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
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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
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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)
-------
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)
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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
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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
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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
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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
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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)
-------
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
-------
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.
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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
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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.
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• 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.
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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).
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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.
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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).
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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)
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