EPA
TVA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park, NC 27711
EPA-600/7-8i-12
July 1981
Tennessee Valley
Authority
Office of Power
Energy Demonstrations
and Technology
Muscle Shoals. AL 35660
TVA/OP/EDT-81/2
        Evaluation  of the Advanced
        Low-NOx Burner,  Exxon,
        and  Hitachi Zosen  DeNOx
        Interagency
        Energy/Environment
        R&D Program Report

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                 RESEARCH REPORTING SERIES


Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into 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.

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                                    EPA-600/7-81-120
                                    TVA/OP/EDT-81-28
                                              JULY 1981
     Evaluation of the Advanced
        Low-NOx Burner,  Exxon,
and Hitachi Zosen  DeNOx Processes
                        By

              J.O. Maxwell and L.R. Humphries
                Tennessee Valley Authority
                    Office of Power
        Division of Energy Demonstrations and Technology
                Muscle Shoals, AL 35660
          EPA Interagency Agreement No. 79-D-X0511
               Program Element No. INE829
             EPA Project Officer: J. David Mobley
          Industrial Environmental Research Laboratory
       Office of Environmental Engineering and Technology
              Research Triangle Park, NC 27711
                     Prepared for
         U.S. ENVIRONMENTAL PROTECTION AGENCY
             Office of Research and Development
                 Washington, DC 20460
                           fl.S, KbivlroTraontal Protection
                            "'     "        '"''

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                                 LEGAL NOTICE
     This report was  prepared  by the Tennessee Valley  Authority and has been
reviewed  by  the  U.S.  Environmental  Protection  Agency  and  approved  for
publication.  Neither TVA, EPA, nor any person acting on their behalf:

     1.  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

     2.  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.

     This report does not necessarily reflect the  views and policies of TVA or
EPA.
                                       ii

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                                   ABSTRACT
     A technical discussion and a preliminary economic evaluation are made for
three  nitrogen oxide  (NOX)  emission  control  methods  at  50% NOX  reduction
and  three  NOX  control methods  at  90% NOX  reduction.   The base-case  power
plant  is  a new 500-MW  coal-fired  unit emitting 0.6  Ib  N02/MBtu in  the  flue
gas.   The three  50% NOX  reduction  processes are the EPA-sponsored  advanced
low-NOx  burner (ALNB),  the  Exxon  Thermal  DeNOx  process,  and  the  Hitachi
Zosen  process, which  have  capital  investments  of  $4.8/kW,  $19.7/kW,  and
$31.4/kW,  respectively,  and  levelized  annual  revenue  requirements  of  0.20,
1.9,  and  4.7  mills/kWh   respectively.    For  90% NOX   reduction,  the  ALNB
process  is combined  with  the  Hitachi Zosen process,  the Exxon process  is
combined with the Hitachi Zosen process, and the Hitachi  Zosen process is used
alone.  Capital investment and levelized annual revenue  requirements for these
three  processes are  $51.8/kW  and  6.7 mills/kWh  for the  ALNB/Hitachi  Zosen
process, $64.2/kW  and  8.2 mills/kWh for the  Exxon/Hitachi  Zosen process, and
$50.9/kW  and  7.9  mills/kWh  for  the  Hitachi  Zosen process.    The  ALNB,  a
combustion  modification,   is  the  least   expensive  NOX  control  method.  As
would  be  expected,  the  costs  for  obtaining  high  levels  of NOX  reduction
(90%) are significantly greater than for more moderate levels (50%).
                                      ill

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                                   CONTENTS
Abstract   	    iii
Figures	    vii
Tables	     ix
Abbreviations and Conversion Factors ... 	      x

Executive Summary  	   xiii

Introduction 	      1

Background 	 ......  	 ..........      3
  NOZ Control Regulations   	      3
  NOX Formation Chemistry   	      3
  Status of Technology	      4
    Combustion Modification  	      4
    Flue Gas Treatment	      8

Status of Processes Evaluated  	     12
  Advanced Low-NOx Burner   	     12
    Process Description  	     12
    Technical Considerations 	     14
    Development Status 	     19
  Exxon Process	     22
    Process Description	     22
    Technical Considerations 	     29
    Development Status 	     30
  Hitachi Zosen Process	     31
    Process Description  	     31
    Technical Considerations 	     33
    Development Status	     40

Premises	     45
  Design Premises  	     45
    Plant Size and Fuel	     45
    Flue Gas Composition	     46
    NOX Control System	     46
    Raw Materials	     48
  Economic Premises	     48
    Capital Investment Estimates ........ 	     49
    Annual Revenue Requirements  	     51

Systems Estimated  	     53
  Advanced Low-NOx Burner  	     53
  Exxon Process  	 .....     57
                                      v

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    NH3 Storage and Injection	     57
    Air Preheater Section  	     57
  Hitachi Zosen Process  	     61
    Process Description (90% NOX reduction)	     62
    Process Description (50% NOX reduction)	     67

Results and Comparison	     72
  Capital Investment 	     72
    Fifty Percent NOX Reduction	     72
    Ninety Percent NOX Reduction 	     73
    Overall Capital Investment Comparison  	     74
  Annual Revenue Requirements  	 ...     76
    Fifty Percent NOX Reduction	     77
    Ninety Percent NOX Reduction 	     77
    Overall Annual Revenue Requirements Comparison 	     78
  Overall Capital Investment and Annual Revenue Requirements
   Comparison  	 ....... 	     81
  Energy Consumption ... 	     81

Conclusions	     86

References	     88

Appendix A	     91

Appendix B	    109
                                     vi

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                                   FIGURES
Number                                                                   Page

 S-l    Assumed NOX reduction for the six cases studied	      xv
 S-2    Cost for reduction of a pound of NOX based on levelized
        annual revenue requirements 	 . 	    xxii
 S-3    Capital investment comparison and accuracy range (based
        on a -20% to +40% range for Exxon and Hitachi Zosen
        processes and a -20% to +100% range for the ALNB)	    xxiv
 S-4    Levelized annual revenue requirements and accuracy range
        (based on a -20% to +40% range for Exxon and Hitachi Zosen
        processes and a -20% to +100% range for the ALNB)	     xxv
   1    Baseline NOX emissions - coal-fired utility boilers 	       5
   2    Pulverized-coal-fired boiler burner zone heat release
        rates	       6
   3    Major stages of the ALNB development	      13
   4    Alternatives for injection of ALNB tertiary air	      14
   5    Effects of ALNB zone stoichiometry, single burner 	      15
   6    Effects of ALNB primary swirl, single burner  	      16
   7    Effects of ALNB secondary swirl, single burner  	      17
   8    Effects of ALNB zone stoichiometry, four burners fired at
        12.5 x 106 Btu/hr each	      18
   9    Effects of ALNB tertiary ports out of service, four burners
        fired at 12.5 x 106 Btu/hr each	      20
  10    Effects of ALNB coal type, four burners fired at 12.5 x 106
        Btu/hr each	      21
  11    Variables evaluated in the single ALNB test program 	      23
  12    Effect of temperature on NO reduction for various levels
        of NH3 injection with the Exxon process	      25
  13    Effect of temperature on NO reduction for various fuel
        sources with the Exxon process	      26
  14    Comparison of NO reductions at the optimum temperature
        condition with the Exxon process	      27
  15    Comparison of the NH3 emissions for all fuels tested
        at the peak NO reduction temperature with the Exxon process .      28
  16    NOz reduction versus reaction temperature for the Hitachi
        Zosen process	      34
  17    Configuration of Hitachi Zosen NOXNON 500 and 600 series
        catalyst	      35
  18    Relationship between exhaust NH3, NOZ reduction, and molar
        ratio for the Hitachi Zosen process	      36
  19    Conditions for the formation of ammonium snlfate/
        bisulfate	      38
                                     vli

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20    Pressure drop versus operating time for the Hitachi Zosen
      process ..... 	 ...... 	      39
21    NOX reduction versus catalyst age for the Hitachi Zosen
      process	      37
22    Influence of NOX concentration on NOX reduction with the
      Hitachi Zosen process .... 	      41
23    Influence of 02 concentration on NOX reduction for the
      Hitachi Zosen process 	      42
24    Assumed NOX reduction for the six cases studied	      54
25    Advanced low-NOx burner flow diagram  	      55
26    Exxon process flow diagram  .	      58
27    Hitachi Zosen process (90% NOX reduction) flow diagram  ...      63
28    Hitachi Zosen process (50% NOX reduction) flow diagram  ...      68
29    Cost for reduction of a pound of NOX based on levelized
      annual revenue requirements 	      82
30    Capital investment comparison and accuracy range (based on
      a -20% to +40% range for Exxon and Hitachi Zosen processes
      and a -20% to a +100% range for the ALNB)	      83
31    Levelized annual revenue requirements and accuracy range
      (based on a -20% to +40% range for Exxon and Hitachi Zosen
      processes and a -20% to +100% range for the ALNB)	      84
                                   viii

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                                   TABLES
Number                                                                   Page

 S-l    Summary of Capital Investments		    ziz
 S-2    Summary of Annual Revenue Requirements 	     zx
 S-3    The Effect of Catalyst Life on Annual Revenue Requirements . .    zzi
 S-4    Energy Requirements  	   zzvi
   1    NOZ Emissions Standards and Projected Research Objectives for
        Large Fossil-Fuel-Fired Boilers  ....... 	      3
   2    Summary of Commercial Applications of Ezzon Thermal DeNOx
        Process	     32
   3    Influence of S02 and H20 Concentrations	     40
   4    Hitachi Zosen Pilot-Plant Experience 	     43
   5    Commercial Plants Using the Hitachi Zosen Process  	     44
   6    Coal Plant Base Mechanical Equipment	     45
   7    Base Case Coal Composition and Input Flow Rate	     46
   8    Flue Gas Composition and Flow Rate at the Economizer Outlet  .     47
   9    Levelized Annual Capital Charges for Regulated Utility
        Financing	     49
  10    Cost Indezes and Projections		     50
  11    Cost Factors	     52
  12    Advanced Low-N0x Burner Material Balance ...........     56
  13    Exxon Material Balance 	     59
  14    Exxon Equipment List		     60
  15    Hitachi Zosen (90% NOX Reduction) Material Balance 	     64
  16    Hitachi Zosen (90% NOZ Reduction) Equipment List	     65
  17    Hitachi Zosen (50% NOX Reduction) Material Balance ......     69
  18    Hitachi Zosen (50% NOX Reduction) Equipment List 	     70
  19    Summary of Capital Investments	     73
  20    Contribution of Direct Investment, Royalties, and Catalyst to
        Capital Investment	     75
  21    Summary of Annual Revenue Requirements ..... 	     76
  22    Contribution of Raw Materials and Utilities to Annual Revenue
        Requirements ..... 	     79
  23    The Effect of Catalyst Life on Annual Revenue Requirements . .     80
  24    Comparison of Energy Requirements  	 .     85
                                     ix

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                     ABBREVIATIONS AND CONVERSION FACTORS
ABBREVIATIONS
ac         acre
aft3/min   actual cubic feet per
            minute
ALNB       advanced low-NOz burner
bbl        barrel
Btu        British thermal unit
°F         degrees Fahrenheit
dia        diameter
F6D        flue gas desulfurization
F6T        flue gas treatment
ft         feet
ft2        square feet
ft3        cubic feet
gal        gallon
gpm        gallons per minute
gr         grain
hp         horsepower
hr         hour
in.        inch
k          thousand
kW         kilowatt (electric)
kWh        kilowatthour
Ib         pound
L/G        liquid to gas ratio in
            gallons per thousand
            actual cubic feet of
            gas at outlet condi-
            tions
M           million
mi          mile
mo          month
MW          megawatt  (electric)
MWt         megawatt  (thermal)
ppm         parts per million
psig        pounds per square inch
             (gauge)
rpm         revolutions per minute
RR          first-year annual revenue
             requirement
SCR         selective catalytic
             reduction
sec         second
sft3/min    standard cubic feet per
             minute (60°F)
Sp          swirl angle, primary air
SNR         selective noncatalytic
             reduction
SRg         stoichiometric ratio, total
             air minus tertiary air
SRp         stoichiometric ratio,
             primary air
SRj         stoichiometric ratio,
             theoretical
Sjj          swirl angle, secondary air
SS          stainless steel
TCI         total capital investment
yr          year

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  CONVERSION FACTORS
     EPA policy is to express all measurements in Agency documents in metric units.   Values in this
report are given in British units for the convenience of engineers and other scientists accustomed to
using the British systems.  The following conversion factors may be used to provide  metric equivalents.
           To convert British
Multiply by
To obtain Metric
ac          acre                              0.405
bbl         barrels of oila                  158.97
Btu         British thermal unit              0.252
°F          degrees Fahrenheit minus 32      0.5556
ft          feet                              30.48
ft2         square feet                      0.0929
ft3         cubic feet                      0.02832
ft/min      feet per minute                   0.508
ft3/min     cubic feet per minute          0.000472
gal         gallons (U.S.)                    3.785
gpm         gallons per minute              0.06308
gr          grains                           0.0648
gr/ft3      grains per cubic foot             2.288
hp          horsepower                        0.746
in.         inches                             2.54
lb          pounds                           0.4536
lb/ft3      pounds per cubic foot             16.02
Ib/hr       pounds per hour                   0.126
psi         pounds per square inch             6895
mi          miles                              1609
rpm         revolutions per minute           0.1047
sft3/min    standard cubic feet per          1.6077
             minute (60°F)
               hectare
               liters
               kilocalories
               degrees Celsius
               centimeters
               square meters
               cubic meters
               centimeters per second
               cubic meters per second
               liters
               liters per second
               grams
               grams per cubic meter
               kilowatts
               centimeters
               kilograms
               kilograms per cubic meter
               grams per second
               pascals (newton per square meter)
               meters
               radians per second
               normal cubic meters per
                hour (0°C)
                          ha
                          L
                          kcal
                          °C
                          cm
                          m2
                          m3
                          cm/s
                          m3/s
                          L
                          L/s
                          kW
                          cm
                          kg  »
                          kg/m3
                          g/s
                          Pa (N/m2)
                          m
                          rad/s
                          m3/h (normal)
ton
ton, long
ton/hr
a.
b.
tons (short)6
tons (long)b
tons per hour


Forty-two U.S. gallons per
All tons, including tons of

barrel of oil
sulfur, are
0.9072
1.016
0.252
•
expressed
metric tons
metric tons
kilograms per
in short
tons
second
tonne
tonne
kg/s
in this report.

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                               ACKNOWLEDGEMENTS
     The authors wish  to acknowledge David G. Lachapelle,  Program Manager of
Utility/Large Industrial  Boiler Technology Development  of  Industrial Process
Combustion  Equipment  Technology  Development  for  EPA,  and G.  Blair Martin,
Program Manager of Advanced Concepts Technology Development and of Fundamental
Combustion  Research  for  EPA,   for  their  assistance   in  the  planning  and
execution of this project.
                                      xii

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             EVALUATION OF THE ADVANCED LOW-NOX BURNER,  EXXON,

                     AND HITACHI ZOSEN DENOX PROCESSES
                              EXECUTIVE SUMMARY
INTRODUCTION

     The new source performance standards (NSPS)  for  steam electric  generating
boilers promulgated  after the Clean  Air Act Amendments  of 1977 require  the
installation  of  the  best available  control technology  (BACT)  for nitrogen
oxides  (NOX)  on  new  or  modified   facilities,  including  electric  power
generating  units.    Therefore,  as  NOX  control   technology  is  further
developed, more stringent standards may  be  required.  The  1977 Clean Air  Act
Amendments  also  require  the  promulgation  of a  short-term nitrogen dioxide
(N02>  ambient air  quality  standard   (three  hours  or  less  averaging  time)
unless  it can be  demonstrated that  the standard is  unnecessary for public
health  protection.   This short-term  ambient  standard may  require  additional
NOX  emission  control  for  stationary  sources.    Prevention  of significant
deterioration  (PSD)  regulations  for  N02 are  also  required by the 1977 Clean
Air  Act Amendments  and  these requirements  may  also lead  to more  stringent
NOX emission control for stationary sources.

     There  are two  basic types  of  NOX  control  technology  currently  under
development:   combustion modifications   and  flue  gas  treatment  (FGT).
Combustion modifications primarily include  the use of low  excess air, staged
combustion  with  either  overfire  air  or burners  out  of  service,  flue   gas
recirculation, burner  design  and operating  modifications,  or combinations  of
the  above.    Combustion  modification  techniques  have   received   the  most
development  emphasis  in  the  United  States.  However,  FGT may  be  needed  to
achieve the NOX emission reductions which may be  required  in the  future.

     FGT  can be  divided into  two general  categories:    dry and wet.    The
majority of dry processes involve  a gas-phase reaction with a reducing agent,
NH3,  which  is  added  to the  flue  gas.  If the  NH3  is  injected  into   the
superheater  region  of the  boiler where  temperatures are  high  (1,740°F),  a
catalyst   is  not  necessary.    These  processes  are  known  as  selective
noncatalytic reduction (SNR) processes.  If  the  flue  gas  is treated  after  the
boiler  economizer,  a  catalyst  is necessary  to  produce  the  needed reaction
rate.    These  processes  are  typically described   as   selective   catalytic
reduction  (SCR)   processes.     Development   of   wet   NOX   FGT processes   has
practically  ceased  because  of the  complexity  and  unfavorable  economics  of
these processes compared with dry processes.
                                     xiii

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     The  major  purposes  of  this  study  are  to  provide  current  technical
information  on the various  selected  NOX control  methods and to  compare  the
economics  of  these  NOX  control methods  using  common  design  and  economic
premises.  The NOZ control  techniques selected for  evaluation  are combustion
modification,  SNR, and  SCR  processes.   Wet processes  are not evaluated.   The
combustion modification technique  evaluated  is the  advanced low-NOx  burner
(ALNB) being developed under the U.S.  Environmental Protection Agency (EPA)
sponsorship by the Energy and Environmental Research Corporation (EERC); a 50%
NOX  reduction  capability  is assumed  for  the ALNB  in  this study.    The Exxon
Thermal  DeNOx  process,  an  SNR  process,   is also  evaluated;   moderate  NOX
reduction  (30%  to 60%)  is attainable  by  this  process.    The   SCR  process
evaluated  in this study  is  the  Hitachi  Zosen process.   This  type of  process
has the capability for high levels of NOX reduction (90%).

     Two  levels  of NOX reduction from NSPS  level are  examined.   Assuming  a
baseline  emission for  the  boiler  of  0.6  Ib  NC>2/MBtu  (450 ppm  at   3%  02)
costs  are determined  for a moderate  50%  NOX  reduction  to  0.3   Ib  N(>2/MBtu
(225  ppm  at  3%  02)   for   each of  the  three processes although  50%  NOX
reduction  is  not  typical  for  the  Hitachi Zosen process.   The  alternative
control  level,  90%  NOX  reduction  to 0.06 Ib N02/MBtu (45 ppm  at 3%  C^),
involves the following three situations:

   1.  Moderate NOX reduction achieved by the ALNB (0.6 to 0.3 Ib
       N(>2/MBtu) and the remaining NOX reduction (80%)  achieved by the
       Hitachi Zosen process (0.3 to 0.06 Ib N02/MBtu).

   2.  Moderate NOX reduction achieved by the Exxon process (0.6 to 0.3 Ib
       N(>2/MBtu) and the remaining NOX reduction (80%)  achieved by the
       Hitachi Zosen process (0.3 to 0.06 Ib N02/MBtu).

   3.  All of  the NOX reduction  (90%) achieved by the Hitachi Zosen process
       (0.6  to 0.06 Ib N02/MBtu).

     The  levels  of  NOX   reduction  assumed for  each   process  and  process
combination evaluated  in this  report  are  graphically  illustrated  in
Figure S-l.


DESIGN AND ECONOMIC PREMISES

     A  specific  set of design  and economic  premises  is used to  compare the
process  economics of   the  different types of  NOX control  technology  on  a
consistent basis.  The  basic premises used in this report were established by
TVA  for  comparative economic evaluations  of power  plant stack gas emission
control processes.

Design Premises

     The  power  plant  assumed  as  a  basis  for  this study  is  a  new  500-MW,
horizontally  opposed,  balanced-draft  boiler  burning  pulverized  coal  and
situated  in  a north-central  location (Illinois,  Indiana, Ohio, Michigan,  or
                                      xiv

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 CN|
O
S3
53
O
M
C/2
CO
M
S
w
 0.7 -.




 0.6




 0.5




 0.4




 0.3




 0.2,



 0.1

0.06,

   0
                    Single Processes
                             Combination Processes

ALNB    Exxon    Hitachi

                  Zosen

                                    ALNB/Hitachi  Exxon/       Hitachi Zosen
                                        Zosen      Hif-arhi  7ncp>n
                                     3       4


                                    CASES STUDIED
Figure  S-l.   Assumed NC>  reduction for the six cases studied.
                        A.
                                   XV

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Wisconsin).   The fuel  is  a bituminous  coal  with  a  heating value  of  11,700
Btu/lb as  fired and containing  3.5%  sulfur and  15.1%  ash.   The  boiler  heat
rate  is  9,500 Btu/kWh.  On-stream  time for the  boiler is 5,500  hr/yr.   Raw
materials  are assumed  to  be received  by  either rail  or truck.   Thirty-day
storage facilities at full load (500 MW) are provided.

     The  estimated  costs  for  the  selected  NOX  control  methods  reported  in
this  study are  differential costs  for new  boilers,  i.e.,  only additional
expenses above present  new boiler costs  are  included.  Costs are not included
for present  combustion modification techniques being applied to new boilers,
which are  reportedly  capable of reducing NOX emissions to the  NSPS of  0.6 Ib
N(>2/MBtu  for  bituminous  coal.  In  the  case  of  the  ALNB,  only  the
differential  costs   over  those  for  regular  burners  are   included.    Also,
separate induced draft  (ID) fans are not included.  Where applicable, a larger
boiler ID fan  is  used  to compensate  for  the higher  pressure drops  of the
combined boiler-NOx  control  process and the  increased  costs are  assigned to
the NOX control process.

Economic Premises

     Capital  investment estimates are based on projected mid-1982 construction
costs.  The revenue requirements are based on projected 1984 costs.  Delivered
raw material  costs and  labor rates are based on a north-central   location.

     Capital  investment consists of  direct investment,  indirect  investment,
and other  capital  investments.    The  direct investment is based on equipment
costs.  Other installation costs (such as piping, electrical, instrumentation,
etc.) are  factored from the equipment costs.  Indirect investment  (engineering
design and supervision, construction  expense,  etc.) is  based   on the  direct
investment.   Other  capital  investments,  such  as  allowance  for  startup and
modification  and  interest  during construction,  are based on  the total  direct
and  indirect  investment.     Other  capital   investments  also   include,  when
applicable, land, working capital, royalties, and initial catalyst charges.

     Two  types  of annual  revenue  requirements are projected—first year and
levelized.   Both are based on 5,500 hr/yr  of  operation at  full load (about a
63%  capacity factor)   and both  use  a levelized capital charge.   Levelized
annual revenue requirements differ from first-year annual revenue  requirements
in that  they  take into consideration  the time value  of money over the life of
the NOX  reduction  unit.  They are  calculated  using a 10%/yr discount factor,
a 6%/yr  inflation factor,  and a 30-year economic life.


PROCESS BACKGROUND AND  SYSTEMS ESTIMATED

Advanced Low-NOy Burner

     An  ALNB  for both  utility and  industrial  applications  is  being developed
under EPA  sponsorship  by  EERC  to  minimize NOX  formation  during  the
combustion of coal.    The  primary objectives are:   (1)  to  provide an initial
fuel-rich,  i.e., oxygen-deficient,  zone  which maximizes  the  conversion of
                                     xvi

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organic  nitrogen coumpounds  to N2,  and  (2)  to blanket  the  fuel-rich  zone
with an oxidizing atmosphere to maximize burnout and to minimize  the  potential
for corrosion  in the  lower furnace section of  the boiler.  The  research  goal
is  to  attain an  NOX  emission level  equivalent  to  0.2  Ib N02/MBtu.  For
this  study,   the  NOX  emission  level  assumed  for  the  ALNB  is  0.3  Ib
N02/MBtu.

     The utility burner  design consists of  a  central  burner, similar  to the
Babcock & Wilcox  (B&W)  dual  register burner,  plus four  tertiary  air ports
located about  one  throat  diameter  from the central burner.  The  air  admitted
through  the  central  burner  is divided  into   three  streams  referred  to  as
primary  and inner and  outer  secondary  air.    Primary air  that carries the
entrained  pulverized  coal  is  about  25%  of  stoichiometric  requirements.
Secondary air  is injected  from an annulus around the primary  air port  and  is
about 45% of  stoichiometric requirements.  Swirl vanes  in  the  inner  secondary
annulus  impart swirl to  control mixing  of  the primary  and  inner  secondary
streams and to control  flame  shape.   The  remaining secondary  air is  admitted
through  the outer secondary  annulus.   About  50%  of  the stoichiometric air
quantity is admitted  through  the tertiary air ports.  Thus, with a  total air
supply of 120% of  stoichiometric requirements,  the  central burner operates  at
about 70% stoichiometry to minimize oxygen availability and conversion of  fuel
nitrogen to NOX, while  the remaining stoichiometric air supplied through the
tertiary air  ports completes  combustion  and  maintains  an overall  oxidizing
atmosphere.

Exxon Process

     The Exxon process,  developed  by Exxon Research and Engineering,  reduces
NOX in  flue gas  by dry  SNR.   NH3  with air  (94-98  volume  % air) is  injected
into  the cavity of  the   secondary  superheater tube  bank region  where the
temperature  is  high enough  for NOX  and NHg  to  react  to  form  N2  and
H20.  For NOX reduction  of  40% to  60%,  the  optimum temperature  range  is
1,650°F to 1,830°F,  and the NH3:NOX  molar ratio varies  from  1:1  to
2:1.    Injecting H2  with  the  NR$  reduces  the  temperature  level  at which
reaction rates   are  adequate  for  efficient NOX  reduction.  At  H2:NH3
molar  ratios  of about  2:1 NOX  reduction  can  occur rather  rapidly at about
1,290°F.  NH3  is  injected through  an  insulated   piping  grid  which  covers
the entire cross-sectional area of the flue gas flow path.

     Since NOX reduction  is sensitive to temperature,  steps must be  taken  to
maintain NOX  reduction  efficiency  with varying boiler loads.  There  are  many
alternative  techniques presently used, i.e.,  the use of one  or multiple grids
to  inject   only  the  NH3,   or  one  or multiple  grids  with  both NH3  and  H2
injection.   In this  study a two grid  system injecting  only  NH3  is  used.   An
NH3:NOX molar ratio of 1.5:1 is assumed to achieve  50%  NOX  reduction.

     The major equipment  for  this  process includes only  NHg  storage  tanks,
NH3  injection  grids,  and  compressors  for  the  air  used  as  the  NH3
carrier.  Also included in  this  study under  equipment  costs  are  costs  for air
heater  design  and  operating modifications that may be  necessary when using
this process with  a  coal-fired boiler.  (These modifications  result  from the
                                     xvii

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NH4HS04  and  (NH4)2S04   deposited  in  the   air  heater  by  reaction  of
NH3 with 863 present in coal-fired flue  gas.)

Hitachi Zosen Process

     The Hitachi Zosen  process  is a dry SCR process  in which  NE^  is  injected
into  the  flue  gas  and  reacts with  NOX selectively,  in the  presence of  a
catalyst,  to  form N2  and  I^O.   The catalyst  allows  the reaction  to  proceed
rapidly  at   temperatures   in   the  600°F   to   750°F   range.   The   corrugated
catalyst units,  made with  a proprietary  catalyst  on a steel  support,  permit
treatment of flue gas with high particulate  loadings.   Therefore, based on the
temperature range and the  lack  of required  particulate removal,  flue  gas from
a coal-fired  boiler  may be fed directly from  the boiler  economizer to  an NOX
reduction reactor.   With  NH3:NOX  molar ratios  of 1:1  or  greater,  90%  NOX
control  is  reportedly  achievable.  This process  requires  only  NH3  storage
and injection facilities and a catalytic reactor.  In this study an economizer
bypass  is also  included to maintain acceptable  reactor temperatures when the
boiler  load is low.   The  temperatures during low boiler  loads  may  not  be high
enough  to  obtain adequate  NOX  control  and  may also be  low enough to allow
NfyHSCfy  and  (1^4)2804  formation  in  the   catalytic  reactor.     Also,  air
heater  design  and  operating   modifications  are  included  to  minimize  the
potentially adverse effects of these salts,  as is done for the  Exxon process.


     For the  case  in which overall NOX reduction  is 90%, two  reactor  trains
are used,  each  treating  50% of  the  flue  gas.   An NH3:NOX  molar ratio  of
1:1 is  used.    For  an  overall  50% NOX reduction  only  one  reactor train  is
used  to treat 56%  of the  flue  gas.    Again,  an NH3:NOX molar  ratio  of  1:1
is used.  A third case is  for  an overall  reduction of 80%, but from  a lower
initial NOX  level  (from  0.3  to  0.06  Ib  N02/MBtu).  This  case  is  used  in
combination with either the ALNB  or Exxon process  to  achieve the  same  overall
degree  of  NOX  reduction  as  with  the Hitachi   Zosen  90%   NOX reduction
case.   Two reactor trains similar in size to the first case  are used, but with
less  catalyst.   An NH3:NOX molar ratio of  0.9  is  used.   A catalyst life  of
one year is assumed for all three cases.


ECONOMIC RESULTS AND COMPARISON

     The process  economics consist of  capital  investment,  first-year  revenue
requirements,   and levelized  annual  revenue  requirements.    Because   of  the
different sources of data, the simplifying assumptions made,  and the necessity
of projecting costs  into  the  future,  these  estimates  are  considered  to  be
accurate to  an overall variation of  -20% to  +40%  for  the  Exxon  and  Hitachi
Zosen processes.  For the  ALNB  the  estimates are considered  to be  accurate to
an overall variation of -20%  to +100%.   This  larger range is  a result  of the
less advanced development status of the  ALNB and the relative lack  of  detailed
design, equipment  needs, and  costs  in  comparison with the NOX  F6T
processes.   The findings of this report  apply only  to a new  installation.
                                    xviii

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Results - Capital Investment

     The  capital  investment results for  the  50% and  90%  NOX reduction cases
are  shown in Table S-l.   The ALNB  has  the lowest capital  investment  of the
three  50%  NOZ  reduction  processes  studied.  Because  of  the  much  greater
amounts of process  equipment,  the  investments  for the Exxon and Hitachi Zosen
processes are significantly higher.  A royalty fee is not charged for the ALNB
technology while  royalty fees are  $1.5M  and  $0..5M for  the  Exxon  and Hitachi
Zosen  processes,   respectively.    The  cost of  the  initial catalyst  charge
($3.7M) represents a large portion of the Hitachi Zosen capital investment.


                 TABLE S-l.  SUMMARY OF CAPITAL INVESTMENTS
                                                   Capital
                                                 investment,
                                                  mid-19825
                        Process	M$   $/kW
                 50% NOX reduction
                   ALNB                           2.4   4.8
                   Exxon                          9.9  19.7
                   Hitachi Zosen                 15.7  31.4
                 90% NOX reduction
                   ALNB/Hitachi Zosen            25.9  51.8
                   Exxon/Hitachi Zosen           32.1  64.2
                   Hitachi Zosen                 25.5  50.9
     For  90%  NOX  reduction,  the  Hitachi  Zosen  and  ALNB/Hitachi Zosen
processes  have  similar  capital  investments,  while  the  investment  for  the
Exxon/Hitachi  Zosen process  is  higher.    Royalty  fees  are   $0.5M  for  the
ALNB/Hitachi  Zosen  and  the  Hitachi  Zosen  processes,  and   $2.0M for  the
Exxon/Hitachi Zosen process.  The initial catalyst charge for the ALNB/Hitachi
Zosen and the Exxon/Hitachi Zosen processes costs $5.0M for each process while
the  Hitachi Zosen  process has  a  cost  for  the initial  catalyst  charge  of
$6.5M.   In contrast  to  the other  processes,  the royalty fee for  the Exxon
process is a major cost item.   It is equal to 15% of  the capital investment.
     Although both  the  Exxon process and  the Hitachi Zosen  process  use
the  equipment  costs associated  with  NH3  are  much larger for  the  Exxon
process.   The investment  for  NH3 storage  and  injection with the  process  is
four  times  larger  than  that  for  the  Hitachi  Zosen  90%  NOX  reduction
process.  This  is  a result of a  larger  NHg consumption  and subsequent larger
storage  needs,  a  more   intricate  and expensive  injection grid,  and a  more
expensive air carrier system for the Exxon process.
                                     xix

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Results - Annual Revenue Requirements

     The first-year and levelized annual revenue requirements for both the 50%
and  90%  NOX  reduction cases are  shown in  Table  S-2.    As with  the  capital
investment,  for  50% NOX  reduction the ALNB  has significantly  lower  revenue
requirements than the  Exxon  or Hitachi  Zosen processes.   The only substantial
revenue requirement item  for the ALNB  is  the levelized  capital charges, while
the  Exxon  and Hitachi Zosen processes  not only have higher capital charges,
but also substantial raw material,  utility, and maintenance requirements.  The
annual catalyst replacement cost is a large portion (33%) of the Hitachi Zosen
annual revenue requirement.
               TABLE S-2.  SUMMARY OF ANNUAL REVENUE REQUIREMENTS
                                         Annual revenue requirements
                                        	(1984$)	
                                          First year       Levelized
                 Process	M$   Mills/kWh   M$   Mills/kWh
50% NOX reduction
ALNB
Exxon
Hitachi Zosen
90% NOX reduction
ALNB/Hitachi Zosen
Exxon/Hitachi Zosen
Hitachi Zosen

0.45
3.4
8.0

11.5
14.2
13.3

0.17
1.2
2.9

4.2
5.2
4.9

0.54
5.1
13.0

18.4
22.6
21.9

0.20
1.9
4.7

6.7
8.2
7.9
     For  90%  NOX  reduction,  although  the  Hitachi  Zosen  and  ALNB/Hitachi
Zosen  processes  have  similar  capital  investments, the Hitachi  Zosen process
levelized  annual  revenue  requirements  are  $3.5M  higher  than those  for the
ALNB/Hitachi Zosen process due to greater catalyst requirements of the Hitachi
Zosen  process.   The revenue requirements for  the  Exxon/Hitachi  Zosen process
are  the  highest  of the three because of  higher conversion cost and levelized
capital  charges.    Annual  catalyst  replacement   is  required  for  all   three
processes.   The  annual  catalyst  replacement  cost  contributes  appreciably to
the  levelized  annual  revenue  requirements:    32%  for  the  ALNB/Hitachi Zosen
process,  26% for  the Exxon/Hitachi  Zosen  process,  and  34% for  the Hitachi
Zosen  process.

     Since  a one-year catalyst life is guaranteed  it was  used  as a basis for
the  cost estimate  however, actual  catalyst life could be  longer.   Should a
two-year  life be  obtainable  for  the  Hitachi  Zosen  process   a  significant
savings  can be  realized in the annual  revenue requirements.  Table S-3  shows
that   a  two-year  catalyst life  will  reduce  the  levelized annual  revenue
                                     xx

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requirements  of the  Hitachi Zosen  (50% NOX  reduction),  ALNB/Hitachi Zosen,
and Hitachi  Zosen  (90% NOX  reduction) processes  by 30% and the Exxon/Hitachi
Zosen  process by 24%.   Even though  this  is a significant  reduction for the
processes  requiring  catalyst,  it  is  not  sufficient  to  change   the  cost
relationship  of the  processes.   For  50%  NOX  reduction  the  ALNB  is still
lowest  followed by  the Exxon  and Hitachi  Zosen processes  and for  90%  NOX
reduction  the ALNB/Hitachi Zosen  remains  the lowest followed  by  the Hitachi
Zosen and Exxon/Hitachi Zosen processes.
                  TABLE S-3.  THE EFFECT OF CATALYST LIFE ON

                         ANNUAL REVENUE REQUIREMENTS
           Process
                                 Annual
                         Hitachi Zosen catalyst
                          replacement cost. M$
                            1-year     2-year
                           catalyst   catalyst
                             life	life	
             Levelized
           annual revenue
         requirements. M$
          1-year    2-year
         catalyst  catalyst
           life      life
     50% reduction
       Hitachi Zosen
     90% reduction
       ALNB/Hitachi Zosen
       Exxon/Hitachi Zosen
       Hitachi Zosen
                             4.3

                             5.8
                             5.8
                             7.5
2.1

2.9
2.9
3.7
13.0

18.4
22.6
21.9
 9.0

12.9
17.1
14.8
On the  basis  of cost per pound  of
                                             removed, as  shown  in Figure S-2,
50%  NOX reduction  is  substantially  less  expensive  than 90%  NOX  reduction,
with the exception of the Hitachi Zosen 50% reduction process.  The large cost
difference between the Hitachi Zosen  50%  reduction case and the two other 50%
reduction cases occurs because the ALNB and Exxon processes do not require the
expensive annual catalyst replacement.

     The Hitachi Zosen  50% NOX reduction case has  a slightly higher cost per
pound  of N(>2  removed  than  the  Hitachi  Zosen  90% reduction  case  for  two
reasons.  First, there  is  some  economy of scale in the capital investment for
the 90%  reduction  case  compared with  the 50%  reduction case.   Therefore, the
level ized capital  charges  and maintenance costs, which  are  factored from the
capital  investment,  are  a  smaller portion of  the  annual revenue requirements
for the 90% reduction case.  Also, certain items are of equal cost at both the
90% and  50% reduction levels,  such  as operating  and analysis labor, resulting
in a smaller cost per pound of N02 removed at the 90% reduction level.

     The N%  cost  for  the Exxon process  is over  twice that  of  the Hitachi
Zosen process  (50%  NOX  reduction case) and  even 1-1/2  times higher than that
                                      xxi

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X

H-
          C/l
          w
          w
          u

          §
          eu
                              ALNB
                             Exxon
                 Hitachi Zosen 50%
                ALNB/Hitachi Zosen
               Exxon/Hitachi Zosen
                 Hitachi Zosen 90%
                                                i      i
                                                                        I     I     •     I


                                                                              50% NOX Reduction
90% NOV Reduction
                                    0    0,2   0.4   0.6   0.8   1.0   1.2   1.4   1.6   1.8   2.0




                                                          $/LB OF N02 REDUCED
            Figure S-2.  Cost for reduction of a pound of NOX based on levelized annual revenue


                         requirements.

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for  the  Hitachi  Zosen  90% NOX  redaction  process  because  of   the  higher
NH3:NOX  molar  ratios  required.  The NH3  costs  are about  15% of  the  Exxon
levelized annual revenue  requirements while  they are only 2% of the levelized
annual revenue  requirements  for either case of the Hitachi Zosen process.

Overall Capital Investment and Annual Revenue Requirements Comparison

     A  comparison  of  the  capital  investment   and  levelized  annual  revenue
requirements  for  each  of  the  six  NOX control  processes  is  shown  in
Figures  S-3  and  S-4  respectively.   Also included  in  the  figures  are  the
accuracy  ranges  on  the  capital   investment  and   levelized annual  revenue
requirements.

     For  50% NOX  reduction  the ALNB  has the  lowest capital  investment  and
levelized  annual   revenue  requirements.    The Exxon process  has   the  second
lowest  and  Hitachi  Zosen has  the highest  capital  investment  and levelized
annual revenue  requirements.

     The  capital  investment  of the  ALNB/Hitachi Zosen and  the  Hitachi  Zosen
processes are almost  equal  for 90% NOX  reduction,  but  the  levelized annual
revenue  requirements  are lower   for  the  ALNB/Hitachi  Zosen  process.    In
comparison  with the  above  two processes,  the  Exxon/Hitachi  Zosen  process
capital  investment  is  substantially higher;  however,  the Exxon/Hitachi  Zosen
levelized revenue requirement is comparable.

     Capital   investment   and  levelized  annual   revenue   requirements  are
significantly higher for 90% NOX reduction than for 50% NOX reduction.


ENERGY CONSUMPTION RESULTS AND COMPARISON

     Energy  consumption  for  all the 50%  and 90% NOX  reduction cases  studied
is  less   than  1%  of the  boiler   capacity,  as   shown  in Table  S-4.   Energy
requirements for the three 50% reduction cases range from none for the  ALNB to
0.4%  of   the boiler  capacity  for  the  Exxon process.    The  range  for  90%
reduction is  from  0.4% of the boiler capacity for  the ALNB/Hitachi Zosen and
Hitachi Zosen  processes  to 0.7% of  the boiler capacity  for the Exxon/Hitachi
Zosen process.   The NOX  control  alternatives   containing  the  Exxon  process
are  the   highest  energy  consumers  at  both  the 50%  and  90%  NOX  reduction
levels.
CONCLUSIONS

     The  economic  conclusions  of  this  study  are  based  on  NOX  control
technology  at  various  early  stages  of development  applied to  a  new  power
plant.  Further development and retrofit applications could greatly alter both
the  absolute  and relative  costs  of the processes.   To develop  accurate and
timely  economics in  this  rapidly evolving  field,  continued  monitoring  of
developments in NOX control technology is necessary.
                                    xxiii

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co
CO
w
u
o
Pi
p-l
                       ALNB
                      Exxon
         Hitachi  Zosen 50%
        ALNB/Hitachi  Zosen
        Exxon/Hitachi  Zosen
         Hitachi  Zosen 90%
                                                                                     50% NOV Reduction
                                                                                           A.
              90% NOX Reduction
                                                     I
I
I
I
                                  10     20     30     40    50    60    70    80    90



                                                        CAPITAL INVESTMENT, S/kW
                 100
                 110    120
    Figure S-3.  Capital investment comparison and accuracy range (based on a -20% to +40% range for

                 Exxon and Hitachi Zosen processes and a -20% to +100% range for the. ALNB).

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w
u

8
P-!
                    ALNB
                   Exxon
       Hitachi Zosen 50%
ALNB/Hitachi Zosen
     Exxon/Hitachi Zosen
       Hitachi Zosen 90%
                                                                                 50% NOX Reduction
                    D
                                                                           90% NOX Reduction
                               1     2     3     4     5     6     7     8      9     10     11     12




                                        LEVELIZED ANNUAL REVENUE REQUIREMENTS,  mills/kWh
    Figure S-4.   Levelized  annual  revenue  requirements  and  accuracy  range  (based  on a -20% to  +40%

                 range for  Exxon and Hitachi  Zosen  processes  and  a -20%  to  +100%  range for the ALNB),

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                       TABLE S-4.   ENERGY REQUIREMENTS
                                                        Total  equivalent
                               Steam,    Electricity,    energy  consumption,
           Process	MBtu/hr    MBtu/hr    % of boiler capacity*
50% reduction
ALNB
Exxon
Hitachi Zosen
90% reduction
ALNB/Hitachi Zosen
Exxon/Hitachi Zosen
Hitachi Zosen

0.0
5.7
6.0

8.0
11.7
10.9

0.0
11.5
7.7

10.2
21.7
10.3

0.0
0.4
0.3

0.4
0.7
0.4

  a.  Does not include energy requirement represented by raw materials.
      Based on a 500-MW boiler,  a gross heat rate of 9,500 Btu/kWh for
      generation of electricity,  and a boiler efficiency of 90% for
      generation of steam.


     For  moderate  NOX  reduction of  50%,  the ALNB  is by  far  the most
economical  alternative,  even  if  its  costs were  to  increase  several  times
relative  to  the  other processes.   The ALNB NOX reduction  efficiency  and  its
effects on boiler efficiency and operation  remain to be fully  demonstrated in
utility applications, however.

     The Hitachi Zosen process has  a  higher capital  investment  than the Exxon
process at  the 50%  reduction  level because  of the  initial catalyst  charge,
reactor,  additional  ductwork, and  additional fan capacity  required.   It also
has  higher   revenue   requirements,   primarily   because  of annual  catalyst
replacement costs, although  the  NHg requirements are much  less  than those of
the  Exxon process.    Changes  in  catalyst  cost  or  NH3  consumption or  cost
would appreciably affect the cost relationship of these processes.

     The  royalties  for  the  Exxon  process  are  a significant  portion  of  the
capital investment.

     For  NOZ reductions  of 90%  the  combination  of  the ALNB/Hitachi  Zosen
process  is,   overall,  the  most  cost  effective  alternative.    Although  the
capital investment for the ALNB/Hitachi Zosen process is slightly higher than
the  capital   investment  for the  Hitachi Zosen process,  the  annual  revenue
requirements  are  substantially  lower.   The  magnitude  of  the difference  in
annual  revenue  requirements  is large  enough to overcome  the  slightly  higher
capital  investment  and  make  the  ALNB/Hitachi   Zosen  process  the most
economically attractive.
                                     xxvi

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     Except  for  the  ALNB  the  energy requirements  to achieve  50%  and 90%
reduction  are  greater than  those for  particulate  removal.   However, energy
requirements  for  NOX reduction are still  modest,  much less  than 1% of the
boiler output,  in comparison with  the energy needed for  removal  of S02 from
flue gas.

     Catalyst  cost  is   a  very  important  economic  factor  for   an   SCR-type
process.   With  the Hitachi Zosen process,  the  catalyst cost may represent as
much as 25%  of  the capital  investment  and 35% of the levelized annual revenue
requirement.   Catalyst  life is  also   a  very important economic  factor.   A
two-year catalyst  life  will reduce  the levelized annual revenue requirements
of the Hitachi Zosen process by about 30%.

     Since with  current  technology  it  is necessary to  use a  process such as
the  SCR-type system  to  achieve  low emission levels (0.06 Ib N02/MBtu), the
costs for obtaining these low levels versus more moderate emission levels (0.3
Ib N02/MBtu) are  substantially  greater.  Achieving  low emission  levels,  as
compared with moderate levels,  may  result in as much as a  tenfold increase in
capital investment and a thirtyfold  increase  in annual revenue requirements.
                                    xxvii

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             EVALUATION OF THE ADVANCED LOW-NOX BURNER, EXXON,

                     AND HITACHI ZOSEN DENOX PROCESSES



                                 INTRODUCTION
     Manmade  nitrogen  oxide  (NOX)  emissions  are  classified,  depending  upon
their source, as stationary or mobile.  Stationary sources are responsible for
about 60%  of the  total  U.S. NOX  emissions.  Fuel combustion,  especially in
industrial  and  utility  boilers,   produces  most  of  the  stationary  source
NOX.  In fact,  industrial  and utility boilers firing  gas,  oil,  and coal were
responsible  for  approximately 50% of  the  manmade NOX produced  in the United
States  in 1978,  with  coal-fired  utility boilers alone  accounting  for  22%
(27).  This  and  the  trend toward increased reliance  on coal as the major fuel
for  electrical  energy  generation  have resulted  in  greater attention  on NOX
control for stationary sources, especially in the utility industry.

     There  are  two basic  types  of NOX  control technology  under development
for coal-firing applications:  combustion modifications and flue gas treatment
(FGT).   Combustion  modifications  primarily include  the use  of  either  low
excess air,  staged combustion with overfired  air or  burners  out of service,
flue  gas   recirculation,   burner   design  and  operating  modifications,  or
combinations  of  the  above.   Combustion modification  techniques have received
the most  development emphasis in the United States.   However, to achieve the
NOX  emission reductions   that  may be required  in  the  future,  FGT  may be
needed.

     The majority  of FGT  processes are  dry processes involving  a gas-phase
reaction with a reducing  agent, usually  NH3,  that is added  to  the flue gas.
If  the  NH3  is  injected  into the  cavities of the secondary  superheater zone
of  the  boiler  where  the  temperature  is  high (1,740°F),  a  catalyst  is  not
necessary.    These  processes  are  known  as  selective noncatalytic reduction
(SNR) processes.   If  the  flue  gas is treated  after the  boiler economizer,
where  the  flue  gas  temperature is  low (730°F),  a  catalyst  is  necessary to
produce the  needed reaction rate.   These  processes are typically described as
selective catalytic reduction (SCR) processes.  Presently, development  of wet-
scrubbing NOX FGT  processes has practically ceased because  of the complexity
and  unfavorable economics of  these   processes  in  comparison  with  the  dry
processes.

     The  major  purposes   of  this  study  are  to provide  current  technical
information  on  the  various  NOX  control  methods  being  developed   and  to

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compare  the  economics of  selected  types of NOZ  control methods using  a  set
of  consistent design  and  economic premises.    The NOZ  control  techniques
selected  for  evaluation   are   combustion  modifications   and  SNR  and  SCR
processes.   The  combustion modification technique evaluated  is  the  advanced
low-NOx  burner  (ALNB)  design being  developed under  the U.S.  Environmental
Protection Agency  (EPA)  sponsorship by  the Energy  and  Environmental  Research
Corporation  (EERC).    The  Exxon Thermal DeNOx  process,  an  SNR process,  is
also evaluated.   Although  the  maximum  NOZ reduction  is lover  than  for SCR,
moderate  NOZ reduction  is  achievable  by this  process.    The SCR  process
evaluated in  this  study  is the  Hitachi  Zosen process.   This  type  of process
has the capability of high (90%) levels of NOZ reduction.

     Two  levels  of  NOZ  reduction  are  examined.   Costs   are  determined  to
achieve  a moderate  NOZ  reduction  to 0.3  Ib N02/MBtu (225  ppm at 3% 02),
for each of  the three processes.   In  addition,  costs are  determined  for a
greater  reduction   in NOZ  to  0.06  Ib  NC^/MBtu  (45  ppm  at  3%  02).  This
degree of NOZ reduction requires either use  of  the Hitachi  Zosen  process or
combination of the  Hitachi Zosen process with one of the other two processes.

     The processes  evaluated in this study are based on technology provided by
the process vendor through  mid-1980.   Since  this  time Hitachi Zosen and Exxon
have recommended process  changes.  Although  the  new technology may  slightly
affect  the  cost  of  each process  as  presented  in this  study, the  overall
comparability between processes should not be affected.

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                                  BACKGROUND
NOX CONTROL REGULATIONS

     Following  enactment  of  the  Clean Air  Act of 1970,  EPA promulgated new
source performance  standards  (NSPS)  for control of NOX emissions from fossil-
fuel-fired steam  electric generating plants in December 1971 (25).  Following
the  1977  Clean  Air  Act  Amendments,  the  NSPS  were  revised  by  EPA  and
promulgated in  June 1979  (26).  The  latest standards for large boilers O250
MBtu/hr) are  shown  in Table 1.  The  Clean Air Act Amendments of 1977 require
(1) the  promulgation of a short-term  N02  ambient  air quality standard (three
hours  or  less  averaging  time),  and  (2)  the  prevention  of  significant
deterioration   (PSD)  regulations  for  NOX.  These  standards may  result  in
additional NOX  emission control on electric power generating facilities.


                   TABLE 1.   NOX EMISSIONS STANDARDS AND

                   PROJECTED RESEARCH OBJECTIVES FOR LARGE

                          FOSSIL-FUEL-FIRED BOILERS
                                       June 1979 NSPS
                                  Lb NOx/MBtu input    NOX
                                     to boiler*	ppmb
                  Gaseous fuel   0.2                   150
                  Liquid fuel    0.3                   225
                  Solid fuel     0.5 (subbituminous)   375
                                 0.6 (bituminous)      450
                  a. Expressed as
                  b. Calculated at 3% excess Oo» dry basis.
NOX FORMATION CHEMISTRY
     For most combustion processes, particularly fossil-fuel combustion units,
the only  significant  quantities of NOX  present in the  flue  gases  are nitric
oxide  (NO)  and nitrogen  dioxide  (N02)  with NO  usually representing  90% to

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95% of  the  total NOX  from  the combustion unit  (7) .   Two  separate mechanisms
contribute  to  the formation  of  NOX.  One source,  thermal NOX,  results  from
the oxidation  of  molecular  nitrogen present in  the  combustion air,  while the
second  source,  fuel NOX,  results  from  the oxidation of  nitrogen  compounds
released  from  coal  (10).    For  a  large  coal-fired  boiler,  the  fuel  NOX
contribution may range from 30% to 80% of the total NOX (15).

     Thermal  NOX emission  levels,  as the  name  implies,   are primarily
dependent  on  the  peak  flame temperature  generated  by   the  burner  and  the
residence time  at  that temperature.  Therefore,  a  decrease in the peak flame
temperature  will  decrease  the  thermal   NOX  emissions.   Principle  reactions
for the oxidation of molecular N2 are as follows:

                              N2 + 0 -> NO + N                           (1)

                              N + 02 -*• NO + 0                           (2)

                              N + OH + NO + H                           (3)

     Unlike  thermal  NOX,  temperature has  little  effect  on  fuel NOX.  Fuel
NOX  is dependent  on  the  availability  of  ©2  in  the flame.  There  are  two
competing  reactions  for  the   nitrogen  containing  compounds   in  the  volatile
flame region:

                               I + R -» NO + ...                         (4)

                              I + NO + N2 + ...                         (5)

     Where  I  is  a  nitrogen containing  intermediate  and  R  is a  hydrocarbon.
Under fuel-rich conditions (high concentration of fuel in  air) reaction (5) is
dominant,  resulting  in  lower NOX  concentrations; however,   under  fuel-lean
conditions  (low  concentration of  fuel   in  air)  reaction  (4)  is  dominant,
resulting in higher NOX concentrations.

     NOX  formation is  dependent on  the  combustion method,  which varies with
boiler  design.   The  typical  baseline  NOX emissions from  different boiler
types are shown in Figure 1.


STATUS OF TECHNOLOGY

     Combustion modifications  and  F6T are the  two  basic  types of NOX control
technology being developed for use with coal-fired boilers.

Combustion Modification

     Combustion modification  includes methods  to inhibit  the  thermal  and fuel
NOX   formation.   One   combustion  modification  technique  for   reducing  NOX
emissions is to increase the burner  zone  surface  area.  This was  not developed
as  a  control  technique but as a method  for  reducing slagging in  boilers.  By
increasing  the burner  zone  surface  area,  the  burner zone  heat  release rate

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     1600
     1400
      1200
 e   1000
 o-
      800
 01
 CHJ
 O
600
      400
      200
                           I        I
                            Wet bottom
                   •'/"/•'Cyclone:'; :."/'.
                   •VYx-'V.*.:' •.'.'•*•"'•;:'•''•'•
           Wall
           0     200
                          Dry botto
                             Horizontally  opposed
                     I	I
                                             I
                   400       600

                        MW
800      1000
Figure 1.   Baseline NOX  emissions - coal-fired utility
            boilers (23).

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(defined  as  the  heat  input  divided  by the  burner  zone  surface  area)  was
decreased.   NOX  emissions decreased  as  a  result  because  gas  temperatures
were lowered by  the  increased heat removal  capacity.   The  larger boiler also
proved  valuable  as  lower  turbulence  burners,  such  as  the  low-NOx  burner,
were developed  because the  increased  size  allows  longer  residence  times  to
complete  carbon burnout.   Commercial  acceptance for  reduced  burner zone heat
release  rates  came  about in  the  1970's.   Figure 2  shows burner  zone heat
release  rates   for  pulverized-coal-fired boilers  ordered  before  and  after
1970.
     w
     W M-l

     H 4-i
     w cs
     o 3
     N O
     w
     g
           800
600


500


400
                        1966
   1970

ORDER YEAR
                                            1974
      Figure  2.  Pulverized-coal-fired boiler burner  zone heat release
                rates  (11).
     Another  combustion modification method is  flue  gas recirculation.  Flue
gas  is  extracted at  the  economizer outlet and  returned  to  the furnace.  The
cooled  flue  gas lowers the overall  temperature  of the gas inside the  furnace
and  reduces  the oxygen concentration.  Flue  gas recirculation works well for
oil  and gas but has not been proven  effective for  coal.

     Overfire  air,  unlike  the  above  two  techniques, which  primarily  lower
burner  zone   temperatures,  is  designed to limit  oxygen  availability  at the
flame.   Air  ports are  installed  above  the  burner zone to inject a portion of
the  combustion air.    The burners are  thus fired  more fuel  rich than  normal.
Fuel-rich  conditions  decrease  fuel NOX  formation.   (This method  maintains

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the burner  zone in a  reducing atmosphere with  an oxidizing atmosphere above
the flame  region.   This  reducing atmosphere is  a more corrosive environment
for the boiler walls.)

     A technique  similar  to overfire air  is burners  out of service.  Instead
of placing air ports in the boiler wall, individual burners or rows of burners
admit  only air.    The remaining  burners  make  up  the difference  by firing
additional coal if  pulverizer  capacity  is  available.   As in overfire air, the
active  burners  operate   at more  fuel-rich  conditions  than normal.    This
technique was developed primarily for retrofit applications.

     Another technique to minimize oxygen  availability is low excess air.  In
this  technique,  sufficient  air  is  admitted  to  the  boiler  to  complete
combustion but is minimized to reduce NOX formation.

     Although  NOX  control  could be  obtained  by  these  boiler modifications,
work was  continued  by boiler manufacturers and  others to obtain lower levels
of  NOX  emission  and  to  avoid  operational  problems  such  as  corrosion,
erosion,  combustion  instability,  and   energy   penalties  from   some  of  the
methods.

     Babcock & Wilcox, Inc.,   (B&W)  developed  their  dual  register  burner to
meet  1971 NSPS  (0.7  Ib NC^/MBtu); however,  test on pulverized coal  units
demonstrated that the  0.6 Ib N02/MBtu level could also be obtained (3).  The
dual register burner features limited turbulence,  conical diffuser mixing, and
secondary air  introduced  around the  primary air  nozzle in two concentric air
zones  that  are  independently  controlled.     Air  flow  to   the  burners  is
controlled by use of a compartmented windbox.

     A  series  of  burners  has been  developed  by  the Foster Wheeler Energy
Corporation for NOX  control.   The  latest is  the controlled-flow/split-flame
burner  (30,  31).    This  burner  uses  dual registers  on the  secondary air to
produce  a substoichiometric  air  zone  near  the  flame.   A  modified  annular
primary  air  nozzle  is also used to  separate  the coal-air mixture  into four
concentrated streams  that form four independent  flames.   Overfire air can be
used with  the controlled-flow/split-flame burner for  additional  NOX control
but it is not recommended.

     NOX control  is being accomplished  by the  Riley  Stoker Corporation using
a controlled diffusion flame and the Turbo®  furnace  (21) .   The Turbo furnace
is designed with a  venturi  shaped bottom to  utilize the lower furnace cooling
surface more  effectively.  Combined with  the Turbo furnace,  downward-tilted,
nonswirl burners are  used to delay mixing of the secondary air with the fuel
and primary air.    In  this  way the  fuel  and secondary  air mix by diffusion,
which decreases the combustion rate and flame temperature.

     Combustion Engineering,   Inc.,  produces tangentially  fired  boilers,  in
which the burners are directed tangent to an imaginary circle at the center of
the furnace.   This provides a large amount of  internal recirculation of the
combustion gases  and  slower mixing  of  fuel  and air (16).   These boilers are
inherently  low in  NOX formation.   Additional  reduction  in  emission levels
can be achieved using overfire air.

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     These combustion modification  techniques  are  described  in greater detail
in other literature (14, 15, and 23).

Flue Gas Treatment

     The FGT methods  of NOX control applicable to  coal-fired  utility boilers
are  well  described  in literature  (1,  9,  and  13).    These  postcombustion
processes  can  be divided  into  dry  or wet types.   The dry processes  can be
further categorized into four subdivisions:  catalytic  reduction, noncatalytic
reduction, adsorption, and irradiation.   The majority of the dry processes are
of the  reduction type.   These catalytic and noncatalytic  reduction processes
can  also  be classified  as selective or  nonselective  processes based  on the
type of  reducing agent  used.   The  majority  are  selective  and  usually use NHj
as the  reducing  agent.   If the NH3 is  injected after  the boiler economizer,
where  temperature  of the  flue gas is  about  700°F to  800°F, a  catalyst is
necessary.  These  processes  are  described  as  SCR processes.     If  NH3  is
injected  into  the  secondary  superheater  region  of  the  boiler,  where
temperature  of  the  flue   gas  is   1,000°F  to  1,800°F,  a  catalyst  is  not
necessary.  These processes are described as SNR processes.

Selective Catalytic Reduction —
     The SCR method is  the most advanced  FGT method, and the one on which the
overwhelming majority of NOX FGT processes  are based.  As with  the majority
of  all  types  of  NOX  FGT,  most  of  the  SCR  processes were  developed  in
Japan.  Since  the  presence  of  some oxygen  improves  the  NOX reduction,  the
reactions of NHj with NOX may best be expressed as follows:

                        4NH3 + 4NO + 02 + 4N2 + 6H20                     (1)

                       4NH3 + 2N02 + 02 •*• 3N2 + 6H2<>                     (2)

In  the presence of  a  catalyst  and with  the optimum  reaction temperature,
usually  570°F  to  840°F,   an  NH3:NO molar  ratio  of   1:1 typically  reduces
NOX  emissions  by  90% with  residual NH3  concentrations of 10  to 20  ppm or
higher.   It should be noted that the Japanese seem to prefer  80% N0£ removal
in  which N^NO molar  ratios range from 0.81:1  to 0.9:1 with  residual NH3
concentration  usually less than 5  ppm.    (This  reduces  capital  and operating
costs   as  well  as  effects  on  downstream  equipment  from ammonium salt
deposition. )
     The  only equipment necessary  is  an NHg storage  and  injection system, a
 reactor,  and catalyst.  Additional  fan capacity  is  necessary  because of  the
 pressure  drop  increase  across the reactor of 2 to 5 in. 1^0 (4 to 9 mm Hg) .

     The  components and precise composition of most catalysts are proprietary.
 However,  catalysts  composed  mostly  of  titanium  and vanadium   oxides   are
 generally used,   since  these components  are resistant  to attack  by  S02  and
 803.   S(>2 oxidation  to 863  can  be  a problem,  especially with  coal-fired
 boilers  where flue gas SC>2 concentrations  are  relatively high.   Proprietary
 additives to  the  catalyst  can  reduce  the  amount of  S(>2 oxidation  to  less
 than 0.5% to 1.5%.

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     In addition to the different catalyst compositions, different reactor and
catalyst configurations have  also been  developed,  primarily to handle .various
particulate  loadings.    With  natural-gas-fired  boilers,  fixed  packed-bed
reactors with  spherical-, cylindrical-,  or  ring-shaped catalyst  pellets are
used.  Parallel  flow  reactors and catalysts are preferred for oil- and coal-
fired  boilers  to  tolerate the  particulate matter  in  the flue  gas  stream.
Parallel flow  designs  include  tubular,  honeycomb,  corrugated,  or parallel-
passage configurations.   The catalyst  may  be  an active material  coated on a
metallic or ceramic carrier or may be a homogeneous material.

     The major  concerns  of  operating  SCR  processes  include:    plugging and
erosion  of  the  catalyst  by  fly  ash;   emission  of NH3  or  ammonium salts;
increased  863   emissions   from  oxidation  of  S02;   effects  on  operation  of
downstream equipment such as the air heater, electrostatic precipitator (ESP),
flue  gas  desnlfurization  (FGD) process,  and baghouse;  environmentally sound
disposal or  reclamation  of catalyst;   lack  of proven  NH3  analytical  control
systems; sensitivity  of the process  to  temperature changes due to boiler load
variations;  and  reliability  of  the  process  and  its  effects on  the boiler
system availability.

     In  spite  of  the potential  problems,  there  are  over 60  full-scale SCR
units  successfully operating  on gas-  or oil-fired  boilers  in Japan.  Over 10%
of  these  units  are  larger   than  330  MW.   Two  commercial  SCR  units  began
operating  in 1980 on coal-fired  boilers  in Japan.  The 175-MW retrofit unit
supplied by Mitsubishi Heavy  Industries at  the Shimonoseki Station of Chugoku
Electric  Power  Company  was   the world's   first  full-scale   coal-fired  SCR
system.  It began operation in April 1980 and is operating at its designed 51%
NOX  reduction   efficiency with  less  than  1  ppm  NH3  slip.    The  other SCR
unit is 90-MW capacity on a new 350-MW boiler at Tomakomai Station of Hakkaido
Electric  Power  Company.     It  was   supplied  by  Babcock-Hitachi   and  began
operation  in October 1980.   Two  other SCR units  on  coal-fired  boilers are
under construction with planned startup by mid-1981.

     In  the  United  States,   EPA  and  the Electric  Power  Research Institute
(EPRI)  are evaluating SCR  technology  on coal-fired pilot-scale  units.   EPA
sponsored  two  0.5-MW-size tests,  each  of which was recently  concluded.   The
UOP  Shell  Flue  Gas  Treatment  process  for  simultaneous  NOX  and  SOX  control
was evaluated at Tampa Electric Company's Big Bend Station.  The Hitachi Zosen
SCR  process was  tested   at  the  Plant  Mitchell   Station  of Georgia  Power
Company.   EPRI  is  currently  operating a 2.5-MW  pilot plant  at  the Arapahoe
Station  of  Public Service   Company  of  Colorado   using  the   Kawasaki  Heavy
Industries, Ltd., process.

     The first  large-scale SCR demonstration  unit  in  the United  States  is
being  erected by Southern California Edision  Company  at  the Huntington Beach
Station.   It is a 107.5-MW capacity on  a gas- and oil-fired unit.

Selective Noncatalytic Reduction—
     Exxon Research  and Engineering Corporation developed  the SNR process in
which  NH3  is  injected into  the boiler  where proper flue  gas   temperatures
allow  the  reduction  of   NOX by reaction  with  NH3   to   proceed  without  a
catalyst.    Generally,  40%  to 60%  NOX  reduction  is  achieved  with

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molar ratios of 1  to 2:1.   SNR may be more attractive than SCR in cases where
only  40% to  60%  NOX  control  is  needed  since  SNR  is  simple  and does  not
require expensive catalysts.

     The general  disadvantage  of SNR  is  the limited NOX  control  achievable,
especially  with  large  boilers,  due  to  the  difficulty  of  achieving  rapid
uniform  mixing  and the  variations  of flue  gas  temperature and  composition
usually  present  within  the  boiler  region  where  the  SNR  is  operated.   NH3
consumption and unreacted NHg levels can also be  high.

     There are several large SNR units installed  in Japan, between 30- and 100-
MW capacity, mostly supplied by  Tonen Technology  (a subsidiary  of Toa Nenryo)
which has  a license  from  Exxon.   These  are  operated  on  gas-  and oil-fired
boilers  or  furnaces.    Practically  all are only  for  emergency use during  a
photochemical smog alert or when total plant emissions exceed the regulation.

     There  are  presently two  commercial  SNR plants  operating  in  the  United
States.  One is on a glass melting furnace and the other a petroleum refinery,
both  located  in  California.   The construction of  five  other industrial-scale
units is planned.   The  SNR process is also  being installed by Exxon  at the
No. 4  oil-fired unit  of the  Haynes  Station of the Los  Angeles  Department of
Water and Power.

Other Flue Gas Treatment Techniques—
     In  addition  to SCR and SNR, dry  processes which are being developed for
simultaneous SOX and NOX control include:

   1.  Activated carbon processes where NH3 reduces NOX to N£.

   2.  Copper oxide processes where NH3 reduces NOX to %.

   3.  Electron beam irradiation processes in which NILj is added to produce
       ammonium sulfate and nitrate.

     The  optimum  temperature   range  for  simultaneous  SOX and  NOX  control
with  activated  carbon  processes  is  430°F  to  445°F.   Although  NOX  may  be
adsorbed  below  212°F,   for  treating  large  quantities  of  flue  gas  above
212°F  the   carbon   is  mainly  useful   as  an  NOX   reduction  catalyst.
Therefore,   while  NOX  is  converted  to  N2  by   reaction  with  NH3  in  the
presence of  the  activated  carbon catalyst,  S02 is  simultaneously  adsorbed by
the   carVon  to  form  I^SO^   The  1^804  may  also  compete  for  NH3  in
forming ammonium  sulfate or bisulfate.  The formation of these  ammonium salts
increases  NH3  consumption   and  also  lowers  catalyst   activity.  The  carbon
must  be regenerated,   either by washing  or thermal  regeneration.    Washing
produces a  dilute  solution, which  requires  much  energy to concentrate  for use
as a  fertilizer.   Thermal regeneration seems to  be preferred.   A concentrated
S02  gas is recovered,  which  can  be  used  for  sulfuric  acid or  elemental
sulfur production.

     The major  drawback of  the  activated  carbon  processes  is the  enormous
consumption of activated carbon, which is more expensive than  ordinary carbon
                                     10

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used  only  for  SOX  removal.  Since carbon  and ammonia  consumption  increases
with  the  S<>2 content  of  the flue  gas,  the process  is  best suited  for  flue
gases  relatively  low  in  S(>2.    In  Japan,   Sumitomo  Heavy  Industries  and
Unitika Company have operated activated carbon pilot plants of 0.6-MW and 1.5-
MW capacity respectively.

     The UOP  Shell  Flue Gas Treatment  process may simultaneously remove  SOX
and  NOX.   SOX  reacts with  the  copper  oxide  acceptor  to  form copper
sulfate.   The copper  sulfate and  copper  oxide are SCR catalysts for the  NOX
reduction by  NH3.   Regeneration  of the multiple  catalyst  beds by a  reducing
gas,  such   as fL^'  yields  a  S02-rich  stream  that  can be  used  to  produce
liquid S(>2»   elemental  sulfur,  or  sulfuric  acid.   By  eliminating  NHg
injection,   the  process  is strictly  an FGD  process,  whereas,  eliminating
regeneration  of  the  catalyst beds  allows the  process to be  used for  only  NOX
control.  The major disadvantages are the large consumption of fuel  for making
hydrogen and  the catalyst  expense.

     In  addition to   the   EPA-sponsored pilot plant mentioned  earlier,  the
process has been installed in Japan on a 40-MW oil-fired  boiler.  The unit  has
demonstrated 90% SOX removal and 70% NOX reduction.

     Another  process  for   simultaneous  SOX  and NOX control  is  the  electron
beam  process  developed by  Ebara  Manufacturing  Company  in Japan.    NH3  is
added  to  the  flue  gas,  after  which  the  gas stream is  irradiated with  an
electron  beam  in  a   reactor,  promoting  the  conversion   of  SOX,  NOX,  and
N%  to ammonium  sulfate   and  ammonium  nitrate.    The  ammonium  sulfate  and
ammonium  nitrate may  be  collected  downstream  in  an  ESP  or  baghouse  and
potentially  sold  as a  fertilizer.   The  most  economically  practical  removal
efficiency  range  appears  to be  80% to  90% for  each of NOX and SOX,  though
higher removals can be  achieved with much greater electron beam  energy input.
The optimum temperature range is 160°F to 195°F.

     Ebara has  worked  on  the  process since  1971.  It  has  been tested at  a
0.3-MW  and  3-MW scale  in  Japan.   Avco Corporation  in  the United States  has
also examined this technique and has a cross-licensing agreement  with Ebara in
sharing of  technology  and in marketing of  the  process.  Although  the process
appears attractive   because   of   simplicity,  simultaneous  SOX   and  NOX
control, and  byproduct formation,  there  are  still many questions  concerning
costs, byproduct quality,  etc.,  which must be  determined.

     The wet  processes  normally  involve  simultaneous  removal  of  SOX  and
NOX.  The  major problem  associated  with wet  NOX control  processes is  the
absorption of NOX  by  the  scrubbing  solution  in which it  can be concentrated
and converted into  other  forms.   NOX  in the  flue  gas  is  predominantly  NO,
which  is  much  less  soluble  than  N02,  whereas,  N02  is   even  less  soluble
than  S02.   The  two common methods  of removing  the  NOX  in  flue  gas by  wet
processes are:   (1)  direct absorption of  the  NOX in the  absorbing  solution
or  (2)  gas-phase oxidation to  convert  the relatively  insoluble  NO  to NO^
followed by  absorption of  N02.  Presently, development of the wet  NOX  FGT
processes has practically  ceased  because of  the complexity and  unfavorable
economics of these processes in  comparison with the dry processes.
                                      11

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                        STATUS OF PROCESSES EVALUATED
ADVANCED LOW-NOX BURNER

     EPA  instituted a  program  to  develop  a coal-firing  burner  capable  of
reducing NOX  formation to  levels  lower  than achieved by  present combustion
modifications.   This program is directed  toward  developing burner prototypes
for industrial and  utility  appplication.   The burner design at various stages
of  development  is  shown  in  Figure 3.    Only  the  utility  ALNB  prototype
development program  is discussed in detail in this report.

Process Description

     The ALNB is  being  designed to  prevent the  formation of both  types  of
NOX  (thermal  and  fuel)   while  maintaining boiler  efficiency   and  meeting
boiler demand.   The primary objectives are:   (1)  to provide an initial fuel-
rich,  i.e.,  oxygen deficient,  zone which maximizes  the  conversion of organic
nitrogen  compounds  to  N2>  and  (2)  create   an  overall  oxidizing atmosphere
around the  fuel-rich zone  to  maximize  burnout and  to minimize  the potential
for corrosion in the lower  furnace  section of the  boiler.   These objectives
are obtained by providing for the optimum interaction between the  primary fuel
jet  and  the  swirl-stabilized  recirculation  zone,  together with  delayed air
addition from the outboard staged air injectors (33).

     For this  study the  ALNB concept was  integrated into a B&W dual register
burner design with  four  tertiary  air ports  located a distance  of about one
throat  diameter   around  the central  burner  (3) .    Air  admitted  through the
burner  is  made up  of three air streams referred  to as  primary, inner, and
outer  secondary air.  Primary air is used as  the medium to carry the entrained
pulverized coal.   Secondary air  is  injected  around the primary air through an
annnlus.   Swirl  vanes  in  the  inner  secondary air  annulus impart  swirl  to
control mixing of the primary and inner secondary streams and to control flame
shape.   The remaining secondary air  is admitted  through the  outer secondary
air  annulus,  which  is  concentric to  the inner  secondary air annulus.   Two
possible configurations for  the  tertiary air ports are shown in Figure 4.  The
first  has four ports per  burner, the  second shares ports between burners.  The
ports  are arranged  to provide specific mixing rates with  the other air streams
and avoid fuel-rich  zones along  the lower furnace wall.  The central burner is
designed  to  operate at  approximately  70%  stoichiometry to  minimize  oxygen
availability  for  conversion of fuel nitrogen to  NOX and the remaining 45% to
50% of the air is  supplied  through the tertiary ports  to  complete  combustion.
                                      12

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              INITIAL  BURNER DEVELOPMENT
                                 FURNACE WALL
                            TERTIARY AIR -

                  - SWIRL BLOCKS
                    SECONDARY1. AIR
           COAL & PRIMARY AIR
                                      N,
                                        COAL INJECTOR
                                                                               IGNITER
                                                                                                                         INDUSTRIAL PROTOTYPE
                                                                                                                           (FOSTER  WHEELER)
                                                                                             COAL INLET
              DISTRIBUTED  MIXING BURNER
             SECONDARY AIR    TERTIARY AIR
             SWIRL VANES
          COAL A
        PRIMARY AIR
            SECONDARY AIR      TERTIARY AIR
FIELD DEMONSTRATION BURNERS
  DISTRIBUTED  MIXING CONCEPT
                                                                                                    TERTIARY AIR
                                                                                                                         UTILITY  PROTOTYPE
                                                                                                                         (BABCOCK & WILCOX)
                                                                                              -COAL
                                                                                              PRIMARY AIR
Figure  3.   Major stages of  the  ALNB development  (11)

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                                 Tertiary  Ports \^
                                                 ^o         O
   o     o       o     o
                                                   o        O        o
   O     O       O     O   ^   Burners
   o     o       o      o                        o          O

 4  Tertiary   Ports   Per  Burner                      Shared   Tertiary  Ports


 Figure 4.  Alternatives for injection of ALNB tertiary air.
     At  the  time of  the  writing of  this  report,  not all  areas  of the ALNB
design had  been defined.   However,  the  general description  given above is
expected to  be  the basis for  prototype  construction.   The research goal for
the NOX emission level from the ALNB is 0.2  Ib N02/MBtu.

Technical Considerations

     In  a  study funded  by EPA  (18,  33)  the  effects of  various  burner and
operating variables on NOX  emissions  were  explored  by EERC.  Both  single and
multiple burner  tests were  performed and  the  results quantified  to  aid in
burner development.

     Results of  the  test on  one burner  evaluated  in  the  single  burner test
program  are  shown  in Figures 5, 6, and  7.   The optimum operating  conditions
for this burner  are  a burner  zone  stoichiometric ratio  (SRg)  of  0.5 to 0.7,
a primary  swirl  vane angle  (Sp) of  45  degrees, and  a  secondary  swirl vane
angle  (Sg)  of  60   degrees.   These  data  were   obtained  at  a  primary
stoichiometric  ratio  (SRp)  of  0.23  and 0.25 and a  theoretical  stoichiometric
ratio  (SRj) of  1.25.   These  results  are  unique   to  a   particular  design
because optimum operating conditions will vary as burner design  varies.

     Mutiple burner  test  results summarized in  Figure 8 show  that lower NOZ
emissions are directly related to burner zone stoichiometry.  The burner zone
stoichiometry  used  must  be weighed  against  the  CO  level  (combustion
                                     14

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a
P.
ft
 04
O
      400
300
      200
      100
        0
                Utah coal
                48 x 106 Btu/hr
                SRp = 0.23
                SS  = 60
                                       SRB =
                                                     SRB = 0.63
         100       110      120        130       140

              OVERALL STOICHIOMETRY (% Theoretical Air)
800
600
ft
ft
*v
s
n
400
CM
Q
O

-------
     400
      300
      200
O
<2J
O
      100
       0
Utah coal
48 x 106 Btu/hr
SRP = 0.23
SRT =1.25
SS  = 60
                                             D  Sp
                                             o  Sp
= 60°
= 45°
= 30°
        40        50         60         70       80
            BURNER ZONE STOICHIOMETRY (% Theoretical Air)
 CN
O
O
<2J

O
      800
      600
      400
      200
        0
         40        50        60       70        80
          BURNER ZONE STOICHIOMETRY (% Theoretical Air)



  Figure  6.  Effects of ALNB primary swirl, single burner (11)
                               16

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 a
 P.
 P.
 CN
O
P.
P.
erf
p
IN
O
o
CJ
     400
300
     200
     100
                                Utah Coal
                                48 x 106 Btu/hr
                                SRp = 0.25
                                SRT =1.25
                                SP  = 450
          40
               60        80       100        120
                4 BURNER ZONE  STOICHIOMETRY  (% Theoretical Air)
     800
     600
     400
200
          40         60        80       100       120
           BURNER ZONE STOICHIOMETRY (% Theoretical Air)
   Figure 7.  Effects of ALNB  secondary swirl,  single burner (11)
                              17

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I
ex
o

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efficiency).   Also  studied  in the  multiple  burner  tests  was the  effect of
removing  rows  or  columns  of  tertiary  air ports  from  service,  as  shown in
Figure 9.   Results  showed  that  NO  emission decreased  slightly but  carbon
burnout (CO level) was more sensitive.  Additional optimization is required.

     A  study by  EERC on the  effects  of coal  type^ was  initiated  to  develop a
data bank  on a full range of  U.S.  coals.   Results from  this  study,  of which
Figure 10  is   an  example,  led  to  the conclusions  that  NOX emissions  are
sensitive  to   fuel  type,  that  the  nitrogen  content  of  the  fuel   does  not
correlate with NOX  emissions,  and that burner efficiency is  sensitive to the
type of coal.

Development Status

     The  first  phase of  low-NOx burner development  by EPA was  initiated in
1970  when EPA  contracted with  the  International Flame Research  Foundation
(IFRF)  to study  the influence  of  burner  variables  on NOX  emissions using
pulverized  coal.    In  the  IFRF  study  the following burner  parameters  were
investigated:

   •  Method of fuel injection

   •  Throat velocity

   •  Geometry of the burner exit

   •  Position of the fuel injector

   •  Type of burner exit

   •  Proportion of primary air

   •  Swirl intensity of the combustion air

     Results of the study show the two variables having the greatest effect on
NOX  emissions  to be  the method  of  fuel injection  and the degree  of swirl.
Test work  was  performed on a 2 to 3  thermal  MW  (6-9  x 106 Btu/hr)  refractory
tunnel.

     To obtain burner data  at  a  more  realistic boiler  size  and  firing rate,
scaleup was performed by EERC on a boiler and  a large  water tube  simulator
capable of firing up  to 40  thermal  MW with  single  or multiple burners.   A
smaller  system  simulating  a  D-type  package  water   tube boiler  was  used to
evaluate various burner designs.

     While the  test program  of  IFRF was designed to determine  the  effect of
various burner parameters  on NOZ emissions,  the EERC program was designed to
quantify  these  effects  for  development of  an experimental burner  and boiler
system.   The  EERC program  thus  had a larger  scope than the  IFRF program,
covering not only single burner  variables  at greater  firing  rates,  but also
                                      19

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                           COLUMN
to
o
    o

n
               ©
                                      0
                           0
                                                      NORMAL LEVELS WITH ALL TERTIARY PORTS IN SERVICE

                                                                  NO     CO
                                               o
                                                          O

                                                          H
                                                          13
                                                          O
                                                          1
                                                          PM
s
W
H
                                                   COLUMN  2
                                                  AND ROW  2
                                                              COLUMN  2
                                                              COLUMN  3
        ROW 2
                                                                 ROW 3
         BURNER AND  TERTIARY  AIR PORT  TEST ARRANGEMENT
                                                                      200          400

                                                                  NO, CO @ 0% 02, DRY, ppm
                                                                                                           600
      Figure  9.   Effects  of  ALNB  tertiary ports out of service, four burners fired at 12.5 x 10  Btu/hr each  (11).

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    400
     300
    200
 CN
O
o
53
100
      0
             64 x 106 Btu/hr
             SRp = 0.23
             SPT = 1.25
                          W.  Va
                           (N = 1.55% dry,  ash free)
                                Utah (N = 1.71% dry, ash free)
                                         Utah
                                         (Baseline -
                                         N = 1.65% dry, ash free)
                                      I
                                               I
       40       60         80         100       120

          BURNER ZONE  STOICHIOMETRY  (% Theoretical  Air)
Figure 10.  Effects of ALNB  coal  type,  four burners  fired  at
            12.5 x 106 Btu/hr  each  (11).
                                   21

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the interactions of multiple burners and the effects of coal  types.   Figure  11
shows one  of  the burners used  in  the  test program, called the  simple  double
concentric burner,  and  the  variables evaluated.   Tertiary air was  used  with
the  simple double  concentric  burner  and other  burners used  in  the  test
program.

     While the EERC test program was being conducted,  another  possible  use for
the  low-NOx  burner  was  being studied  at  a  pilot-plant  scale  by  EPA
(17) .  This study  was exploring sulfur  capture  using a  dry  sorbent.   It  is
hypothesized  that   after  coal  and  sorbent  are  mixed  in the  pulverizer  to
achieve  intimate  contact,  the  ALNB  burner will  create conditions  (fuel-rich
burner zone and  decreased peak flame temperature) that will  be  favorable for
SOX  removal.    Dry  sorbents  that  have  been  tested  are limestone,  Na2CO£,
and  NaHC(>3.   Depending  on  pilot-plant  results,  funding  will  be  sought for
field evaluation  of dry sorbents.   The  stated  goals are  to obtain 50% SC>2
capture  at a 2:1  sorbent:S02  stoichiometry and  a research  goal  of 90% S(>2
removal at 3:1 sorbent:S(>2  stoichiometry.

     Upon  completion of the  ALNB design,  EPA contracted with  B&W to  perform a
field evaluation  of the burner  in a utility boiler.   EERC has received the
subcontract.   The  industrial  boiler   contract  which parallels  the  utility
program was awarded to EERC  with the subcontract  to Foster Wheeler.  The  nine
major task areas that make up the  utility boiler  field evaluation program are
(1) program definition,  (2)  prototype construction and performance  evaluation,
(3)  host-site  boiler  baseline  evaluation,   (4)  burner  installation,  (5)
performance optimization, (6) industry coordination,  (7)  boiler  restoration,
(8) data analysis, and (9)  summary of program results (4,  18).

     The  field  evaluation program   is behind  schedule because  of  delays  in
obtaining  an acceptable host  site.   Some boilers  were omitted as possible  host
sites because more  spacing  between  burners was  required for the  addition  of
tertiary ports  than was  available  while  others required  major  changes  to the
windbox  and boiler  structural  supports.   Further  delays  resulted from  an
unwillingness to participate by owners of possible host sites (4).

     This  program  should provide information on areas of  uncertainty  such  as
the  effect of commercial application of  the  ALNB on boiler  tube  bending and
configuration, boiler wall  structural requirements, and boiler efficiency.


EXXON PROCESS

Process Description

     The   Exxon process,   developed  by Exxon  Research  and  Engineering
Company,  controls  NOX from  flue gas by  injection of NH3  and air  through a
distribution  grid,   or   grids,   directly  into  the  cavity of  the  secondary
superheater (29).

     At  high temperatures,  NOX reacts  with NH3  in  the presence  of  oxygen
     by  the following overall reaction (28):
                                     22

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to
u>
INPUT

• TEMPERATURE
• COMPOSITION
• VELOCITY
• LOAD
• COAL TYPE
                    FURNACE
                     • STAGED AIR
                     • SCALE
                     • BURNER ARRANGEMENT
                                             SWIRL

                                             • EXTENT
                                             • GENERATION  METHOD
                                                                            THROAT
                                                                             • STOICHIOMETRY
                                                                             • MIXING
                                                                             • VELOCITY
     Figure 11.  Variables evaluated in the single ALNB test program (11).

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                       NO + NH3 + 1/402 -> N2 + 3/2H20                    (1)

R.  K.  Lyon  of  Exxon Research  (28)  has proposed  the  following mecha ism  for
this reaction:

                           NH2 + NO -»• N2  + H + OH                        (2)

                           NH2 + NO -*• N2  + H20                           (3)

                             H + 02 -> OH  + 0                             (4)

                            0 + NH3 -*• OH  + NH2                           (5)

                           OH + NH3 -> H20 + NH2                          (6)

                            H + NH3 -> H2  + NH2                           (7)

This reaction proceeds at a  satisfactory rate  in a narrow temperature  range
around  1,740°F   (950°C)   as   shown  in  Figures 12  and  13.  Below  1,650°F
(900°C),  the reaction  rate  is  too  slow for  adequate NOX  control,  causing
NH3  and  NO  to  flow  through  unreacted.    Above  1,830°F   (1,000°C),   the
NH3 reacts with 02 to produce NOX, as illustrated  by the reaction:

                         NH3 + 5/402 -> NO + 3/2H20                      (8)

Because of  this  sensitivity,  temperature  gradients within the boiler  reaction
zone caused by  variable  heat  transfer  and  gas  velocity  or  changes  in  the
boiler load have considerable effect on the process efficiency.

     Residence time  is as important  as reaction  temperature.   The reactants
(NO, NH3,   02)  must  remain  in  the boiler  injection  zone  for  a  sufficient
length of  time  for the reaction  to  go to the desired  completion.   A typical
residence time is 0.1 second.

     Proper  mixing  of  the  reactants with  the  flue  gas  is crucial.    Uneven
distribution  can  cause  pockets  of ammonia as  well as  NOZ to pass through  the
boiler unreacted.   The Exxon process uses proprietary  Exxon gas-phase  mixing
technology  to disperse the small volume of reactants throughout the  flue  gas.

     Ammonia  addition  is  dependent  on  the  NOX  concentration  in  the flue
gas.  Tests at optimum temperature conditions indicate  that a rate of 0.6 to 2
moles  of  NH3 per  mole of  NOX will  accomplish  50%  NOX  removal  or  above,
but the rate  should be lowered to 1.5  or below  when possible to minimize  NH3
emissions (see Figures 14 and 15).

     The  NH3  injection  grid  is   insulated   and   covers  the  entire   cross-
sectional  area  of  the  flue  gas  flow path.    Each grid  is  constructed  of
separate injection  zones  with each  zone  having its own  NH3  controls to deal
with temperature  fluctuations  in  a  plane  normal  to   the flue  gas flow.  If
multiple grids are used, air  is  passed through  idle grids to prevent plugging
                                      24

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     1.0
     0.8
i
 «   0.6
 •H
 4-1
 •H
 C
     0.4
     0.2
       0
4% excess 02
300 ppm NO
                  1
              I
                       I         I

                     (NH3)/(NO), molar


                           0.3
                           0.5
                                         1.6
I
I
       1200     1400      1600     1800     2000     2200

                         TEMPERATURE, °F
Figure 12.  Effect of temperature on NO reduction for various
            levels of NH^ injection with the Exxon process (19)
                            25

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K3
       S-i
       td
       ^

       i
        •H

        fi
        n)
        a
        •H
             1.0
0.8
             0.6
0.4
             0.2
               0
                             Initial    Initial
	 Natural gas

	 Utah  coal

	 Navaho coal

	 Pittsburgh coal

	 Illinois coal
                          I
                     I
                     I
                                   I
1500    1600    1700
                                         1800
                        AVERAGE RADIAL TEMPERATURE,  UF
                                                     1.0
                                                  o
                                                                  0.6
                                                  •H
                                                  c
                                                   2  0.4
                                                   c
                                                  •H
                                                              O
                                                              IS
                                                     0.2
                                                                                 T .  .  , /NOT .  .  n
                                                                                 Initial   Initial
                                                                                    5% Excess 02
                                                                                  I        I

                                                                                      = 1.0
                                                         	 Natural gas

                                                         	 Utah coal

                                                         	 Navaho coal

                                                         	 Pittsburgh coal

                                                         	 Illinois coal
                            I
                   I
1900    2000
0
 1500     1600     1700
I
I
                                                                                 1800     1900
                                                               AVERAGE RADIAL TEMPERATURE, °F
                                                                                         2000
      Figure  13.   Effect of temperature on NO  reduction for various fuel sources with the Exxon process  (19).

-------
     1.0
     0.8
J-l
n)
iH
O
e
     0.6
 n)
 •H
     0.4
     0.2
                        O Natural gas

                        O Utah coal

                        D Navaho coal


                        & Illinois coal


                        O Pittsburgh coal
                                                I
                           0.5
  1.0


NH3
                                                      /NO
                                               Initial   Initial
  1.5


,  molar
2.0
 Figure 14.   Comparison of NO reductions at the optimum temperature condition with  the  Exxon  process  (19)

-------
      0.4
i
 n)
 •H
 j-j
 •H
 c
o
la
  C
 •H
on
      0.3
0.2
      0.1
            O Utah

            a Navaho


            6 Illinois

            O Pittsburgh

            0 Natural gas
                                                  I
                            1.0

                          NH3
                              /NO
                       Initial   Initial
  2.0


,  molar
                                                               3.0
 Figure  15.   Comparison of the NH3 emissions for all fuels tested at the

             peak NO reduction temperature with the Exxon process  (19).
                                    28

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of grid holes (no nozzles are used) and to protect the grid from high flue gas
temperatures.   To prevent  loss  of carrier air, multiple  air compressors are
used;  however,   emergency  steam can be  connected for  use if  total  air loss
occurs.

     Since the main process control  parameter  for  the Exxon process is boiler
load,  initial NH3  injection  rates  are  established based  on  calculated  or
measured flue gas temperatures for a given boiler load or load range including
temperature variations  across  the  plane of the  injection  grid.   This is then
incorporated  into the control  system using  a microprocessor for responding to
load changes.  Temperature  changes which are not a function of boiler load are
also  incorporated into  the control  system allowing injection  rates  to  be
optimized,  NOX  reduction maximized,  and  NHg  breakthrough  minimized.
Carrier air  rate is held constant;  therefore, it is not  a control variable.
To  check  analyzer response to injection rate,  optimization  control  response
logic  is built  into the  microprocessor.   Operator  intervention is required if
large  magnitude  changes for  the   system  are  indicated without  significant
change in boiler operating  parameters.

Technical Considerations

     Since flue  gas temperature is the most important  operating parameter of
the  Exxon process,  anything  that causes  the temperature  to  fluctuate  can
affect  the  performance  of  the  process.   Slagging,  changes  in boiler  load,
changes  in  excess  Q^•  and  other  operational  variations  can  cause  the
temperature profile to  shift in relation to the firebox.   Variations in flue
gas temperature are also present normal to the  flue gas flow.   Boiler tubes at
the walls  absorb heat to produce  steam;  therefore,  temperatures  at  the wall
are  lower than  at the  center.   In  large  utility  boilers  the  temperature
variation can exceed 270°F.

     Two techniques are used by Exxon to deal  effectively with the temperature
variations.   One  method uses  multiple NE^  injection  grids  with each grid
positioned in the boiler to correspond to a different  load or combination of
loads.  In this  way,  as  the temperature  profile of the boiler shifts due to a
load  change,  the  required  reaction  temperature  range,  1,650°F  (900°C)  to
1,830°F  (1,000°C),  is  accessible  by  feeding  the  appropriate  grid.  The
second method uses one grid, instead of using multiple grids,  and the reaction
temperature is manipulated.   This  is accomplished by  injecting  H2 along with
the  NH3.   Based  on  the  H2:NH3  injection  ratio  selected,  NOX  reduction
will  proceed  at  a   satisfactory  rate  at a   temperature  range  of  1,290°F
(700°C)   to   1,830°F  (1,000°C).   Therefore,  one  grid can be  used  to
handle load  changes because the reaction  temperature can be  adjusted  to the
boiler conditions by controlling the H2 flow rate.

     Exxon has  developed a  performance prediction procedure  to  optimize grid
location  in  the boiler  and to  estimate  NOX  removal.  Variables  used  in the
calculations  are:    flue  gas   temperature  and  flow distribution,  including
severity of cross-sectional  variations, flow path geometry, available reaction
time, and suitability of the dimensions of  the zone  for grid placement,  based
on manufacturer's data.   The procedure  will give an estimated NOZ removal
percentage at a particular location in the flue gas path.
                                     29

-------
     To optimize grid placement,  the performance prediction procedure  is used
at a  number  of locations within the boiler  to generate a  graph  of  location
versus  NOX  removal.   This  is  done  for  50%,  75%,  and   100%  boiler  load
conditions.   A  combination-load  grid,  which  will  serve  two  of the  boiler
loads,  is  situated at  the  maximum of  the intersection points  of  the  load
curves.  The  single-load grid  is situated at the maximum of the remaining load
curve.

     For an  actual  installation,  measurements of  the  temperature  and  flow
patterns within  the predicted zone would  be   used  to  confirm or adjust  the
final grid  location.  The most  frequently used  load is emphasized in  designing
grid placement, so that NOX  emissions can be minimized at that load.

     Potential  problems with  the  Exxon  process   generally  relate  to  NH3
emissions.   Emission  levels  from   a  pilot-scale  coal-burning  test   system
averaged 11  to 34 ppm  NH3  at  the  boiler exit.  The assessment of  the  Exxon
process using  the  performance prediction  procedure  for eight major  utility
boiler  types  gave  predicted NHg  levels  at  the boiler outlet of 21  to  43  ppm
for an NE^NO mole injection  rate  of  1.0, and  64  to  129  ppm for  an  NI^iNO
mole  injection rate of  1.5, although these might vary  under actual  operating
conditions.  Operating experience on full-scale  oil- and gas-fired units shows
NH3 levels  of 10 to 40 ppm.

     NHj  emissions  when  combined  with 863  can  cause  problems with
(NH4)2S04  and NH4HS04 formation.  This  is  particularly  true  in  coal-
fired applications, where sulfur content is relatively high.  Studies indicate
substantial   amounts   of   (NH4>2S04   and NH4HS04  are  deposited  in  the
air heater.   Although most  of the  deposits may be removed by  soot  blowing,
modifications in the air heater design  may be  required.   Operating experience
in Japan with low-sulfur oil-fired boilers has  shown that water washing of the
air heaters is necessary two or three times a year.

     The  presence of  NH3  in  the flue gas  has mixed  effects  on  ESP
performance.   It has been used as a flue gas additive to neutralize  condensed
H2S04  and  reduce  reentrainment  losses  by increasing  fly  ash  cohesiveness
(5).   However, NH3  can also cause  excessive  sparking between the electrodes,
especially  with low-sulfur,  high-resistivity, western coal fly ash.  Reactions
of  NH3 with  S03  will deplete  the  803 content  of  the  flue gas which
lowers  collection  efficiency.    The  net  effect  of  these  factors  on  ESP
performance  is  unclear.  It  is  also  unclear  at  this  time whether  the  NH3,
(NH4>2S04,  or NH4HS04 will  present  additional  operating  requirements
for 802 scrubber systems, such  as waste water treatment.

Development Status

     The reaction mechanism  of the Exxon process was developed by Exxon using
simulated  flue gases  in a bench-scale  reactor.   When  the  reaction  mechanism
was  established,  evaluation of   operating   parameters  such  as  reaction
temperature   and  NH3  injection  rate  was  performed  on  a 0.3-MWt  (10°
MBtu/hr) oil- and gas-fired  boiler.  Corrosion  and fouling effects were tested
on a 9-Mfft  (30 MBtu/hr) oil- and gas-fired boiler.
                                     30

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     Commercial application of  the  Exxon process is primarily limited to gas-
and oil-fired units in Japan, as shown in Table 2.  The Los Angeles Department
of Water  and Power's  Haynes Electrical  Generating  Station is scheduled to be
the first U.S. electric utility to  install the Exxon process  (20) with startup
projected for May 1981.   The  Haynes Unit 4  is  a 230-MW boiler burning either
No. 6  fuel  oil containing 0.25% sulfur or gas.   Predicted performance for the
Exxon  process is  51% NOX reduction  at full  load using one  NH3  injection
grid containing six zones.  Exxon is guaranteeing  the  process  for 90% of the
predicted performance which  is 46%  NOX reduction.  At  50%  boiler  load,  no
NOZ reduction is guaranteed.

     Although no  commercial  application of  the  Exxon process on a coal-fired
boiler has  yet been made,  studies  have been made to assess the possibility of
such  an  application.   A coal-fired  pilot-plant  study,  sponsored by  Exxon
Research  and Engineering  and  EPRI  and run by KVB, Incorporated, was completed
in  early  1978.     The project utilized a fire  tube  boiler,  0.9  Mfft  (3
MBtu/hr),  modified  to  fire   pulverized  coal   with  preheated  air.    Three
bituminous  and one  subbiluminous  coals were  fired.    A 65%  NOX  reduction
could  be   obtained  for  all  coals  with  a 1:1  NH3:NOX molar  ratio  feed
rate.  Optimum  operation,  that is,  maximum NOX  reduction  and  minimum  NHj
emissions,  was  55% NOX  reduction  and  10   to  35 ppm  NH3 emitted.  Hydrogen
injection was  tested with one  coal  and found  to  increase NOX  reduction and
decrease NH^ emissions.

     Under  contract with  EPA,  eight different  pulverized-coal-fired  boiler
designs  were assessed  by Exxon  to  predict the  applicability  of  the  Exxon
process.  This  was  done   using  the   Exxon-developed  performance  prediction
procedure and boiler  design data  supplied  by the  manufacturer.   Each boiler
design was  evaluated  at 100%,  75%,  and 50%  load.   As a  basis  two injection
grids were  used and there was  no %  addition.   The best  predicted results of
any design,  coal  type, and load  at  an  NH3:NOZ  molar  ratio  of  1.5:1  was 63%
NOX  reduction  and  the   worst  was  45%  NOX reduction  (28).  Using  updated
technology,   Exxon  now  states  that  the predicted  NOX  reductions  would  be
10-20 percentage points higher.


HITACHI ZOSEN PROCESS

Process Description

     Hitachi Zosen  has developed a process  for  the dry  SCR of NOX with NH3
(32).    U.S.  licensee  for  the  Hitachi Zosen process  is  the  Chemico  Air
Pollution Control  Corporation.    The  process  is based  on a catalyst and  a
reactor design developed  by  Hitachi Zosen that  permits treatment  of the  flue
gas with  a  high particulate  loading.   Therefore,  flue gas from a coal-fired
boiler may be fed directly to the reactor, upstream of  the air heater,  without
previous  particulate  removal.   The  reactor  pressure  drop is  2  to 3  inches
H2<>.   An NH3~air,  N^-steam,  or  NH3  -  flue-gas  mixture  is  injected
into the  flue  gas  upstream of  the reactor  at  an NH3:NOX molar ratio  of 1:1
to  achieve   90%  NOX  removal.    Automatic control  of   the NH3  flow rate  is
                                     31

-------
10
t-0
                                   TABLE 2.   SUMMARY OF COMMERCIAL APPLICATIONS OF

                                             EXXON THERMAL DENOX PROCESS
Source
Industrial boiler
degeneration boiler
Cogeneration boiler
CO boiler
Petroleum heater
Petroleum heater
Industrial boiler
Petroleum heater
Petroleum heater
Oilfield steamer
Utility boiler
Utility boiler
Utility boiler
Refuse incinerator
Utility boiler
*Re finery heaters (14),
boiler (1)
**Refinery heaters (4),
boilers (2)
**Utility boiler
Glass melting furnace
**Petroleum heater
**Petroleum heaters (2)
**Refuse incinerator
Location
Japan
Japan
Japan
Japan
Japan
Japan
Japan
Japan
Japan
California
Japan
Japan
Japan
Japan
Japan

California

California
Cal if ornia
California
California
California
Cal if ornia
Fuel
Oil/gas
Oil/gas
Oil/gas
CO gas/gas
Gas
Gas
Oil
Oil/gas
Oil/gas
Crude oil
Oil
Oil
Oil
Refuse/gas
Oil

Oil/gas

Oil/gas
Oil/gas
Gas
Gas
Gas
Refuse/gas
Heat release,
HBtu/hr
215
1,135
1,135
400
515
190
340
250
250
50
1,210
3,000
1,500
-
2,900

647 (total)

349 (total)
2,100
150
150
47 (total)
160
Approximate
initial NOX
emissions, vtmm
185
140
140
160
130
130
135
79
85
270
160
150
100
100-180
110-140

100-125

100-150
200
1,500-2,000
75
82
216
Reduction
efficiency, %
55
60
60
50
63
63
53
51
53
65
45
33
35
20-70
40

50-60

50
51
>50
50
>60
>60
            *Two heaters in operation, remainder not yet in operation.
           **Not yet in operation.

-------
based  on the flue gas  flow rates and  the  inlet NOX concentration  and  it is
optimized  using  the  outlet  NOX  and  NH3  concentrations.  NH3  is  diluted
by  air to  5% or by steam or flue gas to 5%  to 20%.   This enhances mixing and
places  the NH3-air  mixture outside  of the flammability limits of  15.5% to
27.0%.

     In  the  reactor,  NOX  is  reduced to N2 by  a  reaction with  NH3 in the
presence  of  a  catalyst at  an optimum temperature  of 734°F.   The  reactions
are listed by Hitachi Zosen as follows:

                        4NO + 4NH3 + 02  -> 4N2 + 6H20                    (1)

                             6NO + 4NH3  -> 5N2 + 6H20                    (2)

                       2N02 + 4NH3 + 02  -»• 3N2 + 6H20                    (3)

                            6N02 + 8NH3  •> 7N2 + 12H20                   (4)

                             4NH3 + 302  •»• 2N2 + 6H20                    (5)

     Reactions  (1)  and  (3) predominate when  the molar  ratio  of NH3:NOZ is
approximately  1:1,  which  is  required  for  90%  NOX  reduction;   however,
reactions  (2)   and   (4)  gain  dominance  as  the  NH3:NOX  molar   ratio  becomes
less  than  equimolar.   Reaction  (5)  represents  the breakdown  of  NH3 by 02.
This   undesirable  reaction  becomes  a   problem  at  higher   than optimum
temperatures.    At  the  optimum   reactor  temperature  or   below,  it  is
insignificant.   Hitachi Zosen reports  that the level of  excess  NH3 in the
flue gas leaving the  system is low  «10 ppm).   After leaving the reactor, the
treated flue gas flows to the air heater.

Technical Considerations

     The  temperature range  required to achieve 90% NOX reduction  is  600°F
to  750°F.  As can be seen in Figure 16, additional  reduction can  be obtained
at  temperatures  higher  than  the   acceptable   range  but  NH3   decomposition
becomes  more prevalent.    Below  the acceptable temperature range  reduction
efficiency becomes unsatisfactory.   Since  flue gas  temperature  will  fluctuate
with the boiler load, some method must be  employed at low load to  raise the
flue gas temperature  to acceptable  reactor  conditions.   Four techniques  that
can be used are to operate an auxiliary  furnace,  to bypass hot flue gas around
the  economizer, to  reduce  water  flow to  the   economizer,  or use a  split
economizer  design.     It  might  also  be  possible  to  design  for  low-load
conditions adequate  to  maintain the  required NOX reduction efficiencies.  It
may  be  possible  that  low  loads  will  not have an  adverse   effect on  NOX
reduction efficiency  since  reduced loads will decrease  the  amount  of flue gas
to  be   treated,  resulting  in  an  increased residence  time in the  reactor.
Therefore,  the decreased temperatures may  be offset by the increased residence
time.

     To reduce  the effects  of high fly ash  loadings  from coal-fired flue gas
on the catalyst, Hitachi Zosen uses  a corrugated  configuration  (see Figure 17)
and  the  flue gas passes  parallel  to the  catalyst  surface.   Because  of  this
                                      33

-------
                                                                  NOX  REDUCTION,  %
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-------
geometric surface  area)  i
unique configuration,  aroa velocity  (volumetric flue  gas  flow rate/catalyst
                         ather than space velocity (volumetric  flue  gas  flow
rate/reactor  volume)  is  tsed to determine  the  quantity  of catalyst  required.
                         bhat  the  area  velocity  recommended  for  90%  NOX
                         8  and 33  ft^/hr-ft^,  which corresponds  to a space
Hitachi  Zosen  reports
reduction is  between  22.
velocity of  5,000  to 10,000  ft3/hr-ft3.  The  stoichiometric  requirement  is
given  primary  consideration when  determining  the  NE^tNOg molar ratio
required to  achieve  a given NOX  reduction,  but  other factors must  also  be
considered.    The  stoichiometric  requirement  determines  the  amount  of  NH3
that  must   be   injected   if  NH3   usage  is  100%   efficient.  However,
inefficiencies   result  from  incomplete  mixing   of  NOX  and  NH3   and
consumption  of NH3  by  reactants  other  than  NOX.  Because  of these
inefficiencies  in  NH3   usage,  excess  NH3   must  be   injected.   Here,   care
must be  taken since  too  much additional  NH3  will  result  in increased levels
of  unreacted NH3  passing  through  the reactor.    If  this occurs,   the
breakthrough NH3 becomes a pollutant.  Figure 18 shows representative curves
of  NOX   removal   efficiency  and  exhaust  NH3   as  a  function  of   the
molar ratio.
 Figure 17.   Configuration of Hitachi Zosen NOXNON 500 and 600 series
             catalyst  (32).
     The  oxidation  of  S(>2   can  be  a  problem   in  NOX  catalytic
reduction.  The  catalyst composition may  cause  <1% of  the  S(>2  in the  flue
gas  to  be  oxidized  to  803,   which  will  combine  with  NHg  to   form
           and  NH4HS03.   These   deposit  as sticky solids  on  equipment
                                    35

-------
PERCENT REDUCTION OF NO,
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                     36

-------
 at low  temperatures.   The  sulfate and bisulfate  formation temperatures  are
 dependent   on  the  NHg   and  SOg   concentrations  as   can  be  seen   in
 Figure 19.   Air heater  plugging,  catalyst  masking,  and equipment corrosion  are
 the primary problems related  to  the  deposits.  However, Hitachi Zosen states
 that the deposits  can be  removed  by soot blowing or water washing.

      Pressure drop  for the  reactor  and  catalyst   is  reported to be  2 to  3
 inches I^O  by Hitachi  Zosen  and should  not  increase significantly over  the
 catalyst life.  Figure  20 shows a  typical pressure  drop  versus operating time
 profile for a Hitachi Zosen catalyst.

      Catalyst  life  is  dependent  on  a   number  of  factors   including   the
 resistance  of the  surface  to abrasion  by particulate matter,   the masking  of
 the catalyst  by fine  particulates,  and chemical  attack by compounds  in  the
 flue gas.   Figure  21 is  a plot  of  the  percent NOX reduction  versus  catalyst
 age.    As can  be  seen NOZ reduction decreases with  age.   The  loss  in  NOZ
 reduction efficiency can be  a result  of abrasion gradually  removing  possible
 reaction sites.  Additional reaction  sites can be lost as a  result  of  fine  fly
 ash particles plugging  pores  in the catalyst  surface.   Fly ash  plugging can be
 reduced by  regular  soot  blowing.  S0$  and other  trace  elements  in flue  gas
 can chemically attack the catalyst causing loss  in  reactivity.  Hitachi Zosen
 claims their catalyst is  resistant to  attack  of this nature,  however.
 o
 H
 H
 U
  X
 o
     92  _
     90  -
                          34567

                          CATALYST AGE,  hours x 103
Figure 21.  NOX reduction versus catalyst age for the Hitachi Zosen process (32)
                                      37

-------
                                                          NH3 CONCENTRATION,  ppm
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Temperature: 734 F
Ash concentration: 8.28 gr/sft


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40


30


20

10

n
0 2000 4000 6000 8000


Tl
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                                                   OPERATING TIME,  hours
             Figure 20.   Pressure drop versus  operating time for the Hitachi Zosen process (32).

-------
     The  reactor  inlet  NOX  concentration has  no  effect on  NOX  redaction
efficiency  in  the range  of  150  to  650 ppm  of  inlet  NOX,   as  shown  in
Figure 22,  provided that  the  required NH3:NOX  molar  ratio is  maintained.
As  shown  in  Table 3   it  can be   seen   that  NOX  reduction  efficiency  is
independent of  inlet  S(>2  and H^O concentrations.  The  presence  of 1%  to  2%
02 in the flue gas is necessary for NOX control,  as shown in Figure 23.


                       TABLE 3.  INFLUENCE OF S02 AND H20

                                 CONCENTRATIONS
              Inlet concentration   Temperature/NOT reduction. %
               S02. ppm   H20. %	392QF  482QF  572OF  662OF
0
250
250
10
10
0
55
54
59
73
73
73
86
85
87
94
93
93

              Basis:  Temperature:  392OF to 662op
                      Area velocity:  34.7 sft3/hr-ft2
                      NH3:NOX (mole ratio):  1.0
Development Status

     Hitachi Zosen  has been  developing  an NOX  control process  and  catalyst
since  1970.    Six  different  catalyst  series  have been developed.    They  are
known  as  NOXNON 100,  200,  300,  400,  500,  and 600.    The  100  series  is
nonselective,   for  use  with   CO,  H2»   and   hydrocarbons  as   reducing
agents.  NH3  is  the  reducing agent  for  the  five  remaining series.   Series
200 is used for treating clean flue gas,  that is, gas which does not contain a
significant amount  of SOX or particulate matter.  The  300  and  400  series  are
resistant  to  SOX.    The NOXNON 500  and  600  catalyst were  developed to have
the following characteristics:

   •  High selectivity for adsorption and reaction activation of NH3 and
      NOX

   •  Immunity to SOX attack, especially by 803

   •  A low pressure drop

   •  Tolerance to plugging from gases with high particulate loadings

     A  corrugated,   honeycomb-type  configuration  was  found to  be  the  most
suitable for these conditions.  The NOXNON 500 Type II catalyst was tested for
                                      40

-------
o
M
H
 X
o
    100
    80
     60
    40
    20
                     Area velocity = 24.3
        734°F


        662°F
                                                                 734°F
                     Area velocity = 82.85 sft3/hr-ft2
     662UF
                                        Temperature:  662°F,  734°F

                                        NH3:NO  (molar ratio):  1.0
                         I
                       200                400


                         INLET NOX CONCENTRATION, ppm
600
 Figure 22.  Influence of NOX concentration on NOX reduction with the

             Hitachi Zosen process (32).
                                       41

-------
NJ
               52
               O
               M
               H
               O
               &
                    100
                     80
                     60
                     40
                     20
I    1
                                     O   9
              Area  velocity =  7.68  Nm /m »h

              Temperature:   390°C

              NH3:NOX (molar ratio):   1.0
                                                                    I
                                             5                     10

                                             02 CONCENTRATION, vol %
                                                     15
              Figure  23.   Influence of Q£ concentration on NOX reduction  for  the Hitachi
                           Zosen process  (32).

-------
over  8,000  hours  with  a  negligible  increase  in  pressure  drop,  although
catalyst  activity  exhibited  a  sharp  initial  decrease  due  to  abrasion  of
protruding active  sites  on  the  surface.   The NOXNON 500 Type III catalyst was
designed  specifically  for  increased  surface  hardness,  which was demonstrated
in  over  3,500  hours  of testing  for abrasion  resistance.   The  NOXNON 600
catalyst  has  the  same  composition as the  500  series  catalyst  but the  solid
metal support used  in the 500 series was replaced by a wire mesh support.  The
NOXNON  600  catalyst  was  tested  for  over  14,000  hours  with  a  negligible
increase  in pressure drop and stable NOX removal efficiency.

     Since the beginning of catalyst development, a  total  of  41 pilot plants
have been constructed by Hitachi  Zosen  (see Table 4).  While  a  majority of
these pilot  plants are  at  oil- and gas-fired  installations,  there are  three
pilot plants at  coal-fired  installations.   The  most significant  work in  coal-
burning applications was performed  at  the Isogo Station of the Electric Power
Development Company of Japan.   In  1978,  EPA contracted with Hitachi Zosen to
build a  0.5-MW-size pilot plant at the coal-burning Mitchell Station of the
Georgia Power Company.


              TABLE 4.  HITACHI ZOSEN PILOT-PLANT EXPERIENCE
                                                      No. of plants

         Heavy fuel-oil-fired boilers                      21
         LNG- and LPG-fired furnaces                        6
         Iron ore sintering                                 3
         Heavy oil-fired cement kilns                       2
         Heavy oil-fired glass smelting furnaces            2
         Coke ovens                                         3
         Coal-fired power plants                            3
         LPG-fired simulation gas (for gas turbine)         1

              Total                                        41

         Total raw gas flow through test plants       35,130 Nm3/hr
     There  are  no   existing  commercial  applications  of  the  Hitachi  Zosen
process on  coal-fired boilers.   Table 5 lists nine  commercial  installations
using other fuels.
                                     43

-------
                  TABLE 5.  COMMERCIAL PLANTS USING THE HITACHI ZOSEN PROCESS
       Customer
Treating
capacity,
 Nm3/hr
Flue gas source
     Process
Completion
1  Osaka Gas Company,      53,000
    Sakai
2  Daiki Engineering,       5,000
    Chiba
3  Idemitsu Eosan,        350,000
    Chiba
4  Shin-Daikyowa Petro-   440,000
    chemical, Tokkaichi
5  Hitachi Zosen,           6,000
    Osaka
6  Toshin Steel Mill,      70,900
    Himej i
7  Kawasaki Steel,        762,000
    Chiba
8  Nippon Satetsu,         10,000
    Himej i
9  Maruzen Petro-         150,000
    chemical Company
    (formerly Kansai
    Oil Company), Sakai
            LNG- or naphtha-fired
             furnace
            LPG-fired furnace
            Co boiler
             heater
            Fuel-oil-
             wet-type
            Gas-fired
             furnace
            Kerosene-
             heating
            Iron ore
             wet-type
            Fuel-oil-
             heating
            Fuel-oil
   and gas-fired

  fired boiler with
   desulfurization
   annealing

  fired steel
  furnace
  sintering plant with
   desulfurization
  fired steel
  furnace
  fired boiler
Ammonia reduction     1975

Ammonia reduction     1975

Ammonia reduction     1975

Ammonia reduction     1975

Ammonia reduction     1975

Ammonia reduction     1976

Ammonia reduction     1976

Ammonia reduction     1977

Ammonia reduction     1979

-------
                                   PREMISES
     The following premises were used for the comparative economic evaluations
of  the  processes  in  this  study.    The  premises  are  for  projects  with a
construction  schedule  starting in 1981  and ending  in 1983,  with 1984 as  the
first year of operation.
DESIGN PREMISES

Plant Size and Fuel

     The power unit  is  a new,  coal-fired, horizontally opposed, balance-draft
boiler burning pulverized coal.   A 30-year  life  and a north-central location
(Illinois, Indiana, Ohio, Michigan, and Wisconsin) has been assumed.  The unit
has a net output  of  500 MW including all system energy requirements up to and
including the  ESP's  and  the  induced  draft (ID) fans.  This  does not include
the energy usage  of  any  flue gas  treatment  processes.   The unit has a design
heat rate  of 9,500 Btu/kWh.   Utility basic mechanical equipment is shown in
Table 6.
                TABLE 6.  COAL PLANT BASE MECHANICAL EQUIPMENT
     Total plant electrical capacity*   2,000 MW
     Unit rated electrical capacity*    500 MW
     Steam generator type               Balanced draft
                                        Horizontally fired, dry bottom
                                        Pulverized coal
     Design heat rate                   9,500 Btu/kWh
     Fly ash removal type               Cold-side electrostatic
                                         precipitator
     Fly ash removal efficiency         99.8%

     a.  Net including system energy usage up to and including ESP's
         and the ID fans (does not include F6D or F6T).
     Fuel for  the  plant  is a coal having  a  heating  value of 11,700 Btu/lb as
fired and containing 3.5%  sulfur  and  15.1% ash.   The coal composition and the
input coal requirements (based on a heat rate of 9,500 Btu/kWh) for the 500-MW
                                      45

-------
boiler  are  listed in  Table 7.   The capacity  factor  is equivalent  to 5,500
hours of operation at full load.
                        TABLE 7.  BASE CASE COAL

                              COMPOSITION

                          AND INPUT FLOW RATE

                           (500-MW new unit,
                        9,500 Btu/kWh heat rate)
                   Component  Wt %. as fired   Lb/hr
c
H2
N2
02
S
Cl
Ash
H20
66.7
3.8
1.3
5.6
3.4
0.1
15.1
4.0
270,800
15,400
5,300
22,700
13,800
400
61,300
16,300
Flue Gas Composition

     Flue  gas  compositions  are  based  (2)  on combustion  of pulverized  coal
assuming a  total  air rate after  the  air preheater equivalent to 139%  of the
stoichiometric  requirement.    This  includes   20%  excess  air   to   the
boiler and 19% additional air inleakage at the air preheater.

     It is  assumed  that  80%  of the ash present in  the  coal  is  emitted as fly
ash  and  that  92%   of  the sulfur  is  emitted  as  SOX.  Three  percent  of  the
sultur  emitted  as   SOX   is   S03  and  100%  of the  chlorine  is  emitted  as
HC1.  NOX  emissions are  assumed  to be  0.6 Ib equivalent  N02/MBtu with  95%
being NO  and  5%  N02 .   Table  8  gives  the  composition and  flow rate  at  the
economizer outlet for untreated flue gas.

NOy Control System
     Proper  reheating  credits or  debits  are assigned  as  applicable for  NOZ
removal.   For  dry catalytic  processes,  catalyst  replacement occurs  during
boiler  outages  and does  not  affect  boiler on-stream  time.   Spent  catalyst
disposal costs are assumed to be zero, with the  catalyst support  salvage value
being  equal  to  the   catalyst  coating  removal  and disposal  costs.    This
assumption  may be unique  to  the Hitachi  Zosen  catalyst  which  employs  a
                                      46

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metallic  support made  of  stainless  steel.    It  may not  apply  to ceramic
supports or homogeneous catalyst.   Even with salvage of the metallic support,
disposal costs  may be  greater than zero;  however, Hitachi Zosen feels that
this is a reasonable  assumption for their catalyst.  A sufficient quantity of
catalyst to ensure  the  desired removal  efficiency  is  maintained.  Redundancy
and  the number  of  modules  for dry processes  are  based  on  the NOX removal
system  module  availability  and  the  required  NOX removal   efficiency.  For
this  study,  the  NOX  removal  system availability  is  assumed to be  100%  so
that no redundant trains  are needed.   Redundancy is achieved through sparing
vital equipment in the NHg vaporization  and injection system.
                        TABLE 8.  FLUE GAS COMPOSITION

                    AND FLOW RATE AT THE ECONOMIZER OUTLET

                     (500-MW new unit, coal fired, 9,500
                      Btu/kWh, 3.5% S, 11,700 Btu/lb HHV
                    as fired, 2,249,000 aft3/min at 705<>F)
                  Component   Vol. %
Lb/hr
N2
02
C02
S02
S03
NO
N02
HC1
H20
Ash
74.86
3.27
14.21
0.24
0.008
0.037
0.002
0.007
7.36
-
3,326,900
165,800
992,300
24,600
953
1,765
143
416
210,200
49,000
                              100.00    4,772,100  (appro*.)
     Since  it  is  presently unclear whether the presence of nitrogen  compounds
in waste  water as a  result of air heater washing  to  remove NHg compounds  is
a  significant  problem for  U.S.  applications, no provisions  are made for  the
treatment of waste water.

     Separate  ID fans  are not  included  for  the  systems.    Rather,  a  larger
boiler  ID  fan is  used to compensate for  the higher  pressure drop  of  the
combined  boiler-FGT system  and  the  increased costs are assigned  to the  FGT
process.
                                      47

-------
Raw Materials

     All  raw materials  used  are  assumed  to  be  received  by either  rail  or
truck.  Thirty-day storage facilities at full load are provided.
ECONOMIC PREMISES

     The capital  structure is assumed  to  be 35%  common  stock,  15% preferred
stock, and 50% long-term debt.  The cost of capital is 11.4% for common stock,
10.0% for preferred stock, and 9.0% for long-term debt.  The weighted cost of
capital is 10.0% and the discount rate is 10% (8).

     A  30-year economic  life and  a  30-year tax  life  are  assumed  for the
utility plant.  Salvage value  is  less than 10% and is equal to removal costs.
The annual sinking fund factor for  a  30-year economic life and 10.0% weighted
cost  of capital  is 0.61%.    The use  of  the  sinking fund  factor  does not
indicate that regulated utilities commonly use sinking fund depreciation.  The
sinking  fund  factor  is   used because   it   is  equivalent  to  straight-line
depreciation  levelized for   the  economic  life  of  the   facility using  the
weighted cost of capital.   The depreciation schedule for other types of plants
or facilities is based on their expected useful life.

     An annual  interim replacement  allowance of 0.56%  is  also  included as an
adjustment to  the  depreciation account to ensure  that  the initial investment
will  be recovered within the actual rather  than the forecast   life  of the
facility  (12).    Since power  plant   retirements  occur  at different  ages,  an
average service life is estimated.  The interim replacement allowance does not
cover replacement of individual items of  equipment since  these  are covered by
the maintenance charge.

     The sum  of the years digits method of  accelerated  depreciation is used
for tax purposes.   For a  50%  tax rate, 30-year  tax  life,  30-year book life,
10.0% weighted  cost  of capital,  and  a 0.61% sinking  fund factor, the annual
levelized  accelerated  depreciation  credit is  1.36%.   Using a  10% investment
tax credit rate the  levelized  investment  tax credit is 1.92% annually.  For a
10.61%  capital  recovery  factor  (weighted cost of capital plus  sinking fund
factor),   0.56%   allowance  for  interim   replacements,   3.3%   straight-line
depreciation, 50% debt ratio,  9.0% debt cost, and a  50%  income tax rate, the
levelized  income tax rate  is 4.31%.

     The levelized annual capital charges as shown in Table 9 are  14.7% of the
total investment.  The annual  capital charge includes charges for the capital
recovery factor, interim replacements, insurance and property taxes, State and
Federal  income  taxes, and  credits  for  investment  credit  and  accelerated
depreciation.

     The annual capital charge is applied to the total capital investment.  It
is  recognized  that  land  and  working  capital  (except  spare  parts)  are not
depreciable and that provisions  must be made  at  the  end  of the economic life
of  the  facility  to recover  their  capital  value.   In  addition, investment
                                     48

-------
credit  and  accelerated  depreciation  credit  cannot be  taken  for  land and
working capital  (except  spare  parts).   The cumulative effect of these factors
makes an insignificant change  in the annual capital charge rate in most  cases
and is therefore ignored.


                 TABLE 9.  LEVELIZED ANNUAL CAPITAL CHARGES

                       FOR REGULATED UTILITY FINANCING
                                            Capital charge. %

              Capital recovery factor             10.61
              Interim replacements                 0.56
              Insurance and property taxes         2.50
              Levelized income tax                 4.31
              Investment credit                   (1.92)
              Accelerated depreciation            (1.36)

                   Total                          14.70
Capital Investment Estimates

     Capital  investment  estimates  are  based  on  a  north-central  location
(Illinois,   Indiana,   Ohio,   Michigan,  Wisconsin)   and  represent  projects
beginning 1981 and ending 1983.  Capital cash flows for a standard project are
assumed to be 25%  the  first  year,  50% the second year, and 25% the third year
of  the  project  life.    Capital   costs   are  projected  to  mid-1982,  which
represents the midpoint of the construction expenditure schedule.

     The preliminary capital  cost  estimates are considered  to  have a -20% to
+40% range  of accuracy for  the  Hitachi Zosen and Exxon processes.  They are
based  on  a  process  description,  flowsheet,  material balance,  and equipment
list.   Piping,  ductwork, and instrumentation  are factored.   The  range  of
accuracy for  the  cost  of  the ALNB is -20% to +100%.   It is  based on the best
fixed  capital  investment  estimate for  incremental  costs  above  present burner
costs now available from boiler manufacturers.

     The  total  fixed  capital investment  consists  of direct  capital  costs,
engineering design and supervision, construction expense, contractor fees, and
contingency.  The  total  capital  investment  includes  the total  fixed capital
investment plus  allowances  for startup and modification, royalties,  the cost
of  funds  during construction, plus  the  cost  of  land,  working  capital,  and,
where applicable, cost of the  initial catalyst charge.
                                      49

-------
Direct Investment—
     Direct  capital  costs   cover   process   equipment,   piping,   insulation,
transport  lines,   foundations,  structural,  electrical,   instrumentation,  raw
material  and  byproduct  storage,  site  preparation and excavation,  buildings,
roads  and railroads,  trucks, and  earthmoving equipment.  Direct  investments
are  prepared  using standard  estimation  techniques  (22,  24)  and the  average
annual  Chemical  Engineering  (6)  cost  indexes  and  projections  as shown  in
Table  10.   A premium for  7% overtime  is included in  the construction labor.
Appropriate amounts for sales tax and  for  freight are  included in the  process
capital costs.
                   TABLE 10.  COST INDEXES AND PROJECTIONS
     Year:
1978
1979a   198Qa   198ia   1982a   1983a   1984a
Plant 218.8 240.2
Materialb 240.6 262.5
Laborc 185.9 209.7
259.4
286.1
226.5
278.9
309.0
244.6
299.8
333.7
264.2
322.3
360.4
285.3
344.9
385.6
305.3

a. TVA projections.


b. Same as index in Chemical Engineering
machinery, supports."


c. Same as index in Chemical Engineering
labor."



(24) for

(24) for



"equipment,


"construction


     Necessary electrical substations, conduit, steam, process water, fire and
service water,  instrument air, chilled water,  inert gas, and  compressed air
distribution  facilities  are   included  in  the  utilities  investment.    These
facilities are costed  as  increments  to  the  facilities already required by the
power  plant.    Services,  nonpower  plant  utilities,  and miscellaneous  are
estimated at 6% of the total process capital.

Indirect Investment—
     Indirect  capital   investment  consists   of  engineering  design  and
supervision,  architect and engineering contractor  costs,  construction costs,
contractor fees, and contingency.   Construction costs,  which consist of costs
for  mobile  equipment,   temporary  lighting,  construction  roads, water  supply,
construction  safety  and  sanitary  facilities,  and other   similar  expenses
incurred during construction are considered as part of construction expenses
and  are charged to indirect capital investment.

     Listed below are  the factors used to determine the indirect capital cost.
                                      50

-------
                                              % of direct investment
       Engineering design and supervision               7
       Architect and engineering contractor             2
       Construction expense                            16
       Contractor fees                                  5

            Total                                      30
A contingency  of  20% has been included for unforeseen  expenses.   It  is based
on the sum of the direct investment less waste disposal  and the above  indirect
investments.

Other Capital Investments—
     Startup  and modification  allowances  are  10%  of  the total   fixed
investment.  For  proprietary processes,  the actual royalty  fees are  charged.
Working  capital  is  the  total amount  of money  invested  in  raw  materials,
supplies, accounts receivable, and monies on  deposit  for payment of operating
expenses.   Working  capital  is the  equivalent cost of 1  month's raw  material
cost, 1.5  months' conversion cost,  and  1.5  months' plant  and administrative
overhead costs.  In addition, it includes 3% of the total direct investment to
cover spare parts, accounts receivable,  and monies on deposit to pay taxes and
accounts payable.    Land cost is  assumed to  be   $5,000 per  acre.   For  the
Hitachi  Zosen  process,  a  1982 initial catalyst  charge  of  $600/ft3  is  also
included.

Annual Revenue Requirements

     Annual revenue  requirements use  1984 costs and are  based on  5,500 hours
of operation per year at full load.

Direct Operating and Maintenance  Costs—
     Direct  costs  include  raw materials,  labor,  utilities,  maintenance,  and
analytical   costs.   Raw material,  labor,  and utility  costs  are  listed  in
Table 11.

     Unit costs for steam and electricity are  based on the assumption  that the
required  energy  is  purchased from  another   source.    Unit  costs   ( $/kW,
mills/kWh)   are  calculated  on the basis  that  the  power  unit size  is the  net
power output after  the  addition  of the pollution  control  systems.  Actually,
the  electrical  usage by the pollution control equipment after the  ESP will
result   in  a  derating of   the  utility plant.    To  minimize  iterative
calculations,  instead  of  derating  the  utility plant,  the  pollution control
equipment  is  charged  with  purchased  electricity.   Maintenance  costs  are
estimated to be 5% of the direct  investment.
                                     51

-------
                           TABLE 11.  COST FACTORS
                  1984 Utility Costs

                  Electricity                $0.037/kWh
                  Steam                      $2.70/MBtu

                  1984 Labor Costs

                  Operating labor
                  Analyses

                  1984 Raw Material Costs

                  Ammonia
                  Catalyst (Hitachi Zosen)  $700.00/ft3
 $15.00/man-hr
 $21.00/man-hr
$155.007ton
Indirect Costs—
     Indirect costs cover levelized annual capital charges and overheads.  The
levelized annual  capital  charges  consist of a  sinking  fund  factor,  allowance
for  interim  replacement,  property  taxes,  insurance,  weighted cost of capital,
income tax,  credits for accelerated  depreciation,  and investment credit.  the
levelized annual capital charge as shown in Table 9 is 14.7%.

     Overheads  consist  of  plant,  administrative,   and  marketing  expenses.
Plant and administrative  overhead  is 60% of conversion  costs  less utilities.
The plant and administrative overheads  include  plant  services  such as safety,
cafeteria,  medical,  plant  protection,   and  general  engineering  (excluding
maintenance).  Fringe benefits are included in the base wage rates.

     First-year revenue requirements using the 14.7% levelized capital charges
are  determined.    In addition,  levelized  annual  revenue  requirements  are
calculated using a 10%/year discount factor, a 6%/year inflation factor, and a
30-year economic life that gives a 1.886 levelizing factor (8).
                                      52

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                              SYSTEMS ESTIMATED
     Process descriptions,  flowsheets,  material  balances,  and major equipment
lists  and descriptions  were prepared  for  each of  the  NOZ  control  methods
evaluated in this study, with the exception of the ALNB.  An equipment list is
not available for the ALNB because of its early stage of development.

     Two  levels  of  NOZ reduction  are  examined.   With  a baseline  emission of
the  0.6  Ib  N02/MBtu   (450  ppm  at 3% 02)  NSPS,  costs   are determined  to
achieve  a 50%  NOX  reduction  to  0.3  Ib  N02/MBtu  (225  ppm at  3% 02)  for
each  of  the  three processes  although  50%   NOZ  reduction  is  not  typical  for
the  Hitachi  Zosen  process.   In  addition,  costs  are determined  for  a  90%
reduction  in NOZ to  0.06  Ib  N02/MBtu  (45  ppm  at  3%   02).  The 90%  NOZ
reduction involves the following three process alternatives.
   1.  Moderate NOZ reduction achieved by the ALNB and the remaining NOZ
       reduction achieved by the Hitachi Zosen process.

   2.  Moderate NOZ reduction achieved by the Exxon process and the
       remaining NOZ reduction achieved by the Hitachi Zosen process.

   3.  100% of the NOZ reduction achieved by the Hitachi Zosen process.


     The  levels  of  NOZ  reduction  assumed for  each  process  and  process
combination are  graphically  illustrated in Figure 24.   The  Hitachi Zosen and
Exxon processes  are divided into major operational  areas to  facilitate  cost
comparisons.


ADVANCED LOW-NOX BURNER

     The  flow  diagram and  material balance  for the  base  case are  shown  in
Figure 25 and Table  12  respectively.   For this study an NOZ reduction  to
0.3  Ib  N02/MBtu,  from the  baseline emission  of  0.6  Ib N02/MBtu,  is
believed  to  be a  conservative  objective compared with the research  goal  of
0.2 Ib N02/MBtu.

     The  500-MW  ALNB system has  40 burners,  each with 4  available tertiary
ports.   The  central burner  operates  at 70% of  the  stoichiometric combustion
air  with an  additional   50%  supplied  at  the  tertiary ports.    The  central
burner, which  is  approximately  40 inches in diameter  at the throat, contains
                                     53

-------
u. / -
0.6 .
4J
CNl
o
& 0.4 .
rH
53
° n •}
H 0 . -J •

H
w 0.2.
o
S3
0.1.
0.06.
0
Single Processes Combination Processes
V* «M

•» ••
^

•••



,__

^



^
I
jjjjjg



ALNB Exxon Hitachi
Zosen




ALNB /Hit
•••M


SsS
1
•

•
m
•
^
:acl
.








li EXJ
^|

M
(
•
1
1
m
i
ui
con/











•:*;•!•§
•
•X'X*
:^
I
«
W

^
H:









tachi Zosen
Zosen Hitachi Zosen
                                    CASES STUDIED
Figure 24.  Assumed NOX reduction for the six cases studied.
                                   54

-------
Ui
Ui
                                                                        ELECTROSTATIC
                                                                        PRECIPITATOR
10
   -g-
     COAL
    Figure 25.  Advanced low-NOx burner flow diagram.

-------
TABLE 12.  ADVANCED LOW-NOX BURNER




        MATERIAL BALANCE
Stream

J
2
j
4
5
ft
7
8
9
10
Description


sft3/min (600E)







1


406.000









2
Coal and air

1.318 400









3
Air feed to
air heater
5 072 900

1.121.300
80






4
Combustion air
to boiler
4 37Q *nn

968.100
Anm
Description
Total stream. Ib/hr

sft3/min (600F)
Temperature, op





6
Air to burners
912.400

201,700
535





7
Flue gas to
economizer
4.772.100

1.003.700






^
Flue gas to
air heater
4.772.100

1.003.700
705





q
Flue gas to
ESP
5.465.500

1.157.000
a oo





in
Flue gas to
F6D unit
5.41«,fion

1.157.000
5 on







1
i
j
4
5
ft
7
8
9
10



1
i
\
4
5
ft
7
8
9
10
Stream
Description
Total stream. Ib/hr

sft3/min (60OF)
Temperature. OF




-














11
Fly ash
from ESP
48.900


























































































































                    56

-------
the  primary annulus,  the  inner  secondary  annulus,  and  the  outer  secondary
annulus.    The  primary  annulus  is  approximately  20  inches  in  diameter  and
contains a  conical diffuser fabricated from an abrasion-resistant metal to mix
the  primary air and entrained  coal  particles.   The  inner  secondary annulus,
which  is  constructed   of  stainless  steel,  contains  stainless  steel  swirl
vanes.   These  swirl  vanes  are  used  to  control mixing  between primary  and
secondary  air.    Additional  combustion  air  is  admitted  through   the  outer
secondary  annulus,   which  is  also  fabricated  from  stainless   steel.    The
tertiary ports, made of  stainless  steel,  are  located approximately  one burner
throat diameter from the central burner.   A compartmented windbox constructed
of carbon steel is used to aid in control of the combustion air flow.

     The  ALNB  design  using  tertiary  ports  may  create  installation  and
structural  support problems when retrofitted on existing boilers.   However, on
a new  boiler,  as  is the case  evaluated in this study, these  problems  may be
avoided by  design of a unit compatible with the ALNB.


EXXON PROCESS

     In  this   study   air  is  used   as  the  carrier   for  the  NH3   (2%
NH3~in-air).  Proprietary  Exxon   gas-phase   mixing  technology   is   used  to
disperse  the  NH3  throughout  the  flue  gas.   An  NH3:NOX  molar  ratio  of
1.5:1  is used  to  obtain  a  50% NOX reduction  efficiency.  N^  breakthrough
(loss  in the flue  gas)  is  approximately 50  ppm.   The Exxon process  is  not
expected  to increase  the  pressure  drop  of  the  boiler system,   therefore no
additional  flue gas  fan capacity is included.   The main  control  criteria are
based on boiler load.

     The  flow  diagram  and material  balance  for the base  case  are  shown in
Figure 26  and Table 13  respectively.   Hydrogen addition  is  not used.   The
Exxon  process   is  divided  into  two processing  sections  and the  equipment
assigned to the appropriate  section.  The  equipment  list  and  descriptions by
area are presented in Table 14.  The total land requirement is one acre.

NH3 Storage and Injection

     In  the NH3 storage and injection section  a compressor  (and spare)  for
unloading liquid NH3  from truck or  rail  transport  and a  sufficient quantity
of 250  psig storage tanks for  a 30-day  supply  are included.   Before  NHg is
injected into the  flue gas,  it is vaporized  in  a shell-and-tube  steam-heated
vaporizer and mixed with 25  psig air  supplied by a compressor.   There is one
vaporizer and  there  are three  air compressors,  two  operating and one spare.
Each  compressor handles 50%  of  the required  capacity.   Two  zoned  injection
grids are included to  accommodate  flue  gas  temperature  changes resulting from
load changes as well  as flue gas  temperature variations  across  the  injection
plane.

Air Preheater Section

     In  the air  preheater  section  two  modified  air  heaters are  provided.
These  incorporate possible changes  in  air  heater design required to  prevent
adverse   operational   effects   from   (^4)2804   and   NH4HS04   deposits
                                     57

-------
     RAIL
     OR
     TRUCK
    HOOK-UP
00
                      AMMONIA
                     STORAGE TANK
UNLOADING
COMPRESSOR
                COAL
                 i
                              STEAM
                                II
                                 NH3
                                 VAPORIZER
                                    8	*_
         Figure 26.  Exxon process flow diagram.
                                                                           AIR

                                                                            I.
                                                                                     VvV

-------
                            TABLE 13.  EXXON

                            MATERIAL BALANCE


•>.
i
t,
5
h
7
K
q
in
Stream
Description

sft3/min (60OF)
Temoeratnre. op
Pressure, psig





1 .
Coal to boiler









2
Combustion air
to air heater

1,121,300
80






3
Combustion air
to boiler

968,100
S3S






4
Gas to
economizer









5
Gas to
air heater

1.048,400
705






Stream
Description
1
2
')
4
5
6
7
H
9
If)
Total stream, Ib/hr

sft3/min (60OF)
Temperature, op
Pressure, psig





«
Gas to ESP
5,666,700

1,201,700
300






7
Gas to
FGD unit
5,«17,800

1,201,700
300






8
Air to idle
injection grid
66,500









9
NH3 and
air to active
injection grid
134,700









10
NH3 from
storage
1.582


110
225





Stream
Description
1
2
j
4
b
b
7
8
9
10
Total stream, Ib/hr

sft3/min (600F)
Temperature, op
Pressure, psig





11
Steam to
vaporizer
1,100


298
50





12
Fly ash
from ESP
48,900













































4
5
6
7
8
9
10
                                  59

-------
                                TABLE 14.  EXXON

                                 EQUIPMENT LIST
Item (number);   description
Total equipment
  cost. 1982 $
Area 1—NH3 Storage and Injection

 1.  Compressor. NH3 unloading (2):  Single cylinder, double          61,500
     acting, 300 sft3/min at 250 psig, 30 psig suction, 125 hp,
     cast iron

 2.  Tank. NH3 storage (9):  Horizontal, 9 ft dia x 66 ft long,      311,900
     30,000 gal, 250 psig, carbon steel

 3.  Vaporizer. NHq (1):  Steam at 298°F, tube type, 29 ft2,           6,900
     0.50 HBtu/hr, carbon steel

 4.  Compressor, air (3):  22,900 aft3/min at 25 psig, 14.7        1,132,800
     psia suction, single stage, 2,250 hp

 5.  Injection grid. NH3 and air (2):                                320,400

 6.  Pump. NH3 (2):  6 gpm, 0.5 hp, 28 ft head, carbon steel           3.000

     Subtotal	1.836.500
Area 2—Air Preheater Section

 1.  Air preheater (2):  Modified, size 29.5 Ljungstrom air
     heater

 2.  Soot blower, steam (2):  20 ft, retractable, hot side
     of air heater, 120 Ib/min steam

     Subtotal	
     509,000
      26.400
     535.400*
     Total, Areas 1-2
  2,371,900
a.  Incremental cost resulting from modification of the air preheater system.
                                      60

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resulting from  NH3  breakthrough.   Two soot blowers,  one  per air  heater,  are
included for  hot-side  air heater  cleaning.   The modified design  also  allows
for the combination of the intermediate and cold temperature  sections into one
continuous  element  as  well  as   a  potentially  different   element  design.
However, only the incremental cost  of  the  modified  air heater,  above costs of
the standard  air  heater, is included  in  the  cost estimate.   These  costs  may
change as further  testing and  evaluations are completed with coal-fired  flue
gas.


HITACHI ZOSEN PROCESS

     This   is  a   dry   NOX  FGT  process   for  the   SCR   of   NOX  with
NH3.  Catalyst  for   the  Hitachi  Zosen process  is  designed to  handle  high
particulate loading  with a pressure drop  of 2  to 3 inches of  %() across  the
reactor.  Therefore, flue gas from a coal-fired  boiler may be  fed  directly to
the reactor upstream of the air heater before  particulate  removal.

     Two base  cases  for  the Hitachi Zosen process  are examined for FGT  on a
500-MW  coal-fired  boiler with  a  0.6  Ib  N02/MBtu baseline  emission.  One  is
90%  NOX reduction  from  0.6 Ib/MBtu  to  0.06  Ib/MBtu  by  treatment  of  the
entire  flue gas stream.   The other  case  is a 50% overall NOX  reduction  from
0.6 Ib/MBtu to  0.3 Ib/MBtu by treatment of a  portion of the  flue  gas at a 90%
NOX  reduction level.   (Economics  for   an   80% NOX reduction  case,   0.3
Ib/MBtu  to  0.06  Ib/MBtu,  are   scaled  from the  90% NOX reduction case.   The
80% reduction case is  used in combination  with the  ALNB and  the Exxon process
to  achieve  an  overall  NOX reduction   of 90%  from  the  0.6  Ib  N02/MBtu
baseline emission.)

     For 90%  NOX reduction  NH3  is  injected   into  the flue  gas   upstream  of
the  reactor  at an  NH3:NOX  molar ratio of 1:1.  Air is  mixed with the  N^
(5% NH3  in  air) to obtain improved mixing with  the  flue  gas.   In  the  reactor
NOX  is  reduced  by  NH3  to  N2  in  the  presence  of  the catalyst  at  a
temperature  between  600°F  and  750°F.   The   area  velocity  (flow  rate  of
gas/surface  area  of  catalyst)  is  24.3  ft3/hr-ft2  for  90%  NOX  removal
requiring 10,734 ft3 of catalyst.

     To  obtain a  net 50%  NOX reduction, 56%  of  the flue  gas   leaving  the
economizer  is  treated for 90%  NOX reduction; the  remaining 44%  of  the  flue
gas is  bypassed around the reactor and recombined with the  treated flue  gas.
Operating  conditions  are  the   same  as the 90%  reduction case stated  above
except catalyst requirements are reduced to 6,105 ft3.

     The NH3  flow  rate  is  automatically  controlled  based  on the flue  gas
flow  rate  to  the  reactor,  reactor inlet  and  outlet NOX concentration,  and
NH3  outlet  concentration.  NH3  level  leaving the  reactor  is  assumed to  be
less  than 10  ppm.    To  prevent   formation of  (^4)804  and NH4HS03  at  low
boiler loads the catalyst bed temperature   is controlled by bypassing a part of
the  high-temperature  flue  gas  flow around  the economizer  to the  reactor.
                                     61

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     The  catalyst  is  manufactured  as  individual  units  which are  joined to
form  the  required catalyst  bed.   Flue gas  passes  parallel  to  the catalyst
surface.   The  catalyst  composition  has  not been  revealed  for proprietary
reasons;  however,  Hitachi Zosen  does  state  that  it  is  constructed of common
material.  The  catalyst life is  assumed  to be  one year because the guarantee
by Hitachi Zosen is only one year (the actual life may be longer).

Process Description (90% NOx reduction)

     The  flow diagram  and material balance for  the 90% NOZ reduction  case
are shown  in Figure  27 and Table 15 respectively.   The Hitachi Zosen 90% NOX
reduction process  is  divided into four processing  sections  and the equipment
assigned to  the  appropriate  section.    The  equipment  list and descriptions by
area are presented in Table 16.  The total  land requirement  is 1.5 acres.

NH3 Storage  and Injection—
     A  compressor  (and  spare)  for unloading liquid  NH3 from  truck  or  rail
transport  and a sufficient quantity of 250  psig  storage tanks to maintain a
30-day  NH3   supply are  included.   Before  NH3  is  injected into  the flue  gas,
it is vaporized  in a  she11-and-tube steam-heated vaporizer and mixed with air
supplied by  a  small  blower to  form  a 5%  N^-in-air mixture.  This is below
the  flammability  limits  for  NH3 in  air  (15.5%  to 27.0%)  and improves  flow
control  and  mixing.    There  is  one  vaporizer and  one air-NH3 blower for  each
of the  two reactor trains with  one additional  air-NH3 blower which serves as
a  spare.   A pump  is  placed between the  NH3 storage  tanks  and the vaporizer
of each train to  aid  in the control  of  NH3 flow.   A  third pump serves  as a
spare.   Two  NH3 injection grids, one  per train,  provide even distribution of
the NH3 in the flue gas before  it enters  the  reactor.

Reactor Section—
     Two  reactors  are  provided,  each  handling  50%  of  the   total  flow.   The
reactors are fixed-bed type  and constructed of carbon steel.   Each  reactor is
provided with fly  ash  hoppers for collection  of deposited fly ash and with two
soot  blowers for  periodic  cleaning.    The  catalyst consists  of  corrugated
plates  contained in units of 1 x 1 z  1  meter  and 0.5 x 1  x 1 meter.  These
units  are  joined to  form  the appropriately sized catalyst bed.   Two monorail
cranes, one  mounted on each reactor,  are  supplied to load and unload  catalyst
units.

Flue Gas Handling—
     A  larger ID fan  is provided downstream  of each  ESP  to  compensate  for the
increased  pressure  drop  created  by   the  FGT  system.    However,  only  the
incremental  cost  attributed  to  the   NOX removal  system is  included  in the
cost  estimates.    Because of the  larger  pressure  drop,  additional costs for
bypass  ducting around  the  ID fan  to prevent boiler implosion are  included  with
gas handling.

Air Preheater Section—
     This  area  description is  the  same as  previously given  for  the  same  area
with  the Exxon process.
                                      62

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U)
     Figure 27.  Hitachi Zosen process (90% NOX reduction)  flow  diagram.

-------
              TABLE  15.  HITACHI  ZOSEN  (90%  NOX REDUCTION)

                            MATERIAL  BALANCE



1
2
j
4
b
6
7
«
9
10
Stream


Total stream. Ib/hr

sft3/min (600F)
Temperature, op
Pressure. psi«





1


406.000









2
Combustion air

5,072,900

1,121,300
80






3
Combustion air

4,379,500

968,100
535






4
Gas to

4,772,100

1,003,700
890






5
Flue gas

4,772,100

1,003,700
705






Stream


2
i
4
5
6
/
«
9
111
Description
Total stream. Ib/hr

sft3/min (6flop)
Temperature, °F
Pressure, psl«





6
Flue gas - NH3
mixture to
reactor
4,807,600

1,011,700
697






7
Gas to
air heater
4,807,600

1,011.800
705






8
Gas to ESP
5,501,000

i, ids, 100
300






9
Gas to
FGD unit
5,452,100

1, 1
6
7
8
9
10
Description
Total stream, Ib/hr

*ft3/min (60<>F)
Temperature, op
Pressure, psig





11
NH3 from
storage
1,055


110
225





12
Steam to
vaporiz-er
730


298
50





13
Fly ash
from ESP
48,900

































 A
 5
 6
T
 8
 9
10
                                     64

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                  TABLE 16.  HITACHI ZOSEN  (90% NOX REDUCTION)

                                 EQUIPMENT LIST
                                                                Total equipment
Item (number);  description	cost. 1982 $

Area 1—NH3 Storage and Injection

 1.  Compressor. NH3 unloading (2):  Single cylinder, double          61,500
     acting, 300 sft3/min at 250 psig, 30 psig suction, 125 hp,
     cast iron

 2.  Tank , NH3 storage (6):  Horizontal, 9 ft dia x 66 ft long,     207,900
     30,000 gal, 250 psig, carbon steel

 3.  Vaporizer. NH3 (2):  Steam at 298°F, tube type, 10 ft2,           7,400
     0.33 MBtu/hr, carbon steel

 4.  Blower. NH3 and air (3):  3,950 aft3/min, AP 15 in. H20,         17,900
     15 hp, carbon steel

 5.  Injection grid. NH3 and air (2):                                 74,600

 6.  Pump. NH3 (3):  2 gpm, 0.5 hp, 28 ft head, carbon steel           4.600

     Subtotal	373.900
Area 2—Reactor Section

 1.  Reactor (2):  55 ft x 33 ft x 41 ft high, 700°F               2,054,200
     operating temperature, carbon steel, insulated, with
     fly ash hoppers

 2.  Soot blower, steam (4):  33 ft, retractable, 870 Ib/min          58,000
     steam

 3.  Reactor crane and hoist (2):  33 ft monorail, 2,500 Ib           56.200
     capacity,  40 ft lift

     Subtotal	2.168.400

                                  (continued)
                                     65

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                              TABLE 16 (continued)
                                                                Total equipment
Item (number);   description	cost. 1982$

Area 3—Flue Gas Handling

 1.  Blower, flue gas (4):  468,261 aft3/min, AP 22 in. HfcO,         467.700
     2,500 hp,  316 stainless steel

     Subtotal	467.70Qa
Area 4—Air Preheater Section

 1.  Air preheater (2):  Modified, size 29.5 Ljungstrom air          509,000
     heater

 2.  Soot blower, steam (2):  20 ft, retractable, hot side of         26.400
     air heater, 120 Ib/min steam

     Subtotal	535.40Qt>


     Total, Areas 1-4                                              3,545,400

a.  Incremental cost resulting from increased flue gas pressure drop.
b.  Incremental cost resulting from modification of the air preheater system.
                                      66

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Process Description (50% NOx reduction)

     The  flow  diagram  and  material balance  for  the  50% NOX  reduction case
are shown  in Figure  28 and Table 17 respectively.   The Hitachi Zosen 50% NOX
reduction process  is  divided  into four processing  sections  and the equipment
assigned to the  appropriate section.   The  equipment  list and descriptions by
area are presented in Table 18.  The total land requirement is 1.5 acres.

NH3 Storage and Injection—
     The NH3  storage and  injection system for  this  case is  similar  to that
previously  described  for  the  same  area  with  the  Hitachi  Zosen  90%  NOX
reduction case.

Reactor Section—
     One reactor is provided handling  56% of  the flue gas leaving the boiler.
This reactor  is the  same as  previously  described for  the  same  area  in the
Hitachi Zosen 90% NOX reduction case.

Flue Gas Handling—
     This area  is  the same as previously  described for the  Hitachi Zosen 90%
NOX reduction case.

Air Preheater Section—
     This area is the same as that described for the Exxon process.
                                      67

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oo
                 I~~7  AMMONIA
                    I STORAGE TANK
       RAIL

      TRUCK
      HOOK-UP   UNLOADING
              COMPRESSOR
NH3
VAPORIZER
    Figure  28.  Hitachi  Zosen process  (50% NO   reduction)  flow diagram.

-------
TABLE 17.  HITACHI ZOSEN (50% NOX REDUCTION)




              MATERIAL BALANCE
Stream

J-
2
)
t,
5
6
7
8

-------
                  TABLE 18.  HITACHI ZOSEN (50% NOX REDUCTION)

                                 EQUIPMENT LIST
                                                                Total equipment
Item (number);   description	cost. 1982 $

Area 1—NH3 Storage and In.iection

 1.  Compressor. NH3 unloading (2):  Single cylinder, double          61,500
     acting, 300 sft3/min at 250 psig, 30 psig suction, 125 hp,
     cast iron

 2.  Tank, NH3 storage (3):  Horizontal, 9 ft dia x 66 ft long,      104,000
     30,000 gal, 250 psig, carbon steel

 3.  Vaporizer. NH3 (1):  Steam at 298°F, tube type, 11 ft2,           3,900
     0.371 MBtu/hr, carbon steel

 4.  Blower. NH3 and air (2):  4,385 aft3/min, AP 15 in. H20,         12,400
     15 hp, carbon steel

 5.  Injection grid. MBh and air (1):                                 37,300

 6.  Pump. NH3 (2):  2 gpm, 0.5 hp, 28 ft head, carbon steel           3.100

     Subtotal	222.200


Area 2—Reactor Section

 1.  Reactor (1):  55 ft x 37 ft x 36 ft high, 700°F               1,027,100
     operating temperature, carbon steel, insulated, with
     fly  ash hoppers

 2.  Soot blower,  steam (2):  37 ft, retractable, 870  Ib/min          31,200
     steam

 3.  Reactor crane and hoist  (1):  37 ft monorail, 2,500 Ib           29.100
     capacity, 35  ft lift

     Subtotal     	1.087.400

                                   (continued)
                                     70

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                              TABLE 18 (continued)
Item (number);  description
Total equipment
  cost, 1982$
Area 3—Flue Gas Handling

 1.  Blower, flue gas (4):  466,814 aft3/min, Ap 21 in. H20,         222.700
     2,250 hp, 316 stainless steel

	Subtotal	222.70Qa
Area 4—Air Preheater Section

 1.  Air preheater (2):  Modified, size 29.5 Ljungstrom air          509,000
     heater

 2.  Soot blower, steam (2):  20 ft, retractable, hot side of         26.400
     air heater

     Subtotal	53S.400b
     Total, Areas 1-4
   2,067,700
a.  Incremental cost resulting from increased flue gas pressure drop.
b.  Incremental cost resulting from modification of the air preheater system.
                                     71

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                            RESULTS AND COMPARISON


     Based on  the design and  economic  premises and on  the  process equipment
for  each process,  the  capital  investment,  in 1982  dollars,  and  the  annual
revenue  requirements, in  1984  dollars,  were determined  for  the  three 50% and
three  90%  NCX   reduction  processes.     Annual   revenue  requirements  were
determined foi  the first  full year  of  operation.   Levelized  annual revenue
requirements were  determined  using  a   10%/year  discount  factor,  a 6%/year
inflation  factor,  and  a  30-year  economic  life.    The  individual  capital
investment and annual revenue requirement tables for each process are shown in
Appendix  A.    Costs  for  the  ALNB  are  differential  costs  representing  the
additional capital investment and annual revenue requirements as compared with
a boiler  design  using standard burners.   Because of  the different  sources of
data, simplifying assumptions made, and the necessity of projecting  costs into
the  future,  these  estimates  are  considered  to be  accurate  to  an overall
variation of -20% to  +40% for  the Exxon  and Hitachi Zosen processes.   For the
ALNB the  estimates  are  considered  to be accurate to an overall  variation of
-20% to +100%.

     The  ALNB, Exxon, and Hitachi  Zosen processes  were  evaluated  at 50% NOX
reduction.   This  degree  of  NOX  reduction  corresponds  to  the  reduction of
NOX emissions *!rom 0.6 to 0.3 Ib N02/MBtu.

     The  ALNB/Hitachi Zosen, Exxon/Hitachi Zosen, and Hitachi  Zosen processes
were evaluated  at  90%  NOX reduction.   This  degree of  reduction  lowers  the
NOX emissions from 0.6 to 0.06 Ib NOx/MBtu.


CAPITAL INVESTMENT

     The  capital  investment  results  for  the  50%  and 90%  NOX  reduction cases
are shown in Table 19.

Fifty Percent NOY Reduction

Advanced Low-N0x Burner—
     The  capital  investment for  the ALNB  is  $2.4M ($4.8/kW),  as  shown in
Table A-l.  Because of the burner's early stage of development, a breakdown of
the direct and indirect  investment is not available.  This  value is  based on
the assumption that the ALNB incremental  costs  are  similar to  the incremental
costs   incurred   for  design  and  application   of   the   dual    register
burner/compartmented  windbox  system instead  of  a  high-turbulence  circular
burner/single  windbox  system.    Since   development  of the  ALNB   is  being
sponsored by EPA, a royalty fee is not charged for the technology.
                                     72

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                 TABLE 19.  SUMMARY OF CAPITAL INVESTMENTS
                                                  Capital
                                                investment,
                                                 mid-19 82$
                 	Process	M$   $/kW

                 50% NOX reduction
                   ALNB                           2.4   4.8
                   Exxon                          9.9  19.7
                   Hitachi Zosen                 15.7  31.4
                 90% NOX reduction
                   ALNB/Hitachi Zosen            25.9  51.8
                   Exxon/Hitachi Zosen           32.1  64.2
                   Hitachi Zosen                 25.5  50.9
Exxon—
     The  capital  investment for  the  Exxon process  is $9.9M ($19.7/kW),  as
shown in  Table  A-3.   Approximately one-third of  the  total  capital  investment
is  for  the  NH3  storage  and  injection  equipment  ($3.3M).   Royalties,  at
$1.5M,  rank  second to  the NI^ storage  and injection system  in  contribution
to  the   total   capital   investment.    The  remaining  $5.1M of  the  capital
investment  is   made  up  of various  smaller charges,  such  as  air  preheater
section ($0.6M),  construction expenses  ($0.6M), allowance  for  startup  and
modifications ($0.6M), and interest during construction ($1.0M).

 Hitachi Zosen—
     The  capital  investment  for the  Hitachi  Zosen  process  is  $15.7M
($31.4/kW),  as  shown  in Table A-5.  Equipment costs  for  the reactor and flue
gas  handling sections  and the  initial  catalyst  charge  cost  are   the  major
contributors.  The reactor section requires $2.2M for a reactor,  soot blowers,
and  a monorail  crane and hoist with  the related accessories.  The  flue  gas
handling  section  contributes  $2.1M to  the total capital investment  to  cover
the  incremental cost  for  larger  fans  resulting  from the  increased  flue  gas
pressure  drop   caused by the  reactor  system   and   for  additional  ductwork
required to route the gas to and from  the reactor.


Ninety Percent NOY Reduction

ALNB/Hitachi Zosen—
     To obtain the capital investment  for the  process combination,  the capital
investment for the ALNB (Table A-l) is added to  the capital  investment for the
Hitachi Zosen 80% NOX reduction  case  (Table  A-7) to obtain the  sum  for  the
combined  processes  (Table A-9).   The  capital   investment  estimated  for  the
combined ALNB and Hitachi  Zosen processes  is $25.9M  ($51.8/kW).   Breakdown of
                                     73

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the  direct  and indirect  investments  is not  shown in Table  A-9 since  these
items are not  available for the ALNB  (see  Table  A-l) .   The  initial  catalyst
charge cost  at $5.0M is the largest  cost item in the  capital  investment.

Exxon/Hitachi Zosen—
     To obtain the capital  investment for the combined processes, the  capital
investment for  the Exxon  process  (Table  A-3)  is  added  to the 80%  reduction
Hitachi Zosen  process  capital  investment (Table A-ll)  to  obtain the  sum  for
the two processes  (Table A-13).

     The  capital  investment  for  the  combined  Exxon and  Hitachi Zosen
processes  is   $32.1M   ($64.2/kW).  The   four  primary  cost   areas  of  the
Exxon/Hitachi  Zosen process  are  NH3  storage  and  injection  ($3.9H),  the
reactor section ($4.2H),  flue  gas  handling ($3.1M), and the  initial  catalyst
charge ($5.0M).

Hitachi Zosen—
     The  capital  investment  for  the Hitachi   Zosen process  is  $25.5M
($50.9/kW),  as  shown in Table A-15.   Three areas contribute the majority of
the capital  investment.   The reactor  section is $4.2M,  the flue gas  handling
section is $3.1M,  and  the initial  catalyst charge cost  is the  largest of  the
three at $6.5M.

Overall Capital Investment Comparison

     A comparison  of the  capital  investments for  each of the 50% and  90%  NOX
reduction alternatives is  shown in Table 20,  along with  identification of  the
major cost components.

     For 50% NOX  reduction, the  wide variation in capital investment is  the
result  of  the  varied  approaches  to  NOX reduction  and  the  equipment
employed.   The ALNB requires different  burners  and different  windbox  and
boiler wall construction.  The incremental  cost differences for these  changes
are  thought  to  be  small.    The  Exxon  process  requires  NH3   storage,
vaporization,  and  carrier air  supply  equipment and installation of  two  NH3
injection grids  in the boiler.   The Hitachi Zosen process requires  similar
NHj storage,  vaporization,  and carrier  air supply equipment and an  injection
grid.    In   addition  it  requires   a  reactor,  catalyst,  and  additional  fan
capacity and  ductwork for routing  flue gas to and  from  the  reactor.

     While Hitachi Zosen has the highest capital investment  for  50%  reduction,
it has  the   lowest  capital investment  for 90% reduction.   The ALNB/Hitachi
Zosen process  is  similar  in cost  for 90% reduction because the Hitachi  Zosen
capital  investment  for 80%  reduction  (0.3  reduced  to  0.06  Ib N(>2/MBtu) is
not  significantly  less  than  for  90%  reduction.   As  in  all  Hitachi  Zosen
capital investments, the  initial  catalyst charge cost is a major contributor.
In the  80%  and 90%  reduction  cases the  difference  in capital investment is
primarily a result of the difference in catalyst requirements.

     As shown in Table 20,  the Exxon  process  requires more  capital  investment
for  the  NH3  storage   and injection   system   than  does  the  Hitachi  Zosen
                                     74

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                   TABLE 20.   CONTRIBUTION OF DIRECT  INVESTMENT,  ROYALTIES, AND  CATALYST TO CAPITAL INVESTMENT
Ln
50% reduction

Direct investment
NH3 storage and injection
Reactor section
Flue gas fans
Air preheater section
Total process capital
Other capital charges
Royalties
Catalyst
Subtotal of process capital,
royalties, and catalyst
Other investments
Total capital investment (TCI)
ALNB a Exxon
% of % of
MS TCI MS TCI

3.3 34
-
-
0.6 6
3.9 40

1.5 15
_ _ _ _

5.4 55
- 4.5 45
2.4 9.9
Hitachi Zosen
% of
MS TCI

0.5
2.2
2.1
0.6
5.4

0.5
3.7

9.8
5.9
15.7

3
14
13
4
34

3
25

62
38

90% reduction
ALNB/ Exxon/
Hitachi Zosena Hitachi Zosen
% of % of
M$ TCI M$ TCI

3.9
4.2
3.1
0.6
11.8

0.5 2 2.0
5.0 19 5.0

5.5 21 18.8
20.4 79 13.3
25.9 32.1

12
13
10
2
37

6
16

59
41

Hitachi Zosen
% of
MS TCI

0.8
4.2
3.1
0.6
8.7

0.5
6.5

15.7
9.8
25.5

3
17
12
2
34

2
26

62
38

     a.   Breakdown of the direct investment  for processes  containing  the ALNB  is  not  available.

-------
process.   This  is because  of  the  larger  NHj  storage  requirements,  larger
carrier air  supply  equipment,  and  the  more complex injection grid system with
the Exxon process.

     The costs of  air  heater modifications,  which are not an inherent part of
the  processes but  may  be required  for  process  application  to  coal-fired
boilers when NIL}  injection  is used  in NOX  control,  are also  included with
the Exxon  and Hitachi Zosen processes.   These modifications  may be required
because of ammonium  salt deposition  in the  air heater.   The  cost  for air
heater modifications  used in  this study are the same for both  the  Exxon and
Hitachi Zosen processes, although the Exxon process has a much higher level of
breakthrough  NH^  and  there is  more  potential for  problems  from the ammonium
salts deposition.

     It should be noted  that  the  royalties are  a  significant  portion of the
capital investment for the Exxon process.  As shown in Table 20,  the royalties
are three times higher than those for the Hitachi Zosen process.

     The capital  investment  for 50% NOZ reduction is considerably  less than
that  for   90% reduction.   The ratio  of  the lowest  90%  reduction  capital
investment  to the  lowest 50%  reduction capital  investment  is   approximately
eleven to one.
ANNUAL REVENUE REQUIREMENTS

     The  annual  revenue  requirements for each of  the  NOX reduction processes
are summarized in Table 21.
               TABLE 21.   SUMMARY OF ANNUAL REVENUE REQUIREMENTS
                                         Annual revenue requirements,
                                                    1984$
First year
Process
50% NOX reduction
ALNB
Exxon
Hitachi Zosen
90% NOZ reduction
ALNB/Hitachi Zosen
Exxon/Hitachi Zosen
Hitachi Zosen
MS

0.45
3.4
8.0

11.5
14.2
13.3
Mills/kWh

0.17
1.2
2.9

4.2
5.2
4.9
Levelized
M$

0.54
5.1
13.0

18.4
22.6
21.9
Mills/kWh

0.20
1.9
4.7

6.7
8.2
7.9
                                      76

-------
Fifty Percent NQy Reduction

Advanced Low-N0x Burner—
     The first-year annual revenue requirements  for  the  ALNB are $0.45M (0.17
mills/kWh), as shown in Table A-2.   Levelized annual revenue requirements are
$0.54M (0.20 mills/kWh).  These  are  incremental  costs  above that required for
presently available dual  register  burner systems capable of  meeting  the 1979
NSPS.  Direct  costs are  low  for the ALNB since utilities  and  raw materials,
which normally contribute most of the direct cost,  are not required.  The only
direct cost is $0.06M  for maintenance,  labor,  and  materials.  Capital charges
are the largest cost item of the annual revenue requirements.

Exxon—
     The  first-year annual  revenue  requirements  for the  Exxon  process  are
$3.4M  (1.2  mills/kWh),   as  shown in  Table  A-4.    Levelized annual  revenue
requirements  are   $5.1M  (1.9  mills/kWh).   Raw materials  and  utilities  are
significant portions  of  the  annual  revenue  requirements.   A total  of 4,351
tons  of  NH3  is  used  each  year at  a  yearly  cost  of  $0.67M.    Utilities  at
$0.76M are also a  major  factor.   However, capital  charges of $1.5M constitute
the largest portion of the annual revenue requirements.

Hitachi Zosen—
     The first-year annual revenue requirements  for  the  Hitachi  Zosen process
are  $8.0M (2.9 mills/kWh),  as  shown in  Table A-6.  Levelized  annual revenue
requirements  are   $13.OM  (4.7  mills/kWh).    Raw  materials cost   ($4.5M),
particularly annual catalyst replacement  cost  ($4.3M),  is the major cost item
for  the  Hitachi  Zosen process.   Capital  charges are also high  at $2.3M,  but
this is significantly lower than the annual cost for replacement catalyst.

Ninety Percent NO* Reduction

ALNB/Hitachi Zosen—
     The annual revenue  requirements for the combined ALNB  and  Hitachi Zosen
processes  are  determined by the  same  method used  to  determine  the capital
investment.  The ALNB annual revenue requirements (Table A-2) are added to the
annual revenue  requirements  for Hitachi  Zosen 80% NOX  reduction (Table A-8)
to obtain the total annual revenue requirements  (Table A-10) for a 90% overall
NOX reduction.

     The  first-year annual  revenue  requirements  for  the  ALNB/Hitachi Zosen
process   are   $11.5M  (4.2  mills/kWh).    The  levelized  annual   revenue
requirements are $18.4  (6.7  mills/kWh).   Annual  catalyst replacement at$5.8M
is  the  largest  contributor  to  the   annual  revenue   requirements  and  the
levelized capital charges are the next highest at$3.8M.

Exxon/Hitachi Zosen—
     The annual revenue requirements for  the  combined  Exxon and Hitachi Zosen
processes  are determined by  adding  the Exxon annual   revenue requirements
(Table A-4)  to the annual  revenue  requirements  of  the  Hitachi  Zosen 80% NOX
reduction case (Table A-12) to obtain the total  annual revenue requirements
(Table A-14) for a 90% overall NOX reduction.
                                      77

-------
     The  first-year  annual revenue  requirements  for the  Exxon/Hitachi  Zosen
process are $14.2M (5.2 mills/kWh).  The levelized annual revenue requirements
are  $22.6M  (8.2  mills/kWh).   The annual catalyst  replacement  cost  and  the
levelized capital charges are the two largest costs associated with the annual
revenue  requirements,  $ 5.8M  and  $4.7M,  respectively,  but NH3  at $0.9M  and
utilities at $1.4H are also significant.


Hitachi Zosen—
     The  first-year annual revenue  requirements for  the  Hitachi  Zosen process
are  $13.3M  (4.9  mills/kWh),  as  shown  in Table  A-16.  The  levelized annual
revenue requirements are $21.9M  (7.9 mills/kWh).   Raw material consumption is
the major contributor  to the  total.   Of the $7.9M  for  raw materials, annual
catalyst  replacement  is  $7.5M   and   is  the  single largest  cost.    Other
significant cost items are the levelized capital charges  ($3.7M)  and utilities
($0.8M).

Overall Annual Revenue Requirements Comparison

     A comparison of  the annual  revenue requirements for  each of  the 50%  and
90%  NOX  reduction   alternatives  is  shown   in   Table  22,   along  with
identification of the major cost components.

     Annual  revenue  requirements   for  50%  NOX reduction processes  follow  the
same trend  as capital  investment, i.e., the ALNB  has  the lowest,  the  Exxon
process  is  intermediate,  and the  Hitachi Zosen process  has  the  highest.  The
ALNB has  the lowest annual  revenue requirements  because  no  raw materials or
utilities are required.  Capital charges constitute most  of the annual revenue
requirements  for  the  ALNB.   This  is in contrast  to  the  Hitachi  Zosen process
in  which  raw  materials,  primarily  replacement catalyst,   are   $4.5M  and
utilities are $0.5M.

     As  in  the 50%  reduction  case,  the annual revenue requirements are lowest
for  the  90%  reduction  process  using  the  ALNB/Hitachi  Zosen process.    The
Hitachi  Zosen process  by  itself  follows and the Exxon/Hitachi  Zosen process
has the highest annual revenue requirements.   By using the ALNB in combination
with the  Hitachi Zosen process, the annual revenue requirements can be reduced
below  those  of  the  Hitachi Zosen  process alone.   The decrease is  a result of
reduced   NHg  consumption,  reduced  replacement  catalyst  requirements,  and
reduced utility requirements.

     Catalyst  replacement   requirements have  a  large  effect  on  revenue
requirements  as  can  be  seen when comparing  the  three  50%  NOX  reduction
cases.   The cost is high  and replacement must be made  annually based on the
Hitachi Zosen guarantee  of a  one-year  catalyst  life for  applications  to coal-
fired  flue gas.  Since a one-year catalyst life is guaranteed  it was used as a
basis  for the cost estimate;  however,  actual catalyst  life  could be longer.
Should   a two-year  life  be  obtainable  for  the   Hitachi  Zosen process  a
significant  savings  can  be   realized  in  the annual   revenue  requirements.
Table  23  shows  that  a  two-year catalyst life will reduce  the  levelized annual
revenue  requirements  of the  Hitachi Zosen  (50%  NOX reduction), ALNB/Hitachi
                                      78

-------
            TABLE 22.  CONTRIBUTION OF RAW MATERIALS AND UTILITIES TO ANNUAL REVENUE REQUIREMENTS

50%
reduction
ALNB Exxon
Hitachi Zosen
% of % of

Raw materials
NH3
Catalyst
Total raw material cost
Utilities
Steam
Electricity
Subtotal of raw materials
and utilities
Other costs
MS RR MS

0.7
-^—
0.7

0.1
0^1

1.5
0.5 100 1^9
RR

21
—
21

3
21

44
56
M$

0.2
4_,3
4.5

0.1
0^

5.1
-L.9
% of
RR

3
54
57

1
_6

64
36
ALNB/
Hitachi Zosen
% of
MS

0.2
5^8
6.0

0.1
0^

6.7
JL*
RR

2
50
52

1
_5

58
42
90% reduction
Exxon/
Hitachi Zosen

M$

0.9

6.7

0.2


8.2
6.0
% of
RR

6
42
48

1


58
42
Hitachi

M$

0.4

7.9

0.1
0^6

8.6
4,1
Zosen
% of
RR

3
56
59

1
_5

65
35
First-year annual revenue
 requirements (RR)

Levelized annual revenue
 requirements
0.5
0.5
3.4
5.1
 8.0
13.0
                                     11.5
18.4
                                          14.2
                                                    22.6
                                               13.3
                                                                                                       21.9

-------
Zosen,  and  Hitachi Zosen   (90%  NOX  reduction)   processes  by  30%  and  the
Exxon/Hitachi  Zosen process by  24%.   Even  though  this  is  a  significant
reduction  in levelized annual  revenue  requirements for  the  processes
containing catalyst, it  is  not  sufficient to change the  cost  relationship of
the processes.   For 50%  NOX reduction the ALNB  is  still lowest  followed by
Exxon  and Hitachi  Zosen and  for 90%  NOX reduction  the ALNB/Hitachi  Zosen
remains the lowest followed by Hitachi Zosen and Exxon/Hitachi  Zosen.
                  TABLE 23.   THE EFFECT OF CATALYST LIFE ON

                         ANNUAL REVENUE REQUIREMENTS
           Process
        Annual
Hitachi Zosen catalyst
 replacement cost. M$
   1-year     2-year
  catalyst   catalyst
    life	life
    Levelized
  annual revenue
requirements. M$
 1-year    2-year
catalyst  catalyst
  life	life
50% reduction
Hitachi Zosen
90% reduction
ALNB/Hitachi Zosen
Exxon/Hitachi Zosen
Hitachi Zosen

4.3

5.8
5.8
7.5

2.1

2.9
2.9
3.7

13.0

18.4
22.6
21.9

9.0

12.9
17.1
14.8
     Since  the  Exxon process  is  a  large  consumer of  NHg  and  electricity
 relative  to  the  ALNB,  the  Exxon/Hitachi  Zosen process  has  annual  revenue
 requirements  that are higher than the ALNB/Hitachi Zosen process.

     The  NH3  consumption  for  the  Exxon  process  is one  and  one-half  times
 that  of the  Hitachi  Zosen 90% NOX reduction process and  almost  three  times
 that  of the Hitachi Zosen 50%  NOX  reduction process.   Therefore,  as shown in
 Table  22,   the  annual  NH3  costs  are  greater  for  the  Exxon  process  than for
 the Hitachi Zosen process  in direct proportion to the consumption of NH3.

     As shown in Table 22, there are  no significant differences in steam and
 electricity costs  for  the  Exxon and Hitachi Zosen processes.  The ALNB has no
 charges for utilities.

     Annual revenue requirements for 50%  NOX reduction are considerably less
 than  that  for 90%  reduction.   The ratio of  the  lowest 90% reduction levelized
 annual  revenue  requirements   to  the  lowest  50%  reduction  levelized  annual
 revenue requirement is approximately 34  to  1.
                                      80

-------
     As  can be  seen in Figure  29, 50%  NOX reduction cost  is  also lower  in
 dollars  per pound  of N(>2  removed,  with  the  exception of  the  Hitachi Zosen
 process.    The main  reason  for  the  lower  cost with  50% NOZ  reduction,  as
 explained  earlier,   is  that the ALNB  and Exxon processes  do not require  the
 expensive  annual   catalyst  replacement  needed  for   the Hitachi  Zosen
 process.    The Hitachi Zosen  50%  NOX reduction case  has a slightly higher
 dollar  per pound  of N(>2  removed  cost  than the  90%  reduction  case  for  two
 reasons.   First,  there  is  some economy of scale in  the capital  investment  for
 the  90%  reduction case compared with  the 50% reduction case.  Therefore,  the
 capital  charges   and  maintenance,  which  are  factored  from  the  capital
 investment, are  a smaller  portion  of  the annual revenue requirements for  the
 90%  reduction  case.   Also,  certain  cost items,  such  as labor,  are the same  for
 both 50% and  90%  reduction cases  making them  a  smaller  cost  (per pound  of
 NOX  basis)  for the 90% reduction case.


 OVERALL  CAPITAL INVESTMENT AND ANNUAL  REVENUE REQUIREMENTS  COMPARISON

     Comparisons  of  the  capital  investment  and  levelized annual  revenue
 requirements   for  each  of  the  six  NOX   control  processes  are  shown   in
 Figures  30 and  31.   Also  included  in  the  figures  are  the effect  of   the
 accuracy   range  on   the  capital   investment   and   levelized annual  revenue
 requirements.

     For 50%   NOX  reduction the  ALNB has  the  lowest capital  investment   and
 levelized  annual revenue  requirements.   The  Exxon process has  the  second
 lowest  and Hitachi  Zosen  has  the  highest  capital  investment  and levelized
 annual revenue requirements.

     The capital  investment of the  ALNB/Hitachi Zosen and  the  Hitachi Zosen
 processes  is   almost  equal  for  90% NOX  reduction,  but the  levelized annual
 revenue  requirements  are   lower  for  the  ALNB/Hitachi  Zosen  process.     In
 comparison  with  the above  two  processes,   the  Exxon/Hitachi  Zosen  process
 capital  investment  is substantially higher;  however,  the  Exxon/Hitachi Zosen
 levelized revenue requirement is comparable.

     Capital   investment   and  levelized  annual   revenue  requirements   are
 significantly  higher  for 90% NOX reduction than for 50% NOX reduction.


ENERGY CONSUMPTION

     Energy consumption  for all  of the  NOX reduction cases  studied  is less
than 1% of the boiler capacity, as shown  in Table 24.  Energy requirements  for
the  three  50% reduction cases  range  from none for the  ALNB to 0.4%  of   the
boiler capacity  for  the Exxon process.   The range  for 90% reduction  is from
0.4%  of  the  boiler  capacity  for  the ALNB/Hitachi Zosen and  Hitachi  Zosen
processes to 0.7% of the boiler capacity  for the Exxon/Hitachi Zosen process.
                                     81

-------
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    CO
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OJ
                           ALNB
                          Exxon
              Hitachi Zosen 50%
ALNB/Hitachi Zosen
            Exxon/Hitachi Zosen
              Hitachi Zosen 90%
                                       I      I
                                            I     I
\      I      I     I      I     I

              50% NOY Reduction
                    A.
                                       I	I
                                                                                         90% NOX Reduction
                                                                                 I      I      I
                                      10    20    30    40    50    60    70    80    90     100    110    120

                                                            CAPITAL INVESTMENT, S/kW
         Figure 30.  Capital investment comparison and accuracy range  (based  on  a  -20%  to +40% range for
                     Exxon an.c Hitachi Zosen processes and a -20% to +100%  range for  the ALNB).

-------
00
    w
    o
    P-I
                        ALNB
                       Exxon
           Hitachi Zosen 50%
          ALNB/Hitachi Zosen
         Exxon/Hitachi Zosen
           Hitachi Zosen 90%
ID
                                                                                     50% NOX Reduction
                                                                                     90% NOY Reduction
                                                                                           A.
                                   123456789    10     11




                                            LEVELIZED ANNUAL REVENUE REQUIREMENTS, mills/kWh
                                                                      12
        Figure 31.   Levelized annual revenue requirements and accuracy range (based on a -20% to +40%

                    range for Exxon and Hitachi Zosen processes and a -20% to +100% range for the ALNB)

-------
                 TABLE 24.  COMPARISON OF ENERGY REQUIREMENTSa
            Process
MBtu/hr
Electricity,
  MBtu/hr
 Total equivalent
energy consumption,b
    percent of
  boiler capacity
 50% Reduction
   Advanced Low-N0x Burner
   Exxon
   Hitachi Zosen
 90% Reduction
  0.0
  5.7
  6.0
     0.0
    11.5
     7.7
       0.0
       0.4
       0.3

ALNB/Hitachi Zosen
Exxon/Hitachi Zosen
Hitachi Zosen


8.0
11.7
10.9

10
21
10
.2
.7
.3


0.4
0.7
0.4


a
b
Does not include energy
. Based on a 500-MW boiler
tion of electricity, and
steam.
requirement represented
, a gross heat rate of 9
a boiler efficiency of
by raw materials.
,500 Btu/kWh for genera-
90% for generation of
     Two  of  the  three  90%  NOX  reduction  processes,  the  ALNB/Hitachi  Zosen
and  the  Hitachi Zosen,  have  estimated  energy consumptions equivalent  to the
Exxon  process   (50%  NOX  reduction)  but  the  Exxon/Hitachi Zosen process  is
higher at 0.7% of the boiler capacity.

     The  NOX  control  alternatives  containing   the  Exxon process  are  the
highest  energy  consumers  at both   the  50%  and  90%  NOX reduction  levels
because  of  energy  consumption  of   the  large  air  compressors   in  the
storage and injection section.
                                     85

-------
                                 CONCLUSIONS
     The  economic  conclusions  of  this  study  are  based  on  NOZ  control
technology  at  various  early  stages  of development  applied to  a new  power
plant.  Further development and retrofit applications could greatly alter hoth
the  absolute  and relative  costs  of the processes.   To develop  accurate  and
timely  economics in  this  rapidly evolving  field,  continued  monitoring  of
developments in NOX control technology is necessary.

     For  moderate  NOX  reduction of  50%,  the  ALNB  is by  far  the most
economical  alternative,   even  if  its   costs  are  to  increase  several  times
relative to the other processes.

     The  Hitachi Zosen  process  has  a higher  capital  investment  than  the
Exxon  process  at  the 50%  reduction level  because  of the  initial  catalyst
charge,  reactor,  additional ductwork,  and additional  fan capacity  required.
It also has higher  revenue  requirements, primarily because of annual catalyst
replacement costs,  although its  NH3 requirements  are much less  than those of
the  Exxon process.   Changes  in  catalyst cost  or  NH3  consumption  or cost
would appreciably affect the cost relationship of these processes.

     The  royalties  for  the Exxon  process are  a  significant portion  of  the
capital investment.

     For  high NOX  reductions  of  90%   the  combination  of  the  ALNB/Hitachi
Zosen  process  is the most  cost  effective  alternative.   Although the  capital
investment  for  the  ALNB/Hitachi  Zosen  process is  slightly  higher than  the
capital   investment   for   the  Hitachi   Zosen  process,  the  annual  revenue
requirements  are substantially  lower.   The  magnitude  of the  difference in
annual  revenue requirements is large enough  to overcome  the slightly higher
capital  investment  and  make  the  ALNB/Hitachi  Zosen  process  the  most
economically attractive.

     The  energy  requirements  for  achieving  50%  and  90% NOX  reduction  are
greater  than  that  required  for  particulate  removal  except  for  the  ALNB.
However,  energy  requirements  for  NOX  reduction  are still modest,  much  less
than 1% of the boiler output,  in comparison with the  energy needed for removal
of S02  from flue gas.

      Catalyst  cost  is  a  very  important  economic  factor  with  an SCR-type
process.   With the Hitachi Zosen  process,  the  catalyst cost may represent as
much as  25%  of the  capital investment and 35% of  the levelized annual revenue
requirement.
                                      86

-------
     Catalyst  life is  also  a  very  important economic  factor.    A two-year
catalyst  life  will reduce  the  levelized  annual  revenue requirements  of the
Hitachi Zosen process by about 30%.

     Since  current  technology  requires  SCR-type  systems  to  achieve  low
emission  levels  (0.06  Ib N02/MBtu),  the  cost for  obtaining  these  low levels
versus  more moderate  emission  levels  (0.3   Ib  N02/MBtu)  are  substantially
greater.   To achieve  low emission  levels as compared  with  moderate levels,
based  on the  most economical  alternatives,  could require  about   a tenfold
increase  in capital  investment and  about  a thirtyfold  increase  in  levelized
annual revenue requirements.
                                      87

-------
                                  REFERENCES
 1.   Jumpei Ando.   NOZ  Abatement for Stationary Sources in Japan.
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 2.   B&W.   Steam/Its Generation and Use.   B&W,  New York, 1975.

 3.   E.  J.  Campobenedetto.   B&W,  Barberton,  Ohio,  Private Communication,  April
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 4.   E.  J.  Campobenedetto.   Field Evaluation of Low Emission Coal Burner
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 5.   C.  Castaldini, K. G.  Salvesen, and H. B. Mason.  Technical Assesment of
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 8.   EPRI.  Technical Assessment Guide. EPRI PS-866-SR, Special Report,
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 9.   H.  L.  Faucett, J. D.  Maxwell, and T. A. Burnett.  Technical Assessment
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10.   M.  H.  Heap,  T. M. Lowes, R.  Walmsley, H. Bartelds, and P. LeVaguerese.
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11.   M.  H.  Heap.   Unpublished data presented at the Second Technology Transfer
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                                     88

-------
12.  P. -H. Jeynes.  Profitability and Economic Choice, First Edition, The
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13.  G. D. Jones.  Selective Catalytic Reduction and NO* Control in Japan,
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14.  KVB, Incorporated.  Assessment of NOX Control Technology for Coal-Fired
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     Argonne National Laboratory, Argonne, Illinois, 1977.

15.  K. J. Lim, L. R. Waterland, C. Castaldini, Z. Chiba, E. B. Higginbotham.
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16.  J. J. Marshall and A. P. Selker.  The Role of Tangential Firing and
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17.  G. B. Martin.  U.S. Environmental Protection Agency, Research Triangle
     Park, North Carolina, Private Communication, April 1980.

18.  G. B. Martin.  Field Evaluation of Low NOx Coal Burners on Industrial
     and Utility Boilers, in:  Proceedings of the Third Stationary Source
     Combustion Symposium, Vol. 1, EPA-600/7-79-050a, U.S. Environmental
     Protection Agency, Washington, B.C., 1979, pp. 213-231.

19.  L. J. Muzio, J. K. Arand, and K. L. Maloney.  Noncatalytic NOx Removal
     with Ammonia, EPRI FP-735, Electric Power Research Institute, Palo Alto,
     California, 1978.

20.  Pollution Control Industry News.  Air/Water Pollution Report,
     December 24, 1979, p. 518.

21.  A. H. Rawdon, R. A. Lisauskas, and F. J. Zone.  Design and Operation
     of Coal-Fired Turbo Furnaces for NOx Control, in:  Proceedings of the
     Second NOX Control Technology Seminar, EPRI FP-1109-SR, Electric Power
     Research Institute, Palo Alto, California, 1979, pp. 6-1 to 6-9.

22.  The Richardson Rapid System.  Process Plant Estimation Standards,
     Vol. I, III, & IV, Richardson Engineering Services, Inc., Solano Beach,
     California, 1978-1979 Edition.

23.  R. E. Thompson.  Nitric Oxide Controls for Coal-Fired Utility Boilers
     from an Application Viewpoint, in:  Proceedings of the Second NOX
     Control Technology Seminar, EPRI FP-1109-SR, Electric Power Research
     Institute, Palo Alto, California, 1979, pp. 9-1 to 9-27.
                                       89

-------
24.  V. W. Uhl.  A Standard Procedure for Cost Analysis of Pollution Control
     Operations, Vol. I & II, EPA-600/8-79-018a&b, U.S. Environmental
     Agency, Washington, D.C., 1979.

25.  U.S. Environmental Protection Agency.  Standards of Performance for New
     Stationary Sources, Federal Register, Vol. 36, No. 247, December 23,
     1971, pp. 24876-24895.

26.  U.S. Environmental Protection Agency.  New Stationary Source
     Performance Standards;  Electric Utility Steam Generation Units,
     Federal Register, Vol. 44, No. 113, June 11, 1979, pp. 33580-33624.

27.  U.S. Environmental Protection Agency.  National Air Pollutant Emission
     Estimates, 1970-1978, EPA-450/4-80-002, 1980.

28.  G. M. Varga, Jr., M. E. Tomsho, B. H. Ruterbories, 6. J. Smith, and
     W. Bartok.  Applicability of the Thermal DeNOx Process to Coal-Fired
     Utility Boilers, EPA-600/7-79-079, U.S. Environmental Protection Agency,
     Washington, D.C., 1979.

29.  G. M. Varga, Jr., Exxon Research and Engineering Company, Linden, New
     Jersey, Private Communication, June 1979.

30.  J. Vatsky.  Experience in Reducing NOx Emissions on Operating Steam
     Generators, in:  Proceedings of the Second NOZ Control Technology
     Seminar, EPRI FP-1109-SR, Electric Power Research Institute, Palo Alto,
     California, 1979, pp. 7-1 to 7-17.

31.  J. Vatsky.  Foster Wheeler Energy Corporation, Livingston, New Jersey,
     Private Communication, March 1980.

32.  P. W. Winkler.  Chemico Air Pollution Control, New York, Private
     Communication, October 1979.

33.  D. M. Zallen, R. Gersham, M. P. Heap, and W. H. Nurick.  The
     Generalization of Low Emission Coal Burner Technology, in:  Proceedings
     of the Third Stationary Source Combustion Symposium, Vol. II,
     EPA-600/7-79-050b, U.S. Environmental Protection Agency, Washington,
     D.C., 1979, pp. 73-109.
                                     90

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                                  APPENDIX A

           CAPITAL INVESTMENT AND ANNUAL REVENUE REQUIREMENT TABLES
     Appendix A contains the capital investment and annual revenue requirement
tables for each of the processes evaluated in this study.
	Process	          Page

Advanced Low-N0x Burner                                                  92

Exxon Thermal DeNOx                                                      94

Hitachi Zosen (50% NOX reduction)                                        96

Hitachi Zosen (80% NOX reduction) to be combined with the ALNB           98

Advanced Low-N0x Burner/Hitachi Zosen                                   100

Hitachi Zosen (80% NOX reduction) to be combined with Exxon             102

Exxon Thermal DeNOx/Hitachi Zosen                                       104

Hitachi Zosen (90% NOX reduction)                                       106
                                      91

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                 TABLE A-l.  CAPITAL INVESTMENT SHEET

                        ADVANCED LOW-NOX BURNER
                                                         Investment. $

     Total fixed investment                                1,888,000


Other Capital Investments

Allowance for startup and modifications                      189,000
Interest during construction                                 295,000
Royalties                                                          0
Land                                                               0
Working capital                                               49.000

     Total Capital investment                              2,421,000

Dollars of total capital per kW of generating capacity           4.8

Basis:  New 500-MY? north-central pulverized-coal-fired power unit;
9,500 Btu/kWh heat rate; 3.5% sulfur, 15.1% ash coal; 0.6 Ib/MBtu N02
equivalent uncontrolled emission; 20% excess air to furnace, 39%
total excess air; 1982 cost basis.  Costs are the difference between
those of the ALNB design and those of a boiler with standard burners.
                                   92

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                           TABLE A-2.  ANNUAL REVENUE REQUIREMENTS

                                   ADVANCED LOW-NOj BURNER
                                                                                     Total
                                                                                     annual
Direct Costs - First Year

Conversion costs
  Operating labor and supervision
  Utilities
    Steam
    Electricity
Maintenance
  Labor and material
Analyses

     Total conversion costs

     Total direct costs

Indirect Costs - First Year

Overheads
  Plant and administrative (60% of
   conversion costs less utilities)
  Marketing
Byproduct credit

     Total first-year operating and
      maintenance costs

Levelized capital charges (14.7% of total
 capital investment)

     Total first-year annual revenue require-
      ments

Levelized capital charges (14.7% of total
 capital investment)
Levelized first-year operating and mainte-
 nance costs (1.886 first-year 0 and M)

     Levelized annual revenue requirements
                                      0
                                      0

                                 61,000
                                 	0

                                 61,000

                                 61,000
                                 98,000


                                356.000


                                454,000
First-year annual revenue requirements
Levelized annual revenue requirements
0.45
0.54
Mills/tWh

   0.17
   0.20
Basis:  Power unit as described in capital investment table, operating 5,500 hr/yr at full
load; 1984 cost basis.  Costs are the difference between those of the ALMS design and those
of a boiler with standard burners.
                                             93

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           TABLE A-3.  CAPITAL INVESTMENT SHEET

                    EXXON THERMAL DENOZ
                                             Investment. $

Direct Investment

NH3 storage and injection                      3,268,000
Air preheater section                            585.000

     Total process capital                     3,853,000

Services, utilities, and miscellaneous           231.000

     Total direct investment                   4,084,000


Indirect Investment

Engineering design and supervision               286,000
Architect and engineering contractor              82,000
Construction expense                             653,000
Contractor fees                                  204,000
Contingency                                    1.062.000

     Total fixed investment                    6,371,000


Other Capital Investments

Allowance for startup and modifications          637,000
Interest during construction                     994,000
Royalties                                      1,526,000
Land                                               5,000
Working capital                                  337.000

     Total capital investment                  9,870,000

Dollars of total capital per VH of generating
 capacity                                           19.7

Basis:  New 500-MW north-central pulverized-coal-fired
power unit; 9,500 Btu/kWh heat rate; 3.5% sulfur, 15.1%
ash coal; 50% NOZ reduction from 0.6 Ib/MBtu N02 equiva-
lent uncontrolled emission; and 20% excess air to furnace,
39% total excess air; 1982 cost basis.
                             94

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                           TABLE A-4.  ANNUAL REVENUE REQUIREMENTS

                                     EXXON THERMAL DENOX
 Direct  Costs - First Year

 Raw materials
  NH3

     Total raw materials cost

 Conversion costs
  Operating labor  and  supervision
  Utilities
    Steam
    Electricity
  Maintenance
    Labor and material
  Analyses

     Total conversion  costs

     Total direct  costs
                                                Annual  quantity
                      Unit
                     cost. $
       4,351 tons
       4,380 man-hr

     27888.7 MBtu
18.460 z 106 kVh
       2,190 man-hr
  155/ton
   15/man-hr

 2.70/MBtu
0.037/kWh
   21/man-hr
                                                                                    Total
                                                                                    annual
                                                                                    cost. S
  674.400

  674,400


   65,700

   75,300
  683,000

  204,200
   46.000

1,074,200

1,748,600
 Indirect Costs - First Year
Overheads
  Plant and administrative  (60% of
   conversion costs less utilities)
  Marketing
Byproduct credit

     Total first-year operating and
      maintenance costs

Levelized capital charges (14.7% of total
 capital investment)

     Total first-year annual revenue require-
      ments

Levelized capital charges (14.7% of total
 capital investment)
Levelized first-year operating and mainte-
 nance costs (1.886 first-year 0 and M)

     Levelized annual revenue requirements
                                      189,500
                                            0
                                     	  0
                                    1,938,100


                                    1.450.900


                                    3,389,000


                                    1,450.900

                                    3.655.300

                                    5,106,200
First-year annual revenue requirements
Levelized annual revenue requirements
       3.4
       5.1
Mills/kWh

    1.2
    1.9
Basis:  Power unit as described in capital investment table, operating 5,500 hr/yr at full
load; 1984 cost basis.
                                            95

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           TABLE A-5.  CAPITAL INVESTMENT SHEET

             HITACHI ZOSEN (50% NOX REDUCTION)
                                             Investment. $

Direct Investment

NH3 storage and injection                        494,000
Reactor section                                2,179,000
Flue gas fans                                  2,131,000
Air preheater section                            585.000

     Total process capital                     5,389,000

Services, utilities, and miscellaneous           323.000

     Total direct investment                   5,712,000


Indirect Investment

Engineering design and supervision               400,000
Architect and engineering contractor             114,000
Construction expense                             914,000
Contractor fees                                  286,000
Contingency                                    1.485.000

     Total fixed investment                    8,911,000


Other Capital Investments

Allowance for startup and modifications          891,000
Interest during construction                   1,390,000
Royalties                                        458,000
Land                                               8,000
Working capital                                  339,000
Catalyst                                       3.681.000

     Total capital investment                 15,678,000

Dollars of total capital per kW of generating
 capacity                                           31.4

Basis:  New 500-MW north-central pulverized-coal-fired
power unit; 9,500 Btu/kWh heat rate; 3.5% sulfur, 15.1%
ash coal; 50% NOZ reduction from 0.6 Ib/MBtu N02 equiva-
lent uncontrolled emission; and 20% excess air to furnace,
39% total excess air; 1982 cost basis.
                           96

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                            TABLE A-6.   ANNUAL REVENUE REQUIREMENTS

                               HITACHI  ZOSEN (50% NOZ Reduction)
Direct Costs - First Year
Raw materials
NH3
Catalyst
Total
Unit annual
Annual quantity cost, $ cost, S
1,612 tons 155/ton 249,900
4.254.100
      Total  raw materials  cost

 Conversion  costs
   Operating labor and supervision
   Utilities
     Steam
     Electricity
   Maintenance
     Labor and  material
   Analyses

      Total  conversion costs

      Total  direct costs
       4,380 man-hr

     29922.2 MBtu
12.368 x 106 kWh
       2,190 man-hr
    15/man-hr

 2.70/MBtn
0.037/kWh
   21/man-hr
4,504,000


   65,700

   80,800
  457,600

  285,600
   46.000

  935,700

5,439,700
 Indirect Costs - First Year

 Overheads
  Plant and administrative (60% of
    conversion costs  less utilities)
  Marketing
 Byproduct credit

     Total first-year operating and
      maintenance costs

 Levelized capital charges (14.7% of total
 capital investment)

     Total first-year annual revenue require-
      ments

 Levelized capital charges (14.7% of total
 capital investment)
 Levelized first—year operating and mainte-
 nance costs (1.886 first-year 0 and M)

     Levelized annual revenue requirements
                                      238,400
                                            0
                                     	0
                                    5,678,100


                                    2.304.700


                                    7.982,800


                                    2.304,700

                                   10.708.900

                                   13,013,600
First-year annual revenue requirements
Levelized annual revenue requirements
     _MJ_

       8.0
     13.0
Mills/kWh

    2.9
    4.7
Basis:  Power unit as described in capital investment table, operating 5,500 hr/yr at full
load; 1984 cost basis.
                                           97

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           TABLE A-7.  CAPITAL INVESTMENT SHEET

             HITACHI ZOSEN (80% NOX REDUCTION)

              (To be combined with the ALNB)
                                             Investment. S

Direct Investment

NH3 storage and injection                        582,000
Reactor section                                4,195,000
Flue gas fans                                  3,051,000
Air preheater section                            585.000

     Total process capital                     8,413,000

Services, utilities, and miscellaneous           505.000

     Total direct investment                   8,918,000


Indirect Investment

Engineering design and supervision               624,000
Architect and engineering contractor             178,000
Construction expense                           1,427,000
Contractor fees                                  446,000
Contingency                                    2.319.000

     Total fixed investment                   13,912,000


Other Capital Investments

Allowance for startup and modifications        1,391,000
Interest during construction                   2,170,000
Royalties                                        458,000
Land                                               8,000
Working capital                                  485,000
Catalyst                                       5.034.000

     Total capital  investment                 23,458,000

Dollars of total capital per kW of generating
 capacity                                           46.9
Basis:  New 500-MW north-central pulverized-coal-fired
power unit; 9,500 Btu/kWh heat rate; 3.5% sulfur, 15.1%
ash coal; 80% NOX reduction from 0.3 Ib/MBtu N02 equiva-
lent emission after 50%' reduction from 0.6 Ib/MBtu N02
equivalent with the ALNB; 20% excess air to furnace, 39%
total excess air; 1982 cost basis.
                           98

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                            TABLE A-8.  ANNUAL REVENUE REQUIREMENTS

                               HITACHI ZOSEN  (80% NOZ Reduction)

                                (To  be combined with the ALNB)
Direct Costs - First Year
Raw materials
NH3
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60% of
conversion costs less utilities)
Marketing
Byproduct credit
Total first-year operating and
maintenance costs
Levelized capital charges (14.7% of total
capital investment)
Total first-year annual revenue require-
ments
Levelized capital charges (14.7% of total
capital investment)
Levelized first-year operating and mainte-
nance costs (1.886 first-year 0 and M)
Levelized annual revenue requirements
Total
Unit annual
Annual quantity cost. $ cost. $
1,306 tons 155/ton 202,400
5,817,700
6,020,100
4,380 man-hr 15/man-hr 65,700
39,532.8 MBtn 2.70/MBtn 106,700
16.471 z 106 kWh 0.037/kWh 609,400
445,900
2,190 man-hr 21 /man-hr 46.000
1,273,700
7,293,800
334,600
0
0
7,628.400
3.448.300
11,076,700
3,448,300
14,387,200
17,835,500
First-year annual revenue requirements
Levelized annual revenue requirements
JLL

11.1
17.8
Mills/kWh

    4.0
    6.5
Basis:  Power unit as described in capital investment table,  operating 5,500 hr/yr at full
load; 1984 cost basis.

                                            99

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                 TABLE A-9.  CAPITAL INVESTMENT SHEET

                 ADVANCED LOW-NOX BURNER/HITACHI ZOSEN
                                                         Investment. $

ALNB fixed investment                                      1,888,000
Hitachi Zosen fixed investment                            13.912.000

     Total fixed investment                               15,800,000
Other Capital Investments

Allowance for startup and modifications                    1,580,000
Interest during construction                               2,465,000
Royalties                                                    458,000
Land                                                           8,000
Working capital                                              534,000
Catalyst                                                   5.034.000

     Total Capital investment                             25,879,000

Dollars of total capital per kW of generating capacity          51.8

Basis:  New 500-MW north-central pulverized-coal-fired power unit;
9,500 Btu/kWh heat rate; 3.5% sulfur, 15.1% ash coal; 90% NOX
reduction from 0.6 Ib/MBtu uncontrolled emission; 20% excess air to
furnace, 39% total excess air; 1982 cost basis.
                                  100

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                           TABLE A-10.   ANNUAL REVENUE REQUIREMENTS

                             ADVANCED LOW-NOX BURNER/HITACHI ZOSEN
Direct Costs - First Year
Raw materials
NH3
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60% of
conversion costs less utilities)
Marketing
Byproduct credit
Total first-year operating and
maintenance costs
Levelized capital charges (14.7% of total
capital investment)
Total first-year annual revenue require-
ments
Levelized capital charges (14.7% of total
capital investment)
Levelized first-year operating and mainte-
nance costs (1.886 first-year 0 and M)
Levelized annual revenue requirements
Total
Unit annual
Annual quantity cost. $ cost. $
1,306 tons 155/ton 202,400
5,817,700
6.020,100
4,380 man-hr 15/man-hr 65,700
39,532.8 MBtn 2.70/MBtn 106,700
16.471 x 106 kWh 0.037/kWh 609,400
506,900
2,190 man-hr 21 /man-hr 46.000
1,334,700
7,354,800
371,600
0
0
7,726,400
3.804,300
11,530,700
3,804,300
14.572.200
18,376,500
First-year annual revenue requirements
Levelized annual revenue requirements
 M$

11.5
18.4
Mills/tWh

    4.2
    6.7
Basis:  Power unit as described in capital investment table, operating 5,500 hr/yr at full
load; 1984 cost basis.


                                            101

-------
           TABLE A-ll.  CAPITAL INVESTMENT SHEET

             HITACHI ZOSEN (80% NOX REDUCTION)

                (To be combined with Exxon)
                                             Investment. $

Direct Investment

NH3 storage and injection                        582,000
Reactor section                                4,195,000
Flue gas fans                                  3.051.000

     Total process capital                     7,828,000

Services, utilities, and miscellaneous           470.000

     Total direct investment                   8,298,000


Indirect Investment

Engineering design and supervision               581,000
Architect and engineering contractor             166,000
Construction expense                           1,328,000
Contractor fees                                  415,000
Contingency                                    2.158.000

     Total fixed investment                   12,946,000


Other Capital Investments

Allowance for startup and modifications        1,295,000
Interest during construction                   2,020,000
Royalties                                        458,000
Land                                               8,000
Working capital                                  457,000
Catalyst                                       5.034.000

     Total capital investment                 22,218,000

Dollars of total capital per kW of generating
 capacity                                           44.4

Basis:  New 500-MW north-central pulverized-coal-fired
power unit; 9,500 Btu/kWh heat rate; 3.5% sulfur, 15.1%
ash coal; 80% NOX reduction from 0.3 Ib/MBtu N02 equiva-
lent emission after 50% reduction from 0.6 Ib/MBtu N02
equivalent with Thermal DeNOz; 20% excess air to furnace,
39% total excess air; 1982 cost basis.
                             102

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                           TABLE A-12.   ANNUAL REVENUE REQUIREMENTS

                               HITACHI  ZOSEN (80% NOZ Reduction)

                                  (To be combined with Exxon)



Direct Costs - First Year
Raw materials
NH3
Catalyst
Total
Unit annual
Annual Quantity cost. $ cost. $


1,306 tons 155/ton 202.400
5.817.700
      Total  raw materials  cost

 Conversion  costs
   Operating labor  and supervision
   Utilities
     Steam
     Electricity
   Maintenance
     Labor and  material
   Analyses

      Total  conversion costs

      Total  direct  costs
       4,380 man-hr

    29,464.2 HBtu
16.471 x 106 kWh
       2,190 man-hr
   15/man-hr

 2.70/MBtu
0.037/kwh
   21/man-hr
6,020,100


   65,700

   79,600
  609,400

  414.900
   46.000

1,215,600

7,235,700
 Indirect Costs - First Year

 Overheads
  Plant and administrative (60% of
    conversion costs  less utilities)
  Marketing
 Byproduct credit

     Total first-year operating and
      maintenance costs

 Levelized capital charges (14.7% of total
 capital investment)

     Total first-year annual revenue require-
      ments

 Levelized capital charges (14.7% of total
 capital investment)
 Levelized first-year operating and mainte-
 nance costs (1.886  first-year 0 and M)

     Levelized annual revenue requirements
                                      316,000
                                            0
                                     	0
                                    7,551.700


                                    3.266.000


                                   10,817,700


                                    3,266,000

                                   14.242.500

                                   17,508,500
First-year annual revenue requirements
Levelized annual revenue requirements
      10.8
      17.5
Mills/kWh

    3.9
    6.4
Basis:  Power unit as described in capital investment table, operating 5,500 hr/yr at full
load; 1984 cost basis.
                                             103

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           TABLE A-13.  CAPITAL INVESTMENT SHEET

             EXXON THERMAL DENOX/HITACHI ZOSEN



                                             Investment. $

Direct Investment

NH3 storage and injection                      3,850,000
Reactor section                                4,195,000
Flue gas fans                                  3,051,000
Air preheater section                            585.000

     Total process capital                    11,681,000

Services, utilities, and miscellaneous           701.OOP

     Total direct investment                  12,382,000


Indirect Investment

Engineering design and supervision               867,000
Architect and engineering contractor             248,000
Construction expense                           1,981,000
Contractor fees                                  619,000
Contingency                                    3.220.000

     Total fixed investment                   19,317.000


Other Capital Investments

Allowance for startup and modifications        1,932,000
Interest during construction                   3,014,000
Royalties                                      1,984,000
Land                                              13.000
Working capital                                  794,000
Catalyst                                       5.034.000

     Total capital investment                 32,088,000

Dollars of total capital per kW of generating
 capacity                                           64.2

Basis:  New 500-HW north-central pulverized-coal-fired
power unit; 9,500 Btu/kWh heat rate; 3.5% sulfur, 15.1%
ash coal; 90% NOZ reduction from 0.6 Ib/MBtu N02 equiva-
lent uncontrolled emission; 20% excess air to furnace,
39% total excess air; 1982 cost basis.
                            104

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                          TABLE A-14.  ANNUAL REVENUE REQUIREMENTS

                              EXXON THERMAL DENOZ/HITACHI ZOSEN


Annual quantity

Unit
cost, $
Total
annual
cost, $
Direct Costs - First Year

Raw materials
  NH3
  Catalyst

     Total raw materials cost

Conversion costs
  Operating labor and supervision
  Utilities
    Steam
    Electricity
  Maintenance
    Labor and material
  Analyses

     Total conversion costs

     Total direct costs
       5,657 tons
       8,760 man-hr

    57,352.9 MBtn
34.931 i 106 kWh
       4,380 man-hr
  155/ton
   15/man-hr

 2.70/MBtu
0.037/kWh
   21/man-hr
  876,800
5.817.700

6,694,500
  131,400

  154,900
1,292,400

  619,100
   92.000

2,289,800

8,984,300
Indirect Costs - First Year

Overheads
  Plant and administrative (60% of
   conversion costs less utilities)
  Marketing
Byproduct credit

     Total first-year operating and
      maintenance costs

Levelized capital charges (14.7% of total
 capital investment)

     Total first-year annual revenue require-
      ments

Levelized capital charges (14.7% of total
 capital investment)
Levelized first-year operating and mainte-
 nance costs (1.886 first-year 0 and M)

     Levelized annual revenue requirements
                                      505,500
                                            0
                                     	0
                                    9,489,800


                                    4.716.900


                                   14,206,700


                                    4,716,900

                                   17.897.800

                                   22,614,700
First-year annual revenue requirements
Levelized annual revenue requirements
      14.2
      22.6
Mills/tWh

    5.2
    8.2
Basis:  Power unit as described in capital investment table, operating 5,500 hr/yr at full
load; 1984 cost basis.
                                              105

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           TABLE A-15.  CAPITAL INVESTMENT SHEET

             HITACHI ZOSEN (90* NOX REDUCTION)



                                             Investment. $

Direct Investment

NH3 storage and injection                        840,000
Reactor section                                4,195,000
Flue gas fans                                  3,051,000
Air preheater section                            585.000

     Total process capital                     8,671,000

Services, utilities,, and miscellaneous           520.000

     Total direct investment                   9,191,000


Indirect Investment

Engineering design and supervision               643,000
Architect and engineering contractor             184,000
Construction expense                           1,471,000
Contractor fees                                  460,000
Contingency                                    2.390.000

     Total fixed investment                   14,339,000


Other Capital Investments

Allowance for startup and modifications        1,434,000
Interest during construction                   2,237,000
Royalties                                        458,000
Land                                               8,000
Working capital                                  522,000
Catalyst                                       6.473.000

     Total capital investment                 25,471,000

Dollars of total capital per kW of generating
 capacity                                           50.9

Basis:   New 500-MW north-central pulverized-coal-fired
power unit; 9,500 Btu/kVh heat rate; 3.5% sulfur,  15.1%
ash coal; 90% NOZ reduction from 0.6 Ib/MBtn N02 equiva-
lent uncontrolled emission; 20% excess air to furnace,
39% total excess air; 1982 cost basis.
                            106

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                          TABLE A-16.  ANNUAL REVENUE REQUIREMENTS

                              HITACHI ZOSEN (90% NOZ Redaction)


Annual Quantity

Unit
cost, $
Total
annual
cost, $
Direct Costs - First Year

Raw materials
  NH3
  Catalyst

     Total raw materials cost

Conversion costs
  Operating labor and supervision
  Utilities
    Steam
    Electricity
  Maintenance
    Labor and material
  Analyses

     Total conversion costs

     Total direct costs
       2,901 tons
       4,380 man-hr

     53860.6 MBtn
16.533 z 106 kWh
       2,190 man-hr
                       155/ton
   15/man-hr

 2.70/MBtu
0.037/kWh
   21/man-hr
                 449,700
               7.479.600

               7.929,300
   65,700

  145,400
  611,700

  459,600
   46.000

1,328,400

9,257,700
Indirect Costs - First Year

Overheads
  Plant and administrative (60% of
   conversion costs less utilities)
  Marketing
Byproduct credit

     Total first-year operating and
      maintenance costs

Levelized capital charges (14.7% of total
 capital investment)

     Total first-year annual revenue require-
      ments

Levelized capital charges (14.7% of total
 capital investment)
Levelized first-year operating and mainte-
 nance costs (1.886 first-year 0 and M)

     Levelized annual revenue requirements
                                      342,800
                                            0
                                     	0
                                    9,600,500


                                    3.744.200


                                   13,344,700


                                    3,744,200

                                   18.106.500

                                   21,850,700
First-year annual revenue requirements
Levelized annual revenue requirements
      13.3
      21.9
Mills/kWh

    4.9
    7.9
Basis:  Power unit as described in capital investment table, operating 5,500 hr/yr at full
load; 1984 cost basis.
                                            107

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                                  APPENDIX B

                        CALCULATION OF PROCESS CAPITAL
     Below is  an  illustration of how the process  capital  is  obtained for the
capital  investment  sheet  from  the  equipment  list.  The  NB^  storage  and
injection area  of the Hitachi Zosen  90%  NOX reduction process is  used  as  an
example.

     The  equipment  list  shown in Table  B-l  represents  the major equipment
items  in  the NH3  storage and  injection  section.   These  equipment  items  are
costed on an erected  basis,  that is, the cost  includes the  labor required  to
place  the  equipment  in  position ready for  operation.   The  total  ($373,900)
represents the  total  untaxed  cost of  the  process equipment and is used as the
basis for estimating the field equipment cost shown in Table B-2.

     As can  be  seen in Table  B-2,  the untaxed field equipment cost (column B)
is  estimated as  a  percentage  (column  A) of the  NH3  storage and injection
process equipment  subtotal  ($373,900).   Untaxed field equipment  cost is then
broken  down  into material  and  labor by using  the  labor  to material  ratio
(column C) .   Materials  (column  D)  are  then  taxed  at 4%  to  obtain sales tax
(column E)  which  is  added to the untaxed  field  equipment  cost  (column  B)
giving the field equipment cost (column F).

     No  taxes  are  charged  to  paint since  material cost   is  insignificant
compared  with  labor  cost.    Concrete  foundations  and  excavation  are  not
factored.    Concrete   is  estimated  for  each  equipment   item  and  then
totaled.  Excavation is based on the quantity of land required.

     Freight and  sales  tax  on process equipment are  also  added  to obtain the
area direct  investment.  The weight of each piece of equipment is approximated
and the total  freight cost  is calculated  on  a cost per weight basis.  A sales
tax of 4% is applied to the materials portion of process equipment.

     The  costs  for process equipment,  field equipment,  freight,  and process
equipment sales tax  are  summed to give  the area  investment  for  NHg storage
and injection.

          Process equipment cost                          $373,900
          Field equipment cost                            $395,500
          Freight (based on estimated equipment weight)   $ 57,300
          Process equipment sales tax                     $ 12.900

          Area  investment                                 $839,600

     The  area  investment  is  then  rounded  to  $840,000  which  is  the  NH3
storage and  injection investment listed in Table A-15.


                                      109

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                 TABLE B-l.  HITACHI ZOSEN (90% NOX REDUCTION)

                                 EQUIPMENT LIST
                                                                Total equipment
Item (number);  description	cost. 1982 $

Area 1—NH3 Storage and Injection

 1.  Compressor. NH3 unloading (2):  Single cylinder, double          61,500
     acting, 300 sft3/min at 250 psig, 30 psig suction, 125 hp,
     cast iron

 2.  Tank . NH3 storage (9):  Horizontal, 9 ft dia x 66 ft long,     207,900
     30,000 gal, 250 psig, carbon steel

 3.  Vaporizer. NH3 (1):  Steam at 298°F, tube type, 10 ft2,           7,400
     0.33 MBtu/hr, carbon steel

 4.  Blower. NH3 and air (3):  3,950 aft3/min, AP 15 in. H20,         17,900
     15 hp, carbon steel

 5.  Injection grid. NH3 and air (2):                                 74,600

 6.  Pump. NH3 (2):  2 gpm, 0.5 hp, 28 ft head, carbon steel           4.600

     Subtotal                                                        373,900
                                     110

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                               TABLE B-2.  BREAKDOWN OF FIELD EQUIPMENT COST



Field equipment
Piping and insulation
Concrete foundations
Excavation, site
preparation roads
Structural
Electrical
Instrumentation
Duct, chutes, expansion
joints
Paint and miscellaneous
Total
A
% of
area 1
subtotal
20
-

-
5
20
15

10
4

B
Untaxed field
equipment cost
(labor + material)
74,780
103,300

-
18,695
74,780
56,085

37,390
14,956

C


Labor /material
1.2
2.756

-
1.7
2.0
0.484

7.0
-

D


Material
33,99ia
27,503

-
6,924
24,927
37,793

4,674
-

E

Sales tax on
material (4%)
1,360
1,100

-
277
997
1,512

187
-

F
Field
equipment
cost
76,100
104,400

10,000
19,000
75,800
57,600

37,600
15.000
395,500
a.   Example calculation of material:
material + labor = untaxed field equipment cost
material + 1.2 material = $74,780
               material = $74,780/2.2 = $33,991

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                               TECHNICAL REPORT DATA
                         (Please read Instructions on the reverse before completing)
1. REPORT NO.
 EPA-600/7-81-120
                                                    3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Evaluation of the Advanced Low-NOx Burner, Exxon,
 and Hitachi Zosen DeNOx Processes
            5. REPORT DATE
            July 1981
            6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
J.D. Maxwell and L.R. Humphries
            8. PERFORMING ORGANIZATION REPORT NO.

            TVA/OP/EDT-81/28
9. PERFORMING ORGANIZATION NAME AND ADDRESS
TVA, Office of Power
Division of Energy Demonstration and Technology
Muscle Shoals, Alabama 35660
            10. PROGRAM ELEMENT NO.
            INE829
            11. CONTRACT/GRANT NO.
            EPA-IAG-79-D-X0511
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; 11/79-6/81	
            14. SPONSORING AGENCY CODE
             EPA/600/13
15. SUPPLEMENTARY NOTES
541-2578.
                   IERL-RTP project officer is J.  David Mobley, Mail Drop 61,  919/
16. ABSTRACT
         The report is a technical discussion and preliminary economic evaluation
of six NOx control methods: three at 50% NOx reduction, and three at 90%. The base-
case power plant is a new 500-MW coal-fired unit emitting 0. 6 Ib NO2/million Btu in
the flue gas.  The three 50% NOx reduction processes are the EPA-sponsored advan-
ced low-NOx burner (ALNB), the Exxon Thermal DeNOx process, and the Hitachi
Zosen process,  which have  capital investments of $4.8,  $19. 7, and $31.4/kW, re-
spectively, and levelized annual revenue requirements of 0. 20, 1. 9, and 4. 7 mills/
kWh, respectively. For 90% NOx reduction, the ALNB process is combined with the
Hitachi Zosen process, the  Exxon process is combined with the Hitachi Zosen pro-
cess, and the Hitachi Zosen process is used alone.  Capital investment and levelized
annual revenue requirements for these three  processes are $51. 8/kW and 6.7 mills/
kWh for the ALNB/Hitachi Zosen process  $64. 2/kW and 8. 2 mills AWh for the
Exxon/Hitachi Zosen process, and $50. 9/kW and 7.. 9 mills/kWh for the Hitachi
Zosen process alone. The ALNB, a combustion  modification, is the least expensive
NOx control method.  As expected, the costs for obtaining high levels  of NOx reduc-
tion (90%) are significantly greater than for more moderate levels (50%).
17.
                            KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
                                         b.IDENTIFIERS/OPEN ENDED TERMS
                        c. COSATI Field/Group
Pollution
Nitrogen Oxides
Coal
Combustion
Pollution Control
Stationary Sources
Advanced Low-NOx Bur-
  ner (ALNB)
Exxon Thermal DeNOx
Hitachi Zosen
Combustion Modification
13 B
07B
08G,21D
21B
13. DISTRIBUTION STATEMENT
 Release to Public
                                         19. SECURITY CLASS (ThisReport)
                                         Unclassified
                        21. NO. OF PAGES

                          140
20. SECURITY CLASS (Thispage)
Unclassified
                        22. PRICE
EPA Form 2220-1 (9-73)
                                     112

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