Load, Normal Firing Pattern)
                                                                   Normal Excess

                                                                        Air
                                                                   Low Excess

                                                                      Air
     100
                   20
                          40
60
80
100
                             Coal in Oil-Coal Mixed Fuel Firing
                                       IV- 72

-------
     600
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                                         Figure  3-17


                      PPM NO  vs % Coal  in Coal/Oil Mixed Fuel Firing


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                    20
                                                   Normal Excess Air
                                       Low Excess Air
                                40
60
80
100
                           % Coal in Coal/Oil Mixed Fuel Firing
                                        IV- 73

-------
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                                       Figure 3-18


                    PPM NO  vs % Coal in Coal/Oil Mixed Fuel Firing


                        (Reduced Load - Normal and Staged Firing)
                                                                         Nonnal
                                                                         Excess
                                                                          Air
                                                                          Low
                                                                         Excess"
                                                                          Air
                                                     Normal Firing Pattern
                                             Normal Excess Air
                              Staged Firing Pattern
         20J*—Low Excess Air
                    20
                           40
60
80
100
                            Coal in Coal/Oil Mixed Fuel Firing
                                          IV- 74

-------
numbers shown within circles (normal excess air operation) or squares
(low excess air operation) indicate test run identification numbers.
The conclusions reached from analysis of the data are summarized in the
following paragraphs.

          Low excess air operation (established by the maximum level of
CO emissions (200 ppm) from any single probe) consistently reduced NOX
emissions compared to normal excess air operation.  Under full load
(575 MW) operation the average reduction in NOX emissions was 10% under
normal firing operation and 18% under staged firing operation.  At reduced
load (300 MW), reductions of 5 and 10% were experienced under normal firing
and staged firing, respectfully.  Lines have been drawn through the normal
excess air and low excess air test run data on Figures 3-16 and 3-17 to
facilitate this comparison.

          Staged firing operation (top mill burners on air only) produced
substantially lower NOX emission levels than normal firing operation
(top mill burners firing coal) under both full load and reduced load operation
over a wide range of mixed fuels.  Reductions of 18%, 19% and 32% were
experienced at full load when firing with mixed fuels containing 22% coal,
49% coal and 73% coal, respectively, under normal excess air, staged firing
operation compared to normal excess air, normal firing operation.  The
combination of low excess air and staged firing resulted in further
improvements.  At reduced load (300 MW), NOX emission reductions of 26 to
40% were obtained through staged firing operation compared to normal firing
operation.
          Changing coal burner nozzle tilts had a minor effect on NOX
emissions when firing mixed fuels since the oil burners were fired in a
horizontal position.  Horizontal burner tilts resulted in about 6% lower
NOX emissions than 15
up or down tilting burners.
          Reduced load operation (300 vs 575 MW) resulted in lowered NOX
emissions.  However, the size of the reduction was highly dependent upon
the amount of oil in the coal-oil mixture fired.  While firing mostly
coal (93% at full load and 100% at reduced load), NOX emissions were
reduced an average of only 4%.  However, reducing load while firing 22 to
55% oil in oil/coal mixtures, reduced NOX emissions by 26% under normal
firing and 35% under staged firing.

          NOX emission levels generally increased with increased % coal
in mixed fuel firing.  Figure 3-18 shows this trend over almost the full range
of fuel mixtures under normal firing operation at reduced load.  A straight
line through the NOX data point from test run 25 (100% coal firing) and
test run 21A (5% coal firing) does not pass through the NOX data points for
                                   IV- 75

-------
intermediate mixtures of coal-oil fuel.  Thus, test run 22A (43% coal - 57%
oil fired) emitted 13% higher NOX emissions and test run 24 (62% coal -
38% oil fired) produced 9% higher NOX emission than would be expected from
a linear relationship calculated from 100% coal and 100% oil firing.
Figure 3-16 shows a pronounced variation from a linear relationship for mixed
fuel firing over the range from 22% coal to 93% coal.  Increasing the
percentage coal in the coal-oil mixture from 22% to 45 or 49% resulted
in significantly increased NOX emission rates  (over 100 ppm) but little change
in NO  emission rates occurred with further increases in the % coal fired.
Unfortunately, during the test period, this boiler had limited fuel burning
capability, and therefore, full load test runs on 100% coal or 100% oil
could not be run.  Only 21 of the 32 oil burners were operational due to
mechanical problems, and therefore, 22% of the heat release had to be
supplied from coal»  At the same time, coal supplies were short and some
coal handling equipment could not be operated.  Consequently, operating
management limited the length of time that high coal mixtures could be
burned as well as the maximum coal content of the mixed fuel.

          In summary, we have found that most of the operating variables
included in the experimental program had significant effects on NOX
emission levels.  Low excess air operation reduced NOx emissions by about
10% for a wide range of oil-fuel mixtures at full and reduced load.  Staged
firing operation resulted in 20 to 30% NOx emission reductions over a wide
range of coal/oil fuel mixtures.  Combined low excess air and staged firing
operation reduced NOX by 30 to 40%.  Tilting burners over the range of
+15° to -15° produced minor changes in NOx levels with horizontal levels
producing the lowest NOx emission levels.   Increasing the proportion of
coal in simultaneous oil/coal firing increased NOx emission levels
non-linearly under both normal and staged firing operation.  The NOX
emission level increase was higher in changing from 0% to 50% coal, than
the NOX emission increase when changing from 50% to 100% coal fuel.  It
is possible that such behavior is exhibited because of the relative
contributions of thermal NOX and fuel NOX to the total emissions.
                                 IV-76

-------
     3.1.7  Morgantown, G.E. No. 3 Gas Turbine
            (Potomac Electric Company)

          Potomac Electric Company's G.E. Gas Turbine No. 3 is the
first gas turbine to be tested in our current field test program.
This General Electric model MS 7001 B Gas Turbine is of modern
design and has a maximum continuous rating of 50 MW and a peak
output of 54 MW.  It fires No. 2 distillate oil and is not equipped
for water injection.

          Flue gas samples were taken from the centers of four equal
rectangular areas from each of two stacks and from the centers of each
of the stacks in order that possible stratification could be measured
and to obtain representative flue gas samples.  12 to 18 measurements
were recorded during the 15 to 20 minute duration of each test run.
                            TABLE  3-13

             SUMMARY OF OPERATING  AND EMISSION DATA -
           MORGANTOWN STATION, G.E. GAS TURBINE NO. 3
I
i Bs.te and
I Run No.
" i-fl/75
1
1 2
1 3
; 4
Operating Conditions
Gross Load
(MW)

10
25
48
54
Fuel Flow
(GPM)

33
47
74
81
Exhaust
Temp. (°F)

621
640
905
980
Flue Gas Measurements
% 0


17.9
17.3
15.2
14.7
PPM NO.^ (Dry Basis)
15% 00

82
108
125
133
3% On

247
322
376
398
          Table 3-13 contains a summary of the major operating and
emission data obtained from this test program.  Figure 3-19 presents
the PPM NOX (dry basis) vs Gross Load (MW) data on both a 3% and a
15% 02 correction basis.  As expected, the NOX emission level
increases with load, but not very sharply up to the peak load of
54 MW.

          Measured gaseous concentration stratification was very low
from the stacks of this gas turbine.  For example, the maximum
variation in the 18% oxygen measurements in run number 1 was 17.8 to
18.0%.  The major causes of low stratification was the high velocity
of the flue gas through the long path of ductwork (about 130 feet)
in the switchback silencer and the location of the sample tubes four
diameters from the nearest upstream disturbance.
                                 IV- 77

-------
I
                                            Figure 3-19



                  PPM NO  (3% and 15% 00>  Dry Basis) vs Gross Load  (MW)
                         X              '£,                               "~~


                              (Morgantown No.  3 Gas Turbine)
         40C
    03

    1-t

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    £>
   o
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   PL,
300-
200
                                                                            3% 0,,  Basis
        100
                        10
                            20          30
                                        Gross  Load (MW)
40
50
60
                                            IV- 78

-------
3.2  Particulate Emission Results

          As mentioned in section 2.5, the manner in which the
combustion process occurs using known modifications to limit "NOX"
emissions has a very real tendency to increase burnout problems.
Potentially, burnout problems could adversely affect particulate
emissions which, as a consequence, could decrease precipitator
collection efficiency.  Marginal boiler installations as a result,
therefore, might find it difficult to comply with existing Federal or
State particulate emission regulations under "low NOX" operating
conditions.  Accordingly, the objective of this investigation was to
obtain sufficient data to afford a comparison of the effects of "low NOx"
firing techniques on particulate emissions by comparing measurements of
total quantities, percent unburned carbon, and particle size distribution
with similar data obtained under baseline operation.  Particulate emission
test results obtained in this program are summarized in Tables 3-14, 3-15,
3-16 and 3-17.  The data appear to be reliable and consistent within the
accuracy of this type of testing.  An assessment of any adverse side
effects of "low NOX" operation is possible by a comparison of the
differences in emission values tabulated in the above tables between
baseline and "low NOX" operation.

          In our previous field study (_2), some "side effects" were
noted with "low NOX" firing in that total quantities of particulate
tended to increase but the increases did not appear to be significant
and the effects, if any, appeared to be minor.  Results obtained in
the current program, as exhibited in Table 3-14, showed a similar
tendency for particulate loading to increase on two boilers but,
interestingly, the other two boilers tested exhibited a decrease in
dust loading under low NOX operation.  Again, however, the differences
are relatively minor and probably of little consequence.  An increase in
total particulates would tend to have an adverse effect on electrostatic
precipitator efficiency in meeting Federal or State emission standards.
Conversely, decreases would make it easier to meet standards.

          Carbon loss or unburned combustibles is another potential
side effect of "low NOX" operation.  As indicated in section 2.5, this
could be the result of the tendency toward incomplete combustion or
burnout problems.  Any increase in unburned carbon as a consequence
of "low NOX" combustion modifications affecting the complete utilization
of the fuel fired, obviously, would have a corresponding decreasing
effect on boiler efficiency.  An assessment of the magnitude of this
potential "side effect" is provided from the data tabulated in Table 3-14
by comparing the percent carbon on the particulate between baseline and
low NOX operation.  Referring to Table A, it may be noted that the
carbon content of the particulate, in most cases, decreased under
"low NOX" operating conditions.  This differs from the findings in
                                  IV- 79

-------
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-------
the previous program where increases were noted for "low NOX" firing
conditions, especially in front wall and horizontally opposed fired
boilers.  There is also an indication that participate carbon content
may decrease slightly under "low NOX" conditions in tangentially fired
boilers.  The differences in the data, however, are not statistically
significant and more information would be required to firm up this
point.  Carbon losses in boilers fired with Western coals, as in prior
findings, have again been noted to be very low, attesting to the easy
burnability of these coals.  The effect of the changes in unburned
combustibles on boiler efficiency is discussed in section 3.4 and is
shown to be relatively minor.

          Investigations into potential changes in particle
size distribution was included in the current program in an effort to
determine whether there might be any adverse side effects with "low NOX"
firing.  Potentially, changes in the fine particle sizes could materially
affect electrostatic precipitator collection efficiency which in
borderline cases might inhibit compliance with emission standards.
Tables 3-15, 3-16 and 3-17, respectively summarize the particle size
distribution data developed in this study.  Test data were obtained
upstream of the electrostatic precipitators using a Brink multi-stage
cascade impactor incorporated in an EPA type particulate sampling train,
as described in section 2.5.  Cut-off points in the Brink impactor
were 2.5, 2.0, 1.5, 1.0, 0.5 and 0.25 microns.  Particle size
distribution data reported in Tables 3-15, 3-16 and 3-17 include all
material collected in the probe and the cyclone in the distribtuion
fraction greater than 2.5 microns.  Comparing the data in Tables 3-15
and 3-16, it may be seen that there are no significant differences in
particle size distribution between "low NOX" and baseline operation
for the two boilers tested.  In Table 3-17, however, major increases
are indicated for the smaller size fractions with "low NOX" firing which
would adversely affect precipitator collection efficiency on the boiler
tested.  The significance of the latter data, however, is open to serious
question, first, due to the relatively small size of the sample obtained
in these tests in the Brinks impactor and, second, because of the problems
with leaks in the sampling equipment prevalent in these tests which were
rectified in later tests.  More particle size distribution data which
are in the process of being developed are needed to resolve this
question.
                                IV- 34

-------
3.3  Cprrpsion Probing Results

          In the current program significant changes were made in the
conditions for obtaining corrosion rate data in an effort to better
relate rates obtained on corrosion probes to actual furnace wall tube
corrosion.  In the prior investigation, corrosion rates averaged
approximately 50 mils per year with considerable scatter between high
and low values.  Apparently, these high rates were influenced by the
high exposure temperature of 875°F and the mild acid pickling of the
coupons prior to exposure which it is now believed resulted in high
initial corrosion.  In this program, coupon temperatures were controlled
at temperatures approximating the furnace tube temperature (about 725°F)
and the acid pickling procedure was eliminated.  As a result corrosion
rates obtained (discussed later), were considerably lower and more
consistent in value.  All other test procedures were kept the same,
i.e., probes were installed through openings as close as possible to
vulnerable furnace areas, exposure was maintained the same at
approximately 300 hours, coupons were removed, cleaned ultrasonically
with glass beads, re-weighed and corrosion rates calculated all in
accordance with prior procedures established for these tests.  Total
weight loss data were converted to corrosion rates on a mil per year
basis using the combined inner and outer coupon areas previously found
to give most consistent results, coupon material density and exposure
time.

          Corrosion rates have been determined on 36 coupons installed
on 12 probes (3 coupons/probe) in 6 boilers at three different generating
stations firing pulverized coal.  Additional tests have also been run at
another pulverized coal fired power plant with 4 probes (12 coupons) but
results are not yet available.

          The data obtained in this program are tabulated in Tables 3-18,
3-19 and 3-20.  Referring to these tables it may be observed that in most
cases the corrosion rates obtained varied between approximately 10 and
15 mils per year.  These rates are considerably lower than those
obtained in the previous program under accelerated conditions but they
are still an order of magnitude greater than the 1 to 3 mils per year
corrosion which might be expected on actual furnace tubes, so prediction
or relation of results obtained on probes to what might be expected in
an existing furnace is still difficult.  Data developed in the prior
program averaged approximately 50 mils per year corrosion with
considerable scatter in the data.  The lower and remarkably more
consistent rates obtained in this progam reflect the changes made in
test procedures to more closely approximate actual furnace wall tube
conditions.
                              1V-85

-------
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          Referring to Table 3-20 it may be noted that the coupons on
probes No. 1 and No. 3 indicate higher corrosion rates than those on
probes No. 2 and 4, respectively.  Undoubtedly, this was due to some
of the metal having been removed on these coupons in the disassembling
procedure caused by the galling of the threads between coupons.  The
indicated rate of corrosion for these coupons, therefore, should be
used with caution.

          The major conclusion from these data is that no major
differences in accelerated corrosion rates can be observed for coupons
exposed to "low NOX" firing conditions compared to those subjected to
baseline or normal combustion.

          A comparison of corrosion experienced in long term tests
(6 months plus) on existing furnace tubes with corrosion probe data
obtained in the same furnace is also of paramount importance, and
therefore such information will be obtained in future tests.
                               IV-89

-------

3.4  Boiler Performance Results

          The prior NOx field tests indicated a tendency for particulate
carbon content to increase substantially under low NOx operating
conditions, especially on front wall or horizontally opposed fired
boilers.  Potentially an increase in unburned carbon could result in
lowered boiler efficiency but this adverse side effect did not materialize
in the previous study because the debit, at least partially, was offset
by the increased efficiency resulting from lower excess air operation
at low NOX conditions.  In this study the side effects of "low NOX"
operating techniques on boiler performance were investigated and
evaluated for each major test where particulate data were obtained
under baseline and optimum "low NOx" conditions.  Control room board
data and other pertinent information representative of each test run
were recorded and boiler performance (efficiency) was calculated
following the ASME Steam Generating Units, Power Test Codes using the
Abbreviated Efficiency Test, heat loss method.  Calculations were based
on the assumption that fly ash and bottom ash combustible content were
the same and unmeasured losses were 0.5 percent.  An example of typical
performance data and the calculations made are shown in ASME test forms
in Tables 3-21 and 3-22.

          Table 3-23 tabulates the boiler efficiency calculated for
each test along with other pertinent boiler performance information.
Differences in calculated boiler efficiency between baseline and "low NOX"
tests provide a comparison of any debit or credit accruing to "low NOX"
operating conditions.  These comparisons, however, must be weighed
against other confounding factors, such as, differences in coal ash
content, coal BTU content, boiler load, excess air levels, carbon
content on particulate, etc. for each test run.  Boiler efficiency,
in general, increases with load and decreases with increases in coal
ash or unburned combustible content of the particulate.

          Referring to Table 3-23, it may be noted that there are no
debits to "low NOX" operation which decrease boiler efficiency materially.
In fact, quite the opposite is indicated as reflected by the Tennessee
Valley Authority and Salt River Project test data where increases in
efficiency are evident under low NOX firing due to decreases in
uncombustible losses, lower coal ash, and excess air levels.  Differences
in boiler efficiency are also inconsequential with "low NOX" operation
where carbon losses increased substantially, as in the Southern Electric
Company example.  Here debits to low NOX emission reduction techniques
are offset by decreases in coal ash content and slightly lower excess
air operating levels.
                             IV- 90

-------
                                          TABLE 3-21
SUMMARY SHEET
         ASME  TEST  FORM
FOR  ABBREVIATED EFFICIENCY TEST
                                                                          PTC 4.1-0(1964}
TEST NO. 1A BOILER NO. 6
DATE4-18-72
Q#NER OF PLANT TVA^ LOCATION Widows Creek
TEST CONDUCTED BY Esso Research & Engineering Co. OBJECTIVE OF TEST Boiler Performanc®uRATic*i Hrs.
BOILER, MAKE «. TYPE B&W Radiant RATED CAPACITY ^25 ^j
STOKER, TYPE & SIZE
PULVERIZER. TYPE & SIZE Type E BURNER, TYPE
FUEL USED Bituminous Coal MINE COUNTY STATE

& SIZE
SIZE AS FIRED
PRESSURES & TEMPERATURES FUEL DATA
1
2
3
4
5
6
7
8
. 9
10
11
12
_!!..
STEAM PRESSURE IN BOILER DRUM
L STEAM PRESSURE AT S. H. OUTLET
STEAM PRESSURE AT R. H. INLET
STEAM PRESSURE AT R. H. OUTLET
STEAM TEMPERATURE AT S. H. OUTLET
STEAM TEMPERATURE AT R.H. INLET
STEAM TEMPERATURE AT R.H. OUTLET
WATER TEMP. ENTERING (ECON. l(BOILER)
STEAM QUALITY'S MOISTURE OR P. P.M.
AIR TEMP. AROUND BOILER (AMBIENT)
TEMP. AIR FOR COMBUSTION
TEMPERATURE OF FUEL
GAS TEMP.LEAVING (Boiler) (Econ.) (Air Hlr.)
GAS TEMP. ENTERING AH (II condition! to be
psto
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.
F
F
F
F

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F
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UNIT QUANTITIES
15
16
17
18
19
20
21
22
23
24
25
ENTHALPY OF SAT. LIQUID (TOTAL HEAT)
ENTHALPY OF (SATURATED) (SUPERHEATED)
STM.
ENTHALPY OF SAT. FEED TO (BOILER)
(ECON.)
ENTHALPY OF REHEATED STEAM R.H. INLET
ENTHALPY OF REHEATED STEAM R. H.
OUTLET
HEAT ABS/LBOF STEAM (ITEM 16-ITEM 17)
HEAT ABS/LB R.H. STEAM(ITEM 19-lTEM 18)
DRY REFUSE (ASH PIT * FLY ASH) PER LB
AS FIREO FUEL
Btu PER LB IN REFUSE (WEIGHTED AVERAGE)
CARBON BURNED PER LB AS FIRED FUEL
DRY GAS PER LB AS FIRED FUEL BURNED
Bru/lb
Btu/lb
Blu/lb
3fu/lb
Btu/lb
Blu/lb
Blu/lb
Ib/lb
Blu/tb
Ib/lb
Ib/lb
HOURLY QUANTITIES
26
27
28
29
-.^ -
ACTUAL WATER EVAPORATED
REHEAT STEAM FLOW
RATE OF FUEL FIRING (AS FIRED -t)
TOTAL HEAT INPUT (Item 28 X Item 41)
1000
HEAT OUTPUT IN SLOW-DOWN WATER
T1gJ*L(llem26«treif 20)»(ller>27"llerrt2l)1.l,,.m1o
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Ib/tir
Ib/hr
tb/rir
kBAr
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kB/n,







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FLUE GAS ANAL. (BOILE R) (ECON) (AIR HTR) OUTLET
32
3!
34
35
36
CO,
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N, (BY DIFFERENCE)
EXCESS AIR
\ VOL
% VOL
% VOL ^
". VOL
';
t*J->H~
3.3

COAL AS FIRED
PROX. ANALYSIS
37
33
39
40
MOISTURE
VOL MATTER
FIXED CARBON
ASH
TOTAL
41
42
Btu per Ib AS FIREO
ASH SOFT TEMP.-
ASTM METHOD
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COAL OR OIL AS FIRED
ULTIMATE ANALYSIS
43
44
45
46
47
40
37
CARBON
HYDROGEN
OXYGEN
NITROGEN
SULPHUR
ASH
MOISTURE
TOTAL
6U7
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COAL PULVERIZATION
48
49
64
GRINDABILITY
INDEX-
FINENESS nTHRU
50 M-
FINENESS % THRU
200 M'
-


INPUT. OUTPUT
EFFICIENCY OF UNIT 1

si
52
53
44
41
OIL
FLASH
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ify Deg. API-


VISCOSITY AT SSU-
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r. wt
Blu per
HYDROGEN
Ib

CAS
54
55
56
57
53
59
60
61
CO
CH, METHANE
C,H, ACETYLENE
CjH, ETHYLENE
C,H, ETHANE
H,S
CO,
H, HYDROGEN
TOTAL

62
63
41
TOTAL
% -l
HYDROGEN



r, VOL










DENSITY 68 F
ATM. PRESS.
8tu PER CU FT
Biu PER LB
ITEM 31 '
• 100



ITEM 29
HEAT LOSS EFFICIENCY
65
66
67
68
69
70
71
72
HEAT LOSS DUE TO DRY GAS
HEAT LOSS DUE TO MOISTURE IN FUEL
HEAT LOSS DUE TO H,O FROM COMB.OFHj
HEAT LOSS DUE TO COMBUST. IN REFUSE
HEAT LOSS DUE TO RADIATION
UNMEASURED LOSSES
TOTAL
Blu/lb
A. F. FUEL







EFFICIENCY =(100 - Item 71)

r. of A. F.
FUEL
_£,9o
6.41)
3,ct3
)i2&!
6.CC2.
&.f
/3«A6
$U$

* Not Required For ElticJencr TeMing
t For Po>nt of Measurement See Par. 7.2.B.1-PTC 4.1-1964
                                         IV-91

-------
                                              TABLE  3-22
CALCULATION SHEET
                                                                                         PTC4.1-b (1964)
                                          ASME  TEST   FORM
                              FOR   ABBREVIATED  EFFICIENCY   TEST     Revised September, ?965
OWNER OF PLANT xvA TEST NO. IA BOILER NO. 5 DATE4_ia_72
30
74
25
34

65
64
61
68
6*
70
71
72
ITEM 15 ITEM 17
MgAT OUTPUT |M BOILER BLQW-pOWN WATpp * 1, ft OF WATF& ptQW.DOWN PFP HR x ....... — ......
1000
// impractical to weigh refuse, ffiis
iferr eon fce estimated os follows
% ASH IN AS FIRED COAL
noy (jppn^r pro t fi nF it Piopn FUFI - ... _IT 	 WOTF- IF r
100 - % COMB. IN REFUSE SAMPLE p|T REFUSe
r- -i IN COMBUST
ITEM 43 ITEM 22 ITEM 23 SHOULD BE
CARBON BURNED ^7' 2-7 O'l?2l X ^/^ / 0&& SEPARATEL
PER LB AS FIRED r ' \ta"~ , , 5ao ' ~ s 	 COMPUTATI
FUEL uw L K.SIW J
VB/K/

LUE DUST & ASH
DIFFER MATERIALLY
IBLE CONTENT, THEY
ESTIMATED
Y. SEE SECTION 7,
ONS.
DRY CAS PER LB 11 CO, + 80, t 7(N, + CO)
»e Fi&Ffs riiFi -.. - Y /i R r^AcnOM Aij&Nrri pru i n A^ FI&PO PIIFI i •* ^^

BURNED 3(C0' * C0) / V r 8 ^
ITEM 32 ITEM 33 / ITEM 35 ITEM 34 ) ITEM 24 ITEM 47 1
_ nx /#:$<•*• x.j[.3. +7U^.^* AW x 0.£4>. 4 A77 | //A
/ITEM 32 ITEM 34 \ ,,7
3 x(.^,^. * 0.0*)
CO 1 T C u •) J
rvr-p" O, _ |TPu •)") - |F=M34
AIRt 100X---- — .— ..-100K ~
.J682N, - (0, - C0_ ) ,TEfc, 34
T 7*^7 (ITFU ^5) (|T£U 31 J* }

HEAT LOSS EFFICIENCY
HEAT LOSS DUE LB DRY GAS ITEM 25 (ITEM13) -(ITEM 1 1) ^,-//s
TO DRY GAS = PERLBAS x C x Clvg - 'oir) =.,. xO.24 0^7,, f i? = 7 /&
FIRED FUEL p Unit /A6 -y/2^~d6 ' '
HEAT LOSS DUE TO _ LBH,0 PER LB [(eNTHALpY 0F VAPOB AT 1 PSIA S. T GAS LVGi
MOISTURE IN FUEL ' AS FIRED FUEL x l leNTMALPr gh V* -57^ /JL2. Tr?
(ENTHALPY OF ( "3LIIP AT T AIO)] - x [( FNTHil pr OF ViPOR
- __ _5~6 to° /3 3

HEAT LOSS DUE TO H,O FROM COMB. OF H, ± 9H, x [[ENTHALPY OF VAPOR AT 1 PSIA & T GAS
Lj-,'lfl /77^'79 LVG) - (ENTHALPY OF LIQUIDA.T T AIR)]
_ , Y ITEM 44 x [(ENTHALPY OF VAPOR AT L PSiA » T ITEM 13) _ (ENTHALPY OF LIOUID AT
100 T ITEM ll)j = fji-S2^,.5. . .
HEAT LOSS DUE TO ITEM 22 ITEM 23 o
COMBUSTIBLE IN REFUSE = A/.5"c?7 X J/2"./ = /^~T''O
HEAT LOSS DUE TO TOTAL BTU RADIATION LOSS PER HR
—
RADIATION' LB AS FIRED FUEL - ITEMZ1
UNMEASURED LOSSES "
TOTAL
EFFICIENCY = (100 -ITEM 71)


Biu/lb
AS FIRED
FUEL
770
6*. 3

tib*
1W-8

. O.-i-.






LOSS v
T?HV-
100 =
65
^_ x lOOi
4t
li x 100 -
41
67
	 x 1 00 =
4!
68
— X 100 =
41
6?
x TOO -
41
2i x 100 =
41








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-------
          Overall, it is concluded that no major differences  in
boiler operating efficiency result due to "low NOX" emission  firing
techniques.  Stated another way, reducing NOX emissions in a  utility
boiler need not occur at the expense of increased energy costs.
                             1V-94

-------
                        4.  CONCLUSIONS
          In this section of the paper we present our conclusions from
gaseous emission measurements, particulate emissions (mass and size
distribution), corrosion test data and boiler operating performance.

4.1  Gaseous Emission Measurements

          In section 3.1 we have discussed the results obtained from
each of the 7 individual power generation equipment combustors.  In this
section a summary of the conclusions obtained from the individual units
will be presented as well as the conclusions to be derived by examining
the overall correlations based on the results of the six coal fired
boilers.

          Table 4-1 presents a summary of the NOx emissions for coal
fired boilers under baseline and "low NOx" operation for the 6 boilers
completed so far in this program.  Widows Creek No. 5 boiler is a rear
wall (RW) fired unit; Ernest C. Gaston No. 1 is a horizontally fired
unit (with newly designed low NOx burners); while the last four units
are tangentially fired (of which 3 are equipped with overfire air ports).
Gaseous measurements of % ©2, PPM NOX and PPM CO are listed for baseline
operation, "low NOX-I" (modified firing operation at full load) and
"low NOX-II" (modified firing operation at reduced load).  Baseline PPM
NOX emission levels are listed at both actual excess air levels and
(in parenthesis) the values calculated at 20% excess air for comparison
purposes.

          Both wall fired boilers (Widows Creek No. 5 and Gaston No. 2)
under baseline operation produced NOX emissions above the 0.7 Ib./lO* BTU
Federal standard for new boilers.  However, under modified firing operation
both Widows Creek No. 5 (low excess air, staged firing) and Gaston No^ 1
(low NOX, Babcock and Wilcox burners) were able to meet the standard
under full load operation.  At reduced load (-20%) Widows Creek boiler
No. 5 was able to lower NOX emissions to as low as 305 PPM (49% less
than base).  Gaston No. 1 using the newly designed burners produced
35% less NOX emissions than Gaston No. 2 under baseline conditions.
Modified firing operation of Gaston No. 1 unit at full load and reduced
load reduced NOX emissions by 53% and 69%, respectively, compared to
baseline operation with the normal burners.

          The three tangentially fired boilers equipped with overfire air
ports under full load, baseline operation (cooling air only) met the
0.7 lb./106 BTU NOx standard while Morgantown No. 1 unit was slightly above
the standard for new boilers.  Modified firing using overfire air ports with
low excess air resulted in 37 to 45% NOX emission reductions while staged
                           IV-95

-------
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firing reduced Morgantown No. 1 NOX emissions by 27%.  Comparison of
normalized baseline NOX emissions of these 3 boilers with the four
tangentially fired boilers from our previous program (2) shows an
18% NOX reduction due to cooling air.

          The ranges of NOX emissions measured under normal firing
operation as a function of excess air level (% 02 in flue gas) are
shown in Figure 4-1.  The code letters identifying the power station
and boiler numbers are as follows:
          Code Letters

               WC

               M

               C

               G

               N

               B
    Station
Widows Creek

Morgantown

Comanche

Ernest C. Gaston

Navajo

Barry
Boiler No.

     5

     1

     1

     1

     2

     2
          As discussed in section 3.1, excess air level had a significant
effect on the level of NOX emissions from each boiler under normal firing
operation.  These NOX vs % 02 relationships are shown in Figure 4-1.  With
the exception of Comanche No. 1 unit, (which had limited excess air level
operating flexibility) the slopes (calculated by least squares) of these
lines are fairly consistent.  However, the average NOX levels vary
because of boiler size, type of firing, type and composition of coal
fired, etc.

          Figures 4-2 and 4-3 have been prepared to show the overall
relationship between NOX emission levels and excess air level (% Q£ in
flue gas, on a consistent basis for normal firing and modified firing
operation for the six coal fired boilers tested to date in this program.

          Figure 4-2 is a plot of "normalized" NOX emissions expressed
as a % of baseline NOX emissions (full load and 20% excess air) vs
average % 02 measured in the flue gas for normal firing conditions.
The solid lines shown for each boiler are based on the least-squares,
linear regression analysis of all full load, test runs made under
normal firing operation (all burners firing coal and with closed
overfire air ports).  With the exception of the Comanche boiler
mentioned above, all of the lines fit within a relatively narrow band.

          Figure 4-3 is a plot of "nprmalized" NOX emissions (expressed
as a % of baseline NOX emissions at full load and 20% excess air) vs
average % oxygen measured in the flue gas for modified firing conditions.
Thus, the ordinates are identical in Figures 4-2 and 4-3.  However, the
                               IV-97

-------
    700
                                  FIGURE 4-1


                      PPM NOX VS % OXYGEN IN FLUE GAS

                    (NORWL FIRING - COAL FIRED BOILERS)
    600
    500
    400
 CM
O
-><  300
    200
    100
O  REAR WALL FIRED

D  OPPOSED WALL FIRED
                                                    A TANGENTIALLY FIRED
                             93% COAL ~ 7% OIL MIXED FUEL FIRED
                             _J	I            I	I
                               234

                        AVERAGE % OXYGEN  IN FLUE GAS
                                   IV-93

-------
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                                                 IV-99

-------
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