v>EPA
          United States
          Environmental Protection
          Agency
          Industrial Environmental Research
          Laboratory
          Research Triangle Park NC 27711
EPA-600/7-79-079
March 1979
Applicability of the
Thermal DeNOx Process
to Coal-fired Utility
Boilers

Interagency
Energy/Environment
R&D Program Report

-------
                 RESEARCH REPORTING SERIES


Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination  of traditional  grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:

    1. Environmental Health Effects Research

    2. Environmental Protection Technology

    3. Ecological Research

    4. Environmental Monitoring

    5. Socioeconomic Environmental Studies

    6. Scientific and Technical Assessment Reports (STAR)

    7. Interagency Energy-Environment Research and Development

    8. "Special" Reports

    9. Miscellaneous Reports

This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded  under  the 17-agency Federal  Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from  adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport  of energy-related pollutants and their health and ecological
effects;  assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide'range of energy-related environ-
mental issues.
                        EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.

This document is available to the public through the National Technical Informa-
tion Service, Springfield. Virginia 22161.

-------
                                   EPA-600/7-79-079

                                            March 1979
       Applicability  of the
Thermal DeNOx Process to
   Coal-fired  Utility  Boilers
                     by
       G.M. Varga Jr., M.E. Tomsho, B.H. Ruterbories,
              G.J. Smith, and W. Bartok

        Exxon Research and Engineering Company
           Government Research Laboratories
                   P.O. Box 8
              Linden, New Jersey 07036
              Contract No. 68-02-2649
            Program Element No. EHE624A
         EPA Project Officer: David G. Lachapelle

       Industrial Environmental Research Laboratory
         Office of Energy, Minerals, and Industry
           Research Triangle Park, NC 27711
                  Prepared for

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

-------
                                   FOREWORD


     Two studies relating to Exxon's Thermal DeNOx Process for control  of
NOX emissions from utility boilers have been sponsored by EPA/IERL-RTP.
One, conducted by Exxon Research and Engineering Company under EPA Contract
68-02-2649, is entitled "Applicability of the Thermal DeNOx Process to
Coal-fired Utility Boilers."  The final report number is EPA-600/7-79-079,
March 1979.  The other, conducted by Acurex Corporation under EPA Contract
68-02-2611, is entitled "Technical Assessment of Exxon's Thermal DeNOx
Process."  Its final  report number is EPA-600/7-79-111, May 1979.

     The Exxon-prepared report discusses the Process background, engineer-
ing considerations, and cost estimates for application of this technology
for a number of boiler/fuel cases at various NOX control levels.  Results
of recent pilot-scale tests with coal-firing, sponsored by Exxon and the
Electric Power Research Institute, are included.

     The Acurex-prepa red report objectively critiques the Exxon findings
and also addresses a  variety of environmental, operational, and supply/
demand considerations that are relevant to the Thermal DeNOx Process.

     Together, these  reports give a good overview of this technology.  We
recommend that both reports be obtained, and read, by those wishing to
become better informed about the Thermal DeNOx Process.
                                             J«bti K/ Burchard
                                             Director
                                             IERL-RTP
                                       ii

-------
                                  ABSTRACT
     This EPA-sponsored program was undertaken to project the probable per-
formance of the Exxon Thermal DeNOx Process on selected, representative coal
fired utility boilers and to determine if Thermal DeNOx is better suited to
certain boiler types than others.  Also, budget type cost estimates were
prepared for Thermal DeNOx applied to these boilers.  The non-catalytic
Thermal DeNOx Process is based on selective reduction of NOx with NH3 in the
gas phase.  Thermal DeNOx nas been commercially demonstrated on gas- and
oil-fired boilers and process furnaces.  A pilot scale test on a coal fired
combustor produced results similar to those obtained with oil and gas firing.

     In undertaking the study reported here, Exxon Research and
Engineering Co. (ER&E), selected eight typical coal-fired utility boilers,
representative of the nation's boiler population.  The boilers were chosen
to permit an evaluation of the Thermal DeNOx Process on different utility
boiler sizes, firing methods and coal types.  Thermal DeNOx performance
and process costs were determined for two NOX reduction targets:

     a.  Trimming NOX emissions to meet the proposed New Source Performance
         Standards (NSPS) of 0.6 Ib. NOx/MBtu* (450 ppm NOX**) for bitu-
         minous coal and lignite fired boilers and 0.5 Ib. NOx/MBtu (375 ppm
         NOX) for boilers fired with subbituminous coal.

     b.  Deep reduction in NOx levels to 0.4 Ib./MBtu (300 ppm NOx) for
         boilers fired with bituminous coal and lignite and 0.3 Ib. NOx/MBtu
         (225 ppm) for subbituminous coal fired boilers.

Also considered was the:

     c.  Maximum practical reduction in NOx levels which could be realized
         by the application of the Exxon Thermal DeNOx Process.

     Two initial NOX levels were considered for each of the above NOX targets:
(i) uncontrolled and (ii) reduced by combustion modifications.  Each boiler
was assumed to be equipped with two ammonia injection grids to permit load
*Certain English units, have been used in this report.  A table has been
 provided to facilitate conversion to the SI system.

**Throughout this report volumetric concentrations of NOX are expressed as
  parts per million corrected to 3% 02, dry basis.
                                     iii

-------
following.  In aa'dditien to the six cases, special analyses were performed
for flue gas temperature nonuniformity and the use of hydrogen with ammonia
to permit load following.  A Performance Prediction Procedure developed by
ER&E was used to project Thermal DeNOx performance.  Also, the Thermal DeNOx
costs for reaching NOX levels of 0.3 to 0.4 Ib/MBtu were compared with the
costs of combustion modifications (CM) required to reach these levels.

     All eight units studied were projected to reach the proposed NSPS
using Thermal DeNOx alone.  Five of these units could reach this level using
CM alone.  All units except a cyclone boiler firing lignite were projected
to reach the deep NOX reduction target when Thermal DeNOx was used with CM.
Four boilers were projected to reach the deep reduction target using Thermal
DeNOx alone.  The Thermal DeNOx process costs to reach the proposed NSPS from
an uncontrolled base level ranged from 0.25 to 1.17 mills/KW-Hr.  The costs
to reach the deep reduction target using Thermal DeNOx with CM ranged from
0.38 to 0.51 mills/KW-Hr and averaged 0.45 mills/KW-Hr for the seven boilers
reaching the target.  NOX reductions from uncontrolled initial levels ranging
from 50 to 59% and costs ranging from 0.57 to 1.23 mills/KW-Hr were
 projected using  Thermal  DeNOx  at a  maximum  practical  level  without  CM.  With
 CM,  reductions  ranging  from 62 to 76% were  projected.   Costs  ranging  from
 0.55 to 1.14 mills/KW-Hr were  projected  for the eight boilers studied.

     The Thermal DeNQx Process was projected to be equally amenable to all
units studied.  One overall judgement criteria of performance, ammonia
reagent costs/pound of NOX removed, were nearly equal for all  units at
0.09 $/lb ANOX.  Conventional CM which could reach NOX levels of 0.3 to 0.4
Ib/MBtu were cheaper than Thermal DeNOx, but extreme CM such as derating were
more expensive.

     Thermal DeNOx performance is a function of the cress sectional  tempera-
ture throughout the reaction zone.  The  Performance Prediction Procedure
used assumes that a range of temperatures is present in the plane of the
injection grid.   This temperature range is assumed to be gradually smoothed
out downstream of the injection location.  It was projected that the ammonia
injection grid location would not be affected significantly by assuming a
50°C larger temperature range in the injection plane than that used for
baseline calculations.  However, a temperature range increase of this size
would reduce DeNOx performance by 5 to 10 percentage points (e.g., from 50%
to 40-45%).

     Hydrogen can be used with ammonia to lower the temperature at which the
Thermal DeNOx reaction occurs.   Thus,  in certain cases it may be technologi-
cally possible to utilize ammonia plus hydrogen rather than dual grids to
permit effective DeNOx performance at less than full  boiler loads.  In one
such example considered, the use of hydrogen and ammonia fed through one
grid increased the costs of Thermal  DeNOx relative to the corresponding
ammonia-only, dual  grid cases considered.

     The pilot plant scale test on coal firing noted earlier was sponsored
jointly by Exxon Research and Engineering Co. and by the Electric Power
Research Institute.  The work was performed by KVB Inc. and their report
is included here as Appendix 2.
                                      iv

-------
     A full scale test of the Exxon Thermal  DeNOx Process on a coal  fired
utility boiler is recommended.  This demonstration would be structured to
evaluate ammonia breakthrough and DeNOx performance as a function of load,
the effect of slag formation and fouling on Thermal DeNOx performance, the
formation, deposition and removal of ammonium sulfates, the effect of
ammonium sulfates on electrostatic precipitator performance, the influence
of Thermal DeNOx on particulates, and other pollutants, and the compatibility
of Thermal DeNOx system elements with coal ash levels and soot blowing equip-
ment and procedures.

     This report was submitted in fulfillment of Contract No. 68-02-2649 by
Exxon Research and Engineering Company under the sponsorship of the U.S.
Environmental  Protection Agency.  This report covers a period from
September 30,  1977 to May 31, 1978, when the work was completed.

-------
                               CONTENTS
                                                                    Page

Abstract    	   iii

Figures	   vii

Tables    	   viii

Conversion  Factors  	                 ix

Acknowledgment 	      x

     1.   Introduction  	   1

     2.   Conclusions 	   4

     3.   Recommendations 	   6

     4.   Process Background  	   7

               Chemistry of the Process  	   7
               Engineering Considerations  	   9
               Process Costs 	  10
               Commercial Scale Experience 	  11

     5.   Program Detail	13

               Boilers Selected for Study  	  13
               NOX Reduction Cases	13
               Thermal DeNOx Performance Prediction Procedure  .  .  18
               Cost Estimates	20

     6.   Results and Discussion	27

               Predicted Percent NOx Reduction Levels  	  29
               Feasibility Costs  	  30
               Maximum Reduction  of NOX Levels 	  33
               Normalized Ammonia and Other Operating Costs  ...  34
               Cost Comparison  of Thermal DeNOx with Combustion
                 Modification Techniques 	  37
               Temperature Nonuniformity Sensitivity Study ....  40
               Use of Hydrogen  for Load Following	41

Appendices

     1.   Cost Comparison Summary	47
     2.   Non Catalytic NOX Removal with Ammonia	55
                                  vi

-------
                                 FIGURES



Number                                                                 Page
4-1
6-1
6-2
6-3
Performance of Thermal DeNOx Systems in Commercial

Cost Comparisons for Trim Target Without Combustion
Modifications - 100 Percent Load 	 	 	 	
Comparison Cost of Injecting with and Without H2 in a
Babcock and Wilcox - 333 MW Unit 	
1?
•3C
' 03
•30
4R

-------
                                   TABLES
Number                                                                   Page
 5-1    Boilers Selected for Study   	   H
 5-2    Initial and Final NOX Levels for Boiler/Coal Combinations  ...   17
 5-3    Thermal DeNOx Cost Calculations  	 23-24
 5-4    Costs for Combustion Modifications Established by Acurex-
       Aerotherm	   25
 5-5    Costs for Boiler Derating	   26
 5-6    Combustion Modifications Used to Reduce NOx Levels	   26
 6-1    Predicted Thermal DeNOx Performance Achievable at Full, 75% and
       50% Load	   30
 6-2   Costs  for Reducing NOX Emissions of Coal Fired Utility Boilers
       Using  Thermal DeNOx	   32
 6-3   Maximum Practical NOX Reduction Achievable Using Thermal DeNOx  .   36
 6-4   NOX Levels on 270 MW B&W HO Boiler	   39
 6-5   NOX Levels on 265 MW F-W HO Boiler	   39
 6-6   Examples Contrasting Single Grid-Hydrogen and Dual Grid for Load
       Following	   42

-------
                             CONVERSION FACTORS






To Convert From                      To                          Multiply By


    Ib/Hr                           kg/Hr                          0.4536



    Ib/MBtu                         ng/J                              43°


    ppm N0₯                         mg/m                           1.88*
  *NO  expressed as N0? at 25°C
     j\                £-
                                       IX

-------
                               ACKNOWLEDGMENT
     The authors acknowledge with thanks the boiler manufacturers,  Babcock
and Wilcox, Combustion Engineering, Inc., Foster Wheeler Corp.,  and Riley
Stoker Corp., for providing technical  information on their boilers
required for undertaking this study.

-------
                                SECTION 1

                              INTRODUCTION
     Exxon Research and Engineering Company has developed a new process
called Thermal  DeNOx for reducing emissions of oxides of nitrogen from
large stationary combustion sources.  This non-catalytic process is based
on the selective reduction of NOX with NHs in the homogeneous gas phase
(1_,2).  The Thermal DeNOx process has been commercially demonstrated on
gas-and oil-fired steam boilers and process furnaces.  Exxon Research and
Engineering Company has granted licenses on this process in Japan where
NOX emission regulations are very stringent and in the U.S. where a test
was recently completed on a boiler used for the enhanced recovery of oil.
A test has also been performed on a pilot scale coal fired boiler.

     The Thermal DeNOx process involves the injection of ammonia into the
hot flue gas within a narrow and critical temperature range.  Maximum NOx
reductions ranging from 35% to 65% have been obtained with Thermal DeNOx
on commercial  units.  Although the temperature sensitivity will cause the
reaction's effectiveness to vary from one installation to another, the NOX
reduction is essentially independent of the concentration of oxides of
sulfur or particulate matter in the flue gas.  The specific level achievable
is dependent upon a number of factors, including the boiler design, operating
mode, and initial NOX level.

     Thermal DeNOx may be applied to boilers for additional NOX reduction
after combustion modifications such as low excess air firing, the use of
low NOX burners or overfire air ports have been implemented.  As Thermal
DeNOx is a post-flame injection process, it is not affected by certain
limitations such as derating imposed on combustion modifications that may
affect the usefulness of combustion modification in retrofit applications.
Thus, the Thermal DeNOx process is viewed as an effective supplement to
available combustion modification techniques for attaining low NOX levels
for combustion installations that require a high degree of emission control.

     The purpose of this EPA-sponsored program has been to project the
performance and formulate budget type cost estimates of the Exxon Thermal
DeNOx Process applied to a broad range of typical coal fired utility boilers.
Exxon Research has undertaken an assessment of utility boiler types to
determine if certain boilers as a function of firing method, size, or
manufacturer's design are more amenable to the Thermal DeNOx Process than
others.  To perform this analysis, Exxon Research identified eight represent-

-------
 ative  utility boiler categories which included one or more from each of the
 four major  boiler manufacturers.  These boilers were selected so as to
 permit an assessment of different utility boiler sizes, firing methods and
 coal types.  In undertaking this assessment, Exxon Research consulted with
 and obtained from the four major U.S. utility boiler manufacturers the
 temperature, dimensions, flue gas flow and other non-proprietary boiler
 design information required to undertake this assessment.  Exxon Research
 has also prepared budget type cost estimates of the Thermal DeNOx Process
 applied to  the boilers considered.

     Two key NOx reduction targets were formulated in undertaking the
 amenability analysis and cost estimates noted here.  These were:

     a.  Trimming NOX emissions to meet the proposed New Source Performance
         Standards (NSPS) of 0.6  lb.  NOx/MBtu (450 ppm NOX) for bi< tiinous
         coal and lignite fired boilers and 0.5 lb.  NOx/MBtu (375     NOX)
         for boilers fired with subbituminous coal.

     b.  Deep reduction in NOx levels to 0.4  Ib./MBtu (300 ppm NOX) for
         boilers fired with bituminous coal and lignite and 0.3 lb.  NOX/
         MBtu (225 ppm) for subbituminous coal fired boilers.

 Also considered was the:

     c.  Maximum practical reduction in NOX levels which could be realized
         by the application of the Exxon Thermal  DeNOx Process.

     Two initial NOX levels were considered for each of the above MOX
 targets:  (i) uncontrolled and (ii)  reduced by combustion modifications.
 Thus, a total of 6 cases were established.   This  permitted a thorough
 evaluation of the ability of the Thermal  DeNOx Process to meet NOX target
 levels and to establish a range of costs where practical.

     In addition to the above six cases considered for all boilers, two
 additional special analyses were performed  for one boiler.  One was a
 temperature nonum'formity sensitivity study and the other studied the use
of hydrogen along with ammonia to achieve NOX reduction at reduced boiler
 loads.  The former was prepared because of the significant temperature
 dependence of the Thermal  DeNOx Process and the large temperature nonum'-
 formity encountered in boiler flue gases.   The latter was undertaken to
 illustrate the functioning and costs of the Thermal DeNOx system when
 hydrogen is used to accommodate load variations.   An analysis comparing
 the cost of Thermal DeNOx with the costs of extreme combustion modifications
 in reaching NOX levels for the 0.3 to 0.4 lb.  NOx/MBtu range was under-
 taken.  The limited availability of costs  for combustion modifications for
 reaching this NOX target level limited the  scope  of this comparison.

     The following sections present the conclusions reached and our recom-
mendations for future work.  This is followed by  general  background inform-
ation concerning the Exxon Thermal DeNOx Process  including process chemistry,
 engineering considerations, process  costs  and commercial  scale experience.

-------
After the Process Background discussion is a section which provides Program
Detail including the boilers selected for study, initial and final  DeNOx
reduction levels and cases evaluated, as well  as information on the per-
formance prediction procedure used and the assumptions involved in  cost esti-
mation.  This is followed by a results section which provides the results and
conclusions of the six general cases studied plus results of the temperature
nonuniformity study and the hydrogen addition case.  Cost data generated on
this program is presented in Appendix I.  A report covering the pilot plant
scale test on coal firing, sponsored jointly by Exxon Research and  Engineering
Company and the Electric Power Research Institute is presented as Appendix 2.
The work was performed by KVB Inc. which has also authored the coal study
report.

-------
                                 SECTION 2

                                CONCLUSIONS
     The performance of the Exxon Thermal DeNOx process was projected to
be essectially equivalent for all eight boiler types evaluated, even though
significant differences existed in flue gas temperature profiles and flow
path configurations among boilers.  These differences resulted in the
selection of significantly different injection grid locations among the
boilers of different manufacturers.  The analysis determined that the proposed
NSPS of 0.5 Ib./MBtu. for subbituminous coal and 0.6 Ib./MBtu for lignite and
bituminous coal could be met by all boilers considered using the Thermal DeNOx
Process.  All boilers studied, except the cyclone boiler fired with lignite,
could meet the deep reduction targets of 0.3 and 0.4 Ib./MBtu using Thermal
DeNOx coupled with presently available combustion modifications.

     It was projected that the ammonia injection grid location would not be
effected significantly by assuming a 50°C larger temperature range in the
injection plane than that used for baseline calculations.  However, a temper-
ature range  increase of this size would  reduce DeNOx performance by 5 to 10
percentage points  (e.g. from 50% to 40-45%).  It was also found that overall
NOX removal costs  increased when hydrogen (rather than multiple grids) was
used with only one grid to achieve effective DeNOx performance at other than
full boiler loads.

Other specific projections and conclusions were as follows:

     •  All  units could reach the proposed NOX NSPS using Thermal DeNOx
        alone.  Five of the eight units studied could also reach this level
        using combustion modifications alone.

     0  All  units except one could meet the deep NOX reduction target when
        Thermal DeNOx was used in combination  with combustion modifications.
        The one exception was the cyclone boiler fired with lignite.

     •  Projected costs to reach the proposed  NSPS from an uncontrolled base
        level ranged from 0.25 mills/KW-Hr for the 250 MW CE boiler to a high
        of 1.17 mills/KW-Hr for the lignite fired cyclone boiler.  The average
        cost for all boilers considered was 0.57 mills/KW-Hr, or 0.49 mills/
        KW-Hr not  including the cyclone  boiler.

-------
•  Four of the eight boilers could reach the deep reduction target using
   Thermal DeNOx alone.  Costs ranged from 0.38 mills/KW-Hr to 0.83 mills/
   KW-Hr for these boilers.

•  Projected costs to reach the deep reduction target using Thermal
   DeNOx W1'th combusiton modifications ranged from 0.38 mills/KW-Hr
   to 0.51 mills/KW-Hr, with the average being 0.44 mills/KW-Hr for the
   seven boilers reaching the target level.

•  NOX reductions ranging from 62% to 76% and averaging 70% relative
   to an uncontrolled base case could be achieved using Thermal DeNOx
   at a maximum practical level in combination with combustion modifi-
   cations.   NOX levels in the 0.20 to 0.23 Ib. NOx/MBtu range could be
   realized  for most of the boilers.  Costs ranged from 0.55 to 1.14
   mills/KW-Hr and averaged 0.68 mills/KW-Hr for all boilers studied.
   With the  lignite boiler excluded, the range was 0.55 to 0.67 mills/
   KW-Hr and the average was 0.61  mills/KW-Hr.

•  The costs for onsites and the carrier were found to be proportional
   to boiler size.

•  The total  ammonia reagent costs for all  cases, normalized for the
   amount of NOX removed expressed as N02 (ANOX)» were nearly equal for
   all eight units  studied at $0.09/lb.  ANOX.   This parameter was con-
   sidered to be a  good overall judgment criterion of the chemical
   efficiency and economic efficacy of the  Thermal DeNOx process.

•  The Exxon Thermal  DeNOx Process was considered to  be equally amenable
   to all  units  studied.

•  The costs for reaching NOX levels in  the 0.3 to 0.4 Ib./MBtu range
   were compared for Thermal  DeNOx and combustion modification.  The
   costs of  most conventional  combustion modifications and combinations
   thereof were  lower than that of Thermal  DeNOx.  Extreme NOX reduction
   methods such  as  derating or staged combustion that incurred derating
   would be  more expensive.  Derating would not generally be used as a
   NOX reduction technique.

-------
                                SECTION 3

                              RECOMMENDATIONS
     The primary recommendation resulting from this study is that the
Exxon Thermal DeNOx Process be tested on a coal fired utility boiler.
The boilers of the four major utility boiler manufacturers have been found
to be approximately equally amenable to the Thermal DeNOx Process.  After
the selection of an appropriate candidate boiler, the same type of per-
formance and cost analyses presented here must be prepared.  Temperature and
velocity profile measurements in the boiler heat transfer region are then
required to verify grid placement and performance estimates.  After instal-
lation and startup of the Thermal DeNOx system a careful measurement and
evaluation program will be needed to assess DeNOx performance, cost and
determine any possible side effects which result from the use of the
Thermal DeNOv Process.
             A

      In undertaking  this demonstration, a high level of attention should be
accorded to  those factors which could reduce the overall effectiveness of
the  Thermal  DeNOx Process on coal fired utility boilers, or could have
adverse side effects on boiler operation or the environment.  These factors
include:

      •  Ammonia.and  by-product emissions

      •  Effect  of slag formation and fouling on DeNOx reaction  zone temper-
         atures, and  on resulting DeNOx performance.

      •  Effective DeNOx performance under differing boiler  load conditions.

      •  Effect  of deposition of ammonium sulfates  on metal  surfaces and on
         electrostatic  precipitator performance.

      0  Compatibility  of Thermal DeNOx system  elements with coal ash levels
         and  with soot  blowing equipment and procedures.

-------
                                SECTION 4

                           PROCESS BACKGROUND
     This section provides  general  backgound information on the Exxon
Thermal DeNOx Process.   Presented is  information on the chemistry of the
process, engineering considerations,  process costs discussed in general
terms and a brief summary of commercial  scale experience.

CHEMISTRY OF THE PROCESS

     The process chemistry  relies on  the selective reaction between NH3
and NOX to produce nitrogen and water.   The reaction requires the presence
of oxygen and proceeds  within a critical temperature range.  The overall NO
reduction and production reactions  are  summarized in equations (1) and (2),
respectively:

                     NO +  NH3 + 1/4  02  -»•  N2 + 3/2 H20                (!)

                           NHs + 5/4  02  +  NO + 3/2 H20                (2)

     In typical  flue gas environments,  the NOX reduction shown as equation
(1) dominates at temperatures around  950°C (1740°F).  At higher temperatures,
the NOX production reaction shown as  equation (2) becomes significant, and
it dominates at  temperatures over about  1000°C (1830°F).  As temperatures
are reduced below about 900°C (1650°F),  the rates of both reactions slow,
and the ammonia  flows through unreacted.

     The following chain reaction cycle  was proposed by Dr. R. K. Lyon of
Exxon Research for the  NH3-NO-02 reaction system (2):
                               + NO  -»• N2  + H  + OH                      (3)

                           NH2  + NO  -f N2  + H20                         (4)

                             H  + 02  •»> OH  + 0                            (5)

                            0 + NH3  -»• OH  + NH2                         (6)

                           OH + NH3  •* H20 + NH2                        (7)

                            H + NHa  -»• H2  + NH2                         (8)

-------
This chain reaction mechanism is sufficient to explain qualitatively the
observed  reduction of NO by NH3 in the presence of CL.

     In practice, ammonia is injected into either boiler cavities or tube
banks or  both.  Exxon has shown that in certain applications the practical,
working potential of the Thermal DeNOx Process under varying loads and NOX
levels can be achieved through ammonia injection alone.  Exxon Research has
found that hydrogen can be used to shift the DeNOx temperature window to
lower levels.  The magnitude of this shift is mainly a function of the amount
of H2 injected relative to the NHs.  At Hg/NHs ratios on the order of 2:1,
the NOX reduction reaction can be forced to proceed rapidly at 700°C (1290°F).
By judiciously selecting the H2/NH3 injection ratio, flue gas treatment can
be accomplished over the range of 700-1OOQOC.

     In addition to temperature, the process is also sensitive to initial  NOX
and NH3 concentrations.  The NHs injection rate is generally expressed as  a
mole ratio relative to the initial NOX concentration.  Other variables
affecting performance are excess oxygen and available residence time at the
reaction  temperature.

     The  issue of possible pollutant by-products (HCN, N20, CO, $03 and
NH4HS04)  has been addressed by Exxon Research studies.  Hydrogen cyanide can
be produced only if hydrocarbons are present in the Thermal DeNOx reaction
zone.  Under normal conditions, hydrocarbons are absent from this zone. As
regards N20 production, it represents only one to two percent of the NOX
reduced.  The Thermal  DeNOx Process does not generate CO by reducing C02-
However,  CO oxidation is inhibited by NHs, so tha* if CO is present, it would
be emitted unreacted into the atmosphere.  This effect is of no consequence
under normal operating conditions for most boilers, as CO oxidation is com-
plete before the NH3 injection point.

     Detailed laboratory experiments have shown no interaction between the
Thermal DeNOx Process  and sulfur compounds in the high temperature flue gas
regions.  That is, sulfur or its oxides do not interfere with the NH3-
NOX-02-H2 chemistry.  Additionally, ammonia injection has been shown to
cause neither additional  homogeneous nor additional  heterogeneous oxidation
of S02 to S03.

     To the extent that the thermal  reduction of NO leaves  some NH3 unreacted,
and as the combustion gases cool,  NHs can react with SOs and H20 to form
ammonium sulfates.  Ammonium bisulfate is a viscous liquid  at air heater
temperatures.   Based on laboratory and commercial  tests, these sulfates do
not appear to  create either severe corrosion or unacceptable air heater foul-
ing problems  when Thermal  DeNOx is used in accordance with  its design speci-
fications.  Long term  tests conducted in two oil-fired boilers by Tonen
Sekiyu  Kagaku  K.K.  in  Kawasaki, Japan,  revealed these highly water-soluble
deposits could  be removed by waterwashing the air heaters.   Although long
term data  are  very limited, the frequency of waterwashing in these Japanese
installations  approaches  two to three times per year.  Of course, only
through a  Thermal  DeNOx demonstration on a coal  fired boiler can the washing
requirement be  quantified.
                                      8

-------
ENGINEERING CONSIDERATIONS

     When applying the Thermal  DeNOx Process  to commercial  equipment,
performance is generally limited by the extreme temperature sensitivity of
the reaction and its dependence on the local  concentrations of reactants,
NH3, NOX, 02 and Ho.  The Exxon technology provides a means of adapting
the chemistry requirements to industrial  equipment environments,  and NOx
reductions up to about 60% can  be achieved by the use of Thermal
DeNOx technology in existing boilers.  Application to new,  grass-roots
designs is usually easier because the internal  configuration of the high
temperature zone can be adjusted to complement the process  demands.

     The Thermal DeNOx Process  utilizes proprietary Exxon gas phase mixing
technology to rapidly and efficiently mix the small volume  of reagents with
the hot flue gas.   Correct distribution of reactants is required  because of
non-linearities in the reaction rates.  Locally high concentrations of NH3
will decrease the maximum attainable NOX reduction and will also  result in
the breakthrough of unreacted ammonia.

     Accommodating flue gas temperature varations is important if high
DeNOx rates are to be achieved.  Not only does  the system have to accommo-
date flue gas temperature changes caused by normal load and operating
variations, but it also must allow for fluctuations across  the reaction
zone caused by non-uniformities in flow and heat transfer.   It follows,
therefore, that a  case-by-case  evaluation of  flue gas temperatures and
local conditions is required for the application of Thermal DeNOx for each
installation considered.

     Initially, ammonia was injected only into  boiler cavities, boiler
regions between tube banks, which can be considered to be isothermal to a
first approximation.  Subsequent experimentation by Exxon Research has
shown the feasibility of injecting ammonia into boiler tube bank  regions as
well.  Thus, satisfactory NOx reduction performance can be  obtained by
locating the injector grid in either the boiler cavity or tube bank.  The
ability to inject  ammonia at virtually any post-combustion  boiler location
where temperatures range from 760°C to 1000°C has substantially increased
the flexibility of the Exxon Thermal  DeNOx process.

     The temperature in the post-combustion zone of a boiler can be shifted
by changes in boiler load.  For example, as load is reduced from full  to 50%,
the temperature for optimum Thermal DeNOx will  shift toward the fire box.
Depending on the magnitude of this shift, more than one ammonia injection
grid may be required in order to obtain DeNOx coverage over the range of
practical boiler loads.  Thus,  one grid may be adequate for boiler loads be-
tween 100% and 70% while another would cover  the 70 to 50%  load range.  It
must be noted, however, that the use of hydrogen with its ability to lower
the effective DeNOx temperature window could  permit effective DeNOx over
practical boiler loads with only one grid.  In other cases, both  hydrogen
addition and the use of multiple grids may be required to accommodate  load
changes.  A specific case was considered in which the costs of a  single grid
ammonia-hydrogen system were compared  with the costs of dual grids used with
ammonia alone.                                                y

-------
PROCESS COSTS

     The costs associated with the Thermal  DeNOx Process are sensitive
to the particular circumstances of the application.  Factors influencing
cost include initial  NOX concentration, reduction target, compatibility
of the boiler design  and operation, and local  price and availability of
chemicals and utilities.

     As an example, consider applying the process to a 300 MWe oil-fired
utility plant with an initial NOX level of 225 ppm (about 0.3 Ib.  NOX/M
Btu fired).  Assume the boiler geometry and operating conditions provide a
temperature in the reaction zone which does not require H2, and that for
a 50% NOx reduction target, an approximate NH3/NOX injection ratio of 1.0/1
is feasible.  Thus, Thermal DeNOx will have the following estimated
operating costs:

     (a)  NHs @ 1.0 mole per mole NOX (assume 170 $/ton) = 0.9 t/M Btu
     (b)  Utility air 0 210 SCF per M Btu fired (assume 0.005 
-------
are generally at target levels  over  the  full  range of operating  conditions
because of the reduced NOX  production  at lower loads.   Results  from  six
demonstrations are shown over their  range of  operating conditions  as a
function of flue gas  temperature in  Figure 4-1.  Hydrogen  was  used along
with" ammonia to obtain most of the data  shown in Figure 4-1,
                                    11

-------
    70
    60
                                      D
    50
o
\-
o
3
o
LU
 X
o
    40
    30
    20
    10
     700
                            cP
                            o
                           SIZE
      • 25 t/hr

      • 70 t/hr
      O 120 t/hr
DESCRIPTION

Package Boiler

Industrial  Boiler
      A 100 MWe   )  .......  D .,
      T 100 MWe   I  Utlllty Boiler

      D i en KM  }  Crude Heaters
      v 150 kbbl/d  j
                           1
                               _L
          800                 900

        FLUE GAS TEMPERATURE, °C


Figure 4-1  Performance of Thermal DeNOx systems
           in commercial applications.
                             1000
                                  12

-------
                                 SECTION  5

                              PROGRAM DETAIL

     This section provides  information regarding the boilers selected for
study in this program.   The NOX  reduction cases are discussed,  and the
initial  and final NOX levels for each case are noted.  Also provided is
information on the Thermal  DeNOx Performance Prediction Procedure utilized
in determining the effectiveness of the Thermal DeNOx Process in each case
studied.  The assumptions used for formulating the cost estimates for the
Thermal  DeNOx Process are noted  and other cost estimation information is
provided for the Thermal DeNOx process as well as for combustion modifi-
cations.

BOILERS  SELECTED FOR STUDY

     This EPA-sponsored  analysis has determined the applicability of Thermal
DeNOx to representative  coal  fired boilers of different manufacturers,
firing types, boiler sizes  and coal types.  The boilers/sizes/firing types
selected for study are shown in  Table 5-1.

     The boilers selected were within their size ranges among the most
commonly occurring in the U.S. power generation industry.  Four of the
boilers  fire bituminous  coal,  three subbituminous, and one lignite.  One
or more  boilers from each major  boiler manufacturer has been considered.
One boiler in the 330-350 MW range from each manufacturer has been studied.

NOX REDUCTION CASES

     This subsection notes  the two sets of final NOX target levels which
were used as well as the two initial NOX  levels which were assumed for
baseline-uncontrolled operation  and for combustion modifications.  The four
resulting cases plus two additional cases for maximum practical NOX
reduction are also noted.

Final NOX Levels
     Two sets of final  NOX reduction levels or targets were selected for
this study.  One group  included a trim to the proposed New Source Perform-
ance Standards (NSPS).   The other, a deeper reduction to low levels of NOX,

     The proposed NSPS  for NOX from coal firing are categorized by coal
type.  These standards  are shown below in both Ibs./MBtu and in ppm.  In
this case, the conversion used was NOX, Ibs./MBtu = ppm NOX (@ 3% 02)
x 0.00133 (4,5).
                                     13

-------
                 TABLE 5-1.  BOILERS SELECTED  FOR STUDY
Boiler
Manufacturer
Babcock and
Wilcox
Babcock and
Wi 1 cox
Babcock and
Wilcox
Combustion
Engineering
Combustion
Engineering
Foster Wheeler
Foster Wheeler
Riley Stoker
Boiler Type
Front Wall
Horizontally
Opposed
Cycl one
Tangential
Single Furnace
Tangential
Front Wall
Horizontally
Opposed
Turbo Furnace
Boiler
Size, MW
130
333
400
350
800
330
670
350
Coal Type
Subbituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Subbituminous
Bituminous

                              Proposed  NSPS
            Coal  Type
         Bituminous
         Subbituminous
         Lignite*
Ibs./MBtu

   0.6
   0.5
   0.6
450
375
450
         *  The proposed standard  for  cyclone  firing of North and
            South Dakota and  Montana Lignite is  0.8 Ibs/MBtu (600  ppm).
            This specific case will not  be  considered  here.

     The final  NO  targets were selected to provide an assessment  of
Thermal  DeNOx performance capabilities and  represent a deep reduction  in
NOX emission levels.   These NOX levels were also assumed to be a function
of the coal  type burned  and were:
                                    14

-------
                          Deep  Reduction  Targets

           Coal  Type              Ibs./MBtu              ppro

        Bituminous                    0.4                 300
        Subbituminous                 0.3                 225
        Lignite                       0.4                 300


Initial  NOX Levels

     The initial  NOX levels utilized  in undertaking this study were those
which are characteristic of the selected  types  and  sizes of  boilers firing
the coal types specified.  Most of the initial  values  were derived from
data obtained by Exxon  Research and Engineering Company on the program
"Field Testing:   Application of Combustion Modifications to  Control
Pollutant Emissions  from Power  Generation Combustion Systems"  sponsored
by EPA under Contract No.  68-02-1415  (4). Additional  data were furnished
by the boiler manufacturers.

     NOX levels  were extrapolated  for each boiler studied  under (a) re-
duced load and (b) with the application of combustion  modifications.   In
formulating these NOX levels, two  generalizations based on field test  data
(4_) were utilized:

     (1)  Reducing load by 25%  from full  load lowers NOX emissions by  10%.
          Reducing load by another 25%, to 50%  load lowers NOx emissions  a
          total  of 20%  in  ppm,

     (2)  The application  of combustion modifications  (CM) lowers NOX
          emissions  from an uncontrolled  level  by 40%  at each  load. CM
          are less effective than  this on cyclone boilers.  For the cyclone
          boiler studied,  CM were  assumed to reduce NOX emissions by 10%
          from the base case at each  load.

     A variety of combustion modification techniques are available for
most boiler types considered.   These  generally  can  be  used individually
or in combination to achieve the 40%  NO^  reduction  noted above.  For
example, low NOX burners which  are applicable  to  front wall  and horizontally
opposed fired  boilers  have been introduced  relatively recently and Exxon
Research has shown  that 40%  NOX reductions  are  possible relative to an un-
controlled case  in which conventional burners  are  used  (4_).   Low excess air
firing coupled with  the staging of burners  are  two  techniques also applicable
to these boiler  types.  Low  excess air  firing  can  reduce NOX emissions from
cyclone fired  boilers.  Low  excess air  firing  plus  the use of overfire air
ports are successful in reducing NOX  emissions  with tangential firing, a
combustion system which is inherently a  low NOX producer.  Overfire air
ports plus air vane  direction can  be  used to reduce NOX emissions in
turbofurnace boilers.
                                     15

-------
Cases Established

     As was noted above, one group of NOX reduction levels include a trim
to 450 ppm NOX (for bituminous coal and lignite firing) and 375 ppm NOX
(subbituminous).  These levels are the proposed NSPS levels for coal firing.
For trimming, two cases arise:

Case 1:  Combustion Modifications (CM) cannot be used and the intial NOX
         level is the uncontrolled baseline NOX level.

Case 2:  CM can be used with the result that the initial  NOX levels would
         be reduced.

The other group of NOX reduction levels specifies a deep reduction to 300 ppm
(bituminous and lignite) and 225 ppm (subbituminous).  Two additional cases
arise:

Case 3:  CM cannot be used.

Case 4:  CM can be used thereby reducing the initial NOX level.

     As can be seen, the above define the best case and the worst case for
the two general target NOX levels.  Thus, the estimates produced resulted
in a range of costs rather than in one specific level of cost for the trim
cases and for many of the deep reduction cases.  This should be of greater
utility than  one specific cost level.  (It might be argued that no boiler
of the types  considered here could be so inflexible as to be totally
incapable of  accommodating combustion modifications of some type.  This is
probably true.  However, for this evaluation we assumed this worst case.)
The actual  N0« levels investigated are shown in Table 5-2.  This table
illustrates that in certain cases, the target NOX levels are achievable
using combustion modifications alone.

     In addition to these cases to establish a  range of costs,  two additional
cases have  been considered.  These cases represent the maximum  NOX reduction
that can be achieved on a practical basis with  the Thermal DeNOx Process.
(Grid placement is assumed to be the same as in the other cases studied.)
The two new cases which can be formulated are:

Case 5:  Maximum NOX reduction attainable with  an ammonia to initial NOX
         molar ratio of 1.5.

Case 6:  Maximum NO  reduction attainable with  NH3/NOI = 1.5 with combustion
         modifications.

     In both cases 5 and 6, the final NOX levels attained may be either
greater than or less than the target NOX levels in the prior cases.

     Cost estimates for NOX reduction were  performed for  full load only.
                                     16

-------
                        TABLE  5-2.   INITIAL  AND  FINAL  NOX  LEVELS
                                    FOR  BOILER/COAL  COMBINATIONS
Boiler
Firing Method
Manufacturer and Fuel
8&W FW
Subbituminous


B&W HO
Bituminous


B&W Cyclone
Lignite


CE T-Single Furnace
Bituminous


CE T-Twin Furnace
Subbituminous


FW FW
Bituminous


FW HO
Subbituminous


RS Turbo Furnace
Bituminous


MM Case
130 1
2
3
4
333 1
2
3
4
400 1
2
3
4
350 1
2
3
4
800 1
2
3
4
330 1
2
3
4
670 1
2
3
4
350 1
2
3
4
100%
Initial
500
300
500
300
700
420
700
420
1000
900
1000
900
500
450
500
450
530
375
530
375
850
510
850
510
700
420
700
420
700
420
700
420
Load
Final
Target
375
375*
225**
225
450
450*
300**
300
450**
450
300**
300**
450
450*
300
300
375
375*
225**
225
450
450
300**
300
375
375
225**
225
450
450*
300**
300
75%
Initial
450
270
450
270
630
380
630
380
900
810
900
8TO
450
400
450
400
480
340
480
340
770
460
770
460
630
380
630
380
630
380
630
380
Load
Final
Target
375
375*
225
225
450
450*
300**
300
450
450
300**
300**
450*
450*
300
300
375
375*
225**
225
450
450*
300**
300
375
375*
225**
225
450
450*
300**
300
50X
Initial
400
240
400
240
560
340
560
340
800
720
800
720
400
360
400
360
425
300
425
300
680
410
680
410
560
340
560
340
560
340
560
340
Load
Final
Target
375
375*
225
225*
450
450*
300
300
450
450
300**
300**
450*
450*
300
300
375
375*
225
225
450
450*
300**
300
375
375*
225
225
450
450*
300
300
 *  NOX  level  is  either  below  the  target  level  or  can  be reached using combustion modifi-
    cations  alone.
**  MOX  level  cannot  be  reached with  Thermal  QeNOx alone, assuming 50% NOX reduction.
                                          17

-------
THERMAL DeNOx PERFORMANCE PREDICTION PROCEDURE

     This section provides some background information on the Performance
Prediction Procedure used to estimate the NOX reduction achievable using
the specified initial NOX levels and final NOX targets.  The sequence in
applying the predictive procedure which leads up to the cost estimation
steps is also discussed.  This is followed by some of the assumptions used
in undertaking the performance prediction.

     The selection of the locations where ammonia will be injected is
based on a number of factors which include:  flue gas temperature and
conditions, flow path geometry, the reaction time available and the suita-
bility of the reaction zone with repect to its dimensions and configuration
injector grid.  A Performance Prediction Procedure developed by Exxon
Research and Engineering Company was used to determine the locations of the
ammonia injection grids.

     The Exxon Performance Prediction Procedure is a multistep calculation
procedure which utilizes and/or determines the above noted factors.  The cal-
culation procedure can forecast the percent reduction in initial  NOX level
which would result from the location of an ammonia injection grid at any num-
ber of locations along the flue gas path.  The Performance Prediction
Procedure is based on fundamentals combined with pilot and commercial scale
experience.  For this EPfi-sponsored study program the required temperature
and dimensional information were supplied by the boiler manufacturers.   In the
case of an actual installation, after the tentative selection of the
location(s) of one or more grids using the Exxon procedure, an experimental
program would be conducted to measure temperature, flow and concentration
distributions in the reaction zone.  This information would then be used to
confirm or adjust as required the injector location selected and would be
utilized as input for the final injector design.

     The sequence of events in applying the Thermal DeNOx Performance
Prediction Procedure leading up to the cost estimating steps is listed
below.

1.  The Exxon Thermal DeNOx Performance Prediction Procedure was  applied
    using data supplied by the boiler manufacturers.

2.  The effectiveness of the Thermal DeNOx process was determined for
    most boilers studied at 3 loads:  100%, 75%, and 50%.  For each boiler
    and each load, two levels of NHa injection were considered.  These
    levels were expressed as a molar ratio of NHo to the initial  NOX level
    (NOI).  The two levels possessed NH3/NOI ratios of 1.5 and 1.0.

3.  Two initial NOX levels (both with and without combustion modifications)
    were established from data obtained by Exxon Research and Engineering
    Company on the program, "Field Testing:  Application of Combustion
    Modifications to Control Pollutant Emissions From Power Generation
    Combustion Systems" sponsored by EPA under Contract No. 68-02-1415.
    Some additional data were supplied by the boiler manufacturers.
                                      18

-------
4.  Two sets of final  NOX levels were utilized.   These were:   the proposed
    New Source Performance Standards  (trimming case)  and a  deep reduction
    case.  The use of  two initial  and two final  NOX levels  permitted  a  range
    of costs to be established for certain boilers.

5.  Two ammonia injection grid locations  were selected for  each boiler
    studied based on the results of the Performance Prediction Procedure.
    Thus, for each of  the two grid locations, the percent NOX reduction
    resulting from the use of two  levels  of NH3  was determined.

6.  For each grid location, a plot was made of percent NOX  reduction
    vs. NH3/NOI molar  ratio.  The  third point was assumed to  be the origin,
    zero.  Thus, for each boiler,  two curves were generated,  one for  each
    of the two injector locations. Both  lines terminated at  the origin.
    From these plots the quantity  of  NH3  required to  reach  the specified NOX
    reduction target could be determined.

     Some of the assumptions used  in  application of the Performance Predic-
tion Procedure are noted below.*

1.  There are two injector locations, one designed to serve two boiler
    loads, and the other to serve  one load.   The combination-load grid
    will operate for either the 50 percent/75 percent or the  75 percent/
    100 percent.load combination,  and the single load grid  will  operate for
    either the 50 percent or the 100  percent load.

2.  The combination-load grid is located  where the crossover  of the
    performance curves is a maximum.   The single-load grid  is then
    located where the  performance  curve peaks for the remaining load.
    An exception was made for the  CE  boilers where the combination-
    load grid (50/75 percent load) was placed at the  exit of  the firebox,
    and the single-load grid (100  percent)  was placed at the  peak of  the
    performance curve.  For this screening  study, performance calculations
    were done at the upstream boundary of each flue gas flow  path
    segment and a smooth curve was drawn  through the  predicted points.
    The length of the  cavity upstream of  the first tube bank  was set  at
    150 mm for the B&W 130 MW and  B&W 400 MW boilers.

3.  The carrier is air.

4.  The carrier temperature is 80°C at the feed  pipe  entry  point into the
    flue gas duct.

5.  Flue gas pressure  is 1 atmosphere.
   Certain aspects of the Thermal  DeNOx Performance Prediction Procedure are
   considered to be proprietary in nature and are not described in this
   report.
                                     19

-------
COST ESTIMATES

     This section provides details of how the cost estimates in this pro-
gram were performed.  Provided is specific information regarding ammonia
handling facilities, air compressors and the on-sites.  The assumptions
used in the estimation of Thermal DeNOx costs are noted as are details for
the cost estimates formulated for combustion modifications.

Thermal DeNOx Cost Estimates

     The cost estimates presented here are designed to illustrate the costs
associated with the Thermal DeNOx Process itself.  The techniques and proce-
dures used in producing these cost estimates were the same as would be applied
to a more completely defined project.  In the cases considered here the pro-
jects were not completely specified with  respect to a number of factors which
could have an impact on costs.  The Process was assumed retrofit-installed on
eight typical representative coal fired utility boilers.  It should, however,
be realized that each candidate boiler for the Thermal DeNOx Process must be
considered on an individual basis from both performance and cost viewpoints.
In general, the costs presented here emphasize the costs of the Process it-
self.  Certain costs which may be associated with the Process such as licens-
ing fees and certain preliminary engineering and testing are not included.

      Cost estimates were prepared for three  individual elements of the
 DeNOx  facilities:   ammonia handling  facilities, air compressors, and the
 "on-sites"  which  include the ammonia injection grids.  The costs are pre-
 sented as  of the  second quarter of 1977 and assume a U.S. Gulf coast loca-
 tion.

     Costs  for  three sizes of ammonia handling facilities were estimated
and the costs for  intermediate sizes were interpolated.  The three examples
assumed ammonia consumption at the rates of:  (Example 1) 330 lbs./hr.,
 (2) 1000 lbs./hr., and (3) 3000 lbs./hr.  Estimated were the costs of line
sizes, drum sizes, pump sizes, etc. with all facilities being commensurate
with the rated demand.

     The first two examples assumed receipt of ammonia in pressurized tank
trucks and the use of a single storage drum.  Example 3 assumed receipt in
pressurized rail cars and the use of three storage drums.  The unloading
pumps and lines were similar for all cases and the storage was sized for
seven days. The ammonia storage drums were designed to operate with a mini-
mum temperature of 50°F and were uninsulated.  Ammonia vapor was assumed
to be withdrawn from the storage drums at 90 psia and metered using up to
twelve lines as  dictated by the case in question.

     The total  breakdown in terms of material and labor is presented
below in thousands of dollars for each case.  To these costs were applied
a total erected  cost multiplier of 1.43 which includes field labor, over-
head and burden.   This  value is based on our actual  historical  data for
construction occurring  on  the U.S. Gulf Coast during the second quarter of
1977, the area  and period  selected for all  cost estimates.
                                     20

-------
             Example Number                 1         2        3
             Direct Material, k$           147       195      422
             Direct Labor, k$               53        55       93

               Total M&L, k$              200       250      515

               Total Erected Cost, k$     286       358      736

As was noted above, the  costs for  intermediate  sizes were  interpolated from
these total  erected cost values.

     The use of air as a carrier requires  the  installation of air  com-
pressors.  For the same  three examples  noted above, sizes  of compressors
required were (1) 1000 SCFM, (2) 6000 SCFM and  (3) 20,000  SCFM.  Compressor
costs were obtained from vendor quotes.  Other  material costs were associ-
ated with buildings, concrete, piping,  structural steel, instruments, paint,
etc.  The breakdown in terms of direct  labor expressed  in  thousands of
dollars is presented below.  Again, the  total  erected cost multiplier of
1.43 was applied  to these values resulting in  the total erected  cost.
Costs for intermediate sizes were  interpolated  from these  cost values.

             Example Number                 123
             Direct Material, k$           195       360      530
             Direct Labor, k$               35        45       60

               Total M&L, k$              230       405      590

               Total Erected Cost, k$     330       580      843

     The costs for on-site facilities ("onsites") including the  costs of
grids are based on our historical  experience in the construction of such
facilities.

     The assumptions used in cost  estimation are noted  below:

1.   Fixed costs  are total erected costs,  2nd  quarter 1977,  U.S. Gulf Coast,
     no escalation and no contingency included.

2.   Reagent fixed costs include NH3 storage vessel, vaporizer,  and piping.

3.   Carrier fixed costs include air compressor and  piping.

4.   Onsite fixed costs  include two  injector grids,  instrumentation and
     controls.

5.   Operating costs are for  DeNOx system  operation  at  100 percent load.

6.   The NH3/NOI  ratio   required  to  obtain a  specified  NO,, reduction  is
     calculated by  linear interpolation between the  NHs/NQI ratios of 1.5,
     1.0 and the  origin, 0.   These point constituted  the  performance  curve
     used.  NH3/NOI  =1.5 is  the  maximum NH3 rate  considered.  No  extrapol-
                                     21

-------
      ation to higher rates  was  performed.   In  practice, some molar  ratios
      used were between 0 and 1.0 and  other were between 1.0 and  1.5.

 7.   Calculated NH3 consumptions are  based on  nominal  initial  NOX levels
      and flue gas flow rates.   No adjustments  have  been made for variations
      in excess air levels and  flue gas  moisture content.

 8.   Reagent operating cost is  based  on an NHs cost of $85.00  per 1000  Ib.
 9.    Carrier rate for cost calculations  has  a  maximum value of 1.5% of the
      flue gas rate.   The total  carrier rate  is the  sum of the operating grid
      rate and the rate used for cooling  the  idling  grid.

10.    Carrier operating costs are calculated  as follows:  Air compressor
      power requirements are 1100 HP (820.6 KW) per  10,000 SCFM.   Electri-
      city cost is 0.03 $/KW-Hr.  Resulting carrier  operating cost is  $0.41
      per 10,000 SCF.

11.    Annual fixed charges are taken as 20% of investment.  This  figure
      includes finance costs and maintenance.  Annual  service factor is
      80% of full load.

12.    No licensing fees or royalties are  included.

13.    $/MM-Hr. is equivalent to  mills/KW-Hr.
      $/MW-Hr. = 10 times $/MBtu assuming a heat rate of  10,000 Btu/KW-Hr.

      The equations used in undertaking the Thermal  DeNOx cost estimates
 are shown in Table 5-3.

 Combustion Modification Cost Estimates

      The costs for combustion modifications  were derived from information
 furnished by Acurex-Aerotherm assembled  under  EPA contract  (6).   The  costs
 cover retrofit installation only.   The three techniques based on  combustion
 modifications were Low NOX Burners  (LNB),  Overfire  Air Ports (OFA), and
 Low Excess Air Firing (LEA). Derating was also considered.  Flue gas
 recirculation was not considered as this technique  is not overly  compatible
 with coal  fired boilers.  It was assumed that  for all boilers, the use of
 LNB or OFA coupled with LEA would be sufficient to  achieve the stipulated
 NOX reduction level.

     For cost purposes, it was assumed  that LEA firing had no net  cost
 since (1)  this firing mode can  be implemented  relatively cheaply  with low
 capital and operating costs, (2) a  fuel  savings and cost credit will  result
 in  most cases after  LEA firing  is implemented, and  (3) many utility oper-
 ators are already using LEA firing.

      The general  assumptions used by Acurex-Aerotherm included:

      -  Operation for 7000 hours/year  at or  near full load
      -   Unit  five years old
                                     22

-------
                      TABLE 5-3.  THERMAL DeNOv COST CALCULATIONS
                                             A
• Initial  N0«
              (ppm)
              (ppm)
Input from Table 5-2
t Target NOV
Input from Table 5-2
• Flue Gas Rate (kL /Hr)
                                     Input  from Boiler Manufacturers
• NOX Reduction Required
    - Percent
                                     =  (1-Target N0x/Initial  NOX) x (100)
                                        Initial  NOy-~
                                      = [I
                                                 ]05
                                                                   28.8
                                                                        x (1000.) x
• Reagent Rate
    - NH3/NOi (Molar Ratio)
    - H2/NH3 (Molar Ratio)

    - NH   (kLb/Hr)
    - H2   (kLb/Hr)
                                         From  Thermal  DeNOx Performance Prediction Procedure

                                                                 Flue\
     te ~RF/ x \ NH7/ x VTTTo
                                      ^ Rate ~RF
• Carrier Rate (Air)
    - (SCFM Per Nozzle)
    - (SCFM Total)
                                                    x  (0.484)=(9.7)x(0.484)=4.69  fjjj

                                                                                 Percent
                                                                                  Load
                                        (SCFM  Per  Nozzle)  x  (No.  Nozzles)
• Operating Cost

    - MH3 ($/Hr)


    - Carrier ($/Hr)
    - Total  Operating Cost ($/Hr)
                                      I   J  it£J  y ($§L\
                                      \Rate Hr /  x ULb/
                                     _  [Carrier   <-rrM\ „  (   1   ^
                                     -  V  Rate    SCFMy x  tooo7
                                                                           TW SCFn
                                             ,)
                                     =   NH3  +  Carrier
                                                          /0.746 KW)   /$0.03)
                                                          \      HP7 x \KW-Hr/
• Fixed Cost

    - NH3 (k$)

    - On-Sites

    - Carrier (k$)

    - Total  (k$)
                                     =   Exxon  Cost Estimating

                                     =   Exxon  Cost Estimating

                                     =   Exxon  Cost Estimating

                                     =   NHg +  On-Sites + Carrier


NOTE:   See assumptions  Used  in  Cost Estimation for Further Details
                                              23

-------
                         THERMAL DeNOx  COST CALCULATIONS  (CONT'D)
• Equivalent Costs
    - Cost ($/Lb  AN02)
        Operating Cost

        Yearly Fixed Cost

        Total Cost

    - Cost ($/MW-Hr)
        Operating Cost
        Yearly Fixed Cost

        Total Cost
Total  Operating Cost ($/Hr)/NOx  Reduction Required
(Lb  AN02/Hr)
Total  Fixed Cost (k$)  x /oil/Sit?;2^  x N0x  Reduction
(Lb  AN02/Hr)           (24}(365)(O.B)

Operating Cost + Yearly Fixed  Cost
Total  Operating Cost ($/Hr)/MW rating
Total  Fixed Cost (k$) x (24)(36^(0%  *  M"  rating

Operating Cost + Yearly Fixed Cost
                                            24

-------
     -  Remaining  life of 25 years  for accounting purposes

Indirect operating costs  include depreciation expense,  taxes,  cost  of
capital and insurance. These costs are thus  very similar to the  capital
costs used by Exxon and will be designated as such.   Direct operating  costs
depend somewhat on the nature of the combustion  modification technique
but include any extra  costs  for fan power where  used,  increased maintenance,
and a change for decreased unit efficiency where that occurs.  These costs
are quite similar  to the  operating  costs used here and will be designated
as such.

     Acurex-Aerotherm  established two different  costs for the  retrofit
installation of OFA ports.   These costs depended upon the boiler  firing
type and were lower for tangential  than for wall fired units.   For  cost
estimation purposes, it was  assumed that the  costs of installing  overfire
air ports in a Turbo furnace boiler was the same as  for a wall fired
unit.  The LNB and OFA costs established by Acurex-Aerotherm in units  of
$/KW-Yr. were converted to mills/KVI-Hr. in order to  conform to the  other
data presented herein. The  values  in both units are presented in Table  5-4.
              TABLE  5-4.   COSTS  FOR  COMBUSTION  MODIFICATIONS
                          ESTABLISHED  BY  ACUREX-AEROTHERM
Operating
Capital

    Total
                                                 Overfire  Air  Ports
                 Low NOx  Burners
                         Tangential
                                     Turbo
               $/KH-Yr  mills/KM-Hr   $/KM-Yr  mills/KM-Hr  $/KW-Yr mil is/KM-Hr
0.40
0.01
0.05

0.06
0.32
0.21

0.53
0.05
0.03

0.08
0.52
0.16

0.68
0.08
0.02

0.10
     The derating of a boiler will  also  result  in  reduced emissions of NOX.
As will be apparent, derating is  very expensive and  consequently would be
used only as a last resort when other combustion related procedures cannot
achieve target NOX levels.  Derating  will  not be considered for use in
association with Thermal  DeNOx, although it will be  utilized for comparative
purposes in a subsequent section.

     The basic costs for derating were also furnished by Acurex-Aerotherm
(6).  Acurex-Aerotherm considered staged combustion  in which burners would
be removed from service, thereby  derating the boiler by an amount equal to
20% of capicity.  The operating cost  thus is largely the purchase of make
up power which Acurex-Aerotherm assumed was purchased at 2.5<£/KW-Hr.  Acurex-
Aerotherm believes that this value approximates the cost of generating
electricity.  Transmission costs  were assumed to be minimal at O.U/KW-Hr
yielding a total cost for purchased power of 2.6<£/KW/Hr.  Other factors
included in the operating cost are a  fuel credit for fuel not used and a
very minor loss in efficiency. Aerotherm estimated the operating cost to
be $24.78 KW/Yr.
                                     25

-------
     The capital cost figure determined by Acurex-Aerotherm reflects the
lost capacity.  The boiler has been financed on the basis of full  rated
output but because the boiler has been derated either, (a) a longer period
will be required to recover this financial quantity or Cb) an increased
rate of recovery over the same period must be used.  The capital  charge
thus represents a lost capital charge.

     The Acurex-Aerotherm values were converted to the bases used here and
the results are presented in Table 5-5.
                   TABLE 5-5.  COSTS FOR BOILER DERATING
                           Derate by 20% - Burners out of Service
                                $/KW-Yr
         Operating
         Capital

              Total
            30.12
                                n>ms/KH-Hr
                 4.30
     It was assumed that either low NOX burners or the use of overfire
air, perhaps in combination with LEA firing as required, were sufficient to
reach the initial NOx level designated.  The combustion modification which
was used for each boiler type is shown in Table 5-6.


                   TABLE 5-6.  COMBUSTION MODIFICATIONS USED TO
                                    REDUCE INITIAL NOX LEVELS
           Boiler
Manufacturer
Size
Combustion Modification
    B & W



    CE


    F-U


    RS
130
333
400

350
800

330
700

700
    Low NOX Burners
    Low NOx Burners
    Low NOX Burners

    Overfire Air
    Overfire Air

    Low NOX Burners
    Low NOX Burners

    Overfire Air
                                     26

-------
                                  SECTION  6

                            RESULTS  AND  DISCUSSION


     The feasibility and  costs  for using the Exxon  Thermal  DeNOx  Process on
eight representative coal  fired utility  boilers  was established for  several
target NOV levels.   These target NOX levels included:
         A

     a.  Reduction  by trimming  to the proposed New  Source Performance
         Standards  (NSPS) of 0.6 Ib  NOx/MBtu  (450 ppm  NOX)  for bituminous
         and lignite fired boilers and 0.5 1b NOx/MBtu (375 ppm NOX) for
         boilers fired with subbituminous  coal.

     b.  Deep reduction in NOX  levels to 0.4 Ib  NOx/MBtu  (300 ppm NOX)
         for boilers fired with bituminous coal  and lignite and to 0.3  Ib
         NOx/MBtu (225 ppm) for subbituminous fired boilers.

     In summary, this analysis  projected that the proposed  NSPS could be
met by all boilers  studied using the  Thermal  DeNOx  Process  alone  and that all
boilers, except the  cyclone boiler fired with lignite, could meet the deep
reduction target using Thermal  DeNOx coupled with combustion modifications.
The performance of  the Thermal  DeNOx process was considered to be essentially
equivalent for all  boilers evaluated even  though significant differences
existed in flue gas temperature profiles and flow path configurations among
boilers.  These differences resulted in  the selection  of  significantly
different injection grid  locations among the boilers of different manu-
facturers.

     It was projected that the  ammonia injection grid  location would not be
affected significantly hy assuming a  50°C  larger temperatue range in the
injection plane than that used  for baseline calculations.   However,  a tempera-
ture range increase  of this size would reduce DeNOx performance by 5 to 10
percentage points (e.g. from 50% to  40-50%).  It was also  found that total
NOX removal  costs increased when hydrogen  (rather than dual  grids) was  used
with" only one grid  to realize effective  DeNOx at lower than full  boiler loads.

     Other specific  projections and  conclusions  were as follows:
•  All units could reach the proposed NOX NSPS using Thermal DeNOx alone.
   Some units could also reach this level  using combustion modifications
   alone.
                                     27

-------
•  All  units except one could meet the deep NOX reduction target when Thermal
   DeNOx was used in combination with combustion modifications.  The one ex-
   ception was the cyclone boiler fired with lignite.
•  Projected costs to reach the proposed NSPS from an uncontrolled base level
   ranged from 0.25 mills/KW-Hr for the 250 MW CE boiler to a high of 1.17
   mills/KW-Hr for the lignite fired cyclone boiler.  The average cost for all
   boilers considered was 0.57 mills/KW-Hr, or 0.49 mills/KW-Hr not including
   the cyclone boiler.

•  Four of the eight boilers could reach the deep reduction target using
   Thermal DeNOx alone.  Costs ranged from 0.38 mills/KW-Hr to 0.83 mills/KW-
   Hr for these boilers.

•  Projected costs to reach the deep reduction target using Thermal DeNOx with
   combustion modifications ranged from 0.38 mills/KW-Hr to 0.51 mills/KW-Hr
   with the average being 0.44 mills/KW-Hr for the seven boilers reaching the
   target level.

•  NOX reductions ranging from 62% to 76% and averaging 70% relative to an un-
   controlled base case could be achieved using Thermal DeNOx at a maximum
   practical level in combination with combustion modifications.  NOX levels
   in the 0.20 to 0.23 Ib.  NOx/MBtu range could be realized for most of the
   boilers.  Costs ranged from 0.55 to 1.14 mills/KW-Hr and averaged 0.68
   mills/KW-Hr for all  boilers studied.   With the lignite boiler excluded the
   range was 0.55 to 0.67 mills/KW-Hr and the average was 0.61 mills/KW-Hr.

•  The costs for onsites and the carrier were found to be proportional to
   boiler size.

t  The total  ammonia reagent costs for all  cases normalized for the mass of
   NOX removed expressed as N02 (ANOX) were nearly equal for all eight units
   studied at 0.09 $/lb.ANOx.   This parameter was considered to be a good
   overall judgement criterion of the chemical  efficiency and economic effis
   cacy of the Thermal  DeNOx process.

•  The Exxon Thermal DeNOx Process was considered to be equally amenable to
   all units studied.

•  The costs for reaching NOX levels in the 0.3 to 0.4 Ib./MBtu range were
   compared for Thermal DeNOx and combustion modifications.  The costs of most
   conventional combustion modifications and combinations thereof were lower
   than that of Thermal DeNOx.  Extreme NOX reduction methods such as derating
   or staged combustion that incurred derating would be more expensive.
   Derating would not generally be used as a NOX reduction technique.

   The practical effectiveness of Exxon Thermal DeNOx process can  be determined
from  several evaluations which were  performed during this  study.   These are:

 1.  The percent reduction  in  NOX levels predicted  by the Thermal  DeNOx
     Performance Prediction  Technique.
                                      28

-------
2.  The  feasibility and costs  for reducing NOX emissions to the specified
   target NOX levels, with and without combustion modifications.

3.  The  maximum reduction  in NOX levels achievable and the costs required
   to accomplish this reduction.

4.  The  total ammonia operating costs normalized to the cost per pound of
   NOx  removed.

5.  Comparison of costs for Thermal DeNO  with costs for combustion
   modifications to reach 0.3 to 0.4 1b. NOx/MBtu.

6.  The  effect of unanticipated temperature gradients  in the plane of
   ammonia  injection on Thermal DeNOx performance and grid placement.

7.  Load following using hydrogen along with ammonia rather than using
   multiple grids.

     The results obtained in  each  of these areas are  presented in the
following subsections.

PREDICTED PERCENT NOX REDUCTION LEVELS

     The Thermal DeNOx Performance Prediction Procedure has been discussed
above.   In summary, this calculational procedure utilizes boiler dimensional
information,  flue gas mass flow, temperature and critical residence times
to  arrive at a predicted value for  maximum percentage  NOX reduction as a
function of  ammonia injector grid location.


     The percentage NOX reduction  which  could  be anticipated  for  each of
the eight boilers as predicted using the  Exxon  procedure with  NH3/NOX
molar ratios of 1.0 and 1.5  has  been calculated. The  results  have been
determined for 100% load and in most cases one  or more lower loads.  The
results  obtained are presented in Table  6-1.

     The percentage NOX reductions calculated  for the coal fired  utility
boilers  studied operating  at full load averaged  44.6%  at the molar ratio
of 1.0.   The range for all boilers  considered was 41-47%.  At  a molar ratio
of 1.5,  the  average  DeNOx  performance  increased  to about 57.5%.    In this
case, the range extended from  54 to 63%.  These  results may be considered to
be typical of DeNOx performance.
                                    29

-------
            TABLE 6-1.  PREDICTED THERMAL DeNOx PERFORMANCE ACHIEVABLE
                                   AT FULL, 75% AND 50% LOAD
                                           Percent NOX Reduction at Boiler
                                           Load and NH3/NOI Ratio Indicated
        Boiler                               100%         75l50l
  Manufacturer     MW	Coal Type      1.5  1.0    1.5  1.0    1.5  1.0
B&W
B&W
B&W
CE
CE
F-W
F-W
130
333
400
350
800
330
670
Subbituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Subbituminous
52
63
58
58
57
54
60
42
48
43
45
45
41
47
52
57
58
52
52
•• •*
__
42
44
43
40
40
_ ^
-_
63
57
—
48*
50*
_ _
	
50
44
—
37*
38*
• «
__
      RS           350    Bituminous       58   46     —   —     54*  45*
  *60% Load
     It should be noted that the temperature profile and flow path con-
figuration for the Riley Stoker boiler differed considerably from the other
boilers considered and from the temperature patterns used in formulating
the Thermal  DeNOx Performance Prediction Procedure.  As a consequence, the
values for the performance of the Thermal DeNOx process on this unit and the
values of costs which derive from these should be considered to be subject
to a greater degree of uncertainty than the other boilers studied.

     Application of the Performance Prediction Procedure revealed that
there are definite differences from manufacturer to manufacturer in the
flue gas temperature profiles and flow path configurations.  For example, the
injection grids would be located closest to the furnace exit for the CE units
and furthest downstream for the F-W units.  As was noted above and will be
stated later, the performance (and costs) were effected only minimally by
these configurational differences


FEASIBILITY AND COSTS

     The feasibility of using the Exxon Thermal DeNOx process and the
resulting costs required to reach (a) a final NOX level where NOx emissions
would be "trimmed" and (b) where a significant reduction would be made in
NOy emissions have been evaluated.  As noted earlier, the trim case called
                                     30

-------
for reducing  NOX  emissions to 450 ppm NOX for bituminous coal  and lignite
firing  and  375  ppm  NOX for subbituminous.  These are the proposed NSPS
levels.   The  other  group of NOX reductions required would be significant,
to 300  ppm  NOX  for  bituminous and lignite and 225 ppm NOX for  subbituminous.
In order  to fully evaluate the capabilities for the Thermal  DeNOx process
to meet the target  levels and to establish a range of costs  where practical
two initial NOX levels were considered:  one in which NOX emissions were
uncontrolled  and  the other in which combustion modifications were used.   Thus,
four cases  were formulated:

Case 1:   Combustion modifications (CM) cannot be used and initial NOX
         level  is baseline NOX level.  Trim case.

Case 2:   CM can be  used to reduce initial NOX levels.  Trim  case.

Case 3:   CM cannot  be used.  Deep NOX reduction case.

Case 4:   CM can be  used.  Deep NOX reduction case.

     By the use of  this approach, a range of costs has been  established
for those cases where appropriate NOX reductions could be achieved.  The
nature  of the combustion modification utilized for each boiler was noted
earlier.  A summary of the results obtained is presented in  Table 6-2.
Additional  detail summarizing the costs of ammonia, carrier  and the onsite
cost are  presented  in Appendix 1.

     The  costs  presented here are for those representative boilers selected
for study.  It  should be recognized that each potential candidate boiler
for the Thermal DeNOx process must be studied on an individual basis.

     Table  6-2  shows that at full boiler load and without combustion modifica-
tions,  the  NOX  emissions from each boiler can be reduced to  the NSPS NOX
target  using  Thermal DeNOx.  The costs for the application of the Exxon  Thermal
DeNOx process for the Case 1 trim cases ranged from a low of 0.25 mill/KW-Hr.
for the 250 MW  CE boiler to a high of 1.17 mills/KW-Hr. for  the lignite  fired
cyclone boiler.   The cost for this boiler was more than double that for
almost  all  the  other boilers.  Excluding the lignite boiler, the average
cost was  about  0.49 mills/KW-Hr.; with the lignite boiler included, the
average cost  was  just over 0.57"mills/KW-Hr.  The high cost  for the lignite-
fired boiler  can  be attributed to the very high initial NOX  level assumed
for this  boiler.  The costs of reducing NOX emissions from an uncontrolled
baseline  level  to the proposed NSPS depends upon a number of considerations
including initial NOX level.  This will significantly influence the cost
for the ammonia used.  Examination of the data in Appendix 1 reveals that
unit size can have  some influence on the on-site cost and that the carrier
cost is generally proportional to the flue gas flow rate.  The inherently
low NOX emissions from the CE tangentially fired boilers are responsible
for the low Thermal  DeNOx costs determined for these units.

     With combustion modifications, the NSPS NOX targets can also be reached.
In fact,  for  five of the eight boilers, this target NOX level  can be achieved
                                      31

-------
TABLE 6-2.  COSTS FOR REDUCING NO,, EMISSIONS OF COAL FIRED UTILITY BOILERS USING THERMAL DeNOx1",
Trim Cases
Case 1
W/0 Comb.
Manuf .
B&W


CE

F-W

RS
*
Thermal

Target
t Thermal
Size
MW
130
333
400
350
800
330
670
350
DeNOx

, Firing
Type
FW
HO
Cyclone
Tan
Tan
FW
HO
Turbo
Case 2
Mod. With Comb. Mod.
Deep Reduction Cases
Case 3 Case 4
W/0 Comb. Mod. With Comb. Mod.
Coal Initial Cost Initial Cost Final Initial tost imnai
Type NO- "nm mm/ KW-Hr Nfl- . DOTI H11 1 s/ KW-Hr NOv. opm NO*. POTH1lls/KW-Hr NOx, ppm
Subbit.
Bit.
500
700
L1g. 1000
Bit
Subbit.
Bit
Subbit.
Bit
not required. Final


500
530
850
700
700
NOX level

0.49
0.45
1.17
0.25
0.34
0.71
0.63
0.54
attainable

300 0.06*
420
900
450
375
510
420
420
using

0.06*
0.99
0.08*
0.08*
0.33
0.31
0.10*
375
450
450
450
375
450
375
450
500 ** 300
700 0.63 420
1 000 ** 900
500 0.38 450
530 0.62 375
850 ** 51 0
700 ** 420
700 0.83 420
tost i-inai '
Mills/ KW-Hr NOx. ppm
0.47 225
0.38 300
** 300
0.42 300
0.42 225
0,50 300
0.51 225
0.45 300
Percent
Reduction
From
Jncontroll ed
Case
55
57
"*"
40
58
65
61
57
combustion modifications.





NOX level cannot be reached.
DeNOx
costs do
not include
1 icensing fees and
charges
for preliminary
engineering and testing.

-------
using combustion modifications  alone.   Because the cost of simple combustion
modifications  is far  smaller  than  that of Thermal  DeNOx, combustion modifica-
tions would represent the  preferred,  cost effective approach for these boilers.
In fact, only  three boilers required  use of the Thermal DeNOx process, the
400 MW B&W boiler  firing lignite and  the two F-W boilers.  As was noted
previously, the lignite boiler  has a  very high initial  NOX level, and in all
cases studied  meeting NOX target  levels would be either expensive or
impossible.  In this  case, the  use of combustion modifications lowers the
cost of Thermal DeNOx by about  16%.  Still  the cost of Thermal DeNOx for
this unit using Case  2 NOX levels  is  about three times as great as for any
of the other units studied.   The combination of boiler size and coal type
selected for the F-W  Boilers  (resulting in the NOX levels specified) is
probably responsible  for the  requirement to use Thermal DeNOx in these
cases.  Here,  however, the use  of  combustion modifications serves to reduce
the cost of Thermal DeNOx  by  55% for  the 330 MW boiler and by 52% for the
670 MW unit.

    The reduction of NOX  in  Case  3 is the most difficult because of (a)
the high initial NOX  levels and (b) the deep reduction target.  In fact,
in this case only  half of  the boilers studied were able to achieve the
target NOX levels.  The Thermal DeNOx costs for those boilers which met the
target ranged  from 0.38 to 0.83 mills/KW-Hr.  Because so few boilers were
able to meet this  target,  additional  cases were established for the maximum
reduction in NOX emissions which could be achieved.  These cases are dis-
cussed in the  following subsection.

    Case 4 considers a deep  reduction in NOX emissions achievable by
Thermal DeNOx  in conjunction  with  combustion modifications.  In this case,
all boilers except that firing  lignite met the target NOX level.  It is
interesting to note that the  cost  spread in this case was rather narrow,
ranging from 0.38  to  0.51  mills/KW-Hr. with the average being 0.44 mills/
KW-Hr.  This average  cost  is  lower than the average cost determined for
Case 1 where the NOX  target was not as low and combustion modifications
were not utilized  to  lower the  initial NOX level.  The overall NOx reductions
achieved by the combination of  Thermal DeNOx and combustion modifications
from an uncontrolled  base  case  ranged from 40% to 65% with the average
reduction approximating 56%.   Thus, the combination of Thermal DeNOx and
combustion modification was found  capable of meeting deep reductions in NOx
emissions on existing boilers with a  wide range of sizes, from all manu-
facturers, utilizing  different  firing types and, with the exception of
lignite fired  in a cyclone boiler, all fuels.

MAXIMUM REDUCTION  OF  NOX LEVELS

     In addition to the four  cases noted previously, two additional cases
were studied in which NOX  was reduced to the lowest level attainable by
Thermal DeNOx  as specified by the  Performance Prediction Procedure with
the injector grid  at  the location  selected for full load (i.e., the grid
location was the same as in the cases noted previously).  Thus two additional
cases  are defined:
                                      33

-------
Case 5:  Maximum DeNOx without combustion modifications.

Case 6:  Maximum DeNOx with combustion modifications.

     Without CM, Case 5, the percent NOX reduction realized ranged from 50
to 59%.  Costs ranged from 0.57 mills/KW-Hr. for the small CE boiler to
1.23 mills/KW-Hr. for the lignite  boiler; most cases were in the 0.57 to
0.87 mills/KW-Hr. range, the high  value for lignite again being attributable
to the high initial NOX level.  The results for all boilers are presented
in Table 6-3.

     Combustion modifications, plus Thermal DeNOx, Case 6, combined to reduce
NOX levels an average of 70% from  the uncontrolled base case.  The ranges
extended from 62 to 76% reduction  in NOX.  Final NOX levels in the 150 to
175 ppm range were realized for five of the eight boilers.  Again the lignite
boiler was a significant NOX producer, possessing final NOX emission level
greater than twice that of the five boilers noted above.

     In terms of cost, the lignite boiler had a total cost of 1.14 mills/KW-
Hr.  The cost for all  the other boilers fell  in the rather nerrow range of
0.55 to 0.67 mills/KW-Hr., again about half the cost of the lignite boiler.
Excluding the lignite boiler, the average cost was 0.61 mills/KW-Hr.  Includ-
ing the lignite boiler, the average cost increased to 0.68 mills/KW-Hr.

NORMALIZED AMMONIA AND OTHER OPERATING COSTS

     The total ammonia reagent costs expressed on the basis of the quantity
of NOX removed is an excellent measure of the efficiency of the Thermal
DeNOx Process for combustion equipment.  Specifically,  for coal  fired utility
boilers, this study found that when ammonia-related costs were normalized
with respect to the pounds of NOX removed,  NOX:

•  Total reagent costs were nearly equal for all units in all cases at
    0.09 $71b. NOX removed.

•  Operating costs for all units in all cases approximated 0.08 $/lb. ANO .
                                                                         J\

•  Capital costs for all units in all  cases were about 0.01 $/lb. ANO .
                                                                     /\

     These costs are presented in Appendix 1  for each case considered for
each boiler.  The range of ammonia operating costs for each case considered
for each boiler is shown in Figure 6-1.  The small differences in Thermal
DeNOx efficiency which made some units slightly lower than the average
values noted above were not considered to be significant.

     Of the ammonia cost, approximately 10% represents capital investment
for the storage facilities, and the balance is the operating cost for the
ammonia supply.  At lower ammonia rates (such as less than approximately
                                     34

-------
CO
01
           0.15
   0.10
        CM
       O
       00
       ,1
       CO
       o
       o
       o
a:
LU
    0.05
       o
       s
       S
       <
             COST COMPARISONS 100 PERCENT LOAD
               COST RANGE)
           FOR ALL CASES
TRIM TARGET
WITHOUT COMBUSTION MODIFICATIONS
                                               1
                                             1
                 RATING (MW)
                 MFC
                 COAL TYPE
                          130
                          BW
                        SUBBIT.
          330   333  350  350     400
          FW   BW   RS   CE     BW
          BIT.   BIT.  BIT.  BIT.     LIG.
  670     800
  FW     CE
SUBBIT.  SUBBIT,
                                Figure 6-1  Ammonia operating costs  for boilers studied.

-------
                                  TABLE  6-3.  MAXIMUM  PRACTICAL  NO^  REDUCTION ACHIEVABLE  USING  THERMAL  DeNOxt
Case 5
Without Combustion Modifications
Boiler
Manuf .
B&W


CE

F-W

Size,
HW
130
333
400
350
800
330
670
Firing
Type
FW
HO
Cyclone
Tan
Tan
FW
HO
Coal
Type
Subt.1t.
Bit.
Lignite
Bit.
Subblt.
Bit.
Subblt.

Initial
Level ,
ppm
500
700
1000
500
530
850
700
NOx
Final
Level ,
Ppm
250
290
430
210
230
390
290

Percent
NOX
Reduction
50
59
57
58
57
54
59
Total
Cost
M^ls/KW-Hr
0.71
0.70
1.23
0,57
0,62
0.82
0.87
Case 6
With Combustion Modifications

Initial
Level,
ppm
300
420
900
450
375
510
420
NO*
Ffnal
Level ,
ppm
150
175
385
190
160
230
170

Percent
NOX
Reduction
50
58
57
58
57
55
59
Total
Cost,
Mlls/KW-Hr
0.60
0.55
1.14
0.61
0.59
0.62
0.65
Percent
Total NOx Reduction
Possible From
Uncontrolled Case
70
75
62
62
70
73
76







RS        350    Turbo     Bit.        700      295        58          0.84         420      175        58
t Thermal DeNOx costs do not Include licensing fees and charges for preliminary engineering and testing.
0.67
                    75

-------
1000  Ib/Hr)  the  facilities  cost is  a greater fraction of the total  as
expressed  on a KW-Hr.  basis.

     Other categories  of cost items (carrier cost and on-site costs) deter-
mined were considered  to be related to boiler size rather than to the
efficiency of NOX  removal as  was the reagent cost (see Figure 6-2).  The
carrier cost, for  example,  was found to be a function of flue gas flow rate.
The latter value was found  to be roughly proportional to unit size.  Normal-
ized  carrier cost  was  found to be nearly constant for all units at 0.14
mills/KW-Hr.  Approximately half of this cost was capital investment and
half  was operating cost.

     The on-sites  costs  which includes the cost of the ammonia injection
grid  was found to  be a function of unit size.  Normalized, the on-site
capital investment was found  to be in the range of 0.04 to 0.05 mi11s/KW-Hr
for all units, except  for the smallest B&W boiler.  The normalized cost for
this  boiler  was  approximately double that of the average.

COST  COMPARISON  OF THERMAL  DeNOx WITH COMBUSTION MODIFICATION TECHNIQUES

     A reliable  comparison  of the costs of Thermal DeNOx versus extreme
combustion modifications required to reduce NOX emissions to the 0.3 to 0.4
Ib/MBtu range would be very valuable.  Unfortunately, as of this writing,
no publically disseminated  information is available from the boiler manu-
facturers  concerning the cost of combustion modifications to reach NOx
levels within this range.   In general, combinations of several combustion
modification techniques  will  be required to reach the NOX levels noted above.
In section 5, the  costs  for several combustion modification techniques were
developed.  These  costs  can be applied to available NOX reduction information
obtained on  utility boilers.

     One example presented  below describes the use of low NOX burners plus
the extreme  combustion modification technique of derating to reach the 0.4
Ib/MBtu NOX  range. The  other describes the use of two conventional combustion
modification techniques, low NOX burners combined with overfire air, to reach
the same level.

     The first example considered here is that of the use of low NOX burners
plus derating.   Actual performance data has been obtained under EPA contract
by Exxon Research  on a 270  MW B&W boiler with horizontally opposed firing
of eastern bituminous  coal  (4J.  Data were obtained  (a) before and after the
installation of  low NOX  burners (LNB) and (b) using LNB in combination with
derating of  the  boiler by about 20% by shutting off one row of coal pul-
verizers  (Run 37 in reference 4_).  Table 6-4 presents the data obtained.
                                      37

-------
CO
00
CO

o
                  LJ
    0.40
                  I
                  a
                  LU
                      1.20
                      1.00
                      0.80
                      0.60
                      0.20
                         0
              AMMONIA I
                Operating
                  Capital
                                CARRIER
                                  Operating
                                   Capital
                                ONSITES
RATING (MW)    130
MFC           BW
COAL  TYPE   SUBBIT.
                                            1
                                                              m

                                                    330 333 350 350   400
                                                    FW  BW   RS  CE    BW
                                                    BIT. BIT. BIT. BIT.   LIG.
                                                               670    800
                                                               FW     CE
                                                             SUBBIT. SUBBIT.
                                        Figure 6-2  Cost comparisons  for trim target
                                      without combustion modifications  - 100 percent  load.

-------
                 TABLE 6-4.  NOX LEVELS ON 270 MW B&W HO BOILER
                                      NOX Level
                                            1b/MBtu
Uncontrolled
Low NOX burners
Low NOX burners + Derate
600
375
300
0.8
0.5
0.4
270
270
208 (23% derate)
In this  case derating the boiler by 23% reduced NOX levels to the 0.4 1b/MBtu
(300 pptnj  NOX.   This example is very similar to that of the B&W HO 333 MW
boiler firing bituminous coal considered in this study.  The initial NOX
level  was  700 ppm for this boiler and in Case 4, the final level was 300 ppm.
The cost calculated for Thermal DeNOx plus combustion modifications (low NOX
burners) was 0.38 mills/KW-Hr.  For low NOX burners plus derating the cost
would  be:   4.30 + 0.06 mills/KW-Hr = 4.36 mills/KW-Hr.  Thermal DeNOx is
obviously  far cheaper than the case presented here because of the very high
cost of  derating.  If the staging of burners to achieve target NOX levels
results  in less than full load (thus effectively derating the boiler), the
costs  for  staging can be expected to be similar to the derating case illus-
trated here.

    Another example is that described by Vatsky (7) of a Foster-Wheeler
265 MW bituminous-fired utility boiler retrofitted with overfire air ports
and F-W  low NOX burners.   Even with conventional, high turbulence burners,
this boiler possessed an initial  NOX level  which was within the 600-650 ppm
NOX (0.8 Ib NOx/MBtu) range.  This low initial  level  was ascribed to the
large, conservatively designed fireboxes which  this unit possessed.  Under
normal operating  procedure for this boiler, NOX levels were in the 300-350
ppm (0.4 Ib NOx/MBtu) range using the low NOX burners and with the overfire
air ports  open  no more than 20%.   (Still  lower  emissions could be attained
by this  boiler  -  down to  200-225  ppm NOX -  with overfire air ports fully
open,  but  unburned carbon emissions and slag deposits increased.)  The
applicable  NOX  levels are presented in Table 6-5.

                 TABLE 6-5.  NOX  LEVELS ON  265  MW F-W HO BOILER
                                       NOX  Level
                                   ppm         1 b/MBtu	Reduction
Uncontrolled
Overfire Air Only
Low NOX Burners Only
OFA + LNB
600
425
375
300
0.83
0.56
0.50
0.40
„
32
40
^ rt
50
                                     39

-------
     The costs for accomplishing this reduction in NOX using previously
stated values are:

                  Low NOX Burners         0.06 mills/KW-Hr
                  Overfire Air Ports      0.10 mills/KW-Hr
                       Total              0.16 mills/KW-Hr

     The value of 0.16 mills/KW-Hr is clearly lower than any of the Thermal
DeNOx costs required to reach the 0.4 Ib/MBtu range.  It should be noted,
however, that neither of the combustion modification techniques used here
could be regarded as extreme, but were rather quite conventional.

     In general, it can ,be stated that the costs required to achieve low
NOX emission levels will be dependent upon the boiler and the modifications
which can be applied on a practical basis.  The examples presented here
illustrate a range of costs to reach the stated low levels of NOX, some
greater than and some less than Thermal DeNOx.  Where combinations of simple
combustion modifications can be applied successfully to reach the target
levels of 0.3 to 0.4 Ib/MBtu, combustion modifications will probably be
the preferred techniques.  Where boiler inflexibility or other conditions
prevent the use of most combustion modifications and derating or staging
which results in derating the boiler are the only combustion-related
approaches left to meet specified emission levels, Thermal DeNOx will be
the preferred technique.  Clearly, more refined costs for combinations of
combustion modifications, including case histories, are required before
authoritative comparisons can be undertaken.

TEMPERATURE NONUNIFORMITY SENSITIVITY STUDY

     The effectiveness of the Exxon Thermal  DeNOx Process is critically de-
pendent on temperature.   Thermal  DeNOx performance is a  function of the cross
sectional  temperature throughout the reaction zone.  Because of this signifi-
cant dependence, the level  of NOX reduction attainable will depend upon
placing the ammonia injection grid in the proper location.  One major variable
which is encountered in operating boilers is the nonuniformity in temperature
of the flue gas.  A series of values to account for this AT are incorporated
into the Performance Prediction Procedure used.  This Procedure assumes that
a range of temperatures is present in the plane of the injection grid.  This
temperature range is assumed to be gradually smoothed out downstream of the
grid.  If the flue gas  temperature range is significantly  different  from
that used in the Performance Prediction Procedure, it is possible that
the grid or grids could be  improperly located thereby resulting  in less
than predicted DeNOx performance.  As a consequence a sensitivity analysis
was  undertaken for this study using one boiler in which different tempera-
 ture  ranges, that is different values of AT, were  used  in  the performance
 prediction technique.  This sensitivity analysis is described below.
                                      40

-------
     Initial  studies of the suitability of a unit to Thermal  DeNO  applica-
tion require  that an estimate of the AT be made for each proposed injector
location based upon experience with similar units.  The values of AT used
in calculating performance for this EPA study were based upon data taken  in
a Japanese 160 MW utility boiler.  It must, however, be realized that the
cross sectional  temperature distributions may be quite different even among
units of similar design.   Burner firing patterns, air leakage, flow obstruc-
tions, etc.  are factors which can affect the temperature pattern.

     Application of Exxon Thermal DeNOx Performance Prediction Procedure  re-
vealed that the locations of the injector grids would not be  influenced by a
temperature range up to 50°C larger than that used in the Performance
Prediction Procedure for the other cases presented.  However, a temperature
range of this magnitude could result in DeNOx performance much differed from
the predicted values by 5 to 10 percentage points, for example, performance
could be reduced from 50% DeNOx to 40-45% DeNOx.

USE OF HYDROGEN FOR LOAD FOLLOWING

     There are several approaches for using Thermal DeNOx to  achieve suitable
NOX reductions with different boiler loads.  One method involves the use  of
multiple grids each designed to cover one or more boiler loads.  Only NH3
plus carrier  are used.  This has been the approach studied in the other
sections of this report.  In this section, the results are presented for  a
second approach studied for maintaining NOX reductions during reductions  in
boiler load.   A single injector rather than two was installed, and hydrogen
was injected  along with ammonia and carrier during periods of boiler load
reduction to  maintain the NOx target.  As was noted earlier in this report,
the use of hydrogen in the Thermal DeNOx Process serves to shift the critical
temperature window to lower temperature values, thereby enabling the process
to effectively accomodate reduced load.  The use of hydrogen, however, does
not widen the temperature window; hydrogen merely lowers it.   The necessity
for using hydrogen has been obviated to a large extent because of the
demonstration conducted at Exxon Research which showed that ammonia may be
injected into boiler tube banks and into cavities with essentially equal
success.  For most ammonia-only applications more than one grid will be
required in order to have DeNOx performance at different loads.  In consider-
ing the use of hydrogen, it was assumed that only one grid would be used  and
the temperature lowering ability of hydrogen would permit DeNOx performance
at lower loads and thus lower temperatures.  As a consequence, in these
hydrogen examples, reduced on-sites costs would be "traded off" for increased
reagent costs.

     The hydrogen examples presented here are only one of several grid/
hydrogen combinations possible.  Possible combinations include:

                           1 grid - no hydcegen
                           1 grid - with hydrogen
                           2 grids - no hydrogen
                           2 grids - with hydrogen
                                     41

-------
It is the second combination which has been studied here and contrasted with
the two grid - no hydrogen combination which forms the basis for the balance
of this investigation.

     The effect of hydrogen addition was calculated for the 333 MW Babcock
and Wilcox unit at 75 and 50 percent loads.  The use of hydrogen permits
possible savings in two areas:   (1) the installation of only a single grid
and (2) reduced carrier rates  since cooling of  an  idling second grid is not
required.  The location of  this  single grid is  Based on the frequency of
load changes and normal operating conditions.  We have assumed that maximum
target reductions must be maintained at all load variations, and costs  for
each load are based on continuous operation at  that load.   Grid placement
was critical in that one location was required  to cover the three loads
assumed.

     Six different examples were studied in undertaking this analysis of
the effect of hydrogen addition on extending the useful range of a single
grid system at lower boiler loads (see Table 6-6).  The first three examples
involve the use of two grids.  The first example is identical to the general
Case 3  (deep NOX reductions and no combustion modifications) and considers
initial and final NOx levels of 700 ppm and 300 ppm, respectively, at full


              TABLE 6-6.  EXAMPLES CONTRASTING SINGLE GRID-HYDROGEN
                              AND DUAL GRID FOR LOAD FOLLOWING
Example
A
B
C
D
E
F
Number
of Grids
2
2
2
1
1
1
Hydrogen
Used
No
No
No
No
Yes
Yes
Boiler
Load, %
100
75
50
100
75
50
NOX Level
Initial
700
630
560
700
630
560
s, ppm
Final
300
300
252
300
300
252

 loads.  The second example considered here assumes 75% load and initial and
 final NOX levels of 630 ppm and 300 ppm, respectively.  In the third example
 considered here, the boiler was assumed to be operating at 50% load with an
 initial N0y level of 560 ppm and a final NOX level of 252 ppm.  The latter
                                      42

-------
NOX level  represented the lowest NOX level  which  could  be  realized.   In  the
fourth,  fifth and sixth examples, only one  grid was  assumed  to  be  used.  The
initial  and final NOX levels as well as boiler loads for these  examples  are
the same for the first, second and third examples considered here, res-
pectively.   Hydrogen is added as required to meet the DeNOx  targets in the
fifth and sixth hydrogen examples.

     The assumptions which were used in applying  the Thermal DeNOx Per-
formance Prediction Procedure are listed below:

     1.   There is one injection location which must  meet all the reductions
         required of a dual injector system.

     2.   The grid must be located where the performance at each of the
         loads without hydrogen is greater than zero.

     3.   The carrier is air.

     4.   The carrier temperature is 80°C at the feed pipe  entry point into
         the flue gas duct.

     5.   The effect that a temperature distribution  would  have  on  the
         hydrogen reaction was neglected.

The assumptions used in cost estimating for the hydrogen costs  are listed
below:

     1.   Fixed costs are total erected cost, 2nd Quarter 1977,  U.S.  Gulf
         Coast, no escalation and no contingency included.

     2.   Ammonia fixed costs include NH3 storage vessel, vaporizer,  and
         piping.  Hydrogen is supplied on  truck mounted pressurized
         cylinders and is fed into  the same piping  system used to handle
         the ammonia.

     3.   Carrier fixed costs include air compressor  and piping.

     4.   On-site fixed costs include one injector grid, plus instrumenta-
         tion and controls for ammonia and hydrogen.

     5.   Operating costs are for  continuous operation at 100,  75 and 50%
         loads.

     6.   The NH3/NOI ratio is assumed  to be constant at 1.5.   This ratio
         was determined  from plots  of  data obtained by  Exxon Research.

     7.  Calculated NHq  and H£ consumptions are  based on nominal  initial
         NOX levels and  flue gas  flow  rates.   No adjustments have been
         made  for variations in  excess air levels and flue  gas moisture
         content.
                                      43

-------
     8.  Reagent operating costs for NH3 and H2 are based on $85 and $1400
         per 1000  lb., respectively.

     9.  Carrier rate, for cost calculations, was 6.45 kg/hr/nozzle at all
         loads.  Excess carrier was assumed to be vented when not needed.

    10.  Carrier operating costs are calculated in the same manner as the
         non HZ injection studies.

    11.  Annual amortization  is taken as 20% of investment.  This figure
         represents  finance costs and maintenance.  Annual service factor
         is 80% of full load.

      The costs projected  are  plotted  in Figure 6-3 as a  function of pounds
 of NOX removed for the three  loads.   This  figure  shows that extensive opera-
 tion  at reduced loads can best be handled  with a  dual injector system.  How-
 ever,  if minor variations in  load are foreseen for only  short durations
 there  may  be  economic incentives for the use of hydrogen with a single grid
 rather than for  installing a  second ammonia grid.

      For full  load,  this study projected that the overall cost for a single
 grid system operating with NH3 as the only reagent (i.e. no hydrogen) would
 be almost  identical  to that of a dual grid system.  Clearly, the grid and
 carrier  cost for the  single grid system would be lower than for the dual
 grid system.  However, because the grid position was selected to provide
 NOx reduction coverage at all  loads considered, it was not optimal for any
 one load.  The single grid location was a compromise and, for full load, the
 ammonia operating costs were somewhat higher for the single injection system
 that for the dual grid system (see Figure 6-3).  Thus, the higher capital
 costs of the two grid system were balanced by the higher operating costs of
 the single grid system.  If the operating time at each load had been
 established, it should be possible to identify a  single grid position which
would result in lower operating costs.

     For 75 and 50 percent load,  hydrogen would be used in order to main-
 tain the specified DeNOx coverage.   For these reduced load examples, it
was projected  that the total  cost of single grid  operation in which hydrogen
was used were  higher than the  dual  grid examples,  but the substantially
 higher operating costs for the single grid  examples  more than offset the
 lower fixed costs.
                                     44

-------
F
C
E
B
D
A

''2/%%//2\

'%2/%%%/A
t /
Fixed Operating
Costs Costs
1 \
%^%^

'/2/W/%\

'////A -i r*no/
_ JL UU/u
Load
5%223 1
1 I 1 1 1 1

[
50%
1 Load


75%
Load
A^C -Two injection locations -
no H2 required.
D,E,F - Single injection location -
H2 needed at loads less
than 100%.
1 1 1 1 1 1
0  .02  .04  .06  .08  0.1      0.14     0.18     0.22

                TOTAL  COST, $/LB NOX REMOVED


    Figure 6-3  Comparison cost of injecting with and without H2 in
               a Babcock and Wilcox - 333 MW Unit.
0.26
                                45

-------
                                 REFERENCES
1.  Lyon, R. K., "Method for the Reduction of the Concentration of NO in
    Combustion  Effluents Using Ammonia," U.S. Patent 3,900,554, August 9,
    1975.

2.  Lyon, R. K., "Communication to the Editor:  the NH3-NO-02 Reaction,"
    International Journal of Chemical Kinetics, IB, 315-318 (1976).

3.  Lyon, R. K. and Longwell, J. P., "Selective, Non-Catalytic Reduction of
    NOX by NH3," Paper presented at EPRI NOX Seminar, San Francisco,
    February 1976.

4.  Crawford, A. R., Manny, E.  H.  and Bartok, W., "Control of Utility Boiler
    and Gas Turbine Pollutant Emissions by Combustion Modification - Phase 1,"
    EPA-600/7-78-036a, March 1978.

5.  Federal  Register, Proposed  Emission Monitoring and Performance Testing
    Requirements for New Stationery Soruces, Vol. 39, No. 17-, Part II
    (September 11,  1974).

6.  Lim, K., Acurex-Aerotherm,  Private communication.

7.  Vatsky,  J., "Attaining Low  NOx  Emissions by Combining Low Emission
    Burners  and Off-Stoichiometric  Firing,  presented at AIChE 70th Annual
    Meeting, New York, November 14-17, 1977.
                                      46

-------
                                 APPENDIX 1

                          COST COMPARISON SUMMARY
     This appendix provides a comparison of Thermal  DeNOx process  costs
and the costs associated with combustion modifications for each  full
boiler load case studied.
                                  47

-------
                                                     THERMAL  DENOX  COST  COMPARISON  SUMMARYt


B&W


CE

FW

RS



B&W
CE

FW

1 1*1 1 f
un 1 1
130 MW Subbl luminous
333 MW Bituminous
400 MW Lignite
350 MW Bituminous
800 MW Subbituminous
330 MW Bituminous
670 MW Subbituminous
350 MW Bituminous


Unit
130 MW Subbituminous
333 MW Bituminous
400 MW Lignite
350 MW Bituminous
800 MW Subbituminous
330 MW Bituminous
670 MW Subbituminous
Case 1 . Trim Tar
Initial Target
NOX NO* G
Jppni) (ppm). (
500
700
1000
500
530
850
700
700










Reagent

375
450
450
450
375
450
375
450
get - W1t
Flue
as Rate
k Ib/hr)
1274
2977
5046
3209
8671
3028
8176
3942
Cost - mUls/kW-hr

Operating Capital





0.16
0.24
0.89
0.05
0.16
0.48
0.42
0.06
0.03
0.07
0.02
0.02
0.05
0.03

Total
0.22
0.27
0.96
0.07
0.18
0.53
0.45
hout Combustion Modifications
NOS Reduction
Required
(Percent) (1b
25
36
55
10
29
47
46
36
Carrier Cost -

Operating Cap
0,08 0.
0.07 0.
0.10 0.
0.07 0.
0.09 0.
0.07 0.
0.10 0.
N02/nr)
254
1189
4433
256
2147
1935
4244
1575
mills/kW-hr

1ta1 Total
11 0.19
06 0.13
06 0.16
06 0.13
03 0.12
06 0.13
04 0.14
NH3/NOI
(Molar
Ratio) 0
0.63
0.76
1.41
0.20
0.56
1.24
0.98
0.76
On-Site Cost

mills/kW-hr
0.08
0.05
0.05
0.05
0.04
0.05
0.04
Reagent
perating
0.08
0.07
0.08
0.06
0.06
0.08
0.07
0.07
Total

ml





Cost, $/lbAN02
Capital
0.03
0.009
0.006
0.03
0.006
0.008
0.005
0.008
Thermal
Cost
Hs/fcW-hr
0.49
0.45
1.17
0.25
0.34
0.71
0.63
Total
0.11
0.08
0.09
0.09
0.07
0.09
0.08
0.08
DeNOx







RS   350 MW Bituminous                      0.30      0.04     0.34       0.09      0.06     0.15        0.05
f  Thernal  DeNOx costs do not include licensing fees and charges for preliminary engineering and testing.
0.54

-------
                                                             THERMAL DEMO,  COST COMPARISON  SUMMARY"''



                                                      Case 2.  Trim Target  With Combustion  Modifications
Unit
B&W
CE
FW
130 MW
333 MW
400 MW
350 MW
800 MW
330 MW
670 MW
Subbituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Subbituminous
Initial
NOX
(ppm)_
300
420
900
450
375
510
420
Target
NOX
(PPB11
375
450
450
450
375
450
375
Flue
Gas Rate
(k Ib/hr)
5046

3028
8176
NOj, Reduction
Required
(Percent) (Ib
50
-
12
11
N02/hr)
3627
-
290
588
NH3/NOr
(Molar
Ratio)
1.24
-
0.30
0.24
Reagent
Operating
0.08
-
O.OB
0.07
Cost, $/lb
Capital
0.006
-
0.03
0.02
N02
Total
0.09
- .
0.11
0.09
RS   350 MW Bituminous
420
                                      450


BSW


CF

FW


Unit •
130 KW Subbituminous
333 MW Bituminous
400 MW Lignite
350 MW Bituminous
800 MW Subbituminous
330 MW Bituminous
670 MW Subbituminous

Operating

_
0.71
.
-
0.07
0.06

Capital

.
0.06
.
-
0.02
0.01

Total

_
0.77
_
-
0.09
0.07

Operating

«
0.10
.
-
0.07
0.10

Capital

_
0.06
m
-
0.06
0.04

Total

_
0.16
_
-
0.13
0.14

mills/kW-hr
.
-
0.05
_
-
0.05
0.04
Modification
Technique
LNB
LNB
LEA
OFA
OFA
LNB
LNB
Modification Cost
mills/kW-hr
0.06
0.06
0.0
0.08
0.08
0.06
0.06
DeNO* Cost
mills/kW-hr
.
-
0.98
-
-
0.27
0.25

mills/kW-lr
0.06
0.06
0.98
0.08
0.08
0.33
0.31
RS   350 MW Bituminous
                                                                                                   OFA
   Thermal  DeNOx  costs  do  not  include  licensing  fees  and  charges  for  preliminary  engineering  and testing.
                                                                                                                    0.10
                                                                                                                                                   0.10

-------
                                                 THERMAL DeNO  COST COMPARISON SUMMARYt
en
o
Unit
B&W
CE
FW
RS
B&W
CE
130
333
400
350
800
330
670
350
130
333
400
350
800
MM Subb1tum1nous
MM Bituminous
MM Lignite
MM Bituminous
MM Subbl luminous
MM Bituminous
MM Subbl luminous
MM Bituminous
Unit
MM
MM
MM
MM
MM
Subbi luminous
Bituminous
Lignite
Bituminous
Subb1tum1nous
Case
Initial
NOX
(ppm)
3. Deep Reductlc
Target Flue
NOx Gas Rate
(ppm) (k Ib/hr)
500 225 1274
700 300 2977
1000 300 5016
500 300 3209
530 225 8671
850 300 3028
700 225 8176
700 300 3942
Reagent Cost - mllls/kM-hr
Operating
0.41
0.17
0.43
Capital
0.40
0.03
0.03
Total
0.45
0.20
0.46
•x
m Target Mlthout Combustion
NOX Reduction NHa
Required (Mo
i (Percent)
(lb N0?/nr) Ra
55
57 1902 1.
70
40 1025
58 4224 1 .
65
88
57 2519 1.
Carrier Cost - m1lls/kM-hr
Operating
0.07
0.07
0.09
Capital Total
0.06 0.13
0.06 0.13
0.03 0.12
Modifications
/NOT Reaqent Cost, $/lbANO?
lar
t1o) Operating Capital Total
31 0.07
76 0.06
5 0.08
46 0.08
On-S1te Cost
m1lls/kM-hr
0.05
0.05
0.04
0.007 0.08
0.01 0.07
0.006 0.09
0.007 0.09
Total Thermal DeNOx
Cost

m1lls/kM-hr
0.63
0.38
0.62

        FM   330 MM Bituminous

             670.MM Subb1tum1nous


        RS   350 MM Bituminous
0.58
0.05    0.63
0.09
0.06    0.15
0.05
0.83
        t  Thermal  DeNOx costs do not include licensing fees and charges for preliminary engineering and testing.

-------
                                                               THERMAL  DeNO..  COST  COMPARISON

B4W
CE
FW
RS

B&W
CE
FW
Unit
130 MW Subbitunlnous
333 MW Bituminous
400 MW Lignite
350 MW Bituminous
800 MW Subbituminous
330 MW Bituminous
670 MW Subbituminous
350 MW Bituminous
Unit
130 MU Subbitufflinous
333 MW Bituminous
400 MW Lignfte
350 MW Bituminous
800 MU Subbituminous
330 MW Bituminous
670 MW Subbituminous
Initial T.
NOX 1
JjJpffl)
300
420
900
450
375
510
420
420
Reagent Cost
arget
NOX
(ppm)
225
300
300
300
225
300
225
300
Flue
Gas Rate
Case 4. Deep Reduction Target
NO* Reduction NH,/NO
Required (Molar
(k Ib/hr) (Percent) (Ib
1274
2977
5046
3209
8671
3028
8176
3942
- mills/kW-hr
Operating Capital
0.09
0.11
0.13
0.16
0.23
0.25
0.05
0.03
0.03
0.02
0.03
0.02
Total
0.14
0.14
0.16
0.18
0.26
0.27
25
29
67
33
40
41
46
29
Carrier Cost -
Operating Cap
0.08 0.
0.07 0.
0.07 0.
0.09 0.
0.07 . 0.
0.10 0.
N0,/hr) Ratio
153 0.63
571 0.61
769 0.64
2077 0.77
1016 1.00
2546 0.98
756 0.62
With Combustion Modlff cations
j Reagent Cost, $/lbANO^
1 Operating Capital Total
0.08
0.07
0.06
0.06
0.08
0.07
0.07
mllls/kW-hr On-Site Cost
ital Total mills/kW-hr
11 0.19
06 0.13
06 0.13
03 0.12
06 0.13
04 0.14
0.08
0,05
0.05
0.04
0.05
0.04
0.05 0
0.02 0
0.01 0
0.006 0
0.01 0
0.006 0
0.01 0
Combustion
Modification
Technique
im
LNB
LEA
OFA
OFA
LNB
LNB
.13
.09
.07
.07
.09
.08
.08
Combustion
Modification Cost
" mills/kW-hr
0.06
0.06
0.0
0.08
0.08
0.06
0.06




Total Thermal
DeNOx Cost
mills/kW-hr
0.4}
0.32
0.34
0.34
0.44
0.45




Total Cost
mills/kW-hr
0.47
0.38
0.42
0.42
0.50
0.51
RS  350 MW Bituminous
0.15
0.03    0.18
                                                        0.09
                                      0.06    0.15
                                                                                     0.05
                                                              OFA
                                                                                                                    0.10
                                                                                                         0.38
                                                                                                                                                   0.18
t  Thermal DeNOx costs do not include licensing fees and charges for preliminary engineering and testing.

-------
                                                  THERMAL DeNO^.  COST COMPARISON  SUMMARY4



                                Case  5.   Maximum  DeNOx  at N^/NOj  - 1.5 Without  Combustion Modifications
01
ro





B&W
CE
FW
RS
Unit
130 MW Subbituminous
333 MW Bituminous
400 MW Lignite
350 MW Bituminous
800 MW Subb1tum1nous
330 MW Bituminous
670 MW Subb1tum1nous
350 MW Bituminous
Initial
NOX
(ppm)
500
700
1000
500
530
850
700
700
Target
NOX
(ppm)
250
291
430
210
228
391
280
294
Flue
Gas Rate
(k Ib/hr)
1274
2977
5046
3209
8671
3028
8176
3942
Reagent Cost - mills/kW-hr

B&W


CE

FW

RS

130
333
400
350
800
330
670
350
Unit
MM Subbituminous
MW Bituminous
MW Lignite
MW Bituminous
MW Subbituminous
MW Bituminous
MW Subbituminous
MW Bituminous
Operating
0.37
0.47
0.95
0.35
0.43
0.59
0.64
0.59
Capital
0.07
0.04
0.07
0.04
0.03
0.05
0.05
0.05
Total
0.44
0.52
1.02
0.39
0.46
0.64
0.69
0.64
NOX Reduction
Required
i (Percent)
50
63
57
58
57
54
60
58
lib N0?/h
509
1945
4594
1486
4183
2220
5484
2556
Carrier Cost - mill
Operating
0.08
0.07
0.10
0.07
0.09
0.07
0.10
0.09
Capital
0.11
0.06
0.06
0.06
0.03
0.06
0.04
0.06
NHa/NO
(Molar
r}_ Ratio
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
s/kW-hr
Total
0.19
0.13
0.16
0.13
0.12
0.13
0.14
0.15
I Reagent Cost, $/1bANO?
) Operating
0.09
0.08
0.08
0.08
0.08
0.09
0.08
0.08
On-Site Cost
mills/kW-hr
0.08
0.05
0.05
0.05
0.04
0.05
0.04
0.05
Capital
0.02
0.008
0.006
0.008
0.006
0.008
0.006
0.007
Total
Total
0.11
0.09
0.09
0.09
0.09
0.10
0.09
0.09
Thermal DeNOx
Cost
mills/kW-hr








0.71
0.70
1.23
0.57
0.62
0.82
0.87
0.84
    t  Thermal DeNOx costs do not include licensing fees and charges for preliminary engineering and testing.

-------
                                                     THERMAL  DENO,,  COST  COMPARISON  SUMMARY*

B&W 1 30
333
400
CE 350
800
FW 330
670
RS 350
Unit.
MU Subbituminous
MW Bituminous
MW Lignite
MW Bituminous
MU Subbituminous
MW Bituminous
MU Subbituminous
MU Bituminous
Initial
NO*
(ppm)
300
420
900
450
375
510
420
420
Reaqent Cost -
Unit Operating Cap
B&W 130 MW
333 MW
400 MW
CE 350 MU
800 MW
FW 330 MW
670 MW
RS 350 MW
Subbituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Subbituminous
Bituminous
0.22 0.
0.28 0.
0,86 0.
C.31 0.
0.31 0.
0.35 0.
0.39 0.
0.35 0.
Case 6. Ma>
Target
NO* Ga
(ppm) (l<
150
175
387
189
161
234
168
176
millsAW-hr
ital Total
06 0.28
04 0.32
07 0.92
04 0.35
02 0.33
04 0.39
03 0.42
04 0.39
cimum DeNOv at NH»/NOT = 1.5 With Combust
X j 1
Flue NOX Reduction NH3
is Rate Required (Mo
: Ib/hr) (Percent) (Ib NtWhr) Rat
1274
2977
5016
3209
8671
3028
8176
3942
Carrier Cost
50
63
57
58
57
54
60
58
305 1
1165 1
4135 1
1292 1
2964 1
1335 1
3291 1
1536 1
- mills/kU-hr On-Site Cost
Operating Capital
0.08 0.11
0.07 0.05
0.10 0.06
0.07
0.09
0.07
0.10
0.09
0.06
0.03
0.06
0.04
0.06
Total mills/kW-hr
0.19 0.08
0.13 0.05
0.16 0.05'
0.13 0.05
0.12 0.04
0,13 0.05
0.14 0.04
0.15 0.05
ion Mod 11
/NO]
lar
jiL c
.5
.5
.5
.5
.5
.5
.5
.5
Fi cations
Reagent Cost, $/lb
Iperating Capital
0.10 0.03
0.08 0.01
0.08 0.006
0.08
0.08
0.09
0.08
0.08
0.009
0.007
0.01
0.006
0.009
JO,
Total
0.13
0.09
0.09
0,09
0.09
0.10
0.09
0.09
Combustion Combustion Total Thermal
Modification Modification Cost DeNOx Cost
Technique
LNB
LNB
LEA
OFA
OFA
LNB
LNB
OFA




mills/kW-hr
0.06
0.06
0.0
0.08
0.08
0.06
0.06
0.10
mills/kW-hr
0.55
0.50
1.13
0.53
0.49
0.57
0.60
0.59




Total Cost
mills/kW-hr
0.61
0.56
1.13
0.61
0.57
0.63
0.66
0.69
Thermal DeNOx costs do not include licensing fees and charges for preliminary engineering and testing.

-------
THIS PAGE INTENTIONALLY LEFT BLANK
                 54

-------
                  APPENDIX  2
Noncatalytic NOX Removal With Ammonia
                     FP-735
             Research Project 835-1

               Final Report, April 1978
                   Prepared by

                    KVB, INC.
                 17332 Irvine Blvd.
              Tustin, California 92680

               Principal Investigators
                    L. J. Muzio
                   J. K. Arand
                  K. L. Maloney
                   Prepared for

        Exxon Research and Engineering Inc.
                   RO. Box 55
             Linden, New Jersey 07036

                      and

          Electric Power Research Institute
               3412 Hillview Avenue
             Palo Alto, California 94304

              EPRI Project Manager
                   D. Teixeira
     Fossil Fuel and Advanced Systems Division
                     - 55  -

-------
                                   LEGAL  NOTICE

This report was prepared by  KVB,  Inc.  as an  account  of work sponsored by  the
Electric Power Research Institute,  Inc.  (EPRI)  and EXXON  Research and Engineering,
Inc. (ERE).  Neither EPRI, members  of  EPRI,  ERE, KVB, or  any person acting on behalf
of any:  (a) makes  any warranty  or representation,  express or implied, with.respect
to the accuracy, completeness, or usefulness of the  information contained in this
report, or that the use of any information,  apparatus, method, or process disclosed
in this report may not infringe privately owned rights; or (b) assumes any liabilities
with respect to the use of,  or for  damages resulting from the use of, any information,
apparatus,  method, or process disclosed  in this report.

-------
                                  ABSTRACT

        A potential approach to the control of nitric oxide in utility
boilers, in addition to modification of the combustion process, is the
selective homogeneous gas-phase reduction of nitric oxide  with ammonia.
A laboratory study  at a scale of 3,000,000 Btu/hr was conducted to evaluate
the applicability of ammonia injection for the reduction of nitric oxide in
coal-fired power plants.  Four coals (Utah bituminous, New Mexico subbituminous,
Illinois bituminous,  and Pittsburgh bituminous)  were tested to determine
levels  of NOx reductions achievable and the byproduct emissions.  The
primary variables investigated (in addition to coal type)  were (1)  the
amount  of ammonia injected,  and (2)  the temperature of the combustion
products at the  point of injection.   The effect of the simultaneous addi-
tion of hydrogen along with  ammonia on the NOx removal process was also
investigated.  The  results of these experiments indicated that NO reductions
obtained with ammonia injection into coal-derived combustion products were
similar to those obtained with natural gas firing in the same system and were
comparable to those previously obtained in natural gas and oil-fired systems.
On the order of 65% reductions in NO were obtained at an ammonia injection
rate of one mole of ammonia per mole of NO.  However, the temperature de-
pendence was found to vary from coal to coal.  The Navaho exhibited peak
reductions at the lowest temperatures, 1720 °F, while the Illinois coal
showed peak reduction occurring at 1830 °F.  Typically, natural gas exhibited
peak reductions at  1750 °F.   The unexplained variation in optimum process
temperature with coal type indicates that evaluation testing would be prudent
in situations where maximum NOx control was desired and no previous experi-
ence was available  for the coal in question.  The simultaneous addition of
small quantities of hydrogen can be used to increase the NO reductions and
decrease ammonia emissions at temperatures lower than the optimum.
                                      ill

-------
                              ACKNOWLE DGEMENTS

        KVB, Inc., Electric Power Research Institute, and Exxon Research
and Engineering extend their appreciation to Utah International for donat-
ing the coal from its Navaho mine for use in this study.  In addition,
the authors are grateful for the technical discussions and support by
S. Stahl and A. Tenner of Exxon Research and Engineering throughout this
study.
                                      IV

-------
                                    CONTENTS
Section
                                                                     Page
  1.0      INTRODUCTION AND  OBJECTIVES
          1.1  Background
          1.2  Objectives
  2.0      EXPERIMENTAL APPROACH AND APPARATUS
          2.1  Approach
          2.2  Combustion Facility
          2.3  Instrumentation
          2.4  Experimental Procedure  and Test Matrix
  3.0      EXPERIMENTAL RESULTS
          3.1  Temperature  Distributions
          3.2  Coal Properties
          3.3  Nitric Oxide Reductions
          3.4  NH  Emissions
          3-5  Cyanide and  Nitrate  Emissions
          3.6  Sulfate and  SO  Emissions
          3.7  Carbon Monoxide Emissions
          3.8  SO  and NOx  Measurements
          3.9  Ammonia and  Hydrogen Injection
  4.0      CONCLUSIONS
          REFERENCES
 APPENDICES:
         A.
         B.
         C.
         D.
EXPERIMENTAL APPARATUS
SULFATE AND SO3 EMISSION MEASUREMENT PROCEDURE
DATA SUMMARY
FUEL ANALYSIS
                                                         1
                                                         2
                                                        4
                                                        4
                                                        8
                                                       12
                                                       15
                                                       15
                                                       17
                                                       19
                                                       30
                                                       38
                                                       38
                                                       40
                                                       41
                                                       43
                                                       49
                                                       51
A-l
B-l
C-l
D-l

-------
THIS PAGE INTENTIONALLY LEFT BLANK
               vi

-------
                               EXECUTIVE SUMMARY
        The U.S. Environmental  Protection Agency has  published research
goals for  the  emissions  of  nitric  oxide  from stationary sources which
would limit flue gas  concentrations  to 100 ppm from coal-fired power plants
by 1985  (Ref.  1).  Numerous approaches are being evaluated for controlling
NOx emissions  from stationary combustion sources.  These approaches cover
the spectrum from  "front end" control  of the combustion process to the
physical or chemical  removal of the  oxides of nitrogen in the downstream
regions  of the unit.   One potentially  attractive process for coal-fired
utility  boilers entails  the selective  gas-phase decomposition of nitric oxide
by ammonia. In this  process, ammonia  is injected into the combustion pro-
ducts.   If the temperature  of the  combustion products is between 1200 °F and
2000 °F, the ammonia  will selectively  react with the  nitric oxide in the
presence of excess oxygen to form  primarily nitrogen  and water.  However,
nitric oxide reductions  on  the  order of  50% or greater occur in the vicinity
of 1750  °F (±  100  °F).  Hydrogen can be  used along with the ammonia to lower
the temperature at which the selective reduction occurs.  A patent is held by
the Exxon  Research and Engineering Company on this process (Ref. 2).
        While  a significant amount of  data have been  gathered on the selec-
tive reduction of  NOx in oil- and  gas-fired systems,  little information is
currently  available as to the applicability of the process to coal-fired sys-
tems.  In  particular,  the  levels  of NOx reductions achievable, the byproduct
emissions,  and the possible catalytic  interaction due to the coal ash with NH
injection  into coal-derived combustions  have not been characterized. A labora
tory study was conducted at a scale of 3,000,000 Btu/hr to evaluate the appli
cability of NH  injection to coal-firing systems.  The specific objectives of
the study  were to: (1) Determine the levels of NOx removal and ammonia emis-
sions with ammonia injection into  the  combustion products resulting
from pulverized coal  combustion;  (2)  Determine the type and levels  of
                                      vn

-------
byproduct emissions:  (SO ,  SO ,  CO, HCN, NH ,  unburned hydrocarbons, nitrate
particulates,  and sulfate particulates);  (3)  Determine any effects that vary-
ing coal types might have on the process.   A variety of coals were repre-
sented  in the  study  (Utah bituminous,  Navaho sibbituminous,  Pittsburgh Seam
8 bituminous,  and Illinois  bituminous);  and (4) Determine  the extent to which
hydrogen can lower the temperature  at which NH  would remove NOx from coal-
derived combustion products.
         The basis of the experimental system was a  firetube boiler modified
to  fire pulverized  coal with preheated combustion air  (600 °F) .  The burner
was a geometrically scaled version  of a burner currently in use in a coal-
fired utility boiler in the  western United States.   The  ammonia was in-
jected with a carrier stream of nitrogen through five water-cooled injectors
in  the main firetube (33 in. diameter).   The temperature at the point of  in-
jection was controlled by (1) moving  the injectors  axially in the firetube,
 (2) changing the heat renoval rate  from the main firetube with stainless
steel liners,  and  (3)  varying firing  rate.
         A summary of the nitric oxide reductions obtained for all fuels
tested during this  study is  shown in  the two figures below.
     i.o
     O.B
     o.e
     0.4
     0.2
                   Natural Gas
•- Utah Coal
.- Navaho Coal
__ Pittsburgh Coal
— Illinois Coal
       1500    1600   1700    1300    10    2COO
             Average Radial Temperature, *r
                        A.
                                               l.C
                                               O.B
                                               o.e
                                               0.4
                                               0.2
	 Natural Gas
	 Utah Coal
— Navaho Coal
	 Pittsburgh Coal
— Illinois Coal
                                                       I
                                             I
        («H./HOo • 0.5. Excess O^ A. S.0»)
                               1500   1600   1700    1800    1900    2000
                                      Average Radial Temperature, *F
                                {NH3/NOQ - 1.0, Excess 02 -v. 5.01)
                                        V1U

-------
       NO reductions obtained with  ammonia  injection  during  this  study  were
similar for all fuels tested.  At  the optimum temperature,  on the  order  of 65%
reductions in NO were obtained at  an ammonia injection rate of one mole  of am-
monia per mole of NO for all  fuels.  However,  the  temperature dependence varied
from coal to coal.  The Navaho exhibited peak reductions  at the lowest tempera-
ture, 1720 °F, while the Illinois  coal  showed peak reductions occurring  at 1830
°F.  The optimum temperature  for natural gas was  1750  °F.   A  very  limited series
of tests was conducted to  determine  the cause of  the variation in  optimum tem-
perature, however no definitive  reason  could be found  to  explain this tempera-
ture variation.   The unexplained variation in optimum process temperature
with coal type indicates that evaluation testing would be prudent in situations
where maximum NOx control was desired and no previous experience was avail-
able for the coal in question.
        In general,  the  ammonia  breakthrough emissions- are comparable for
all the  fuels  tested during this program.  The highest emissions of ammonia
occurred  when  the temperature of the combustion products  at the point of in-
jection was  less  than  that required  for optimum NO removal.  With  judicious
selection of the  temperature at  the  point of injection, it was possible  to
achieve nitric oxide reductions  of 55%  while limiting  NH   emissions to the
range of  10  to  35 ppm  (for reference purposes, the odor level of ammonia is
commonly  stated to  be  50 ppm).
       With ammonia injection,  no statistically significant changes in the
cyanide and  nitrate species concentrations were measured relative to  the
baseline  case  of  no ammonia injection.    This supports previous studies
(Refs.  3, 4) that cyanide  and nitrates  are not byproducts of the selective
homogeneous  reduction  process.   The  primary products of the NOx removal pro-
cess are  molecular  nitrogen  (N ) and water  (H~0).
        The  SO levels in the flue gas tended to be lower when ammonia was
injected  to  reduce  the oxides of nitrogen; this suggests sulfate producing
reactions between NH  and SO .   Quantitative variations in sulfate levels
with ammonia injection were somewhat inconclusive as only small changes  were
measured.  However,  SO  levels  were  reduced for each of the coals  tested.
Further  clarification  of this point would seem warranted.
                                       IX

-------
        The experiments while firing the Pittsburgh seam coal further confirmed
that the addition of small quantities of hydrogen injected along with ammonia
can be used to increase the NO reductions and decrease the ammonia emissions
at lower temperatures than observed without hydrogen injection.  At a given
temperature and ammonia injection rate, there exists an optimum rate of hy-
drogen injection.  Further increase in the hydrogen injection rate results
in decreases in the amount of NO removed.  This optimum hydrogen rate in-
creases as the temperature at the point of injection decreases.
        With the exception of the variation in optimal process temperature
with coal type, the findings with NH  injection into coal-derived combustion
products are in substantial agreement with previous experimental results
for gas and oil-fired systems (Refs. 3, 4) in terms of achievable NO reduction,
ammonia emissions, and byproduct formation.

-------
                                  SECTION 1.0
                         INTRODUCTION AND OBJECTIVES
1.1     BACKGROUND
        Numerous  approaches  are being considered for  controlling NOx emissions
from stationary combustion sources.   These approaches cover the spectrum
from "front  end"  control  of  the combustion process  to the physical or chemical
removal  of the oxides  of  nitrogen in the downstream regions of the unit.   A
process  that appears to be attractive for control of  NOx emissions from coal-
fired utility boilers  entails the selective gas phase decomposition of nitric
oxide by ammonia.  In  this process,  ammonia is injected into the combustion
products; if the  temperature of the  combustion products is between 1200 °F and
2000 °F, the ammonia will selectively react with the  nitric oxide in the pre-
sence of excess oxygen to form nitrogen and water vapor.  However, nitric
oxide reductions  on the order of 50% or greater occur in the vicinity of 1750 °F
(+_100 °F).   A patent  is  held by the Exxon Research and Engineering Company
on this  process  (Refs.  2, 3).
        Previously, EPRI  sponsored a program to investigate the potential
for the  gas  phase reduction  of NOx in utility boilers  (Refs. 4, 5).  During
this study a small natural gas-fired combustion tunnel was used to determine
the conditions  of concentration, temperature, and reducing agent type which
would result in the selective reduction of NOx in the presence of varying
amounts  of oxygen and nitric oxide.   A selective reduction of NOx was found
to occur when ammonia was injected into combustion products which were
at a temperature  from 1300 °F to 2000 °F with peak reductions occurring in
a narrow temperature region about 1750 °F.  Typical  results which were ob-
tained in this  gas-fired combustion tunnel in terms  of the effect of tempera-
ture and the amount of ammonia which was  injected  are  shown in  Figure 1.  As
can be seen  from this figure, approximately 80% of the NOx is removed when
one mole of  NH_ is injected for every mole of NOx  initially present.

-------
            1.0
            0,8
          ~ 0,6
            0.2-
              1200
        Figure 1.
                                           (NH)/(NO), MOLAR
                                                 1.6
                                  I
                                    I
               1400      1600      1800
                       TEMPERATURE, "F
2000
2200
           Effect of temperature on NO reductions with ammonia
           injection.   (Excess  oxygen 4%,  initial NO 300 ppm,  Ref.  4)
        Exxon Research and Engineering  (the patent holder for the process)
has also done an extensive amount of proprietary development work on  this pro-
cess.  In fact, the process has been applied to a number of oil- and  gas-
fired industrial boilers and process heaters in Japan.
1.2
OBJECTIVES
        While a significant amount of data has been gathered on  the selective
reduction of NOx in oil- and gas-fired systems, little  information is  cur-
rently available as to the applicability of the process to coal-fired  power
plants.   In particular,  the  levels of NOx reductions which are achievable and the

-------
associated byproduct emissions,  as well as the possible catalytic  or  other
effects  due to the coal ash and the injected ammonia must be developed.


        The specific objectives  of the  study  involved the

           Determination of the  levels  of  NOx removal and  ammonia  emissions
           with ammonia  injection into  the combustion products resulting
           from pulverized coal  combustion.   The primary variables of the
           study were the temperature at the  point of NH3  injection,  the
           amount  of NH^ injected, and  the coal type.

           Determination of the  type and levels of byproduct  emissions.  In
           particular the following were determined:   SC>2,  803, CO, CM, NH3,
           unburned hydrocarbons, nitrate  particulates,  sulfate particulates.

           Determination of any  effects that  varying  coal  types might have
           on the  process.   A variety of coals were used in the study
           including: a Utah bituminous,  a Navaho subbituminous,  Pittsburgh
           Seam 8  bituminous and an Illinois  bituminous.   The results are
           compared to the NOx emissions obtained with natural gas.

           Determination of the  extent  to  which hydrogen can  lower the
           temperature at which  NH3 would  remove NOx  from  coal derived
           combustion products and to determine the effect of H2 on the
           ammonia emissions at  various temperature levels.

-------
                                  SECTION 2.0
                      EXPERIMENTAL APPROACH AND APPARATUS

 2.1     APPROACH
         The objectives of the present program were accomplished through a
 systematic series of experiments conducted in a pulverized coal combustion
 facility capable of firing at rates up to approximately 3,000,000 Btu/hr
  (nominally 250 Ib/hr coal feed).  A description of the combustion facility
 as well as the instrumentation  employed and the experimental procedure com-
 prises the remainder of this section.

 2.2     COMBUSTION FACILITY
         The combustion facility used in this program had the capability of
 firing either natural gas or pulverized coal.   A schematic diagram of the
 facility is shown in Figure 2.
 2.2.1   Combustor
        The basic combustion facility consisted of a firetube boiler which
was modified to fire pulverized coal.  A detailed description of the boiler
and auxiliary equipment is contained in Appendix A.
         Stainless steel liners were installed in the main firetube as a means
 of varying the gas temperatures at the point of ammonia injection {e.g., lower
 gas temperatures were attained by removing sections of the liners).

-------
                                          To  Baghouse
        Air Preheater
                        Venturi
                                   NO
                      0
Secondary Air

Venturi
   Tempering Air
Rotameter
                          Primary Air
         Calibrated
             Feeder'
     Burner
 Natural
   Gas
                      Coal
                              Diluent
                            I
                                                             Heated  Sample Line
                                fyvyiv,,. ,-ff. **...,™-*--'v
                      r
|.TT^y>









Water C"o6Tec[
NH Injectors \
Stainless
Steel Liner













i


}














. . . .. i j




                      I
SO   NO/  UHC
     NOx
                                                                                           Con-
                                                                                           denser
0_   NO   CO   CO,
                                                                       NH  ,HCN
                             Ammonia Input System
                                                 Gas Analysis
               Figure  2.    Schematic diagram of combustion facility.

-------
         The natural  gas  burner was  a ring-type  burner with a single air
 register.   During some of the natural gas  tests,  nitric oxide was added to
 the  combustion air to raise the exhaust gas nitric  oxide  levels to approxi-
 mately 500 ppm in order  to provide  a more  direct  comparison to the coal-fired
 test results.
         The coal  burner  was a scaled-down  version of a commercial burner
 presently  being used in  a utility boiler firing western coal.  This burner
 incorporated a single  adjustable air register and the primary air/coal
 stream was mixed  with  the secondary air by swirling the primary mix ~
 ture.
 2.2.2   Ammonia Injection System
         The ammonia  injectors were  designed to  (1)  provide rapid dispersion
 of the ammonia into  the  combustion  products,  (2)  allow axial positioning  in
 the  boiler.
         The injectors were fabricated of stainless  steel  and water cooled.
 The  ammonia was injected with a nitrogen carrier  gas to increase the  pene-
 tration and mixing of the ammonia with the combustion products.
         The injector system schematic is shown  in Figure  3.  It was found
 early in the testing that the use of five  injection points was the most ef-
 fective means of  achieving the best NO reductions and therefore the majority
 of the tests were conducted with this configuration.  For a commercial appli-
 cation, a  more extensive optimization of the  NH3  injection system  is  warranted.
        The mass flow rate of the injected nitrogen, ammonia,  and hydrogen
were  measured by rotameters as shown in Figure 4.   The  five separate ammonia
rotameters downstream of the main ammonia rotameter were used primarily to
balance the flows to the injectors and the total ammonia flow was determined
by the most accurate single rotameter.

-------
                                                                                           Support S-and
i
                                    Figure  3.    80 HP boiler ammonia injection  schematic.

-------
2.3     INSTRUMENTATION
        All air flows  and gas  flows  into the combustion facility were measured
either by calibrated rotameters  or venturi flow meters.  A complete description
is given in Appendix A.
        Since  the combustion product temperature and the level of excess oxygen
level were the primary variables of  interest, no effort was made to accurately
calibrate the  coal feeder.  Instead, the coal firing rate was deduced from the
coal analysis, flue gas oxygen concentration and combustion air flow rate.

        Low temperature measurements were made  using chromel-alumel  thermo-
couples.  Gas temperatures in the combustion section were  measured using  an
aspirated thermocouple probe.
2.3.1   Aspirated Temperature Probe
        An aspirated Pt-Pt/10% Rh thermocouple  was used to obtain the tempera-
ture profile data.  The aspirated thermocouple  is used to  minimize radiation
losses.  In this device,  the thermocouple is isolated  from the  surroundings
through a series of concentric ceramic radiation shields.  At the same  time,
the convective heat transfer to the thermocouple is increased by aspirating
the hot combustion gases  past the thermocouple  and radiation shields.   The
probe used in the study is shown in Figure  5 and is a  slightly  modified de-
sign as used by the International Flame  Research Foundation  (IFRF)  (Ref.  6).
2.3.2   Gas Analysis
        The chemical analysis performed during  these experiments included a
wide variety of techniques.  Continuous gas  analyzers  were used to measure >
excess oxygen (O2), oxides of nitrogen  (NO/NOx), carbon monoxide  (CO),  carbon
dioxide (CO )  , unburned hydrocarbons  (UHC),  and sulfur dioxide  (SO,,).
        Batch techniques were utilized  for the determination of ammonia
 (NH ), cyanide  (CN),  sulfur trioxide, sulfates,  and nitrates.   The
 ammonia, cyanide, and nitrate species were bubbled through appropriate

-------
Circuit for
Single
Injector
  Rotameter
  0 - 1.55 scfm
Rotameters
0-3 scfm
                                                                -Injectors
                                                  Rotameter
                                                  0-0.3 scfm
         Rotameter
         0-0.3 scfm
              Figure  4.   Ammonia injection flowmeters.

-------
      Combustion Gases
      to Aspirating Puir.p
Thermocouple tf
Readout     *
           Out    In
Cooling
 Water
                                                                      Sheathed
                                                                      Pt/Pt-30% Rb
                                                                      Thermocouple
                                                                                               Section A-A
                                                                  Radiation
                                                                  Shields
                                                                                Approximately
                                                                                1 in. O.D.
            Figure  5.    Schematic Diagram of Aspirated Thermocouple Probe.
                         (Not  to Scale.)

-------
absorbing solutions — dilute sulfur acid for ammonia, sodium hydroxide for
cyanide,  and distilled water for nitrates.  The resultant solution and the
probe and sample line washings were then analyzed using specific ion elec-
trodes.   A summary of the gas analysis instrumentation is presented in Table
1.  Further details of the instrumentation and procedures for the determination
of ammonia, cyano, and nitrate is contained in Reference 4.
        Sulfates  and SO, were determined  by a procedure outlined by R. K. Lyon
of Exxon Research and Engineering  (Ref. 7}.   The sulfate was collected by
sampling the combustion products with a heated quartz probe and collecting
the sample on a heated filter maintained  at 310  °F.   A gravimetric procedure
was used for the  sulfate analysis.  The SO concentration was determined by
using the  sulfate sampling  system  and adding an  excess of  ammonia to  the
probe.  It was  assumed that the excess  ammonia injected into  the probe re-
acted with  the  free  SO., in the sample to form a sulfate.   The  difference between
 the sulfate levels with  and  without ammonia injected into  the  sampling probe
 is taken to be the SO  concentration in the sample.   Appendix  B contains a
 more detailed description of the procedure  for  sulfate and SO  determination.
                    TABLE  1.   GAS ANALYSIS INSTRUMENTATION
   Species
                   Analyzer
   NO/NO,
   °2
   CO
   co2
   UHC
   so2
   NH3
   CN
   so.
TECO Model 10A  Chemiluminescent  (molybdenum converter)
Beckman Model 742 Electrolytic
Horiba Model PIR 2000 NDIR
Horiba Model AIA 21 NDIR
Beckman Model 402 Flame lonization Detector
Du Pont Model 401 Photometric
Orion 95-10 Specific Ion Electrode (701 Meter)
Orion 94-06 Specific Ion Electrode (701 Meter)
Orion 93-07 Specific Ion Electrode (701 Meter)
Gravimetric Analysis of filter catch
Gravimetric Analysis following conversion to sulfate
                                        11

-------
2.4     EXPERIMENTAL PROCEDURE AND TEST MATRIX
2.4.1   Experimental Procedure
        One of the primary parameters of interest was the combustion product
temperature at the point of ammonia injection.  It was found that in order
to obtain the temperature range of 1500 to 2000 °F within the main firetube
the boiler had to be fired at a rate of approximately 1.5 to 2.0 million Btu
per hour.  At this rate it required approximately one and one-half hours for
the boiler to stabilize before sampling could begin.  Temperatures at the
point  of NH  injection could be varied 300 °F by simply changing the axial
position of the  injectors while maintaining all other test conditions con-
stant.  Removal  of the stainless steel heat shields  from the main firetube
provided further variation in temperature.  By the combination of heat shield
removal and change in axial location of the NH, injectors, the temperature
range of approximately 1600 to 1950 °F was available.
        Normally, temperature measurements were made during this warm-up
period to establish the point at which the boiler was stable and also to en-
able projections of the rate of changes of the gas temperature with time.
This was necessary since ash accumulation in the combustion section acted
as insulation and  resulted in a continuous increase in temperature on
the order of one-half degree per minute after the initial warm-up period.
The gas temperature was also measured after each set of data to establish the
temperature-time history during the test period.  Interpolation of this
temperature time history was used to determine the combustion product tempera-
ture at the point of ammonia injection.

        This increase in temperature with time complicated the determination
of the exact temperature at the point of NH  injection.  The following pro-
cedure was adopted.  The boiler was fired and the excess air set to yield ap-
proximately 5% excess oxygen at the firing rate which produced the desired
temperature range.  These conditions were not changed during a test.  The
aspirated thermocouple was inserted and the temperature of the gas along
the boiler centerline, was monitored until the rate  of change approached
                                      12

-------
1/2 °F per minute.  Once this condition was achieved temperatures were
recorded at the various axial locations to determine the temperature range
available.  Baseline NH , HCN, and NO  emissions were taken during this time.
                       •3             j
The probe was then removed and the ammonia injectors were inserted to the axial
plane which yielded the desired test temperature.   An NH-j injection
rate was then set and all sampling commenced; the NH , CN, and NO  samples
were taken concurrent with the continuous analyzer data of O , NO, NOx, CO,
CO , UHC, and SO  .
        After all NH3 injection data had been obtained,  the ammonia injectors
were removed and the temperature probe was reinserted and again  tempera-
tures were recorded.  The temperature during the ammonia injection test was
then determined by interpolating between the temperatures recorded at the
beginning and end of each test.

        A series  of preliminary tests were conducted to assess the potential
problems that might occur when using the aspirated temperature probe to
measure exit gas  temperatures under coal fly  ash conditions.  Using the
Utah coal it was  found that plugging of the probe tip occurred after a few
minutes of aspirated operation.  The problem  was so severe  as to make  it
impractical, from fuel usage  and time considerations, to  attempt to fully
calibrate the temperature probe when firing  coal.
         The  basic calibration of the  temperature probe  was  done  while  firing
natural  gas.  The optimum aspiration  rate  on gas  firing for the  probe  was
used for all other  tests where it was  necessary to  obtain "true" gas  tempera-
tures.
 2.4.2   Test Matrix
         The  scope of the testing covered the following  range of  variables:
           primary fuel type
           ammonia concentration
           combustion gas temperature
           hydrogen concentration.
                                       13

-------
        The actual range of the above variables which were investigated are
presented in the test matrix outlined in Table 2.
                              TABLE 2.  TEST MATRIX

                              a.  Ammonia Injection Tests
Variable
Excess Oxygen
Nitric Oxide Level
Temperature at
Injection Point
NH Injection Rate
Approximate number of test
conditions for each fuel
Approximate total number
of ammonia injection tests

Range
Approx. 5%
Burner Produced
(500-810 ppm) S
1330 "F - 1965 °F
NH3/NO - 0-1.5* molar

Fuel
Natural
Gas
1*
1
4
4
16
Utah
Coal
1
1
10
4
40
Navaho
Coal
1
1
6
4
24
Illinois
Coal
1
1
6
4
24
Pittsburgh
Coal
1
1
9
4
36
140
                              b.  Ammonia/Hydrogen Tests
Excess Oxygen
NOx Level
Temperature at
Injection Point
NH. Injection Rate
H Injection Bate
Approximate number of NH,/
H_ Injection Tests
Approx . 5%
Burner Produced
(approx. 650 ppn)
1300 °F - 1700 °F
NH /NO "V 1,0, 1.5 molar
H2/NOQ =0-2.5

~
~
~
~
—
~
«
—
~
—
—
—
~
—
--
~
—
—
~
~
~
—
—
—
1
1
4
2
4
32
  *Signifies approximate  number of test conditions
   Limited testing  done at ratios approaching 6
       the natural  gas tests,  NO was added to the combustion air to produce
   a stack level  of 500 ppm
                                       14

-------
                                  SECTION 3.0
                             EXPERIMENTAL RESULTS

 3.1     TEMPERATURE DISTRIBUTIONS
 3.1.1    Axial  Temperature Profiles
        For each fuel type, an axial centerline  temperature profile was
established for determination of  the proper location of the ammonia injec-
tors for each test.  A comparison of typical profiles for each fuel is
given in Figure 6.   In this figure, changes in the axial centerline tempera-
ture are plotted relative to the  temperature two feet from the back wall.
This was done to allow a more direct comparison  for the fuels tested.  The
change in temperature with axial  location is influenced by the firing rate,
ash content of the  coal,  and number of heat shields used.  A common curve
for all fuels and all conditions  would not be expected; however, the axial
profiles are similar from coal to coal.

3.1.2   Radial Temperature Profiles
        Radial temperatures were  measured for all  fuel types except the high
ash Navaho coal.  Two of  the three coals showed  flat radial temperature pro-
files with a total  temperature variation of  less than  200  °F.  The natural
gas fuel showed a radial  temperature variation of  approximately  250  °F.
Typical radial variations are  shown on Figure 7.  The  differences  in the
absolute temperatures in  Figure  7 result from the  fact that these  data were
obtained at various  axial locations.   The data shown for the Pittsburgh coal
were obtained with the stainless  steel liners removed in order to illustrate
the range of radial  temperature gradients experienced throughout  the study.
                                      15

-------
 600
                Natural Gas
                Utah Coal
                Navaho Coal
                Illinois Coal
             O Pittsburgh Coal
                       2                           4
                Axial Distance From Rear Furnace  Wall, feet
Figure 6.   Typical axial variations of centerline  temperature.
                                  16

-------
        From Figure 7  it can be  seen that the axial centerline temperature
 represents very nearly the  average temperature for all of the coal types.
 However,  for the natural gas fuel, the centerline temperature is approxi-
 mately  100 °F higher than the average radial gas temperature.
        In all of the  following  data presentation, the centerline gas temper-
 ature has been used as representative of the average radial temperature for
 the  coal  tests.  For the natural gas tests, the average radial temperature
 is taken  to  be 100 °F  lower than the measured centerline temperature.
        The  differences in  the radial temperature profiles between natural
 gas  and coal firing were attributed to the burners.  The gas burner was fired
 at a lower air swirl setting than the coal burner to insure flame stability.
 As a result  of the lower swirl,  the gas burner flame was visibly longer and
 further from the walls than was  that of the coal burner flame.
 3.2     COAL PROPERTIES
        The  coals chosen  for  the test program were  intended to cover  a wide
 range of  composition and  to be  representative of typical steam coals  currently
 in use  and of potential  future  use by  the utilities.

        All  coals  were  procured in bulk form,  air dried and then  pulverized.
Pulverized coal  samples were obtained during the  test program for each of
the coals  tested.  An analysis of these coal samples is contained in Appendix
D.  A brief  comparison  of the primary coal properties is presented  in
Table 3.
                                     17

-------
    1900
    1800
&H  1700
-P

rt)
 e  leoo
   1500
   1400 —
   1300
                    Avg
                                c
                                 L
             Nat.Gas     Utah Coal    I11.Coal    Pitt.Coal
Figure 7.   Typical radial temperature variations.
                             18

-------
                     TABLE 3.  COAL PROPERTIES  (AS FIRED)
Rank
Proximate Analysis
% Moisture
% Ash
% Volatile
$ Fixed Carbon
HHV (Btu/lb)
Ultimate Analysis (% wt)
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Oxygen
Sulfur Forms
% Pyritic Sulfur
% Sulfate Sulfur
% Organic Sulfur
Total Sulfur
Utah Navaho
Bituminous Subbituminous

4.24
4.85
36.38
54.53
13111

4.24
71.52
5.44
1.52
0.01
0.54
11.88

0.19
0.01
0.34
0.54

8.33
17.00
34.53
40.14
10336

8.33
57.98
4.40
1.48
0.01
0.57
10.23

0.19
0.00
0.38
0.57
Illinois
Bituminous

12.02
10.24
33.27
44.48
10941

12.01
60.42
4.36
1.07
0.03
2.94
8.93

1.27
0.06
1.61
, 2.94
Pittsburgh
Bituminous

1.67
7.16
37.13
54.04
13624

1.67
76.16
5.10
1.48
0.02
1.81
6.60

0.93
0.02
0.86
1.81
        Ash content varied from 4.85% for the Utah coal to 17% for the Navaho
subbituminous.  The sulfur levels covered a wide range from 0.54% for the
Utah coal to 2.94% for the Illinios coal.  The fuel nitrogen did not vary
greatly from one coal to another.
3.3     NITRIC OXIDE REDUCTIONS
3.3.1   Effect of Temperature^ and Coaj- Type
        One of the primary variables which determines the amount of NOx removed
by the injected ammonia is temperature.   Previous studies have shown that
the selective homogenous gas-phase reduction of nitric oxide occurs optimally
                                       19

-------
 at about 1750 °F in gas and  oil-fired  systems.   One  of the major objectives
 of this study was to determine  if  comparable  results would be obtained with
 coal-fired systems and the extent  to which varying coal properties  (e.g.,
 sulfur content, ash characteristics, etc.) might affect the efficiency of
 the process.  A summary of the  results obtained  during this study for all
 four coals and natural  gas is shown in Figures 8a and  8b at molar ratios of
 ammonia to initial nitric oxide of 0.5 to 1.0 respectively.   It  should be
 noted that the curves shown in Figures 8a and 8b are cross plots of the data,
 and not curves drawn directly through the data points.
         For comparison,  the data from Reference 4 are  shown relative  to the
 natural gas tests obtained during this program in Figure 9.   The data  from
 Reference 4 represent NO reductions by ammonia in a natural gas-fired com-
 bustion tunnel which was isothermal radially and provided rapid  mixing of
 the ammonia with the combustion products.  The NO reductions obtained with
 coal  and gas firing during this study were not as great as those previously
 obtained in  the  small combustion tunnel (Ref.  4).  This is probably  attri-
 butable  to the radial temperature gradients in the larger coal and gas fired
 combustion tunnel.
         The  other point to be noted is  that while the temperature retired
 for peak NO  reductions  fell within the  range  of 1720  °F and 1830 °F,  the
range for natural gas and the Utah, Navajo, and Pittsburg coals was  between
1720 °F  and  1760  °F.  The temperature  required for peak NO reduction on
Illinois  coal  was approximately 1830 °F.   The levels  of NO reduction on all
fuels tested were comparable.
                                     20

-------
  1.0
  0.8
  0.6
O
3
O
Z
  0.4
  0.2
    0
           	•— —•— Natural Gas
- 'Jtah Coal
- Navaho  Coal
— Pittsburgh Coal
— Illinois Coal
    1500      1600      1700     1800     1900
             Average Radial Temperature, °F
                              2000
                                           1.0
                                                              0.8
                                           0.6
                                        O
                                        S
                                        3
                                           0.4
                                                              0.2
                                                         — —	Natural Gas
                                                         	 Utah Coal
                                                         	    .. Navaho Coal
                                                         •         Pittsburgh Coal
                                                         	 Illinois Coal
                                                                           I
                                                                I
                                                                                 I
I
                                                    1500     1600    1700      1800     1900
                                                              Average Radial Temperature,  °F
                                                                                          2000
                 A.

  =0.5, Excess 0^ r
o                2
                                 5.0%)
                                                                                        B.
                                              (WH  /NO  =1.0, Excess 0. ^ 5.0%)
                                                3   o                 2
                    Figure 8.   Effect of temperature on NO reductions, coal and natural gas firing.

-------
1.0
0.8
0.6
0.4
0.2
            i	1	r
                \
                 \
	  Present Study
      .  Results from Ref.  4
                      I	I
  1500     1600     1700     1800      1900     2000
                   Temperature, °F
                                                  1.0
                                                            0.8
                                                            0.6
                                                          §
                                                  0.4
                                                            0.2
                                                              0
                                                                        i	r
                                                                   	 Present Study
                                                                   -~~~~~" Results from Ref. 4
                                                                        i        i          i
                                                    1500     1600
 1700     1800
Temperature,  °F
1900     2000
                          A.
                                                                             B.
    [NH /NO  = 0.5 (molar), Excess O  ^ 5.O%]
                                                      [NH /NO  =1.0 (molar),  Excess O_ "a 5.0%]
                                                         3   o                        t-
                          Figure 9.   Comparison of NO reductions for natural gas fuel.

-------
        One possible reason for the variation of temperature required
for peak reduction might be the sulfur content of the fuel.   Limited testing
was conducted to determine the possible effect of sulfur on the NO reduction
process.  During these tests, the unit was fired with a distillate type oil.
Carbon disulfide (CS2> was used to vary the sulfur content of the flue gases.
Ammonia was then injected at molar ratios of NH^ to initial NO of 1.0, and
the injectors moved axially in the furnace to change the average temperature
at the point of injection.  The results of these tests are shown in Figure 10
for sulfur dioxide levels in the combustion products ranging from 120 to
2900 ppm.  Over the range of sulfur tested, there was no effect in terms of
the temperature at which maximum NO reductions were achieved.  In Figure 10
the data have been plotted as a function of axial location at the point of
NH3 injection along with a scale showing the approximate average axial
temperature.  This was done since the radial temperature gradients with oil
firing are greater than with coal, and sufficient characterization was not
made in order to establish an accurate average radial temperature.  While
these tests do not conclusively eliminate sulfur as having an effect on the
NO reduction process, they suggest very strongly that the sulfur does not
interfere with the NO/NH, chemistry.

3.3.2   Effect of Ammonia Injection Rate

        The effect of the amount of ammonia injected on the NO reductions is
shown in Figures 11 through 15 for the four coals and natural gas.  In these
figures, the ratio of the final NO concentration to initial NO concentration
is plotted versus the ratio of the amount of ammonia injected to the initial
concentration of NO (molar basis).  Two test series are shown in these
figures.  The open symbols represent tests for which ammonia, cyanide, and
nitrate data were obtained.  The closed symbols represent results of tests
in which only the reductions in NO were determined to establish repeatability.
                                     23

-------
          1.0.
          0.8
          0.6
       o
       I
       53
           0.4
           0.2
                         T
                T
                Excess Oxygen ^ 5%
                Initial NO (NOO) :  350 ppm
                NH.YNO  ^ 1
                  3   o
           Back
           Wall
                      ri SO  = 2900 ppm
              r—     A
    so.
     I
= 1100 ppm
=120 ppm
                                     I
                     I
I
     12           34
Plane of NH3 Injection,  Ft From Back Furnace Wall
 	.1.1          I         I
                                 1500        1600        1700      1800
                                    Approximate Average  Temperature, °F
Figure 10.  Effect of sulfur on NO reduction  (oil  firing.)
                                     24

-------
      1.0
      0.8
    O
    3
                               NH /NO ,  Molar
                                 3   o
                                   Open Symbols -  Byproduct emissions
                                   Closed Symbols  -  Other Data
                                   Avg Temperature at Injection Point
                                          £  1515 °F
                                          ^  1625 °F
                                          £  1725 °F
                                          £  1780 °F
                                           Initial  NO -  500-550 ppm
                                           Excess O  - 4.7-5.3%
Figure 11.  Effect of NH, injection rate on NO reductions  (natural gas
            fuel).
                                   25

-------
                           NH./NO
                             3   o
                                2.0                 3.0
                        Molar
                   Open Symbols - Byproduct Emissions
                   Closed Symbols - Other Data
                               Average Temperature at Injection Point
                               01600 °F
                                  1700 °F
                                  1730 & 1750 °F
                                  1770 & 1780 °F
                      1790

                      1830

                      1870
                                        F

                                       °F

                                       °F
Figure 12.
                      1880 & 1890 °F
                   ^ 1925 °F
                   A 1945 °F
                    Initial NO  660-810 ppm
                    Excess O   4.7-5.3%

Effect of NH3 injection rate on NO reductions (Utah
coal) .
                                26

-------
   1.0
   0.8
g
   0.6
   0.4
   0.2
                                                            o
                       0.5
                                    NH /NO ,
                                      3   o
1.0                1.5               2.0
   Molar   Open Symbols - Byproduct
                          Emissions
           Closed Symbols - Other Data

           Average Temperature at
           Injection Point
           ^f 1625-1660 °F
           Al685-1700 °F
           • 1715-1740 °F
           ^1830-1855 °F
           • 1880-1890 °F
           01950 °F
           Initial NO  570-760 ppm
           Excess O   4.8-5.6%
       Figure 13.    Effect of NH, injection rate on NO reductions (Navaho
                    coal) .
                                        27

-------
   1.0
   0.8
   0.6
   0.4
   0.2
O
                         0.5                  1.0                  1.5
                            NH /NO , Molar
                                       Open Symbols - Byproduct
                                                      Emissions
                                       Closed Symbols - Other Data
                                       Average Temperature at
                                       Injection Point
                                         1660 °F
                                         1750-1780 °F
                                         1815-1830 °F
                                      0 1860-1865 °F
                                      • 1890-1915 °F
                                      • 1965 °F
                                      Initial NO  730-790 ppm
                                      Excess O   4.7-5.4%
Figure 14.  Effect of NH  injection rate on NO reductions (Illinois
            coal) .
                                 28

-------
 1.0
                             NH_/NO ,  Molar
                               3   O
                                      Open Symbols - Byproduct
                                                     Emissions
                                      Closed Symbols - Other Data

                                      Average Temperature at
                                      Injection Point

                                     ^1330-1395 °F
                                     91405-1490 °F
                                        1500-1540 °F

                                        1545-1580 °F
                                        1615-1635 °F
                                            ^1670-1700 °F
                                           ^1725-1760 °F

                                            • 1770-1815 °F
                                            ^1830-1900 °F
Figure 15,
                         Initial NO  550-800 ppm
                         Excess O2  4.6-5.8%

Effect of NH  injection rate on NO reduction (Pittsburgh
coal).
                                  29

-------
Scatter in the data is suspected to be primarily due to variations in the
radial temperature gradients in the firetube, and the ash accumulation which
made a single temperature determination difficult.
        As discussed in Section 3.2, the temperature at peak NO reductions
differed somewhat from fuel to fuel.  A comparison of the data obtained at
the temperature where the maximum NO reductions are achieved is shown in
Figure 16.  This figure shows that although  the optimum temperature varied
 from coal to coal,  the peak  reductions  in NO were within  the data  scatter for
 all fuels tested during  this study.
 3.4    NH3 EMISSIONS

        Ammonia emissions were measured for at least four temperatures cover-
ing the range of 1600 to 2000 °F for each coal.  These measurements were made
at the same conditions at which cyano and nitrate species were determined.
        The results of these tests show that the ammonia breakthrough dimi-
nishes as the gas temperature at the point of injection increases.   At
approximately 1900 °F, all traces of excess ammonia in the flue gas had
disappeared.  The disappearance of the excess ammonia coincides with the
diminished effectiveness of the ammonia in producing NO reductions.  At the
higher temperature, the injected ammonia will begin to react with the oxygen
in the combustion products to form rather than eliminate nitric oxide.
       The  ammonia breakthrough data for all fuels tested are shown in
Figure 17 through 21.   In these figures, the data are plotted in terms of
the ratio of  the  ammonia concentration  in the  flue gas to the initial nitric
oxide concentration.  This allows a direct comparison among the various testc
where the initial  nitric oxide concentration varied.  The scale on the right-
hand side of Figures  17  through  21 represents  the approximate absolute level
of NH3 in the stack gases based  on the  average initial nitric oxide level
for the test series.   As with the NO reduction data,  it  is  of  interest to
compare the ammonia  emissions at the temperature  of peak  NO reductions;  this
is shown in Figure  22.   This figure indicates  that the ammonia  emissions, when
normalized to the initial NO concentrations, were comparable except  for  the
Illinois coal tests.  The NH3  emissions from the  Illinois coal  tests were
significantly lower throughout the range of ammonia injection rates  tested.
                                      30

-------
  1.0
   0.8
   0.6
O
S3
   0.4
   0.2
                      I


                      |Q>   Natural Gas


                      O   Utah Coal


                      D   Navahb Coal


                          Illinois Coal


                          Pittsburgh Coal
                                                  00
                         0.5
1.0
                                                                  1.5
                                                  NH./NO  , Molar
                                                    3   o
                                                                                       2.0
                Figure 16.   Comparison of NO reductions  at  the  optimum temperature  condition.

-------
                   Injected, NH /NO , Molar
Figure 17.    Ammonia emissions,  natural  gas  fuel.
*Based on the  average initial nitric oxide level

 level  for the test series.
                                                          350
                                                           300
                                                        _  250
                                                        —  200
1515 °F


1625 °F


1780 °F
         Initial NO:  500 - 525 ppm
                                                                 I
                                                                 a,
                                                                 tn
                                                                 c
                                                                 o
                                                                 •H
                                                                 W
                                                                 w
                                                                 •H
                                                                 X
                                                                 z
                                                                 0)
                                                                 4*
                                                                 10
                              32

-------
   0.7
   0.6 _
   0.5
o
0°0.4
in
§  0.3
-H
H
   0.2
   0.1
              I
O 1600 °F
Q 1700 °F
A 1725 - 1755 °F
Q 1770 °F
£} 1880 and 1890 °F
O 1945 °F
Initial NO: 660-810 ppm
Excess O :  4.8-5.4%
                                                              _  500
                         0.5
                                           1.0
                                                                 400
                                                                300
                                                                 200
                                                                 100
                                                               1.5
                         Injected,  NH  /NO  , Molar
           Figure 18.    Ammonia emissions,  Utah coal.
       *Based  on the average initial nitric oxide level for
        the  test series.
                                                                      I
                                                                      04
                                                                     0}
                                                                     c
                                                                     o
                                                                     -H
                                                                      W
                                                                      K
                                                                      2
                                                                      QJ
                                                                      +J
                                                                      (0
                                                                      -H
                                                                      a
                                   33

-------
   0.7
    0.6
    0.5
 01


 O
••H
 03
 0)
••H


H
0.3
   0.2  _
   0.1
                                                                  400
 ^1625-1660 °F


 A 1685-1700 °F


 D 1715-1740 °F


O 1830-1855 °F


O 1880-1890 °F


O 1950 °F

   Initial NO  570-760 ppm
                                                                  300
                                                               200
           Excess
                         4.8-5.6%

                                                                       o
                                                                       -H
                                                                       in
                                                                       in
2

0)
4J
(0

•H
X
o
M
a
ft
                                                                   100
                                            1.0
                                                            1.5
                              NH.YNO
                                3    o
       Figure 19.  Ammonia emissions, Navaho  coal.
*Based on the average initial  nitric oxide level

 for the test series.
                                   34

-------
0.7
0.6
0.5
0.4
 W
 c
 0

 B   0.3
 M
-H

W
0.2
0.1
                                                               500
                                                               400
Q  1780 °F

A  1830 °F

O  1860 °F

    1890 °F
                                                               300
             Initial NO -  715-810 ppm

             Excess O  - 4.8-5.5%
                                                  200
                                                               100
                             NH /NO
                               3   o
      Figure  20.   Ammonia  emissions,  Illinois coal.
 *Based on the average  initial nitric oxide level for
  the test series.
                                                        •a
                                                        a
                                                        a
                                                                        o
                                                                        • H
                                                                        U)
                                                                        01
                                                                        •H
                                                                     ro

                                                                     §

                                                                     01
                                                                     4J
                                                        -H
                                                        X
                                                        O
                                                        ^
                                                        Ck
                                                        s-
                                35

-------
u
m
CD
•H


W
   0.7
   0.6
   0.5
   0.4
   0.3
  0.2
  0.1
                                                                500
OlSOO-1540  °F


Ol670-1680  °F





Ql770 °F


Q1830-1900 °F

Initial NO

Excess O_
                       0.5
                           1.0
                               NH./NO
                                 3   o
                                                                400
1.5
       Figure 21.  Ammonia emissions, Pittsburgh coal.
       *Based on the average nitric oxide level for the test

        series.
                                 36

-------
  0.4
        Q Utah


        Q Navaho


        /\ Illinois


        ^Pittsburgh


          Natural Gas
   0.3
 o

i  0.2
   0.1
              D
                               a
                           a
                          1.0
2.0
                                  NH_  /NO
                                    3     o
                                    o
                                                                    3.0
    Figure 22.   Comparison of the NH3 emissions for all fuels

                 tested at the peak NO removal temperature.
                                  37

-------
 3.5     CYANIDE AND NITRATE EMISSIONS
         Cyanide and nitrate emissions were  determined at the same test points
 at which  ammonia  breakthrough was  determined.
         Typical test results of the cyanide and nitrate measurements are
 shown in Table 4.   (The complete test results are contained in Appendix C.)
 The data in this table show that (1) for the majority of the data points with
 coal firing, the cyanide emissions were less than 2 ppm, and (2) the cyanide
 concentrations do not correlate with the amount of ammonia injected.  During
 several test series, higher cyanide concentrations were measured in the combus-
 tion products but again this occurred also at the baseline condition with no
 ammonia injection; no correlation to ammonia injection rate was observed.
 In fact, in some cases, the cyanide concentrations were less with ammonia in-
 jection than without.   These tests  support the conclusions from previous
 studies (Refs.  3,  4)  that cyanide species are not a byproduct of the NO reduc-
 tion process by ammonia.
         The nitrate emissions also  showed no change when ammonia was in-
 jected as compared to the condition when no ammonia was injected, indi-
 cating that nitrates are  not  a major byproduct of the NO reduction process.
 3.6     SULFATE AND SO EMISSIONS
         Table 5 contains  the  sulfate and SO  emissions data for the four coals
 tested  with and without ammonia  injection.   The effect of the ammonia on the
 sulfate emissions  was  not conclusive since  in two cases there was no change
in the sulfate emission; in one case there was an apparent increase and in the
other case there was an apparent decrease.  The fact that the data are some-
what inconclusive can be partially attributed to two factors:  (1) experimental
difficulty in maintaining the probe and filter at a constant temperature, and
 (2) no effort was made to determine if sulfate was retained in the boiler.
The procedure used to determine the sulfate and SO  emissions was outlined in
 Section 2.3 and discussed in Appendix B.
                                       38

-------
TABLE 4.  SUMMARY OF CYANIDE AND NITRATE CONCENTRATIONS
Fuel
Natural Gas




Utah Coal


Navaho Coal




Pittsburgh Coal






Illinois Coal







Ammonia In j .
T
AVg
<°F)
—
1780
1780
1725
1620
—
1700
1770
—
1700
1740
1840
1880
—
1730
1750
1760
1770
1850
1870
—
1830
1830
1830
1830
1860
1860
1860
Condition
NH3/N00
Molar
0
0.55
1.23
1.21
2.5
0
1.14
3
0
1.04
1.14
1.28
1.5
0
0.6
1.0
1.26
1.5
1.0
1.5
0
0.5
1.0
1.3
1.6
1.0
1.25
1.57
Flue
NO/N00
1.0
0.53
0.24
0.29
0.3
1.0
0.27
0.07
1.0
0.31
0.35
0.41
0.79
1.0
0.59
0.41
0.27
0.21
0.54
0.38
1.0
0.55
0.39
0.32
0.27
0.41
0.27
0.20
Gas Composition
CN
ppm
<1
<1
<1
<1
<1

-------
                   TABLE 5.  SULFATE AND SO3 EMISSIONS WITH
                      AND WITHOUT AMMONIA IN THE FLUE GAS
Coal
Utah


Navaho

Illinois

Pittsburgh

ppm, uncorrected
NH3 S04 S03
0
77
108
0
32
0
22
0
18
5
5
4
7
7
20
26
32
31
1
1
1
5
3
21
18
19
10
        However, the SO  emissions were observed to decrease when ammonia
was injected into the boiler for each coal tested and suggests that reac-
tions between NH, and SO, are occurring.  The decrease, however, was not in
proportion to the amount of excess ammonia present in the flue qas.
        Within the accuracy of the experimental measurements, it was not pos-
sible to detect a significant change in neutral sulfate emissions, although
a slight reduction in SO  emissions with ammonia injection was observed-  Further
work to clarify this matter would seem warranted.
3.7     CARBON MONOXIDE EMISSIONS
        The emissions of  carbon monoxide  from coal fired utility boilers while
not of primary concern  from the standpoint of pollution can  have an impact on
the efficiency of the unit.   R. K.  Lyon of Exxon Research  and Engineering has
indicated  that the selective NO reduction process will inhibit  the oxidation
of CO to CO  .  Thus if  CO is still  present at the point of ammonia injection
 its  oxidation could be  prevented  and it could be emitted to  the atmosphere.
                                        40

-------
         The test results from the present program on coal fired systems
 indicate that while there does appear to be some inhibition of the oxidation
 of CO to CO  this is not a problem over the range of ammonia concentrations
 of interest.  Typical baseline CO emissions for the four coals tested are
 shown in Table 6 along with the CO levels over a range of ammonia injection
 rates at various temperature rates.  As can be seen from the results of
 these tests, incremental emissions of CO with ammonia injection are slight
 and should not be a problem in coal-fired systems (further data can be found
 in the data summary sheets in Appendix C).
 3.8     SO  AND NOx MEASUREMENTS
         During the test program both SO  and NOx were measured to determine
 (1) if any excess ammonia reacted with the SO  and  (2) if there was a change
 in the NO/NOx ratio  (e.g. did the ammonia selectively react with NO or both
 NO and NO ).  For the case of the Utah and Navaho coals the NOx to NO ratio
 did not change upon the addition of ammonia indicating that the total oxides
 of nitrogen were reduced during the process.

        Some difficulty was  experienced in measuring  the  NO  and  NOx through
the heated line under conditions where the flue gas contained high concen-
trations of NH  and SO ;  in particular for the tests  with the Illinois and
Pittsburgh coal.   Reactions occurred in the heated sample line which resulted
in a net loss of NOx.   For instance, the dew point of the combustion products
from the Illinois coal was on the order of 270 °F.  Unfortunately the heated
sampling line was only capable of operation to 260 °F.   Thus some condensation
was expected with subsequent reaction with the ammonia and NOx in the sample.
Ideally it would be desirable to operate the sampling line above the dew
point and temperature at which the ammonia/sulfur compounds form (i.e.,
approximately 320 °F).
                                      41

-------
TABLE 6.   EFFECT OF AMMONIA INJECTION ON CO EMISSIONS
Fuel
Utah



Navaho




Illinois



Pittsburgh



Ammonia Iniection Condition
T
OF
—
1770
—
1770
1700
—
1715
1725
1740
—
1735
—
1830
1830
1830
—
1730
1750
1770
NH /NO
3 o
0
1.17
0
1.14
2.93
0
0.4
0.92
1.14

1.04
0
0.51
1.02
1.57
0
0.56
1.0
1.5
Flue Gas Composition
NO/NO
o
1.0
0.36
1.0
0.21
0.08
1.0
0.7
0.43
0.35
1.0
0.31
1.0
0.55
0.39
0.27
1
0.59
0.41
0.21
NH3
ppm
0
108
0
178
1008
—
32
13
22
—
—
—
3
12
112
—
5
41
100
CO
ppm
55
65
60
85
90
75
75
75
65
50
70
50
50
50
50
50
80
100
iqo
                          42

-------
         A similar situation was encountered with the continuous measurement
 of SO .   When the ammonia content of the sampled combustion products  was on
 the order of a third of the SO  concentration a loss of SO  was observed in
                               £                           £
 the sampling lines.   This was a sampling line phenomena and not occurring in
 the boiler since when the ammonia was turned off the heated line took approxi-
 mately 20 to 30 minutes to stabilize.  This suggests an adsorption-desorption
 process  on the teflon sampling line rather than a process occurring in the
 boiler.   At lower SO  to NH  ratios in the flue gases there appeared  to be
                     ^      *J
 no significant change in the SO  levels with ammonia injection.   The  observed
 changes  were as much associated with sulfur variability in the  coal fed to
 the boiler as any reaction with the excess ammonia.   The sulfate and  SO
 measurements tend to support this observation.
 3.9     AMMONIA AND HYDROGEN INJECTION
         A limited number of tests were conducted to  determine the effect of
 combined ammonia and hydrogen injection upon the NO  reductions  in coal-
 derived  combustion products.   The Pittsburgh seam #8 coal was used for these
 experiments .

         Exxon studies with oil and gas fuels had shown that at  a given tempera-
 ture,  hydrogen had the effect of increasing the NO reduction and simultaneously
 reducing the ammonia breakthrough.   That is,  the hydrogen can be used to pro-
duce higher nitric oxide reductions at lower temperatures.
        The data collected during this study confirms that the hydrogen allows
 the reduction of NO with ammonia to occur at a lower temperature.   A  typical
 representation of the NO reduction effect is shown on Figure 23.   It  can be
 seen from this figure that the addition of hydrogen  is beneficial in  the low
 temperature range.
         When the data such as that shown in Figure 23 are cross  plotted against
 the amount of hydrogen injected (H2/NH3 molar ratio)  for a given temperature,
 the resulting curve will exhibit a minimum (or maximum in terms of NO removal).
                                       43

-------
     1.0
    0.8
    0.6
o
2:
        1300
1400
                                             I
                                      I
                                                                        985
1500        1600         1700
        Centerline Temp.  °F
                                                                    1800
                                                  1
                                                             1900
2000
     Figure  23.   typical  NO reduction  with  ammonia  and  hydrogen  injection  - Pittsburgh  coal.

-------
The locus of all maximum NO reductions plotted versus temperature are then
plotted in Figure 24.  This shows the maximum NO reductions achievable over
the temperature range for a given amount of injected ammonia.  Figure 24
clearly shows that at temperatures below the optimum, the NO reductions can
be significantly better with H /NH  injection than with ammonia alone.
        The ammonia  emissions were measured for three temperature levels
with H /NH  injection.  The corresponding NO and NH  data are shown in
Figures 25 and 26 respectively.  These tests show that along with an
increase in NO reductions, hydrogen also results in  lower ammonia emissions.
At high hydrogen injection rates, the NO levels begin to increase while the
NH  levels in the combustion products continue to decrease.
         The experimental results presented in this  section are  drawn from
data summarized for each fuel  type in Appendix C.
                                     45

-------
     1.0
      0.8
      0.6
   I
      0.4
      0.2
                                                       NH /NO  % 1.0
                                                         3   o
                                 No Hydrogen Injection
Maximum Reduction
Obtainable with Hydrogen
Injection
                           I
                   I
I
                1300     1400      1500     1600     1700

                            Centerline Temperature, °F
                                              1800
                  1900
Figure 24.  Cross plot of the optimum NO reduction for NH /NO  = 1.0 (variable
            hydrogen injection),  Pittsburgh coal.             °
                                       46

-------
    0.2
      0
 c
                                                 ppm   Temp. Range
                                                 655   1395-1445
                                                 610   1540-1640
                                                 680   1700-1705
                                                 680   1710-1715
                              1.0
2.0
                                                                             3.0
                                    H2/NH3, Molar
Figure 25.  NO reductions with ammonia and hydrogen injection - Pittsburgh coal.
                                      47

-------
oo
                          0.2  —
                                                                             2.0
                                                             H /NH ,  Molar
                                                                                                       600
                                                                                                    _ 500
                                                                                                    _ 400
                                                                                                       300
                                                                                                    — 200
a
in

o
•H
w
en
•H
0)
+J
<0

•H
X
o
                                                                                                    _ 100   ft
                                                                                                    3.0
                                 Figure 26.   Ammonia emissions for ammonia and hydrogen  injection - Pittsburgh coal.
                                          *Based on the average initial NO level  (See Figure 25.)

-------
                                  SECTION 4.0
                                  CONCLUSIONS

1.      NO reductions obtained with ammonia injection into coal-derived
        combustion products were comparable to those previously obtained
        in natural gas and oil-fired systems.  On the order of 65% reduc-
        tions in NO were obtained at an ammonia injection rate of one
        mole of ammonia per mole of NO.
2.      The temperature dependence varied from coal to coal.  The Navaho
        coal exhibited peak reductions at the lowest temperature, 1720 °F,
        while the Illinois coal showed peak reductions occurring at
        1830 °F.  No definitive reason could be found to explain this
        variation in temperature. The  unexplained variation in optimum
       process  temperature with  coal type  indicates that evaluation  test-
       ing would be prudent  in situations  where maximum NOx control  was
       desired  and no previous experience  was  available for the  coal in
       question.
3.      In general,  the ammonia emissions (or breakthrough)  are comparable
        for all  fuels tested during this program.   The highest emissions
        of ammonia  occur when the temperature of the combustion products
        at the point of injection was less than that required  for optimum
        NO removal.   With judicious selection of the temperature at the
        point of injection,  nitric oxide reductions of 55%  were achieved
        while limiting NH  emissions to the range 11 to 34  ppm.
4.      Using injection rates of ammonia less than 2:1 NH /NO, no stati-
        stically significant changes in the cyanide or nitrate species
        concentrations were measured relative to the baseline  case of no
        no ammonia injection.  It was concluded that they are  not by-
        products of the deNOx process in coal-fired systems.
                                     49

-------
5.      Within the accuracy of the experimental measurements, there was a
        tendency to reduce the SO  level in the combustion products during
        ammonia injection.  However,  due to the small changes in the sulfate
        levels with and without ammonia injection,  the question of sulfate
        formation is inconclusive.
6.      The addition of small quantities of hydrogen can be used to increase
        the NO reductions and decrease the ammonia  emissions at temperatures
        lower than optimum.
7.      At a given temperature and ammonia injection rate there exists an
        optimum rate of hydrogen injection.  Further increase in this
        optimum rate results in decreases in the amount of NO removed.
        This optimum hydrogen injection rate increases as the temperature
        at the point of injection decreases.
8.     These findings with NH  injection into coal-derived combustion pro-
       ducts were in substantial agreement with previous experimental re-
       sults with gas- and oil-fired systems (Refs. 2, 3) in terms of
       achievable NO reductions, ammonia emissions, and byproduct formation.
                                      50

-------
                                 REFERENCES
1.      Proceedings of the Stationary Source Combustion Symposium,  Volume
        I - Fundamental Research, EPA-600/2-76-152a,  p. 1-14,  June  1976.

2.      Lyon, R.  K., "Method for the Reduction of the Concentration of
        NO in Combustion Effluents using Ammonia," U.S. Patent No.
        3,900,554, assigned to Exxon Research and Engineering  Company,
        New Jersey, August 1975.

3.      Lyon, R.  K. and Longwell, J. P., "Selective,  Non-Catalytic  Reduction
        of NOx with NH3," EPRI NOx Control Technology Seminar, San  Francisco,
        California, February 5 and 6, 1976 (EPRI Special Report SR-39) .

4.      Muzio, L. J. and Arand, J. K., "Homogeneous Gas Phase  Decomposition
        of Oxides of Nitrogen," EPRI Report FP-253, August 1976.

5.      Muzio, L. J., Arand, J. K., and Teixeira D. P., "Gas Phase  Decompo-
        sition of Nitric Oxide in Combustion Products," EPRI NOx Control
        Technology Seminar, San Francisco, California, February 5 and 6,
        1976

6.      Chedaille, J. and Braud, Y., Industrial Flames, Volume 1; Measure-
        ments in Flames, Edward Arnold Ltd., London,  1972.

7.      Lyon, R.  K., personal communication, 1977.
                                      51

-------
THIS PAGE INTENTIONALLY LEFT BLANK
                52

-------
      APPENDIX A




EXPERIMENTAL APPARATUS
          A-l

-------
                                 SECTION A-1.0
                      EXPERIMENTAL APPARATUS AND PROCEDURE

         The test equipment,  shown in  Figures A-l  through A-4,  can be divided
 into five categories:  (1) burners,  (2) air supply,  (3)  fuel supply, (4)
 boiler furance,  and (5)  instrumentation.  Each of these  categories is dis-
 cussed separately below.
 A-l.l   TEST BURNER DESIGN
         A Foster  Wheeler burner  currently being used in  a  modern coal-fired
 utility boiler was  chosen as the basis for the laboratory  scaled burner.
 The modeling approach used was to preserve the temperature,  velocities,
 and volumetric heat release rate of the full size unit as  well as geometrical
 similiarity  of the  burner.  The  scaled-down version  of the full-size burner
 is  shown schematically in Figure A-4.
A-l.2   AIR SUPPLY
        The  air supply system is shown schematically in  Figure A-5.
        Three venturi meters and one  rotameter were  used to  measure  the
various air  flows into the boiler.  The total air flow was the sum of the
flows measured by the "main air  flow" venturi and the "tempering air"
rotameter.  Air from an indirect-fired preheater  passed  through the  main
air flow venturi, where the total mass flow of preheated air was measured.
The preheated air was then split into two streams:   one  to supply part of
the primary combustion air, and the other to furnish secondary air to the
burner.
        The solid fuel was added to the conditioned  primary  air  just upstream
of the burner.  The primary air-coal mixture entered the burner  tube tangen-
tially, forming a vortex.
                                     A-2

-------
 LEGEND -  For Figures  A-l - A-3
 1.   Primary Air Duct
 2.   Primary Air Valve
 3.   NOx-Port Air Duct
 4.   NOx-Port Air Valve
 5.   NOx-Port Air Venturi
 6.   NOx-Port Air Flexible Hose
 7.   NOx-Port Air Injection
     Torus and Inlet Pipe,
     Variable Position
 8.   Water Injection Nozzle
 9.   Burner Support Cylinder
10.   Air Register
11.   Flame Detector
12.   Ignitor
13.   Burner
14.   Ceramic Quarl - 5-1/2"
     Throat Diameter
15.   Observation Door
16.   Fire  Brick 25" Inside
     Diameter
17.   View  Ports
18.   Water Wall of Scotch  Boiler
     Steam Vent
19.
20.
     Stainless Steel Liner
     34" Inside Diameter
21.  Fire Tubes (62 with
     Diameter 2-7/8")
22.  Recirculation Gas Duct
23.  Recirculation Gas Venturi
24.  Damper
25.  Stack
                                      Instrumentation
                                         Temperature s:
                                          26.   Windbox
                                          27.   Hot End
                                          28.   Stack
                                          29.   Secondary Venturi
                                          30.   Recirc.  Venturi (Not Shown)
                                          31.   Primary  Air
                                          Pressures:
                                          32.   Windbox
                                          33.   Secondary Venturi
                                          34.   Recirc.  Venturi (Not Shown)
                                          Gas  Sample:
                                          35.   Hot End
                                   A-3

-------
     From Preheatei_j^f~~^
        and Fan
         Burner
          Air
I
        iner       Combustion
            33"    Chamber    l
                              h-
                           2*7"
                Solid Fuel    »• —
K\\\\\\\\\\\\\\\\\\\\\V\V\\
                                                             9'3"
                                                                                       22"
                                 t
                               Primary
                                Air
                                                                                                              Second-Stage
                                                                                                                 Air
                 Figure A-l.   Schematic of  eighty-horsepower boiler.

-------
                                  o©
Figure A-2.  Cross section through windbox.
Figure A-3.  Cross section through firebox.

-------
Castable
Refrac-
  tory
2.3
Castable
Refrac-
tory (High
Purity
Alumina)
                                                Primary Inlet 2x2 inside diam.
                                                                            Ignitor Gas •*- Air
                                      Coal

1


H'l
T

t 1.675
condary Air
1— 	 1
8.0
dia.
J Ter
*



tiary
1


                                                    t
                                                  .70 I.D.
                                                                             All dimensions in inches
  Figure A-4.  Small-scale version of a full-scale  coal burner.

-------
Gr
V_y Re
                                             Tempering Air
Rotameter
                                                                     Steam Fuel
                                                                           i    I
                                                                   Primary  Air
                                                          Secondary Air
                                                          NOx Port Air
                                                                                 To Burner's
                                                                                 Fuel Annulus

                                                                                 To Burner's
                                                                                 Air Register
                                                                                      To Torus
                                             Venturi
                        Figure A-5.   Schematic of combustion air supply.

-------
         The remainder of the preheated air passed through an insulated  duct
 to a point about ten feet upstream of  the windbox where two valves  were
 used to regulate the flow split between burner secondary and second-stage
 (NOx-port) air.   This feature was  not  used in  the current study and the
 second-stage air torus (#7,  Fig. A-l)  was removed.
         The secondary air  (delivered to the burner) was  split into  two
 streams which entered the windbox from opposite sides.   This air flowed
 into the combustion chamber through the burner's  air register vanes, which
 imparted a swirl to the flow in the same direction as the primary mixture's
 swirl.
         The second-stage, air passes through a  venturi meter, then into  a
 pipe leading to a perforated torus inside  the  combustion chamber.   The  air
 can  be  injected from the torus radially toward the axis  of  the  combustion
 chamber through 32 orifices, each 9/16" in diameter.
A-1.3   FUEL SUPPLY
        The solid fuels were fed into the  primary air stream by a Vibra-Screw
feeder with a vibrating-bottom bin.  The  feed  rate of the 1-1/2" diameter
spring-type screw was continuously variable.
        The feed flow included fluctuations which varied with each  fuel.
Fluctuations in flue gas excess O  indicated fuel-flow variations of as
much as +^ 5% in some cases.
        The natural gas fuel was supplied  by the  high-pressure  supply from
the meter  (5 psig).  Flow rate was varied  manually by a  gate valve  downstream
of a rotameter.
A-l.4   BOILER FURNACE
        The boiler shell  is  an 80 horsepower Scotch dry-back type boiler
originally designed for low  combustion  intensity.  The  steam produced was
vented  at one atmosphere.  Schematics  of  the boiler and  burner  were given
 in Figures A-l through A-4.
                                     A-8

-------
        The boiler's combustion  chamber was fitted with a stainless steel
 liner to give wall temperatures  of approximately 800 °F, which is typical
 for the combustion chambers of utility and large industrial boilers.
        The fly ash was removed  from the flue gas by a reverse-pulse
 baghouse.  Sulfur oxides were dispersed by discharging the ash-free
 products (through an induced-draft fan) to a 42-ft high stack.

        A valve at the baghouse  inlet was used to maintain the boiler
 pressure within 0.1 IWG of atmospheric pressure, thus minimizing leakage
 into or out of the system.
A-1.5   INSTRUMENTATION
        Flue gas samples were withdrawn by a diaphragm-type vacuum pump
 at three points just upstream of the boiler's draft damper.  Each of these
 sample lines had a porous metal  filter at its end to prevent fly ash from
 being drawn into the sample line.  The lines were periodically backflushed
 to prevent blockage of the filter.
        One of the sample lines  was used for the supply to the SO , NOx,
 and UHC analyzers.  The other two sample lines were fed to water-filled
bubblers where the sample flow rate from each line were approximately
balanced by adjusting the bubbling rates to be approximately equal.  The
 samples were then blended into a single stream which was passed through a
 filter and a Hankison Series E refrigerator-type drier to remove water
vapor.
        Concentrations on a dry  basis of NO, O , CO, and CO  were measured
 continuously using a Thermo Electron Corp.  chemiluminescent nitric oxide
 analyzer with a NO  converter, a Beckman Model 742 oxygen electrolytic
analyzer,  a Horiba Model PIR2000 nondispersive infrared carbon monoxide
 analyzer,  and a Horiba Model AIA-21 nondispersive infrared carbon dioxide
 analyzer.   These instruments were calibrated several times per hour using
known calibration gases.  The outputs of these instruments were monitored
 continuously on a Texas Instruments recorder.
                                    A-9

-------
        Sulfur dioxide was measured using a Dupont Model 411 photometric
analyzer.  The Thermo Electron NOx analyzer was used with a NO  moly
converter to obtain total NOx.  The converter was necessary to prevent
catalytic conversion of NH  to NO in the converter- which can occur with
a  stainless steel converter.
        Ammonia, cyanide, and nitrates were collected and analyzed with
specific ion electrodes as discussed in Reference 4.
        A Beckman Model 402 hydrocarbon analyzer was used to measure
unburned hydrocarbons.
        Temperature measurements other than the gas temperature in the main
firetube were made using chromel-alumel thermocouples.  The temperature
probe used to determine the gas temperatures at the point of ammonia injec-
tion were described previously in Section 2.3.1.
A-1.6   AMMONIA INJECTORS
        The basic schematics and a detailed design of the ammonia injectors
are given in Figures A-6 through A-8.  With the arrangement shown, the
ammonia can be injected at either a single location on the boiler center-
line (with six tip injection points) or at five locations as shown in
Figure A-6 (each with six tip injection points).  All injection orifices
are located perpendicular to the average flue gas streamlines (radial
injection).
        To maintain the integrity of the injectors, they were fabricated
from stainless steel and water cooled.  They were sized for 2 gpm per
injector flow rate at the most adverse temperature conditions with a maxi-
mum of 4 ft of each injector exposed to the hot gases.
        Nitrogen was used as a carrier gas for the ammonia to assist in
optimum penetration and mixing.  Each injector ammonia flow rate as well
as the total ammonia and nitrogen flow rates were measured as shown in Figure
A-8-
                                    A-10

-------
                                                                   Support Stand
               Combustion
                Products
Figure A-6-  Eighty-horsepower boiler ammonia injection schematic.

-------
to
                                  3.25-
                           2.0
                   —- 1.0
0.06
Washer Weld *"|
to Both  v
  Tubes   >|  *
I
                                                             See View A
                     3/16 x 0.029 wall
                     321 SS tubing
                            2.50
                                     3.75
                           5/8 x 0.035 wall
                           321 SS tubing
                                                           3/8 x 0.016 wall
                                                           321 SS tubing
                                                            96.0  —
, .38
rr
, 1


I


, -14
Kiz-
0.04 ^-\
0.03
View A

1
i —
-•
/
i-«
— i
s 180 dec
r orific
Ilnje
Inje
ODQ
~ ' 0.08
0.13
0.12
	 0.25
0.24
                                                               Six orifices equally  spaced with  two  orifices
                                                               180 deg.  apart  in  line with Swagelok  fittings
                                                                 Injector  #1  -  0.029-0.030
                                                                 Injector  #2  -  0.012-0.013
                                                     Fab only 1 injector
                                                     Fab      5 injectors
                                        Figure A-7.    Water cooled ammonia injection system.

-------
Circuit for
Single
Injector
I
T
            Rotam.

           0-0.3
            scfm
                             Rotameter   CO

                             0-1.5 scfm
                                          N,
                                                                    — Injectors
                                                     Rotameter
                                                     0-3  scfm
                Figure  A-8 .    Ammonia injection flow metering system.
                                      A-13

-------
        The ammonia injector orifices were sized to give sonic flow at
maximum ammonia flow rates.  The calculated pressure drop through a single
injector is 7.9 psi for the maximum combined flow rate of nitrogen and
ammonia.  The maximum ammonia flow rate per injector is 0.3 scfm (air
equivalent) .
                                   A-14

-------
                  APPENDIX  B
SULFATE AND SO  EMISSION MEASUREMENT PROCEDURE
                        B-l

-------
                                SECTION B-1.0
                    SAMPLING TRAIN AND SAMPLING PROCEDURES

         Figure B-l shows a schematic of the  sulfate  and  SO   sampling  system.
 It consisted of a heated quartz probe, a glass tube  adapter  for  introducing
 ammonia in the probe, a heated box which contains  the filter holder,  acid
 washed asbestos fiber filter, impinger train, ice  bath,  dry  gas  meter,  and
 a pump.
                      Probe
               Duct
                             Probe Adaptor (2nd Sample Use "T")
                                        'Heated Filter Box
                                                           Pump
                                                        Impingers 1st,  2nd,  3rd
                                                        thermometer 50  ml each
                                                        3% H202
                                                     Ice Bath
                   Figure B-l.   Sulfate sampling  equipment.

        A 30 cfm sample was collected at 1 cfm  from the  stack during which
time the probe was maintained at 205 °F, the heated box  was maintained  at
310 °F, and the impingers at 70 °F.  The impingers contain a solution of 3%
hydrogen peroxide in water.
        Two sampling modes were used.  One mode collects the sample directly
from the stack without any dilution or additions to the probe.  In the second
mode,  ammonia is bled into the probe before the heated filter to react with
any free SO  that might be present to form (NH.) SO. which would then be
collected on the filter.  Table B-l contains a list of compounds and their
melting points that potentially could be formed with the ammonia.
                                      B-2

-------
                         TABLE B-l.  AMMONIUM COMPOUNDS
Compound
ammonium sulfate (NH ) SO
ammonium bi sulfate (NH.)HSO,
4 4
ammonium sulfamate NH.NH_SO
ammonium sulfite (NH_)SO • HO
£ 3 £.
ammonium bisulfite NH HSO
ammonium hydrosulfide NH HS

ammonium monosialfide (NH .) S
rap (°F)
d 454
295.8
256.4
d 139.4 - 157.4
sub 301.4 in N
244
150 atm
d
bp (°F)
	
d
d 319.4
sub 301.4
	
1623
19 atm
	
        d = decomposes; sub = sublimes

        Following the  sample  collection, the .probe, connections, and front
half of the  filter holder were washed with distilled water.  The filter was
added to these washes  and reduced to pulp to dissolve all of the collected
sulfate.  The back half of the filter holder and connections were washed
with distilled water and added to the impinger condensate.  The impingers
contain the  SO  component and the filter contained either the SO  or SO
reacted to NH.SO  with added  probe ammonia.
B-l.l   SO   AND NEUTRAL SULFATE ANALYSIS
        The  gravimetric procedure was used to determine the neutral sulfates.
In this technique, the initial filter wash is filtered through a Whatman #4
filter paper.  The filtrate is heated to near boiling and concentrated ammo-
nium hydroxide is added.  This solution is then filtered again to remove
iron and aluminum and made acidic with concentrated hydrochloric.  Ten milli-
liters of a  10% barium chloride solution is added to the warm acidic solution
and allowed  to stand overnight to precipitate BaSO .  This solution is then
passed through a tare-weighed Gooch crucible.  The crucible is then baked
at 800 °C for 1 hour,  cooled, and weighed to determine the resultant
The amount of SO  equivalent  sulfate is calculated using the following
expression:
                                     B-3

-------
                              10,400 (weight sulfate as SO )
                SO ,wet     standard cubic feet of sampled gas

        The level of  sulfur trioxide in the flue gas was obtained by assum-
ing that the ammonia  injected into the probe reacted with all of the SO .
Thus the difference between the sulfate determined with and without NH,
injected into the probe is  the concentration of SO .
        The presence  of free SO  was detected by adding a few drops of methyl
orange to the filter  wash solution.   If the indicator turned the solution  red,
then free SO  was present and a standard acid-base titration procedure using
0.01 N sodium hydroxide titrant was performed.
                                     B-4

-------
 APPENDIX C





DATA SUMMARY'
    C-l

-------
NATURAL GAS FUEL
Test
Date
i-tt-n





























Time
I014S





(US'

IZoS






^IS"




1430




IS2o




2A
scfm
32 l(o
irao : . o
HN3 ; 0
14Z8 15
i&ss" zr
1611 * 35"
nat
1«4HC»
7o
o
Ifcft : ir
it-^o 2r
1703 sr
1130 70
14,3^ ! 0
ie«j( i it
1867
1^0^
zr
?r
\&ta i 75*
        C-2

-------
NATURAL GAS FUEL
Test
Date
l-H-77


















1-23-77










Time
1053


I2oo


I3o5





\52S~


I5S5T



loiS"










scfm
3Z

r
3S5"




i




»
3^o




>






3^






>






t



°2
Pet
H.5

^

-
5.S

i

r
S.-aj




«




F
6.1






t

r

7.q













*



Temp. Probe
Location
Axial
2




>




r
3

>

r
14

'

t
4 4
I
f
z

\



2






\






r



Radial
c^
















1
















f

O_

1

•
8
M
6
2
<^



Temperature
mzc,
i»0
O
20
7S
o
2o
70
O
nn i 20
nio
15QO
n&7
1 ^ ^.*3
1 TO J^
10
0
2o
7o
Itoq ; o
nil ] 20
I6S3
7o
l3C*i ; O
m£iQ j
ni^ t
143o
ISR4









i



       C-3

-------
NATURAL GAS  FUEL
Test
Date
1-31-77










2-/-77


















Time
leSS-










IC^S













1135




scfm
332








i










31o

































!
J
°2
Pet
7.o








)








/

SI

























P
62



1



f
Temp. Probe
Location
Axial
1}








^










3












•












r
•2.
X'/2
3
M
H'4
Radial
c^
4
8
^
5
(b
7
e
3
c^

CL


>
H


^

H'-i
8
8'/2_
2.
i)/*}
v?
T
G'4
^




i




(
Temperature Aspi^r
°F PC
IMlM 1
isii
i3«ie
less
1716
IM3I
151Z
lU7o
N73
iMol

1^03 7
ISBl
160-8
1734,
nto
\i^
ittr
\4«41
t-/^
[74,4,
147 e
Wftl
15-3^
1733
I6i|
11*21
n**r
ife^fc
l^f/M :
                                                ./
        C-4

-------
NATURAL GAS FUEL
Test
Date
2-1-17
















a-7-n












Time

















1015
12MO
132.0










scfm
390











i









1


i

3SI
4
?











Pet
s.



e



i
i
j
;
!










]


-

5,0
5,1
5
.or










Temp. Probe
Location
Axial
H








i








1
2.
3
M-
a
3
14

3
i
T










Radial
Q.
8
^
M
5
G
7
2
3
Q.
1




i

Ci.

i




i














Temperature
op
1S4G
Hft5
UTI
1851
ITte
H85
l4M*i
16^5
1^90
n^o
\1T(
134,1
mw
icia
nzs
1^2S
fl^,-
10
o
1
1

/^7I
lobo
161 S




I


I





        C-5

-------
                                    NATURAL GAS FUEL
Test
Date
Time
scfm
Pet
                               Temp. Probe
                                Location
Axial •
                    Radial
Temperatvire
    °F
         looo
        3 £5"
                                       3'4.
                                                   S
                                                   1
                                                                16S5"
                                                                1513
                                           C-6

-------
                           UTAH COAL A
Test
Date
          Time
                  scfm
°2
Pet
                                    Temp . Probe
                                      Location
Axial
Radial
                                                      Temper at lire
3-q-n
                LlCUT
        IS'IO
                                                       1325
        isvr
        tSSB
        IGZo
                          H.fc

                                                        IS52
                                                      13&4
3-vn
                         5.o
                                                       Ifcoo
                                            8
                                                      IfeSl
        itsr
                          53
                                                       IS4B
                                   v
                                   u
                  x
                                                           ASF
                               C-7

-------
UTAH COAL A
Test
Date
3-2$- -17












5-IZ-T7
















Time
1330
I3SO
mis*
HSr
iwr
HVf
lS2o
issr
I$"M'
4,4


i





rr
S.


i
5.
5
^

S


/
t
,1
(
(*
g.l
q^-
1
5,t
5.^
S.T


Temp. Probe
Location
Axial
z
1
^
3
«4
>
'
2.
•4




>




•


2
>
f
3
(i


>



^
V
4
V
^
t
V
3


Radial
^








t
?
^
•4


5
7
3


c^















y


Temperature
oF
/32o
IG01> A.CJP
I'^l'i
i'-r;>:
1121 Ast-'
161 G /'.-:,
N5|
[LJ37_
1^/1
IS^T
lLi--:ci
I'sipO


I3ol
\llQ (\^
HIS" ^<;r
l§^3 Asp
IS2o
I5SS"
i^ti f;-y
|2~/3
i? §s iW
i^ c "^i
1 I I 1 ' \*-* (•**
\2G2-
t— »-^ f * J*.
i/6 /\MJ
|7»4 i\cv-


    C-8

-------
NAVAHO COAL B
Test
Date
3-31-17





























Time
oc\\o
I 1 lo
tl IS"
1(25
1130

























QA
scfm
LIGHT
372,


i

























°2
Pet
ore
5.f


i p

























Temp . Probe
Location
Axial

a
\
4
y

























Radial

GL.


% '

























Temper at \xre
OF

1290
\5oe> ksp.
1^3
I43o ASP

























      C-9

-------
ILLINOIS COAL C
Test
Date
4-ZO-T7











•j-A-7"'









s-mi







Time
03 OS
0'-!o5~
fc-c;

1010

|02S^
Wi

BIT


09 20
13MS"
IVJT
Woi
Wfc
m? c
IvA
r,.."
H:',o

c-'-.s- .
Hri
W'i\'
ViV.,




scfm
LlGtlT
34.7








]








t

LlGv\l
3(,x









Y

I
'A >\
\
\




°2
Pet
orr
b^
5/L












i

orp
A|.g








!
t

t v
H.s-


1
y




Temp. Probe
Location
Axial

2}4
2
i
M
4-.
1
i|




V


H
;





Y


I
's .
ll




Radial

^










V


CL
4
S
^
^
7
3
c^


c.u
i
t
i






Temper at ure

IZfco
^0
I6,3o ds^
ISfB
I^S ASP
12.^0
1523
I8SO Asf
i^n
Ron As«J


/ tj I ^3
I / (j /^
\^>2^(
1 / f *^
I (^ \ /
14SZ
l^'/
1 9' |6 Asf*


\6W: r\..v
\(- • I- •
Kl'^/i




     C-10

-------
                          PITTSBURG SEAM  8 COAL D
Test
Date
            Time
scfra
02
Pet
                                          Temp. Probe
                                            Location
Axial
Radial
Temperature
    oF
         llT-o
                               ' r
                             £,D
                                          X
                                        V
                                                                 nsi
         WD
                                          •3
         ISC*
                             V
                                                                 ..
                                                                     AsP
         L
                                                            r SHIP 1.05   £'•-••
6-I-77
         12
                                       '2..
                                                    Cu
                                           Wo
         Wio
                             V
         CSVT
                             5.c
         Mo
                                                    e
         IC'i'C
          li is
          HIS
                   J:
                                  C-ll

-------
TMt
D«t«
I- I-TI
S-.V.i' '"• : '• -•••
••;-Lf-













o
KJ





''-1-1"
f... t,:r ', .- ••
L .. - L.P












time

\S'-j
15 -~
iJ': =
if-.r

'.. •
]•;,-
."••7
15*0
• -••
i ?. -. -
Kii
I--. :'
It: 2
Iw 1
:L:.'-i

il, ~
', ' ' :)
•..:-.
\'.'.-\
IM:

::£j
• >-(
:'V:1
,55]
1^.3

vt't
;-il
I;-,?
''•T






mel Type

Uftf






















K,\r















&A?






















1?^














Gas Tow

i:>i?
1
|


r .- ••.


,
•<
":• :.



•\








11? 5

!o
'^,
i





f
nji


Y














































Plow Raton (scfrn)
^
?J '
|
!
!




!












V

?3:.i
j
!






^





"NO
J9&
I
I
i


i
1
1
t
.:fl


V
.V:^



,

1
y

.ITj








•^





n
Nil 3
O
.'/-'.
.ni
.-:.;
1 '..
i>: -.
Itn
:; ,j.

-*1-;
4cr
s/,..
3:i-
Jj3
Li^i,
-.,"'
r •* '
'j'v'J


-

_2z

5,1
-.•-
- .->
. .1
-
;-_..


c.o__

S, I
f.O
^.'1
if r.
";.!
" -,
". „
J. ,
', _ ,
",. ••
5,0


5.1
5.1
:;.|
",|
3,1
'j ' 1
.?;.'
i'l
5,i




ro

— •






















r

!0

t

i
1
1
1

v


-•

CO,
1— itt_
1'^






!





,






"T '


If

^,5







j


[
^




ml
^

-
I




\
I

i
I

!




,





p
i
y

-



I



'








HI
~l

—




!













|
i
!

1


—
i
I
!

1
!
i
V1.




TIO-j

—


























1.
-
|






"l













w«t
so

"T
1



















r

—







~








i





NO

-
!



















t

—








1











—

N'»e

-




i


!














f

—











•-








-

line
_ffa.
—
1
I


















Y

-





	







.Molar __ Ratios
 NII3   KO    Ha
              ~
 l.d
      /.c
      ,7s
      .153

-------
Test
Data
            VI
           il'Ll
            i n
           1',"-.
  Priivary
Fuel  Type
Center line
Gas   Temp
flow Roto* {acfm)
^
31o




























—


—



V
. ! ?- 'i



Y
.ir/r;






i







j

,!%




f
.IT1
J..

Y
	



°NHj
0
.C?l
.i8(i
.2? '
'j:!
,i-ii
.?3
•VI
,?lu
.icl
.-,
.fi'rt
.?IS
.-•'.'/
:'•'!
."ill
,11.'..
.Hi
.i';-;
.i'i't-
••/''•
0
0
c-l
.!*.'«
?p-
.M
o
o
,3^^
MS'f



°H,
O
|




!
;
!







'_



1



!





.._

                                                                                                            Stock Emissions
                                                              5 in
                                                                                |O
                                                                              /'b
                                                                                     5,1
                                                                   -f,/
                                                                                              Dry
                                                                                                J.
                                                                         Mil,    HCN   NO
                                                                                                                                                              Molar  Ration
NIJ3   NO
NU0 I NOp
                                                                                                                                                              (.17
                                                                                                                                                              US'
                                                                                                                                                               -lf.
                                                                                                                                                                    1.0
                                                                                                                                                  •'•'1
                                                                                                                                                                   1.0
                                                                                                                                                                    1.0
-"2j
NX

-------
        Pilwry
      ru«i  TYP*
Ontarlinr

Gas   Temp
NZi'
iiio
US'
                  nzr
riov Rit«» (»cf»)
?Wt
^=|o









!












j

Y

31-)











—










i
1



So
,n
• ••;-
;ur
-T
irfs-
/•r
; ;?
1:1
:,'•-

Soo
JSO
330
Ito
'-(T
4;.- o
l"'
llo
i;^0


-

.2?

s. 1




1
;
j





j







5.0
























v




CO






i










i
'•


!

Y

10













;



f


-

CO,

'J '


















1

t

9

*















!


1
Y




NHi






1
1








r

_

i

;


'
i
i


•

Y




HCN




1
i



;






Y

	


i












!

i
y



NOj








|






i




1
y

_



















t


	


Wat
'•2

—






















f

_

i


'







'


f





NO







i



;




1

t

—





















Y



_.

NOx







i
I









Y

—
















	





1

''




OHC






|



!



.-L
v

-
—









^-

Y

	
—    "Q
Nl^o I NOn  TNH"
                                                                                                                                            Molar  Ratio*
                                                                                                                                             LIO
                                                                                                                                             .Jf-
                                                                                                                                             1.11
                                                                                                                                             l.tit,
                                                                                                                                             /.it
                                                                                                                                             l.t1?
                                                                                                                                                  .'73
                                                                                                                                                  I.C
                                                                                                                                                   .0
                                                                                                                                                  1,0
                                                                                                                                                  .10
                                                                                                                                                   •'1
                                                                                                                                                  l.o
                                                                                                                                                  .(, b"
                                                                                                                                                  l.o

-------
      To«t
      Data
?.-'-!- "17
                Time
                I'1-!
                15'IJ
                I*?-!
  Primary
ratl  Type
Centerline
Gas   Tent
                 '. K
                                  Sr/
Flow Rates (scfm)
2ut
3tr


























t

M-,"
































"NO
,13
o

—



_^









1
7i"

                                                                                                           Stack Emissions
                                                                                so
                                                                               CEm_ SXA.
                                                                                /i'O
                                                                                n?
                                                                                w;
                                                                                     5,?
                                                                                      i.V
                                                                                     s.ir
                                                                                     s.c,
                                                                                     S.i.
                                                                                     f.S
                                                                                     S.',
                                                                                     ?o
                                                                           CO?
                                                                          _V_.
                                                                                ±

                                                                                            X
                                                                                            JL
                                                                                                                                       Wet
                                                                                                                                               -ppa
                                                                                                                                                V.
                                                                                                                                                           Molar  Ratios
                                                                                                                                                           NH3  MO
NU0
                                                                                                                                                           1.01
                                                                                                                                                            ,(,fe
                                                                                                                                                           ill
                                                                                                                                                          M
                                                                                                                                                            O
     NOp   NH3
                                                                                                                                                                 1.0
                                                                                                                                          /.£>

-------
     TMt


     D*t«
q-6-'/7
   -2-
   -5s.
              InCO
                   NAT
                            C«n t«r line
                                "'•C
/.i:
                            IBS
                                 $'<

?&
3



















i

















Mo
it
ir

!










f

^


^

ff

















H It
°K













1


,;'






,n

,,.-


i
l'f








At*
O


.










{

'A
>v





^
u
•

i










>
M

•)
S

>

>






n)
8«













i

f
*




£


















2













r

>


/

5

















St4Ck Emissions
Dry
NO

$J-J
*?'•:
'ft'<
;,
'} ' "
4'~j
'it'::.
•>'?~
i'^'J
>SO
Sio

Si?
5^0
;.'.:i
^1^9

Sz;-
3or>
OSo
S'co
^a,-;
UJT3
520
I5o
5IS
=,5
SI?





£>

ser
,
.'»./
. /
,'."'
4
2-
C'.V"
r,f!-'
6.Z
'f?
^,J_
§
v
(o
f
s.°(

S.'i


,



1

s.q
S,M
5.4
5.5
5.^
S.-i
5.M
%ii
S-'l
3
5
M
j
5, -a,





CO

—










t

y

-
i

'

{

-









1















CO,

?.7
j

3
V
5 » j
?.7
r
•?.3
s-7


t
t

9.1
i
") '

1-1









r





liH,

—




t







V

C.S
-
/2a

	 .
3"?.S
-
-
20"!
_
-
721
-
,'j
_





HCtJ

	






j





V'

—


^



r
_









!














NO,







,


|



j.

—

1
—
f

—









•

...















W t
1 :v 7 .

_












y

r


_5


^_
-

























—


HO

-





1




i
!
v'

-


_L.
-




























NOx

...





1
i



[



y

— .


J_
—





















—


UHC



























t_
_
1
[
-^
-

!







1









:
Molar Ratio.
Jffi3
N00




























'

o
<••
'/.T
0

C
.s
0
C
I.It
o
o
2. "4,
0
c
fr°
o





NO
N00

—

.










V

l.o
l,ci
.
-------
T«t
Date
2-10-17














.
>— ^
-o






2-/I-77














TiM

I2ST
I'iaO
1312.
1321
l?=sS
!?•?(-
i ="•,$-
!=SS
|Uso
Mf
W<£
IMi~
ITpi
ISIo
Ifif
I?3S
ISSs
Itoo
IU5
It If
IUo
It??

l«o
IU2S
W5o
l2
Slo
l«
SiiS"

5oo
310
Sc-S"
210
5or
Wo
110
S^
ss
?IT



JOj

H
1
S.o
i





5,





f

!
i

'



j
s.. ••:
S.'.S
S.o
S. 1
S.o
i

S.
o










!
1




1
I
;
;
~r

•


r

o




















—
NO

—
1
















_-.

1

'

—







1







—




-.-
NOx

	
3/o
-
255
—
—
//o
—
—
5S
—
32T
—
3.2 r
_
ISo
—
—
-?£•
iz
—

—









...





—




UHC

-
t
















1
f
^

—
|
1


~^
-f-

1
i

Molar  Ratios
NH3  SO    H;
            ~
.so
.So
 H7
 .17
7,o
 o_
      l.o
     I.O
     1,0
      .24
     1.0
     1,3
     l.o
     l.e
     i.O
     l.o
     (.0
     1,0
      faZ
     l.o
     l.o
     1,0
     .118

-------
TMt
D«t.
2 -is -n










2-l(.-"n


0
CO






















Tin*

lljf
1210
mo
in£
IVi'S
lie?
BIO
BIS*
I33S
fiSO

loSo
1112
HZo
1130
II?1?
IISO
1200
1707
"-'T
iz^.T
12'?
ii'iT
115 'J
|5,;r.
r- .11
IV 1 "
B'^o
l^-'.
J'iSi"









rriMry
ni«l ivcw

()AT










>\K'



























(.*.'*










'^^;



























Cent«rlin«
Ga« Tern

It









80








/

J8'/-i


















nzo







i























































flow Fates (icfm)
ite
331
1
1
1
1



i
j

3T/



1







'
?n







_i










E

v
,o'^Z7
,l?0



,
,f77
,iji
;
.153
•


61

,o3»(
,l?0



1








.nc.



,i






2



.1.

,
—


5\?
113
5 IS
W
5"3o
io
S'JO

Cjrq
5(0
xVO
510
ISO
Slo
SS
Slo
>1
Slo
5bo
3"te
i'to
?•'/ ,•>
Sts
K.1
Sis
9':
b'Ao






0

?

5,|
S.o
1
,1
5.1
H.I
5,o
u,^
5.0
q.«l
i^

H
?








I


f
4.S


! .






1








CO

-
1

















-

1

i




r
-









i








C02



















'

1-3









—


Y
1.1




i
i

t

i




—


Nil!

s.g
—
It
_
S'o
-
Moo
_
isr-1


—



!


_.


?
-_
1








1

1

/






11 CM

< \
-
^|
^
->.|
-
•'•I
_
•'-I
-

^/
—
-I.)
_
-< |
-
-M
_



















—


NO
"
-
'I
I






v

-

t






—
t
—







)







1

...




:::[..


NOx

-

XSo
-..
—
—
Mt,
-
22,
—

-
—
_
—
m
—
s?
-
2.2
-
—
-
-
''OO
—
i ^o
7?
—



... .

UIIC

-
!

1

i



Y

—






	
y
—







,/




—
Molar  MtiM
NHJ   MO
  O_
5_X
  O

 o
 o
 .21
2. (a
 .sz
2.T
S.4
      N00
      /.o
      l.o
       AO
      ,076
      1,0
      1,0
      /.O
      i. a
      1,0
      l.o
     I.e.
     ,10?,'
           ."*-,

-------
TMt
Date

2-P-77













-
• ^

2-21-11




















Time

O*VZ
IM
lOlt
I0| t,
lo'ia
IOVO
ISSl
III',.
H7.i|
till
HV7
!Nl.
liuz.
iluo
Ij.jt,
I2:t

1510
\yJ0
W4
1^0
if??
I'vtr
















Primary
Fuel Type

or
















MftT





















6f.S
















4lVS





















centerline
Gas Tcmr

1C.I?"
1
i

1

I







!
V

1120




^




























































Flow Rates (acfml

WAj

X
5to









i






f

3?fc




•




















v
J8J>
^
.iff
^
. ! V-
.m
y
,111
. X'i
_t_
,191'

y
,177

V

.nt
,171!





!,
,i^






—









^,
0
o
o
.el";
c
0
,^r'/r
o
0
,/"•!
o
O
,44
0
.V ; "
o

o
0
.'i'?

,/
0















°H2
O




j









if

0 .



















NO


Sir
:>/••,
./>'.
'\'j '>
;:?-.•
r ,-
-5ft;
5ir>
95'.
u.'i
3 -"i
?I3
?!'--
r .-
K''


9^
fK
ISO
KS"
ISS
93^











-



«s?


5,1
'i. (»
fj ,
r • ••
r ^
',"1
r>. I
^•1
S.I
5,7
5.1
b.7
r 'i
£.7
<"/
S.77


  o
1.14,
  O
>.?•)
      SO    H2
      NOp
      1.0
      /.o
      ."7
      l.O
      l.o
      l.o

-------
   TWt
   Data
3-»-77
             1319
             111?
             /i/r
             '•/41}
             W/.T
             ••wr
                         TYPS
Csntcrlln*
Gas   T 7
',97
- 'x*
31Z
Y)f.
2-7;
-?«"
e«
it*'
'i'/i'
i'',-
2V,?
i,':r
?"/.'
37?
.???>
i ^r
2'';
•?•>?
i'.' :
372
12?
-//'•
JTi'
r2£.
12L


BNO
(3.29S
J.51J
:.;'f
;.27?
:. x>/
:.37fc
:.2"i
•;-5J.,
j.^'i
-.;-?i
:.2ii
:.v?i
i-2^0
^.?,'.',
j.;'1:.
r.?1)'
'.>•?;.
-. >7t
^.Jll
'••si:.
'.: 7?i
;.?7i
C.7U
C.V'i-
«.Ji;.
'.:• *i'
r, ;?(.
-.:•/•
5. 3"(.
i.^?i
:.3T.
•'J?'
c.y-:
'. . -n:.
r.vi'.



^IHs
O
5./7^
s.r/7
5.775
3.«'
C
0./74
».i?r
i.:s/
^.a;
tf./7/.
tf. 37i'
s.^;;;
5.S/
A/7t
^. ?7i"
*.W/
;;.^ I
^./76
^.i?r
'-. '/;/
x'.fl/
*./74
s. 3rs
.'.7?/
^.s/
i./76
r. 57-;
^•7«l
J.«/
i.573
;.'i')2
j. "/
4.7) 5"
i!.ii»
--

%
O
a
0

f
o
o
o
Q
o
0


                                                                                                        Stack Emissions
                                                                                 JKt-
                                                                            773
                                                                             1C,
                                                                            -IV.
                                                                             Sf,
                                                                            210
                                                                            tic
                                                                             110
                                                                             no
                                                                                  S.O
                                                                                  S.I
                                                                                  S.I
                                                                                  S.o
                                                                                  S.I
                                                                                  t.S
                                                                                  '11
                                                                                  "'.7
                                                                                  f.fl
                                                                                  •U
                                                                                       i.f5L— ...CO? - NHl — HCT   NO3
                                                                                       no
                                                                                       65
                                                                                        ss
                                                         1C
                                                         /i*,5
                                                                                        &S
                                                                                        75
                                                                                        Cfi
                                                                                        7S
                                                                                             /*/,'/
                                                                                             IS.o
                                                                                             MM
                                                                                             1-1.7
                                                                                             rt.'t
                                                                                             fl.7
                                                                                             i-i.7
                                                                                             if '7
                                                                                                                           255-
                                                                                                                          37L
                                                                                                                          310
                                                                                                                           'fC7
                                                                                                                                                       Molar  Ratio*
                                                                                                                                                       2.SJ
                                                                                                                                                       1.27
                                                                                                                                                       (,.9
                                                                                                                                                       i.t-l
                                                                                                                                                       1.2
                                                                                                                                                             /.O
                                                                                                                                                             /.£)
                                                                                                                                                            a.S-J
                                                                                                                                                            C.62
                                                                                                                                                            tf.i'5
                                                                                                                                                            c./if

-------
T«t
Date

2- IS -77













3-2I-77
'•P







a-2--i-77


3-»-77












Tine

6'!<
I lIC
<:?0
»' 3 * 5"
/;-/£
'J'5"
/ 7 '• 5
)>"_,'_
I' lit.
i"ZC
is:*
iZSi
I'o 1$

i'-i'j
wv.
i'l:C
l"<:0
!?<•'
15'j'j
/rrr
i;j'iZ

fiSc
/53r;

1610
IC3?
n^lS
we.
yjri
e&






Primary
ruel Typ«

Jlti!'













•J~n
-^
Icn
He'1
'!e?
'-'.'.-I
•JCT
u,.
'«••?
*''
lie]
W
ijyl
^il
•09



*/»'.
•-.I.'
?•".
3T
^,, •
??:.
1-.7..

2-i
0. 2'. S
^.3^9
r5. •-I^<:?



a 1,01
•).:<•:}
O.V.I
fl.5?'J
r-'.;'T'/
^, »?'l
•;, ioi

3. 7?i
".'?.!

#,^/3
5,i5/2
3. Z1??
L:B_'i

	



• (scfv
°HH3
O
O
3.ISZ
5.S"i
C..CSI
(,.11
o
O-tl
6.2ZI
C.2'11
0.1 S3.
C.
C


-*
c
1 ,l\-.
'••'•'? 1'.
0
m;
•>. w,
0

o
o

o
*.3^3
''• l'<3
a
o

	



A
°H2
O
O
e
c
0
o
3
Z
f,
O
0
o
o


•
O
0
0


o
o
o
o
o
£3

	 	



                           Stack Emissions
7AC
C-.2C
CO
gCf,
SIC
/?£"
SK>
     o?
-/•£
      s,z
      S.c
      S.I
           1C,
           if
            rr
                /"' 7
                 rt.7
                H.I
                 I'-l.'i
                      NH,
                       1.7
                       'l.i
                      ICC 9
                      111
                       7.3
                       •1.2
                      Ill,
                       77
                       fy
                            S.'4
                            'S.7
                                             33,0
                                                  NO    NOx    UHC
                                                   If
                                                   725'
                                                        7^0
                                                        7C-C
                                                        765
                                                   -'9
                                                        130
                                                        730
                                                              •V C)
                                                              //fi
                                                              AW
                                                              /y/i
                                                                    NHJ  N0_
                                                                   lr^  ' NOp  I NH3
                                                                         Molar  Ratioi
                                                                          3.0
                                                                         AT
                                                                         s. Sir;
                                                                         A/V
                                                                          /.IS"
                                                                               1,0
                                                                               1,6
                                                                               I.C
                                                                               .ori
                                                                              0.011
                                                                               1.0
                                                                               l.o
                                                                               I.C
                                                                               l.o

-------
tut
D«t«

5- 21--77









5-?- 77




9 •
to





















Tio»

\0\0
tlOO
"35-
11*16
IJOC.
/7'IC
iy?o
I\IO
i3ir

rn?
I'i.r.C
i333
1211.
:11'>
K'is
/3'/.7
mi 7
tylj
/35V
US-'/
"j-J'S
I'lX
i~ie'j
l«0'l
l"Si,
l"itg
MIC
Hi2
/""I
Hit,
)•>.!)







Prinary
IMel Type

yr/w









•JTM




























-~cr,Ll-









•Mi"/,'




























Ccnterllnc
Ca» Te«tc

-
-
—
IS
\-' /
!•.'/;
>,'"'
I'1:.'!
i^ i ^
''•••. "
.?'.)
!"!

!Eii













































flow RatM fscfm)
2»u
373
375
37;
175
l'-
-i-jr.
170
VK
iTi

Z?*;
5VI

i;'/'.'
vo.)
y?-"'
i'r'.-:
il'i
1


	

V
3.S"2
5,2"!
'I, 1'**
3.7'^
^. y ^
a,?-1
:;.;>•;
».3.?;•?
-. 2. -,'•?
-. '.'.t
-..1:1
S. 35 H
;.'«'/
^, '•;."?
"S
'


—

°™3
o
o
o
S.I1I
5.55.?
S.f
&.1T
fi.Vl
0

0
5.T«
•3.J5''
' ••>*
f'~ ' J f'.
'••'-''-
fj.,ft
}.'•':?
t.ift
J.'VS
*.'4"S
.'-.'fff
A.';'i-
i./i'f
i.HS
e.i'J3
j:'-f
t.lf't
!).'«
?./rs



•—

°H2
—
-
—
-
—
—
—
-
—

—
-
—
-
-
-
—
-
-
-
—
—
-
—
—
—
—
-
—
-

	


                             St«ek Emission*
     iCt_
fr;y

£"'!'.
5 IS
I'C

ar,
     .22
      5.4
      f.3
      r.r
      s.v
            PC
            7C
                  CO,
                  .'4,7
                  W.7
                  Mo
                  "•'.fi
                  /V.C
                  ll.ff
                         3.0
                              7.5
2L°3
                                                 333
                                                 '/i'C
                                                 'He
                                                      NO	 NOx    UHC
                                                                               Molar  Ratios
NH3   MO    H»
n(i _ T^TT!"*""f™i.. .T
                                                                                    ^.a?3
                                                                                     MOo
                                                                                     I'O
                                                                                     I.O.
                                                                                     1,0
                                                                                    f.^f
                                                                                    S.~!f.-<
                                                                                    t.S'S
                                                                                    C.3i.
                                                                                    0.5-/
                                                                                    «.^r
                                                                                     y.o
                                                                                           JJHJ

-------
Test
Date

f-r-77














. 9
-- '• ro
w









S-17-77












Tine

S.?5"
r 3."
i'-'O
S'-'i
?•':
I5*>'i
?':°l
rrr
/rr?
/r:T9
:6;/
>^'->z
'i'5"
,'frj •'
/ii?
/i/c
/fc'3
/.' '<•/
^'£
/^'?
H.2C
li,2~
;62';
u^i
/iJ?

/;??
13 la
1312
l?l?
1217
an
123.1
1225"
1777
>?'!
m\
c
Primary
Fuel Type

CT/5"

























•rrnii










?VI-

;fii if

























-MILK"











Ccntorlinc
Gas Temp

-
15?"-
| • _ '';
n-;>
ITV-
; '.^
i ''. '
i ' / ;
r-',1.


;.
11 >~r\
li- ^
1 . / 'j
1'fJl


"/''•>
|'rV,

]'(V-
Ir,
i ," .>
IV.'.

!W

—
I WO
112?
IHo
(8Zo
lets
Hlo
ili?
1*10
\n<
f)?0








































flow Rat«s (scfm)
^iU
?0'
i''7
-' ^"
'-.?/
•'//?•
'^77.
^T
27S"
'-:??
5-7?
rf'o
:<73
?7«
i?J
< r>
il?
"•7^
»r?
-••>••
2?j
X "/i"
i-7"

'.'.
•r. j'
«.7f
rt.3?
,T . yj
. "'^tT
''•??
>,.*•<"?

Z.s**"
f.yfs
o. *$•'.
c. y z •;
a.w
«.2«
4.s?f
s.5Z£
*,;«•:
<3.2Si'
c.ysj

^KHj
tf./«
4./S2
i>./S2
5. ;J3
C- IS3
a./s;:
''./ii
i./J'i'
'•''.'s
S,.IS?.
S.IS3.
C..IS3
z.'i;
c.i'.:
'/./•' ^'
4jjrj
^./cy
c.i1'.:
^•'..'
i.i'.:
^'. ll.'s
r-.i^'J

C
a/i.2
5.14?
5.«2
CJ42
f.;42
S.Ji>
<5.33V
^ ^*7
&3i':
5.^27

°H2
—
—
-
—
—
•-

—
—
-
—
-•
—
—
—
-
—
-
-
-
-
-
—
—
-

-
—
—
-
—
"-

                            Stack Emissions
(65
H.O
ISO
 S7C,
(,10
(.10
MO
     r.v
      £.'/
      r.-y
      S.I
      S.I
      5.1
           co	co2
            £".5
            55
            5(5
            fi?
                 •".a
                  I'l.C
                  J'i.f
                  H.-J
                  H.'i
                                                3-2
                                                H/
                                                                              Molar  Ratios
                                                                                   O.SJi
                                                                              A7?
                                                                              .'.2
                                                                              A -7?
                                                                                   O.I
3,6)
                                                                              e.stft
                                                                              A/9
                                                                              A/"?
                                                                              A/"?
A/1?
     N2_H2
     NOp    MH3
                                                                                    I.C
                                                                                   5.5?
                                                                                    .ZTI
                                                                                   y. in
                                                                                   O.IS2
                                                                                   a.uz
                                                                                    .77
                                                                                    .Ufl

-------
T«»t
D«t«
S-12-77
               JS3?
               '3-11
               /S'l"
               15)7
               ifl'l
               •T'7
  Primary
m«l . TfP«
                           fi f!
                                Centarline
                                Ga«
                                Ij'lr,
                                 HKT
                                 Hoo
                                 IT.C.
Plow Ratei (»cfm)
?M£
Zfl//
7»'r
3"!'1
-3^ll
jj-?ii
?>•'
..o*;
?«..'
J;t' '
•>9/J
•:/'/
sq>;
13?^
\Zl4
-,nl
v-ij
1 ?-.•'
v9/.;
wi
37..
3")-/
'i'l'i
{':.l
111'
i"'1/
iH
i?'-'
JC/V
3V
?•>. .
^?/('
3?7
°HO
S.«S
5,?ir
J.?f.S
tf.331
•5.7J-T
«•>??
5. yji
i.sjcr
«.?;'.''
:-'Z-r
'.;•!' .
•5.':'?
a .?•.:•'
S.3T'
S.^'t
4.71 •'..
••..;»'
^.?ii.
'."','.
{.;•!:'•
r* . ^ - C.
" * -
i.y>/-
', ;i'.
c.sn.
r?;l.
C • ~ 't>
:.3'i

o. } * .'.
.•..iiA
!5.3li
J.PI/,
«.P'i
j.yit,
.'•.;"••-
'••>'',
•t.jii
°NH3
tf.337
<:,J37
«.ssg
2.5E?
n.I5g
',.<',2
i.-rrs"
p.CCf
6. if?
•-,.7£2
a. JT.'
'".,', ^ •»
C.Sl''
O.ttl
&/5S-
«.Uf
a. 'C r
.1. /?(,
^r. if-;
e.UC
a. ?z?.
i.-s.i
'j.^1. J
:.Ji:'
•!.Ji3
'*. '•'T/rf
C.tfil
S:.''-1
• "•;".
.).•>₯)
s> .''^7
5.6Si
».4ft
i.uK
•f.^Ci
«.(^/-
°H2
o
o
o
o
C
lj
o
fl
a
c
&
^
c
o
o
0
5
<3
O
C
C
0
O
o
o
o
c
6
c
c
6
c
c
6
0
3
a
                                                                                                             Stack Emissions
                                                                                 .pm   KJL
                                                                                 0,0
                                                                                 II
                                                                                  16
                                                                                 31C
                                                                             £££

                                                                             3^7
                                                                              ;?o

                                                                              7<"
                                                                                      5". a
                                                                                      S.I
                                                                                      £.')
                                                                                        .f
                                                                                       5.V
                                                                                       £.7
                                                                                            50
                                                                                                   C07
                                                                                                  •/.•y
                                                                                                  I'l-'f
                                                                                                  H'l
                                                                                                        NH,
                                                                                                                     NO,
TTT^TI'
                                                                                                                                      NO   HOX    UHC
                                                                                                                                                              Molar  lutios
                              NH3_NO_
                              N00   NOo
                                                                                                                                                               .ie.
                                                                                                                                                              /.ft
                                                                                                                                                                   fl.S.T
                                                                                                                                                              a./
                                                                                                                                                              3.'
                                                                                                                                                               3.1
                                                                                                                                                               3 I
                                                                                                                                                              ,-lf
                                                                                                                                                               l-li
                                                                                                                                                               /,/s
                                                                                                                                                              1.1$
                                                                                                                                                               i.'S
                                                                                                                                                              J.ol
                                                                                                                                                              3.135
                                                                                                                                                                   c-.sn

-------
Test
Date

3-?,! - 77





1- »' ^





*•'-£•- 7?


•n
1 t^j
;<^i



H - 6 - 77






'(-.<;- 77










Tine

;/zi
i/'?
>n;
'1? '^
'-Bi

/ ' 2 f
1 1 C '
/:>;;•
'3/i
•'?.-:.

;'£ T7
v;?i
r-^
:^-_',
1''"!,
• 'f. ' '
•« O.

/r v r
Mi"
; :;
; .- .-
"5*
;;../
i •* ^
W It-




Primary
Fuel Type

.'.'A /,





/Y/^ ,',





.vr .'.







AV) V.






'If-;.


	







•Zt-^Z





Ci/;;..»





f''/. ri







'.ti-.ik






" :>'•'.' r<










Centerline
Gas Temp

—
:• .
; •:
.". .
!'. •

—
r>T
'.- ••

I'l-ic

—
-
n-'
i"?;.t
K'''.

—

...
..

; -"•; *'
nv"
—


...
iC: ;
t .- '-..
: i - •".
i S;:;i
—









































Plow Rates (scfm)
2ait
^7
v-
?-;
i-:
-:7^-

37?.
'J.7r.
^-7
;•';-.
'-,'; ^

3i/
r--.-
'.1-'

:•--*
'.• -.
'-•-;

?.'..Z
? ' •'
- ' /
"J '^f
•a / /

3£.'.

ii7
2J.7
247
2t7
2i7
'.ii.7
317
_3i7


«NO
s.rs-1
5.7;-
j.?f
:.;•••
'- 7; 7

'-?>?
j. * * f
•j. '•'•'.
'.:••;.
£ . - -' 3

5. Si
4.?-*
-.•.y?";
: :••:-
.'. ^ .' ^

- - _
i . ./ i '.

',.1/2
'-.35?
;.;J9
^. ^ ; ?
'.33?



5.23-5
r-.^i./
i.?(./
'-.>f-l
:.»?•/
5. s*4'.'
i.jrH

n
Vmi3
0
;.c?.'
j.yr.',
,'."i2'i
,;.:-rr/

o
:-*i:
r.;.<:
r.;-i')
i.'i'.-;

e
o
5.1
•;.;•••;
J.r-y.1

^ • r '.j
.<•

C
o
a
i.?'.'S
'. ij-^*
c

0
C
.--'34
O
£. 2^7
•:.?(:'/
*.V2i'
C


c«2
0
a
c
&
c

o
^
O
o
rj

0
o
c
a
c,
c
o

-
—
—
-
-
-

-
—
—

                       Stack Emissions
£".7
5.2
 r1.'?
£.1
            !•>.. 7
                         J.ii
                        '..12
                               r. <•
                               S.'7
                               7. /
                                            '-AC
                                            5*0
                                                 (, ?
                                                        0,5
                                                               12.
                                                               ia
                                                                           NHJ   NO    H2
                                                                           NOO  ( NOOTNH~
                                                                           Molar  Ratios
                                                                            C
                                                                                 i.C
                                                                                  I.C
                                                                                 1-0

-------
T«t
Oat*
V-/2-77














P« UN. VHS Center line ! ;,-; -, !'?5 {•-. W'.: ,-.'' • — Plow Rites (Bcfml iu. 2?i 2• = >-: y>: 11: lie, *.->•• TiC So i.J-fl ^.7? S.5'? c.;? s.:i S.i'-l 5.^> S.3T '•''7 «.?.!•" . Sn.3 C tf '.|Pa i- «.(2^ '..?•'•/ 4*17 >• -«*" '•.•;•_-"' «."';•' J^ CHJ o c c 0 c. o e> 0 o Ci ....... Stack Emissions Dry NO OKU. T-lr, 7M 7*c tss •~Z6 !Sc tte 'T1"'/ '.''," -.1C J3l DCt 5.'.' S.Z 1.2 £.^ •:.?. €.0 5.5 S.I Z.I ''.1 CO ppm C-T /So '•' j" .'./• "r t-s •if "^5 ''•} *iC • CO, prt /'/.7 ;••'. 7 ."'. ^ /•/.y v. '•' •W.7 W.7 ^-'.7 •.V ~T >•>•"! Nil, ppffl '/.3 — 3 - 3.' — u-l — 7.1 — II CN [•pn1 .0. ^ - tf./j- - 5.'-J - i,/y — '.i'.T - NO, Pf* 7.9 - ^. C - '•• 2 — ^-7 — 7, •-'s :• ~:? ' s& $*c •''33 C'j , sw .._.. NO — — fen — f£? — '<•',' — J'~ ' — ... NOx — -- ^Z/, — '.IK- — '•:•: — J'T- • — UMC - -- £'• — (, — 6 — / O — r. Molar mtio« JJHJ Np___Hj MOO " C.H73 c.-m /.o I.C


-------
Test
Date

')''," 3- 77







*•-;•' -~>~1






\c,t i\"t -_ /, . V 3 -^ /i*,1: i/*r •<>.f /'M"£ /S;5 .'-3: /33T /;;f ;:••>; /J'J*/ • J-y? /5"i Primary F\jel Type /tt. ;Li. //i. o.v-;.V C.I-I.C' CCftL 'C ' Centerline Gas Tenp '^•y 1 1 1 .i;v. >t '•<\' \V; li \r. !?«)9 • 3 '• — ne: "i i !; , I 1'' f[f so 't '\~> Plow Rates (scfm) ?*U 36? 'It? 2ii t,'iV i'- '^ ?'-2 -. • ^ :^..'" -,'.": V/..0 •J/ ^ '•-',- J t C -','-,'• i!.,? •.^ -J,iS, -"(' .? Itf •-.'.; •^r •'.'.'J -•.: 2H? i ;..;-. - i> j.'.v "tiV 'J.' 1 ^(^ — V o.a?i O.Z75" I.-7r -.375- J.J7S- '•n* '.•272 ;.34I V.347 5.317 /).3t7 -1.SL7 ^.ii7 ••«7 o.v;.7 r.JdT 5.3i7 •>•!<,"', -•.sr4 "•••I-: 4. V >- o 2 ;-; '-. 2Vf '-' , / 7 ' -;.7?1 •^ .;'''* '. ^',"' ^ . '? 7} '.-,•.' ^3 C? O 3- /3i*» fT.J-t i. ?-e ^.«2 o o o s.;U i.5V2 o. SV- a. HZ t.-ji fi.H'i. c..h7 C."Z '..»-' 7. C O i./zt C.3-.J ». 2O s.*.j-/r o c.'-SS r,.H \' f.'l-,i, '^•!lf — - «H3 O

ses— *ct Stack Emissions 770 -ii S" £•30 7? if./ S.c S.o £•1 5-'' '•l-l CO C02 So JJCt- ••/,-y H.I 3.12 A7/1 3.73 3.20 V./7 /.77 4,73 fl-V? (3.3 13.1 11.2 SO, NO !)0x UJ1C X X •395" 10 MH3 ltd H; NUp | NOp | NH~ Molar Ratios AJ7 /.O /.O /.O


-------
TMt
D«t«
>l- 27 -77




4-?S-7V





*y-r?- 77



9
to





















TlW

//oo
;vr
/^ir
;*££

/,Wf
I'K
/7?r
/i«/r
'i;r

i1 i- *"*•.
ii yo
"?7
• if"
uis
••IK
\''M
I'iO-l
1105
U'3
/3is

















Primary
ru«l TYI*

/i: .




/^*..





in..



























'•.V'.-.V




•':/ t.e'





CJ/Vc



























Ctnterline
Gaa Tenp

-
—
,*•
1?.:"

i: -•










l"r'.





ir'






K. ' •
/ •,
iiir
—























































Mov tutc» (scfm)
?4ii
•%2
362
•(,2
3;.-.

sto
Jtc
?ts
U6
iCC,


'it'
•?o'
2' '.
2u£
":.'.'.
ii.-
2tC
.?/••£.
3tc.







—


	


V
3. 3il
0.347
3.3-3
s.;--)

a. as f
5. JSJ-
5. ?S5'
e. 2Si
o. is:

-^.JSI

;.T5
',.2',;
£• >',r

-•3'*',
f-.K-S
C.V.I
0.3SS







-•

'
— .»_»

^NHj
<3
O
0.2J3
«.."SJ

0
•:./«
5. 5SJ
6. J Ji"
S.'H?

z.
O
«•'•?
-.'?":
S.3'4
C« '• ??
i. a * r
• , L; ').;
.?,;?£
0










	

%
O
O
0
0

c
o
o
o
0

c
o
0
o
o
o
c
e>
o
o









	

                            Stock EmiMlonft
745
SIC
 30
11.0
MS
     jKi.
      5.3
      •V-f
      r.a
       .a
               Dry
            so
                  CO,
                 /•/.O
                 '','.7
                 w.o
                        2.6V
                        J.n
                                   _NOj
                                               zric
                                                     NO   NOx    UHC
                                                                  1C
                                                                  10
                                                                 13.
                                                                             Mol«r  lutlo.
lr~3  , "°
       "Op I NHl
                                                                                  «.*?
                                                                             l.tf
                                                                             I.S7
                                                                             I.S'i
                                                                             I.S-
                                                                             I.S'i
                                                                             I.S'i
                                                                                   /•C
                                                                                   1.0
                                                                                  o.S-1
                                                                                   y.c
                                                                                   1.6

-------
 9
"N> '
Tine
.-'37
HI S'
        Primary
      Fuel  Type
      F'77.
                  Gas   Temp
                 ISIO
                  wr
                 it?0
                 Ho1"
                 nzf
                 UJo
Flow Rates (scfm)
5a»x
265
V ' '
2f,0
7^y-|
»«.;c
*-; ', v
r'/.i,
2o*

^' ',

7 ' •
y ' .-
'•>'*.*
5 i.e.

v^-^
'**'•'•
'£'- "
V* •_•
:.'/•!
:'.'-:

•iiV
? ,i-
'.'>••
*!,*'
ii'l
\3Ul
[«7i

E

So
5.?r?
''•>lg
>.;K
1 . " '1 '
f.J37
.;.-;-;
">. .r1-'"'
'.3-^'

;. i'3;
;.5«.T
-.i«/i
:.»-*:T
I.I'i;"
' "'"^

C
:.5i9
;.^i9
t. J'.T
r.2'.T
-..;•'. '
O

t.l'i,
•''-'1
.•:•;•-]
'• ' ; ;
'•J'^i
f- ^1.
ri
,
.— ~~

°HH3
O
O
O
;./37
', *1"'»-1
J.i^I
*• '"'..I1!
O

5
r;
5.'V
1. 2^
>-:*.7-~
S.'l*'

o
a
«.Hi
.-.-',/.
j.i^S
;.r/
a

o
o
^, ;-'.f
;.7f/
"•?7V
'..JJ7
C

^ — -

°H2
C
0
£
G
C
C
o
C

G
a
o
o
G
(O

C
C
o
o
0
^
•o

0
C
0
C
C
G
O

... ..

                                                                                           Stack Emissions
                                                                HO   05
                                                               I2>T_ JKi
                                                                27?
                                                                73.C
                                                                      V,?
                                                                     £'./
                                                                     .£.£,
                                                                     £,?
                                                                     T.f
                                                                     i. 7
                                                                               Dry
                                                                           CO    CO?
                                                                           pnm   t*c1
                                                                                /"'. 7
                                                                                             /" 7

                                                                                             jV.7

                                                                                             /•'(  7
                                                                                 /*, 7
                                                                                      -77
                                                                                      17.7
                                                                                      5*3
                                                                                      3.77
                                                                                      3.E7
                                                                                             HOJ   NO,
                                                                                            2. "7
                                                                                            i". /
                                                                                                  7-?
                                                                                                                               n
                                                                                                                               u
                                                                                                                               13
                                                                                                                               12
                                                                                                                               1C
                                                                                                                               1C
                                                                                                                                           Molar   Ratio*
                                                                                                                                                       NHj  MO

                                                                                                                                                       NO0 | HOp  | KH
                                                                                                                                           i.f
                                                                                                                                                /.if
                                                                                                                                                     ::

-------
TMt
D«t«
5-5T-77












r-^i-v?

9
O

' f-1/-77



















Tine

;«Vi"
1'CS
::'C
ii 3t
ii- "
I*-.:'
'527
-r;f
/?; -1
''54
?.?^
.<2r

">/C;
//^S"
«r•:'
• :-C-~
iiH
lf.''"~-
• r ? •"
l'.~'i'!
IfCC
~.z?
• *'r «r
- 5 /
•'^ ' •"
't: a
/ii'r
IM,
>lf'$
I' 3C




Prinary
ru«l Type

P/TT.












,6'T7.




?/rr.




















•:•. S












*^i ?




-:/i f




















6a* Tenc

—
—
Igllf
1^3
I'-1T
1^50
l^'f
I'l-""
ifcir
\i;r
1 '••'".
—

_
—
I7"o
mo

	
IUf
)i-?5'
itso
It'fO
it%'
rue
\~\>*.
',••<->
IT;.'
' //
! '/I';
r/.-»
m<
I7i>
n'--
iin.









































rlow Rate* (icftn)
k*
24:T
It.'
2lC
•:t,-:
7j'"
*i ^
str
2iC
26T
?.•'.'
- • .- '

i:.';
54-'
36"
i'>'

->l^
"i/,7
H6:
3£.'J
^'.v
i^r-
j/^
''.''•

-•!'.

ill
J6?
3ii
V,7
it--i.

So
J.JZ-T
?.;>73
C.T7S
-..-;
1.3-'?
'.2-.-t
:-nt
C.tl'i
:.}->?
'.?'.'£
;.'JC

w-
'. *11
'..}*'<
;.;>>;•

•>.J?'^
'..?*t
*.-' ji"
•..-.'•:
' . v ; ^
i..ni'.
i.3';';
'j. . 'i i
•./-••>
:.'l i
. -' :. I
VJi'l
g.j'n
*.«•/
&.>27
;.:3<7
J?

Tfflj
C
lt2
o

fi«2
i?
c
o
o
o
c.
o
•3
O
o
c
o

o
o
o
o

o
o
•l.^'-l
o
•..;/»'
&
C
C
'..'Mi.
-..no
-.;-/•;
C
'..'•It
-.171
'.Z57
1-"I1
O

                             Stack Emiuiona
lc.0
SIC
nt
      ''7
      V.7
      r. /
      S.I
      S.I
      s.f)
                Dry
            CO     CO?  Nil,    IICN   NO,
            ICC:
            it.:
            17 S
            '•".a
            1C.
             If
                  /<•  7
                   V 7
                  If.C
                  ,"•' I
                  l-i.l
                  I'I. 1
                  "I.I
                         M3
                        a 8
                        I'll
                               3.2
                                  -I..TI
                                                 1 37
                                                 ISM
                                                 ///r
                                                 (317
                                                       NO    NOx    UHC
                                                             ite
                                                             Tis
                                                                    iZ
                                                                                Molw  Ratios
NH]   NO
"    ' NOo   NHl
                                                                                /.ir
                                                                                I.S'i
                                                                                     S.2J.S'
                                                                                _O	
                                                                                /,32
                                                                                I.S'i
                                                                                 e
                                                                                ^-3
                                                                                1, 3
/•s-r
                                                                                      AC
                                                                                      i.e.
                                                                                      I.C
                                                                                      . 3S»
                                                                                           ••3!:

-------
Te»t
Data
S-17-77














_
U)
^~




















Time

1110
I'll
i;i'r
nii.
n if.
! •(.•;
//V2
/3i£
'2i«
,'?£(, "
r!:"'j
•. -r. .-
; ;• |H*
1 ' ' '."
>'.•'
|3'.-'
i'i • ;
'I'! ^
I'jIS'
HiO

It:-;
>r*.
\ '< '• 'f
rt,'-

sl.'.i
i-:.','"'
!?ii
i ''..'•'
|',r-
'V'.,























































Flow Rat^a fscfm)

3i.^
2 f-i
3i"'
?-'/
3;-1/
i-''/
li'i
l.'o'V
'I!.'/
26'/
»r,v
it'/
:-;;•/
J///
?/;v
3iV
3dV
34^
ii'/
5"4
34.4
36V
34V
2iV
j^y




—







9(10
C.J9?
5. 5 '-I
""' C
r,;'1?
•'•"•'V
;,-••'.'
',,?'v-
r.i'1'
.".-'•;
.•;. ;•'.:'
•j.*''i
'..'••*
'..i^T
;.:'•'?
C.t-':i.
i.y-'ii
t.y-:f
'•'••i
'•'-'i
t.:."i ;
S.+'l?.
>. r;1f
c.v'S
(,.:-.i
1.2'!;




	

i





^
0
C.I If
s.i;->.
7.11?
t.l\°:
o.iri
a.ni
-..r--*:
*.2!-M
!>.?£*•
:.s;'~
'.::?-
•>.J?li
•7. -.3V.
:.^X
',.-:2-'.
- v-
r./i-"-
a.^lV
J. 27.r
<••;•;

«. ?T

c. S'f?








— -•

««»
C
0
o
o
0
o
C
z
0
f.
C,
t.
^
-
Cj
C
C.
o
c.
^
o
C
.-.'
tf









StAcX Emission*
Drv
NO
atm—
ICC
^7f.
"So
HSa
*7'75
CiC,
*£0
r'
'-'•' 'j
13''
J.'.'
?M
17 f
i?Z
>'5
is
* :'•
I'.-f
/2.:
:?t
'Si
-''x','-











-22
pet

v.g
JV.O
"•?
•<•$
*•>
•!.•[
>', f
'A 7
'/,;
4,7
•M
"••'
''V
. ; ^
, ' ^"
*/, 7
»/ 4
*/ !"

•; . >T
" ' .:'
•i.f
'J,:'
'/'• '
V.?-











CO
niTinv

£•0
i(5
/.,£
50
sa
'"
''o
£j~
ft
so
r*r
r-.
'..r'
•V'
Lef.



••'f
L >
rv,
75
•y •

7''









-

CO,
pet

;•)'."
.'•/. 7
^.7
/•y •;
;*J_ T
rt.7
,W. 7
l".~
':•!. 1
H.7
J'1,~!
*« "",*
;•/ v
"•'7
;-.'.7
/'/.7
;iJi "^
K7
rt'.y
,"/. 7
!••'?
IH.7
11,7
/'/. ^
/'/.7











NHi
Hum

-
-
-
-
—
—
—
—
—
—

...
--
-
-
-
—
"
—
	
—
—
—
—
-








	

11 CM
nrmi

—
-
—
—
-
-
—
—
—
-

...
•-
~
—
-
—
—
—
	
-
—

-
-








	
NOi
tinn

-
—
—
—
-
—
—
—



.--
--
-
-
—
—
—
...
—
—
—
—
-
—








	



Mot
SO,


3=5(5
*'(•"
-£5V.
35*
Z-i"£
we
~±OI6
-*-T.
-•?,v-
—
	
._


?.' '•"/
:•.."•'.-•
•.;i/,,:
"^ X
.^'- ':''
ii/4
^.v ^
-.?;*
•i'Ji:"
a.'i/i
-\*i:.''.
%3/J1




	




::]
NO


_
_
-
—
—
—
—
—

—
—
...


--
—
—
—
...
—
_
-
—
—
—
—




	






NOx


-
—
—
—
-
_..
—
—


—
—


-
—
—
—
-
--
-
—
—
—
—
_,



	



—

UHC


-
—
—
—
—
—
_

....
—
—
—


—
..-
—
—
....
....
_
—
—
—

—




	



..._

 NH3
pu0
 Molar  Ratios
0.£9/

 /.-•r
 1.1,
/.51?
NOp
      5. S'7

-------
T««t
D«t«
i-/- 77














.

! '- s's 1'3'i r.'--1/ '. p;' r^i fJ7 raj C'i'l 53i i'3) T27 r •' -.' 9 4 Primary Fuel Type PlTT ce •i'» S ;7. Centerline G«» T«mr — nrr i'J'io :;!.!>" . " j j ', ' *J if- 3 1 ;-. r '';''' 1^-' •j' •'" r-,'^ i'!1; i-l? |5>S '" ^ IV.', 'i ''"" '~ \'v> vAf> W I'V'J --3 ^' '" ''// '•* V/o '-/c U'v\" u?r L''o .'.;:> A/o r,9-' ^•; •wr KO 3=>^ Flow Rates («cfm) kt 3?r •':' r 1*. *:'." •i- '- •iy; T^- C ' sr. f X ', ;'• ^ '^-' [;2f ! *- '" ?;•' ^y ' >;-•: :','•••' ; > •' •"."" ;>: '•.:'. :. - '.. ~i'jtj 1'J-'. i !> f -'''; i' ' i ^. i '->' i>'. -'i'- -±i. i^-; 33r: iJ-r "»P 5. 3;i r . >.^; ',.3ct. ;.ir<. "..'.-ci- \:'!\- '..'.'. ': J. ' , ,•>, - vf. :.3'.t i.O'-'. •f.y't ':. *t •'. -. ^'' ' ' - >: ' •:.:.'?, • . ; • ', i. ?'Y. o. ;.c '. -..,-'. '•-''., >, . '. .101. ' I'l, HI., . s? v. •i'l ,jrf .J'( f'.'Jf! .',?'. •./Ci'- =NH3 a i.-ju *.?•-• -. : n ;. >ix ',-301 '..:'-*. ~ . Jf ' '. '*' * ' . ^ ' ,' !.',:•? :.?:.-* '. J.' ;•' * ','.* !/ •....-.. ^. - ' ' '...-•: '.. ?r- ' .'*'.'j :.;•.? ;.?C2 :.'J?.l ' . • *.' ','J?; ',.,'.•! ,;;7 ;.'syr -.;•'-< ;.;:l ''. -'o ; i. a;/ -,yr/ 5.JC7 ^.7^7 3.JK7 OHJ 0 o o 0 e o o . ,... •.-.,' :/.••: J C''C '."' •• <- T( ;.r": '.<"•' r -.,,,, '.ir.'f '•l-. '!.< :n>l i.r>'l '.n't '•***'' ~,'.i:t . -).;>"••' i.?u- Stack Emissions H.I V.7 •'•7 'A 7 I7C COj H 1 I'l.l .'V.; w./ "Li Nil, NO! /Hi if'f'S ill? 1^77 // W7 - Moltr Ratio. '."Si /.o •I','


-------
 T«»t
 Date
U)
            Time
            15-17
            if. A.
            -657
            ILK
            .'US'
            II '40
  Primary
Fuel  Type
                  pnr.
Centerlinc
Gas   Tew
                               It'-
                               14,'! '
                               r>o
                               Wio
                              ro
Flow Rates {scfml
feu
33?
?.3'
53'
33'.'
?? 5
£"T
33 T
?>',
*;•''
*>r
r-.r
i -* '7
.' ~ '
£-'2

•r-T
VJ.^
s;?T
•;-••:
?'-•
;'f
?•>•:'
V.
•&•'.
3Ji"
3i-r
?iT
^?:

s>
336
J?i
2"^'
?^'..
33 &
So
9.3^.
3. ?: r-
',.?:..'.
;.3:.'-
•.:';r-
J.ICi
-.;.-'.
rC.3'^.
«-7Ci
a;-:.
C.Z'.'
t -^ . ,-
'.^'.'.
;.iri
'..?•'
-.2".
;,i"t
'.J.'.i
<.7".
.<.;-,i.
s.j.-r
".".".
'i.7''6
C.3.'i
i.3it
.^.^.' !-
O
0

.'-.2C7
4.«S
~7
-..A:.:'
«.J^7
SH,
a. 357
5.3' /
f.l;l
•?.!''
-!.«»!
^.^'1
;.-•'
^. i/'
?'.2'/
i.i'/
5. ;M
5. -i'l
',,•>•<
i.i,'.1

/". "''
fl.H.'l
6.3"
!!.»JI
5. 'ill
(5.3^1
/5/i'.'
£.•;/'
0. ?/'
<;.3J/
A3"
o
o

C
O
',.213
1
0
°H2
<7
(5
O
C
*
5
O
:.:•, 'i
:.z; ;
r.JAy
- ",j
:.".;•

.'. '• 'i
'.if!
'.i. '"I
C.l-:=t
r..i"<>
••./'•?
^.J"T;
«.^C(
c.rj;
C.XI
CW
t.KI
s
o
d

o
o
S
:cn
S
o
                                                                                                             Stack  Emissions
                                                              •Sc
                                                                                      '.'.f
                                                                                       - ?
                                                                                      */.?
                                                                                      •'.V
                                                                                      V, 7
                                                                          CO    CO,   KIU     HCN
                                                                                            I'C,
                                                                                            lie
                                                                                                  •'1 •>
                                                                                                  • •l.h
                                                                                                  /*•'.-<
                                                                                                  /'•'.*/
                                                                                                        I'H
                                                                                      £13
                                                                                                              IC.I
                                                                                                              IS.'.
                                                                                                              H.'
                                                                                                  9.V.S
                                                                                                                    '7.3
                                                                                                                    11.1
                                                                                                                                 "S3
                                                                                                                                 .'f.'g
                                                                                                               'i.ij.\_jr_
                                                                                                                                                                Molar  Ratios
                                                                                                                                                                NH3   HO
                                                                                                                                                                N00   NOp   NH
                                                                                                                                                                i. Si
                                                                                                                                                                i.i'l
                                                                                                                                                                1.5'
                                                                                                                                              I.?!

                                                                                                                                              LSI


                                                                                                                                                                I.S3.
                                                                                                                                                                I.S3.
                                                                                                                                                                 o
                                                                                                                                                                      1.0
                                                                                                                                                                      I-C
                                                                                                                                                                     /.o
                                                                                                                                                                            '•S'
                                                                                                                                                                            ••Si

-------
TWt
D«t«
^--5-77














9
ji.









^-£.-77











TIM

/?:7
;?'/?
3**if*
,'7^7
•;.
}''•.'.'
•"•' :
'} •' /

I'l6's
f~i':
i-'t'>
!»'>?
MIC
1 '; H
" >
/'.-'/'/
/"'.'/,

/..'.-•
'.";.?
;2/2
;?2;
'3C£
':-::•'
'?.-•/






Prinuy
ru«l Typ«

P'T7,

























.^-•: ;












:r»-.i.'J>

























•'••'.-












Centtrllnc
Gas Temr

1^3
Ir5«.
Wlf
I'J'i'
' j'
'-.-,• ";
ll'XC,
/( )C
;.',•.•/
\m
iutr
:'^o
—
is* ,
IV>.
li.:.T
JI^o
17^3
i /-7T
!'!?C'
I'Wo
),.•-><
!t.".r
i'.to
ivi>r

-
O/c
;ss.3
/!, t.''.-
J-'J
//,'A;
—












































Flow Rates (ncfrn)
SMI
•427


J
1
1



i
j
Y
3t4




,





j
Y

i'1'.'
?-,-/

I
VI
	

°NO
,l°9
1
!
1
l

1
!
i
!
i
y
,5.4
1
1

.
1
1
:
1
!

i
t

'.;?;r
:. •"'
'.;?C
'^.'l'1.1'-,.
xi
	

*m>
~S




IB




y
^14.







Y
o
57.4




1


.J-
.•H»


1




j



O
'. V. ' /
'..i.'.1
•i'.r:-
(5
	

%
0
c
a
<:.
c
0
C:
C.
c.
5
c.
0
c
a
<"


e
0
c
0
c
c,
r,
•'•

O
CJ
'.!•>>>
" ' *
f
	

                            Stack  Emission*
3/.V;
     £.'•?
     4.7
            CO     CO}
                  V-/
                 K'
                       Nil!
                       Si
                            lit
                             12.3
I3.C
                                   J!?3
     1!3
     m'a
ILL
13 .t
                                                                            MoltrRatloi
                                               NHJ   NO_Hj
                                              '       NOO  |NH!
                                                                            /.S"
                                                v
                                                o
                                               i.y?
                                                                                  /.O

-------
 APPENDIX D





FUEL ANALYSIS
     D-l

-------
                 COMMERCIAL TESTING  &  ENGINEERING CO.
                 GENERAL OFFICES: 91* NORTH L> SALLE STREET, CHICAOO. ILLINOIS SOS01  • AREA CODE 311 7J8-84S4
PLE"E ADDRESS ALL CORRESPONDENCE TO
1«   \N DRUNEN ROAO. SOUTH HOLLAND. ILLINOIS 60«73
                                                     SIMCE 1*O*
                                                                                               OFFICE TEL |313) H4-1173
                                                                      March  15, 1977
      KVB, INC.
      17332 Irvine Blvd.
      Tustin, CA  92680

     Kind c? sample
      reported to us
    Sample taken at     __

    Sample taken by     KVB/ Inc>

      Date sampled     ____
                                                                Sample identification
                                                                by
                                                                  KVB,  Inc.
                                                                  P.  O. #  12 121
                                                                  Project  #  15500
                                                                  P.C 12
                                                                  Coal  sample
                                       Analysis report no.  71-461882
            PROXIMATE ANALYSIS  As received     Dry basis          ULTIMATE ANALYSIS
% Moisture
%Ash
% Volatile
% Fixed Carbon
4.24
4.85
36.38
54.53
JQOCXX
5.06
37.99
56.95
                             Btu
                         % Sulfur
                   % Alk. as Na,O

                  SULFUR FORMS
                   % Pyritic Sulfur
                   % Sulfate Sulfur
                  % Organic Sulfur
       WATER SOLUBLE ALKALIES
                       % Na-.O =
                                    100.00
                                     13111
                                       0.19
                                       0.01
                                       0.34
                                       0.54
                                     xxxxx
                                     xxxxx
                                                 100.00

                                                  13692
                                                   0.56
                                                   1.97
 0.20
 0.01
 0.35
 0.56
xxxxx
xxxxx
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen (diff)
4.24
71.52
5.44
1.52
0.01
0.54
4.85
11.88
                                                                                              % Weight
                                                                                        As received     Dry basis
                                                    XXXXX
                                                    74.69
                                                     5.68
                                                     1.59
                                                     0.01
                                                     0.56
                                                     5.06
                                                    12.41
                                                   100.00
                             100.00
    FUSION TEMPERATURE OF ASH   Reducing     Oxidizing
                  Initial Deformation    2130 °F   2200 °F
                   Softening (H = W)    2310 °F   2400 °F
                 Softening (H - %W)    2360 °F   2440 °F
                             Fluid    2700+ F   2700+°F
      % EQUILIBRIUM MOISTURE -    xx
HARDGROVE GRINDABILITY INDEX =    xx
          FREE SWELLING INDEX =    xx
H i. co~ H.ISM
w .. coo. width
MINERAL ANALYSIS  OF ASH
                Silica; SiO,
              Alumina, AI,O,
               Titania, TiO,
          Ferric oxide, Fe,Oi
                 Lime, CaO
             Magnesia, MgO
        Potassium oxide, K,O
         Sodium oxide, Na,O

          Sulfur trioxide, SO3
        Phos. pentoxide. P,OS
              Undetermined

     SILICA VALUE =  84.84
 BASE: ACID RATIO
  T250 Temperature =  2890
% Weight Ignited Basis
      60.46
      18.88
      1.10

      4.60
      5.30
      0.90
      1.15
      3.14
                                                      Respectfully submitted,
                                                      COMMERCIAL TESTING & ENGINEERING CO.
                                                       R  A HOUSER. Min.g.r Mldo.lt Dlvi.lon


                                                       °~:                            RAH:hs  Ch.
   OMCMO. ftlMM • CM«JIL£tTOM. W VA. • CLAflKIKJM. W.V*. • CLCVfeANO. OHIO • MOMFOLK. VA • HENDERSON. KT • TOLEDO. OHtO • OENVCN. COLORADO * •ittMift&MAM. ALABAMA * VANCOUVER. B C

-------
                 COMMERCIAL TESTING &  ENGINEERING  CO.
                 GENERAL OFFICES: 998 NORTH LA SALLE STREET, CHICAGO. ILLINOIS 80601  • AREA CODE 81* ?26-»*3*
  "E ADDRESS ALL CORRESPONDENCE TO
   'AN ORUNEN ROAD. SOUTH HOLLAND. ILLINOIS 60473
      KVB,  INC.
      1306  E. Edinger
      Suite B
      Santa Ana,  CA    92705
                              OFFICE TEL (312) M« 1173
                                                                       April 20, 1977
                                                                   Sample identification
                                                                   by
     Kind of sample
      reported to us  Coal
    Sample taken at
KVB, INC.
P.  O. f  12311
Project  # 15500
P.C. 12
Utah Coal  "A"
Taken: 1340 Hrs.
3-23-77
    Sample taken by  KVB,  INC.
      Date sampled
                                                Analysis report no.  71-458638
                                   SULFUR FORMS
                                                               Dry
                                   Pyritic Sulfur           0.15
                                   Sulfate Sulfur           0.00
                                   Organic Sulfur(dif)      0.38
                                   Total  Sulfur             0.53
                                                     Respectfully submitted,
                                                     COMMERCIAL TESTING & ENGINEERING CO.
                                                                              ..
                                                     R  A HOUSER. Manager Midwasl Oivliidrt"^-^"1	'

                                                      D"3                            RAH:hs
                                                                                                Charter M«mt>«f
CHICAGO. ILLIHOtt • CHARLESTON. W VA • CLARKSBURG. W VA • CLEVELAND. OHIO - NORFOLK. VA • HENDERSON. KV • TOLEDO. OHIO • DENVER. COLORADO • BIRMINGHAM ALABAMA . VANCOUVER. B C

-------
               COMMERCIAL TESTING & ENGINEERING CO.
               GENERAL OFFICES: »• NORTH LA SALLE STREET. CHICAaO, ILLINOIS 60601 • AREA CODE (19 73I-I434
PI - - *E ADDRESS ALL CORRESPONDENCE TO
1 'AN DRUNEN ROAD. SOUTH HOLLAND, ILLINOIS £0473

, f KVB, INC.
1306 E. Bdinger
Suite B
Santa Ana, CA 92705

Kind of sample
reported to us Coal




Sample taken at
Sample taken by ^ JNC'
^^^ OFFICE TEL 1312)264-117!
^^Ifcfc. April 20, 1977
SINCE 1306



Sample identification
by
KVB, INC.
P. 0. # 12311
Projcet # 15500
P.C. 12
Utah Coal "A"
Taken 1520 Hrs. 3-23-77

Date sampled
                                             Analysis report no.  71-458639
                                 SULFUR FORMS
                                                          Dry
                                 Pyritic Sulfur          0.12
                                 Sulfate Sulfur          Q.OO
                                 Organic Sulfur(dif)    0.42
                                 Total  Sulfur            0.54
                                                 Respectfully submitted.
                                                 COMMERCIAL TESTING 4 ENGINEERING CO
                                                 R  A  HOUSER Minig.r M.dwtll Divition
                                                  D-4
                                                                                RAH:hs
j	
CMCAOO. KXHIOt* - CHAALESTOM. W VA • CLAHKSMIHG. W VA - CLEVELAND. OMtO • HOW OIK. VA . HENDERSON. «V - TOLEDO. OMlO • OENVEH. COLOBADO • »IMMINGMAM. ALABAMA - V/ANCOUVEB. • C

-------
                 COMMERCIAL TESTING  &  ENGINEERING  CO.
                 BENERAL OFFICES: >» NORTH LA SALLE STREET, CHICAOO, ILLINOIS IOS01  • AREA CODE 813 79S-S43*
>l ' -E ADDRESS AIL CORRESPONDENCE TO
I'   AN DRUNEN ROAD. SOUTH HOLLAND. ILLINOIS 60473
       KVB,  INC.
       1306  E. Edinger
       Suite B
       Santa Ana,   CA     92705
      Kind of sample
       reported to us
      Sample taken at
Coal
                                                                   April 20,  1977
 Sample identification
 by

KVB,  INC.
P. O. # 12311
Project i  15500
P.C.  12
Utah  Coal   "A"
Sample taken 1000  Hrs.
                                                                          OFFICE TEL (31J) M4-1U3
                                                                                                3-24-77
     Sample taken by  KVB' 3NC>
        Date sampled
                                                Analysis report no.  71-458640
                                   SULFUR FORMS

                                   Pyritic Sulfur
                                   Sulfate Sulfur
                                   Organic Sulfur(dif)
                                   Total Sulfur
                                           Dry
                                           0.08
                                           0.00
                                           0.46
                                           0.54
                                                    Respectfully submitted,
                                                    COMMERCIAL TESTING i ENGINEERING CO
                                                    R A  HOUSER Minag«r Midmit Oivulon

                                                     D-5
                                                                  FAII:hs
                                                                                             Ch.rt.r M«inb«r
           > CHARLESTON. W VA • CLARKMURG. W VA • CLEVELAND. OHIO • NOWOIK. V* • «ENDE«SON. KV . TOiEOO. 0«10 - OEHVER. CO1.DMADO • tlBMIHOHAM. ALABAMA . VANCOUVER. • C

-------
                  COMMERCIAL TESTING  &  ENGINEERING  CO.
                  GENERAL OFFICE*: 11* NOKTH LA SALLE STREET, CHICAGO, ILLINOIS (0*01 • AKEA CODE »1J 7M-14J4
<•!' -E AOODESS ALL COIMES'ONDENCE TO
II   AN DIIUNEN dOAO. »OUTM HOLLAND. ILLINOIS
       KVB,  INC.
       1306 E. Edinger
       Suite B
       Santa Ana,   CA    92705
       Kind of sample
       reported to us
      Sample taken at
Coal
                                                                                               OFFICE TEL (311) JM 1173
                                                                     April 20,  1977
 Sample identification
 BY

KVB,  INC.
P. O. I  12311
Project  #  15500
P.C.  12
Utah Coal  "A"
Sample taken 1230 hrs.
                                                                                                3-24-77
     Sample taken by
                    KVB.  INC.
        Date sampled
                                                 Analysis report no. 71—458641
                                    SUIFUR POEMS

                                    Pyritic Sulfur
                                    Sulfate Sulfur
                                    Organic Sulfur (dif)
                                    Total Sulfur
                                             Dry
                                             0.12
                                             0.00
                                             0.42
                                             0.54
                                                     Respectfully submitted.
                                                     COMMERCIAL TESTING & ENGINEERING CO.
                                                     R  A HOUSER. Manager, Midw«st Division
            CMMUSTON. w VA • CLAAKMUM, W.VA. • CLEVELAND. OHIO
                                                   . V* • HENOEHKM. «v »
                                                                                    RAHlhS
                                                                    O. OM»Q * MNW£H. CO«.OMAOO » »I«M»IGMAM, ALABAMA

-------
               COMMERCIAL TESTING  &  ENGINEERING CO.
               SENERAL OFFICES: 21* NORTH LA SAILE STREET, CHICAGO. ILLINOIS »0«0t • AREA CODE 311 72S-B434
•L€ •
t
 <• ADDRESS ALL CORRESPONDENCE TO
  N OnuNEN DOAD. SOUTH HOLLAND. ILLINOIS (0473
      KVB,  INC.
      1306  E.  Edinger,  Suite B
      Santa  Ana,  CA       92705
                                                                                               OFFICE TEL (312) 264-1173
                                                   SlNCC 1»OB
                                                                              April 22,  1977
Kind of sample Coal
reported to us

Sample taken at xxxxx
Sample taken by KVB, Inc
Date sampled 4/6/77

PROXIMATE ANALYSIS
% Moisture
% Ash
% Volatile
% Fixed Carbon


Btu
% Sulfur
% Alk. as Na,O
SULFUR FORMS
% Pyritic Sulfur
% Sulfate Sulfur
% Organic Sulfur

WATER SOLUBLE ALKALIES
% Na30 =
%K30 =

FUSION TEMPERATURE OF ASH
Initial Deformation
1 1. con. H*ight Softening (H - W)
v i. co« width Softening (H = % W)
Fluid
% EQUILIBRIUM MOISTURE -
iARDGROVE GRINDABILITY INDEX -
FREE SWELLING INDEX =



*

Analysis
As received
8.33
17.00
34.53
40.14
100.00

10336
0.57
xxxxx

0.19
0.00
0.38


xxxxx
xxxxx

Reducing
2400
2700+
2700+
2700+
xxxxx
xxxxx
xxxxx





uaiupiu luaiiiiii^aiiwti
* John Arand
"Navaho" Coal B"
on 4/6/77


reportno. 71-458643
Dry basis
xxxxx
18.54
37.67
43.79
100.00

11275
0.62
0.56

0.21
0.00
0.41


xxxxx
xxxxx

Oxidizing
2540
2700+
2700+
2700+



ULTIMATE ANALYSIS
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen (diff)

MINERAL ANALYSIS OF ASH
Silica; SiO;
Alumina, AI3O3
Titania, TiO,
Ferric oxide, Fe,O,
Lime, CaO
Magnesia, MgO
Potassium oxide, K,O
Sodium oxide, Na3O
Sulfur trioxide, SO,
Phos. pentoxide, PjOs
Undetermined

SILICA VALUE =
BASE: ACID RATIO
^250 Temperature =


taken 1130 hrs



% Weight

.




As received Dry basis
8.33 xxxxx
57.98 63.
4.40 4.
1.48 1.
0.01 0.
0.57 0 .
17.00 18.
10.23 11.
100.00 100.
25
80
61
01
62
54
17
00
% Weight Ignited Basis
57.53
26.93
1.17
3.51
3.92
0.98
0.81
2.48
2.20
0.09
0.38
100.00
87.25
0.14
2900+















       RAH/dh
                                                     Respectfully submitted,
                                                     COMMERCIAL1 TESTING & ENGINEERING CO.
                                                         R A  HOUSER. Manigec Mid»«t Division

                                                         D-7
CHKMO. ftXMO* • CMMLESTOft. W V* • CLAMUWWa, W V* • CLEVELAND. OMK> • HOHFOLK. V* • HENDERSON. KV . TOLEDO OHIO • DENVER. COLORADO • »IRM)N&MAM. ALABAMA - VANCOUVER. • C

-------
                  COMMERCIAL TESTING  &  ENGINEERING CO.
                  OENERAL OFFICES: $3S NORTH LA SAtLE STREET, CHICAGO, ILLINOIS 606O1  • AREA CODE S13 728-8434
.PI "  *£ ADDRESS ALL CORRESPONDENCE TO
1    'AN ORUNEN ROAD, SOUTH HOLLAND. ILLINOIS 60473
        KVB, INC.
        1306 E.  Edinger
        Suite B
        Santa Ana,  CA  92705
       Kind of sample
        reported to us  Coal
      Sample taken at
      Sample taken by  KVB,  INC.
        Date sampled
                                                                                               OFFICE TEL (J12> 2M-1173
                                                                  April  20, 1977
 Sample identification
 by
KVB,INC.
P. O. # 12311
Project #  15500
P.C.  12
"Navaho B"
Taken:   1000 Hrs.  on
                                                                                             4-6-77
                                                Analysis report no. 71-458642
                                    SUITOR FORMS
                                    Pyritic Sulfur         0.18
                                    Sulfate Sulfur         0.00
                                    Organic Sulfur(dif)    0.46
                                    Total Sulfur           0.64
                                                     Respectfully submitted.
                                                     COMMERCIAL TESTING & ENGINEERING CO.
                                                     R A  HOUSER Manager. MidWMt Division
                                                      D-8
                                                                                   RAH:hs
                                                                                                  f M«mb«r
                     V* • CLARKSAUHG. W V* • CLEVELAND. OHIO • MCMVOLK VA - HENDERSON K* . TOLEDO. OHIO • DENVER. COLORADO • BIRMINGHAM ALABAMA • VANCOUVER. B C

-------
              COMMERCIAL TESTING & ENGINEERING  CO.
              GENERAL OFFICE*! 198 NORTH LA SALLE STREET, CHICAGO. ILLINOIS SOS01 • AREA CODE 311 724-S434
SE ADDRESS ALL CORRESPONDENCE TO
VAN DRUNEN ROAD. SOUTH HOLLAND. ILLINOIS 60473
     KVB,  INC.
     17332 Irvine  Blvd.
     Tustin,  CA     92680
                                                                                           OFFICE TEL (312)264-1173
                                                                    May 25,  1977
                                                 SINCE 1»OB
Kind of sample
reported to us Coal

Sample taken at — — — —
Sample taken by KVBt Inc0
Date sampled 4/27/77

PROXIMATE ANALYSIS
% Moisture
% Ash
% Volatile
% Fixed Carbon


Btu
% Sulfur
% Alk. as Na,O
SULFUR FORMS
% Pyritic Sulfur
% Sulfate Sulfur
% Organic Sulfur


WATER SOLUBLE ALKALIES
% Na,O =
% K,O -

FUSION TEMPERATURE OF ASH
Initial Deformation
H i, coo. Might Softening (H = W)
w i« COM width Softening (H - % W)
Ruid
% EQUILIBRIUM MOISTURE -
HARDGROVE GRINDABILITY INDEX =
FREE SWELLING INDEX -






Analysis
As received
12.02
10.24
33.27
44.48
100.00

10941
2.94
xxxxx
1.27
0.06
1.61
2.94


xxxxx
xxxxx

Reducing
I960 »F
2090 *F
2130°F
2350»F
XX
XX
XX






Sample Identification
by

KVB, Inc.
P. 0. # 12393
Project # 15500
Illinois Coal C
Taken 1325 hrs4

report no. 71-1163
Dry basis
xxxxx
11.64
37.81
50.55
lOOoOO

12434
3.34
0.31
1.44
0.07
1.83
3
-------
             COMMERCIAL TESTING  & ENGINEERING CO.
             SENEDAL OFFICE*: «• MORTH LA SAILE STUEET, CHICAGO. ILLINOIS SOtOI • A»EA CODE 112 7J«-«4»4
  AODMESS ALL COMMCSPONOENCE TO
. <*N DRUNCH HOAO. SOUTH HOLLAND. ILLINOIS 60473
     KVB,  INC.
     1306  E. Edinger
     Suite B
     Santa Ana,     CA     92705

    Kind of sample
     reported to us    Coal
   Sample taken at
   Sample taken by    KVB,  Inc.
     Date sampled
                                                                                  OFFICE TEL (312)2*4-1173
                                                                May 20, 1977
                                                         Sample identification
                                                         by
                                                            KVB,  Inc.
                                                            P.O.  #  12393
                                                            Project  # 15500
                                                            Illinois Coal  C
                                                            Taken 1115 hrs on 4/27/77
                                         Analysis report no.    71-1164
                          SULFUR FORMS

                          Pyritic  Sulfur
                          Sulfate  Sulfur
                          Organic  Sulfur(diff)
                          Total Sulfur
                                                    % Wt.  -  DRY
                                                         1.40
                                                         0.09
                                                         2.80
                                                         4.29
                                            Respectfully submitted.      ,
                                            COMMERCIAL ,1E?1I%G & e^GINEERING CO
                                             R A HOUSER Mmag«r. Midwvsl D
-------
               COMMERCIAL TESTING  & ENGINEERING  CO.
               4ENERAL OFFICES: «• NORTH LA SALLE STREET, CHICAGO. ILLINOIS 60(01  • AREA CODE 313 726-8434
« ADDRESS «U COftRESPONDENCE TO
VAN DRUNEN-ROAD. SOUTH HOLLAND. ILLINOIS 6047}
       KVB,  INC.
       1306  E.  Edinger,  Suite  B
       Santa  Ana,  CA   92705
                                                                                               OFFICE TEl (312) 264-1173
                                                                  June  16,  1977
Kind of sample
reported to us —
Sample taken at 	
Sample taken by KVB, Inc.
Date sampled 	
Analysis report no.
PROXIMATE ANALYSIS As received Dry basis
% Moisture 1-67 xxxxx
%Ash 7.16 7.28
% Volatile 37.13 37.76
% Fixed Carbon 54.04 54.96
100.00 100.00

Btu 13624 13855
% Sulfur 1-81 1-84
% Alk. as Na,0 xxxxx 0.10
SULFUR FORMS
% Pyritic Sulfur 0.93 0.95
% Sulfate Sulfur 0.02 0' . 0 2
%. Organic Sulfur 0.86 0.87

WATER SOLUBLE ALKALIES
% Na,O = xxxxx xxxxx
% K,O = xxxxx xxxxx

FUSION TEMPERATURE OF ASH Reducing Oxidizing
Initial Deformation 212 0°F 2445°F
H,.con.H.iBh, Softening 
-------
                COMMERCIAL TESTING &  ENGINEERING CO.
                8ENERAL OFFICES: »l-MOUTH LA SALIC STREET, CHICAGO, ILLINOIS (0101  • AREA CODE 111 79S-(4a«
f   I ADDDESS All COBKESPONDENCE TO
111.. VAN DRUMEH KOAO. SOUTH HOLLAND. ILLINOIS «M73
          KVB,  INC.
          1306  E. Edinger, Suite  B
          Santa Ana,  CA   92705
      Kind of sample
       reported to us
                                               SINCE WOO
                                                                                      OFFICE TEL (312) M4-I1T1
     Sample taken at
                                                             June  16,  1977
 Sample identification
 by
KVB, Inc.
Purchase order  12439
Pittsburgh #8  fired @1010
5/26/77
     Sample taken by     KVB,  Inc.
       Date sampled
                                            Analysis report no. 71-1835
                                     DRY SULFUR FORMS
                                     %  Pyritic  Sulfur   1.05
                                     %  Sulfa'te  Sulfur   0.01
                                     %  Organic  Sulfur   0.91
                                     %  Total Sulfur      1.97
     RA H:ljd
                                               Respectfully submitted.
                                                R  A HOUSER bUnag«rMidw*»t Div
                                                D-12
          • CHARLESTON. W V* . CLANKMuMQ. W V* " CLEVELAND. OH*O • MOHFOLK. VA - MCNOf ««OM. KT • TOLEDO. OHIO • DENVER. COLORADO • IIMMIMGHAM ALABAMA • VANCOUVER. • C

-------
                               TECHNICAL REPORT DATA
                         (Please read Instructions on the reverse before completing}
 . REPORT NO.
 EPA-600/7-79-079
                          2.
                                                     3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Applicability of the Thermal DeNOx Process to
 Coal-fired Utility Boilers
           5. REPORT DATE
            March 1979
           6. PERFORMING ORGANIZATION CODE
         G.M. Varga Jr. ,M.E.Tomsho, B.H.Ruter-
bories, G. J.Smith,  and W. Bartok
                                                     8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
 Exxon Research and Engineering Company
 Government Research Laboratories
 P.O. Box 8
 Linden, New Jersey  07036	
            10. PROGRAM ELEMENT NO.
            EHE624A
            11. CONTRACT/GRANT NO.
           68-02-2649
12. SPONSORING AGENCY NAME AND ADDRESS
 EPA, Office of Research and Development
 Industrial Environmental Research Laboratory
 Research Triangle Park, NC  27711
            13. TYPE OF REPORT AND PERIOD COVERED
            Final; 9/77 -  5/78	
           14. SPONSORING AGENCY CODE
             EPA/600/13
is. SUPPLEMENTARY NOTES IERL-RTP project officer is David G. Lachapelle, MD-65, 919/
541-2236.
16. ABSTRACT Tne report gives a. projection of the performance and cost of the Exxon
Thermal DeNOx Process applied to coal-fired utility boilers. Eight units were selec-
ted, representing different boiler manufacturers, sizes, firing methods, and coal
types. Thermal DeNOx performance was  projected both with and without combustion
modifications for all boilers at full load and at one or more loads down to  50%.  Three
NOx reduction targets were used: the proposed New Source Performance Standards
(NSPS), reduction to about two-thirds of the proposed NSPS, and the maximum prac-
tical NOx reduction that could be achieved.  All costs are for full load.  Thermal
DeNOx was projected to be equally applicable for all boilers studied, despite signi-
ficant differences in flue gas temperatures  and flow paths. Maximum Thermal DeNOx
performance ranged from 50 to 59% for the boilers studied. Costs ranged  from 0.25
to 1.23 millsAWh, excluding preliminary engineering costs and licensing  royalties.
A full-scale demonstration of Thermal DeNOx on a coal-fired utility boiler is
recommended, including investigation of potential downstream effects of the process.
17.
                             KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
                                         b.lDENTIFIERS/OPEN ENDED TERMS
                          COS AT I Field/Group
Pollution
Ammonia
Performance
Cost Estimates
Nitrogen Oxides
Boilers
Coal
Pollution Control
Stationary Sources
NH3 Injection
Thermal DeNOx Process
Utility Boilers
Denitrification
13B
07 B
14B
05A,14A

13A
21D
18. DISTRIBUTION STATEMENT

 Unlimited
19. SECURITY CLASS (ThisReportj
Unclassified
 1. NO. OF PAGES
     191
20. SECURITY CLASS (Thispage)
Unclassified
                        22. PRICE
EPA Form 2220-1 (9-73)
                                        D-13

-------