EPA-650/2-73-021




September 1973
ENVIRONMENTAL PROTECTION TECHNOLOGY SERIES

                                         ^^^^^x^^^x^^^^^^^>x^&*^^^x!&
                                                           iisg^iis^w^jSist


-------
EPA-650/2-73-021   PROCEEDINGS, COAL COMBUSTION SEMINAR,  JUNE 19-20,  1973
                   RESEARCH  TRIANGLE PARK, N.C. 27711

-------
                                        EPA-650/2-73-021
                 PROCEEDINGS,
      COAL  COMBUSTION SEMINAR,
              JUNE  19-20,  1973
RESEARCH  TRIANGLE PARK,  N.C.   27711
                  Robert E. Hall, Chairman
                         
               David W. Pershing, Vice Chairman
                Environmental Protection Agency
    National Environmental Research Center - Research Triangle Park,
                 Control Systems Laboratory,
                 Combustion Research Section
                 Program Element No. 1A2014
                      Prepared for

            NATIONAL ENVIRONMENTAL RESEARCH CENTER
              OFFICE OF RESEARCH AND DEVELOPMENT
             U.S. ENVIRONMENTAL PROTECTION AGENCY
              RESEARCH TRIANGLE PARK, N.C.  27711
                     September 1973

-------
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.
                                ii

-------
                                 PREFACE

     The Coal Combustion Seminar was held June 19-20, 1973 in the auditorium
of the National Environmental Research Center, Research Triangle Park, North
Carolina and was sponsored by the U. S. Environmental Protection Agency,
Office of Research and Development, Control Systems Laboratory, Combustion
Research Section.
     The Seminar, under the chairmanship and vice-chairmanship of Messrs.
Robert E. Hall and David W. Pershing, began Tuesday morning.  The official
welcome and  introduction were given by Dr. E. E. Berkau, Chief, Combustion
Research Section.
     The Seminar consisted of four sessions divided into two main areas:
fundamental  research, and pilot and full scale tests.
     Sessions 1 and 2, chaired by Robert E. Hall and G. Blair Martin, respec-
tively, were concerned with fundamental research.  David W. Pershing and
David G. Lachapelle were chairmen for Sessions 3 and 4, respectively, which
dealt with pilot and full scale tests.
     A tour  of the Combustion Research Section's laboratory was given on
Wednesday afternoon by John H. Wasser, G. Blair Martin, David W. Pershing,
and David G. Lachapelle.
     All papers presented during the Seminar are included in these proceedings,
Except where noted all ppm values are given corrected to zero percent CL, dry
basis (i.e.,at stoichiometric conditions).  To convert ppm values from 0% 02
to 3% 02 multiply the ppm value at 0% 02 by 0.857.
                                   iii

-------
                               CONTENTS


Title

     Preface	in
     Introduction - E. E. Berkau	i


                     FUNDAMENTAL  RESEARCH - PART I

     A. E. Axworthy and M. Schuman

     Investigation of the Mechanism and Chemistry of Fuel
          Nitrogen Conversion to  Nitrogen Oxides in
          Combustion 	   9

     V. Quan, J. R. Kliegel, N. Bayard de Volo, and D. P. Teixeira

     Analytical Scaling of Flowfield and Nitric Oxide in
          Combustors	43


                     FUNDAMENTAL  RESEARCH - PART II

     D. W. Pershing, J. W. Brown, and E. E. Berkau

     Relationship of Burner Design to the Control of
          NOX Emissions through Combustion Modification  	  87

     M. P. Heap, T. M. Lowes, R.  Walmsley, and H. Bartelds

     Burner Design Principles for Minimum NOX Emissions  	141

     C. England and J. Houseman

     NOX  Reduction Techniques in  Pulverized Coal
          Combustion   	173


                  PILOT AND FULL  SCALE TESTS - PART I

     W. J. Armento and W. L. Sage
     The  Effect of Design and Operation Variables on NOX
          Formation in Coal Fired Furnaces 	193

     C. R. McCann, J. J. Demeter, and D. Bienstock

     Preliminary Evaluation of Combustion Modifications for
          Control of Pollutant Emissions from Multi-Burner
          Coal-Fired Combustion Systems  	205

-------
A. R. Crawford, E. H. Manny, and W. Bartok
NOX Emission Control for Coal-Fired Utility                               ,,,,-
  X  Boilers	215


             PILOT AND FULL SCALE TESTS - PART  II

C. E. Blakeslee and A. P. Selker

Pilot Field Test Program to Study Methods
     for Reduction of NOX Formation in
     Tangentially Coal Fired Steam
     Generating Units  	  287

G. A. Hoi linden and S. S. Ray

Control  of NOX Formation in Wall, Coal-Fired
     Utility Boilers:  TVA-EPA Interagency
     Agreement	305

-------
               INTRODUCTION TO
      PULVERIZED COAL COMBUSTION SEMINAR
                 Presented at

     U.  S.  Environmental  Protection Agency
    Research Triangle Park, North Carolina

                   June 1973
                       By

                 E.  E.  Berkau
    U. S. Environmental Protection Agency
      Office of Research and Development
         Control Systems Laboratory
   National Environmental Research Center
Research Triangle Park, North Carolina 27711

-------
                         COAL COMBUSTION SEMINAR

         Good morning, I would like to thank you for taking the time
to attend our meeting and hope that you find it of value.  The subject,
as you know, relates to EPA's research and development activities for
control of air pollutant emissions from the combustion of pulverized
coal.  To review and discuss the work we have invited representatives
from industry and other government agencies who are intimately involved
with the burning of coal.  A list of attendees, as well as copies of the
papers to be presented, will be made available to each of you.

         The meeting is being sponsored by the Combustion Research Section
CCRS) of the Control Systems Laboratory.  Our responsibilities are to
research and develop economical and efficient combustion modification
techniques for the control of air pollutant emissions from burning of
conventional and waste fuels in all stationary combustion systems.  EPA's
Combustion Control Program was officially formulated about 2 years ago
although EPA and formerly NAPCA have been involved with combustion studies
for many years.  To date our efforts have concentrated on control of
nitrogen oxides and combustible emissions such as carbon, carbon monoxide,
and unburned hydrocarbons from pulverized coal combustion.

     Our program consists of coordinated in-house and contracted studies.
We have selected this approach to allow us in the Combustion Research Section
to become technically involved with the direction and development of
combustion control technology.  We feel that this approach is essential
(1) if we are to understand the practical problems involved in the develop-
ment and application of technology to conventional combustion systems and
processes, and (2) to establish private industry's confidence in our
abilities and thereby encourage industry to participate in and accept the
results of our R&D efforts to control air pollutant emissions.

     While this meeting is concerned only with coal combustion, we would
like to use the seminar as a tool for disseminating technical information
and for obtaining guidance and participation of industry and other government

-------
agencies in our studies.  We  feel  this  approach will provide several benefits:
0) industry will receive the technical  results of  our work before the final
reports are distributed?  (2)  industry can  have input to, and thereby affect the
direction of, our studies  at critical stages;  and  (3) industry can coordinate
or integrate their own  activities  with  ours.   It  is anticipated that the
format for future meetings will  be similar to this  one; but the subject
could relate to either  specific  combustion hardware or other fuels and will
be largely dependent upon the progress  in  our R&D efforts.  However, future
meetings will  always be designed to emphasize applications of technology
for industrial utilization.   Your comments as to  the suitability of this
approach and the adequacy of  the present meeting  for these purposes will
be appreciated.

         The specific  purpose of the present  meeting is  for  us  to  review
 the Combustion Research Section's in-house and contract  studies designed
 to develop  combustion  modification technology for control  of NOx and
 combustible emissions  from  pulverized coal fired  boilers.  The  studies which
 will  be presented  for  your  review and discussion  encompass very fundamental
 research through field testing of practical applications  of  combustion
 control  technology.  The  former are designed  to provide  quantified under-
 standing of the  conditions  leading to the  formation of pollutants  and  will
 establish the basis  or foundation for the  ultimate  in combustion control
 technology.  For example, Rocketdyne of Rockwell  International  will present
 the results of their work to decipher  the  combustion chemistry  and kinetics
 of fuel nitrogen conversion to NOx.  On the other extreme, Combustion
 Engineering and TVA will  discuss their  plans  to establish installation
 and operating costs and develop design  guidelines through applications of
 combustion control methods  to actual field utility  boilers.   Emphasis  will
 be placed on techniques which have been established from our field testing
 program to be effective for NOX control of pulverized coal fired utility
 boilers and which will be described by  ESSO Research  & Engineering.   In
 support of the TVA and CE long terra development  studies  the  U.  S.  Bureau
 of Mines will present  their  preliminary data  on  the design and  NOx control
 limitations of various combustion modification techniques for a four  burner,
 5001/hr experimental boiler.

-------
     A number of other studies lying between the very fundamental and the
field testing have also been included in the agenda.  The International
Flame Research Foundation's ClFRF] Research Station in Umuiden, Holland,
will review their work to develop single burner design criteria to control
pollutant emissions from coal and oil fired boilers, and Babcock & Wilcox
will discuss their studies to establish the more promising individual or
combination NQx combustion control techniques for use with current burner/
boiler design practice.  EPA's in-house study to coordinate the IFRF and
B&W work with coal and other related fuels (gas, oil) R&D contracts will
also be summarized.

     Since technology derived from subscale studies with single burner
experimental equipment must ultimately be tested and applied to field
units of much greater size (100 times larger) and involving banks of
burners (16 or more),two other studies are  apropos to the meeting.
The Jet Propulsion Laboratory (JPL) in Pasadena, California,will inves-
tigate for EPA on a laboratory scale the effects of multiburner arrays
on single burner NOx control techniques.  Since this study has just been
initiated, there are no results to present.  However, to introduce you to
JPL, we have asked them to present the results of their company sponsored
bench scale coal combustion studies.  Finally, KVB Engineering, who will
be conducting our industrial boiler field testing program, has been asked
to present the results of their company sponsored studies to arrive at
criteria for scaling up combustion control technology from subscale test data.

         I have briefly summarized the objectives of the meeting and
introduced the topics to be discussed.  I would like to reiterate, however,
that the overall purpose of this meeting is to make you aware of, and
hopefully a part of, EPA's combustion research and development program.
Through your involvement we can be assured that air pollutant emissions
will be controlled through the development and application of technically
and economically sound technology.  The initial step toward this rapport
can be accomplished through your active participation in the meeting.
Therefore, we invite your comments, discussion and recommendations for  the
technical activities as well as for future meetings.  To provide you with

-------
guaranteed attentive ears for your  comments,  I would like to introduce
the members of the Combustion Research.  Section and mention briefly their
primary responsibilities in the  Combustion  Control Program.  They are:

        R. E. Hall - Industrial  equipment survey and field testing
                     of conventional  stationary  combustion systems-

        J. H. Wasser - In-house  testing of  conventional  commercial
                       combustion systems.

        D. G. Lachapelle -  Applications of  combustion  control  technology
                            to  conventional  stationary  combustion systems-

        D. U. Pershing - Research & Development  of combustion techniques
                         for  control  of air pollutant  emissions from
                         combustion fuels.

         G.  B.  Martin -  Characterization of  the emission types and levels
                        from the combustion  of fuels  and the identification
                        of potential combustion control  techniques.

      To proceed with the program,  I will now turn the  meeting over to Bob
 Hall.  Bob has been responsible for the planning and organization of the
 Seminar and for making all  arrangements.  He has a few announcements to
 make before introducing the first speaker.   Thank you.

-------
FUNDAMENTAL RESEARCH




       PART I

-------
INVESTIGATION OF THE MECHANISM'"AND CHEMISTRY OF FUEL NITROGEN

         CONVERSION TO NITROGEN OXIDES IN COMBUSTION


                              BY


                 A, E, AXWORTHY AND M, SCHUMAN
          ROCKETDYNE DIVISION/ROCKWELL INTERNATIONAL
                   CANOGA PARK, CALIFORNIA
                       PRESENTED AT THE

                   COAL COMBUSTION  SYMPOSIUM
                ENVIRONMENTAL  PROTECTION  AGENCY
                 TRIANGLE  PARK,  NORTH  CAROLINA
                      19-20 JUNE 1973

-------
       INVESTIGATION OF THE MECHANISM AND CHEMISTRY OF FUEL NITROGEN
                CONVERSION TO NITROGEN OXIDES  IN COMBUSTION

                                    by

                       A. E. Axworthy and M. Schuman


                Rocketdyne Division/Rockwell International
                         Canoga Park, California

                               INTRODUCTION

This presentation is a progress report covering approximately the first half
of an analytical and experimental program being conducted to determine and
model the kinetics and mechanism of the decomposition of fuel nitrogen com-
pounds,* the fate of the nitrogen-containing pyrolysis products, and the im-
portant physical and chemical processes in the formation of nitrogen oxides
from these species in flames.  Much of the background information pertinent
to this study is presented in an excellent review by Sternling and Wendt
(Ref. 1).  The general objective of the program is listed in Table 1 and a
program outline is presented in Table 2.

Figure 1 shows the probable chemical path for the formation of "thermal NO"
and hypothetical example of potential chemical paths for the formation of
"fuel NO".  Thermal NO is that which forms from the conversion of molecular
nitrogen in air to NO during combustion and fuel NO is that which forms from
nitrogen compounds present in fossil fuels.  The chemical mechanisms are
undoubtedly not independent because intermediates formed from fuel nitrogen
have the potential to react with NO or with N atoms formed in the Zeldovitch
mechanism to form N2  The paths for the formation of thermal NO from N
*The chemically bound nitrogen compounds present in fuel oils and coals,
                                    11

-------
                 TABLE 1.  PROGRAM OBJECTIVE

THE OBJECTIVE OF THIS PROGRAM IS TO DEVELOP A REALISTIC
MATHEMATICAL COMBUSTION MODEL FOR THE FORMATION OF NITROGEN
OXIDES FROM THE CHEMICALLY BOUND NITROGEN COMPOUNDS PRESENT
IN FOSSIL FUELS AND TO INVESTIGATE EXPERIMENTALLY THE  IM-
PORTANT PHYSICAL AND CHEMICAL PROCESSES INVOLVED IN THE
FORMATION OF "FUEL NO",
                            12

-------
                      TABLE 2.  PROGRAM OUTLINE
PHASE IA - THEORETICAL ANALYSIS

    PYROLYSIS OF FUEL NITROGEN COMPOUNDS (PREFLAME REACTIONS)
    FORMATION OF THERMAL AND FUEL NO
    MODELING OF OIL DROPLET/COAL PARTICLE BURNING

PHASE IB - FUEL DECOMPOSITION EXPERIMENTS

    PYROLYSIS OF MODEL FUEL NITROGEN COMPOUNDS
     (DECOMPOSITION KINETICS AND PRODUCT DISTRIBUTION)
    PYROLYSIS OF FUEL OILS AND COALS (DETERMINE INITIAL
     PRODUCTS OF FUEL NITROGEN COMPOUNDS)

PHASE IIA - NITROGEN COMPOUND COMBUSTION EXPERIMENTS

    BURNER STUDIES WITH INTERMEDIATES FORMED IN PREFLAME
     REACTIONS OF FUEL NITROGEN COMPOUNDS
    EFFECTS OF INTERMEDIATE CHEMICAL TYPE AND COMBUSTION
     CONDITION ON CONVERSION TO NOX

PHASE I IB - MATHEMATICAL CORRELATIONS

    MODEL FOR FUEL NO FORMATION
    EXTEND DROPLET/PARTICLE-MODELS TO COMBUSTION OF
     PARTICLE ENSEMBLES UNDER REALISTIC CONDITIONS
                              13

-------
CO, H20, C02, 02,
AIR
OH, H
HYDROCARBON
SPECIES
NITROGEN
SPECIES
FUEL
PARTICLE
i


SOLID
PARTICLE


w
- 	  ^
CO + OH - C02 + H
H + 02 - OH + 0
CO + 02 - C02 + 0
fcr

0-ATOM FORMATION
0X1 DATIVE PYROLYSIS j
1
1
2 w, HETROGENEOUS 1 w .... .
(C02, H^ FUEL
NO ^ "n
N + NO - N + 0
NH  NO - N2 + OH
CN + NO  N2 + CO
NH + N - N2 + H
Ik.

0 + N2 - NO + N
N * 02 - NO + 0
N2  02 - 2 NO
THERMAL NO FORMATION
VIA ZELDOVICH MECHANISM
HCN + 0 - NCO -l- H
NCO + 02 - CO + NO + 0
HCN + H - H2 + CN
CN + 02 - CO + NO
FUEL NO FROM HCN
NH + OH - N + H20
N + OH - NO + H
FUEL NO FROM NH

           INTERACTION OF
           FUEL NO AND THERMAL NO
           MECHANISMS
Figure 1.  Potential Paths for NO Formation

-------
under fuel-rich conditions by reactions not involving 0 atoms, as proposed
by Fenimore and Iverach, are not included in Fig. 1.

The mechanisms shown for the formation of fuel NO in Fig. 1, which are highly
speculative, indicate the possible complexity of the formation of NO from
fossil fuels.  The HCN path is  included because experiments conducted during
this program have shown that under certain conditions the nitrogen contained
in coal,  fuel oils, and model compounds can be converted nearly quantitatively
to HCN.   The HCN reactions listed are those presented in Ref. 1. The NH mechan-
ism in Fig. 1 is of the type proposed by Fenimore (Ref. 2) to account for the
similar behavior of various nitrogen compounds including ammonia.  However,
if soot particles are present,  the thermodynamically favored reaction
NH3 + Cs  = HCN + H2 makes an HCN mechanism plausible even with NHg.  A reac-
tion between HCN and OH should  be added as a likely initial reaction in the
formation of fuel NO.

The heterogeneous formation of  fuel NO is a very likely path not only in the
case of coal particles but with fuel oils, also.  Experimental results ob-
tained during this program indicate that even volatile heterocyclic nitrogen
compounds have a strong tendency to form carbonaceous residues during pyroly-
sis and these residues contain  considerable nitrogen.  Thus, nitrogen-
containing soot particles could form in oil droplet combustion leading to
heterogeneous fuel NO formation in the flame front.

                             COMBUSTION MODELS

As shown  in Fig. 2, the droplet particle combustion models being developed are
of three  types:  (1) droplet vaporization model, (2) droplet/particle flame-
front model, and (3) heterogeneous coal combustion model.  These have been com-
bined with the necessary chemical reaction rate constants to give an average
film kinetic/diffusion model that includes the rate of formation of thermal NO.
Chemical  reactions are being added for the formation of fuel NO but the cal-
culated fuel NO formation rates will be only qualitative at present because of
the uncertainties in the reaction mechanisms and rate constants.
                                    15

-------
                                     COMBUSTION  MODELING
                                          ANALYSIS
   DROPLET MODEL
      CONCEPT
DROPLET VAPORIZATION
       MODEL
DROPLET 6 COAL
 FLAME-FRONT
   MODEL
                                      COAL MODEL
                                        CONCEPT
HETEROGENEOUS COAL
 COMBUSTION MODEL
                         DESCRIBE:
                           COMPOSITION HISTORY, TEMPERATURE HISTORY,
                           FILM PHENOMENA, RATE OF  EVOLUTION OF N
                           COMPOUNDS, ETC.

                         PARAMETERS:

                           FUEL TYPE, DROPLET OR  PARTICLE SIZE,
                           SURROUNDING ENVIRONMENT, DEGREE OF
                           CONVECTION, ETC.
                                    AVERAGE FILM KINETIC/
                                       DIFFUSION MODEL
r
FUEL N* REACTIONS

FUEL 'NO
^%



1
r
OTHER NITROGEN
PRODUCTS
                                1
                                                                  THERMAL N2/
                                                                     REACTIONS
                                                                    THERMAL NO
                            Figure  2.   Combustion Modeling  Analysis

-------
It can be seen from Fig. 3 through 5 that the heterogeneous coal combustion
model developed on this program gives results that agree with the coal
particle composition histories measured by Howard and Essenhigh (Ref. 3).
Inspection of the initial time region of the volatile matter and fixed car-
bon contents shown in Fig. 3 and 4 suggests that during the first 0.05
seconds, volatile matter is evolved without heterogeneous combustion.  The
heterogeneous combustion then begins at a sufficiently high rate that volatile
matter loss due to heterogeneous combustion is as fast or faster than the
volatile matter loss due to gaseous evolution.   After about 0.2 seconds, the
volatile reactions become very slow and the remainder of the volatile mate-
rial is lost due to heterogeneous combustion (Fig. 5).  The reactions of C02
and HgO at the solid surface (Table 3) have been added to the coal combustion
model.  The importance of these reactions on the result obtained is being
investigated.

The chemical reactions presently included in the kinetic/diffusion model are
listed in Table 4.  The results of a preliminary calculation with the kinetic/
diffusion model for a No. 2 fuel oil are shown in Fig. 6.  Under the conditions
of this calculation (relatively low flame temperature), the diffusion of
species to the droplet surface is quite rapid.  The temperature at the flame
zone  (and, therefore, the rate of formation of thermal NO) is strongly depend-
ent  on the free-stream temperature with this model.  Therefore, the use of this
model to  predict the rate of formation of thermal NO must await extention of
the model during Phase II.

The concentrations of CO and 0 in Fig. 6 are very much greater than the pre-
dicted equilibrium values.  This appears to result mainly from allowing all of
the fuel to react to CO rather than COg.  High oxygen atom concentrations then
form by the reactions shown at the top of Fig. 1.  This overshoot will be con-
trolled by reducing the fraction of reaction that goes to CO.
                                     17

-------
  o
  ui

z _i
ui <
o 
o z
a:
ui u.
UI (_}
_i a:
      100
       EXPERIMENTAL
        POINTS (REF.3)

     PARTICLE  SIZE
     	15 ^RADIUS
     	1*0 A* RAD I US
                            CALCULATED
                                          0.8
                      TIME,  SECONDS
                 Volatile Matter Content
                                                     100
                                    80
                             S 2   60

                             lo
                             ne i_
                                                      20   r
                                                     EXPERIMENTAL
                                                      POINTS (REF. 3)
                	REF.  RATES
                	REF. 5 RATES
                                                       0.4
                                                  TIME, SECONDS

                                  Figure 4.   Fixed Carbon Content
DC
UI
0.
                  o
                  CO
                  ce
                  o
                  o
                  o
                  o
                  i
                       100
                        80
                        60
                       20
       1
                 1
                                       1
                                   EXPERIMENTAL
                                    POINTS (REF. 3)
                                    PARTICLE SIZE
                                  i	15/U RADIUS
                                              RADIUS
_L
       100     80     60      40      20
FIXED CARBON CONTENT, WEIGHT PERCENT  OF  ORIGINAL
                   Figure 5.   Variation of Composition of Solid Material
                              With Degree of Burnout
                                            18

-------
CHEMISORPTION REACTIONS:

          Kl
CF + 02   -*co + 0

       K2
CF + 0-C0

          K3
CF + C02 ^  CO + CQ

         K5
                          TABLE 3.  COAL COMBUSTION MECHANISM
COAL REACTION RATE:
(C)
                                      + Kc  (HoO)

K1(02)  +  K2 (0)
                                (i)
                                  (C02)
GASIFICATION REACTION:
     K7
C0    CO + CF
WATER-GAS SHIFT REACTION:
           K8
CO + H20       C02  +  H2

-------
               TABLE 4.  REACTIONS FOR THE KINETIC/DIFFUSION MODEL
                      (EXCLUDING FUEL NITROGEN REACTIONS)
2.  CO  + OH = C02  + H                            -

3.  02  + H2 = 20H                            11-   H

4.  OH  + H2 = H20  + H                         12-   N2 + 0  = NO +

5.  02  + H = OH +  0                           13.'   M + 02-MO +

6.  0 + H2 = OH +  H                           W.   H + 0 + H-HO

7.  0 + H20 = 20H                            15.   N

8,  2H + H =  H2 + H
                                       20

-------
                                                    NO. 2 FUEL OIL
                                                        VELOCITY -  10 FPS
       N(l)  NITROGEN-CONTAINED FUEL
.001
                              RADIUS/DROPLET RADIUS

           Figure 6.   Preliminary Results  With Flame-Front Model
                                         21

-------
                           PYRQLYSIS EXPERIMENTS

One of the processes involved in the formation of fuel NO that has received
little attention is the pyrolysis of fuel nitrogen compounds (Fig. 1).
Hurd and Simon (Ref. 6) pyrolyzed pyridine and picolines at 850 C but
did not establish the kinetic parameters or the fate of most of the nitrogen.
An activation energy and reaction order are required to permit the pyrolysis
rates to be extrapolated to combustion temperatures for the mathematical
models.

Although it is difficult to determine the exact structures of the nitrogen com-
pounds present in fossil fuels (particularly in coals), it has been established
that they are mainly aromatic compoundsmostly heterocyclics.  The structures
listed in Table 5 are believed to include most of the classes of fuel nitrogen
compounds.  Because of the large number of nitrogen compounds believed to be
present in fuels, most of the experimental effort during this program has been
with the pyrolysis of model nitrogen compounds.  A number of fuel oils have
also been pyrolyzed and one coal sample.  Additional coal experiments are
planned using a rapid heating technique that was developed to investigate the
pyrolysis of solid propellant ingredients and is being modified for use with
coal.

APPARATUS

A schematic of the experimental setup is shown in Fig. 7.  Most of the model
compound experiments involved the vaporization of a 0.2 microliter sample
into a  helium stream that flows through a quartz reactor.  The reactor is
2.2 mm  ID with a volume of 1.2 cc and a nominal residence time of 0.75
seconds.  Experiments were also conducted with a vapor injector in which the
sample  vapor was premixed with He or He/02 and a 1 cc slug introduced into the
He stream before it entered the reactor.  The organic products were identified
by temperature-programmed gas chromatography and mass spectrometry.  HCN and
NH3 were trapped in neutralizing solutions and determined, respectively, by a
                                       22

-------
                                     TABLE 5.  NITROGEN COMPOUNDS IN FOSSIL FUELS
S3

OJ
                  PYRIDINES
                 QUINCLINES
I SO-QUINCLINES
                   PYRROLES
                    INDOLES
                                                                       CARBAZOLES
                                                                       PHENAZINES
                                                                    BENZONITRILES
                                                                                                CN
                                                                                              H
                                                                                              t
                                                                       QUINOLONES

-------
The unadjusted pH is quite low and the acid requirement is also low.
Considering acid requirements, the need of soda ash and lime and the
importance of proper dosage is illustrated in the following tabulation:
    Table 1.  ACID REQUIREMENT BASED ON CHEMICAL TYPES USED.
Chemicals used
Soda ash only
Soda ash and lime
Optimum dosage,
soda ash and
lime
Average acid requirement,
per 1,000 gal. brine
0.71 gal.
0.18 gal.
0.04 gal.
Complete tabulation summary of unadjusted brine pH and acid usage is to
be found in Appendix B,

Laboratory bench tests were run to verify empirically established
"optimum" dosages.  Since the reactions are equilibria, any of the
reactions can be reversed with a change in conditions.  The equilibria
move in a given direction because of relative solubilities.  These
solubilities are recorded in Table 2.


    Table 2.  SOLUBILITY OF COMPOUNDS1-
              (in grams/100 grams of water at 20 degrees C.)
CaC03
Ca(OH)2
Mg(C03)
Mg(OH)^
NaCl
Na2C03
Mgci2
CaCl
0.0012
0.165
0.0106
0.0009
36.0
21.5
54.5
59.5
                                24

-------
cyanide specific electrode and Nessler's reagent.  N2 was measured on a molecu-
lar sieve column GC.  Between experiments, the chromasorb 103 column was back
flushed and the residue in the reactor burned out.  The oil pyrolysis experi-
ments were conducted in a similar manner except that the reactor had a 2 cc
bubble blown near the center and the sample was introduced into the heated reac-
tor by quickly moving a small quartz boat containing 1 to 2 milligrams of oil
into the heated zone.  The initial coal experiments were conducted in this
oil pyrolysis apparatus.

MODEL COMPOUND EXPERIMENTS

The model compounds chosen for study were pyridine, pyrrole, quinoline, and
benzonitrile.  These represent many of the nitrogen structures shown in
Table 5.  The nitrogen compounds present in the fossil fuels are highly sub-
stituted and of much higher molecular weights but it is expected that experi-
ments with these  parent compounds will be indicative of the types of high-
temperature reactions that can occur with chemically bound nitrogen.

Decomposition Rates as a  Function of Temperature

Pyrolysis experiments were conducted at temperature intervals of about 25
degrees.  The experimental decomposition curves obtained for the model compounds
 (in  helium) are  shown in  Fig. 8.  Pyridine and pyrrole gave similarly shaped
curves  with slopes  that remained steep until beyond 95 percent decomposi-
tion.   The pyrrole  is less stable than pyridine, the curves being separated by
about  60 degrees.   Quinoline  gave a decomposition curve that is nearly linear
with temperature.   Quinoline  is less stable than all of the other compounds
below  910 C but  is  more stable than pyrrole above that temperature.  Quinoline
is unusual in that  its decomposition curve remains steep up to about 960 C and
then tails out to high temperatures.   In fact, 4 percent remained undecomposed
even at a temperature of  1100 C.  Thus below 1000 C, pyridine is more stable
than benzonitrile,  while  above 1000 C, the reverse is true.
                                      25

-------
Q
Ul
O
o
100


 90


 80


 70


 60


 50
  30


  20


  10
                          PYRROLE

                          PYRIDINE

                          QU INCLINE

                          BENZONITRILE
                                                                         
                                                                         O
             ^5>

            N'
             CN
   850
                900
                   Figure 8.
950            1000
   TEMPERATURE,  C
1050
                            Model Compound Decomposition Curves in Quartz
                            (at a nominal residence time of 0.75 seconds,
                            helium carrier gas)
1100

-------
The experimental decomposition curves were fitted to rate expressions for use
in the combustion models.  Figure 9 shows the pyridine pyrolysis curve* plotted
in a semi-log form along with three theoretical first-order rate expressions.
It is apparent that the data fit a first-order expression with an activation
energy of 70 kcal/mole.  Similar first-order fits were obtained for the pyrrole
and quinoline data giving the rate parameters listed in Table 6.  The benzo-
nitrile data are still being analyzed and it appears that a complex rate expres-
sion may be involved.

The rate parameters obtained for pyridine and pyrrole indicate that the rate-
determining step is a unimolecular reaction.  Such reactions typically have
pre-exponential factors in the range of 10   to 10   sec"  (Ref. 7).  The sur-
prising feature is that pyrrole, which is less aromatic than pyridine, has a
higher activation energy for decomposition.  The low quinoline pre-exponential
factor suggests a heterogeneous reaction.

Shown in Fig. 10 is an Arrhenius plot of the decomposition half-life of pyri-
dine as a function of temperature.  The results of this study and the rates
measured by Hurd and Simon fall on the solid line.  Figure 10 shows that the
 (extrapolated)  half-life for pyridine is about 0.1 milliseconds at 1800 K and
that this extrapolated half-life will be in error about 15 percent for each
1  kcal/mole error in the activation energy.

Pyridine experiments using the vapor injector gave decomposition rates that
were slower by  about a factor of three than when liquid sample injection was
employed.  The  pyridine concentration in the reactor is estimated to be lower
by about a factor of 100 with the vapor injector.  This indicates that the
reaction is of  an order somewhat smaller than one but some other experimental
parameters may  be changing slightly instead.

Pyridine experiments were conducted with the vapor injector using a mixture of
5  mole percent  oxygen in helium as the diluent gas.  The data are not yet
*This curve was from an early experiment that gave a smaller pre-exponential
 factor  than did the curve  in Fig. 8.
                                      27

-------
CO
            2.0
            1.5
         o
         Ul
         />
         o
         a.

         o
         o
         Ul
         o
            1.0
        o
        o
           0.5
             Oh-
                   900
         k - 2.1* X 10UEXP(-65,000/RT)
         k - 1.8 X 1012 EXP (-70,000/RT)




         k - 1.0 X 1011* EXP (-80,000/RT)-
950
1000
1050
                                                          TEMPERATURE, C


                                        Figure 9.  Pyridine Pyrolysis Curve  (Log Scale)

-------
10.0
 6.5
                           30                      60
                        TIME , minutes
    Figure 15.  Treated Brine pH, as Functions of Soda Ash
                Dosage and Reaction Time.
                              29

-------
1000
        1800   1600
 TEMPERATURE, K

JitOO        1200    1100
1000
                           1000/T, K
   Figure 10.   Half-Life for Pyridine  Decomposition  as  a  Function
               of Temperature (Arrhenius  Plot)
                                 30

-------
reduced but the oxidatlve pyrolysls temperatures are lower by about 100 to
200 degrees for a given extent of decomposition.  The oxidative pyrolysis
rate parameters will also be  included in the combustion models.

Decomposition Products

Only minor amounts of ammonia were detected in the products from the pyroly-
sis experiments.  Additional  tests for ammonia are being made using the
ammonia converter (Fig. 7) to decompose the NH3 to N giving a more sensitive
test.  The mass balances obtained in the model compound experiments (with
helium carrier gas) are summarized in Table 7 as a function of temperature.
Depending upon the temperature, from 4 to 100 percent of the carbon is present
in the observed products and  0 to 90 percent of the nitrogen is found.

Benzonitrile forms almost no methane, quinoline up to 4 percent methane,
pyridine about 10 percent, and pyrrole about 25 percent methane.  The other
observed organic products, HCN, and a few (as yet unidentified) GC peaks
account for from 4 to 74 percent of the carbon under the various conditions.
Thus, the unrecovered carbon  (believed to be in the carbonaceous residue
that forms on the reactor wall) amounts to from 0 to 96 percent of the sam-
ples (Table 7).

The amount of HCN formed was  strongly temperature dependent ranging from 24
to 89 percent of the nitrogen in the sample at about 1100 C to less than a
few percent (near the detection limit) at temperatures of 1000 C and lower.
The amount of nitrogen found  in the identified organic products ranged from
none from benzonitrile to 36  percent for pyrrole.  The amount of nitrogen
present in the unknown peaks must be small except for pyrrole at 900 C where
it could amount to as much as 50 percent of the total nitrogen.

It appears that the unrecovered nitrogen in these experiments is contained
in the carbonaceous residue present in the reactor after each experiment.
The residue from two experiments with pyridine at 970 C was analyzed.for
nitrogen by the Dumas method  and about two-thirds of the missing nitrogen was
                                   31

-------
reaction time.  The graphs clearly show the increased pH values due to
the solubility of calcium hydroxide.

The laboratory data were reviewed with the determination that the
optimum dosages should be less than stoichiometric:  85$ for soda ash
and 68% for hydrated lime.  With these dosages, then, a third series
of laboratory tests were made with waste brine to be reclaimed.  The
waste brine was treated with soda ash (85% of stoichiometric), stirred
45 minutes, then treated with hydrated lime (68% stoichiometric) and
stirred an additional 45 minutes.  The reactants were sampled
periodically and analyzed for calcium, magnesium and pH.  Triplicate
tests were performed:  the values were averaged for preparation of
Table 19 in Appendix C.  The tabular data was then used to prepare the
graphs of Figures 18, 19 and 20.

Figure 18 shows the remaining calcium hardness as a function of time.
The figure shows that the soda ash addition was sufficient to reduce
the calcium hardness to zero but that the subsequent hydrated lime
addition increased the calcium hardness.

Figure 19 plots the remaining magnesium hardness and clearly shows
that the magnesium hardness was unaffected by the soda ash addition
and that the hydrated lime significantly reduced the magnesium.

Figure 20 shows the treated brine pH value.  It clearly indicates that
the pH increases with soda ash addition, but that subsequent addition
of hydrated lime reduces the pH.  A review of this data indicates that
the optimum dosages will yield a reclaimed brine of suitable quality
except that the pH of about 9 must be reduced with subsequent addition
of acid.

With the established dosages and with the addition of soda ash first
and lime second, minimal amounts of acid were required for pH adjust-
ment of the effluent.  This adjustment was made by adding a
predetermined amount (usually 100-150 ml) of hydrochloric acid
(20 Be') as the decantation was occurring.  This provided sufficient
agitation for mixing.

The brine as originally drawn off had a turbidity of 20 JTU, due to
unsettled small particles of precipitate.  The acid added for pH
adjustment dissolved the precipitate to produce a product brine of
about 1.0 JTU.  The slight increase in hardness that resulted was not
sufficient to cause failure to meet specifications.

The established procedure is outlined in detail in Appendix D, which
includes plant operation, lab testing, etc.  This procedure was used
throughout the subsequent demonstration runs.
                                 32

-------
recovered.  Another experiment was conducted in which the residue from the
pyrolysis of pyridine at 970 C was heated to 1100 C for 15 minutes.  No HCN
was evolved indicating that the HCN formed in the high-temperature pyroly-
sis experiments forms directly in the initial pyrolysis reaction.

The individual organic products that were present in the model compound
decomposition products are shown'-in Fig. 11 through 14.  The products ob-
tained from pyridine at the lower temperatures (Fig. 11) are the same as
those reprorted by Hurd and Simon but are recovered at much higher concentra-
tions.  This probably results from the shorter residence time and the im-
proved experimental procedure.*  At higher temperatures, the less thermally
stable products decrease in concentration and only the stable products are
observed.  The products from quinoline (Fig. 12) are similar to those from
pyridine  (benzene and benzonitrile) except that methane, acetonitrile, and
acrylonitrile are at much lower concentrations or absent.  It is reasonable
that quinoline forms mostly residue since it represents the first step in
the condensation of pyridine to residue.

The major products from benzonitrile (Fig. 13) are benzene and biphenyl indi-
cating that the first step is a C-C bond rupture followed by hydrogen abstrac-
tion to  form benzene and some association of phenyl radicals.  The surprising
feature  is that most of the nitrogen apparently goes into the residue even
though the initial formation of CN radicals is indicated.

The experiments with pyrrole, conducted very recently, are interesting in that
all of the carbon is recovered at low temperature and possibly most of the
nitrogen, i.e., little residue is formed.  The unknown that accounts for 48
percent  of the carbon at 875 C (Fig. 14) has a retention time on the GC column
about the same as do pyridine ard the picolines.  It would be quite unexpected
*It was established during  this  program that the fraction of pyridine going
 to residue  increases  if  the  residue  is allowed to build up (i.e., the resi-
 due catalyzes  its own formation).
                                    33

-------
10
-p-
        o
        
        o.
        z
        Ul
UJ
O
CC
UJ
Q.
           100

            80

            60
  30


  20



  10

  8

  6



  3


  2



  1

0.8

0.6


0.4

0.3


0.2 -
                           950
                                           1000                    1050
                                                 TEMPERATURE C
                                                                                          1100
                                        Figure 11.  Pyrolysis  Products of Pyridine

-------
LO
              too
               80
               60
               50
               IfO
               30

               20
o
o   10
1    8
z    6
    5
(9   > J|
e    3
           o
           oc
           43

           111
     1
   0.8
   0.6
   0.5
   0.4
   0.3

   0.2
                              850
                                            900
                                            TEMPERATURE,
950
1000
                                    Figure 12.  Products  of Quinoline Decomposition

-------
OJ
            100

            80

            60
             30
         o

         a
         o
         cc
         a.
         19

         o
         X
         C9


         UJ
         o
         CC
             20
            10

             8
  J

  3
  1

0.8

0.6


0.4

0.3


0.2 -
                                                                                                 HCN
                                                   METHANE
                            950
                                         1000                    1050

                                               TEMPERATURE, C
UOO
                                      Figure 13.  Pyrolysis Products of  Benzonitrile

-------
  100
   80
   60 1    UNKNOWN (C5-C6)
   50
   30
   20
I  10
z   8
>   6
3   5

  0.8
  0.6
  0.5
  0.4
  0.3

  0.2

                                                                    \
         UNKNOWN (~C2)
                               \
\
                                    \
                                           I
                         I
                  850
900                     950
     TEMPERATURE,  C
             1000
                        Figure 14.   Products  of  Pyrrole Decomposition

-------
if the first step in pyrolysis of pyrrole turns out to be the formation of the
aromatic pyridyl ring.

To summarize the important results of the model compound experiments to date,
virtually no ammonia or HCN are formed at lower temperatures but large amounts
of HCN are formed at the higher temperatures.   It is quite possible that in
the combustion process, where heating rates are high, HCN is the only important
fuel  nitrogen intermediate.  The other important observation is that even
volatile nitrogen compounds in the vapor phase have a strong tendency to form
a solid residue which contains a major fraction of the nitrogen (at lower tem-
peratures).  Thus, the  heterogeneous  combustion of soot particles could be a
source of fuel  NO in a  diffusion flame.

FUEL  PYROLYSIS EXPERIMENTS

Six samples of No. 6 fuel  oil  were pyrolyzed in helium in the oil  apparatus
at 1100 and 950 C.  The amounts of HCN formed  are listed in Table 8.   Each of
these values is the average of two runs  that gave moderately good reproduci-
bility.  It can be seen that,  as with the model compounds, much more HCN is
formed at the higher temperature than at the lower.   Of the fuel  oils, only
the first (Table 8) formed appreciable HCN at 950 C.   The Wilmington crude
also gave considerable  HCN at 950 but gave twice as much at 1100 C.

The one coal sample that has been run in this  apparatus gave (reproducibly)
large quantities of HCN at both temperatures.   Calculation of the percent
nitrogen that went to HCN is less certain with coals  because of the small  sam-
ple size and the possibility of a nonhomogeneous nitrogen distribution.  In
addition, this coal sample was determined to have about twice the listed nitro-
gen content a few months earlier (see below).

It was found that the presence of sulfide ion can cause an interference in the
cyanide electrode method used to measure the HCN.  Calibration experiments
revealed that sulfide ion alone will  not be detected as HCN but, in the presence
of HCN, sufficient sulfide ion will increase the response factor by about 40
                                     38

-------
       TABLE 8.   FUEL  PYROLYSIS  EXPERIMENTS

GULF NO. 6 FUEL OIL
(VENEZUALIAN CRUDE)
GULF NO. 6 FUEL OIL
(VARIOUS CRUDES)
GULF NO. 6 FUEL OIL
(MAINLY CALIFORNIA CRUDE)
CONOCO NO. 6 FUEL OIL
NO. 6 FUEL OIL
(EPA IN-HOUSE)
NO. 6 FUEL OIL
(EX-ULTRASYSTEMS)
WILMINGTON CRUDE
COAL
(EPA IN-HOUSE)
%N
0.43
0.44
1.41
0.3
0.5
0.38
0.63
(0.59)
JS
2.31
0.73
1.63
0.66
0.9
0.33
1.59

XN AS HCN
1100 C
69
49
33
<6
24
7
127
120
950 C
47
5
6

4

57
101
TABLE 9.  COAL ANALYSES AND VOLATILE NITROGEN RESULTS
COAL
IFRF-A
IFRF-N
EPA
EPA
(DUPLICATE)
N, XW
JAN '73
1.16
1.47
1.17

MAY '73
0.54, 0.64
0.91, 1.16
0.60
0.58
% VOLATILES
27.3
41.5
38.0
38.9
N, %U IN
RESIDUE
0.16
0.18
0.27
0.25
XN IN
RESIDUE
21.5
11.5
27.8
26.5
                           39

-------
percent.  It may be necessary to reduce the HCN values in Table 8 by about
one-third.  This sulfide interference will  have no effect on the model
compound results because sulfur was not present.  A colorimetric method has
been found that will determine HCN accurately in the presence of sulfide
ion.

Some of these oils and coals were rerun to  investigate the amounts of ammonia
and nitrogen that are formed, if any.  The  data are being reduced but it does
appear that these will be important products.

The fuel pyrolysis results were encouraging in that they indicate that real
fuels behave similarly to the model compounds.  That is, they form large
amounts of HCN at the higher temperatures.   It is again possible that under
combustion conditions these fuels may form  HCN quantitatively.

                         COAL AND RESIDUE ANALYSIS

Three coal samples were analyzed for nitrogen in January 1973 by the Dumas
method.  The results obtained are shown in  the first column of Table 9.
These analyses were repeated four months later giving the much lower results
shown.  The reason for these lower results  is not known but sample in-
homogeneity must be suspected.  After the second series of analyses, the per-
cent volatiles were determined for these coals as well as the percent nitro-
gen in the residues.  It can be seen from Table 9 that only about one-fourth
of the nitrogen remained in the residue (or less if the higher nitrogen
values are correct).  These are smaller amounts of nonvolatile nitrogen than
have been estimated previously (Ref. 1).
                                      40

-------
                                REFERENCES

1.  Sternling and Wendt, Shell Development Company Report No.  S-14129,
    August 1972.
2.  Fenimore, C. P., Combustion and Flame. T9_ 289-296 (1972).
3.  Howard, J. B. and R. H. Essenhigh, "Pyrolysis of Coal  Particles in Pul-
    verized Fuel Flames," I&EC Process Design and Development.  Vol. 6,
    No. 1, January 1967, pp 74-84.
4.  Essenhigh, R. H., R. Froberg, and J.  B. Howard, "Combustion Behavior
    of Small Particles," Industrial and Engineering Chemistry,  Vol. 57,
    No. 9, September 1965, pp 33-43.
5.  Smith, I. W., "Kinetics of Combustion of Size-Graded Pulverized Fuels
    in the Temperature Range 1200-2270 K," Combustion and Flame. Vol.  17,
    (1971), pp 303-314.
6.  Hurd, C. D. and J. I. Simon, J. Amer. Chem. Soc., 84,  4519  (1962).
7.  Benson, S. W., "Thermochemical Kinetics," John Wiley and Sons,  New York,
    1968.

                              ACKNOWLEDGMENT

This program is sponsored by the Environmental Protection Agency under Con-
tract 68-02-0635.  The EPA program monitor is G.  Blair Martin.   Other
Rocketdyne personnel who have contributed to this program include:   V. H.
Dayan, G. Lindberg, E. Welz, R. I. Wagner, A. Miles, R. Kessler, W. Nurick,
P. Combs, and I. Lysyj.
                                  41

-------
              ANALYTIC SCALING OF FLOWFIELD

             AND NITRIC OXIDE IN COMBUSTORS*
                            BY
     VICTOR QUAN,  JAMES R,  KLIEGEL, NICK BAYARD DE VOLO
        KVB ENGINEERING, INC,, TUSTIN, CALIF, 92680

                           AND
                   DONALD P,  TEIXEIRA
 SOUTHERN CALIFORNIA EDISON COMPANY, ROSEMEAD, CALIF, 91770
"PRESENTED AT THE EPA PULVERIZED COAL COMBUSTION SEMINAR,
 RESEARCH TRIANGLE PARK,  NORTH CAROLINA, JUNE 19 AND 20,
 1973,

                              43

-------
                         CONTENTS
                                                            Page

ABSTRACT	    46
1.      INTRODUCTION	    47
2.      SCALING CRITERIA AND SIMILARITY LAWS	    49
3.      DERIVATION OF SCALING RELATIONS	    52
        3.1  Governing Equations	    52
        3.2  Scaling of Flow Properties and Nitric  Oxide    55
        3.3  Turbulent Transport  	    60
        3.4  Boundary Conditions  	    63
4,      SOURCE TERMS AND MOLECULAR TRANSPORT  	    64
        4.1  Oil and Coal Combustion	    64
        4.2  Molecular Transport	    70
        4.3  Thermal Radiation  	    71
        4.4  Gravity and Finite-Rate  Chemistry  	    73
5.      DISCUSSION AND SUMMARY	    75
NOMENCLATURE	    78
REFERENCES	    81
FIGURES 1 and 2	    82
                             45

-------
                        ABSTRACT

        The criteria for flow and chemical similarity including
nitric oxide formation in turbulent flows are derived from the
conservation equations.  It is shown that the flowfield and
primary combustion product concentrations in fullscale com-
bustors can be practically simulated in laboratory subscale
combustors, but that the nitric oxide concentration is pro-
portional to the combustor characteristic dimension if the non-
linear effect of radiation heat loss is neglected.  For gas
fired combustors, the similarity conditions require only that
the geometries and boundary conditions be similar.  For oil
fired units, only one additional particle size scaling relation
must be satisfied.  For coal fired units, however, additional
burning rate scaling relations are imposed.
                               46

-------
1.      INTRODUCTION
        The similarity conditions for chemically reactive systems
has been investigated by Penner  (1955), Spalding  (1963), and
others.  Because of the large number of parameters in combustion
processes/ exact combustion system scaling is impossible.  Thus,
only partial modeling can be successful; and in typical problems
(liquid fuel rocket engines treated by Penner, flame propagation
in spark-ignition engines discussed by Spalding, etc.) experience
has shown that only a few significant dimensionless groups are
important and need be considered in practical modeling and
scaling.
        The present study considers turbulent diffusion flames in
industrial combustors, and special attention is directed at the
formation of nitric oxide therein.  The scaling approach taken
is basically pragmatic although its derivation is mathematical.
The objective is to be able to perform simple laboratory experi-
ments  in geometrically scaled combustors without pressure or
gravity scaling and be able to correctly interpret the measured
results in terms of fullscale combustor performance with little
error.  For this purpose, one must determine those dominant effects
which  must be scaled correctly and to determine the scaling
correction factors for small effects and perturbations.
        It is a physically known fact that turbulent transport
mechanisms dominate molecular transport mechanisms in industrial
combustors and that combustion kinetics are extremely rapid ex-
cept for kinetically limited contaminant formation. It can be shown
that if a combustion medium is optically thick, the turbulent
transport process dominates the radiant energy transport
process.  Gravitational effects are also known to be small in
industrial combustors.  To good first approximation, the flow in
an industrial combustor can be treated as an optically thick
                             47

-------
turbulent flow in chemical equilibrium.  Such flows scale
exactly for similar geometries and wall conditions.  Main  flow
departures from this scaling are small and can generally be
treated as either scaling corrections or accepted as experimental
errors.  Wall effects do not scale as directly but may be  com-
pensated for by wall temperature changes if important.  This
approach results in the simple scaling laws, given in the  next
section, which allow realistic combustor scaling.  These scaling
laws provide for the practical scaling of the dominant combustor
flow features for gas, oil,  and coal fired units and for simple
extrapolation, which requires further correction only for  thin
gas radiation effects, of contaminant formation to full size
units.
                              48

-------
2.      SCALING CRITERIA AND SIMILARITY LAWS
        A list of the conditions for similarity is given below.
These are sufficient conditions of which some may not be neces-
sary and some may be altered to achieve certain desired scaling
results.  Items 1 to 9 are operating variables to be kept equal
for subscale model and fullscale prototype.  Item 10 concerns
geometric scaling, and item 11 concerns particle size scaling
in oil and coal fired units.  Items 12 to 15 are idealized
assumptions of the physical processes.
        1.   Fuel composition
        2.   Oxidizer composition
        3.   Fuel temperature
        4.   Oxidizer temperature
        5.   Pressure
        6.   Equivalence ratio
        7.   Inlet velocities
        8.   Wall temperatures
        9.   Inlet turbulence levels
        10.   Geometries are similar between model and prototype
        11.   With particles, their size distribution varies with
             one-half power of combustor dimension
        12.   Fuel-oxidizer combustion is limited only by diffusion
        13.   Molecular processes are unimportant compared to
             turbulent transport processes
        14.   Radiation effects are negligible
        15.   Body forces are negligible
        The above conditions for similarity are surprisingly
few.   In  fact, similarity in combustors for laminar flow is
much more difficult to achieve as noted in a later section.  Of
the conditions listed above, the operating variables 1 to 9 can
easily be kept the same between model and prototype.  Geometric
similarity, item 10, can be achieved to a large extent, at least
in the important characteristics.  Particle size, item 11,

-------
certainly can be chosen at inlet.  It will be shown in a later
section that the particle size will remain scaled throughout
the flowfield for oil burning, but an additional scaling con-
dition between burning rate and combustor size is required for
coal burning.  Only items 12 to 15, which are physical processes
occurring within the combustor, may be difficult to control in
certain circumstances.  Corrections for their effects are
discussed in a subsequent section.
        From the scaling study, the following results of
similarity relations are obtained.  Items 1 to 7 correspond
to results obtained under the idealized conditions listed above,
and items 8 to 10 concern relaxation of the idealized conditions.
        1.   The velocity components, temperature, pressure,
density, and major chemical species are equal at corresponding
positions between subscale and prototype.

        2.   The velocity components, temperature, and density
of the particle cloud are equal at corresponding positions.
        3.   The mass fraction of nitric oxide is directly pro-
portional to the combustor length at corresponding positions.
(This scaling rule is affected by the non-ideal effects of
radiation, molecular dissipation of turbulent eddies, and
non-equilibrium chemistry.)
        4.   The heat fluxes, shear stresses, and mass diffusion
rates are equal at corresponding positions.
        5.   The effective turbulent viscosity is proportional
to the characteristic density PQ, velocity UQ, and combustor
length L.

        6.   The source term effect is inversely proportional
to the product of PQ and UQ in the mass and energy conservation
equations  and to the product of PQ uQ2 in the momentum equations,
                             50

-------
and these effects are all directly proportional to L.  Hence
the effects of these source terms  (gravitational force,  finite-
rate chemical reaction, and thin gas radiation, etc.) on the
flowfield can be simulated in subscale models by employing smaller
PQ and UQ and by taking the dependencies, if any, of the source
terms on p  and u  into account.
          o      o
        7.   In oil or coal fired units, the rule of varying
the particle size with the square root of combustor length
provides for similarity in gas-particle mass, momentum,  and
energy transfers.
        8.   The reference velocity u  need not be maintained
equal for subscale and fullscale, as long as the velocity ratios
at corresponding boundaries are kept equal and the kinetic energy
dissipation and pressure variation are small.  The velocity com-
ponents normalized by u  are then still similar in the combustors.
        9.   The reference density p  or the reference pressure
p  need not be maintained equal for subscale and fullscale, as
long as the density or pressure ratios at corresponding  boundaries
and the reference temperature T   (and hence the ratio p  /p )
are kept equal.  In this case, the local density and pressure
normalized by  p  and p  , respectively, remain similar between
subscale and fullscale.
       10.   Radiation, in optically thick conditions, has
negligible influence on the scaling of turbulent flowfield and
nitric oxide.  Under thin gas conditions, however, ratiation
exerts greater effect on larger combustors and affects the
scaling of nitric oxide in a nonlinear manner.
                              51

-------
 3.       DERIVATION  OF  SCALING RELATIONS
         The  scaling criteria will be derived from the conservation
 equations  for  two-dimensional turbulent  flow for simplicity.
 The  results  obtained are applicable to three-dimensional flows
 as well.   In this section, attention will be focused on gaseous
 turbulent  diffusion flames.  Accounts for two-phase flow,
 radiation, finite-rate combustion, molecular transports, etc.
 will be  pursued in  a subsequent section.
 3.1      Governing Equations
         The  conservation equations governing the flow of a
 compressible reacting gas can be found in textbooks (e.g., Gosman
 et al. (1969)).  For steady plane or axisymmetric two-dimensional
 flows, these equations can be written in the  form
mass:
x-momentum:
                        f-1^
                          f n
y-momentum:
6-momentum:
                                I   ^


energy:
                                      - r,,/
species:
r
  52
                                 fu

-------
where a = 0 for planar flow and a = 1 for  axisymmetric  flow.
The velocity components, u, v, and w are in  the  directions  of
x, y, and 6, respectively, which denote -the  axial,  vertical
or radial, and azimuthal  (for a = 1) coordinates, respectively.
For rectangular geometry or in the absence of  swirl for cylin-
drical geometry, the  6-momentum equation is  not  needed  since
                                               'b
w is then zero everywhere.  The symbols p, p,  h, and m.  denote,
respectively, density, pressure, specific  stagnation enthalpy,
and mass fraction of  chemical species i.   Also,  q   and  j.
where a = x, y, or  0  denote heat flux and  diffusion flux of
species i, respectively, in the direction  a; and T   where  m, n =
x, y, or 8 denotes  shear stress in the plane perpendicular  to
the m axis and in the direction parallel to  n.   The R represents
a mass source due to  particle vaporization.  The P   and F   repre-
                                                  x     y
sent momentum sources due  to body forces,  particle  drags, etc.;
Q is an energy source accounting for thermal radiation,  particle
heat transfer, etc.;  and R. is a mass source for species i  due
to  chemical  reaction, particle vaporization, etc.   These "source
terms will be left  unspecified at this point.
                                                  <\j
        The  relations between stagnation enthalpy h, enthalpy
h,  and  temperature  T  are given by

                h  r  h  H-i^"2*"2)                      fa

                    h =  f wt- He                               ft)
 where  h.   is the reference  enthalpy  of  species  i  at  temperature
 T ,  and c .  is the  constant-pressure specific heat of  species  i
 The  equation of state is  taken  as

                      P =   R T
                              53

-------
where R is the gas constant of the gaseous mixture.  In addition,
the following relations may be used:
                                                              03)
f
                             aw
                             57                             05)


                                                            66)
                                                            67)
where y, k, and D denote viscosity, conductivity, and diffusion
coefficient of species i, respectively.

-------
        The conservation equations given above are strictly
valid only for laminar flows.  At present, no rigorous  and
generally successful theory governing turbulent recirculating
flows is available.  The simplest approach is the one taken by
Gosman et al.  (1969) which merely replaces the molecular transport
coefficients u, k, and D^ by effective values.  One may note that
the differential equations for this approach are slightly dif-
ferent from those obtained by taking time-mean values of the
conservation equations.  For example, in the Gosman approach,
the first term in equation  (1) is simple 3/3x(pu) where the bar
indicates time-mean values.  On the other hand, if one takes
time-mean of the term 3/3x(pu), one obtains 3/3x(pu +p'u' )
where the prime indicates fluxtuating quantities.  The differences,
however, are generally small and Gosman *s approach is employed
here for simplicity.  Furthermore, the discussions here apply
to either approach.  The expressions for the effective transport
coefficients will be specified later.
3.2     Scaling of Flow Properties and Nitric Oxide
        The  following non-dimensional variables are defined:
              (J =

              H = JiAo     =
                      *
                    P  "  ?/?o  .   f=f/fo                (24)

                                                             (25)

where  the  subscript o refers to a  reference  value and L is a
                            55

-------
characteristic length.  The governing equations can then be
written in the form

                                                     -

             ,  r/- r) +
           f i
                                                   -/*o

where
                  p*  r f*R
                            56

-------
                       
-------
means that, under the stated conditions, the flowfields  are
completely similar for combustors of various sizes; i.e.,  the
properties p*, p*, U, V, W, H, and m. are equal at corresponding
positions  (?,n) of various geometrically similar combustors.
For combustors containing turbulent diffusion flames,  R^ (i =  fuel,
oxidant, and combustion products) is zero except at the  flame
front where it becomes infinite.  The position of the  flame front
is similar at corresponding  and n for equal stoichiometric
fuel-oxidant ratio, and hence R. is independent of L.  Thus,
the local mass fractions of combustion reactants and products
can be simulated.  This occurs because the combustion  chemistry
is extremely rapid and the primary reaction products which dominati
the fluid dynamics are in essential equilibrium.  This is  not true
of contaminants whose rate of formation  (NO) or destruction  (CO)
are kinetically controlled.  Nitric oxide  (NO), being  a  trace
species, has negligible influence on the flowfield and is  con-
sidered separately from the flow variables.  If the NO concen-
tration m^0 is far below the equilibrium value as is generally
the case, its formation rate R-j0 is independent of ICL,Q and
equation  (31) shows m^ to vary linearly with the geometric size
of the combustor.
        The third important observation is that under certain
circumstances, even some boundary conditions need not be
similar in order to produce similar non-dimensionalized  properties,
For example, in many types of combustors such as power plant
boilers, the pressure is practically uniform and the kinetic
energy is small compared to thermal and chemical energies. The
pressure gradient terms in equation  (27) and  (28) then disappear.
Provided that Re is independent of UQ in addition to L,  a  con-
dition which will be shown to be valid, and provided that  the
effects of the source terms on the flowfield are small,  the
non-dimensionalized flow properties are then independent of u .
That is, if the reference velocity UQ is different between
                             58

-------
subscale and prototype, the normalized values of  U, V, W,  H,
and m.^  (i = fuel, oxidant, and combustion products) are  still
similar at corresponding non-dimensionalized positions  (,n)
between subscale and prototype.  It is interesting to observe
from equation  (31) that nitric oxide concentration m^o/  however,
is inversely proportional to UQ as well  as being  directly  pro-
portional to L.  As an illustration, consider applying the
scaling rule to the study of Quan et al. (1972)  on nitric oxide
formation in the turbulent diffusion flame formed between  semi-
infinite plane streams of fuel and oxidant.  There, the  scaling
length  is the distance downstream, x, and the scaling velocity
may be  taken as the fuel velocity, u,.   Then, for fixed  air-
fuel velocity ratio, the scaled nitric oxide mass fraction
profile, itL,Q u,/x, across the mixing layer is independent  of
u, or x.  This is shown in Fig. 1.  Thus even nitric oxide
concentration profiles may be simulated  by changing the  injec-
tion velocities in proportion to the scale of the combustor,
providing that one remains within flame  stability limits,-  etc.
        As  another example of changing the boundary condition
in scaling, consider changing p  or p  between  model  and  proto-
type  (but keeping h  ,  and hence the ratio P0/PO/  the same),
then the non-dimensionalized equations without  the source  terms
are still similar.  The advantage of this maneuver is that, by
changing the pressure  in a model combustor, one may counteract
the effect  of  changing size so that finite-rate chemical reactions,
for instance, may be scaled as well as the flow properties.
        In  view of the large number of parameters associated
with combustion problems, it is somewhat surprising that a two-
dimensional combustor  can be simulated or modeled, at least
ideally, with so few restrictive conditions.  The success  can be
attributed mainly to the fact that, in the regions of turbulent
flow, the Reynolds number Re does turn out to be  independent of
                              59

-------
p ,  u ,  and L.   That is,  the effective turbulent viscosity is
Ko'   o
determined by the flow and is proportional to the density, the
convective velocity, and  the characteristic dimension.  This is
the reason for the well known experimental observation on
turbulent diffusion flames that the flame length to jet orifice
diameter ratio is independent of the jet velocity, density,
and orifice diameter.  It should be noted, however, that al-
though this length ratio  is independent of either the fuel or
the oxidant velocity and  density, the fuel/oxidant velocity and
density ratios themselves must be kept constant in order to
achieve similarity in non-dimensionalized boundary conditions.
It may also be interesting to note that for laminar flow, the
Reynolds number Re is, in contrast to turbulent flow, directly
proportional to p , u , and L.  Thus, for example, if a model
of one-tenths of the prototype size is used, then the velocity
must be increased by a factor of ten in order to keep Re the same!
At least in this sense, then, a turbulent combustor is easier
to model than a laminar combustor.
        Of course, even a turbulent combustor contains regions
of laminar flow near the  walls and the dissipation of turbulent
eddies,  which has been shown by Quan, et al. (1972) to have a
dominant influence on the amount of nitric oxide formed, involve
molecular processes.  Corrections and additions to the above
scaling relations in order to account for the molecular processes,
as well as for the source terms due to two-phase flow, etc., are
discussed in a later section.  In the remaining parts of the
present section, the scaling of the effective turbulent viscosity
and the application of boundary conditions will be discussed.
3.3     Turbulent Transport
        The scaling of effective turbulent viscosity will be
analyzed for three commonly employed and representative models
of turbulent flows.  It will be shown that the viscosity is

-------
proportional to the characteristic  density  p  ,  velocity u ,
and length L; and that  the proportionality  coefficient, and
hence the Reynolds number Re  as  defined by  equation (38), is
a function of only the  normalized boundary  conditions  and
the normalized positions  (,n) and  is  thus  independent of p  ,
UQ, and  L.   In regions  of turbulent flow, the effective turbu-
lent Prandtl and Schmidt numbers, Pr and Sc., are essentially
invarient between model and prototype  and hence will not be
discussed further.
         Consider the  expression  for the effective turbulent vis
cosity  given by Gosman  et al. (1969) for turbulent diffusion
flames  in recirculating flows:
                       */3  -1/3  2/3  ,.    2    -   2v'/3
             /t =  KD  W   p   (nfVfZ+ "M )

where  K is  a constant,  D  the  combustion chamber diameter, W the
 chamber length,  m  a mass  flow  rate, and V  the  velocity; the
 subscripts  F and  A denote  conditions at the fuel and oxidant
 inlets, respectively.  Taking pp, and  VF/ and D to be  the
 characteristic density  p   velocity  u , and  length L, respectively,
 one obtains                      .
          > -  KAu.L $*)* tiff  (I* %$)*

where  d is  the diameter of the  fuel inlet orifice.   For combus-
 tors of similar geometry,  the ratios W/D and d/D are constant;
 and for similar boundary  conditions, the mass flow ratio m,/fti-.
 and the velocity ratio  V  /V_  are also  constant.  Hence the
 Reynolds number,  pouQL/y,  is  independent of pQ, UQ, and L as
postulated  and varies only with p*  which is similar at corres-
: ponding locations of model  and  prototype.
         Consider another  common model  of effective turbulent
viscosity y, namely,  the  mixing-length theory for parabolic
                             61

-------
or boundary layer flow.  Here,

                 /*.  - fJLZ  ?"

where Jt is the mixing length given by

                     /  r CX                                 (46)

where c is a mixing constant.  Equation  (45) can be written  as
 Since  2 and  3U/3n are similar between model and prototype,
 the  similarity requirement that y/pouQL be independent of
 p  ,  u  , and L is again satisfied.
        As a  third illustration, consider the approach of
 Gosman et al.  (1969) in which y is given by
 where  c   approaches a constant for highly turbulent flow, and
 k and j  denote  the turbulence kinetic energy and the turbulence
 length scale, respectively.  In this approach, k and j are
 assumed  to be governed by differential equations containing
 convection, diffusion, and source terms.  Examination  of their
                                   o
 equations show  that the ratios k/uQ  and j0/L are independent of
 PO,UQ, and L for highly turbulent flow.  Hence equation (48),
 written  in the  form
                                          c*                   to)
                                           /
               O       ^.
where k* = k/uQ  and ji = jf/L, shows that y/p u L  is  also
independent of pQ, UQ,  and L for this method of approach.
It  is believed that any rigorous turbulence model  will  yield
this scaling relation  and the above scaling is thus universal.
                             62

-------
3.4     Boundary Conditions
        In the elliptic differential equations governing recir-
culating flow, the values of the gradients of U, V, W, H, mi/ and
p* or p* must be prescribed at all boundaries.  To achieve
similarity, these boundary conditions must be equal at corres-
ponding positions of ?b and nb between subscale and fullsccale,
where the subscript b denotes boundary positions.
        For diffusion flames where the fuel and oxidant are
injected separately into the combustion chamber, similar boundary
conditions imply that at the inlet the fuel-oxidant ratios of
velocities, temperature or enthalpy, and density or pressure
must be maintained invarient between subscale and fullscale.
The normalization values of u , h , and p  or p  may be chosen
to be the velocity, enthalpy, and density or pressure, respectively,
of either the  fuel or oxidant stream.  As indicated earlier,
under the conditions that the pressure variation is small and
the kinetic energy dissipation is negligible, u  need not be
equal between  subscale and fullscale to achieve similarity.
Also, p  and p need not be kept the same as long as h  is.

         If a   k-and-/  type of turbulence model is used to
evaluate y, then the differential equations for k and JL require
additional boundary conditions.  Similarity requirement shows
         9
that k/u  and JL/l> must be similar between subscale and full-
scale at corresponding boundary positions.
                               63

-------
4.      SOURCE TERMS AND MOLECULAR TRANSPORT
        The source terms in the non-dimensionalized momentum,
energy, and species equations are all proportional to L, i.e.,
the source term effects on the flow properties are greater for
larger combustors.  The source terms due to particle-gas inter-
action, gravitational forces, finite-rate chemistry, and
thermal radiation are discussed in this section.  Accounts for
laminar or molecular processes and other factors that may
influence nitric oxide scaling are also discussed.

4.1     Oil and Coal Combustion
        For the particle phase, the conservation equations have
the following form
              
-------
        Letting
one may write equations (50) to (54) in the form
                                         - -     f
               "r V + r n WtW -        - -
where
Here again, if the source terms can be made inversely propor-
tional to L, then the particle properties, like the fluid pro-
perties, are seen to be independent of L.  This scaling possi-
bility is investigated below.
        To consider the particle-gas interaction terms of R ,
F   , F  , and Q  , the effects of turbulent fluctuations on
particles will be neglected.  First, consider oil particles
in Stokes flow regime  (small particle Reynolds number).  Since
R  is proportional to the particle number density, which is
proportional to  Pp/rp  where r  is the particle radius, and to the
vaporization rate of a single particle, which is proportional
                             65

-------
to r ,  one obtains
Thus, in order to have the right-hand-side of equation  (59)
independent of pQ, UQ, and L, one may choose the particle
size such that
        The particle momentum sources, from the work of Marble
 (1969) , may be shown to be
 Since R  has the form of equation (65) , one obtains
                                                                to;
Thus, in order to have the right-hand-side of equations  (60)
                                                         2
and  (61) independent of PQ, UQ, and L, one needs  (L/pQuo ) ^
 (r   /p U ) and this yields the identical relation as equation
 (66).
        Similarly, the particle energy source has the form

                                    ,   U0L/fFpx +
 Since R  , F   , and F   have the forms of equations  (65) and
 (69), one obtains
                <3  - f. /*  ,  A *?/*? .  f^o /                 (71 )
Equation  (71) shows that Q  * 1/r 2.  Although u  and h  must
remain invarient in order to have a strictly valid scaling  law,
the contribution to the energy source by the particle drag
forces are small in many instances.  In these cases, the second

-------
term on the right-hand-side of equation  (71) need not be
considered and, keeping hQ invariant, one obtains from equa-
tion  (63) the scaling relation of  (L/p u ) ^  (r 2/P  ) which
yields again the identical relation as equation  (66).
        Thus, perhaps fortuitously, the scaling law  of r   ^ L
satisfies similarity in vaporization, momentum transfer,
and energy transfer as well.  In addition, if kinetic energy
dissipation is negligible, u  can  also be employed for scaling
                       2
and the rule becomes r   ^ L/u  .   It may be noted that scaling
                      p       o
for two-phase flow in laminar boundary layer is not  feasible
because the convection and diffusion terms there have different
scaling lengths.
        Two more aspects must be considered for particle scaling.
One is that -the particle radius must remain scaled as vaporization
occurs, i.e., r /r   must be independent of L and u  at given
position  of , n.  The particle radius is governed by
 where p  denotes  the  particle bulk  density, and n  is the number
 of particles per  unit volume given  by
                     nr  *
 Equations (72)  and (73)  become
                Up
where  r   = r /r     Since  r n  is  chosen  such  that R  *>  p u  /L,
        p     p  po          po                      p    o o
equation (74)  shows  that r  * is indeed  independent of u  and L.
         The second aspect to be considered  is  that of non-Stokes
flow.   In most regions  of oil fired  combustors,  the particles
move in the vapor stream that originates  from  the droplet surfaces
and thus the relative velocities between  particles and vapor
are small.   Consequently, the particle  size scaling rule of
                               67

-------
r   'u L/U  derived for  Stokes flow is a good approximation
in the dominant regions.  However, if one is primarily  interested
in simulating the  initial region of a combustor where the
particles are injected  into the air stream and where the relative
velocities between particles and air are large, then the source
terms for particle vaporization, drag, and heat transfer. are  all
multiplied by a factor  of approximately  (1 4- 0.276 Pr^ ^' Rep  '  )
where Pr, is the Prandtl number based on molecular properties
of the gas and Re   is the particle Reynolds number defined by

       Re  - 2 C^-Wp)% (v-^             i

           = 2 Koo L(U- Uf
where y^ denotes  molecular viscosity of gas.  Thus for moderate
particle Reynolds numbers, the scaling relation is given by
                         o. Z76  ?
                  pz (\
                               32
which may be approximated by  r   ^ L p /u  for high particle
Reynolds numbers .
        Having investigated the modeling of oil droplet combus-
tion by scaling the droplet size, it may be interesting to
consider solid particles  such as coal.  Here, the gas-particle
momentum and energy transfers are similar to those for oil  and
hence the particle size scaling still applies.  The question
concerns the scaling of the combustion rate.
        The combustion of coal  may be separated into two modes.
One is the gasification of volatiles.  This is an internal  decom-
position process which, from  Field et al.  (1967), may be
described by
               Rr  = ^"^/-/p  c      '                   (77)
                             68

-------
where GI is the mass fraction  of volatile  matter in the  coal,
C2 is a characteristic decomposition  time,  and C, is a charac-
teristic temperature.  Equation  (77)  shows  that R  is inde-
pendent of particle size.   To  scale the  right-hand-side  of
equation  (59), one needs
Thus, to  simulate  gasification of  volatile  matter in subscale
models, one  needs  to substitute a  different volatile matter of
shorter decomposition time and/or  to decrease the flow velocity
u  .   The  scaling requirement given by equation (78)  arises,
because decomposition is rate-limited and is thus in contrast
to the assumption  of diffusion-limited combustion which is
listed as assumption 12 in Section 2.
        The  other  combustion mechanism of coal is the burning
of the char  structure.  From Davis et al. (1969), one may take
the burning  rate for a cloud of particles as
 where K, , K0, and K_ may be considered as fixed constants,  Xn
        \-   .       3                                         ")
 is the mole fraction of 0, at the edge of the particle boundary
 layer, and f is the steric factor.  The first and second terms
 in the denominator of equation (79 )  account for resistances on
 surface reaction rate and on counter-diffusion rate of COj  and
 O9 near the surface, respectively.  To satisfy scaling of mass
 transfer, equation  (59) requires R  *> PQUQ/L; and to satisfy
 momentum and energy transfers, the scaling rule of r   ^ L/uQ
 as given by equation (66) is required.  The combination requires
 R  i> o /r  .  Examination of equation (79) shows that this  con-
  P      P
 dition is satisfied if the combustion of char is diffusion-
 controlled, which is a valid approximation for large particles
                             69

-------
and/or high pressure.  If the surface reaction rate controls,
however, then one must either accept the result of R  ^ r
given by equation (79) as an approximation to the scaling rule
          -2                                           "*1
of R  ^ r    or increase p0or pQ such that pQor pQ ^ r
in order to obtain R  ^ r   .
        For high particle Reynolds numbers, correction for
their effects on the scaling rules may be made in a manner
similar to that given for oil.

4.2     Molecular Transport
        Molecular processes affect the scaling of turbulent
flow in three major respects.  One is that heat transfer to
the walls are governed by laminar diffusion in the wall regions.
Another is that the dissipation of turbulent eddies, which has
been shown by Quan et al. (1972) to have a dominant influence
on the amount of nitric oxide formed, is governed by molecular
processes.  The third is that the gas-particle interaction in
two-phase flow, which has already been considered, is dependent
on molecular properties.
        To correct for the heat transfer in the wall regions of
a model, one may balance the heat flux through the laminar
boundary layer by the turbulent heat flux at the edge of this
layer at corresponding positions of ,n.  That is, h(T  - T )
                                                      6    W
=  (k9T/3y)  where h and k are the convective heat transfer
coefficient and turbulent conductivity, respectively; and the
subscripts e and w denote the edge of the laminar layer and
wall, respectively.  Since k3T/3y is proportional to p u  and
independent of L and since h may be represented, for example,
by h ^  (P0uo)'8L~'2, one obtains
 Since Tg is similar  (i.e., independent of pQ, u  , and L) , equa-
 tion  (80) provides a scaling relation for T  and shows  that  a
                                           inf
                              70

-------
subscale model requires higher wall temperatures  to keep  the
temperatures in the turbulent bulk gas region similar  to
those of the prototype.  The 0.2 power in equation  (80) may
become significant when the model and prototype length ratio
is large.
        On the molecular dissipation of turbulent eddies, the
mechanism is not well established at present.  Here, one  may
merely indicate that no additional requirement for similarity
appears for both limiting cases of no molecular mixing and
complete mixing of the eddies.  The situation is  analogous to
chemical reaction where no time or length scale is introduced
if the flow is either frozen or at equilibrium, but finite-rate
process would introduce a time scale.

4.3     Thermal Radiation
        Radiation  affects the formation of NO in  a nonlinear
manner, and will be discussed here for the optically thick and
optically  thin limits, equations for which are given by Vincenti
and  Kruger (1965).
        The thick  gas approximation is valid when the  radiation
mean free  path is  much smaller than the flame dimensions.  In
this case, radiation is treated as heat conduction with the
conductivity  given by
                                         "J
where a is the Stefan-Boltzmann constant,  and M.  and KR  are
the  mole fraction and Rosseland mean  absorption coefficient,
respectively,  of species j.   The gaseous species  from hydrocarbon
combustion that participate  in radiation are  mainly  H2O,  C02,
and  CO for which the values  of KR are given by Abu-Romia  and
Tien (1967)  as functions of  pressure  and temperature.  The
ratio of radiation conductivity to turbulent  conductivity shows
                              71

-------
that k A ^ (P u L KR)    and is generally small except for
small combustors.  In typical combustprs, then radiation in the
thick-gas regime need not be considered because radiation con-
duction is small compared to turbulent conduction.
        The thin gas approximation may be applied when the
radiation mean free path is much greater than the flame dimen-
sions.  Here, radiation is treated as an energy sink in the
energy conservation equation with
                QA =  - 4 T T* ? M
where K   is the Planck mean absorption coefficient of species j.
Values o? K   are also given by Abu-Romia and Tien (1967), and
vary with temperature and are proportional to pressure.  To
have the source term in equation (30) independent of p , u , and
L, one needs K  ^ p u h /L.  Since <  is proportional to p  and
hence p  , scaling of thin gas radiation is achievable by
employing u  ^ L.
        The potential effect of radiation on NO formation has
been assessed, and the differences in flame temperature history
are shown in Fig. 2.  This configuration corresponds to the
sample problem investigated by Quan et al. (1973) for nitric
oxide formation in recirculating flows.without radiation.  In
the absence of radiation, the calculated results show that the
combustor of 32 ft in length forms 327 ppm of NO, that a subscale
combustor of 3.2 ft in length forms 32 ppm of NO, and that the
turbulent flowfields of these two combustors are similar.  Thus,
the scaling relations for both the flowfield and NO production
are observed.  With thick-gas approximation, radiation is found
to have negligible effect on the flowfield and NO production.
With thin-gas approximation and considering each gas element
only to emit radiation and not to absorb any, however, radiation
is found to have a strong influence on the temperature field and,
consequently, NO production; although its effect on the velocity
field is still small.  For the larger combustor, NO is reduced

                             72

-------
from 327 ppm to 71 ppm; whereas  for  the  smaller  combustor  for
which the effect of thin-gas radiation is smaller,  NO is reduced
from 32 ppm to 23 ppm.  The effect of thin-gas radiation on  the
flame temperature distribution is illustrated in Fig.  2.   Thus
if a combustor is optically thin or  if the  subscale combustor
is optically thin while the fullscale combustor  is  optically
thick, radiation differences between model  and prototype will
cause nonlinear NO scaling.

4.4     Gravity and Finite-Rate  Chemistry
        Gravitational forces are proportional to p g.  For
                                                    O        2
absolute  similarity,  equations  (28)  and  (29) require Lg *  u
In industrial  combustors,  gravitational  effects  are generally
negligible and gravitational scaling is  generally unimportant.
        Finite-rate kinetics may be  simulated, according to
the  source term in equation  (31), by requiring that R. ^ p u /L.
Thus if the species production rate  R. is independent of density
p ,  one may simply take  p  u  ^ L.  If R. is dependent  on pressure
p or density  p  , then one may change the pressure  such that
R./P  ^ u /L.  In the case of NO formation, if the  NO concen-
tration is low so that R.  is independent of NO,  no  change  in
operating condition is necessary and equation  (31)  shows that one
may  simply scale the  NO concentration in direct  proportion to L
except for radiation  effects.
        Besides radiation, there are other  factors  which may
render the scaling of NO with combustor  length nonlinear.  If
NO is  near equilibrium or  if there is significant conversion
of NO  to  N02,  then R..Q is  a function of  m^, and thus  mNO  does
not  vary  linearly with L.  In two-phase  flow, fuel  nitrogen
effects may become important, e.g.,  there may be a  certain
fixed  amount of NO formed  due to fuel nitrogen regardless  of
combustor size.  The  kinetics of fuel nitrogen conversion  is
not well known; but if it  is found that  a fixed  amount of  fuel
                             73

-------
NO is formed, then one may simply sub tract this amount and
scale the remainder of the NO.  Keeping the total NO level
high also tends to minimize the fuel nitrogen effect.  The
question of "prompt NO" is associated with non-equilibrium oxygen
concentration near the flame front.   As indicated in the pre-
ceding paragraph, one way of scaling this finite-rate chemistry
effect is to set u  ^ L.  However, for small L in subscale, one
must be certain that u  is not so low that the flow becomes
                      o
laminar or unstable.
                            74

-------
5.      DISCUSSION AND SUMMARY
        The reason that turbulent flowfields can be scaled in
geometrically similar combustors is that the turbulent transport
coefficients are proportional to density pQ, velocity UQ, and
geometric dimension L.  As a result, the ratio of diffusive
transport to convective transport becomes independent of  p  ,
UQ, and L.  This is the reason that, for example, the flame
length to jet diameter ratio in turbulent diffusion flames does
not vary with jet diameter, density, or velocity as long as  the
air-fuel density and velocity ratios are kept constant.
        The effects of the source terms in the conservation
equations are all proportional to L and inversely proportional
to p  u  .  Hence one may  scale the source terms by simply
requiring p u   ^ L.  In modeling, it may not be practical to
change p  , and  the range  of u  that may be modified may also
be limited by the considerations of flame stabilization, flow
laminar iz at ion, etc.   In  principle, however, the fact tha't equal
absolute  velocity is not  a necessary condition for similar flow-
field is  due to two main  reasons.  One is that kinetic heating is
negligible so that enthalpy is practically independent of velocity.
The other, again, is that the diffusive transport coefficients
are proportional to velocity.  The velocity ratios at corresponding
boundary  positions of  subscale and fullscale must be kept equal,
however,  in order to achieve similarity in non-dimensionalized
boundary  conditions.   This rule applies to the density ratios
as well.
        Another interesting aspect which contributes to similarity
in turbulent flow is that the shear stress, heat conduction  flux,
and mass diffusion flux are independent of combustor size.   For
example,  the temperature  gradients are much steeper for subscale,
but the heat conduction coefficient is much smaller by the same
proportion and  the net result is that the heat flux at corres-
ponding positions of subscale and fullscale are the same.  If

                              75

-------
the absolute velocities are not the same, however, the fluxes
will differ accordingly.
        For oil and coal combustion, one may scale the particle-
gas momentum and energy transfers by scaling the particle radius
as r 2 ^ L for fixed POUQ.  For oil, this scaling also insures
proper scaling of vaporization rate.  For coal, additional scaling
                                        2
of the burning rate is required.  The r   ^ L is applicable
                                       \~
for Stokes flow regime.  For moderately high Reynolds numbers,
it becomes r  *  ^ L.
            P
        The particle size scaling for oil provides for equal
ratio of all three rates: fuel vaporization, vapor and oxidizer
convection, and vapor-oxidizer diffusion.  The vaporization-
diffusion ratio is important in ensuring a similar combustion
mode.  For example, if vaporization rate is too slow, oxidizer
may diffuse into the cloud of droplets and combustion can occur
mainly around the drops instead of mainly near the vapor-oxidizer
interface as experimentally observed.  In combustors that are
only partially similar in geometry, the proper characteristic
length L should be chosen as the diameter of the vapor cloud where
a diffusion flame occurs.
        It is interesting to point out here that for laminar flows,
the vaporization-diffusion ratio requires equal r /L while the
vaporization-convection ratio still requires equal r  /L. Thus, a
consistent scaling law does not exist for two-phase laminar
boundary layers, whereas it does exist for turbulent boundary
layers as well as for inviscid flows since both vaporization-
diffusion  (for turbulent flow) and vaporization-convection ratios
                             2
are then satisfied by equal r  /L. It should be mentioned however,that
the effects of turbulent fluctuations on gas-particle interactions
have not been considered here.
        For nitric oxide, since the source term in its continuity
equation is scaled with L/PQUO/ the NO concentration varies
                              76

-------
linearly with geometric size for given density and velocity.
This conclusion holds for all two or three dimensional flows.
This linear relation, however, is modified if radiation and
other nonlinear effects become important.

        In terms of load or power input to a combustor, NO
concentration varies with the square root of load since load
varies with the square of the inlet dimension for axisymmetric
combustors.  Load by itself is not a good scaling parameter,
however, because it is a function of two parameters: geometric
size and velocity.  If the velocity is maintained constant, then
nitric oxide increases linearly with one-half power of load.  If
the geometry is fixed  (for same size combustors), however, NO
may increase, decrease, or does not change with varying load.
These conflicting trends are substantiated by experimental data,
and can be accounted for by the trade-off between the effect
of residence time and the effect of increasing power output as
velocity is increased.  In general, the effect of increase in
power output, which increases wall temperatures and hence flow-
field temperatures, dominates and NO increases with loading.
However, this trend certainly should not be attributed to
flame length which is independent of velocity for given fuel-
oxidizer velocity ratio.
                              77

-------
                      NOMENCLATURE




c       specific heat at constant pressure


D       effective diffusion coefficient


E        (u2 + v2 + w2)/2 hQ


F       momentum source


g       gravitational acceleration


H       h/no


h       specific enthalpy


h       specific stagnation enthalpy


j       mass diffusion flux


j*      j/P u


k       effective heat conductivity


L       characteristic combustor geometric dimension


M       molecular weight


m       mass fraction


Pr      Prandtl number, yc /k
                          P

p       pressure


P*      P /P0


Q       energy source


q       heat diffusion flux



q*      <3/P0uoho

R       mass source


Re      Reynolds number, p u L/JJ


R       gas constant


r       radius of particle

                              78

-------
  Sc      Schmidt number/  y/pD
  T       temperature
  U       U/UQ
  u       axial velocity
  V       v/uo
  v       vertical or radial velocity
  W       W/W0
  w       swirl velocity in axisymmetric flow
  x       axial distance
  y       vertical or radial distance
Greek Letters
  n       y/L
  8       azimuthal coordinate
  <       Planck mean absorption coefficient
  KR      Rosseland mean absorption coefficient
  y       effective viscosity
         x/L
  p       density
  P*      P/P0
  p       particle bulk density
  T       shear stress
  o       =0 for plane flow,  = 1 for axisymmetric flow;
          Stefan-Boltzmann constant
                                79

-------
Subscripts
  o       reference point
  i       index for chemical species
  m       index for x, y, 6
  n       index for x, y, 6
  NO      nitric oxide
  p       particle
  r       reference state
  x       in x-direction
  y       in y-direction
  a       index for x, y, 9
  0       in 6-direction
                              80

-------
                         REFERENCES

 Abu-Romia,  M.  M.  and Tien,  C.  L.,  1967,  Appropriate Mean
         Absorption Coefficients  for Infrared Radiation of Gases,
         J.  Heat Transfer,  89,  321.

 Davies,  T.  W., Beer, J.  M.  and Siddall,  R.  G. ,  1969, The Use of
         a Mathematical Model for the Prediction of the Burn
         Out of Char Suspensions,  Chem.  Eng.Sci. 24, 1553.

'Field, M. W.,  Gill, D. W.,  Morgan, B.  B.,  and Hawksley, P. G. W.,
         1967,  Combustion of Pulverized Coal, Brit. Coal Utilization
         Res. Assoc.

 Gosman,  A.  D., Pun, W. M.,  Runchal, A.  K.,  Spalding, D. B., and
         Wolfshtein, M.,  1969,  Heat and Mass Transfer in Recir-
         culating Flows,  Academic Press.
 Marble,  F.  E., 1969, Some Gasdynamic Problems  in the Flow of
         Condensing Vapors,  Astronautica Acta,  14, 585.
 Penner,  S.  S., 1955, Similarity Analysis for Chemical Reactors
         and the Scaling  of Liquid Fuel Rocket Engines, Combustion
         Researches and Reviews,  Butterworths Sci.Pub., pp 140-162.

 Quan, V., Marble, F. E., and Kliegel,  J. R., 1972, Nitric Oxide
         Formation in Turbulent Diffusion Flames, presented at
         the Fourteenth Symposium  (International) on Combustion,
         and to be published in Symposium Volume.
 Quan., V., Bodeen, C. A., and Teixeira, D.  P.,  1973, Nitric Oxide
         Formation in Recirculating Flows,  to be published in
         Combustion Science and Technology.
 Spalding, D. B., 1963, The Art of Partial  Modeling, Ninth
         Symposium  (International)  on Combustion, Academic
         Press, pp 833-843.
 Vincenti, W. G. and Kruger, C. H.  Jr., 1965, Introduction to
         Physical Gas Dynamics, John Wiley  and Sons.
                               81

-------
0.06
                           P - 1.0 ATM
                           u .  /u,  ,  =0.25
                            air'  fuel
                           T .   - 1210 R
                            air
                                   537 R
                            fuel
                           Fuel: Methane
             FLAME FRONT
                                  BASED ON NO MIXING
                                  OF TURBULENT EDDIES
                      BASED ON COMPLETE MIXING
                         TURBULENT EDDIES
 Fig. 1.
    0.2       0.4        0.6        0.08       1.0
 DISTANCE FROM AIR BOUNDARY/MIXING ZONE WIDTH


Scaled Nitric Oxide Concentration Profile in
Turbulent Diffusion Flame Between Plane Streams
of Methane and Air.
                           82

-------
       TEMPERATURES (R) ALONG STOICHIOMETRIC LINE
POINT:
NO RADIATION:
RADIATION, SUBSCALE:
RADIATION, FULLSCALE:
                          PEAK TEMPERATURE CONTOUR
                         (NEAR STOICHIOMETRIC LINE)
         32.0 FT FOR FULLSCALE,3.2 FT FOR SUBSCALE.
 Fig. 2.  Effect of Thin Gas Radiation on Flame Temperatures.

-------
FUNDAMENTAL RESEARCH




       PART II
          85

-------
      RELATIONSHIP OF BURNER DESIGN TO
        THE CONTROL OF NO  EMISSIONS
       THROUGH COMBUSTIONXMODIFICATION
                     by

               D.  W.  Pershing
                 J. W.  Brown
                E. E. Berkau
    U. S. Environmental Protection Agency
     Office of Research and Development
         Control Systems Laboratory
   National Environmental Research Center
Research Triangle Park, North Carolina  27711
                      87

-------
                                ABSTRACT

     The combustion of propane, distillate oil, a 0.3 percent nitrogen
oil, and pulverized bituminous coal has been examined in a versatile
laboratory furnace.  In each case testing was conducted to determine the
relationship of burner (and process) parameters to the control of NO
                                                                    A
emissions.  The results show that in general propane and distillate oil
give about the same NO . the 0.3 percent N oil  about twice the NO, and
                      X                                          A
coal at least 2-1/2 times as much.   Increased burner throat velocity
and flue gas recirculation were shown to be extremely effective in
reducing thermal NO , but neither worked very satisfactorily with the
                   s\
high nitrogen oil or coal.  Increasing air preheat substantially
increased the NO  emissions from propane and distillate oil and caused
                X
lesser increases with the high nitrogen distillate and pulverized
coal.  Future work will extend the program to natural gas and No. 6 oil
and will consider two stage combustion.
     This paper summarizes results  obtained under ROAP 21ADG-Task 42
(in-house) under the sponsorship of the U. S. Environmental Protection
Agency.  The work reported herein was completed June 13, 1973.
                                   88

-------
                              INTRODUCTION

BACKGROUND
     Several groups have recently noted the importance of burner
parameters in NO  formation.  Some of the earliest work was done by
                /\
Wasser et  al.  in a 3 GPH refractory lined test furnace.  Their data
indicated that with distillate oil NOV emissions increase with firing
                                     A
rate, decrease when the excess air is increased from 25 to 45 percent, and
are most strongly a function of burner swirl.  With the burners at full
load, Wasser was able to vary NO from 130 ppm to 480 ppm (no air preheat)
by changing only the amount of swirl in the combustion air stream.  The
data were correlated using cold flow residence time distribution data.  From
this, it was shown that the large changes in NO were due to changes in
primary zone combustion intensity induced by the effect of swirl on the
combustion fluid dynamics.
     The most comprehensive study of burner parameters to date was conducted
              p
by Heap et al.  at the International Flame Research Foundation in a 2 x 2 x
6.25 m refractory wall furnace.  The variables considered included fuel
injector design and position, secondary air velocity, quarl type and angle,
burner swirl, and fuel types (gas and coal).  Heap found that for natural
gas flames when the fuel jet remains on the flame axis, NO emissions increased
with increasing swirl.    Increasing the combustion air velocity from 25 m/sec
(82 fps) to 50 m/sec (164 fps) reduced NO emissions.  In natural gas flames
where the internally recirculating gases form a closed zone on the flame
axis (as with a radial hole injector) NO emissions generally decreased with
increasing swirl; however, increasing the combustion air velocity again
                                    89

-------
reduced NO.  In all cases the decrease is probably due to the entrainment



of cooled product gases.



     In coal flames with strong axial fuel jets, Heap found that increasing



swirl usually decreased the emission of NO .  Increased secondary air
                                          A


velocity usually increased emissions.  In flames from radial coal injectors



(where there is reverse flow on the centerline) the NO  emissions were
                                                      /\


essentially independent of swirl.  In general, the coal data suggested that



any change which spread the pulverized coal jet or increased the 0,,/fuel


                                                4

ratio near the injector increased NO  emissions.
                                    A


     Hemsath et al.5 investigated the importance of proper burner design



for low emissions from large industrial natural gas furnaces and found the



key to a low emission burner was reducing the combustion temperatures



followed by rapid mixing of the combustion products with the surrounding



furnace gases.  Seven commercial burners were tested in a refractory lined



chamber and based on the results a new "low emission" burner was designed.



The NO  emissions from the commercial burners ranged from near 100 ppm at
      A


fuel  rich  or  large  (> 50 percent) excess air conditions to over 400 ppm



at 7  percent  excess air.  Emissions from the new low emission burner were



50 to 75  percent lower than those from the conventional burners.  While



the  exact design of the new burner is proprietary, available information



indicates  that emission reduction is achieved through the use of a very



small burner  block  for ignition stability and very high velocity combustion



air  (small  burner  throat).  The latter results in significant entrainment



of cooler flue products and in effect provides aerodynamic flue gas



recirculation.
                                   90

-------
     Shoffstall et al.   examined the importance of burner design by



testing five different types of natural gas burners.  In each case, the



effect of excess air, load, fuel injector design, and air preheat temperature



on NO  emissions was determined.  Burner/injector pairs, where the fuel jet
     A


remained on the axis, gave long luminous flames with low NO  emissions.
                                                           A


Increasing the excess air in these cases increased emissions up to at least



20 percent excess air (4 percent Og).



     Burners with high swirl or radial gas injection had internal reverse



flow (of combusted products) on the centerline and short, very intense flames.



     In these  cases  NO  emissions were generally higher than the axial
                      A


flames and, based on in-flame measurements, nearly all the NO  was formed
                                                             A


very near  the  burner, many times within the burner block itself.  These



burners also increased in NO  output as excess air was increased but peaked
                            X


much earlier,^generally before  15 percent excess air (3 percent 02).  The



earlier peak and  higher emissions may be due to better fuel/air mixing which



results in more rapid  (and thereby more intense) combustion.



      In the 10-20 percent excess air range increasing air preheat increased



NO   in all  cases  tested, sometimes by as much as 1 ppm per degree F.  As
  A


excess air was reduced toward zero the effect lessened.  Shoffstall  concluded



that the most  obvious means of  reducing NO  emissions (without lowering air
                                          A


preheat and losing efficiency)  was to use either low excess air firing or



change to  an axial fuel injector.



     While  the above groups were examining the control of NO  through burner
                                                            A


design, many other organizations were conducting laboratory and full scale



testing on  the more  classical NO  control techniques:  low excess air (LEA)
                                     91

-------
firing, staged combustion (SC), and flue gas recirculation (FGR).  Since
the status of this work has recently been reviewed in considerable depth
it will not be discussed here, except to say that available data indicate
that LEA and SC (with its variations) are effective in reducing NOX from
gas, oil, and coal systems.  FGR is extremely effective with natural gas
flames and to a lesser extent with oil.   Unfortunately, none of the
techniques are without their problems:  FGR is economically unattractive
and both LEA and SC could cause flame instability, slagging, and corrosion
difficulties in coal-fired systems.

PURPOSE
     The purpose of this program is to utilize a versatile laboratory combustor
to examine the control of NO  and other emissions through both burner and
                            J\
combustion modifications.  The work is directed at present day fossil fuels;
specific goals are to:
     (1) Determine what effect burner parameters have on the effectiveness
of known NO  control  techniques.
           /\
     (2)  Compare the NO reduction possible through proper burner design to
that possible through combustion modifications.
     (3)  Establish the effect of fuel type on NOV control.
                                                 X
     (4)  Investigate novel design ideas for further development under
contract funding.
     This paper is a status report on the work completed to date on
Goals 1, 2,and 3.
                                     92

-------
     Environmental  Protection Agency policy is to express all measurements
in Agency documents in metric units.  When implementing this practice will
result in undue costs or lack of clarity, conversion factors are provided
for the non-metric units used in a report.  Generally, this report uses
British units of measure.  For conversion to the metric system, use the
following conversions:
To convert from

F
in.
gal.
GPH
BTU/hr
ft/sec
  To

C
cm
1
1/min
Cal/hr
m/sec
Multiply by

5/9 (F-32)
  2.54
  3.79
  0.0632
   252
  0.304
                                      93

-------
                           EXPERIMENTAL APPROACH
     The program is designed to consider present day fossil fuels including
the following:
                           Natural  gas
                          *Propane
                          *Distill ate oil
                          *Distill ate oil  doped to 0.3 percent N
                           No.  6 oil  (residual)
                          *Bituminous coal
The distillate  oils were -included in  the program because together they provide
a mechanism for examining the conversion of fuel nitrogen.   In each case the
oil is identical except that in the latter the nitrogen content has been
artificially increased to 0.3 percent (by  weight).   It has  been postulated
by Martin  and  others that any difference  in NO  emissions  between the two
                                               A
cases can be directly related to conversion of the fuel nitrogen to NO .
                                                                      /\
     In each case the fuel is  first chemically characterized and the effect
of the following burner (and process) variables on NO  emissions determined:
                                                     /\
                          *Burner swirl
                          *Fuel injector design
                           Wall cooling
                          *Fuel injector position (in the burner throat or
                               at the quarl exit)
                          *Air preheat (ambient to 600F)
                           Firing rate  (up to 300,000 BTU/hr)
                          *Combustion air velocity (45, 100, and 200 ft/sec)
      *Work either completed or already in progress.
                                   94

-------
     Because of time limitations all possible combinations  are not
investigated.  The 280,000 BTU/hr (input), 5 percent excess air, 530F
preheat, 100 ft/sec air case has been selected as a base line.  The
conditions are then varied parametrically around this.
     Once the effect of the burner  (and process) parameters on NO  emissions
                                                                 /\
is established for the normal combustor mode, the following control modes
are considered and the process repeated:
                *Low excess air (down to 1 percent)
                 Staged combustion
                *Flue gas recirculation
     As the  asterisks indicate, the experimental work is approximately 50
percent complete at the present time; the mathematical analysis and correlation
of the results is just beginning.
     This  report considers the most significant results to date; namely,
the effect of:
                (1) Fuel type
                (2) Burner swirl
                (3) Air preheat
                (4) Burner throat velocity
                (5) Flue gas recirculation
                (6) Throat velocity on the effectiveness of flue gas
                       recirculation
     *Work either completed or already in progress.
                                    95

-------
                          EXPERIMENTAL FACILITY
FURNACE DESIGN
     The experimental  furnace is  illustrated in Figure 1.   The combustion
chamber is vertical  with the burner mounted  on  top.   The walls are made of a
high temperature plastic refractory and normally run about 2500F with 530F
air preheat.  A 1.5  inch water positive pressure is  maintained within the chamber.
The chamber is cylindrical  with  a diameter of  16 inches  and is * 55 inches
long.  The six observation  ports  provide good access in two planes and at
varying heights for  flame observation, photography,  and insertion of either
a water-cooled gaseous sampling  or temperature  probe.   The burner is designed
to accept a variety  of injectors  for gas, oil,  or pulverized coal as fuel and
is water cooled.  Staged air addition is accomplished by means of water-cooled
air injectors inserted around the burner through the furnace top.  The point
of staged air addition is varied  by changing the insertion depth of the injectors.
     To cool the combustion gases prior to the  flue, a forced air heat exchanger
is attached at the bottom of the  furnace perpendicular to  its center line.
It consists of concentric steel  cylinders -  16  and 20 inches in diameter and
= 75 inches long.

SUPPORT EQUIPMENT
     The combustor supporting devices are shown in Figure  2 and are designed
to provide a wide choice of operating conditions with optimum individual process
parameter control.  Under normal  operating conditions combustion air is supplied
by an ambient temperature main blower through a manifold to the swirl, axial,
and primary (coal only) air lines.   A high-temperature (600F) blower forces
                                      96

-------
                            BURNER
                            ACCESS
WINDOW
 PORTS
EXHAUST
 STACK
                                               Figure 1.  Furnace design.

-------
                                                                      FUEL
                                                                    INJECTOR
                                                                                      PRIMARY AIR
                                                                            by
                                                                    BURNER   /
                                           .y V
                           AXIAL AIR


                           SWIRL AIR
                         EXHAUST
          SAMPLE PROBE
                            t
o
00
                                             HEAT
                                          EXCHANGER
               occ
                                                                           =
_   __ |



                     I
                                                             LAMINAR FLOW ELEMENTS
                                                                      AIR FLOW CONTROL PANEL

-------
flue gas (from the exhaust stack) through a second part  of  the  distribution
manifold to the proper air line.  The third main section of the manifold  is
connected to a bottled gas supply and provides an Ar/02  atomosphere  to  any
of the three air lines.  The flow in each of the three air  lines  (swirl,  axial,
and primary) is controlled by the manifold valves and is filtered for dust
and particulate removal before  going through laminar flow elements which  are
connected to inclined water manometers for measuring the quantities  delivered.
Each  line also has  an electric  air preheater with proportional  controller to
provide  controlled  air temperatures from ambient to 700F.

FURNACE  BURNER
      A specially  designed water-cooled burner as illustrated in Figure  3  is
provided with separate axial  air inlet and swirl chamber.   The  axial air  enters
through a  port  angled  at  = 45 degrees into the center pipe  and  then  passes
through straightening  vanes.  Swirl air enters a vaned swirl chamber via  two
tangential  ports  180 degrees  opposed and passes through  six 3/4-inch curved
swirl vanes as  shown in Figure  4.  The ID of the burner  itself  is 2.067 inches;
however, nine burner sleeves  are provided so that axial momentum can be main-
tained at  air velocities between 45 and 200 ft/sec for a variety of  mass
flows, air preheats, etc.  The  burner is fitted with a 35-degree refractory
quarl and  has an  adjustable collar at the top (inlet) to allow  for varying the
position of the fuel injector relative to the quarl exit.
                                      99

-------
  FUEL
INJECTOR
Figure 3.  Burner.



    100

-------
Figure 4.  Swirl vanes.
        101

-------
FUEL INJECTORS
     A variety of injectors are provided for each type of fuel and are
generally characterized as either rapid or slow mixing as shown in Figures
5 and 6.   Short bulbous flames are produced by the rapid mixing injectors.
The propane radial  injector has six equally spaced holes (0.05996 inches in
diameter) perpendicular to the axis.   The oil  injector is a commercial 2.25
GPH nozzle with an  80 degree solid spray angle.  The divergent coal injector
has three equally spaced (0.2656 inches in diameter) holes angled to distribute
the coal  away from  the axis.
     The slow mixing injectors give long predominantly axial flames.  The
propane axial injector has a single hole (0.1094 inches in diameter) on the
axis.  The zero degree air atomizing oil nozzle has one hole (0.5937 inches
in diameter) angled on the top to prevent clogging.  While the rapid mixing
injectors produce noticeably more stable flames, all injectors produced
stable flames from  about 20 to 95 percent swirl under most conditions.  The
work reported here  was all conducted with the  rapid mixing injectors since
these are more typical of current industrial practice.
STANDARD FUELS
     Compositions of the fuels used to date are given in Table 1.  The
propane is commercial grade and supplied from  100-gal. pressure-regulated
cylinders.  Flow is controlled by a regulating needle valve and measured on
a calibrated gas rotameter.  Distillate (#2) oil is delivered by a constant-
volume displacement metering pump which is electronically controlled to maintain
constant speed.  The 0.3-percent N distillate  oil is supplied by adding the
                                   102

-------
PROPANE
RADIAL
(6-HOLE)
   I
o    o      o
                                               FUEL OIL
                                             80 - DEGREE
                                                SOLID
                                               NOZZLE
                                      r	
                                         u
  COAL
DIVERGENT
 (3 - HOLE)
                                                                                             I
                                                                                           i
         rt
                                                                                  r     1     \
                          Figure 5.  Rapid-mixing  injectors.

-------
PROPANE
  AXIAL
(1 - HOLE)
   I I

  FUEL OIL
ZERO-DEGREE
 AIR NOZZLE
                                            ,*,
                                        AIR
                                      \    I
                                        \l
        AIR
                                             K
                                           11
                                           ,y
                                           \  /
                                            1 1
                                            ii
  COAL
  AXIAL
(1 - HOLE)
                                       k
                                       !\
                                       i    !


                                            \
                                              \
                              Figure 6.  Slow-mixing injectors.

-------
                       Table  1.   FUEL  ANALYSIS
Component
C
H
S
N
0
Ash
Wt Percent
Distillate
Oil
87.0
12.9
0.22
<.05
0.15
0.004
High Nitrogen
Distillate Oil3
86.7
12.7
0.21
0.31
0.15
0.004
Coal
69.6
5.3
3.0
1.17
9.6
10.4
Propane:  Commercial Grade with > 90% CgHg and < 5% propylene,  2%  ethane,
          1% isobutane, < 0.5% N-butane.

    aDoped to 0.31 percent N by the addition of quinoline
                                     105

-------
appropriate amount of quinoline to the oil supply prior to the combustor.
The quinoline is supplied at a constant rate from a special pressurized
feed apparatus which is controlled by a micro-needle valve and measiured by a
calibratedrotameter.  (At any given test condition the normal distillate
and 0.3 percent N distillate cases are run consecutively to minimize possible
errors due to slightly different combustor conditions, preheat temperatures,
etc.)   Pulverized coal is delivered to the injector along with the primary
air by a vibrating hopper screw feeder.  Feed rate is controlled by a
variable-speed gear motor drive.

ANALYTICAL PROCEDURES
     The flue gas sampling system used in this work is shown in Figure 7.  It
consists of:  paramagnetic oxygen analysis; nondispersive infrared analysis for
carbon monoxide, carbon dioxide and nitric oxide; flame ionization analysis
for unburned hydrocarbons; and chemiluminescent analysis for NO and N02 (NOX).
Sample conditioners consist of a dryer (water condenser) and two particulate
filters in the main sample line.  When burning coal a glass wool trap is
placed upstream of the dryer.
     The Q, CO, C02, and HC analyzers are further moisure protected by a
Drierite (CaSO^) dessicant cannister and molecular sieve traps (Grace SMR 4-635).
The NDIR NO analyzer is also Drierite protected.   The chemiluminescent unit
requires no additional moisture removal.  The Drierite cannisters are changed
daily and  the sieves are replaced as dictated by moisture indicators.  The
particulate filters are inspected daily and replaced as needed.  The glass wool
trap is replaced before each coal test.  All instruments are calibrated with
                                     106

-------
                                                             PARTICULATE
                                                                FILTER
                                                                             GLASS WOOL
                                                                               TRAP
                       PARTICULATE
                         FILTER
                                             DRIERITE
                         O
                                                                        HANKISON
                                                                         DRYER
                                                                                                STACK
                                                                                    m//A
                 MOLE-
                 CULAR
                 SIEVE
  O
                   O
                                                                                       DRIERITE,
  PARA-
MAGNETIC
ANALYZER
>?
YZ
                                                                  GLASS WOOL
                                                                     TRAP
  NDIR
   CO
ANALYZER
  NDIR
   CO?
ANALYZER


FLAME
IONIZING
HC
ANALYZER
                                                                                  O
  NDIR
   NO
ANALYZER
CHEMI LUMI-
 NESCENT
   NOX
 ANALYZER
                                         Figure 7.  Analytical system.

-------
zero and span gas twice daily or before each test if required.
     The sample probe is a 3/8-inch diameter quartz tube placed inside the
exhaust stack.  All  sample lines are either stainless steel or Teflon tubing.

SAFETY FACILITY
     Flame failure safe operation is assured by a Honeywell R4150 flame
safeguard detection  system.  The flame signal for both gas ignition pilot
and main flame is produced by an ultraviolet flame detector.  An automatic
power-off cutout is  provided for both air flow loss and burner cooling water
flow loss.  In addition a thermal limit switch is provided for any unusual
temperature rise at  the burner.
                                  108

-------
                             DISCUSSION OF RESULTS
DEFINITION OF TERMS
     Before considering the results it is important to explicitly define
the terminology used.  All emissions data are presented as ppm NO, dry reduced
to stoichiometric (zero percent excess air).  To obtain the mass/heat input
the following conversions can be used.
Fuel
Propane
Distillate Oil
Coal
To convert to Ibs N02/106 BTU
multiply by
0.00108
0.00108
0.00147
To convert to gms
multiply by
0.00194
0.00194
0.00265
N02/106 cal



     All data are reported in terms of a swirl index for common reference.
                                                                             n
 (This  is not exactly the same as the swirl number defined by Beer and Chigier
 because the swirl vanes used in this study were curved to maximize the efficiency
 of swirl generation.)  The swirl index S, is defined as:
                               S = G^
                                      , R
where
Ge = P
and
                                  = P
              R = burner throat radius
              R  = radius at swirl vanes
              p  = oxidizer density
                                        109

-------
          V   = volumetric flow rate through swirl vanes
          V   = total  volumetric flow rate
          A   = minimum open area in swirler*
           o
          A   = burner throat area
(No claim is made for the swirl index as a universal scaling parameter;
analysis of this type is just being initiated.  It is used here only as a
reference basis.)
     Flue gas recirculation is defined as follows:
          Percent FGR = wt FGR	   x 100^
                        wt air + wt fuel
where
     wt FGR = weight of flue gas recirculated
     wt air = weight of the combustion air used
     wt fuel = weight of fuel burned

FUEL TYPE AND SWIRL
     Figure 8 shows the data taken for propane, distillate oil (< 0.05 percent N),
high-N  (0.31 percent N) distillate, and pulverized coal as a function of swirl.
In these and all other tests reported here the propane entered the burner through
a six-hole radial injector at a velocity of 300 ft/sec; distillate oil through
an 80-degree solid-cone pressure-atomizing nozzle; and coal through a divergent
three-hole injector.  All the data in Figure 8 were taken at a firing rate of
300,000 BTU/hr, 5 percent excess air, 530F air preheat, and 100 ft/sec burner
throat velocity (combustion air).  As the data indicate, the propane and
    *Based on the axial depth of the swirl vanes times the perpendicular
     distance between vanes at the point of entry into the axial  flow.
                                    110

-------
Figure 8.  Effect of fuel  type and swirl.
                  Ill

-------
distillate oil give nearly identical  average emissions; however, the oil
is more strongly a function of swirl.  The 0.3 percent N distillate has
nearly the same form as the previous  pair but is about 220 ppm higher over
the range, corresponding to about 45  percent conversion of the fuel N
(assuming the thermal component can be subtracted directly as proposed by
Martin et al.8).  The coal  data are generally the highest of all, as would be
expected.  The average emission is about 500 ppm of which a large part is
almost certainly due to the fuel  N in the coal.
     At this point no absolute evidence is available regarding the mechanism
behind the effect swirl has on each of the curves; however, the following
is proposed based on observation  of the flames,  experience, and work by
others.3'4
     Gas and Distillate Oil:   At very low swirl, combustion is delayed
     farther downstream due to poor fuel/air mixing.  This spreads the flame
     zone over a larger area and  reduces the average local flame temperature
     through both the added bulk  of entrained products and increased
     radiative heat transfer.   As the swirl  is increased, the fuel/air
     mixing increases, the combustion zone shrinks (causing increased
     local temperatures),  and  the NO   increases.  As the swirl is further
                                   A
     increased, the internal reverse-flow zone on the burner axis becomes
     substantial and begins forcing significant  amounts of burned products
     into the base of the  flame.   This dilutes the fuel/air mixture and
     lowers local  temperatures by acting as  a type of flue gas
     recirculation.
                                    112

-------
    0.3-Percent N Distillate:   The  emission  data  for the high nitrogen
    distillate follow  the  normal  distillate  curve quite closely over
    the entire swirl range.   This indicates  that  the conversion of the
    fuel nitrogen is essentially  constant (at about 45 percent) and
    therefore  is not a function of swirl  in  this  case.

    Coal:   The coal data are most easily  explained starting at the high
    swirl  setting since even the  divergent injector tends to give a fairly
    axial  coal  flame.
          As the  swirl  is decreased from its  maximum, the NO  emissions drop
                                                            A
     slightly then  begin a definite rise.   Flame photographs reveal  that
     this increase  begins at the point where  the flame lifts off the
     injector.  At the peak shown  in Figure 8, ignition is occurring about
     6 inches from the point of injection.  Thus,  as the emissions are
     increasing the point of ignition is moving steadily away from the  injector.
     The increase in NO  here is almost certainly associated with better mixing
                       A
     of coal jets and  the combustion air prior to ignition.  This, in turn,
     increases the availability of oxygen and hence the conversion of fuel
     nitrogen.  The decrease after the peak is of little consequence since
     at this point it  is not an acceptable flame for industrial use.

AIR PREHEAT
     Figures 9 through 12 show the effect of increasing air preheat from ambient
(100F) through 300F to 530F at 100 fps throat velocity and 5 percent excess  air
for propane, No.  2  oil, 0.3 percent N distillate oil, and coal.  As the data  in
Figures 9 and 10 indicate with gas and distillate oil, increasing air preheat
                                   113

-------
0.4
0.8             1.2             1.6
          SWIRL INDEX, S
2.0             2.4
     Figure 9.  Effect of air preheat using propane.
                             114

-------
3:
      0              0.4
      1.2



SWIRL INDEX, S
1.6             2.0             2.4
                         Figure 10.  Effect of air preheat using No.-2 oil.



                                                 115

-------
                              1.2
                         SWIRL INDEX, S
1.6
2.0
2.4
Figure 11.  Effect of air preheat  using No. 2 oil (0.3% N).
                          116

-------
700]
GOO
500
 400
 300
 200
 100
                                                                          530" F
                                                                       3000 F
0.4
                                   0.8              1.2
                                     SWIRL INDEX, S
1.6
                  Figure 12.  Effect of air preheat using coal.
                                        117
2.0

-------
markedly affects NO .   This is almost certainly due to an increase  in  local  flame
                   /\
temperature.  With both gas and No. 2 oil the preheated cases show  a definite
peak.  (It is certainly possible that the ambient (100F) cases would  have
also peaked had higher swirl been available.)  Figure 13 shows the  peak  NO
for the distillate oil and propane runs plotted against theoretical (adiabatic)
flame temperature for the given case.  This figure demonstrates that,  for a
given air preheat, the peak emissions from No. 2 oil are only slightly higher
than from the corresponding propane case.  Since all the data lie on the
same line (within the experimental error) this suggests that the slightly
higher emissions from oil may be due to the intrinsically higher flame
temperature (because of a higher C/H ratio) rather than to any type of droplet
burning process.  There iss therefore, some question as to the importance of
droplet burning in the thermal fixation mechanism.
     Figures 11 and 12 show that air preheat has a lesser effect on the emission
from the 0.3 percent N distillate oil and pulverized coal flames.  This tends
                                         o
to support the postulate of Martin et al.  that fuel nitrogen conversion is
not as temperature sensitive as fixation.

BURNER THROAT VELOCITY
     Figures 14 through 17 show the effect of increasing the burner throat
velocity from 100 fps to 200 fps (at 5 percent excess air and 530F air
preheat) for propane, No. 2 oil, 0.3 percent N distillate oil, and coal.  As
the data with gas indicate increased velocity decreases the NO  by about
                                                              A
60 percent.  A similar, but slightly more dramatic, effect is observed with
distillate oil.  In both cases the increased velocity increases entrainment
                                      118

-------
600
400
                                                      O NO. 2 OIL

                                                      D PROPANE
 200
 100
  80
  60
 40
 30*
  23.6
                                                                               36000
                                  37000 F
                                    f
23.8
 24.0            24.2            24.4            24.6

RECIPROCAL ADIABATIC FLAME TEMPERATURE (T-l), 105 OR-1



 Figure 13.  Peak NO emissions versus T~1.
                                                  119
24.8
25.0

-------
280
240
200
160
120
 80
 40
                                                   200 fps
                                                                       100 fps
                 0.4
                                                                 1.6
                        0.8              1.2
                           SWIRL INDEX, S
Figure 14.  Effect of burner throat velocity using propane.
                              120
2.0

-------
 0.4
0.8              1.2             1.6
            SWIRL INDEX, S
2.0
2.4
Figure 15.  Effect of burner throat velocity using No. 2 oil.

                               121

-------
   700
    600
    500
    400
a
o"
    300
    200
200 fps
    100
0.4             0.8             1.2             1.6

                          SWIRL INDEX, S
                                                                                     2.0
                                                  2.4
                Figure 16.  Effect of burner throat velocity using No.  2 oil (0.3% N).

                                                    122

-------
   1000
    900
                                                                         200 fps
    700
a
o
     600
     500
                                                                             100 fps
     400
    300
                      0.4
0.8              1.2

  SWIRL INDEX, S
1.6
2.0
                Figure 17.  Effect of burner throat velocity using coal.

                                           123

-------
of "cooler" combustion products and thereby decreases the local combustion



temperatures which in turn reduces NO.  With the high nitrogen distillate
                                     A


the percent reduction is less but the absolute magnitude is greater, indicating



a decrease in the fuel nitrogen conversion.  With coal, however, the emissions



actually increase with velocity.  Thus, increased axial velocity appears



to decrease NO  emissions where thermal fixation dominates, but gives mixed
              A


results in systems giving both thermal and fuel NO .
                                                  A






FLUE GAS RECIRCULATION



     The effect of approximately 25 percent flue gas  recirculation on the NO



emissions from each of the four fuels is presented in Figures 18 through 21.



As the data indicate, this caused about an 80 percent reduction in emissions



with propane and about a 65 percent reduction with distillate oil.  In both



cases the reduction was almost certainly due to reduced local flame temperature.



In these cases, as with all previous work to date, the effect of swirl is



essentially negligible with high FGR levels.  Hence,  in designing a burner for



high FGR running it should be possible to set the swirl to minimize operating



problems (e.g., flame instabilities), fan power, etc. without substantially



affecting emissions.



     As the data in Figures 20 and 21 show, FGR is not nearly as effective



in reducing NO  emissions from the 0.3 percent N distillate oil and coal
              A


flames.  Again, however, there is a marked difference in the behavior of the



two systems; the oil shows very little effect while the coal did experience



a' 38 percent reduction at  24 percent FGR.  These data suggest that flue gas



recirculation is going to be of limited value in systems with large quantities



of fuel nitrogen (e.g., residual oils and coals).
                                     124

-------
280
240
200
 160
 120
  80
 40
0.4             0.8
                                                 1.2
                                            SWIRL INDEX, S
                         Figure 18.  Effect of FGR  using propane
                                               125
1.6             2.0
2.4

-------
  360
_;i 200
                    0.4             0.8             1.2
                                     SWIRL INDEX, S
1.6
2.0
                    Figure 19.  Effect of FGR using No. 2 oil.
                                          126

-------
700
600
500
 400
 300
 200
 100
                  0.4
0.8
      1.2




SWIRL INDEX, S
1.6
2.0
                    Figure 20.  Effect of FGR using No. 2 oil  (0.3% N).
                                               127
2.4

-------
0.4
0.8             1.2
  SWIRL INDEX, S
1.6
2.0
  Figure 21.  Effect of  FGR using coal.
                    128

-------
EFFECT OF THROAT VELOCITY ON FGR
     In the previous sections we have shown that both burner throat
velocity and flue gas recirculation drastically reduce thermal NO  .   In
                                                                 /\
the last test series, the two were combined to investigate possible additive
effects; Figures 22 through 25 show these results.  As the data in Figure 22
indicate with propane, high air velocity and 25 percent FGR together  reduced
the uncontrolled emissions from about 240 ppm to about 30 ppm.  With
distillate oil, a similar level was achieved; however, the addition of FGR
produced no added reduction.  With the 0.3 percent N oil, the addition of
FGR has no added effect  over just increasing the air velocity from 100 to
200 ft/sec; with 25 percent FGR and high air velocity, the emissions  are still
over  200 ppm.  With coal, increasing the velocity increased the NO  as
                                                                  A
previously discussed;  however, the addition of 24 percent FGR reduced the
emissions  to  essentially the uncontrolled level.
 BURNER PRESSURE DROP
      Since burner pressure  drop  is  directly related to required fan power
 and hence operating costs,  burner AP must be considered in any analysis of
 NO  control  through burner  design.  The burner used in this work normally
   X
 runs with a  wind box pressure  of 3  inches water gauge under axial conditions.
 At high  swirl  the swirl  cage pressure is also about 3 inches water.  (The
 axial would  normally be  less than the swirl; however, this burner has axial
 straightening  vanes to ensure  proper flow of the axial stream).  Increasing
 the  throat velocity from 100 fps to 200 fps caused a corresponding increase
                                   129

-------
280
240
2001
                                                                 0% FGR (100 fps)
 1601
 120)
                                                  0% FGR (200 fps)
 401
                                           25% FGR (200 fps)
                  0.4
0.8              1.2
  SWIRL INDEX, S
1.6              2.0
         Figure 22.  Effect of throat velocity on FGR using  propane.
                                       130

-------
                                   0% FGR (200 fps)



                                           25% FGR (200 fps)
                              SWIRL INDEX, S







Figure 23.  Effect of throat velocity on FGR using distillate oil.





                                131

-------
700
600
500
 300
 200
                     25% FGR (200 fps)
                   FGR (200 fps)
                                                                                0% FGR (100 fps)
 100
                   0.4
0.8
     1.2

SWIRL INDEX, S
1.6
2.0
           Figure 24.  Effect of throat velocity on FGR  using No. 2 oil (0.3% N).

                                                132
2.4

-------
1000
 900
                                                             0% FGR (200 (ps)
  700'
  600
  500
  400.
                                           24% FGR (200 fps)
                                                                 0% FGR (100 fps)
 300
0.4
0.8              1.2
  SWIRL INDEX, S
                                                                   1.6              2.0
           Figure 25.  Effect of throat velocity on FGR using coal.
                                       133

-------
in both the axial and swirl streams to 5 inches water gauge.  FGR had
no noticeable effect on burner pressure drop but of course it did require
additional fan power and ducting.

OTHER EMISSIONS
     CO and HC emissions were continuously measured during all tests and
were essentially zero with propane and distillate.   With pulverized coal
combustion, HC emissions were always  less  than 10 ppm.   Spot checks for
NO,, were also made.   The data confirm that the primary  NO  emission is NO;
  ^                                                      f\
in all cases examined, NO^ was less than 5 ppm.
                                134

-------
                              CONCLUSIONS

RESULTS
     1.  Under as nearly identical conditions as possible average NOX
emissions are as follows:  propane  *  distillate oil  <  0.3% N oil
< coal.
     2.  Increasing air preheat substantially increases the emissions
from propane and distillate oil and causes a lesser increase with the
high nitrogen distillate and pulverized coal.
     3.  Under peak NOX conditions propane and distillate oil are
essentially identical with respect to NOX emissions.  There is little
evidence that the difference in the phase of the fuel (gas vs. liquid)
has  any significant effect on emissions.
      4.  Increasing burner throat velocities substantially reduces
emissions  with propane and distillate oil, has little effect with the
0.3  percent N oil, and increases  emissions with coal.
      5.  Flue gas  recirculation is very effective with propane and distil-
 late oil,  has almost  no effect with the 0.3 percent N oil, and is only
moderately effective  with pulverized coal.  When effective FGR is
essentially independent of burner swirl.
      6.  Doped distillate oil (0.3 percent N) and coal behave very
differently even though at least  half the NOV emissions from both are almost
                                            A
certainly  the result  of fuel nitrogen conversion.
IMPLICATIONS
     1.  Conversion of a unit from a low nitrogen oil to gas or vice versa
                                135

-------
should not result in  major  increases  (or decreases) in NOV emissions.
                                                        A
     2.   Increasing  combustion air preheat can be expected to increase
    Hi
FGR).
thermal  NO  unless  some  type of counteracting measures are taken (e.g.,
          A
     3.   Increasing  burner throat velocities (and hence entrainment of cooled
combustion gases)  can  be  as effective a control technique for thermal NO
                                                                       A
as application  of  substantial FGR.
     4.   Flue gas  recirculation cannot be expected to provide large emission
reductions with high nitrogen oils or coals.

                          NOTE
         The implications cited above (1 through 4)  are based
         on the results of this research investigations.
                                 136

-------
                              FUTURE EFFORTS
     The experimental work on this program during  the next  few months
will be directed at finishing the test matrix and  at specialized  analysis
experiments.  The present coal data will be extended to  include a wider
variety of  injector types at higher excess airs.   Natural gas  and No.
6 oil will  be examined.  Two stage combustion testing will  also be con-
ducted with each of the  fuels.
      In one of the limited, specialized  test series coal, No.  6 oil,
and  the 0.3 percent N  distillate will be burned  in an Ar/02 atmosphere.
Finally,  some of the anomalies which have surfaced so far will be examined
in  greater  detail.   For  example, increasing the  burner throat  velocity
has  been  proposed as a means of achieving flue gas recirculation  inside
the furnace (through the entrainment cooled product gases).  Further, with
gas and distillate oil increased throat  velocity and F6R do indeed  cause
similar,  significant NOX reductions.  However, with the  0.3 percent N oil
doubling the  velocity  halves  the NOV while 25 percent F6R does nothing.
                                   A
With coal,  doubling  the  velocity more than doubles the NOX  while  24 percent
F6R reduces it  by 40 percent.
                                   137

-------
                             BIBLIOGRAPHY
1.  Wasser, J.  H.  and Berkau, E.  E., "Combustion Intensity Relation-
ship to Air Pollution Emissions from a Model  Combustion System", Air
Pollution and Its  Control,  126, Volume 68, 1972 A.I.Ch.E. Symposium
Series.

2.  Heap, M. P., Lowes, T.  M., and Walmsley,  R., "The Effect of Burner
Parameters on Nitric Oxide  Formation in Natural  Gas and Pulverized Fuel
Flames," presented at the ARC/EPA "American Flame Days," Chicago,
September 1972.

3.  Heap, M. P. and Lowes,  T. M., "Nitric Oxide Production in Large
Scale Natural Gas  Flames,"  PR 10, EPA Contract No.  68-02-0202, Inter-
national Flame Research Foundation, December  1972.

4.  Heap, M. P. and Lowes,  T. M., "Nitric Oxide Formation in Pulverized
Coal Flames," PR # 11, EPA  Contract No. 68-02-0202, International Flame
Research Foundation, December 1972.

5.  Hemsath, K. H., Schultz,  T. J., and Chojnacki,  D. A., "Investigation
of NOX Emissions from Industrial  Burners," presented at the ARC/EPA
"American Flame Days," Chicago, September 1972.

6.  Shoffstall, D. R. and Larson, D. H., "Aerodynamic Influences on Com-
bustion Process Pollution Emissions," presented at Central States Section
Combustion Institute, Urbana, Illinois, March 1973.
                               138

-------
7.  Jain, L.  K.,  Calvin, E.  L.  and Looper, R.  L., "State of the Art for
Controlling NOV Emissions in Utility Boilers," Final  Report, EPA
              A
Contract No.  68-02-0241, Catalytic, Inc., September 1972.
8.  Martin, G. B. and Berkau, E. E., "An Investigation of the Conversion
of Various Fuel Nitrogen Compounds to Nitrogen Oxides in Oil  Combustion,"
Air Pollution and Its Control. 126, Volume 68, 1972, A.I.Ch.E. Symposium
Series.

9.  Beer, J.  M. and Chigier, N. A. Combustion Aerodynamics, Applied
Science Publishers, Ltd., London, 1972.
                                 139

-------
 BURNER DESIGN PRINCIPLES FOR MIHTM01I NO  EMISSIONS
                                        X
         M.P. Heap, T.JI. Lowes, R. Valmsley
                   and H. Bartelds

      International Flame Research Foundation
                   IJrauiden, Holland
Paper presented at the E.P.A. Coal Combustion Seminar,
19-^0 Juno, 197:5 lies ear ch Triangle Park, North Carolina
                         141

-------
1.  INTRODUCTION
   Various control techniques are available to reduce nitrogen oxide
   (NO )  emis
   include:-
(NO )  emissions from large steam raising plant. These techniques
   - operating modifications ie. reduced load, excess air or preheat;
   - combustion modifications i.e. flue gas recirculation or staged
     combustion;
   - burner modifications.

   All these techniques will necessitate variations in accepted plant
   operating conditions and may also increase the unit cost of the
   power produced. This paper discusses the principles upon which
   burners with minimum emission characteristics can be designed.
   The paper is mainly concerned with pulverised coal (p.f.) burners
   for utility boilers, however reference will be made to other fuels.
   In the long term burner modifications may well provide the most
   efficient method of controlling NO  emissions from all forms of
   fossil fuel fired furnaces and boilers.

   Minimum NO  emission characteristics are not the only desirable
   design feature of burners. Consideration must also be given to:

   - ignition stability;
   - fuel burnout;
   - noise production;
   - the generation of other pollutants;
   - burner production and running costs;
   - peak temperatures;
   - flame shape.

   The design principles for minimum NO  emissions will have an effect
                                       Jt
   upon many of the characteristics listed above and wherever.
   possible these effects  will be discussed in the present paper.
                                143

-------
2. NO  FORMATION IN TURBULENT DIFFUSION FLAMES
     y        		Ljjinm|I	:r-n

   The NO  emitted from fossil fuel fired combustors is the result
   of two processes:-

   - the oxidation of molecular nitrogen producing thermal N0x;
   - the conversion of nitrogen compounds contained in the fuel,
     fuel NO ;

   In order to  understand the influence of various burner parameters
   on the formation of NO  in flames it is necessary to briefly
   summarise the controlling influences on the formation of thermal
   and fuel NO
              x.

   2.1. The Formation of Thermal NO
   The formation of thermal NO  in combustion processes has been
                              .X
   studied extensively in recent years.  Although the precise details
   of the interaction between hydrocarbon combustion and thermal NO
   formation remain unknown, the controlling influences of time,
   temperature and combustion stoichiometry are generally recognised
   Pi, 2^. Virtually all attempts to control the formation thermal
   NO  involve the reduction of peak temperatures.
     Jl.

   In the majority of combustors thermal NO  formation can be
                                           J^.
   considered as a flame phenomenon since residence times at bulk
   gas temperatures are normally too short to allow the formation
   of significant quantities of NO  within the bulk gases. The amount
                                  jC
   of N0x produced within the flame region depends upon:-

   - the initial temperature of the freshly formed combustion products
     within the flame;
   - the rate of temperature decay of these freshly formed products.
                                 144

-------
Both the initial temperature and the rate of temperature decay
can "be controlled by burner parameters since these parameters
dictate the mixing pattern of the fuel, air and recirculating
gases.

The temperature of the freshly formed products of combustion within
the flame will obviously depend upon the composition and enthalpy
of the reactants. Combustion in diffusion flames is complicated
because the reactants must be mixed on a molecular scale before
combustion can take place. The location and mixture strength of
the reaction  zone  in  diffusion  flames  are matters for  conjectures;
reaction will proceed wherever  the mixture strength lies within
the limits of flammability and there is a source of ignition.
Thus  maximum  temperatures are attained when the fuel reacts in
proportions close  to  stoichiometric before either the  fuel or air
have  been  diluted  with recirculating products. The high temperature
combustion products are  cooled subsequent to formation by mixing
with  the  bulk gases and their rate of temperature decay depends
upon the rate of mixing  with and temperature of the bulk gases.
 2.2.  The Formation of Fuel  NO
                             x
 Both residual fuel oils and coal  contain nitrogen compounds.
 Although it is almost universally accepted that the oxidation of
 these nitrogen compounds contributes  significantly to the total
 NO  emission from combustion processes,very little is known concerning
 the oxidation process. The  oxidation  of the fuel nitrogen compounds
 in flames can be  considered in two stages:-

 -  the  evolution  of nitrogen compounds XN from liquid  droplets or
   coal particles;
 -  subsequent reactions of these nitrogen compounds.

 Mo  positive  identification  of the intermediate nitrogen compounds
 XN  has  been  made under flame conditions.  However it is probable
 that both the  type  of  compound evolved and the rate of the
 evolution  will depend upon the heating rate of the fuel. At the
 present time theories  concerning  fuel NO  formation must be based
                                        A
 upon information gained  from experiments with doped fuels or from
 the combustion of simple nitrogen compounds.
                              145

-------
Sternling and Wendt Pjl have recently summarised the available
information concerning the ultimate fate of fuel nitrogen
compounds in combustion processes :-

- with doped fuel oils it has been shown that the fraction of
  fuel nitrogen converted to nitric oxide increases with in-
  creasing excess air and decreases with fuel nitrogen concen-
  tration 45[]s

- it  is possible to reduce HO to Np under fuel rich conditions;
- the conversion of fuel nitrogen appears to be a strong function
  of burner/combustion chamber combination;
- flue gas recirculation does not appear to be effective in
  reducing emissions of fuel NO  5j

In order to explain the above experimental information it is
necessary to postulate some kind of kinetic mechanism. Fenimore 61
suggests that all the fuel nitrogen goes through an intermediate
compound I which reacts either to produce HO or N:-
     I + R - ^ if o +
     I + NO - '-> N2 +
Fenimore considers that R is probably OH and that I could either
be NH2 or N. In an attempt to model the reduction of NO under
fuel rich conditions Sternling and Vendt [3] account for the
formation of the  nitrogen-nitrogen bond by the reaction:-

     H + NO'	=N2 + 0                              

which is faster under fuel rich conditions than:-

     N + On	5>NO + 0                              A
                             146

-------
2.J NO  Formation in Pulverised Coal Flames
The combustion of p.f. is a complex process  involving:-

- particle heating by convection and radiation;
- rapid evolution of the volatile  fraction;
- combustion of the volatile fraction;
- char burnout.

The fuel is normally injected  into the  furnace as a  coal/air
suspension. The proportion of  air  in the primary jet varies but is
typically between  15 and 20$ of the total air flow.  The additional
air required for combustion is supplied in an .annular preheated
secondary stream surrounding the primary jet. Upon injection into
the furnace the particles receive  heat  either by radiation
from  the surroundings   (which  may  include furnace walls, bulk gases
and the ignition front) or by  convection from the preheated
secondary stream and entrained recirculating gases.  When the coal
particles reach a  sufficiently high temperature they begin to
decompose producing tars and gases usually referred  to as
volatiles. The composition of  the  volatiles  and the  particle
weight  loss   depends  upon  the time/temperature history of the
particle. Thus the rate of heating of the particle and its final
temperature influence  the quantity and  composition of the evolved
volatiles.

"The volatile fractions begin to combust when the temperature
is sufficiently high and the fuel/air mixture lies within the
flammable limits.  The time required for the  ignition of the
volatile fractions  depends upon the rate of mixing of the primary/
secondary and.recirculation gases  and the bulk gas temperature.
The distance from  the point of injection and the visible ignition
front will be referred to as the ignition distance.  The solid
particles remaining after devolatilisation, soot, cenospheres  and
cellular particles are collectively referred to as char. There is
a fundamental difference between the combustion of the char and
volatile.fractions. The reactions  involved in the combustion of
                               147

-------
the volatiles have finite rates but these are usually high
compared with the surface reactions involved in the combustion of
char. Also the combustion of the char particles involves several
steps in sequence:-

- transport of oxygen or other reactant gas to the particle
  surface;
- reaction with the surface;
- transport of the reactants away from the surface.

The overall reaction rate is,of course, dependent upon the slowest
of these steps.

NO  formation in p.f. flames may be considered in four stages:-
- fuel NO  formation during volatile combustion;
         A
- thermal NO  formation during volatile combustion;
            2.
- fuel NO  formation during char burnout;
         ji.
- thermal NO  formation during char burnout.

In the absence of definite information it is necessary to make
several simplifying assumptions concerning NO  formation in p.f.
flames in order to explain the effect of burner parameters on
total emissions.-These assumptions are:-
  the .most significant fraction of the total emission is fuel
  NO  . Thermal NO  will be produced during the combustion of the
    jt            JL
  volatile fractions but peak temperatures will be low since the
  volatiles will be diluted with entrained combustion products
  prior to ignition. During char burnout high surface temperatures
  could produce thermal NO  but this possibility is ignored.
                          JC.

  the majority of the fuel NO  is produced during the combustion
                             jC
  of  the volatile fraction. Sternling and Wendt [5] consider that
  the total nitrogen content of the initial coal will be divided
  between the char and volatile fractions and therefore char
  combustion could be a source of fuel NO . However, measurements
                                         Jx            '
                             148

-------
     tend to suggest  that  this  will be a negligible fraction of
     the total  emission.

  Accepting  these  assumptions,  then the conversion of volatile
  nitrogen compounds  to NO or N_ is explained by the following
  sequence of  events :-

  a) the coal  particles are heated and the volatile fractions
     evolved containing nitrogen compounds XN, which may react
     directly or undergo pyrolysis prior to reaction in combustion
     zones;

  b) in the  combustion zone two overall competing reactions1 can
      take place:
           XN + Y - ^  NO +
           XN 4- Z - ^ -N2 +
   The identity of reactants Y and Z needs to be specified.  The
   ultimate conversion of XN to either N ' or NO is dependent upon
   the quantity of oxygen associated with the combusting volatiles.
   In oxygen rich regions reaction 5 will predominate and the
   formation of fuel NO  is promoted. In oxygen deficient regions
                       .X.
   reaction 6 is dominant and the conversion of fuel nitrogen to
   NO is limited. Burner parameters can be used to vary the  emission
   of NO  from p.f. flames because they control the mixing history
        JC
   of the fuel particles, the combustion air and the recirculating
   gases which will dictate the oxygen available during the
   combustion of the volatile fractions.
5.  BURNER DESIGN PARAMETERS FOR THE CONTROL OF NOY EMISSIONS
   PROM FOSSIL FUEL FLAIiES
   Investigations at IJmuiden have shown that NO  emissions  from
                                                wd
   natural  gas,  fuel oil- and p.f.  flames can be  varied over  a wide
   range by a  suitable  choice of burner parameters.  The parameters
   which have  been investigated include:-

                               HP

-------
- the method of fuel injection;
- the position of the fuel injector;
- the degree of swirl in the combustion air;
- the velocity of the combustion air;
- the angle of the burner exit;
- the presence of swirl impellers on the oil gun;
- the division of the total air between primary/secondary and
  tertiary streams;
- the velocity of the tertiary stream.

The investigations were carried out in an almost uncooled
refractory tunnel furnace (2 m x 2m x 6.25 m) and relate to single
burner emissions. The burner used during the investigations(see
fig. 1) had the facility to vary the swirl intensity of the
secondary stream continuously from zero to a maximum value deter-
mined by the burner geometry.

In the results presented in this paper the swirl intensity of the
secondary stream will be expressed as a relative swirl index, Rg,
defined by:
        _ Actual opening of the swirl blocks
      s ~ Maximum opening of the swirl blocks
Figure 2 shows the relationship between E  and S, the swirl number
                                         S
for several combinations of burner throat diameter and outside
diameter of the primary pipe. Swirl number is a dimensionless cri-
terion that has been used to characterise swirling flows and is
defined by:
      o   flux of angular momentum
      D 
         flux of axial momentum x burner radius

The  two parameters with the most influence on NO  emissions are
                                                Jt
the  method of fuel injection and the swirl intensity of the
combustion air. Figures 3, 4 and 5  illustrate how flue gas nitric
oxide concentrations depend upon 'these parameters for natural  gas,
fuel oil and pulverised coal flames. The combination of these
parameters also controls such important characteristics as flame

                             150

-------
stability,  smoke production and heat release rate. The influence
of the method of fuel injection and the swirl 'intensity of flame
characteristics can be more easily understood by reference to the
flame classification scheme presented in fig. 6. This scheme
refers to gaseous, liquid and solid flames.

a) Lifted Flames (fiff. 6a)
The ignition front is stable some distance downstream from the
primary injector. The stabilisation of lifted natural gas flames
is helped by high external recirculation temperatures. In
increase in' throughput can blow-off the lifted flame completely.

b) Injector Stabilised Flames (fig. 6b)
This  type of flame is normally produced by single hole injectors.
Stability is achieved either by a "bluff body effect" or by an
auxiliary pilot. Although the fuel jet is entirely surrounded by
flame,  the flame does not completely fill the burner exit.

c) Primary Jet Penetrating; a Region of Reverse Flow (fig. 6c)
With single hole injectors of high primary velocity and "medium"
swirl or low primary velocities and low swirl it is possible that
the  primary  jet will penetrate the swirl induced internal reverse
flow zone. The internal reverse flow zone then takes the form of
an annulus surrounding the central fuel jet. The flame may be
divided into two sections, a short bulbous zone close to the burner
and  a long tail. The two sections are connected by a neck  which under
particular circumstances may break and only the bulbous base remains.

d) Divided Fuel Jets (fig. 6d)
This  type of flame with a closed internal recirculation zone on
the flame axis  is characteristic of the type of flame used in
utility boilers. It is short with a high heat release rate per
unit volume of  "flame". It can be produced in p.f.  flames with
intermediate  swirl values by using radial injectors,  coal spreaders,
annular injectors or low velocity single hole injectors.  This type
of flame is produced with fuel oil by the use of pressure jets or
steam atomised  injectors.
                              151

-------
Although the flames of different fuels can be classified according
to the simple scheme shown in fig. 6, their emission characteris-
tics are dependent upon the fuel type. Thus although p.f. flames
with divided fuel jets always give maximum emissions, the emission
levels of all four types of natural gas flame are similar under
particular conditions.

In section 2 the conditions necessary to reduce the formation of
"both thermal and fuel HO  were discussed. Ample experimental
                        jt
evidence has been obtained to show that burner parameters affect
NO  emissions from natural gas, fuel oil and p.f. flames. Emissions
  A
from p.f. flames can be reduced to the same level as those of
natural gas and fuel oil flames with comparable input conditions
(i.e. preheat and thermal load). However, to achieve this
emission level radically different flame characteristics must be
tolerated. Consequently design parameters for minimum NO  emissions
                                                        ^C
can be judged from two viewpoints:-

- what are the burner parameters necessary to give minimum
  emissions regardless of flame characteristics?
- which parameters can be used to reduce emissions without
  seriously affecting flame characteristics?

Flame characteristics are not the only consideration, the design
parameters necessary to reduce HO  may also increase the burner
                                 *h
pressure drop or increase burner maintenance costs.

If the assumptions suggested in section 2 are correct then the
minimum 110  emissions are achieved by restricting the available
          A.
oxygen during the combustion of the volatile fractions. Ideally
the volatile fractions containing the nitrogen compounds XH should
burn in a diffusion flame because this would give the minimum
conversion to HO 3 j. However this is not possible since the coal
is supplied with air and the volatiles are mixed with air as they
are evolved from the coal particles. Also mixing of the primary
and secondary streams prior to ignition will increase the oxygen-
coal ratio from the input condition.  '
                              152

-------
The emission curve presented in fig; 7 illustrates the reduced
emission resulting from restricting the amount of primary/secondary
mixing. These results were obtained accidentally. Initially  the
fuel injector was uncooled and at high swirl levels with the
ignition front stable on the injector a coating of red hot char
was deposited on the thick interface. This char acted as an
ignition source so that when the swirl was reduced to zero the
ignition zone remained stable on the injector. Pig. 7 shows
measured flue gas HO concentrations as the swirl level is increased
to a maximum and then decreased. The coal jet was always enclosed
by a visible ignition zone as the swirl was reduced to zero.

The only significant difference between the emission levels is at
low swirl  levels. This difference is attributed to the variation
in the coal-oxygen ratio during the combustion of the volatile
fractions  for  the lifted flame and the injector stabilised flame.
Prior  to injection the coal oxygen ratio of the two flames is
identical. However the lifted flame has an ignition distance of
approximately  0.75 m and mixing between the primary and secondary
 stream increases  the amount of oxygen associated with the volatile
 fractions. With the  injector stabilised flame the oxygen available
 for mixing with the  evolved volatile fractions is limited to that
 of the input primary stream since the primary and secondary
 streams are separated by a region of combusting volatiles.
Provided sufficient  combustible gases are available and the ignition
front  is  complete, oxygen  from the secondary stream will not be
able  to penetrate into the fuel jet.
 Thus  the conditions necessary for minimum 1TO  emissions from p.f.
 flames are:-
  minimum primary air supply;
  minimum primary/secondary mixing prior to completion of the
  combustion of the volatile fraction;
  ignition stability at the injector;
  dilution of the secondary air with recirculating combustion
  products prior to contact with the fuel.
                              153

-------
These conditions are satisfied by using a single hole high velocity
injector positioned at the exit of the burner divergent. The coal
is supplied with the minimum amount of primary air and swirl is
used to stabilise the ignition at the injector. The consequence
of variation from these conditions can be seen from the following
examples:-

- Fig. 8 shows the effect of primary velocity; the higher the
  primary velocity, the lower the emission level. The variations
  in emission level are caused by variation in mixing pattern
  produced by the interaction of the internal reverse flow regions
  and the primary jet. Lifted flames -were observed with all injec-
  tors for swirl levels less than R  =0.4.  With the low primary
                                   s
  velocity of injectors B and C the swirl induced reverse flow
  zone is sufficient to split the fuel jet as it emerges from the
  injector producing the flame type shown in fig. 6c. Thus primary/
  secondary mixing is enhanced and emissions increase. As the
  swirl level is increased,  combustion within the burner divergent
  intensifies causing an increase in axial momentum which enables
  the primary jet to penetrate the internal  reverse flow region.
  The primary/secondary mixing is reduced and consequently the
  emission decreases. Injector B, which has  the lowest primary
  momentum, produces a flame with a divided   fuel jet which then
  changes to a flame where the internal reverse flow zone is
  penetrated by the fuel jet and then reverts to a divided fuel
  jet flame as the swirl is  increased?

- The effect of increasing the primary air supply whilst maintaining
  the primary velocity can be seen in fig. 9.  Minimum emissions
  are obtained with the lowest primary air percentage;

- Figs.lOa and 10b show that emissions  are less when the injector
  is  placed at the exit of the divergent and emissions are less
  with a divergent angle of  25 rather than  a parallel exit.
                              154

-------
Earlier it was stated that flames with divided fuel jets are
normally used in utility boilers. It is possible to produce this
type of flame without swirling the combustion air by  injecting the
p.f. normal to the burner axis. Provided some swirl is used
divided fuel jet flames can also be produced with an  annular or a
low velocity single hole injector or some other device to spread
the fuel. Due to the rapid mixing divided fuel jet flames have
high heat release rates and wide ignition stability limits.
However, this flame type has the maximum ITO  emission characteris-
tics with p.f.  It is believed that this is because the coal
particles are intimately  mixed with all the available air, thus
providing ideal conditions for fuel 110  formation.
                                      JK.

The results presented in figs. 11. and 12 show that with radial or
annular injection varying swirl or primary air percentage has
very little  influence on the emission level. Using a  coal "spreading
injector"  three possibilities exist  to vary emission levels:-

- vary the swirl  level  of the secondary air. In fig.  13 it can
   be  seen that  ITO  emissions increase as the swirl intensity of
   the  secondary air increases. This type of injector  would not
   normally be used  at  swirl levels less than R  = 4 since ignition
                                              s
   is not stable  within  the burner exit. At high swirl intensities
   the  emission  is reduced after the flame form passes through an
   instability condition. The difference between the high and low
   emission conditions   is visually apparent: at high  swirls the
   flame forms a closed  ball;

-  increase the primary  air flow. Emissions are reduced because the
   increased axial momentum reduces the effectiveness  of the spreading.
   device and thus less  fuel/air mixing takes place (see fig. 14a).

-  change the position of the point of fuel injection. In fig. 14b
   it can be seen that emissions are reduced when the point of
  injection is changed. Emissions are less when the injector is
  moved towards the exit plane of the burner.

                               155

-------
   Although emissions from divided fuel jet p.f.  flames can be
   reduced by burner parameters,  the reductions are bought at the
   expense of increased burner pressure drop (to  produce swirl) or
   by a lengthening of the flame.  Recent work at  IJmuiden has shown
   that triple concentric  burner  systems have the potential to reduce
   emissions from flames with divided fuel  jets with gaseous liquid
   and solid fuels. However,  the  tertiary velocity is critical and
   incomplete combustion may  result from inadequate burner design.

4. CONCLUSIONS

   Jk.
   NO  emissions  from fossil  fuel  fired furnaces  and combustors can
   be reduced by  the optimisation  of burner design parameters.

   it
   NO  emissions  from p.f. flames  can be reduced  to the same level as
   those from comparable gas  flames.  However,  the reduced emission is
   achieved by a  radical change in flame form.  Adequate ignition
   stability and  burnout are  possible but the  flame becomes longer
   and thinner.
   Limited reductions  are possible with flame forms which  are  in use
   at present.
   Burners with tertiary  air  supplies can be designed  to reduce NO
   emissions  without  changing the flame form. However,  care must be
   exercised  in design, otherwise CO and solid emissions can be
   increased.

   ACKNOWLEDGEMENTS

   The  work reported  in this  paper was carried out under contract
   number 68-02-0202  for  the  Environmental Protection  Agency.
                                156

-------
REFERENCES
  ~  BREEN, B.P.
     Emissions from Continuous Combustions System. Ed. ny
     . Cornelius and V.G. Agnew, Plenum Publishing Corp.,
     New York p. 325.


 2~  WESTENBERG, A.A.
     Comb. Sci. Techn.  59 (1971).


 3~  STERKLING, C.Y. and WENDT, J.O.L.
     Kinetic Mechanisms governing the Pate of Chemically Bound
     Sulfur and Nitrogen in Combustion. Final Report EHS-0-71-45
     Task  14 Shell- Development Company, Emeryville, California
     (1972).


 4"  MARTIN, G.B. and BERKAU, E.E.
     An Investigation of the Conversion of Various Fuel Nitrogen
     Compounds  to Nitrogen Oxides in Oil Combustion. Paper
     presented  at A.I.Ch.E.   National Meeting Atlantic City
     1971.

  5~  TURNER, P.V. et-al.
     Influence  of Combustion Modifications and Fuel Nitrogen
     Content  on 1TO   Emissions from Fuel Oil Combustion.
     Paper presented at Annual Meeting of A.I.Ch.E.,San Francisco
      1971.

  6~  FENIMORE,  C.P.
     Combustion and  Flame  J2 289  (1972).
                               157

-------
                                                APPEHDIX I.
FUEL COMPOSITIONS

  Natural Gas
    CH4                  81,3 #
    C2H6                   2,9 /o

    C3H8                   0,4 $
    C4H1Q                  0,4 *
    CnHm                   0,1 %
    C02                    0,8 fo
    N2                   14,4 #
  Fuel Oil
    C                    86,05fo
    H2                   11,54?*
    N2                     0,24fb
    S                      C
    Ash                    C
  Coal
    Volatile Content     32
    ish                    
    C                    78,487o
    Hp                     4,77?
                          0,75?^
                              158

-------
                                                     APPENDIX II.




  COAL INJECTOR CHARACTERISTICS
                                                              _ t
Injector    Outside Diameter      Mean Primary Velocity m sec.
                   cm.            10?o          20$           30$
                              Primary air  'Primary air   Primary air



    A             11,5            19           38            57



    3              6,0            19           38            57



    C              6,0            26           52



    H              6,6            52
                               159

-------
                   JEUtt
fe?
block adjustment
mechanism
                         fuel gas nozzle
                         (throat DOS.)
                            cooling
                            water
                                                fixed blocks
                                                          movable blocks B-j
Fig -1: Moving  block   swiri   burner

-------
2.0-
1,5
0.5
 0
      Curve
2
3
A
       Throat
        diam.
         Injector
           o.d
17,6cm
13,1 cm
17,6cm
13.1 cm
           0,2
             0.4
                        Q8
1.0  R
  Fig. 2 ;The relationship  between  relative  swirl
         index   Rg  and  swirl  number S
                          161

-------
 NO
ppm
 100-
    A
  80-
  60
  40"
             Injector  Type_
             A  Multihole  Divergent
             x  Multihole  Radial
             o  Single Hole Axial
  20-
           Lifted  flame
    0
0,2
OA
06
0,8
1,0 R,
 Fig -3 -.The  effect  of  swirl and  injector type on NO
        emissions   from  gas  flames  5% excess air
        throat 176cm diam   injector  in  throat
        injector od 6,0 cm
                            162

-------
                                       Atomiz er   Type
                                       x  Single hole air
                                         Pressure Jet  30 Spray
                                       a  Steam 100 Spray
                                        x-	-x
100
                    0.4
0,6       0,8
1,0 R<
 Fig. I*: The effect of oil  injector type and  swirl  on
        NO  emissions
      (divergent  35 excess air 5%  injector 6,0cm o.d
        in  throat   secondary  air  30 C )
                           163

-------
400?
200-
                Injector  Type
                x   Single hole A
                              C
                o              H
                A   Radial hole
 0 L
   0
0,2
OA
0,6
0.8
10 R,
Fig - 5: Effect of swirl and injector  type on the emission
      characteristics  of PF flames
     (30QC  preheat -  5%  excess  air )
                        164

-------
         N    Ignition
       oC?distance
            a) Lifted  flames
                           Ignition  zone
            b)  Injector  stabilised  flame
                    Reverse  flow
            c)  Primary  jet  Penetrating  Internal  Reverse
                                                    Flow
              Reverse  flow
           d) Divided  fuel  jet
Fig. 6  : Simple  Flame  Classification   Scheme
                          165

-------
NO
ppm

 8001
                                o  Swirl Adjustment  Increasing

                   \            a    .,       ,,       Decreasing
                    1
 700      X       I
                    I
                    1  Lifted Flame
                    I
                    I
                    I
                    I
                     1
 600
  500
I
1
                              Injector  Stabilised
                                       Flame
                       0,4       0,6        0,8        1,0  Rs

   Fig-7:Effect  of  stabilisation of ignition  front  on the
         injector  ( 5% excess air 300 C preheat
         injector  o.d. 6,0 cm  throat  17.6cm  diam)

-------
   0
Fig 8 :The  effect  of  primary  velocity (throat 17.6cm diam.-
      5%  excess air-300 C  preheat - primary air 10%
      of  stoichiometric)
                         167

-------
 NO
ppm
          Proportion of  Primary air
          x   30%  of  stoichiometric  (B)
             20%  of  stoichiometric  (C)
          o   10%  of  stoichiometric  (H)
 600-
 400-
 200-



                                         X
    0
02
0.4
0.6
0.8
1.0 Re
  Fig 9: Effect of  primary air  supply  (throat 176cm  di
        inj'ector  at  throat - 5%  excess  air-300C preheat]
                           168

-------
                                Injection  position
                                o  throat
                                  exit
300
200-
   0        0,2       0,4        0,6       0,8        1,0 Rs
Fig.lOa; Effect of injection  position (injector  H - throat
         17.6cm  diam - 5% excess air-300C preheat -
         10% primary  air
                             Burner  exit  geometry
                               parellel   exit
                             o  25 divergent
200
   0        0,2       0,4        0,6       0,8       1,0  Rs
 Fig. 10b:Effect  of  burner  exit geometry (injector H at exit-
         throat  176cm diam-5% excess air-300Cpreheat
         10% primary air
                           169

-------
  700-
  600-
      Proportion  of  primary air
    x 10/o  of stoichiometric
    o 20%  of stoichiometric
                                          0.8
                             1.0 R
     o        02       OA        0,6
Rg-11 Emission  characteristics of  divided fuel jet  flames
      .produced  with  a radial  injector (injector 6,0 cm o.d-
      throat 176cm diam.- 5% excess air-300C preheat I
 NO  J
ppm
 700
 600-
 500-
        /   Proportion of primary  air
           o  20/o  of  stoichiometric
           B  30%  of  stoichiometric
             0,2
OA
                                 0.6
0,8
1P Rs
Fig-12:Emission  characteristics  of divided  fuel  jet
       produced  with an  annular injector (injector 11.5cm
       throat 17.6cm diam-5%excess air-30QC  preheat)
                           170

-------
 NO
ppm
  900
  800
   700
  600
                                           x
     0       Q2       0,4       0,6      0,8   Rs   1,0
 Fig. 13 : The Affect  of  swirl  on  NO  emissions  with
                          device
       J_30 (LfCL preheat, - 15%  excess air
        25 diver g ent   17,6 cm  id.  throat
        injector  6,0 cm   o.d.  in  throat )

-------
           NO  REDUCTION TECHNIQUES
              X.

                           IN


          PULVERIZED COAL COMBUSTION
                          by
        Christopher England and John Houseman


     Jet Propulsion Laboratory,  Pasadena, California
 (Presentation to the Pulverized Coal Combustion Seminar,

June 19-20, 1973, National Environmental Research Center,

        Research Triangle Park, North Carolina)
                          173

-------
                     NO REDUCTION TECHNIQUES IN
                        x
                     PULVERIZED COAL COMBUSTION*
                                     by
                  Christopher England and John Houseman
               Jet Propulsion Laboratory, Pasadena, California
                              INTRODUCTION
      The technology of the combustion of coal in utility boilers has been
developed to optimize combustion efficiency, plant efficiency,  and boiler life-
time.  Increasing restrictions on emissions, however,  require new procedures
which balance overall efficiencies with emission control.  Because flue gas
treatment to remove low-level pollutants is generally uneconomical,  other
means are being sought to prevent the formation of undesirable compounds
during the combustion process.  These efforts center on fuel-processing to re-
move sulfur,  ash and nitrogen compounds in the coal, and on combustion pro-
cess modifications to prevent the formation of oxides of nitrogen.

      Several studies have been made of the effect of low excess air operation
(_!_, 2, 3) and staged combustion (4)  on NO  emissions from pulverized coal
combustion, and all showed reduced emission levels  with reduced excess air.
Data are available,  however, only over limited  ranges of coal-air stoichio-
metry,  primarily because of experimental difficulties in operating at rich or
very lean conditions.  Other combustion modifications designed to lower peak
flame temperatures,  such as reduced air  preheat and product gas recirculation,
have  not been studied widely, and their effects are not fully understood.

      The present paper describes a study in which coal was burned in a pre-
fired tubular furnace in which air-fuel ratio and air preheat (both primary and
secondary) could be varied  routinely and independently to determine their  effects
on NO  production.  The purpose of the study was  to  obtain parametric data over
*This paper presents the results of one phase of research carried out at the Jet
 Propulsion Laboratory,  California Institute of Technology,  under Contract No.
 NASA 7-100, sponsored by the National Aeronautics and Space Administration.
                                    175

-------
 the widest possible range of operating conditions to evaluate the effects of the
 various combustion process modifications on NO  emissions.
                                                Js.

                        EXPERIMENTAL APPARATUS

 Furnace

      Combustion was carried out in a horizontally-fired Mullite furnace tube
 with an inside diameter of 7. 6 cm (3. 0 in.) and an overall length of 154 cm
 (60 in.). The furnace was insulated with approximately  0.6 cm (0.25 in.)  of
 zirconia fiber wrapping,  and with approximately 5 cm (2. 0 in. ) of vermiculite
 packing (see Fig. l).   Pulverized coal was fed from a conventional vibrating
 screw feeder at  a variable rate,  usually from about 1. 3  to 5. 5 kg per hour
 (3 to  12 lb/hr).  Coal was mixed with primary air by  means of a jet ejector which
 used  primary air as the working fluid.  The  amount of outside air inducted with
 the coal was determined by calibration without coal flow  and by  neglecting the
 influence of the solids on the induction rate.   The coal-air mixture entered the
 furnace through  a 2. 5 cm  (1. 0 in.) diameter tube,  the flow from which was
 interrupted by a bluff-body stabilizer as shown in Fig. 1.  The stabilizer was
 used to increase combustion efficiency over  that of coaxial injection.  Secondary
 air was added from a concentric ring which introduced air uniformly into the
 furnace.  Natural gas, used for prefiring, was introduced with the primary air.
 Both primary and secondary air streams  could be preheated independently,
 with maximum capabilities of  66 C (150F) and 400 C (750 F),  respectively,
 at the 3.2 kg/hr  (7 lb/hr)  nominal feed rate.   Coal and air feed  rates were con-
 trolled  remotely, the  former by D.C. motor control on the screw feeder,  and
 the latter by remote flow regulators which controlled  the  pressure behind  criti-
 cal flow metering orifices (see Fig.  2).

 Sampling System

      Chemical samples were  taken at the furnace exit and analyzed by a non-
dispersive infrared analyzer (NDIR) specifically for nitric oxide. A water-cooled
quartz probe was used which separated particulates from the gas to be analyzed
by inertial techniques. Figure 3 shows a schematic drawing of the probe.   Dirty
                                     176

-------
              NITROGEN BLANKET
LIVE COAL BIN
PREHEATED PRIMARY AIR
                                            NATURAL  GAS
                                                            ttWVWttmttZ ZIRCONIA rax:;*:*:*:*:.:*:-:*?
                           PREHEATED SECONDARY AIR

                                                                                                6 cm
                                                           v///////.
W////////////A
       Fig.  1.  Schematic Drawing of Coal Feeding Apparatus and Coal Burner

-------
-J
oo
            M-
             V
          Y AIR
                               QUADRUPOLE MASS
                               SPECTROMETER
                         NON-DISPERSIVE
                         INFRARED ANALYZER
MULLITE
FURNACE
                               3" I.D.
                                 60"
                  SECONDARY AIR
X


X



O_






COLD
TRAP



COLD
TRAP


\
r
1
]
1
-W\r




-78C
0C

1
PROBE
COOLING
WATER
1

i
^
^/
//Y/
yy,
///:






QMS
AMPLIFIER
O/-W



NDIR
_Q AMPLIFIER


TO COMP

9 9
TELE


INPUT FROM
PRESSURE TRANSDUCERS

AMPLIFIER

-I r
MULTIPLEXER
1
DIGITAL
VOLTMETER

 THERMOCOUPL
CONTROL ROOM
                                                                                                          COMPUTER
                     Fig.  2-  Schematic Drawing of Coal C ombustion Apparatus and Ins trvzmentatiora

-------

3.

5"
 


TO WATER ASPIRATOR 
 	 ^ a/i6" i.u.
It

_x


i


_x


COOLING WATER OUT<~ 	

-^


V.

^_
T
^^ QUARTZ WALL AND TUBING
4 1 rii r>l*
^ 1 ,ZO UIA.
^ SAMPLE TO NDIR

Fig. 3.  Schematic Drawing of a Water-Cooled Dirty Gas Sampler
                               179

-------
furnace gases were aspirated into the probe at a rate of about 40 */min,  corre-
sponding to a sampling velocity of about 30 m/sec.  A particulate-free gas
sample was withdrawn from this stream by pumping at right angles to the
accelerated dirty sample stream.  The sample rate of the clean gas stream was
approximately  1.5  A/min.  Cooling water at 88 C (190 F) was circulated to pre-
vent condensation of water in the  probe.  Clean gas samples were then dried by
successive wet ice  and dry ice cold traps, and analyzed by the NDIR.
Coal
      The coal used in the study was from the Mojave  field,  and was supplied
as a wet powder.  The material was air-dried and sifted through a 160-mesh
screen.  The  resulting powder was  such that 70% passed through a 200-mesh
screen.  The  ultimate analysis for this  coal is given in Table 1.

                  Table 1.  Ultimate Analysis of Mojave Coal
% c 	
% H 	
% S 	
% N 	
% O 	
% Ash ....
Btu/lb ....
68.3
5. 16
1.0
1. 21
23.4
10.9
9, 520
Temperature Measurements

      Furnace temperature was measured with platinum-platinum/10% rhodium
thermocouples placed on the outside of the Mullite furnace tube.  Thermocouples
were placed at 2.5 cm (1 in.), 50 cm (20 in.) and 140 cm (54 in.) from the burner.
In addition, a bare-wire thermocouple was placed in the exit plane gases to mea-
sure the temperature  of the sample.  The furnace temperature was taken as the
middle (50 cm) thermocouple temperature.  Air temperature measurements,
both for  air preheat and flow  metering,  were made with chromel-alumel thermo-
couples.  All thermocouple readings were  referenced to 65.56C (150 F).
                                     180

-------
Experimental Procedure

     The furnace was prefired with natural gas and preheated secondary air
before  each experimental point was taken.  Upon achieving proper furnace
temperatures,  primary and secondary air flows were  adjusted, the natural gas
flow was stopped,  and coal was introduced.  Peak furnace temperatures from
prefiring ranged from 1400 C  (2550 F) to 1300C (2370 F), depending on the
level of secondary air preheat. The NO  emission level was read when the
                                       ji.
furnace temperature dropped to the desired point.

                         EXPERIMENTAL RESULTS

Effect of Equivalence Ratio on NO
                                 J\.

      Both constant air flow and constant fuel flow tests were made to determine
the influence of equivalence ratio (defined as fuel-to-air) on the formation of NO  .
In the  case of constant air flow,  the primary air  rate was  1.37 kg/hr (30.2 Ib/hr)
and the secondary air rate was 28. 2 kg/hr (64. 3  Ib/hr). At stoichiometric con-
ditions (air-fuel ratio of  13. 8), the coal feed rate was  3.11 kg/hr (6. 85 Ib/hr).
The primary air preheat level was  65. 6 C (150 F) while the secondary  air was
unheated and entered at 21 C (70 F).   For tests with constant fuel flow, the coal
feed rate was maintained at 3.52 kg/hr (7.75 Ib/hr), the primary air remained
constant at 13.7 kg/hr,  and the secondary air was variable. In each case, data
were taken when the furnace temperature fell to 2100F.

      Figure 4 compares the results of each method of operation on an as mea-
sured  basis.  For constant air flow, the level of  NO  increased steadily from
160 ppm at an equivalence ratio of 0. 5 (200% theoretical air) to a maximum of
1160 ppm at an  equivalence ratio  of 1. 8 (56% theoretical air).  The NO  -equiva-
lence ratio  profile was nearly  linear and it appeared that the data may have
reflected  a  counting of coal particles, with each particle contributing equally to
NOx production.  The results  with constant fuel flow,  however, showed quite
similar results,  indicating that the  effect was truly attributable to mixture ratio.
      Figure 5 shows the same data but reduces the NO  levels to an equivalence
ratio of unity.  This was done by dividing the NO value as measured by its
                                     181

-------
oo
to
              i
              CL
              X
              O
              z

              (J
              Z
              O
              u
1000
 800
              u_   600
                   400
 200
                     0
                              FURNACE TEMPERATURE = 2100  F
_   COAL ANALYSIS:
          C
          H
         ASH
          S
          N
                              CONSTANT AIR
                              FEED RATE (94.5 Ib/hr)
                                                   CONSTANT COAL
                                                   FEED RATE (7.75  Ib/hr)
                                                                   FUEL-RICH
            68.31%
             5.16%
             10.99%
              1.00%
              1.21%
                              0.2      0.4       0.6      0.8       1.0      1.2
                                                     EQUIVALENCE RATIO
                                                                 1.4
                                                                      1.6
                  Fig.  4.  Influence of Burner Equivalence Ratio and Furnace Operating Procedures
                            on Nitric Oxide Emissions from Pulverized Coal Combustion

-------
 II
-e-
   1000
z
Q
z
LLJ
U
Z
o
u
    800
o
UJ
ss


I
o.
 V
LU
X  600
O
Z 400
   200
                  FURNACE  TEMPERATURE = 2100F
                             CONSTANT AIR FEED

                               RATE  (94.5 IbAr)
                                                    CONSTANT COAL FEED

                                                       RATE (7.75
                                 I
              0.2     0.4      0.6      0.8      1.0


                                 EQUIVALENCE RATIO
1.2
1.4
1.6
    Fig. 5.  Influence of Burner Equivalence Ratio and Furnace Operating Procedures

               on Nitric Oxide Emissions from Pulverized Coal Combustion

-------
equivalence ratio.  This  procedure is  accurate in air-rich flames where the
oxidation product is primarily CO ,  but is not accurate in fuel-rich flames where
the composition of the combustion gases is uncertain.

      On a reduced basis, the level of NO  was relatively low in the very lean
                                        !X
flames,  but approached a steady value of about 650 ppm between equivalence
ratios of 0. 9 and 1. 8.  The fuel-rich behavior was quite unexpected since one
expects  a reduction in both fuel nitrogen conversion and air nitrogen fixation in
the overall reducing atmosphere  of the fuel-rich flames.  Since the  same be-
havior was observed in both constant air and constant fuel operating modes,
however, the effects must be attributed to those of air-fuel  stoichiometry. For
the Mojave coal, fuel nitrogen amounted to 1.21%,  corresponding to nitric
oxide levels  of about 1550 ppm on a dry basis.  It is possible that the constant
650 ppm level represents the volatile part of the fuel nitrogen,  i.e., the  fraction
'that burns first in  an overall oxidizing atmosphere.

The Effect of Secondary Air Preheat

      To test the influence of combustion air temperature on NO , the tempera-
                                                               5t
ture of the secondary air was varied while holding  the primary air preheat tem-
perature constant at 65. 6 C (150F).  The tests were run with  a constant air
feed rate with variable coal  feed.  Primary air represented 31% (13. 7 kg/hr)
of the total air,  and the coal feed rate  at stoichiometry was 3. 1 kg/hr (6. 85 Ib/hr),

      Figure 6 shows the results of tests over a range of equivalence ratios,
and secondary air  temperatures,  but a constant furnace temperature of 2100F.
Secondary air preheat appears to have a strong influence on NO in very  air-rich
                                                              3C
flames, with  NO  levels at an equivalence ratio of 0. 5 (200% theoretical air)
               X.
ranging  from 450  ppm without preheat  to 1250 with 343 C  (650 F> preheat.  All
NO -equivalence ratio profiles,  however, converged on the 650 ppm level in
fuel-rich flames.   At an equivalence ratio of 0. 8 (125% theoretical air) where
industry prefers to operate, the reduction in NO with secondary air preheat
                                               ji.
amounted to  38% as the secondary air  preheat  dropped from 343 C (650 F) to
21 C (70 F).  The primary air was preheated  only to 66 C (150 F) and repre-
sented almost a third of the  total air.  Thus, the average  air preheat at  343 C
(650 F)  secondary air preheat was approximately 257 C (495 F).
                                      184

-------
00
Ul
               II
               -6-
               O

               Q 1000
               UJ
               Q
               LLJ
                  800
O
X  600

U
                  400

              UJ
              U
              Z
              O
              U
                  200
                                                      FURNACE TEMPERATURE = 2100 F
                                         (70F)
                                 I
FUEL-RICH -

  I	I
              0.2      0.4       0.6       0.8       1.0
                                     EQUIVALENCE RATIO
          1.2
1.4
1.6
                    Fig.  6.  Influence of Burner Equivalence Ratio and Secondary Air Preheat
                             on Nitric Oxide Emissions from Pulverized Coal Combustion

-------
The Effect of Furnace Temperature

      The prefired furnace was designed to operate over a very wide range of
stoichiometry,  and, as a result, had a high surface-to-volume ratio (0. 526 cm" )
relative to other furnaces of similar throughput. Thus,  the effect of furnace wall
temperature would be magnified in this furnace if,  indeed, the wall temperature
influenced NO  formation.  Figure 7 shows the  results of tests with 343 C
secondary air preheat at three air-coal mixtures.  As expected,  lower furnace
temperatures lower NO   emissions,  but the reduction from 1200C (2200 F) to
                      .X
870 C (1600 F) was only 22%.   Bienstock et al. (1) showed similar results
correlating  the effect of primary zone flame temperature on NO  formation.
While their  measured NO levels were lower,  a 20% reduction in NO  was ob-
                         x                                         x
served for the same-(600 F) reduction in measured flame temperature.  They
observed, however, that the effect of temperature from 1200 C (2200 F) to
1425 C (2600 F)  was quite large.

      The effect of furnace wall temperature was greater at the lean conditions
than at stoichiometric conditions.  This was probably due to the lesser heat re-
lease rate at the lean conditions. The nominal  heat release rate at stoichio-
                               92                   3
metric conditions was 2.66 x 10 cal/hr  m (300, 000  Btu/hr ft ).

                                DISCUSSION

The Influence of Furnace Design

      The results shown were obtained in a coal furnace  of fixed burner design
and with a short residence time for combustion gases.  The average residence
time in the furnace at stoichiometry and  with a  coal feed rate  of 3. 1 kg/hr was
about 0. 6 sec, which was not nearly sufficient for char burnout.  Thus, the
results pertain primarily to the NO^. formed near the  primary flame zone.  The
absolute  NO  levels were relatively high in this study, and this can be attributed
           Ji
to the lack of sufficient residence time for the  NO  to dissociate at lower furnace
                                                .X.
temperatures.  Bienstock,  et al. (_!) noted a rather large relaxation in NO
                                                                        X.
levels as the combustion gases  traveled through their more conventional furnace,
and attributed these to dissociation of NO.  It is also  possible that reactions
during char burnout lower the NO  substantially.
                                     186

-------
oo
-4
    1000
UJ
o
X
o

y   aoo
             z

             IS
             u

             o
                 600
    400
                 200
                                                                D
AIR FEED RATE = 94.5  Ib/hr

(31% PRIMARY)


SECONDARY A PREHEAT = 650F

PRIMARY AW  PREHEAT  =  I50F
                                              I
                                          I
                           1600
                                1800              2000              2200

                                 FURNACE WALL TEMPERATURE, F
                  Fig. 7.  Influence of Furnace Wall Temperature and Burner Equivalence Ratio
                             on Nitric Oxide Emissions from Pulverized Coal Combustion

-------
      The configuration of the burner is known to be an important factor in NO
                                                                             X
formation (5).   The purpose of the present work,  however, was to make a
parametric study of combustion modifications only, with possible burner design
studies to be made later.  In the  present case,  primary and secondary air in-
jection occurred in close proximity, and it is likely that both  air streams were
well-mixed before combustion commenced.  Thus,  in the present design, one
probably would not expect a large influence on NO  of the relative flow rates
of the  two air streams.  In addition, air preheat could probably be considered
as an average primary and secondary air temperature.

The Influence of  Combustion Modifications^

      Low excess air firing generally reduces emissions of nitric oxide in both
boiler operation  (6) and in research furnaces (l_, 2, 3_, 4).   Data in highly fuel-rich
flames has  not been available, however, and only a limited amount of data have
been presented on the effects of air preheat.  The results shown in Fig.  6 indi-
cate that, while the air-rich NO  characteristics of the coal-air flame are highly
                               .X
dependent on secondary air  preheat, NO  from  stoichiometric and fuel-rich
                                       J\.
flames is relatively independent of both preheat and air-coal ratio.  These re-
sults  are quite different from those from similar tests on gas and oil firing
where moderately fuel-rich operation results in sharp reduction in NO  .  The
                                                                    j
level  of NO  in fuel-rich coal flames corresponds to about 42% of the NO  that
           X                                                           X
would  be found with 100% fuel nitrogen conversion.  Coincidentally,  it has been
reported that the volatile fraction of fuel nitrogen is about 40% of the total in
some pulverized fuels (3).

      It is  suggested that NO  emissions in near-stoichiometric and fuel-rich
                            X.
flames are  due almost exclusively to conversion of the volatile fuel nitrogen
to nitric oxide.   The volatile fraction of the coal is burned in  an overall oxidizing
atmosphere as long as the overall burner stoichiometry is below about 2. 5
(corresponding to stoichiometry with 40% volatiles). In these flames,  conversion
of gaseous fuel nitrogen is high, and NO  emissions, reduced to stoichiometric,
                                       jfi
are relatively independent of coal-air ratio and air preheat.   At overall burner
stoichiometries in the air-rich region,  emissions of NO  are  strongly  dependent
                                                       X,
on secondary air preheat, indicating that the flame temperature in these regions
dominates both fuel nitrogen conversion and molecular nitrogen conversion.
                                     188

-------
      This view of NO  formation in pulverized coal flames indicates two alter-
                     3C
natives to NO  control by combustion modifications.  First, NO  can be reduced
             X.                                                3i
by reducing combustion temperature of the volatiles.  This can be accomplished
by product gas recirculation, water injection,  or similar methods designed to
vitiate the initial fuel-air mixture.  Second,  NO can be reduced by burning the
                                               jC
volatiles at overall burner equivalence  ratios greater than  2. 5.  This can be
accomplished by limiting primary air to substantially less than 25% of the total
required for combustion.

                            ACKNOWLEDGEMENT

      This work was supported by the Director's Discretionary Fund at the Jet
Propulsion Laboratory.  Coal was  supplied by Dr. J. Shapiro of the Bechtel
Corporation.
                                     189

-------
                               REFERENCES
1.    Daniel Bienstock, Robert L.  Amsler and Edgar R. Bauer,  Jr.,  "Forma-
      tion of Oxides  of Nitrogen in Pulverized Coal Combustion, " Journal of the
      Air Pollution Control Association,  1_6 (8), 442(1966).
2.    C.  R. McCann, J. J. Demeter,  A. A. Orning, D.  Bienstock,
      Emissions at Low Excess Air Levels in Pulverized Coal Combustion, "
      Presentation at ASME Winter Meeting, New York,  N.Y.,  November 29-
      December 3,  1970.

3.    M. P. Heap and T.  M. Lowes, "Development of Combustion System De-
      sign Criteria for  the Control of Nitrogen Oxide Emission from Heavy Oil
      and Coal Furnaces,  "  Progress Report No.  11, Contract No.  68-02-0202,
      U.S.  Environmental Protection Agency, Durham,  N. C., December 15,
      1972.

4.    C.  R. McCann, J. J.  Demeter,  J.  Dzubay,  and D. Bienstock,  "NO
      Emissions from Two-Stage Combustion of Pulverized Coal, "  Presenta-
      tion at 65th Annual Meeting of the Air Pollution Control Association,
      Miami Beach, Fla. ,  June 18-22,  1972.

5.    M. P. Heam, T.  M. Lowes and R. Walmsley,  "The Effect of Burner
      Parameters  on Nitric Oxide Formation in Natural Gas and Pulverized
      Fuel Flames, " Presentation at "American Flame Days, " Air Pollution
      Meeting,  Chicago, 111.,  September 6-7, 1972.

6.    Dr. J. Shapiro, Bechtel Corporation, Personal Communication, June 1972.
                                    190

-------
PILOT AND FULL SCALE TESTS




       PART I
        191

-------
                                        The  Effect of Design
                                        and  Operation
                                        Variables on NOX
                                        Formation in
                                        Coal  Fired Furnaces
                                        W. J. Armento
                                        Research Specialist
                                        Chemistry and Combustion Section
                                        Alliance Research Center
                                        Alliance, Ohio


                                        W. L. Sage
                                        Group Leader, Combustion Systems
                                        Chemistry and Combustion Section
                                        Alliance Research Center
                                        Alliance, Ohio
                                        Presented to
                                        Pulverized Coal Combustion Seminar
                                        National Environmental  Research Center
                                        Research Triangle Park,  North Carolina
                                        June 19-20, 1973
                                        Sponsored by
                                        Environmental Protection Agency
                                        Research Triangle Park, North Carolina
                                        Contract No. 68-02-0634
DTP 73-4                          193

-------
 THE EFFECT OF  DESIGN AND  OPERATION  VARIABLES
 ON  NOX  FORMATION IN COAL FIRED FURNACES

 W. J. Armento, Research Specialist, Chemistry and Combustion Section,
 Alliance Research Center, Alliance, Ohio

 W. L. Sage,  Group  Leader, Combustion Systems, Chemistry  and  Combustion Section,
 Alliance Research Center, Alliance, Ohio
 Presented to Pulverized Coal Combustion  Seminar,  National  Environmental  Research  Center,
 Research Triangle Park, North Carolina, June 19-20, 1973

 Sponsored by Environmental Protection Agency,
 Research Triangle Park, North Carolina
 Contract No. 68-02-0634
             I.  INTRODUCTION

The purpose of this EPA contract is to
determine the effectiveness of methods
of NOX  control which can be used on coal
fired utility boilers, present and
future.   In addition, we wish to iden-
tify  potential problems in boiler oper-
ation and thermal efficiency.  A com-
parison of the relative effectiveness
of these  combustion control methods is
also  to be made for gas and oil.

The contract is divided into three
phases which are defined below:

   Phase  I  -  Identification of impor-
    tant variables  in NOX control and
    qualitative determination of change
    in NOX emission levels with change
    in each method  of combustion control
    separately  (6-month effort, now fin-
    ished using a single burner unit).

   Phase II  -  Quantitative correlation
    of the trends found in Phase I and
    determination of the extent of
    interdependence of variables (6-
    month effort which will include con-
    struction of a  multiburner unit for
    use  in Phase III).

    Phase III - Verification and expan-
    sion of the quantitative correla-
    tions found in  Phase II using the
   new  multiburner unit (12-month
    effort due to start about January,
    1974).
 The basic combustion tunnel used for
 testing in Phase I is a single burner
 unit which fires ~ 227 kg hr-1 of coal
 (~500 Ib/hr) at normal load.  The coal
 used in Phase I had a combustion enthal-
 py of  6.67 kcal g-1 ( 12,000 Btu/lb)
 dry and this corresponded to a heat
 release rate in the active furnace vol-
 ume of  390,000 kcal m"3 hr'1 (-44,000
 Btu/ft3/hr).  The total heat release
 rate is ~ 1.4 x 10 kcal hr'1 (~ 5 6 x
 10 Btu/hr).
There  are two types of control for the
reduction of NOX which can be used:
operational control techniques and
design methods.   Operational control
techniques are more easily applied to
existing units;  the physical change on
the unit is minimized and the cost of
the change will  be lower.  Design
methods  would be applied to new units
yet to be constructed; thus a minimum
of redesign/reconstruction costs would
be entailed.   The operational variables
that have been studied in Phase I are:
(1) excess air,  (2)  firing rate of the
fuel (or unit load),  (3)  preheat of the
air, and (4)  swirl (for natural gas
firing only).  The design variables
included in Phase I  studies were:  (1)
flue gas  recirculation, (2) two-stage
combustion,  (3)  fuel  type (gas, coal, or
oil), and (4) heat removal rate from the
combustion  gases  (quench).
                                       194

-------
            II.  UNIT DESIGN

The basic combustion unit used for the
Phase I tests  (Figure  1) is  a cylindri-
cal tunnel 1.4 meters  (4.5 feet)  in
diameter and 2.4 meters  (8 feet)  in
length with an overall effective  furnace
volume of 3.60 m3  (127 ft3).   The fuel
and air normally enter into  the furnace
together through the burner  area.  For
coal  transport, about  15%  of the  rated
load  total air carries the coal into the
furnace through the central  fuel  pipe;
this  air  is  defined as the primary air.
The balance  of the combustion air nor-
mally enters the  furnace around the cen-
 ter pipe  and is defined as the secondary
 air.   With gas, there is no primary air
 and oil is steam atomized so that again
 there is  no primary air.
perpendicular to  the burner axis and
are offset circumferentially to create
a swirling action.   The  combined inlet
area of the side  slots is  the same as
the front slots.

The coal burner (Figure  4) consists of
a pipe with concentric pieces of flared
welded sheet metal  at the  end to spread
the coal into the secondary air.  The
burner arrangement  used  during most of
the tests consisted of six fixed
(non-moveable), curved vanes in the
burner throat to  add some  swirl to the
secondary air.  The coal spreader is
normally just at  the inside entrance to
the throat during firing.   At other
positions further into the throat,
the flame leaves  the burner and travels
partway down the  furnace.
  NATURAL GAS
  LIGHTER
        FIGURE 1. BASIC COMBUSTION UNIT
               (SINGLE BURNER)
                                                     FIGURE 2.  FRONT SLOT POSITIONS
 There are two slot positions for two-
 stage combustion in the front and side
 of the furnace  (Figures 2 and 3).  The
 two front slots are cut 3" by 12"; the
 1" on either side of the center 1" x 12"
 opening is bricked in.  The front slots
 are arranged so that the second stage
 air enters parallel to the burner axis.
 The combined inlet area of the front
 slots is one half of the burner inlet
 area.

 The two side slots for two-stage com-
 bustion are cut 6" by 6" and bricked 2"
 on either side of the 2" x 6" opening.
 The side slots add the second stage air
          FIGURE 3. SIDE SLOT POSITIONS
                                       195

-------
            FIGURE 4. COAL BURNER


The natural gas igniter  is  left on
during all coal firing tests  to ensure
that ignition  is maintained in the
furnace, especially during  unstable
combustion conditions.   The flow is set
at 20% full gas flow  for the  igniter,
but this flow  of gas  supplies less than
1% of the total heat  release  at normal
loads.  Under  reduced loads,  it is less
than 2% of the total  heat release in
the furnace.

The gas burner (Figure 5) is  a supply
ring with eight equally  spaced spuds
for gas inlet  into the throat.   There
is a split washer about  1"  from the tip
of the spud which serves the  purpose of
holding the flame.  Next to the washer
are two sets of holes drilled diamet-
rically opposed.  The two sets  are side
by side on the burner axis.   The holes
are oriented for all  eight  spuds so
that the gas exits tangent  to an imag-
inary circle which is approximately one
half of the burner diameter.
FIGURE 5. GAS BURNER
                                 The secondary air  swirler used for gas
                                 and oil firing  is  a set of 16 moveable
                                 vanes which can be set from 0, or no
                                 swirl, to about 30,  or maximum swirl.
                                 Only the gas flame remained ignited in
                                 a stable manner at no swirl;  the coal
                                 flame left the  burner at lower swirl
                                 angles (less than  20 to 30)  and went
                                 out or was half-way down the  furnace
                                 under no swirl  (0 to 10).

                                 The dual fluid  oil burner (Figure 6)
                                 employs steam as the  atomizing medium
                                 and consists of three concentric pipes
                                 mounted on the  axis of the  burner.
                                 The outermost pipe holds the  impeller
                                 which is a conical slotted  disk of
                                 sheet metal with the  vanes  bent to
                                 create a slight swirl.   The innermost
                                 pipe carries the steam and  the middle
                                 pipe carries the oil.   There  is an
                                 atomizer tip on the end of  the two
                                 inner pipes (Figure 7).   The  center
                                 hole in the atomizer  (Y-jet)  carries
                                 the steam and the  No.  6 oil, which is
                                 preheated to retain fluidity,  is  in
                                 the branched opening  which  enters the
                                 steam jet.
                                             FIGURE 6. OIL BURNER
                                            FIGURE 7. OIL ATOMIZER
                            196

-------
          III. INSTRUMENTATION

The flue gas is sampled in the stack
where the average temperature is down
to less than 500K  (450F).  A stain-
less steel probe extends half-way
across the  stack.   The gas sample  is
passed through a condenser maintained
at 283K  (50F) and then is  split  and
monitored by the following instrumen-
tation  (Figure 8):

   (1) An  MSA LIRA  CO analyzer (measur-
       ing from 0 to 5000 ppm)

   (2) A Whittaker  S02 analyzer  of the
       chemical cell type  (0  to  5000
       ppm)

   (3) An MSA paramagnetic 02 analyzer
       (0 to 25%)

   (4) A Bailey 02 Meter (0 to 10%)
       and  total combustibles (0 to  5%)
       hot wire analyzer.

    (5) A  TECo  (Thermo Electron Corp.)
       chemiluminescence NOX monitor
        (0 to 10,000 ppm)

    (6) Whittaker NOX chemical cell
       analyzer  (0 to 5000 ppm) with a
       Mallcosorb  column

    (7) A  Beckman NDIR for NO (0 to
       1500 ppm)
 The Beckman NDIR requires the use of
 another ice bath maintained at a con-
 stant 274K (34F exactly, 0.5F) to
 remove a maximum amount of water.  Even
 so, enough water remains in the gas to
 be measured so that a 60 ppm correction
 must be made to the final measurement
 as a residual H20 correction.

 The gases  used for the NOX calibrations
 are certified calibration gases from
 Matheson containing about 200,  500,
 800, and 1200  ppm NO (less than 5 - 20
 ppm N02) in N2-   The gases, when pur-
 chased,  are checked against the previous
 standards before  being put into reg-
 ular use.
                                                             MALLCOSORB COLUMN
 60 F ICE BATH
            WHITTAKER
            S02
          FIGURE 8.  INSTRUMENTATION
            IV.  TEST PROGRAM

The test program for Phase I called  for
identification of the major variables
for NOX control.  The major variables  to
be investigated were divided into design
and operational variables.  Design vari-
ables were expected to be more easily
implemented in new units not yet built.
In order to change existing units, the
expense would be very great when com-
pared to modifying operational condi-
tions.  It might also be physically  or
economically impractical to modify
existing units.  The design variables,
therefore, suggest that physical and
mechanical changes could be made in  the
unit and would include flue gas recir-
culation, staged combustion, quench
rate, and basic fuel type.  On the
other hand, it would prove less expen-
sive to modify the operational variables
for existing units such as excess air,
fuel firing rate, air preheat, and
swirl.  (These groups of variables are
not meant to be mutually exclusive).

Since the basic contract fuel require-
ment was for coal firing, limited tests
with gas and oil were used for compar-
ison with the coal results under the
same furnace conditions.  The burner
configuration for the coal was changed
from the fixed 6-vane burner to the
variable angle 16-vane burner only
once in an attempt to study the effect
of swirl on coal combustion.  Base
tests with coal through either burner
showed less than 10% variation in NOX
emission levels.
                                       197

-------
              V.  RESULTS

The objective of  the  initial phase  of
this investigation was  to establish
relative effects  of changes in  oper-
ational and design variables.   Hence,
an attempt was made to  hold other con-
ditions constant  and  to change  the
variable under  study  over a wide range.
However, many of  these  are interrelated,
hence as load,  excess air, preheat,
staged combustion, flue gas recircula-
tion and the other variables were
changed, air velocities changed leading
to a variation  in mix rate, turbulence
and combustion  intensity.  To date, no
attempt has been  made to interrelate
these variables,  but  an attempt to  do
so is projected as a  part of Phase  III.

During operations, continuous mea-
surements were made of  C>2 (two  instru-
ments), CO, combustibles, SCL,  and NO
(three instruments).  The measurements
were all recorded on  strip chart
recorders.  On  random occasions, about
201 of the time,  ash  loadings in the
stack gases were  obtained for deter-
mination of unburned  carbon.

When surveying  a  single variable,
generally the extremes  and the  middle
of the range were tested.  The  trends
were determined in this way.  However,
it should be emphasized that in many
cases, the extremes on  a single vari-
able are beyond the range of what is
considered acceptable operating prac-
tice.  Furthermore, it  should be
emphasized that these results apply to
a small single  burner test unit.
Although it is  believed that the trends
shown will probably hold for a  large
multiburner furnace,  the magnitude  of
the changes may be appreciably  dif-
ferent; also, some of the test  vari-
ables may not be  operationally  accept-
able on large units.

The effect of each single variable
will be discussed below.  In the case
where absolute measurements of  NO
emission levels are shown, a single
test (or two) to  verify proper  instru-
mentation operation was made and the
 test runs for data collection were made.
 But, when relative measurements of NO
 emission levels are shown, the tests
 were run in pairs.  The base line test
 and the data test were run in the same
 day to eliminate possible day-to-day
 variations.  The NO reduction was then
 calculated by comparing the change in
 NO emission level to the emission level
 in the base line test.

 A.  Excess Air

 Figure 9  shows  the effect of excess
 air at rated load with 600 - 650 K
 (600 -  700F) air preheat on NO emis-
 sion for  natural gas  (no fuel-bound
 nitrogen),  #6 fuel oil (0.23% fuel-
 bound nitrogen),  and  coal (1.1% fuel-
 bound nitrogen).   The relative
 positions of the curves  with coal
 highest,  gas intermediate,  and oil
 slightly  below  gas agrees in general
 with data from  field  units.   However,
 the  natural  gas  and oil  NO emission
 levels  fall  in  a low  range  and one
 explanation for  this  is  the fairly
 conservative rating (furnace heat lib-
 eration rate) for these  fuels in our
 test unit.
                     20

                  EXCESS AIR, %
      FIGURE 9. EFFECT OF EXCESS AIR ON NOX


The NO emission from gas  is  a result
of thermal fixation  of  atmospheric
nitrogen.  The degree of  thermal  fix-
ation of N2 into NO  depends  on tem-
perature and excess  oxygen level.
At lower excess air  levels,  the effect
of increasing the oxygen  level more
                                      198

-------
than offsets the decrease in temper-
ature, hence the rising curve.   In
addition, at low excess air, the flame
can be more luminous and this may lead
to a more rapid quench rate.  At higher
excess air, eventually the decreasing
temperature becomes the overriding
effect and the curve drops again after
reaching a maximum.

In contrast, the coal contains  fuel-
bound nitrogen and the conversion of
this  represents a  second source of  NO.
It  is expected that the differences in
the  shape  of the curve and peak posi-
tion when  compared to  the gas  curve is
a result of the  fuel-bound nitrogen
conversion.  The  trend shows a cor-
relation of higher fuel-bound nitrogen
 conversion to NO with higher excess
 air levels.   The evidence for this  is
 shown in a steeper slope  to the NO
 curve at lower excess air levels and
 a peak position at higher excess air
 level.  It is not felt at this stage
 in the program that the fuel-bound
 nitrogen conversion can yet be quanti-
 tatively evaluated.

 The  initial thought for oil is  that
 this curve should be higher than gas
 due  to the fuel-bound nitrogen  con-
 tent.  In our unit, oil burns with a
 more luminous flame than gas and has
 a larger visible  flame envelope.
 Hence, the lower NO levels from oil
 are attributed to better radiating
 properties and therefore  a lower bulk
 gas temperature.

B.  Load

The dependence  of coal NO emissions
on load  is illustrated in Figure 10.
There is no  indication of a  peak level
being reached under these conditions.
Gas and oil NO levels show only a
slight dependence  on firing  rate.
Again it should be pointed out  that
with  the burner arrangement  used in
these tests, the air velocity through
the 'burner and the turbulence change
with load.
Also to be considered is  the refractory
shielding in the  front of the fur-
nace.  This probably  means that there
is less response  of NO to load than
would be obtained with a  higher
quench rate.

C.  Preheat

The dependence  of NO  emission level
on air preheat  can  be seen in Fig-
ures 11, 12, and  13.   Figure 11
results from plotting all points run
at 15% excess air,  Figure 12 from all
points run at normal  load and low
excess air, and Figure 13 from all
points run at normal  load and 151
excess air.  Figure 11 indicates a
high dependence of  coal and gas on
air preheat  (about  50 ppm NO increase
per 100F increase  in preheat)  with
oil showing a smaller effect.   How-
ever, if the percentage increase in
NO is used instead  of absolute  change
in ppm NO from  400  to 650K (300 to
700F) preheat, coal  shows a 35%
increase, oil 33%,  and gas 71%.  Fig-
ure 12, the curves  for low excess air,
shows a significant dependence  on pre-
heat for gas only.  There is no effect
for coal and oil.   The change for gas
is still about  50 ppm NO  increase per
100F of preheat  increase.  Figure 13
at normal load  and  15% excess air shows
about the same  effects as Figure 11.
A comparison of these three figures
leads to the tentative conclusion that
conversion of fuel-bound  nitrogen
increases with  decreasing air pre-
heat.
                     200

                FIRING RATE, Kg. COAL/HR.
                                                 FIGURE 10.  EFFECT OF FIRING RATE ON NO
                                      199

-------
                      500
                     PREHEAT. F
       FIGURE 11.  EFFECT OF PREHEAT ON NOX
                (CONSTANT EXCESS AIR)
                      500

                     PREHEAT, F
       FIGURE 13.
                EFFECT OF PREHEAT ON NOX
                (CONSTANT LOAD AT NORMAL
                EXCESS AIR)
D.  Flue Gas Recirculation


The  coal burner arrangement which has
been used requires  transport air for
the  coal which is defined as primary
air  (see Figure 14).   The balance of
the  burner air is called secondary air.
The  primary air is  about 15% of the
total  air under normal load and excess
air.   At low loads,  the percentage of
primary air increases to over 20%.  The
oil  is steam atomized and, therefore,
for  both gas and oil,  there is no
primary air in the burner.
                      I PREHEAT UP TO 400 C
                SECONDARY \ 900-2300 Kg./HR
                         r*	PRIMARY
                          NO PREHEAT

                          180-270 Kg./HR
        300             500             700
                    PREHEAT. P

     FIGURE 12.  EFFECT OF PREHEAT ON NOX

              (CONSTANT LOAD AT LOW EXCESS
              AIR)
                                                      Primary  Flue Gas Recirculation
                                                             (Coal Only)
Figure  15 shows the result of primary
flue  gas  recirculation for coal com-
bustion.   The flue gas was substituted
for air so that the total transport
gas weight remained constant.  The air
displaced by the flue  gas was added
to the  secondary air to maintain a
constant  air to fuel ratio.  Since the
primary air represents about 15% of
the total air for combustion, a high
level of  flue gas substitution repre-
sents only a small amount of flue gas
recirculation.  Blending the flue gas
with  the  primary air does tend to
affect  the primary ignition zone and
hence burner performance.  As a result,
data  obtained under these test con-
ditions showed considerable scatter.
However,  it is felt that the trend
shown in  Figure 15 is  probably real-
istic and that any reduction in NO by
this  approach is relatively insignif-
icant.
     FIGURE 14.   AIR INPUT FOR COAL COMBUSTION
        02468

                 FLUE GAS RECYCLED. %

     FIGURE 15.  PRIMARY FLUE GAS RECIRCULATION
              (COAL ONLY)
                                          200

-------
      Secondary Flue Gas Recirculation

Figure 16 shows the percentage  of NO
reduction versus the percentage of
flue gas recycled.  The flue  gas was
added to the secondary flow and the
air to fuel ratio was held constant.
                FLUE GAS RECYCLED, '
       FIGURE 16.  FLUE GAS RECIRCULATION


The curve for coal indicates  for the
application of 10% to 15%  flue  gas
recirculation that a maximum  reduction
of only 10% to 15% can be  expected  in
NO emission levels.  The curve  for  gas
shows a very great reduction  in NO
levels even with relatively low flue
gas recirculation.  The dotted  portion
of the line indicates that no tests
have been run below 101 flue  gas recir-
culation for gas and the curve  is
simply interpolated from the  origin to
the data available.  The oil  curve
shows very little reduction of  NO
emissions with flue gas recirculation.

At present, it is felt that these
data indicate flue gas recirculation
is effective in reducing thermal fix-
ation of NO but may increase  the
amount of NO formed from conversion
of fuel-bound nitrogen.

E. Staged Combustion

As seen in Figure 17, there are two
areas in a normal utility  unit  where
second stage air can be added for
final combustion.  The air can  be
added in the burner area by running
some burners  rich and some lean, or
by putting air  only through separate
burners, etc.   Or,  the air can be
added at a distance away from the
burner area.  Our two sets of slots
are spatially arranged to simulate
either method of second stage air
addition.  The  front slots simulate
addition of air in the burner area,
or very close to it, whereas the side
slots simulate  addition of the air
further away  from the burner area
with rapid mixing for the second
stage combustion.
                                                                	#2

                                                               (SIMILAR TO SIDE SLOTSI
                       #1
                         (SIMILAR TO
                         FRONT SLOTS)
       FIGURE 17.  STAGED COMBUSTION OPTIONS


A comparison of  results obtained with
the two port locations  is shown in
Figure 18.  At the  higher burner to
total air ratios results are similar.
It should be noted  that these data
were obtained with  fixed burner and
slot openings.   Thus as the burner
to total air ratio  decreases and
staging increases,  the  air velocity
through the ports increases and the
burner velocity  decreases.  This
effect on combustion performance is
unsatisfactory at lower burner to
total air ratios when using the side
slots for staging.   The curves do
indicate that a  50% reduction in NO
emission levels  by  staging is possible
for coal firing.
                                      201

-------
             STOICHIOMETRY AT BURNERS,
     FIGURE 18.  STAGED COMBUSTION FOR COAL
              PORT POSITION VARIABLE
Figures  19,  20,  and 21 represent the
results  from observation of staged
combustion for coal, oil, and gas,
respectively.   For coal and oil, flue
gas recirculation showed no further
reduction in NO when used in com-
bination with staged combustion.

There are  two  curves for staged com-
bustion with coal (Figure 19).   The
"S" shaped curve represents normal
two-stage  combustion for the front
slot firing  at 15%  total excess air
and normal load.  The straighter line
represents substoichiometric firing
in which the second stage air was
simply shut  off  and the overall air to
fuel ratio is  the same as the burner
ratio in the first  stage.  The straight
line intercept indicates that below
75% burner air to fuel ratio,  no NO
would be  expected to appear in the
first stage  combustion.  The two-stage
combustion curve indicates that a min-
imum in  the  NO occurs at a burner air
to fuel  ratio  of about 50%.  This min-
imum is not  unexpected because it
represents the diminishing return on
the reduction of conversion of the
fuel-bound nitrogen in the first stage
as contrasted to increasing thermal NO
formation due  to increased Btu content
in the second stage.  There are two
major conclusions to be drawn from
this information.  First, there is a
lower level  of burner stoichiometry
below which  the  NO  formation in the
 first stage appears to drop  to zero and
 it is of no further benefit  to lower
 the air to fuel ratio at  the burner.

 Secondly, with the latent Btu content
 of the gas increasing rapidly in  the
 residual gas to be burned in the  sec-
 ond stage, the second stage  flame tem-
 perature and therefore the thermal fix-
 ation of NO is expected to rise again.
 The position of maximum NO reduction
 is influenced by port position and
 heat removal rate as well as other
 factors such as air velocity and  mix-
 ing rate.  It is therefore certain
 that such a turnover in the  NO reduc-
 tion curve should and probably does
 exist.

 The oil curve (Figure 20) is the  same
 shape as the coal curve.  The degree
 of reduction in NO levels for staging
.oil is less than coal because of  the
 much lower base levels of NO.
              STOICHIOMETRY AT BURNERS, %

        FIGURE 19.  STAGED COMBUSTION (COAL)
                   I
                          I
                                I
                      100
              STOICHIOMETRY AT BURNERS, %


        FIGURE 20.  STAGED COMBUSTION (OIL)
                                        202

-------
For two-stage combustion of gas
(Figure 21), the addition of flue
gas recirculation becomes very impor-
tant.  The greater effect for the
flue gas recirculation  is found in
the burner.  This indicates that it
prevents or reduces the formation of
the precursors in the first stage
which leads to thermal  NO as well as
preventing formation of NO in the
second stage.  If the only function
of flue gas recirculation in a natural
gas flame were temperature drop and
initially lowered 02 concentration,
it would be just as effective in the
second stage air as it  is in the
burner air since combustion taking
place in the first stage is usually
substoichiometric.  An  increase in
velocity and mixing in  the first
stage is also expected  when flue gas
is added through the burner.
             STOICHIOMETHY AT BURNERS, %
       FIGURE 21.   STAGED COMBUSTION (GAS)

 F. Swirl (gas only) and Quench (coal  only)

 Decreasing the  swirl with our burner,
 as shown in Figure  5,  for coal firing
 led to combustion instability; hence
 this variable was not  investigated
 for coal during this phase.

 Only maximum swirl  (30 vane setting)
 and no swirl (0 vane  setting) tests
 were run for gas (Table 1).   In gen-
 eral, the effect of increased velocity
 on mixing is shown.  Higher  load and
 higher excess air led  to greater
 reductions in NO.   The effect at low
 air regardless  of load (the  point at
 low load, low air was  10,  the average
of 13 and 6 although the value of 6
is thought to be the correct one)
indicates that the 02 concentration
is never  high enough to directly
influence thermal NO formation, or in
other words, the NO may be kinetically
limited rather than diffusion limited.
    TABLE 1.  EFFECT OF SWIRL (GAS ONLY) NO
           REDUCTION, % (MAXIMUM TO NO SWIRL)
LOW
AIR
LOW
LOAD
10
MID
LOAD
HIGH
LOAD
4
MID
AIR
8
18
18
HIGH
AIR
12
18
21
The change in quench  in the basic com-
bustion unit was made by removal of
part of the refractory brick lining
in the furnace.  All  tests except the
quench tests were  run with a 1-inch
thick refractory brick lining on the
inside of the furnace from the burner
to half way down the  furnace, or to
a distance of 4 feet.   For a change
in heat removal rate  for the quench
test, half of the  brick was stripped
out so that it covered the interior
from the burner down  a 2-foot length
of the furnace.  The  results of these
tests are shown in Table 2.  Although
this alteration changed the quench
rate, there is not enough information
to make a quantitative calculation of
the change.  All conditions except
low excess air showed about the same
reduction in NO emission levels.
       TABLE 2.  EFFECT OF QUENCH ON COAL
              (PERCENT REDUCTION IN NO)
LOW
AIR
LOW
LOAD
MID
LOAD 0
HIGH
LOAD
MID
AIR
	
20
(20 STAGED)
20
HIGH
AIR
	

20
                                         203

-------
             VI.  SUMMARY

The most effective means of controlling
NO emissions from an operational point
of view as found in the basic combustion
unit would appear to be to control
excess air, preheat, and load together
since they are heavily interdependent
(ref. Table 3).  If load cannot be
varied, control of the combination of
lower preheat and excess air does not
appear to be more effective than con-
trol of the excess air alone.

To date, pilot plant results indicate
the concept of staged combustion or
perhaps delayed mixing appears to be
the most effective means of NOx reduc-
tion.  If this can be accomplished by
progressive mixing in the individual
burner zone, then operator acceptance
seems assured.  However, if effective
control requires a wide physical sep-
aration of the two sources of air,
there is a real concern that unaccept-
able slagging and corrosion problems
may be encountered.  Therefore, field
testing of a unit under controlled
conditions to establish the long term
effect of operating in this manner
would be required before universal
acceptance can be assured.
                                               TABLE 3.  SUMMARY OF QUALITATIVE EVALUATION
INCREASING:
EXCESS AIR
LOAD - LOW PREHEAT
- HIGH PREHEAT
PREHEAT - LOW AIR
- HIGH AIR
FLUE GAS
RECIRCULATION
STAGED COMBUSTION
- POSITION
- WITH FGR
QUENCH (DECREASING)
SWIRL
COAL
H-f
-H-
0
0
++


	
+
0
+
ND
GAS
+
0
+
++
-H-

	
	
0
	
ND
+
OIL
+
f
H
0
0

-

0
0
ND
ND
                                       204

-------
 PRELIMINARY EVALUATION OF COMBUSTION MODIFICATIONS FOR CONTROL OF
POLLUTANT EMISSIONS FROM MULTI-BURNER COAL-FIRED COMBUSTION SYSTEMS
                                    By

              C. R. McCann, J. J. Demeter and D. Bienstock

            U. S. Department of the Interior, Bureau of Mines
         Pittsburgh Energy Research Center, Pittsburgh,Pa. 15213
          The Bureau of Mines  (through an interagency agreement with EPA)

has extended a program to evaluate the effects of combustion  modifications

on control of emissions from multi-burner coal-fired systems.  Experimenta-

tion was conducted in a 500 Ib. per hour pulverized-coal fired unit whose

operation closely simulates industrial practice.  A photograph of the furnace

is shown in figure 1.  The unit is 12 ft. high, 7 ft. wide, and 5 ft. deep,

with water cooled walls.  Four burners are located on the front wall.  A

half section of the combustor is  shown in figure 2.  Combustion gases

leave the furnace at about 2000  F, cool to about 1000 F in the convective

heat transfer zone, then exchange heat with secondary air in the recupera-

tive air heater.  The effects of  several operating techniques have been

investigated	single stage combustion with reduced excess air, two stage

combustion, bias-firing, and flue gas recirculation.

          Coal feed rate was maintained at 500 Ib per hour, fuel particle

size at 75 percent through 200 mesh and secondary air temperature at 600 F

in all tests.  Except for the series of reduced excess air tests, excess

air was maintained at 20 percent.
                                   205

-------
Variations in Excess Air




          By decreasing the amount of excess air from the conventional




levels of 20-25 percent, a substantial lowering of NOX emissions can be




achieved.  As shown in figure 5, NOx decreased from 1.45 gm/10  cal at




20 percent excess air, to .5 gm/106 cal at about 2 percent excess air.




However, as shown in figure 4, this reduction in NOX emission was




accompanied by a decrease in carbon combustion efficiency.






Two-Stage Combustion




          In two-stage combustion, the first stage was supplied with




air  ranging from 80 to 105 percent of stoichiometric.  Sufficient air




was  introduced at the furnace outlet to produce 20 percent overall excess




air. Figure 5 shows a plot of NOX emissions as a function of air supply




to the  first stage.  Nitrogen oxides emission decreased from about




1.1  gm NO2/10  cal when 105 percent of stoichiometric air was supplied




to the  first stage to  .77 gm NO2/106 cal when 80 percent of stoichiometric




air  was  supplied to the first stage.  This reduction was accomplished while




maintaining carbon combustion efficiency  greater than 98 percent.  Also




shown in this  figure are the results of bias-firing experiments.  This




is a variation of staged combustion, where stoichiometric air or less than




stoichiometric is supplied to the  lower burners, with sufficient air




supplied to the upper burners to provide  20 percent excess air  overall.




It  is evident  that  little reduction occurred when  105 percent of




stoichiometric air was  supplied  to the  lower burners.   Some  reduction did




occur when  90  percent of  stoichiometric air was  supplied  to  the lower




burners. It wasn't possible  to  reduce  the air to  the  lower  burners  below
                                  206

-------
90 percent, because of the increased demand on  the upper burners.
A reduction to 80 percent of  stoichiometric to  the lower burners would
require 160 percent of stoichiometric to the upper burners.  Stable
flames could not be maintained with air supplied in this amount.
To further investigate the effect  of two-stage  combustion, the second
stage air probe was relocated to a point nearer to the  flame zone.  A
sketch of the probe location  is shown in figure 6.  with air introduced
at this point, a survey was made of NOX emissions when  the probe was rotated
through an angle of 180 from a point normal to the front wall to a point
normal to the rear wall.  Also shown are the NOX values obtained when second
stage air was introduced at the various angles.  Most significant reduction
occurred with air introduced  normal to the front and rear walls.  Highest
NOX values were obtained when air  was introduced at an  angle approximately
30 from normal to the front  wall. At this point the second stage air
penetrated the primary combustion  zone, increasing the  intensity of
combustion.  The flames were  forced sown along  the front sloping wall
resulting in overheating of the lower furnace section.  Since the coal
feed rate was constant during the  test, the oxygen values are an indication
of carbon combustion  efficiency.   Although a relatively large change in
NOV emissions occurred as the angle of introduction of  second stage air
  A
was varied, the oxygen values indicate that carbon combustion efficiency
was relatively constant.   Furnace outlet temperatures  were  1750 F, 1920 F,
and 1850 F when air  was introduced at points 1, 2, and 7, respectively.
When the second stage air was introduced at an  angle of about 45 at the
original probe location near  the exit of the furnace, the NOX value was
about 300 ppm and the furnace outlet temperature was
                                  207

-------
Flue Gas Circulation to Secondary Air
          Figure 7 shows the results of tests in which various amounts
of flue gas were recycled to the furnace through the secondary air streams.
Temperature of the recycled gas was about 300 F.  The curve indicates
that a significant reduction in NOV emission occurs when flue gas is
                                  A
recycled to the furnace through the secondary air streams.  Furnace outlet
temperature decreased with recycle from 2000 F at zero recycle to 1890 F
at 24 percent recycle.  The curve appears to flatten out between 24 and
30 percent recycle.  The 30 percent point and an intermediate point will
be checked to further define the curve in this region.  In addition,
several tests are planned to determine the effect of flue gas recycle
in the primary air stream.
          In addition to monitoring Oj and NOX, the following components
were also measured during the tests - NC^, SC>2, CO, CC^, hydrocarbons,
particulate, and furnace outlet temperature.  The NO2 was monitored with
a chemiluminescent analyzer; the NO2 generally ranged from 3-7 percent
of the NOX value.  An NDIR analyzer was also used to monitor NO.
          The CO emissions, as measured with an NDIR analyzer, generally
ranged from 30 to 60 ppm for the standard and other tests except those
operated at low excess air levels.  In the test operated at 5 percent
excess air, the CO increased to 1,000 ppm, at 2 percent excess air the
CO further  increased to 5,000 ppm.
                               208

-------
          Total hydrocarbon emissions were monitored during the tests




with a flame ionization analyzer.  The analyzer indicated that ambient




and combustion air contained about 2-3 ppm hydrocarbons.  Flue gas concentra-




tions were on the order of 0.5 to 0.8 ppm in tests conducted at 20 percent




excess air levels.  The hydrocarbon emissions increased at lower




excess air levels to 2 to 5 ppm at 5 percent excess air.




          The amount of slagging experienced at a given operating condition




is difficult to ascertain because of the relatively short period of opera-




tion at a given test condition.  As far as could be noted visually, the




degree of slagging was minor, and no difference could be noted between




tests.




          After the flue gas recycle tests are completed, the survey of




the effect of the point of  introduction of second stage air will be




completed to include rotation of the second stage air probe through the




remaining two quadrants.  Thereafter the combustion studies will be




continued to include combinations of the various combustion modifications.
                                209

-------
Figure 1.  View of 500 Ib/hr pulverized coal-fired combustor.
                         210

-------
                                  Rcuprotiv
                                  0" preheoter,,
 Convtclive heol tfontfer section
 Figure  2.   500 Ib/hr coal combustor.
  EPA  regulations, coat fired plants
             5               10
                EXCESS AIR f percent
Figure 3.  Nitric oxide formation as  a function of excess air.
                            211

-------
         100
      1
      i
          98
          96
         94
      (fl
      S

      I

      8
      o
      00
      ft  9O

      3    O
                         \
\
\
\
                        IO      IS      2O      25


                         EXCESS AIR, percent
                       3O
Figure 4.  Carbon combustion efficiency as a function of excess air.
          1.6
     i
     8
         1.2
 a

 8   i-o
  *
 "5

<

 2  O.8





 O*  0.6
 




    0.*
                       EPA regulations , coat find plants
                                      A
                                              A  Bias firing


                                              x  Two-stage combustion
                          I
            7O          8O           9O            IOO


                     Alt? TO FIRST STAGE, % of stoicAiomettic
                                                            110
Figure 5.   Nitric oxide formation with off-stoichiometric firing.
                                  212

-------
 BURNERS
f. 	 3'-V 	 4^1' tin
' ^
: ^
^5* L * 7
3^
P 3 ; .
l_
1

^^=^
^
>
i



POINT
1
2
3
4
5
6
\ / ?




3.5
3.5
3.6
3.5
3.7
3>
3JS




2SO 265
375 39O
3OO 310
32O 33O
345 355
295 3IO
270 29O
 Figure 6.  Effect of air injection ang1? upon NO  emissions.

                                                 X
 s~
 o


 8

o

3
 o
 o

M

 O
 s
 Dl
     2.O
                               EPA regulations , coal  fired plants
        O     .05     .10      .15     .20    .25     .30     .35


              FLUE  GAS RECIRCULATION , mass flu* gas/ mass inlet air (fuel




  Figure 7.   Flue gas recirculated to secondary air, percent.
                               213

-------
                              EMISSION CONTROL FOR
                         COAL-FIRED UTILITY BOILERS

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

                    Prepared for "Coal Combustion Seminar"
                 Organized by the Combustion Research Section,
                          Control Systems Laboratory,
                        Environmental Protection Agency
                     Research Triangle Park, North Carolina
                               June 19-20, 1973
SUMMARY

          Esso Research and Engineering Company is conducting field studies
on utility boilers under EPA sponsorship, to develop NOX and other pollutant
control technology, by modifying combustion operating conditions.  In the
current phase of continuing work on this problem, Esso's mobile sampling-
analytical system has been used to test eight pulverized coal fired boilers
of cooperating electric utilities.  These boilers, including wall, tangentially,
and turbo-furnace fired units, had been recommended by major utility boiler
manufacturers as representative of their current design practices.

          In addition to gaseous emission measurements, particulate emissions
and accelerated furnace corrosion rates have been also determined in a number
of cases.  Esso's test design consisted of three phases.  First, statistically
designed short term runs were made, to define the optimum "low NOX" conditions
within the constraints imposed by boiler operability and safety, slagging, unburned
combustible emissions and other undesirable side effects.  Second, the boilers
were usually operated for about two days under the "low NOX" conditions defined
in the first phase, to check operability on a sustained basis.  Third, several
boilers were operated under both baseline and "low NOX" conditions for about
300 hours, with carbon steel corrosion coupons mounted on air-cooled probes
exposed near the water walls of the furnaces, to obtain relative corrosion
tendencies with accelerated rates.

          Analysis of the gaseous emission data obtained shows that combustion
operating modifications, chiefly low excess air firing, coupled with staged
burner patterns, can reduce NOX emissions from the coal fired boilers tested
by 25 to 60%, depending on the unit and its flexibility for modifications.
The NOX emissions measured have been successfully correlated for both normal
and modified firing conditions with the per cent stoichiometric air supplied
to the burners.
                                       215

-------
          There are no major differences between particulate loadings under
baseline and "low NOX" operating conditions.  However, unburned carbon in
the fly-ash increases considerably with "low NOX" firing for front wall and
horizontally opposed fired boilers but, decreases substantially for tangentially
fired units.  The potential debits in overall performance based on these
limited data for front wall and horizontally opposed fired boilers should
be offset by improved efficiencies realized by lower excess air operation
in "low NOX" firing.

          The accelerated corrosion tests have not revealed major
differences in corrosion rates between normal and staged firing operations.
More tests and long term runs, with particular emphasis on corrosion and
slagging problems are needed to demonstrate the promising leads uncovered
to date in this study.
                                       216

-------
1.  INTRODUCTION

          In continuing studies sponsored by EPA, Esso Research and Engineering
Company (Esso) is involved in the development of nitrogen oxides  (NOx) emission
control techniques for stationary sources.  Our "Systems Study of Nitrogen Oxide
Control Methods for Stationary Sources"  (1-3) characterized the nature and
magnitude of the stationary NOX emission problem, assessed existing and potential
control technology based on technical feasibility and cost-effectiveness,
developed a first-generation model of NOX formation in combustion processes,
and prepared a set of comprehensive  5-year R&D plan recommendations for the
Government with priority rankings.

          Fossil fuel fired electric utility boilers were identified by the
above study as the largest single stationary NOX emission sector, responsible
for about 40% of all stationary NOX.  Consequently, as part of Phase II of our
"Systems Study of Nitrogen Oxide  Control Methods for Stationary Sources", we
conducted a systematic field study of NOX control methods for utility boilers
 (4-6).  xhe objectives of this field study were to determine new or improved
NOX emission factors according to fossil fuel type and boiler design type,
and to explore the application of combustion modification techniques to control
NOX emissions from such installations.

          Esso provided a specially  designed mobile sampling-analytical van
for the above field testing.  Our van was equipped with gas sample, thermocouple
and velocity probes, with associated sample treating equipment, and continuous
monitoring instrumentation for measuring NO, N02, CO, C02, 02, S02, and
hydrocarbons.

          Gas, oil, and coal fired utility boiler representative of the U.S.
boiler population were tested, with  gas, oil, and coal fuels, respectively.
Combustion modifications were implemented in cooperation with utility
 owner-operators  (and with major boiler manufacturer subcontractors for three
 of the coal fired boilers tested), and emission data were obtained in a
 statistically designed field program.  The 17 boilers  (25 boiler-fuel
 combinations) tested included wall-fired, tangentially-fired, cyclone-fired,
 and vertically-fired units ranging in size between 66 and 820 MW generating
 capacity.

          Major  combustion operating parameters investigated consisted of
 the variation of gross boiler  load,  excess air level, staged firing patterns,
 flue  gas  recirculation, burner  tilt, primary/secondary air ratio, and air
preheat temperature.  Operation under reduced load conditions reduced the NOX
 emissions, but only for gas firing was the percent NOX reduction  greater than
 the percent load reduction.  Base-line emissions were correlated  in a
 statistically significant manner  with the MW generated per "equivalent" furnace
 firing wall.  In general, unburned combustible emissions, i.e., CO and
hydrocarbons were found to be negligibly small under base-line  conditions,
 and acceptably low even with NOX  control combustion modifications.  The N02
portion of the flue gas was always five  percent or less of the  total NOX emitted.
                                       217

-------
          The effectiveness of combustion modifications was found  to vary
with individual boiler characteristics for each fuel.  For gas fired boilers,
NOX emissions could be reduced on the average by about 60% at full load, even
though in large, gas fired boilers limited by heat transfer surface, NOX
emission levels as high as 1000 ppm prevailed in the absence of combustion
modifications.  Uncontrolled emissions from fuel-oil fired boilers averaged
lower values than for>gas firing, but combustion modifications could be less
readily implemented.  With coal firing, only two of the seven boilers tested
(one a tangential unit, the other a front wall fired boiler) could be operated
in a manner conducive to reducing NOX emissions.  This operation consisted of
firing the operating burners in the lower burner rows or levels with
substoichiometric quantities of air, and supplying the additional air required
for the burn-out of combustibles (keeping overall excess air as low as possible)
through the air registers of the uppermost row or level.  In these short-term,
exploratory tests, NOX emissions were reduced by over 50%, compared with the
standard firing mode, without decreasing thermal efficiency or increasing the
amount of unburned carbon in the fly-ash.  Due to deactivating the pulverizer
mill to the top level of burners, the amount of fuel that could be fired was
reduced, resulting in a decrease of about 15% from maximum rated capacity.
The NOX reductions achieved were not affected by these reductions in load,
as normal and modified combustion operations were compared at the same boiler
load.

          While the exploratory data obtained in the above study on controlling
NOX and other pollutant emissions from utility boilers by combustion modifications
showed good potential, a number of critical questions have remained to be
answered.  Thus, for coal fired utility boilers, problems of slagging, corrosion,
flame instability and impingement, increased carbon in the fly-ash, the actual
particulate loadings and potential decreases in boiler efficiency which may
result from the modified combustion operations need to be assessed in sustained
test runs.

          The purpose of Esso's present field testing program, sponsored by
EPA under Contract No. 68-02-0227, is to obtain the necessary data on the
application of combustion modification techniques to coal fired utility boilers,
in cooperation with boiler operators and manufacturers coordinated by EPA.
Major U.S. utility boiler manufacturers (Babcock and Wilcox, Combustion
Engineering, Foster Wheeler, and Riley-Stoker) have recommended boilers
characteristic of their current design practices.  They have provided their
help in making arrangements for testing with the cooperating boiler
owner/operators, and in a number of cases assigned representatives to
participate in Esso's field tests.

          In addition to the continuous monitoring instrumentation described
above, four EPA-type particulate sampling trains have been added to Esso's
system.  These trains and other equipment are transported to the testing site
in an auxiliary van.
                                      218

-------
          The approach used for field testing coal-fired boilers is first,
to define the optimum operating conditions for NOX emission control in
short-term, statistically design test programs, without apparent unfavorable
side effects.  Second, the boiler is operated for 1-3 days under the "low NOX"
determined during the optimization phase, for assessing boiler operability
problems.  Finally, where possible, sustained 300-hour runs are made under
both baseline and modified combustion ("low NOX") operating conditions.
During this period, air-cooled carbon steel coupons are 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 fire-side water tube
corrosion rates.  Particulate samples are obtained under both base-line and
"low NOX" conditions, and engineering information on boiler operability, e.g.,
on slagging problems, data boiler performance are also obtained.

          So far, two front-wall, two horizontally opposed, three tangential,
and one  turbo-furnace coal fired boilers have been tested in the present study.
The results obtained on  these coal-fired boilers are discussed in this paper.
                                       219

-------
2.  TEST PROGRAM APPROACH

          This section of the present paper discusses the approaches used
for representative boiler selection (in conjunction with EPA and utility
boiler manufacturers); the various phases of the statistical test program
designs; and the test methods employed.  Methods of gaseous emission testing
were quite similar to those used in Esso's "systematic field study"  vi~JL'
In addition, particulate loadings of the flue gas stream, and the carbon
content of the particulates were determined, and corrosion probing tests
were conducted.

2.1  Test Program Design

          This cooperative program of field testing utility boilers was
conducted by Esso Research with the cooperation of utility boiler manufacturers
and operators under the coordination of EPA.  The proper selection of boilers
representing current design practices for this program was the result of a
cooperative planning effort.  Esso Research developed a comprehensive list
of selection criteria (see Appendix), to assist EPA and boiler manufacturers
in preparing a list of potential boiler candidates.  Each boiler manufacturer
submitted a list of suggested boilers to EPA for review and screening.  After
consideration of such factors as design variables, operating flexibility,
fuel type, geographic location and logistics, a tentative list of boilers
was selected by EPA and Esso.  Field meetings were then held at power stations
to confirm the validity of the boilers selected and to obtain necessary boiler
operating and design data.

          The field meetings were attended by representatives of EPA, Esso
Research, boiler manufacturers and utility boiler operating management.
EPA described the background and need for the program and how it fits into
the overall EPA program.  Esso Research presented a broad summary of our
previous findings, an outline of the three-phase program to be run at each
boiler, and led the discussion aimed at developing the information necessary
to construct a detailed program plan.  These discussions produced an agreed
upon list of combustion operating variables, the specific levels to be tested,
estimated ease and length of time to change from one level to another, how
the variables were interrelated, and what operating limitations or restrictions
might  be encountered.  In addition, the proper number and specific location of
sampling ports for gaseous, particulate, and corrosion probe insertion were
also agreed upon.  Tentative testing dates were scheduled with provision
made for possible segregation of coal  types, scheduling  of pretest boiler
inspection, calibration of measuring instruments and controls, scheduled
maintenance, and other preparatory steps.

          The up-to-date, comprehensive information obtained in these field
meetings provided the necessary data for Esso  to develop detailed, run-by-run
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
to determine NOX emission reduction capability of  the boiler;  (2)  a  1-3  day
sustained "low NOX" run to determine if slagging or other  operating  problems
exist,  and  (3) 100-hour sustained "low N0x" and normal operation runs, to
determine quantitative measures of accelerated furnace  side wall  corrosion
rates.
                                    220

-------
          Statistical principles  (as explained in more detail in our
"Systematic Field Study" (4) provide paractical guidance in planning 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.
Table 1 will be used to illustrate briefly these principles applied to a
front-wall fired boiler, TVA's Widows Creek Boiler No. 6.   (Tangentially
fired boilers present a more complex problem in experimental planning, since
there are additional operating variables such as burner tilt, and secondary
air register settings, that should be included in the experimental design.
However, the same statistical principles apply,)  There are four operating
variables:  (1) load, (2) excess air load, (3) secondary air register settings,
and (4) burner firing pattern.  Assuming three levels of each of the first
three variables and eight different firing patterns available at each load,
there are 216 different operating modes.  However, only the 33 test runs
shown, i.e., 15% of the potential maximum, provided the required information
on this boiler to define practical "low NOX" operating conditons.

          Test run 10 operating conditions were chosen for the second phase
of the experimental program, while test run 26 operating conditions are
recommended for "low NOX" operation under reduced load conditions.  Test
run 10 conditions can be selected with  considerable confidence, since examination
of the data indicates that each of the  So firing pattern runs produced lower
NOjj levels than the corresponding 82 firing pattern.  The effects of day-to-day
variables, such as coal type variability, etc. not under study were balanced
between  the two firing patterns, since  runs 5,6, 7 and 8 were run on one day,
and 9, 10, 11 and 12 were run on another day.  It should also be noted that
each day's runs completed a one-half replicate of the complete factorial
accomplished by two days of testing.  Thus, the main effects of each factor
and interactions between factors  can be estimated independently of each other,
with maximum precision.  Repeat test runs under test run 10 conditions, during
a two-day sustained period, were used to validate these results and to obtain
an independent estimate of experimental error.

          The same principles were applied to planning the 16 runs (13 through 28)
Four test runs were completed each day, one run on each of the four staged
firing patterns, and one run on each of the four excess air and secondary
air register setting combinations.  Thus, the conclusion that the S^ firing
pattern  is the best of those tested rests on the combined results of 16 runs
over a total of four days, and is generally true over all excess air and
secondary air register settings.  Note  also that during staged firing, low
excess air with secondary air registers set at 20% open, always gave the
lowest NQjj levels over each of the four days of testing at 110 MW, and also,
over the two days of testing at 125 MW. Because of the consistency of results
such as  these, the number of test runs  required on similar type boilers tested
later could be substantially reduced by judicious selection of run conditions
for validation purposes.

          Table 2 contains a summary of the eight coal fired boilers tested
to date.  Four are wall fired  (two front-wall and two horizontally opposed);
three are tangentially fired; and one is turbo-furnace fired.  Boilers 1,  3
and 4 are Babcock and Wilcox units, boilers 5, 6 and  7 are  Combustion Engineering
boilers, while Crist No. 6 is a Foster  Wheeler boiler, and Big Bend No. 2 was
designed and constructed by Riley-Stoker.  Full load  ratings,  the number of
burners, and number of burner levels are shown for each boiler in Table 2,
as well as the number of combustion operating test variables,  and the number
of test runs completed on each of these boilers.

                                     221

-------
                                         TABLE 1


                      TEST PROGRAM DESIGN FOR WIDOWS CREEK NO. 6 UNIT

             (Run No., Average % 00 and Average ppm NO  Emissions (0% 0 , Dry))
                                  .                   X                fc


\. 2nd
v . >s. Air
Firings.
Pattern\.
Si - 16 Coal
0 Air Only
S2 - 14 Coal
DI 04 Air
83 - 14 Coal
AI A^ Air
84 - 12 Coal
AI A2 A3 A4
S5 - 12 Coal
AI A4 B2 B3
S6 - 12 Coal
Al A4 Bl B4
87 - 12 Coal
AI A4 DI D4
Sg - 12 Coal
BI B2 83 84
L - Full Load (125 MW)
A - Normal Air
20%
Open
(3) 2.8%
706
(11) 3.8%
724
(7) 4.5%
645





60%
Open
(1) 3.2%
693
(5) 4.0%
639
(9) 4.1%
622





A - Low Air
20%
Open
(4) 1.9%
581
(6) 2.0%
451
(10)* 
-L  / /o
397





60%
Open
(2) "2.0%
593
(12) 1.5%
498
(8) 2.7%
458


/


L - Reduced Load (110 MW)
AI - Normal Air
20%
Open
(31) 4.9%
794


(24> 4.5%
465
(27) 4.9%
579
(15) 5.2%
549
(18) 4.3%
488

60%
Open
(29) 4.8%
734


(13) 4.5%
537
(17) 4.4%
560
(21) 6.1%
641
(25) 4.5%
577

A - Low Air
20%
Open
(32) 2.8%
541


(26)**
* ; 2.7%
346
(22) 3.4%
357
(19) 3.1%
351
(16) 3.0%
384

60%
Open
(30) 2.7*
525


(20) 3.0^
402
(14) .
l.bh
399
(28) 4.5Z
511
(23) q,
J  7/0
511
(20A) ,
.  ,m
454
*   "Low NOX" condition
    selected for sustained
    run.

**  "Low NOx" condition
    with further load
    reduction.
Pulverizer

A - Top Row
B - 2nd Row
C - 3rd Row
D - Bot. Row
Burner No.
1
0
0
0
0
234
000
000
000
000
                                             222

-------
                                                        TABLE 2
                                         SUMMARY  OF  COAL  FIRED BOILERS TESTED
OJ
                   *   FURNACE  DIVISION WALL




                  **   TWIN FURNACE
    	 ___^___^_^^^^____
STATION AND
BOILER NO.
1. WIDOWS CREEK 6


2 . CRIST 6
3. HARLLEE BRANCH 3

4. FOUR CORNERS 4
j
i
| 5. NAUGHTON 3
|

| 6. BARRY 4

|
! 7. BARRY 3
8. BIG BEND 2

j
TYPE OF
FIRING
FRONT WALL*


FRONT WALL
HOR. OPPOSED

HOR. OPPOSED*


TANGENTIAL


TANGENTIAL


TANGENTIAL**
TURBO


FULL
LOAD (MW)
125


320
480

800


330


350


250
350


NO. OF
BURNERS
16


16
40

54


20


20


48
24


NO. OF
LEVELS
4


4
4

6


5


5


6
x


TEST
VARIABLES
4


4
4

5


6

!
7


4
* i


NO. OF
RUNS
43


22
45

26


26


35


8 j
14 i
219 1
$

-------
2.2  Test Methods

          In this section the gaseous and particulate sampling and analytical
methods are described.  Furnace corrosion probing techniques and equipment
used are also discussed.

     2.2.1  Gaseous Sampling and Analysis

          The objective of obtaining reliable gaseous emission data in field
testing boilers requires a sophisticated sampling system.  The sampling and
analytical system used in this program has already been described in detail
in the Esso Research and Engineering Company Report, "Systematic Field Study
of NOX Emission Control Methods for Utility Boilers" (4).

          For the present study, further capabilities were added to the
analytical instrument train by installing a Thermo-Electron chemiluminescent
analyzer to provide measurements of NO and NOX in addition to those obtained
with the Beckman NO and N0 spectroscopic monitors.  Figure 1 is a
schematic diagram of the present configuration of Esso's sampling and
analytical system.

          Since samples are taken from zones of "equal areas" in the flue
gas ducts, gas sampling probes are "tailor-made" for each individual boiler
tested.  Three stainless steel sampling tubes (short, medium, and long) are
fabricated on the job site, and installed in quick-disconnect mounting probe
assemblies, along with a thermocouple located at the mid-point of the duct
for gas temperature measurement.  At least two probes of this type 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.  Thus, a minimum of 6 sample points per duct,
or 12 per boiler are provided, thus assuring representative gas samples.
All connections between the Esso Analytical Van and the probes are of the
quick-disconnect type for ease of assembly and assurance of leak-proof joints.

          In running field tests, the gas samples are withdrawn from the
boiler under vacuum through the stainless steel probes to heated paper
filters where the particulate matter is removed.  These paper filters are
maintained at 300-500F.  The gases then pass through rotameters, which are
followed by a packed glass wool column for SOg removal.  Initially, gas
temperatures are kept as high as possible to minimize condensation in the
particulate filters.  After leaving the packed column at 250-300F, the
gas samples pass at temperatures above the dew-point through heated Teflon
lines to the vacuum/pressure pumps.  The sample is then refrigerated to a
35F dew-point before being sent to the van for analysis.  Usually, the van
is located 100 to 200 feet from this point and the gas stream flows through
Teflon lines throughout this distance.

          As in our previous studies  (4-6), our analytical van was equipped
with Beckman non-dispersive infrared analyzers to measure NO, CO, C02 and S02
a non-dispersive ultraviolet analyzer for N0 measurement, a polarographic 02
analyzer and a flame ionization detector for hydrocarbon analysis.  The
Thermo-Electron chemiluminescent instrument, as indicated above, was added
to provide improved capabilities for NO and NOX measurements.  The measuring
ranges of these continuous monitors are listed in Table 3.
                                      224

-------
    PROBE  (4 EACH)
                                  ESSO  RESEARCH TRANSPORTABLE  SAMPLING
                                        AND ANALYTICAL  SYSTEM
                 THERMOCOUPLE
BOILER
 DUCT
800F
                         PITOT TUBE
                         PARTICULATE FILTERS  (HEATED)
                                  ROTAMETERS
          HEATED LINES
            CO
CO,,
            NO
            SO,
                     CU
       HYDROCARBONS
         NO  & NO
           x
                                             REFRIGERATOR
                                                   fr
                                                                                                    SAMPLING
                                                                                                       VAN
                                                                                                       J
                                                                       SOLENOID
                                                                        VALVE
                                                                            if
                                                                                if
                                                                                                   VENT

                                                                                                   5 PSI RELIEF VALVE

-------
                                TABLE 3

                          CONTINUOUS ANALYTICAL
                         INSTRUMENTS IN ESSO VAN
    Beckman
  Instruments

NO
         Technique
2

co2

CO


so2


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

0-5%
0-25%

0-20%

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
                                    226

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

          Boiler flue gas samples are pumped continuously to the analytical
van through four composite probes.  While one sample is being analyzed,  the other
three are being vented.  Switching to a new sample requires  only the flushing
of a very short section of sample line before reliable readings may be obtained.
Four duplicate sets of analyses from each probe can be obtained in  less  than
32 minutes, thus speeding up the task of obtaining reliable  gaseous emissions,
and/or avoiding the need to hold the boiler too long at steady state conditions.

          The validity of using the Thermo-Electron chemiluminescent NO/NOX
analyzer as the primary NOX monitoring instrument was  checked during the
first series of tests conducted in this program, on TVA's Widows Creek Boiler
No. 6.   As shown in Figure 2, the NOX data measured with  the chemi luminescent
analyzer were correlated with the sum of NO plus NC>2 data measured with  the
Beckman non-dispersive infrared NO and non-dispersive  ultraviolet N02
instruments.  As seen from the regression in Figure 2, excellent agreement
was obtained between the chemiluminescent and spectroscopic  instrumental
methods.  Thus, the chemiluminescent monitor was validated against  the
spectroscopic instruments, which in turn had been validated  against a variety
of other techniques, including the wet chemical phenoldisulfonic acid method,
in previous Esso field studies (4-6).

          Our instrumental measurement technique for flue gas Q and C02
determinations were checked by comparing the measured  02  vs. C02 relationship
to that calculated from fuel analysis, firing rate, and known excess air level.
In our previous studies  (4-6)  we validated the instrumental 02 and C02
measurements against Orsat analyses of grab samples.

          The comparison of measured to calculated 02  vs. C02 relationships
 is shown  in Figure  3,  based  on data obtained  in  testing TVA's. Widows, Creek
No. 6 Boiler.

          As  can be seen from Figure 3, the agreement  between the regressions
based on measurements  and calculations is very good over  the range  of actual
measurements.

     2.2.2  Particulate Sampling

          Modifications in the combustion process to minimize NOX emissions
tend to result in slower, less intense combustion conditions.  Lowering excess
air increases flame temperature which: aids combustion, but limits the amount
of oxygen available for the combustion process, directionally increasing
the probability of burnout problems.  Similarly, staging  of burners,
where some burners are operated at sub-stoichiometric conditions, and the
remaining burners (or  ports) are used as "air-ports" to complete combustion
of the fuel, drastically limits available oxygen in the initial combustion
phase, lengthens out flames and, with the slower, less intimate mixing of
air and fuel, potentially increases unburned combustibles.   Therefore, it
was necessary to consider that combustion modifications implemented to
minimize NOX emissions could potentially increase particulate emissions
from pulverized coal-fired boilers.
                                      227

-------
                                                                    FIGURE 2
ro
ro
oo
NO REGRESSION - BECKMAN NO + NO,, VS CHEMILUMINESCENCE NO MEASUREMENTS
700
600
ii
w 500

3
CN
O
* 400
o
S5
u 300
H
PQ
O
g 200
P-I
P-I

100

A 	 ^ ^
' ' ' 	 ~/?
- QO Oo/
nO
 rv
ocSr
o cf
0%'
O .^^
c^Xo
yT O
XQ
0^0
 >n
^  y = 0.42 +
/ r = 0.985
y Sy(est) =

1 ' 1


~




~

-

1.0172 X
-
L9 ppm NO
X
/ALL READINGS EXPRESSED AS
PPM NOX, CORRECTED TO 3%
^ 02, DRY BASIS.
' /
/ . 1 . 1 i 1 . 1 i 1 i 1 .

1 . 1
0 100 200 300 400 500 600 700 800

-------
                                       FIGURE  3


              RELATIONSHIP BETWEEN % C00 AND % 00  FLUE GAS MEASUREMENTS
                                       fa '        ^
                        (WIDOWS CREEK BOILER NO. 6 - RUN IB)
18
16
                                                            CALCULATED FROM
                                                           /COAL ANALYSIS
                                                            (Y = 18.5-0.
14
                         CALCULATED FROM FLUE GAS ANALYSIS
                                (Y = 18.4-0.95% 02)
O
  I
                               0  IN FLUE GAS  (DRY BASIS)
                                            229

-------
          In view of the above, an important phase of our field test program
on coal fired boilers was directed at particulate emissions.  The objective
of this effort was to obtain sufficient dust loading information to determine
the potential adverse side effects of "low NOX" combustion modifications
on particulate emissions, with respect to total quantities and per cent
unburned carbon, vs. similar data obtained under normal or baseline operating
conditions.  Specifically, such data are needed to evaluate the changes,
if any, that might occur in total dry filterable solids passing through the
boilers, and on unburned combustibles in the fly-ash resulting from "low NOX"
emission modifications.  Other information, such as changes in particle size
distribution or in electrical conductivity which could affect electrostatic
precipitator collection efficiency, would also be of interest, but this was
beyond the scope of our program.

          Four Research Appliance Company EPA-type particulate sampling
trains, including four sample boxes, probes, and two isokinetic pumping sets
were used in obtaining dust loading data on six pulverized coal fired utility
boilers to date.  The names of the utilities and details of the boilers tested,
including size, type of firing, numbers of burners, etc. are given in Table 2.
Except for tests at Utah Power & Light Company's Naughton Station, Boiler No. 3,
all dust loading data were obtained in the flues at convenient locations
downstream of the air-heaters.  At the Naughton Station testing was done
ahead of the air-heaters, due to inaccessibility of locations downstream of
the air heaters.  Also, on Alabama Power Company's Boiler No. 4 at Barry
Station, testing was carried out downstream of the precipitator (with the
precipitator shut-off), immediately before entering the stack.  In all cases
two traverses were made in each flue with one probe assembly, in accordance
with prescribed procedures.  However, strict adherence to EPA-recommended
test methods was not always possible due to the limited availability of sample
port locations, interferences with building and boiler appurtenances, and
the limited time and manpower available for these tests.  However, it should
be remembered that the objective of these tests was to determine relative
changes between normal and modified firing operations, not to measure accurate
dust loadings.

     2.2.3  Furnace Corrosion Probe Testing

          Pulverized coal fired boilers do, on occasion, experience wastage
of the furnace wall tubes (corrosion).  Normally, this type of corrosion is
experienced in areas of localized reducing atmospheres adjacent to the
midpoint of furnace sidewalls near burner elevations where flame impingement
could occur.  Remedies have been to increase the excess air level  so that
an oxidizing atmosphere prevails at these locations, and to increase the
fineness of pulverization, so that complete oxidation of the pyrites in the
coal is accomplished before these species have a chance to reach the furnace
wall tubes.  For new boilers, another remedy has been to increase distances
between the burners and the sidewalls, to minimize potential impingement.
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 600-900F) and iron sulfide, or S03 from the pyrites.
                                      230

-------
          Combustion modifications  for NOX  emission  control  are  generally
most effective at low excess air  or substoichiometric  air  conditions  in
the flame zone, i.e., at conditions that  may  contribute  to furnace  tube
wall corrosion.  Our prior field  tests of coal-fired boilers have been  of
short duration, allowing no time  to assess  such  side-effects.  However,
it has been recognized that the effects of  modified  firing operations on
furnace tube wall corrosion need  to be evaluated (4_-6).  Discussions  with
boiler manufacturers and operators  indicated  that  this potential problem
was one of their greatest concerns.   It was also evident that acclerated
corrosion probe tests would be necessary  to establish  that "low  NOX"
operation with coal could be carried out, since  there was  a  general
unwillingness to operate on a long-term basis using  the  boiler as a test
medium.

          Accordingly, one of the important aspects  of our field test
program was to design and construct controllable corrosion probes,  and  to
define the extent of the potential  corrosion  problem.  The objective  of
our furnace corrosion probing runs  was to obtain "measurable" corrosion
data on potential side effects of "low NOX" firing conditions on furnace
wall tubes.  We received excellent  advice and help in  evaluating the  problem
and defining our approach to corrosion studies by  Combustion Engineering
Company research representatives, and by  Esso's  corrosion  experts.

          Our approach to obtaining data  was  to  expose corrosion probes
inserted into available openings  located  at the  "vulnerable"  areas  of the
furnace (see Figure 4), under both  baseline and  "low NOX"  firing conditions.
Based on prior corrosion testing, it was  concluded that  exposure for
approximately 300 hours at elevated coupon  metal temperatures  (above normal
furnace tube metal temperatures)  to accelerate corrosion,  would  produce
"measurable" corrosion on SA-192  carbon steel (furnace tube  type) coupon
material.  Since our objective was  to show  relative  differences  in  corrosion,
if any, between baseline and "low NOX" firing, exposure  temperatures  at both
conditions were set at approximately 875F; i.e., high enough  to accelerate
corrosion, and just below the 900F limit above  which pyrosulfates  apparently
are not formed.

           Figure  5  and 6  show details of  the  corrosion probes, based
 on Combustion  Engineering's  design.  Essentially,  this design consists  of
 a "pipe within a pipe", where  the cooling air (plant air supply) is admitted
 to the ring-coupons  exposed  to  furnace  atmospheres at one  end of the  probe
 through a %-inch  stainless  steel tube roughly centered inside of the  coupons.
 The amount of  cooling  air is  automatically  controlled to maintain the desired
 set-point  temperature  (875F)  on 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  presentation,  thermocouples
 installed  in each coupon are not shown  in Figures  5  and  6.  Normally,
 one thermocouple is  used for  control, and the other  one  for  recording.   The
 cooling air travels  backwards  along the  2%-inch  extension  pipe and  discharge
 outside of the furnace.  Thus,  there is no interference  with the cooling  air
 and the furnace atmosphere  at  the coupon  location.
                                      231

-------
                                           FIGURE  4
                GEORGIA POWER
           HARLLEE BRANCH STATION
              BOILERS NO. 3&4
                  FURNACE CORROSION
                   PROBE LOCATIONS
                                         UTAH  POWER AND  LIGHT COMPANY

/
F.W.
BURNE

RS
SI
SLAG BLC
BLOWER NO,
NO. 9 1
.\ I
/ I
PROBE
3B PROBE!
3 A, 4 A, 41
V
AC
)WE
3
~1
B
RS
&8
SLAG
 BLOWER INSPECTION
= 8' TOP
i x TJTTDKTT7T?
X ELEV.
1 TOP BURNER
ELEV.
V
R.W.
URNERS



-PROBE PROBE
NO. 2 NO. 1
\ /
-D Q D 00
INSP.
DOORS .
PROBE PROBE
NO. 4 NO. 3

^K

                   SIDE ELEV.
                                                                      FRONT ELEVATION
                                                                      (CORNER BURNERS)
 SLAG
BLOWER
              ARIZONA PUBLIC SERVICE COMPANY
           FOUR CORNERS STATION - BLRS.  NO.  4&5
                       SLAG .BLOWERS
     TOP
    BURNER-
    ELEV.
         BURNERS
   A
-  
 -V
                      PROBE
                    LOCATIONS
                   (BOTH SIDES)
                                        v
                                        \
                                      BURNERS
                       SIDE ELEV.
                                               ALABAMA POWER COMPANY
                                            BARRY STATION - BOILER HO. 4

                                                     SLAG BLOWERS
                                                       N0.18&26
                                   LOWER
                                   BURNER
                                   ELEV.
                                     SLAG

                                     ELEV.

I
11'
t


r
	





t



PROBES NOS. 3
PROBES I
 - t
_ j
IOS. 1
-

                                               232
                                                       SIDE ELEV.
                                                    (CORNER BURNERS)

-------
                                                           FIGURE 5
                                                       CORROSION PROBE
                                     DETAIL OF 2%" IPS EXTENSION PIPE AND END PLATE
                                                     (OUTSIDE OF BOILER)
                        DRILLED AND TAPPED FOR 1/8" IPT THREAD.

      (SWAGELOCK FITTINGS - FOR THERMOCOUPLES)
13
DRILLED
  ACCEPT
" SS AIR
SUPPLY
TUBING
          HOLE FOR 1/4" SS
          GAS SAMPLING TUBE
                          d
   END PLATE
                                       END PLATE
WELD
                                                                     2%"  I.P.S.  PIPE
                                                                       EXTENSION






(
(
A
u






































^
H~

4:




^^^^



^
i4

=HJ
A






/
X^
^

XX
'//
'//




//,
%
P^$J$$JJ^^
,1/16" THERMOCOUPLES (2)
X /




	 T)
AIR SUPPLY y
** (%" SS TUBING) \
- 	 )


                                                                           1/4" GAS SAMPLING TUBING (SsT
                                                                          SEAL
                                           SWAGELOCK FITTING DRILLED FOR %" SS AIR SUPPLY
                                         TUBE (THREADS  CUT  OFF  AND  FITTING WELDED OR  SILVER
                                                        SOLDERED  TO END PLATE)

                         WELD
                                                                                                 AIR DISCHARGE
                                                                               1-1/4" COUPLING

-------
                                                      FIGURE 6

                                                    CORROSION PROBE

                                           DETAIL OF CORROSION COUPON ASSEMBLY
                                                  (INSIDE OF FURNACE)
                      2%" PIPE EXTENSION
                                \
NJ
OJ
1/4"
                                                                    CORROSION
                                                                    COUPONS

                                                   S.S. COOLING AIR SUPPLY TUBE
                 S.S.  GAS SAMPLING
                     TUBE
                                                                                            THERMOCOUPLE SOCKETS
1


1
^
?
                                                                                           1-1/4'I	
                                      -5/8*V
                                    END CAP
                                          FACE OF FURNACE WALL TUBES

-------
             Sustained, 300-hour corrosion probe tests were run on boilers of
   four utility companies, as shown in Table 4 below:

                                    TABLE 4

                       SUMMARY OF CORROSION PROBING TESTS
         Utility
   Station
Georgia Power Co.

Utah Power & Light Co.

Arizona Public Service Co.

Alabama Power Co.
Harllee Branch

Naughton

Four Corners

Barry
 Boiler Number
Base   "Low NO "
	   	x
  4        3

  3

  5        4

  4        4
   Type of Firing

Horizontally Opposed

Tangential

Horizontally Opposed

Tangential
                                          235

-------
3.  FIELD TEST RESULTS

          The field test results obtained on individual boilers under diverse
operating conditions are presented in three sections.  These sections consist
of gaseous emission measurements, flue gas particulate loading measured upstream
of particulate collector equipment, and corrosion probing data obtained in
accelerated furnace fire-side water-tube corrosion tests.  Gaseous emission
and most of the particulate emission data were obtained under normal, as well
as staged firing conditions.  As discussed before, 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
staged firing patterns on flue gas particulate loadings in coal combustion.
Similar considerations apply to the sustained, 300-hour corrosion tests, which
had as their objective the determination whether staged firing of coal accelerates
furnace water tube corrosion rates.

          The gaseous emission data obtained under baseline and staged firing
conditions, at various load levels, are presented first.  Throughout this paper,
pollutant concentrations are expressed as ppm, adjusted to zero per cent 02 in
the flue gas, on a dry basis.

3.1  Gaseous Emission Results for
     Individual Coal-Fired Boilers
          The data obtained are grouped according to boiler design type,
i.e., wall-fired (front wall or horizontally opposed), tantentially fired,
and turbo-furnace boilers.

     3.1.1  Widows Creek Boiler No. 6

          The Tennessee Valley Authority's Boiler No. 6 at their Widows Creek
Station was the first boiler tested in our present study.  Thirty-two short-term
test runs were made in a statistically design optimization program, to minimize
NOX emissions.  These tests were followed by two sustained runs, one at full load,
the other one at reduced load, with the optimum staging patterns.  The sustained
corrosion probing run was deferred at TVA's request, until high sulfur coal
could be fired, and other data would be available to show that staged firing
would not cause abnormally high furnace corrosion rates.

          Widows Creek Unit No. 6 is a 125 MW, 16-burner, front-wall,
pulverized coal fired Babcock and Wilcox boiler.  It has a single dry-bottom
furnace with a division wall, and the 16 burners are arranged with four burners
in each of four rows.  Each row is fed with coal by a separate pulverizer.

          The statistical test design shown in Table 1 for this boiler has
been discussed earlier.  The NOX emission data, expressed as ppm NOX corrected
to zero per cent 02 in the flue gas (dry basis) obtained with the various firing
patterns tested are presented in Figures 7 and 8.  In Figure 7, the measured
emissions are plotted vs. per cent of stoichiometric air to the active burners.
Figure 8 shows the same emission data, but plotted as a function of the overall
per cent stoichiometric air.  Corresponding to each firing pattern (designated
by "S"), least squares regression lines have been fitted to the data points.
                                      236

-------
                                              FIGURE 7



                            PPM NOX (0% 02, DRY) VS % STOICHIOMETRIC AIR

                            	TO ACTIVE BURNERS	


                                     (WIDOWS CREEK - NO. 6 BOILER)
    900
    800
    700
CO
H


3
o

&?
o
o
a
    600
    500
    400
    300
    200
                   S4_7  (80-110  MW)
                                                                                 I


                                                                              (110 MW)
/ A *
/ A
/ s\
D / /A S2-3 (125 m
a*
x
/
/
f
FIRING
PATTERN:
SYMBOL (ACTIVE /AIR)

0 S1 (16/0)
 S^^ (16/0)
A S2_3 (14/2)
D S4_? (12/4)
1 1 1 1 1
GROSS
LOAD
(MW)

125
110
120-125
80-112


-



-

I
        80
90
100
                                            110
                                    120
130
140
                                % STOICHIOMETRIC AIR TO ACTIVE BURNERS
                                                 237

-------
                                              FIGURE  8


                                 PPM NOX  (0% 02, DRY)  VS OVERALL
                                 	STOICHIOMETRIC  AIR	

                                  (WIDOWS CREEK  -  NO.  6 BOILER)
    900
     800 -
     700 -
(=>
 (N
O
6-S
O
O
a
PH
PLI
    600 -
    500 -
    400 -
    300,
       '80
90
100
110
120
130
140
                                     % OVERALL STOICHIOMETRIC  AIR
                                                  238

-------
          The data show the strong influence of reduced oxygen supply on
decreasing NOX emissions.  This effect is further enhanced by staged firing
patterns, as shown in Figures  7 and  8.

          Low excess air operations  consistently reduced NOX emission levels.
Average reductions were 23% under normal firing, 34% at full load staged
operation and 27% at reduced load staged operation.  Staged firing at full
load resulted in an average of 14% NOX reduction at full load, and an average
of 27% at reduced load.  The lowest  practical level of excess air was dictated
by acceptable CO emissions and stack appearance.  The combination of low
excess air and staged firing reduced NOX emissions by 40% at full load, and
from 33% to 50% at reduced load.  The optimum combination of operating
variables reduced NOX by 47% at full load and by 54% at reduced load.

          Of the firing patterns tested, operating the top row of burners on
air only, with low overall excess air, gave the highest reductions in NOX.
Operating with the top wing burners  on air only resulted in slightly lower
NOX emissions than with the bottom wing burners on air only.

          Opening or closing down the secondary air registers was found to
have small, but statistically  significant effects on NOX emission levels.

          The data shown in Figure 7 call attention to an apparent anomaly.
A cursory inspection of the data would indicate, that while as expected, NOX
levels decrease with decreasing air  supply to the active burners, staging the
burners could result in higher NOX emissions than normal operation at the
same burner air/fuel air ratio.  The true interpretation of these data is that
for staged burner configurations, it is generally necessary to operate at a higher
overall level of air supply than for normal firing.  Thus, for a given air/fuel
ratio to the burners, the overall level of excess air is higher in staged firing
than in normal operation.  Furthermore, the desirable effect of heat removal
between "first" and "second" stages  is not as effective in staging the burners
as when special "NO-ports" or  "over-fire" air ports are available for secondary
air admission.  Thus, it is reasonable to expect that in new installations,
designed for staged combustion, even higher NOX reductions may be accomplished
than in these tests which deliberately "de-activated" burners to achieve staging.

          The foregoing remarks on comparing NOX emissions with staging to
those with normal firing, as a function of the per cent stoichiometric air
to the active burners, are not unique to Widows Creek No. 6, but to all boilers
tested, as will be shown later.

     3.1.2  Crist No. 6 Boiler

          Gulf Power Company's Boiler No. 6 at their Crist Station is also
a front-wall fired unit.  This Foster Wheeler boiler has a single furnace,
with a maximum continuous rating of  345 MW gross load.  Its 16 burners are
arranged in four rows of four  burners each.

          A cooperative test program by Gulf Power, Foster Wheeler and Esso,
coordinated by EPA, was planned for  this unit.  Plans included short-term
firing pattern optimization runs for minimizing NOX emissions, accompanied
by boiler performance tests by Foster Wheeler, followed by boiler operability
check-out at "low NOX", than a sustained 300-hour test under "low NOX" and
baseline operating conditions  for assessing corrosion problems, and an optional
long-term test period of about 6 months for determining actual furnace water
tube wastage.


                                       239

-------
          Because of load demands on this boiler, to date it has been possible
only to explore firing patterns in short-term runs, without performance  tests,
for minimizing NOX from this boiler.

          As shown by the data in Figure 9, the general trend of decreasing
NOX emissions with reduction of per cent stoichiometric air followed trends
similar to those observed in the Widows Creek Boiler No. 6 tests.  Again, NOX
levels decrease sharply with decreasing the % stoichiometric air to the  active
burners, including normal firing patterns.

          The data in Figure 9 are subdivided into the "A" and "B" sides
of the boiler.  The flue gas stream leaving the furnace is split into these two
ducting faths, and although the boiler operator and manufacturer could at times
achieve 02 balance in the two sides, the NOX levels measured were clearly
higher for the A side than the B side, with all firing patterns tested.  The
reason for this behavior is unexplained at present, although it may be related
to differences in air flow, and uncertainties of the accuracy of air damper
settings on the two sides of the boiler.

          To simplify the presentation, Figure 9 shows only the least square
regression lines fitted to the data points.  Si denotes normal firing, while
S2> S3> and S4 are staged firing patterns, where 82 denotes top row using
burners on air only, 83, top row middle burners on air only, and 84, all top
row burners on air only.  Combining all data points for the A and B sides of
the boiler, respectively, results in the two similar, although not quite
parallel least squares regressions shown in heavy lines, indicating similar
trends.

          As expected, the 83 pattern results in somewhat lower NOX emission
levels than the 82 pattern, because of the larger spacing between active
burners in the former configuration.  The most effective combustion modification
is, of course, operating the top row burners on air only (84) with low overall
excess air, but for this boiler, such a firing pattern entails a load reduction
of about 15%.

          It is hoped that eventually an opportunity may arise for completing
the planned program on this unit.

     3.1.3  Harlee Branch Boiler No. 3

          Georgia Power Company's No. 3 Boiler at their Harlee Branch Station
was tested through all three phases of our test program procedure.  In this
section of the present paper, the gaseous emission results are summarized while
particulate measurements and corrosion probing results will be presented later.

          Harlee Branch unit No. 3, with a maximum rated capacity of 480 MW
gross  load, is a single furnace, pulverized coal fired Babcock and Wilcox boiler.
It has 40 burners arranged in twenty burner cells of two burners each, with two
rows of five burner cells located in both the front and rear walls of the furnace.
The burner configuration and pulverizer layout are shown in Figure 10 for this
boiler.
                                       240

-------
                                            FIGURE 9
     1200
     1100 H
     1000 h
H
CO
o
6*!
O
g
g
PJ
CM
                          PPM NOX (0% 02, DRY) VS % STOICHIOMETRIC
                           	AIR TO ACTIVE BURNERS
(CRIST NO. 6 BOILER)
      I            T
                                                                       S -S. - "A" DUCT
                                                                        1  4
                                                                        s  s  - "B" DUCT
                                                                         1  4
                                                                               GROSS
                                                             FIRING PATTERN    LOAD
                                                              (ACTIVE/AIR)      MW
                                                                   (16/0)
                                                                   (14/2)
                                                                   (14/2)
                                                                   (12/4)
                                       320-270
                                       320
                                       320
                                       270
                                100          110          120         130
                             % STOICHIOMETRIC  AIR TO ACTIVE BURNERS
                                          140
                                                241

-------
                             FIGURE 10


                 HARLLEE BRANCH  NO.  3 BOILER

               PULVERIZER AND COAL PIPE LAYOUT
               TWO-BURNER CELL


             PULVERIZER LETTER

                 BURNER NUMBER
                                    
                                            
                                              D
                                              3
                                             ^-^

                                              J
                                             ,*->
                                              4
                                     
                                      B
                                     ^
                                      4

       
        4
        *+-~*

        E

        f

        3
         4
        /

         G
        ^
         3
 4
1^

 C

<-
,3
                                      2
                                     >^_

                                      A
                                     K
                                            
                                      2
                                      .'
                                      D

                                      v
                                      3
                               3
                              *	'
                               K
                              f.
                               4
A

T
                                              FACING REAR FACE
 H



                4
               *>.

                F
         FACING FRONT FACE
[4


 H


(3*
                                  242

-------
          Because of the arrangement  of  pulverizer mills  for  this boiler, it
was possible to shut off the  coal  supply through  individual pipes, and  therefore,
there was added flexibility for exploring staging patterns during the short-term
testing phase.

          Baseline NOX emission levels averaged about 870 ppm.  Lowering the
level of excess air was possible both under  normal and  staged operating conditions
down to flue gas 02 concentrations of about  1.5%  or  even  lower, without apparent
undesirable side effects.  The steep  effect  of reducing the per cent of
stoichiometric air to the  active burners on  decreasing  NOX emissions is shown
by the least squares regressions of the  data in Figure  11.  This figure combines
the data obtained under normal firing using  40 burners, with those measured using
a large variety of burner  staging  patterns.

          Interestingly, by operating four to six top burner  cell row burners
on air only, it was possible  to maintain boiler load at 480 MW, and reducing
the NOX emission levels to about 580  ppm.  This level corresponds to a reduction
in NOx of about one-third, compared with the  baseline level.  Usually,
using burners of the top rows of front and rear walls were operated on air
only, but the NOX emission levels  were not particularly sensitive to the exact
location of the inactive burners in the  top  row.

          With only 30 active burners, i.e.,  10 top  row burners on air only,
it was possible to reduce  NOX emissions  to about  390 ppm  at low levels of
excess air, or a reduction of over 50% from  the baseline  level.  However,
load was also reduced by 17%  from  480 MW to  400 MW using  this staging patterns.

          For the 300-hour sustained  run,  a  full  load,  low excess air condition
(overall 107% stoichiometric  air,  with three wing burners on both front and
rear faces of the boiler on air only) was  selected.

     3.1.4  Four Corners Boiler No. 4

          Arizona Public Service's No. 4 Boiler at their  Four Corners Station
was also tested according  to  our test program design, except  that continuous
electricity demand on the  station  prevented  testing  at  low loads, and the
currently inoperative flue gas recirculation system  could not be utilized.
This unit, with a maximum  rated capacity of  800 MW gross  load, is a single
furnace (with division wall), pulverized coal fired  Babcock and Wilcox boiler.
It is fired with low sulfur,  high  ash Western coal.  Boiler No. 5 at the
Four Corners Station is a  "sister"-unit  of similar size and design.  The latter
was used for determining accelerated  furnace water tube corrosion rates under
baseline operating conditions.

          In each of these two boilers,  nine pulverizers  feed 54 burners,
arranged in 18 cells of three burners each,  as shown in Figure 12.  The front
wall has ten burner cells, while eight burner cells  are located in the  rear
wall of the furnace.  Each boiler  can maintain the full load  capacity of
800 MW with eight or nine  pulverizers in operation,  when  good quality coal
is fired, and all equipment is in  good operating  conditions.
                                      243

-------
                                              - 30 -
                                             FIGURE 11

                           PPM NO  (0% 02, DRY) VS % STOICHIOMETRIC
                           	AIR TO ACTIVE BURNERS	
                              (HARLLEE BRANCH - NO. 3 BOILER)
   900
    800 -
w   700 -
    600 ~
6-S
O
O
a
s
    500 -
    400-
    300
                 NORMAL FIRING - 480 MW
                 (40 BURNERS FIRING)
STAGED FIRING - 480 MW
(4 TO 6 BURNERS AIR ONLY)
                                    STAGED FIRING -  400 MW
                                    (10 BURNERS  - AIR ONLYl
                               80           90         100         110

                             % STOICHIOMETRIC AIR TO ACTIVE BURNERS
                                               244

-------
                                       FIGURE 12

                         FOUR CORNERS STATION - BOILER NO. 4
                           PULVERIZER-BURNER CONFIGURATION
                                                    REAR WALL (EAST)
         NORTH
         WALL
42S.X"
                                                                    SOUTH WALL
                       FRONT WALL (WEST)

 9 PULVERIZERS  NUMBERED 41 THROUGH 49.
18 BURNER CELLS NUMBERED WITH PULV. NO. "N" OR "S" FOR NORTH OR SOUTH OF DIVISION WALL.
54 BURNERS DESIGNATED "T", "M" OR "B" FOR TOP, MIDDLE OR BOTTOM OF EACH CELL.

E.G., 45NT IS TOP  LEFT BURNER IN FRONT WALL OF NO. 4 BOILER
           TOP  BURNER OF CELL
           'NORTH SIDE OF DIVISION WALL
           'NO.  5 PULVERIZER
           'NO.  4 BOILER
                                            245

-------
          Operating variables during the short-term optimization phase of
the tests were boiler load, burner firing pattern, excess air level and
secondary air register setting.  Our gaseoug sampling system was modified
to allow sampling from 18, instead of the usual 12 duct positions, with two
three-probe assembly each in the north, middle, and south ducts between the
economizer and the air heaters.

          The NOX emission data measured are summarized in Figure 13.  Baseline
NOX emissions under normal operating conditions averaged a high level of about
1070 ppm, which is consistent with that expected from a large, horizontally
opposed, coal-fired boiler.  Reducing the per cent stoichiometric air to the
active burners sharply reduced NOX emissions for both normal and staged firing.

          Staged firing with 46 active burners (eight top burners on air only)
resulted in further reductions in NOX, particularly when the per cent
stoichiometric air to the active burners was decreased below 100%.  As shown
by the least squares regressions of the data in Figure 13, NOX emissions could
be reduced by about 45% to 570 ppm, with 95% of the stoichiometric air supplied
to the active burners.  Even further reductions in NOX could be achieved at
the full load of 800 MW by operating 12 burners on air only, to 530 ppm, or a
reduction of 50%.

          Wide  open  secondary  air  register  settings  could reduce NOX emissions
by a small  amount  compared with closed  settings  (presumably because of  reduced
combustion  intensity), but only in combination with  low  excess  air firing.
As before,  the  effect of  damper settings on NOX emissions was significant but
second-order with  respect to the main effects of reduced excess air and staging.

          As  for  the boilers discussed  before, the plot  of ppm  NOX vs.  per  cent
stoichiometric  air to the active burners shows the effect of  staging.   Again,
the apparent dichotomy of higher NOX emissions measured under staged firing
conditions  than for  baseline operation  at the same levels of  per  cent
stoichiometric  air is due to the fact  that  the overall excess air is higher
at the  same burner air supply  for  staging than for normal firing.

           The solid triangle data  points obtained with staged firing
(46 active  burners,  eight burners  on air) were measured while the boiler
operator used water  injection  to help improve precipitator efficiency for
particulate removal.  The rather impressive reduction in NOX  of over 100 ppm
from about  700  ppm is not altogether surprising, based on our estimate  of
0.2 Ib.  HO injected/lb.  coal  fired.  This  quantity  of water  injection  should
reduce  flame  temperatures sufficiently  to allow  for  the  above degree in NOX
emission reduction.

     3.1.5  Naughton Boiler No. 3

          Utah  Power and  Light's No.  3  boiler  at  their Naughton Station was
one of  two  modern,  350 MW maximum  rated single furnace,  pulverized coal fired,
Combustion  Engineering boilers  tested.  The other one was Alabama Power's No.  4
Boiler  at their Barry Station.  Both boilers have  five  levels of  four corner
burners  each.   Gaseous emission results obtained  in  testing  the latter  will
be presented  in the next  section of this paper.
                                      246

-------
                                        FIGURE 13

                         PPM N0x  (0% 02, DRY)  VS  % STOICHIOMETRIC
                         	AIR TO ACTIVE  BURNERS	

                                (FOUR CORNERS  NO.  4 BOILER)
1100
1000
 900
 800
 700
 600
                STAGED FIRING
                (12 AIR, 42 COAL)
                      STAGED FIRING
                      (8 AIR, 46 COAL)
                                                               NORMAL FIRING
                            _L
 500,
    90
100
110         120         130         140

    % STOICHIOMETRIC AIR TO BURNERS
                                                            150
                                              247

-------
          Naughton unit No, 3 was designed to fire a sub-bituminous, low
heat content (9,500 Btu/lb. HHV), low sulfur, high moisture content Western
coal.  The boiler was designed for a larger turbine-generator than the one
actually installed.  This factor, in combination with the lack of "seasoning"
of the superheat and reheat surfaces, and the type of coal fired in this new
unit has resulted in a steam temperature control problem.  The use of tilting
burners and attemperation water are the means available for controlling steam
temperatures.  To the date of our test, it has been necessary at load levels
exceeding 280 MW to tilt the burners down, add attemperation water, lower
excess air and use furnace soot blowers almost continuously.  It may be
necessary, according to Combustion Engineering representatives, to reduce
the reheat surface area to overcome this control problem.

          Other operating problems encountered in this test program were
furnace slagging (particularly at high loads, with low excess air and tilting
burners down) even under normal operating conditions, and the high silica content
of the boiler feed-water, causing pin-hole leaks in the condenser tubing.

          The above problems were taken into account for the design of the
statistical test program.  Our short-term, NOX optimization phase was conducted
at less than full load levels, to avoid the limited flexibility associated
with operating problems.  The six operating variables studied in the short term
optimization tests were gross boiler load, burner firing pattern, excess air
level, burner tilt, secondary air damper setting, and coal pulverizer fineness
setting.  Because of the above-mentioned operating problems with this new
boiler, the 300-hour accelerated test was performed only under normal operating
conditions, as will be discussed later.

          Normal classifier fineness, horizontal or down-tilt burner position,
and low coal-air register settings resulted in the lowest NOX levels.  Based
on these initial findings, most of the NOX optimization test were run under
these conditions, to explore the effectiveness of the major variables, staging
and excess air, on NOX emissions.

          The emission data obtained are in testing this boiler are shown by
the least square regressions of Figure 14.  Significant reductions in NOX
emissions were achieved from the baseline level of about 650 ppm (which is
relatively low for a coal fired boiler of this size, but typical of tangential
fired units, from the standpoint of  NOX emissions).  With normal firing,  quite
a steep decrease was found by reducing the per cent stoichiometric air to the
active burners to 110%, resulting in a reduction by about 30% to 450 ppm.
Staged firing in combination with low overall excess air (less than stoichiometric
air/fuel ratio in the active burners) resulted in NOX levels as low as 250 ppm,
or a reduction of about 60% from the baseline NOX level.  The highest reductions
in NOX were achieved with "abnormal" air register settings  (coal-air 30% open,
and auxiliary air 70% open), as opposed to the normal settings of coal-air 80%
open, and auxiliary air 20% open.  Additional small reductions in NOX emissions
could be obtained through the use of optimum burner tilt positions, and
pulverizer mill fineness, each contributing about 10% to the NOx emission
reductions achieved.
                                       248

-------
                                            FIGURE 14
                              PPM NOX (0% 02, DRY) VS % STOICHIOMETRIC
                              	AIR TO ACTIVE BURNERS	
                                  (NAUGHTON STATION, NO. 3 BOILER)
   700
   600

B  500|
8
                                                         NORMAL FIRING
                                                         (260-330 MW)

                                                               DOWN-TILT
                                                          /
                                                            H
                                                         HORIZONTAL TILT
   400
   300
   200
                                                             STAGED FIRING
                                                             (250-260 MW)
                                                     HORIZONTAL AND UP-TILT
   100
                             _L
             J.
_L
_L
     60
                 70
 80          90         100         110

I  STOICHIOMETRIC AIR TO ACTIVE BURNERS
                                                                             120
                                    130
                                               249

-------
     3.1.6  Barry Boiler No. 4

          Alabama Power's Boiler No. 4 at their Barry Station was tested
successfully through all three phases of our test program design.  Representatives
of Combustion Engineering actively participated in this series of tests.  As
mentioned before, this new 350 MW maximum rated capacity, single furnace,
pulverized coal fired Combustion Engineering boiler is similar to Naughton
unit No. 3.  Both are representative of that manufacturer's current design
practices.  In Barry No. 4, five pulverizers feed 200 burners that are
corner-mounted at five levels of the furnace.  This boiler is designed for
firing Eastern bituminous coal, having a HHV of 12,000 Btu/lb.
          Altogether, 35 statistically designed short term period
optimization runs were made during the first phase of the test program.  The
gaseous emission data obtained in this phase are presented in the least squares
correlations of Figure 15.
          Among the minor operating variables from the standpoint of
emission control, burner tilt position had the most promised effect, as shown
in Figure 15.  Horizontal and 30 up-tilt burner positions produced lower NOx
emissions than the 30 down-tilt position, particularly with all burners firing
coal.  Varying burner tilt position, of course, has as its primary purpose to
control steam temperatures.  With the burners tilted down, a large proportion
of the combustion process occurs in the direction of the bottom of the furnace
(hence increased slagging there) , and higher peak flame temperatures at longer
gas residence times produce more NOX.  These increased NOX levels can be
partially offset by the ability to operate at lower excess air levels with the
down-tilt position, as more residence time is available for burn-out of the fuel.
With horizontal or up-tilt burner positions, there may be less than one complete
rotation of the swirling gases before reaching the boiler arch, which can lead
to some stratification (about one per cent difference in 62 between "A" and "B"
ducts.

          The other minor variables studied, air register settings and coal
pulverizer fineness, did not produce significant changes in N0x  As expected,
the most pronounced effect on NOX was that of reducing the per cent stoichiometric
air to the burners under normal firing conditions, as shown by the data of
Figure 15 .  From baseline levels of about 510 ppm (these remarkably low levels
are likely to be due in part to the ability to operate this boiler with only
10% excess air, and in part to the slightly lower bound N-content of Alabama
and Midwestern coals than that of the Western coal fired at Naughton) , reducing
the per cent stoichiometric air to 104% resulted in NOX emissions of 390 ppm,
or a reduction of about 23%.

          Further significant reductions in NOX were achieved by staged firing,
admitting air only to the top level burners , and operating four or three
pulverizers, depending on load conditions.  With only one pulverizer inactive,
and supplying 90% of the stoichiometric air to the active burners, the NOX
level was as low as 290 ppm, or a reduction of about 43% from the baseline
level with a reduction in load of about 15% due to staging.  Interestingly,
the NO  level was slightly higher, and the per cent reduction somewhat lower
than those found in testing Naughton Boiler No. 3, presumably because of
differences in boiler operation and coal type.
                                        250

-------
                                           FIGURE 15

                           PPM NOX (0% 02, DRY) VS % STOICHIOMETRIC
                           	AIR TO ACTIVE BURNERS	

                                  (BARRY STATION NO. 4 BOILER)
   7QO|-                                                               NORMAL FIRING
                                                                      (325-350 MW)

                                                                 DOWN-TILT
   6001
                                                                    (HORIZONTAL
                                                                    |AND UP-TILT

   500[                                            '  u
0N     I      STAGED FIRING
K  4001-   A~ 280-300 MW                  /   
-------
          Significantly, no slagging problems were encountered in testing
Barry unit No. 4 even at the lowest levels of excess air used (as opposed to
Naughton) and consequently, the 300-hour sustained "low NOX" run could be made
under excellent conditions.

     3.1.7  Barry Boiler No. 3

          Alabama Power Company's Boiler No. 3 at their Barry Station was
tested at the boiler operator's request for gaseous emissions only in a
short-term optimization program.

          This unit is a 250 MW maximum continuous rating, twin furnace,
tangential, pulverized coal fired Combustion Engineering boiler.  It has a
separated furnace arrangement, with radiant and horizontal superheater surfaces
in both furnaces.  The pendant and platen sections constitute the superheat
surface in one furnace, and reheat surface in the other one.  Six pulverizers feed
24 tangential burners (six levels of four burners) in each of the two furnaces.

          This boiler was of special interest, because of the small value of
31.25 MW per "equivalent furnace firing wall".  Our correlation based on
previously obtained data for coal fired boilers (4) would predict a baseline
NOX emission level of 475 ppm for this parameter.  Actual measurements gave
baseline NO  value of 479 ppm, in good agreement with the correlation.

          Operating variables included in the actual test program were excess
air level, air damper settings, and mill pulverizer fineness setting.  Planned
reduced load and staged firing tests could not be implemented, because mechanical
problems with a condenser water valve prevented such operation, despite all
the efforts of the plant personnel to correct the problem.

          As expected, excess air level exerted a major effect on NOX emissions,
while that of damper settings was very small, and that of mill fineness was
negligible.

          These results are shown in the least squares regressions of Figure 16.
From a baseline level of about 530 ppm at 122% stoichiometric air to the burners,
NOX emissions were reduced by about 32% (in line with our previous experience)
to 360 ppm at 106% stoichiometric air.

     3.1.8  Big Bend Boiler No. 2

          Tampa Electric Company's Boiler No. 2 at their Big Bend Station has
been the only Riley-Stoker turbo-furnace unit tested by us to date.  This
pulverized coal fired, 450 MW maximum continuous rating, single furnace boiler
is fed by three pulverizer mills.  Altogether, 24 Riley directional flame
burners are fired normally, with one row of 12 burners in the front wall, and
another row of 12 burners in the rear wall.

          Maximum load was limited to 375 MW, due to steam temperature,
potential slagging, and other operating problems.  (It is our understanding
that gross load on this unit has never exceeded 400 MW.)  Excess air was set
at normal operating levels, or at the minimum level dictated by maximum acceptable
CO levels measured in the flue gas, and in the slag catcher at the bottom of the
furnace.  Other operating variables included in the statistically design
short-term phase (this was the only phase of our overall program design performed
                                      252

-------
                                         FIGURE 16

                          PPM NOX (0% 02, DRY) VS  % STOICHIOMETRIC
                          	AIR TO ACTIVE  BURNERS	

                                    (BARRY NO. 3 BOILER)
7001
6001
500!
400
                                                                     100 AUX/30 COAL
                                                                    I 2ND AIR REG.
                                                                40 AUX/100 COAL
                                                                2ND AIR REG.
300
200
                                                   J_
                                                 _L
   80
90
100         110         120         130

  % STOICHIOMETRIC AIR TO BURNERS
                                            253

-------
at Big Bend) were operating with fly-ash reinjection (practiced to improve
carbon burn-out efficiency and slagging characteristics) or without it, and
positioning of the directional air vanes.  Normal position is 15 below the
horizontal for the air vanes.  During our tests, they were aligned either 15
below the normal position, in both front and rear burners, or the front
directional vanes were set at 15 below the normal position, and the rear
directional vanes 15 above it.  Simulated "staged" firing, at reduced load
levels, was attempted by opening up the secondary air registers on selected
burners, so that the active burners were supplied with 80% of stoichiometric air.

          The NOX emission results obtained are shown in the least squares
regression  of Figure 17.  Reducing the air to the burners from the normal
level of 115% of stoichiometric to 107%, decreased NOX emissions from about
675 ppm at 370 MW to 470 ppm with 107% of stoichiometric air, or a reduction
of about 45%.  This decrease in NOX with reducing excess air is steeper than
that generally observed in wall and tangentially fired units.  On the other
hand, it should be noted that the "baseline" NOX emission was determined at a
load reduction of 18%, compared with maximum continuous rating.  Further load
reduction produced, as expected, further decreases in NOX.

          "Staged" firing, which in this instance was quite different from the
normal pattern of staging burners, produced only a 10% reduction in NO  at the
low load of 230 MW, as shown in Figure 17.

          The best NO,, reductions were obtained with front wall directional
air vanes tilted 15 
-------
                                        FIGURE 17

                        PPM NOX (0% 02, DRY)  VS  %  STOICHIOMETRIC
                        	AIR TO ACTIVE  BURNERS	

                                  (BIG BEND NO. 2 BOILER)
80C
700
600
500
 400
                                                                 NORMAL FIRING  (370 MW)
                                                                  NORMAL FIRING  (300  MW
                                 "STAGED" FIRING  (230 MW)

                                       I	I	L
 300
   70
80
90         100          110          120

% STOICHIOMETRIC AIR TO ACTIVE  BURNERS
                                                                           130
                                             255

-------
TABLE 5
PARTICULATE



Utility


TVA




Georgia
Power
Company


Arizona
Public
Service Co.

Alabama
Power
Company


Utah Power
& Light Co.

Gulf Power Co.




Test No.
1A
IB
10-C-l
10-C-3
26-A-l
1C
ID
IE
1G
1H
52D
52E
IE
IF
12A
12B
42A
42B
19A
19B
23
23
25
26
1
26B


Firing
Condition
Base
Base
Low NOx
Low NOX
Low NOX
Base
Base
Base
Low NOX
Low NOX
Low NOX
Low NOX
Base
Base
Low NOX
Low NOX
Base
Base
Low NOX
Low NOX
Base
Base
Base
Base
Base
Low NOX

02
Before
A.M.
3.9
3.6
3.05
3.23
2.73
3.0
3.7
3.5
1.2
1.3
1.9
2.0
3.44
3.12
4.28
3.67



 
3.56
3.56
4.31
4.46
3.6
3.4
Calc.
2
After
A.H.
5.17
4.89
4.38
4.55
4i09;
4.34
4.99
4.80
2.67
2.76
3.32
3.41
4.75
4.45
5.52
4.96
5.03*
4.49*
4.64*
4.34*
4.86
4.86
5.55
5.69
4.89
4.71
Av.
Gr/SCF
@ Std.
Cond.
2.68
4.62
2.32
3.36
3.13
1.83
1.86
2.26
2.47
2.60
2.00
2.65
4.52
5.36
4.87
3.26
1.17
3.08
3.31
3.32
0.448
0.301
0.752
0.800
2.54
3.82
DATA




Reqd.
Efficiency
Gr/SCF
@
0% 0?
3.55
6.02
2.93
4.29
3.89
2.31
2.44
2.93
2.83
2.99
2.38
3.16
5.84
16.80
6.40
4.27
1.53
3.92
4.25
4,19
0.58
0.38
0.34
1.10
3.31
4.92

lb./106
BTU
4.65
7.89
3.84
5.62
5.10
3.03
3.20
3.84
3.71
3.92
3.12
4.14
7.65
8.91
8.38
5.59
2.00
5.14
5.57
5.49
0.76
0.51
0.44
1.48
4.34
6.45

Grams /
106 cal.
8.37
14.20
6.91
10.12
9.18
5.45
5.76
6.91
6.68
7.06
5.62
7.45
13.77
16.04
15.08
10.06
3.60
9.25
10.03
9.88
1.37
0.92
0.81
2.59
7.81
11.61
To Meet
0.1 lb/
106 BTU
97.85
98.73
97.40
98.22
98.04
96.70
96.88
97.40
97.30
97.45
86.79
97.58
98.69
98.88
98.81
98.21
95.00
98.05
98.20
98.18
86.91
80.55
77.73
93.04
97.70
98.45
%
Carbon :cm
Particulate
6.29
5.90
10.55
8.46
12.40
5.50
3.17
2.80
6.73
11.82
9.98
7.41
0.69
0.53
0.18
0.46
24.23
25.83
14.75
18.77
22.62
22.62
4.44
1.80
5.08
8.15
Coal HHV
Ash BTU/lb.
Wet, % Wet
15.87 11,452
18.39 11,477
11.5 11,918
14.38 11,231
15.39 10,961
12.05 12,310
9.72 12,589
8.58 12,121
11.28 12,200
8.43 12,574
10.3 11,178
11.86 11,887
21.92 8,821
21.96 8,811
23.13 8,913
21.12 8,915
4.89 12,706
4.86 12,641
10.68' 11,918
8.82 12,720
8.16 10,293
8.16 10,293
6.78 10,273
8.10 9,992
Not Yet .
Available

-------
          Average emission data in  grains  per cubic  foot at standard conditions
were calculated from the particulate  data  obtained in  the  tests and are listed
in Table 5.  These data are also presented in terms  of grains per SCF at
zero percent oxygen, pounds per million BTU  and  grains per million calories.
For comparison purposes, a calculation  of  the required precipitator collection
efficiency to meet current federal  standards of  0.1  pounds per million BTU
fired is included in Table 5.

Tennessee VajJ-ey_Authority

          As indicated in Table 5,  five  particulate  tests were made at TVA.
The unit tested was boiler No. 6 at the Widows Creek Station.  Two tests were
run at baseline conditions and three  at optimized "low NOX" firing.  Comparing
results of tests 1A with 10-C-3 and 26-A-l,  all  conducted  while firing
approximately the same ash content  coal, it  can  be seen that emissions increase
from a baseline of 4.65 lb/106 BTU  to 5.62 and 5.10  lb/106 BTU at "low
operation, respectively.  The carbon  content of  the  particulate in these
tests increases from 6.29% at baseline  to  8.46 and 12.40%, respectively,
under "low NOX" operation.  Relatively  small increases in  electrostatic
precipitator efficiency are required, however, to meet present standards,
i.e., 97.85% to 98.22% and 98.04%,  respectively.

          Based on the data obtained  on the  No.  6, 125 MW, front wall fired
boiler at TVA's Widows Creek Station, it appears that particulate emissions
increase directionally, but not significantly, when  "low NQX" firing
configurations are employed.  Particulate  carbon content which initially is
relatively low on the TVA boiler, increases  substantially  (doubling in one case)
under "low NOX" firing conditions but the  increases  do not appear to be in
direct relationship with the emissions  or  coal ash data.   Only small increases
in electrostatic precipitator collection efficiency  would  be required to
accommodate the higher dust loadings  produced with "low NOX" firing.  However,
if real, the incremental increases  at these  levels of performance may be
difficult and costly to achieve.

          Georgia Power

          A total of seven particulate  tests were conducted on the No. 3,
480 MW, horizontally opposed fired  boiler  at Georgia Power Company's Harllee
Branch Station, three at baseline or  normal  operating conditions and four
while firing the boiler using "low  NOX" modifications.  Particulate emission
data for all tests were relatively  consistent (see Table 5), ranging from
3.03 to 4.14 pounds per million BTU's fired.   Average emissions at normal
or "base" conditions were 3.36 lb/106 BTU  compared to 3.72 lb/106 BTU for
"low NO " producing conditions.  Particulate carbon  content was variable
and again was inconsistent with other factors.   Under normal firing conditions,
percent carbon was reasonably low,  varying from  a low of 2.8 to 5.5 percent.
At "low NO " operation these values ranged from  6.73. to 11.83 percent.
Increases in the required precipitator  efficiency to meet  present standards
again would be small, and probably  of minor  importance.
                                      257

-------
Arizona Public Service Company

          Particulate test results obtained on the No. 4, 800 MW, horizontally
opposed fired boiler at Arizona Public Service Company's Four Corners plant
are of particular interest because of the low sulfur, high ash Western coal
fired.  Four tests were conducted, two under baseline and two under "low NOx"
operation.  Particulate emissions, as expected, due to the high ash (^ 23%)
coal fired were high in all tests.  Referring to Table 5, the results are
somewhat  confused by the high emissions obtained in one base run and the
low emissions obtained in one of the "low NOX" tests.  However, if results
of test IE are compared with 12A, a more normal pattern is apparent.
Particulate emissions of 7.65 lb/106 BTU for baseline operation (test IE)
increase  to 8.38 lb/106 BTU for "low NOX" test 12A.  The increase, as in
previous  tests, is not substantial but is in line with what might be expected.
Data on the percent carbon on particulates for all tests are startling.  In
the first place, the values are very low, averaging about 0.47%, confirming
the easy burning qualities of Western coals.  Secondly, particulate carbon
content decreases with "low NOX" firing as indicated in Table 5, from
0.695 and 0.528% in "base" tests IE and IF, respectively, down to 0.182 and
0.461% for "low NOX" tests 12A and 12B, respectively.  Thus, according to
these data a benefit accrues to "low NO " operation with respect to unburned
combustibles for this horizontally opposed fired boiler.  With respect to
precipitator performance, efficiency should only increase from 98.7 percent
(baseline operation, test IE) to 98.8 percent (low NOX firing, test 12A) to
accommodate the increased particulate emission produced under "low NOX"
firing conditions.

Alabama Power Company

          Four dust loading tests were conducted on the 350 MW, tangential
fired No. 4 boiler at Alabama Power Company's Barry Station, two at normal
operation and two while using "low NOX" emission reduction techniques.  Referring
to Table  5, the data obtained under baseline operation in test 42A appear
to be unreliable.  Comparing the results obtained in the other 3 tests
(tests 42B, 19A & 19B) it can be seen that particulate emissions for this
tangentially fired boiler increase from 5.14 lb/10" BTU under normal operation,
to 5.57 and 5.49 lb/106 BTU when "low NOX" emission techniques are used.
Particulate carbon content for baseline operation (test 42B) of 25.83 percent
(see Table 5) is very high, and considerably higher than for other types of
firing.   Surprisingly, substantial reductions in these carbon losses appear
to occur with "low NOX" operation.  This behavior is shown by tests 19A and 19B
with decreases in particulate carbon content down to 14.75 and 18.77 percent,
respectively.  Here again, "low NOX" firing techniques apparently have
beneficial results.  Only nominal increases, probably of no major importance,
are required in precipitator collection efficiency when employing "low NOX"
techniques.

Utah Power & Light Company

          Tests for particulates on the 330 MW, tangentially fired, No. 3
boiler at the Naughton Station were made in the ducts leading into the air
heaters,  since downstream test locations were poor, and accessibility was
limited.  Four tests were run, all of which were conducted under normal or
baseline  firing conditions.  Referring to Table 5 it can be seen that the
emission values are not consistent with other data obtained in this study,
especially in view of the consistency and levels of the ash content of the
coal fired.
                                      258

-------
          Since the tests were  conducted in accordance with prescribed
procedures, it is difficult  to  understand the reasons for these  inconsistencies.
One possible explanation is  that  the  superheater and reheater  surfaces  on
the No. 3 boiler were overdesigned necessitating operation with  the burners
at a horizontal position or  tilted downwards.   As a result, the  lower furnace
surfaces including the ash hopper slopes were slagged,  while the superheater
reheater and convection section surfaces were extremely clean  on this relatively
new unit.  It is possible that  a  major  portion of the ash was  impinging on the
sticky slag particles and remained in the boiler, thus  accounting for the low
dust loadings.
    u    -    vflues rePrted  for particulate  carbon  content are of interest.
 As shown in Table 5, it may be noted  that  carbon content in test No. 23 was
 22.62 percent.  This value is  consistent with  the high values reported for
 the Alabama Power Company tests  (Tests  42A and 42B) .  Particulate carbon
 content reported for the latter, tangentially  fired boiler was 24.23 and
 25.83 percent, respectively, at baseline operating  conditions.  However, the
 values of 4.44 and 1.80% carbon content reported for  tests 25 and 26 for normal
 operation are surprising since they are low and at variance with the Alabama
 Power Company test results for baseline conditions.  More data on other
 tangentially fired boilers are required to resolve  this apparent anomaly.

 Gulf Power Company

          Due to the limited scope of testing,  particulate data were obtained
 in only two tests on the 320 MW, front wall fired, No. 6 boiler of Gulf Power
 Company's Crist Station.  One was at normal operating conditions, and the other
 under "low NOX" operating conditions.  As  shown in Table 5,  the  results
 appear to be in line with other emission data  measured.  Particulate emissions
 for baseline operation increases, as might  be  expected from 4.35 percent to
 6.45 percent under "low NOX" operating conditions.  Similarly, carbon content
 of the particulate increases from 5.08 percent  at normal operation to 8.15
 percent when "low NOX" burner  configurations are used.  Required precipitator
 efficiency to meet present standards would  increase from 97.7% for base
 conditions to 98.4% to accommodate the higher  emissions produced with "low NOX"
 firing.

 3.3  Corrosion Probing Results

          As mentioned in section 2.2.3, corrosion probes were installed in
 the furnaces of the boilers tested, by inserting them through available
 openings closest to the areas of the furnace susceptible to corrosion, as
 indicated in Figure 4.  Prior  to installing the probes in the test furnace,
 the probes were prepared by mild acid pickling  and pre-weighing the coupons ,
 and screwing them onto the probes along with the necessary thermocouples.
 Each probe was then exposed to the furnace  atmosphere prevailing for the
 particular type of operation desired for approximately 300 hours at coupon
 temperatures of about 875F in order to accelerate corrosion.  After exposure,
 furnace slag was cleaned off and saved for  future analyses,  and the coupons
were carefully removed from the probes.  In the laboratory the coupons were
 cleaned ultrasonically with fine glass beads to the base metal,  and re-weighed
 to determine the weight loss.  To date in our  tests, corrosion rates have
been determined for 40 coupons installed on 20  probes (2 coupons /probe) ,
in boilers  at four different generating stations as listed in section 2.2.3.
Corrosion data obtained are tabulated in Tables 6 through. 10.
                                      259

-------
       TABLE 6

 GEORGIA POWER COMPANY
HARLLEE BRANCH STATION
 CORROSION PROBE DATA
Boiler
No.
3
3
4
4
Firing
Condition
Low NO
X
Low NO
X
Base
Base
Exposure
Hrs
297
297
304
304
Probe
No.
3A
3B
4A
4B
Coupon
No.
0
0
f"
111
f12
I 13
Corrosion Rate
Mils/Yr
27.5
122.0
75.9
155.0
75.3
72.2
25.7
47.9
           260

-------
                             TABLE 7

                    UTAH POWER & LIGHT COMPANY
                         NAUGHTON STATION

                          CORROSION DATA
Boiler    Firing     Exposure     Probe     Coupon     Corrosion
  No.      Cond.        Hrs       . No.        No.         MPY
          Base
          Base
          Base
          Base
287.0
287.5
283.5
283.75
124

 65

 43

 47

 16

 24

 25

 25
                                   261

-------
                           TABLE 8

                ARIZONA PUBLIC SERVICE COMPANY
                     FOUR CORNERS STATION
                        CORROSION DATA
Boiler    Firing    Exposure   .Probe    Coupon    Corrosion
  No.     Cond.        Hrs       No.        No.         MPY
   4     Low NO      255.25
   4     Low NO      255.5
         Base
         Base
273.5
273.75
C
R

P
Q
N
0
 61
160
 25
 24
157
 59
 45
 59
                              262

-------
      TABLE 9

ALABAMA POWER COMPANY
    BARRY STATION

   CORROSION DATA
   BASE OPERATION
Boiler Firing Exposure Probe Coupon
No. Cond. Hrs No. No.
( W
4 Base 295.5 1 /
I W
4 Base 295.5 2 /
I5
4 Base 295.75 3 <
I"
/17
4 Base 295.25 4 (
! 18
Corrosion
MPY
34
24
17
18
11
13
16
17
            263

-------
                             TABLE 10

                       ALABAMA POWER COMPANY
                           BARRY STATION

                       ."LOW ,NO^"  OPERATION
                               X
Boiler     Firing     Exposure     Probe     Coupon     Corrosion
  No.      Cond.         Hrs        No.        No.         MPY
u
4 Low NO 282.75 I* (
\B
f K
4 Low NO 282 2* \
1 M
32

26
41

52
                                                            77
                                                            13
   4      Low NO..      281.75       4**
                                                            18
   *   Eleven feet  below lower burners  in  side walls  (slag blowers
      No.  3  and  11).

  **   Eleven feet  above top burners  in side walls  (slag blowers
      No.  18 and 26).
                                 264

-------
          Total weight loss data were  converted  to corrosion  rates  on  a mils
per year basis, using the  combined  inner and outer coupon areas,  coupon
material density, and exposure  time.   Wastage was  found to have'occurred
on the internal surfaces of some of the  coupons, possibly because of the
oxidation of the hot metal by the cooling air.   Attempts were made  to
determine "internal" and "external" corrosion rates by  selective  cleaning
and weight loss determinations, but the  results  were found to be  more
consistent and reliable on an overall  basis.

      3.3.1  Georgia Power  Company

          The  first furnace  corrosion  probe tests  were  conducted  on boilers
numbers  3 and  4  at  the Harllee  Branch  Station of the Georgia  Power  Company.
Boiler No. 3,  as  indicated in Table 6, was fired at "low NOX" conditions
while boiler No.  4, a sister-unit was  used to obtain baseline data  under
normal operation.   All probes were  inserted through slag blower ports
 extending through the windbox at an elevation about 8 ft. above the top
burners.  Exposure  of the probes was maintained for approximately 300  hours
 at these firing  conditions,  after which the corrosion coupons were  removed
 and processed  in the  laboratory.

          Corrosion rate determinations  for the  Georgia Power Company  tests
are  tabulated  in  Table 6.  It may be noted that  the corrosion rates on
coupons No. 6  and 8 exposed  to  "low NOX" firing  conditions are  the  same as
those obtained on coupons  No. 10 and 12, exposed to normal firing.  Rates  on
"low NOjj" coupons Nos. 7 & 9, however, are considerably higher  than those
 obtained under normal operation.  Analyses of these data, however,  indicate
 that the differences  are not statistically significant.  Since  this one was
 our first furnace corrosion  tests  conducted, a possible explanation for the
higher corrosion  rates obtained on  the same probe,  i.e.,  coupons  No. 6, 7,
and  8, 9, is that metal  temperatures on  adjacent coupons may  not  have  been
balanced, and  potentially  could have been higher on those coupons showing
higher corrosion  rates.  This could also explain some of the  differences in
 corrosion rates between  "low NOX" and  baseline operation.

          It is  concluded  that  there are no significant differences between
 the  corrosion  rates under  "low  NOX" firing conditions in Harllee  Branch
boiler No. 3,  and those  in No.  4 operated under  normal  firing conditions,
even though somewhat higher  corrosion  rates were measured on  two  coupons on
probes exposed to "low NOX"  conditions.

      3.3.2  Utah  Power & Light  Company

          Four corrosion probes were installed in  inspection  doors  on  the
front wall of  boiler No. 3 at the Naughton Station of the Utah Power & Light
Company, as indicated in Figure 4.   The  objective  was to obtain both
"baseline" and "low NOX" corrosion  data  at the same time, under "low NOX"
firing conditions.  This attempt was based on the  high  02 levels  expected
 to prevail at  the-upper  inspection  doors,  where  probes  No. 1  &  2  were  located.
Reducing atmospheres were  expected  to  prevail in the vicinity of  probes
No  3 &  4 located in  the middle of  the burner array.  However, potential
furnace  slagging  conditions  and critical system  load conditions prevented
sustained operation at "low NOX" conditions on  this unit.  Accordingly,
the  corrosion  probes were  exposed to normal operating conditions  for a
period of 300  hours.  Although  the  data  obtained on these probes  do not
permit comparison of  corrosion  rates at  "low NOX"  and baseline  conditions
for  this unit  they do provide  information on baseline  corrosion  rates of
value for comparison with  similar data obtained  on other boilers.

                                       265

-------
          Corrosion rates obtained at the Naughton Station are listed in
Table 7.  It may be seen that the corrosion rates on all coupons are
reasonably consistent, ranging between 16 and 65 mils/yr., with the exception
of probe No. 1 which had a higher rate and is out of line with the others.
Corrosion rates on probes Nos. 1 & 2, ranging between 43 and 124 mils/yr.,
are higher than those on probes No. 3 & 4 (16-25 mils/yr.).  Measured
oxygen levels at the latter probes were lower at this location than that
prevailing at probes No. 1 & 2.  These data, therefore, provide some
indication that corrosion rates at lower oxygen levels may be less than
that of coupons exposed to higher oxygen atmospheres.

          It is concluded that the Naughton data are indicative of accelerated
corrosion rates prevailing under normal firing conditions on tangentially
fired boilers.  These data also indicate that corrosion rates may be lower
on probes exposed to lower oxygen level environments.

     3.3.3  Arizona. Public Service Company

          Two corrosion probes each were installed in Boiler No. 4, at the
Four Corners Station, the "low NOX" test unit, and Boiler No. 5, the "base"
operation unit, which is a duplicate of Boiler No. 4.  The probes were
inserted through the slag blower ports which extend through the windbox
of these horizontally opposed fired units.  Corrosion data obtained are
shown in Table 8.

          Probes No. 1 & 2 in boiler No. 4 were exposed for about 255 hours,
essentially at "low NOX" firing conditions.  However, there were periods
during this time span when the unit was not operated entirely at the
prescribed "low NOX" conditions, due to mill losses, upsets in plant
operation, and other problems.  For the major part of the time, though,
the probes were exposed under "low NOX" firing conditions.  It can be seen
from Table 8 that corrosion rates range between 24 and 160 mils/yr. on
the coupons mounted on probes No. 1 & 2 exposed to "low NOX" conditions.
These values compare to a range of 45 to 157 mils/yr. obtained on the
"baseline" probes (No. 3 & 4) which were exposed to normal firing conditions
for about 274 hours.  The lowest corrosion rates, 24 & 25 mils/yr., were
experienced on coupons R & S mounted on probe No. 2 exposed to "low NOX"
firing.  The lowest rate on the base operation probes was 45 mils/yr.,
on coupon "N".  Comparison of the corrosion rates on the remaining coupons
shows that there are no significant differences between the coupons exposed
under "low NOX" firing and those exposed under normal firing conditions.
In fact, the rates are remarkably consistent, and practically equal.

          From the corrosion data obtained at the Four Corners Station, it
is concluded that corrosion rates are essentially the same under "low NOX"
and baseline firing conditions.  Also, based on these limited data, there
is an indication that corrosion rates under "low NO " conditions may even
be somewhat lower than under "baseline" operating conditions.
                                     266

-------
          Four corrosion probes were installed  on boiler No.  4 at the
Barry Station of the Alabama Power Company  and  exposed for about  282 hours
under "low NOX" operating conditions.  The  probes were removed at the  conclusion
of this test, refitted with new coupons  and re-inserted in the same boiler
and locations and exposed for about 282  hours under  normal firing conditions.
Locations of the probes in the boiler are detailed in Figure  4 and corrosion
data are tabulated in Table 9 for baseline  operation, and Table 10 for
"low NOX" firing.

          Comparing Tables 9 and 10 it will be  noted that coupon  corrosion
rates for "low NOX" operation are higher than for a  baseline  operation.  The
"low NOX" corrosion rates are significantly higher at about the one per  cent
probability level.  The corrosion test in boiler  No.  4 was probably the  most
reliable test made under "low NOX" conditions to  date.   Load  and  "low  NOX"
firing conditions during the test period were maintained steadier than in
other tests.  Also, except for some minor variations; the coupon  temperatures
were maintained more consistently at the 875F  set point than in  other tests.
In contrast, even though coupon temperatures were maintained  at a reasonably.
consistent level, boiler load conditions under  the base operation test period
varied widely.  This problem was primarily  due  to pulverizer  failures  which
required removing pulverizers from service.  When the test was  first started
four pulverizers were in service.  Mills were progressively dropped off  until
only two were in service for a good portion of  the test period.   This  factor
could have a significant effect on the corrosion  rates shown  in Table  9
for baseline operation.

          Referring to Table 9, it should be noted that coupon  corrosion
rates on probes 1 & 2 installed below the lower burners averaged  24 mils
per yr. compared to an average of 14 mils per yr.  for probes  Nos.  3 &  4,
located above the top burners.  Under "low  NOX" firing conditions  (Table 10)
the reverse occurred; average corrosion  of  coupons on probes  1  &  2 was
38 mils per yr. compared to 49 mils per  yr.  for probes No.  3  &  4.  This
difference could be explained by the less intense firing conditions prevailing
in the area of probes No. 3 & 4 during the  baseline  test due  to firing the
 lower burners only.  However, it is doubtful that this reversal in corrosion
rates between the upper and lower probes under  the different  firing conditions
is truly significant.

          Based on the data of Tables 9  and 10  for the Alabama  Power Company
tests, it is concluded that corrosion rates under "low NOX" firing conditions
are significantly  (but not catastrophically) higher  than those  measured  under
baseline operating conditions.  Furthermore, corrosion rates  on probes at
 different locations in the boiler may be different,  depending on  whether the
boiler is fired normally, or with "low NOX" firing modifications,  and  also,
with the location of the flame zone in the  furnace.
                                       267

-------
4.  DISCUSSION

          In this section of the paper, the overall correlations of the NO^
emission data, and the significance of particulate emission measurements and
accelerated corrosion tests are discussed.

4.1  Gaseous Emission Measurements

          Tables 11 and 12 summarize the NO  emission levels measured from
wall-fired and tangentially-f ired (plus a turbo -furnace) boilers, respectively.
Inspection of Table 11 reveals that all of the wall-fired boilers have baseline
NOX emission levels greater than the current federal standard of 0,7 pounds
NOX/106 BTU or 1.26 grams NOX/106 cal for new units.  "Low NOX" operation
at full load reduced NOX emission levels by 25 to 47% from baseline levels,
and only Crist No. 6 boiler was unable to meet the federal NOX standard for
new boilers.  "Low NOX" operation at reduced load resulted in 40 to 54% NOX
emission reductions from baseline operation.  The high CO emission levels shown
under "low NOX" operations were generally reduced to acceptable levels during
the sustained test periods.
          Examination of Table 12 reveals that baseline NOx emission levels
from tangentially fired boilers are lower than baseline NOx emission levels
from wall fired boilers.  (The turbo-furnace boiler was tested at 370 MW
compared to design full load of 450 MW, and hence,  additional testing is needed
to measure baseline, full load NOX emission levels.)  "Low NOx" staged firins
operation with 15-20% load reduction enabled these boilers to decrease NOX
below the federal NOx emission standard for new coal fired boilers by a large
margin, while each of these boilers demonstrated the capability of meeting
such standards at full load with low excess air operation during the short-
period tests.  "Low NOx" operation with further load reduction resulted in
NOx emission reductions of 55 to 64% compared to full load, baseline  emission
rates.

          As noted in Section 3, it should be recognized that these results
were obtained during short-term test periods and that long-term testing is
needed to study slagging, corrosion and other operating conditions.  It is
expected that slagging problems in some boilers can be largely overcome by
increasing slag blower steam pressures, increasing the use of slag blowers
and perhaps the addition of slag blowers at troublesome locations.  Lower NOX
emissions would also be expected in many boilers from improved furnace maintenance,
so that air-to-fuel ratios are as uniform as practical across the furnace.
Research at extremely low % stoichiometric air to the active burners (less
than 75%) with staged firing may yield significantly improved NOX emission
rates with decreased slagging, because of lower temperatures.  Also, the
addition of "NO-ports" would probably allow most boilers to reduce NOX emissions
significantly during full-load operation with all burners firing coal.
                                  268

-------
                                      TABLE 11



                          SUMMARY OF NOX EMISSION LEVELS FROM

                                  WALL FIRED BOILERS	
BOILER
1. WIDOWS
OPERATING MODE
(GROSS LOAD-MW)
BASE (125)
CREEK No. 6 | "LOW NOX"* (125)
(FW)

2. CRIST
NO. 6
(FW)
3. HARLLEE
BRANCH NO. 3
(HO)

4. FOUR
CORNERS NO. 4
(HO)
i
i "LOW NOX"** (100)

BASE (320)
"LOW NOX"* (320)
"LOW NOX"** (272)
BASE (480)
"LOW NOX"* (478)
"LOW NOX"** (400)

BASE (800)
"LOW NOX"* (800)
I "LOW NOX"** (600)
2
3.0
1.7
2.7

3.6
2.6
3.1
NOY EMISSIONS
PPM
(0% 00)
750
395
346

990
740
600
3.5 } 870
LBS/
106 BTU
0.84
0.44
0.39
:
1.10
0.82 i
0.67 [
!
0.97
1.7 575 1 0.64
1.3

5.0
390 | 0.43

1070
3.2 570

1.19
0.64
3.0 ] 525 I 0.59

GRAMS/
106 BTU
1.50
0.79
0.69
.
1.98
1.48
1.20
PPM
CO***
(0% 0,)
300
1140
980

26
580
310
1.75 24
1.15 61
0.78 | 1080
si
2.15 ( 23
1.15 ( 200
1.05 } 33

  *  "LOW NO " CONDITIONS SELECTED FOR SUSTAINED RUN,  AT FULL LOAD.



 **  "LOW NO " CONDITIONS AT REDUCED LOAD.
            X


***  LOWER CO LEVELS MEASURED UNDER SUSTAINED STEADY-STATE CONDITION IN REPEAT RUNS.

-------
                                                        TABLE 12
N)
^J

O

BOILER -
5. NAUGHTON
NO. 3
6. BARRY
NO. 4
7 . BARRY
NO. 3
SUMMARY OF NOX EMISSION .LEVELS FROM
TANGENT lALLY FIRED BOILERS

OPERATING. MODE
(GROSS LOAD-MW)
BASE (328)
"LOW NOX"* (256)
"LOW NOX"** (200)
BASE (348)
"LOW NOx"* (285)
"LOW NOX"** (185)
BASE (250)
"LOW NOx"* (250)
2
3.9
2.9
3.2
4.6
3.3
3.7
3.1
1.3

NOX EMISSIONS
PPM
(0% 00)
600
230
214
485
285
220
480
360
LBS/
106 BTU
0.67
0.26
0.24
0.54
0.32
0.24
0.54
0.40
GRAMS/
106 CAL.
1.20
0.46
0.43
0.97
0.57
0.44
0.96
0.72

PPM
CO
(0% OJ
35
440-
65
1
28
68
328
71
116 l
TURBO-FURNACE BOILER |
8. BIG BEND
NO. 2
BASE (370)
"LOW NOX" * (300)
"LOW NOX"** (230)
2.8
1.8
3.5
715
400
365
0.79
0.44
0.41
;
1.43
0.80
0.73
30
80 \
260 I
                   *   "LOW NO " CONDITIONS SELECTED FOR SUSTAINED RUN.
                              x
                   **  "LOW NO " CONDITIONS WITH FURTHER LOAD REDUCTION.
                              x

-------
          Figures 18, 19 and 20 have been  prepared  to  show  the  overall
correlations of NOX emissions vs % stoichiometric air,  and  gross load
per furnace firing wall for the eight  coal fired boilers  tested to date in
this program.

          Figure 18 is a plot of "normalized" NO  emissions, expressed as
a % of baseline NOX emissions (full load and 20% excess air) vs. % overall
stoichiometric air (or % stoichiometric air to  active burners)  under normal
firing conditions.  The solid lines shown  for each  boiler are based on
least-squares, linear regression analysis  of all test  runs  made under normal
(all burners firing coal)  full load firing conditions.  With the exception
of the turbo-furnace boiler, all of these  regression show very  good agreement
with about a 20% reduction in N0x at 110%  vs. 120%  stoichiometric air.  The
three tangentially fired boilers show  especially good  agreement in this
significant correlation of NOX emission levels  with excess  air  levels.

          Figure 19 is a plot of normalized NOx emissions expressed as a %
of baseline NOX emissions  (full load and 20% overall excess air) vs. %
stoichiometric air to the  active burners under  modified firing  conditions.
Thus, the ordinates are identical in Figures 18 and 19.   However, the least
squares regression lines of Figure C2  do not necessarily  pass through the
100% normalized NOX point  at 120% stoichiometric air to the active burners,
as they must, by definition, in Figure 18.  Regression lines for Barry No. 3
and Big Bend No. 7 do pass through the 100%/120% point, since staged firing
was not employed for those boilers.
          Figure  19  indicates  the  importance  of  low excess air firing on
emissions, as well as  the  further  benefits  of staged firing and additional
firing modifications.   The opposed wall  fired boilers Harllee Branch No. 3
and Four Corners  No.  4 boilers showed  excellent  agreement, as would be expected,
since both of them represent modern  design  practices of Babcock and Wilcox
with their cell-type burners.   The tangentially  fired boilers, Barry No. 4
and Naughton No.  3,  that employed  staged firing  showed similar trends, with
Naughton No. 4  giving the  lower NOX  emissions because it was tested at lower
% stoichiometric  air levels.   Widows Creek  No. 6 boiler showed consistently
larger reductions with normalized  NOX  than  Crist No. 6 boiler at the same
stoichiometric  levels.   Boiler parameters such as  size, coal type fired,
pulverizer conditions,  and other design  and operating variables undoubtedly
contribute to the differences  found.  We are  in  the course of examining
whether the correlation methods of Figures  18 and  19 are applicable to oil
and gas fired boiler NOX emission  data obtained  in earlier work.

          Figure  20  is a plot  of baseline NOX emission levels (ppm at 0% 02,
dry basis) vs.  gross load  per  furnace  firing  wall  for the 8 boilers under
baseline operation.   The dashed line is  calculated from the 1971 "Systematic
Field Study"  (4). There appears to  be a good correlation on this basis.
However, we expect to find an  improvement by  combining the results of all
15 coal'fired boilers tested to date.  The  regression intercept of 478 ppm
NO  at zero load  corresponds to about  25% conversion of the average fuel
nitrogen content  of  1.3 wt% of the coals fired in  this study.  This
observation is  a  strong indication of  the significant contribution of bound
fuel nitrogen to  NO   emissions from  coal fired boilers.  Substoichiometric
air supply to the active burners is  expected  to  reduce both the fixation
of molecular N2,  and the oxidation of  fuel  nitrogen, based on independent
laboratory data.
                                       271

-------

-------
                                                         FIGURE  19
                                                 EFFECT OF EXCESS  AIR ON NOX
                                               UNDER MODIFIED EJRING CONDITIONS
      100
w
                                                                                                          TYPE OF
                                                                                                          FIRING
                                                                                 HARLLEE BRANCH NO. 3   OPPOSED W
                                                                                 FOUR CORNERS NO.
                                                                                 CRIST NO.
                                                                                 BARRY NO.
                                                                                 NAUGHTON NO.
                                                                                 WIDOWS CREEK NO.
                                                                                 BARRY NO.
                                                                                 BIG BEND NO.
                                    OPPOSED W
                                    FRONT W.
                                    TANG.
                                    TANG.
                                    FRONT W.
                                    TANG.
                                    TURBO
                                             90
100
                                                                                            110
                                                                                                                    120
                                               STOICHIOMETRIC AIR TO ACTIVE BURNERS

-------
                                           FIGURE 20
                                       COAL FIRED BOILERS
                            UNCONTROLLED N0x EMISSIONS VS GROSS LOAD
                                    PER FURNACE FIRING WALL
  1200T
  1000-
    800
M
    600
O
53
    400
   200
                1971 "SYSTEMATIC
                   ;;LD STUDY"  (4.)
                         PPM NO  = 451 + 1.622 MW/FFW
                                                        CODE   TYPE OF FIRING
                                                       O
                                A
                                O
                               FRONT WALL

                               OPPOSED WALL

                               TANGENTIAL

                               TURBO
                                   LETTERS INSIDE SYMBOLS
                                   DENOTE BOILER ABBREVIATIONS
              50
100
150
200
250
300
350
400
                             GROSS LOAD PER FURNACE  FIRING WALL  - MW
                                             274

-------
4.2  Particulate Measurements

          Obtaining good particulate  data is  a difficult,  time  consuming
task.  One must be involved  in  the  actual test work  to  appreciate  the
difficulties encountered.  C. A.  Gallaer  discusses this matter  in  detail
in his paper on the testing  of  large  precipitators (7).

          In this program, four Research  Appliance Company EPA-type particulate
sampling trains were used.   The design  of this equipment is very good, but
many difficulties occur in operation, as  is inherent  to particulate testing.
Care must be taken to assure that the probes  and  tests  boxes are at specified
temperatures.  Even then, especially  in cold  weather, moisture  in  the flue
gases condensing in the apparatus can quickly plug filters and  abort the
test.  Tests for leaks in each  train  prior to testing is also needed if
meaningful data are to be obtained.   Plugging of  sampling  probes on occasion
also occurs, and can present difficulties in  boilers with  high  dust loadings.

          The facilities to  be  tested are another source of numerous problems.
Rarely is a boiler encountered  with convenient testing  facilities.  Sample
test ports are usually located  too  close  to bends in  the flue ducts where
particulate concentrations,  due to  centrifugal action,  cannot possibly be
uniform.  Interferences of the  probes with supports inside the  flue ducts
and of the test apparatus with  other  obstructions outside  the boiler, near
test locations, all contribute  to the difficulty  in running particulate
loading  tests.  Last but not least, the EPA-type  test train is  built
for horizontal probing, while most  boiler test locations require vertical
probing.  Our equipment has  been  modified for7 vertical  probing, so that
usually  the construction of  scaffolding is necessary  for access to the equipment.

          Despite the problems  of conducting  particulate tests, the results
obtained on this program, summarized  in Table 5,  are internally consistent
and appear to be reliable within  the  limitations  of  this type of testing.
The objective of our work was to  develop  information  on potential  "side effects"
of "low  NOX" firing techniques  on total quantities and  the carbon  content of
the particulates generated.   It is  recognized that strict  adherence to EPA
procedures was not always possible  especially with regard  to the number of
sampling ports and traverse  points, but the same  procedures were used for
under both baseline and "low NOX" conditions.  Therefore,  the differences
shown by the results on particulate emissions and particulate carbon content
in Table 5 should be quite reliable.

          Not unexpectedly,  some  "side  effects" did  develop with "low NOX"
firing.  Total quantities of particulate  tend to  increase  but not  signicantly
and the  consequences appear  to  be relatively  minor.   This  trend would have
an adverse effect on the required collection  efficiency of electrostatic
precipitators to meet present Federal emission standards,  but the  increases
in efficiency indicated by these  limited  tests appear to be quite  small.
                                       275

-------
          Another "side effect" of "low NOX" operation is that on carbon
losses.  Carbon content of the particulates with "low NOx" operation,
according to the data, increase significantly for front wall and horizontally
opposed fired boilers.  The data are quite scattered, and these increases
do not appear to be directly related to the change in emissions with "low NOX"
firing techniques, or other boiler operating variables.  Comparative performance
calculations have not yet been completed for assessing the magnitude of such
adverse effects of staged firing with coal.  It is possible, however, that
this debit may be offset by improved boiler efficiency due to the lower excess
air operation at "low NQx" conditions.  Surprisingly, there is some evidence
that "low NOx" firing techniques for tangentially fired boilers decrease
carbon losses significantly.  If this finding can be substantiated for other
tangentially fired boilers, a net credit may be applied to "low NOX" operation
of these units.  It also appears that "low NOX" firing may decrease carbon
losses for boilers fired with western coals.  Such improvements, however,
would not be substantial since unburned combustible losses with the easy-to-burn
Western coals are already low.

          More data are needed on all types of boilers to substantiate these
findings.  It is important to note, however, that no major adverse "side effects"
appear to result from "low NOX" firing with regard to particulate emissions.

4.3  Furnace Corrosion Testing

          Corrosion of boiler furnace sidewall tubes was experienced in the
early days of the development of pulverized coal firing.  Considerable effort
was expended at the time in the field, to find solutions to the problem; and
in the laboratory, to determine the corrosion mechanism.  Eventually, simple
solutions were found by increasing the level of excess air and taking steps
to avoid impingement of ash particles on sidewall tubes.  Apparently, not
much information had been published, probably because a practical solution
to the problem was available.

          Recent regulations requiring reduction of nitrogen oxide emissions
have led to the reduction of excess air levels in firing boilers, as one of the
techniques to achieve lower emission levels.  This approach has resulted in
considerable speculation and apprehension that furnace sidewall tube corrosion
problems will again be encountered.  Quite naturally, boiler owners are
reluctant to subject their units to long term tests to determine potential
corrosion problems without some assurance that risks are not grave.

          For the above reasons, part of the current program was devoted to
obtaining "measurable" corrosion rates on probes exposed to actual furnace
conditions.  The objective of this effort was to obtain data on potential
effects of "low NOX" firing conditions on furnace wall tube corrosion rates.
The approach used in obtaining these data was to deliberately accelerate
corrosion on coupons exposed to temperatures in excess of normal tube metal
temperatures.  It was decided that exposure for 300 hours at 875F in
susceptible furnace areas would be sufficient to show major differences in
corrosion rates between coupons exposed to "low NOX" firing conditions and
those'exposed under normal conditions.
                                      276

-------
          Aj.chougn there was some scatter  in  the data  obtained, most of the
information was quite consistent.  A major finding was  that no major
differences in corrosion rates were observed  for coupons exposed to "low NOX"
conditions compared to those subjected  to  normal operation.   In fact, for
some probes, the corrosion rates were found to be even  lower  than for "low NOX"
exposure.

          Since corrosion was deliberately accelerated  in  the corrosion probe
test work in order to develop "measurable" corrosion rates in a short time
period, measured rates, as expected, are much higher than  normal wastage
experienced on actual furnace wall  tubes.   In future tests, coupons will not
be pickled to remove oxide coatings, and coupon temperatures  will be reduced
to bring corrosion rates more nearly in line  with actual tube wastage.

          Much more data are obviously  required to  resolve the question of
furnace  tube corrosion under "low NOX"  firing conditions.  The limited data
obtained in this program should be  helpful in providing evidence that furnace
tube corrosion may not necessarily  be a severe  "side effect"  of low NOX
firing.  Long term "low NOX" tests  using corrosion  probes  and the simultaneous
development of actual furnace wall  tube corrosion rates by "before" and "after"
ultrasonic  thickness determinations are recommended for future studies.
                                        277

-------
5.  CONCLUSIONS

          The results obtained in this study to date show that modifications
of the combustion operation have a good potential for reducing NOX emissions
from coal-fired utility "boilers without undesirable side-effects.  Lowering
the level of excess air and staging the firing of burners resulted in
significant reductions in NOX, averaging about 40-50% for the boilers tested
in the short-term phase of our test programs.  The degree of reduction, as
well as the baseline NOX level varied with the type and size of the coal-fired
boiler tested, and presumably also with coal type.  In general, tangentially
fired boilers were found to produce the lowest NOX emissions, both under
baseline and modified firing conditions.  However, the burner firing patterns
could be changed for wall-fired units without load reduction, resulting in
decreases in NOX emissions of as much as 50% under full load conditions.
There is too little information on the one turbo-furnace unit tested to draw
firm conclusions on the effect of this type of boiler design on NOX emissions.

          The NOX emission data were successfully correlated with per cent
stoichiometric air supplied to the burners, for both normal and staged firing
patterns.  These correlations show the strong effect of firing coal burners
under net reducing conditions on decreasing NOX emissions.  One anticipates
even further improvements if boiler operability problems, particularly slagging
and corrosion can be overcome.  In combination with the correlation of baseline
NOX emissions per megawatts generated (or firing rate) per "equivalent firing
wall", these correlations of the present study should be useful for predicting
the level of NOX emitted under normal and staged firing conditions.  (Similar
correlations may be developed for gas and oil fired boilers, based on our
data obtained in previous studies.)  The correlations suggest that on the
average, about 25% of the chemically bound nitrogen in coal is converted
to NOX.  Thus, fuel nitrogen is an important factor in NOX emissions from
coal-fired utility boilers.

          Particulate loading and carbon in fly-ash measurements made under
baseline and staged firing, "low NO " conditions, appear to show some increase
for both of these parameters under  low NOX" conditions, but in some cases
the opposite behavior has been observed.  No  extreme differences in flue gas
particulate loadings and in the carbon content of the fly-ash have been found
during our boiler tests.

          Under the "low NOX" firing conditions defined during the short-term
optimization tests, 300-hour accelerated corrosion tests have been conducted
on several boilers in this program.  Comparison of the accelerated corrosion
rates measured under "low NO " and those measured under normal firing conditions
does not reveal major differences.  Therefore, it is recommended that
long-term corrosion tests should be conducted with staged firing of coal on
carefully selected, representative boilers.

          Further test work is needed to optimize and demonstrate the promising
NOX control technology based on the results of this work.  As mentioned above,
particular attention should be paid to long term corrosion testing.  In addition,
boilers fired with different coal types should be tested to define the limitations
imposed at present by slagging problems on the level of substoichiometric air
that can be supplied to the active burners.  Based on such information, techniques
for minimizing slagging problems should be developed.  Careful control of boiler
operation in additional tests should allow the optimization of NOX emission
control for coal-fired utility boilers.
                                      278

-------
6.  REFERENCES

1.  W. Bartok, A. R. Crawford, A. R. Cunningham, H. J. Hall, E. H. Manny
    and A. Skopp, "Systems Study of Nitrogen Oxide Control Methods for
    Stationary Sources," Esso Research and Engineering Company Final Report
    GR-2-NOS-69, Contract No. PH 22-68-55  (PB 192 789), November, 1969.

2.  Idem, in "Proceedings of the Second  International Clean Air Congress"
    H. M. England and W. T. Beery, editors, pp. 801-818, Academic Press,
    New York, 1971.

3.  W. Bartok, A. R. Crawford and A. Skopp, "Control of NO  Emissions from
    Stationary Sources," Chem. Eng. Prog.  67, 64  (1971).  X

4.  W. Bartok, A. R. Crawford and G. J.  Piegari, "Systematic Field Study of
    N0x Emission Control Methods for Utility Boilers," Esso Research and
    Engineering Company Final Report No. GRU.4G No. 71, Contract No. CPA 70-90
    (PB 210  739), December 1971.

5.  Idem, "Systematic Investigation of Nitrogen Oxide Emissions and Combustion
    Control  Methods  for Power Plant Boilers,  in "Air Pollution and its Control,"
    AIChE Symposium  Series, 6J5  (126), pp.  66-74, 1972.

 6.  W. Bartok, A. R. Crawford, E. H. Manny and G. J. Piegari, "Reduction of
    Nitrogen Oxide Emissions  from Electric Utility Boilers by Modified Combustion
    Operation," presented at  American Flame Days," American Flame Research
    Committee,  Chicago, September,  1972.

 7.  Gallaer, C.  A.,  "Practical Problems  in Efficiency Testing of Large Fly Ash
    Precipitators," presented at ASME Winter Annual Meeting, Washington, D.C.,
    November, 1971.
                                      279

-------
7.  ACKNOWLEDGMENTS

          This study was conducted under the sponsorship of the Environmental
Protection Agency, pursuant to Contract No. 68-02-0227.  We wish to acknowledge
the active participation of Mr. R. E. Hall, the EPA Project Officer, in planning
the test program and providing coordination with boiler manufacturers and
operators.  The cooperation and advice of major U.S. utility boiler manufacturers,
Babcock & Wilcox, Combustion Engineering, Inc., Foster Wheeler Corp., and
Riley-Stoker were essential to planning, and scheduling these tests.
Our thanks are due to the electric utility concerns for their voluntary
participation in making their boilers available for testing.  These boiler
operators were the Alabama Power Company, Arizona Public Service,  Georgia
Power Company, Gulf Power Company, Tampa Electric Company, Tennessee Valley
Authority, and Utah Power and Light Company.  Also, the able assistance of
Messrs. L. W. Blanken, R. W. Schroeder and A. J. Smith in performing these
test programs is acknowledged.
                                       280

-------
                               APPENDIX

                        EMISSION FIELD PROGRAM
                    EPA/OAP Contract No. 68-02-022?
                 Esso Research and Engineering Company


                Recommendations for Selection Criteria
                 for Field Testing Coal Fired Boilers
 I.  Design Factors

         1.  Size:  150 to 1200 MW max. cont. rating, representative of

             current and future design practices of boiler manufacturers.

         2.  Type of firing:  tangential, horizontally opposed, front wall,

             and cyclone*.

         3.  Furnace loading.

         *i.  Furnace design:  number of furnaces and/or division walls.

         5-  Furnace bottom design:  wet or dry.

         6.  Burner configuration:  size, number, and spacing.

         7.  Draft system:  pressurized or balanced.

         8.  Special features available for NO  control:   NO-ports,  flue gas

             recirculation into flame zone**.  Control of air flows  (e.g.,

             primary/secondary).
 *  Cyclone  boiler to be  tested only if combustion modification flexibility
    available.

**  Or  possibility of diverting existing FGR  (now used for steam temperature
    control) into  flame zone.

 II.  Boiler Operating Flexibility

         1.  Excess  air:  5$ to 30%.  LEA operation (< 15* desirable for

             sustained operation).

         2.  Furnace load with all  burners firing:  60* to 100* of MCR.

         3.  Staged  firing:  individual  burners or rows of burners on air

             only; or biased firing of  individual burners.

                                     231

-------
          h.   Flue  gas  recirculation:   location of  injection point  and




              amount  recirculated.




          5.   Windbox pressure:   control  from low to high,  over  full  range




              of furnace load and excess  air  levels.




          6.   Combustion air preheat temperature variation.




          7.   Air register settings.




          8.   Fuels available:   coal types, characteristic  of major U.S.




              regions*.








*  Potential  of mixed oil  or gas/coal  firing  for stable  staged combustion




   may be a desirable feature.






III.   Boiler  Measurement  and Control Capability




          1.   Fuel rate:   by furnace and  pulverizer.




          2.   Air flow  rate.




          3.   Steam temperature  control:    attemperation water,  tilting




              burners*, secondary to primary  air ratios.




          Ij..   Flue gas  components monitored by operator:  CU, CO, combustibles,




              smoke.




          5.   Steam temperature  and pressure, air  and  flue  gas temperatures




              for steam side efficiency analysis.




          6.   Availability of furnace  viewing ports for burner  flames, slag




              build-up, etc. observation.




          7.   Availability of adequate fuel and flue gas sampling ports.











*  For tangential boilers only.
                                    282

-------
IV.  Management Operating and Research Policy




         1.  Management support:  make available necessary supervisory,




             technical and operating personnel for planning and testing.




         2.  Research-mindedness:  willingness to exploit  full boiler




             operating flexibility in test program.




         3.  Willingness to schedule load changes, calibrate boiler




             instruments, and bring boiler into proper operating condition




             for test program.  Cooperation in coal sampling and analysis




             desirable.




         U.  Prior experience in emission test programs.




  V.   Logistics  and Efficiency




         Other  factors being equal:




         1.  Select  utility and/or station with more than one boiler




             meeting criteria.




         2,  Scheduled annual outage to  suit test program schedule.




         3.  Increased program  efficiency by minimizing travel costs.
                                      283

-------
PILOT AND FULL SCALE TESTS




          PART II
             285

-------
        PILOT FIELD TEST PROGRAM TO
      STUDY METHODS FOR REDUCTION OF
    NOX FORMATION IN TANGENTIALLY COAL
      AFIRED STEAM GENERATING UNITS
             BY C. E. BLAKESLEE
                A. P. SELKER
        COMBUSTION ENGINEERING, INC.
            FOR PRESENTATION AT
     PULVERIZED COAL COMBUSTION SEMINAR
             JUNE 19 & 20,1973
SPONSORED BY THE COMBUSTION RESEARCH SECTION OF
    THE ENVIRONMENTAL PROTECTION AGENCY
           RESEARCH TRIANGLE PARK
            NORTH CAROLINA  27711
                      287

-------
                    ABSTRACT
This paper describes the work completed on Phase I
of a "Pilot Field Test Program to Study Methods for
Reduction of NOx Formation in Tangentially Coal Fired
Steam Generating Units" performed under the sponsor-
ship of the Office of Air Programs of the Environmental
Protection Agency (Contract No. 62-02-0264).  Phase I
of the program consisted of selecting a suitable
utility field steam generator to be modified for experi-
mental studies to evaluate NOx emissions control.  This
effort included the preparation of engineering drawings,
a detailed preliminary test program, a cost estimate
and detailed time schedule of the following program
phases and a preliminary application economic study
indicating the cost range of each combustion technique
as applied to existing and new steam generators.
                          288

-------
INTRODUCTION
The purpose of this program  is  to  investigate  various  means  for
emission control as applied  to  coal  fired  utility steam  generators.
While current coal firing combustion and  control  technology  have
minimized smoke, CO, hydrocarbon and solid combustible emissions,
proven techniques for the control  of NOX  have  not been fully developed
and evaluated.  Review  of combustion process modifications which had
been found effective in reducing NOX emissions from  oil  and  gas fired
steam generators and recent  staged combustion  simulations with coal
firing indicated that gas recirculation to the firing  zone and/or
staged combustion should be  evaluated as  commercially  feasible methods
of NOx reduction.  For  these reasons a program was developed to eval-
uate the feasibility of these as well  as  other methods of NOX control
on a commercially sized pilot plant unit.   This unit would be modified
to incorporate the systems to be studied  for evaluation  of potential
operating and control problems  and the establishment of  optimum methods
for both transient and  long  term operation.

Phase I was conducted as part of a projected five phase  program to
identify, develop and recommend the most  promising combustion modi-
fication techniques for control of N0xs without objectionable increases
in related pollutants,  from  tangentially  coal  fired  utility  steam gener-
ators.  Phase I comprises the following tasks.

Task I    -  Selection  of a  suitable tangentially coal fired
             unit for emission  control modification  and  testing.

Task II   -  Preparation of  a detailed preliminary test  program.

Task III  -  Preparation of  engineering drawings, modification
             costs and  time  schedule.

Task IV   -  Estimate modification cost ranges for each  combustion
             modification technique as applied to existing and
             new  boilers.

DISCUSSION
 TaSK  I   -   UNIT SELECTION

 To  select  a test unit,  Combustion Engineering  conducted a survey of utility
 companies  using tangentially coal fired steam  generators to determine their
 interest in participating in the NOX control program.  As a result of this
 survey   seven (7) utility companies expressed  a  desire to cooperate with CE
 in  the  oroaram   These  companies were subsequently  reviewed to determine if
 they  had within their generating systems units meeting the remaining criteria
 specified  for the test  unit.

 nf  <=PVPral  units found  to be generally acceptable for the test program,
 Alabama Power Co.[ Barry Station Unit No.  1 was  finally selected.
                                   239

-------
This unit is a natural circulation, balanced draft, steam generator,
firing coal through four elevations of tilting tangential fuel nozzles.
The superheat steam capacity at maximum continuous rating is 900,000 IBS/
Hr main steam flow with a superheat outlet temperature and pressure of
1000 F and 1875 PSI6.  Superheat and reheat temperatures are controlled
by fuel nozzle tilt and spray desuperheating.  A side elevation of this
unit is shown in Figure 1.

The criteria upon which the selection was based are as follows.

     1.  The unit is representative of the tangentially coal fired
         steam generators currently designed by CE which facilitates
         the transfer of technology to existing and new boiler designs.

     2.  The unit, while representative of current utility boiler
         design, is small enough (125 MW) to minimize modification
         costs and permit a versatile experimental program.  The
         control system installation can be coordinated with a
         planned outage for installation of a hot electrostatic pre-
         cipitator.  This precipitator would eliminate the need for
         additional dust removal equipment to protect the gas re-
         circulation system fan.

     3.  The unit location permits testing of various coals without
         incurring additional coal transportation costs.  Coals cur-
         rently being burned at the station include both local Ala-
         bama and Illinois varieties.  The station has existing
         facilities for receiving and handling of both rail and barge
         coal deliveries.

     4.  Alabama Power Company had expressed their willingness to
         cooperate and participate in this program by making the
         unit available for the required modifications and tests.

     5.  The results of a unit operating survey indicated that Barry 1
         is acceptable for the planned experimental NOv control study
         modifications.  Briefly, unit operating flexibility, ash
         handling systems, fan capacities and normal  operation NOv
         levels were found to be acceptable for the purposes of this
         program.  A plot of NOx values versus excess air at various
         unit loadings is shown in Figure 2.

Task II - DETAILED TEST PROGRAMS

The detailed test programs were developed using a statistical program
design approach.  In this manner maximum program efficiency can be
attained by obtaining the maximum informational output from each test.

Using this approach the individual variables considered for evaluation
were first identified and then the minimum number of variable combina-
tions which must be tested to properly evaluate each variable was
established.

The individual variables identified for evaluation in one case were as
follows:
                                  290

-------
     Excess Air

     Unit Loading

     Air Preheat Temperature
     Biased Firing

     Gas Recirculation to:

         a.  Secondary Air Ducts

         b.  Coal Pulverizers

         c.  Combination of the above.
     Overfire Air

     Water Injection to the Firing Zone

For the second case, the variables to be evaluated were:
     Excess Air

     Unit Loading

     Biased Firing

     Overfire Air

The degree to which each process variable or modification would  be  applied
and the process measurements necessary to evaluate unit performance follow,

Process Modifications

     A.  Overfire Air System

         The overfire air system was designed to introduce a  maximum of
         20 percent of full load combustion air above the fuel admission
         nozzles through two additional compartments  in each  furnace cor-
         ner located approximately eight feet above the fuel  admission zone.

         Overfire air can also be supplied to the furnace through the top
         two compartments of the existing windbox when the upper elevation
         of fuel nozzles is not in use.  The overfire air nozzles will
         tilt +30 in the vertical plane independently of the main  fuel
         and air nozzles.   Independent dampers for each overfire air com-
         partment will  be provided as a means to study the influence of
         location and velocity of overfire air introduction.

     B.   Gas Recirculation System

         The gas recirculation system was designed to recirculate flue
         gas to the secondary air duct and coal  pulverizers either
         separately or in  combination.  The system would  provide for a
         maximum of 40  percent recirculation at 80 percent unit  loading
         and permit substituting gas recirculation for hot air to the coal
                                  291

-------
         pulverizers while introducing tempering air in the conventional
         manner.  A gas recirculation temperature range from 300 to 650F
         would be possible by varying the weight ratio of flue gas taken
         from the air preheater gas inlet and outlet.

     C.  Air Preheat System

         The preheated air temperature entering the secondary air duct
         can be varied by bypassing the air and/or gas side of the air
         preheaters to provide the maximum system flexibility.

     D.  Hater Injection System

         Water injection can be admitted into the furnace through two eleva-
         tions of atomizing spray nozzles located between the top two and
         bottom two fuel nozzle elevations.  A maximum injection rate of 50
         pounds per million BID fired can be used.

Process Variables
Excess air, unit load, and fuel and air distribution will  be varied within
the current limitations of the existing equipment.   These  limits were evalu-
ated in the unit operating survey conducted in Task I.

Process Measurements
Operation of the unit as proposed in the experimental  study will  produce
variations in unit operation and thermal performance.   The following process
measurements are required to properly assess the impact of these  changes on
new unit design and the retrofitting of existing units.

     A.  Furnace Absorption

         Recirculating gases to the secondary air compartments  and
         staging of combustion air will effect changes in both  peak
         and average furnace waterwall  temperatures and absorption
         rates.  The waterwall crown temperatures and  absorption  rates
         must therefore be determined to evaluate the  impact of
         variations in average and peak rates and absorption profiles
         on unit design.

     B.  Furnace Corrosion Probes

         Unit operation with staged combustion air may result in  local
         reducing atmospheres within the furnace envelope, resulting
         in accelerated waterwall corrosion rates.  To assess the
         impact of this type of operation on waterwall wastage, furnace
         corrosion probes will be utilized.
                                  292

-------
C.  Sensible Heat Leaving the  Furnace

    Variations in furnace heat absorption  rates  due  to modifying
    the combustion process will  result  in  increasing or decreasing
    the sensible heat leaving  the  furnace  envelope and entering
    the superheat and reheat sections of the  unit.   To determine
    the sensible heat leaving  the  furnace,  the exit  gas temperature
    will be measured at the vertical furnace  outlet  plane using
    water cooled probes with radiation  shielded  thermocouples.

D.  Superheat, Reheat and Economizer Section  Absorptions

    Variations in the gas temperature and  gas flow leaving the
    furnace envelope and entering  the convective sections of the
    unit will affect the total heat pickup  of each section.  To
    assess the impact of modified  operation on superheat, reheat
    and economizer performance,  the absorption rates  for each sec-
    tion will be determined.

    Variation in heat absorption rates  may  require resurfacing when
    retrofitting existing units  for modified  operation.

E.  Air Heater Performance

    Air and gas temperatures and gas side oxygen concentrations
    entering and leaving the air heater are required  to calculate
    air heater performance, unit efficiency,  heat losses and air
    and gas flow rates.

F.  Fuel and Ash Analysis

    During each test, a representative  fuel sample must be obtained
    for later analysis.  The fuel  analyses are required to perform
    combustion calculations necessary to determine excess air levels
    and unit gas and air flow  rates.  Pulverized coal fineness samp-
    les will be obtained to determine the effect, if any, on furnace
    wall deposit characteristics,  solid combustibles  losses, NOx
    levels and related emissions.

    In addition, coal ash analyses are  required to determine ash
    properties such as base/acid ratios and ash deformation, soft-
    ening and fluid temperatures necessary  for evaluating the furnace
    wall deposit characteristics of coal fuels.  Furnace bottom ash,
    fly ash and coal pulverizer  rejects analyses are also required
    to determine heat losses and material balances.   Specific instru-
    mentation and methods to be  used in measuring these process vari-
    ables and the flue gas emission constituents are defined in the
    detailed test plan.
                              293

-------
Task III - ENGINEERING DRAWINGS. COST ESTIMATES AND DETAILED TlMh sCntDUL.E

Engineering Drawings

Arrangement drawings were completed showing necessary duct arrangements
for the overfire air and gas recirculation systems, the overfire air
register arrangements and control system interfaces with the existing
unit.  The general arrangement drawings for the ductwork indicate that
the proposed control systems can be physically installed within the ex-
isting station without serious structural interferences.

The modification ductwork final locations were determined by an extensive
design review and engineering field check of actual existing equipment
configurations and locations.

Cost Estimates
The cost of fabricating, installing and testing the overfire air and gas
recirculation systems were estimated both as a complete system and as
individually installed systems.  These estimates do not include additional
fuel costs incurred during the test program as Alabama Power Company has
agreed to assume these costs.

Detailed Time Schedules

Due to difficulties encountered in establishing when authorization to pro-
ceed with follow-on program phases would be received, it was not possible
to finalize a detailed time schedule for installation of the control sys-
tems.  Schedules based on elapsed time from start of contract were pre-
pared and are shown in Figures 3 and 4.  These schedules must be coordina-
ted with a unit outage occurring in the tenth to twelfth program month.
Such an outage is currently available in the spring of 1974.


Task IV - COMBUSTION TECHNIQUE APPLICATION COSTS

Application Study Results

Based on the cost estimates developed under Task III and Combustion Engineer-
ing, Inc. 's current knowledge, cost ranges were developed for applying the
NOx control techniques proposed in this program to new and existing unit
designs.  These cost ranges are illustrated in Figures 5 and 6.
Specifically, four possible methods of reducing NOx emission levels from
tangentially coal fired steam generators were evaluated and the cost trends
for each method estimated for both new and existing units.  The reduction
methods considered included overfire air, gas recirculation to the secondary
air ducts, gas recirculation to the coal pulverizer/primary air system and
furnace water injection.  The cost trends for these methods were projected
over a unit size range of 125 to 750 MW.
                                   294

-------
The results of the study indicate that for any given unit size (450 MW
chosen for an^example comparison) the lowest cost method is found to
be overfire air which results in a  .14 to .50 $/KW additional unit cost
for a new or existing unit respectively.

This method incurs no loss in unit  efficiency or increased operating
expenses.                                   J               K      3

Gas recirculation introduced either through the secondary air ducts or
the coal pulverizers and primary transport air system results in higher
equipment costs than overfire air and requires additional power for fan
operation.

Water injection introduced into the fuel firing zone of the unit is at-
tractive from the standpoint of low initial equipment costs, however,
losses in unit efficiency resulting in increased fuel costs and signi-
ficant water consumption make it the most expensive system to operate.

The use of either gas recirculation or water injection in existing
units could result in a 10 to 20 percent decrease in load capability
due to increased gas flow weights.

The following conclusions were drawn from this study.

     1.  The  lowest cost method for reducing NOX emission levels on
         new  and existing units is  the incorporation of an overfire
         air  system.  No additional operating costs are involved.

     2.  Gas  recirculation either to the windbox or coal pulverizers
         is a promising control system but is significantly more costly
         than overfire air and requires additional fan power.  In ex-
         isting units, the necessity to reduce unit capacity to main-
         tain acceptable gas velocities imposes an additional penalty.

     3.  Gas  recirculation to the coal pulverizers would cost approxi-
         mately 15 percent less than windbox gas recirculation, however,
         this method may require increased excess air to maintain ade-
         quate combustion.

     4.  Water injection has initially low equipment costs, but due to
         high operating costs resulting from losses in unit efficiency,
         is the least desirable of  the systems evaluated.  This system
         may  also require reduced unit capacity.

     5.  In general, the cost of applying any of the control methods
         studied to an existing unit is approximately twice that of a
         new  unit design.

Application Study Design

For the purpose of this study the following five modes of unit operation
were chosen as potentially effective means for the reduction of  NOX emis-
sions.
                             295

-------
2.
The quantities of overfire air, gas recirculation and water injection
selected for the economic evaluation, while reasonable, do not neces-
sarily represent commercially feasible operation or control methods
which would be recommended by Combustion Engineering, Inc.

     1.  Introducing 20 percent of the total combustion air over the
         fuel firing zone as overfire air.

         Introducing 30 percent flue gas recirculation through the
         secondary air ducts and windbox compartments.

     3.  Combining the 20 percent overfire air and 30 percent flue
         gas recirculation of 1 and 2.

     4.  Introducing 17 percent flue gas recirculation through the
         transport air/coal pulverizer system.

     5.  Introducing water injection into the fuel firing zone at a
         rate of 5 percent of total evaporation.

The economic comparisons of the five NO  emission control methods were
based on 1973 delivered and erected costs for the steam generators and
associated equipment.

The cost estimates presented for the revision of existing units were
based on studies performed on units within the 125 to 750 MW size range
including those costs generated under Phase I, Task 3, for the Barry
No. 1 unit.  The cost estimates presented for incorporating control
methods in new unit designs were based on Combustion Engineering expe-
rience and current practice for overfire air and gas recirculation
systems.

As can be seen from Figures 5 and 6 the cost ranges for existing units
vary more widely than new units.  This is due mainly to variations in
unit design and construction which either hinder or. aid the installation
of a given control system.  For example, an overfire air system may be
designed as a windbox extension unless existing structural requirements
and obstructions necessitate installation of a more costly system in-
cluding extensive ductwork and individual air injection ports.  The
same condition exists for water injection systems when the need to
maintain unit capacity dictates changes in unit ducting.  Except where
noted, all system costs are estimated on a +JO percent basis.  The
cost range of the combined overfire air and windbox gas recirculation
system was arrived at as the sum of the cost ranges of the individual
systems.  The cost ranges presented for existing units do not include
any changes to heating surface as these changes must be calculated on
an individual unit basis.  Due to variations in existing designs,
heating surfaces may increase, decrease or remain unchanged for a
given control method.

At approximately 600 MW, single cell fired furnaces reach a practical
size limit and divided furnace designs are employed.  Since a divided
tangentially fired furnace has double the firing corners of a single
                           296

-------
cell furnace, the costs of windboxes and ducts increase significantly
as shown on Figures 5 and 6.  As shown, the costs of overfire air,
windbox gas recirculation and windbox water injection increase from 30
to 50 percent.

In addition to the increased capital costs resulting from including an
NOx control system in a unit design, the increased unit operating costs
must be considered.  The increased annual operating costs were determined
for a 100, 450 and 750 MW unit of new design and are shown in Table I.
The equipment costs shown are determined from Figure 5.  Using the 450
MW unit as an example at a rate of .14 $/KW results in an increase in unit
capital cost of $63,000.  The additional annual fixed charges, fuel and
fan power costs for each of the five NOx control methods studied and the
criteria on which these costs are based are also listed on Table 1.

Again using the 450 MW unit as an example the study indicates that water
injection is the most expensive system to operate at .332 mills/KWHR due
primarily to increased fuel costs resulting from losses in unit efficiency.
The least expensive control system to operate was overfire air at .004 mills/
KWHR with gas recirculation either alone or in combination with overfire
air ranging from  .108 to .121 mills/KWHR.

To put these operating costs in perspective, they can be compared to
"average" generating costs presented in Table 1 for various sizes of un-
modified units.

Operating costs were developed only for a new unit design as it is possible
to assume that design parameters would remain unchanged from a unit designed
without NOx controls.  However for existing units, gas and air flow rate
changes, increased draft losses and changes in unit load capabilities would
vary to such a degree that each unit would have to be treated individually
regardless of rating and costs would vary to such a degree that they would
not be useful to  a general study.
                                    297

-------
ALABAMA POWER COMPANY - BARRY NO. 1
               298

-------
                 ALABAMA POWER COMPANY   -   BARRY NO.  1
                       NOX VS. PERCENT  EXCESS AIR
CO
o
cc.
 X
o
      0.6-
      0.5-
      0.4--
O.3.-
      0.2--
      0.1
               4 Mill  Operation
                                         3 Mil! Operation
                                   Overfire Air Operation
                                              LEGEND
                                              Unit Load
                                            A  142 MW
                                            )  127 MW
                                            0  113 MW
                                                                  500
                                                            400
300
                                                           -200
                                                                  --100
                                                                            CVJ
                                                                           o
                                                                           ro
                                                                           O
                                                                           -D
                                                                           Q
                                                                     Q.
                                                                     Q.
                                                                      X
                                                                     O
                           PERCENT EXCESS  AIR
                                                          FIGURE 2
                                   29!?

-------
                         PROGRAM SCHEDULE
        FOR EVALUATION  OF OVERFIRE  AIR,  GAS  RECIRCULATION, AIR
PREHEAT AND WATER INJECTION  SYSTEMS AND  EXISTING  PROCESS VARIABLES
                                              Program Month
Phase
2











3




4




5

Task
1


2

3

4

5


1

2


1

2


1

Task Description
Prepare Design Drawings for
Fabrication & Erection of NOv
Control Systems
Purchase Equipment & Fabricate
Equipment
Install Test Instrumentation

Perform Baseline Tests

Perform Bias Firing Tests


Deliver Eauipment and Modify
Unit
Final Test Preparation


Conduct Tests

Evaluate Results & Prepare
Final Report

Prepare Application Guidelines
for Minimizing NO*, 
O i CMfO^t-LoiDr^OOCTtOr CVJCO^t-inVQ

1

jPurch Fabricate

1

Test RPT

| Test | RPT |


1 1

I


1 Test 1

| Evaluate | Report !


!

                                                                                   FIGURE 3

-------
                                                     PROGRAM SCHEDULE.
Phase
                                     FOR EVALUATION  OF BIASED AND .OVERFIRE AIR FIRING
                                              AND EXISTING PROCESS  VARIABLES
Task
Task Description
                                                                                 Program Month
r  CM o  <  to  to rx  co
Oi  CM  w <
CMCM  CM  CM CM
                 Prepare Design Drawings for
                 Fabrication & Erection of NOX
                 Control Systems
                 Purchase Equipment & Fabricate
                 Equipment
           3     Install Test Instrumentation
           4     Perform Baseline Tests
           5     Perform Bias Firing Tests
                 Deliver  Equipment  and Modify
                 Unit
                 Final Test Preparation
            1      Conduct Tests
            2      Evaluate  Results  &  Prepare
                  Final  Report
                  Prepare  Application  Guidelines
                  for  Minimizing  NOX
                                                        |Purch (Fabricate
                                                            (Test I   RPTJ
                                                                 | Test!  RPT
                                                                               j	jest	
                                                                                           \-Evaluate-  -f Report
                                                                                                                   FIGURE 4

-------
        COSTS OF NOX CONTROL METHODS
         NEW COAL FIRED UNITS
         (INCLUDED IN  INITIAL DESIGN)
                                        WIN DBOX GAS RECIRCULATION
                                      azfOVERFIRE AIR
                                        COMBINED
                                        OVRFIRE AIR AND WINDBOX
                                           GAS RECIRCULATION

                                           p~ RECIRCULATION THRU
                                            MILLS
                                        1SUMDBOX WATER INJECTION
200
300    400    500


     UNIT SIZE

       (MW)
600
700
800
                                              FIGURE 5
                            302

-------
               COSTS OF NOX CONTROL METHODS
                        COAL FIRED UNITS
100
            (HEATING SURFACE CHANGES NOT
                                                WINDBOX GAS RECIRCULAT10N
                                                OVKRFIRE AIR
200
              300
400    500    600

  UNIT SIZE
    (MW)
                                   700
                                               CONFINED
                                               OVEJRFIRE AIR AND WINDBOX
                                                   RECIRCULATION
                                                   RECIRCULATION THRU MILLS
                                                   ER INJECTION INCLUDING FAN
                                                 6 DUCT CHANGES
  IR INJECTION WITHOUT FAN
  1DUCT CHANGES
800
                                                       FIGURE 6
                                 303

-------
                                                                          TABLE  I

                                                      1973 OPERATING COSTS OF  NOX  CONTROL  METHODS FOR
                                                                  NEW  COAL FIRED  UNITS

                                                                     SINGLE FURNACE
CONTROL METHOD
MW RATING
EQUIPMENT COSTS 10 $
LJ ANNUAL FIXED CHARGE 10 $
O
ADDITIONAL ANNUAL FUEL
COST 10J$
ADDITIONAL ANNUAL FAN
POWER COST 10 $
*5
TOTAL ANNUAL COST 10 $
OPERATING COST MILLS/KWHR
OVERFIRE
AIR (20$)
100
31
5
. 	
5
0.009
450
63
10
...
10
0.004
750
90
14
-__
14
0.003
WlNDBOX
FLUE GAs
RECIRC. (30$)
100
350
56
21
77
0.143
450
1185
190
95
285
0.117
750
1650
264
158
422
0.104
COMBINATION
OF 1 AND 2
100
375
60
21
81
0.150
450
1248
200
95
295
0.121
750
1800
288
158
446
0.110
COAL MILL
FLUE GAS
RECIRC. (17$)
100
300
48
22
70
0.130
450
1015
162
100
262
0.108
750
1425
228
166
394
0.097
WATER
INJECTION
100
160
26
147
13
186
0.344
450
560
90
660
58
808
0.332
750
825
132
1099
97
1328
0.3271
 BASED ON:  A.  DELIVERED AND ERECTED  EQUIPMENT  COSTS  (+  10$ ACCURACY).  EXCLUDING  CONTINGENCY AND  INTEREST DURING CONSTRUCTION.
            B.  5400 HR/YR AT RATED MW AND  NET PLANT HEAT RATE OF  9400 BTU/KWHR.
            C.  50$i/106BTU COAL  COST.
            D.  $250/HP FAN POWER COST, OR  $40/HP PER  YEAR.
            E.  ANNUAL FIXED CHARGE RATE OF  16$.
            F.  OPERATING COSTS  ARE +  10$.
            G.  DOES NOT  INCLUDE COST  OF WATER PIPING  IN  PLANT OR  COST OF MAKEUP WATER.
 BASE UNIT OPERATING COSTS* FOR  COAL  FIRED  POWER  PLANTS  EXCLUDING 50%  REMOVAL SYSTEMS.

 UNIT SIZE               MW         100    450     750
 OPERATING COST  MILLS/KWHR        16.2    13.5   12,6
INCLUDES 1973 CAPITAL COSTS, LABOR,  MAINTENANCE,  FUEL COSTS +20$ CONTINGENCY +17$  INTEREST  DURING  CONSTRUCTION.

-------
CONTROL OF NOX FORMATION IN WALL, COAL-FIRED UTILITY BOILERS:

                TVA-EPA INTERAGENCY AGREEMENT
                             By

           Gerald A. Hollinden and Shirley S. Ray
                    Power Research Staff
                 Tennessee Valley Authority
                   Chattanooga, Tennessee
                 Prepared for Presentation at
              Pulverized Coal Combustion Seminar
       Sponsored by the Environmental Protection Agency
            Research Triangle Park, Worth Carolina
                       June 19-20, 1973
                              305

-------
       CONTROL OF NOX FORMATION IN WALL, COAL-FIRED UTILITY BOILERS:

                       TVA-EPA INTERAGENCY AGREEMENT
                                     By
                   Gerald A. Hollinden and Shirley S.  Ray
                            Power Research. Staff
                         Tennessee Valley Authority
                           Chattanooga, Tennessee
                                  ABSTRACT



An agreement has been formed between the Tennessee Valley Authority and

the Environmental Protection Agency to study, on a field utility boiler,

combustion modification techniques to control NOX and related pollutant

emissions from wall, coal-fired utility boilers.  This agreement will

provide more accurate and detailed engineering design information on the

application of specific combustion modification techniques and their

effects on NOX and other pollutant emissions, slagging, fouling, corrosion,

and general boiler operation and performance over a longer period of time

than has been possible in other field tests.
                                     306

-------
specific combustion modifications to a wall, coal-fired utility boiler have




on the formation of NOX and related pollutants and to assess their effects




on corrosion, flame stability, slagging, and general boiler performance.




The project will result in a guide for operational control using this




technology to reduce NOX and other emissions under a variety of conditions.




The agreement was drawn under Section lOU of the Clean Air Act as amended.




Duration of the project will be the 12-month period from June 1, 1973,  to




June 1,
The tasks that TVA will perform under this agreement include selection of




a suitable unit, preparation of test program, management of the baseline




emissions study and testing program, and evaluation of results.  TVA will




also prepare cost estimates for studies relating to the practicality of




utilizing "NO" ports, flue gas recirculation system, alternate fuels, and




combinations of these techniques for reduction of NOX emissions.






Unit Selection



A wall-fired pulverized coal utility boiler will be selected to satisfy




the following criteria:






1.  Representative of current design and use.






2.  Have boiler size such as to minimize modification costs, probably from




    100 to 250 MW.






3.  Permit testing of various coals at reasonable costs.






h.  Have capability for flue gas recirculation.






5.  Have demonstrated operational flexibility to permit evaluation of the




    combustion modifications to be studied (e.g., pulverizer capacity).
                                    307

-------
Test Program




A test program will be designed to characterize normal boiler performance




and to evaluate specific process variables.  Baseline emissions and thermal




performance will be determined, as well as the operating conditions within




which the unit can be operated reliably.  Baseline corrosion rates will be




established also as a necessary reference to which corrosion data from




experimental studies can be compared.  Among the process variables to be




evaluated through the test program are excess air level, load, effect of




furnace wall deposits, and firing patterns for staged firing.






Staged firing will be particularly tested as a control technique for




reducing WOX and related pollutant emissions.  The number and duration of




these tests will be sufficient to permit characterization of the effects




that staged firing has on emissions as well as its long-term effects on




corrosion, flame stability, and thermal performance.






In optimizing this technique, TVA will evaluate such factors as:






1.  Maximum emissions control throughout the normal load range.






2.  Maximum emissions control at full load only.






3.  Control of emissions to meet and maintain emissions standards through-




    out the normal load range.  This may require varying levels of control



    for different loads to maintain a fixed emissions level.






The results of these tests should provide guidelines as to when combustion




modifications must be employed to meet promulgated standards.  For example,




at reduced loads, the degree to which staged firing is necessary may be




less than at higher loads.
                                      308

-------
The objective of these tests is to develop guidelines as to the levels of




pollutant reductions which are possible with staged firing, the load




conditions under which staged firing must be employed to meet emissions




standards, ard the long-term effects that staged firing has on corrosion



and boiler performance.






TVA will provide for use in the test procedures continuous monitoring




instruments to measure NOX, 02, CO, CC>2, and hydrocarbons, as well as




particulate monitoring equipment, corrosion probes, and the instrumentation



required to characterize unit performance.






Cost Estimates




In addition to the preparation, conduct, and evaluation of the test program




to determine the effects of combustion modifications on pollutant emissions




and on boiler performance, TVA will provide cost analyses for studies to




determine the effects of "NO" ports, flue gas recirculation,  combinations




of techniques, and alternative fuels on WOX emissions and boiler performance.






A.  Effects of "WO" Forts




    Costs and a timetable will be determined for the following tasks:






    1.  Design, construct, and install tilting "WO" ports above the top row




        of burners.  These ports will be sized to allow introduction of up




        to 25 percent of the total combustion air and will permit adjust-



        ment of the discharging air velocity and temperature  (through air




        preheater control).






    2.  Conduct a study to optimize the use of "HO" ports for control of




        NOX emissions consistent with reliable boiler performance, consider-




        ing rate, velocity, temperature, and tilt of overfire air.
                                       309

-------
    3.  Operate the unit under the optimum conditions of overfire air




        firing for at least 300 hours in order to assess the effects of




        overfire air firing on fireside corrosion.   In determining costs,




        consideration should be given to operating the unit at other than




        the optimum condition (in terms of pollutant emissions),  since



        the optimum condition for emissions control may not be best with




        regard to corrosion, slagging, stability, and boiler performance.






    k.  Operate the unit under the optimum conditions of overfire air




        firing for four to six months in order to study long-term corrosion




        effects.






    For each testing phase, the costs associated with emissions testing,




    fuel and corrosion probe analysis, boiler derating,  outages,  and data




    reduction will be included in the required cost estimates.






B.  Effects of Flue Gas Recirculation




    Costs and time needed to complete the following tasks will be determined.






    1.  Design, construct, and install a flue gas recirculation (FGR)




        system.  This system will be sized to allow up to l0-percent




        recirculation at 80-percent load, will permit the use of  recircu-




        lated gas as both transport air to the coal mills and as  secondary




        air, and will provide for mixing hot air with flue  gas to supply



        the coal mills and secondary air compartments.






    2.  Conduct a study to determine the optimum use of recirculated flue




        gas for control of NOX emissions consistent with reliable boiler




        performance.  This study will evaluate the location where flue  gas




        is introduced and provide for at least two rates of recirculation



        and three flue gas temperatures.





                                      310

-------
    3.  Operate the unit under the optimum conditions of  flue  gas  recircu-




        lation for at least 300, hours in order to assess  the effects of




        flue gas recirculation on fireside corrosion.






    k.  Operate the unit under the optimum conditions of  flue  gas recircu-




        lation which are consistent with reliable.boiler  performance for




        four to six months in order to determine long-term corrosion



        effects.






    Costs for each testing phase will include the costs of emissions testing,




    fuel and corrosion probe analysis, boiler derating, outages, differential



    operating costs, and data analysis.






C.  Combination of Techniques




    Costs and time will be determined for an optimization study, an operation




    phase of at least 300 hours, and a long-term corrosion study of two to




    three months.  The optimization study will evaluate the most effective




    combination of overfire air, staged firing,  and flue gas recirculation




    with regard to HOX emissions and boiler performance.  It will also




    determine the minimum level of excess air which can be achieved, the




    effects of low air preheat, and the effects  of load variation consider-




    ing flue gas recirculation, staged firing, and overfire air.






D.  Evaluation of Alternate Fuels



    The costs and time needed to evaluate the effects of coal type  on NOX




    emissions when the most effective combination of combustion techniques




    is employed will be determined.   At least two different types of coal




    supplies will be evaluated.  These tests will define the operating




    limits within which these fuels  may be burned to achieve reduced NOX
                                    311

-------
emissions and reliable boiler performance.   Costs  data will include



differential fuel and operating costs,  corrosion probe analysis,  emissions



testing, derating, outages, and data reduction and correlation.
                                 312

-------
 BIBLIOGRAPHIC DATA
 SHEET
                   1. Report Not
                      EPA-650 72-73-021
4. Title and Subtitle
Proceedings   Coal Combustion Seminar,  June 19-20, 1973
3. Recipient's Accession No.
  Research Triangle Park,  N.C. 27711
                                                               5. Report Date
                                                                 September 1973
                                                               6.
7. Author(s)
R.E
               D W. Pershing (Chairman and Vice  Chairman)
               ,.   _ M*i mo * n/^ Afinrf*ss
8. Performing Organization Kept.
  No.
      --.".*-.*. u-*"rT "- '* -    ....
9. Performing Organization Name and Address

 Miscellaneous
                                                               10. Project/Task/Work Unit No.
                                                               Pgm Element 1A2014
                                                               11. Contract/Grant No.
12. Sponsoring Organization Name and Address
EPA, Office of Research and Development
NERC-RTP,  Control Systems Laboratory
Research Triangle Park, N.C.  27711
                                                               13. Type of Report & Period
                                                                  Covered

                                                                 Proceedings
                                                               14.
 5. Supplementary Notes
 6. Abstracts Tne proceedings document the 10 presentations made during the Seminar,
 which dealt  with subjects related to EPA's research and development activities for
 control of air pollutant emissions from the combustion of pulverized coal. The
 Seminar was divided in two parts: participating in the portion on fundamental
 research were Rockwell Inter national's Rocketdyne Division, KVB Engineering, Inc.
 and Southern California Edison Co. , EPA, Holland's International Flame Research
 Foundation, and Jet Propulsion Laboratory;  and taking part in the portion on pilot-
 and full-scale tests were Babcock and Wilcbx"(Alliance  Research  Center), U.S.
 Bureau of Mines, Esso Research and Engineering Co. ,  Combustion Engineering, Inc.
 and Tennessee Valley Authority.  Purpose of the Seminar was to provide contractors
 and industrial representatives with the latest information on coal combustion
 research.
 7. Key Words and Document Analysis.  17a.
 Air Pollution
 Combustion
 Combustion Control
 Combustion Chambers
 Coal
 Nitrogen Oxides
 Carbon Monoxide
 Carbon
 Hydrocarbons
 7b. Identifiers/Open-Ended Terms
 Air Pollution Control
 Stationary Sources
 Unburned Hydrocarbons
 Fuel Nitrogen
 Fundamental Research
 c. COSATI Field/Group  13A , 13B , 21B
                              Descriptors
                                Pulverized Fuels
                                Boilers
                                Utilities
                                Pilot-Scale Tests
                                Full-Scale Tests
  Availability Statement
                        Unlimited
                                                    19..Security Class (This
                                                       Report)
                                                         UNCLASSIFIED
                                                    20. Security Class (This
                                                       Page
                                                         UNCLASSIFIED
         21. No. of Pages
            319
                                                                        22. Price
 'RM NTIS-35
           - 3'72)
                                       313
                                                                        USCOMM-DC M952-P72

-------
    INSTRUCTIONS  FOR COMPLETING  FORM  NTIS-35 (10-70) (Bibliographic Data Sheet based on COSATI
   Guidelines to Format Standards for Scientific and Technical Reports Prepared by or for' the Federal Government,
   PB-180 600).

    1.  Report Number.  Each individually bound report shall carry a unique alphanumeric designation selected by the performing
       organization or provided by the sponsoring organization.  Use uppercase letters and Arabic numerals only.  Examples
       FASEB-NS-87 and FAA-RD-68-09.

    2.  Leave blank.

   1  Recipient's Accession Number.  Reserved for use by each report recipient.

   4.  Title and Subtitle.  Title  should  indicate clearly  and briefly the  subject coverage of the report, and be displayed promi-
       nently.  Set subtitle, if  used,  in smaller type or otherwise subordinate it to main title.  When a report is prepared in  more
       than one volume, repeat  the primary title, add volume number and  include subtitle for the specific volume.

   5.  Report Date, l-.ach report shall carry a date indicating at  least month and year.  Indicate the basis  on which it was selected
       (e.g., date of issue, date of approval, date of preparation.


   6.  Performing Organization Code.  Leave blank.

   7.  Author(s).   Give name(s) in conventional order  (e.g., John R. Doe,  or J.Robert Doe).  List author's affiliation if it differs
       from the performing  organization.

   8.  Performing Organization Report Number.  Insert if performing organization  wishes to assign this number.

   9.  Performing Organization Name and Address. Give name,  street, city, s.tate, and zip code.   List no more than two levels of
       an organizational hierarchy.  Display the name  of the organization exactly as it should appear in Government indexes such
       as USGRDR-I.

   10.  Project/Task/Work  Unit Number.  Use the project, task and work  unit numbers under which the report was prepared.

   II.  Controct/Grant  Number.  Insert contract or grant number under which report was prepared.

   12-  Sponsoring Agency Name and Address.   Include- zip code.

   13.  Type of Report  and  Period Covered.  Indicate interim, final, etc., and, if applicable, dates covered.

   14.  Sponsoring Agency Code.  Leave blank.

   15.  Suoplementory Notes.  Enter information not included  elsewhere but useful, such a.c: Prepared in cooperation  with . . .
       Translation of  ...  Presented at conference of  ...  To be published in ...  Supersedes . . .       Supplements . . .

   16.  Abstract.  Include a brief  (200 words or less) factual .summary  of the most significant information contained in the report.
       If the  report contains a significant bibliography or literature survey, mention it here.

   17.  Key Words and Document Analysis,  (a).  Descriptors.  Select from the Thesaurus of Engineering and Scientific Terms the
       proper authorized terms that identify the major concept  of the research and are sufficiently specific and precise to be used
       as index entries for cataloging.
       (b). Identifiers and Open-Ended Terms.  Use identifiers  for project names, code names, equipment designators, etc.  Use
       open-ended terms written in descriptor form for those subjects for which no descriptor exists.
       (c).  COSATI Field/Group.  Field and  Group assignments  are to be taken from the  1965 COSATI  Subject  Category List.
       Since  the majority of documents  are multidisctplinary in nature, the  primary Field/Group assignment(s) will be the specific
       discipline, area of human endeavor, or type- of physical object.  The applications) will be cross-referenced with secondary
       Field/Group assignments that will follow the primary posting(s).

   18.  Distribution Statement.   Denote  rc-leasability to the  public  or limitation for reasons  other than security for  example  "Re-
       lease  unlimited".  Cite any availability to the public, with  address and price.

   19 & 20. Security Classification.  Do not submit classified reports to the National Technical

   21.  Number of Pages.  Insert the total number of pages,  including this  one and unnumbered pages, but  excluding distribution
       list, if any.

   22   Price.  Insert the price  set by the National Technical  Information Service ot the Government Printing Office, if known.
FORM NTIS-35 (REV. 3-72)                                                                                   USCOMM-DC 14952-P72

-------