xvEPA
United States     Industrial Environmental Research  EPA-600/7-79-178h
Environmental Protection  Laboratory          December 1979
Agency        Research Triangle Park NC 27711
Technology Assessment
Report for  Industrial
Boiler Applications:
Particulate  Collection

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-600/7-79-178H

                                         December 1979
 Technology Assessment  Report
for Industrial Boiler Applications:
          Particulate  Collection
                        by

               D.R. Roeck and Richard Dennis

                 GCA/Technology Division
                    Burlington Road
               Bedford, Massachusetts 01730
                 Contract No. 68-02-2607
                     Task No. 19
                Program Element No. INE830
             EPA Project Officer: James H. Turner

           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
                     US EPA

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                                 ABSTRACT
     The report assesses applicability of particulate control technology
to industrial boilers. It is one of a series to aid in determining the
technological basis for a New Source Performance Standard for Industrial
Boilers. It gives current and potential capabilities of alternative par-
ticulate control techniques, and identifies the cost, energy, and environ-
mental impacts of the most promising options. Fabric filters and electro-
static precipitators (ESPs) can exceed 99% control efficiency and can be
used on industrial boilers. A baghouse seems more economical for very small
combustion units or to meet a very stringent emissions requirement when
burning low sulfur coal. An ESP might be more aptly applied to the largest
industrial units, involving intermediate or moderate control levels for
very small boilers and higher sulfur coals. Wet scrubbers are not expected
to be used for,particulate control alone, but might be used to control both
S02 and particulates in the case of modest particulate control levels.
Mechanical collectors could be important for some cases. Control costs
exert a significant impact as boiler size and control level decrease. For
regulatory purposes, this assessment must be viewed as preliminary, pending
relults of the more extensive examinations of impacts called for under
Section III of the Clean Air Act.
                                    ii

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                                   PREFACE


     The 1977 Amendments to the Clean Air Act required that emission

standards be developed for fossil-fuel-fired steam generators.  Accordingly,

the U.S. Environmental Protection Agency (EPA) recently promulgated revisions

to the 1971 new source performance standard (NSPS) for electric utility steam

generating units.  Further, EPA has undertaken a study of industrial boilers

with the intent of proposing a NSPS for this category of sources.  The study

is being directed by EPA's Office of Air Quality Planning and Standards, and

technical support is being provided by EPA's Office of Research and Develop-

ment.  As part of this support, the Industrial Environmental Research Labora-

tory at Research Triangle Park, N.C., prepared a series of technology assess-

ment reports to aid in determining the technological basis for the NSPS for

industrial boilers.  This report is part of that series.  The complete report

series is listed below:

                      Title                                   Report No.

The Population and Characteristics of Industrial/          EPA-600/7-79-178a
  Commercial Boilers

Technology Assessment Report for Industrial Boiler         EPA-600/7-79-178b
  Applications:  Oil Cleaning

Technology Assessment Report for Industrial Boiler         EPA-600/7-79-178c
  Applications:  Coal Cleaning and Low Sulfur Coal

Technology Assessment Report for Industrial Boiler         EPA-600/7-79-178d
  Applications:  Synthetic Fuels

Technology Assessment Report for Industrial Boiler         EPA-600/7-79-178e
  Applications:  Fluidized-Bed Combustion
                                    iii

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                      Title                                   Report No.

Technology Assessment Report for Industrial Boiler         EPA-600/7-79-178f
  Applications:  NOX Combustion Modification

Technology Assessment Report for Industrial Boiler         EPA-600/7-79-178g
  Applications:  NQx Flue Gas Treatment

Technology Asssessment Report for Industrial Boiler        EPA-600/7-79-178h
  Applications:  Particulate Collection

Technology Assessment Report for Industrial Boiler         EPA-600/7-79-178i
  Applications:  Flue Gas Desulfurization

     These reports will be integrated along with other information in the

document, "Industrial Boilers - Background Information for Proposed Standards,1

which will be issued by the Office of Air Quality Planning and Standards.
                                    iv

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                                  CONTENTS






Abstract	     ii




Preface	    iii




Figures	   viii




Tables	     xi




Acknowledgment	xviii




     1.0  Executive Summary	      1




          1.1  Introduction	      1




          1.2  Systems of Emission Reduction for Coal-Fired Boilers. .      3




          1.3  Systems of Emission Reduction for Oil-Fired Boilers  . .     19




          1.4  Systems of Emission Reduction for Gas-Fired Boilers  . .     19




     2.0  Emission Control Techniques.	     20




          2.1  Principles of Control	     20




          2.2  Controls for Coal-Fired Boilers 	     23




          2.3  Controls for Oil-Fired Boilers	     90




          2.4  Controls for Gas-Fired Boilers	     95




          2.5  References	     97




     3.0  Candidates for Best Systems of Emission Reduction	    102




          3.1  Criteria for Selection	    102




          3.2  Best Control Systems for Coal-Fired Boilers	    104




          3.3  Best Control Systems for Oil-Fired Boilers	    Ill




          3.4  Best Control Systems for Gas-Fired Boilers	    114




          3.5  Summary	    114




          3.6  References	    117

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                         CONTENTS (continued)


4.0  Cost Analysis of Candidates for Best Systems of Emission
       Reduction	    118

     4.1  Costs to Control Coal-Fired Boilers	    118

     4.2  Costs to Control Oil-Fired Boilers 	    187

     4.3  Costs to Control Gas-Fired Boilers 	    187

     4.4  Summary	    191

     4.5  References	    196

5.0  Energy Impact of Candidates for Best Emission Control
       Systems	    198

     5.1  Introduction	    198

     5.2  Energy Impact of Controls for Coal-Fired Boilers ....    198

     5.3  Energy Impact of Controls for Oil-Fired Boilers	    224

     5.4  Energy Impact of Controls for Gas-Fired Boilers	    224

     5.5  Summary	    228

     5.6  References	    229

6.0  Environmental Impact of Candidates for Best Systems of
       Emission Reduction	    230

     6.1  Introduction	    230

     6.2  Environmental Impacts of Controls for Coal-Fired Boilers    231

     6.3  Environmental Impacts of Controls for Oil-Fired Boilers     242

     6.4  Environmental Impacts of Controls for Gas-Fired Boilers     242

     6.5  Summary of Major Environmental Impacts of Control
            Techniques	    243

     6.6  References	    244
                                vi

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                          CONTENTS (continued)






7.0  Emission Source Test Data	    245




     7.1  Introduction	    245




     7.2  Emission Source Test Data for Coal-Fired Boilers ....    246




     7.3  Emission Source Test Data for Oil-Fired Boilers	    257




     7.4  Supplemental Test Data	    258




     7.5  Test Methods	    276




     7.6  Accuracy of Test Methods at Lowered Emission Levels.  .  .    281




     7.7  References	    283
                                vii

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                                   FIGURES
Number                                                                   Page

   1    Typical precipitator cross section 	     24

   2    Drop in precipitation rate We with increasing fly ash resis-
          tivity for a representative group of precipitators 	     29

   3    Relation of We to coal sulfur content for flue gas temper-
          atures in the neighborhood of 149°C (300°F) as determined
          by several investigators 	     31

   4    Variation of fly ash resistivity with temperature for coals
          of various sulfur contents	* .  .     34

   5    Fly ash resistivity versus coal sulfur content for several
          flue gas temperature bands	     34

   6    Variation of resistivity with sodium content for fly ash from
          power plants burning western coals 	       34

   7    Emission rate versus specific collector area (SCA) based
          on UARG survey	     41

   8    Actual performance data for Research-Cottrell hot
          precipitators, 1967 to 1976	     43

   9    Measured fractional efficiencies for a cold-side ESP with
          operating parameters as indicated, installed on a pulverized
          coal boiler burning low sulfur coal	     45

   10    Relationship between collection efficiency and specific corona
          power for fly ash precipitators, based on field test data   .     47

   11    Efficiency versus specific corona power extended to high
          collection efficiencies, based on field test data on
          recently installed precipitators 	     47

   12    Isometric view of a two-compartment pulse-jet fabric filter.  .     49

   13    Cutaway view of a reverse air baghouse (courtesy of Western
          Precipitation Division, Joy Industrial Equipment
          Company)	     50

                                   viii

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                             FIGURES (continued)

Number                                                                    page

  14    Predicted and observed outlet concentrations for bench scale
          tests.  GCA fly ash and Sunbury fabric	   62

  15    Penetration versus air-to-cloth ratio for different bag
          materials	   63

  16    Several types of scrubbers used for particulate control  ....   66

  17    Scrubber particulate performance on coal^fired boilers 	   73

  18    Aerodynamic cut diameter versus pressure drop with liquid-to-gas
          ratio as parameter	   74

  19    Variations in fly ash penetration with inlet concentration for
          16 FGD systems presented in Table 24	   81

  20    Multitube cyclone and exploded view of a single tube (courtesy
          of Zurn Industries)	   84

  21    Typical overall collection efficiency of axial-entry cyclones. .   88

  22    Efficiency versus particle size for various multicyclone
          systems	   88

  23    Capital costs of electrostatic precipitators and wet scrubbers
          on new coal-fired utility power plants.  Emission level = 43
          ng/J  (0.1 lb/106 Btu)	120

  24    Capital costs of electrostatic precipitators and wet scrubbers
          on new coal-fired utility power plants.  Emission level = 22
          ng/J  (0.05 lb/106 Btu)	121

  25    Capital costs of electrostatic precipitators and fabric filters
          on new coal-fired utility power plants.  Emission level = 13
          ng/J  (0.03 lb/106 Btu)	122

  26    Approximate break-even point in operating costs between
          baghouses and precipitators for specified sulfur and
          efficiency levels.  (Argonne National Laboratory)	125

  27    Capital investument (April 1978 $) versus system size for
          several coal-fired boilers controlled by fabric filters  ...  127

  28    Total turnkey cost as a function of boiler size for three
          collectors at three emission levels  	  128
                                     rx

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                               FIGURES (continued)

Number                                                                    pag{

  29    Cost-effectiveness of particulate removal as a function of
          boiler size for precipitators and baghouses installed on a
          spreader stoker boiler (based on annualized cost) 	    130

  30    The capital cost of a precipitator as a function of size as
          reported by several manufacturers 	    132

  31    Capital cost of basic equipment (including installation) and
          auxiliaries as a function of system size (reported by Vendor
          A for a pulverized coal boiler)   	    133

  32    Installation cost as a function of system size (reported by
          Vendor A for a pulverized coal boiler)	    134

  33    Annualized cost of an ESP installed on a pulverized coal boiler
         . (58.6 MW or 200 x 106 Btu/hr heat input) as a function of
          emission control level and coal sulfur content  	    192

  34    Annualized cost of an ESP installed on a spreader stoker boiler
          (44 MW or 150 x 106 Btu/hr heat input) as a function of
          emission control level and coal sulfur content  	    193

  35    Annualized cost of an ESP installed on a chain grate stoker
          boiler (22 MW or 75 x 106 Btu/hr heat input) as a function of
          emission control level and coal sulfur content  	    194

  36    Annualized cost of an ESP installed on an underfeed stoker
          boiler (8.8 MW or 30 x 106 Btu/hr heat input) as a function of
          emission control level and coal sulfur content  	    195

  37    Electrical consumption of control equipment on the spreader
          stoker boiler burning 0.6 percent sulfur coal 	    218

  38    Electrical consumption of an electrostatic precipitator on the
          pulverized coal boiler burning three coals  	    219

  39    Electrical consumption of an electrostatic precipitator on the
          spreader stoker boiler burning three coals  	    220

  40    Electrical consumption of an electrostatic precipitator on the
          chain grate stoker boiler burning three coals 	    221

  41    Electrical consumption of an electrostatic precipitator on the
          underfeed stoker boiler burning three coals 	    222

  42    Electrical consumption of an ESP on a residual oil-fired boiler
          burning 3.0 percent S oil	    227

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                                   TABLES


Number                                                                  Page

   1    Standard Boilers Selected for Evaluation 	     4

   2    Design Parameters for a Field-Erected, Water-tube, Pulverized
          Coal-Fired Boiler 	     s
   3    Design Parameters for a Field-Erected, Water-tube, Pulverized
          Coal-Fired Boiler 	

   4    Design Parameters for a Field-Erected, Water-tube, Spreader
          Stoker Coal-Fired Boiler	
   5    Design Parameters for a Field-Erected, Water-tube, Chain Grate
          Stoker Coal-Fired Boiler	      8

   6    Design Parameters for a Package, Water-tube, Underfeed Stoker
          Coal-Fired Boiler 	 	      9

   7    Design Parameters for a Package, Water-tube, Residual Oil-
          Fired Boiler	     10

   8    Design Parameters for a Package, Scotch Fire-tube, Distillate
          Oil-Fired Boiler  	     11

   9    Design Parameters for a Package, Scotch Fire-tube, Natural
          Gas-Fired Boiler	     12

  10    Annualized Costs and Steam Characteristics for Eight "Standard"
          Boilers (Uncontrolled)	     13

  11    Summary Cost and Operating Data for Particulate Control
          Equipment	     15

  12    Uncontrolled Particulate Emissions from "Standard" Industrial
          Boilers	     21

  13    Particle Size Data (urn) Associated with Seven "Standard"
          Firing Methods (Uncontrolled) 	     22

  14    Critical Parameters for Electrostatic Precipitator Operation.     28

  15    Pxange of Basic Design Parameters Found in the Field for Fly
          Ash Precipitators	     30

  16    Summary oi UARG Survey ESP Test Data	     37
                                     xi

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                               TABLES (continued)


Number                                                                   Page

  17    Design and Test Data for Electrostatic Precipitators in
          Operation or Planned for Powerplants Burning North Dakota
          Lignites	    42

  18    Baghouse Installations on Utility Boilers - U.S	    53

  19    Baghouse Installations on Industrial Boilers - U.S	    55

  20    Performance Data for Coal-Fired Utility and Industrial Boilers
          Controlled by Fabric Filters 	    60

  21    Overall Particulate Collection Efficiencies for Various Pres-
          sure Drops in a Spray Scrubber	    75

  22    Summary Data on Particulate Scrubbers Operating on Boilers
          Burning Low-Rank Western U.S. Coals (1976) 	    76

  23    Particulate Scrubber Performance Data for Three Coal-Fired
          Boilers	    77

  24    Wet Scrubber (FGD) Performance for Particulate Control ....    79

  25    Performance Data for Coal-Fired Boilers Equipped with
          Mechanical Collectors .	    89

  26    Oil-Fired Combustion Systems Controlled with Electrostatic
          Precipitators 	    92

  27    Boston Edison Scrubber Tests at Mystic Station - Oil fired
          Boiler No. 6	     96

  28    Applicability of Particulate Emission Control Techniques to
          Achieve a Moderate Emission Level of 107.5 ng/J
          (0.25 lb/106 Btu) for Coal-Fired Industrial Boilers	   105

  29    Applicability of Particulate Emission Control Techniques to
          Achieve a Stringent Level of 12.9 ng/J (0.03 lb/106 Btu) for
          Coal-Fired Industrial Boilers 	   112

  30    Applicability of Particulate Emission Control Techniques to
          Achieve an Intermediate Level of 43 ng/J (0.10 lb/106 Btu)  for
          Coal-Fired Industrial Boilers 	    113

  31    Particulate Control Options and Required Efficiencies ....    115

  32    Summary Capital and Operating Costs for Utility and Industrial
          Boilers Controlled by Fabric Filters 	    126


                                    xii

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                              TABLES (continued)


Number                                                                   Page

 33a    Capital Costs for a Pulse-Jet Fabric Filter (at the Stringent
          Level) Installed on a Pulverized Coal Boiler - 58.6 MW
          (200 x IQ6 Btu/hr) Input	    140

 33b    Annualized Costs for a Pulse-Jet Fabric Filter (at the
          Stringent Level) Installed on a Pulverized Coal Boiler -
          58.6 MW (200 x 106 Btu/hr) Input	    141

 34a    Capital Costs for an Electrostatic Precipitator (at the
          Intermediate Level) Installed on a Pulverized Coal Boiler -
          58.6 MW (200 x IQ6 Btu/hr) Input	    142

 34b    Annualized Costs for an Electrostatic Precipitator (at the
          Intermediate Level) Installed on a Pulverized Coal Boiler -
          58.6 MW (200 x 106 Btu/hr) Input	    143

 35a    Capital Costs for an Electrostatic Precipitator (at the In-
          termediate Level) Installed on a Spreader Stoker Boiler -
          44 MW (150 x 106 Btu/hr) Input	    144

 35b    Annualized Costs for an Electrostatic Precipitator (at the
          Intermediate Level) Installed on a Spreader Stoker Boiler -
          44 MW (150  x  106  Btu/hr) Input	    145

 36a    Capital Costs for a Mechanical Collector (at the Intermediate
          Level) Installed on a Spreader Stoker Boiler - 44 MW
          (150 x 106 Btu/hr) Input	    146

 36b    Annualized Costs for a Mechanical Collector (at the Inter-
          mediate Level) Installed on a Spreader Stoker Boiler -
          44 MW (150 x 106 Btu/hr) Input	    147

 37a    Capital Costs for an Electrostatic Precipitator (at the Inter-
          mediate Level) Installed on an Underfeed Stoker Boiler -
          8.8 MW (30 x 106 Btu/hr) Input	    148

 37b    Annualized Costs for an Electrostatic Precipitator (at the
          Intermediate Level) Installed on an Underfeed Stoker
          Boiler - 8.8 MW (30 x io6 Btu/hr) Input	    149

 38a    Capital Costs for a Mechanical Collector (at the Intermediate
          Level) Installed on an Underfeed Stoker Boiler - 8.8 MW
          (30 x 106 Btu/hr) Input	    150

 38b    Annualized Costs for a Mechanical Collector (at the Inter-
          mediate Level) Installed on an Underfeed Stoker Boiler -
          8.8 MW (30 x 10G Btu/hr) Input	    151

                                     xiii

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                               TABLES (continued)
Number
Page
 39a    Capital Costs for a Pulse-Jet Fabric Filter (at the Stringent
          Level) Installed on a Spreader Stoker Boiler - 44 MW
          (150 x 106 Btu/hr) Input	     152

 39b    Annualized Costs for a Pulse-Jet Fabric Filter (at the Stringent
          Level) Installed on a Spreader Stoker Boiler - 44 MW
          (150 x 106 Btu/hr) Input .	     153

 40a    Capital Costs for a Pulse-Jet Fabric Filter (at the Stringent
          Level) Installed on an Underfeed Stoker Boiler - 8.8 MW
          (30 x 106 Btu/hr) Input	     154

 40b    Annualized Costs for a Pulse-Jet Fabric Filter (at the
          Stringent Level) Installed  on an Underfeed Stoker Boiler  -
          8.8 MW (30 x 106 Btu/hr) Input	     155

 41a    Capital Costs for a Flooded Disc Scrubber (at the Intermediate
          Level) Installed on a Spreader Stoker Boiler - 44 MW
          (150 x io6 Btu/hr) Input	     156

 41b    Annualized Costs for a Flooded Disc Scrubber (at the Inter-
          mediate Level) Installed on a Spreader Stoker Boiler -
          44 MW (150 x 106 Btu/hr) Input	     157

 42a    Capital Costs for an Electrostatic Precipitator (at the Inter-
          mediate Level) Installed on a Spreader Stoker Boiler -
          45 MW (154 x IQ6 Btu/hr) Input (IGCI  Data)	     158

 42b    Annualized Costs for an Electrostatic Precipitator (at the
          Intermediate Level)  Installed on a Spreader Stoker Boiler -
          45 MW (154 x IO6 Btu/hr) Input (IGCI  Data)	     159

 43a    Capital Costs for a Pulse-Jet Fabric Filter (at the Stringent
          Level) Installed on a Spreader Stoker Boiler - 55 MW
          (188 x IO6 Btu/hr) Input (IGCI Data)	     160

 43b    Annualized Costs for a Pulse-Jet Fabric Filter (at the Stringent
          Level) Installed on a Spreader Stoker Boiler - 55 MW
          (188 x IO6 Btu/hr) Input (IGCI Data)	     161

 44a    Capital Costs for a Mechanical Collector (at the Moderate
          Level) Installed on a Spreader Stoker Boiler - 40 MW
          (137 x IO6 Btu/hr) Input (IGCI Data)	     162

 44b    Annualized Costs for a Mechanical Collector (at the Moderate
          Level) Installed on  a Spreader Stoker Boiler - 40 MW
          (137 x IO6 Btu/hr) Input (IGCI Data)	     163

                                     xiv

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                               TABLES (continued)


Number                                                                   Page

 45a    Capital Costs for a Two-Stage Ionizing Wet Scrubber (at the
          Stringent Level) Installed on a Chain Grate Stoker Boiler -
          22 MW (75 x 106 Btu/hr) Input	     164

 45b    Annualized Costs for a Two-Stage Ionizing Wet Scrubber (at the
          Stringent Level) Installed on a Chain Grate Stoker Boiler -
          22 MW (75 x io6 Btu/hr) Input	     165

 46a    Capital Costs for a One-Stage Ionizing Wet Scrubber (at the In-
          termediate Level) Installed on a Chain Grate Stoker Boiler -
          22 MW (75 x IO6 Btu/hr) Input	     166

 46b    Annualized Costs for a One-Stage Ionizing Wet Scrubber (at the
          Intermediate Level) Installed on a Chain Grate Stoker Boiler -
          22 MW (75 x 106 Btu/hr) Input	     167

 47a    Capital Costs for an Electrostatic Precipitator (at the
          Stringent Level) Installed on a Pulverized Coal Boiler -
          58.6 MW  (200 x io6 Btu/hr) Input	     168

 47b    Annualized Costs for an Electrostatic Precipitator (at the
          Stringent Level) Installed on a Pulverized Coal Boiler -
          58.6 MW  (200 x 10s Btu/hr) Input.	     169

 48a    Capital Costs for an Electrostatic Precipitator (at the
          Stringent Level) Installed on a Spreader Stoker Boiler -
          44 MW (150 x 106 Btu/hr) Input	     170

 48b    Annualized Costs for an Electrostatic Precipitator (at the
          Stringent Level) Installed on a Spreader Stoker Boiler -
          44 MW (150 x 106 Btu/hr) Input	     171

 49a    Capital Costs for an Electrostatic Precipitator (at the
          Stringent Level) Installed on a Chain Grate Stoker Boiler -
          22 MW (75 x io6 Btu/hr) Input	     172

 49b    Annualized Costs for an Electrostatic Precipitator (at the
          Stringent Level) Installed on a Chain Grate Stoker Boiler -
          22 MW (75 x IO6 Btu/hr) Input	     173

 50a    Capital Costs for an Electrostatic Precipitator (at the
          Stringent Level) Installed on an Underfeed Stoker Boiler -
          8.8 MW (30 x IQ6 Btu/hr) Input	     174

 50b    Annualized Costs for an Electrostatic Precipitator (at the
          Stringent Level) Installed on an Underfeed Stoker Boiler -
          8.8 MW (30 x IO6 Btu/hr) Input	     175

                                     xv

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                               TABLES (continued)
Number                                                                   Page

 51a    Capital Costs for an Electrostatic Precipitator (at the SIP
          Level) Installed on a Pulverized Coal Boiler - 58.6 MW
          (200 x IQ6 Btu/hr) Input	       176

 51b    Annualized Costs for an Electrostatic Precipitator (at the
          SIP Level) Installed on a Pulverized Coal Boiler -
          58.6 MW (200 x 106 Btu/hr) Input	       177

 52a    Capital Costs for an Electrostatic Precipitator (at the
          SIP Level) Installed on a Spreader Stoker Boiler -
          44 MW (150 x 106 Btu/hr) Input	       178

 52b    Annualized Costs for an Electrostatic Precipitator (at the
          SIP Level) Installed on a Spreader Stoker Boiler -
          44 MW (150 x 106 Btu/hr) Input	       179

 53a    Capital Costs for an Electrostatic Precipitator (at the SIP
          Level) Installed on a Chain Grate Stoker Boiler - 22 MW
          (75 x io6 Btu/hr) Input	       180

 53b    Annualized Costs for an Electrostatic Precipitator (at the
          SIP Level) Installed on a Chain Grate Stoker Boiler -
          22 MW (75 x IO6 Btu/hr) Input	       181

 54a    Capital Costs for an Electrostatic Precipitator (at the SIP
          Level) Installed on an Underfeed Stoker Boiler - 8.8 MW
          (30 x IO6 Btu/hr) Input	       182

 54b    Annualized Costs for an Electrostatic Precipitator (at the
          SIP Level) Installed on an Underfeed Stoker Boiler -
          8.8 MW (30 x IO6 Btu/hr) Input	       183

 55     Costs of "Best" Particulate Control Techniques for Coal-Fired
          Boilers	       185

 56a    Capital Costs for an Electrostatic Precipitator (at the Inter-
          mediate Level) Installed on a Residual Oil-Fired Boiler -
          44 MW (150 x IO6 Btu/hr) Input	       188

 56b    Annualized Costs for an Electrostatic Precipitator (at the
          Intermediate Level) Installed on a Residual Oil-Fired
          Boiler - 44 MW (150 x io6 Btu/hr) Input	       189

 57     Costs of "Best" Particulate Control Technique for a Residual
          Oil-Fired Boiler 	       190
                                    xvi

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                               TABLES (continued)
Number                                                                   Page

  58    Fan and Pump Power Requirements of Particulate Controls for
          Coal-Fired Boilers 	      199

  59    Design Parameters and Energy Consumption of Electrostatic
          Precipitators on Coal-Fired Boilers	      203

  60    Electrical Energy Consumption for Particulate Control Tech-
          niques for Coal-Fired Boilers	      208

  61    Design Parameters and Energy Consumption of an Electrostatic
          Precipitator on the Residual Oil-Fired Boiler	      225

  62    Electrical Energy Consumption for Particulate Control Tech-
          niques for Residual Oil-Fired Boilers	      226

  63    Air, Water, and Solid Waste Pollution Impacts from "Best"
          Particulate Control Techniques for Coal-Fired Boilers. . .      232

  64    Properties of Ash Pond Discharge Waters	      240

  65    Detailed Emission Source Data for Information Presented in
          Table 16	      247

  66    Coal Analyses for Sources Listed in Table 65	      253

  67    Supplemental Particulate Emissions Test Data for Controlled
          and Uncontrolled Fossil Fuel Boilers 	      259

  68    Supplemental Particulate Emissions Test Data for Controlled
          Fossil Fuel Boilers	      270
                                    xvii

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                               ACKNOWLEDGMENT






     The authors would like to express their appreciation to Dr. James H. Turner,




EPA Project Officer, for his advice and technical guidance provided throughout




the project and to the Economic Analysis Branch of EPA for their recommendations




concerning the preparation of Section 4.0.




     We also wish to acknowledge the efforts of numerous individuals at Acurex




Corp., -who were responsible for reviewing the draft sections.




     Special thanks are also directed towards the following members of the




Publications Department at GCA/Technology Division; Alice Christensen, Dorothy




Sheahan, Deborah Stott, Ester Steele, and Judith Wooding.
                                   xviii

-------
                          1.0  EXECUTIVE SUMMARY


1.1  INTRODUCTION

     This technology assessment report is intended to provide background in-

formation relative to particulate emissions control for fossil fuel-fired,

industrial boilers used primarily for steam production.

     Eight industrial-sized boilers have been chosen for evaluation such that

a reasonable cross section of the industrial boiler population is represented.

     Four types of control devices have been selected; i.e., electrostatic

precipitators, fabric filters, multitube cyclones and wet scrubbers; to deter-

mine the potential economic, energy and environmental impacts for each par-

ticle collection system.  These impacts must be addressed as delineated in  the

following excerpt from 40 CFR Part 52.21:

     "Best available control technology means an emission limitation (in-
      cluding a visible emission standard) based on the maximum degree of
      reduction for each pollutant subject to regulation under the act
      which would be emitted from any proposed major stationary source or
      major modification which the Administrator, on a case-by-case basis,
      taking into account energy, environmental, and economic impacts and
      other costs, determines is achievable for such source or modification
      through application of production processes or available methods,
      systems, and techniques, including fuel cleaning or treatment or in-
      novative fuel combustion techniques for control of such pollutant."

     Emission control levels for which these various impacts have been determined

have been specified to allow assessment of the different control techniques at

selected efficiency levels; the arbitrarily chosen values are as follows:

-------
     SIP (average state implementation plan level):




         coal - 258 ng/J (0.6 lb/106 Btu)



         oil  -  43 ng/J (0.1 lb/106 Btu)



     Moderate - 107.5 ng/J (0.25 lb/106 Btu)



     Intermediate - 43 ng/J (0.1 lb/106 Btu)



     Stringent - 12.9 ng/J (0.03 lb/106 Btu)




     In the ensuing discussions of emission control technologies in various



portions of this report, candidate technologies are compared using these three



emission control levels.  These control levels were chosen only to encompass



all candidate technologies and form bases for comparison of technologies for



control of specific pollutants considering performance, costs, energy, and non-



air environmental effects.



     From these comparisons, candidate "best" technologies for control of



individual pollutants are recommended for consideration in any subsequent



industrial boiler studies.  These "best technology" recommendations do not



consider combinations of technologies to remove more than one pollutant and



have not undergone the detailed environmental, cost, and energy impact assess-



ments necessary for regulatory action.  Therefore, the levels of "moderate,



intermediate, and stringent" and the recommendation of "best technology" for



individual pollutants are not to be construed as indicative of the regulations



that might be developed for industrial boilers.  EPA will perform rigorous
                                                              f"
                                                              _s


examination of several comprehensive regulatory options before any decisions



are made regarding standards for emissions from industrial boilers.



     The data presented in this report are directly applicable to the specific



boiler types, sizes, fuels, operating conditions, control devices, and emis-



sion control levels presented herein.  Caution should be exercised when extra-



polating to sets of conditions not specified in this report.


                                      2

-------
     The units selected for evaluation are listed in Table 1 while the de-




tailed design and operating parameters and fuel analyses are given in Tables 2




through 9.   In addition, steam production rates and boiler costs without con-




trols are given in Table 10 for each of these units.  Finally, Table 11 pro-




vides a comprehensive summary of capital, annualized, and operating costs for




60 appropriate boiler/fuel/control level/control device combinations.




1.2  SYSTEMS OF EMISSION REDUCTION FOR COAL-FIRED BOILERS




     In terms of technological capabilities (Section 2.0) , all of the control




devices have been judged acceptable for each of the coal-fired units, although




not at every control level.  For example, electrostatic precipitators have




been shown to be suitable at all control levels for each of the boilers whereas




wet scrubbers and multitube cyclones can only be used where uncontrolled




particle size distributions are high and/or required efficiencies are less




than about 95 percent.  Fabric filters would be suitable only at the stringent




level.  This information is summarized in Section  3.0, Table 31.  In develop-




ing this table, the following factors have been taken into consideration:




all control techniques  including equipment reliability, the range of control




efficiencies achievable based upon particle size by a given device,  the costs




of control, energy consumption as a function of control level and coal sulfur




content, environmental  impacts, potential adverse  or beneficial impacts on




boiler operation and maintenance, and compatibility with other pollutant con-




trol systems or multipollutant control capabilities.




     Control equipment  costs, Section 4.0, have been shown to be inversely pro-




portional to emission  control level, and, in the case of an electrostatic pre-




cipitator, also inversely proportional to coal sulfur content.  Detailed cost




estimates derived from vendor-supplied information indicate an average cost

-------
   TABLE 1.  STANDARD BOILERS SELECTED FOR EVALUATION
                                            Thermal input
      Boiler type                Fuel            MW
                                            (106 Btu/hr)

Field-erected, water-tube  Pulverized coal      117.2
                                                (400)

Field-erected, water-tube  Pulverized coal       58.6
                                                (200)

Field-erected, water-tube, Coal                  44.0
  spreader stoker                               (150)

Field-erected, water-tube, Coal                  22.0
  chain grate stoker                             (75)

Package, water-tube,       Coal                   8.8
  underfeed stoker                               (30)

Package, water-tube        Residual oil          44.0
                                                (150)

Package, Scotch fire-tube  Distillate oil         4.4
                                                 (15)

Package, Scotch firetube   Natural gas            4.4
                                                 (15)

-------
             TABLE 2.   DESIGN PARAMETERS  FOR A FIELD-ERECTED, WATER-TUBE, PULVERIZED COAL-FIRED BOILER
t-n
Boiler configuration
Thermal input, MW (106 Btu/hr)
Fuel

Fuel rate, kg/sec (ton/hr)
  Analysis (as received)
    % sulfur
    % ash
    Heating value, kJ/kg (Btu/lb)
Excess air, %
Flue gas flow rate,  m'/sec  (acfm)
Flue gas temperature,  °C (°F)
Load factor % (hr/yr)
Flue gas constituent,  kg/hr (Ib/hr)
  Fly ash
  S02
  NOX
  CO
  Hydrocarbons as CH^
                                           Field erected, water-tube, pulverized coal
                                              117.2  (400)          117.2  (AGO)
                                              Eastern high
                                              sulfur coal
                                                4.27 (16.95)
     3.5
    10.6
27,447 (11,800)
    30
    70.62 (149,639)
   204° (400°)
    60 (5,256)

 1,304.0 (2,874.72)
 1,022.6 (2,254.35)
   138.4 (305.1)
     7.7 (16.95)
     2.3 (5.09)
                         Eastern medium
                         sulfur coal
                           3.82 (15.14)
     2.3
    13.2
30,733 (13,213)
    30
    71.34  (151,153)
   204° (400°)
    60 (5,256)

 1,450.4 (3,197.57)
   600.2 (1,323.24)
   123.6 (272.52)
     6.9 (15.14)
     2.1 (4.54)
                         117.2  (400)
                         Eastern low
                         sulfur coal
                           3.65 (14.49)
     0.9
     6.9
32,099 (13,800)
    30
    66.79  (141,528)
   177°  (350°)
    60 (5,256)

   725.6 (1,599.70)
   224.8 (495.56)
   118.3 (260.82)
     6.6 (14.49)
     2.0 (4.34)
                         117.2  (400)
                         Subbituminous
                         coal
                           5.25  (20.83)
     0.6
     5.4
22,330 (9,600)
    30
    68.88 (145,950)
   177° (350°)
    60 (5,256)

   816.3 (1,799.71)
   215.4 (474.92)
   170.1 (374.94)
     9.4 (20.83)
     2.8 (6.24)

-------
                  TABLE 3.  DESIGN PARAMETERS FOR A FIELD-ERECTED, WATER-
                            TUBE, PULVERIZED COAL-FIRED BOILER
Boiler configuration
Thermal input, MW (106 Btu/hr)
Fuel

Fuel rate, kg/sec (ton/hr)
Analysis (as  received)
  % sulfur
  % ash
  Heating value, kJ/kg (Btu/lb)
Excess air, %
Flue gas flow rate, m3/sec (acfm)
Flue gas temperature, °C  (°F)
Load factor, %  (hr/yr)
Flue gas constituent, kg/hr  (Ib/hr)
  Fly ash
  S02
  NOX
  CO
Hydrocarbons as
Field-erected, watertube, pulverized-coal
58.6   (200)      58.6   (200)     58.6    (200)
Eastern high
sulfur coal
2.13   (8.47)
3.5
10.6
27,447 (11,800)
30
35.30  (74,800)
204    (400)
60     (5,256)
Eastern low
sulfur coal
Subbituminous
coal
1.83   (7.25)    2.63   (10.42)

0.9              0.6
6.9              5.4
32,099 (13,800)  22,330 (9,600)
30               30
33.32  (70,600)  34.55  (73,200)
177    (350)     177    (350)
60     (5,256)   60     (5,256)
650.74 (1436.51)  362.58 (800.40)  407.83  (900.29)
510.31 (1126.51)  112.32 (247.95)  107.62  (237.58)
69.06  (152.46)   59,12  (130.50)  84.96   (187.56)
3.84   (8.47)     3.28   (7.25)    4.72    (10.42)
1.15   (2.54)     0.99   (2.18)    1.42    (3.13)

-------
              TABLE 4.  DESIGN PARAMETERS FOR A FIELD-ERECTED, WATER-TUBE,
                        SPREADER STOKER COAL-FIRED BOILER
Boiler configuration
Thermal input, MW  (106 Btu/hr)
Fuel

Fuel rate, kg/sec  (ton/hr)
Analysis (as received)
  % sulfur
  7o ash
  Heating value, kJ/kg (Btu/lb)
Excess air, %
Flue gas flow rate, m3/sec  (acfm)
Flue gas temperature, °C  (  F)
Load factor, % (hr/yr)
Flue gas constituent, kg/hr  (Ib/hr)
  Fly ash
  S02
  NOX
  CO
Hydrocarbons as
Field-erected, watertube, spreader  stoker
44.0   (150)      44.0    (150)      44.0    (150)
Eastern high
sulfur coal
1.60   (6.36)
3.5
10.6
27,447 (11,800)
50
30.58  (64,800)
204    (400)
60    (5,256)

397.01 (876.41)
383.18 (845.88)
43.22  (95.40)
5.76   (12.72)
2.88   (6.36)
Eastern low
sulfur coal
Subbituminous
coal
1.37   (5.43)    1.97    (7.81)

0.9              0.6
6.9              5.4
32,099 (13,800)  22,330  (9,600)
50               50
28.69  (60,800)  29.64   (62,800)
177    (350)     177     (350)
60     (5,256)   60      (5,256)

220.64 (487.07)  248.36  (548.26)
84.12  (185.71)  80.67   (178.07)
36.90  (81.45)   53.07   (117.15)
4.92   (10.86)   7.08    (15.62)
2.46   (5.43)    3.54    (7.81)

-------
                         TABLE 5.  DESIGN PARAMETERS  FOR A FIELD-ERECTED, WATER-TUBE,
                                   CHAIN GRATE  STOKER COAL-FIRED BOILER
oo
Boiler configuration
Thermal input, MW (106 Btu/hr)
Fuel

Fuel rate, kg/sec (ton/hr)
Analysis  (as  received)
  % sulfur
  % ash
  Heating value, kJ/kg  (Btu/lb)
Excess air, %
Flue gas flow rate, m3/sec  (acfm)
Flue gas temperature,   C (  F)
Load factor, % (hr/yr)
Flue gas constituent, kg/hr (Ib/hr)
  Fly ash
  S02
  NOX
  CO
Hydrocarbons  as
                                                 Field-erected, watertube, chain grate
                                                 22.0   (75)        22.0   (75)      22.0   (75)
                                                 Eastern high
                                                 sulfur coal
                  Eastern low
                  sulfur coal
                 Subbituminous
                 coal
                                                 0.80   (3.18)      0.69   (2.72)    0.99   (3.91)
3.5
10.6
27,447 (11,800)
50
15.24  (32,300)
204    (400)
60     (5,256)

76.35  (168.54)
191.59 (422.94)
21.61  (47.70)
2.88   (6.36)
1.44   (3.18)
0.9              0.6
6.9              5.4
32,099 (13,800)  22,330 (9,600)
50               50
14.21  (30,100)  14.82  (31,400)
177    (350)     177    (350)
60     (5,256)   60     (5,256)
                                                                   42.51  (93.84)
                                                                   42.14  (93.02)
                                                                   18.48  (40.80)
                                                                   2.46   (5.44)
                                                                   1.23   (2.72)
                 47.82   (105.57)
                 40.38   (89.15)
                 26.57   (58.65)
                 3.54    (7.82)
                 1.77    (3.91)

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                 TABLE 6.  DESIGN PARAMETERS  FOR A PACKAGE, WATER-TUBE,
                           UNDERFEED  STOKER COAL-FIRED BOILER
Boiler configuration
Thermal input, MW  (106 Btu/hr)
Fuel

Fuel rate, kg/sec  (ton/hr)
Analysis  (as received)
  % sulfur
  % ash
  Heating value, kJ/kg (Btu/lb)
Excess air,  %
Flue gas flow rate, m3/sec  (acfm)
Flue gas temperature, °C  ( F)
Load factor, % (hr/yr)
Flue gas constituent, kg/hr  (Ih/hr)
  Fly ash
  S02
  NOX
  CO
Hydrocarbons as
Package, watertube, underfeed
8.8    (30)       8.8     (30)
                 8.8
        (30)
Eastern high
sulfur coal
Eastern low
sulfur coal
Subbituminous
coal
0.32   (1.27)     0.27    (1.09)    0.39    (1.56)
3.5
10.60
27,447 (11,800)
50
6.09   (12,900)
204    (400)
60     (5,256)

30.49  (67.31)
76.52  (168.91)
8.63   (19.05)
1.15   (2.54)
0.58   (1.27)
0.9              0.60
6.90             5.40
32,099 (13,800)  22,330  (9,600)
50               50
5.76   (12,200)  5.90    (12,500)
177    (350)     177     (350)
60     (5,256)   60      (5,256)
17.04  (37.61)
16.89  (37.28)
7.41   (16.35)
0.99   (2.18)
0.49   (1.09)
19.08  (42.12)
16.13  (35.60)
10.60  (23.40)
1.41   (3.12)
0.71   (1.56)

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 TABLE 7.  DESIGN PARAMETERS FOR A PACKAGE, WATER-TUBE,
           RESIDUAL OIL-FIRED BOILER
Boiler configuration
Thermal input, MW (106 Btu/hr)
Fuel
Fuel rate, m3/hr (gal/hr)
Analysis
  % sulfur
  % ash
  Heating value, kJ/kg (Btu/gal)
Excess air, %
Flue gas flow rate, m3/sec (acfm)
Flue gas temperature, °C (°F)
Load factor, % (hr/yr)
Flue gas constituents, kg/hr  (Ib/hr)
  Fly ash
  S02
  NOX
  CO
Hydrocarbons as
Package, watertube
44.0   (150)
Residual fuel oil
3.79   (1,000)

3.0
0.1
43,043 (149,800)
15
22.04  (46,700)
204    (400)
55     (4,818)

14.95  (33.0)
213.36 (471.0)
27.18  (60.0)
2.27   (5.0)
0.45   (1.0)
                           10

-------
  TABLE 8.  DESIGN PARAMETERS FOR A PACKAGE, SCOTCH FIRE-TUBE,
            DISTILLATE OIL-FIRED BOILER
Boiler configuration
Thermal input, MW (106 Btu/hr)
Fuel
Fuel rate, m3/hr (gal/hr)
Analysis
  % sulfur
  % ash
  Heating value, kJ/kg  (Btu/gal)
Excess air, %
Flue gas flow rate, m^/sec  (acfm)
Flue gas temperature, °C  (  F)
Load factor, % (hr/yr)
Flue gas constituent, kg/hr  (Ib/hr)
  Fly ash
  S02
  NOX
  CO
Hydrocarbons as
Package, Scotch firetube
4.4    (15)
Distillate oil
0.41   (108)

0.5
Trace
45,346 (139,000)
15
2.36   (5,000)
177    (350)
45     (3,942)
0.10
3.47
1.08
0.24
0.05
(0.22)
(7.67)
(2.38)
(0.54)
(0.11)
                               11

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  TABLE 9.  DESIGN PARAMETERS FOR A PACKAGE, SCOTCH FIRE-TUBE,
            NATURAL GAS-FIRED BOILER
Boiler configuration
Thermal input, MW (106 Btu/hr)
Fuel
Fuel rate, m3/sec (ft3/hr)
Analysis
  % sulfur
  % ash
  Heating value, MJ/m3 (Btu/ft3)
Excess air, %
Flue gas flow rate, m3/sec (acfm)
Flue gas temperature, °C (°F)
Load factor, % (hr/yr)
Flue gas constituent, kg/hr  (Ib/hr)
  Fly ash
  S02
  NO..
    *V
  CO
Hydrocarbons as
Package, Scotch firetube
4.4    (15)
Natural gas
7.08   (15,000)

Trace
Trace
373    (1,000)
15
2.45   (5,200)
177    (350)
45     (3,942)

0.07   (0.15)
0.005  (0.01)
1.19   (2.63)
0.12   (0.26)
0.02   (0.05)
                               12

-------
u>
                       TABLE  10.   ANNUALIZED COSTS AND STEAM  CHARACTERISTICS FOR EIGHT "STANDARD"
                                     BOILERS  (UNCONTROLLED)
Boiler type
heat, input,
MW
(106 Btu/hr)
and fuel type
Steam
conditions
kPa/°C
(psig/°F)
Steam
enthalpy
kJ/kg
(Btu/lb)
Steam
production
rate*
kg/hr
(Ib/hr)
Total
annualized cost of
uncontrolled boiler
($)
Steam cost
based upon
steam output
$/103 kg ($/103 Ib)
Steam cost
based upon net
thermal output
of steam
$/103 J ($/106 Btu)
Pulverized Coal
     117.2

     (400)

Eastern high sulfur
Eastern medium sulfur  5171/399     3195     127,772
Eastern low sulfur    (750/750)     (1375)   (281,690)
Subbituminous

      58.6

     (200)

Eastern high sulfur
Eastern medium sulfur  5171/399     3195      63,887
Eastern low sulfur    (750/750)     (1375)   (140,845)
Subbituminous

Spreader Stoker

      44.0

     (150)

Eastern high sulfur
Eastern medium sulfur  3103/316     3025      51,000
Eastern low sulfur    (450/600)    (1302)   (112,434)
Subbituminous

Chain Grate Stoker

      22.0

      (75)
                                                                      7,783,600
                                                                      7,840,700
                                                                      8,109,500
                                                                      7,930,000
                                                                      4,247,700
                                                                         NA
                                                                      4,380,000
                                                                      4,368,600
                                                                      3,075,000
                                                                         NA
                                                                      3,186,300
                                                                      3,121,100
11.60 (5.26)
11.68 (5.30)
12.08 (5.48)
11.82 (5.36)
12.65 (5.74)

13.05 (5.92)
13.01 (5.90)
11.46 (5.20)

11.88 (5.39)
11.64 (5.28)
4.13
4.16
4.30
4.21
4.50

4.65
4.64
4.35

4.50
4.42
(4.36)
(4.39)
(4.54)
(4.44)
(4.75)

(4.90)
(4.89)
(4.59)

(4.75)
(4.66)
Eastern high sulfur
Eastern medium sulfur
Eastern low sulfur
Subbituminous

1034/186
(150/366)


2779
(1196)


28
(62


,129
,014)

1,851
1,861
1,893
1,865
,200
,500
,900
,800
12.
12.
12.
12.
52
59
81
61
(5.68)
(5.71)
(5.81)
(5.72)
5.23
5.27
5.36
5.28
(5.52)
(5.56)
(5.65)
(5.57)
                                                             (continued)

-------
                                        TABLE  10  (continued)

Boiler type
heat input,
MW
(106 Btu/hr)
and fuel type
Underfeed Stoker
8.8
(30)
Eastern high sulfur
Eastern medium sulfur
Eastern low sulfur
Subbituminous
Residual Oil
44.0
(150)
3.0% S
Distillate Oil
4.4
(15)
0.5% S
Natural Gas
4.4
(15)
trace sulfur
Steam
conditions
kPa/°C
(psig/°F)


1034/186
(150/366)

5171/399
(750/750)

1034/186
(150/366)

1034/186
(150/366)
Steam
enthalpy
U/hr
(Btu/lb)


2779
(1196)

3195
(1375)

2779
(1196)

2779
(1196)
Steam
production
rate*
kg/hr
(Ib/hr)


11,251
(24,805)

47,915
(105,634)

5,626
(12,403)

5,626
(12,403)
Total "earn C08t
annualited cost of *ased UP°"
uncontrolled boiler 8team output
(§) $/103 kg ($/103 Ib)


952,300 16.09 (7.30)
NA - -
957,900 16.20 (7.35)
976,900 16.51 (7.49)

2,527,200 10.96 (4.97)


558,600 25.20 (11.43)


496,000 22.35 (10.14)

Steam cost
based upon net
thermal output
of steam
$/103 J ($/106 Btu)


6.74 (7.11)
6.78 (7.15)
6.91 (7.29)

3.90 (4.11)


10.53 (11.11)


9.36 (9.87)


Steam production rate calculated by assuming a boiler efficiency of  85 percent and a feedwater enthalpy of
390 kJ/kg (168 Btu/lb) at 93°C (200°F).

NA - Not available.

-------
TABLE 11.  SUMMARY COST AND OPERATING  DATA FOR PARTICULATE CONTROL EQUIPMENT
Boiler type
J1'"1"'"1',, , Flow rtu Control
MW (106 Btu/hr> , ,*
Fuel nVhr (act*)
* S i Ash
A. Pulverized Coal
58.6 (200)
3.5 10.6 1.27«10S (74,800) S
S
I
SIP
0.9 6.9 1.2xlOs (70,600) S
S
I
SIP
0.6 5.4 1.24«105 (71,200) S
S
I
SIP
8. Spreader Stoker
44 (150)
3.5 10.6 1.1*10S (64,800) S
S
I
I
M
SIP
0.9 6.9 1.03*105 (60,800) S
S
I
I
M
SIP
0.6 5.4 1.07xl05 (62,800) S
S
I
I
M
SIP
Control
effi-
ciency
(*)

99.58
99. SB
98.61
91.64
99.25
99.25
97.50
85.0
99.33
99.33
97.78
86.67

99.5
99.5
98.3
98.3
95.72
89.73
99.1
99.1
96.92
96,92
92.31
81.54
99.18
99,18
97.27
97.27
93.17
83.61
Control
device'1'

FF
ESP
ESP
ESP
FF
ESP
ESP
ESP
FF
ESP
ESP
ESP

FF
ESP
ESP
FDS
MC
ESP
FF
ESP
ESF
ros
MC
ESF
FF
ESP
ESP
FDS
MC
ESP
Capital Investment
$

986,823
767,280
680,647
435,238
969,927
1,231,8110
1,183,172
870,061
972,658
1,279,726
1,190,957
1,032,921

794,508
665,558
553,094
572,648
100,369
345,427
7S4.10S
1,154,789
1,062,224
562,418
100,199
705,365
785,803
1,163,651
1,135,079
564,028
100,267
881,421
$/m3/hr

7.77
6.04
5.36
3.43
8.09
10.27
9.86
7.25
7.82
10.29
9.58
8.30

7.22
6.04
5.03
5,20
0.91
3.14
7.59
11.18
10.28
5,44
0.97
6.83
7.36
10.91
10.64
5.29
0.94
8.26
($/acfm)

13.19
10.26
9.10
5.82
13.74
17.45
16.76
12.32
13.29
17. 48
16.27
14.11

12.26
10.27
B.54
6.84
1.55
5.33
12.90
18.99
17.47
9.25
1.65
11.60
12.51
18.53
18.07
8.98
1.60
14.04
Annuallzed cost!
$

330,223
279,168
262,690
210,718
262,638
301,103
288,719
222,345
273,564
322,358
302,604
260,991

239,292
205,330
184,982
278,644
26,717
141,961
197,694
254,706
235,782
237,724
26,039
165,260
204,473
264,911
256,071
244, M
26,310
201,827
S/103 kg

96.64
81.70
77.61
67.01
138.42
158.71
154.92
136.79
128.05
150.89
143.91
139.98

114.90
98,58
102.86
135.39
-
75.58
171.50
220.96
232.07
210.72
-
174.13
157.40
203.92
221.55
ISl.i?
-
184.24
($/ton)

87.85
74.27
70.56
60.92
125.84
144.28
140.84
124.35
116.41
137.17
130.83
127.25

104.45
89.62
93.51
123.08
-
68.71
155.91
200.87
210,98
191.56
-
156.30
143.09
185.38
201.41
174.15
-
167.49
Annual
5

177,796
162,589
159,807
146,415
110,211
108,323
103,503
86,347
121,137
122,511
116,672
99,564

115,230
102,562
100,038
162,239
11,255
89,703
73,632
72,779
68,435
121,319
10,577
54,223
80,411
81,937
77,473
127,759
10.848
63,083
operating coat *"•»«!' """""P"""5
S/m3/hr

1.40
1.28
1.26
1.15
0.92
0.90
0.86
0.72
0.98
0.99
0.94
0.80

1.05
0.93
0.91
1.47
0.10
0.82
0.71
0.71
0.66
1.18
0.10
0.53
0.75
0.77
0.73
1.20
0.10
0.59
(S/acfm)

2.38
2.17
2.14
1.96
1,56
1.53
1.47
1.22
1.65
1.67
1,59
1.36

1.78
1.58
1.54
2.50
0,17
1.38
1.21
1.20
1.13
2.00
0.17
0,S9
1.28
1.30
1.23
2,03
0.17
1.00
kw

95.4
31.7
26.4
18.4
90.2
99.3
77.2
44.4
93.2
124.0
9*. 5
55.8

82.6
26.7
22.0
231.2
82.6
15.1
77.6
82.4
63.2
151.7
77.6
35.3
80.1
102.1
78.6
224.0
80.1
43.9
X of
heat Input

0.164
0.055
0.044
0.031
0.154
0.171
0.133
0.075
0.160
0.212
0.165
0.096

0.188
0.061
0.051
0.525
0.188
0.034
0.177
0.187
0.143
0.344
0.177
0.082
0.181
0.232
0.177
0.508
0.181
0.099
Solid
g/sec

180
180
179
166
100
100
98
B6
113
113
111
98

110
110
109
109
106
99
61
51
60
60
57
50
69
69
67
67
64
58
waste

-------
                                                         TABLE  11  (continued)
Boiler type
«,h"0«Hr> "~ »» «-«.* ^I!1
TMi .»/hr racbn cl««*
• /HI teem] ...i
	 C»;
X S X Alh
35 (188) .
0.8 7.5 1.48»10S (17,100) S 99.7
45 (154)
0.8 7.3 1.41»10S (83,100) I 97.3
C. Chain Crate
Stoker
22 (73)
3.5 10.6 5.49»10* (32,300) S 98.67
S 98.67
I 95.56
SIP 73.33
0.9 6.9 5.1«10* (30,100) S 97.6
S 97.6
I 92.0
SIP 32.0
0.6 5.4 5.34«10U (31,400) S 97.87
S 97.87
I 92.91
SIP 57.45
Control
device1
rr
ESP

ESP
IWS
IH8
ESP
ESP
IWS
IWS
ESP
ESP
IWS
IWS
ESP
I Capital lavettMnt
$
380,908
731,114

306,711
1,000,061
, 483,179
105,026
723,868
998,040
483,189
183.897
831,551
998,374
483,506
262,924
"•'""
3.93
3.19

3.59
18.22
8.84
1.91
14.16
19.32
9.45
3.60
13.59
18.72
9.06
4.93
(1/acfO
6.67
8.82

9.50
30.96
13.02
3.25
24.05
33.16
16.03
6.11
26.48
31.80
15.40
8.37
Annu
$
244,277
212,202

72,586
283,314
152,222
34,034
137,242
277,229
144,260
40,169
137,352
278,565
145,528
54,835
allied coi
»/10> kg
143.16
135,41

182.71
718.18
395.83
115.19
626.42
1,265.36
699.06
343.20
638.69
1,130.71
622.89
379.36
itt Annual operating coat
<$/ton>
130.14
141.28

166.10
652.89
339.86
104.72
569.47
1.150.33
635.51
313.82
580.63
1,027.92
566.26
344.87
$
141,282
88,282

23,854
73,460
49,788
17,185
21,956
67,375
41,826
10,483
25,026
68,711
43,094
12,641
Energy eonatnption'
l/ei'/hr (f/acf») kN
0.93
0.63

0.43
1.37
0.91
0.31
0.43
1.32
0.82
0.21
0.47
1.29
0.81
0.24
1.62
1.06

0.74
2.34
1.54
0.53
0.73
2.24
1.39
0.33
0.80
2.19
1.37
0.40
138.7
141.7

11.2
115.0
115.0
5.7
32.8
107.2
75.2
10.1
40.9
111.8
78.4
12.7
X of
heat Input
0.252
0.315

0.051
0.322
0.522
0.027
0.150
0.488
0.341
0.044
0.188
0.508
0.338
0.058
Solid waite
g/aec
90
72

21
21
20
16
12
12
11
6
13
13
12
8
(Ib/hr)
714
572

167
167
162
124
92
92
87
49
104
104
99
61
    40   (137)
    ITs~                       M     97.0     MC      226,080    1.81    3.08  195,060     58.16   52.88 163,376   1.31   2.23   98.5     0.246     177   1404

D.  Underfeed  Stoker
   8.8  (30)
3.5 10.6 2.2X1011 (12,900) S
S
I
M
SIP
0.9 6.9 2.07xlOu (12,200) S
S
I
M
SIP
98.66
98.66
95.54
88.84
73.21
97.6
97.6
92.0
80.0
52.0
nr
ESP
ESP
MC
ESP
n
ESP
ESP
MC
ESP
242,571
131,435
96,517
51,745
44,906
241,764
348,001
242,085
51,718
78,332
11.07
6.00
4.40
2.3(5
2.03
11.67
16.79
11.68
2.30
3.79
18.80
10.19
7.48
4.01
3.48
19.82
28.52
19.84
4.24
6.44
57,948
32,501
26,360
10,506
16,113
54,719
66,633
48,329
10,397
18,910
364.24
204.29
239.95
-
136.35
620.52
7M.85
709.87
-
407.86
331.13
183.72
218.14
-
123.93
564.11
687.14
645.34
-
370.78
17,923
11,197
10,598
2,404
8,492
14,694
10,820
9,316
2,295
5,824
0.81
0.31
0.48
0.11
0.39
0.71
0.52
0.45
0.11
0.28
'1.39
0.87
0.82
0.19
0.66
1.20
0.89
0.76
0.19
0.48
16.4
4.3
3.5
16.4
2.2
15.6
13.0
9.3
13.6
4.0
0.188
0.048
0.041
0.188
0.024
0.177
0.147
0.106
0.177
0.044
8
8
8
7.5
6
5
5
4
4
2.5
66
66
64
60
49
37
37
35
30
20
                                                                      > (continued)

-------
                                                                TABLE  11   (continued)
Boiler type
MW^MuJhr) Flowme Jo"™,1 "Sri? ?"«»J Capital indent
Fuel «Vhr Ucfn)
% S % Ash •
0.6 5.4 2.12»10'1 (12,500) S
S
I
M
SIP
clency
$
Annuallzed coac|
S/n3/hr ($/acfm) S
Annual operating cost
$/103 kg CS/ton) S
Energy consumption*
$/m3/hr (S/acfm) kW
Solid waste
i...! °
-------
Impact (increase) of about 5 percent over uncontrolled, annualized boiler cost
data.
     Energy penalties associated with operation and maintenance of control
equipment are shown in Section 5.0 to be lowest for precipitators when 3.5
percent sulfur coal is burned followed by multitube cyclones, fabric filters,
and scrubbers.  Fabric filter power requirements are essentially insensitive
to coal sulfur content (although unusually high acidity levels may damage some
fabrics) and emission control level while electrostatic precipitator energy
requirements exceed those for fabric filters at the low sulfur - low emission
level combination.  The increased electrical consumption of an electrostatic
precipitator at these low sulfur levels is primarily due to decreased particle
migration velocities which necessitate increased plate area and correspondingly
higher energy inputs for electrification, rapping, and gas handling.  Scrubbers
are shown to be very energy-intensive, especially for the capture of fine
particles.
     Environmentally-related impacts of particulate reduction are judged
in Section 6.0 to be generally beneficial.  This is based on the potential
ramifications of decreased stack emissions versus increased solid waste dis-
posal.  In addition, environmental impacts resulting from utility-supplied
energy requirements should also be small since these (utility) units will be
well-controlled.  The potentially adverse impacts of increased solid waste dis-
posal can be minimized even further with the advent of new and stricter disposal
regulations and increased fly ash utilization in such areas as road construc-
tion, brick manufacturing, and concrete production.
     The performance data presented in Sections 2.0 and 7.0 show particulate
control systems to be well advanced, commercially available, and generally re-
liable if properly operated and maintained.  However, as the emission control
                                     18

-------
level becomes stricter, costs and reliability must be carefully scrutinized.




Because of variations in boiler operation, occasional stack emissions in ex-




cess of any emission control level may occur over long periods of operation.




The probability of this happening increases as the control level becomes more




stringent.  Opacity considerations are addressed in general only as a more




in-depth analysis of opacity versus mass emissions is presently ongoing at




GCA/Technology Division, with a report to be published in early 1980.




1.3  SYSTEMS OF EMISSION REDUCTION FOR OIL-FIRED BOILERS




     The electrostatic precipitator appears to be the only practical control




device for reduction of particulate emissions from residual oil-fired




facilities.  Multitube cyclones or wet scrubbers could also be used, but only




at modest emission control levels.  For distillate oil-fired units, controls




will be unnecessary for boilers that are properly operated and maintained




because of the low levels of uncontrolled emissions.




     The costs of particulate emissions control are lower for residual oil




systems than for coal-fired plants, but much less cost-effective based on




annualized dollars per unit of pollutant removed per year.  This is due to




the lower uncontrolled dust loadings for the residual oil-fired boiler as com-




pared to the coal-fired units, and the higher proportion of fine-sized, light-




weight fly ash emitted by the oil-fired units.




1.4  SYSTEMS OF EMISSION REDUCTION FOR GAS-FIRED BOILERS




     Gas-fired boilers fall into the same category as distillate-fired units;




uncontrolled emission rates are very low and with proper operation and main-




tenance of equipment will not require particulate controls.
                                      19

-------
                      2.0  EMISSION CONTROL TECHNIQUES






2.1  PRINCIPLES OF CONTROL




     In this section, the control options available to industrial boiler fa-




cilities firing coal, residual and distillate oil, natural gas and those




capable of firing multiple fuels will be delineated.  Four control techniques




will be considered; electrostatic precipitation, fabric filtration, wet




scrubbing, and mechanical collection.




     In order to properly assess the capability of each control technique,




uncontrolled emissions from each of the boiler types considered must first be




examined.  Uncontrolled emission levels are given in emission factor documents




(AP-42), calculable from mass balances, and as field performance data.  Repre-




sentative information is presented in Table 12.




     Particle size parameters for these uncontrolled emissions are also neces-




sary for an accurate appraisal of the capabilities of the various control alter-




natives considered.  Table 13 shows the expected ranges in particle sizes for




uncontrolled emissions from various boilers.  Generally, stoker boilers emit




the coarsest material, while oil- and natural gas-fired systems discharge




predominantly fine material, < 2y.  The sizes reported in Table 13 are the




mass median diameters.
                                      20

-------
           TABLE  12.   UNCONTROLLED PARTICULATE EMISSIONS FROM "STANDARD"
                          INDUSTRIAL BOILERS
Boiler data
Boiler type
A. Coal - pulverized dry bottom






B. Coal - spreader stoker


C, Coal - chain grate stoker


D. Coal - underfeed stoker


E. Residual oil
F. Distillate oil
G. Natural gas
Heat input
MW
(106 Btu/hr)
117.2
(400)



58.6
(200)


44.0
(150)


22.0
(75)


8.8
(30)


44.0 -
(150)
4.4
(15)
4.4
(15)
Firing
rate*
4.27
(16.95)
3.82 .
(15.14)
3.65
(14.49)
5.25
(20.73)
2.13
(8.47)
1.83
(7.25)
2.63
(10,42)
1.60
(6.36)
1.37
(5.43)
1.97
(7.81)
0.8
(3.18)
0.69
(2.72)
0.99
(3.91)
0.32
(1.27)
0.27
(1.09)
0.39
(1.56)
3.8
(1000)
0.41
(108)
7.08
(15,000)
Uncontrolled emissions
ng/J (lb/106 Btu)
Fuel
% S
3.5
2.3
0.9
0.6
3.5
0.9
0.6
3.5
0.9
0.6
3.5
0.9
0.6
3.5
0.9
0.6
3.0
0.5
""
% ash
10.6
13.2
6.9
5.4
10.6
6.9
5.4
10.6
6.9
5.4
10.6
6.9
5.4
10.6
6.9
5.4
0.1
"
HHVt
27,447
(11,800)
30,733
(13,213)
32,099
(13,800)
22,330
(9,600)
27,447
(11,800)
32,100
(13,800
22,330
(9,600)
27,447
(11,800)
32,100
(13,800)
22,330
(9,600)
27,447
(11,800)
32,100
(13,800)
22,300 '
(9,600)
27,447
(11,800)
32,100
(13,800)
22,330
(9,600)
43,043
(149,800)
45,346
(139,000)
373
(1000)
AP-42^
3,281
(7.63)
3,651
(8.49)
1,827
(4.25)
2,055
(4.78)
3,281
(7.63)
1,827
(4.25)
2,055
(4.78)
2,511
(5.84)
1,397
(3.25)
1,574
(3.66)
967.5
(2.25)
537.5
(1.25)
606.3
(1.41)
387
(0.90)
215
(0.50)
241
(0.56)
94.6
(0.22)
6.19
(0.0144)
2.15-6.45
(0.005-0.015)
PEDCo
_ . standard
Test data , . ,
boiler
data5
3,092
(7.19)
3,436
(7.99)
1,720
(4.00)
1,935
(4.50)
3,087
(7.18)
1,720
(4.00)
1,935
(4.50)
2,511
(5.84)
1,397
(3.25)
1,574
(3.66)
967.5
(2.25)
537.5
(1.25)
606.3
(1.41)
963.2
(2.24)
537.5
(1.25)
602
(1.40)
16.6-154.6
(0. 0385-0. 3596)1
3.74-14.6 6.45
(0. 0087-0. 0339)1 (0.015)
0.34-5.11 4.3
(0. 0008-0. 0119)1 (0.01)
 Coal - kg/s  (ton/hr)
 Oil  - rae3/hr (gal/hr)
 Gas  - m5/sec (ft3/hr)

+HHV  - high  heating value;
 Coal - kJ/kg (Btu/lb)
 Oil  - kJ/kg (Btu/gal)
 Gas  - MJ/rn3 (Btu/ft3
    Publication AP-42 — "Compilation of Air Pollutant Emission
 Factors."  Given as follows  (A and S are percent by weight of
 ash and sulfur respectively) :

 A.  17A Ibs particulate per  ton coal burned.
 B.  13A Ibs particulate per  ton coal burned.
 C.  5A Ibs particulate per  ton coal burned.
 D.  2A Ibs particulate per  ton coal burned.
 E.  10(S) + 3 Ibs particulate per 1000 gallons burned.
 F.  2  Ibs particulate per 1000 gallons burned.
 G.  5  to 15 Ibs particulate  per 106 ft3 burned.
 See Tables 2 through 9 for  uncontrolled emission data.

                                                   21

-------
      TABLE 13.  PARTICLE SIZE DATA  (ym) ASSOCIATED WITH SEVEN "STANDARD"
                 FIRING METHODS (UNCONTROLLED)


                                  Particle size - mass median diameter - (ym)
                               Reference 2  Reference 3  Reference 4  Reference 5
A.  Coal - pulverized              10           20           20

B.  Coal - spreader stoker          -           70           48           -

C.  Coal - chain grate stoker       -          100           75           -

D.  Coal - underfeed stoker         -           -            16           -

E.  Residual oil                    2.5         -         90% < 2y       1.2

F.  Distillate oil                  5.0         -         90% < 2y

G.  Natural gas                     -           -         90% < 2y
                                       22

-------
2.2  CONTROLS FOR COAL-FIRED BOILERS




2.2.1  Electrostatic Precipitation




2.2.1.1  System Description—




     The basic collection processes taking place in an electrostatic precip-




itator (ESP)  are as follows:  (1)  suspended particles are given an electrical




charge; (2)  the charged particles  then migrate to a collecting electrode of




opposite polarity while subjected  to a diverging electric field; and (3) the




collected material is then dislodged from the collection electrodes.




     Electric charging of the particles is usually caused by ions produced in




the high voltage d-c corona.  Removal of the collected material is accomplished




by rapping or vibrating the electrodes.




     A typical cross section of an ESP is shown in Figure 1.




     Some of the key components and subsystems associated with an ESP unit




are:  (1) the collecting and discharge electrodes; (2) high voltage transformers




and rectifiers; (3) electrode rappers; (4) gas distributors (guide vanes); and




(5) structural features such as the shell, manifolds, hoppers and ducting.  A




brief discussion of each is given in the following paragraphs.7




     Most discharge electrodes in the U.S.A. appear as smooth wires of about




0.254 cm (0.1 inch) diameter that are held in a fixed position by weights




suspended from the lower ends.  These wires are usually protected from burning,




which ultimately leads to breaking, by electrostatic shrouds at the tops and




bottoms of the wires.  Collecting plates often consist of solid-sheet with




structural stiffeners although special contours; e.g., corrugated, may be in-




corporated in some designs to improve gas flow distribution and facilitate




cleaning.
                                      23

-------
fO
           BUS DUCT

              INSULATOR
             COMPARTMENT
           TRANSFORMER
           RECTIFIER —
            GAS
         DISTRIBUTION
           DEVICE -
             COLLECTING
               SURFACE
                                                      RAPPER  INSULATOR

                                                         HIOH VOLTAGE SYSTEM
                                                          SUPPORT  INSULATOR

                                                              COLLECTING  SURFACE
                                                                    RAPPER
DISCHARC^ELECTRODE
                        .GAS PASSAGE
                            DISCHARGE
                            ELECTRODE
                                 Figure  1.   Typical precipitator cross  section.6

-------
     The high voltage equipment used in the ESP serves the dual role of pro-




viding intense electric fields and the corona currents necessary for particle




charging.  Automatic control of rectifier output is usually required for




boiler applications because of varying electrical loads and fuel conditions.




     Perhaps the most difficult task encountered in applying electrostatic




precipitators is that of removing the dust deposits from the collection plates




while minimizing their reentrainment in the outlet gas stream.  Ideally, a




sharp rap of a collecting electrode at the proper intensity should accelerate




the dust mass sufficiently to break the adhesive bonds at the dust/plate inter-




face.  When the thickness and composition of the dust layer permit a uniform




dislodgement, fly ash can be very effectively removed.  Observations on some




units have revealed a complete detachment of platelike dust layers or sheets




that fall into the collection hopper below.  Under the above circumstances,




the redispersion and resuspension of fine particles in the gas stream is




usually minimized unless the dust level is too high in the hoppers.  In gen-




eral practice, however, both deposition and dislodgement patterns are non-




uniform such that optimum particle capture is not achieved and dust reentrain-




ment may account for an appreciable fraction of the total emission.




     Deliberate interruption of power to a plate section undergoing cleaning




may increase the dust removal via reduced adhesion.  Lowered gas velocities,




with no decrease in plate area, aid in reducing reentrainment.  Although the




resultant increase in SCA favors increased collection, the physical plant




can no longer accommodate the required gas flow rate.  Electrode rapping or




vibrating with its attendant reentrainment potential  cannot be avoided unless




a flush-down, wet plate system is used.  However, by  sectionalizing the
                                      25

-------
system in multiple series - parallel arrays - there will always be an elec-




trical backup except when the most downstream plate sections are rapped.




     Good gas flow distribution is a function of the form of the intercon-




necting breeching between the boiler and  the precipitator but most ESP's




employ guide vanes to prevent flow separation at elbows and diffusion screens




to reduce turbulence at the collector  entrance.  Improvement in gas flow




uniformity can result in greatly increased efficiency.  For new installations,




the use of models at 1:16 or 1:8 scale for flow analysis is routine practice.




     Structural features of an ESP are important insofar as maintaining elec-




trode alignment and configuration.  They  are especially important in "hot"




precipitators (those installed upstream of the air heater) because of the




potential for distortion caused by large  thermal stresses.  Complete insula-




tion of shell, hoppers, and connecting duct work is required to prevent cor-




rosion due to condensation of moisture and acid and also to minimize stresses




due to temperature differences.




     Since electrostatic precipitation is a well-established technology, there




is usually no problem with respect to  commercial availability.  The time re-




quired to establish specifications, design, fabricate, ship, and erect an ESP




unit for a utility boiler is on the order of 2 to 4 years, depending on site-




specific factors and vendor workload.8 It is conceivable that a shorter




period could be realized for smaller-sized industrial plants.



     Electrostatic precipitation technology dates back to the early 1900's




when the first successful application was made by Cottrell in 1907 for collec-




tion of acid mist at a sulfuric acid plant.   The first power boiler application




was in 1923 at Detroit Edison's Trenton Channel Plant.9  This installation con-




sisted of three units handling a total gas flow of 1.36 x  106 m3/hr  (800,000  acfm) ,






                                      26

-------
designed for a collection efficiency of 90 percent.  Several years were re*-




quired before the many operational problems encountered were solved.




     Limited data are available with respect to the number of ESP systems sold




over the last several years for control in the boiler industry.  In terms of




millions of dollars,  ESP sales in the United States were as follows for the




1972 to 1975 period:10




                         1972    1973    1974    1975




                         86.2   167.5   326.2   226.8




     The 1978 precipitator market for the United States is projected to be




around $400 million.




     Data for power boilers indicate that shipments were expected to decline




in 1977 to $1,020 million with a capacity of 89 million kg (197 million pounds)




of steam per hour as  compared with $1,140 million in 1976 with capacity of




99 million kg (218 million pounds) of steam.11




     The applicability of ESP technology to the coal-fired boilers being




studied in this document presents no problems with respect to the boiler fir-




ing methods and their respective sizes from an engineering standpoint.  Gen-




erally, ESP modules can be furnished in sizes down to about 8500 m3/hr




(5000 acfm).  With respect to fuel characteristics, there are several factors




which may adversely affect ESP performance, such as the sulfur or alkali metal




content of the coal being fired.  These problems are discussed in greater de-




tail subsequently.




     Some of the more important design criteria to be considered in the se-




lection and utilization of electrostatic precipitators are given in Table 14.*^




Additionally, some basic parameters used in precipitator design as well as
                                     27

-------
   TABLE 14.  CRITICAL PARAMETERS FOR ELECTROSTATIC
              PRECIPITATOR OPERATION12

A.  Design
    1.  Collection plates

          Specific area
          Aspect ratio
          Plate area/rapper
          Plate area/transformer set
          Number of plate sections
            •  Series connected
            •  In parallel

    2.  Corona electrodes
          Number/section
            •  Series and parallel connected
          Length/rapper
          Alignment stability
          Insulation methods
            •  Heating, shielding, gas flush
          Corona power density (W/ft2)
          Corona power (W/cfm)
          Corona electrode tensioning

    3.  Electrical system
          Average field strength
          Wave form
          Automatic voltage control

    4.  Cleaning procedures
          Number rappers/unit plate area
          Method, location and intensity of rapping
          Dust level in hoppers
          Dust removal from hoppers

B.  Operating Parameters
          Gas flow rate/linear velocity/residence time
          Gas temperature in ESP
          Use of flue gas conditioners
          Gas flow distributors
          Cleaning (rapping) frequency

C.  Aerosol Properties
          Gas temperature and moisture content
          Dust concentration and size properties
            Fly ash components
               Sulfur, alkaline oxides
               Catalytic agents (Fe203>
               Trace metals
                          28

-------
typical numerical values used for  fly  ash systems are given in Table 15.


The variations in design parameters, which are commonplace, are attributable


to broad differences in fly ash properties encountered in the field, different


efficiency requirements, and conservatism in design practice.


     The three most important design criteria are the precipitation rate  (W ),


the specific collection area (SCA), and  the gas velocity, V.  Because precipi-


tation rate can vary with resistivity, particle size distribution, gas velocity


distribution, rapping, and electrical  factors, an effective rate parameter or


migration velocity is usually adopted.   Variation of this parameter with  fly


ash resistivity and coal sulfur content  is shown in Figures 2 and 3.llf
                       0.6
                       0.5
                       0.3

                      I

                      1 0.2
                      «J
                      2
                       0.1
                        109
10
                                   10
         10
                                            ll
                                                     15.2
                                                     12.2 u
                   9.1 -
                      c
                      o

                   6  S
                      'S
                      'o

                   3  I
                  10*
                                  Resistivity, ohm-cm
     Figure 2.  Drop in precipitation rate We with increasing fly ash
                resistivity  for  a  representative group of precipitators.
                                      29

-------
                               TABLE 15.   RANGE OF BASIC DESIGN PARAMETERS FOUND IN
                                          THE FIELD FOR FLY ASH PRECIPITATORS13
                Parameter
                                 Symbol
                      Range of values
u>
o
Duct spacing

Precipitation rate


Specific collector area


Gas velocity

Aspect ratio
(plate length/plate height)


Corona power


Corona current
  plate area

Plate area per electrical set

Number of high tension
sections in gas flow direction

Degree of high tension
sectionalization
                                          s     20.3 to 30.5 cm (8 to 12 in.)

                                         We     0.015 to 0.183 m/s (0.05 to 0.60 ft/s)


                                      SCA or ^  328 to 2630 m2/1000 m3/min (100 to 800 ft2/1000 cfm)


                                          V     1.2 to 2.4 m/s (4 to 8 ft/s)
                                          H

                                                0.5 to 1.5 (dimensionless)
                                           -     1770 to 17,700 watts/1000 m3/min (50 to 500 watts/1000 cfm)
                                         ~     54 to 753 yamps/m2 (5 to 70 yamps/ft2)
                                         As     465 to 7430 m2/el. set (5000 to 80,000 ft2/el. set)
                                                2 to 8 sections
0.4 to 4.0 H.T.  bus sections
         2830 m^/min
1.4 to 4
                                                                                        H_/T._  bus sections j
                                                                                           100,000 cfm     /
       H.T.  = high tension

-------
     An average W  value  of  about 6 to 9.1 cm/s  (0.2 to 0.3 ft/s) is repre-


sentative of recent installations designed for high collection efficiencies


(99+ percent) where resistivity does not exceed  about 2 x 1010 ohm-cm.
                       0.7
                       0.6
                       0.5
                      £0.4

                      5


                      10.3
                      3
                      a.

                      £
                      £0.2
                       0.1
                                       Ill
                                        Ramsdell
                                      curve 300°F
Barrett regression
 analysis curve
              TVA data 320°F  '
                           21.3



                           18.3
12.22

   c
   o

9.1 'i

                         0    0.5   1.0   1.5    2.0   2.5   3.0
                                  Coal sulfur, percent



      Figure 3.  Relation of  We to coal sulfur content  for flue gas tem-

                 peratures  in the neighborhood of  149°C (300°F) as

                 determined by several investigators.14


     If one could rely solely upon plate area, A,  volume flow rate, V, and


average electrical migration velocity, w,  to  compute fly ash collection effi-


ciencies by means of  the well-known Deutch-Anderson (D-A) equation, collection


efficiency would be estimated as:


                     Efficiency = n = 1 - exp -  (w A/V)                    (l)


     In most cases, however,  field data indicate lower  efficiencies than  pre-


dicted by the D-A relationship.  To account for  the observed particle collec-


tion levels, White15 designates the empirical relationship:
                               1 - exp - (w. A/V)°'5
                                                (2)
as a more realistic predictor of particulate collection efficiency.  The ex-


ponent, 0.5, is applicable when the ESP system  is  handling coal fly ash.  In
                                       31

-------
Equation (2), the term w^ is an "effective" migration velocity computed from




experimental measurements.  This parameter results in a better estimate of




SCA at high removal efficiencies.




     The collection surface required for a given gas flow and efficiency may




be estimated from Equation (2).  Practical values of SCA range between 328 to




2630 m2/1000 m3/min (100 and 800 ft2/1000 acfm) for most field applications.




     Gas velocity in the precipitator is extremely important since collection




is highly sensitive to velocity variations.  The critical velocity depends on




such factors as plate configuration and precipitator size and the judicious




use of flow distributors is required to minimize velocity gradients.  The




design velocity limit for high efficiency fly ash precipitators is about 1.5




to 1.8 m/s (5 to 6 ft/s).




     In general, the performance of a given ESP unit is a function of "the




size of the box" (plate area and depth), the resistivity and size properties




of the fly ash, the electrical parameters defining particle charge and field




strength and proper operation and maintenance of equipment.  Electrical con-




trols are readily adjustable but are typically maintained at predetermined




levels.  The main reason for impaired system performance is faulty equipment




maintenance.  On the other hand, some degradation of system components with




time is unavoidable.  Since compliance testing is usually performed with all




boiler and control device equipment properly tuned, cleaned and in good "repair,




true emission levels between testing intervals are difficult to predict except




that they probably exceed compliance test levels.




     Variations in fuel characteristics can play an important role in deter-




mining performance of an ESP.  This is especially true of industrial boiler




fuel supplies (as opposed to utility boilers) since the former will usually







                                      32

-------
"spot" purchase coal rather than commit themselves to any long-term coal con-
tracts.   What this means is that industrial boilers can expect to see larger
variations in coal properties (over time)  than utility boilers, which, with
an ESP for particulate control, will be reflected by the outlet concentra-
tions.  The most notable fuel properties are sulfur and alkali (primarily
sodium)  contents of the coal being burned, which affect the resistivity of
the fly ash, as illustrated in Figures 4,  5, and 6.16  Figures 4 and 5 show
that resistivity is altered (lessened) favorably with increasing sulfur
content or decreasing flue gas temperature.  Figure 6 indicates the desirable
effect of reduced resistivity with an increasing percentage sodium in the
ash.
     Consideration must also be given to other metal oxides and when design-
ing specifically for an ESP application, it is desirable to preferentially
select coals whose ash contents have high Na£0 (> 1.0 percent), Li20 and
Fe203, and low CaO, MgO (< 20 percent combined), Si02, and P205 (< 1.0 percent).
     Most users (utilities) of ESP equipment have become very familiar with
equipment operation over the years.  Electrostatic precipitators account for
at least half of the market in terms of particulate control equipment.  Fur-
thermore, there is a great deal of interaction between vendors and users that
has resulted in many innovations and design improvements.  Invariably, improve-
ments in design result in better performance, such as zig-zag electrode con-
figurations for improved electrification and gas flow distribution.
     Current research and development is aimed primarily at improved voltage
regulation through the use of automatic voltage control  (a necessity whenever
boiler load is expected to fluctuate).  Improved electrode configurations that
more efficiently distribute the charge while at the same time are better able
to tolerate fly ash buildup, and innovations in rapper designs are also part
                                      33

-------
  13 "00
 10
  12
 10
TEMPERATURE,°C
     ISO        ZOO
  i,
£-10
  10
 10
 io9
     0.6% sulfur coal
                 I
                       0.25% sulfur coal
                       2.1% sulfur coat
                    3.6% sulfur coal
   200
         250
    300   350
    Temperature. °F
                            400
                       450
   Figure  4.
    Variation  of fly  ash
    resistivity with
    temperature for coals
    of  various sulfur
    contents.16
                                                        1.0
 1.5   2.0   2.5
 Coal sulfur, percent
                                                                            3.0    3.5
Figure 5.
Fly  ash resistivity
versus coal  sulfur
content for  several
flue gas temperature
bands.16
                          14
                         10
                          13
                         10
                       I
                       M
                       I  n
                       f  10
                          10
                          10
                          10;
                           0.1
                   Figure  6.
                    0.2 0.3  0.5 0.7 1    235
                      Sodium content as Na20, percent
                                                        7 10
                    Variation  of resistivity  with
                    sodium content for fly ash from
                    power plants burning western
                    coals.16

-------
of the current R&D effort.   In addition, there is vigorous activity in the




area of improved charging concepts (e.g., bias pulse charging, pulsed ener-




gization, and precharging or preionization).   The net result of all of these




measures will, hopefully, be to improve overall collection efficiency:




     The main problems with retrofit installations are space limitations and




timing the control device installation with the scheduled boiler outage to




minimize loss of capacity.   With an ESP installation, space factors are crit-




ical if the duct work from the boiler to the control device is contorted to




the extent that the gas flow into the ESP is no longer uniformly distributed.




Space limitations can also affect the required installation time and therefore




the overall project cost.  Except in extreme cases, however, it is expected




that most sources could be retrofitted successfully.




2.2.1.2  System Performance—




     Most test data that are available for coal-fired boilers controlled by




precipitators come from the utility rather than the industrial boiler sector.




The fact that the power generated by a utility boiler is its sole product,




whereas the industrial boiler output is only one of several factors contrib-




uting to the ultimate product cost, probably results in more careful regulation




and more sophisticated operating procedures for the utility boiler and its




emission control system.  Additionally, load levels are more constant and




shutdowns less frequent for the utility boiler.  At the same time, the phys^




ical properties of the coals burned by utilities are less variable in that




the fuel is purchased under long-term contracts with more rigid composition




specifications.  The three items cited above are expected to contribute to




reduced emissions for utilities operations when the same fuel is burned»  In




the event that stoker firing is used, it is possible that those industrial




boiler emissions may be lower than that seen with pulverized coal utility




                                     35

-------
boilers because of the increased particle size with stoker-firing, and hence,




greater ease of collectability in all collectors.




     Furthermore, since most test data derive from compliance testing, they




should be interpreted as representing the best possible system performance and




not typical, day-to-day or average emission levels.  The implication here is




that few compliance tests are undertaken unless the system is operated under




the following conditions;  correct fuel at the rated load levelj clean duct




and electrode surfaces; all ionizing electrodes functioningj and no leaks or




defective dampers in the gas handling system.  In actual practice, real systems




are subject to deviations from the above such that a gradual increase in emis^




sion levels probably occurs with increased on-line servicet




     A recent GCA report prepared for the Utility Air Regulatory Group of the




Edison Electric Institute documented the performance capabilities of a large




number of utility stations across the country controlled by electrostatic




precipitators.17  A comprehensive summary of these data is presented in




Table 16.  All boilers in this table are dry bottom units burning pulverized




coal except Gannon units 5 and 6 (Tampa Electric Co.) which are pulverized




wet bottom, and all units were designed to meet emission levels within the




range being considered in this report.  A plot of emission rate in ng/J




(lb/106 Btu) versus specific collector area (SCA) for these tests is shown




in Figure 7, but since the SCA values encountered were nonuniformly distributed




over the reporting range, and because of other system variabilities, the cor-




relation obtained was not significant.  Other performance data for utility




boilers burning lignite coals, Table 17, show ESP collection efficiencies




ranging from 97 to 99.8 percent.18
                                     36

-------
                                TABLE 16.   SUMMARY OF UARG SURVEY ESP TEST DATA17
OJ

1.














2.








3.

4.















Utility/Station
American Electric Power Co.
Clen Lyn No. 5
(lien Lyn No. 6
Amos No. 3
Big Sandy No. 1
Big Sandy No. 2
Clinch River No. 1
Clinch River No. 2
Clinch River No. 3
Gavin No. 1
Gavin No. 2
Kanawha R. No. 1
Kanawha R. No. 2
Tanners Cr. No. 1
Tanners Cr, No. 2
Consumers Power Co.
Campbell No. 1
Campbell No. 2
Campbell No. 3
Whiting No. 1
Whiting No. 2
Whiting No. 3
Karn No. 1
Karn No. 2
Cleveland Electric Co.
East lake No. 5
Duke Power Co.
Allen No. 3
Allen No. 4
Allen No. 5
Belews Creek No. 1
Belews Creek No. 2
Buck 3 No. 5
Buck 3 No. 6
Buck 4 No. 7
Buck 5 No. 8
Buck 6 No. 9
Cliffside No. 1
Cliffside No. 2
Cliffside No. 3
Cliffside No. 4
Cliffside No. 5
Control
Installation
date

1974
1975
1973
1970
1969
1975
1974
1974
1974
1975
1969
1969
1977
1977

1976
1978
1980
1973
1973
1973
1976
1976

1972

1973
1972
1973
1974
1975
1972
1972
1972
1973
1973
1972
1972
1973
1973
1972
device
Percent of
time fully
operational

100
100
58
54
100
4
0
0
85
88
73
100
100
100

NA
NA
NA
95
95
95
NA
NA

18

87
7
74
90
88
95
98
92
96
99
88
79
98
98
85
Designed to meet:
NSPS State standard of
(0.1 lb/106 Btu)a (lb/106 Btu)a

X
X
0.05
0.245
0.19
X
X
X
X
X
0.05
0.05
X
X

0.08-0.095
0.08-0.095
X
0.08-0.095
0.08-0.095
0.08-0.095
0.08-0.095
0.08-0.095

0.1

0.15
0.15
0.15
0.1
0.1
0.24
0.24
0.24
0.18
0.18
0.24
0.24
0.21
0.21
0.12
Tested
emission
rate
(lb/106 Btu)a

0.003
0.001
0.04
0.24
0.17
0.05
0.05
0.05
0.013
0.014
0.03
0.03
0.01
0.01

0.0354 gr/scf
0.015 gr/scf
0.06 gr/scf
0.006 gr/scf
0.036 gr/scf
0.009 gr/scf
0.026 gr/scf
0.026 gr/scf

0.04

0.247b
0.324b
0.228b
0.09
0.804b
-
-
_
-
0.045
0.042
0.18
0.094
0.133
0.048
Type of source
Compliance Stack test
test by EPA AS ME power
Method 5 test code 27

X
X
X
X
X
X
X
X
X
X
X
X
X
X



not tested






X

X
X
X

X





X
X
X


test
Other test
modi f i cation
















X
X

X
X
X
X
X






X

X
X
X
X
X



X
X
                                                       (continued)

-------
                                                         TABLE  16 (continued)
CO
00
Control device
Designed to meet:
Utility/Station. In8talUtion *?"«*«' NSPS State standard of
date optional <°'1 lb/1°6 Btu)" U"/">6 "«>•
4. Duke Power Co, (continued)
Dan River No. 1 1971
Dan River No. 2 1971
Dan River No. 3 1972
Lee No. 1 1970
Lee No. 2 1970
Lee No. 3 1973
Marshall No. 3 1972
Marshall No. 4 1972
Rlverbend 4 No. 7 1973
Rlverbend 4 No. 8 1972
Rlverbend 6 No. 9 1972
Rlverbend 7 No. 10 1973
5. Pennsylvania Power & Light Co.
Montour No. 1 & No. 2 1971

99 0.21
NA 0.21
96 0.13
100 0.6
100 0.6
100 0.6
55 0.12
70 0.12
86 0.24
98 0.24
75 0.23
84 0.23

80 O.lc
Brunner I. No. 1 1961/1965 70 O.ld
Brunner I. No. 2 1965/1976 >99e 0.1
Sunbury No. 3 1952/1976 100 0.1
Sunbury No. 4 1954/1975 100 ' 0.1
6. Public Service Co. of Colorado
Arapahoe No. 1 1976
Comanche No. 2 1975
7. Salt River Project
Navajo No. 1 1974
Navajo No. 2 1975
Navajo No. 3 1976
Hayden No. 2 1976
8. Gulf Power Co.

95 0.1
70 X

84
79 1
75 I0'06
100 X

Crist No. 4 1968/1976 NA 0.
Crist No. 5 1969/1976 NA 0.
Crist No. 6 1970
Crist' No. 7 1973
NA 0.
NA 0.
Lansing Smith No. 1 1965/1976 NA 0.
Tested
emission
rate
(lb/106 Etu)a

0.134
0.083
0.081
0.10
0.11
0.12
0.119
.
_
0.046
_
0.042

0.05-0.9
0.6-2.0
0.086
0.087
0.26

0.028
0.04

0.05
0.071
0.0471
0.1-0.11

0.033
0.082
0.085
0.099
0.043
Lansing Smith No. 2 1967/1977 NA 0,
Scholz No. 1 1974
Scholz No. 2 1974
9. Tampa Electric Co.
Gannon No. 5 1975
Gannon No. 6 1974
NA 0.
NA 0. 1

NA 0.1
NA 0.1
0.019
0.075

0,06
0.06
Type of source
Compliance Stack test
test by EPA ASME power
Method 5 test code 27




X
X
X
X








X
X
X






X


X
X
X
X
X
X
X
X

X
X
test
Other test
modification

X
X
X




X
X
X
X
X

X
X





















X

                                                            (continued)

-------
                                                    TABLE  16 (continued)
vo
Utility/Station
10. Tennessee Valley Authority
Allen No. 1
Colbert No. 2
Colbert No. 3
Colbert No. 4
Colbert No. 5
Cumberland No. 1
Cumberland No. 2
John Sevier No. lf
John Sevier No. 2f
John Sevier No. 3£
John Sevier No. 4f
Johnsonville No. lf
Johnsonville No. 2f
Johnsonville No. 3f
Johnsonville No. 4^
Johnsonville No. 5^
Johnsonville No. 6*
Johnsonville No. 7^
•Johnsonville No. 8*
Johnsonville No. 9f
Johnsonville No. 10f
Kingston No. lf
Kingston No. 2f
Kingston No. 3f
Kingston No. 4f
Kingston No. 5f
Kingston No. 6f
Kingston No. 7f
Kingston No. 8f
Kingston No. 9f
11. Virginia Electric and Power
Mt. Storm No. 1
Mt. Storm No. 2
Mt. Storm No. 3
Chesterfield No. 6
Bremo No. 3
Bremo No. 4
Control
Installation
date

1972
1972
1972
1972
1976
1972
1973
1973
1973
1974
1974
1976
1976
1951/1976
1952/1976
1952/1975
1952/1975
1958/1974
/1974
/1974
/1974
/1976
/1976
/1976
/1976
/1976
/1976
/1976
/1976
/1976

1973
1973
1973
1969
1973 \
1973)
device
Percent of
time fully
operational

95
94
92
91
85
84
73
93
98
96
96
97
99
98
96
99
96
71
86
91
89
NA
99
94
NA
NA
98
91
94
98

95
94
91
28
0
20
Designed to meet:
NSPS State standard of
(0.1 lb/106 Btu)a (lb/106 Btu)a

0.1-0.14
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
-0.14
0.1-0.14
0.1-0.14
0.1-0.14
0.1-0.14
0.1-0.14
0.1-0.14
0.1-0.14
0.1-0.14
0.1-0.14

0.05
0.05
0.05
0.1
\"-f\ 1 ^
> U. ID
Tested
emission
rate
(lb/106 Btu)a

0.05
0.06
0.096
0.088
0.08
0.12
0.12
0.013
0.021
0.026
. 0.008
0.04
0.01
0.03
0.03
0.03
0.03
0.18
0.06
0.05
0.07
-
0.027
0.019
-
0.012
0.017
0.015
0.012
0.01

0.025
0.045
0.113
0.04
0.022
0.022
Type of source test
Compliance Stack test „ .
tesi by EPA ASME power "J« «"
Method 5 test code 27 ^ification

X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X

X
X
X
X
X
X
                                                            (continued)

-------
                                                             TABLE  16  (continued)
Utility/Station
ADDENDUM
Union Electric Co.
Rush Island No. 1
Rush Island No. 2
Iowa Public Service Co.
Neal 1
Neal 2
Neal 3
Neal 4
Kansas City P&L Co.
Kansas Gas & Elec. Co.
LaCygne No. '2
Kansas City P&L Co.
Hawthorn No. 1
Hawthorn No. 2
Control
Installation
date


1976
1977

1971
1971
1975
1979


1977

1977
1977
device
Percent of
time fully
operational


59
94

70
95
95
--


>99h

ioo£
100h
Designed to meet:
NSFS State standard of
(0.1 lb/106 Btu)a (lb/106 Btu)a


X
X

0.5838
0.3808
0.4398
X


X

Clty-0.18}
Clty-0.18
Tea ted
emission
rat*
(lb/106 Btu)a


0.04
0.06

0.456
0.178
0.039
-


0.012

0.014
0.022
Type of source test
Compliance Stack test Q h t t
'vVilf* *SMEP?M;, -o«ll««ti«-
Method 5 test code 27


X
X

X
X
X



X

X
X
a0.1 lb/106  Btu " 43 ng/J.  To convert from lb/10s Btu to ng/J multiply by  430.
 Not considered representative of current performance.
 Experimenting with Apollo additives
'Hfith and without 803 Injection.
eConfidentlal!
 Preceded by mechanical collectors.
8Allowable emissions based on multiple stack.  Design efficiencies are 99.0, 99.0, and 99.7 percent,  respectively.
^Percent of time all fields operational is not available.
^State requires 0.12 for station average.
 NA « Not Applicable.

-------
   10°
               656
                       = m2/IOOO m3/min

                     1312       1968     2625
                              3280
            O
                    e
to-'
 0
r
 o
 e
9
 X
                                    e
              e
                    o

-------
                TABLE  17.   DESIGN AND TEST DATA FOR ELECTROSTATIC PRECIPITATORS  IN OPERATION
                              OR PLANNED FOR POWERPLANTS BURNING NORTH DAKOTA LIGNITES18
Utility company
Basin Electric
Power Cooperative
Station

Location

ESF installation on new
or existing boiler


ESF vendor

Completion date
Boiler capacity (MW)
Firing method

Number of transformer-
rectifier sets
Flue gas
Temperature, °F
°C
Velocity, ft/sec
(m/sec)
Flow, ft Vain*
(m3/mln)
Specific collecting area
ft2/1000-ft3/minT
(n>2/1000-m3/mln)
Inlet loading, gr/ftat
(g/m3)

Outlet loading, gr/ftjt
(g/m3)
Design efficiency (X)
Measured efficiency
Migration velocity, cm/ sec
I 	 	 	
Leland
Olds No. 1
Leland
Olds No. 2
Stanton,
North
Existing



Research-
Cottrell
11/74
215
pc

16


360
(182)
5.01
(1.53)
1,000,000
(28,300)

320
(1050)
2.30
(5.26)

0.0125
(0.0286)
99.50
99.45X
8.26
Dakota
New



Western

9/75
440
cyclone

40


373
(189)
5.00
(1.52)
2.100,000
(59,500)

267
(876)
1.30
(2.97)

0.0125
(0.0286)
99.05
NA
NA
Mlnnkota
Otter Tall Power
Montana Dakota Utilities
Power Cooperative
Milton R.
Young No. 1
Milton R.
Young No. 2
Center,
North
Exla-tlng



Research-
Cottrell
6/75
235
cyclone

16


385
(196)
5.55
(1.69)
1,170,000
(33,100)

288
(945)
1.00
(2.29)

0.01
(0.0229)
99.00
99.82%
11.15
Dakota
New



Wheel-
abrator
5/77
438
cyclone

32


380
(L93)
5.00
(1.52)
2,200,000
(62,300)

375
(1230)
1.0 to 2.7
(2.29 to
6.18)
0.006
(0.0137)
99.40
NA
NA
Hoot
Lake No. 2
Fergus
Hoot
Lake No. 3
Falls,
Minnesota
Existing



Research-
Cottrell
5/72
61
pc

k


330
(166)
4.23
(1.29)
280,000
(7,900)

252
(827)
1.87
(4.28)

0.015
(0.0343)
98.50
99.00%
9.28
Existing



Researeh-
Cottrell
4/72
79
pc

4


310
(154)
5.07
(3.28)
390,000
(11,000)

236
(774)
2.09
(4.78)

0.015
(0.0343)
98.50
995! +
9.9
Ortonvllle

Ortonvllle,
Minnesota
Existing



Research-
Cottrell
6/72
21
spreader-
stoker
It


345
(174)
4.25
(1.30)
133,000
(3,800)

280
(919)
0.97
(2.22)

0.0042
(0.0096)
98.90
99% +
8.4
Big Stone

Mllbank,
South Dakota
New



Wheel -
abrator
5/75
440
cyclone

24


288
(142)
5.25
(1.60)
2,330,000
(66,000)

355
(1165)
1.17
(2.68)

0.014
(0.0320)
98.80
99.63X
8.01
Heskett No. 1

Heskett No. 2

Man dan,
North
Existing



Research-
Cottrell
6/75
25
spreader-
stoker
6


418
(214)
3.80
(1.16)
189,300
(5,400)

352
(1155)
2.5 to 4.1
(5.72 to
9.38)
0.0225
(0.0515)
99.45
0.1 gr/ft3
NA
Dakota
Existing, ESF
in series with
mechanical
collector
Reeearch-
Cottrell
6/75
66
spreader-
stoker
10


333
(167)
4.28
(1.30)
451,800
(12,800)

280
(919)
0.3 to 0.6
(0.69 to
1.38)
0.021
(0.0480)
97.00
0.1 gr/ft3
NA
United Power
Association
UFA - Stanton

Stanton,
North Dakota
Existing



Research-
Cottrell
5/76
160
PC

12


350
(177)
5.17
(1.58)
853,750
(24,200)

235
(771)
NA
NA

NA
NA
98.0
NA
NA
 Volume flow rate at the entering flue gaa temperature divided by croaa-sectlonal area of preclpltator.
 Flue gas volumes are computed at the entering flue gas temperature.
Note: NA - Data not available.

-------
     Performance statistics  from Research-Cottrell are shown in Figure 81 •


for hot-side precipitator  applications, and the relatively  poorer performance


on western coals as opposed  to eastern coals should be noted.   Unfavorable


distributions of alkali metals as well as reduced sulfur  levels, probably


account for the diminished efficiencies for western applications.   The data


set shown for western coals  represent hot precipitator installations on pul-


verized coal boilers before  corrective actions were taken.   The investigations


leading to the causes and  correction of the performance deficiencies encoun-


tered at two of these plants have significantly enhanced  the vendor's knowl-


edge relating to proper application of precipitators  for  western low sulfur


coals.


                   SPECIFIC  COLLECTION AREA, m2/lOOO m3/min
                 197
328
39.99 -





 99.9 f
   I

 998 r

 99.6 •


 99.0 i-


 98.0'

 97.0 I

 96.0

 95.0
                                      1312
                                      , 1
1968
 1
 3280
-,—I

                                                  a •
                                     /
                     fP
tfU.U

?nn



/•

/
:
\/

/





LEGEND
• Eastern • Tests prior to May 1974
• Western Tests prior to May 1974
O Eastern • Tests post May 1974
Q Western Tests post May 1974
                  i    3  8
                             SPECIFIC COLLECTION AREA FT2/1000 ACFM
          Figure 8.  Actual performance data for  Research-Cottrell
                     hot  precipitators, 1967 to 1976. l'
                                       43

-------
     Lodge-Cottrell (Dresser Industries, Inc.), another leading equipment




supplier, offers only cold-side units and has had reasonable success on all




coal types.  Limited test data for five boilers are shown in the addendum to




Table 16.  These five boilers each burn < 1 percent sulfur coal and were




designed for efficiencies of about 99.6 percent.




     In discussing performance, reference must be made to visible emissions




since opacity standards almost always accompany mass emission limits.  Plume




opacity is usually associated with the fine (< 2 jam and predominantly sub-




micrometer) fractions of stack emissions which, because of their extended




particle surface, have the capacity to absorb and/or scatter incident light.




The data currently being studied at GCA indicate very little correlation




between mass and visible emissions, except on a very site-specific basis.




In fact, there have been cases where opacity values have been excessive even




though mass emission limits had been achieved.  McCain has presented frac-




tional particle size efficiency data for high efficiency electrostatic pre-




cipitators .showing that particle removals are essentially the same for the




size range < 1 ym to 10 ym with a significant dropoff in the 0.1 to 1.0 ym




range as indicated in Figure 9.20  The latter effect is suspected to be the




result of agglomerate reentrainment by the existing gas stream, bypass leak-




age and sparkover events which tend to obscure the collector's true collec-




tion capability.  Improving ESP performance to meet more stringent mass




standards would reduce penetration of light scattering particles.  However,




the reduction in mass emissions will not necessarily result in a proportional




reduction in opacity.  One utility plant has found the opacity from the stack




to be dependent on the sodium (Na) content of the ash, with > 2 percent Na




resulting in visible emissions.21   The role of the sodium (as shown earlier






                                     44

-------


c
V
o
l_
o.

o
z
UJ
0
u.
u.
UJ
— A
»
~ +
" A o
4" An
— °0 o
+ ^ A
^ nA
	 A O O
° MEASUREMENT METHOD-'
A CASCADE IMPACTORS
—
—
_

—
bj
—I
—

^ .^


	


o OPTICAL PAPTICLE COUNTERS
+ DIFFUSIONAL
-
_ PRECIPITATOR CHARACTERISTICS;.
TEMPERATURE -320°F
SCA-340ft2/IOOOocfm
CURRENT DENSITY 0.015
| , | EFFICIENCY- 98. 3% ,
0.05 O.I 0.5 1.0 5.0

-
mA/ft2 -

10.
                         PARTICLE  DIAMETER,
Figure 9.   Measured fractional  efficiencies for a cold-side ESP with
           operating parameters as indicated, installed on a pulverized
           coal boiler burning  low sulfur coal.""
20

-------
in Figure 6) appears to be mainly that of a dust-cake conditioner such that




reduced ash resistivity improves the precipitating capacity of the system.




     Other performance testing of high efficiency (99.8 to 99.9) electro-




static precipitators on coal-fired boilers indicated that significant portions




of mass emissions were caused by reentrainment of coarse particles during the




rapping of collector plates.22*23  For hot side units, 60 to 80 percent of




total mass emissions originated from the rapping sequence in contrast to about




30 percent for cold side precipitators.  Most of the reentrained particulates,




which were larger than 2 micrometers, were identified as major contributors




to overall mass penetration in the high efficiency collectors.  This mode of




particle penetration would tend to obscure the effect of other ESP design and




operating characteristics.




     Energy requirements for ESP units are discussed in terms of corona power




and gas handling capacity.  Corona power is usually expressed in terms of




energy per unit flow volume or plate area.  Two curves based upon actual field




test data show the energy-efficiency relationship, Figures 10 and ll.2t+




Figure 10 depicts this correlation for actual field test data.  Figure 11



shows the same relationship extrapolated to include efficiencies above 99




percent and demonstrates the nonlinearity of this function when very high




efficiencies are obtained.




     The performance data presented here show that emission levels down to




4.3 ng/J (0.01 lb/106 Btu) and below (in rare instances) are achievable with




ESP technology applied to coal-fired boilers.  Usually, the installation of




control equipment involves additional requirements such as added manpower




for operation and maintenance and monitors for pressure drop, temperature,




and opacity.  Because cold side precipitators are sensitive to corrosion,






                                     46

-------
            99
         I
98

97
96
9f-
93
90


80

70
60
SO
30
                Corona power, wot1»/IOO  m^min
                  88   ITT   265  3S3  442
                    • Test data
•Theoretical curve
tor k«0.55
                  25    50   75   100   125   150
                   Corona power, watts/1000 acfm
  99.9

  99.8
  99.7
£99.5
899.3
£99

£98
397
•95
§93
$j 90
Sso
  70
  50 K
                                                                      Corona power, watts/100
                                                                      353   TOT  1060  1413   I76T
                                                                       100   200   300   400   500  600
                                                                         Corona power, watts/1000 acfm
Figure 10.   Relationship between collection effi-
              ciency  and specific corona power for
              fly ash precipitators,  based on field
              test data.21*
                                                      Figure  11.  Efficiency  versus  specific corona
                                                                   power extended to  high collection
                                                                   efficiencies, based on field test
                                                                   data on recently installed
                                                                   precipitators.2^

-------
they should be fully insulated to avoid heat loss.  Generally, these added




requirements present no unusual problems.




     Vendors supplying ESP equipment will guarantee an emission level or an




efficiency at a specified boiler steam load or air flow.  A typical guarantee




might  include an emission rate of 43 ng/J (0.1 lb/106 Btu) or 0.07 g/Ntn3 (0.03




gr/scfd)  and a 20 percent opacity.  These guarantees usually apply to specific




ranges in gas flow rate and/or fuel properties.




     For  the most part, the performance data reported here are for utility




boiler emissions.  Although these data should represent the approximate capa-




bilities  of ESP equipment as applied to industrial boilers, the previously




cited  differences in boiler size and variations in load level and fuel compo-




sition suggest that higher emissions might be encountered in industrial appli-




cations.  The differences in terms of system size and inlet loadings, however,




should present few engineering problems in applying ESP technology.




2.2.2   Fabric Filtration




2.2.2.1  System Description—




     The  basic mechanisms available for filtration are inertial impaction,




diffusion, direct interception, and sieving.  The first three processes pre-




vail only briefly during the first few minutes of filtration with new or just




cleaned fabrics while the sieving action of the dust layer accumulating on




the fabric surface soon predominates, particularly at high, > 1 g/m3 (0.437




gr/ft3) dust loadings.   The latter process,  in the case of coal fly ash fil-




tration, leads to  high  efficiency collection unless defects such as pinhole




leaks or cracks  appear  in  the  filter cake.25




     An isometric view  of  a pulse-jet fabric filtration unit is shown in




Figure 12,26 while  a  reverse air  baghouse  is shown in Figure 13.   A baghouse






                                     48

-------
Clean Air Outlet
Branch Header
        Nozzle
          Pyramidal or
          Trough Hoppers
                                                                            Access Plates
                                                                              Solenoid Valves

                                                                              Compressed Air
                                                                              Manifold
                                                                             Dirty Air Inlet
                                                                                 Baffle Plate
                                                                         Access Door
    Figure  12.   Isometric view of a  two-compartment pulse-jet  fabric filter
                                                                                  26

-------
                                           Cross Sectional Vleu; of WP Custom High Temperature Boqhouw?
                                                               Hs JOY
Figure  13.
Cutaway  view of a  reverse air baghouse (courtesy of Western
Percipitation Division,  Joy Industrial Equipment Company).
                                      50

-------
consists of  a number of filtering elements (bags) arranged in compartments,




a cleaning mechanism or subsystem  and the main shell structure and hoppers.




The bags used in coal-fired boiler applications are usually fiberglass with a




coating of silicone, graphite, and/or Teflon.  One-hundred percent Teflon




fabrics have had limited field applications since their cost has discouraged




broad usage.  The bag material is most important since the bags are usually




the highest  maintenance cost component.  It has been estimated that bag lives




of 2 or more years are required in order for fabric filtration to be competi-




tive with electrostatic precipitation,27 assuming that the latter approach can




satisfy emission regulations.  The cleaning processes used in coal-fired systems




ordinarily consist of reverse-flow with bag collapse, and mechanical shaking




sometimes in combination with each other.  Pulse-jet cleaning also has had con-




siderable application while the reverse jet concept (travelling blow ring) has




seen limited field trials.  The pulse-jet cleaning method is distinguished from




the others in that (a) it is almost always used in conjunction with felted




fabrics, 0.54 to 0.81 kg/m2, (16 to 24 oz/yd2) and (b) pulse-jet systems can




operate at much higher filtration velocities, 1.2 to 2.4 m/min (4 to 8 ft/min)




or greater,  depending upon the dust characteristics.  Mechanical shaking,




which is normally used with woven fabrics, 0.27 to 0.41 kg/m2, (8 to 12 oz/yd2)




requires generally lower filtration velocities, usually less than 1.2 m/min




(4 ft/min).




     Fabric  filtration is a well-established technology with early industrial




process applications dating back to the late 1800's.  However, application to




boiler effluents has been a recent endeavor with  the first successful instal-




lations designed in the late 1960's and early 1970Ts.  For example, available




statistics on air pollution control costs by fabric filtration show that in






                                      51

-------
 1977  the industrial boiler sector spent only $5 million dollars in contrast

 to  $146 million for all industries combined.2®  For comparison, in 1972 total

 fabric filtration sales in the United States were about $53 million.

      Although fabric filbration has only recently been applied to coal-fired

 boilers, limited field performance data have so far been encouraging for both

 stoker and pulverized coal boilers.  At the present time, there are about 39

 utility boilers equipped with baghouses with another 25 scheduled for instal-

 lation or under construction.  These facilities are listed in Table 18 along

with  their key operating parameters.  The data sources were equipment vendors,

various newsletters, and an article appearing in the January 1977 issue of

Power magazine.

     There are approximately 100 industrial boilers at 61 locations employing

or planning on using fabric filtration systems and these units are shown in

Table 19.  Of the total, there are 55 stoker-fired units, and 25 pulverized-

coal units.  As indicated in Tables 18 and 19, the controlled boilers range

in size from 100 hp to 575 MW (electric) with flue gas rates of 9,345 to

6.3 x 106 m3/hr (5,500 to 3.68  * 106 acfm).  Sulfur contents vary from 0.5 to

 3.2 percent (not listed in these tables).
     The basic parameters taken into consideration in the design of fabric

 filter systems are as follows:29
      1.   Dust properties and concentration

      2.   Gas stream temperature, pressure, and composition

      3.   Fabric material

      4.   Cleaning method

      5.   Gas-to-cloth ratio

      6.   Positive or negative pressure system

      7.   Materials handling
                                      52

-------
            TABLE  18.   BAGHOUSE  INSTALLATIONS  ON UTILITY BOILERS  -  U.S.

1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
Name/location
Board of Public Utilities
Kansas City, (Cans.
Central Telephone and Utilities Corp.
Pueblo, Colo.
City of Colorado Springs
Colorado Springs, Colo.
City of Colorado Springs
Colorado Springs, Colo.
City of Columbia
Columbia, Ho.
City of Fremont
Fremont, Nebr.
City of Rochester
Rochester, Minn.
Colorado-Ute Electric Assoc.
Craig No. 3
Colorado-Ute Electric Assoc.
Nucla, Colo.
Colorado-Ute Electric Assoc.
Montrose, Colo.
Crisp County Power Co.
Cor dele, Ga.
Golden Valley Electric Assoc.
Healey No. 1
Fairbanks, Alas.
Harquette Board of Light and Power
Shiras No. 3
Harquette, Hich.
Minnesota Power & Light
Cohasset, Minn.
Montana-Dakota Utilities
Manu-
facturer
Tbd
MP
WP
EB
CAR
CAR
CAR
Tbd
WF
ICA
ZU
ICA
Tbd
WP
WF
Cleaning
mechanism
Tbd
Tbd
RA
Tbd
RA
RA
RA
Tbd
RA, sa
RA
RA
Tbd
Tbd
Tbd
RA, sa
Boiler
firing
method
PC
S
PC
PC
(2)-PC
(2) -PC
(D-s
PC
(3)-S
2-PC
PC
PC
PC
(2)-PC
C
Size
(MW)fi
44
20
200
85
(2)-40
(2)-38.5
(D-16
400
(3)-39
2-12
10
20
40
(2)-75
440
A/C*
Tbd
Tbd
1.9/1
Tbd
2.75/1
2.6/1
2.43/1
Tbd
2.8/1
3/1
3.1/1
Tbd
Tbd
Tbd
2.49/1
acfmf
300,000
Tbd
1.0 x 106
400,000
264,900
270,000
160,000
Tbd
258,000
44,000
60,000
Tbd
Tbd
348,000
1.9 x io6
Startup
date
1979
1979
1980
1978
1979
1978
1978
1981
1973
1977
1975
1980
1982
1978
1981
    Coyote Station,
    Buelah,  N. Dak.

16.  Nebraska Public Power
    Kramer Station
    Bellevue, Nebr.

17.  Ohio Edison Company
    W. H. Sammis Station
    Stratton, Ohio

18.  Pennsylvania Power & Light
    Brunner's Island
    Allentovm, Pa.

19.  Pennsylvania Power & Light
    Holtwood, Pa.

20.  Pennsylvania Power & Light
    Sunbury  Station
    Shamokin Dam, Pa.

21.  Public Service of Colorado
    Cameo No. 1
    Palisade, Colo.
ICA



AAF



CAR



WF


WP



CAR
         RA
RA
RA
          (4)-PC   <4)-113   1.7/1      558,000     1978
                     each
                   (4)-185   2/1       -  600,000    1982
                     each                each
            PC
350     2.31/1   1.2 x 196     i960
RA, sa      PC        79     2.3/1     235,000     1975


RA        (4)-PC    (4)-175   1.9/1     888,000     1973
         RA
                    PC
                              22     2.85/1    170,000     1978
                                              (continued)
                                                  53

-------
                                        TABLE  18  (continued)

22.


23.


24.


25.

26.

27.

28.

29.

30.

31.

32.

33.

34.

Name/ location
Sierra Pacific Power Co.
North Valley No. 1
Reno, Nev.
South California Edison
Alamltos Station
Long Beach, Calif.
Southwestern Public Service
Harrington Station
Amarillo, Tex.
Tennessee Valley Authority
Shavnee Steam Plant
Texas Utilities
Monticello, Tex.
United Power Association
Coal Creek Station
Pennsylvania Power & Light?
Holtwood Sta. , Allen town, Pa.
Public Service of Colorado
Cameo Station
Baltimore Gas & Electric
Wagner Station No. 3
Houston Lighting & Power
Parish Station No. 8
United Power Association
Elk River Station
Marquette Board of Light 6 Power
Shiras No. 1 & 2, Marquette, MI
Kansas City Power & Light
Kansas City, MO
Manu-
facturer
CAR


ME


WF


EB

WF

WF

F

WP

EE

RC

RC

AAF

2-ICA
1-EB
_, . Boiler
Cleaning
mechanism meth(j*
RA PC


RA OF & GF


RA, sa (2)-PC


RA (10)-PC

RA, sa (2)-PC

RA, sa (2)-S

PC

_ -

pilot

RA PC

RA 1-PC
2-S
- -

-

Size
(MW)e
250


320


(2)-350
each

175 each

(2)-575
each
(2)-26

79

•

A/C* acfrn^
2.71/1 1.246 x io6


5.7/1 820,000


3.27/1 1.65 x IO6


1.84/1 6.5 x 105
each
2.71/1 3.68 x io6

2.94/1 175,000

235,000

-

installation

550

3-48

-

3-140


2/1 2.2 x io6

2.45/1 255,800

-

-

Startup
date
1980


1965


1978-
1979

1981

1977

1977

-

August
1979
May
1979
May
1983
1978

1979

1979

*A/C - given in ft/min.   To  convert to m/min, multiply by 0.3048
"''To convert acfm to m3/hr, multiply by 1.699
$To be installed in parallel with existing baghouse and will handle 60 percent of the emissions and will
 replace existing wet  scrubber.
Manufacturers

AAF - American Air Filter
CAR - Carborundum Co.
EB  - Envirotech-Buell Div.
ICA - Industrial Clean Air,  Inc.
ME  - Menardi Southern
WF  - Wheelabrator-Frye,  Inc.
WP  - Joy Mfg. Co.-Western Precip. Div.
ZU  - Zurn Industries
F   - Fuller Co.
EE  - Environmental Elements
RC  - Research-Cottrell
MP  - MicroPul
- air-cloth ratio
- cyclone-fired
- gas-fired
- oil-fired
- pulverized coal
- reverse air
- reverse air, shake assist
- stoker
- To be determined
                                                      54

-------
TABLE  19.   BAGHOUSE INSTALLATIONS ON INDUSTRIAL  BOILERS - U.S.

1.

2.

3.

4.

5.

6.

7.

8.
9.

10.

11.

12.

13.

14.

15.

16.

17.

18.

19.

20.

21.

22.

23.

24.

25.

26.


Name/location
Adolph Coors Co.
Golden, Colo.
Allied Chemical
Southpoint, Ohio
Allied Chemical
Moundsville, W. Va.
Amalgamated Sugar Co.
Nampa , Idaho
Amalgamated Sugar Co.
Nampa , Idaho
Amalgamated Sugar Co.
Kyssa, Or eg.
Amalgamated Sugar Co.
Kyssa, Oreg.
Amalgamated Sugar Co.
Twin Falls , Idaho
Ametek, Inc.
Koline, 111.
Ashland Chemical Co.
Peoria, 111.
Carborundum Co.
Niagara Falls, N.Y.
Case Western Reserve U.
Cleveland, Ohio
Caterpillar Tractor Co.
Decatur, 111.
Consolidated Rail Corp.
Altoona, Pa.
Delco-Remy-Div. Oi
Anderson, Ind.
Denver Federal Center
Denver, Colo.
E.I. DuPont Co .
Cooper R, S.C.
E.I. DuPont Co.
Martinsville, Va.
E.I. DuPont Co.
New Johnsonville, Tenn.
E.I. DuPont Co.
Parkersburg, Va.
E.I. DuPont Co.
Wayne sboro, Va.
Energy Development Co.
Hanna, Wyo.
Formica Corp.
Evandale, Ohio
Hanraennill Paper Co.
Lockhaven, Pa.
Hanes Dye and Finishing
Winston-Salem, N.C.
Harrison Radiator-
Division CM
Lockport, N.Y.
Manu-
facturer
WF

WF

WF

WP

EB

WF

WP

WP
AAF

SH

CAR

FK

SH

HF

SH

ZU

WP

WP

SH

SH

WP
(test unit)
ICA

WF

ICA

DX

WP


Cleaning
mecha-
nism
RA, sa

RA, sa

RA, sa

RA

Sh

RA, sa

RA

RA
RA

P

RA

Tbd

POL

RA, sa

P

RA

RA, va

RA, va

P

P

RA, va

RA

RA, sa

RA

P

P


Boiler
firing
method
PC

PC

s

PC

PC

s

PC

1-PC
1-S
s

s

s

-

s

s

s

s

s

PC

s

s

PC

s

s

s

s

s


?™> A/C*
33 2.3/1

<6)-12 2.99/1

(4)-32 2.89/1

28 2.4/1

29 2.5/1

21 3.56/1

13 2/1

21 2.5/1
each
9 4/1

16 4.4/1

9 2/1

Tbd

33 4.3/1

(3)-18 3.5/1

(3)-9 3/1
f
9 2.23/1

20 1.9/1

45 1.9/1

(2)-29 4.4/1

(4)-50 4.4/1

76 1.9/1

5 2.5/1

3 3.38/1

53 2/1

(2)-13 8.3/1

30 5/1


acfm
150,000

59,000

156,400

126,000

130,000

92,000

57,000

100,000
each
40,000

70,000

42,000

Tbd

150,000

108,000

24,000

174,000

90,000

203,000

130,000

221,000

340,000

24,000

42,000

150,000

61,000

139,000


Startup
date
1976

1978

1978

1974

1975

1973

1975

1975
1974

1976

1967

Tbd

1976

1978

1976

1978

1977

1977

1975

1974

1977

1976

1978

1976

1975

1974


                                (continued)
                             55

-------
TABLE  19 (continued)

27.

28.

29.

30.

31.

32.

33.

34.

35.

36.

37.

38.

39.

40.

41.

42.

43.

44.

45.

46.

47.

48.

49.

50.

Name/ location
Hiram Walker & Sons
Peoria, 111.
Keener Rubber To.
Alliance, Ohio
Kerr Industries
Concord, N.C.
Kingsley Air Force Base
Klanath Falls, Oreg.
Long Lake Lumber Co.
Spokane, Wash.
Lubrizol Corp.
Painesville, Ohio
Monroe Reformatory
Monroe, Wash.
Pennsylvania Glass Sand Corp
Union, Pa.
Republic Steel
Warren, Ohio
Simpson Timber Co.
She 1 ton, Wash.
Sorg Paper Co.
Middletown, Ohio
Uniroyal, Inc.
Painesville, Ohio
Uniroyal, Inc.
Mishauaka, Ind.
University of Illinois
Chicago, 111.
University of Iowa
Oakdale, Iowa
University of Minnesota
Minneapolis, Minn.
University of North Carolina
Chapel Hill, N.C.
University of Notre Dame
South Bend, Ind.
Utah-Idaho Sugar Co.
Moses Lake, Wash.
U.S. Navy
Hawthorne, Nev.
U.S. Steel Co.
Provo, Utah
Westinghouse Electric
Richland, Wash.
Westvacp
Tyronne , Pa .
Witco Chemical
Bradford, Pa.
Manu-
facturer
Tbd

WF

ES
(test unit)
SH

MP

SH

ICA

FD

WF

SH

ZU

SH

Tbd

DV

ES

CAR

WP

WF
(test unit)
EB

ICA

WF

MP

WF

WF

mecha-
nism
Tbd

P

Var

P

P

P

Sh

P

RA, sa

POL

RA

P

Tbd

P

Tbd

RA

RA

P

Sh

RA

RA, sa

RA

RA, sa

RA, sa

Boiler
firing
method
PC

Hdf

S

S

HF

OF

S

PC

PC

HF

PC

PC

PC

OF

-

S

-

S

S

S

PC & gas

S

S

1-S
1-PC
Size
60

100 hp

8

5

5

8

3

6

35

51

10

9

22

8

'

20

(2)-6
each
1

22

21

(3)-90

7

20

(2)-18

A/C*
Tbd

4.36/1

3-14/1

5/1

4.5/1

4.3/1

2.8/1

7/1

3.34/1

4.3/1

1.8/1

2.6/1

Tbd

6/1

Tbd

2/1

Tbd

7/1

2/1

1.7/1

3.2/1

2/1

3.26/1

3.17/1

acfmT
270,000

5,500

35,000

24,000

24,000

35,000

11,000

40,000

275,000

230,000

45,000

42,000

100,000

35,000

Tbd

90,000

Tbd

3,500

98,000

96,000

-900,000

32,000

135,000

105,000

Startup
date
1978

1977

1974

1976

1973

1974

1976

1972

1978

1976

1972

1976

1977

1976

Tbd

1976

1978

1972

1976

1976

1977

1976

1979

1978

        (continued)
       56

-------
TABLE 19 (continued)
„ Cleaning Boiler
Name/location fairer aecha- flring (MW)
nisei met nod ^
51. General Motors Corp. SH - 7-S
Kettering & Norwood, Ohio
Three Rivers, Mich.
Warren, Ohio
52. Scott Paper Co. - - 5-HF
Everett, Wash.
53. Federal Bureau of Prions ES - S
Fed. Correct. Institution
Alderson, W.Va.
54. Tennessee State Univ. CE RA 3-coal
Nashville, Tenn.
55. Georgetown Univ. ES - FBC
Washington, D.C.
56. GSA, West Heating Plant RC P 2-S
Washington, D.C.
57. Westpoint-Pepperell, Inc. BS - coal
Opelika, Ala.
58. U.S. Gypsum Co. - P 3-S
Plasterco Plant
Saltville, Va.
59. AVTEX Fibers. Inc. EB - 5-coal
Front Royal, Va.
60. Michigan State Univ. RC RA 2-PC 2-60
61. 3-M Company ICA RA 2-S 2-14
St. Paul, Minn.

*A/C as given is in ft/Bin. To convert to m/min, multiply by 0.3048.
'To convert acfm to m3/hr, multiply by 1.699
Manuf ac tur ers : Symbo 1 s
AAF - American Air Filter Co. Hdf
CAR - Carborundum Co. Pollution Control Div. HF
DV - DaVair Inc. OF
DX - Dustex, Sub. Amer. Precision Ind . P
EB - Envirotech Corp. Buell Div. PC
ES - Enviro System Inc. Pol
FD - Fuller Co. , Sub GAIX RA
FK - Flex-Kleen - Sub. R.C. RA, sa
ME - Menardi-Southern Div., U.S. Filter Corp. S
MP - Mikropul Corp., Sub. U.S. .Filter Corp. Sh
SK - Standard Havens Inc. Sp
WF - Wheelabrator-Frye Inc. Tbd
WP - Joy Mfg. Co Western Precip. Div. Var
ZU - Zurn Industries, Air Systems Div. FBC
CE - CE Air Preheater
RC - Reseiarch-Cottrell
BS - Banco Systems, Inc.
A/C* acfmf Startup
datG

1979



260,000 1979

2.6/1 16,000 1979


50 ,000

5/1 43,000

1979

_

41,500


600,000 March
1980
1.9/1 300,000 1980
2.2/1 70,000 1978




; :
-' Hand-fired
- Hogged fuel
- Oil-fired
- Pulse
- Pulverized coal
- Pulse, off-line
- Reverse air
- Reverse air, shake assist.
- Stoker-fired
- Shaker
- Special
- To be determined
- Various
- Fluidized Bed Combustion



          57

-------
      8.  Gas  conditioning  and/or  fabric  conditioning




      9.  Structural  factors, modular, prefabdications




      10.  Maintenance factors




      11.  System controls,  automation and monitoring




      Cleaning  methods normally used for coal-fired boilers include reverse air,




reverse air with shaker assist, and pulse-jet.  Gas-to-cloth ratios are




typically 0.61 to 1.2 m/min (2 to  4 ft/min) with some installations operating




at 2.4 m/min (8 ft/min) or  higher.  The trend in the industry has been towards




negative pressure or  suction baghouses (fan located downstream  of the control




device that handles cleaned gas) and a modular design to readily adapt to a




broad range of gas handling capacities.   Fabric conditioning, where used, con-




sists of limestone, dolomite or sometimes fly ash injection to  precoat the bags




prior to initial operation.  Once  the bags become coated with a dust filter




cake, this practice is discontinued.




      There are no unusual operational procedures which would affect system




performance other than the  deliberate bypassing of the baghouse.  The main




area  for concern is that frequent  and thorough maintenance inspections of all




system components be  a basic part  of the  operating procedure.   Inspection of




the bags at regular intervals is most important.  Indications of trouble are




visible emissions and rapid changes in pressure drop (increase  or decrease).




      Variations  in fuel properties are not as critical as with  ESP technology,




but sulfur and water  content are important from the corrosion and liquid con-




densation standpoints.  It  is essential that baghouse temperatures always be




maintained above  the  dewpoint of the gas so that condensation of highly acidic




liquid will not occur on the compartment walls and, more importantly, on the




filter surface.   In the latter case, the problem of severe plugging may dras-




tically reduce gas flow and also cause irreversible bag damage.




                                     58

-------
     Although the users of fabric filtration equipment have been generally




satisfied with past equipment performance, more stringent regulations would




require solid user-vendor interaction if optimum filtration is to be attained.




     In 1978, fabric filters accounted for only about 5 percent of the market




for industrial boiler particulate control, whereas an increase to over 10




percent is projected by 1981.30




     Current research and development under EPA sponsorship includes:  assess-




ment of full-scale filter systems on two-stoker-fired boilers; assessment of




a full-scale system on a 350-MW utility boiler burning low sulfur coal; assess-




ment of combined S0x/particulate control with a baghouse; and mathematical/




computer modeling of the fabric filtration process.31




     Additional work is being done in areas concerning new fabric materials




and electrostatic effects, all of which will lead to better designs, improved




performance and reliability, and longer fabric life.




     As with ESP control systems, retrofitting can be difficult because of




severe space limitations and, therefore, can result in higher costs for




installation.  However, the problems are solvable and where such difficulties




arise, the main concern will be the overall economic impact.




2.2.2.2  System Performance—



     Of the systems listed in Tables 18 and 19, many units are not yet




operational or have operated for only brief periods.  A  summary of perfor-




mance data and related operating parameters for those  facilities  for which




test data are available is presented in Table  20.   Information on the  fuel




burned, the type of test, and  the  inlet loading to  the baghouse are  shown when




available.  Emission  rates given in units  other than ng/J  (lb/106  Btu) were




converted to  the latter units  for  uniformity  in reporting.





                                      59

-------
               TABLE 20.   PERFORMANCE  DATA  FOR COAL-FIRED UTILITY  AND  INDUSTRIAL BOILERS CONTROLLED
                            BY FABRIC FILTERS
Oh

1.



2.

3.

4.


5.

6.



7.

8.

9.

10.

11.

12.

Source
Pennsylvania Power & Light32
Sunbury Station


Colorado-Ute Elec. Assoc. 33
Nucla Station
Pennsylvania Power & Light 3i*
Holtwood Station
Nebraska Public Power
District35
Kramer Station
Adolph Coors Co. 36
Golden, Colo.
U.S. Steel Co.37
Provo, Utah


Caterpillar Tractor Co.38
Decatur, 111,
Simpson Timber Co. 38
She 1 ton, Wash.
Kings ley AFB38
Klatnath Falls, Oreg.
E.I. DuPont38
Parkersburg, W. Va.
E.I. DuPont38
New Johns onvi lie, Tenn.
Amalgamated Sugar Co. 39
Twin Falls, Idaho
Fuel analysis
I S % Ash Btu/lb
1.9 23 10,000
(15-35? petroleum coke
+ anthracite silt +
buckwheat anthracite)
0.7 14 12,500

0.7 20-35 8,000

0.4- 4 10,300
0.8

0.4 18-25 8,750

Plant gas (blast fur-
nace, mixed, and
natural)
0.55 7.0 13,300
2.9 8-9

Hogged fuel

0.8 12

2.5 7

3.2 7

0.85 NA 10,000

Type
of
test
EPA-5



EPA-5

Modified
EPA-5
EPA-5


EPA-5

NA



EPA-5

NA

NA

NA

NA

EPA-5

Outlet emission rate reported
,Ini" Given as: Calculated
loading
(gr/acf or .. ,._5
other) or other 8r/acf gtr/scfd lb/106 Btu
-3 gr/scfd 0.0045- - -0.002
0.0058


-2 gr/scfd 0.01 - 0.0031

-7* 0.042 - -

0.3? - 0.00966 0.0162 0.0457


7.9-25 - - 0.027-
Ib/hr 0.085
0.53 10.69 0.0013 0.0025 0.01
Ib/hr


See Table 68

- - - 0.005 0.027

0.008 0.02

- 0.007 0.0169

0.008 0.0188

3.39- 0.004- 0.007- 0.012-
30.4 Ib/hr 0.0345 0.0651 0.11
Efficiency
99.92



99.84

99 .,91-
99.94
96.98
(calculated)

-

99.77



-

-

-

-

_

-

      Note:  To convert  from Btu/lb to kJ/kg,  multiply by 2.326
            To convert  from lb/106 Btu to ng/J, multiply by 430
            To convert  from Ib/hr to kg/hr, multiply by 0.454
            To convert  from gr/ft3 to g/tn3, multiply by 2.29

-------
     These data, although limited, show emission levels of 1.935 to 47.3 ng/J




(0.0045 to 0.11 lb/106 Btu) and reported efficiencies up to 99.94 percent.




The emissions data for sources 8 to 11 were given only as gr/scfd outlet with




no other information on the type of test, load level excess air rate or other




operating conditions.  Therefore, calculated rates in terms of ng/J (lb/106 Btu)




should be treated as rough estimates only.




     Recent laboratory studies with fabric filters have demonstrated a strong




correlation between outlet concentration and face velocity (air-to-cloth ratio)




for a given loading and type of fabric.  The relationship, which is presented




in Figure 14, ° indicates that care must be exercised when increasing face




velocity to improve system economics.  Field pilot studies also show the same




effect, Figure 15,   although there are some inconsistencies probably due to




control problems in field experimentation.




     It must also be noted that higher gas velocities can lead to increased




filter resistance and hence greater power costs.  Additionally, increased




cleaning to reduce filter resistance will require increased cleaning energy




and may also reduce bag service life.  The costs generated by the aforemen-




tioned factors will ultimately override the advantage of smaller collector




size and less fabric area, leading to an optimum filtration velocity in terms




of total annualized cost.




     The major factors affecting boilers controlled by fabric filters are




additional maintenance requirements, potential corrosion problems, and tran-




sient operations.  Regular maintenance is particularly important with respect




to the bags.  Usually, close inspection of the stack for signs of visible




emissions and use of pressure sensors and hopper level indicators will fore-




cast potential trouble.  Corrosion problems are associated mainly with startups





                                       61

-------
to
            28.6
                FABRIC LOADING (W), gr/ft*
            57.3       85.9      114.6      143.2
                                        171.9
I  V

2 +

3 \>

4 a
 96

AVERAGE

 9ft

 97
                                                      FACE  VELOCITY
         V        V   	
INLET CQMC. (Q/m>l     m/min   It/min
     6.09           0.40      |.3
     7.01

     S 37

     4 60
                                                    0 61
                                                    3 33
ZO

5.0

11.0
      NOTES SOLID  LINES  ARE  CURVES PREDICTED BY  MODEL
            SYMBOLS REPRESENT ACTUAL  DATA  POINTS
K>
   0
   20       40       66                 r
                 FABRIC  LOADING (W). g/m2
                                                                      0.44
                                                                      4.4 K I0
                                                                            ~*
                                                                     I4O
   Figure 14.   Predicted and  observed outlet  concentrations  for bench
                 scale  tests.   GCA fly  ash and  Sunbury fabric.1*0
                                     62

-------
     O.I

    0.08

    0.06


    0,04
o
I-
o:
i-
UJ
a.
    0.02
    0.01

  0.008



  0.005
O  NOMEX
A  DRALON T
0  GORE-TEX
•  TEFLON
                  0.91          1.83        2.74        3.66
                   (3)          (6)         (9)          (12)
             AIR-TO-CLOTH RATIO,  m/min (ft/min)
          Figure 15.  Penetration versus air-to-cloth ratio
                    for different bag materials.41
                                 63

-------
and shutdowns (or fluctuating loads) at which time gas stream temperatures may




fall below the acid or moisture dewpoint.  Bypassing or preheating the baghouse




prior to system startup, continuous gas recirculation during brief shutdowns,




and/or sufficient insulation (7.6 cm or 3 inches of mineral wool or fiberglass)




will minimize corrosion problems.  The above items indicate that operating




conditions such as temperature, velocity, pressure, airflow and fan static




pressure need to be monitored closely to guarantee effective fabric filtration.




     The test data that have been presented are limited, such that there is




yet no solid data base to project the likely effective service lives of the




fabrics.  However, these data do show that low emission levels are achievable




for all types of fuels, a major concern of boiler operators.  Although vendors




will usually guarantee to meet any emission level down to about 0.046 g/scmd




(0.02 gr/scfd), they seem to be reluctant to specify emissions in terms of




ng/J (lb/106 Btu).




     Performance with respect to visible emissions is excellent with no visual




opacity being the general rule.  Where visual emissions do occur, they are




usually indicative of system startup or bypass leakage due to a ruptured bag(s).



Also, since most emissions are due to gross tears or ruptures in the bags,




downstream and upstream particle size distributions are similar.




2.2.3  Wet Scrubbers




2.2.3.1  System Description—




     Although collection of particulate matter by scrubbing devices has been




ascribed to several capture phenomena, the two most important mechanisms are




usually inertial impaction and Brownian diffusion.  The former process is




responsible for collection of particles greater than about 0.5 ym whereas the




latter applies mainly to the smaller size fractions.







                                      64

-------
     Small particles are recovered from the gas stream by direct contact with




suspended liquid droplets or by adhesion to the scrubber walls followed be




subsequent flushing into a waste disposal system.




     Where scrubbing is applied for control of fly ash from combustion pro-




cesses, the selection is usually confined to several types:  gas atomized spray




scrubbers such as Venturi and flooded disc scrubbers; fixed-bed absorbers such




as sieve tray units; turbulent contact absorbers (TCA) (or moving bed scrubbers);




and high pressure spray impingement scrubbers.  In those systems where gas tem-




peratures and moisture content are high, the introduction of low temperature




sprays produces a condensing atmosphere that enhances supportive collection




mechanisms described as flux force/condensation processes by Calvert, et al.1*2




Although the above processes almost always contribute to particle collection




in all wet scrubbers and gas absorbers, it is very difficult to establish their




quantitative roles.




     Schematic drawings of the more common scrubber designs are shown in




Figure 16.43




     The main advantages of wet scrubbers are listed below:




     •    they collect both particulate materials and gases




     •    they function in wet, corrosive, and/or explosive gas




          atmospheres




     •    they may occupy less space than either fabric filter




          or electrostatic precipitation systems.




     The main disadvantages are the following:




     •    the energy penalties associated with their operation




     •    possible high effluent opacity and the necessity for reheat




     •    potential corrosion problems
                                       65

-------
    GAS
     IN
                        LIQUID
                         OUT
           (a) MOVING BED
                                     ENTRAPMENT
                                       SEPARATOR
                                         LIQUID IN
                                       LIQUID
                                     OVERFLOW
                                        GAS & LIQUID
                                        TO ENTRAPMENT
                                        SEPARATOR
               LIQUID
                 IN

             (b)VENTURI
Figure 16.  Several types of scrubbers used for particulate control.4^
                          66

-------
                     GAS OUT
                                LIQUID
                                LIIU
                             _^^^
                                >PLATES
OS
            LIQUID
          DOWNCOMER
                       o o o o o o o o;c
                      ooooooooo
                      'OOOOOOOOO
                      ooooooooo
                       ooooooood
                      ooooooooo
                       ooooooooo
                                                                SIEVE
                                                        PERFORATIONS
                                                                FOAM

                                                                PLATE
LIQUID
 OUT
                                      (c)SIEVE PLATE/TOWER
                              Figure 16 (continued).

-------
     •    exceptionally high pressure loss to attain equivalent




          (ESP or filter) efficiencies




     •    poor efficiency for fine particulates




     •    the introduction of a water-solid waste disposal problem




     •    water availability and land requirements may also restrict




          use of scrubbers in certain geographical areas.




     Some of the more important subsystems in a scrubbing system are:  liquid




pump, piping, sprays and recycle tank, mist eliminator or entrainment separator,




provisions for reheat if required (either by steam coils or by direct oil or




gas firing) and waste storage and disposal.  Consideration must be given to




the construction materials used in the basic unit, especially for scrubbers




where the slurry is recirculated without benefit of alkaline additives and




the pH may fall below 3.  For acid environments, 316L stainless steel is in-




adequate and Fiberglas reinforced polyester or rubber-lined steel are usually




used.  In the same context, where the particulate scrubber precedes a gas




absorber, the fan will generally be located downstream of the absorber so




that it will not be subjected to low pH liquid carryover.




     When a Venturi scrubber is chosen, it is desirable to install a variable




throat system (enabling control of pressure drop) so as to be able to maintain




a constant efficiency at varying boiler loads.




     Another component that may be required is a liquid cyclone or thickener




to remove large particles from recycled liquid streams before reintroduction




to spray nozzles to minimize plugging.




     Although particulate control by wet scrubbing is a well-established




technology, it, like fabric filtration, has only been adopted within the last




10 to 20 years to control fly ash emissions from power boilers.  Although the





                                      68

-------
 use of  wet  scrubbers  in Great Britain for cleaning boiler  flue gases  dates




 back to the 1933  to 1955 era, it was  not until the early 1960's that  this




 technology  was  applied  to fossil fuel-fired  boilers in the U.S. for combined




 particulate collection  and S02 absorption.£|lt




      Wet scrubber sales for industrial boiler  particulate  control  in  1978,




 which are estimated at  $3 million (5  percent of total  nonboiler and industrial




 boiler  applications), are projected to rise  to about $12 million (12  percent)




 in 1982.^   Related statistics for 1976 were $1 million in sales and  2 percent




 of total wet scrubber market.




      It appears,  therefore, that wet  scrubbers, like fabric filters,  hold a




 relatively  small  share  of the present market.   It  is expected that their




 application may increase over the next several years,  depending on sulfur di-




 oxide and particulate removal requirements ultimately  required.




      Because of the auxiliary equipment required in a  scrubbing system (liquid




 pumps,  recirculation tank(s), reheaters,  etc.)*  good maintenance is most im-




 portant  to  ensure  equipment longevity.




     Major  research and development efforts  are directed at  improved  geo-




.metries  for more efficient  contacting of liquid and gas streams while reducing




 energy  consumption.  However, it is not  expected that  recent innovations will




 improve  particulate control in the boiler application  area.   Notwithstanding,




 some  designs that  are being used in asphalt  concrete plants  and metal smelting




 operations  appear  to show promise.




      Application of wet scrubbers to  the industrial boilers  under  consider-




 ation appears limited since these devices are  inherently inefficient  for sub-




 micron particles.   However,  they have been used on  pulverized coal-fired
                                       69

-------
boilers (whose emissions have been shown to range from 10 to 20 ym) with a




fair degree of success.  (See Table 22.)




     Major factors in the design of wet scrubbers for particulate control are




gas velocity, gas flow versus spray direction, materials of construction,




liquid recirculation, and pH control.




     For the venturi scrubbers, gas velocities may range from 61 to 183 m/s




(200 to 600 ft/s) while liquid-to-gas, ratios  (L/G) vary from 1.0 to 2.0 liters/m3




(8 to 15 gal/1000 ft3).  Pressure drops range from 1.5 to 25 kPa (6 to 100




inches W.C.) depending on application and desired removal efficiency.  The




liquid is usually introduced in the throat region at right angles or concurrent




to gas flow direction.



     Impingent plate scrubbers operate at superficial gas volocities of 2 to




3 m/s (8 to 10 ft/s), L/G values of 0.4 to 0.7 liters/m3 (3 to 5 gal 1000 ft3)




and pressure drops of 0.25 to 2.0 kPa (1 to 8 inches W.C.)..




     For TCA scrubbers, pressure drops can vary from 2.5 to 5.0 kPa (10 to




20 inches W.C.) while L/G ratios may be as high as 6.7 liters/m3 (50 gal/




1000 ft3).



     The transient, nonsteady state periods of boiler operation are the most




critical in terms of control system performance.  At these times, temperature,




airflow, and particulate loadings show extreme variations which usually affect




(adversely) system performance.  Once steady state operation is reached,




correct settings for liquid injection rate, head loss, and water/solids re-




circulation rate can be easily maintained.  The chance for incorrect settings




is a real possibility, given the varying loads often encountered with process




steam boilers.
                                     70

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     Maintenance is especially critical in wet scrubbing systems due to the




corrosive nature of sulfur gases which are absorbed in most scrubbers even




when sulfur removal is not the main objective.  Since there are more ancillary




components with this technology, there are more areas for troublesome operation.




Hence,  frequent and thorough inspections of equipment are a must.




     Variations in fuel properties are important, especially as they affect




the resultant particulate loading that reaches the control device.  Since




scrubber performance has  been found to depend on the  inlet loading,  decreases




or increases in ash content will affect the ultimate removal efficiency.




(This will be discussed in more detail, subsequently).  Variations in ambient




conditions affect visible emissions from a wet scrubber in that outside tem-




perature determines the volume of the water vapor plume before dissipation




(plume volume being inversely proportional to temperature).  Because of water




vapor content, smoke reading is difficult on these systems and opacity vio-




lations are more difficult to datect.




     As discussed previously for ESP and fabric filtration technology, retro-




fit installations are expected to be more costly and more difficult.




     Even though flange-to-flange scrubber modules take up less space than




equivalent-sized precipitators and baghouses, the additional equipment re-




quired may create space problems in some industrial plants which have limited




amounts of accessible area.  In such situations, additional piping and duct




work will increase  capital costs because of  the added materials required.




Moreover, operating costs will increase because of increased pressure loss




in moving the air stream and pumping liquids or slurry.
                                       71

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2.2.3.2  System Performance—


     Attempts have been made to relate the performance of a wet scrubber to


the pressure drop and liquid-to-gas ratio, L/G.  Correlations with the former


parameter are indicated in Figure 17. **6


     Because the high velocities and reduced droplet sizes associated with the


collection of particles less than 1 ym require increased energy expenditure,


the operating pressure loss across Venturi scrubbers, for example, provides


an indirect measure of particle collection capability.  The relationship is


reflected by the data given in Figure 18 in which the ordinate shows the


size of the unit density sphere collected at 50 percent efficiency (aero-



dynamic cut diameter) .^


     A wide range of pressure drops can be required for efficient collection


depending on the type of scrubber, the dust characteristics and the liquid-to-


gas ratio, L/G.  Usually, combustion processes utilizing scrubbers for par-


ticulate collection operate in the low-to-moderate energy range of 1.24 to



5.0 kPa (5 to 20 in. W.C.).


     Given a coal fly ash whose size parameters are 13 vm for mass median


diameter (HMD) and 3.0 for the geometric standard deviation (a ), the range
                                                              &

of overall weight collection efficiencies have been estimated by GCA as listed


in Table 21 for the indicated pressure losses.  Gas temperature was assumed


to be 149°C (300°F) in the above case for the scrubbing system.


     In Table 22, Gronhovd and Sondreal1*8 have summarized the performance of



various scrubber designs on low-rank U.S. western coals having sulfur contents


ranging from 0.5 to 0.8 percent.  Generally, particulate removals exceeded



98 percent with incidental sulfur capture of 20 to 40 percent.
                                     72

-------
       0.5
       0.01
                      PRESSURE  DROP, KPo
                 1.24    2.5     3.7     5.0    6.2
                  5      K)      15     20     25     30
                    PRESSURE DROP,INCHES  W.C.
Figure 17.   Scrubber particulate performance on coal-fired boilers.
                                  73

-------
    5.0
:L
 fr
tr
2
<   1.0
o
u

o   0.5
0
o

-------
                  TABLE 21.   OVERALL PARTICULATE COLLECTION
                             EFFICIENCIES FOR VARIOUS PRES-
                             SURE DROPS IN A SPRAY SCRUBBER*
                          "             Percent efficiency
kPa
1.24
2.5
5. a
7.5
(in. H20)
( 5)
(10)
(20)
(30)
(overall)
88.0 -
91.9 -
94.9 -
96.2 -
94.9
97.0
98.4
98.9

                 *Dust characteristics: fly ash
                    MMD = 50% size « 13 ym

                    „   - 87% size _   n
                    °g  - 50% size - 3'°

     Additional performance data were available from a previously cited report

for the Edison Electric Institute.49  These data, showing test results for two

western and one eastern power stations, are presented in Table 23.   The Venturi

scrubber at Pennsylvania Power & Light's Holtwood Station is installed in

parallel with a fabric filter and during the performance test the scrubber

was handling 59 percent of the flow.  An efficiency of 99.4 percent correspond-

ing to a mass emission rate of 55.9 ng/J (0.13 lb/106 Btu) was obtained while

the Venturi was operated at 1.5 kPa (6.2 inches W.C.).  It is important to note

that at this particular station, the opacity of emissions ranges from 35 to

40 percent (exclusive of soot-blowing) and is therefore allegedly out of com-

pliance with the state's 20 percent opacity limit.  It seems probable that the

scrubber is unable to collect the fine particle fraction of the gas stream which

could account for 10 to 20 percent of the total particle surface area present.

     The other two stations for which scrubber information was available are

Valmont and Cherokee of the Public Service Co. of Colorado.  Valmont's Unit

                                      75

-------
               TABLE 22.  SUMMARY DATA  ON PARTICULATE SCRUBBERS  OPERATING ON  BOILERS  BURNING
                            LOW-RANK  WESTERN U.S.  COALS48  (1976)
Arizona Public
Utility Company
Station

Location 	 	 	
Scrubber startup date
Reagent

Vendor

Design and Operating Parameters:
Scrubber type

No. of equipped boilers
No. of scrubber modules per boiler
Total capacity equipped with
scrubbers, MW
Reheat
Bypass
Capital cost, $/kW
Coal, atate, rank
Sulfur in coal, pet
Ash in coal, pet
Calcium oxide in ash, pet
L/C, gal /I, 000 actual ft3*
AP, total inches H20*
Open or closed loop

Water requirement, acre-tt/MW-yr*
Scrubber power consumption,
pet of generating capacity
Inlet dust loading, gr/ft35
	 (g/m3) 	
Inlet S02, ppm, v/v dry
Particulate removal
S02 removal, pet
Availability, pet
Service Company
Four Corners,
r'arnlngton,
New Mexico
12/71
none

Chemico


venturi

3
2
575
yes
no
52
NM subblt
0.7
22
• It
9
28
open

5.91

3-4
12
(27.5)
650
99.2%
30
80
Pacific Power and
Light Company
Dave Johnston,
Glenrock,
Wyoming
4/72
none

Chemico


venturi

1
3
330
no
no
24
WY subbit
0.5
12
20
13
15
intermittent
open
2.42

2.3
4 '
(9.15)
500
99%
40
HA*
Public Service Company of
Colorado
Valmont,
Boulder,
Colorado
11/71
none

UOP


3-stage TCA

1
2
118
yes
yes
30
WY subblt
0.6
5.2
20
50
10-15
open

2.88

5.09
0.8
(1.83)
500
97.5%
40
80
Arapahoe ,
Denver ,
Colorado
9/73
none

UOP


3-stage TCA

1
1
112
yes
yes
41
WY subbit
0.6
5.2
20
50
10-15
open

2.68

4.02
0.8
(1.83)
500
97.5%
40
20-40
Minnesota Power and Light
Company
Clay Boswell,
Cohasset,
Minnesota
5/73
none

MCrebs


high pressure
spray
1
1
350
no
no
NA
MT subbit
0.8
9
11
8
4
open

4.29

0.86
3
(6.86)
800
99%
20
NA
Aurora,
Aurora,
Minnesota
6/71
none

Krebs


high pressure
spray
2
1
116
no
no
NA
MT, subbit
0.8
9
11
8
4
open

30.2

0.86
2
(4.58)
800
98%
20
NA
Montana Dakota
Utilities
Sidney,
Sidney,
Montana
12/75
Limestone for
pH control
Research-
Cottrell

flooded disk
venturi
1
1
50
no
yes
90
MT lignite
0.7
8.5
25
15-25
13
closed

1.46

1.2
1.25
(2.86)
700
98%
NA
NA
 To convert from gal/1000 aft3 to liters/am3, multiply by 0.1337.
fTo convert from in. H20 to kPa, multiply by 0.2488.
*To convert from acre-ft/MW-yr to m3/MW-yr, multiply by  1233.
^Volume at one atmosphere and 15.5°C (60°F) for dry gas.
 NA • Data not available.

-------
            TABLE 23.   PARTICULATE SCRUBBER PERFORMANCE DATA FOR THREE  COAL-FIRED  BOILERS49

Power company and
station
Penn. Power & Light,
Holtwood
Public Service Co.
of Colorado,
Valmont
Cherokee

Boiler No.
size
No. 17
79 MW
No. 5
166 MW

No. 4
350 MW
Scrubber
type
Venturi

UOP -.
TCAh

UOP -
TCAh
Flow rate
(acfm)a
229,800

350,000


1.182 x 106

A P
(in. Hi;0)l
6.2f
0.38
10-18


10-18

Test
, efficiency
(percent)
99.4

97


99.6

L/G ratio
(gal/1000 aft3)c
15.4

58.3


55.3

Emission
(lb/106 Btu)d
0.13

0.04


0.04

rate
(gr/sft3)6
0.047

0.02


0.02


3To convert  from acfm to m3/hr, multiply by 1.699.




 To convert  from in. H?0 to  kPa, multiply by 0.2488.




GTo convert  from gal/1000 aft3  to liters/am3,  multiply* by 0.1337.




 To convert  from lb/106 Btu  to  ng/J, multiply  by  430.




6To convert  from gr/sft3 to  g/sm3, multiply by 2.29.




 Across  venturi throat.
g
 'Across  mist eliminator.
hTurb
ulent contact absorber.

-------
No. 5 has a turbulent contact absorber  (TCA)  in parallel with a  "cold" Elecro-




static precipitator while Cherokee's Unit No. 4 has  the same arrangement.




Both units have achieved an emission rate of  17.2 ng/J  (0.04 lb/106 Btu) while




operating at  2.5  to 4.5 kPa  (10  to  18 inches  W.C.).




     In  addition  to these data,  a survey was  made of 16 flue gas desulfur-




ization  units, because of the limited use of  scrubbers  in  combustion  appli-




cations  for particulate collection  alone.   These data are  presented in



Table 24.50-65  It should be noted  that  all values are actual measurements




except for inlet  loadings which were calculated based on the heating  value




and ash  content of the coal and an  assumed  80 percent ash  entrainment in the



flue gas.  These data are displayed in Figure 19.




     As expected, a strong correlation is evidenced between penetration and




inlet concentration, despite the fact that  the data point  pairs  also  reflect




significant variations in L/G ratio and  operating pressure loss  (Table 24).




For example, one expects to see increased particle collection whenever the




L/G value or the collection resistance increases.




     The most important conclusion to be drawn from Figure 19 is that




scrubber weight efficiencies are high (and penetrations low) when there is no




upstream precleaning device in the system.   Basically, Figure 19 states




that scrubber efficiencies are strongly dependent on inlet loading such that




it is extremely risky to assume that high,~99 percent collection, is  routinely




attainable.   The increase in efficiency with loading is attributed to  the




increased chances for particle-to—particle and fparticle-to-water droplet




collisions when the concentration of the particles in the gas stream increases.




     In summary, the scrubber performance data presented bear out the  follow-




ing important relationships:






                                     73

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TABLE 24.  WET  SCRUBBER (FGD) PERFORMANCE FOR PARTICULATE CONTROL50-65

1.
2'.
3.
4.
5.
6.
7.
a.
9.
10.
11.
12.
Power station
Reid Gardner ,
Nevada Power Co. 50
Mohave
So. Calif. Edison51
Will County52
Commonwealth Edison
Hawthorne
Kansas City Power
and Light53
La Cygne
Kansas City Power
and Light 5I*
Lawrence
Kansas City Power
and Light S5
Paddy ' s Run
Louisville Gas
and Electric 56
Cane Run
Louisville Gas
and Electric 57
Phillips
Duquesne Light 58
Elrama
Duquesne Light •"
Cholla
Arizona Public
Service 60
Colstrip
Montana Power 6*

Type
Venturi and
sieve tray
Four-stage TCA
absorber
Venturi and
two-stage
sieve tray
scrubber
Marble bed
Venturi and
two-stage
sieve tray
Venturi and
marble bed
absorber
Marble bed
two-stage
TCA
absorber and
spray tower
Venturi one-
stage
Venturi three-
stage
(four parallel
modules)
Venturi
Flooded disc
scrubber and
absorber
Venturi and
spray tower
Scrubber description
> luieL concentration r OuuleL concentration r,. .
T/rraMn "vntem resi qf-anrp efficiency
(gal/ 1000 ft3) (in. water) * lb/106 Btu§ gr/sft3" lb/106 Btu5 gr/sft3' percent
10 (venturi) 20 - 25 1.36 0.3 - 0.6 0.05 0.02 95.6-96.3
0.145 0.07 0.0026 - 98.2
34 (varies 25 0.85 - 0.16-0.19 - 78-81
with load)
10-12 9.1 - 0.18 - 98.8
33 21 - 24 21.2 - 0.15 - 99.3
20 (venturi) 12 7.85 3.0 0.063 0.025 99.2
30 (tower)
38 16 0.328 0.2 - 0.4 0.033 0.027-0.035 90.0
50 - 60 11 0.12 0.08-0.09 0.028 0.02 76.5
30 - 70 10 - 12 3.2 - 0.046 - 98.5
30 - 50 10 - 12 12.8 - 0.02-0.07 - 99.4-99.8
49 12 2.4 2,0-2.5 0.027 0.008-0.01 98.9
15 (venturi) 17 6.88 - 0.033 - 99.5
18 (tower)
                                 (continued)

-------
                                                 TABLE 24  (continued)
Power station
13. Sherburne
Northern States
Power ^2
14. Widows Creek
Tennessee Valley
Authority63
15. South West
00 Springfield City
0 Utilities61*
16. Green RiverSS
Kentucky Utilities
Scrubber description
Type L/G "tlo* J
(gal/1000 ft3)
Venturi and 27
marble bed
Venturi and 50
marble bed
TCA 60
absorber
Venturi and 35
TCA absorber

System resistance ' ' ' e « e //
(in. water) T lb/106 Btu3 gr/sft3" lb/106 Btu3 gr/sft3
22 - 25 8.6 4.0 0.078 < 0.04
(design
estimate)
30 10.0 5.6 0.128
(design
estimate)
13 0.022 0.01 0.017

9.2-12.2 1.87 - 0.14

Scrubber
efficiency
99.1

98.7

23.0

92.5


 To convert  from  gal/1000 ft3 to liters/am3,  multiply by 0.1337.




 To convert  from  inches water to kPa, multiply by  0.2488.




^Inlet concentration based on heating value and ash  content of coal and an assumed 80  percent ash entrainment in flue gas.
§
 To convert  from  lb/106 Btu to ng/J, multiply by 430.




 To convert  from  gr/sft3 to g/sm3, multiply by 2.29.

-------
00
M
                      100


                        7


                        5
                   o
10.0



   T


   5
                   Ul


                   HI
                   a.
                    z
                    ui
bJ
a.
                      O.I
                              8.6
                        INLET CONCENTRATION, (Cj ) ng/J



                       43                 430
                                                                4300
                               LINEAR  REGRESSION LINE


                                  CORR. COEF: = -0.84
                              PERCENT Pn=4Cj
                                             -0.655
                                                 I   It  I TTTT
                        0.01
             I	1—I I I  I I I	1	1	L_J	
                 5    o. I     2       5     L0     2       5



                     INLET CONCENTRATION (C j ) Ib/IO6  Biu
                                                                10.0
                                                                     O
                     Figure 19.   Variations in fly ash  penetration with  inlet concentration for

                                  16 FGD systems presented in Table 24.

-------
      1.   Emission  rate  is strongly dependent on  fly ash  loading to



          the scrubber




      2.   High pressure  drops are required to capture  submicron




          particles




      3.   Opacity is difficult to predict or measure and  in some cases




          may actually be increased by scrubbing  systems.




      Boiler deratings are sometimes necessary to  operate  scrubbers because of




their high energy consumption.  On large utility  boilers, this can amount to




as much as 5 to 10 percent of rated capacity.  Corrosion  is certainly possible




in particulate scrubbers because of the low pH of recirculating water streams.




Thus, rubber-lined pumps and/or fiberglass reinforced  polyester materials of




construction are often required.




     As with the other control technologies, much of the  available performance




data  are from the utility sector (pulverized coal burning installations).




Although there could be  an advantage with the smaller  size industrial units




with  respect to fewer gas flow distribution problems with a scrubbing tower,




the relative cost of the apparatus might be greater because of the larger




fraction of the total cost borne by the instrumentation and special maintenance




needed to guarantee effective performance.




     Again, vendor guarantees are site specific depending on operating flow




rate ranges, fuel properties, and local emission codes,




2.2.4 Mechanical Collectors (Multitube Cyclones)




2.2.A.I  System Description—




      Multitube cyclones, which represented the most common type of inertial




collector used for  fly ash collection before stricter  emission regulations




were  enacted, depend upon centrifugal forces (i.e., inertial impaction) for
                                     82

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particle removal.  They consist of a number of small-diameter cyclones  (~5 to




30.5 cm diameter)  (~2 to  12 inch diameter) operating in parallel and having a




common gas inlet and outlet.  The flow pattern differs from that in a conven-




tional cyclone in  that the gas, instead of entering tangentially to initiate




the swirling action, makes an axial approach to the top of the  collecting




tube wherein a stationary "spin" vane positioned in its path imparts a  rota-




tional motion to the gas.  Figure 20 illustrates a typical multitube cyclone




along with a view  of a single tube.




     The only supplemental equipment required for this relatively simple




inertial design are dust hopper level indicators, vibrators and/or heaters




and an ash conveying and removal system.




     Fly ash collection by multitube cyclones is a well-established technology




that has been applied for many years on all types of coal-fired industrial and




utility boilers.   However, comparative sales for 1974 and 1975, 24.5 and 17.3




million dollars,66 respectively, indicate that because of efficiency limita-




tions they now function mainly as precleaning devices.




     In general,  users of inertial collection have been quite satisfied with




their operation (mostly as precleaners) primarily because of their minimal




maintenance requirement.




     Major R&D efforts for mechanical collectors have been directed at en-




hancing the gas spin properties through the use of specially-shaped stationary




vanes and the introduction of secondary air to minimize dust contact with the



wall of the collector in the inlet region of the unit.   If successful, the




need for abrasion  resistant materials or extra heavy construction can be par-




tially eliminated.  However, it is not expected that significant improvements




can be made in overall collection efficiency for the fine particulate emis-




sions from pulverized coal systems, for example.




                                      83

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                      CENTRIFUGALLY
                         -CAST
                       COLLECTING
                         TUBE
                           DUST
                         DISCHARGE
                           BOOT
                	   DUST DISCHARGE

COMPLETE COLLECTING TUBE ASSEMBLY
             Figure 20.   Multitube cyclone and exploded view of a  single tube
                           (courtesy of Zurn Industries).

-------
     The most critical design parameters for a cyclone collector are the in-




let gas velocity, the diameter of the tubes, the number and angle of axial




vanes, and the construction materials.  Most multitube cyclones are axial-gas




entry units designed for gas velocities of 25.4 to 35.6 m/sec (5,000 to




7,000 ft/min) in the entry vane region.57  Such high velocities require the




use of hard alloy materials for the vanes (gray or white iron or chromehard)




to minimize vane erosion.  Particle collection efficiency for most cyclonic




devices varies inversely with the diameter of the collecting tube which gov-




erns the gas stream radius of curvature.  A reduction in tube diameter in-




creases the radial force acting upon the particles so that their transit to




the wall region is accelerated.




     The main considerations in evaluating construction materials are:




     •    Gas temperature




     •    Abrasiveness of dust particles




     •    Corrosiveness of gas stream




     In addition to the above factors during normal operation, transient con-




ditions such as startup, shutdown, or emergency upsets must be anticipated in




the design.  Moisture or sulfuric acid condensation is most important in coal-




fired systems since fly ash can become very sticky if cooled to the point where




condensation takes place.  Some preventive measures to alleviate this problem
are:
          Preheating the system before startup




          Continuing hot gas airflow after shutdown until the system




          has been completely flushed of dust and humid gas




          Insulating duct work, cyclone body, and hopper




          Providing artificial heating of the hopper by electric




          heating or steam tracing prior to insulation application.




                                      85

-------
     There are no specific operational procedures related to the boiler/control




device system that would severely hamper system performance other than the




transient moisture condition mentioned previously.  An attractive feature of




most inertial devices is that the operating pressure loss is nearly independent




of inlet dust loading as it is with electrostatic precipitators.  As with other




control devices, maintenance is very important although the lack of moving




parts significantly reduces the necessity for detailed full-time maintenance




inspections.  However, it is important that cyclone pressure loss be accurately




monitored so that any tendency to plug can be signaled at once by an appro-




private alarm system.



     Variations in fuel properties are not critical unless coal-sulfur content




changes appreciably from that specified when the control equipment was designed




and provisions have not been taken to adequately insulate the unit or to use




the proper construction materials.



     Retrofit installations in the mechanical collector category will probably




be nonexistent simply because it is highly unlikely that any practical design




changes could be made that would enable the devices to meet any future




stringent emission requirements.



     In some cases it has been found more practical to leave in place the




existing cyclone units and simply append in series the necessary high efficiency




collectors such as fabric filters or ESP systems.  In has occasionally been




necessary, however, to remove or alter the multiclone tubes so that pressure




loss through the device could be lowered sufficiently to meet draft fan




capabilities.



     The addition of high efficiency equipment may not be possible in many




situations due to space limitations.  Hence, removal of the inertial device




may be necessary.  An attempt to operate in very cramped quarters (leaving




                                     86

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the multicyclone in place) could also disturb the gas flow pattern into the




high efficiency collector, which would be particularly critical in the case of




an electrostatic precipitator.  An example of a case where the control system




could not be retrofitted would be an installation having a stack on the roof




with a very short breeching between boiler and stack and a roof construction




incapable of bearing added weight.  Obviously, there are many possible field




configurations where the addition of a supplemental control device would




severely effect overall system performance because of poor gas flow distribution.




2.2.4.2  System Performance—




     The performance of any mechanical collection system is primarily a func-




tion of the aerosol particle size.  Many types of "grade" efficiency curves




are available such as the curves shown in Figures 21 and 22.   Figure 21




illustrates comparative collection efficiencies for two axial-entry cyclones




with diameters of 15.2 and 30.5 cm (6 and 12 inches), respectively, as a func-




tion of percent of dust under 10 ym.68  If, for example, one considers a pul-




verized coal unit with approximately 50 percent of the fly ash less than 10 ym,




then efficiencies of about 85 and 73 percent would be expected for these two




cyclones, respectively.  Figure 22 shows estimated efficiencies as a func-




tion of particle size.69  If the size distribution is available for the inlet




dust, the overall collector efficiency may be estimated from Figure 22.  Both




of these curves appear to be somewhat optimistic in terms of collection of




particles 10 ym or less based upon available performance data.  Current




performance data for mechanical collectors are limited since these devices




are often used in conjunction (series) with another control device in which




only the overall efficiencies are given.  Some test data were available,




however, from a previous EPA-sponsored program, Table 25.70>71  Although
                                     87

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         u
         111
         III
         o
         u
100

 95

 90

 85

 80

 75

 70

 65
     (30.5 em)
      12 in.

»p. gc OF OUST:2to3

PRESSURE DROP « 3 in WATE
                                        GAUGE
                  10  20  30  40  50  60  70  80
                   ptrcent  OF OUST UNDER  10/tm
 Figure 21.  Typical overall collection efficiency  of
              axial-entry cyclones.6 8
       99.9
       99.5


         99
        90
        50
                   5       10       IS       20
                     PARTICLE SIZE, microns
                                       25
Figure  22.   Efficiency  versus particle  size for various
             multicyclone systems.^9
                           88

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tests 20/21 showed the lowest emission rate, there were two 180° bends in the

system in addition to the multitube cyclone which probably accounted for sig-

nificant dropout of material.  As can be seen from these data, emission rates

via this control technology are too high to meet the intermediate or stringent

emission control levels.

     It should be noted that most data are based on stoker firing which usually

produces a coarser fly ash than that generated by pulverized coal.  (See

Table 13.)

     The test data presented in Table 25 are predominantly for small utility

boilers (-73 MW or 250 x 106 But/hr heat input) where mass loadings would be

slightly lower than encountered with industrial coal-fired units because of

firing method, method of combustion regulation and variations in load level.

           TABLE 25.  PERFORMANCE DATA FOR  COAL-FIRED BOILERS
                      EQUIPPED WITH MECHANICAL COLLECTORS.70'71

Test/location
18/11

20/21

26/12

27/14

28/14

134/30
165/35
Boiler _. Steam load*
No. Furnace type (103 Ib/hr)
1 spreader stoker
water tube
3 spreader stoker
water tube
24 pulverized
water tube
1 spreader stoker
water tube
4 spreader stoker
water tube
- spreader stoker
chain grate
110

63

181

120

162

82
104
Emission rate''"
(lb/106 Btu)
2.83

0.1915

0.9931

2.016

0.339

3.05
0.31
      *To convert from Ib/hr to kg/s,  multiply by 1.26 x lO

      +To convert from lb/106 Btu to ng/J,  multiply by 430.
                                     89

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     Pressure drops through mechanical collectors are on the order of 0.75 to




1.5 kPa (3 to 6 inches W.C.) and boiler deratings are not required.  Other




potential impacts on boiler operation such as corrosion, startup and shutdown,




and additional maintenance requirements, have been discussed previously.




     Since the difference in inlet concentration is not expected to exert any




significant effect on efficiency per se, one should expect to see proportionately




higher emissions with industrial boilers.  On the other hand, efficiency data




from utilities sources can probably be translated directly provided that mon-




itoring and maintenance regimens are similar.




2.3  CONTROLS FOR OIL-FIRED BOILERS




2.3.1  Electrostatic Precipitation




2.3.1.1  System Description—



     Because detailed design parameters, subsystems, development status, main-




tenance aspects and other relevant criteria have been discussed previously in




subsection 2.2, only those items which are peculiar to oil-fired systems will




be analyzed herein.



     Although applications of ESP technology to oil-fired boilers are limited,




there are facilities utilizing ESP systems, most of which were designed orig-




inally to collect coal fly ash.  Boilers now firing oil which formerly burned




coal, have employed the use of existing precipitators, sometimes with little




or no modification.




     Precipitators employed for service on oil-fired systems would utilize




special systems for periodic removal of any sticky, tar-like ash deposits




from the collecting plates.  These deposits can develop because of the hygro-




scopic character of the oil fly ash.72  If the oil ash is allowed  to accumulate




on cool surfaces where condensation and moisture absorption can take place,
                                     90

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 they may be a potential cause of arcing and short circuiting.  Locating the




 precipitator upstream of the air heater (if one exists) is one possible means




 of maintaining all collector (and electrode) surfaces at high enough tempera-




 tures to minimize ash buildup on high tension wires, insulators and in the




 dust hoppers.




     The carbonaceous content of fuel oil results in a lowered resistivity




 level for the ash, roughly 107 to 109 ohm-cm.  Occasionally, the solids are




 so conductive that they fail to hold a charge and therefore are easily re-




 entrained in the gas stream.  The above factors combined with the extremely




 fine size of oil particulate emissions (generally less than 2 ym) can make




 efficient collection by electrostatic precipitation very difficult.  It should




be noted that the sulfur content of the oil and the stack gas temperature




have little impact on resistivity relative to the changes caused by the




carbonaceous material.73




     Due to the above-mentioned problems, maintenance is very critical,




especially because the high combustible content of oil-fired particulates may




present a potential fire hazard in the collection hoppers.  Steam quenching




or fly ash reinjection may remedy this situation.




2.3.1.2  System Performance—




     The collection efficiency of precipitators on oil-fired boilers can vary




from 45 to 90 percent.71*  An ESP unit originally designed for coal and sub-




sequently used for collection on an oil burning unit with no modifications




may only provide an efficiency of about 50 percent.  Table 26 summarizes




typical test data for oil-fired boilers controlled by ESP technology.75  When




upstream concentration measurements were made, the computed efficiencies




ranged from 16 to 71 percent.  No supplemental data were available relative
                                     91

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N3
                       TABLE  26.   OIL-FIRED  COMBUSTION SYSTEMS  CONTROLLED WITH ELECTROSTATIC
                                   PRECIPITATORS75

Company Boiler
number/capacity '° ° /0 A8n
(MW)
1.

2.






3.


4.

5.





Polaroid Corp.
New Bedford
Boston Edison .
Mystic Station?





Hartford Electric Light Co.
Middletown Station

United Illuminating Co.
Bridgeport Harbor
Consolidated Edison
Ravenswood'l'
Astoria*



1/10
2/10
3/48
3/48
3/48
3/48
3/48
3/48
3/48
2/119
2/117
2/119
3/406
3/405
30/600

50/320
30/350
40/355
50/385
0.7
0.7
2.4
2.4
2.4
2.4
2.3
2.3
2.3
1.95 0.09
1.86 0.07
1.79 0.07
1.80 0.08
1.77 0.09
0.3 0.02

0.3
0.37
0.3
0.37
Additive
used
No
No
Yes
No
Yes
No
Yes
Yes
No
Yes
Yes
Yes
Yes
Yes
No

No
No
No
No
Fuel
consumption
rate A
(gal/hr)
390
340
3,600
3,600
3,600
3,600
3,600
3,600
3,600
7,800
7,800
7,800
26,000
26,000
57,000

19,000
19,000
19,000
19,000
Control
efficiency
(z>
40
51
38
57
71
34
-
-
—
-
.
—
_
-
16

51
54
40
45
Particulate
emission
rate
(lb/106 Btu)f
0.055
0.070
0.113
0.150
0.033
0.148
0.244
0.154
0.154
0.070
0.057
0.067
0.150
0.126
0.017

0.008
0.012
0.012
0.012
             To convert gal/hr to liters/hr, multiply by 3.785.

             To convert lb/106 Btu to ng/J, multiply by 430.

            '''ESP originally designed for  coal.
             §
             ESP originally designed for  coal, later modified for oil.

-------
to precipitator plate area (SCA) or "hot" or "cold" installation.  It is,




therefore, difficult to draw any specific conclusions from these findings.




2.3.2  Fabric Filtration




2.3.2.1  System Description—




     Control of particulate emissions from oil-fired units by this technology




is extremely rare.  The hygroscopic character of the uncontrolled fly ash




mentioned previously has the potential to plug fabrics and cause serious,




irreparable damage.  Blinding, as it is called, can occur when excessive dust




is irreversibly retained within the fabric pores such that gas flow resistance




rises to prohibitively high levels.




     Since baghouses require fabric lives of 2 or more years to be competitive




with precipitators, anything which will adversely affect a fabric service life




would most likely eliminate filtration as a candidate control technology.




2.3.2.2  System Performance—




     One facility which has employed this technology is the Alamitos Generating




Station of Southern California Edison Company.7,6  A full-scale baghouse de-




signed to treat all the flue gas from Unit No. 3 (320 MWe) was placed in ser-




vice in 1965 and was arranged in a circular fashion around the stack.  This




unit fired 69,916 kg/hr (154,000 Ib/hr) of high viscosity residual oil at full




load.  Average ash and sulfur contents were 0.06 and 1.6 percent, respectively.




Gas flow at full load was 1.39 * 106 m3/hr (820,000 acfm) at 126°C (258°F)




when firing oil (the boiler is also capable of firing natural gas).  Gas-to-




cloth ratio under  these conditions was 1.7/1-m/min  (5.7/1-ft/min) with all




12 compartments in service and 2.0/1-m/min (6.5/1-ft/min) with one compartment




down for cleaning.  Dampers were provided to permit bypassing of the filter-




house when natural gas is the fuel.  During startup of this unit, an alkaline
                                      93

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additive was injected into the gas stream at the air heater outlet which served
to neutralize sulfur trioxide (SOs) in the flue gas and to form a filter cake
on the bag surfaces.  Major problems associated with this installation were:
     1.   Fabric deterioration due to flue gas in-leakage when the
          bypass system was used
     2.   High system pressure drop and uneven flow distribution
          (A P of 2.4 kPa (9.5 inches W.C.) were recorded)
     3.   Problems with ash-conveying.
     Although extensive modifications have resulted in improvements in oper-
ation, maintenance, and bag life and the stack opacity was very low, the bag-
house is presently on a standby basis because of gas firing.
     Two other installations which have employed fabric filtration on oil-
fired units are the Lubrizol Corp. in Painesville, Ohio and the University of
Illinois in Chicago.  (See Table 19.)  The Lubrizol installation which is
used with an 8 MW, 59,465 m3/hr (35,000 acfm) system with Teflon fabric and
pulse cleaning went on line in 1974.  The University of Illinois filter was
installed in 1976, used glass fabric, and was a similarly-sized unit.
     Recent data from Lubrizol Corporation have indicated that stack test data
have been obtained but are unavailable.  The source has indicated that the
installation is very atypical (it is similar to a waste incinerator) and they
would not be willing to provide information on its success or lack of success.
     With regard to the University of Illinois, they have switched from oil
to natural gas and have taken the baghouse out of service.
2.3.3  Wet Scrubbing
2.3.3.1  System Description—
     Since the emissions from oil-fired boilers are predominantly < 2 ym, the
use of scrubbers for particulate control is limited.  However, these devices
                                     94

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could theoretically be used to control acid smut emissions or smoke and carbon




emissions during soot-blowing operations.  (Soctblowing in industrial boilers




is usually done every 8 hours for durations of 6 minutes or less.  Simultaneous




cleaning of all heat transfer surfaces during these intervals results in coarse




particle emissions (-200 ym) due to the reentrainment of solid deposits




from air preheater surfaces.)  It would not be practical, however, to install




scrubbers solely for control of soot-blowing operations.




2.3.3.2  System Performance—




     Test data were available from the Mystic Station of the Boston Edison Co.




which had previously employed a scrubber utilizing magnesium oxide for S02




control, Table 27.77  In tests 1, 2, and 4, some of the stack gas bypassed




the scrubber so that the control device's design capacity would not be ex-




ceeded.  In test 3, the scrubber was handling the system's full flow.  This




scrubbing system, which was designed for S02 removal only, has since been




dismantled.  Therefore, these results should not be interpreted as being typical




of scrubber performance on oil-fired units.  It,has also been reported that




corrosion problems and difficulties in obtaining a satisfactory precipitate




of the magnesium and calcium salts were experienced.




2.3.4  Mechanical Collection




     As with wet scrubbers, multicyclone systems are not normally designed




strictly for particulate control on oil-fired units.  Theoretically, they




could be utilized to control acid smut or soot emissions during transient




upset conditions.  No test data were found for this type of control.




2.4  CONTROLS FOR GAS-FIRED BOILERS




     Due to the nature of emissions from industrial gas-fired units (as de-




lineated previously in subsection 2.1), controls for particulate matter are
                                      95

-------
not employed.  Theoretically, one could apply any of the four control tech-

niques except wet scrubbing, which would require an excessive pressure loss,

to capture the fine particle emissions.  Mechanical collectors would be un-

able to collect these fine emissions but could potentially eliminate any

excessive particulate emissions during transient operations.  At this point,

no need is seen for particulate control systems with properly operated and

maintained gas-fired units.

         TABLE 27.  BOSTON EDISON SCRUBBER TESTS MYSTIC STATION -
                    OIL-FIRED BOILER NO. 677

Performance factor
Sulfur content of fuel (wt %)
Ash content of fuel (wt %)
Boiler operating capacity (MW)
Inlet particulate loading
(lb/106 Btu)*
Outlet particulate loading
(lb/106 Btu)*
Particulate removal efficiency
(wt %)
Sulfur dioxide removal efficiency
(wt Z)
Test number
1 2
2.15 2.10
0.09 0.10
146.0 144.0
0.277 0.171
0.085 0.085
69.5 50.5
92.7 91.4
3 4
1.89 2.04
0.07 0.07
151.0 148.0
0.281 0.108
0.106 0.059
62.4 45.7
93.4 89.2

  To convert from lb/106 Btu to ng/J, multiply by 430.
                                    96

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                                2.5  REFERENCES
 1.   Cato, G. A., et al.  Field Testing:  Application of Combustion Modifica-
      tions to Control Pollutant Emissions from Industrial Boilers - Phase I.
      EPA-650/2-74-078-a.  October 1974.  pp. 46-58.

 2.   Ibid,  pp. 76-83.

 3.   Smith, W. S., and C. W. Gruber.  Atmospheric Emissions from Coal
      Combustion - An Inventory Guide.  U.S. Department of Health, Education,
      and Welfare AP-24.  April 1966.  p. 57 (Figure 7-4), p. 59 (Figure 7-6),
      and p. 60 (Figure 7-7).

 4.   Midwest Research Institute.  Particulate Pollutant System Study - Vol. II
      Fine Particle Emissions.  APTD-0744.  August 1, 1971.  pp. 67-73
      (Figure 23).

 5.   Levy, A., et al.  A Field Investigation of Emissions from Fuel Oil Com-
      bustion for Space Heating.  Battelle-Columbus Laboratories.  November 1,
      1971.  p. VI-6 (Table VI-3) and p. F-10 (Figure F-l).

 6.   industrial Gas Cleaning Institute (IGCI) Terminology for Electrostatic
      Precipitators Publication No. E-P1, January 1973.

 7.   White, H. J.  Electrostatic Precipitation of Fly Ash.  J Air Pollut
      Control Assoc., Vol. 27, No. 4.  April 1977, pp. 308-312.

 8.   Dennis, R., S. V. Capone, and D. R. Roeck.  ESECA Compliance Schedule
      Evaluation.  Prepared for U.S. Environmental Protection Agency by
      GCA/Technology Division, Contract No. 68-01-4143.  January 1978.
      p.  25 and p. 32.

 9.   White, H. J.  Electrostatic Precipitation of Fly Ash.  J Air Pollut
      Control Assoc;, Vol. 27, No. 1.  January 1977.  p. 15.

10.   The Mcllvaine Co.  Electrostatic Precipitator Manual.  Chapter 1,
      p.  55.3.

11.   U.S. Department of Commerce.  U.S. Industrial Outlook 1977.  January 1977.
      p.  457.

12.   Dennis, R., D. R. Roeck, and N. F. Surprenant.  Status Report on Control
      of  Particulate Emissions from Coal-Fired Utility Boilers.  GCA-TR-77-38-G.
      May 1978.  p. 23.
                                      97

-------
13.   White, H. J.  Electrostatic Precipitation of Fly Ash.  J Air Pollut
      Control Assoc.  Vol. 27, No. 3.  March 1977.  p. 207.

14.   Ibid,  pp. 208-209.

15.   White, H. J.  January 1977.  op. cit.  p. 20.

16.   White, H. J.  Electrostatic Precipitation of Fly Ash.  J Air Pollut Con-
      trol Assoc.  Vol. 27, No. 2.  February 1977.  pp. 119-120.

17.   Dennis, R.  Status Report ... op. cit.  pp. 34-36.

18.   Gronhovd, G., and E. Sondreal.  Technology and Use of Low Rank Coals in
      the U.S.A.  Grand Forks Energy Research Center.  ERDA.  April 20-22, 1976.
      p. 28.

19.   Walker, A. B.  Operating Experience with Hot Precipitators on Western
      Low-Sulfur Coals.  American Power Conference Proceedings.  Vol. 39.
      March 1977.  p. 583.

20.   McCain, J. D., et al.  Results of Field Measurements of Industrial Par-
      ticulate Sources and Electrostatic Precipitator Performance.  J Air Pollut
      Control Assoc. Vol. 25, No. 2.  February 1975.  pp. 117-121.

21.   Personal Communication with Mr. John Rich, Salt River Project, Phoenix,
      Arizona.  September 28, 1977.

22.   Electric Power Research Institute (EPRI), test data reported in the
      "Precip Newsletter," the Mcllvaine Co., Northbrook, Illinois, Number 21.
      October 20, 1977.  p. 8.

23.   Ibid.  Number 18, July 20, 1977.  p. 7.

24.   White, H. J.  op. cit.  March 1977.  p. 214.

25.   Dennis, R., and N. F. Surprenant.  Particulate Control Highlights:
      Research on Fabric Filtration Technology.  EPA-600/8-78-005d.
      June 1978.  p. 2.

26.   The Mcllvaine Co., Northbrook, Illinois.  Fabric Filter Manual.
      Chapter VI.  p. 29.1.

27.   McKenna, J. D., et al.  Applying Fabric Filtration to Coal-Fired Indus-
      trial Boilers.  EPA-650/2-74-058a.  August 1975.  p. 2.

28.   The Mcllvaine Co.  op. cit.  p. 90.4.

29.   Smith, G. L.  Engineering and Economic Considerations in Fabric
      Filtration.  J Air Pollut Control Assoc.  Vol. 24, No. 12.
      December 1974.  p. 1155.
                                      9.8

-------
30.   The Mcllvaine Co.  op. cit.  Fabric Filter Manual.  Chapter I.  p. 90.4.

31.   Turner, J. H.  Application of Fabric Filtration to Combustion Sources.
      Presented at 85th National Meeting.  AIChE.  June 4-8, 1978.  p. 9.

32.   Cass, R. W., and R. M. Bradway.  Fractional Efficiency of a Utility
      Boiler Baghouse:  Sunbury Steam-Electric Station.   EPA-600/2-76-077a.
      March 1976.  p. 1 and pp. 43-45.

33.   Bradway, R. M., and R. W, Cass.  Fractional Efficiency of a Utility
      Boiler Baghouse - Nucla Generating Plant.  EPA-600/2-75-013a.
      August 1975.  p. 1 and p. 36.

34.   Dennis, R.  Status Report  ,..  op. cit.  p. 90 and p. 94.

35.   MacRae, T.  Design, Start^Up and Operating Experience on Western
      Pulverized-Coal Fired Boiler Baghouses.  Presented at 71st Annual
      Meeting of Air Pollution Control Association.  Houston, Texas.
      June 25-30, 1978.  p. 1 and p. 8.

36.   Personal Communication with Mr. Paul Adams, Environmental Engineer,
      Adolph Coors Co.  April 11, 1978.

37.   Personal Communication with Mr. H. A. Huish, General Superintendent -
      Geneva Works - U.S. Steel Corp.  July 10, 1978.

38.   Personal Communication with Mr. Kelly Emmons, Field Sales Manager -
      Standard Havens, Inc.  October 25, 1977.

39.   Personal Communication with Mr. Alan Swenson, Plant Engineer,  Amalgamated
      Sugar Co., Twin Falls, Idaho.  August 17, 1978.

40.   Dennis, R., et al.  Filtration Model for Coal Fly Ash with Glass
      Fabrics.  EPA-600/7-77-084.  August 1977.  p. 345.

41.   McKenna, J. D.  op. cit.  p. 123.

42.   Calvert, S., et al.  Study of Flux Force/Condensation Scrubbing of Fine
      Particles.  EPA-600/2-75-018.  August 1975.  p. 3.

43.   Calvert, S.  Wet Scrubber System Study Vol. 1 Scrubber Handbook.
      PB-213-016.  August 1972.  p. 3-4, 3-8, and 3-13.

44.   Fox, R. A. (ed.).  New Developments in Air Pollution Control.   Papers
      presented at Metropolitan Engineers Council on Air Resources (MECAR)
      Symposium, New York, N.Y.  October 23, 1967.  p. 16.

45.   The Mcllvaine Co.  op. cit.  Fabric Filter Manual.  Chapter I.  p. 90.4.

46.   The Mcllvaine Co.  Scrubber Manual.  Chapter IX.  p. 170.1.
                                      99

-------
47.   Yung, Shui-Chow, et al.  Venturi Scrubber Performance Model.  EPA-600/
      2-77-172.  August 1977.  p. 150.

48.   Gronhovd, G., and E. Sondreal.  op. cit.  p. 29.

49.   Dennis, R.  op. cit.  Status Report  ...  p. 54.

50.   Gerstle, R. W., and G. A. Isaacs.  Survey of Flue Gas Desulfurization
      Systems, Reid Gardner Station, Nevada Power Company,  EPA-650/2-75'-057j,
      U.S. Environmental Protection Agency, Office of Research and Development,
      Washington, D.C.  1975.

51.   Isaacs, G. A., and F. K. Zada.  Survey of Flue Gas Desulfurization
      Systems, Mohave Station, Southern California Edison Company.  EPA--650/2-
      75-057k, U.S. Environmental Protection Agency, Office of Research and
      Development, Washington, D,C.  1975..

52.   Isaacs, G. A., and F. K. Zada.  Survey of Flue Gas Desulfurization
      Systems, Will County Station, Commonwealth Edison Company,  EPA-650/2-
      75-057i, U.S. Environmental Protection Agency, Office of Research and
      Development, Washington, D.C.  1975.

53.   Isaacs, G. A., and F. K. Zada.  Survey of Flue Gas Desulfurization
      Systems, Hawthorn Station, Kansas City Power and Light Company.
      EPA-650/2-75-057h, U.S. Environmental Protection Agency, Office of
      Research and Development, Washington, D.C.  1975.

54.   Isaacs, G. A., and F. K. Zada.  Survey of Flue Gas Desulfurization Systems,
      La Cygne Station, Kansas City Power and Light Company and Kansas Gas and
      Electric Company.  EPA-650/2-75-057b, U.S. Environmental Protection Agency,
      Office of Research and Development, Washington, D.C.  1975.

55.   Isaacs, G. A., and F. K. Zada.  Survey of Flue Gas Desulfurization
      Systems, Lawrence Power Station, Kansas Power and Light Company.
      EPA-650/2-75-057e, U.S. Environmental Protection Agency, Office of
      Research and Development, Washington, D.C.  1975.

56.   Isaacs, G. A.  Survey of Flue Gas Desulfurization Systems, Paddy's Run
      Station, Louisville Gas and Electric.  EPA-650/2-75-057d, U.S. Environ-
      mental Protection Agency, Office of Research and Development, Washington,
      D.C.

57.   Personal Communication with Mr. Van Ness, Louisville Gas and Electric
      Company.  February 28, 1978.

58.   Isaacs, G. A.  Survey of Flue Gas Desulfurization Systems, Phillips
      Power Station, Duquesne Light Company.   EPA-650/2-75-057c, U.S. Environ-
      mental Protection Agency, Office of Research and Development, Washington,
      D.C.  1975.

59.   Personal Communication with Mr. Steve Pernick, Duquesne Light Co.
      February 21, 1978.


                                     100

-------
60.    Personal Communication with Mr.  Lyman K.  Mundth, Arizona Public Service
      Co.   March 2, 1978.

61.    Berube, D. T., and C. D. Grimm.   Status and Performance of the Montana
      Power Company's Flue Gas Desulfurization System.  Paper presented at 4th
      Symposium on FGD, Hollywood, Florida.  November 8-11, 1977.

62.    Personal Communication with Mr.  John Noer, Northern States Power Co.
      February 15, 1978.

63.    Personal Communication with Mr.  Joseph Barkley, Tennessee Valley
      Authority.  February 22, 1978.

64.    Personal Communication with Mr.  Larry Killingsworth, Springfield City
      Utilities.  February 16, 1978.

65.    Laseke, B. A.,  Jr.  Survey of Flue Gas Desulfurization Systems:  Green
      River Station,  Kentucky Utilities.  EPA-600/7-78-048e.  March 1978.

                                                                          55.3.
66.
67.
68.
69.
70.
71.
The Mcllvaine Co. op. cit. Electrostatic Precipitator Manual
Horzella, T. I. Selecting, Installing and Maintaining Cyclone
Collectors. Chem Eng J. January 30, 1978. pp. 84-92.
Ibid. p. 87.
Courtesy of Poly Con Corporation.
Cato, G. A. op. cit. pp. 46-58,
Cato, G. A., L. J. Muzio, and D. E. Shores Field Testing: Ap
. p.
Dust
plica
      of Combustion Modifications to Control Pollutant Emissions from Indus-
      trial Boilers - Phase II.  EPA-600/2-76-086a.  April 1976.  pp. 35-38.

72.    Ramsdell, R.  G., Jr.  Practical Design Parameters for Hot and Cold
      Electrostatic Precipitators.  Combustion.  October 1973, p. 41.

73.    GCA Corporation.  Particulate Emission Control Systems for Oil-Fired
      Boilers.  EPA-450/3-74-063.  December 1974, p. 34.

74.    Offen, G. R.  et al.  Control of Particulate Matter from Oil Burners
      and Boilers.   Prepared for EPA under Contract No. 68-02-1318 by
      Aerotherm Division/Acurex Corp.  October 1975.  p. 4-37.

 75.  GCA Corporation, op. cit.  p. 10.

 76.  Bagwell, F. A., L. F. Cox, and E. A. Pirsh.  Design and Operating Experi-
      ence:  A Filterhouse Installed on an Oil-Fired Boiler.  J Air Pollut Con-
      trol Assoc.  Vol. 19, No. 3.  March 1969.  pp. 149-154.

 77.  GCA Corporation,  op. cit.  p. 24-25.
                                     101

-------
           3.0  CANDIDATES FOR BEST SYSTEMS OF EMISSION REDUCTION






3.1  CRITERIA FOR SELECTION




     In Section 2.0 — Emission Control Techniques — control methods were




discussed that would most likely be used to collect particulate matter from




industrial boilers.  This section provides analyses of those control tech-




niques which are capable of meeting three key emission levels (i.e., strin-




gent, intermediate, and moderate).  This analysis is based primarily on the




technical or engineering capabilities of the various control devices and on




the economic, energy, and environmental impacts incurred at these three emis-




sion control levels.




     In the ensuing discussions of emission control technologies candidate




technologies are compared using these three emission control levels.  These




control levels were chosen only to encompass all candidate technologies and




form bases for comparison of technologies for control of specific pollutants




considering performance, costs, energy, and nonair environmental effects.




     From these comparisons, candidate "best" technologies for control of




individual pollutants are recommended for consideration in any subsequent




industrial boiler studies.  These "best technology" recommendations do not




consider combinations of technologies to remove more than one pollutant and




have not undergone the detailed environmental, cost, and energy impact




assessments necessary for regulatory action.  Therefore, the levels of




"moderate, intermediate, and stringent" and the recommendation of "best
                                    102

-------
 technology" for individual pollutants are not to be construed as indicative




 of the regulations that might be developed for industrial boilers.   EPA will




 perform rigorous examination of several comprehensive regulatory options




 before any decisions are made regarding standards for emissions from industrial




 boilers.




      The controlling factor in assessing overall applicability will be the




demonstrated performance capabilities of a specified control system  as de-




scribed in Section 2.0.  Data which were purely theoretical, fragmented, or




of questioned origin and which were not utilized in Section 2.0, will not be




used in Section 3.0 to determine candidate systems.




      The applicability of a particular control method with respect  to the




seven boiler firing methods will be reviewed as well as its status of




development.




      Economic impacts will be based mainly on the capital and operating




costs for the various control methods.  The energy impact will be treated




as a function of the energy consumed by the operation of the control system




per se while environmental impacts will be defined by such factors as stack




emissions, sludge disposal, dry fly ash disposal, and/or water pollution.




 3.1.1  Moderate Level of Control




      The "moderate" level, which has been defined as 107.5 ng/J (0.25 lb/106




 Btu), is the least stringent control level to be reviewed.  This level will




 require some degree of removal for the coal-fired boilers (roughly 50 to 97




 percent efficiency), minimal removal for residual oil-fired boilers (< 31 per-




 cent efficiency) and no removal for the distillate oil and natural gas-fired




 boilers.
                                     103

-------
3.1.2  Stringent Level of Control




     The stringent level of control, which has been set at 12.9 ng/J (0.03




lb/106 Btu) is representative of the level specified by EPA for utility boilers




in the Federal Register of June 11, 1979.  This (12.9 ng/J) level will require




substantial emission reductions for coal-fired boilers (94 to 99.65 percent




efficiency) and up to 92 percent efficiency for residual oil-fired units.




There are indications that control at the stringent level may be very difficult




on a continued, long-term basis (even for utility boilers).




3.1.3  Intermediate Level of Control




     This level has been selected at 43 ng/J (0.1 lb/106 Btu) (the original




NSPS for utility boilers), and represents a typical emission limitation en-




forced in many states.  This level appears to be the critical value below




which significant cost and energy penalties may occur.  Because this level




has been in effect for several years, cost data are available for control at




this level and will be utilized in Section 4.0.




     For coal-fired boilers controlled at the intermediate level, efficiencies




of 80 to 98.82 percent would be required while residual oil-fired boilers




would require efficiencies ranging up to 72 percent.




     The three levels of omission control selected should provide a realistic




range within which to work and properly assess the impacts of particulate reduc-




tions from the boilers selected for evaluation.




3.2  BEST CONTROL SYSTEMS FOR COAL-FIRED BOILERS




3.2.1  Moderate Reduction Controls




     A summary description of four coal-fired boilers, their control devices,




and the impact of moderate control upon such factors as cost, energy con-




sumption, reliability, etc., is presented in Table 28.  The various factors
                                    104

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             TABLE 28.   APPLICABILITY OF PARTICULATE EMISSION  CONTROL TECHNIQUES  TO ACHIEVE.  A
                          MODERATE EMISSION  LEVEL OF 107.5 ng/J  (0.25  lb/106  Btu) FOR COAL-FIRED
                          INDUSTRIAL BOILERS

Boiler type
and
heat input
MV'
(106 Btu/hr)
Pulverized
58.6 & 117.2
(200) (400)

Spreader stoker
44
(150)
l_*
o
01 Chain grate
stoker
22
(75)
Underfeed
stoker
8.8
(30)
Control
device
MC
WS
ESP
FF
MC
WS
ESP
FF

MC
WS
ESP
FF
MC
WS
ESP
FF
Technical
capability
to meet
moderate
level
C
B
A
A
B
B
A
A

A
A
A
A
B
B
A
A
Cost
impact
A
C
C
C
A
B
C
C

A
B
D
D
A
C
D
D
Energy
impact
B
D
A
C
B
C
A
C

B
B
A
C
B
D
A
C
Environ-
mental
impact
C
C
A
A
B
C
A
A

A
B
A
A
B
C
A
A
Boiler
operation
or
safety
A
A
A
B
A
A
A
B

A
A
A
B
A
A
A
B
Reliability
A
B
A
A
A
B
A
A

A
B
A
A
A
B
A
A
Avail-
ability
to sources
after 1/81
A
A
A
A
A
A
A
A

A
A
A
A
A
A
A
A
Adapt-
ability to
existing
sources
C
C
C
C
C
C
C
C

C
C
C
C
C
C
C
C
Multi-
pollutant
control
capability
D
A
C
B
D
A
C
B

D
A
C
B
D
A
C
B
Overall
i • *
ranking
C
C
A
B
A
B
B
B

A
B
C
C
B
C
B
C

 Rating System - Each control device is  rated by a  letter code (A = best; B  = good;  C = acceptable; D = poor; E =  inappropriate)
 relating to each factor listed  in the table.  The  overall ranking applies to all factors listed as well as those  discussed in the
 text.

Note:  MC  - Multitube Cyclone
      WS  - Wet Scrubber
      ESP - Electrostatic Precipitator
      FF  - Fabric Filter

-------
listed in the table, which would be affected by the installation of a given




control device on each of the boilers, are discussed in the following




paragraphs.




     The third column assess the technical capability of the control option




to meet the moderate emission level of 107.5 ng/J (0.25 lb/105 Btu).  This




capability is a function of the boilers' uncontrolled emission rate (refer




to Table 12), the mass median diameter of these uncontrolled emissions (refer




to Table 13), the established efficiency range for the control device, and,




in the case of electrostatic precipitators, the variations in sulfur and




sodium (or alkali) content of the coal.



     Economic factors considered, Column 4, are the installed capital costs




and the annual operating costs reported for each of the control devices.




Generally, installed capital costs are lowest for multitube cyclones and in-




crease for scrubbers, precipitators, and fabric filters, in the order named.



     Operating costs are lowest for precipitators and mechanical collectors,




followed by fabric filters and scrubbers, although these costs are strongly




dependent on site-specific factors, particularly sulfur and alkali metal con-




tent of the coal burned.  Electrostatic precipitators and fabric filters are




ranked unfavorably in terms of cost because of variations in coal properties



and uncertainties in bag service life, respectively.




     The energy impact of each control system (Column 5) is based on the re-




quired pressure drop through the device to attain the necessary fly ash col-




lection for the particular boilers in question.  Precipitators, operating at




less than 0.25 kPa (1 inch W.C.) resistance, are shown to be the least




energy-intensive of the four control methods.
                                    106

-------
     The environemntal impact of each device, Column 6, is examined under




four categories; fly ash emissions from the stack, dry fly ash disposal,




sludge disposal, and water pollution.  The wet scrubber is rated the lowest




because of sludge disposal and potential water pollution problems.




     With respect to boiler operation and safety, Column 7, the fabric filter




(which does not have "natural bypass" capabilities like an ESP or MC) appears




to be the only device that has potential for problems in that inadequate fabric




cleaning procedures could result in sudden pressure drop increases that might




affect the operation of the boiler.  However, proper attention to the fabric




filter operating parameters should minimize problems in this area.




     Reliability of the various control devices  (Column 8) appears to be gen-




erally adequate with the scrubber rated slightly lower than the other control




methods because of corrosion problems and ancillary equipment requirements




and, therefore, the potential for more equipment failure.




     The availability of all four methods of control to sources installed and




operated after January 1981, is projected to be no problem because of the




fact that all are well-established technologies.




     Adaptability to existing sources, Column 9, is rated as only acceptable




for all control approaches since site-specific problems will be the control-




ling factors for most retrofit installations.




     The wet scrubber, Column 10, has been shown to be the best system for




multipollutant control due to its added capability for absorption of SC-2 and




other gaseous pollutants.  The baghouse is rated good in terms of multi-




pollutant control, due to active research work underway in the area of dry S02




removal.1  The emergence of dry scrubbing technology as a nonregenerable form




of flue gas desulfurization has culminated in the first U.S. commercial
                                     107

-------
installation at Strathmore Paper Co. in Strathmore, Massachusetts.   This sys-

tem, designed and installed by MikroPul Corp., consists of a spray  dryer fol-

lowed by a baghouse.  It is installed on a pulverized coal boiler burning 2.5

percent sulfur coal and guaranteed for 75 percent S02 removal.  A second

industrial facility, the Celanese Corp. in Cumberland, Maryland, has adopted

this technology with completion of its spray dryer/filter system scheduled

for early 1980.  This system, developed jointly by Rockwell International and

Wheelabrator-Frye, will consist of a lime-based spray dryer followed by a bag-

house.  It will control emissions from a stoker-fired boiler burning 1.5 to

2.0 percent sulfur coal at a rated flue gas flow of 1841 m3/min (65,000 acfm).

Utility groups planning on installing dry scrubbing systems are the Basin

Electric Power Cooperative (Bismarck, N. Dak.) and the Otter Tail Power Co.

(Beulah, N. Dak.).  The Basin Electric Power Cooperative plans facilities

at its Laramie River Station - Unit 3 in Wheatland, Wyoming and its Antelope

Valley Plant in Beulah, N. Dak.  The Laramie River boiler which is  rated at

500 Mw  and a flue gas rate of 56,634 m3/min (~ 2 x 106 acfm), will burn sub-

bituminous coal from Wyoming with a maximum sulfur content of 0.81 percent.

The collection system will consist of a lime-based, horizontal spray dryer

followed by an electrostatic precipitator.  Startup is anticipated  for 1980.

The Antelope Valley boiler is rated at 440 Mwe, a flue gas volume of 50,000

m3/min (1.8 x 106 acfm), and will burn 1.22 percent sulfur lignite.  This

system, slated for operation in 1982, includes a lime-based spray dryer

followed by a baghouse.  The Otter Tail Power Co. Coyote Station boiler is

rated at 410 Mwe, a flow rate of 53,519 m3/min (1.89 x 1Q6 acfm), and will

burn 0.78 percent sulfur lignite.  This system will employ a sodium carbonate -

(soda ash or Na2C03) based spray dryer followed by a baghouse and is scheduled

for completion in late 1981.
                                    108

-------
     Dry scrubbing is accomplished by dry injection of naturally occurring
sorbents such as soda ash, trona (a hydrous sodium carbonate), and nahcolite
(sodium bicarbonate), or by spray drying, in which heat from the flue gas is
used to evaporate the water from a sprayed alkali slurry such as lime or soda
ash.  The outcome in either situation is the formation of a dry-powder mixture
of fly ash and sulfates, which is collected by a baghouse or electrostatic
precipitator.  The advantages of dry scrubbing over wet scrubbing are:
improved waste handling, less corrosion potential, lower investment and
operating costs, and less energy and water consumption.  One important limi-
tation of dry scrubbing technology is that it appears to be economically
feasible only at low 802 concentrations in the flue gas.
     For more information on 862 removal options, the reader is referred to
the technology assessment report on flue gas desulfurization.
     Other factors affecting the applicability of particulate control that
are not listed in Table 28 are:  status of development of the control option,
operation and maintenance requirements, and compatibility with and impact on
other pollutant control systems.
     Operation and maintenance requirements which are important for all of
the control devices from the standpoint of system performance are equally
or more important for stringent and intermediate control requirements.
     The aspect of compatibility with other control systems requires a careful
and thorough review and any interactions among the various control techniques
must be evaluated.  Available data from a series of tests performed by KVB
Engineering, Inc. in 1976 sheds some light on the effects of combustion modi-
fications to reduce NO., emissions on particulate emissions.2  Some of the more
                      Ji
important conclusions resulting from this study are outlined as follows:

                                    109

-------
     1.  Reduced excess air - Particulate emissions decreased by




         as much as 30 percent in four of six tests.  However,




         the fraction of fine particles increased in the case of




         a chain grate boiler.




     2.  Staged combustion air - Particulate emissions increased




         by 20 to 48 percent in three of six tests.




     3.  Burners out of service - Particulate emissions increased




         by 25 to 95 percent.




     4.  Burner register adjustment - No significant effect on par-




         ticulate emissions.




     5.  Flue gas recirculation - Recirculating 25 percent of the




         flue gas resulted in a nitrogen oxides reduction of about




         12 percent and a particulate emission increase of about




         15 percent.




     6.  Reduced firing rate - In one test, nitrogen oxides




         increased by 10 percent and particulates decreased by




         45 percent.




     Although these data are based on a limited number of tests, they do in-




dicate some potential problems when NOX reduction techniques are to be employed




in conjunction with particulate control; however, the reader is referred to the




ITAR on Combustion Modification for NCv control for a more detailed discussion.
                                      A



Since the preceding discussion also applies to stringent and intermediate con-




trol levels, it will not be repeated in the latter sections.




3.3.2  Stringent Reduction Controls




     A summary of the four coal-fired boilers, their control devices, and the




influence of stringent control standards upon such factors as cost,  energy






                                     110

-------
consumption, reliability, etc., is presented in Table 29.  This level of emis-




sion reduction would have the greatest adverse impact on the cost of control




as well as precluding (in some cases) the sole use of multitube cyclones, wet




scrubbers and even precipitators for the very low sulfur coals.




     The rationale for assigning the ratings given to each control option




is the same as that described previously for moderate emission levels and




for all dust collector categories.




     The stringent level of control would certainly preclude the sole use of




multitube cyclones and in all cases except for chain grate boilers (because




of particle size and inlet loading) the wet scrubber would be excluded from




consideration.  Precipitators and fabric filters would be required in most




cases and at low sulfur coal burning installations (or small boilers < 50 MW




or 171 x io6 Btu/hr heat input) fabric filters would appear to be the more




logical choice.




3.2.3  Intermediate Reduction Controls




     A summary of the four coal-fired boilers, .their control devices, and the




impact of intermediate control upon economics, energy consumption, reliability,




etc., is presented in Table 30.  It is seen that at this level of emission




control, more options would be open to the industrial boiler operator as each




of the control devices could be used on one or more of the boilers under study.




3.3  BEST CONTROL SYSTEMS FOR OIL-FIRED BOILERS




     The three levels of control which have been outlined previously also




apply to the oil-fired boilers.  Because of the less stringent efficiencies




(see Table 31) that would be required to collect uncontrolled emissions from




the residual and distillate oil-fired units, the small particle size of the
                                    111

-------
NS
                     TABLE 29.   APPLICABILITY OF PARTICULATE EMISSION CONTROL TECHNIQUES  TO ACHIEVE
                                  A STRINGENT  LEVEL OF  12.9 ng/J (0.03 lb/106  Btu) FOR COAL-FIRED IN-
                                  DUSTRIAL BOILERS

Boiler type
and
capacity
GJ/hr
(106 Btu/hr)
Pulverized
211
(200)

Spreader stoker
158.2
(150)

Chain grate
stoker
79.1
(75)
Underfeed
stoker
31.6
(30)
Control
device
MC
WS
ESP
FF
MC
WS
ESP
FF
MC
WS
ESP
FF
MC
WS
ESP
FF
Technical
capability
to meet
stringent
level
E
D
B
A
E
C
B
A
E
B
B
A
E
C
B
A
Cost
impact
E
D
C
C
E
D
C
C
E
C
C
C
E
D
C
C
Energy
impact
D
D
A
B
D
C
A
B
D
C
A
B
D
D
A
B
Environ-
mental
impact
D
D
A
A
D
D
A
A
D
D
A
A
D
D
A
A
Boiler
operation
or
safety
A
A
A
B
A
A
A
B
A
A
A
B
A
A
A
B
Reliability
D
D
B
A
D
C
B
A
D
C
B
A
D
C
B
A
Avail-
ability
to sources
after 1/81
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
Adapt-
ability to
existing
sources
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
Multi-
pollutant
control
capability
D
B
C
B
D
B
C
B
D
B
C
B
D
B
C
B
Overall
ranking '
E
D
B
A
E
C
B
A
E
B
B
A
E
C
B
A

Rating System -
Each control device
is rated
by a letter code
(A - best;
B " good; C "
acceptable;
D = poor; E
= inappropriate)
        relating to each factor listed in the table.  The overall  ranking applies  to all  factors  listed as well  as those discussed in
        the text.

       Note:  MC  - Multitube Cyclone
             WS  - Wet Scrubber
             ESP - Electrostatic Precipitator
             FF  - Fabric  Filter

-------
                   TABLE 30.
M
M
U>
APPLICABILITY OF PARTIOJLATE EMISSION CONTROL TECHNIQUES  TO ACHIEVE
AN INTERMEDIATE LEVEL OF 43  ng/J  (0.10 lb/106 Btu)  FOR COAL-FIRED
INDUSTRIAL BOILERS

Boiler type
and. Control
Capacity device
GJ/hr
(105 Btu/hr)
Pulverized
211
(200)

Spreader stoker
158.2
(150)

Chain grate
stoker
79. 1
(75)
Underfeed
stoker
31.6
(30)
-',-
Rating System
MC
WS
ESP
FF
MC
WS
ESP
FF
MC
WS
ESP
FF
MC
WS
ESP
FF
- Each
Technical
capability £
to meet . '
,. impact impact
intermediate
level
E
C
A
A
D
B
A
A
D
B
A
A
C
C
A
A
control device
E
D
C
C
E
D
C
C
E
C
D
D
A
C
D
D
is
B
D
A
C
B
C
A
C
B
C
A
C
B
C
A
C
rated by a
_ . Boiler
Environ-
mental operation Reliabilit
or '
impact .
•safety
D
D
A
A
D
C
A
A
-• D
C
A
A
C
C
A
A
letter code
.11 ._ . . i
A
A
A
B
A
A
A
B
A
A
A
B
A
A
A
B
(A = best;
D
C
B
A
D
C
B
A
D
C
B
A
B
C
B
A
B = good ;
. 	 _ i i r
Avail- Adapt- Multi-
ability ability to pollutant Overall
to sources existing control ranking"
after 1/81 sources capability
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
C = acceptable;
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
D = poor;
_ _ 1 1 	 .1
D
A
C
B
D
A
C
B
D
A
C
B
D
A
C
B
E =
E
D
A
B
D
B
A
B
D
B
A
B
C
C
A
B
inappropriate)
        relating to each factor listed  in the  table.  The overall ranking applies to all factors listed as well as  those discussed  in

        the text.


       Note:  MC  - Multitube Cyclone
              WS  - Wet Scrubber
              ESP - Electrostatic Precipitator

              FF  - Fabric Filter

-------
emitted fly ash, and the hygroscopic nature of the oil fly ash, an electro-




static precipitator would be the preferred device at any of the control levels.




Fabric filters are a second choice until more experience is available for the




filtration of hygroscopic aerosols.




3.4  BEST CONTROL SYSTEMS FOR GAS-FIRED BOILERS




     Because of the fact that uncontrolled emissions from gas-fired units are




considerably less than the stringent level of control that has been selected,




no need is seen for control of properly operated gas-fired boilers.




3.5  SUMMARY




     A summary of the data presented in this section is given in Table 31.




This table lists each boiler type, the type of fuel fired, the range of un-




controlled emissions excerpted from Table 12 and the average mass median




diameter (MMD) for these uncontrolled emissions (Table 13).  Following this



information, the three levels of control are indicated along with the range




of efficiencies that would be required to achieve the stated emission levels.




     The next three columns indicate the minimum acceptable control device




that would be required to meet each of the control limits based upon the tech-




nological capabilities presented in Section 2.0.  The control equipment has




been "ranked" at the bottom of Table 31 in terms of overall capabilities.  It




might be argued that electrostatic precipitators should be rated ahead of




fabric filters because of greater usage and hence experience, but the higher




efficiency and lesser dependence upon fuel sulfur content are the reasons for




giving a slight advantage to the fabric filter.




     The definition of "minimum acceptable control device" should be inter-




preted as follows:  if, for example, a wet scrubber (WS) is listed in the




table as the device capable of meeting the emission limitation, then an
                                     114

-------
          TABLE. 31.   PARTICULATE  CONTROL OPTIONS AND  REQUIRED EFFICIENCIES








Boiler type


A.







B.







C.







D.





E.


F.

G.



Pulv. Coal
3.5% S
10.6% A
2.3% S
13.2% A
0.9% S
6.9% A
0.6% S
5.4% A
Sp. Stoker
3.5% S
10.6% A
0.9% S
6.9% A
0.6% S
51 ti t.
.4% A
Chain Grate
3.5% S
10.6% A
0.9% S

6.9% A
0.6% S
5.4% A
Underfeed
Stoker
3.5% S
10.6% A
0.9% S
6.9% A
0.6% S
51 mf .
.4* A
Residual
Oil
3.0% S
0.1% A
Distillate
Oil
OCV C*
.5% S
Natural Gas



Uncont ro 1 led
emissions
range
ng/J (lb/10 Btu)
See Table 12

3087-3280
(7.18-7.63)

3436-3651
(7.99-8.49)
1720-1827
(4.00-4.25)

1935-2055
(4.50-4.78)

2511
(5.84)

1397
(3.25)
1574
(3.66)

967.5
(2.25)

537.5
(1.25)

606.3
(1.41)
387-963.2
(0.90-2.24)

215-537.5
(0.50-1.25)

241-602
(0.56-1.40)

16.6-154.6
(0.0385-0.3596)


3.74-14.6
(0.0087-0.0339)

0.34-6.45
(0.0008-0.015)

Particle
" size
average
HMD
See Table 13

16.7

16.7

16.7

16.7

59


59

59


88


88


88

16

16

16

<2


<2

<2

Level of
emission control and
efficiency (7.) required to
achieve that level
ng/J (lb/106 Btu)


Stringent
12.9
(0.03)
99.58-99.61

99.62-99.65

99.25-99.29

99.33-99.37

99.49


99.08

99.18


98.67


97.60


97.87

96.7-98.7

94-97.6

94.6-97.9

22.3-91.7


0-11.6




.
Lnt€ rTnedi-d 1 6 Mode ITS ts
43 107.5
(0.10) (0.25)
98.61-98.69 96.52-96.71

98.75-98.82 96.87-97.06

97.50-97.65 93.75-94.12

97.78-97.91 94.44-94.77

98.29 95.72


96.92 92.31

97.27 93.17


95.56 88.89


92.00 80.00


'92.91 82.27

88.9-95.5 72.2-88.8

80.0-92.0 50.0-80.0

82.2-92.9 55.4-82.1

0-72.2 0-30.5


~




Minimum acceptable
control device
required at
specified level*
Stringent Intermed. Mod.

FF ESP ESP

FF ESP ESP

FF ESP ESP

FF ESP WS

FF WS WS


FF WS WS

FF WS WS


WS WS MC


WS WS MC


WS WS MC

ESP ESP ESP

ESP WS MC

WS or FF WS MC

ESP
ESP only ESP only Qnly


--


	
*Control devices are ranked by their overall capabilities  in terms of fuel sulfur content, overall efficiency
 considering particle size, capital cost, and energy required to operate:

      1.  Fabric Filter (FF)
      2.  Electrostatic Precipitator (ESP)
      3.  Wet Scrubber (WS)
      4.  Multitube Cyclone (MC)


                                                  115

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electrostatic precipitator or a fabric filter would  serve as well if not




better.  If only one or two devices can be used,  they  are so specified in




Table 31.
                                     116

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                               3.6  REFERENCES
1.   Miller, Irene.  Dry Scrubbing Looms Large in S02 Cleanup Plans.   Chemical
     Engineering.  August 27, 1979.  pp. 52-54.

2.   Cato, G. A., L. J. Muzio, and D. E. Shore.  Field Testing:  Application
     of Combustion Modifications to Control Pollutant Emissions From Indus-
     trial Boilers - Phase II.  EPA-600/2-76-086a.  April 1976, pp. 192-209.
                                     117

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                  4.0  COST ANALYSIS OF CANDIDATES FOR BEST
                       SYSTEMS OF EMISSION REDUCTION
4.1  COSTS TO CONTROL COAL-FIRED BOILERS

     The cost of any particulate control system is of paramount importance to

the potential user.  Control equipment costs include the initial cost of many

components such as those for the basic collector, connecting ductwork, storage

hoppers, and ash handling system; installation costs; and the annual operating

costs consisting of electricity, labor, maintenance, component replacement,

and waste disposal.

     The technical literature contains a myriad of economic studies for boilers

utilizing particulate collection equipment.  Unfortunately, most data represent

costs for large, utility-sized boilers and not for the smaller, industrial-

sized plants that are being studied in this technology assessment report.  In

addition, the available studies often use different costing procedures, differ-

ent outlet emission rates, boiler sizes, and different years for the cost anal-

yses, such that data comparisons are difficult.  Further complication arises

from the fact that this industrial boiler study is, in part, considering eight

different oil-, gas-, and coal-fired boilers, four levels of emission control,

four types of control equipment, and varying coal compositions.  Although cer-

tain control devices cannot be used with all boilers or at each control level,

there are still many combinations of the above for which costs will differ.

It has not been practicable nor possible to obtain information from vendors or

the literature on all of the possible boiler/fuel/control level/control device

                                     118

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combinations.  Therefore, the available data require interpolation and/or
extrapolation along with sound engineering judgment to define those situations
that have not been described directly.
     Before presenting a standardized format for costs and their bases, general
cost statistics and related information from available references will be re-
viewed to show the expected cost range for the boilers being studied.
4.1.1  PEDCo Study
     A recent report by PEDCo1 evaluated particulate control system costs for
new utility boilers at three levels of emission control; 43.0, 22.0, and 13.0
ng/J (0.1, 0.05, and 0.03 lb/106 Btu, respectively).  Two coals were considered;
0.8 percent sulfur, 8.0 percent ash and 3.5 percent sulfur, 14.0 percent ash.
The costs presented in the PEDCo study, which refer to August 1980 dollars
(using an inflation rate of 7.5 percent per year), have been discounted back
to June 1978 dollars using the following equation:
                                  P = Fe-rt                              (1)
where . P = present cost
       F = future cost
       r = annual inflation rate
       t = number of years
     For the time period in question  (2.17 years) and the inflation rate of
7.5 percent, Equation (1) reduces to P = 0.85F.  The PEDCo study evaluated
fabric filters (FF) and electrostatic precipitators (ESP) at the 13 ng/J
(0.03 lb/10G Btu) level and considered only electrostatic precipitators and
Venturi scrubbers at the two higher emission levels, 22.0 and 43.0 ng/J.
Plant sizes analyzed ranged from 25 to 1000 MW electrical output.  The rela-
tionships between boiler size and capital costs  (including installation) are
shown in Figures 23, 24, and 25 for varying levels of control, type of fuel

                                      119

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1000
 TOO
 500
                      BOTH  COALS
  200
N
W
  100
   TO
   50
   25

   20
                                            O	OESP
            3.5 %S
            14% A
   10
             40
                      80
                               120
                                   |/kW
                                        160
                                                200
                                                                  280
Figure 23.   Capital costs of  electrostatic precipitators and  wet
             scrubbers on new  coal-fired utility power plants.
             Emission level =  43  ng/J (0.1 lb/106 Btu).  Raw
             data:  Reference  1 - PEDCo Study.
                                 120

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1000
 700
 500
 ZOO
N
55
<
a.
Q	QESP
A-	Aws
  100 -
   20 -
    10
                               120      160
                                  1/kW
 Figure 24.   Capital costs of electrostatic precipitators and wet
              scrubbers on new coal-fired utility power plants.
              Emission level = 22 ng/J (0.05 lb/106 Btu).  Raw
              data source:  Reference 1 - PEDCo Study.
                                 121

-------
 1000
  700 -
  500 -
  200 -
u
N
n
                                       O	OESP
                                       O	OFF
  100 —
                              120       160
                                 1/kW
    Figure 25.  Capital costs  of  electrostatic precipitators and
                fabric filters on new coal-fired utility power
                plants.  Emission level = 13 ng/J (0.03 lb/106 Btu.
                Raw data source:   Reference 1 - PEDCo Study.
                                   122

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and method of control.  These data show that (a)  decreasing system size will




increase the unit cost in terms of dollars per kW output, and (b) that there




is an inverse relationship between sulfur content and ESP cost.  (If it is




desired to express the power costs in terms of steam production rate in kilo-




grams per hour (kg/hr), the conversion factor for 1 dollar/kVJ will range from




185 to 278 mills/kg steam per hour for boiler/turbine efficiencies of 42.6 to




28.4 percent, respectively.)




4.1.2  Joy Manufacturing Study




     Another cost study on large-sized boilers was performed by a leading




manufacturer of control equipment for a boiler size of 500 to 600 MW£ while




firing an unspecified low-sulfur coal.2  Comparisons were made between a hot




and cold ESP and a baghouse operating at 99.5 percent efficiency.  If one




assumes that the boiler is firing pulverized coal and that the uncontrolled




emission rate is about 3,000 ng/J (7.0 lb/106 Btu), then the outlet emission




rate is nearly equivalent to a reduction to the  stringent  level  of emission.




Items considered in the total investment cost .were base equipment, accessories,




plenums, flues, support structures,  erecticn, insulation,  ash handling,  capac-




ity charge  (equal  to  $900/kW and based on  the total expected power consumption




required for the whole system) and  land  at $10,000 per acre.   (The capacity




charge  is also referred to  as a power penalty and is  the  cost  that a  utility




assesses each bidder  based  on the projected full-load power  consumption of




the  control device.)   The resultant unit costs were  $33.42/kW,  $37.36/kW and




$25.57/kW  (output)  for the  hot ESP, cold ESP,  and baghouse,  respectively.   The




final  conclusion of this  study  that baghouse investment  costs  are less than




those  for  precipitators when firing low-sulfur coal  is  generally acknowledged.
                                      123

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Another study shows, Figure 26, the break-even point in operating costs between
the two control approaches for specified efficiency levels and sulfur contents.3
4.1.3  GCA Study
     Prior GCA studies under a previous contract with EPA* led to the compi-
lation of cost statistics for fabric filters from several data sources,
Table 32 and Figure 27.  These data also suggest a decrease in unit cost
(dollars/unit flow rate) as the system size increases, despite the fact that
the solid line used for overall regression statistics (with a slope of nearly
one) indicates a simple, direct relationship.  However, the smaller slopes for
the dashed lines representing the individual data classes used for the average
values, suggest a reduction in unit cost with increasing size.  Because these
costs were prorated earlier to April 1978 by Chemical Engineering cost indexes,
they are considered comparable to June 1978 reference data specified for this
industrial boiler study.
4.1.4  IGCI Study
     The IGCI study alluded to in Table 32 and Figure 27 presented costs for
fabric filters, electrostatic precipitators and mechanical collectors for
boiler sizes ranging from 3 to 73 MW (10 to 250 x 106 Btu/hr) input and for
three different control levels.11  Total Turnkey costs (adjusted to June 1978
prices) are graphed against boiler size for these data in Figure 28.  It
should be noted that the coal specified in the IGCI study is similar to the
Eastern low-sulfur coal evaluated in this report:
                         0.8  percent S
                         7.5  percent ash
                        29,773 kJ/kg (12,800 Btu/lb)
                         5.0  percent water
 EPA Contract No.  68-02-2177
                                     124

-------
    0.999
    0.998
                  BA6HOUSE
c   0.997
o
o
o
    0.996
o
z
bJ
    0.995
                A/C =2.5'l
                                             ELECTROSTATIC
                                              PRECIPITATOR
    0.994
    0.993
                             I                  2
                                   S, percent
      Figure  26.  Approximate break-even point in operating costs
                 between baghouses  and precipitators for  specified
                 sulfur and efficiency levels.3  (Argonne National
                 Laboratory).
                                 125

-------
          TABLE  32.   SUMMARY CAPITAL AND OPERATING COSTS  FOR UTILITY  AND
                        INDUSTRIAL BOILERS CONTROLLED BY  FABRIC FILTERS
^v Cost
^«v Cost
^X^ base
^•v. year
Data source ^s.
I. Utility boilers
EPRI1' 1977
Joy Mfg. Co.5 4/77
Sunbury/GCA6 3/76
Nucla/GCA7* 8/75

II. Industrial boilers
IGCI8 1/77



EPA9 8/75
GCA case study10 1972



Capital costs
Plant
size
(103 acfm)

1,400
2,500
888
260


5.4
46
87
116
70
100
200
400

Total
dollars
in millions,
April 1978*

14.4
15.5
6.8
4.2


0.079
0.34
0.55
0.74
0.80
1.51
2.62
4.57

Dollars/acfm
Base year

9.25
5.50
6.20
12.75
tog =

12.60
6.44
5.49
5.48
9.00
8.76
7.57
6.61
Avg =
April 1978*

10.31
6.20
7.65
16.15
10.0

14.62
7.47
6.37
6.36
11.40
15.13
13.08
11.42
10.73
Annual operating cost
Dollars/acfm
Base year

NA
0.31
0.67
1.11
Avg =

1.56
0.81
0.72
0.70
0.25
0.74
0.68
0.63
Avg =
April 1978?

NA
0.33
0.77
1.34
0.81

1.67
0.87
0.77
0.76
0.30
1.19
1.10
1.00
0.96

 Scaled  from base year using Chemical Engineering Fabricated Equipment Cost Index.

 Includes electrical power, maintenance and  repair, and bag replacement.  Does not include amortized
 capital costs, space occupancy, depreciation, etc.

tScaled  from base year using Chemical Engineering Fabricated Equipment Index for bag replacement cost
 (20 percent of operating cost), Construction Labor Index for labor (55 percent), and electric rate
 indexes for power cost (25 percent).

 Because Nucla.is in a remote location with  no shipping facilities and no skilled work force, their
 costs are atypically high.  Therefore, the  average unit costs based on all data sources are probably
 lower than indicated.

Note: NA = not available.
                                              126

-------
   10
     8
     2

*  IQ7
O
O
 •»
H
Z
Ul
2


UJ
   10
   10
Q.
<
U
     2

     5


     5


     2
   10*
                       SYSTEM  SIZE,m3/min

                  283         2832         28,317
                   I
                LINEAR  REGRESSION  LINE
                  r=0.976 (log  data)
                  r= 0.954 (actual data)
                                              I
                      x {PILOT  PLANT STUDY)
                      A (UTILITY  BOILER   DATA)

                      o INDUSTRIAL BOILER DATA) ~

                      o GCA CASE  STUDY
                        (INDUSTRIAL  BOILER  DATA)

   NOTE'DASHED LINES SHOW  APPROXIMATE
REGRESSION LINES FOR INDIVIDUAL DATA GROUPS.
  .     .    I    .     .    i    .      .    I    i
     I03  2
                       2    5   I05  2    5
                        SYSTEM SIZE,acfm
                                     I06   2
10'
    Figure 27.  Capital Investment (April 1978 $) versus system size
              for several coal-fired boilers controlled by fabric
              filters (see Table 32).
                             127

-------
    1000


     700


     500
   OT
   (T
   o
   O 200
  ro
   O
   o
   0  100
   u
      70
      50
   O
      20
       10
              11.7
        BOILER  SIZE.MW INPUT

       23.4   35.2    46.9    58.6    70.3
                                 82
  I       I       I
 (SPREADER  STOKER)
ESP(O.I lb/!06Btu)
                        FFtO.OI lb/!06Btu   "
                        (SPREADER STOKER)
                    MC(0.3 lb/IOw Btu)
                  (CHAIN GRATE STOKER)
                               COAL'
                                 0.8%S, 7.5% A
  1
1
1
1
1
                                                  1
  40     80     120     160    20O    240

   BOILER  SIZE, !06Btu/hr INPUT
                                                        260
Figure 28.  Total turnkey cost as a function of boiler size for
           three collectors at three emission levels.  Raw data
           source:  Reference 11 — IGCI Study.
                             128

-------
     Other assumptions in  the IGCI  cost.analyses are:




     •    boilers operated at 65 percent load factor




     •    spreader stoker  considered for fabric filter  (FF) and ESP




          (65 percent of the particles > 40y)




     •    chain grate stoker considered for mechanical  collector (MC)




          (54 percent of the particles > 40y)




     •    ash-handling system not included in costs




     •    all collectors have 5.1 cm (2 inches) of insulation




     •    outlet emission  levels:




          -    ESP - 43 ng/J (0.1 lb/106 Btu)




          -    FF  - 4.3 ng/J (0.01 lb/106 Btu)




          -    MC  - 129 ng/J (0.3  lb/106 Btu)




     Because it is difficult to interpret collector costs when the outlet




emission rate is different  for each device, Figure 29 was prepared to define




the cost in terms of weight of pollutant removed.  This graph shows the fabric




filter to be more cost effective than the ESP at boiler sizes roughly less




than 50 MW (171 x 106 Btu/hr) input, for the emission rates specified above.




(If the emission rate for the precipitator were lowered to correspond with




that for the fabric filter, it is believed that the case for the fabric filter




would be reinforced even further.)  Other factors which should be considered




are the additional amounts of fine particulate matter and trace elements that




are removed by the baghouse at the 4.3 ng/J (0.01 lb/106 Btu) control level.




The case for the baghouse  becomes better and better when these factors as well




as insensitivity to coal sulfur content are considered.




     The IGCI costs are utillized in the detailed cost estimates later in this




section.  (See Tables 42 through 44.)
                                     129

-------
   250


   240



   220



   200



   180



   160

Q
UJ
>  140
UJ
   120
    80



    60



    40



    20
      BOILER  SIZE,I06 Btu/hr  INPUT


    50    100	150      200    240
                                     T
                             O	O ESP

                             A	A FF
     Sr*-OUTLET  EMISSION RATE  IS

        43ng/J (O.I  Ib/IO6 Btu)
OUTLET EMISSION  RATE  IS

4.3 ng/J(O.OI Ib/IO6  Btu)
                                            220
                                             176
                                                 UJ
                                                 >
                                                 o
                                                 2
                                                 UJ
                                                 (T
                                                        no o
                                                            o
66
           8.8   17.6   29.3      44       58.6

                    BOILER  SIZE.MW INPUT
                                     70.3
 Figure 29.
Cost-effectiveness of particulate removal as a function of

boiler size for precipitators and baghouses installed on a

spreader stoker boiler (based on annualized cost).  Raw

data source:  Reference 11 — IGCI Study.
                              130

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4.1.5  Manufacturer's Data




     For electrostatic precipitators, vendor cost estimates were converted




to unit costs (i.e., dollars per unit plate area) and graphed against the




plate area to show the relative increase in control system cost as the system




size decreases, Figure 30.  For the sake of confidentiality, specific vendors




are identified as A and B in the text and are listed irrespective of letter




code in the reference section.12  Generally, the ESP costs ranged between




$86 to $516/m2 ($8 to $48/ft2) of plate area, depending on the size of the




system required.




     Additionally, cost data were provided by one of the vendors for the




boiler sizes in question and for boilers 10 times as large.  The statement




from the manufacturer was basically that a tenfold increase in size led to




a fivefold cost increase.  This is shown in Figures 31 and 32 for installed




basic equipment and installation alone, respectively, for a pulverized coal




boiler.  It may be inferred from these data that the cost impact upon the




industrial boiler user for control equipment purchase and installation may be




more severe than that for the utility boiler operator.




4.1.6  Detailed Cost Estimates




     Detailed cost estimates are presented subsequently for 60 boiler/fuel/




control level/control device combinations.  These cost estimates are given in




June 1978 figures and are based on a number of assumptions regarding capi-




talization and annualization provided by PEDCo in their report entitled "The




Population and Characteristics of Industrial/Commercial Boilers."




     In addition to vendor-supplied cost data, efforts were made to model the




capital and annualized costs of particulate control equipment installed on




the standard boilers.  Cost models developed by a leading equipment manufacturer13
                                     131

-------
                                                 PLATE  AREA.m*
                                              9,290
92,900
S3
                                                     PLATE  AREA, ft*
                      Figure 30.  The capital cost of a precipitator as a function of size
                                  as reported by several manufacturers.12

-------
                                    m3 / MIN
          566
2830
100
28.300
  10
o
e
                                           ESP
                                                                          177
                                                                             10
                                                                          35-3
    10'
 10*
  10'
                                     acfm
     Figure 31.  Capital cost of basic equipment  (including installation)
                 and auxiliaries as a function of system size (reported
                 by Vendor A for a pulverized  coal boiler).
                                      133

-------
10.0
             566
m3/min
 2830
                                                                     28,300
                                     I
                   J	L
                             J	1-
                                                      ESP
                                             •MC
  I05
 acfm
                                                                        177
                                                                        35.3
                                          C
                                          E


                                          o
                                                                       I06
      Figure 32.   Installation cost as a function of  system size (reported
                  by Vendor A for a pulverized coal boiler).
                                     134

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and by the Department of Energy/Argonne National Laboratory were utilized to




compute equipment costs for hot and cold precipitators, fabric filters, and




wet scrubbers.  These models were originally designed for large utility boilers




and were modified by GCA to reflect key assumptions inherent in this study and




current fabric costs of $7.00/m2 ($0.65/ft2) for 10 percent Teflon-coated glass




fabric installed on a reverse air fabric filter.14  The results (presented in




earlier drafts of this report) were judged to underestimate the actual costs




for particulate control and are not included in this final report.




     The following sections discuss the estimating techniques provided by




PEDCo.




4.1.6.1  Capital Costs—




     Capital costs for particulate control systems are composed of direct and




indirect costs incurred up to the successful commissioning date of the facility.




Direct costs include basic and auxiliary equipment costs, the labor and ma-




terial required to install the equipment, and land.  Indirect costs are com-




prised of items such as engineering, construction, field expenses, construc-




tion fees, startup, performance or acceptance tests, contingencies, and working




capital.




     Equipment and related installation costs have been obtained from vendors




and the technical literature.  Values for indirect capital costs, which are




based on various percentages provided by PEDCo, are listed below:




     •    Engineering - 10 percent of installed cost




     •    Construction and field expenses - 10 percent of installed cost




     •    Construction fees - 10 percent of installed cost




     •    Startup - 2 percent of installed cost
                                     135

-------
     •    Contingencies - 20 percent of direct and indirect costs




     •    Working capital - 25 percent of direct operating costs




     It should be emphasized that these percentages are utilized for consis-




tency only; realistically, each of these items would vary depending on the




piece of control equipment used, the vendor's experience, and other site-




specific factors.




     The average cost of a performance test, based upon GCA experience, can




range from $2,000 to $10,000.  A value of $5,000 has been used in all examples




given in this report.




     The cost of land required for a pollution control device, which is




usually a small fraction of the overall costs, would probably be included in




the land cost for the entire boiler facility.  However, the costs given in




this section have been based on a factor of 0.46 m2 (5.0 ft2) per 100 kW of




capacity and a land cost of $2.50 per m2 ($10,000 per acre).15




     The total capital costs for the various systems presented subsequently



are also expressed in terms of the volumetric flow rate for the purpose of com-




parison and to indicate the exponential increase in cost with decreasing size.




4.1.6.2  Annualized Costs—



     Annual operating costs are made up of direct costs such as labor, super-




vision, replacement parts, energy costs (electrical) to run the equipment,




waste disposal, and steam, water, or chemicals where required.  In addition,




overhead and capital charges are taken into consideration in computing a




resultant annualized cost.




     For all detailed cost estimates, operatling labor and supervision costs




related to the control equipment are based upon the following factors derived




from the IGCI study (Reference 8):






                                    136

-------
                                        ESP     FF and WS     MC

          Operating labor
            man-hours per
            hour of operation          0.035       0.1        0.003

          Supervision
            % of man-hours
            for operating labor       18           5        25

     The cost for operating labor is taken as $12.02/man-hour and the cost  for

supervision as $15.63/man-hour as provided by PEDCo. Maintenance labor,  ma-

terials, and replacement parts were taken as percentages of total equipment

purchase price (excluding installation) as shown below:16

     •    Electrostatic precipitators -  2 percent

     •    Fabric filters              -  2 percent

     •    Scrubbers                   - 13 percent

     •    Mechanical collectors       -  1 percent  (assumed)

     Electricity costs were based on a unit cost of $0.0258 per kW hour (as

provided by PEDCo) and electrical consumption figures calculated in Section 5.0,

Table 60.

     Water consumption by a scrubber is based on a water cost of $0.032/1000

liters  ($0.12 per 1,000 gallons).

     Fly ash disposal is assumed to take place  at a hauling distance of 32 km

(20 miles) and a unit cost of  $1.38/1000 kg-km  ($2.00/ton-mile), dry basis,

for a total cost of  $44.16/1000 kg  ($40.00/ton).17  (This value has been

utilized by PEDCo in determining bottom ash disposal costs  for  the uncontrolled

boilers).

     Payroll overhead is taken as 30 percent of direct  labor while plant over-

head is taken at 26  percent of labor, materials,  and maintenance.  Overhead

charges representing business  expenses, rather  than being charged directly to
                                     137

-------
a particular part of the process, are added as a separate group.  Such costs
may include administrative, safety, legal, and medical services as well as
employee fringe benefits and public relations.
     The capital investment for a particulate collection system is generally
translated into annual capital charges.  General and administrative costs,
taxes, and insurance combined are taken at 4 percent of depreciable investment
or total turnkey cost.
     The capital recovery factor (CRF) is a function of the annual interest
rate and the expected equipment service life.  Calculations are based on the
following equation:
                              CRF .                                      (2)
where  i = interest rate (decimal)
       n = number of years
     Equipment service lives  (for accounting purposes) are taken at 20 years
for precipitators , baghouses, and mechanical collectors, and 10 years for wet
scrubbers.18  Based on an annual interest rate of 10 percent, the capital re-
covery factor becomes 0.11746 for a 20-year service life and 0.16275 for a
10-year life.  Total capital charges are therefore 15.75 percent (11.75 + 4.0)
and 20.3 percent (16.3 + 4.0) of total turnkey cost, respectively.  The total
annualized cost of the pollution control device is therefore the sum of direct
operating costs, overhead, and capital charges.  For each estimate, unit costs
are given in terms of the amount of pollutant removed  (i.e. , cost-effectiveness)
Although this type of unit cost is an indicator of actual system cost in terms
of pollutant removed, it is not directly applicable to control of fly ash
since the collected material  is thrown away.  Also, this parameter must
                                     138

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 obviously increase when higher efficiencies  are required  for removal  of  the




 finer-sized,  light-weight emissions.   This definition of  cost-effectiveness




 (showing the  multitube cyclone to have the highest rating) would be better




 applied in situations where the collected material is recovered as a  valuable




 product.




      The detailed cost figures for 60 specific cases  with the assumptions de-




 scribed previously are given in Tables 33 through 54.  Capital investment and




 annualized costs for the same system are designated a and b, respectively.




      Tables 33 through 41 and 47 through 54  contain costs developed by GCA in




 conjunction with costs supplied by various equipment  suppliers.^  For example,




 the vendor-supplied costs graphed in Figure  30 were used  with plate area re-




 quirements calculated in Section 5.0 to arrive at installed  cost figures.




 Tables 42 through 44 show cost figures developed by the Industrial Gas Clean-




 ing Institute (IGCI),20 which have been inflated to June  1978 costs and  nor-




.malized to the extent possible so as to agree with the assumptions in this




 study.  Tables 45 and 46 contain data provided by Vendor  D.21




      Table 35 shows cost information for a spreader stoker boiler controlled




 by an ESP and Table 36 shows the same boiler controlled by a mechanical  col-




 lector.  The  vendor has stated that these two devices are to be used  in  series




 on this boiler to achieve the desired control efficiency. This is also  true




 for the underfeed stoker boiler given in Tables 37 and 38.  For these two




 boilers, labor and supervision, and waste disposal related costs have been




 included only on the precipitator cost sheet.
                                     139

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   TABLE 33a.  CAPITAL COSTS FOR A PULSE-JET FABRIC FILTER (AT THE
               STRINGENT LEVEL) INSTALLED ON A PULVERIZED COAL
               BOILER - 58.6 MW (200 x 106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal
388,500
TOTAL DIRECT COSTS
  (equipment and installation)
INSTALLATION COSTS, INDIRECT
  Engineering
  Construction and field
  expense
  Construction fees
  Startup
  Performance test
    Subtotal
  Contingencies
TOTAL TURNKEY COSTS
  Land
          Working Capital
GRAND TOTAL
 $/m3/hr
($/acfm)
INSTALLATION COSTS,
  DIRECT
Foundations
and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
  Subtotal         202,500
           591,000

            59,100

            59,100
            59,100
            11,820
             5,000
           194,120
           157,024
           942,144
               230
            3.5
          percent
             S
                                                 0.9
                                               percent
                                                  S
            44,449   27,553
           986,823  969,927
             7.77
            13.19
    8.09
   13.74
   0.6
 percent
    S
 30,284
972,658
  7.82
 13.29
                                    140

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                                          12,937   12,232   12,638
TABLE 33b.  ANNUALIZED COSTS FOR A PULSE-JET FABRIC FILTER (AT THE
            STRINGENT LEVEL) INSTALLED ON A PULVERIZED COAL BOILER -
                        58.6 MW (200 x 106 Btu/hr) INPUT

                                            3.5      0.9       0.6
                                          percent  percent   percent
                                             S        S         S
DIRECT COSTS
  Direct labor             6,318
  Supervision                411
  Maintenance labor,
  materials and parts      7,770
  Electricity
  Steam
  Cooling water              ~
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                  2,019
  Plant                    2,020
    TOTAL OVERHEAD         4,039
CAPITAL CHARGES
  G&A, taxes and insurance          37,686
  Capital recovery factor          110,702
    TOTAL CAPITAL CHARGES          148,388
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
                                          150,360    83,480   94,000

                                          177,796   110,211  121,137
                                          330,223  262,638  273,564
                                           96.64   138.42    128.05
                                          (87.85) (125.84)  (116.41)
                                141

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   TABLE 34a.  CAPITAL COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE
               INTERMEDIATE LEVEL) INSTALLED ON A PULVERIZED COAL BOILER -
                            58.6 MW (200 x  106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)   -
  Required auxiliaries _
    Subtotal
228,883 (3.5% S)
415,248 (0.9% S)
416,869 (0.6% S)
INSTALLATION COSTS,
  DIRECT
Foundations
and supports  -
Ductwork      -
Stack
Piping
Insulation    -
Painting
Electrical
  Subtotal
                                                                  171,662  (3.5%  S)
                                                                  311,436  (0.9%  S)
                                                                  312,651  (0.6%  S)

TOTAL DIRECT COSTS
(equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Contingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/m3/hr
($/acfm)
3.5% S

400,545

40,055
40,055
40,055
8,011
5,000
133,176
106,744
640,465
230
39,952
680,647
5.36
(9.10)
0.9% S

726,684

72,668
72,668
72,668
14,534
5,000
237,538
192,844
1,157,066
230
25,876
1,183,172
9.86
(16.76)
0.6% S

729,520

72,952
72,952
72,952
14,590
5,000
238,446
193,593
1,161,559
230
29,168
1,190,957
9.58
(16.27)
                                         142

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TABLE 34b.  ANNUALIZED  COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE IN-
            TERMEDIATE  LEVEL) INSTALLED ON A PULVERIZED COAL BOILER -
                           58.6 MW  (200 x 106 Btu/hr) INPUT
DIRECT COSTS
  Direct labor          2,211
  Supervision             518
  Maintenance labor,
  materials and parts
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                 819
  Plant
    TOTAL OVERHEAD
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery  factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
                                              3.5      0.9       0.6
                                            percent  percent   percent
                                               S        S         S
  4,578    8,305     8,337
  3,580   10,469    13,086
148,920   82,000    92,520
159,807  103,503   116,672
  1,190
  2,009
2,159
2,978
 25,619   46,283
 75,255  135,955
  2,168
  2,987

 46,462
136,483
100,874  182,238   182,945
262,690  288,719   302,604
 77.61   154.92    143.91
(70.56)  (140.84)  (130.83)
                                   143

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      TABLE 35a.   CAPITAL COSTS  FOR AN  ELECTROSTATIC PRECIPITATOR  (AT
                  THE INTERMEDIATE LEVEL) INSTALLED ON A SPREADER
                  STOKER BOILER  - 44 MW (150  x  106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal
188,280 (3.5% S)
374,799 (0.9% S)
400,266 (0.6% S)
                          INSTALLATION COSTS,
                            DIRECT
Foundations
and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
  Subtotal
                                                                 141,210 (3.5% S)
                                                                 281,099 (0.9% S)
                                                                 300,200 (0.6% S)
TOTAL DIRECT COSTS
(equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Con tingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/m3/hr
($/acfm)
3.5% S
329,490

32,949
32,949
32,949
6,590
5,000
110,437
87,985
527,912
172
25,010
553,094
5.03
(8.54)
0.9% S
655,898

65,590
65,590
65,590
13,118
5,000
214,888
174,157
1,044,943
172
17,109
1,062,224
10.28
(17.47)
0,6% S
700,466

70,047
70,047
70,047
14,009
5,000
229,150
185,923
1,115,539
172
19,368
1,135,079
10.64
(18.07)
                                      144

-------
                                              3,766
                                              2,983
7,496
8,570
                                                979
                                              1,798
1,949
2,768
 8,005
10,659
  TABLE 35b.  ANNUALIZED COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT
              THE INTERMEDIATE LEVEL) INSTALLED ON A SPREADER STOKER
              BOILER - 44 MW (150 x 106 Btu/hr) INPUT
DIRECT COSTS
  Direct labor         2,211
  Supervision            518
  Maintenance labor,
  materials and parts
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                819
  Plant
    TOTAL OVERHEAD
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
                                              3.5      0.9       0.6
                                            percent  percent   percent
                                               S        S         S
                                             90,560   49,640    56,080
                                            100,038   68,435    77,473
 2,081
 2,900
                                             21,116   41,798    44,622
                                             62,030  122,781   131,076
                                             83,146  164,579   175,698
                                            184,982  235,782   256,071
                                            101.22   229.28    219.01
                                            (92.01) (208.44)  (199.10)
Note:  Cost-effectiveness is calculated by including the annualized cost
       of the mechanical collector given in Table 36b since these two
       collectors are to be used in series.
                                   145

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       TABLE 36a.  CAPITAL COSTS FOR A MECHANICAL COLLECTOR (AT THE
                   INTERMEDIATE LEVEL) INSTALLED ON A SPREADER STOKER
                   BOILER - 44 MW (150 x 106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal
37,300
INSTALLATION COSTS,
  DIRECT
Foundations
and supports     -
Ductwork         -
Stack
Piping
Insulation
Painting
Electrical
  Subtotal       20,500
TOTAL DIRECT COSTS
   (equipment and installation)    57,800
INSTALLATION COSTS, INDIRECT
   Engineering                       5,780
   Construction and field expense    5,780
   Construction fees                 5,780
   Startup                           1,156
   Performance test                  5,000
    Subtotal                      23,496
   Contingencies                   16,259
TOTAL TURNKEY COSTS               97,555
   Land                               ~
   Working Capital
GRAND TOTAL
   $/m3/hr
   ($/acfm)
                                          3.5% S
                               0.9% S
                    0.6% S
                   2,814
                 100,369
                   0.91
                  (1.55)
        2,644
      100,199
        0.97
       (1.65)
  2,712
100,267
  0.94
 (1.60)
                                       146

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 TABLE 36b.   ANNUALIZED  COSTS  FOR A MECHANICAL COLLECTOR  (AT THE INTER-
             MEDIATE LEVEL)  INSTALLED ON A  SPREADER STOKER BOILER -
                          44 MW  (150 *  IQ6  Btu/hr) INPUT

3.5
percent
S
0.9
percent
S
0.6
percent
S
DIRECT COSTS
  Direct labor
  Supervision              -
  Maintenance labor,
  materials and parts      373
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals                -
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll
  Plant                     97
    TOTAL OVERHEAD          97
CAPITAL CHARGES
  G&A, taxes and insurance       3,902
  Capital recovery factor       11,463
    TOTAL CAPITAL CHARGES       15,365
TOTAL ANNUALIZED COSTS
 7,503    7,051
7,232
 7,876    7,424
7,605
23,338   22,886    23,067
                                  147

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   TABLE 37a.   CAPITAL COSTS  FOR AN  ELECTROSTATIC PRECIPITATOR (AT THE IN-
               TERMEDIATE LEVEL)  INSTALLED ON  AN UNDERFEED  STOKER BOILER -
                             8.8 MW  (30 x  IQ6  Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal
 31,686 (3.5% S)
 84,315 (0.9% S)
100,774 (0.6% S)
                          INSTALLATION COSTS,
                            DIRECT
Foundations
and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
  Subtotal
                                                                 23,764 (3.5% S)
                                                                 63,237 (0.9% S)
                                                                 75,581 (0.6% S)
TOTAL DIRECT COSTS
(equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Contingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/m3/hr
($/acfn>)
3.5% S
55,450

5,545
5,545
5,545
1,109
5,000
22,744
15,639
93,833
34
2,650
96,517
4.40
(7.48)
0.9% S
147,552

14,755
14,755
14,755
2,951
5,000
52,216
39,954
239,722
34
2,329
242,085
11.68
(19.84)
0.6% S
176,355

17,636
17,636
17,636
3,527
5,000
61,435
47,558
285,348
34
2,603
286,985
13.56
(23.04)
                                     148

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TABLE 37b.  ANNUALIZED COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE
            INTERMEDIATE LEVEL)  INSTALLED ON AN UNDERFEED STOKER BOILER
                          8.8 MW (30 x 106 Btu/hr)  INPUT
3.5 0.9 0.6
percent percent percent
S S S
DIRECT COSTS
Direct labor 2,211
Supervision 518



   Maintenance labor,
   materials  and parts
   Electricity
   Steam
   Cooling water
   Process water
   Fuel
   Waste disposal
   Chemicals
     TOTAL DIRECT COSTS

 OVERHEAD
   Payroll                819
   Plant
     TOTAL OVERHEAD
 CAPITAL CHARGES
   G&A, taxes and insurance
   Capital recovery factor
     TOTAL CAPITAL CHARGES
 TOTAL ANNUALIZED COSTS
   $/103 kg removed
   ($/ton removed)
   634    1,686     2,015
   475    1,261     1,546
  6,760    3,640     4,120
 10,598     9,316    10,410
    165
    984

  3,753
 11,025
 14,778
             438
           1,257

           9,589
           28,167
           37,756
 26,360   48,329
235.13   701.35
   524
 1,343

11,414
33,528
44,942
                     56,695
                    709.38
(213.76)  (637.59)   (644.89)
  Note:   Cost-effectiveness is calculated by including the annualized
         cost of the mechanical collector given in Table 38b since  these
         two collectors are to be used in series.
                                    149

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TABLE 38a.  CAPITAL COSTS FOR A MECHANICAL COLLECTOR (AT THE IN-
            TERMEDIATE LEVEL) INSTALLED ON AN UNDERFEED STOKER
            BOILER - 8.8 MW (30 x 106 Btu/hr) INPUT

EQUIPMENT COSTS
Basic equipment
(includes freight)
Required auxiliaries -
Subtotal 18,000





TOTAL DIRECT COSTS
(equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Con tingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/n»3/nr
($/acfm)
INSTALLATION COSTS,
DIRECT
Foundations
and supports -
Ductwork
Stack
Piping
Insulation -
Painting
Electrical
Subtotal 10,500
3.5% S 0.9% S 0.6% S
28,500

2,850
2,850
2,850
570
5,000
14,120
8,524
51,144
-
601 574 588
51,745 51,718 51,732
2.36 2.50 2.44
(4.01) (4.24) (4.14)
                                 150

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 TABLE  38b.  ANNUALIZED COSTS FOR A MECHANICAL COLLECTOR (AT THE INTER-
            MEDIATE LEVEL) INSTALLED ON AN UNDERFEED STOKER BOILER -
                          8.8 MW (30 x io6 Btu/hr) INPUT

3.5
percent
S
0.9
percent
S
0.6
percent
S
DIRECT COSTS
  Direct labor             -
  Supervision
  Maintenance labor,
  materials and parts      180
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll
  Plant                     47
    TOTAL OVERHEAD          47
CAPITAL CHARGES
  G&A, taxes and insurance       2,046
  Capital recovery  factor        6,009
    TOTAL CAPITAL CHARGES        8,055
TOTAL ANNUALIZED COSTS
1,483    1,410
1,447
1,663    1,590
1,627
9,765     9,692
 9,729
                                   151

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       TABLE 39a.  CAPITAL COSTS FOR A PULSE-JET FABRIC FILTER (AT THE
                   STRINGENT LEVEL) INSTALLED ON A SPREADER STOKER
                   BOILER - 44 MW (150 x 106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal
283,000
INSTALLATION COSTS,
  DIRECT
Foundations
and supports     ~
Ductwork         ~
Stack
Piping
Insulation
Painting
Electrical
  Subtotal         196,500
TOTAL DIRECT COSTS
  (equipment and installation)   479,500
INSTALLATION COSTS, INDIRECT
  Engineering                     47,950
  Construction and field expense  47,950
                                          3.5% S
                               0.9% S
                    0.6% S
  Construction fees
  Startup
  Performance test
    Subtotal
  Contingencies
TOTAL TURNKEY COSTS
  Land
  Working Capital
GRAND TOTAL
  $/m3/hr
  ($/acfm)
        47,950
         9,590
         5,000
       158,440
       127,588
       765,528
            172
                   28,808
                  794,508
                    7.22
                  (12.26)
       18,408
      784,108
        7.59
      (12.90)
 20,103
785,803
  7.36
(12.51)
                                       152

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  TABLE 39b.   ANNTJALIZED COSTS FOR A PULSE-JET FABRIC FILTER  (AT THE
              STRINGENT LEVEL) INSTALLED ON A SPREADER STOKER BOILER -
                          44 MW (150 x  IQ6  Btu/hr)  INPUT



DIRECT COSTS
Direct labor
Supervision
3.5 0.9 0.6
percent percent percent
s s s

6,318
411
  Maintenance labor,
  materials and parts      5,660
  Electricity
  Steam
  Cooling water
  Process water              -
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                  2,019
  Plant                    1,472
    TOTAL OVERHEAD         3,491
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
            11,201    10,523    10,862
            91,640    50,720     57,160
           115,230   73,632     80,411
 30,621
 89,950
120,571
           239,292  197,694   204,473
           114.90   171.50    157.40
          (104.45) (155.91)  (143.09)
                                   153

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       TABLE 40a.  CAPITAL COSTS FOR A PULSE-JET FABRIC FILTER (AT THE
                   STRINGENT LEVEL) INSTALLED ON AN UNDERFEED STOKER
                   BOILER - 8.8 MW (30 * 106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)    -
  Required auxiliaries
    Subtotal            98,500
                   INSTALLATION  COSTS,
                     DIRECT
                   Foundations
                   and supports      -
                   Ductwork         -
                   Stack
                   Piping
                   Insulation       -
                   Painting
                   Electrical
                     Subtotal       48,000
TOTAL DIRECT COSTS
  (equipment and installation)   146,500
INSTALLATION'COSTS, INDIRECT
  Engineering                     14,650
  Construction and field expense  14,650
                                          3.5% S
                        0.9% S
               0.6% S
  Construction fees
  Startup
  Performance test
    Subtotal
  Contingencies
TOTAL TURNKEY COSTS
  Land
  Working Capital
GRAND TOTAL
  $/m3/hr
  ($/acfm)
 14,650
  2,930
  5,000
 51,880
 39,676
238,056
     34
            4,481
          242,571
           11.07
          (18.80)
  3,674
241,764
 11.67
(19.82)
  3,807
241,897
 11.39
(19.35)
                                      154

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  TABLE 40b.  ANNUALIZED COSTS FOR A PULSE-JET FABRIC FILTER (AT THE
              STRINGENT LEVEL) INSTALLED ON AN UNDERFEED STOKER
              BOILER - 8.8 MW (30 x 106 Btu/hr) INPUT
                                              3.5      0.9       0.6
                                            percent  percent   percent
                                               S        S         S
DIRECT COSTS
  Direct labor
  Supervision
  Maintenance labor,
  materials and parts
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll
  Plant
    TOTAL OVERHEAD
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
6,318
  411

1,970
                   2,224    2,115     2,170
                   7,000    3,880     4,360
                  17,923   14,694    15,229
2,019
  512
2,531
       9,522
      27,972
      37,494
                  57,948   54,719
                 364.24   620.52
                (331.13) (564.11)
  55,254
 557.61
(506.92)
                                   155

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      TABLE 41a.  CAPITAL COSTS FOR A FLOODED DISC SCRUBBER (AT THE INTER-
                  MEDIATE LEVEL) INSTALLED ON A SPREADER STOKER BOILER -
                              44 MW (150 x 106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries  -
    Subtotal            189,714
                  INSTALLATION  COSTS,
                    DIRECT
                  Foundations
                  and  supports   -
                  Ductwork
                  Stack
                  Piping
                  Insulation    -
                  Painting
                  Electrical
                    Subtotal    142,286
TOTAL DIRECT COSTS
  (equipment and installation)   332,000
INSTALLATION COSTS, INDIRECT
  Engineering                     33,200
  Construction and field expense  33,200
                                          3.5% S
                        0.9%  S
               0.6%  S
  Construction fees
  Startup
  Performance test
    Subtotal
  Contingencies
TOTAL TURNKEY COSTS
  Land
  Working Capital
GRAND TOTAL
  $/m3/hr
  ($/acfm)
 33,200
  6,640
  5,000
111,240
 88,648
531,888
    200
           40,560
          572,648
            5.20
           (8.84)
 30,330
562,418
  5.44
 (9.25)
 31,940
564,028
  5.29
 (8.98)
                                     156

-------
   TABLE Alb.  ANNUALIZED COSTS FOR A FLOODED DISC SCRUBBER (AT  THE
               INTERMEDIATE LEVEL) INSTALLED ON A SPREADER STOKER
               BOILER - 44 MW (150 x 1Q6 Btu/hr) INPUT

                                              3.5      0.9       0.6
                                            percent  percent  percent
                                               S        S         S
DIRECT COSTS
  Direct labor              6,318
  Supervision                411
  Maintenance labor,
  materials and parts      24,663
  Electricity
  Steam
  Cooling vater              -
  Process water
  Fuel
  Waste disposal
  Chemicals                  -
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                   2,019
  Plant                     6,412
    TOTAL OVERHEAD          8,431
CAPITAL CHARGES
  G&A, taxes and insurance         21,276
  Capital recovery factor          86,698
    TOTAL CAPITAL CHARGES         107,974
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
 23,731   23,731    23,731
  16,556    16,556    16,556
  90,560    49,640    56,080
 162,239   121,319   127,759
 278,644  237,724
 135.39   210.72
(123.08) (191.56)
 244,164
 191.57
(174.15)
                                  157

-------
   TABLE 42a.   CAPITAL COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE IN-
               TERMEDIATE LEVEL) INSTALLED ON A SPREADER STOKER BOILER -
               45 MW (154 x 106 Btu/hr)  INPUT (IGCI DATA)
EQUIPMENT COSTS
  Basic equipment
  (includes freight)    235,758*
  Required auxiliaries   86,059
    Subtotal            321,817
INSTALLATION COSTS,
  DIRECT
Foundations
and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
  Subtotal
 14,657
 67,413
 10,816
108,237
 64,427
  2,314
 37,701
305,565
TOTAL DIRECT COSTS
(equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Contingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/m3/hr
($/acfm)
0.8% S
627,382

14,964
31,342
1,026
5,904
8,000
61,236
21,005
709,623
172
23,319
733,114
5.19
(8.82)

*SCA = 47 m2/m3/sec (239 ft2/1000 acfm)
                                      158

-------
 TABLE 42b.   ANNUALIZED COSTS  FOR AN ELECTROSTATIC PRECIPITATOR  (AT THE
             INTERMEDIATE LEVEL)  INSTALLED ON  A SPREADER  STOKER  BOILER -
             45 MW (154 x 106  Btu/hr) INPUT (IGCI DATA)

                                                       0.8
                                                     percent
                                                        S
DIRECT COSTS
  Direct labor              2,344
  Supervision                 508
  Maintenance labor         3,482
  Materials                    171
  Parts                       878
  Electricity                                         20,812
  Steam                       -
  Cooling water
  Process water               -
  Fuel
  Waste disposal                                      60,087
  Chemicals
    TOTAL DIRECT COSTS                                88,282
OVERHEAD
  Payroll                     536
  Plant                     2,781
    TOTAL OVERHEAD          3,317
CAPITAL CHARGES
  G&A, taxes and insurance            -
  Capital recovery factor
    TOTAL CAPITAL CHARGES         120,603
TOTAL ANNUALIZED COSTS                                212,202
  $/103 kg removed                                    155.41
  ($/ton removed)                                    (141.28)
                                  159

-------
        TABLE  43a.   CAPITAL  COSTS FOR A PULSE-JET FABRIC FILTER (AT THE
                    STRINGENT LEVEL)  INSTALLED  ON A SPREADER STOKER
                    BOILER - 55 MW  (188 *  106 Btu/hr) INPUT (IGCI DATA)
EQUIPMENT COSTS
Basic equipment
(includes freight) 226,538*
Required auxiliaries 46,409
Subtotal 272,947






TOTAL DIRECT COSTS
(equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Contingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/m3/hr
($/acfm)
INSTALLATION COSTS,
DIRECT
Foundations
and supports 17,574
Ductwork 67,413
Stack 10,827
Piping
Insulation
Painting
Electrical
Other
Subtotal
0.8% S
493,136

17,449
13,278
4,251
4,046
5,129
44,153
8,126
545,415
172
35,321
580,908
3.93
(6.67)
4,570
63,504
3,077
17,791
35,433
220,189















*A/C =1.5/1 (m/min) (4.8/1 - ft/min)
                                      160

-------
  TABLE 43b.   ANNUALIZED COSTS FOR A PULSE-JET FABRIC FILTER (AT THE
              STRINGENT LEVEL) INSTALLED ON A SPREADER STOKER BOILER
              55 MW (188 x 106 Btu/hr)  INPUT (IGCI DATA)

0.8
percent
S
DIRECT COSTS
Direct labor 9,652
Supervision 436
Maintenance labor 5,764
Materials 2,718
Parts 27,250
Electricity
Steam
Cooling water
Process water -
Fuel
Waste disposal
Chemicals
TOTAL DIRECT COSTS


20,382



75,080

141,282
OVERHEAD
  Payroll                   1,909
  Plant                     8,371
    TOTAL OVERHEAD         10,280
CAPITAL CHARGES
  G&A, taxes and insurance           -
  Capital recovery factor
    TOTAL CAPITAL CHARGES         92,715
TOTAL ANNUALIZED COSTS                                244,277
  $/103 kg removed                                    143.16
  ($/ton removed)                                    (130.14)
                                   161

-------
     TABLE 44a.  CAPITAL COSTS FOR A MECHANICAL COLLECTOR  (AT THE MOD-
                 ERATE LEVEL) INSTALLED ON A SPREADER STOKER BOILER -
                 40 MW (137 x 106 Btu/hr) INPUT (IGCI DATA)
EQUIPMENT COSTS
  Basic equipment
  (includes freight)      58,182
  Required auxiliaries    11,682
    Subtotal              69,864
INSTALLATION COSTS,
  DIRECT
Foundations
and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
  Subtotal
 10,257
 60,643
  9,984
  4,445
  7,796
    137
  9,118
102,380
TOTAL DIRECT COSTS
  (equipment and installation)
INSTALLATION COSTS, INDIRECT
  Engineering
  Construction and field expense
  Construction fees
  Startup
  Performance test
    Subtotal
  Contingencies
TOTAL TURNKEY COSTS
  Land
  Working Capital
GRAND TOTAL
  $/m3/hr
  ($/acfm)
      0.8% S
      172,244

        2,279
        5,129
        2,165
        1,140
        2,279
       12,992

      185,236

       40,844
      226,080
        1.81
       (3.08)
                                       162

-------
  TABLE 44b.  ANNUALIZED COSTS FOR A MECHANICAL COLLECTOR (AT THE MOD-
              ERATE LEVEL) INSTALLED ON A SPREADER STOKER BOILER -
              40 MW (137 x io6 Btu/hr) INPUT (IGCI DATA)

                                                       0.8
                                                     percent
                                                        S
DIRECT COSTS
  Direct labor             120
  Supervision               39
  Maintenance labor        351
  Materials
  Parts                    832
  Electricity                                        14,474*
  Steam                      -
  Cooling water
  Process water
  Fuel
  Waste disposal                                    147,560f
  Chemicals
    TOTAL DIRECT COSTS                              163,376
OVERHEAD
  Payroll                   34
  Plant                    160
    TOTAL OVERHEAD         194
CAPITAL CHARGES
  G&A, taxes and insurance         -
  Capital recovery factor
    TOTAL CAPITAL CHARGES       31,490
TOTAL ANNUALIZED COSTS                              195,060
  $/103 kg  removed                                   58.16
  ($/ton removed)                                   (52.88)

*AP = 1.5 kPa  (6.2 in. W.C.)
1~A high waste disposal cost is  indicated  since just over  635 kg/hr
  (1,400 Ib/hr) are removed by the-collector.
                                   163

-------
     TABLE  45a.   CAPITAL  COSTS FOR A TWO-STAGE IONIZING WET SCRUBBER (AT THE
                 STRINGENT LEVEL) INSTALLED ON A CHAIN GRATE STOKER BOILER -
                              22 MW (75  x 106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal
256,500
INSTALLATION COSTS,
  DIRECT
Foundations
and supports          -
Ductwork              -
Stack
Piping
Insulation            -
Painting
Electrical
  Subtotal       359,100
TOTAL DIRECT COSTS
  (equipment and installation)   615,600
INSTALLATION COSTS, INDIRECT
  Engineering                     61,560
  Construction and field expense  61,560
                                          3.5% S
                               0.9%  S
                    0.6% S
  Construction fees
  Startup
  Performance test
    Subtotal
  Contingencies
TOTAL TURNKEY COSTS
  Land
  Working Capital
GRAND TOTAL
  $/m3/hr
  ($/acfm)
         61,560
         12,312
          5,000
        201,992
        163,518
        981,110
             86
                   18,865
                1,000,061
                   18.22
                  (30.96)
       16,844
      998,040
       19.52
      (33.16)
 17,178
998,374
 18.72
(31.80)
                                      164

-------
              3,716      3,471     3,607
  TABLE 45b.  ANNUALIZED COSTS FOR A TWO-STAGE IONIZING WET SCRUBBER
              (AT THE STRINGENT LEVEL) INSTALLED ON A CHAIN GRATE
              STOKER BOILER - 22 MW (75 x 106 Btu/hr) INPUT

                                              3.5      0.9       0.6
                                            percent  percent   percent
                                               S        S         S
DIRECT COSTS
  Direct labor           6,318
  Supervision              411
  Maintenance labor,
  materials and parts   33,345
  Electricity
  Steam
  Cooling water
  Process water         14,190
  Fuel
  Waste disposal
  Chemicals                -
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                 2,019
  Plant                   8,670
    TOTAL OVERHEAD      10,689
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery  factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg  removed
  ($/ton removed)
             17,480     9,640     10,840
             75,460    67,375    68,711
 39,244
159,921
199,165
            285,314   277,229   278,565
            718.18   1265.36   1130.71
           (652.89) (1150.33) (1027.92)
   165

-------
    TABLE 46a.  CAPITAL COSTS FOR A ONE-STAGE IONIZING WET SCRUBBER (AT THE  IN-
                TERMEDIATE LEVEL) INSTALLED ON A CHAIN GRATE STOKER BOILER -
                                22 MW (75 x IQ6 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal
                          132,200
                   INSTALLATION COSTS,
                     DIRECT
                   Foundations
                   and supports            -
                   Ductwork                -
                   Stack
                   Piping
                   Insulation              -
                   Painting
                   Electrical
                     Subtotal        162,400
TOTAL DIRECT COSTS
  (equipment and installation)
                                          3.5% S
                        0.9% S
               0.6%  S
294,600
INSTALLATION COSTS, INDIRECT
  Engineering                     29,460
  Construction and field expense  29,460
  Construction fees
  Startup
  Performance test
    Subtotal
  Contingencies
TOTAL TURNKEY COSTS
  Land
  Working Capital
GRAND TOTAL
  $/m3/hr
  ($/acfm)
 29,460
  5,892
  5,000
 99,272
 78,774
472,646
     86
           12,447
          485,179
            8.84
          (15.02)
 10,457
483,189
  9.45
(16.05)
 10,774
483,506
  9.06
(15.40)
                                      166

-------
  TABLE 46b.   ANNUALIZED COSTS FOR A ONE-STAGE IONIZING WET SCRUBBER
              (AT THE INTERMEDIATE LEVEL)  INSTALLED ON A CHAIN GRATE
              STOKER BOILER - 22 MW (75 x  106 Btu/hr)  INPUT

                                              3.5      0.9       0.6
                                            percent  percent   percent
                                               S        S         S
DIRECT COSTS
  Direct labor           6,318
  Supervision              411
  Maintenance labor,
  materials and parts   17,186
  Electricity
  Steam
  Cooling water
  Process water           7,095
  Fuel
  Waste disposal
  Chemicals                -
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll
  Plant
    TOTAL OVERHEAD
2,019
4,468
6,487
 CAPITAL  CHARGES
   G&A, taxes  and  insurance
   Capital recovery  factor
     TOTAL CAPITAL CHARGES
 TOTAL ANNUALIZED  COSTS
   $/103  kg removed
   ($/ton removed)
                    1,858     1,736     1,804
                   16,920     9,080    10,280
                   49,788    41,826    43,094
       18,906
       77,041
       95,947
                  152,222
                  395.85
                 (359.86)
 144,260
 699.06
(635.51)
 145,528
 622.89
(566.26)
                                   167

-------
      TABLE 47a.  CAPITAL COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE
                  STRINGENT LEVEL)  INSTALLED ON A PULVERIZED COAL BOILER -
                              58.6  MW (200 * 105 Btu/hr)  INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal
260,000 (3.5% S)
432,400 (0.9% S)
448,365 (0.6% S)
INSTALLATION COSTS,
  DIRECT
Foundations
and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
  Subtotal
                                                                 194,800 (3.5% S)
                                                                 324,246 (0.9% S)
                                                                 336,273 (0.6% S)
TOTAL DIRECT COSTS
(equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Contingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/m3/hr
($/acfm)
3.5% S
454,800

45,480
45,480
45,480
9,096
5,000
150,536
121,067
726,403
230
40,647
767,280
6.04
(10.26)
0.9% S
756,646

75,665
75,665
75,665
15,133
5,000
247,128
200,755
1,204,529
230
27,081
1,231,840
10.27
(17.45)
0.6% S
784,638

78,464
78,464
78,464
15,693
5,000
256\085
208,145
1,248,868
230
30,628
1,279,726
10.29
(17.48)
                                      168

-------
                                            5,200
                                            4,300
 8,648
13,466
                                            1,352
                                            2,171
 2,248
 3,067
 8,967
16,815
TABLE 47b.  ANNUALIZED COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT
            THE STRINGENT LEVEL) INSTALLED ON A PULVERIZED COAL
            BOILER - 58.6 MW (200 x 106 Btu/hr) INPUT

                                            3.5      0.9       0.6
                                          percent  percent   percent
                                             S        S         S
DIRECT COSTS
  Direct labor         2,211
  Supervision            518
  Maintenance labor,
  materials and parts
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                819
  Plant
    TOTAL OVERHEAD
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery  factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
                                          150,360    83,480    94,000
                                          162,589    108,323    122,511
 2,331
 3,150
                                           29,056    48,181    49,955
                                           85,352   141,532   146,742
                                          114,408   189,713   196,697
                                          279,168   301,103   322,358
                                           81.70    158.71    150.89
                                          (74.27)  (144.28)  (137.17)
                                 169

-------
      TABLE  48a.   CAPITAL COSTS  FOR AN  ELECTROSTATIC PRECIPITATOR  (AT THE
                  STRINGENT  LEVEL)  INSTALLED ON A SPREADER STOKER  BOILER -
                                44  MW (150  x 106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)    ~
  Required auxiliaries  -
    Subtotal
228,600 (3.5% S)
407,800 (0.9% S)
410,170 (0.6% S)
TOTAL DIRECT COSTS
  (equipment and installation)
INSTALLATION COSTS, INDIRECT
  Engineering
  Construction and field expense
  Construction fees
  Startup
  Performance test
    Subtotal
  Contingencies
TOTAL TURNKEY COSTS
  Land
  Working Capital
GRAND TOTAL
  $/m3/hr
  ($/acfm)
INSTALLATION COSTS,
  DIRECT
Foundations
and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
  Subtotal
                                                                 171,492  (3.5% S)
                                                                 305,850  (0.9% S)
                                                                 307,630  (0.6% S)
3.5% S
400,092
40,009
40,009
40,009
8,002
5,000
133,029
106,624
639,745
172
25,641
665,558
6.04
(10.27)
0.9% S
713,650
71,365
71,365
71,365
14,273
5,000
233,368
189,404
1,136,422
172
18,195
1,154,789
11.18
(18.99)
0.6% S
717,800
71,780
71,780
71,780
14,356
5,000
234,696
190,499
1,142,995
172
20,484
1,163,651
10.91
(18.53)
                                     170

-------
                                           4,572
                                           3,621
            8,156
           11,174
                                            1,189
                                            2,008
            2,121
            2,940
                                           25,590    45,457
                                           75,170    133,530
                                          100,760    178,987
                                          205,330    254,706
                                           98.58     220.96
  8,203
 13,845
TABLE 48b.  ANNUALIZED COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT
            THE STRINGENT LEVEL) INSTALLED ON A SPREADER STOKER
            BOILER - 44 MW (150 x 106 Btu/hr) INPUT

                                            3.5      0.9       0.6
                                          percent  percent   percent
                                             S        S         S
DIRECT COSTS
  Direct labor         2,211
  Supervision            518
  Maintenance labor,
  materials and parts
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                819
  Plant
    TOTAL OVERHEAD
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
                                           91,640    50,720    57,160
                                          102,562    72,779    81,937
  2,133
  2,952

 45,720
134,302
180,022
                    264,911
                    203.92
(89.62)   (200.87)   (185.38)
                                171

-------
     TABLE 49a.  CAPITAL COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE
                 STRINGENT LEVEL) INSTALLED ON A CHAIN GRATE STOKER BOILER -
                               22 MW (75 x 106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries  ~
    Subtotal            106,313  (3.5% S)
                        256,960  (0.9% S)
                        295,529  (0.6% S)
TOTAL DIRECT COSTS
  (equipment and installation)
INSTALLATION COSTS, INDIRECT
  Engineering
  Construction and field expense
  Construction fees
  Startup
  Performance test
    Subtotal
  Contingencies
TOTAL TURNKEY COSTS
  Land
  Working Capital
GRAND TOTAL
  $/m3/nr
  ($/acfm)
INSTALLATION COSTS,
  DIRECT
Foundations
and supports
Ductwork      -
Stack
Piping
Insulation    -
Painting
Electrical
  Subtotal
3.5% S
186,048
18,605
18,605
18,605
3,721
5,000
64,536
50,117
300,701
86
5,964
306,751
5.59
(9.50)
0.9% S
449,680
44,968
44,968
44,968
8,994
5,000
148,898
119,716
718,293
86
5,489
723,868
14.16
(24.05)
 79,735 (3.5% S)
192,720 (0.9% S)
221,647 (0.6% S)
      0.6% S
      517,176

       51,718
       51,718
       51,718
       10,344
        5,000
      170,498
      137,535
      825,208
           86
        6,257
      831,551
       15.59
      (26.48)
                                     172

-------
                                           2,126
                                           1,519
  5,139
  4,448
                                          17,480
                                             553
                                           1,372

                                           12,028
                                           35,332
                                           47,360
                                           72,586
                                          182.71
  1,336
  2,155

 28,732
 84,399
113,131
137,242
626.42
  5,911
  5,546
TABLE 49b.  ANNUALIZED COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT
            THE STRINGENT LEVEL) INSTALLED ON A CHAIN GRATE STOKER
            BOILER - 22 MW (75 x106 Btu/hr) INPUT

                                            3.5      0.9       0.6
                                          percent  percent   percent
                                             S        S         S
DIRECT COSTS
  Direct labor          2,211
  Supervision             518
  Maintenance labor,
  materials and parts
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                 819
  Plant
    TOTAL OVERHEAD
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery  factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
  9,640    10,840
                                          23,854    21,956    25,026
  1,537
  2,356

 33,008
 96,962
129,970
157,352
638.69
                                         (166.10)   (569.47)   (580.63)
                                 173

-------
TABLE 50a.   CAPITAL COSTS FOR AN ELECTROSTATIC PRECIPITATOR  (AT THE
            STRINGENT LEVEL)  INSTALLED ON AN UNDERFEED STOKER BOILER
                         8.8  MW (30 x  106 Btu/hr) INPUT
EQUIPMENT COSTS INSTALLATION COSTS,
DIRECT
Basic equipment
(includes freight) - Foundations
and supports
Required auxiliaries
Ductwork
Subtotal 44,229 (3.5% S)
122,388 (0.9% S)
147,060 (0.6% S) Piping
Insulation -
Painting
Electrical
Subtotal 33,171 (3.5% S)
91,792 (0.9% S)
110,295 (0.6% S)

TOTAL DIRECT COSTS
(equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Contingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/m3/hr
($/acfm)
3.5% S

77,400

7,740
7,740
7,740
1,548
5,000
29,768
21,434
128,602
34
2,799
131,435
6.00
(10.19)
0.9% S

214,180

21,418
21,418
21,418
4,284
5,000
73,538
57,544
345,262
34
2,705
348,001
16.79
(28.52)
0.6% S

257,355

25,736
25,736
25,736
5,147
5,000
87,355
68,942
413,652
34
3,050
416,736
19.62
(33.34)
                                174

-------
                        518
                                             885
                                             583
             2,448
             1,763
                                           7,000
             3,880
                                             230
                                           1,049

                                           5,144
                                          15,111
                                          20,255
               636
             1,455

            13,810
            40,568
            54,378
 2,941
 2,170
TABLE 50b.  ANNUALIZED COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT
            THE STRINGENT LEVEL) INSTALLED ON AN UNDERFEED STOKER
            BOILER - 8.8 MW (30 x 106 Btu/hr) INPUT
DIRECT COSTS
  Direct labor         2,211
  Supervision            518
  Maintenance labor,
  materials and parts
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll
  Plant
    TOTAL OVERHEAD
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
                                            3.5      0.9       0.6
                                          percent  percent   percent
                                             S        S         S
 4,360
                                          11,197    10,820    12,200
   765
 1,584

16,546
48,604
65,150
                                                    66,653    78,934
                                                   755.85    796.59
  32,501
 204.29
(185.72)  (687.14)   (724.17)
                                 175

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     TABLE 51a.  CAPITAL COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE
                 SIP LEVEL) INSTALLED ON A PULVERIZED COAL BOILER -
                            58.6 MW (200 x IQ6 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal            141,560 (3.5% S)
                        303,840 (0.9% S)
                        361,400 (0.6% S)
INSTALLATION COSTS,
  DIRECT
Foundations
and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
  Subtotal
                                                                106,170 (3.5% S)
                                                                227,880 (0.9% S)
                                                                271,050 (0.6% S)
TOTAL DIRECT COSTS
(equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Contingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/m3/hr
($/acfm)
3.5% S
247,730

24,773
24,773
24,773
4,955
5,000
84,274
66,400
398,404
230
36,604
435,238
3.43
(5.82)
0.9% S
531,720

53,172
53,172
53,172
10,634
5,000
175,150
141,374
848,244
230
21,587
870,061
7.25
(12.32)
0.6% S
632,450

63,245
63,245
63,245
12,649
5,000
207,384
167,967
1,007,800
230
24,891
1,032,921
8.30
(14.11)
                                     176

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TABLE 51b.  ANNUALIZED COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT
             THE SIP LEVEL) INSTALLED ON A PULVERIZED COAL BOILER -
                       58.6 MW (200 x 106 Btu/hr) INPUT

                                            3.5      0.9       0.6
                                          percent  percent   percent
                                             S        S         S
                      2,211
                        518
DIRECT COSTS
  Direct labor
  Supervision
  Maintenance labor,
  materials and parts
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                 819
  Plant
   . TOTAL OVERHEAD
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery  factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
   ($/ton removed)
                                            2,831
                                            2,495
                                              736
                                            1,555

                                           15,936
                                           46,812
                                          210,718
                                           67.01
 6,077
 6,021
  1,580
  2,399

 33,930
 99,669
                                           62,748   133,599
222,345
136.79
  7,228
  7,567
                                          138,360    71,520    82,040
                                          146,415    86,347    99,564
  1,879
  2,698

 40,312
118,417
158,729
260,991
139.98
                                           (60.92)   (124.35)   (127.25)
                                 177

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    TABLE 52a.   CAPITAL COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE
                 SIP LEVEL) INSTALLED ON A SPREADER STOKER BOILER -
                             44 MW (150 x 106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal            114,296 (3.5% S)
                        247,344 (0.9% S)
                        310,057 (0.6% S)
INSTALLATION COSTS,
  DIRECT
Foundations
and supports  -
Ductwork      -
Stack
Piping
Insulation    -
Painting
Electrical
  Subtotal
                                                                  85,722 (3.5% S)
                                                                 185,508 (0.9% S)
                                                                 232,543 (0.6% S)
TOTAL DIRECT COSTS
(equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Contingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/m3/hr
(S/acfm)
3.5% S
200,018

20,002
20,002
20,002
4,000
5,000
69,006
53,805
322,829
172
22,426
345,427
3.14
(5.33)
0.9% S
432,852

43,285
43,285
. 43,285
8,657
5,000
143,512
115,273
691,637
172
13,556
705,365
6.83
(11.60)
0.6% S
542,600

54,260
54,260
54,260
10,852
5,000
178,632
144,246
865,478
172
15,771
881,421
8.26
(14.04)
                                      178

-------
                                              2,286
                                              2,048
4,947
4,787
                                                594
                                              1,413

                                             12,913
                                             37,932
 1,286
 2,105
6,201
5,953
TABLE 52b.  ANNUALIZED COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE
            SIP LEVEL) INSTALLED ON A SPREADER STOKER BOILER -
                          44 MW (150 x 106 Btu/hr) INPUT

                                              3.5      0.9       0.6
                                            percent  percent   percent
                                               S        S         S
DIRECT COSTS
  Direct labor         2,211
  Supervision            518
  Maintenance labor,
  materials and parts
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                819
  Plant
    TOTAL OVERHEAD
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery  factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
                                             82,640    41,760     48,200
                                             89,703    54,223    63,083
1,612
2,431
27,665    34,619
81,267   101,694
                                             50,845   108,932   136,313
                                            141,961   165,260   201,827
                                             75.58    174.13    184.24
                                            (68.71)  (158.30)  (167.49)
                                 179

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     TABLE 53a.  CAPITAL COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE
                 SIP LEVEL) INSTALLED ON A CHAIN GRATE STOKER BOILER -
                               22 MW (75 x 106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal
34,143 (3.5% S)
63,200 (0.9% S)
91,514 (0.6% S)
                          INSTALLATION COSTS,
                            DIRECT
Foundations
and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
  Subtotal
                                                                 25,607 (3.5% S)
                                                                 47,400 (0.9% S)
                                                                 68,636 (0.6% S)
TOTAL DIRECT COSTS
(•equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Contingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/m3/hr
($/acfm)
3.5% S
59,750

5,975
5,975
5,975
1,195
5,000
24,120
16,774
100,644
86
4,296
105,026
1.91
(3.25)
0.9% S
110,600

11,060
11,060
11,060
2,212
5,000
40,392
30,198
181,190
86
2,621
183,897
3.60
(6.11)
0.6% S
160,150

16,015
16,015
16,015
3,203
5,000
56,248
43,280
259,678
86
3,160
262,924
4.93
(8.37)
                                     180

-------
                                               683
                                               773
  1,264
  1,370
                                            13,000
  5,120
                                               178
                                               997

                                             4,026
                                            11,826
                                            15,852
                                            34,034
                                           115.19
    329
  1,148

  7,248
 21,290
 28,538
 40,169
345.20
  1,830
  1,722
TABLE 53b.  ANNUALIZED COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE
            SIP LEVEL) INSTALLED ON A CHAIN GRATE STOKER BOILER -
                          22 MW (75 x io6 Btu/hr) INPUT

                                              3.5      0.9        0.6
                                            percent   percent    percent
                                               S        S         S
DIRECT COSTS
  Direct labor          2,211
  Supervision             518
  Maintenance labor,
  materials and parts
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                 819
  Plant
    TOTAL OVERHEAD
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery  factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
  6,360
                                            17,185    10,483    12,641
    476
  1,295

 10,387
 30,512
 40,899
 54,835
379.36
                                           (104.72)   (313.82)   (344.87)
                                   181

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     TABLE 54a.   CAPITAL  COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE
                 SIP  LEVEL) INSTALLED ON AN UNDERFEED STOKER BOILER -
                             8.8 MW  (30 x 106 Btu/hr) INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries
    Subtotal
13,257 (3.5% S)
25,629 (0.9% S)
35,886 (0.6% S)
                          INSTALLATION COSTS,
                            DIRECT
Foundations
and supports
Ductwork
Stack
Piping
Insulation
Painting
Electrical
  Subtotal
                                                                  9,943 (3.5%  S)
                                                                 19,221 (0.9%  S)
                                                                 26,914 (0.6%  S)
TOTAL DIRECT COSTS
(equipment and installation)
INSTALLATION COSTS, INDIRECT
Engineering
Construction and field expense
Construction fees
Startup
Performance test
Subtotal
Contingencies
TOTAL TURNKEY COSTS
Land
Working Capital
GRAND TOTAL
$/m3/hr
($/acfm)
3.5% S
23,200

2,320
2,320
2,320
464
5,000
12,424
7,125
42,749
34
2,123
44,906
2.05
(3.48)
0.9% S
44,850

4,485
4,485
4,485
897
5,000
19,352
12,840
77,042
34
1,456
78,532
3.79
(6.44)
0.6% S
62,800

6,280
6,280
6,280
1,256
5,000
25,096
17,579
105,475
34
1,661
107,170
5.04
(8.57)
                                     182

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TABLE 54b.  ANNUALIZED COSTS FOR AN ELECTROSTATIC PRECIPITATOR (AT THE
            SIP LEVEL) INSTALLED ON AN UNDERFEED STOKER BOILER -
                          8.8 MW (30 x 106 Btu/hr) INPUT



DIRECT COSTS
Direct labor 2,211
Supervision 518
3.5 0.9 0.6
percent percent percent
S S S



  Maintenance labor,
  materials and parts
  Electricity
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal
  Chemicals
    TOTAL DIRECT COSTS
OVERHEAD
  Payroll                819
  Plant
    TOTAL OVERHEAD
CAPITAL CHARGES
  G&A, taxes and insurance
  Capital recovery  factor
    TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS
  $/103 kg removed
  ($/ton removed)
     265
     298
   5,200
   8,492
      69
     888

   1,710
   5,023
   6,733
  16,113
 136.35
    513
    542
  2,040
  5,824
    133
    952

  3,082
  9,052
 12,134
 18,910
407.86
    718
    678
  2,520
  6,645
    187
  1,006

  4,219
 12,393
 16,612
 24,263
423.64
(123.95)   (370.78)   (385.13)
                                   183

-------
     To determine the economic impact of each of the 60 cost  estimates,




Table 55 is presented to show the percentage increase in annualized  costs over




uncontrolled boilers and, where possible, SIP-controlled boilers.  Each  of the




examples in Table 55 corresponds to part b of Tables 33 through  54.   The cost




differences are shown to be very significant and represent increases from




about 3.5 to 14.7 percent over uncontrolled boilers and 0.9 to 5.5 percent




over SIP-controlled units.
                                     184

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TABLE 55.   COSTS  OF "BEST".PARTICULATE  CONTROL TECHNIQUES FOR COAL-FIRED BOILERS
System
Standard
Heat input
MW
(106 Btu/hr)
1. 58.6
(200)
0.6-3.5% S
2. 58.6
(200)
0.6-3.5% S
3. 58.6
(200)
0.6-3.5% S
4. 44
(150)
0.6-3.5% S
8 5. 44
(150)
0.6-3.5% S
6. 44
(150)
0.6-3.5% S
7. 45
(154)
0.8 % S
8. 55
(188)
0.8% S
9. 44
(150)
0.6-3.5% S
10. 40
(137)
0.8% S
11. 22
(75)
0.6-3.5% S
boilers
Type
Pulverized
coal
Pulverized
coal
Pulverized
coal
Spreader
stoker
Spreader
stoker
Spreader
stoker
Spreader
stoker
Spreader
stoker
Spreader
stoker
Chain grate
stoker
Chain grate
stoker
Type /and
level
of control
Fabric filter/
Stringent
ESP/
Intermediate
ESP/
stringent
ESP and MC
in series/
intermediate
Fabric filter/
Stringent
Wet scrubber/
intermediate
ESP/
intermediate
Fabric filter/
stringent
ESP/
stringent
MC/
moderate
Wet scrubber/
stringent
Control
efficiency
(%)
99+
99+
99.25
to
99.58
99+
99+
99+
\
97.3
99.7
99.1
to
99.5
97.0
-98
Annualized
costs
(5)
-263,000
to
330,000
-263,000
to
303,000
-279,000
to
322,000
-212,000
to
282,000
-198,000
to
239,000
-250,000
-212,000
-244,000
-205,000
to
265,000
-195,000
-280,000
Impact based
Annualized upon annuallzed cost
$/J/sec % Increase in* % Increase in^
(5/106 Btu/hr) costs over the costs over the
uncontrolled boiler SIP-controlled boiler
0.0045 - 0.0056 -6.0 - 7.8% NA
(1315 - 1650)
0.0045 - 0.005 -6.2 - 7.0% -0.9 - 1.2%
(1315 - 1515)
0.0048 - 0.0055 -6.6 - 7.4% -1.3 - 1-5%
(1395 - 1610)
0.0048 - 0.0064 -6.9 - 9.0% NA
(1413 - 1880)
0.0045 - 0.0054 —6.2 - 7.8% NA
(1320 - 1593)
0.0057 -8.1% NA
(1667)
0.0047 -6.6% NA
(1377)
0.0044 -6.1% NA
(1298)
0.0047 - 0.006 -6.7 - 8.5% -2.0%
(1367 - 1767)
0.0049 -7.8% NA
(1423)
0.013 -14.7% NA
(3733)
                                     (continued)

-------
                                                               TABLE 55  (continued)
00
cr<
System

12.
13.
14.
15.
16.
17.
18.
19.
20.
*
Standard
Heat Input
MM
(106 Btu/hr)
22
(75)
0.6-3.5% S
22
(75)
0.6-3.5% S
8.8
(30)
0.6-3. SIS S
8.8
(30)
0.6-3.5X S
8.8
(30)
0.6-3.5% S
58.6
(200)
0.6-3.5% S
44
(150)
0.6-3.5% S
22
(75)
0.6-3.5% S
8.8
(30)
0.6-3.5% S
boilers
Type
Chain grate
stoker
Chain grate
stoker
Underfeed
stoker
Underfeed
stoker
Underfeed
stoker
Pulverized
coal
Spreader
stoker
Chain grate
stoker
Underfeed
stoker
Annualized cost
Annualized
Type/and Control costs
level efficiency (5)
of control (%)
Wet scrubber/
intermediate
ESP/
stringent
ESP and MC
in series/
intermediate
Fabric filter/
Stringent
ESP/
stringent
ESP/SIP
ESP/StP
ESP/SIP
ESP/SIP
	 v i nn
92.0
to
95.56
97.60
to
98.67
99+
99+
97.60
to
98.66
85.00
to
91.64
81.54
to
89.73
52.00
to
73.33
52.00
to
73.21

Annualized uncontrolled boiler cost """
Annual! zed cost - SIP Annualized cost
~150.000
~ 73, 000
to
157,000
~37,000
to
67,000
~56,000
~33,000
to
79,000
211,000
to
261,000
142,000
to
202,000
34,000
to
55,000
16,000
to
24,000
- x inn
Annual
cost
5/J/
($/10« B
Impact based
ized upon annuallzed cost
sec % Increase in* % Increase In*
Itu/hr) costs over the costs over the
uncontrolled boiler SIP-controlled boiler
0.0068 -7.9% NA
(2000)
0.0033
(973
0.0042
(1233
- 0.007 -3.9 - 8.4% ~2.1 - 5.3%
- 2093)
- 0.0076 -3.9 - 6.9% NA
- 2233)
0.0064 -5.8% NA
(1867)
0.0038
(1100
0.0036
(1055
0.0032
(947
0.0015
(453
0.0018
(533

- 0.009 -3.5 - 8.1% . -1.8 - 5.5%
- 2633)
- 0.0045 -5.0 - 6.0%
- 1305)
- 0;0046 -4.6 - 6.5%
- 1347)
- 0.0025 -1.8 - 2.9%
- 733)
- 0.0027 -1.7 - 2.5%
- 800)

                  Annuallzed uncontrolled boiler cost + SIP Annualized cost


                 Note:  NA - Not Available

-------
4.2  COSTS TO CONTROL OIL-FIRED BOILERS




     Electrostatic precipitators were cited in Sections 2.0 and 3.0 as being




the best and possibly the only control device that could be used on residual




oil-fired boilers.  (Controls were shown to be unnecessary in the case of dis-




tillate oil for pxoperly operated steam plants.)  Required control efficiencies




for residual oil-fired units were shown in Section 3.0 to range up to 92 per-




cent depending upon the level of emission reduction.  The only equipment manu-




facturer who quoted a price for an ESP (Vendor A)22 quoted an efficiency of




75 percent as indicative of the intermediate level of emission reduction.  The




capital cost for equipment and installation was given as $325,000 and $193,000,




respectively.  The detailed cost estimate shown in Table 56 indicates that




control at this level is not very cost effective due to the relatively low




inlet dust loading.  Electircal consumption for this case is about $3,282 per




year based on 26.4 kW (see Table 62) and 4,818 hours of operation per year




(0.55 load factor).  The cost impact is shown in Table 57.




4.3  COSTS TO CONTROL GAS-FIRED BOILERS




     In Section 2.0 it was noted that particulate controls would be unnecessary




for properly operated gas-fired boilers and therefore no cost analyses have




been performed for these types of units.
                                     187

-------
   TABLE 56a.   CAPITAL COSTS FOR AN  ELECTROSTATIC PRECIPITATOR (AT THE  IN-
               TERMEDIATE LEVEL) INSTALLED ON A RESIDUAL OIL-FIRED BOILER
                            44 MW (150 x  106 Btu/hr)  INPUT
EQUIPMENT COSTS
  Basic equipment
  (includes freight)
  Required auxiliaries   ~
    Subtotal             325,000
INSTALLATION COSTS,
  DIRECT
Foundations
and supports
Ductwork        -
Stack
Piping
Insulation      -
Painting
Electrical
  Subtotal      193,000
TOTAL DIRECT COSTS
  (equipment and installation)
INSTALLATION COSTS, INDIRECT
  Engineering
  Construction and field expense
  Construction fees
  Startup
  Performance test
    Subtotal
  Contingencies
TOTAL TURNKEY COSTS
  Land
  Working Capital
GRAND TOTAL
  $/m3/hr
  ($/acfm)
     3.0% S
     518,000

      51,800
      51»800
      51,800
      10,360
       5,000
     170,760
     137,752
     826,512
        172
       3,504
     830,188
      10.46
     (17.77)
                                     188

-------
  TABLE 56b.   ANNUALIZED COSTS  FOR AN ELECTROSTATIC PRECIPITATOR (AT
              THE INTERMEDIATE  LEVEL) INSTALLED ON A RESIDUAL OIL-
              FIRED BOILER -  44 MW  (150  x  1Q6 Btu/hr) INPUT

                                                       3.0
                                                     percent
                                                        S
DIRECT COSTS
  Direct labor                                         2,027
  Supervision                                            474
  Maintenance labor,
  materials and parts                                  6,500
  Electricity                                          3,282
  Steam
  Cooling water
  Process water
  Fuel
  Waste disposal                                       1,733
  Chemicals
    TOTAL DIRECT  COSTS                                 14,016
OVERHEAD
  Payroll                                                75°
  Plant                                                L690
    TOTAL OVERHEAD                                    2,440
CAPITAL CHARGES
  G&A,  taxes  and  insurance                            33,060
  Capital recovery factor                             97,115
    TOTAL CAPITAL CHARGES                           130,175
TOTAL ANNUALIZED COSTS                               146,631
  $/103 kg  removed                                     3,751
  ($/ton removed)                                     (3,410)
                                    189

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       TABLE  57.   COSTS OF "BEST"  PARTICULATE CONTROL  TECHNIQUE FOR A RESIDUAL OIL-FIRED BOILER
M
VO
O

Standard boiler
Heat Input
MW Type
(106 Btu/hr)
44 Residual
(150) oil
3.0% S
Annualized
System

Type/and
level
of control
ESP/
intermediate
and SIP
C08t ., in

, , . , Annualized
Annualized
Control costs 1°,*,
efficiency ($) (5/106 Btu/hr)
(%)
75 ~ 146, 600 0.0033
(978)
n
Impact based
upon annualized cost
% Increase in % Increase
costs over the costs over
uncontrolled boiler SIP-controlled
-4.5 %


in
the
boiler


Annualized uncontrolled boiler cost

-------
4.4  SUMMARY




     The cost ranges for the purchase, installation, operation and maintenance




of particulate control equipment are summarized in this section.  Where possible,




all cost data have been adjusted to June 1978 dollars.  All costs related to




labor and electricity or other energy costs, as well as percentages assigned to




the annualization of capital costs, have been provided by PEDCo.




     The cost estimates have revealed several important trends in control




equipment costs with respect to coal sulfur content and emission control level.




First of all, the fabric filter is shown to be more cost-effective (annualized




cost divided by weight of pollutant removed per year) than the electrostatic




precipitator at the stringent level when the 0.9 and 0.6 percent sulfur coals




are burned.  (This conclusion is supported by independent data presented in




Figure 26.)  When 3.5 percent sulfur coal is burned, the ESP becomes more cost-




effective except on the smallest (8.8 MW input) of the standard boilers (the




underfeed stoker boiler).




     With respect to emission control levels, the ESP annualized costs are




shown to increase significantly when the control levels become more stringent




as shown in Figures 33 through 36 for the four coal-fired boilers.  (The dif-




ference in scale for the annualized cost for the chain grate and underfeed




stoker units should be noted.)




     The costs presented for particulate emission control are subject to various




inaccuracies resulting from vendor quotes, capitalization and annualization




estimating techniques, and various other assumptions and computations.  Budgetary




prices quoted by vendors are typically ± 10 percent.  For fabric filters and




mechanical collectors, therefore, the costs are accurate to this figure.  For




precipitators and scrubbers, however, -the costs are accurate to ± 20 percent,




due to additional calculations and assumptions.




                                       191

-------
Ki
 v>
 u.
 O
 "o
 •o
1-0
 o
  •»
 CO
 o
 o
 o
 LJ
 Nl
340
320
300
280
260
240
220
200
180
160
140
120
100
   0
               .01
                             EMISSION   CONTROL  LEVEL, ng/J
                               12.9                43            107.5
                                                                         258
                          0.03               0.10            0.25
                        EMISSION CONTROL  LEVEL, Ib/IO6  Btu
0.60
        Figure 33.  Annualized cost of an ESP installed on a pulverized coal boiler (58.6 MW or 200
                  x 106 Btu/hr heat input) as a function of emission control level and coal sulfur
                  content.

-------
vO
         340





         320





         300





         280


      
-------
vo
        200
         180
      2  ieo
      o
      TS

     IO

      S  140
S  120
u



§  100
      z
      z
      <
    80 -
         60 -
         40-
         20 -
           0.01
                                   12.9
                                           EMISSION  CONTROL LEVEL, ng/J

                                                         43
                    1075
                              0.03
0.10
                                                                                   0.25
                                          EMISSION CONTROL LEVEL,  Ib/IO6 Btu
                      Figure 35.
                            Annuallzed cost of an ESP installed on a chain grate stoker

                            boiler  C22 m or 75 x 106 Btu/hr heat input) as a function

                            of  emission control level and coal sulfur content.
258
 0.60

-------
Ul
            120
            110
         52  100
        J3
         o   90
       ro
        O
O
o
o
LL)
N
        ID
        z
        <
80
70
60
50
40
30
20
10
 0
               0.01
                                 EMISSION   CONTROL  LEVEL,ng/J
                               12.9                43             107.5
                        0.03               0.10           0.25
                      EMISSION  CONTROL  LEVEL, Ib/IO6  Btu
                                                                       258
                                                                   0.60
        Figure 36.  Annualized cost of an ESP installed on an underfeed stoker boiler (8.8 MW or 30 x
                  106 Btu/hr heat input) as a function of emission control level and coal sulfur content.

-------
                             4.5  REFERENCES
 1.   Farticulate  and Sulfur Dioxide Emission Control Costs for Large  Coal--
     Fired  Boilers.  PEDCo Environmental, Inc,  EPA-450/3-78-007,  pp.  3-1 to
     3-20.   February 1978.

 2.   Harrison, M.  E.  Economic Evaluation or Precipitators and Baghouse for
     Typical Power Plant Burning Low Sulfur Coal.  Western Precipitation
     Division, Joy Manufacturing Co,  Paper presented at  1978 American  Power
     Conference.

 3.   Farber, P.  S, Capital and Operating Costs of Particulate Control  Equip-
     ment for Coal-Fired Power Plants,  Energy and Environmental Systems
     Division, Argonne  National Laboratory,  Paper presented at the 5th Annual
     National Conference on Energy and  the Environment.   November  1977,

 4.   Cost data supplied by the Electric Power Research  Institute  (EPRI) -
     Personal Communication from Dr. Donald P» Teixeira,  October  1977.

 5.   Harrison, M. E.   op. cit.  April 2, 1977 (earlier  edition of  the paper).

 6.   Cass,  R. W.  and R. M. Bradvay,  Fractional Efficiency of a Utility Boiler
     Baghouse:   Sunbury Steam-Electric  Station*  EPA-600/2-76-077a,   pp. 12-16.
     March  1976,

 7.   Bradway, R.  M, and R. W, Cass,  Fractional Efficiency of a Utility
     Boiler Baghouse:   Nucla Generating Plant,  EPA-600/2-75-013a,  pp. 15-16.
     August 1975.

 8.   Industrial Gas Cleaning Institute  ClGCI),  Particulate Emission  Control
     Costs  for Intermediate-sized Boilers,  EPA Contract  No, 68-02-1473,
     Task No. 18.  pp.  3-1 to 3-10,  February 1977,

 9.   McKenna, J.  D,, et al.  Applying Fabric Filtration to Coal-Fired Indus-
     trial  Boilers.  EPA-650/2-74-058a,  August 1975.   p, 97,

10.   Fraser, M, D. and  G, J. Foley.  Cost Models for Fabric Filter Systems.
     67th Annual  Meeting of the Air Pollution Control Association.  Denver,
     Colorado.  June 9-13, 1974.  p. 12,

11.   IGCI,  op. cit.
                                    196

-------
12.  Personal communication with various equipment manufacturers:
          MikroPul Corp.
          Research-Cottrell
          United McGill Corp.
          Joy Industrial Equipment Co.
          American Air Filter

13.  Bubenick, D. V.  Economic Comparison of Selected Scenarios for Electro-
     static Precipitators and Fabric Filters.  Journal of the Air Pollution
     Control Association.  28(3):279-283.  March 1978.

14.  Personal Communications with three fabric manufacturers:
          Mr. Fred L. Cox - Menardi/Southern Division United States
                            Filter Corp.  7/7/78
          Mr. Glair A. Hoffman - W. W. Criswell, Inc.  7/7/78
          Mr. Ty Headley - Globe Albany Filtration, 7/10/78

15.  Harrison, M. E.  op. cit.  1978.

16.  Card, Inc.  Capital and Operating Costs of Selected Air Pollution Control
     Systems.  EPA-450/3-76-014.  p. 4-89.  May 1976.

17.  Personal Communication with Mr. Larry Gibbs, PEDCo Environmental, Inc.
     December 12, 1978.

18.  Card, Inc.  op. cit.

19.  Reference 12, op. cit.

20.  IGCI, op. cit.

21.  Personal Communication with Mr. H. W. Case - Vendor D.  October 1978.

22.  Reference 12, op. cit.
                                     197

-------
                  5.0  ENERGY IMPACT OF CANDIDATES FOR BEST
                       EMISSION CONTROL SYSTEMS
5.1  INTRODUCTION

      The primary energy impact arising from the installation of particulate

control equipment is the consumption of electrical power to operate the con-

trol device(s).  All systems require a fan sized to overcome the pressure

losses generated by the duct, breechings, stack and, in particular, the fly

ash collector itself.  In the case of an electrostatic precipitator (ESP),

additional energy is required to create the corona discharge and to run auxil-

iary equipment such as electrode rappers and the ash conveying system.

      For fabric filtration (FF) systems, energy is also required to operate

the cleaning equipment (a reverse air fan, a compressor for pulse systems or

a mechanical shaker) as well as the ash conveying system.  A wet scrubber (WS)

requires a liquid pump/slurry handling system and a mechanical collector (MC)

requires an ash removal system over and above the standard gas moving fans.

5.2  ENERGY IMPACT OF CONTROLS FOR COAL-FIRED BOILERS

5.2.1  New Facilities

      Energy consumption for the various candidate control systems is indi-

 cated in this section.  Fan and pump power requirements, Table 58, show the

 energy usage for all control systems that might conceivably achieve the re-

 quired efficiency level given previously in Table 31.  Pump requirements are

 calculated for scrubber systems only.  Various pressure drops are assumed for

 wet scrubbers depending upon uncontrolled fly ash loadings and size properties.


                                     196

-------
TABLE 58.  FAN AND PUMP POWER REQUIREMENTS OF PARTICIPATE
           CONTROLS FOR COAL-FIRED BOILERS

Boiler type ,
heat input and fuel
A. Pulverized coal
58.6 MW
(200 x 106 Btu/hr)
3.5% S
3.5% S
0.9% S
0.9% S
0.6% S
0.6% S
0.6% S
0.6% S
B. Spreader stoker
44.0 MW
(150 x 106 Btu/hr)
3.5% S
3.5% S
3.5% S
3.5% S
3,5% S
0.9% S
0.9% S
0.9% S
0.9% S
0.6% S
0.6% S
0.6% S
0.6% S
0.6% S
C. Chain grate stoker
22.0 MW
(75 x 106 Btu/hr)
3.5% S
3.5% S
3.5% S
3.5% S
3.5% S
*
Flow rate
Q
(acfm)


74,800
74,800
105,500
70,600
109,800
73,200
73,200
73,200



64,800
64,800
64 , 800
64,800
64,800
91,200
60,800
60,800
60,800
94,200
62,800
62,800
62,800
62,800



32,300
32,300
32,300
32,300
32,300
AP*
inches
W.C.


0
6
0
6
0
6
15
20



0
6
5
10
15
0
6
5
10
0
6
5
10
15



0
6
5
10
15


.5
.0
.5
.0
.5
.0
.0
.0



.5
.0
.0
.0
.0
.5
.0
.0
.0
.5
.0
.0
.0
.0



.5
.0
.0
.0
.0
Energy requirements?
Control
device


Cold ESP
FF
Hot ESP
FF
Hot ESP
FF
WS
WS



Cold ESP
FF
WS
WS
WS
Hot ESP
FF
WS
WS
Hot ESP
FF
WS
WS
WS



Cold ESP
FF
WS
WS
WS
Fan
hp


10
128
15
121
15
125
351
417



9
110
92
185
277
13
104
86
173
13
107
89
179
269



4
55
46
92
138



.6



.6






.2
.8
.3




.6

.4
.4
.5





.6
.2



kW


7
95
11
90
11
93
262
311



6
82
68
138
207
9
77
64
129
10
80
66
133
200



3
41
34
68
102



.9
.4
.2
.2
.6
.2





.9
.6
.8


.7
.6
.6

.0
.1
.7
.5
.6



.4
.2
.3
.6
.9
hp


—
-
-
-
-
-
36.
36.



—
-
32.
32.
32.
-
-
30.
30.
-
-
31.
31.
31.



-
-
16.
16.
16.
Pump









6
6





4
4
4


4
4


4
4
4





2
2
2
kW


-
-
-
-
-
-
27.3
27.3



—
-
24.2
24.2
24.2
-
-
22.7
22.7
-
-
23.4
23.4
23.4



-
'
12.1
12.1
12.1

                       (continued)
                           199

-------
TABLE 58 (continued)

Boiler type,
heat input and fuel
A
Flow rate
Q
(acfm)
Energy requirement ST
inches
W.C.
Control
device
Fan
hp
kW

Pump
hp
kW
Chain grate stoker
(continued)
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
i).
0.
9%
9%
9%
9%
9%
9%
6%
6%
6%
6%
6%
6%
S
S
S
S
S
S
S
S
S
S
S
S
45,150
30,100
30,100
30,100
30,100
30,100
47,100
31,400
31,400
31,400
31,400
31,400
0
6
5
10
15
4
0
6
5
10
15
4
.5
.0
.0
.0
.0
.0
.5
.0
.0
.0
.0
.0
Hot ESP
FF
WS
WS
WS
MC
Hot ESP
FF
WS
WS
WS
MC
6.4
51.5
43
86
129
34.3
6.7
53.7
45
89.5
134.2
35.8
4.
38.
32
64
96
25.
5.
40.
33.
66.
100.
26.
8
4



6
0
0
5
7
1
7
-
-
15
15
15
-
-
-
15.7
15.7
15.7
—
-
-
11.2
11.2
11.2
-
-
-
11.7
11.7
11.7
—
D. Underfeed stoker
8.8
(30
3.
3.
3.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
MW
X
5%
5%
5%
9%
9%
9%
9%
6%
6%
6%
6%
6%
6%

106 Btu/hr)
S
S
S
S
S
S
S
S
S
S
S
S
S


12,900
12,900
12,900
18,300
12,200
12,200
12,200
18,750
12,500
12,500
12,500
12,500
12,500


0
6
20
0
6
10
15
0
6
5
10
15
4


.5
.0
.0
.5
.0
.0
.0
.5
.0
.0
.0
.0
.0


Cold ESP
.FF
WS
Hot ESP
FF
WS
WS
Hot ESP
FF
WS
WS
WS
MC


1.8
22
73.5
2.6
20.9
34.8
52.2
2.7
21.4
17.8
35.6
53.4
14.3


1.
16.
54.
1.
15.
26
38.
2.
16.
13.
26.
39.
10.


3
4
8
9
6

9
0
0
3
6
8
7


-
-
6.45
-
—
6.1
6.1
-
-
6.3
6.3
6.3
—


-
-
4.8
-
-
4.5
4.5
-
-
4.7
4.7
4.7
—

      (continued)
          200

-------
                            TABLE 58 (continued)
Boiler type,
heat input and fuel
Flow rate
Q
(acfm)
A P t
inches ,
w.c. devlce
Energy requirementsT
Fan Pump
hp kW hp kW
E.  Pulverized coal
    117.2 MW
    (400 x 106 Btu/hr)
3.
3.
2.
2.
0.
0.
0.
0.
0.
0.
5%
5%
3%
3%
9%
9%
6%
6%
6%
6%
S
S
S
S
S
S
S
S
S
S
149,639
149,639
151,153
151,153
211,418
141,528
218,024
145,950
145,950
145,950
0.
6.
0.
6.
0.
6.
0.
6.
15.
20.
5
0
5
0
5
0
5
0
0
0
Cold ESP
FF
Cold ESP
FF
Hot ESP
FF
Hot ESP
FF
WS
ws
21.
256
21.
258
30.
242
31.
250
624
832
3

5

1

1



15.9
191
16
192
22.4
180
23.2
186
465
620
-
-
-
—
-
-
-
-
73
73
-
—
—
—
-
-
-
—
54.4
54.4
 To convert acfm to m3/hr, multiply by 1.699

^To convert inches W.C. to kPa, multiply by 0.2488

"("Any energy requirements supplied by the boiler would have to be multiplied by
 -3.0 because of boiler/turbine efficiency.
                                       201

-------
      The fan power requirements are estimated from the following equation
                                                                           .1
                            P = 2.85 x icr1* Q.J. AP                        (1)

where   P = power consumed, hp
       Q  = gas flow, acfm
       AP = pressure drop, inches water column
      This equation is based on an assumed combined efficiency of 55 percent
for fan and motor.
      The  liquid pump requirements for a scrubber system are  based  upon a
power parameter of  17.6 hp/1000 m3/min (0.5 hp/1000 acfm).2   The  flow  rate,
pressure drop, and  collector type are given in Table  58 for each  of the
coal-fired boiler systems.   A cold electrostatic precipitator has been selected
for the 3.5 and  2.3 percent sulfur coals.  In the case  of low-sulfur coals
 (0.9 percent and 0.6 percent)  hot-side precipitation  was selected such that
the gas flow volumes were appreciably increased. It  is realized  that  this
type of approach is rather simplified and  certainly some vendors  would specify
cold-side  ESPs for  any  coal type.  However,  the  lack  of a detailed  coal analy-
sis has prevented any other type of  design consideration.
      Table 59 lists the various  design parameters for electrostatic precip-
itators that relate to  the coal-fired boiler  systems  of interest.  For the
current analysis, two basic equations were used:3
                               W, = W In I ^ ]                               (2)
and
                                           771                              (3)
 where   A = plate  area
         V = gas  flow
         Q = fractional penetration
        W,  = modified precipitation rate parameter
         W = migration velocity or precipitation rate
                                     202

-------
                      TABLE 59.  DESIGN PARAMETERS AND ENERGY CONSUMPTION OF ELECTROSTATIC
                                 PRECIPITATORS ON COAL-FIRED BOILERS
10
O
Boiler type,
heat input and fuel
Pulverized coal
58.6 MW
(200 x io6 Btu/hr)
3.5% S




0.9% S




0.6% S




Spreader stoker
44.0 MW
(150 x IO6 Btu/hr)
3.5% S




0.9% S




0.6% S




Type and
level of
control



Cold ESP
SIP
Moderate
Intermediate
Stringent
Hot ESP
SIP
Moderate
Intermediate
Stringent
Hot ESP
SIP
Moderate
Intermediate
Stringent



Cold ESP
SIP
Moderate
Intermediate
Stringent
Hot ESP
SIP
Moderate
Intermediate
Stringent
Hot ESP
SIP
Moderate
Intermediate
Stringent
Control
efficiency
(percent)




91.64
96.52
98.61
99.58

85.00
93.75
97.50
99.25

86.67
94.44
97.78
99.33




89.73
95.72
98.29
99.49

81.54
92.31
96.92
99.08

83.61
93.17
97.27
99.18
Precipitation
rate, Wk *
(fpm)




89
121
154
197

28
42
55
73

25
36
48
63




82
113
146
190

25
38
52
70

23
34
45
61
SCAf

-------
                                                                      TABLE  59   (continued)
to
O
Boiler type, Type and
heat Input and fuel level °f
control
Chain grate stoker
22.0 MW
(75 « 10b Btu/hr)
3.5* S Cold ESP
SIP
Moderate
Intermediate
Stringent
0.9X S Hot ESP
SIP
Moderate
Int ^rmedlate
Stringent
0.6* S Hot ESP
SIP
Moderate
Intermediate
Stringent
Underfeed stoker
8.8 MW
(30 » 106 Btu/hr)
3.5X S Cold ESP
SIP
Moderate
Intermediate
Stringent
0.9* S Hot ESP
SIP
Moderate
Intermediate
Stringent
0.6% S Hot ESP
SIP
Moderate
Intermediate
Stringent
Control
efficiency
(percent)




73.33
88.89
95.56
98.67

52.00
80.00
92.00
97.60

57. 45
82.27
92.91
97.87




73.21
88.84
95.54
98.66

52.00
80,00
92.00
97.60

57.14
82.14
92.66
97.86
Precipitation
rate, Wk *
(fptn)




48
79
112
156

11
24
38
56

11
22
33
48




47
79
112
155

11
24
38
56

11
22
33
48
SCAf

-------
                                                              TABLE 59  (continued)
to
CD

Boiler type,
heat input and fuel
Pulverized coal
117.2 MW
(400 x 106 Btu/hr)
3.5% S




2.3% S




0.9% S




0.6% S




Type and
level of
control



Cold ESP
SIP
Moderate
Intermediate
Stringent
Cold ESP
SIP
Moderate
Intermediate
Stringent
Hot ESP
SIP
Moderate
Intermediate
Stringent
Hot ESP
SIP
Moderate
Intermediate
Stringent
Control
efficiency
(percent)




91.64
96.52
98.61
99.58

92. 49
96.8?
98.75
99.62

85.00
93.75
97.50
99^25

86.67
94.44
97.78
99.33
Precipitation
rate, Wk
(fpm)




89
121
154
197

62
83
105
134

28
42
55
73

25
36
48
63
SCA1"
(ft2/103 acfm)




69
93
119
152

108
145
183
232

126
185
246
326

160
229
302
397
Plate*
area
(ft2)




10,325
13,916
17,807
22,745

16,325
21,917
27,661
35,067

26,639
39,112
52,009
68,922

34,884
49,927
65,843
86,556
Power consumption
To energize
Corona (kW)




15.5
20.9
26.7
34.1

24.5
32.9
41.5
52.6

50.6
74.3
98.8
131.0

66.3
94.9
125.1
164.5
Auxiliary
(kW)




6.0
8.3
11.0
14.4

10.0
13.8
17.9
23.3

17.2
26.3
36.1
49.3

23.1
34.5
46.9
63.5

                        To convert  from  fpm to cm/sec,  multiply by 0.508


                        To convert  from  ft2/103 acfm to m2/acm/min, multiply by 3.28


                       TTo convert  ft2 to m2, multiply  by  0.0929


                        Any energy  requirements supplied by  the boiler would have  to be multiplied by -3.0 because of boiler/turbine
                        efficiency.

-------
     Values of W were obtained from the Electrostatic Precipitator Manual,4
in which W values are specified as a function of coal sulfur content as shown
below:
                  W = 18.3 cm/sec (0.6  ft/sec) at 3.5% S
                  W m 12.2 cm/sec (0.4 ft/sec) at 2.3% S
                  W = 7.6 cm/sec (0.25 ft/sec) at 0.9% S
                  W m 6.4 cm/sec (0.21 ft/sec) at 0.6% S
     Using these velocities, W^ is calculated followed by the computation
of plate area based upon the desired fractional penetration.  The efficiency
values are obtained from Table 31 and, in the case of the SIP (State Implemen-
tation Plan) control level, the efficiency is calculated using the average
uncontrolled emission level for the given boiler and the average SIP require-
ment of 258 ng/J (0.6 lb/106 Btu) for coal-fired boilers.
     Once the appropriate ESP design parameters are established, the power
consumption to energize the corona and to operate auxiliary equipment (e.g.,
electrode rappers and ash handling equipment) is calculated by means of the
following two equations:
     Energizing Power;5
                               P = A D x 1(T3                            (4)
where  P = power consumption, kW
       A = plate area, m2 (ft2)
       D = input power density:
                 Cold ESP =16.15 watts/m2 (1.5 watts/ft2)
                  Hot ESP = 20.45 watts/m2 (1.9 watts/ft2)
     Auxiliary Power;^
                           P - 2.1 x IQ-1* (A)1-11                        (5)
where  P = power consumption, kW
       A = plate area, m2 (ft2)
                                     206

-------
      For particulate control by electrostatic precipitators, the total energy




usage is the sum of the fan, corona, and auxiliary power requirements.  In the




case of scrubbers, total energy consumption is defined by fan and pump require-




ments only.  Energy usage by fabric filters is given as a function of air flow




requirements only.  Reverse air fan or compressor power requirements for




cleaning are not included since many types of systems are available and all




vary in their design and operation.  The pressure drop utilized for baghouse




computations is 1.5 kPa (6.0 inches W.C.) which may be excessive for normally




operated baghouse units.  It is believed, therefore, that this excess pressure




loss will take into account cleaning energy requirements.  Multitube cyclone




energy consumption is based solely on a- 1.0 kPa (4.0 inches W.C.) pressure




loss.




      The final tabulation of electrical energy consumption is presented in




Table  60.   Energy consumption is  given  in kW for  each  control  device  at  the




specified levels of control.  These values are then expressed as a percentage




of boiler heat input — to give the percent increase in energy consumption




over the uncontrolled boiler case — and as a percentage of boiler heat input




plus the SIP energy requirement — to give the percent increase in energy




consumption over that required at the SIP level of control.  (See the footnote



at the bottom of Table 60.)




     Table  60 shows several important trends in control device energy usage.




For example, the increase in electrical requirements for an ESP on a pulverized




coal boiler (58.6 MW input) burning 0.6 percent sulfur coal from the SIP level




to the stringent level is significant.  The required efficiency increases from




86.67 to 99.33 percent (a 15 percent increase), whereas the energy consumed
                                     207

-------
                        TABLE 60.  ELECTRICAL ENERGY CONSUMPTION FOR PARTICULATE CONTROL
                                   TECHNIQUES FOR COAL-FIRED BOILERS
CO
System
Standard boiler _
Type and
Heat input , level of
HW (10* Btu/hr) ^P" contro1
58.6 (200) Pulverized
3.5X S SIP
10.6? A Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
ESP
0.9X S SIP
6.9% A Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
ESP
0.6% S SIP
5.4X k Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
US
SIP
Moderate
Electrical energy consumption
Control
efficiency
(percent)
91.64
96.52
98.61
99.58

91.64
96.52
98.61
99.58

85.00
93.75
97.50
99.25

85.00
93.75
97.50
99.25

86.67
94.44
97.78
99.33

86.67
94.44
97.78
99.33

86.67
94.44
Energy consumed
by
control device
(MO
18.4
22.2
26.4
31.7

95.4
95.4
95.4
95.4

44.4
60.5
77.2
99.3

90.2
90.2
90.2
90.2

55. B
75.5
96.5
124.0

93.2
93.2
93.2
93.2

289
338
% Increase in
energy use
over uncontrolled
boiler *
0.031
0.038
0.044
0.055

0.164
0.164
0.164
0.164

0.075
0.102
0.133
0.171

0.154
0.154
0.154
0.154

0.096
0.130
.0.165
0.212

0.160
0.160
0.160
0.160

0.495
0.577
% Change in
energy use over
SIP controlled
boiler +
0
+ 0.006
+ 0.014
+ 0.023

0
0
0
0

0
+ 0.027
+ 0.056
4 0.094

0
0
0
0

0
4 0.034
•f 0.069
+ 0.116

0
0
0
0

0
•f 0.083
                                                    (continued)

-------
                                                   TABLE 60  (continued)
S3
o
VO
System
Standard boiler Type and
MW He!UTu/nr, *- ^»;f
44.0 (150) Spreader
3.5% S SIP
10.6% A Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
ws
SIP
Moderate
Intermediate
ESP
0.9% S SIP
6.9% A Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
MS
SIP
Moderate
Intermediate
ESP
0.6% S SIP
5.4% A Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
WS
SIP
Moderate
Intermediate

Control
efficiency
(percent)

89.73
95.72
98.29
99.49

89.73
95.72
98.29
99.49

89.73
95.72
98.29

81.54
92.31
96.92
99.08

81.54
92.31
96.92
99.08

81.54
92.31
96.92

83.61
93.17
97.27
99.18

83.61
93.17
97.27
99.18

83.61
93.17
97.27
Electrical
Energy consumed X
by
control device over
(kW)

15.1
18.6
22.0
26.7

82,6
82.6
82.6
82.6

93.0
162.2
231.2

35.3
48.8
63.2
82.4

77.6
77.6
77.6
77.6

87.3
151.7
151.7

43.9
60,6
78.6
102.1

80.1
80.1
80.1
80.1

90.1
156.9
224.0
energy consumption
Increase In
energy use
uncontrolled
boiler *

0.034
0.041
0.051
0.061

0.188
0.188
0.188
0.188

0.211
0.368
0.525

0.082
0.113
0.143
0.187

0.177
0.177
0.177
0.177

0.198
0.344
0.344

0.099
0,136
0.177
0.232

0.181
0.181
0.181
0.181

0.205
0.358
0.508
X Change in
energy use over
SIP controlled
boiler +

0
+ 0.008
+ 0.016
+ 0.026

0
0
0
0

0
+ 0.157
+ 0.313

0
+ 0.031
+ 0.063
+ 0.107

0
0
0
0

0
+ 0.146
+ O.U6

0
+ 0.038
+ 0.079
+ 0.132

0
0
0
0

0
+ 0.152
+ 0.304
                                                          (continued)

-------
TABLE 60  (continued)
System
Standard boiler Tvoe and
MW ""iontu/hr) *- """"I*
22.0 (75) Chain grate
3.55! S SIP
10. 6Z A Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
ws
SIP
Moderate
Intermediate
Stringent
ESP
0.9Z S SIP
6.9% A Moderate
Intermediate
Stringent
&L
SIP
Moderate
Intermediate
Stringent
WS
SIP
Moderate
Intermediate
Stringent
MC
SIP
Moderate

Control
efficiency
(percent)
73.33
88.89
95.56
98.67

73.33
88.89
95.56
98.67

73.33
88.89
95.56
98.67

52.00
80.00
92.00
97.60

52.00
80.00
92.00
97.60

52.00
80.00
92.00
97.60

52.00
80.00
Electrical
Energy consumed X
by
control device over
(kW)
5.7
7.3
9.0
11.2

41.2
41.2
41.2
41.2

46.4
80.7
115.0
115.0

10.1
16.6
23.5
32.8

38.4
38.4
38.4
38.4

43.2
43.2
75.2
107.2

25.6
25.6
energy consumption
Increase In
energy use
uncontrolled
boiler *
0.027
0.034
0.041
0.051

0.188
0.188
0.188
0.188

0.211
0.368
0.522
0.522

0.044
0.075
0.106
0.150

0.174
0,174
0.174
0.174

0.198
0.198
0.341
0.488

0.116
0.116
% Change in
energy use over
SIP controlled
boiler t
0
+ 0.007
+ 0.015
+• 0.025

0
0
0
p

0
4- 0.156
+ 0.311
+• 0.311

0
+ 0.030
+ 0.061
+ 0.103

.0
0
0
0

0
0
+ 0.145
+ 0.290

0
0
        (continued)

-------
TABLE 60  (continued)
System
Standard boiler _ .
Type and
MW "^ofCU, *»' Z££
Chain grate stoker (continued)
ESP
0.6X S SIP
5.41 A Moderate
Intermediate
Stringent
TF
SIP
Moderate
Intermediate
Stringent
MS
SIP
Moderate
Intermediate
Stringent
HC
SIP
Moderate
D. 8.8 (30) Underfee-
3.5Z S SIP
10. 6X A Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
WS
SIP
Moderate

Control
efficiency
(percent )


57.45
82.27
92.91
97.87

57.45
82.27
92.91
97.87

57.45
82.27
92.91
97.87

57.45
82.27
73.21
88.84
95.54
98.66

73.21
88.84
95.54
98.66

73.21
88.84
Electrical
Energy constated I
by
control device over
(kW)


12.7
20.9
29.5
40.9

40.0
40.0
40.0
40.0

45.2
45.2
78.4
111.8

26.7
26.7
2.2
2.8
3.5
4.3

16.4
16.4
16.4
16.4

59.6
59.6
energy consumption
Increase in
energy use
uncontrolled
boiler *


0.058
0.095
0.133
0.188

0.181
0.181
0.181
0.181

0.205
0.205
0.35B
0.508

0.121
0.121
0.024
0.031
0.041
0.048

0.188
0.188
0.188
0.188

0.678
0.678
X Change in
energy uae over
SIP controlled
boiler t


0
+ 0.037
+ 0.076
+ 0.128

0
0
0
0

0
0
•t- 0.151
+ 0.302

0
0
0
+ 0.007
+ 0.015
+ 0.024

0
0
0
0

0
0
         (continued)

-------
                                                    TABLE 60  (continued)
S3
M
NJ
System
Standard boiler Type and
level of
MW "lUTu/Hr) ^
Underfeed stoker (continued)
ESP
0.9X S SIP
6,9* A Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
WS
SIP
Moderate
Intermediate
MC
SIP
Moderate
ESP
0.6X S SIP
5.4X A Moderate
Intermediate
Stringent '
FF
SIP
Moderate
Intermediate
Stringent
WS
SIP
Moderate
Intermediate
Stringent
MC
SIP
Moderate
Intermediate

Control
efficiency
(percent)


52.00
80.00
92.00
97.60

52.00
SO. 00
92.00
97.60

52.00
80.00
92.00

52,00
92.00

57.14
82. 14
92.86
97.86

57. 14
82.14
92.86
97.86

57.14
82.14
92.86
97.86

57.14
82.14
92.86
Electrical
energy consumption
Energy consumed X Increase in
by energy use
control device over uncontrolled
(kW) boiler *


4.0
6.5
9.3
13.0

15.6
15.6
15.6
15.6

30.5
30.5
43.4

10.4
10.4

5.0
8.2
11.4
16.0

16.0
16.0
16.0
16.0

18.0
31.3
31.3
44.5

10.7
10.7
10.7


0.044
0.075
0.106
0.147

0.177
0.177
0.177
0.177

0.348
0.348
0.494

0.118
0.118

0.058
0.092
0.130
0.181

0.181
0.181
0.181
0.181

0.205
0.355
0.355
0.505

0.122
0.122
0.122
X Change in
energy use over
SIP controlled
boiler f


0
+ 0.028
+ 0.060
+ 0.102

0
0
0
0

0
0
+ 0.146

0
0

0
+ 0.036
+ 0.073
+ 0.125

0
0
0
0

0
+ 0.151
+ 0.151
+ 0.301

0
0
0
                                                                (continued;

-------
TABLE 60  (continued)
Syiten
St.nd.rd boiler Tyw and
HU "-Wlu/HO *»• ^
117.2 (ADO) Pulverised
3. 51 S SIP
10. « A Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
ESP
2.3* S SIP
13. 2X A Moderate
Intermediate
Stringent
FF
SIP
Moderate
Interned late
Stringent
ESP
0.9Z S SIP
6.9Z A Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
Electrical energy
Control
efficient;
(percent)

91.64
96.52
98.61
99.58

91.64
96.52
98.61
99.58

92.49
96.67
98.75
99.62

92.49
96.87
98.75
99.62

85.00
93.75
97.50
99.25

85.00
93.75
97.50
99.25
Energy consumed
by
control device

-------
                          TABLE 60  (continued)
System
Standard boiler
Heat Input -
MW (106 Btu/hr) lype
Pulverized coal (continued)

0.62 S
5.M A










A
energy consumed
heat input 1UU
enerRy consumed - SIP energy

Type and
level of
control

ESP
SIP
Moderate
Intermediate
Stringent
FF
SIP
Moderate
Intermediate
Stringent
WS
SIP
Moderate





Control
efficiency
(percent)


86.67
94.44
97.78
99.33

86.67
94.44
97.78
99.33

86.67
94.44




Electrical
Energy consumed X
by
control device over
(kW)


112.6
152.6
195.2
251.2

186.0
186.0
186.0
186.0

519.4
674.4




energy consumption

Increase in % Change in
energy use energy use over
uncontrolled SIP controlled
boiler* boiler1'


0.096
0.130
0.167
0.214

0.159
0.159
0.159
0.159

0.443
0.575






0
-M).034
+0.070
+0.118

0
0
0
0

0
+0.132




heat input + SIP energy

-------
increases from 55.8 to 124.0 kW (a 122 percent increase).  A comparison of




these increases indicates that it costs progressively more per unit of




recovered dust as the efficiency requirement is increased.  However, viewing




these numbers from the perspective of the impact on effluent concentration,




it is seen that the emissions are reduced about 20 times for less than a 2.5




times increase in energy requirement.




     The increase in electricity demand is also borne out by the power con-




sumption statistics for the ESP on the bases of coal sulfur content.  For the




same pulverized coal' boiler at the stringent level of control, power require-




ments increase from 31.7 kW to 124.0 kW as sulfur content decreases from 3.5




to 0.6 percent to meet a similar overall efficiency requirement.  It should




also be noted that the baghouse becomes less energy intensive than the ESP at




the stringnet control level for both pulverized and spreader stoker boilers




burning 0.6 and 0.9 percent sulfur coal.




     The significantly higher energy consumption for a wet scrubber is also




shown in Table 60.



      Taking all levels of control into consideration for  all standard boilers,




the precipitator is the least energy intensive CO,024 to 0,23 percent increase




over  uncontrolled)  followed by  the multitube  cyclone  (0.116  to  0.122 percent




increase),  fabric  filter  (0.16  to 0.19  percent increase),  and the wet scrubber




 (0.2  to  0.7 percent increase  over uncontrolled boilers).   (It should be  noted




 that  the absolute  electrical  consumption  figures are  more important than the




 preceeding percentages when evaluating control system costs.)




      The following is an example of the  calculation  of power requirements




 for an ESP controlling particulate  emissions  at the stringent level from a




 spreader stoker boiler burning  0.6  percent sulfur coal:





                                     215

-------
Example calculation;

(1)  Fan power requirements:

                     P = 2.85 x ICT4 Q  AP

     (a)  The air flow for the spreader stoker boiler is given as
          1,778 acm/min (62,800 acfm) at 177°C (350°F) when burn-
          ing 0.6 percent sulfur coal.  Because of the lowered
          resistivity, a precipitator would be best placed up-
          stream of the air heater where the temperatures average
          about 400°C (750°F) .  Consequently, the resulting flue
          gas flow rate will increase; i.e.,
,1  -,-,*    i  *  ^   273
(1,778 acm/min)
                                   .1°C + 400°C\
                                   .^ + 177ocJ
               = 2,667 acm/min or 94,200 acfm

     (b)  A typical flange-to-flange pressure drop through an
          ESP is about 0.12 kPa (0.5 inches W.C.).  Therefore,
          the power needed to meet the gas moving requirement
          as computed from Equation (1) becomes:
           P = (2.85 x 10-^(9.42 x lo1*) 0.5 = 13.4 hp

          or by converting to kW

              P = (13.4 hp)(0.7457 kW/hp) = 10.0 kW

(2)  Power for energizing corona:

     (a)  At 0.6 percent S coal, W = 6.4 cm/sec (0.21 ft/sec)
          - 384 cm/min (12.6 ft/min)

     (b)  wk = w ii

     (c)  Required efficiency at the stringent level of control
          from Table 3-4 is 99.18 percent.  Therefore Q,
          penetration, = 0.0082

     (d)  Wfc = 384 In (1/0.0082) = 1,845 cm/min

                           or

          Wfc = 12.6 In (1/0.0082) - 61 ft/min
                               216

-------
                A    1 . 2
                v = IT ln
                  = 0.381 = 381 ft2/1000 acfm
                                  -f«-2
           (f)  Plate area -      ™   x 94,200 acfm
                           = 35,890 ft2 (3,334 m2)

           (g)  By means of Equation 4 and assuming a power density,
                D, of 1.9 watts/ft2 for a hot-side precipitator ,
                the corona energizing power is calculated as follows:

                P = A D x io-3 = (35, 890) (1.9) CIO'3) = 68.2 kW

      (3)  Auxiliary power:

                      P - 2.1 x HT1* (A)1'11                     (Equation 5)

                      P = 2.1 x 10-" (35,890 ft2)1'11

                      P = 23.9 kW

      (4)  Total power consumption = fan + corona + auxiliary

           Total Power = 10 kW + 68.2 kW + 23.9 kW
                           Total power = 102 kW
      In the above case, the energizing power is roughly the equivalent of an

additional 0.9 kPa (3.5 inch W.C.) pressure loss across the ESP.  It should also

be noted that the 102 kW required by the ESP at the stringent level of control

for the boiler/fuel combination cited in the illustration exceeds that required

by a baghouse by about 27.5 percent.  This effect is shown in Figure 37.

     The dependence of ESP energy usage upon coal sulfur content is shown in

Figures 38 through ^1 for four coal-fired standard boilers.  The

difference in scale (kW — x-axis) for the chain grate and underfeed stoker

boilers should be noted.

                                     217

-------
     i.o
     0.6
    0.25
 OD
CD
 O
 \
 £   0.1
 CD
 CD
 co
 UJ
    0.03
    0.01
                                        WS
               50     100     150    200    250     300
                  ELECTRICAL  CONSUMPTION, kW
258
07.5
43
     o»
     c
     CO
                                                                   CD
                                                                   CO
    LJ
                                                               21.5
12.9
       Figure 37.  Electrical consumption of control equipment on the
                 spreader stoker boiler burning 0.6 percent sulfur coal.
                                   218

-------
  1.0
  0.6
 0.25
   0.
M

O
M
CO
2
UJ
  0.03
  0.0
              25
                         0.6% S
                               0,9%S
50       75        100        125

   ELECTRICAL CONSUMPTION, Kw
                                                                         256
                                                                         IOT5
                                                                          43
                                                    co
                                                    m
                                                    hi
                                                                          21.5
                                                                          12.9
ISO
  Figure 38.  Electrical  consumption  of an electrostatic precipitator
               on the pulverized coal  boiler burning three  coals.
                                      219

-------
 1.0
 0.6
029
 0.1
0.09
0.01
        1
               •3.5%S
                        0.9% S
                                            0.6% S
                      50
75
KX>
125
                         ELECTRICAL CONSUMPTION.Kw
                                                            ISO
                                        256
                                                                        107.5
                                                                        43
                                                                           m
                                                                           m
                                                                        21.9
                                        12.9
Figure 39.  Electrical consumption of  an electrostatic precipitator

             on the spreader stoker boiler burning three coals.
                                   220

-------
  i.O
   0.6
  0.25

2 Ul 0.03 0.0 0.6 %S 20 40 ELECTRICAL CONSUMPTION, Kw 60 258 1075 "I 1 V) w Ul 21.5 12.9 Figure 40. Electrical consumption of an electrostatic precipitator on the chain grate stoker boiler burning three coals. 221


-------
  l.O
  029
£


"o
m

O

m
m


u
   O.I
  0.03
0.6 %S
  0.0
                        I
                                                                        298
                                                                         107.9
                                                                         43
                                        o>
                                        m
                                       u
                                                                         21.5
                                                                         12.9
                        10                 20

                           ELECTRICAL CONSUMPTION, Kw
                          30
   Figure 41.  Electrical consumption of an electrostatic precipitator

               on the underfeed  stoker boiler burning three coals.
                                     222

-------
     Minimization of electrical energy consumption by particulate control
equipment is important to the boiler operator and cannot be overemphasized.
Sound operating procedures such as the monitoring of boiler parameters are
normal practice and result in efficient overall plant operation.  Parameters
such as air and water temperature, air-to-fuel ratio, fuel feed rate, oxygen
in the flue gas, and steam or kW production should be monitored closely to
enable the boiler load to be accurately and efficiently increased or decreased.
Maintenance of the boiler/turbine system as well as the particulate control
device is essential to efficient operation and minimal energy consumption.
Consistent and frequent boiler maintenance results in efficient fuel consumption
while control equipment maintenance will ensure equipment longevity and will
prevent excessive energy usage and correspondingly high operating costs.
     Where it is allowed by local authorities, fuel switching offers one
means of energy and fuel savings in that switching from coal to oil would
likely mean bypassing the control equipment.  This procedure would be em-
ployed during episode or stagnation periods and, therefore, energy savings
would probably be small.  The problem with fuel switching is that the additional
equipment required for the switch may offset the potential energy savings that
would be incurred when bypassing the particulate control equipment.
5.2.2  Modified and Reconstructed Facilities
     It is most difficult to attempt to quantify the factors that would
affect energy consumption at modified facilities.  Electrical energy usage by
the control devices mentioned previously would be the same unless installation
problems resulted in greater pressure losses through frequently contorted
connecting ductwork found in retrofit systems.  Generally, the basic difference
between a new and a retrofit installation will be reflected in the cost of the
installation and not the energy consumption of the particulate control device.
                                      223

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5.3  ENERGY IMPACT OF CONTROLS FOR OIL-FIRED BOILERS

     As can be noted in Table 31,  the best system of control for the residual

oil-fired boiler is an electrostatic precipitator for reasons mentioned in.

Section 2.0.  For the purposes of  this section, the maximum efficiencies listed

in Tabel 31 are utilized in calculating power requirements.

     Although there are limited data available concerning the sizing^of ESP's

for oil-fired boilers, the same procedures used for coal are employed with

one exception.  Whereas the power  density used for the coal-fired case is

16.15 to 20.45 watts/m2 (1.5 to 1.9 watts/ft2), the power input, as deter-

mined from the Electrostatic Precipitator Manual,7 is about 11.8 watts/m2

(1.1 watts/ft2) for the oil-fired  system.  The size of the precipitators re-

quired for the three levels of control (the SIP level and the intermediate

level are the same) is very small  and thus the power requirements which are

shown in Table 61 are minor.

     The fan electrical requirement is 6.6 hp (5.0 kW) as determined by

Equation (1).  The total energy requirements given in Table 62 are illustrated

in Figure 42.  The three levels of emission control show increases of less

than 0.1 percent over uncontrolled boilers.

     Factors relating to energy savings, retrofit installations and mainte-

nance practices that were mentioned previously for coal-fired boilers also

apply for the oil-fired boilers.

     As will be noted from Table 31, distillate oil-fired boilers would not

require control equipment if properly operated and maintained.

5.4  ENERGY IMPACT OF CONTROLS FOR GAS-FIRED BOILERS

     Because of the minimal uncontrolled emission values for gas-fired units,

particulate control would not be required and there would therefore be no

additional energy consumption.
                                      224

-------
       TABLE 61.  DESIGN PARAMETERS AND ENERGY CONSUMPTION OF AN ELECTROSTATIC PRECIPITATOR
                  ON THE RESIDUAL OIL-FIRED BOILER

• . , . Type and
Boiler type, level of
heat input and fuel control
Residual oil
44 MW
(150 10 Btu/hr)
3.0% S Moderate
Intermediate
ro ,
N) and
01 SIP
Stringent
Control ^
efficiency /. <.
(percent) (fpm)



30.5 5.134
75.0 5.134
91.7 5.134
SCAf
(ft2/103 acfm)



71
270
485
Plate'!1
area
(ft2)



3,316
12,609
22,650
Power consumption
To energize
Corona (kW)



3.6
13.9
24.9
Auxiliary
(kW)



1.7
7.5
14.3
x
*To convert from fpm to cm/sec, multiply by 0.508
 To convert from ft2/103 acfm to m2/acmm, multiply by 3.28
TTo convert from ft2 to m2, multiply by 0.0929

-------
TABLE 62.  ELECTRICAL ENERGY CONSUMPTION FOR PARTICULATE CONTROL
           TECHNIQUES FOR RESIDUAL OIL-FIRED BOILERS

System
Standard boiler
Heat input
MW (106 Btu/hr)
44 (150)
3.0% S




_, level of
Type control
Residual oil ESP
Moderate
Intermediate
and
SIP
Stringent
Electrical energy consumption
Control Energy^consumed
efficiency controlydevlce
(percent) (kw)
30.50 10,3
75.0 26.4


91.70 44.2
% Increase in
energy use
over
uncontrolled
boiler
0.023
0.06


0.10
% Change in
energy use
over SIP
controlled
boiler

0


+0.04

-------
    1.0
   0.25

-------
5.5  SUMMARY




     Data presented in this section show that particulate control equipment




would require a 0.02 to 0.7 percent increase in energy consumption over uncon-




trolled coal-fired boilers.  Oil-fired boilers would require 0.02 to 0.1 percent




additional energy.  These percentages have been based upon the boiler input and




one should look at actual electrical loads when evaluating energy impacts




associated with varying levels of control.




     These data show that the ESP is the least energy intensive control device




at all levels of control when 3.5 percent S coal is burned.  When the coal




utilized is either 0.9 percent or 0.6 percent S, the baghouse becomes less




energy intensive for pulverized and spreader stoker boilers at the stringent




control level.




     It should be stressed that certain assumptions have been made in the




preceding analyses to simplify the computations.  The use of a constant power




density for cold and hot ESP systems would not exist in a real system since




lower sulfur coals {higher resistivities) result in decreasing power den-




sities necessitating larger collectors (plate area).  However, it is felt that




the overall trends indicated depict a fair representation of the systems




evaluated.
                                      228

-------
                              5.6  REFERENCES
1.   Fraser, M. D., and G. J. Foley.  Cost Models for Fabric Filter Systems.
     67th Annual Meeting of the Air Pollution Control Association.   Denver,
     Colorado.  June 9-13, 1974,  p. 12.

2.   Edmisten, N. G., and F. L. Bunyard.  A Systematic Procedure for Deter-
     mining the Cost of Controlling Particulate Emissions from Industrial •
     Sources.  Journal Air Pollution Control Association.  Vol. 20, No,  7.
     July 1970.  p. 452.

3.   White, H. J.  Electrostatic Precipitation of Fly Ash.  Journal of Air
     Pollution Control Association.  Vol, 27, No. 3.  March 1977.  p. 210,

4.   Oglesby, S., Jr., and G. B. Nichols,  A Manual of Electrostatic
     Precipitator Technology - Volume II - Applications.  Prepared  for
     Environmental Protection Agency.  1970.  p. 369.

5.   Bubenick, D. V.  Economic Comparison of Selected Scenarios for Electro-
     static Precipitators and Fabric Filters.  Journal of Air Pollution  Control
     Association.  Vol. 28, No. 3.  March 1978.  p. 281.

6.   Farber, P. S.  Capital and Operating Costs of Particulate Control
     Equipment for Coal-Fired Power Plants.  Paper presented at the 5th
     National Conference - Energy and the Environment,  October 31-
     November 3, 1977.  p. 435.

7.   Oglesby, S., Jr.  op. cit.  p. 373.
                                     229

-------
                 6.0  ENVIRONMENTAL IMPACT OF CANDIDATES FOR
                      BEST SYSTEMS OF EMISSION REDUCTION
6.1  INTRODUCTION

     The purpose of this section is to evaluate the environmental impacts of

the candidate control technologies under consideration.  Any reduction in

stack gas particulate emissions will cause an increase in solid waste, for

example, the effects of which must be fully assessed.  These multiple and/or

interrelated impacts can also result from the energy requirements of control

equipment since more fuel must necessarily be burned to generate the required

electrical power.

     Also of obvious concern is whether particulate emission control systems

will cause an increase in emissions of harmful pollutants (carcinogens, toxic

trace elements, etc.).

     Other impacts such as increased water, thermal, and/or noise pollution

will also be addressed.
                                     230

-------
6.2  ENVIRONMENTAL IMPACTS OF CONTROLS FOR COAL-FIRED BOILERS

6.2.1  Air Pollution

     The primary source of air pollutants from a fossil-fueled boiler operation

is the flue gas exhaust stack.  Other minor sources include emissions from ash

handling, cooling tower drift or spray (where one is used), and coal storage,

handling, and preparation facilities.

     The primary air environmental impact resulting from particulate control

will be beneficial in that the stack emissions will be reduced considerably.

Accompanying the overall decrease in particulate emissions will be the cor-

responding reduction of the particulate/sulfate complex which is believed to

have an adverse/synergistic effect on human health.1  Table 63,  which includes

air impacts for the best systems of emission reduction under the subheading of

"Primary Pollutants" shows particulate emission rates for all boiler/fuel/

control level combinations.  Units are given as g/sec (Ib/hr) and ng/J

(lb/106 Btu).  The column entitled "Other Pollutants" refers to the "criteria"
                                            /
pollutants (sulfur dioxide, oxides of nitrogen, carbon monoxide, and hydro-

carbons) and any deviations in their respective emission rates as a result of

particulate control are indicated in the table.  It has been determined, how-

ever, that particulate controls do not significantly affect the emissions of

these criteria pollutants, although S0£ adsorption on deposited fly ash layers

on ESP plates or fabric filters may reduce its effluent concentration.

     Emissions of other substances not included in either of the Primary Pol-

lutants categories are listed as Secondary Pollutants with beneficial or ad-

verse impacts.  Secondary air pollutants could be trace metals or any chem-

icals used to treat the fuel or boiler feedwater that are exhausted through

the stack as vapors, droplets or solids.  Boiler feedwater chemicals can only


                                    231

-------
TABLE 63.  AIR, WATER, AND SOLID WASTE POLLUTION IMPACTS FROM "BEST"
           PARTIOJLATE CONTROL  TECHNIQUES FOR COAL-FIRED BOILERS

Standard boiler
HeatMLnput ^ ^
(106 Btu/hr) fuel
System
Control level
(name/Z reduction)

Type of
control
Primary pollutants Secondary pollutants^
Particulates Other pollutants*
g/sec
(Ib/hr)
,_ T, . Beneficial
ne/J n^i Degree Z
Ub/MBtu) P°llutant cnange
Adverse
(solid waste)
g/sec
(Ib/hr)*
117.2 Pulverized
(400) coal
3.5Z S
10. 6Z A












2. 31 S
13. 2Z A












0.9Z S
6.9Z A










Uncontrolled

SIP/91.66


Moderate/96.52


Intermediate/98. 61


Stringent/99.58


Uncontrolled

SIP/92.50


Moderate/96.88


Intermediate /98. 75


Stringent/99.63


Uncontrolled

SIP/85.0

Moderate/93. 75


Intermediate/97. 5
Stringent/99.25



-

ESP, US
or FF

ESP or
FF

ESP or
FF

ESP or
FF

_

ESP, WS,
or FF

ESP or
FF

ESP or
FF

ESP or
FF

_

ESP, US,
or FF
ESP, US,
or FF

ESP or
FF
ESP or
FF


363
(2,875)

30
(240)

13
(100)

5
(40)
.
1.5
(12)
403
(3,198)

30
(240)

13
(100)

5
(40)

1.5
(12)
202
(1,600)
30
(240)

13
(100)
5
(40)

1.5
(12)

3092 S02 CO NA NA
(7.19) NOj HC

258 NA NA NA
(0.6)

107.5 NA NA NA
(0.25)

43 NA NA NA
(0.10)

12.9 NA NA NA
(0.03)
3440 S02 CO NA NA
(8.0) NOg HC

258 NA NA NA
(0.6).

107.5 NA NA NA
(0.25)

43 NA NA NA
(0.10)

12.9 NA NA NA
(0.03)
1720 S02 CO NA NA
(4.0) NOx HC
258 NA NA NA
(0.6)

107.5 NA NA NA
(0.25)
43 NA NA NA
(0.10)

12.9 NA • NA NA
(0.03)

-


332
(2.635)

350
(2,775)

358
(2,835)

. 361
(2,863)



373
(2,958)

391
(3,098)

398
(3,158)

402
(3,186)
-

172
(1,360)

189
(1,500)
197
(1,560)

200
(1,588)
                               (continued)
                                  232

-------
TABLE  63 (continued)
System
Standard boiler

Heat input _ . , Con^01 ieve* .
^ r Type and (name/Z reduction)
(106 Btu/hr) fuel
0.62 S Uncontrolled
5.4X A
SIP/86.67


Moderate/94.44


Intermediate/97 . 78


Stringent/99.33


58,6 Pulverized
(200) coal
3.5Z S Uncontrolled
10. 6% A
SIP/91.64

Moderate/96.52

Intermediate/98.61

Stringent/99.58

0.9% S Uncontrolled
6.9% A
SIP/85.0

Moderate/93.75


Intermediate/97.50

Stringent/99.25




Type of
control
_

ESP, WS,
or FF

ESP, WS,
or FF

ESP or
FF

ESP or
FF



_

ESP or
FF
ESP or
FF
ESP or
FF
ESP or
FF
_

ESP or
FF
ESP or
FF

ESP or
FF
ESP or
FF


Primary pollutants
Secondary pollutants
Particulates Other pollutants* Adverse
g/sec
(Ib/hr)
227
(1,800)

30
(240)

13
(100)

5
(40)

1.5
(12)


181
(1,436)
15
(120)
6.2
(49)
2.4
(19) '
0.8
(6)
100.8
(800)
15
(120)

6.3
(50)
2.5
(20)

0.8
(6)
(Ib/MBtu) Pol^tant
1935 S02 CO
(4.5) NOX HC

258 NA
(0.6)

107.5 NA
(0.25)

43 NA
(0.10)

12.9 NA
(0.03)


3,087 S02 CO
(7.18) NOX HC
258 NA
(0.6)
107.5 NA
(0.25)
43 NA
(0.10)
12.9 NA
(0.03)
1,720 S02 CO
(4.0) NOX HC
258 NA
(0.6)

107 . 5 NA
(0.25)
43 NA
(0.1)

12.9 NA
(0.03)
Beneficial «""" »<""-=.>
change (Ib/hr)^
NA NA


NA NA 197
(1,560)

NA NA 214
(1,700)

NA NA 222
(1,760)

NA NA 225
(1,788)


NA NA NA

NA NA 166
(1316)
NA NA 175
(1387)
NA NA 178.7
(1417)
NA NA 180
(1430)
NA NA NA

NA NA 85 . 8
(680)

NA NA 94,6
(750)
NA NA 98.4
(180)

NA NA 100
(794)
       (continued)
         233

-------
TABLE  63 (continued)
System
Standard boiler
,, . . . Control level
Heat input _ . , ,„ , , >
IQJ v Type and (name/% reduction)
UO6 Btu/hr) fuel
0.6% S Uncontrolled
5.4% A
SIP/86.67


Moderate/94.44


Intermediate/97. 78

Stringent/99.33


44 Spreader
(150) stoker
3.5% S Uncontrolled
10.6% A
SIP/89.73


Moderate/95.72


Intermediate/98. 29


Stringent/99.49


0.9% S Uncontrolled
6.9% A
SIP/81.54


Moderate/92.31


Intermediate/96.92


Stringent/99.08



Type of
control
-

ESP or
FF

ESP or
FF
WS
ESP or
FF
ESP or
FF



-

ESP or
FF
US
ESP or
FF
WS
ESP or
FF
WS
ESP or
FF

_

ESP or
FF
ws
ESP or
FF
WS
ESP or
FF
WS
ESP or
FF

Primary pollutants Secondary pollutants
Particulates
g/sec
(Ib/hr)
113.4
(900)

15
(120)

6.3
(50)
2.5
(20)

0.8
(6)


110
(876)

11.4
(90)

4.7
(37.5)

1.9
(15)

0.6
(4.5)
61
(487)

11.4
(90)

4.7
(37.5)

1.9
(15)

0.6
(4.5)
ng/J
(Ib/MBtu)
1,935
(4.5)

258
(0.6)

107.5
(0.25)
43
(0.1)

12.9
(0.03)


2511
(5.84)

258
(0.60)

107.5
(0.25)

43
(0.10)

12.9
(0.03)
1398
(3.25)

258
(0.60)

107.5
(0.25)

43
(0.10)

12.9
(0.03)
Other pollutants Adverse
_ Beneficial . was
Pollutant Defree * ,?u/u%±
change (Ib/hr)}
S02 CO NA NA NA
NOX HC

NA NA NA 98.4
(780)
107.2
NA NA NA (850)
same and U.P.
NA NA NA 111
(880)

NA NA NA 112.7
(894)


S02 CO NA NA NA
NOX HC
99
NA NA NA (786)
same and W.P.
105.7
NA NA NA (838.5)
same and W.P.
108.6
NA NA NA (861)
same and W.P.

NA NA NA 109.9
(871.5)
S02 CO NA NA NA
NOX HC
50
NA NA NA (397)
same and W.F.
56.7
NA NA NA (449.5)
same and W.P.
59.5
NA NA NA (472)
same and W.P.

NA NA NA 60.8
(482.5)
        (continued)
         234

-------
TABLE  63 (continued)
System
"
Standard boiler
Control level
MW Type and (name/% reduction)
(106 Btu/hr) £uel
0.6% S Uncontrolled
5.4% A
SIP/83.61


Moderate/93.17


Intermediate/97.27


Stringent/99.18


22 Chain grate
(75) stoker
3.5% S Uncontrolled
10.6% A
SIP/73.33


Moderate/88.89


Intermediate/95.56


Stringent/98.67


0.9% S Uncontrolled
6.9% A
SIP/52.0



Moderate/82.0




Type of
control
_

ESP or
FF
WS
ESP -or
FF
WS
ESP or
FF
WS
ESP or
FF



_

ESP or
FF
WS
ESP or
FF
WS
ESP or
FF
WS
ESP or
FF
WS
_

ESP, FF
or MC
WS

ESP, FF
or MC
WS



r ma y po
Secondary pollutants '

Particulates Other pollutants* Adverse
g/sec
(lb/hr)
69
(548)

11.3
(89.8)

4.7
(37.4)

1.9
(15)

0.6
(4.5)


21.3
(169)

5.7
(45)

2.4
(18.8)

0.9
(7.5)

0.3
(2.2)
11.9
(94)

5.7
(45.1)


2.1
(16.9)
t-^iLi, •, Pollutant
(Ib/MBtu)
1574 S02 CO
(3.66) NOX HC

258 NA
(0.60)

107.5 NA
(0.25)

43 NA
(0.10)
-
12.9 NA
(0.03)


968 S02 CO
(2.25) NOX HC

258 NA
(0.60)

107.5 NA
(0.25)

43 NA
(0.10)

12.9 NA
(0.03)
538 S02 CO
(1.25) NOX HC

258 NA
(0.60)


107.5 KA
(0.25)
De ree 7 Beneflclal /sec
change (lb/hr)*
NA NA NA

57.8
NA NA (458.2)
same and W.P.
64.4
NA NA (510.6)
same and W.P.
67.2
NA NA (533)
same and W.P.

NA NA 68.5
(543.5)


NA NA NA

15.6
NA NA (124)
same and W.P.
18.9
NA NA (150.2)
same and W.F.
20.4
NA NA (161.5)
same and W.P.
21
NA NA (166.8)
same and W.P.
NA NA NA


NA NA 6.2
(48.9)
same and W.P.
9.7
NA NA (77.1)
same and W.F.
        (continued)
           235

-------
TABLE 63 (continued)
System

ScdDuflrd boiler*
„ . " Control level
MH Type "ld (name/Z reductlon>
(106 Btu/hr) fuel
Intermediate/92.0


Stringent/97.6


0.6Z S Uncontrolled
5.4Z A
SIP/57.45


Moderate/82.27


Intermediate/92.91


Stringent/97.87


8.8 Underfeed
(30) stoker
3.5Z S Uncontrolled
10. 6Z A
SIP/73.21


Moderate/88.84


Intermediate/95.54


Stringent/98.66




Type of
control
ESP or
FF
US
ESP or
FF
US
-

ESP, FF
or MC
• us
ESP, FF
or MC
US
ESP or
FF
US
ESP or
FF
US


-

ESP or
FF
US
ESP or
FF
US
ESP or
FF
US
ESP or
FF


Primary pollutants
Particulates Other pollutants*
g/sec
(Ib/hr)

0.9
(7.5)

0.3
(2.3)
13.4
(106)

5.7
(45.1)

2.4
(18.8)

0.9
(7.5)

0.3
(2.3)


8.4
(67)

2.3
(18)

0.9
(7.5)

0.4
(3)

0.1
(0.9)
,,^ ^ Pollutant De*ree Z
(Ib/MBtu) change

43 NA NA
(0.10)

12.9 NA NA
(0.03)
606 S02 CO NA
(1.41) NOX HC

258 NA NA
(0.60)

107.5 NA NA
(0.25)

43 NA NA
(0.10)

12.9 NA NA
(0.03)


963 SO2 CO NA
(2.24) NO* HC

258 NA NA
(0.6)

107.5 NA NA
(0.25)

43 NA NA
(0.10)

12.9 NA NA
(0.03)
Secondary pollutants*
Adverse
;eneficial (sol^s^te)
(lb/hr)|
10.9
NA (86.5)
same and U.P.
11.6
NA (91.7)
same and W.P.
NA NA

7.7
NA (60.9)
same and U.P.
11
NA (87.2)
same and U.P.
12.4
NA (98,5)
same and U.P.
13
NA (103.7)
same and U.P.


NA NA

6.2
NA (49)
same and U.P.
7.5
NA (59.5)
same and U.P.
8
NA (64)
same and U.P.

NA 8.3
(66.1)
        (continued)
         236

-------
                                          TABLE 63  (continued)
System
Standard boiler
Heat input Control level
„, Type and (name/2 reduction)
ww _ _
(106 Btu/hr) fuel
0.92 S Uncontrolled
6.92 A
SIP/52.0
Moderate/80.0
Intermediate/92.0
Stringent/97.6
0.62 S Uncontrolled
5.42 A
SIP/57.14
Moderate/82.14
Intermediate/92.86
Stringent/97.86

Type of
control
-
ESP, FF
or MC
US
ESP, FF
or MC
US
ESP or
FF
WS
ESP or
FF
-
ESP, FF
or KC
US
ESP, FF
or MC
US
ESP, FF
or MC
US
ESP or
FF
WS

Primary pollutants
Secondary pollutants
Particulates Other pollutants Adverse
g/sec
(Ib/hr)
4.8
(38)
2.3
(18.2)
1.0
(7.6)
0.4
(3.0)
0.1
(0.9)
5.3
(42)
2.3
(18)
0.9
(7.5)
0.4
(3)
0.1
(0.9)
(IbStu) P°llutant
538 S02 CO
(1.25) NOX HC
258 NA
(0.60)
107.5 NA
(0.25)
43 NA
(0.10)
12.9 NA
(0.03)
602 S02 CO
(1.40) NOx HC
258 NA
(0.60)
107.5 NA
(0.25)
43 NA
(0.10)
12.9 NA
(0.03)
_ , Beneficial """» "01-c'
Degree 2 g/sec
change (Ib/hr)*
NA NA NA
2.5
NA NA (19.8)
same and W.P.
3.8
NA NA (30.4)
same and U.P.
4.4
NA NA (35)
same and U.P.
NA NA 4.7
(37.1)
NA NA NA
3
NA NA (24)
same and U.P.
4.4
NA NA (34.5)
same and U.P.
NA NA 4.9
(39)
same and U.P.
5.2
NA NA (41.1)
same and U.P.
S02 • sulfur dioxide;
affected  (NA).
 Secondary pollutants
•All numerical entries
NOX - oxides of  nitrogen; CO « carbon monoxide; HC *  hydrocarbons.   If none listed, none are

could be other chemicals, trace metals, etc.
; represent fly ash solid waste.  W.P., where indicated, means potential  for water pollution impact.
                                                      237

-------
discharge via the stack when water tubes develop leaks due to severe corrosion.




However, the above problem would not be related to the installation of partic-




ulate control equipment.




     Trace elements may pose a serious health hazard since they concentrate




largely on the surfaces of fly ash particles from which they may be readily




desorbed following inhalation.2  The process by which trace element concen-




trations are enriched on the smallest particles begins in the combustion zone




with the volatilization of some chemical species containing the element.




Downstream of the combustion zone, condensation and adsorption on particulate




surfaces takes place.  Surface area, a large fraction of which is represented




by the smallest particles, plays an important role in determining rate of




adsorption.  Trace elements which are adsorbed on fly ash are antimony, arsenic,




cadmium, chromium, copper, gallium, lead, mercury, nickel, polonium, selenium,




thallium, and zinc.3  Because of the fact that installation of some particulate




control equipment will result in a higher proportion of fine particulate matter




to be discharged to the atmosphere, the fraction of inhalable trace metal-




bearing solids in the effluent will be higher.  However, the net impact of




the control equipment should be to reduce the atmospheric concentrations for




these substances.



6.2.2  Water Pollution




     The potential sources for water pollution at a fossil-fuel facility are




ash handling systems, wet scrubber flue gas cleaning systems, boiler feedwater




treatment, boiler blowdown, and boiler system equipment cleaning.  The last




three items, which are unrelated to pollution control operations, are not




considered in this report.  Ash handling, when carried out on a dry basis,




is discussed under solid waste impact.  However, if the ash is transported to







                                     238

-------
a settling pond by a hopper sluicing system, it may generate water pollution



problems at the storage site.



     Wet scrubbers used for particulate control will produce significant



quantities of liquid waste which may be discharged to an ash settling pond



or piped to a local water treatment plant after solids removal treatment.



The quantities discharging from conventional boiler facilities are difficult



to predict since these systems often use differing liquid-to-gas (L/G) ratios



as well as different degrees of recirculation.  A Venturi scrubber on a pul-



verized coal boiler (3.5 percent sulfur) operating at an L/G ratio of 0.9



liters/m3 (7 gal/1000 ft3) with no recirculation will discharge about 2000



liters/min (525 gal/min).  Usually this discharge is pumped to a settling



pond where the fly ash settles to the bottom and the liquid is either dis-



charged, evaporated, or recycled.  Pond liners may be used to prevent leaching



of any metals or chemicals into the soil and surrounding water table.  Although



intrusion upon a local water body or supply is always possible, good operating
                                         x


procedures can minimize this potential pollution impact.  Any water pollution



impacts are designated in Table 63 as Secondary Particulates, where W.F. means



potential for water pollution.



     Since the properties of ash pond discharge waters differ from plant to



plant, it is unreasonable to specify average values.  Thus, Table 64 shows



the concentration ranges expected for some of the more important chemical



constituents.4



6.2.3  Solid Waste



     The greatest environmental effect of particulate control systems will be



that of increased solid waste generation and its resulting impact due to



handling and disposal.  However, it must be realized that without particulate
                                     239

-------
TABLE 64.  PROPERTIES OF ASH POND
           DISCHARGE WATERS4

Water parameter
Total solids
Total dissolved solids
Total suspended solids
Oil and grease
Hardness
Alkalinity
*• • f- ^J
Al
Cr
Na
NH3
NO 3
Cl
Cu
Fe
Range of
concentration ,
mg/A
300-3500
250-3300
25-100
0-15
200-750
30-400
100-300
0.2-5.3
0.1
20-173
0.1-2
0.1-6.1
20-2000
0.1-0.3
0.02-2.9
               240

-------
control, solid wastes appear as stack emissions which are equally or more

detrimental to human health.

     The amounts of solid waste generated at the various control levels for

all boiler/fuel combinations are indicated in Table 63 as Secondary Pollutants

(adverse impact) with units of g/sec (Ib/hr).  These amounts are, as expected,

inversely proportional to the efficiencies required for each level of emission

reduction.

     The percentage increase in fly ash collection compared to that for the

boiler controlled at the SIP level of 258 ng/J (0.6 lb/106 Btu) ranges from

about 8 to 88 percent depending on boiler and fuel types, and degree of con-

trol.  The 88 percent figure refers to the underfeed stoker boiler burning

coal containing 0.9 percent sulfur and 6.9 percent ash and collecting 2.5

g/sec (19.8 Ib/hr) and 4.7 g/sec (37.1 Ib/hr) at the SIP and stringent levels,

respectively.

     The primary method of fly ash disposal is by landfilling, and as with
                                          s
settling ponds, liners and proper operating procedures, can minimize runoff

or leaching into the water table.  Aside from outright disposal, other solu-

tions to the fly ash problem are its utilization in road embankments and as

a component of concrete mixtures.  However, fly ash application in the United

States has lagged behind the European countries.  In 1969, Great Britain and

France used 42 and 55 percent, respectively, of their total fly ash production,

as compared to only 9 percent for the United States.

6.2.4  Other Environmental Impacts

     Other potential environmental impacts arising from increased particulate

control are noise generation from fans, compressors, pumps, electrode rappers,

and/or cooling towers.  The above impacts would have to be examined on a


                                     241

-------
case-by-case basis to accurately determine their absolute effect on the




surrounding community.




6.2.5  Environmental Impact on Modified and Reconstructed Facilities




     The environmental impacts associated with retrofit installations are




essentially the same as those for new facilities.  These impacts, however,




may be more serious depending upon the age of the plant and the equipment




in use.  For example, in the case of a retrofit installation, it is often




necessary to operate within adverse space and geometry constraints such that




optimum collection systems are more difficult to install.




6.3  ENVIRONMENTAL IMPACTS OF CONTROLS FOR OIL-FIRED BOILERS




     The impacts of oil-fired facilities on the environment are essentially




the same as those for coal-fired plants except that they are less severe due




to the much lower uncontrolled ash emissions.




     However, although the quantities of ash produced by an oil-fired plant




are much smaller than those for a coal-fired plant, the ash-settling charac-




teristics are more unfavorable in the case of oil because of its much smaller




size properties.




     On the positive side, because the vanadium content of oil fly ash is




potentially toxic to aquatic life, even partial collection will result in an




overall beneficial impact.  It has been found in some cases that recycling oil




fly ash to the furnace increases combustion efficiency and eliminates the ash




disposal problem.




6.4  ENVIRONMENTAL IMPACTS OF CONTROLS FOR GAS-FIRED BOILERS




     Due to the fact that gas-fired boilers exhibit inherently low uncontrolled




emission rates and therefore do not require particulate control, there will be




no recognized environmental impacts at the present time.






                                     242

-------
6.5  SUMMARY OF MAJOR ENVIRONMENTAL IMPACTS OF CONTROL TECHNIQUES




     The primary environmental impact of more stringent particulate control




requirements will be the added requirement for solid waste disposal.  One




must consider the relative impacts of uncontrolled stack emissions and the




requirements for solid waste disposal.




     The potential impact of solid waste disposal is dependent on such factors




as land availability, available transportation routes, leaching of elements




into ground-water supplies, runoff into water bodies used for recreational




purposes, and whether or not the potential for fly ash utilization becomes




more fully realized.




     Considering all factors, it appears that the environment can only benefit




from increased particulate control at the stack since fly ash disposal as solid




or liquid wastes is a controllable process.




     The environmental impact of the increased fuel usage required to provide




the energy necessary to operate particulate control equipment is difficult to




assess, although power supplied by large utility plants will likely result in




minimal environmental impact because utility plants will probably be well




controlled.
                                     243

-------
                            6.6  REFERENCES


1.   Stern, A. C., et al.  Fundamentals of Air Pollution.  Academic Press, Inc.
     1973.  pp. 135-136.

2.   Surprenant, N. F., et al.  Preliminary Emissions Assessment of Conventional
     Stationary Combustion Systems - Volume II - Final Report.  EPA-600/
     2-76-046b.  March 1976.  pp. 115-126.

3.   Ibid,  p. 123, Table 40.

4-   Ibid,  p. 138, Table 47.

5.   Ibid,  p. 136.
                                     244

-------
                       7.0  EMISSION SOURCE TEST DATA






7.1  INTRODUCTION




     The purpose of this section is threefold:




     •    To describe fully any new source test data that have become




          available during the conduct of this industrial boiler tech-




          nical assessment.




     •    To elaborate upon the test data and associated test methods




          presented in Section 2.0.




     •    To discuss the relative accuracies of the various test methods




          available for particulate sampling with respect to the three




          levels of emission control.




     The selection of a given test method depends on numerous factors such as




the pollutant to be sampled, the fuel burned, the temperature and pressure of




the pollutant stream, the sampling location, the presence of corrosive sub-




stances, and the ultimate data application; i.e., to demonstrate compliance




with specified emission regulations, to determine the efficiency of a given




control device (performance test), or to determine whether vendor-guaranteed




emission levels are being achieved (acceptance tests).




     The application of test data may also be a decisive factor in deciding




who conducts the source test.  Organizations such as EPA and State agencies,




private consulting companies, equipment manufacturers, source personnel,




or combinations of the above are the groups by whom test data are usually




procured.




                                    245

-------
     Regardless of test classification or the testing group, efforts are nor-




mally made to obtain accurate and realistic information over the measurement




period.  Ideally, sampling should be performed in locations where there are




minimum distortions or perturbations in gas stream flow profiles and where




contaminant concentrations are uniform over the sampled cross section.




     In actual practice, such ideal conditions seldom prevail in the field




due to the absence of lengthy, straight runs of duct and the presence of




elbows, tees, dampers or baffles that may lead to asymmetry in both velocity




and concentration profiles.  Hence there is a need to sample at many points




within the test cross section to obtain a representative measure of pollutant




concentration.




7.2  EMISSION SOURCE TEST DATA FOR COAL-FIRED BOILERS




     Test data provided in Section 2.0 have been reviewed and an attempt has




been made to further clarify or supplement this information.  The following




discussion provides further explanation of the former data.




     Table 16 provided source test data for a number of coal-fired utility




boilers controlled by electrostatic precipitators (ESP).  The raw data




constituting the bases for Table 16 are presented in this section in




Tables 65 and 66.  Boiler design parameters and test data are shown in




Table 65 for the 10 surveyed utilities while fuel compositions are given in




Table 66.




     Table 65 shows pertinent design information such as boiler size, fuel




consumption rate, furnace type, coal-firing method and control equipment




operating and performance parameters at the time of the emission test as




compared to those specified in the design criteria.  The fuel data, Table 66,




provide a good geographical sampling of coals burned in this country and the






                                    246

-------
TABLE  65.   DETAILED EMISSION SOURCE DATA FOR INFORMATION PRESENTED IN  TABLE 16
Station
Boiler data
Fuel consumption,
tons/hr
No. MW Design Average method
Control equipment data
Outlet
Temp.
Primary Manuf . °F
Flow
rate,
acfm
parameter Design Test
Overall
efficiency,
percent
Design Test ft/sec
Particulate
emission rate
lb/106 Btu
                              AMERICAN ELECTRIC POWER. CANTON, OHIO
Amos 3

Big Sandy 1

2

Clinch River 1
2
3
Gavin 1

2

Glen Lyn 5
6
Kanawha River 1
2
Tanners 1
Creek
1300 485

280 105

fiOC 300

240 80
240 80
240 80
1300 485

1300 485

105 48
240 80
210 80
210 80
150 60
150 60
Front
and
rear
Front
and
rear
Front
and
rear
Top
Top
Top
Front
and
rear
Front
and
rear
Front
Front
Top
Top
Top
Top
ESP Koppere 328 403 4.41xl06 4.477xl06 99.75 99.67 5.44 0.04

ESP Koppers 300 223 950,000 853,300 98.5 98.5 6.3 0.24

ESP EC 360 153 2.79xl06 2.93xl06 98.5 98.2 6.3 0.17

ESP Koppers 310 963 900,000 850,000 99.7 99.7 3.09 0.05
ESP Koppers 310 963 900,000 850,000 99.7 99.5 3.09 0.05
ESP Koppers 310 • 963 900,000 850,000 99.7 99.5 3.09 0.05
ESP Koppers 340 403 4.41xl06 4.429xl06 99.75 99.87 5.44 0.013

ESP Koppers 340 403 4.4lxl06 4.429xl06 99.75 99.77 5.44 0.014

ESP Am> Std. 315 607 509,000 527,000 99.7 99.9 4.09 0.003
ESP Am. Std. 310 967 900,000 850,000 99.7 99.9 4.12 0.001
ESP Buell 317 315 775,000 734,000 98.5 99.75 4.94 0.03
ESP Buell 320 315 775,000 734,000 98.5 99.75 4.94 0.03
ESP RC 280 1045 640,000 312,000 99.9 99.7 3.1 0.01
ESP RC 280 1045 640,000 312,000 99.9 99.7 3.1 0.01
                        CLEVELAND ELECTRIC ILLUMINATING CO., CLEVELAND, OHIO
East lake 5
680
230
164
Front ESP
RC 285 209 2.15xl06 - 99.5 98.4 6.95 °-02 gr/scf
                              CONSUMERS POWER CO., JACKSON, MICHIGAN
D. E. Karn

J. R. Whiting


1
2
1
2
3
265 159
265 125.1
100 52
100 52
125 60
111.3
110.9
42
42
52.4
Tang.
Front
Front
Front
Front
2-ESPs E.E.
2-ESPs E.E.
ESP Am. Std.
ESP Am. Std.
ESP Am. Std.
315
315
285
285
300
245
245
320
320
320
1.172xl06 l.OlxlO6
1.172xl06 1.01x10°
400,000 362,000
475,000 351,000
430,000
97.0 99
97.0 99
99 99.6
99 99.6
99 99.6
5.53
5.53
4.75
4.75
4.75
0.026 gr/scf
0.026 gr/scf
0.006 gr/scf
0.036 gr/scf
0.009 gr/scf
                                        (continued)

-------
                                                           TABLE 65 (continued)

Station
J. K. Campbell




Boiler data

Boiler
No.
1
2

3


Fuel consumption ,
tona/hr
MW Design Average
265 132. 5 106.6
385 170 160,2

800 300 210


Firing
method
Tang.
Front
and
rear
Front
and
rear


Outlet
Temp.
Primary Manuf. °F
2-ESPa Buell 313
2-ESPs Buell 300

ESP Buell 305

Contra]

Critical*
parameter
206
500

640.4

equipment data
Flow
rate,
acfm
Ceslpn Teat
1,177,200 1.03xl06
1,491,700 1,061,400

3.4xl06


Overall
efficiency,
percent
Design Test
97
98

98.58-
99.32



Velocity
ft/sec
5.19
3.19

5.83


Particulate
emission rate
lb/106 Btu
est:
0.0354 gr/acf
0.015 gr/scf

0.06 gr/scf

                                                        DUKE POWER CO., CHARLOTTE, NORTH CAROLINA"
Allen 1
2
3
4
5
Belews Creek 1
2
Buck - 3 5&6
- 4 7
- 5 8
- 6 9
Cliffside ' 1
2
3
it
5
Dan River 1
2
3
Lee 1
2
3
166 56
165 56
275 91
275 91
275 91
1140 360
1140 360
40 17
40 17
125 48
125 48
40 17
40 17
65 28
65 28
572 238
70 30
70 30
150 55
90 40
90 40
165 59
Tang.
Tang.
Tang.
Tang.
Tang,
- Opposed
PCOP
Opposed
PCOP
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
ESP HC 308 150.38 532,000 677,459 99 98.41 5.5 0.1547
ESP RC 308 150.38 532,000 637,455 99 97.35 5.5 0.2332
ESP RC 630 269.57 1.25xl06 1,177,648 99.2 97.65 5.94
ESP RC 630 269.57 1.25xl06 1,176,140 99.2 98.18 5.94
ESP RC 630 269.57 1.25xl06 1,055,527 99.2 97.88 5.94
ESP RC 260 304.56 3.2xl06 3,930,530 99.7 97.38 5.25 0.09
ESP RC 260 304.56 3.2xl06 3,244,601 99.7 91.34 5.25
ESP Buell 695 239.29 337, 000 ea 99 - 5.4 ea
ESP Buell 725 239.29 337,000 - 99 - 5.4
ESP Buell 625 237.94 640,000 - 99.08 - 5.1
ESP Buell 632 237.94 640,000 576,478 99.08 99.65 5.1 0.0459
ESP Buell 732 239.29 337,000 • 287,395 99 99.2 4.5 0.042
ESP Buell 756 239.29 337,000 293,413 99 98.3 4.5 0.18
ESP RC 648 218.7 400,000 362,301 99 99.16 5.5 0.0943
ESB RC 655 218.7 400,000 396,925 99 98.86 5.5 0.1331
ESP RC 263 211.15 1.78xl06 1,613,413 99.5 99.29 5.7 0.0485
ESP RC 622 216.42 402,000 360,674 99 98.73 5.52 0.1347
ESP RC 644 216.42 402,000 378,509 99 99.55 5.52 0.083
ESP Buell 300 296.07 535,000 492,954 99.2 98.93 5.0 0.0817
ESP RC 622 222.22 540,000 541,531 99 99.15 5.4 0.10
ESP RC 622 222.22 540,000 - 99 - 5.4 0.11
ESP Buell 622 • 230.4 825,000 740,525 99 99.23 4.6 0.12
NJ
J>
CO
                                                                    (continued)

-------
                                                                TABLE  65 (continued)
Station
Marshall



Riverbend - 4
- 5
- 6
- 7
Boiler data
Boiler
No.
1
2
3
4
7
8
9
10
Fuel consumption,
tona/hr
MU Design Average
350 117
350 117
650 208
650 208
100 41
100 41
133 52
133 52
Firing
method
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.

Primary
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP

Manuf.
Buell
Buell
RC
RC
Buell
Buell
Buell
Buell

Outlet
Temp.
oF
260
260
260
260
640
640
614
614
Control
Critical8 -
parameter
174.39
174.39
261.82
261.82
232.62
232.62
235.2
235.2
equipment data
Flow
rate,
acfm
Design Test
1.09xl06 1,145,937
1.09xl06 1,085,205
2.2xl06 1,662,278
2.2xl06
585,000
585,000 483,538
675,000
675,000 587,556

Overall
efficiency,
percent
Design Test
99.5 99.24
99.5 93.61
99.7 98.96
99.7
99.03 99.56
99.03 99.59
99.06 99.74
99.06 99.65

Velocity,
ft/sec
6.1
6.1
4.07
4.07
5.2
5.2
5.1
5.1
Particulate
emission rate
lb/106 Btu
0.11
0.10
0.1195
-
-
0.0467
-
0.0421
                                                               GULF POWER CO., BIRMINGHAM, ALABAMA
Crist 4
5
6
7
Lansing 1
Smith
2
Scholz 1
2
94 32.1
94 32.15
370 125
578 197.1
150 56.4
190 71.3
49 19.6
49 19.6
16.9
16.8
79.1
145.9
52.6
64.8
16.79
16.79
Tang.
Tang.
Tang.
Tang.
Tang.
Tang.
Front
Front
2-ESPs Buell
hot/cold
2-ESPs Buell
hot/cold
ESP Buell
ESP Buell
2-ESPs Buell/
hot/cold Am. Std.
2-ESPs Buell/
hot/cold Am. Std.
ESP Buell
ESP Buell
300
300
268
267
258
268
300
300
257/179
257/179
137
158
284
126
574
574
515x10 3
290x10 3
515xl03
290x10 3
505,000
830,000
853x10 3
460x10 3
l.lxlO6
540x10 3
190,600
190,600
99.1
99.1
98.0
98.2
99.1
99.1
99.5
99.5
99.5
98.9
98.6
98.2
99.7
-
99.8
99.3
4.48
4.675
4.48
4.675
5.84
5.9
4.7
5.68
4.7
6.25
1.86
1.86
0.033
0.082
0.085
0.099
0.043
-
0.019
0.075
ro
s
                                                       PENNSYLVANIA POWER AND LIGHT, ALLENTOWN, PENNSYLVANIA0
Holtwood 17

Sunbury 1A.1B,
2A.2B
3

4

79

44

880

140

45

20.5

45

55

Front Baghause WF 325 2.42/1 200,000 234,800 0.017 99.93 - 0.042
gr/acf
Front Baghouse WP 325 2.048/1 222,000 219,000 - 99.94 - 0.041

Front ESP Buell 300 292 415,000 405- 99.5 99- 2.8 ,, na7
415,000 99.4 2.6 ° M/
Front ESP Buell 315 299 600,000 550- 99.5 97 3.5
612,000 2.8 6
                                                                         (continued)

-------
                                                                TABLE 65  (continued)





Station
Brunner
Island
25 ppm
SO 3 injection


Montour

Boiler data



Boiler Size
No. MW
1 350



2 390

1&2 750
ea

Fuel consumption
tons/hr


Design Average
125



150

250
ea



Firing
method
Tang.



Tang.

Tang.






Primary Manuf .
2-ESPs Buell/
RC


2-ESPa Buell/
RC
ESP Joy




Outlet
Temp.
°F
325



300

290

Control



Critical* -
parameter
135



287

175

equipment data
Flow
rate,
acfm


Design
IxlO6 1



1.44x10* 1

2.26xl06 2






Test
.IxlO6



.3xl06

. 5xl06

Overall
efficiency,
percent


Design Test
99.5 80-98



99.5 99

99.5 90-
99.3



Velocity,
ft/sec
5-6



3.75

4.5-5.5




Particulate
emission rate
lb/106 Btu
0.6-2.0



0.086

0.05-0.9

                                                         PUBLIC SERVICE CO.  OF COLORADO, DENVER,  COLORADO0
Valmont

Comanche
Cherokee

Arapahoe
(S03 injection)
5 166 75 60 Tang.

2 350 217 185 Front
and
back
4 350 150 140 Tang.

1 44 30 25 Top
ESP/US

ESP
ESP/WS

ESP
RC/UOP

RC
RC/UOP

E
270
250
650
150

295
SCA - 89
L/C - 58
307
SCA " 135
L/C - 55
279
746,000
463,000

8 250°F )
1.63xl06
@ 295°F
1.182xl06
@ 180°F

2.75xl05 99.2
@ 295°F
7.5
97
9.2-12.5
98 5.2
99.6 9.2-12.5

99.7 2.75

0.04
0.04
0.04

0.028
N}
Ui
o
                                                     SALT RIVER PROJECT WATER & POWER DISTRICT,  PHOENIX, ARIZONA
Navajo 1

2

3

Hayden 2
750 326

750 326

750 326

268 131
279

280

286

130
Tang.

Tang.

Tang.

Tang.
ESP Joy 662 307 3.94xl06 4.3xl06 99.5 99.5 5.22 D 0.0504
5.69 A
ESP Joy 662 307 3.94xl06 4.3xl06 99.5 - 5.22 D 0.071
5.69 A
ESP Joy 662 307 3.94xl06 4.3xl06 99.5 - 5.22 D 0.0471
5.69 A
ESP WF 685 339 1.684xl06 1.6l9xl06 99.6 99.1 5.16 0.1-0.11
                                                                TAMPA ELECTRIC CO.,  TAMPA, FLORIDA
F . J . Gannon
6
5
414 151.4
239 93.4
98. 14 Opposed
71.2 Opposed
ESP
ESP
RC
RC
293
293
327
311
1.35xl06 1.35X106
820,000 820,000
99.8 99.84
99.78
4.9
5.14
0.029 gr/scf
0.029 gr/scf
                                                                           (continued)

-------
                                                             TABLE  65  (continued)
Station
Boiler data
Fuel consumption,
tons /hr
No. MW Design Average method
Control equipment data
Outlet
Temp.
Primary Manuf . °F
Flow
rate,
acfm
parameter Design Test
Overall
efficiency,
percent
Design Test ft/sec
Partlculate
emission rate
lb/106 Btu
                                                   TENNESSEE VALLEY AUTHORITY, CHATTANOOGA, TENNESSEE
Allen 1
Colbert 2
3
4
5
Cumberland 1
2
John Sevler 1
2
3
4
Johnsonvllle 1
2
3
4
5
6
7
8
9
10
Kingston 1
2
3
4
5
6
7
8
9
330 102
200 81
223 81
223 81
550 213.5
1300 540
1300 540
223 83
223 83
200 83
200 83
125 59
125 59
125 59
125 59
147 59
147 59
173 62
173 62
173 62
173 62
175 63
175 63
175 63
175 63
200 83
200 83
200 83
200 83
200 83
96
71
72
65
162
502
486
75
75
77
75
48
41
50
49
54
51
55
52
52
52
50
51
50
50
77
75
78
78
77
-
PCFR
PCFR
PCFR
PCOP
PCOP
PCOP
PCTA
PCTA
PCTA
PCTA
PCTA
PCTA
PCTA
PCTA
PCTA
PCTA
PCFR
PCFR
PCFR
PCFR
PCTA
PCTA
PCTA
PCTA
PCTA
PCTA
PCTA
PCTA
PCTA
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
"SP
ESP
ESP
ESP
ESP
ESP
ESP
2 ESPs
2 ESPs
2 ESFs
2 ESPs
2 ESPs
2 ESFs
2 ESPs
2 ESPs
2 ESPs
LC
LC
LC
LC
CE
Am. Std.
Am. Std.
LC
LC
LC
LC
AAF
AAF
^AAF
AAF
AAF
AAF
LC
LC
LC
LC
AAF
AAF
AAF
AAF
AAF
AAF
AAF
AAF
AAF
293 253.4 1.265xl06 IxlO6 99 98.1 4.73 0.05
352 196 906,000 810,000 97 99.4 5.1 0.06
360 199 906,000 797,000 97 99.0 5.0 0.096
351 203 906,000 780,000 97 99.1 4.9 0.088
289 387 2xl06 1.69xl06 99.5 99.2 3.9 0.08
290 170.3 4.7xl06 - 99 99.1 5.86 ' 0.12
290 170.3 4.7xl06 - 99 99.06 5.86 0.12
295 487 920,000 647,000 98.5 99.0 3.36 0.031
309 453 920,000 696,000 98.5 99.3 3.61 0.021
293 ' 488 920,000 645,000 98.5 99.1 3.35 0.0263
301 477 920,000 660,000 98.5 99.4 3.43 0.0088
349 276 478,000 461,000 99.2 99.4 4.9 0.04
296 264 478,000 481,000 99.2 99.8 5.1 0.01
329 264 478,000 482,000 99.2 99.7 5.1 0.03
329 246 478,000 516,000 99.2 99.7 5.4 0.03
310 282 478,000 451,000 99.2 99.7 4.8 0.03
338 269 478,000 472,000 99.2 99.5 5.0 0.03
294 220 525,000 505,000 98.5 96.9 5.5 0.18
293 204 525,000 543,000 98.5 98.7 5.9 0.06
306 201 525,000 553,000 98.5 98.3 6.0 0.05
283 202 525,000 550,000 98.5 96.7 6.0 0.07
325 476 500,000 - 99.2 - 4.2
307 438 500,000 544,000 99.2 - 4.5 0.027
310 439.5 500,000 542,000 99.2 - 4.5 0.019
325 476 500,000 - 99.2 - 4.2
340 439 700,000 723,000 99.2 - 4.5 0.012
313 489 700,000 650,000 99.2 - 4.0 0.017
325 418 700,000 760,000 99.2 - 4.7 0.015
313 445 700,000 714,000 99.2 - 4.4 0.012
287 512 700,000 620,000 99.2 - 3.9 0.01
to
Ui
H
                                                                   (continued)

-------
                                                                     TABLE  65  (.continued)


Station
Boiler data
Fuel consumption,
tons/hr
No. MW Design Average method

Outlet
Primary Manuf. °F
Control equipment data
Flow
rate,
acfm
parameter Design Test

Overall
efficiency,
percent
Design Test ft/sec

Particulate
lb/10b Btu
tn
N)
                                                              VIRGINIA ELECTRIC & POWER CO.,  RICHMOND, VIRGINIA
Bremo

Chesterfield
Mount Storm


3 69 30
4 185 55.8
6 693.9 233
1 570.24 215
2 570.24 215
3 522 214
21.43
55.89
171.5
199.97
208.7
188.9
Front
Front
Tang.
Tang.
Tang.
Tang.
ESP
ESP
ESP
ESP
ESP
ESP
Joy
Joy
RC
RC
RC
RC
630
612
-
255
275
-
274
287
176
350
350
108
617,300
980,000
1.93xl06
2xl06
2xl06
2,230,000
501,600 99.38 99.75
662,700 99.38 99.7
99.5
1,949,544 99.83 99.75
1,822,200 99.83 99.7
99.2
-
-
6
4.75-6.28
4.75-6.28
i6
0.022
0.022
0.04
0.025
0.045
0.113
 ESP - SCA -  ft2/1000 acfm
 Scrubber  - L/G - gal/1000 ft3
 Baghouse  - A/C • acfm/ft2 cloth

 Duke Power Co.  -
 Allen units  16.2 and Marshall units 1&2:  ESPs preceded by mech.  coll.
 Marshall  unit  2:  experimenting with Apollo additives

 Pennsylvania Power and Light -
 Holtwood: baghouse Installed in parallel with Chemico venturl scrubber
 Sunbury 1&2:  mech. coll. ahead of baghouse
 Sunbury 3&4:  new ESPs in parallel with exiating ESP/mech. coll.  (RC)
 Brunner Is.  1&2:  ESPs in parallel

 Public Service of Colorado -
 Valmont:   parallel arrangement

eTennessee Valley Authority -
 All ESPs  at  TVA (except  for those at Allen, Colbert, and Cumberland  stations)
 are installed  in series  with mech. coll.

Notes;  To convert  tons/hr to kg/sec, multiply by 1.8
        To convert  from °F to °C:  °C - 5/9 (°F - 32)
        To convert acfm to am3/min, multiply by 2.8317 x 10~2
        To convert ft/sec to cm/sec, multiply by 30.48
        To convert lb/106 Btu to ng/J, multiply by 430

-------
TABLE 66.  COAL ANALYSES FOR SOURCES LISTED IN TABLE 65
Company /station
TVA



Allen No. 1
Colbert



No.
No.
No.
No.
Cumberland


2
3
4
5
No. 1
No. 2
John Sevier No.






No.
No.
No.
Johnsonville No.









Kingston








PP&L









No.
No.
No.
No.
No.
No.
No.
No.
No.

No.
No.
No.
No.
No.
No.
No.
No.
No.
1
2
3
4
5
6
7
8
9







1
2
3
4
1
2
3
4
5
6
7
8
9
10










Holtwood
Sunbury No.

No.
1&2
3&4
Brunner Isl. No.


Mont our No.
No.
1&2


1
2
Average
heating value,
Btu/lb*

11
11
11
11
11
10
10
11
11
11
11
10
10
10

10

10
10
10
10
11
11
11

11
11
11
11
11

8
9
12

,180
,430
,470
,180
,420
,530
,480
,540 '
,470
,520
,520
,770
,760
,750
—
,730
-
,790
,780
,770
,760
,540
,580
,580
' —
,480
,480
,490
,550
,560

,000
,971
,250
11,000-13,000
11,000-13,000
11,000-12,500
Sulfur,
percent

3.
3.
4.
3.
4.
3.
3.
2.
2.
2.
2.
3.
3.
3.
3.
3.
3.
3.
3.
3.
3.
2.
2.
2.
2.
2.
2.
2.
2.
2.

0.
1.

3
9
0
9
0
8
8
1
2
2
2
2
1
1
1
1
1
1
1
1
1
3
2
2
3
2
2
3
3
3

7
9
1.8-2.5
1.0-3.0
1.0-3.0
1.0-2.5
Ash,
percent

11.4
15.4
15.5
15.6
15.4
17.2
17.2
14.3
14.6
14.2
14.2
15.3
15.4
15.5
15.6
15.2
15.3
15.3
15.4
15.3
15.4
16.6
16.4
16.4
16.5
16.7
16.7
16.5
16.4
16.5

20-35
23.2
11-15
10-25
10-25
12-25
Volatiles,
percent

35
34
34
34
34
33
33
33
33
33
33
32
33
33
33
33
33
33
33
33
33
31
32
32
31
31
31
31
31
31








.7
.6
.8
.7
.9
.2
.0
.0
.2
.1
.3
.9
.0
.0
.3
.6
.1
.2
.3
.2
.1
.6
.0
.0
.8
.4
.8
.5
.8
.9







Water,
percent

11.0
6.5
6.2
6.4
6.3
9.3
9.7
7.0
7.1
7.1
7.1
9.8
9.7
9.8
9.6
9.9
9.6
9.7
9.6
9.7
9.7
5.2
5.4
5.4
5.5
5.5
5.5
5.7
5.5
5.3

12-18
13.3
6-9
3-8
3-8
3-8
                       (continued)





                         253

-------
                            TABLE  66  (continued)
  Company/station
   Average
heating value,
   Btu/lb*
Sulfur,     Ash,   Volatiles,   Water,
percent   percent   percent    percent
Duke Power Co.
Allen
Belews Creek
Buck
Cliffside
Dan River
Lee
Marshall
Riverbend
VEPCO
Bremo
Chesterfield
Mt. Storm
Salt River Project
Navajo No. 1,2,6.3
Hayden No. 2

11,964
11,839
11,766
11,985
11,821
11,706
11,722
11,633

12,390
12,480
11,308

10,674
10,333

1.0
1.02
1.02
1.28
0.98
1.23
1.06
1.17

0.775
0.96
1.72

0.47
0.46

13.91
13.25
14.35
14.61 30.0
14.77
13.99
14.54 32.0
14.26 30.0

8.83
8.98
18.04

10.51 36.88
11.52 33.74

6.53
6.42
7.17
6.54
6.38
7.48
7.37
7.47

7.61
6.32
6.72

11.9
12.23
Cleveland Electric
  Ilium.  Co.

  Eastlake No. 5         11,595

American Elect. Power

  Amos No. 3             11,614
  Big Sandy No. 1        11,300
            No. 2        11,506
  Clinch R. No. 1,2,&3   11,900
  Gavin No. 1&2          10,100
  Glen Lyn No. 5&6       12,100
  Kanawha R. No. 1&2     11,500
  Tanners Creek No. 1&2  11,200

Consumer Power Co.
                    3.49
                   0.92
                   1.13
                   1.14
                   0.76
                   2.62
                   0.96
                   0.79
                   2.17
           13.49
           15.0
           13.18
           13.6
           15.9
           15.7
           15.7
           16.4
           14.3
33-45
30.0
  Kara No. 1&2           11,431          2.76      12.03      33-40
  J.R. Whiting No. 1.2&3 12,846          0.74      7.92      33-37
  Campbell No. 1&2       11,116          2.92      15.47      36-40
  Campbell No. 3         Designed for low sulfur Eastern  coal

Gulf Power Co.
7.18
6.8
9.1
7.4
6.1
6.1
5.3
6.2
9.1
                                                   8.64
                                                   5.94
                                                   7.38
Crist No. 4,5,6&7
Scholz No. 1&2
Lansing- Smith No. 1&2


11,970
12,233
11,595


3.2
2.7
1.1
(continued)
254
10.5
13.5
12.4


35.0
35.0
26.0


7.5
5.2
7.7



-------
                             TABLE 66 (continued)
Company /station
Tampa Electric Co.
F.J. Gannon No. 5&6
Public Service Co.
of Colorado
Arapahoe No. 1
Valmont No. 5
Comanche No. 2
Cherokee No. 4
Average
heating value,
Btu/lb*

12,500


10,700-11,400
10,300-11,000
7,900-8,700
10,700-11,400
Sulfur, Ash,
percent percent

1.3


0.35-0.55
0.5-0.8
0.25-0.45
0.35-0.55

8.0


8-12
6-11
4-6
8-12
Volatiles ,
percent

35.0


30-34
30-35
30-32
30-34
Water,
percent

8.0


7-11
10-15
26-30
7-11
*To convert Btu/lb to kJ/kg, multiply by 2.326
                                     255

-------
results show the varying degrees of collector performance encountered with




these fuels.  By combining Tables 16 and 65, there are sufficient data to




enable an improved appraisal of the capabilities of precipitators as particu-




late control devices for coal-fired boilers.




     Tables 17 and 22 presented information on facilities burning sub-




bituminous coals (lignites) that were controlled by ESP's and scrubbers,




respectively.




     Experience with ESFs used at power plants burning North Dakota lignites




has been generally satisfactory.  The reported ESP performance is attributed




partly to differences in coal properties wherein lignite has higher moisture




and soidum contents than most bituminous coals.  The principal operating prob-




blems with the above boilers relate to removal difficulties of fly ash from




hoppers caused by the caking tendencies of high sodium fly ash.2  It was




noted that for eight power stations (Table 17) providing complete emission




data, only two plants indicated emissions less than 13 ng/J (0.03 lb/106 Btu)




while six plants reported emissions less than 43 ng/J (0.1 lb/106 Btu).




     Data presented for wet scrubber installations have shown nominal recoveries




for particulate matter and incidental sulfur oxide removal.  Solids emissions




ranged from 32.25 to 172 ng/J (0.075 to 0.4 lb/106 Btu) with four out of seven




systems emitting less than 43 ng/J (0.1 lb/106 Btu).  Precipitation of calcium




sulfate and resultant scale formation has plagued some installations requiring




that these plants resort to dilution of recirculating liquor so as to remain




below the saturation level.  No additional data on the boilers tested were




available in the report.




     Table 20 provided performance data for 12 tests on utility and industrial




boilers controlled by fabric filters.  EPA Method 5 was used to rate the filters
                                     256

-------
on 7 of the systems.  Information on the test method for the remaining five



units was not available.




     In table 23, performance data were shown for three utility boilers con-




trolled by wet scrubbers.  Further information on these units can be found




in Tables 65 and 66.




     Due to the paucity of emissions data for particulate control by wet scrub-




bers, a survey of the particulate removal capabilities of flue gas desulfuriza-




tion (FGD) systems was undertaken; see Table 24.  This information was obtained




from a series of EPA reports and numerous follow-up telephone conversations




with the source operators.  Further data on the individual source test proce-




dures are not available although EPA participation would most likely indicate




that approved test methods were utilized.




     Test data presented in Table 25 summarize emission rates from coal-fired




boilers equipped with mechanical collectors.  These test data were obtained




by KVB, Inc. under a previous EPA study during which EPA test methods were




used for all gaseous and particulate sampling.  Only baseline (at least 80 per-




cent of full load) test data were reported in Table 25.  Although samples were




analyzed for total and solid particulate material, only solid particulate




emission levels were selected for listing in Table 25 to enable comparison




with any test data obtained by EPA Method 5.




7.3  EMISSION SOURCE TEST DATA FOR OIL-FIRED BOILERS




     In Table 26, test data for oil-fired boilers controlled by electrostatic




precipitators were presented.  This information, deriving from a previous GCA




study, was based upon emissions compliance tests performed by GCA/Technology




Division and stack test data provided by the Massachusetts Bureau of Air




Quality Control.3  Therefore, although not specified directly, all emissions
                                      257

-------
data were based upon EPA Method 5 sampling since all data accepted and re-




ported by the state agency must be obtained by appropriate EPA reference




methods.  Similarly, all GCA compliance testing is performed by EPA methods.




     Table 27 indicated performance of a magnesium oxide scrubbing system




previously installed at Boston Edison's Mystic Station - Boiler No. 6.  (The




scrubber has since been dismantled.)  These data showed that particulate re-




movals of 45 to 70 percent could be obtained even though the system had been




designed solely for sulfur oxide removal.  Since the rated capacity of boiler




No. 6, Table 27, was approximately 160 MWe, all tests were run with the




boiler operating at greater than 90 percent load.  It should be noted from




Table 27 that the average inlet particulate loadings, 90.3 ng/J (0.21 lb/106




Btu) were at the high end of the range given previously in Table 12 for un-




controlled residual oil-fired boilers; 16.6 to 154.6 ng/J (0.0385 to 0.3596




lb/106 Btu).  The higher levels are attributed to the use of the magnesium




oxide additive.  The outlet dust concentrations were also high, probably due




to the low (1 kPa or 4 in. W.C.) pressure drop across the scrubber.  An in-




crease in the pressure drop would be expected to provide increased particulate




removal.  The above tests, which were performed for the Massachusetts state




agency, utilized EPA sampling methods.




7.4  SUPPLEMENTAL TEST DATA




     During the preparation of this document, additional test data have been




obtained by subcontract* and from EPA's Office of Air Quality Planning and




Standards (OAQPS).  Table 67 presents source test data (controlled and un-




controlled) obtained from the Indiana, Maryland, Pennsylvania, and West Vir-




ginia state agencies and from a testing program conducted by the American
  Contract No. 1-614-029-222.
                                     258

-------
S3
             TABLE 67.  SUPPLEMENTAL PARTI.CULATE EMISSIONS TEST DATA FOR CONTROLLED AND UNCONTROLLED
                        FOSSIL  FUEL BOILERS
Facility,
name,
location
and code No.
(test date)
Central State
Hospital
Indianapolis, IN



(12/72)
1.

2. (8/75)
Richmond State
Hospital
Richmond, IN




(8/75)
3.
Boiler type
and heat
Input capacity
MW Control
(106 Btu/hr) equipment


Erie City Boiler
w/Laclede
Traveling Grate
Stoker
23.4 None
(80)
Same unit None



Henry Vogt
boiler
w/Laclede
Traveling Grate
Stoker
20.5 None
(70)
Test

Flow
rate
m'/min
(acfra)






2,538
(89,623)
1,018
(35,953)







1,384
(48,887)
conditions

Heat
°C *•**£* methoc
( F) (106 Btu/hr)






254 22.3
(490) (76) EPA-5
134 14.6
(274) (50) EPA-5







176 19
(349) (65) EPA-5
Test

Run Run
results

Run
1 2 3
ng/J







606.3 235.6
(1.41) (0.548)
165.1 151.8
(0.384) (0.353)







213.3 302.3
(0.496) (0.703)






198.7
(0.462)
142.8
(0.332)







267.9
(0.623)
Fuel analysis

Average
Sulfur Ash content
% 7. kJ/kg
(Btu/lb)






348.3 25,728
(0.81) 2.96 11.1 (11,061)
153.5 25,884
(0.357) 2.16 12.8 (11,128)







261 26,879
(0.607) 2.38 9.9 (11,556)
                                                           (continued)

-------
                                                   TABLE 67  (continued)
N>
O>
O
Facility,


location
and code No.
(test date)


Muscatatuck
State Hospital
Muscatatuck, IN



(8/75)
4.
Madison State
HpspUal
Madison, IN



(8/75)
5.
Evansville State
Hospital
Evansville, IN


(8/75)
6.
Boiler type Test <°"dill°"»


input capacity Flow Heat - Run
MV; Control rate T§™p' input *"" 1
(1U- Btu/hrj equipment raVmin o^. MW mecnoa




Keeler Boiler
w/Laclede
Traveling Grate
Stoker
25.2 None 996 212 16.7 EPA-5 283.8
(86) (35,180) (413) (57) (0.66)


Keeler Boiler
w/Laclede
Traveling Grate
Stoker
17-& None 1,105 154 13.9 EPA-5 224.9
(&0) (39,013) (309) (47.5) (0.523)


Laclede
Traveling
Crate Stoker '
U.I None 1,068 163 - 9.1 EPA-5 307.5
(38) (37,733) (325) (31) (0.715)
Test results


Run Run Average
2 3 Heat
,. Sulfur Ash content
fit fir$ T)I- ^ A. KJ/KK
(Btu/lb)






227.9 163.4 223.6 24,281
(0.53) (0.38) (0.52) 1.92 13.8 (10,439)






359.5 311.8 298.9 24,881
(0.837) (0.725) (0.695) - 8.85 (10,697)





194,4 191.8 231.3 23.493
(0.452) (0.446) (0.538) - 12.1 (10,100)
                                                              (continued)

-------
                                                     TABLE 67  (continued)
to
Facility,
name,
location
and code No.
(test date)
Norman Beatty
Hospital
Westville, IN
(8/75)
7.
Loganaport State
Hospital
Logansport, IN
(9/75)
8.
Lafayette
Soldiers Home
Lafayette, IN
(9/75)
9.
... , Test conditions
Boiler type
and heat 	
input capacity Flow Heat _ Run
MW Control rate Temp. input e? . 1
(106 Btu/hr) equipment m3/min Oc MH method


27.8 None 1,547 187 19.4 167.7
(95) (54,617) (368) (66.3) EPA-5 (0.39)

B&W Boiler
w/Laclede
Traveling
Grate Stoker
27 None 1,725 128 11.4 EPA-5 163.4
(92) (60,933) (263) (39) (0.38)
Keeler Boiler
w/Laclede
Traveling
Grate Stoker
12.9 None 530 134 7.3 EPA-5 107.5
(44) (18,717) (274) (25) (0.25)
Test results Fuel analysis

Run Run Average „
2 3 Heac
,j Sulfur Ash content
(Btu/lb)

253,3 200.8 207.3 24,493
(0.589) (0.467) (0.482) - 12.9 (10,530)


232.2 189.2 193.5 20,950
(0.54) (0.44) (0.45) - 17.4 (9,007)

202.1 154.8 154.8 24,311
(0.47) (0.36) (0.36) - 10.9 (10,452)
                                                              (continued)

-------
TABLE 67 (continued)
Facility,
name,
location
and code No.
(test date)

Slippery Rock
State College
Slippery Rock, PA
(6/78)
10.
Rockville State
Correctional Inst.
Rock view, PA
(3/77)
11.
Ashland State
General Hospital
Ashland, PA
12.(3/7?)
_ ., Test conditions
Boiler type
and heat 	
input capacity Flow Heat _ Run
MK Control rate T§";p> input mlthod 1
(10e Btu/hr) equipment m3/min o*. MW



B&W Boiler
w/Single Retort
Stoker
9.7 None 591 194 5.9 EPA-5 304.9
(33) (20,888) (382) .(20) (0.709)

Keeler Boiler
w/Multiple
Retort Stoker
12.9 None 9.1 EPA-5
(44) " ' (31)

Keeler An-
thracite
Boiler
w/Slngle
Retort Stoker
3.5 None - - 2.1 EPA-5
(12) (7)
Test results ^ analysls

Run Run Average
., Sulfur Ash content
"F X f kJ/ke
Aii,/if\K ntn^ , , •> * RJ/KK
(lb/10 Dtu) • (Btu/lb)


31,401
1.3 11.0 (13,500)

382.7 • 32,015
(0.89) 1.35 10.35 (13,764)

94.6 29,405
(0.22) 0.57 12.6 (12,642)
           (continued)

-------
                                                                 TABLE 67  (continued)
             Facility,
               name,
             location
            and code  No.
            (test date)
                    Boiler type
                      and heat
                   input capacity
                         MU
                    (106 Btu/hr)
                                                            Test conditions
                                                                                                          Test results
                                                                                            Fuel analysis
 Control
equipment
 Flow
 rate
m3/min
(acfm)
Temp.
 °C
    Heat
   Input
     MU
(106 Btu/hr)
 Test
method
                                                   Run
                                                    1
Run       Run
 2         3
     ng/J
(lb/106 Btu) -
                                                         Average
               Heat
Sulfur  Ash   content
  %      %     kJ/kg
              (Btu/lb)
to
(^
10
        Holidaysburg
        Veterans Home
          Holidaysburg, PA
                   Keeler CP
                   Boiler w/multiple
                   Retort Stoker
   (1/78)
                               12
                                           None
13.
        Ebensburg State
                              8.2
                              (28)
                                                                                    EPA-5
                                                                  219.3
                                                                  (0.51)
                                                                                                                            0.88
                                                                                 29,905
                                                                          13.0  (12,857)
School & Hospital
Ebensburg, PA
(3/77)
14.
PPG Industries
Cumberland, MD
(5/72)
15.
Keeler CP
Boiler w/Detroit
Vlbragrate
Stoker
11.7 None
(40)
CE Boiler
w/Travellng
Grate Stoker
13.2 None
(45)

6.2 EPA-5 - - ' 154.8 30,122
(21) (0.36) 1.76 13.7 (12,950)

5.9 EPA-5 103.2 103,2 98.9 101.9 27,912
(20) (0.24) (0.24) (0.23) (0.237) 1.0 12.0 (12,000)
                                                                               (continued)

-------
                                                    TABLE  67  (continued)
NJ
Facility,
name,
location
and code No.
(test date)

Greenbrier Hotel
White Sulphur
Springs, W.Va.
(9/76)
16.
Indiana State
Prison
Michigan City, IN
(8/75)
17.
(10/75)
18.
State Correctional
Institution
Huntingdon, PA
(4/78)
19.
„ ., Test conditions
Boiler type
and In.1 at
input capacity Flow Heat .
MW Control rate o™"' input ^^
( 1U' iHn/lir equipment m /mJn /°c\ ""


Detroit
Multiple-Retort
Stoker
16.4 None 853 228 14.7 EPA-5
(56) (30,139) (442) (50)

Keeler
Boiler w/Laclede
Traveling Grate
Stoker
10.8 MC - 282 7.9 EPA-5
(37) (539) (27)
Same MC 454 226 7.6 EPA-5
(16,043) (438) (26)

Keeler CP Boil-
er w/Detroit
Multiple Retort
Stoker
MC 606 287
(21,400) (549)
Test results _ , ,

Run Run Run Average
« o T ' Heat
1 no/! Sulfur Ash content
».!!c ~ * % % kJ/ke
(Btti/lb)

364.2 122.6 211.6 232.6 33,143
(0.847) (0.285) (0.492) (0.541) 0.88 3.1 (14,249)

645 731 1075 817 - '22,290
(1.5) (1.7) (2.5) (1.9) 13.6 (9,583)
150.5 137.6 137.6 141.9 22,483
(0.35) (0.32) (0.32) (0.33) 2.56 7.7 (9,666)

196.1 30.703
(0.456) 3.0 13.0 (13,200)
                                                              (continued)

-------
                                                   TABLE 67  (continued)
N>
Facility,
name,
location
and code No.
(test date)
Indiana University
of Pennsylvania
Indiana, FA
(6/78)
20.
State Correctional
Institution
Pittsburgh, PA
(7/78)
21.
ABMA Program
Test Site C
(4/78)
22.
23.
Boiler type Te8t co"dlti°«V Test results
and heat 	 __
input capacity Flow Heat T f Run Run Run
MW Control rate *$"?" input _ ff . 123
U0f Btu/hr) equipment ra3/min OL MW ™ecnoa /}

Union Boiler
w/Detrolt
Vlbragrate
Stoker
8.8 MC 379 250 5.6 EPA-5 -
(30) (13,395) (482) (19)
Keeler Boiler
w/Traveling
Grate Stoker
7.9 MC 397 263 5.6 EPA-5
(27) (14,021) (505) (19) -
B&W Boiler
w/Detroit Roto-
grate Stoker
73 MC - - - EPA-5 Boiler 2589-15,661
(249) outlet (6.02-36.42)
MC 153.1-461
outlet (0.356-1.072)
Fuel analysis
Average Hea(.
Sulfur Ash content
% % kJ/kg
(Btti/lb)
220.2 30,703
(0.512) 1.4 13.0 (13,200)
185.3 31,634
(0.431) 1.6 8.5 (13,600)
19,745-
28,517
0.7- 9.0- (8,490-
2.9 11.2 12,260)
                                                             (continued)

-------
TABLE 67 (continued)
Facility,
name,
location
and code No.
(test date)
ABMA Program (Cont
Test Site D



24.
(7/78)
25.

Test Site E
(11/78)
26.

27.
Monsanto Co.
Nitro, W.Va.

(7/75)
28.
Boiler type
and heat
Input capacity
MK Control
(106 Btu/hr) equipment
'd)

B&W Boiler
w/Detroit
Vlbragrate
Stoker

26.4 MC
(90)


Riley Boiler
w/Spreader "L
Stoker
52 8
(180)

Spreader MC &
Stoker ESP
/ / in
44 .
(150) senea
Test condition, TeBt result§
Flow _ Heat _ .. Run Run Run Average
"« SCP' '"IT -'nod 1 2 ., 3
m3/mln ,0:;. MW na/J





302.7 - 477.3
Boiler outlet (0.704 - 1.11)
- - - EPA-5 139.8 - 326.8
MC outlet - (0.325 - 0./6)


- - - EPA-5 1299 2180 2713 2064
(3.02) (5.07) (6.31; (4.8)
137.2 91.6 114.4 114.4
(0.319) (0.213) (0.266) (0.266)



44 EPA-5 5.2 4.3 3.4 4.3
(150) (0.012) (0.01) (0.008) (0.01)
Fuel analysis
Heat
Sulfur Ash content
X Z kJ/kg
(Btu/lb)





29,773-
0.8- 6.85- 31,634)
2.65 8.0 (12,800-
13,600)


32,120
1.0 4.48 (13,809)



26,468
0.57 11.4 (11,379)
           (continued)

-------
                                                      TABLE 67  (continued)
N>
C^
-vl
Facility, Boiler type
name , and heat
Test conditions

location input capacity Flow Heat T f Run
and code Ko. MW Control rate TS™P' input np7v!n,t X
(test date) (io6 Btu/hr) equipment ra3/min .Op. MW
y--«_\ \ «* ) /irtfi «^__/i-_\ . —

ABMA Program
Test Site B
Rlley Boiler
w/Spreader
Stoker
(11/77) 75
29. (257)

30.

31.
Joseph E Seagram's
& Sons, Inc.
Baltimore, MD B&W Boiler

(3/77) 22
32. (75)
ABMA Program
Test Site A
Foster-Wheeler
Boiler w/De-
troit Spreader
Stoker
'(8/77) 98
34, (333)

35.



MC & ESP
In Series

- - - EPA-5 4876
(11.34 -
248.5
(0.578 -
8.6
(0.02 -


MC & ESP
in Series
22 EPA-5 60.2
(75) (0.14)


MC, ESP &
SOz Scrubber
in Series 6201
(14.42 -
64.5 EPA-5 275.2
(220) (0.64 -
64,8 EPA-5 7.1
(221) (0.0166)
Test
Run
2
n







Average of

Average of

Average of




34.4
(0.08)





Average of

Average of
8.3
(0.0194)
results
Run Average
3
I'3







22 Readings)

18 Readings)

2 Readings)




50.3 48.2
(0.117) (0.112)





13 tests)

8 tests)
24.8 13.4
(0.0576) (0.0312)
Fuel analysis
Heat
Sulfur Ash content
% % kJ/kg
(Btu/lb)





30
0.85 8.0 (13
30
0.85 8.0 (13
30
0.85 8.0 (J3




28
9.3 (12




24
0.5 5.7 <10
24
0.93 6.1 (10
24
0.65 5/8 (10





,761
,225)
,761
,225)
,761
,225)




,145
,100)




,531
,469)
,532
,547)
,411
,495)
                                                                  (continued)

-------
                                                TABLE 67 (continued)
CO
Facility, Boiler type

name. and heat
location input capacity
and code No. MW
(test date) (106 Htu/hr)

Control
equipment
Test conditions



Flow Temp. H*8t Test
rate Brr input __m_,
3 . . C ;-, metnO(
ra /mm f°p^ ™
(acfm) (106 Btu/hr)
Test results Fuel analyals

Run Run Run Average „ ..
123
1 ,j Sulfur Ash content
• (lb/10 Btu) • (Btu/lb)
ABMA Program (Cont'd)
Test Site A
(8/77)
36.
Test Site X
Kewanee Boiler
w/Canton Under-
feed Stoker
(11/77) 1.5 FF
37. <5)
Notes
1.
2.
3.
4.
5.
6.

11.
12.
13.
14.
15.
;
Sampling in breeching
Sampling in stack
Sampling in stack
Sampling in stack
Sampling in stack
Ash buildup the cause of
high results in Run 1
Sampling in' breeching
Sampling in breeching
Sampling in breeching
Sampling in breeching
Sampling in stack

16.
17.
18.
20.
21.
22.
23.
24.
25.
26.
27.

53
(181)
1.5
(5)

Sampling breeching
Collector not operating
Collector operating
Collector outlet'
Collector outlet
Collector inlet
Collector outlet
Collector inlet
Collector outlet
Collector inlet
Collector outlet

EPA-5
EPA-5

28.
29.
30.
31.
32.
33.
34.
35.
36.
37.


5.5 24,258
(0.0128) - 0.78 4.8 (10,429)
533.2 455.8 339.7 442.9 26,991
(1.24) (1.06) (0.79) (1.03) 0.6 6.3 (11,604)

Sampling in stack
Boiler outlet
MC outlet
Downstream of ESP & MC
Sampling in stack
Boiler outlet
MC outlet
ESP outlet '
Sampling in stack
Collector inlet



-------
Boiler Manufacturers' Association (ABMA).  Data given for uncontrolled boilers




or collector inlet tests can be used to  supplement the uncontrolled data




presented previously in Table 12.  Data  for controlled boilers are mainly for




mechanical collectors and indicate the difficulty in achieving emissions less




than the moderate level with this type of control.




     Worthy of note is test number 28, which shows the performance for a




mechanical collector and electrostatic precipitator in series installed on a




spreader stoker boiler.  The test results showed an average outlet emission-




rate of 4.3 ng/J (0.01 lb/106 Btu).  Other results (Tests 31 and 32) for the




same collector arrangement show average  emission rates of 8.6 ng/J (0.02




lb/106 Btu) and 48.2 ng/J (0.112 lb/106  Btu), respectively.




     Emission source test data obtained  from OAQPS is presented in Table 68.




These data show a variety of collector combinations and emission results.




     Comments concerning all tests in each of these tables are indicated at




the end of each table and are identified by the test code number.
                                      269

-------
TABLE 68.  SUPPLEMENTAL PARTICULATE EMISSIONS TEST DATA FOR CONTROLLED FOSSIL FUEL BOILERS


E.I
Facility,
naae,
location
and code No.
(test date)
. DuPont
Parkersburg, W.Va
Boiler type Te" condltlOT»
and heat .
Input capacity Flow
MK Control rate *er8~
(106 Btu/hr) equipment m?/min C]J£
(acfm) ^OFJ

4-Spreader 4-Unlts

Heat
Input
MH
(10s Btu/hrl



Te«t *?"
meth-
od



Test results


Run Run
2 3
ng/J







Average



Fuel analysis
Heat
Sulfur Ash content
it X kJ/kg
(Btu/lb)


Washington Works stokers equipped

1.



2.

3.

4.

(3/76)



(3/76)

(11/75)

(12/75)
18.7 ""k miti~ 163
(64) gSSSby ' (325)
fabric
filters
36.6
(125)
53
(181)
70.6
160
(320)
188
(370)
182
(241) * - (360)
19-20
(64-67)


35-36
(121-122)
59-60
(200-205)
76-78
(261-266)
8.0
EPA-5 (0.0187)


4.3
EPA-5 (0.01)
49.9
EPA-5 (0.116)
27.5
EPA-5 (0.064)
6.5
(0.0151)


3.4
(0.008)
14.2
(0.033)
7.0
(0.0163)
3.9
(0.009)


2.3
(0.0053)
6.5
(0.015)
17.1
(0.0398)
6.1
(0.0143)


3.4
(0.0078)
23.7
(0.055)
17.2
(0.04)
31,365
2.8 7.0 (13,500)


32,295
3.0 7.0 (13,900)
32,295
3.0 6.9 (13,900)
32,062
3.0 7.7 (13,800)
                                            (continued)

-------
                                                     TABLE 68  (continued)
S3

Facility, Boiler
nane , and
type
heat
Test

location input capacity Flow
and code No. MW Control rate
(test date) (106 Btu/hr) equipment m3/min
(acfia)
conditions
Tern-

p«a- Heat
input
ture |£J
(op) (lo6 Btu/hr)

_ Run
Test j^
meth-

Teat

Run
2
n

results

Run
3





Average


Fuel analysis
Heat
Sulfur Ash content
Z Z kJ/kg
(Btu/lb)
Duke Oniveraity
Durham, N.C. 2-Spreader
West Campus stokers
26.4 MC 770
5.
(7/75) (90) (27
,200)
22 MC 623
6.

7.


8.


9.
J.
(7/75) (75) (22
,000)
110
(230)
157
(3*5)
10-13
(33-45)
6-11
(20-38)
5268
EPA-5 (12.25)
417
EPA-5 (0.97)
959
C2.23)
464
(1.08)
1871
(4.35)
598
(1.39)
2700
(6

(1
.28)
495
.15)
not available

not available
Spreader
Stoker MC 750

(10/75)


(4/76)

P. Stevens & Co.
(26
1
MC (42

1
MC (47

,500)
,206
,600)

,356
,900)

166
(330)
121
(250)

123
(253)

16
(56)
20
(69)

26
(90)

396
EPA-5 (0.92)
9,297
EPA-5 (21.62)
omit
77.4
EPA-5 (0.18)

783
(1.82)
748
(1.74)

137.6
(0.32)


-
254
(0.59)

90.3
(0.21)


(1

(1

589
-37)
501
• 1£5)



not available


103.2
to

.24)

not available

Roanoke Rapids, N.C.



10
Koaeoarie
Plant No. 1
Erie




Cltv 484
. (4/74) Boiler - («
,100)


150
(302)



-


214.6
EPA-5 (0.499)


241.2
(0.561)








228
—
(0
.53)
not available
                                                                  (continued)

-------
                                                      TABLE 68  (continued)
NJ
-J
S3
Facility,
locat Ion
and code No.
(test date)
The Great Western
Sugar Co.
Denver, Colo.
Boiler type

Test

input capacity Flow
MW Control rate
(10* Btu/hr) eq-


Coal-fired Koch
Ipment n'/mln
(acfn)



conditions

Tem-
pera-
ture
DC




in"t Test T





Test result*
Run Run
2 3
ng/J





Average





Fuel analysis

Heat
Sulfur Ash content
Z Z kJ/kg
(Btu/lb)
'


boiler • Venturl
11.

(12/74)

12.
13. (10/75)
Caterpillar
Tractor Co.
Moasvllle, Illinois
scrubber . ...







2-Detroit FGD
(54,500)

1,410
(49,800)
3,228
(114,000)



47
(116)

41
(106)
49
C120)



39 28
(134) EPA-5 (0.065)

40
(138) EPA-5
54 45.6
(185) EPA-5 (0.106)



28
(0.065)


-
46 80.4
(0.107) (0.187)



28
(0.065)

40
(0.093)
57.3
(0.133)



23,373
10,54 (10,060)

29,927
8.52 (12,881)
23,215
(9,992)



spreader scrubber

14 (1-2/77)

13.
stokers
23
(80)
44 FGD

—
_
(150) scrubber

76
(169)
92
(197)

23 55.5
(80) EPA-5 (0.129)
31 67.6
(105) EPA-5 (0.1572)

42 37.1
(0.0977) (0.0862)
69.7 86
(0.1622) (0.1999)

44.8
(0.1043)
74.4
(0.1731)

23,419
3.0 9.23 (10,080)
22,536
2.9 8.95 (9,700)
                                                                 (continued)

-------
TABLE 68 (continued)
Facility,
name,
location
and code No.
(teat date)
Mossville, Illinois
(Cont'd)
16.
Jolliet, Illinois
(4/77)
Boiler type
and heat
Test conditions
T*M._

Input capacity Flow "™~ Heat
MW Control rate P«»- lnput
(106 Btu/hr) equipment m3/mln ™* MM
(acfm) (0pj (106 Btu/hr

44 FCD

85
(150) scrubber (185)

2-Spreader Both

have

44
(150)



_ Run
Test .
neth- 1
\ od


38.3
EPA- 5 (0.089)


Test results


Run Run
2 3
ng/J


46.1
(0.1073)




47.5
(0.1105)



Average


44
(0.1023)


Fuel analysi

s

Heat
Sulfur Ash content
t % kJ/kg
(Btu/lb)

22,
2.88 8.28 (9.



627
825)


stokers mechanical
collectors
17.

18.
Hossvllle, Illinois
19.
plus wet _ 52
(80) scrubbers (12J)
29
(100)
Detroit FGD
54
(130)
209
spreader scrubber (409)
21
(70)
26
(90)
23
(80)
58.1
EPA-5 (0.135)
120
EPA-5 (0.279)
2679
EPA-5 (6.23)
93.3
(0.231)
86.9
(0.202)
2967
(6.90)
88.6
(0.206)

-
2980
(6.93)
82.1
(0.191)
103.6
(0.241)
2877
16.69)
29
2.8 12.0 (12
29
2,8 12.5 (12
23
2.86 8.8 (10
,042
,500)
,623
,750)
,524
,125)
stoker (Venturl)

20. (10/76)

21.

22.

23.

24.
23
(80)








70
(158)
198
(388)
77
(171)
179
* (354)
88
(191)
23
(80)
16
(56)
16
(56)
8
(28)
8
(28)
50.4
EPA-5 (0.1173)
2404
EPA-5 (5.59)
58.1
EPA-5 (0.135)
2176
EPA-5 (5.06)
53.8
EPA-5 (0.125)
37.3
(0.0868)
2434
C5.66J
56.8
(0.132)
2137
(4.97)
42.3
(0.0984)
62.5
(0.1453)
2709
C6.30)
63.2
(0.1471
1621
C3.77)
60.7
(0.1411)
50.1
CO. 1165)
2516
(5.85)
59.3
(0.138)
1978
(4.60)
52.2
(0.1215)
23
2.86 8.8 (10
23
2.9 8.3 (9,
23
,524
,125)
,187
980)
,187
2.9 8.3 (9,980)
23
2.8 9.6 (10
23
2.8 9.6 (10
,426
,083)
.426
,083)
          (continued)

-------
                                                TABLE  68 (continued)
NS
•sj
Facility, Boiler type
name, and heat
location Input capacity
and code Ho. MW
(test date) (10* Btu/hr)
Decatur, Illinois

25. (4/77)*

26.
City Utilities of
Springfield , Mo.
Southwest Pulverized
Power Station coal
512
27. (9/77) (1747)

28.

29.
Tennessee-
Eastaan Co.
P.O. Box 511 Stoker-
Klngsport, TN fired
63
30. (6/76) (215)
Test
Flow
Control rate
equipment m3/min
(acfm)

Fabric 9f>Q
filter (33,900)
881
(31,100)


ESP &
FGD
scrubber ^^
(469,333)
ESP 18,487
(652,850)
ESP 19,131
(675,600)




2,222
ESP (78,473)
conditions
Tem-
pera-
ture
oc
<°F)

165
(329)
162
(324)




56
(132)
135
(275)
154
(309)




152
(305)
Heat
input
«W
(106 Btu/hr)


-

-




499
(1702)
499
(1702)
499
(1702)




42
(142)
Test
meth-
od


EFA-5

EPA-5





EPA-5
ASME
No. 27
ASME
No. 27





EPA-5
Run
1


18.1
(0.042)
12.9
(0.03)




8.6
(0.0201)
3006
(6.99)
8.7
(0,0203)




43.9
(0.102)
Teat result*
Run Run
2 3
ng/J


28.4 9.9
(0.066) (0.023)
21.1 22.8
(0.049) (0.053)




6.1 9.0
(0.0141) (0.0209)
3281
(7.63)
7.1
(0.0165)




40.8 21.1
(0.095) (0.049)
Fuel analysis
Average
Sulfur Ash
« * *


18.9
(0.044) 2.0 11.7
18.9
(0.044) 1.8 8.8




7.9
(0.0184) 3.56 14.1
3143
(7.31) 3.56 14.1
7.9
(0.0184) 3.56 14.1




35.3
(0.082) 0.94 9.1
Heat
content
kJ/kg
(Btu/lb)

29,685
(12,777)
29,713
(12,789)




29,634
(12,755)
29,634
(12,755)
29,634
(12,755)




30,064
(12,940)
(continued)

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                                                  TABLE 68  (continued)
N3
-»J
Ln
Facility,
name,
Boiler typ
and heat
Test

location input capacity Flow
and code No. HW Control rate
(test date) (10* Btu/hr) equipment m'/min


Adolph COOFE
Golden, CO
31. (6/77)
Test
Notes
1.
2.
3.
4.
5.

6.

7.
8.
9.
10.



Co.


Pulverized
coal
73
(250)
results given as -
metric units: mg/dsm3
Boiler No. 2
Boiler
Boiler
Boiler
Boiler
Grates
Boiler
Runs 1
Boiler
Boiler
Boiler
No. 4
No. 5
No. 6
No. 2 -
cleaned
No. 3 -
and 2
No. 2 -
No. 2-
No. 2 -



Old Stack


Fabric 4,814
filter (170,000)
(English units) : gr/r'tcf



- Fly Ash Reinjectlon -
between Runs 1 and 2
New Stack

Collector
Collector
Collector
- Crates cleaned between

Inlet
Outlet
Outlet
Sampling in breeching








conditions


p«a- Heat
' input
ture £.,
oc r


179
(355)
11.
12.
13.

14.
15.
16.
17.
18,
19.
20.
21.





Test results


Run Run Run
123






73 EPA-5 14.4 13.6 18.4
(250) EPA-17 (0.0336) (0.0316) (0.0428)
Banna (Rosebud)
Lisbon coal
Runs 1 and 2 -
Run 3 - AP - 0.
Boiler No. 1 -
Boiler No. 4 -
Boiler No. 4 -
Boiler No. 2
Boiler No. 3
Scrubber Inlet
Scrubber Outlet
Scrubber Inlet


coal

iP -

1.24 kPa (5 in.W.C.)
22.

23.
75 kPa (3 in. W.C.)
Avg.
Avg.
Avg.


- AP

- AP


iP - 5 kPa (20 in.W.C.)
AP - 5.4 kPa (21.8 in.W.C.)
AP - 6.4 kPa (25.7 in.W.C.)


- 5.1 kPa (20.3 in.W.C.)

- 5 kPa (20 in.W.C.)


24.

25.
26.
27.
28.
29.
30.
31.



Average
Sulfur Ash


15.5
(0.036) 0.53 10.2
Scrubber Outlet - AP -
(20 In.W.C.)
Scrubber Inlet - AP » 3
(15.2 In.W.C.)
Scrubber Outlet - AP -
(15.2 In.W.C.)
Pulse-jet cleaning
Reverse Air Cleaning
rsis
Heat
content
kJ/kg
(Btu/lb)

25,650
(11,040)
5 kPa

.8 kPa

3.8 kPa



Downstream of both collectors
ESP inlet
ESP outlet
Boiler No. 21
Boiler Ho. 4 - In-stack
out-of-stack



plus


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7.5  TEST METHODS

     Most of the test data presented in Section 2.0 were developed under EPA

contracts using approved EPA sampling methods; i.e., Methods 1 through 5 for

particulate materials as originally published in the Federal Register -

Thursday, December 23, 1971, Volume 36, No.  247 - "Standards of Performance

for New Stationary Sources."  These methods  are listed as follows:

     Method 1 - Sample and Velocity Traverses for Stationary Sources

     Method 2 - Determination of Stack Gas Velocity and Volumetric
                Flow Rate (Type S Pitot Tube)

     Method 3 - Gas Analysis for Carbon Dioxide, Excess Air, and Dry
                Molecular Weight

     Method 4 - Determination of Moisture in Stack Gases

     Method 5 - Determination of Particulate Emissions from Stationary
                Sources.

     Particulate sampling by these EPA reference methods requires that, if at

all possible, the sampling site be located at least eight duct diameters

downstream and two duct diameters upstream from any flow disturbance or per-

turbation.  When these conditions are met, the minimum number of traverse

points would be 12.  However, deviations from these conditions are often en-

countered that usually require several additional sampling points.  Additional

sampling criteria are that the minimum sampling time be 1 to 2 hours and that

the minimum sample volume be 0.85 m3 (30 ft3) per run when corrected to stan-

dard conditions on a dry basis.  Appropriate meter readings, temperatures, pres-

sures, and other relevant information are to be recorded every 5 minutes.

Test results are deemed acceptable when sampling is carried out between 90 and

110 percent of isokinetic flow.  Isokinetic  sampling prevails when the average

velocity of the gas sample entering the probe is equal to the local duct

velocity.

                                     276

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     Adherence to Methods 1 through 5 results in a stack test which is well




documented, representative, and usually repeatable since the same procedures




and analyses are used each time a test is performed.  However, special pre-




cautions must be taken to guarantee complete recovery of any particulate




material that deposits in the upstream section of the sampling train.  It




should also be recognized that the presence of high SOX concentrations coupled




with a condensing atmosphere can cause artificially high particulate accumula-




tions on dry filter media because of added moisture.




     Although the original Method 5 specified that the sampling filter located




outside the duct be maintained at a minimum temperature of 121°C (250°F - 25°F)




a more recent EPA revision of August 1977 allows the collection temperature to




range up to 160°C (320°F).  This change allows the "in-stack" Method 17 par-




ticulate sampling method discussed in the 24 September 1976 Federal Register




(41FR42020) to be used interchangeably with Method 5.  It is specified that




 Method 17 is an acceptable procedure for sampling combustion effluents pro-




vided that the stack temperature does not exceed 160°C (320°F).  The method




is not considered acceptable for higher flue gas temperatures because of the




possibility that certain combustion products that might condense as particu-




late material at 160°C (320°F) may penetrate the filter media.




     A major advantage of Method 17 is that it eliminates the difficult and




potentially error-producing probe washing step which is an integral part of




Method 5.  Method 17 actually evolves from a sampling technique described origi-




nally in the ASME Power Test Code No. 21 of 1941.k  The above method was later




modified at Harvard University by substituting high efficiency all-glass thimbles




for the porous, rigid ceramic thimbles suggested by ASME.  Use of the all-glass




thimble was described by Dennis (1952)5 et al., and more recently in a memorandum




from Dennis submitted to the State of Massachusetts in August 1972.6  The latter





                                      277

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method was accepted in Massachusetts until the State adopted EPA Method 5 for

standardization purposes in May 1975.  The only major equipment differences

between the Method 17 and the Harvard technique were that rugged and inexpensive

Venturi-type flow meters were used in place of the delicate and very expensive

dry meters used in the Methods 5 and 17 sampling trains.  Additionally, a

separate Pitot-static tube was used to establish local gas velocities at the

sampling locations.

     A current test method often used by source operators to determine par-

ticulate emissions is a revised version of the original Power Test Code of

1941; Power Test Code No. 27 (PTC-27) - "Determining the Dust Concentration

in a Gas Stream" published by the American Society.of Mechanical Engineers

(ASME) in 1957.7  The above method is very similar to EPA Methods 1 through

5 except that PTC-27 is not as detailed in its requirements and can be modi-

fied depending upon site-specific factors.  In addition, the participate filter

contained within a sampling nozzle is usually inserted directly into the gas

stream as opposed to the EPA Method 5 extraction approach in which the filter is

located outside of the duct but maintained at a minimum temperature of

121°C (250°F ± 25°F).   Unless an upper limit in stack temperature; e.g.,

160°C (320°F) is set for PTC-27, it can be argued that this method may fail to

capture any vapor phase material that would condense at 160 C (320 F) or lower.

     General test requirements and procedures followed in PTC-27 are listed

below and compared to the EPA methods where appropriate:

     •    PTC-27 is designed for particles * ly with coarse alundum
          thimbles for collection.

     •    Where the range of velocities does not exceed 2 to 1, from
          12 to 20 points are recommended for large ducts (> 25 ft2 in
          cross section) and from 8 to 12 points for small ducts.

     •    Where steep velocity gradients or extreme turbulence are en-
          countered, the number of points may be doubled or trebled.


                                     278

-------
     •    The method of subdividing a duct into sampling points is the
          same as EPA Method 5.

     •    Operating conditions should be kept constant for 1 hour prior
          to the start of each run.

     •    Where steady state operation is not possible, the sampling rate
          should be adjusted so as to maintain a zero differential between
          static pressure within and outside of the sampling nozzle mouth
          when a null-type probe is used.

     •    Filters used should have a filtering efficiency of 99.0 percent
          by weight for the dust to be encountered during the test.

     •    When dust concentrations are very high, a moderate efficiency
          filter within the probe nozzle can be followed by a high effi-
          ciency filter located outside the duct (basically the EPA
          Method 5 system).

     •    At least two runs should be made at each basic flow rate
          within the stack.  EPA Method 5 requires three runs.

     •    Samples should be operated for a minimum of 10 minutes at each
          point.  EPA Method 5 requires a minimum of 2 minutes per point.

     •    Where steady conditions exist and a predetermined setting for
          velocity pressure has been computed for each point, a record
          of the computations shall be kept.

     •    Where the null method is used and sampling velocity is adjusted
          to the existing dust velocity, no record need be made of
          velocity pressure.

     •    Average gas pressure and temperature at the metering device for
          each sampling point shall be recorded during each test.  Other
          indicating instruments shall be read every 15 minutes.

     EPA Methods 5 and 17 and ASME PTC-27 are viable methods for particulate

sampling where strict adherence to procedures is followed.  EPA Method 5 re-

quires more detailed operation and more recording of data than PTC-27, but

there are situations where the ASME method would be the better choice.  For

example, a gas stream with a high grain loading might be better sampled with

an in-stack moderate efficiency thimble and an external backup filter.  The

thimble would pick up coarser material and allow smaller-sized particles to
                                      279

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pass through and be collected at the filter..  Use of the EPA Method in this




case might result in rapid plugging of the filter and an attendant reduction




in flow.  The necessary changes in flow rate to achieve isokinetic sampling




would be difficult and would leave more room for sampling error.  However,




the EPA Method can be modified by including a cyclone in the sampling train




which will collect coarse material and reduce the loading to the filter.




     In summary, it can be said that the EPA Methods are suitable where all




tests are to be performed on the same basis (for compliance purposes, for




example) such that comparison of several tests would be possible.  The ASME




test methods may be preferable for unique source conditions and where the




interest is only for the particular source sampled.
                                     280

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7.6  ACCURACY OF TEST METHODS AT LOWERED EMISSION LEVELS

     Regardless of the type of testing procedure chosen for particulate sampling,

the accuracy of the final result is a function not only of the test methods,

but also the competence of the individuals performing the tests and the related

final analyses and calculations.

     The requirement of EPA Method 5 for isokinetic sampling between 90 to  110

percent of the stack velocity implies a minimal error in sampling of + 1 percent
                                       Q
for particle diameters less than 15 um.   One must also consider potential

inaccuracies in gravimetric analyses, equipment meter readings, and possible

sample losses to arrive at the overall accuracy for the test results.  Assuming

that all associated equipment is properly maintained and calibrated, one could

add another deviation of roughly ± 10 percent to give an overall accuracy of

around ± 11 percent.  Obviously, this could mean the difference between com-

pliance and noncompliance in some cases.

     There are other factors which should be considered as control levels are

made more stringent.  For a controlled steam generating unit operating near

the 43 ng/J (0.1 lb/106 Btu) emission level, the amount of particulate collected

in a train for a 0.85 Nm3 (30 dscf) sample over a 1-hour period (for ideal

conditions) would be about 80 mg, proportioned between the probe and the filter.

The ratio of probe catch to filter catch ranges between 15/85 and 50/50

depending on the sampling velocity and particle size distribution.  Another

requirement for a valid test is that the minimum weight collected on the filter

must be no less than 5 percent of the filter weight.  Since a typical filter

weighs 220 mg, the minimum allowable filter catch is 11 mg.  Therefore all

conditions for a valid test are clearly met by a 1-hour test for a dust load-

ing corresponding to emissions of 43 ng/J (0.1 lb/106 Btu).
                                       281

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     On the other hand a source emitting at the 4.3 ng/J (0.01 lb/106  Btu)




level could, by a similar analysis require a 3-hour test period to collect




sufficient material.   A longer test may increase the chances for equipment  and




procedural errors or  failures as well as increasing the cost of a stack test.




These factors must be considered in the formulation of emission control




levels.
                                      282

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                             7.7  REFERENCES


1.   Dennis, R., D.R. Roeck, and N.F.  Surprenant.   Status Report on Control of
     Particulate Emissions from Coal-Fired Utility Boilers.  GCA-TR-77-38-G.
     May, 1978.  Appendices A-2 and A-3.   pp, 89-99.

2.   Gronhovd, Gordon H. and Everett A. Sondreal.   Technology  and Use  of Low-
     Rank Coals in the U.S.A.  Grand Forks Energy  Research Center.  ERDA.
     April 20-22, 1976.  p. 27.

3.   Sahagian, J., Dennis, R. and Surprenant, N.   "Particulate Emissions
     Control Systems for Oil Fired Boilers"  EPA-450/^-74-063.  GCA/Technology
     Division, Bedford, MA.  (December 1974).  p.  11.

4.   American Society Mechanical Engineers, "Test  Code for Dust Separating
     Apparatus,"  ASME Power Test Codes,  New York, 1941.

5.   Dennis, R., Johnson, G.A., First, M.W. , and Silvennan,  L., "How Dust
     Collectors Perform,"  Chem. Erig., 196, February (1952).

6.   Dennis, R.  "Stack Sampling for Particulate Concentrations - GCA  Testing
     Procedures"  Submitted 27 August 1972' to Mr.  A.  Redcay, Bureau of Air
     Control, Massachusetts Department of Public Health.

7.   The American Society of Mechanical Engineers, "Determining Dust Concentration
     in a Gas Stream"  Performance Test Code - 27-1957.  pp. 5-14.

8.   Watson, H.  "Errors in Anisokinetic Sampling"  American Industrial Hygiene
     Association, Quarterly 15, 21 (1954).
                                       283

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                               TECHNICAL REPORT DATA
                         (Please read Instructions on the reverse before completing)
1. REPORT NO. ,
EPA-600/7-79-178h
                           2.
                                                      3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Technology Assessment Report for Industrial Boiler
 Applications: Participate Collection
                                  5. REPORT DATE
                                   December 1979
                                  6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)

D. R. Roeck and Richard Dennis
                                  8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
GCA/Technology Division
Burlington Road
Bedford,  Massachusetts  01730
                                  10. PROGRAM ELEMENT NO.
                                  INE830
                                  11. CONTRACT/GRANT NO.

                                  68-02-2607, Task 19
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
                                  Task Final; 6/78-10/79
                                  14. SPONSORING AGENCY CODE
                                    EPA/600/13
is. SUPPLEMENTARY NOTES IERL-RTP project officer is James H. Turner, Mail Drop 61,
919/541-2925.
  . ABSTRACT
              report assesses applicability of particulate control technology to indus-
trial boilers.  It is one of a series to aid in determining the technological basis for a
New Source Performance Standard for Industrial Boilers.  It gives current and poten-
tial capabilities of alternative particulate  control techniques, and identifies the cost,
energy, and environmental impacts of the most promising options. Fabric filters and
electrostatic precipitators  (ESPs) can exceed 99% control efficiency and can be used
on industrial boilers. A baghouse seems more economical for very small combustion
units or to meet a very stringent emissions requirement when burning low sulfur
coal. An ESP might be  more aptly applied to the largest industrial units ,  involving
intermediate or moderate control levels for very small boilers and higher sulfur
coaJs.  Wet scrubbers are not expected to be used for particulate control alone, but
might be used to control both SO2 and particulates in the case of modest particulate
control levels. Mechanical collectors could be important for some cases. Control
costs exert a significant impact as boiler size and control level decrease. For regur
latory  purposes, this assessment must be viewed as preliminary, pending results of
the more extensive examinations of impacts called for under Section 111 of the Clean
Air Act.
 7.
                             KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
                                          b.lDENTIFIERS/OPEN ENDED TERMS
                                              c.  COSATI Field/Group
Pollution
Assessments
Dust
Aerosols
Boilers
Flue Gases
Fabrics
Filters
Electrostatic Precip-
  itators
Scrubbers
Pollution Control
Stationary Sources
Particulate
Industrial Boilers
Fabric Filters
Baghouses
13B
14B
11G
07D
13A
21B
HE
131
07A
13. DISTRIBUTION STATEMENT
 Release to Public
                      19. SECURITY CLASS (This Report)
                      Unclassified
                         21. NO. OF PAGES
                            302
                      20. SECURITY CLASS (Thispage)
                      Unclassified
                                               22. PRICE
EPA Form 2220-1 (9-73)
                                        284

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