FUEL OIL
COMBUSTION
AP-42 Section 1.3
Reference Number
EMISSIONS ASSlSSM€NTt7FCONVENTIONAL STATIONARY
COMBUSTION SYSTEMS: VOLUME III. EXTERNAL COMBUSTION SOURCES
FOR ELECTRICITY GENERATION
Noofvember 1980
by:
C.C. Shih, R.A. Orsini, D.G. Ackerman, R. Moreno,
E.L. Moon, L.L. Scinto, and C. Yu
TRW Environmental Engineering Division
One Space Park, Redondo Beach, CA 90278
EPA Contract No.; 68-02-2197
EPA Program Element No.: C9KN1C
Project Off leer: Michael C. Osborne
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, N.C. 27711
Prepared for:
U.S. Environmental Protection Agency
Office of Research and Development
Washington D.C. 20545
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ABSTRACT
Multimedia emissions from external combustion sources for electricity
generation are characterized in this report. In the assessment process,
existing emissions data were first examined to determine the adequacy of the
data base. This was followed by the conduct of a measurement program to
fill the identified data gaps. Emissions data obtained from the sampling
and analysis program were combined with existing emissions data to provide
estimates of emission levels, and to define the need for additional data.
The results of this study indicate that external combustion sources for
electricity generation contribute significantly to the nationwide emissions
burden. Flue gas emissions of NO , S07, and particulate matter from these
A Cm
sources account for approximately 50 percent, 57 percent, and 25 percent,
respectively, of the emissions of these pollutants from all stationary sources,
Additionally, flue gas emissions of sulfates and several trace elements from
coal- and oil-fired utility boilers also require further attention. POM com-
pounds in flue gas emissions are mostly naphthalene, phenanthrene, and pyrene.
However, d1benz(a,h)anthracene and possibly benzo(a)pyrene, both active car-
cinogens, were detected at a limited number of coal-fired sites.
A second major source of air emissions is vapors and drifts from cooling
towers. Air emissions of chlorine, magnesium, phosphorus and sulfates from
mechanical draft cooling towers were found to be comparable to flue gas emis-
sions of these pollutants from oil-fired utility boilers.
The multiple use of water in steam electric plants results in wastewater
streams from several operations. Overall, concentrations of iron, magnesium,
manganese, nickel, and phosphorus are at levels that may be of environmental
concern. Average organic levels ranged from 0.01 mg/1 for ash pond effluents
to 6.0 mg/1 for boiler blowdown. Also, no POM compound was detected.
Data on coal fly ash and bottom ash show that from eleven to sixteen
trace elements are present at potentially harmful levels. The only POM com-
pounds detected, however, were naphthalene, alkyl naphthalenes, and other
relatively nontoxic compounds.
ii
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CONTENTS
Page
Abstract 11
Figures. ........ vi
Tables viii
1. Executive Summary and Conclusions 1
1.1 Assessment Methodology. .... 1
1.2 The Existing Emissions Data Base (J
1.3 The Source Measurement Program ^3
1.4 Sampling and Analysis Methodology 4
1.4.1 Level I Field Testing 4
1.4.2 Modified Level I Laboratory Analysis . . 5
1.5 Results 9
1.5.1 Air Emissions 9
1.5.2 Wastewater Effluents 14
1.5.3 Solid Wastes ....... 16
1.6 Conclusions 18
/i
1.6.1 Characteristics of Flue Gas Emissions 20
1.6.2 Characteristics of Air Emissions From Cooling Towers 22
1.6.3 Characteristics of Wastewater Discharges 22
1.6.4 Characteristics of Solid Wastes. . 22
1.6.5 Key Data Needs 23
2. Composite Results 25
2.1 Current and Future Fuel Consumption 25
2.2 Nationwide Emissions. 27
2.2.1 Air Emissions. 27
2.2.2 Wastewater Discharges. ... 39
2.2.3 Solid Waste Generation . 41
3. Introduction 45
4. Source Description 51
4.1 Source Definition and Characterization. ..... 51
4.2 Emission Sources and Unit Operations. ..... 61
4.2.1 Air Emissions and Control Technology ........ 61
4.2.2 Wastewater Effluents and Control Technology. .... 71
4.2.3 Solid Wastes and Disposal/Recovery Practices .... 74
111
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CONTENTS (Continued)
Page
5. Air Emissions 77
5.1 Source and Nature of Air Emissions 77
5.2 Criteria for Evaluating the Adequacy of Emissions Data ... 78
5.3 Evaluation of Existing Emissions Data 79
5.3.1 Flue Gas Emissions 79
5.3.2 Cooling Tower Emissions 138
5.3.3 Emissions From Coal Storage Piles 149
5.3.4 Status of Existing Emissions Data Base 152
5.4 Emissions Data Acquisition ...... 155
5.4.1 Selection of Test Facilities 155
5.4.2 Field Testing 161
5.4.3 Laboratory Analysis Procedures 173
5.4.4 Test Results 196
5.5 Analysis of Test and Data Evaluation Results ........ 233
5.5.1 Flue Gas Emissions 233
5.5.2 Cooling Tower Emissions 298
5.6 Data Reliability 308
6. Wastewater Effluents. . 312
6.1 Sources and Nature of Wastewater Effluents 312
6.1.1 Cooling Water Systems 313
6.1.2 Water Treatment Processes 317
6.1.3 Boiler Slowdown 318
6.1.4 Chemical Cleaning 319
6.1.5 Ash Handling 321
6.1.6 Wet Scrubber Systems 323
6.1.7 Coal Storage Piles 323
6.2 Criteria for Evaluating the Adequacy of Effluent Data. ... 324
6.3 Evaluation of Existing Data 325
6.3.1 Waste Streams From Cooling Systems 326
6.3.2 Waste Streams From Water Treatment Processes 328
6.3.3 Waste Streams From Boiler Slowdown 332
6.3.4 Waste Streams From Chemical Cleaning 332
6.3.5 Waste Streams From Ash Handling 340
6.3.6 Waste Streams From Wet Scrubber Effluents 347
6.3.7 Waste Streams from Coal Storage Piles 347
6.4 Wastewater Data Acquisition 352
6.4.1 Field Testing ...... 353
6.4.2 Laboratory Analysis Procedures 355
iv
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CONTENTS (Continued)
Page
6.5 Analysis of Test and Data Evaluation Results ........ 355
6.5.1 Waste Streams From Cooling Systems. ......... 357
6.5.2 Waste Streams From Boiler Slowdown 362
6,5.3 Waste Streams From Ash Ponds 362
6.5.4 Other Waste Streams 367
6.5.5 Summary of Wastewater Effluents .... 367
6.6 Data Reliability 376
7. Solid Wastes 379
7.1 Source and Nature of Solid Wastes 379
7.2 Criteria for Evaluating the Adequacy of Emissions Data . . . 330
7.3 Evaluation of Existing Data 383
7.3.1 Fly Ash and Bottom Ash 383
7.3.2 Wastes From Water Treatment Processes 391
7.3.3 Wastes From Flue Gas Desulfurization Systems 397
7.4 Solid Waste Data Acquisition 403
7.4.1 Samples Acquired 403
7.4.2 Laboratory Analysis Procedures 403
7.5 Analysis of Test and Data Evaluation Results 404
7.5.1 Fly Ash and Bottom Ash 404
7.5.2 Scrubber Sludge 423
7.6 Data Reliability 426
References 427
Appendices
A Criteria for Evaluating the Adequacy of Existing Emissions
Data for Conventional Stationary Combustion Systems 441
B Data Reduction Procedure 452
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FIGURES
Number Page
1 Basic Level 1 Sampling Flow and Analytical Plan for
Particulates and Gases 6
2 Basic Level 1 Sampling Flow and Analytical Scheme for
Solids, Slurries and Liquids 7
3 Pulverized Coal Firing Methods ......... 54
4 Diagram Showing Emission Streams Associated With a
Pulverized Coal-fired Utility Boiler 64
2
5 Water Flows (m /hr) for a Typical 100 MW Coal-fired Power
Plant at Full Load 73
6 Cumulative Drift Droplet Size Distributions of Three
Mechanical Draft Cooling Towers 147
7 Cumulative Drift Droplet Size Distributions of Six Natural
Draft Cooling Towers 148
8 Schematic of Source Assessment Sampling System (SASS). . . . 163
9 Cooling Tower Sampling Train . 171
10 Cooling Tower Sampling Train Suspension System 172
11 Level I Inorganic Analysis Plan 180
12 Current Level I Inorganic Analysis Plan 181
13 Level I Organic Analysis Flow Chart 188
14 Level I Organic Analysis Methodology ............ 189
15 EACCS Sample Control Numbers 210
16 Decision Matrix for Liquid/Slurry Sampling ......... 354
17 Comparison of Cooling Tower Slowdown Data From Present Study
to Existing Data Base 369
18 Comparison of Trace Element Data From Present Study to
Existing Data for Cooling Tower Slowdown 370
19 Comparison of Boiler Slowdown Data From Present Study to
Existing Data Base 371
20 Comparison of Trace Element Data From Present Study to
Existing Data for Boiler Slowdown. 372
21 Mean Trace Element Concentrations in Bottom Ash Pond
Overflow Obtained by Combining Data From Present and Past
Studies 374
VI
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FIGURES (Continued)
Number Page
22 Mem Trace Element Concentrations in Fly Ash Pond
Overflow Obtained by Combining Data From Present and Past
Studies 375
23 Mean Trace Element Concentrations in Combined Ash Pond
Overflow Obtained by Combining Data From Present and Past
Studies 377
A-l Step 1 Screening Mechanism for Emissions Data 442
vii
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TABLES
Number Page
1 Summary of Assessment Results for Flue Gas Emissions From
Bituminous Coal-fired Utility Boilers 10
2 Summary of Assessment Results for Flue Gas Emissions From
Lignite-fired Utility Boilers 11
3 Summary of Assessment Results for Flue Gas Emissions From
Residual Oil- and Gas-fired Utility Boilers 12
4 Summary of Assessment Results for Cooling Tower Slowdown,
Boiler Slowdown and Ash Pond Overflow 15
5 Summary of Assessment Results for Water Treatment Waste-
water, Chemical Cleaning Wastes, Wet Scrubber Wastewater,
and Coal Pile Runoff 17
6 Summary of Assessment Results for Fly Ash and Bottom Ash
From Bituminous Coal-fired and Lignite-fired Boilers .... 19
7 1978 and Projected 1985 Fuel Consumption for Utility
Boilers 26
8 Current Nationwide Emissions of Criteria Pollutants From
External Combustion Sources for Electricity Generation ... 28
9 Current Nationwide Flue Gas Emissions of Trace Elements From
External Combustion Sources for Electricity Generation ... 29
10 Current Nationwide Flue Gas Emissions of Polycyclic Organic
Matter From Bituminous Coal-fired Utility Boilers. ..... 31
11 Current Nationwide Flue Gas Emissions of Polycyclic Organic
Matter From Lignite-fired Utility Boilers 32
12 Current Nationwide Flue Gas Emissions of Polycyclic Organic
Matter From Residual Oil-fired Utility Boilers ....... 32
13 Projected 1985 Nationwide Emissions of Criteria Pollutants
From External Combustion Sources for Electricity Generation. 34
14 Projected 1985 Nationwide Flue Gas Emissions of Trace
Elements From External Combustion Sources for Electricity
Generation 35
15 Projected 1985 Nationwide Flue Gas Emissions of Polycyclic
Organic Matter From Bituminous Coal-fired Utility Boilers. . 36
16 Projected 1985 Nationwide Flue Gas Emissions of Polycyclic
Organic Matter From Lignite-fired Utility Boilers 37
17 Projected 1985 Nationwide Flue Gas Emissions of Polycyclic
Organic Matter From Residual Oil-fired Utility Boilers ... 37
18 Current Nationwide Wastewater Discharge Rates From External
Combustion Sources for Electricity Generation. . 42
viii
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TABLES (Continued)
Number Page
19 Current and Projected 1985 Nationwide Solid Waste Genera-
tion Rates From External Combustion Sources for Electricity
Generation 44
20 Classification of Combustion Systems 52
21 Generating Capacity, Fuel Consumption and Population
Characteristics of Electric Utility Boiler in 1978 56
22 Projected Generating Capacity of Electric Utility Boilers
in 1985 58
23 Comparison of 1978 Fossil Fuel Consumption by Electric
Utilities With Historical 1975 Regional Fuel Consumption . . 59
24 Origin of Coal Delivered to Electric Utilities in 1975 ... 60
25 Domestic Petroleum Production for the First Half of 1978 . . 62
26 Crude and Refined Oil Imports for the First Half of 1978 . . 63
27 Relevance of Unit Operations to Air, Water and Solid Waste
Emissions 65
28 Distribution of Particulate Control Equipment for
Bituminous Coal-fired Utility Boilers 66
29 Total Mass Efficiency of Particulate Control Devices for
Coal-fired Utility Boilers - 1978 67
30 Total Mass Efficiency of Particulate Control Devices for
Coal-fired Utility Boilers - 1985 68
31 Process Type and Efficiency of Operating FGD Systems for
Utility Boilers in 1978 70
32 Summary of NOX Control Methods and Generating Capacity for
Utility Boilers in 1978 72
33 Ash Collection and Utilization in 1977 76
34 Summary of NOX Data From Bituminous Coal-fired Electricity
Generation Sources 82
35 Summary of CO Data From Bituminous Coal-fired Electricity
Generation Sources 82
36 Summary of SOg Data From Bituminous Coal-fired Electricity
Generation Sources ... 83
37 Summary of Particulate Data From Bituminous Coal-fired
Electricity Generation Sources 83
38 Summary of Total Hydrocarbon Data From Bituminous Coal-fired
Electricity Generation Sources 84
39 Summary of Particulate Data From Bituminous Coal-fired
Electricity Generation Sources Equipped With High-Efficiency
Particulate Control Devices 86
IX
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TABLES (Continued)
Number Page
40 Summary of NOX Data From Lignite-fired Electricity
Generation Sources ............. ........ 88
41 Summary of S0£ Data From Lignite-fired Electricity
Generation Sources ..................... 88
42 Summary of CO Data From Lignite-fired Electricity Generation
Sources. ........... ............... 89
43 Summary of Rarticulate Data From Lignite-fired Electricity
Generation Sources ..................... 89
44 Summary of Hydrocarbon Data From Lignite-fired Electricity
Generation Sources ............. . ....... 90
45 Summary of Criteria Pollutant Emissions Data From
Anthracite-fired Electricity Generation Sources ....... 91
46 Summary of Criteria Pollutant Emissions Data From
Oil-fired Utility Boilers .................. 93
47 Summary of Emissions From Gas-fired Utility Boilers ..... 94
48 Size Distributions for Controlled and Uncontrolled
Particulate Emissions From Utility Boilers . . ...... . 97
49 Efficiencies of Particulate Removal by Control Devices for
Various Size Fractions ............. . ..... 99
50 503 Data From Bituminous Coal -fired Electricity Generation
Sources ........................... 101
51 Primary Sulfate Data for Bituminous Coal -fired Electricity
Generation Sources ..................... 103
52 Emission Factors and Mean Source Severity for 50$ and
Primary Sulfate Emissions From Coal -fired Utility Boilers. . 104
53 503 Data for Oil -fired Electricity Generation Sources. ... 105
54 Primary Sulfate Data for Oil-fired Electricity Generation
Sources ....................... .... 106
55 Emission Factors and Mean Source Severity Factors for
and Primary Sulfate Emissions From Oil -fired Utility
Boilers ....... . ........... ... ..... 107
56 Partitioning of Elements in Coal Combustion Residues .... Ill
57 Average Trace Element Concentrations in Coal ........ 115
58 Trace Element Enrichment Factors for Coal-fired Utility
Boilers Equipped With Electrostatic Preci pita tors,
Mechanical Preci pi tators, and Wet Scrubbers ......... 117
59 Emission Factors and Source Severities of Trace Element
Emissions From Pulverized Bituminous Coal-fired Dry Bottom
Boilers Equipped With Electrostatic Precipitators ...... 120
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TABLES (Continued)
Number Page
60 Emission Factors and Source Severities of Trace Element
Emissions From Pulverized Bituminous Coal-fired Dry Bottom
Boilers Equipped With Mechanical Precipitators ....... 121
61 Emission Factors and Source Severities of Trace Element
Emissions From Pulverized Bituminous Coal-fired Dry Bottom
Boilers Equipped With Wet Scrubbers 122
62 Emission Factors and Source Severities of Trace Element
Emissions From Pulverized Bituminous Coal-fired Wet Bottom
Boilers Equipped With Electrostatic Precipitators. ..... 123
63 Emission Factors and Source Severities of Trace Element
Emissions From Pulverized Bituminous Coal-fired Wet Bottom
Boilers Equipped With Mechanical Precipitators 124
64 Emission Factors and Source Severities of Trace Element
Emissions From Pulverized Bituminous Coal-fired Wet Bottom
Boilers Equipped With Wet Scrubbers 125
65 Emission Factors and Source Severities of Trace Element
Emissions From Bituminous Coal-fired Cyclone Boilers
Equipped With Electrostatic Precipitators. ... 126
66 Emission Factors and Source Severities of Trace Element
Emissions From Bituminous Coal-fired Cyclone Boilers
Equipped With Mechanical Precipitators 127
67 Emission Factors and Source Severities of Trace Element
Emissions From Bituminous Coal-fired Cyclone Boilers
Equipped With Wet Scrubbers. 128
68 Trace Element Emission Factors for Pulverized Lignite Coal-
fired Dry Bottom Boilers 131
69 Trace Element Emission Factors for Lignite Coal-fired
Cyclone Boilers 132
70 Average Trace Element Concentrations of Residual Oil .... 134
71 Emission Factors and Mean Source Severities of Trace Element
Emissions From Oil-fired Utility Boilers 135
72 Average Emissions of Organic Species From Coal-fired Utility
Boilers. 136
73 POM Emission Factors for an Industrial Boiler Firing
Pulverized Bituminous Coal 137
74 Distribution of Cooling System Types for Steam-Electric
Power Plants 139
75 Description of Cooling Tower Drift Measurement Techniques. . 141
76 Drift Rates From Mechanical and Natural Draft Cooling Towers 142
77 Drift Fraction and Salt Mass Emission Fraction for
Mechanical and Natural Draft Cooling Towers 143
xi
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TABLES (Continued)
Number Page
78 Air Emission Factors for Fresh Water Cooling Towers. .... 145
79 Coal Storage Requirement for Coal-fired Utility Boilers -
1978 150
80 Concentrations of POH Compounds in Coal Samples 152
81 Summary of Status of Existing Data Base for Flue Gas
Emissions From Utility Boilers ... 153
82 Characteristics of Bituminous Coal-fired Utility Boilers
Selected for Testing 157
83 Characteristics of Lignite-fired Utility Boilers Selected
for Testing 158
84 Characteristics of Residual Oil-fired Utility Boilers
Selected for Testing 159
85 Characteristics of Gas-fired Utility Boilers Selected for
Testing . 160
86 Characteristics of Cooling Tower Sites Selected for Testing. 162
87 Operating Load and Fuel Feed Rates of Bituminous Coal-fired
Utility Boilers 166
88 Operating Load and Fuel Feed Rates of Lignite-fired Utility
Boilers 167
89 Operating Load and Fuel Feed Rates of Residual Oil-fired
Utility Boilers 168
90 Operating Load and Fuel Feed Rates of Natural Sas-fired
Utility Boilers. 169
91 Power Plant Design Specifications and Operations During Tes.t 174
92 Cooling Tower Operation During Test. ..... 175
93 Cooling Tower Additives . 176
94 Program Related Additions and/or Deletions to Level 1
Procedures 177
95 Modification and EPA Directed Changes to Level 1 Procedures. 178
96 Analytical SASS Train Detection Limits 186
97 Mass to Charge Values Monitored 196
98 Minimum List of POM Compounds Monitored 197
99 Flue Gas Emissions of S02, CO, Particulates and Hydrocarbons
From Bituminous Coal-fired Utility Boilers Tested 199
100 Flue Gas Emissions of S02, CO, Particulates and Hydrocarbons
From Lignite-fired Utility Boilers Tested 200
101 Flue Gas Emissions of S02, CO, Particulates and Hydrocarbons
From Residual Oil-fired Utility Boilers Tested 201
xii
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TABLES (Continued)
Number Page
102 Flue Gas Emissions of CO, Particulates, and Hydrocarbons
From Natural Sas-fired Utility Boilers Tested 202
103 Flue Gas Emissions From Bituminous Coal-fired Utility
Boilers, Summary of Organic Analysis Results 205
104 Flue Gas Emissions From Lignite Coal-fired Utility Boilers,
Summary of Organic Analysis Results 206
105 Flue Gas'Emissions From Residual Oil-fired Utility Boilers,
Summary of Organic Analysis Results 207
106 Flue Gas Emissions From Gas-fired Utility Boilers, Summary
of Organic Analysis Results. 208
107 Flue Gas Emissions From Bituminous Coal-fired Utility
Boilers, Summary of LC Separation Results 211
108 Flue Gas Emissions From Lignite Coal-fired Utility Boilers,
Summary of LC Separation Results 213
109 Flue Gas Emissions From Residual Oil-fired Utility Boilers,
Summary of LC Separation Results ... 214
110 Flue Gas Emissions From Gas-fired Utility Boilers, Summary
of LC Separation Results 215
111 Flue Gas Emissions From Bituminous Coal-fired Utility
Boilers, Compound Classes Identified by Infrared
Spectrometry 217
112 Flue Gas Emissions From Lignite Coal-fired Utility Boilers,
Compound Identified by Infrared Spectrometry 220
113 Flue Gas Emissions From Residual Oil-fired Utility Boilers,
Compound Classes Identified by Infrared Spectrometry .... 222
114 Flue Gas Emissions From Gas-fired Utility Boilers, Compound
Classes Identified by Infrared Spectrometry. 224
115 Flue Gas Emissions From Bituminous Coal-fired Utility
Boilers, Results of LRMS Analyses 225
116 Flue Gas Emissions From Lignite Coal-fired Utility Boilers,
Results of LRMS Analyses . . 228
117 Flue Gas Emissions From Residual Oil-fired Utility Boilers,
Results of LRMS Analyses 229
118 Flue Gas Emissions From Gas-fired Utility Boilers, Results
of LRMS Analyses 230
119 Flue Gas Emissions From Bituminous Coal-fired Utility
Boilers, POM Concentrations 231
120 Flue Gas Emissions From Lignite-fired Utility Boilers, POM
Concentrations 233
xm
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TABLES (Continued)
Number Page
121 Flue Gas Emissions From Residual Oil-fired Utility Boilers,
POM Concentrations . 234
122 Summary of Emission Factor Data for Flue Sas Emissions of
Particulate, S02, CO, and Total Organics From Bituminous
Coal-fired Utility Boilers Tested 235
123 Summary of Emission Factor Data for Flue Gas Emissions of
Particulates, SOg, CO, and Total Organics From Lignite-fired
Utility Boilers Tested 238
124 Summary of Emission Factor for Flue Gas Emissions of
Particulates, S02, CO, and Total Organics From Residual
Oil-fired Utility Boilers Tested .... 240
125 Summary of Emission Factor Data for Flue Gas Emissions of
Particulates, CO, and Hydrocarbons From Gas-fired Utility
Boilers Tested . 241
126 Comparison of Criteria Pollutant Emission Factors for
Bituminous Coal-fired Utility Boilers 243
127 Comparison of Criteria Pollutant Emission Factors for
Lignite-fired Utility Boilers 245
128 Comparison of Criteria Pollutant Emission Factors for
Residual Oil- and Gas-fired Utility Boilers. 247
129 Best Estimates of Average Emission Factors for Criteria . . 249
Pollutants
130 Mean Source Severity Factors for Criteria Pollutants .... 251
131 Controlled Particulate Emissions Size Distribution Data From
Bituminous Coal-fired Utility Boilers Tested . 252
132 Controlled Particulate Emissions Size Distribution Data From
Lignite Coal-fired Utility Boilers Tested. .... 255
133 Particulate Emissions Size Distribution Data From Residual
Oil-fired Utility Boilers Tested 256
134 Comparison of Current Study and Existing Size Distribution
Data for Particulate Emissions 257
135 Particulate Sulfate Emission Data From Bituminous Coal-fired
Utility Boilers Tested 259
136 Emission and Source Severity Factors for Particulate Sulfate
Emissions From Bituminous Coal-fired Utility Boilers .... 262
137 503 Emission Data From Bituminous Coal-fired Cyclone Boilers 263
138 Particulate Sulfate Emission Data From Lignite Coal-fired
Utility Boilers Tested 264
139 Emission and Source Severity Factors for Particulate Sulfate
Emissions From Lignite-fired Utility Boilers ... 265
xiv
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TABLES (Continued)
Number Page
140 Particulate Sulfate Emission Data From Residual Oil-fired
Utility Boilers Tested 266
141 Emission and Source Severity Factors for Particulate Sulfate
Emissions From Oil-fired Utility Boilers 267
142 $03 Emission Data From Residual Oil-fired Utility Boilers
Tested 267
143 S03 Emission Data From Residual Oil-fired Utility Boilers. . 268
144 Summary of Emission and Source Severity Factors of Trace
Element Emissions From Pulverized Bituminous Coal-fired Dry
Bottom Utility Boilers Tested 270
145 Summary of Emission and Source Severity Factors of Trace
Element Emissions From Pulverized Bituminous Coal-fired Wet
Bottom Utility Boilers Tested 271
146 Summary of Emission and Source Severity Factors of Trace
Element Emissions From Bituminous Coal-fired Cyclone Utility
Boilers Tested 272
147 Summary of Emission and Source Severity Factors of Trace
Element Emissions From Bituminous Coal-fired Utility Stokers
Tested 273
148 Emissions of Chromium and Nickel From Bituminous Coal-fired
Boilers Equipped With Electrostatic Preci pita tors 275
149 Comparison of Trace Element Emission Factors for Pulverized
Bituminous Coal-fired Dry Bottom Boilers 277
150 Comparison of Trace Element Emission Factors for Pulverized
Bituminous Coal-fired Wet Bottom Boilers . . 278
151 Comparison of Trace Element Emission Factors for Bituminous
Coal-fired Cyclone Boilers . ........... 279
152 Summary of Emission and Source Severity Factors of Trace
Element Emissions From Pulverized Lignite-fired Dry Bottom
Utility Boilers Tested 282
153 Summary of Emission and Source Severity Factors of Trace
Element Emissions From Lignite-fired Cyclone Utility Boilers
Tested 283
154 Summary of Emission and Source Severity Factors of Trace
Element Emissions From Lignite-fired Utility Stokers Tested. 284
155 Summary of Emission and Source Severity Factors of Trace
Element Emissions From Oil-fired Utility Boilers Tested. . . 285
156 Comparison of Trace Element Emission Factors for Residual
Oil-fired Utility Boilers 289
157 Summary of Emission and Source Severity Factors of Trace
Element Emissions From Gas-fired Utility Boilers TEsted. . . 290
xv
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TABLES (Continued)
Number Page
158 Comparison of Trace Element Emission Factors for Gas-»
Oil-, and Coal-fired Utility Boilers ............ 291
159 Summary of POM Emission Data From Pulverized Bituminous
Coal-fired Dry Bottom Utility Boilers 292
160 Summary of POM Emission Data From Pulverized Bituminous
Coal-fired Wet Bottom Utility Boilers 293
161 Summary of POM Emission Data From Bituminous Coal-fired
Cyclone Utility Boilers 294
162 Summary of POM Emission Data From Bituminous Coal-fired
Stoker 295
163 Summary of POM Emission Data From Lignite-fired Utility
Boilers 296
164 Summary of POM Emission Data From Oil-fired Utility Boilers. 297
165 Measured Air Flow Rates and Water Evaporation and Drift
Rates for Cooling Tower Tested ..... 299
166 Summary of Trace Element Emission Factors for Air Emissions
From Cooling Towers Tested 300
167 Air Emissions of Chlorine, Phosphorus, and Magnesium From
Cooling Towers Tested 303
168 Air Emissions of Sulfates From Cooling Towers Tested .... 305
169 Comparison of Inorganic Emission Factors for Cooling Towers. 305
170 Air Emissions of Organics From Cooling Towers Tested .... 307
171 Spark Source Mass Spectrometric Analyses of Trace Element
Emissions for Site 135 310
172 Chemical Treatment Summary for Recirculating Cooling Systems 316
173 Common Acids Used in Chemical Cleaning 320
174 Mean and Variability of Existing Data for Cooling Tower
Slowdown 327
175 Comparison of Mean and Upper Limit Cooling Tower Slowdown
Concentrations With MATE Values 328
176 Mean and Variability of Existing Data for Boiler Water
Pretreatment (Ion Exchange Waste) 329
177 Mean and Variability of Existing Data for Boiler Water
Pretreatment (Clarification Waste) ..... 330
178 Comparison of Mean and Upper Limit Ion Exchange Waste
Concentrations With MATE Values . 331
179 Comparison of Mean and Upper Limit Clarification Waste
Concentrations With MATE Values 331
xvi
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TABLES (Continued)
Number Page
180 Mean and Variability of Existing Data for Boiler Slowdown. . 333
181 Comparison of Mean and Upper Limit Boiler Slowdown Concen-
trations With MATE Values. . 334
182 Mean and Variability of Existing Data for Chemical Cleaning
Wastewater (Acid Phase Composite) 335
183 Mean and Variability of Existing Data for Chemical Cleaning
Wastewater (Alkaline Phase Composite) 336
184 Mean and Variability of Existing Data for Chemical Cleaning
Wastewater (Neutralization Drain) 337
185 Comparison of Mean and Upper Limit Chemical Cleaning Waste
(Acid Phase Composite) Concentrations With MATE Values ... 338
186 Comparison of Mean and Upper Limit Chemical Cleaning Waste
(Alkaline Phase Composite) Concentrations With MATE Values . 339
187 Comparison of Mean and Upper Limit Chemical Cleaning Waste
(Neutralization Drain) Concentrations With MATE Values . . . 340
188 Mean and Variability of Existing Data for Ash Handling (Fly
Ash Pond Discharge). 341
189 Mean and Variability of Existing Data for Ash Handling
(Bottom Ash Pond Discharge). . 342
190 Mean and Variability of Existing Data for Ash Handling
(Combined Ash Pond Discharge). 343
191 Comparison of Mean and Upper Limit Fly Ash Pond Discharge
Concentrations With MATE Values 344
192 Comparison of Mean and Upper Limit Bottom Ash Pond Discharge
Concentrations With MATE Values 345
193 Comparison of Mean and Upper Limit Combined Ash Pond
Discharge Concentrations With MATE Values 346
194 Mean and Variability of Existing Data for FGD (Lime-
Limestone) System: Scrubber Sludge Liquor 348
195 Comparison of Mean and Upper Limit FGD Scrubber (Lime-
Limestone) Sludge Liquor Concentrations With MATE Values . . 349
196 Mean and Variability of Existing Data for Coal Pile Runoff
(3.9% Total Sulfur) 350
197 Mean and Variability of Existing Data for Coal Pile Runoff
(2.1% Total Sulfur). 351
198 Liquid Stream Sampling and Analysis Protocol . 356
199 Inlet Once-Through Cooling Water Analyses 358
200 Outlet Once-Through Cooling Water Analyses 359
xvn
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TABLES (Continued)
Number Page
201 Cooling Tower Slowdown Analyses 360
202 Cooling Tower Slowdown Trace Element Analyses 361
203 Boiler Slowdown Analyses . 363
204 Boiler Slowdown Trace Element Analyses ... 364
205 Ash Pond Overflow Analyses ......... 365
206 Ash Pond Overflow Trace Element Analyses 366
207 Estimated Precision and Accuracy of Hach Kit Analyses
Results 378
208 Characteristics of Wastes Generated by Water Treatment
Processes 381
209 Distribution of Coal Ash by Boiler Type. .......... 384
210 Variations in Chemical Composition of Coal Ash With Rank for
the Major and Minor Constituents ........ 386
211 Major and Minor Constituents in Fly Ash and Bottom Ash
Fractions From Coal-fired Utility Boilers. . 387
212 Trace Element Constituents in Fly Ash and Bottom Ash
Fractions From Coal-fired Utility Boilers 388
213 Estimated Hydrocarbon Concentrations in Coal Ash 389
214 Estimated POM Concentrations in Coal Ash 390
215 Characteristics of Alum Sludge . . 392
216 Average Turbidities and Estimated Solids Production of
Selected United States Water Supplies Employing Coagulation. 392
217 Estimated Sludge Solids Produced by Alum Coagulation .... 394
218 Chemical Composition of Dry Solids From Water Softening. . . 395
219 Estimated Softening Sludge Production 396
220 Quantities of Solids Produced in Waste Sludge From Lime-
Soda Ash Softening 397
221 Identification of Chemical Phases of FGD Sludge 400
222 Trace Element Ranges in FGD Waste Solids .......... 401
223 Mean Trace Element Concentration in FGD Sludges 402
224 Summary of Fly Ash Trace Element Data for Bituminous Coal-
fired Utility Boilers. 405
225 Summary of Bottom Ash Trace Element Data for Bituminous
Coal-fired Utility Boilers 406
226 Discharge Severity of Trace Elements in Fly Ash and Bottom
Ash From Bituminous Coal-fired Utility Boilers 407
xvi i i
-------
TABLES (Continued)
Number Page
227 Adequacy of Trace Element Data Base for Fly Ash and Bottom
Ash From Bituminous Coal-fired Utility Boilers ....... 409
228 Summary of Fly Ash Trace Element Data for Lignite-fired
Utility Boilers 410
229 Summary of Bottom Ash TRace Element Data for Lignite-fired
Utility Boilers 411
230 Summary of Discharge Severity of Trace Elements in Fly Ash
and Bottom Ash From Lignite-fired Utility Boilers 413
231 Adequacy of Trace Element Data Base for Fly Ash and Bottom
Ash From Lignite-fired Utility Boilers 414
232 TCO and Gravimetric Organic Data for Fly Ash and Bottom Ash
From Bituminous Coal-fired Utility Boilers 416
233 Summary of Low Resolution Mass Spectrometric Analyses
Results for Selected LC Fractions From Ash Samples 418
234 Summary of Infrared Analysis Results of LC Fractions of Ash
Samples From Bituminous Coal-fired Utility Boilers 419
235 Polynuclear Organic Materials (POM) Identified in Ash
Samples From Bituminous Coal-fired Utility Boilers 420
236 Summary of TCO and Gravimetric Organic Data for Fly Ash and
Bottom Ash From Lignite-fired Utility Boilers 421
237 Summary of Infrared Analysis Results of Gravimetric
Residues (>Cie) for Lignite-fired Utility Boilers. ..... 422
238 Trace Element Content of Scrubber Discharge Solids From Coal
Firing - Test 135. 425
A-l Maximum Ratio of Extreme Ranking Observations 450
B-l Elemental Composition and Higher Heating Value of Fuels. . . 454
xix
-------
1. EXECUTIVE SUMMARY AND CONCLUSIONS
Emissions from external combustion sources for electricity generation
are characterized in this report. According to the classification system in
the current study, all fossil fuel-fired boilers owned by public and private
utilities to generate electricity are included in this source category. The
term "external combustion" is used to denote that thermal energy for the
generation of steam in a boiler is supplied externally by the combustion of
fossil fuel. The steam generated is then converted to mechanical energy in
a turbine coupled to an electricity generator. Exhaust steam is condensed
and returned to the boiler.
For the purposes of this study, all major process operations and on-
site facilities involved in the generation of power by utilities are covered
in this source category. Support facilities and operations addressed in this
report include: coal storage, cooling water systems, makeup water treatment,
chemical cleaning of boiler tubes, air and water pollution control, and solid
waste disposal. Fugitive emissions from ash handling and storage and fuel
handling are not considered here because characterization of these emissions
is outside the scope of the current effort.
1.1 ASSESSMENT METHODOLOGY
The assessment method employed in the current study involved a critical
examination of existing emissions data, followed by the conduct of a measure-
ment program to fill data gaps based on phased sampling and analysis strategy.
Data acquired as a result of the measurement program, in combination with
the existing data, were further evaluated. Data inadequacies identified at
the completion of the current program are discussed with respect to the need
for additional study.
Specifically, the phased approach to environmental assessment is de-
signed to provide comprehensive emissions information on all process waste
streams in a cost effective manner. To achieve this goal, two distinct
sampling and analysis levels are being employed in this project. Level I
utilizes semiquantitative (± a factor of 3) techniques of sample collection
-------
and laboratory and field analyses to: provide preliminary emissions data
for waste streams and pollutants not adequately characterized; Identify
potential problem areas; and prioritize waste streams and pollutants in those
streams for further, more quantitative testing. Using the information from
Level I» available resources can be directed toward Level II testing which
involves specific, quantitative analysis of components of those streams
which contain significant pollutant loadings. The data developed at Level
II are used to identify control technology needs and to further define the
environmental hazard associated with each process stream.
1.2 THE EXISTING EMISSIONS DATA BASE
A major task in this project has been the identification of gaps and
inadequacies in the existing data base for emissions from external combustion
sources for electricity generation. Decisions as to the adequacy of the data
base were made using criteria developed by considering both the reliability
and variability of the data. Estimated environmental risks associated with
the emission of each pollutant were also considered in the determination of
the need for, and extent of, the sampling and analysis program. For criteria
pollutants, comparison of calculated maximum ground level concentrations with
national primary ambient air quality standards was used as the basis for
estimation of environmental risks.
Existing emissions data were evaluated prior to the conduct of the
sampling and analysis program. As a result of the data evaluation effort,
a number of data inadequacies have been identified. For flue gas emissions,
the status of the existing data base can be summarized as follows:
• The existing data base for criteria pollutants is generally
adequate.
t For sulfuric acid emissions, the existing data base is
adequate for bituminous coal-fired boilers, residual oil-
fired boilers, and gas-fired boilers, and inadequate for
lignite-fired boilers. For emissions of primary sulfates,
the existing data base is adequate for pulverized bituminous
dry bottom and wet bottom boilers, residual oil-fired
boilers, gas-fired boilers, and inadequate for other com-
bustion source categories.
e For emissions of particulates by size fraction and trace
elements, the existing data base is adequate for gas-fired
boilers and inadequate for all other combustion source
categories.
-------
• For emissions of specific organics and polycyelic organic
matter (POM), the existing data base is inadequate for
all combustion source categories.
Two other sources of air emissions of environmental concern are cooling
tower emissions and emissions from coal storage piles. The existing data
bases characterizing air emissions from these two sources are considered to
be inadequate, because past studies were primarily focused on the measure-
ments of a limited number of chemical constituents and total particulates.
Emissions from ash handling and storage and fuel handling are not addressed
here because characterization of these emissions is outside the scope of
this study.
For wastewater effluents from external combustion sources for electrici-
ty generation, the existing data base is considered to be adequate for waste-
water from water treatment processes, and inadequate for all other streams.
This is because past studies were limited to the characterization of gross
parameters such as pH and total suspended solids (TSS) and a few inorganic
constituents. Organic characterization data are generally not available.
The evaluation of existing emissions data for solid wastes indicated
the inadequacy of the organic data base for coal fly ash and bottom ash, and
the inadequacy of the inorganic and organic data bases for FGD sludges. On
the other hand, the inorganic data base for coal ash is considered to be
adequate because of the adequate characterization of the Inorganic content
of coal. Similarly, the data base for water treatment wastes is considered
to be adequate, because the waste constituents are inorganic and can be
estimated from the raw water constituents and the treatment method used.
1.3 THE SOURCE MEASUREMENT PROGRAM
Because of the deficiencies in the existing emissions data base, 46
.sites were selected for sampling and analysis of flue gas emissions, and 6
sites were selected for sampling and analysis of air emissions from cooling
towers. At a selected number of these sites, wastewater streams and solid
wastes were also sampled and analyzed. Wastewater streams sampled and
analyzed included cooling tower blowdown, once-through cooling water, boiler
blowdown, fly ash pond overflow, bottom ash pond overflow, and combined ash
pond overflow. Intermittent wastewater streams such as chemical cleaning
-------
wastes and coal pile runoff were not sampled. Solid waste streams sampled
and analyzed included fly ash, bottom ash, and F6D scrubber sludge.
The emphasis on air sampling in this project was an attempt to minimize
duplication of efforts. At the beginning of the project, review of the
ongoing studies indicated a number of parallel projects that were directed
towards the characterization of wastewater and solid waste discharges from
power plants. These projects included TVA studies to characterize coal pile
drainage, ash pond discharges, chlorinated once-through cooling water dis-
charge, and chemical cleaning wastes from periodic boiler-tube cleaning to
remove scales, and studies conducted by the Aerospace Corporation to provide
data on the characteristics of wastewater discharges from flue gas desulfur-
ization systems. Additionally, extensive scrubber sludge characterization
studies are conducted by Arthur D. Little, Inc. under the direction of EPA.
1.4 SAMPLING AND ANALYSIS METHODOLOGY
1.4.1 Level I Field Testing
The Source Assessment Sampling System (SASS) train, developed by EPA,
was used to collect both vapor and particulate emissions in quantities
sufficient for the wide range of analyses needed to adequately characterize
emissions from external combustion sources. Briefly, the SASS train con-
sists of a conventional heated probe, three cyclones and a filter in a
heated oven which collect four particulate size fractions (>10 ym, 3-10 pm,
1-3 pm, <1 pm); a gas conditioning system; an XAD-2 polymer adsorbent trap
to collect gaseous organics and some inorganics; and impingers to collect
the remaining gaseous inorganics and trace elements. The train is run until
at least 30 m of gas has been collected.
In addition to using the SASS train for stack gas sampling, other
equipment was employed to collect those components that could not be analyzed
from the train samples. A gas chromatograph (GC) with flame ionization de-
tection was used in the field to analyze hydrocarbons in the boiling point
range of -160 to 90°C (reported as C,-Cg) collected in gas sampling bags.
Additionally, these samples were analyzed for CO, COg, 02i and S02 by GC
using a thermal conductivity detector.
-------
Water samples were generally taken by either tap sampling or dipper
sampling. Tap samples were obtained on contained liquids in motion or static
liquids in tanks or drums. This sampling method was generally applicable to
cooling tower blowdown or boiler blowdown. The method involved the fitting
of the valve or stopcock used for sample removal with a length of pre-cleaned
Teflon tubing long enough to reach the bottom of the container. The dipper
sampling procedure, applicable to sampling ponds or open discharge streams,
was used in the acquisition of ash pond discharge samples. The method in-
volved the use of dipper with a flared bowl and attached handle, long enough
to reach discharge areas. After sample recovery, water analyses using the
Hach kit were performed in the field to determine pH» conductivity, total
suspended solids (TSS), hardness, alkalinity or acidity, ammonia nitrogen,
cyanide, nitrate nitrogen, phosphate, sulfite and sulfate.
For solids sampling, the fractional shovel grab samples procedure was
used unless the plant had an automatic sampling system. The concept of
fractional shoveling involves the acquisition of a time-integrated grab
sample representative of overall process input or output during a given run
time period. A standard square-edged shovel, 12 inches wide, was used. For
streams entering or exiting a process operation, a full cross-stream cut
sample was taken from the belt on an hourly basis. Each hourly shovel sample
was added to a pile to eventually form a run time period composite. At the
conclusion of the run this pile was coned and quartered to form a final
representative sample weighing from 2.3 to 4.5 kilograms. When plants were
equipped with automatic samplers to remove representative cross sections of
a stream while automatically forming a homogeneous composite, these were
used in preference to the shovel technique.
In addition to the above sampling methods, sampling for air emissions
from cooling towers was performed using a modified EPA Method 5 train with-
out the filter assembly.
1.4.2 Modified Leye1 | Laboratory Analysis
The basic Level I schematic outlining flow of samples and analysis
plans for particulate and gaseous emissions is depicted in Figure 1. The
corresponding schematic for solid, slurry, and liquid samples is presented
in Figure 2. These schematics provide a general idea on the apportionment
-------
PARTICULAR
MATTER
1
.«y»3
T
SOURCE — »
T
OfACITY
(STACKS)
GAS
•WIIGH
INDIVIDUAL
CATCHES
IF INORGANICS
ARE GREATER THAN
10% OF TOTAL CATCH.
1 ^ 1
-HJLJ 1
H3-IOM * 1 • «
, , , 1
tt 1-3|i * 1— »
* f ~
HC^
_ ORGANIC
~ * MATERIAL C| -C*
ONE-SITE GAS
CHROMATOGRAPm
XAD^_
MODULE RINSE
1 EXTRACTION
ON-SITEGAS
CHMDMATOGRAPHY
« PHYSICAL SEPARATION
a INTO LC FRACTIONS,
1
r, ELEMENTS (SSMS) AND
L> SELECTED ANIONS
CS ELEMENTS AND
SELECTED ANIONS
.. ELEMENTS (SSMS) AND
-5 SELECTED ANIONS
11 ELI
IKinRfXAMIfXl
I 5E'
, , , PH
1 — »| ORGANICS j ||!
IR/
, PHYSICAL SEPARATION
* INTO LC FRACTIONS, IR/LRMS
_ _^ INORGANIC!
ORGANICS
* C7-CW
ORGANICS
-'C14
| ELEMENTS (SSMS) AND
' 1 SELECTED ANIONS
ALIQUOT FOR GAS
CHROMATOGRAPH1C
ANALYSIS
PHYSICAL SEPARATION
INTO LC FRACTIONS, IR
ELEMENTS (SSMS) AND
SELECTED ANIONS f
PHYSICAL
SEPARATION
INTO LC FRACTIONS,
Figure 1. Basic Level 1 Sampling Flow and Analytical Plan
for Particulates and Gases
-------
SOLIDS
SOURCE
SLURRIES
LIQUIDS
LEACHABLE
MATERIALS
INORGANICS
PHYSICAL SEPARATION
C FRACTiONS
(SSMS) AND
ELEMENTS (SSMS)AND
SELECTED ANIONS
PHYSICAL SEPARATION
ORGANICS I INTO LC FRACTIONS, IR/LRMS
SUSPENDED
SOLIDS
ElEMENTS (SSMS) AND
SELECTED
«.^* ,.,.^«. • PHYSICAL SEPARATION
ORGANICS I INTO LC FRACTIONS, IR/LRMS
IMngr_AHir"r 1 gj-EMENTS fSSMSl AND
INORGANICS "'^
SELECTED
WATER
TESTS
ORGANIC
EXTRACTION
OR DIRECT
ANALYSIS
ORGANICS
ORGANICS
-------
of samples for analysis. For example, it is shown in Figure 1 that the probe
and cyclone rinses combination will only be subjected to inorganic analysis
if the dried sample exceeds 10 percent of the total cyclone and filter sample
weight. Details ,of the sample handling, transfer, and analysis procedures
can be found in the I|RL-RTPProcedures Manual: Level I Environmental.
Assessment, EPA-600/2-76-160a. A brief description of inorganic and organic
analyses performed and the deviations from the basic Level I procedure
follows.
Inorgan1c Ana1yses
Level I analysis was used for all inorganic analyses. It was designed
to identify all elemental species in the SASS train fractions and to provide
semiquantitative data on the elemental distributions and total emission fac-
tors. The primary tool for Level I inorganic analysis is the Spark Source
Mass Spectrometry (SSMS). SSMS data were supplemented with Atomic Absorption
Spectrometry (AAS) data for Hg, As, and Sb and with specific ion electrode
determinations for chlorides.
The following SASS train fractions were analyzed for their elemental
composition: 1} the particulate filter, 2) the XAD-2 sorbent, and 3) a
composite sample containing portions of the XAD-2 module condensate and HNOg
rinse, and the first impinger solution. Analyses of the carbon, hydrogen,
nitrogen, oxygen, and trace element contents and heating values of the fuel
were also performed for the coal-fired and oil-fired sources.
Organic Analyses
Level I organic analyses provides data on volatile (boiling point range
of 90 to 300°C, corresponding to the boiling points of £7-^5 n-alkanes and
reported as C^-C^g) and non-volatile organic compounds (boiling point >300°C,
corresponding to the boiling points of >C,g n-alkanes and reported as >C,g)
to supplement data for gaseous organics (boiling point range of -160 to 90°C,
corresponding to the boiling points of C^-Cg n-alkanes and reported as C-j-Cg)
measured in the field. Organics in the XAD-2 module condensate trap and
XAD-2 resin were recovered by methylene chloride extraction. SASS train
components including the tubing were carefully cleaned with methylene chlo-
ride or methylene chloride/methanol solvent to recover all organics collected
in the SASS train.
8
-------
Because all samples are too dilute to detect organic compounds by the
majority of instrumental techniques employed, the first step in the analysis
was to concentrate the sample fractions from as much as 1000 ml to 10 ml in
a Kuderna-Danish apparatus in which rinse solvent is evaporated while the
*
organics of interest are retained . Kuderna-Danish concentrates were then
evaluated by gas chromatography (SC)» infrared spectrometry (IR), liquid
chromatography (LC), gravimetric analysis, low resolution mass spectroscopy
(LRMS), and sequential gas chromatography/mass spectrometry (GC/MS) . The
extent of the organic analysis is determined by the stack gas concentrations
found for total organics (volatile and non-volatile). If the total organics
3
indicate a stack gas concentration below 500 vg/m , a liquid concentration
below 0.1 mg/1, or a solid concentration below 1 mg/kg, further analysis is
not conducted. If the concentrations are above these levels, a class frae-
tionation by liquid chromatography is conducted followed by GC and IR
analyses. Additionally, if the concentrations in a LC fraction are above
these levels, LRMS is conducted for that particular LC fraction.
1.5 RESULTS
1.5.1 Air Emissions
The results of the field measurement program for flue gas emissions
from utility boilers, along with supplementary values for certain pollutants
obtained from the existing data base, are presented in Tables 1, 2, and 3.
Also listed in these tables are source severity factors, defined as the
ratio of the calculated maximum ground level concentrations of the pollutant
species to the level at which a potential environmental hazard exists. The
source severity factor defined in this manner is known as ambient severity.
A severity factor of greater than 0.05 is indicative of a potential problem
requiring further attention. The "greater than 0.05" criterion reflects an
uncertainty factor of 20 in the calculation of ambient severity, because of
potential errors introduced in the application of the dispersion model, and
in Level I sampling and analysis.
Kuderna-Dantsh is a glass apparatus for evaporating bulk amounts of
solvents.
The major modification in the Level I sampling and analysis procedure was
the addition of GC/MS analysis for POM.
-------
TABLE 1. SUMMARY OF ASSESSMENT RESULTS FOR FLUE GAS EMISSIONS
FROM BITUMINOUS COAL-FIRED UTILITY BOILERS
Pulverized Dry Bottom
Pollutant
N0x
Total Hydrocarbons
CO
Partlculates (Controlled)
S02 (Uncontrolled)
so3
Parti cul ate Sulfate (Controlled)
Trice Elements
Aluminum
Beryl 1 1 urn
Calcium
Chlorine
Fluorine
Iron
Lead
Lithium
Nickel
Phosphorus
Silicon
POM
Dibenz( a, h) anthracene
Benzo(a)pyrene/Benzo(e)pyrene
Total POM
Emission
Factor
(ng/J)
259*. 379f
4.5
17
251
1,407
13.9
0.72
8.5
0.0022
5.6
33.9
4.1
8.4
0.039
0.024
0.062
0.11
15.2
0.00022
BO
0.0039
Source
Severity
Factor
1.95*. 2.85f
0.027
0.0005
0.66
2.64
3.50
0.15
0.53
0.23
0.12
1.03
0.34
0.22
0.053
0.23
0.13
0.22
0.31
0.50
NA
NA
Pulverized
Emission
Factor
(ng/J)
380
4.5
86
213
1,407
13.9
2.9
6.9
0.0018
4.6
33.9
4.1
6.8
0.031
0.020
0.050
0.086
12.4
BD
0.0035
0.042
Wet Bottom
Source
Severity
Factor
1.70
0.016
0.0015
0.33
1.57
2.09
0.37
0.16
0.11
0.056
0.61
0.20
0.11
0.026
o.n
0.06
0.11
0.15
NA
21
NA
Cycl one
Emission
Factor
(ng/J)
678
9.5
82
57
1,407
14.1
10.8
1.4
0.00037
0.95
33.9
4.1
1.4
0.0066
0.0041
0.011
0.018
2.6
BD
BD
0.0059
Source
Severity
Factor
6.36
0.072
0.0030
0.19
3.29
4.45
2.84
0.071
0.048
0.025
1.28
0.42
0.047
0.011
0.048
0.027
0.046
0.066
NA
NA
NA
Stokers
Emission
Factor
(ng/J)
241
11
157
603
1,407
13.9
10.5
2.6
0.0055
2.6
33.9
4.1
20.9
0.61
0.011
1.4
0.55
8.7
BO
BD
0.015
Source
Severl ty
Factor
0.13
0.0048
0.0003
0.12
0.19
0.26
0.16
0.008
0.041
0.004
0.075
0.024
0.040
0.061
0.008
0.211
0.083
0.013
NA
NA
NA
BD - Below detection limit. Detection limit for POM was 0.3 wg/m or approximately 0.0001 ng/J.
NA - Not applicable.
For tangentlally-flred pulverized bituminous dry bottom boilers.
For wall-fired pulverized bituminous dry bottom boilers.
*For pulverized dry bottom, pulverized wet bottom, and cyclone boilers, the trace element emission factors presented are for
units equipped with electrostatic precipltators. For stokers, the trace element emission factors presented are for units
equipped with multlclones.
-------
TABLE 2. SUMMARY OF ASSESSMENT RESULTS FOR FLUE GAS EMISSIONS FROM LIGNITE-FIRED UTILITY BOILERS
Pollutant
NOX
Total Hydrocarbons
CO
Particulates (Controlled)
SO? (Uncontrolled)
S03
Parti cul ate Sulfate (Controlled)
*
Trace Elements
Aluminum
Ban" urn
Beryl 1 1 urn
Calcium
Copper
Fl uori ne
Magnesium
Nickel
Phosphorus
POH
Bi phenyl
Trimethyl propenyl naphthalene
Pul veri zed
Emission
Factor
(ng/J)
260
9.0
33
62
628
ND
0.82
0.068
<0.025
<0.001
0.39
<0.030
0.24
<0.22
<0.068
<0.034
BO
0.0033
Dry Bottom
Source
Severity
Factor
4.28
0.12
0.002
0.36
2.57
ND
0.38
0.006
<0.023
<0.23
0.017
<0.068
0.044
<0.016
<0.31
<0.16
NA
0.0001
Cyclone
Emission
Factor
(ng/J)
333
4.7
33
132
628
ND
0.49
<0.067
<0.037
<0.0003
<1.5
0.013
0.80
<0.16
<0.047
<0.013
0.00002
0.00034
Source
Seven' ty
Factor
5.33
0.061
0.002
0.74
2.50
ND
0.22
<0.006
<0.032
<0.066
<0.067
0.029
0.14
<0.011
<0.21
<0.055
<0.0001
< 0.0001
Stokers
Emission
Factor
(ng/J)
195
4.4
65
615
628
ND
47.6
15.2
2.0
0.0059
< 140
0.083
0.42
< 27
0.28
1.5
BD
0.0032
Source
Severi ty
Factor
0.14
0.002
0.0002
0.15
0.11
ND
0.93
0.056
0.076
0.057
<0.27
0.008
0.003
<0.085
0.053
0.30
NA
<0.0001
ND - No data.
BD - Below detection limit. Detection limit for POM was 0.3 vg/m-' or approximately 0.0001 ng/J.
NA - Not applicable.
For pulverized dry bottom and cyclone boilers, the trace element emission factors presented are for
units equipped with electrostatic precipitators. For stokers, the trace element emission factors
presented are for units equipped with multiple cyclones.
-------
TABLE 3. SUMMARY OF ASSESSMENT RESULTS FOR FLUE GAS EMISSIONS
FROM RESIDUAL OIL- AND GAS-FIRED UTILITY BOILERS
ro
Residual 011
Pollutant
NOX
Total Hydrocarbons
CO
Particulates
SO? (Uncontrolled)
S03
Parti cul ate Sulfate
Trace Elements
Beryl 1 1 urn
Chlorine
Copper
Lead
Magnesi urn
Mercury
Nickel
Phosphorus
Selenium
Vanadi urn
POM
Benzopyrenes/ ,
perylenes
Total POM
ND - No data.
BD - Below detection
Tangential
Emission
Factor
(ng/J)
114
4.6
56
30
448
13.8
3.3
0.0024
3.1
0.35
0.034
2.4
0.0015
0.43
0.13
0.025
3.7
>.25xlO"7
0.0047
Firing
Source
Severity
Factor
1.90
0.060
0.0035
0.17
1.79
7.43
1.48
0.52
0.20
0.77
0.098
0.18
0.013
1.90
0.57
0.056
3.22
0.014
NA
limit. Detection 1
Wall
Emission
Factor
(ng/J)
190
4.6
56
30
448
13.8
3.3
0.0024
3.1
0.35
0.034
2.4
0.0015
0.43
0.13
0.025
3.7
6.25xlO"7
0.0047
imit for POM
Fi ri ng
Tangential
Source Emission
Severity
Factor
1.17
0.022
0.0013
0.061
0.66
2.76
0.55
0.19
0.072
0.29
0.036
0.065
0.005
0.71
0.21
0.021
1.19
0.005
NA
was typically
Factor
(ng/J)
124
2.4
33
0.25
0.25
ND
ND
BD
2.9
0.021
BD
BD
0.0049
0.042
0.070
BD
BD
BD
BD
•3
0.3 yg/nT
Natural Gas
Fi ri ng
Source
Severity
Factor
3.21
0.047
0.0031
0.0021
0.0015
ND
ND
NA
0.29
0.069
NA
NA
0.064
0.28
0.46
NA
NA
NA
NA
Mall
Emission
Factor
(ng/J)
233
2.4
33
0.25
0.25
ND
ND
BD
2.9
0.021
BD
BD
0.0049
0.042
0.070
BD
BD
BD
BD
or approximately 0.
Fi ri ng
Source
Sever! ty
Factor
2.94
0.024
0.0015
0.0010
0.0007
ND
ND
NA
0.14
0.034
NA
NA
0.031
0.14
0.23
NA
NA
NA
NA
0001
NA -
ng/J. However, lower detection limits were obtained for less complex samples with fewer inter-
ferences or closely eluting GC peaks.
Not applicable.
-------
As can be seen from Tables 1, 2, and 3, the major criteria pollutants
of concern are nitrogen oxides from all combustion source categories, and
sulfur dioxide from all but gas-fired combustion sources. Source severity
factors are also greater than 0.05 for controlled particulate emissions from
bituminous coal-fired and lignite-fired sources, uncontrolled particulate
emissions from residual oil-fired sources, and total hydrocarbon emissions
from bituminous coal-fired cyclone boilers, lignite-fired pulverized dry
bottom and cyclone boilers, residual oil and gas tangentially-fired boilers,
indicating the environmental significance of the emissions of these pollu-
tants. Emissions of carbon monoxide from utility boilers do not appear to
be a problem. Additionally, source severity factors for emissions of SOg
(in the form of sulfuric acid vapor and aerosols) and particulate sulfate
from all coal-fired and oil-fired utility boilers are greater than 0.05.
The environmental problems associated with emissions of nitrogen oxides,
sulfur dioxide, and particulate from utility boilers are well known. On
December 23, 1971, EPA issued the original New Source Performance Standards
(NSPS) to limit emissions of these pollutants from power plants. The Clean
Air Act Amendments, enacted August 7, 1977, required EPA to revise its 1971
standards for power plants to reflect advances in control technology. On
June 11, 1979, EPA promulgated the revised NSPS to further limit emissions
of nitrogen oxides, sulfur dioxide, and particulate matter from power plants.
Particulate size distribution data acquired in the current study showed
that for bituminous coal-fired utility boilers equipped with electrostatic
precipitators, the >10 pm fraction accounted for 1.4 to 82 percent of the
total particulate emissions. For lignite-fired utility boilers equipped
with multiclones, the >10 jim fraction contributed from 50 to 59 percent of
the total particulate emissions. An average of less than 15 percent of the
particulate emissions from uncontrolled residual oil-fired utility boilers
were >10 ym in size.
Trace element data summarized in Tables 1, 2, and 3 are for elements
associated with source severity factors greater than 0.05 in at least one of
the source subcategories (e.g., pulverized dry bottom boilers firing bitumi-
nous coal). Among the trace elements, emissions of beryllium, nickel and
phosphorus appear to be a common concern for bituminous coal-fired, lignite-
13
-------
fired, and residual oil-fired sources. An unusual result is that for gas-
fired utility boilers, chlorine, copper, mercury, nickel, and phosphorus
were found to have source severity factors greater than 0.05. The validity
of these observations will require confirmation by Level II tests.
Data for polycyclic organic matter (POM) indicated the presence of
dibenz(a,h)anthracene in pulverized bituminous dry bottom boilers, and
benzo(a)pyrene/benzo(e)pyrene in pulverized wet bottom boilers. Both
dibenz(a,h)anthracene and benzo(a)pyrene are active carcinogens. A benzo-
pyrene, possibly benzo(a)pyrene, was also detected at a residual oil-fired
site. The only POM compounds detected at lignite-fired sites were biphenyl
and trimethyl propenyl naphthalene, neither of which is known to be carcino-
genic. No POM was detected at gas-fired utility sites. The detection limit
3
for POM was typically 0.3 pg/m , or approximately 0.1 pg/J.
Air emissions of chlorine, phosphorus, and magnesium from cooling
towers are of the same order of magnitude as those from residual oil-fired
utility boilers and of environmental concern. Based on thermal energy input
to the associated power plants, the mean emission factors for chlorine,
phosphorus, and magnesium were determined to be 2.4 ng/J, 0.22 ng/J, and
0.56 ng/J, respectively. The high emission rates for chlorine and phosphorus
were due to the use of chlorine and phosphate additives. The high emission
rate for magnesium was due to the high solids content in the source of
cooling water at one site.
All six cooling towers tested employed sulfuric acid as an additive.
Sulfate emissions from these cooling towers ranged from 3 to 41 ng/J. By
comparison, controlled sulfate emissions from coal-fired utility boilers and
sulfate emissions from oil-fired utility boilers are typically in the 20 to
30 ng/J range.
1.5.2 Wastewater Effluents
The results of sampling and analysis for cooling tower blowdown, boiler
blowdown, and ash pond overflow in this program were combined with existing
data and summarized in Table 4. Also listed in this table are discharge
severities, defined as the ratio of discharge concentration to the health
based water Minimum Acute Toxicity Effluent (MATE) value. A discharge
14
-------
TABLE 4. SUMMARY OF ASSESSMENT RESULTS FOR COOLING TOWER SLOWDOWN,
BOILER SLOWDOWN, AND ASH POND OVERFLOW
Constituent
Gross Parameters
pH
Conductivity,
Hardness,
(as CaCO,), ng/1
Alkalinity
(as CaCO,), «g/1
TSS, ng/1 4
BOD, ng/1
COD, nig/1
Trace Elements, mg/1
Arsenic
Calcium
Cadmium
Chromium
Iron
Magnesium
Manganese
Nickel
Phosphorus
Selenium
Silicon
Chloride, mg/1
Sulfate, mg/1
Phenols, mg/1
Organ ics, mg/1
Total volatile
Total nonvolatile
Cooling Tower
Effluent
Concentration
7.3
3,050
1,220
56
26
18
94
0.28
1,700
0.094
0.48
1.8
650
0.30
...
9.9
0.081
...
—
1,300
0.021
1.4]
Slowdown
Discharge
Severity
NA
NA
NA
NA
NA
NA
NA
1.1
0.89
1.9
1.9
1.2
1.4
1.2
—
6.6
1.6
—
—
1.0
—
NA
NA
Boiler Slowdown
Effluent
Concentration
10.5
150
340
97
87
3.0
53
...
...
—
—
—
—
8.0
—
—
—
0.026
1.3
4.7
Discharge
Severity
NA
NA
NA
NA
NA
NA
NA
...
—
...
—
5.3
—
—
—
—
5.2
NA
NA
Fly Ash Pond
Effluent
Concentration
5.8
10,000
220
30
49
ND
ND
8.7
...
—
1.2
0.2S
0.40
—
—
—
—
—
—
0
0.056
Overflow
Discharge
Severi ty
NA
NA
NA
NA
NA
NA
NA
35
—
—
...
0.80
. — •
1.0
1.8
—
—
—
—
NA
NA
Bottom Ash Pond Overflow
Effluent
Concentration
7.4
6,000
205
62
41
ND
ND
2.2
—
—
—
2.5
410
0.19
—
—
—
—
—
—
—
0.00?
0.090
Discharge
Severity
NA
NA
NA
NA
NA
NA
NA
8.9
—
—
—
1.7
0.85
0.76
—
—
—
—
—
—
NA
NA
Combined Ash Pond Overflow
Effluent
Concentration
9.2
480
185
81
33
ND
ND
—
...
—
—
—
—
—
—
...
—
—
0
0.070
Discharge
Severity
NA
NA
NA
NA
NA
NA
NA
—
—
—
—
—
...
—
—
—
—
—
—
—
NA
NA
ND - No data because analysis for these parameters w*s not performed.
NA - Not applicable because there are no KATE values associated with these parameters to compute discharge severities.
Data for constituents with discharge severities less than 1.0 are indicated by "—".
-------
severity greater than 1.0 is indicative of a potential hazard requiring
further characterization or development of improved control technology. The
"greater than 1.0" criterion instead of the "greater than 0.05" criterion
for ambient severity was used because calculation of discharge severities
was based on conservative MATE values. Also, the uncertainty in the calcula-
ted values only involved potential sampling and analysis errors. The error
due to the application of dispersion models was no longer a component.
Other wastewater effluents, including water treatment wastewater,
chemical cleaning wastes, FGD wet scrubber wastewater, and coal pile runoff,
were not sampled in this project. Characterization data for these wastewater
streams, based on results of previous studies reported in the literature,
are summarized in Table 5. In both Tables 4 and 5, data for wastewater
constituents with discharge severities less than 1.0 are not presented.
Also, data for once-through cooling water are not included in Table 4, as
discharge severities for all constituents in this wastewater stream are
extremely low.
The summary data presented in Tables 4 and 5 show that cooling tower
blowdown, clarification wastewater, chemical cleaning wastes, FGD wet
scrubber wastewater, and coal pile runoff all contain a significant number
of constituents with discharge severities greater than 1.0. The pollutants
of most concern are copper, iron, manganese, nickel, and phosphorus. Based
on discharge severities, the boiler blowdown and ash pond overflow streams
appear to be less environmentally significant. Of all the wastewater streams
investigated, the ash pond overflows are the only streams which have been
subjected to treatment by sedimentation. If all the other wastewater streams
were also sent to settling ponds before release, their discharge severities
should also be considerably lower.
The average organic levels in the wastewater streams sampled were less
than 6 mg/1. POM compounds were not found above the detection limit of
2 yg/1.
1.5.3 Solid Wastes
A number of fly ash and bottom ash samples from bituminous coal-fired
and lignite-fired utility boilers were acquired and analyzed in the current
16
-------
TABLE 5. SUMMARY OF ASSESSMENT RESULTS FOR WATER TREATMENT WASTEWATER, CHEMICAL CLEANING WASTES,
WET SCRUBBER WASTEWATER, AND COAL PILE RUNOFF
Water Treatment Wasttwater
Constituent
Gross Parameters
PH
Hardness
Sas CaO>3), mg/1
Alkalinity
(as CiCOa), mg/1
TSS, mg/1
BOO, mg/1
COO, mg/1
Trace Elements, mg/1
Aluminum
Beryllium
' ChronluBi
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Phosphorus
Selenium
Sodium
Zinc
Chloride, mg/1
Sulfatt, ng/1
AmKHila, ng/1
Hydra; Ine, mg/1
Phenols, mg/1
Ion Exchange
Effluent
Concentration
NO
1,000
560
32
36
48
—
0.27
4.2
—
—
...
...
—
...
3, ZOO
—
1,800
.-.
—
—
Discharge
Severity
NA
NA
NA
NA
NA
NA
—
1.0
—
2.8
—
—
.--
...
—
...
4.0
—
1.5
...
—
Clarification
Effluent
Concentration
ND
3,300
340
25, ZOO
20
160
160
—
0.61
—
350
—
—
—
...
0.32
—
...
—
...
...
—
—
Discharge
Severity
NA
NA
NA
NA
NA
NA
1.1
—
2.4
—
233
—
—
—
...
1.5
—
...
...
—
...
...
—
Acid Phase Composite
Effluent
Concentration
1.1
ND
NO
45
ND
2,870
...
—
2.9
15
2,880
2.1
—
19
...
178
35
...
—
48
...
~ —
—
0.044
Discharge
Severity
NA
NA
NA
NA
NA
NA
—
12
3.0
1,920
8.2
—
77
...
809
23
...
—
1.9
—
...
—
—
8.8
Chemical Cleaning Hastes
Alkaline Phase Composite
Effluent
Concentration
ND
ND
ND
67
NO
90
—
—
530
2.4
—
—
—
...
1.6
143
...
—
—
—
...
2,740
—
Neutralization Drain
Met Scrubber
Wastewater
Discharge Effluent Discharge Effluent Discharge
Severity Concentration Severity Concentration Severity
NA
NA
NA
NA
NA
NA
—
—
106
1.6
—
...
...
_..
7.1
95
...
...
10
—
11.4 NA
ND NA
ND NA
47 NA
ND NA
70 NA
— —
— —
— — .
5.1 1.0
7.3 4.8
— —
— —
— —
... -~-
... —
755 503
... ..~
0.060 1.3
— —
— —
...
— —
0.013 5.7
7.5
ND
108
ND
ND
185
—
0.04
—
—
—
...
580
0.85
0.044
0.50
—
0.59
1,100
—
2,500
4,700
...
—
NA
NA
NA
NA
NA
NA
—
1.3
—
—
—
—
1.2
3.4
4.4
2.3
—
12
1.4
—
2.1
3.6
—
—
Coal Pile Runoff
Effluent Discharge
Concentration Severity
2.7
ND
ND
330
NO
ND
150
0.03
—
—
660
—
—
33
1.5
—
—
...
—
...
—
NA
NA
NA
NA
NA
NA
1.0
1.0
-_.
—
440
—
—
131
-.-
6.6
—
™_.
.--
—
„_.
..-
—
—
'Sludge liquor from 1 lmt/1 linestone FGO scrubber.
ND - No d«U.
NA - Not applicable because there ire no NATE values associated with these parameters to compute
discharge severities.
Data for constituents »1th discharge severities less than 1.0 are indicated by "—".
-------
study. The analysis results, supplemented by additional data from the
existing literature, are summarized in Table 6. Discharge severities pre-
sented in the same table are defined as the ratio of concentration in the
solid to the health based solid MATE value. Data for ash trace element
constituents with discharge severities less than 1.0 are not presented.
The data on fly ash and bottom ash show that from 11 to 16 of the trace
element constituents in ash have discharge severities greater than 1.0.
The pollutants of most concern are aluminum, arsenic, calcium, chromium,
iron, manganese, nickel, potassium, and silicon. Also, the concentrations
of arsenic, barium, boron, calcium, and magnesium in lignite ash appear to
be substantially higher than the concentrations of these elements in bitu-
minous coal ash.
Most of the organics in fly ash and bottom ash are present as the >C,g
fraction. POM compounds were found in only two of the samples above the
detection limit of 2 ppm. Even for these two samples, the POM compounds
detected were naphthalene, alkyl naphthalenes and other compounds with high
MATE values and do not appear to pose a potential hazard.
Characterization for scrubber sludges in the current study was limited
to samples obtained from a single limestone FGD scrubber system. Analyses
for the samples indicated that concentrations of ten trace elements in the
scrubber sludge exceeded their respective health based solid MATE values.
These ten trace elements were: aluminum, arsenic, beryllium, calcium, cad-
mium, iron, manganese, nickel, lead, and zinc. Organics detected in the
scrubber sludge samples were limited to approximately 5 ppm of CQ and 2 ppm
of C-jg. Further, POM was not detected at the 2 ppm level.
1.6 CONCLUSIONS
The current study involved the evaluation of an extensive amount of
data from existing sources and the field sampling and analysis program. As
a result of this assessment process, a number of conclusions were reached
regarding the emission characteristics of external combustion sources for
electricity generation. These conclusions are listed as follows.
18
-------
TABLE 6. SUMMARY OF ASSESSMENT RESULTS FOR FLY ASH AND BOTTOM ASH
FROM BITUMINOUS COAL-FIRED AND LIGNITE-FIRED BOILERS
Pollutant
Trace Clements
Alunlnum
Arsenic
Barium
Boron
Calcium
Chromium
Cobalt
Iron
Lead
Lithium
Magnesium
Manganese
Htrcury
Nickel
Phosphorus
Potassium
Selenium
Silicon
Organ 1cs
Total volatile
(CI-CIB)
Total nonvolatile
{>C]g)
Bituminous
Concentration
{ppm)
4,300-100,000
3-240
280-640
25-700
1,100-121,000
19-300
7- 57
32,000-143,000
7-110
46- 86
820- 13,400
100-300
0.01 - 28
10-250
82- 5,100
2,900- 20,000
4- 32
17,000-276,000
<14- 87
0-420
Fly Ash
Discharge
Severity
0.27 -6,3
0.06 -4.8
0.28 -0.64
0.003 -0.075
0.023 -2.5
0.38 -6.0
0.047 -0.38
110 - 480
0.14 -2.2
0.66 -1.2
0.046 -0.74
2.0 -6.0
0.0005-1.4
0.22 -5.6
0.027 -1.7
0.69 -4.8
0.4 -3.2
0.57 -9.2
NA
NA
Bituminous
Concentration
{PP*)
3,700- 90,000
1- 18
220-450
5.5 -300
3,100- 93,000
15-220
4- 31
47,000-213,000
6-120
3- 60
1,300- 12.400
37-860
0.1 - 0.5
0.3 -100
120- 3,800
1,000- 15,800
<1- 5.6
7,500-276,000
<14- 87
0-900
Bottom Ash
Discharge
Severl ty
0.23 -5.6
0.02 -0.36
0.22 -0.45
0.0006-0.032
0.065 -1.9
0.30 -4.4
0.027 -0.21
160 - 710
0.12 -2.4
0.043 -0.86
0.072 -0.69
0.74 - 17
0.005 -0.025
0.007 -2.2
0.04 -1.3
0.24 -3.8
<0.1 -0.56
0.25 -9.2
NA
NA
Lignite Fly Ash
Concentration
(ppm)
3,500- 35,000
79-830
1,200- 15,000
320- 13,000
27,000-130,000
8.1 - 64
7.1 - 1,200
1.000- 11,000
9.3 -160
1.3 - 62
17,000- 32,000
200- 1,300
0.086- 2.0
21- 1,600
120- 4,600
1,200- 30,000
<2.1 - 19
34,000- 53,000
0.5 - 15
43-300
Discharge
Severity
0.22 -2.2
1.6 - 17
1.2 - 15
0.034 -1.4 .
0.56 -2.7
0.16 -1.3
0.047 -8.0
3.3 - 37
0.19 -3.2
0.019 -0.89
0.94 -1.8
4.0 - 26
0.0043-0.1
0.47 - 36
0.04 -1.5
0.29 -7.1
«0.21 -1.9
1.1 -1.8
NA
NA
Llgni te Bottom Ash
Concentration
(PP*)
8,100- 27,000
22-400
2,100- 20,000
490- 6,300
63,000-130,000
5.1 - 22
6- 11
27.000- 71,000
4.3 -150
3.8 - 79
4.600- 35,000
310- 1,000
«0,017- 0.094
44-140
110- 5,200
660- 15,000
1.3 - 5.5
31,000- 50,000
0.9 - 11
150-300
Discharge
Severl ty
0.51 -1.7
0.44 -8.0
2.1 - 20
0.053-0.68
1.3 -2.7
0.10 -0.44
0.04 -0.073
90 - 240
0.086-3.0
0.054-1.1
0.26 -1.9
6.2 - 20
<0.001-0.0047
0.93 -3.1
0.037-1.7
0.16 -3.6
0.13 -0.55
1.0 -1.7
NA
NA
NA - Not applicable. Discharge severities for C]-Cig and >Cjg organics were not computed because there is no representative
MATE value for either group.
-------
1.6.1 Characteristics of FlueGas Emissions
Criteria Pollutants--
• Emissions of NOX from external combustion sources for electricity
generation are a significant environmental problem. These emis-
sions account for approximately 50 percent of the total NOx
emissions from all stationary sources. Of the NOX emissions from
external combustion sources for electricity generation, 77 percent
are contributed by burning of bituminous coal. Source severity
factors for NOx emissions from utility boilers range from 0.13
for bituminous coal-fired stokers to 6.4 for bituminous coal-fired
cyclone boilers.
t Emissions of S02 from external combustion sources for electricity
generation contribute significantly to the national emissions
burden. These emissions account for approximately 57 percent of
the total S0£ emissions from all stationary sources. Approxima-
tely 88 percent of the S02 emissions from external combustion
sources for electricity generation are contributed by burning of
bituminous coal. Source severity factors for uncontrolled 562
emissions range from 0.0007 for natural gas, wall-fired boilers
to 3.3 for bituminous coal-fired cyclone boilers.
• Emissions of particulates from external combustion sources for
electricity generation, despite the widespread application of
control devices, are still a significant environmental problem.
These emissions account for approximately 25 percent of the total
particulate emissions from all stationary sources. Almost all
(M55 percent) particulate emissions from external combustion
sources for electricity generation are contributed by burning of
bituminous coal. Source severity factors for particulate emis-
sions range from 0.001 for natural gas, wall-fired boilers to 0.74
for lignite-fired cyclone boilers.
• Emissions of total hydrocarbons from external combustion sources
for electricity generation contribute approximately 4 percent of
the total emissions of these pollutants from all stationary
sources. Source severity factors for emissions of total hydro-
carbons range from 0.005 to 0.12.
• Emissions of CO from external combustion sources for electricity
generation are not an environmental concern. Source severity
factors for CO emissions are all well below 0.05. Total CO emis-
sions from these sources account for approximately 0.6 percent of
CO emissions from all stationary sources.
Sul fates-
Flue gas emissions of $03 (in the form of sulfuric acid vapor and
aerosol) and particulate sulfate from bituminous coal-fired,
lignite-fired, and residual oil-fired utility boilers require
20
-------
further attention. Source severity factors for known $03 emissions
range from 0.26 to 7.4. Source severity factors for controlled
emissions of particulate sulfate range from 0.15 to 0.93.
Trace Elements—
• Of the trace elements present in bituminous coal, flue gas emis-
sions of aluminum, beryllium, chlorine, cobalt, chromium, iron,
nickel, phosphorus, lead, and silicon from most coal-fired boilers
are of environmental significance.
• Of the trace elements present in residual oil, flue gas emissions
of beryllium, chlorine, copper, magnesium, nickel, phosphorus,
lead, selenium, and vanadium from residual oil-fired boilers, with
mean source severity factors greater than 0.05, warrant special
concern.
• Measurements of flue gas emissions from gas-fired utility boilers
indicated that the average emissions of chlorine, copper, mercury,
nickel, and phosphorus were associated with source severity factors
greater than 0.05. This is a surprising result requiring further
characterization studies for confirmation.
Organics and POM—
• Analysis of organic emissions from utility sites indicated that
the principal organic constituents in flue gas are glycols, ethers,
ketones, and saturated and aliphatic hydrocarbons. The most
prevalent species appear to be the glycols and ethers which have
MATE values in the range of 10 to 1100 mg/m3. Mean source severi-
ties calculated using these MATE values indicated that emissions
of specific organics (excluding POM) are probably not of concern
with respect to human health.
• POM compounds emitted at the highest concentrations in flue gas
streams from bituminous coal-fired sources include naphthalene,
phenanthrene, and pyrene. Dibenz(a,h)anthracene and possibly
benzo(a)pyrene, both active carcinogens, were detected at a
limited number of sites at levels of environmental concern,
t The only POM compounds identified in flue gas emissions from
lignite-fired sources were biphenyl and trimethyl propenyl naph-
thalene. Carcinogenic POM compounds were not detected. The POM
data base for lignite-fired utility boilers is considered to be
adequate.
• For residual oil-fired sources, POM compounds emitted at the
highest concentrations in flue gas streams are naphthalene and
biphenyl. Carcinogenic POM compounds were not detected. The POM
data base for residual oil-fired utility boilers is adequate.
• No POM was detected in flue gas streams from gas-fired utility
boiler sites.
21
-------
1.6.2 CharacterIstjcsj>f Air Emissions From Cooling Towers
• Air emissions of chlorine, magnesium, and phosphorus from
mechanical draft cooling towers with high drift rates are com-
parable to flue gas emissions of these elements from residual oil-
fired utility boilers and of environmental significance.
• Sulfate emissions from mechanical draft cooling towers employing
sulfuric acid as an additive, and with design drift losses in the
0.1 to 0.2 percent range, are of the same magnitude as sulfate
emissions from coal-fired and oil-fired utility boilers.
1.6.3 Characteristies of^Wastewater Pischarges
• The major sources of wastewater discharges from external combus-
tion sources for electricity generation are: once-through cooling
water, blowdown from recirculating cooling systems, wastes from
water treatment processes, chemical cleaning wastes, and coal pile
runoff. Discharges from once-through cooling systems amount to
7,780,000 I/sec and account for approximately 99.8 percent of the
total wastewater from conventional utility power plants. Of the
remaining sources, blowdown from recirculating cooling systems is
the largest contributor to wastewater discharge.
• From an environmental standpoint, the pollutants of most concern
in wastewater effluents from conventional utility power plants are
iron, magnesium, manganese, nickel, and phosphorus.
• The average organic levels in the ash pond effluents sampled were
less than 0.1 mg/1. Average organic levels in the cooling tower
blowdown and boiler blowdown sampled were 1.5 mg/1 and 6.0 mg/1,
respectively. POM compounds were not found above the detection
limit of 2 yg/1.
• Based on discharge severities, the once-through cooling water and
ash pond overflow streams appear to be of lesser environmental
significance than the other wastewater streams from conventional
fossil-fueled steam electric plants. Total pollutant loading from
wastewater streams will, however, depend on individual discharge
flow rates.
1.6.4 Characteristics of Solid Wastes
• Solid waste streams generated by conventional utility power plants
consist primarily of coal ash and sludge from FGD systems. In
1978, total ash production was 63.6 Tg and total FGD sludge produc-
tion was 2.1 Tg (on ash-free basis).
• Concentrations of 11 to 16 trace elements in bituminous coal ash
and lignite ash exceed their health based solid MATE values. The
pollutants of most concern are aluminum, arsenic, calcium, chromium,
iron, manganese, nickel, potassium, and silicon.
22
-------
t Organics in bituminous coal ash and lignite ash are mostly present
as the >C]£ fraction. POM concentrations in fly ash and bottom
ash are not at levels of environmental concern. The only POM com-
pounds detected were naphthalene, alkyl naphthalenes, and other
compounds with high MATE values.
1.6.5 Key Data Needs
Flue Gas Emissions--
• The combination of emissions data from this measurement program
and the existing data base provides adequate characterization of
flue gas emissions of criteria pollutants from most external com-
bustion sources for electricity generation. The notable exception
is the lack of emissions data for pulverized dry bottom boilers
firing Texas lignite. This is a serious data deficiency because
approximately 16,000 MW of added generating capacity are planned
for this source category in the 1978-1985 period.
• Size distribution data for flue gas emissions of particulates are
inadequate for bituminous coal-fired, lignite-fired, and residual
oil-fired utility boilers.
t For bituminous coal-fired and residual oil-fired utility boilers,
the data base for $03 emissions is adequate. However, SOa emis-
sions data for lignite-fired sources are presently unavailable.
• The data base for uncontrolled particulate sulfate emissions from
residual oil-fired sources is adequate. The data base for con-
trolled particulate sulfate emissions from bituminous coal-fired
and lignite-fired sources, however, is inadequate.
• For bituminous coal-fired boilers equipped with electrostatic
precipitators, the data base characterizing flue gas emissions is
adequate for most trace elements. Similar data bases character-
izing flue gas emissions of trace elements from sources equipped
with wet scrubbers and mechanical precipitators, however, are
inadequate.
• Existing data for flue gas emissions of trace elements from
lignite-fired utility boilers are generally not available. Analy-
sis of the data acquired in this program indicated the need for
additional characterization studies. The most serious data
deficiency is the characterization of flue gas emissions of trace
elements from pulverized dry bottom boilers firing Texas lignite,
a source category with increasing importance in power generation.
• The data base characterizing flue gas emissions of trace elements
from residual oil-fired utility boilers appears to be adequate
except for beryllium, calcium, chlorine, copper, fluorine, magne-
sium, lead, selenium, and vanadium. The emissions data base for
these trace elements can be improved by analysis of additional
residual oil samples.
23
-------
t The Level I SSMS technique has served its purpose in providing
valuable trace element survey and screening data. To more accura-
tely determine the emission levels of these potentially hazardous
trace elements, it is important that future source tests and
analyses be conducted using Level II techniques on a selected
number of trace elements, with the primary objective that meaning-
ful enrichment factors can be calculated.
t Although current data indicated that emissions of specific organics
(excluding POM) are probably not of concern with respect to human
health, more detailed Level II organic analysis would be required
to conclusively determine the significance of organic emissions.
t The data base characterizing flue gas emissions of POM from
bituminous coal-fired sources is adequate except for dibenz(a,h)-
anthracene and benzo(a)pyrene. Emissions of these specific POM
compounds will require further characterization.
Wastewater Discharges--
0 The data bases characterizing cooling tower blowdown, ash pond
overflow, chemical cleaning wastes, wet scrubber wastewater, and
coal pile runoff are inadequate. The present study has been
instrumental in applying Level I techniques to identification of
wastewater constituents which pose potential environmental
problems. Since potential problems were detected by Level I tech-
niques, further studies using Level II techniques will be required
to adequately characterize wastewater effluents from utility
boilers.
Solid Wastes—
• Data on FGD scrubber sludge are limited. Needed data will be
provided by extensive scrubber sludge characterization studies
currently in progress under the direction of EPA and the Electric
Power Research Institute (EPRI).
24
-------
2. COMPOSITE RESULTS
On the basis of the results of current sampling and analysis efforts
and the existing emissions data base, estimates of current national emissions
and projected 1985 national emissions from external combustion sources for
electricity generation have been made by using current and predicted future
fuel consumption rates.
2.1 CURRENT AND FUTURE FUEL CONSUMPTION
Both current and future fuel consumption data are available from esti-
mates provided by the National Electric Reliability Council (NERC). For
1978, NERC (7) estimated total fuel consumption of 120.4 Tg of western bitu-
minous coal (2,698 PJ), 316.6 Tg of eastern bituminous and anthracite coal
(8,280 PJ), 31.1 Tg of lignite coal (477 PJ), 94.1 x 106 m3 of residual oil*
(3,830 PJ), and 62.9 x 109 m3 of natural gas (2,399 PJ) for utility boilers1".
According to NERC estimates, the projected fossil fuel requirements for
1985 will be: 263.6 Tg of western bituminous coal (5,910 PJ), 381.7 Tg of
eastern bituminous and anthracite coal (9,982 PJ), 66.4 Tg of lignite coal
(1,020 PJ), 109.2 x 106 m3 of residual oil (4,458 PJ), and 37.4 x 109 m3 of
natural gas (1,426 PJ) for utility boilers. These figures represent a 47.6
percent increase and 16.4 percent increase 1n coal and oil consumption,
respectively, and a 40.6 percent decrease in natural gas consumption from
1978 to 1985. The increase in coal consumption will be mostly due to
significant increases in the consumption of western bituminous (119.0 per-
cent) and lignite coal (113.8 percent). The consumption in eastern bitumi-
nous coal is only projected to increase by 20.6 percent during the same time
period.
The 1978 and projected 1985 fuel consumption figures for utility
boilers by firing type and fuel are presented in Table 7. Total consumption
Includes 2.9 percent distillate oil.
fTg (teragrams) = 1012 g; PJ (petajoules) - 1015 J,
25
-------
TABLE 7. 1978 AND PROJECTED 1985 FUEL CONSUMPTION
FOR UTILITY BOILERS
Combustion System
Category
Electricity generation
External combustion
Coal
Bituminous
Pulverized dry
Pulverized wet
Cyclone
All stokers
Anthracite
Pulverized dry
All stokers
Lignite
Pulverized dry
Cyclone
All stokers
Petroleum
Residual oil
Tangential firing
All others
Gas
Tangential firing
All others
Fuel Consumption,
1015 j
1978
17,684
11,455
10,949
8,370
1,266
1,217
94
31
11
20
477
384
83
10
3,830*
3,830*
1,582
2,248
2,399
583
1,816
1985
22,796
16,912
15,870
13,156
1,351
1,298
65
22
8
14
1,020
941
72
7
4,458f
4,458f
1,843
2,615
1,426
347
1,019
Percent
Change
1978-1985
+ 28.9%
+ 47.61
+ 44.91
+ 57.2%
+ 6.7%
+ 6.7%
- 30.9%
- 29.0%
- 29.0%
- 29.0%
+113.8%
+145.1%
- 13.3%
- 30.0%
+ 16.4%
+ 16.4%
+ 16.4%
+ 16.4%
- 40.6%
- 40.6%
- 40.6%
Includes 2.9 percent distillate oil.
fIncludes 3.6 percent distillate oil.
26
-------
figures for each type of fuel were based on NERC estimates. For different
boiler types fired with the same fuel, individual fuel consumption estimates
were derived by assuming that consumption is proportional to the installed
generating capacity for each boiler type. The current and projected 1985
installed generating capacity for different combustion system categories are
described in Section 4,1 of this report.
2.2 NATIONWIDE EMISSIONS
2,2.1 Air Emissions
Flue Gas Emissions
Total 1978 national emissions of criteria pollutants from external com-
bustion sources for electricity generation were determined based on combined
emission factors from the current study and existing data (Section 5.5.1.1}
and the estimated 1978 fuel consumption rates discussed in the previous
section. Nationwide emission totals for the criteria pollutants are pre-
sented in Table 8. In 1978, 62 percent of the fuel consumed by external
combustion sources for electricity generation was bituminous coal. In terms
of individual pollutants, 77 percent of NO emissions, 67 percent of total
<&
hydrocarbon emissions, 54 percent of CO emissions, 95 percent of participate
emissions, and 88 percent of S02 emissions from all external combustion
sources for electricity generation were contributed by burning of bituminous
coal.
Emissions of total hydrocarbons and carbon monoxide from external com-
bustion sources for electricity generation were relatively minor and amounted
to approximately 0.6 percent and 4 percent, respectively, of emissions of
these pollutants from all stationary sources in 1978. Emissions of NOX, S02>
and particulates from external combustion sources for electricity generation,
however, were significant. NO , S09, and particulate emissions from these
A tm
sources accounted for approximately 50 percent, 57 percent, and 25 percent,
respectively, of the emissions of these pollutants from all stationary
sources.
Current trace element emissions from external combustion sources for
electricity generation are summarized in Table 9. Emissions from gas-fired
boilers were negligible relative to coal-fired and oil-fired boilers and not
27
-------
TABLE 8. CURRENT NATIONWIDE EMISSIONS OF CRITERIA POLLUTANTS FROM
EXTERNAL COMBUSTION SOURCES FOR ELECTRICITY GENERATION
Combustion System Emiss 1 ons, Gg/year
Category "TTO^ Rl"Cu Part.
Bituminous Coal
Pulverized dry bottom
Pulverized wet bottom
Cyclone
All stokers
Lignite
Pulverized dry bottom
Cyclone
All stokers
Residual Oil
Tangential firing
Wall firing
Natural Sas
Tangential firing
Wall firing
2,771
481
825
23
100
28
2
180
427
72
423
37.7
5.7
11.6
1.0
3.4
0.4
0.04
7.3
10.4
1.4
4.4
141
109
100
15
13
3
0.7
89
126
19
59
2,800
355
86
105
24
11
11
47
66
0.14
0.44
11,120
1,520
1,590
132
188
41
6
709
1,007
0.15
0.45
Total 5,331 83.3 675 3,506 16,314
reported. Trace element emissions from pulverized bituminous dry-bottom,
pulverized bituminous wet-bottom, and bituminous cyclone boilers were
estimated based on existing data emission factors for these boilers with
electrostatic precipitators (Section 5.3.1.4), and adjusted using the
average efficiency of particulate control devices on these source categories
(Section 4.2.1). For bituminous coal-fired stokers, trace element emissions
were estimated using current study emission factors for units with mechani-
cal precipitators, and the average efficiency of particulate control devices
on stokers. Trace element emissions from lignite-fired boilers were all
calculated using current study emission factors. Trace element emissions
28
-------
TABLE 9. CURRENT NATIONWIDE FLUE GAS EMISSIONS OF TRACE ELEMENTS
FROM EXTERNAL COMBUSTION SOURCES FOR ELECTRICITY GENERATION
Trace Element
Aluminum (A1)
Arsenic (As)
Boron (6)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (LI)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Ho)
Sodium (Na)
Nickel (N1)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Bituminous Coal-fired Sources
Pulverized
Dry Bottom
267.7
0.80
2.8
2.8
0.069
2.9
176.9
0.053
283.8
0.25
1.7
0.72
34.0
265.0
0.059
35.4
0.75
38.6
1.2
0.31
16.1
1.9
3.3
1.2
0.31
0.88
478.8
0.41
4.7
0.044
0.026
0.85
1.4
Pul verl zed
Wet Bottom
32.9
0.10
0.34
0.34
0.0086
0.43
21.7
0.0067
42.9
0.030
0.21
0.086
5.1
32.5
0.0090
4.4
0.095
4.7
0.15
0.040
2.0
0.24
0.41
0.15
0.039
0.11
58.8
0.052
0.58
0.0052
0.0032
0.10
0.17
Cyclone
8.2
0.025
0.086
0.086
0.0021
0.42
S.4
0.0017
41.3
0.0074
0.053
0.022
4.9
8.2
0.0086
1.1
0.023
1.2
0.038
0.010
0.50
0.063
0.11
0.038
0.0097
0.027
14.7
0.013
0.14
0.0013
0.00080
0.026
0.042
Stokers
0.57
0.37
0.11
0.026
0.0016
0.033
0.75
0.0016
3.2
0.017
0.18
0.033
0.38
6.0
0.00066
0.65
0.0031
0.16
0.030
0.044
0.26
0.40
0.16
0.17
0.0086
0.0060
1.9
0.0037
0.019
0.0011
0.00097
0.020
0.27
Emissions
, Gg/year
Lignite-fired Sources
Pulverized
Dry Bottom
0.026
<0.00038
0.0026
<0.0096
<0.00038
<0.0065
0.15
<0. 00058
0.13
<0.00023
0.0033
<0.012
0.093
<0.033
<0.000038
0.040
0.000077
<0.083
<0.0028
<0.00035
0.15
<0.026
<0.013
<0.0022
<0.00019
<0.0014
0.050
<0.0017
<0.013
<0. 00069
<0. 00046
0.00023
0.016
Cyclone
<0.006
0.0002
0.0091
<0.0031
<0.00002
<0.0017
<0.13
0.00004
0.0059
<0.000033
<0.00027
0.0011
0.066
<0.0091
0.000017
<0.0094
—
<0.013
<0. 00039
<0.000042
0.019
<0.0039
<0.0011
<0. 00032
<0.000017
0.00015
0.023
0.00021
<0.0036
<0. 000091
<0.000066
<0. 000025
0.00078
Stokers
0.15
0.0011
0.023
0.020
0.000059
0.00088
<1.4
0.000023
0.011
0.000077
0.00013
0.00083
0.00423
0.19
0.000024
0.0292
0.000094
<0.27
0.0077
0.000042
<0.18
0.0028
0.015
0.00066
0.000033
0.00051
0.18
0.000072
0.037
0.000077
0.000040
0.00066
0.0055
Residual Oil-fired Sources
Tangential -
Firing
0.21
0.019
0.025
0.049
0.0038
0.0097
2.3
0.011
4.9
0.015
0.033
0.55
0.24
0.72
0.0023
0.62
0.0027
3.8
0.021
0.019
2.1
0.69
0.20
0.054
<0.0068
0.039
0.94
<0.012
0.051
0.016
<0.014
5.8
0.10
Wall-
F1 ri ng
0.30
0.027
0.036
0.070
0.0054
0.014
3.2
0.016
7.0
0.022
0.047
0.79
0.33
1.0
0.0034
0.88
0.0038
5.4
0.029
0.027
2.9
0.97
0.29
0.076
<0.0097
0.056
1.3
<0.017
0.072
0.022
<0.020
8.2
0.15
-------
from residual oil-fired boilers were calculated using the analysis results
of oil samples acquired in the current program, and by assuming that all
trace elements present in the oil feed were emitted through the stack. The
exception was that for vanadium emissions, the existing data emission factor
was used (Section 5.5.1.4).
The estimates presented in Table 9 show that among the trace elements,
aluminum, calcium, chlorine, iron, and silicon were emitted in the largest
quantities. Emissions of trace elements from lignite-fired and residual
oil-fired boilers were low when compared with emissions from bituminous
coal-fired sources. This is because most of the lignite generating capacity
are new additions and associated with highly efficient particulate control
devices, and because of the lower trace element content of residual oil
relative to coal. Total quantities of trace metals (excluding bromine,
chlorine, and fluorine) emitted from external combustion sources for elec-
tricity generation amounted to approximately 1,600 Gg in 1978.
Emissions of polycyclic organic matter (POM) from bituminous coal-fired,
lignite-fired, and residual oil-fired utility boilers are summarized in
Tables 10, 11, and 12, respectively. These emissions were all estimated
using POM emission factors developed by the current study. POM emissions
from gas-fired utility boilers were not detected. Total POM emissions from
external combustion sources for electricity generation were estimated to be
114 Mg (megagrams) in 1978. POM compounds emitted in the largest quantities
were naphthalene, phenanthrene/anthracene, and pyrene. However, the active
carcinogens dibenz(a,h)anthracene and possibly benzo(a)pyrene (indistin-
guishable from benzo(e)pyrene in the current study) were also emitted from
some bituminous coal-fired sources. Of particular interest is the fewer
number of POM compounds emitted from lignite-fired sources. This can be
partially explained by the higher hydrogen to carbon ratio in lignite as
compared to bituminous coal. The hydrogen to carbon ratio is related to the
amount of aromatics and unsaturated hydrocarbons in coal, both of which pro-
mote the formation of POM.
Based on the projected 1985 fuel consumption for utility boilers pre-
sented in Section 2.1, future nationwide emissions from these combustion
30
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TABLE 10. CURRENT NATIONWIDE FLUE GAS EMISSIONS OF POLYCYCLIC ORGANIC MATTER
FROM BITUMINOUS COAL-FIRED UTILITY BOILERS
POM Compound
Naphthalene
Phenyl naphthalene
Blphenyl
Benzo(g,h,1)perylene
o-phenyl enepyrene
01benz(a,h)anthracene
Plcene
D1benz(a,c)anthracene
9,10-d1hydrophenanthrene
Phenananthrene/anthracene
Pyrene
Fl uoran thene
Chrysene
Benzo ( a | py rene/benzo ( e ) py re ne
Benzo(b)fl uoranthene
Indeno(l ,2,3-c,d)pyrene
Ethyl blphenyl /dlphenyl ethane
Methyl phenanthrene
Decahydronaphthalene
Dltert-butyl naphthalene
Dimethyl Isopropyl naphthalene
Hexamethyl blphenyl
Hexamethyl hexahydro Indacene
Dlhydronaphthalene
CIQ substituted naphthalene
C]Q substituted decahydronaphthalene
Methyl naphthalene
9,10-dlhydronaphthalene/l ,1 ' dlphenylethene
! ,1 '-b1s(p-ethylphenyl)-ethane/tetramethyl blphenyl
5-me thy 1 -benz-c-acri d1 ne
2,3-dlmethyl decahydronaphthalene
Mixture of 3,8-d1methyl-5-(l-methyl ethyl)-! ,2-
naphthalene dione and tr1 methyl naphthalene
Z-ethyl-l.l'-biphenyl
Pulverized
Dry Bottom
20.2
0.027
2.2
4.1
2.4
1.9
0.52
1.3
<0.8
<0.8
<0.8
«0,8
<0.8
<0.8
<0.8
«0.8
<0.8
<0.8
«0.8
•eO.8
<0.8
<0.8
«0.3
<0.8
«0.8
<0,8
<0.8
<0.8
<0.8
<0.8
<0,8
_n Q
-------
TABLE 11. CURRENT NATIONWIDE FLUE GAS EMISSIONS OF POLYCYCLIC
ORGANIC MATTER FROM LIGNITE-FIRED UTILITY BOILERS
Emissions, Mg/year
POM Compound Pulveri zed Cyclone Stokers
Dry Bottom
Trimethyl propenyl 1.3 0.028 0.032
naphthalene
Blphenyl <0.04 0.0019 <0.001
TABLE 12. CURRENT NATIONWIDE FLUE GAS EMISSIONS OF POLYCYCLIC ORGANIC
MATTER FROM RESIDUAL OIL-FIRED UTILITY BOILERS
Emissions, Mg/year
POM Compound Tangential-Wall-
Fi ri ng F1H ng
2-ethyl-l.r biphenyl 0.083 0.12
l,2,3-trimethyl-4-propenyl n n,9 0 ndfi
naphthalene 0<0^ u'wb
Naphthalene 6.8 9.6
Phenanthridine 0.0074 0.011
Dibenzothlophene 0.015 0.021
Anthracene/phenanthrene 0.030 0.042
Fluoranthene 0.025 0.035
Pyrene 0.025 0.035
Chrysene/benz(a)anthracene 0.025 0.035
Benzopyrene/perylenes 0.0099 0.0014
Tetramethyl phenanthrene 0.015 0.021
Blphenyl 0.41 0.59
32
-------
categories were estimated. The assumptions used in the estimate of future
emissions included the following:
• The 1985 emission factors will be the same as 1978 emission
factors for all source categories, except pulverized bituminous
coal-fired dry bottom boilers and pulverized lignite-fired dry
bottom boilers. The latter are the only source categories with
planned generating capacity additions.
t For pulverized bituminous coal and lignite dry bottom boilers,
the NO* emission factor for increased fuel consumption will be
260 ng/J, in conformance with New Source Performance Standards
(NSPS). The S02 emission factor will be 330 ng/J for pul-
verized bituminous dry bottom boilers, and 292 ng/J for pul-
verized lignite dry bottom boilers, based on the average of the
older NSPS requirement of S0£ emissions not to exceed 520 ng/J
and the current NSPS of 90 percent reduction in S02 emissions.
Similarly, the particulate emission factor will be 28 ng/J»
based on the average of the older and the current NSPS. These
estimated NOx, S02, and particulate emission factors can only
be applied to estimate increased emissions due to increased
fuel consumption.
t For the same two source categories, the 1985 emission factors
for CO, total hydrocarbons, and POM compounds will be the same
as 1978 emission factors.
• The 1985 trace element emission factors for pulverized lignite-
fired dry bottom boilers will be the same as 1978 emission
factors, as current emission factors are based on particle
collection efficiencies of high efficiency electrostatic
precipitators.
t Increases in trace element emissions from pulverized bituminous
coal-fired dry bottom boilers will be based on increased con-
sumption of western coal as well as lower particulate emissions.
With the exception of the volatile elements bromine, chlorine,
fluorine, and mercury, trace element emissions from increased
fuel consumption will be proportional to the particulate emis-
sion factor of 28 ng/J.
Estimated future nationwide emissions for the criteria pollutants and
trace elements are presented in Tables 13 and 14. The projected 1985 NO
A,
particulate, and SOg emissions from external combustion sources for elec-
tricity generation represent increases of 25 percent, 45 percent, and 13
percent over the corresponding 1978 emissions. Total 1985 hydrocarbon and
CO emissions will increase by 33 percent and 10 percent over their respective
1978 emissions, but will still be insignificant. Total 1985 emissions of
33
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TABLE 13. PROJECTED 1985 NATIONWIDE EMISSIONS OF CRITERIA POLLUTANTS
FROM EXTERNAL COMBUSTION SOURCES FOR ELECTRICITY GENERATION
Combustion System
Category
Bituminous Coal
Pulverized dry bottom
Pulverized wet bottom
Cyclone
All stokers
Lignite
Pulverized dry bottom
Cyclone
All stokers
Residual Oil
Tangential firing
Wall firing
Natural Gas
Tangential firing
Wall firing
Emissions, Gg/year
NOX
4,015
514
880
16
245
24
1
210
497
43
237
HC
59.2
6.1
12.3
0.7
8.4
0.3
0.03
8.6
12.1
0.8
2.5
CO
221
117
106
10
31
2
0.5
103
146
11
33
Part.
2,930
379
92
73
40
10
8
54
77
0.09
0.25
so2
12,700
1,620
1,700
91
351
35
4
826
1,170
0.09
0.25
Total 6,682 111.0 781 3,665 18,497
trace metals from external combustion sources for electricity generation
represent only a 5 percent increase from the 1978 trace metal emissions, as
a result of the stringent NSPS for parti oilate emissions.
Future nationwide emissions of POM from bituminous coal-fired, lignite-
fired, and residual oil-fired utility boilers are presented in Tables 15,
16, and 17. The total 1985 POM emissions from external combustion sources
for electricity generation will amount to 141 Mg per year, or approximately
a 24 percent increase over the 1978 POM emissions.
34
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TABLE 14. PROJECTED 1985 NATIONWIDE FLUE GAS EMISSIONS OF TRACE ELEMENTS
FROM EXTERNAL COMBUSTION SOURCES FOR ELECTRICITY GENERATION
OJ
01
Trace Element
Aluminum (Al)
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Ho)
Sodium (Ma)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (SI)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V) ,
Zinc (Zn)
Bituminous Coal -fired Sources
Pul veri zed
Dry Bottom
280.4
0.82
3.0
3.0
0.072
4.1
189.8
0.056
3B5.6
0.26
1.7
0.75
57.7
275.1
0.084
36.6
0.77
41.3
1.3
0.32
17.0
2.0
3.5
1.3
0.32
0.91
501.5
0.43
5.0
0.046
0.027
0.88
1.5
Pul veri led
Wet Bottom
35.1
0.11
0.36
0.36
0.092
0.46
23.2
0.0071
45.8
0.032
0.22
0.092
5.4
34.7
0.0096
4.7
0.010
5.0
0.16
0.043
2.1
0.26
0.44
0.16
0.042
0.12
62.7
0.056
0.62
0.0055
0.0034
0.11
0.18
Cyclone
8.7
0.027
0.092
0.092
0.0022
0.45
5.8
0.0018
44.0
0.0079
0.057
0.0023
5.3
8.7
0.0092
1.2
0.025
1.3
0.041
0.011
0.53
0.067
0.12
0.041
0.010
0.029
15.7
0.014
0.14
0.0014
0.00085
0.028
0.045
Stokers
0.39
0.26
0.076
0.018
0.0011
0.023
0.52
0.0011
2.2
0.012
0.12
0.023
0.26
4.1
0.00046
0.45
0.0021
0.11
0.021
0.030
0.18
0.28
0.11
0.12
0.0059
0.0041
1.3
0.0026
0.013
0.00076
0.00067
0.014
0.19
Emissions
, eg/year
Lignite-fired Sources
Pulverized
Dry Bottom
0.064
<0. 00094
0.0064
<0.024
< 0.00094
<0.016
0.36
<0.0014
0.32
<0.00056
0.0081
<0.028
0.23
<0.081
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TABLE 15. PROJECTED 1985 NATIONWIDE FLUE GAS EMISSIONS OF POLYCYCLIC ORGANIC
MATTER FROM BITUMINOUS COAL-FIRED UTILITY BOILERS
CO
CTl
POM Compound Pulverized
Dry Bottom
Naphthalene 31.7
Phenyl naphthalene 0.042
Blphenyl 3.5
Benio(g»h,1)perylene 6.5
o-phenylenepyrene 3.7
D1benz{a,h)anthracene 2.9
Plcene 0.82
D1benz(a,c)anthracene 2.1
9,lO-d1hydrophenanthrene €1.3
Phenananthrene/anthraeene «1 . 3
Pyrene <1.3
Fl uoranthene <1.3
Chrysene « 1 . 3
Benzo(a)pyrene/benzo(e)pyrene <1.3
8enzo{b)fl uoranthene «1.3
Indeno(1»2,3-c,d)pyrene <1.3
Ethyl blphenyl /dlphenyl ethane «1.3
Methyl phenanthrene <1.3
Decahydronaphthalene <1.3
D1tert-buty1 naphthalene <1.3
Dimethyl Isopropyl naphthalene <1.3
Hexamethyl blphenyl . «1.3
Hexamethyl hexahydro Indacene <1.3
Dlhydronaphthalene <1.3
CIQ substituted naphthalene <1.3
CIQ substituted decahydronaphthalene <1.3
Methyl naphthalene <1.3
9,10-d1hydronaphthalene/1,1' dlphenyl ethene €1.3
I,l'-b1s{p-ethylphenyl)-ethane/tetramethy1 blphenyl <1.3
S-wethyl-benz-c-acHdlne <1.3
2,3-d1methy1 decahydronaphthalene <1.3
Mixture of 3,8-d1methy1-5-(1-niethy1 ethyl)-!, 2- «i>3
naphthalene dlone and trlmethyl naphthalene
2-ethy 1-1,1 '-blphenyl «'-3
Emissions, Mg/year
Pulverized Cyclone
Wet Bottom
15.4 5.3
€0.1 0.25
1.1 0.32
1.0 '€
-------
/Volumetric I / _ \ c u
/Emission* .,,, i Concentration^ <•*") * F * "s
t Factor / ("9/J) = 7r~; f X
/Fuel I ,.,.. ,._1% 1 .- 4.762
I Heating Value! IKJ/|C9
where s = subject emission species
MS = molecular weight of species s
For emission species measured on a mass concentration basis (mg/m or
yg/m ) at 20°C, the emission factor expressed as ng/J, can be computed using
the following equation:
/Mass \ i..nfj) x F x 24<04
/Emission* ,no/n _
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TABLE 124. SUMMARY OF EMISSION FACTOR FOR FLUE GAS EMISSIONS OF PARTICULATES, S0«» CO,
AND TOTAL ORGANICS FROM RESIDUAL OIL-FIRED UTILITY BOILERS TESTED *
ro
•js.
O
Combustion Site
Source No.
Type
Tangent! ally- 210
fired 211
322
323
Wall -fired 105
109
118
119
141-144
305
324
Mean x
s(x)
ts(x)/x
Parti culates
7.39
24.3
57.1
45.4
6.87
6.65
3.93
9.44
7.5
1.99
42.1
19.3
5.9
0.68
Emission Factor,
S02
(Uncontrolled)
330
290
990
1120
180
140
180
120
78
370
1130
448
126
0.63
ng/J
CO
<10
< 9.4
<44
<55
<210*
<230*
<19
<29
6.6
<250*
<47
28
6.8
0.58
Total
Organl cs
1.84 - 3.30
0.66 - 0.80
1.98- 3.24
14.23 - 15.49
No Data
8.23 - 9.96
0.94 - 2.01
0.45 - 2.47
0.28 - 0.58
10.35 - 11.79
1.40 - 2.73
4.04 - 5.24
1.65
0.71
These CO data showed large "less than" values and were not used 1n the computation of the mean
emission factor for CO.
-------
concern. However, as discussed in Section 5.5.2, air emissions of the
different constituents are dependent on the additives used and source of
cooling water. Therefore, estimates of nationwide emissions of pollutants
from cooling towers, based on limited source test data, would not be mean-
ingful.
2.2.2 Wastewater Discharges
The major sources of wastewater discharges from external combustion
sources for electricity generation include the following:
t Once-through cooling water
• Slowdown from recirculating cooling systems
t Wastes from water treatment processes
* Boiler blowdown
• Chemical cleaning wastes
• Ash pond overflow
• Coal pile runoff
The major constituents present in the wastewater streams are described in
Section 6. Because of significant plant-to-plant variations in the genera-
tion and handling of water streams, the types of chemical additives used,
and the source of raw water, estimates of discharges of pollutants on a
national level based on available data would not be meaningful. Neverthe-
less, order-of-magnitude estimates of wastewater discharges from each of the
major sources could be made to determine the extent of the problem.
Average usage of cooling water for recirculating systems was reported
to be 3,890 1/MW-hr (137). Approximately 52 percent of the cooling water
makeup is for blowdown losses, while the reamining 48 percent is for evapo-
rative and drift losses. Thus, average blowdown from recirculating cooling
5
systems is 2,040 1/MW-hr. Since 815 x 10 MW-hr of electricity were gener-
ated in 1978 by utility boilers with recirculating cooling systems, the
12
estimated total blowdown was 1.66 x 10 liters. This is equivalent to a
discharge rate of 53,000 I/sec in 1978.
Total discharges from once-through cooling water systems were estimated
using water withdrawal rate data. In 1974, it was reported that 5.62 x 10
I/sec of fresh water and 2.25 x 10 I/sec of saline water were withdrawn for
39
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cooling purposes (19). Subtracting the water usage for makeup in recircu-
lating systems, total discharge rates from once-through cooling systems in
1974 should be approximately 5.5 x 10^ I/sec of fresh water and 2.2x10 I/sec
of saline water. Because of the trend towards recirculating cooling systems,
total discharge rates from once-through cooling systems in 1978 would be
about the same as for 1974.
Water treatment in power plants is primarily to supply makeup water for
boiler and cooling tower operation. Average boiler makeup water requirement
was reported to be 98 1/MW-hr (137). Since 1664 x 106 MW-hr of electricity
were generated in 1978 by utility boilers (7), total boiler makeup water
requirement was calculated to be 1.63 x 10 liters. This is equivalent to
a makeup water rate requirement of 5,200 I/sec. Total makeup water rate
requirement for recirculating cooling systems is 100,000 I/sec; however,
only a fraction of the makeup water is treated. Based on the quantities of
alum and lime used (19), the quantity of cooling makeup water treated is
approximately 2.1 times the quantity of boiler makeup water treated, or
11,000 I/sec. According to the Edison Electric Institute (23), waste volumes
generated by water treatment processes are 2-5 percent of the flow for fil-
tration, clarification, and cold time softening processes, 4-6 percent of
the flow for sodium cation exchange processes, and 10-20 percent of the flow
for demineralization processes. Although the quantity of wastewater gener-
ated depends on the water treatment process(es), it would be reasonable to
assume that on the average 10-20 percent of the raw water treated for boiler
water makeup, and 4-10 percent of the raw water treated for cooling water
makeup, are discharged. Thus, total wastewater discharge rate from water
treatment processes were estimated to be between 1,000 and 2,400 I/sec in
1978.
Average boiler blowdown was reported to be 13 1/MW-hr (137). Again,
based on 1978 electricity generation, total boiler blowdown rate was calcu-
lated to be 670 I/sec.
Chemical cleaning wastes are mainly generated from boiler tube cleaning,
boiler fireside cleaning, and air preheater cleaning. Typical waste volumes
generated per boiler are 3.2 x 10 liters for boiler tube cleaning at a
frequency of once a year, 1.1 x 10 liters for boiler fireside cleaning
40
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five times a year, and 0.76 x 10 liters for air preheater cleaning eight
times a year (137). Total cleaning wastes generated per year per boiler are
14.8 x 10 liters. As there are approximately 3,000 utility boilers nation-
wide (137), the total discharge rate of chemical cleaning wastes was
estimated to be 1,400 I/sec in 1978.
In 1978, an estimated 45,500 Gg of fly ash and 18,100 Gg of bottom ash
were generated (Section 2,2.3). According to Jones et al. (156), 34 percent
of the fly ash and 44 percent of the bottom ash generated are disposed by
ponding. Design quantities of water for ash transport are typically 8.8
I/kg for fly ash and 14.2 I/kg for bottom ash (23). Also, approximately 2/3
of the ash transport water is discharged as pond overflow (Section 4).
Based on the above information, total ash pond overflow rate was calculated
to be 5,300 I/sec.
Depending on ranges of rainfall rates, coal pile runoff for a 1000 MW
plant can vary from 64 to 189 x 10 liters per year, with more typical
values being about 76 to 98 x 106 liters per year (23). In 1978, the total
Installed generating capacity for coal-fired utility boilers is 233,373 MW
(Section 4). Thus, total coal pile runoff was at the average rate of 560
to 720 I/sec in 1978.
In Table 18, 1978 wastewater discharge rates from the various sources
are summarized for comparison purposes. As these discharge rates are only
order-of-magnitude estimates, projected 1985 wastewater discharge rates
were not calculated.
2.2.3 Solid Waste Generation
Solid waste streams generated by utility boilers consist primarily of
coal ash, sludge from FGD systems, and water treatment sludges. Coal ash
includes bottom ash or slag and fly ash which may, at least in part, be
Incorporated with scrubber sludge, depending on the extent of particulate
removal prior to flue gas desulfurlzatlon. Water treatment sludges were
discussed in conjunction with wastewater discharges (Section 2.2.2) and will
not be discussed 1n this section. Estimation of nationwide bottom ash, fly
ash and sludge production rates is difficult due to limited published data.
However, estimates of total coal ash production may be made based on fuel
41
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TABLE 18. CURRENT NATIONWIDE WASTEWATER DISCHARGE RATES FROM
EXTERNAL COMBUSTION SOURCES FOR ELECTRICITY GENERATION
Wastewater Source
Once-through cooling, fresh water
Once- through cooling, saline water
Slowdown from recirculatlng cooling systems
Water treatment
Boiler blowdown
Chemical cleaning
Ash pond overflow
Coal pile runoff
Discharge Rate, I/sec.
5,530,000
2,250,000
53,000
1,000-2,400
670
1,400
5,300
560-720
consumption and average ash content data. Similarly, estimates of ash-free
sludge production may be made based on fuel consumption and sulfur content
data, and scrubber efficiency data.
Total coal ash production rates were estimated utilizing fuel consump-
tion data for western bituminous and lignite coals and eastern bituminous
coal presented by the National Electric Reliability Council (NERC). Average
ash contents for these coal groupings were determined to be 9.81 percent for
western lignite, 12.96 percent for western bituminous coal and 14.20 percent
for eastern bituminous coal (19). Anthracite, which accounts for less than
0.3 percent of all coal consumed by electric utilities in the U.S., was
neglected during computation of total ash production estimates. The total
ash production thus estimated for 1978 is 63.6 Tg, of which 60.6 Tg are
from combustion of bituminous coal. By 1985 the annual ash production rate
is estimated to be 94.9 Tg, of which 88.4 Tg will be from bituminous coal
combustion. These estimates are only slightly higher than the total ash
production figures indicated by National Ash Association data, namely,
about 62 Tg in 1978 and 82 Tg in 1985 (24). NERC data indicate only a
slight increase in the percentage of lignite utilized during the next six
42
-------
years. However, significant changes in the physical and chemical properties
of generated ash may be anticipated due to increased use of western bitumi-
nous and subbituminous coals relative to eastern bituminous coal utilization.
Sludge production rates from FGD systems depend on a number of variables
including fuel consumption, fuel ash, fuel sulfur, particulate removal
efficiency, SOg removal efficiency, percent excess reagent, reagent grit,
SOg/SO^ ratio and efficiency of dewatering. However, dry, ash-free sludge
generation rates were estimated for each FGD system in operation by the end
of 1978 under the assumption that reaction products consisted solely of
CaS03-l/2 H20 and CaS04-2 HgO. Average sulfite to sulfate mole ratios in
the scrubber sludges were assumed to be 4.5 for lime-based systems and 3.3
for limestone-based systems (150). Forced oxidation was not considered,
although such treatment would effect an increase in dry sludge generation
rates of approximately 15 percent while substantially decreasing the quan-
tity of wet sludge produced. Stoichiometric excesses of lime and limestone
were assumed to be 10 percent and 50 percent, respectively. Further, all
systems were assumed to have an operability index of 65 percent (20).
Based upon the stated assumptions, dry, ash-free sludge production
during 1978 is estimated to be 2.1 Tg. Assuming an FGD operability index of
95 percent and neglecting the effect of increased western coal usage, avail-
able data indicate that dry, ash-free sludge production during 1985 will be
approximately 8.9 Tg. However, it should be noted that fly ash and moisture
generally constitute a significant fraction of an FGD sludge. Fly ash can
be present at proportions ranging from trace amounts to 50 percent or more,
depending on variables such as fuel ash and particulate removal efficiency.
Similarly, the final sludge solids content may vary from 30 to 80 percent
depending on sludge characteristics and the dewatering methods employed (157)
In Table 19, the estimated 1978 and 1985 solid waste generation rates
from external combustion sources for electricity generation are summarized.
The FGD operability index is defined as hours the FGD system was operated
divided by boiler operating hours in period, expressed as a percentage
(20).
43
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TABLE 19. CURRENT AND PROJECTED 1985 NATIONWIDE
SOLID WASTE GENERATION RATES FROM EXTERNAL
COMBUSTION SOURCES FOR ELECTRICITY GENERATION
Solid Waste Source Generation Rate, Tg/y_ear_
1978 1985
Coal Ash 63.6 94.9
FGD Sludge 2.1* 8.9*
*
Dry, ash-free basis.
44
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3. INTRODUCTION
The combustion of common fuels - coal, oil, gas, and wood - in conven-
tional stationary systems for heating and power generation is one of the
largest and most widespread sources of environmental pollution. Combustion
of these fuels affects air, water, and land. In a preliminary assessment
of the significance of stationary combustion systems as sources of pollution
(1), it was estimated that these combustion sources contribute a major
portion of the total man-made emissions of nitrogen oxides, sulfur dioxide,
and particulate matter. Further, many of the combustion processes and asso-
ciated pollution control technologies also produce solid wastes, in the
form of ash and sludge, that present disposal problems. Leaching of chemical
compounds and heavy metals from solid fuel or waste material, as well as
direct discharges of wastewater streams, may result in contamination of water
resources. Assessment of the environmental impacts is complicated by cross-
media and multi-media effects, as pollutants merge with or pass between
environmental media. For example, removal of sulfur dioxide and particulate
matter from flue gases significantly increases the amount of solid wastes
requiring disposal.
The U.S. Environmental Protection Agency (EPA) has long been active in
regulating the release of pollutants from stationary conventional combustion
processes. The involvement has included characterization of emission streams,
research on the health and ecological effects of combustion pollutants,
development and demonstration of pollution control technologies, and setting
and enforcing of environmental standards. Much of the earlier work on
combustion pollutant characterization, however, was focused on the three
major air pollutants - sulfur dioxide, nitrogen oxides, and particulate
matter, and the subsequent development of control technologies and standards
for these pollutants. As a consequence, the early characterization work
was limited in scope and did not adequately address the emissions of other
potentially hazardous pollutants or the multi-media aspects of combustion
emissions. These observations were confirmed in the preliminary assessment
45
-------
study (1), which identified the inadequate characterization of flue gas
emissions of trace elements, sulfates, particulate matter by size fraction,
and polycyclic organic matter (POM). In addition, the same study also iden-
tified the genera] inadequacy of the data base characterizing air emissions
from cooling towers and coal storage piles, and wastewater effluents and
solid wastes from combustion processes.
From the above discussion, it is apparent that much of the data des-
cribing pollutant types and quantities released from stationary conventional
combustion processes were unavailable. A comprehensive characterization of
emissions from these processes, therefore, was needed as a basis for iden-
tifying the pollutants of concern, for estimating the total quantities of
pollutants emitted, for assessing the impacts of pollutant emissions on
health and the environment, and for evaluating the need for control techno-
logy development. In response to the need for a comprehensive characteriza-
tion, the EPA's Industrial Environmental Research Laboratory at Research
Triangle Park (IERL-RTP) in North Carolina established the Conventional Com-
bustion Environmental Assessment (CCEA) Program as the primary vehicle for
filling the identified data gaps. The component project under which this
study was performed is known as the Emissions Assessment of Conventional
Combustion Systems (EACCS) project, and the specified objectives of this
project are:
t Compilation and evaluation of all available emissions data
on pollutants from selected stationary conventional combus-
tion processes.
• Acquisition of needed new emissions data from field tests.
• Characterization of air emissions, wastewater effluents,
and solid wastes generated from selected stationary conven-
tional combustion processes, utilizing combined data from
existing sources and field tests.
• Determination of additional data needs, including specific
areas of data uncertainty.
Because of the comprehensive characterization requirement, the assess-
ment process in the current project is based on a critical examination of
existing data, followed by a phased sampling approach to fill data gaps.
In the first phase, sampling and analysis procedures are used to provide
results accurate to a factor of 3 so that preliminary assessments can be
46
-------
made and problem areas identified. The methodology employed is similar to
the Level I sampling and analysis procedures developed under the direction
of the Industrial Environmental Research Laboratory of the U.S. Environ-
mental Protection Agency (2), the major addition being that GC/MS analysis
for POM is performed on the samples collected in this project. Evaluation
of results from the first phase will determine all waste stream/pollutant
combinations requiring a more detailed and accurate Level II sampling and
analysis program. In terms of major potential benefits, the characterization
of combustion source emissions from this project will allow EPA to determine
the environmental acceptability of combustion waste streams and pollutants
and the need for control of environmentally unacceptable pollutants.
The combustion source types to be assessed in this project have been
selected because of their relevance to emissions and because they are among
the largest, potentially largest, or most numerous (in use) of existing
combustion source types. A total of 51 source types have been selected for
study. Selected source types have been classified under the following
principal categories:
1) Electricity generation - External combustion
2) Industrial - External combustion
3) Electricity generation and industrial - Internal combustion
4) Commercial/institutional - Space heating
5) Residential - Space heating
These five principal categories have been further divided into subcategories
based on fuel type, furnace design, and firing method. The subcategorization
is needed because of the differences in the emission characteristics of
combustion source types.
This project report is the third in a series of five group/category
reports; the two published reports are concerned with the characterization
of emissions from gas- and oil-fired residential sources (EPA-600/7-79-Q29b)
and from internal combustion sources (EPA-600/7-79-029c). The main purposes
of this report are to discuss data evaluation and test results, and to pro-
vide in a single document, best estimates of emission factors or discharge
stream concentrations for effluents from external combustion sources for
47
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electricity generation. These emission estimates were derived utilizing
combined data from existing information sources and field tests conducted
in the current project. The report also provides estimates of nationwide
emissions from external combustion for electricity generation, and identifies
major gaps in emissions data. As such, information contained in the report
can be used for:
t Compilation of emission factors for pollutants and waste
streams for which no existing data were available.
t Upgrading of existing emission factors for pollutants and
waste streams.
• Performing environmental assessments of external combus-
tion sources for electricity generation.
• Determining the nationwide burden of emissions from
external combustion sources for electricity generation.
• Evaluating the need for control technology development,
based on analysis of the environmental impacts of uncon-
trolled and controlled emissions.
t Planning of future Level II field tests to provide critical
data needs.
• Providing input to the development of emission standards.
A total of sixteen combustion source types were considered in this
report:
• Bituminous coal-fired utility boilers - pulverized dry
bottom, pulverized wet bottom, cyclone, and stokers.
t Anthracite coal-fired utility boilers - pulverized dry
bottom and stokers.
• Lignite-fired utility boilers - pulverized dry bottom,
pulverized wet bottom, cyclone, and stokers.
• Residual oil-fired utility boilers - tangential firing
and wall firing.
• Distillate oil-fired utility boilers - tangential firing
and wall firing.
• Natural gas-fired utility boilers - tangential firing
and wall firing.
Of these sixteen types of combustion systems, the lignite pulverized wet
bottom category was eliminated from this study because there is no existing
pulverized wet bottom boiler firing lignite coal. Additionally, the two
48
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distillate oil categories were eliminated because distillate fuels are
primarily used for startup and flame stabilization in utility boilers, and
for blending with residual oil to reduce the total sulfur content of the
fuel oil consumed.
For the purposes of this study, all major on-site facilities involved
in the generation of fossil-fueled power by utilities are also covered in
this source category. Support facilities and process operations addressed
in this report include coal storage, cooling water systems, makeup water
treatment, chemical cleaning of boiler tubes, air and water pollution con-
trol, and solid waste disposal. Specifically excluded are fugitive emissions
from ash handling and storage and fuel handling, because characterization
of these emissions is outside the scope of the current effort.
Concurrent with field tests conducted under the EACCS project, there
were a number of projects with specific objectives of characterizing waste-
water and solid waste discharges from conventional steam electric plants.
These projects included TVA studies to characterize coal pile drainage, ash
pond discharges, chlorinated once-through cooling water discharge, and
chemical cleaning wastes from periodic boiler-tube cleaning to remove scales,
and studies conducted by the Aerospace Corporation to provide data on the
characteristics of wastewater discharges from flue gas desulfurization sys-
tems. Additionally, extensive scrubber sludge characterization studies are
conducted by Arthur D. Little, Inc., under the direction of EPA. Available
data from these studies have been incorporated into the emissions data base
for the current project. Because of the concentration of these studies on
characterizing wastewater and solid waste discharges, the field tests in
this project were designed with emphasis on air sampling to minimize duplica-
tion of efforts. As a result, only a selected number of wastewater and solid
waste streams were sampled and analyzed in this project.
The approach utilized in the emissions assessment of external combustion
sources for electricity generation was similar to that utilized for the
assessment of other combustion source types. First, available information
concerning the process and population characteristics of external combustion
sources and their emissions was assembled and assessed to determine the
49
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adequacy of the available data base. Sampling and analysis were then con-
ducted at selected representative sites to fill data gaps. The results were
evaluated to determine the need for and type of additional sampling and
analysis, and to identify the environmentally significant substances emitted
from external combustion sources. These evaluations led to the recommenda-
tion of Level II tests. Results from these specific Level II tests will be
separately reported. Lastly, emissions data obtained from the sampling and
analysis program were combined with existing emissions data to provide
estimates of current and future nationwide emissions of pollutants from
external combustion sources for electricity generation.
This report is organized into seven sections. Section 1 summarizes the
significant findings and conclusions derived from this study. Section 2
presents the composite results by providing estimates of current national
emissions and projected 1985 national emissions from external combustion
sources for electricity generation. Section 3 is the introduction to the
report. Section 4 describes the different categories of combustion systems
and their characteristics, the sources of waste streams and emissions, and
the pollution control technologies and disposal options commonly employed.
Section 5 discusses in detail the evaluation of existing air emissions data,
the acquisition of additional air emissions data through field tests and
laboratory analysis, and the analysis of test and data evaluation results.
Sections 6 and 7 discuss in detail wastewater effluents and solid wastes,
respectively. These sections are arranged in the same form as Section 5.
In Appendix A, the criteria for evaluating the adequacy of emissions data
are described. The data reduction procedure is presented in Appendix B.
50
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4. SOURCE DESCRIPTION
Of the electric energy generated in the United States today, over 70
percent was produced in conventional steam plants using fossil fuels. In
1978, an estimated 1,664,000 million kw-hr of electric energy were delivered
by these plants, at an average net plant efficiency of 33.3 percent. Al-
though the proportional use of oil and natural gas for electric energy gener-
ation is expected to decline in the future, the planned construction of
coal-fired utility boilers ensures that conventional steam plants will
continue to be the principal source for the production of electric energy
during the next ten years.
The present study is concerned with the characterization of emissions
associated with electric utility fossil fuel-fired boilers. For the purpose
of this study, these boilers are also termed "external combustion" sources
because thermal energy is recovered from a fuel combustion source external
to the working fluid; the steam produced then expands against the blades of
a high-speed turbine to generate electric energy.
This section provides an overview of the electric utility industry with
brief descriptions of the types and population characteristics of fossil
fuel-fired boilers, installed generating capacity, types and origins of fuel
used, future industry trends, and the unit operations and processes which
are sources of emissions from conventional steam plants.
4.1 SOURCE DEFINITION AND CHARACTERIZATION
The combustion systems considered in this study were classified in an
earlier report (1). As noted in Table 20, 16 types of combustion systems
are included under the electricity generation, external combustion source
category. Of these 16 types of combustion systems, the lignite pulverized
wet bottom category was eliminated from this study because there is no
existing pulverized wet bottom boiler firing lignite coal. Additionally, the
two distillate oil categories were eliminated because distillate fuels are
primarily used for startup and flame stabilization in boilers, and for
51
-------
TABLE 20. CLASSIFICATION OF COMBUSTION SYSTEMS (1)
System No. Combustion System
Electric generation
External combustion
Coal
Bituminous
1 Pulverized dry
2 Pulverized wet
3 Cyclone
4 All stokers
Anthracite
5 Pulverized dry
6 All stokers
Lignite
7 Pulverized dry
8 Pulverized wet
9 Cyclone
10 All stokers
Petroleum
Residual oil
11 Tangential firing
12 All other
Distillate oil
13 Tangential firing
14 All other
Gas
15 Tangential firing
16 All other
52
-------
blending with residual oil to reduce the total sulfur content of the fuel
oil consumed.
The classification system in Table 20 categorizes utility boilers
according to the type of fuel used and furnace design. Fuels used in utili-
ty boilers include bituminous coal, anthracite coal, lignite coal, residual
oil, and natural gas. In this study, subbituminous coal is considered as a
subcategory of bituminous coal.
The design of furnaces and boilers for coal firing is based on the
physical and chemical characteristics of the coal, the steam conditions re-
quired, and the emission levels to be met. Coals with high fusion tempera-
tures are suitable for burning, when pulverized, in hopper-bottom furnaces
with dry-ash removal. Coals with low fusion temperatures may be burned,
when pulverized or crushed, in wet bottom furnaces with slag-tap ash removal.
For pulverized dry bottom and wet bottom furnaces, three burner arrangements
are used for coal firing:
• Tangential firing
• Front wall firing
• Horizontally opposed firing
These burner arrangements are shown schematically in Figure 3. The vertical
firing method, not shown here, is seldom used for utility boilers. Vertical
firing furnaces are no longer sold and will not be discussed.
In the tangential firing method, developed by Combustion Engineering,
Inc., pulverized coal is introduced from the four corners of the furnace in
vertical banks of burner nozzles, and directed tangentially towards the cir-
cumference of an imaginary circle in the center of the chamber. Such a
firing mechanism results in the formation of a large vortex with its axis on
the vertical center line.
In front wall and horizontally opposed fired furnaces, pulverized coal
is introduced through a horizontal row of burners mounted normal to the
furnace wall(s). For boilers less than 400 MW in size, the burners are ty-
pically located on only one wall. For larger boilers, the burners are
located on both the front and back walls firing directly opposed to each
other. Horizontally opposed fired furnaces are generally newer because of
53
-------
PRIMARY A[R
AND COAL
X
SECONDARY
AIR
TANGENTIAL FIRING
X
PLAN VIEW OF FURNACE
MULTIPLE INTiRTUBE
PRIMARY AIR
AND COAL
SECONDARY AIR
PRIMARY AIR
ND COAL
HORIZONTAL FIRING
SECONDARY
AIR
SECONDARY
PRIMARY AIR
AND COAL
AIR
CYCLONE
CYCLONE FIRING
Figure 3. Pulverized Coal Firing Methods (3)
54
-------
the recent trends toward boilers of larger capacity. The major manufacturers
for these furnaces include Babcock and Wilcox Co., Riley Stoker Corp., and
Foster Wheeler Energy Corp.
In cyclone fired furnaces, the coal is not pulverized but is crushed to
4-mesh size, and admitted with the primary air in a tangential fashion to a
horizontal, cylindrical chamber (Figure 3). The finer coal particles are
burned in suspension, while the coarser ones are thrown to the walls by cen-
trifugal force. The wall surface, having a coating of molten slag, retains
most of the coal particles until they are burned. The cyclone furnace was
developed by Babcock and Wilcox Co. to burn coals with slag viscosity of 25
Pa*s (250 poises) at temperatures of 1430°C or lower (4).
Instead of burning coal in suspension, mechanical stokers can be used
to burn coal in fuel beds. All mechanical stokers are designed to feed coal
onto a grate within the furnace, with provisions for ash removal. Among the
several types of stokers, the spreader stoker is the most generally used in
utility size units. The spreader stoker projects coal into the furnace over
the fire with a uniform spreading action, permitting suspension burning of
the finer coal particles. The heavier coal pieces cannot be supported in
the gas flow and fall to the grate for combustion in a thin bed. However,
anthracite is not burned in spreader stokers because of its high ignition
temperature.
The burner arrangements in oil- and gas-fired utility boilers are
similar to those in pulverized coal-fired utility boilers, with tangential,
front wall, and horizontally opposed as the primary firing configurations.
The generating capacity, average size, and "capacity average age" of
utility boilers by firing type and fuel are presented in Table 21. The uti-
lity boiler characteristics were derived from the GCA study (1), and updated
using data from the Energy Data Report (5), Steam Electric Plant Factors (6),
fossil fuel requirements projected by the National Electric Reliability
Countil (7), a cyclone boiler study (8), and plant design surveys conducted
by the Power Engineering Magazine (9,10,11,12,13,14). Several assumptions
were used in the updaging of the GCA data:
55
-------
TABLE 21. GENERATING CAPACITY, FUEL CONSUMPTION AND POPULATION
CHARACTERISTICS OF ELECTRIC UTILITY BOILER IN 1978
in
Combustion System
Category
Electricity generation
External combustion
Coal
Bituminous
Pulverized dry
Pulverized wet
Cyclone
All stokers
Anthracite
Pulverized dry
All stokers
Lignite
Pulverized dry
Cyclone
All stokers
Petrol eum
Residual oil
Tangential firing
All others
Gas
Tangential firing
All others
Generating
Capacity,
MW
401 ,467
233,373
223,210
170,660
25,817
24,808
1,925
672
235
437
9,491
7,791
1,515
185
102,133
102,133
42,175
59,958
65 ,961
16,029
49,932
Fuel
Consumed ,
1015J
17,684
11,455
10,949
8,370
1,266
1,217
94
31
11
20
477
384
83
10,
3,830;
3,830T
1,582
2,248
2,399
583
1,816
Average
Size of
Unit,
MW
200
120
250
15
235
10
430
380
17
270
100
200
100
Capacity
Average
Age*,
years
11
19
12
43
16
43
4
3
19
9
11
13
16
average age
:(capacity X age)
Ecapaclty
Includes approximately 2.9 percent distillate oil.
-------
• There is no increase in the installed capacity for pulverized
wet bottom boilers from 1972 to 1978. Pulverized wet bottom
furnaces are no longer being manufactured dur to operational
problems with low sulfur coals and higher NO emissions.
f\
• The installed capacity for anthracite boilers and the annual
consumption for anthracite coal declined at a rate of 6.5
percent per year during the 1974 to 1978 period (1).
• The installed capacity for bituminous coal-fired stokers
declined at a rate of 6.1 percent per year during the 1972
to 1978 period due to retirements (1).
• The annual fuel consumption for each boiler type subcategory
is proportional to the total installed capacity of boilers
in that subcategory.
Of the installed generating capacity in 1978, 58.1 percent are coal-
fired boilers, 25.5 percent are oil-fired boilers, and 16.4 percent are gas-
fired boilers. For coal-fired boilers, the bituminous pulverized dry bottom
category accounts for over 73 percent of the total installed generating
capacity. During the 1979-1985 period, generating capacity additions of
approximately 80,000 MW are projected for this combustion category (7). The
only other major generating capacity additions will be 17,300 MW for the
lignite-fired pulverized dry bottom category (6). Coal-fired pulverized wet
bottom and cyclone boilers are no longer being sold because of their inabi-
lity to meet NOV standards, and coal-fired stokers are being phased out by
A
retirements because of their inefficiencies. The projected installed gener-
ating capacity for utility boilers in 1985, as presented in Table 22, also
shows a small increase in generating capacity for oil-fired boilers, and a
small decrease in generating capacity for gas-fired boilers. By 1985, 66.6
percent of the installed generating capacity for utility boilers will be
coal-fired, 20.9 percent will be oil-fired, and only 12.5 percent will be
gas-fired.
A comparison of the total 1978 coal, fuel oil, and gas consumption with
the historical 1975 fuel consumption by region is presented in Table 23.
These figures indicate a 15 percent increase in the consumption of both coal
and oil, but a 24 percent decrease in the consumption of gas. On a regional
basis, the largest consumers of coal, oil, and gas are the east north central,
the south Atlantic and the west south central areas, respectively.
57
-------
TABLE 22. PROJECTED GENERATING CAPACITY OF
ELECTRIC UTILITY BOILERS IN 1985
Combustion System
Category
Electricity generation
External combustion
Coal
Bituminous
Pulverized dry
Pulverized wet
Cyclone
All stokers
Anthracite
Pulverized dry
All stokers
Lignite
Pulverized dry
Cyclone
All stokers
Petroleum
Residual oil
Tangential firing
All others
Gas
Tangential firing
All others
Generating
Capacity
HW
496,896
330,826
303,210
251 ,346
25,817
24,808
1,239
420
147
273
27,196
25,096
1,915
185
103,962
103,962
42,980
60,982
62,108
15,093
47,015
Change
1978-1985,
%
+ 23.8
+ 41.8
+ 35.8
+ 47.3
0
0
- 35.6
- 37.5
- 37.5
- 37.5
•H86.5
+222.1
+ 26.4
0
+ 1.8
+ 1.8
+ 1.9
+ 1.7
' - 5.8
- 5.8
- 5.8
Source: References 6 and 7.
58
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TABLE 23. COMPARISON OF 1978 FOSSIL FUEL CONSUMPTION BY ELECTRIC
UTILITIES WITH HISTORICAL 1975 REGIONAL FUEL CONSUMPTION
Geographic
Region
Northeast
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
1976 Consumption
1978 Consumption
Coal ,
Si
699
41 ,792
129,755
45 ,432
77,723
60,798
11,205
35,150
3,954
406,508
468,083
on,
103m3
11 ,409
19,120
3,800
1,163
22,000
2,032
4,034
1,223
16,899
81 ,680
94,132
Gas,
106m3
85
416
2,052
5,157
3,740
932
58,037
4,304
8,307
83,030
62,891
Source: References 7 and 15.
The origins of coal used by electric utilities In 1975 Is presented In
Table 24, A significant trend is the greater increase in the consumption of
western coal and lignite compared to the consumption of eastern coal. In
1978, the total consumption of western coal and lignite by electric utilities
amounted to 120,360 Gg and 31,080 Gg (7), respectively. These represent 81
percent and 114 percent increases in the consumption of western coal and
lignite from 1975 to 1978. By comparison, the consumption of eastern coal by
electric utilities only increased by 9.9 percent, to 315,740 Gg in 1978 (7).
59
-------
TABLE 24. ORIGIN OF COAL DELIVERED TO
ELECTRIC UTILITIES IN 1975
Region
Bituminous and
Anthracite Coal
Appalachian
Interlor-Fastern
I nteH or- Wes tern
Western
Northern
Lignite Coal
Western
Northern
States
Pennsylvania, Maryland, West
Virginia, Ohio, Virginia,
Kentucky (East), Tennessee,
Alabama.
Kentucky (West), Illinois,
Indiana,
Iowa, Arkansas, Kansas, Missouri,
Oklahoma.
Colorado, New Mexico, Arizona,
Wyoming, Utah.
Montana, Washington, Alaska
Texas .
North Dakota, South Dakota.
*
Deliveries
Gg
189,563
114,137
6,880
40,262
23,203
8,297
6,260
388,602
Source: Reference 6.
*
Deliveries rarely equal to consumption for the year because of changes in
stockpiles.
60
-------
The origins of residual fuel oil consumed by electric utilities are not
directly available. However, data for domestic petroleum production presented
in Table 25 indicate that over 76 percent of the domestic crude oil originates
from four states - Texas, Louisiana, Alaska, and California. In 1978, crude
and refined oil imports almost equalled the domestic crude oil production.
The countries of origin for these oil imports are presented in Table 26.
Saudi Arabia, Nigeria, and Venezuela were the leading sources of U.S. oil
imports.
4.2 EMISSION SOURCES AND UNIT OPERATIONS
Air, water and solid waste pollutants are emitted from a number of oper-
ations within a steam electric power plant. The process stages which are
sources of waste streams and emissions in a typical coal-fired utility boiler
are shown in Figure 4. This figure is a generalized depiction of a coal-fired
power plant; the exact number of waste streams and their discharge rates and
compositions will depend upon specific plant practices regarding water treat-
ment, cooling, ash handling, equipment cleaning, and flue gas control measures.
Because a coal-fired power plant involves more process stages and waste stream
sources than other combustion sources, many of the waste streams shown in
Figure 4 will not be pertinent to oil- or gas-fired boilers. The relevance
of the various process stages or unit operations to air, water, and solid
-waste emissions for all fuel types is presented in Table 27.
%
4.2.1 %ir Emissions andControl Technology
largest source of air emissions from steam electric power plants is
flue gas emissions from stacks. Air pollutants in the flue gas stream include
nitrogen oxides, sulfur oxides, carbon monoxide, particulates, sulfates, trace
elements contained in particulates and as gaseous species, organic compounds
such as hydrocarbons and oxygenated hydrocarbons, and polycyclic organic
matter (POM). The rate at which these pollutants are emitted from stacks de-
pends on the type and quantity of fuel burned, the design of the combustion
system, as well as the type and performance of control devices installed.
Other sources of air emissions are emissions from ash handling and
storage, fuel handling and storage, and cooling systems in the form of drifts
and vapors. These sources of air emissions are considered to be relatively
minor when compared with flue gas emissions. Little information is available
61
-------
TABLE 25. DOMESTIC PETROLEUM PRODUCTION
FOR THE FIRST HALF OF 1978
State
Texas
Louisiana
Alaska
California
Oklahoma
Wyoming
New Mexico
Others
U.S. Total
Production
Quantity
103 m3/day
485
239
172
154
66
50
37
174
1,377
% of Total
35.19
17.34
12.47
11.17
4.82
3.60
2.70
12.71
100.00
Source: Reference 16.
for fugitive air emissions from ash handling and storage; however, air emis-
sions from cooling systems and coal storage piles will be discussed in
Sections 5.3.2 and 5.3.3, respectively.
Air pollution control on utility boilers is mainly directed at reducing
flue gas emissions of particulates, sulfur dioxide, and nitrogen oxides. For
control of partlculate emissions, electrostatic precipltators (ESP) and cen-
trifugal separators (cyclones) are the most common types of devices used.
The distribution of particulate control equipment in use on bituminous
coal-fired utility boilers has been computed on the basis of August 1975
National Emission Data System (NEDS) data and is presented in Table 28 (16).
The results of this analysis show that, based on fuel consumption, 83 percent
of pulverized dry bottom, 77 percent of pulverized wet bottom, 89 percent of
62
-------
TABLE 26. CRUDE AND REFINED OIL IMPORTS*
FOR THE FIRST HALF OF 1978
Country
of Origin
Saudi Arabia
Nigeria
Venezuela
Algeria
Libya
Iran
Indonesia
Canada
Virgin Island
United Arab Emirates
Others
Total
Import
Quantity
103 in3/ day
169
115
104
99
94
81
80
70
67
66
301
1,246
% of Total
13.53
9.21
8.33
7.94
7.54
6.51
6.39
5.64
5.35
5.27
24.32
100.00
Source: Reference 16.
*Approx1mately 751 of the oil was Imported as crude, and 25% as
refined oil products.
cyclone-fired boilers, and 44.4 percent of stokers were controlled by ESP in
1975. Further analysis of the NEDS data show that the majority of the pul-
verized dry bottom, pulverized wet bottom, and cyclone-fired boilers were
controlled by high efficiency ESP, with particulate collection efficiency of
greater than 95 percent. For new installations that have to meet New Source
Performance Standards, a particulate collection efficiency of the order of
99 percent is needed. Based on previous SCA (1) and MRI (18) data, and the
assumption of an average particulate collection efficiency of 99 percent for
63
-------
»
1 AIR EMISSIONS
v *
Jf~
STACK
I WASTE WATER ) f
"^ i ~" **TEB
AIR EH
BOILER TUBE
' AIR EMISSIONS 1 ' AIR EMISSIONS I FIRESIDE * "~ST
FlUEGAS
ncciniu Cl EANUP
> (EG PARTI
DT BLOWER J CULATE OR
\iSir\ ' SO2 REMOVAL!
1 1
CO*1- k COAL fUEl fc „ FiUE GASES , __— — I
STOHAlit P1 PREPARATION " " *'«*"" •- • — - _ ~~
, mMB'Miill .. OENERATINO STfAU TdRHINF
i ~t '
t IEACHATE }
CHEMICALS
^*w , _„,„„„„ ^
i
| WASTE WATER ,
1
ASH
HAND
SVSTI
•°"-eR GENERATOfl
i '
' SLOWDOWN ^ 1
1
1
T
;
BOTTOM I'AIREMBSIONS^, CONDENSER
^5" v ,^ Jim . ^^ ^p
c ^^
4 WATER i J
-i, ' DISCHARGE
1 * «"*TFH(«J(
1
f
\
• fcf SOLID WASTE *
\ _ _ X
^
/ WASTE WATllf»
(TO ASH HANOLHtGI
ONCE THROUGH
COOLING WATEM
1 ' REORCULATINC COOLING WATER
t
\ AIR EMISSIONS ,
** V \ COOLING TOWER /
TO , \ /
-'' \ /
X "• ~". <" •* MAKE-UP .11 ' ,
1 WASTE WATER ' | SOLID WASTES I WATER T 1 +
| BLOW DOWN I
Figure 4. Diagram Showing Emission Streams Associated
With a Pulverized Coal-Fired Utility Boiler
-------
TABLE 27. RELEVANCE OF UNIT OPERATIONS TO
AIR, WATER AND SOLID WASTE EMISSIONS
Unit Operation
Flue gas emissions
Ash handling/storage*
Fuel handling/storage1"
Cooling system
Boiler feedwater treatment
Boiler blowdown
Equipment cleaning
Flue gas cleaning*
A1r
X
M
M
M
NA
NA
NA
NA
Water
NA
X
X
X
X
X
X
X
Solid Waste
NA
X
NA
NA
M
NA
NA
X
Note: X - source
M - minor source
NA - not applicable
*
Ash handling/storage and flue gas cleaning wastes are primarily
derived from coal-fired sources.
Fugitive air emissions are generated from coal and oil handling/
storage; wastewater streams are generated from coal pile drainage.
new coal-fired utility boilers, estimates of the average efficiency of parti-
culate control devices on these source categories for 1978 were made and
listed in Table 29.
For lignite pulverized dry bottom and cyclone-fired boilers, particulate
collection efficiency data were obtained from the summary report of Federal
Power Commission Form 67 data (19) and the EPA Utility FGD Survey (20), sup-
plemented by telephone contacts with individual plants. For lignite stokers,
the average particulate collection efficiency was assumed to be the same as
that for bituminous coal-fired stokers. Estimates of the average efficiency
of particulate control devices on lignite coal-fired utility boilers for 1978
are also presented in Table 29.
65
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TABLE 28. DISTRIBUTION OF PARTICULATE CONTROL EQUIPMENT FOR
BITUMINOUS COAL-FIRED UTILITY BOILERS
en
Percent Distribution of Parti cul ate Control
Combustion System Category
Pulverized dry bottom
Number basis
Capacity basis
Fuel consumption basis
Pulverized wet bottom
Number basis
Capacity basis
Fuel consumption basis
Cyclone
Number basis
Capacity basis
Fuel consumption basis
Stoker
Number basis
Capacity basis
Fuel consumption basis
ESP
60
79
83
52
66
77
61
83
89
8.4
28.8
44.4
Centrl fugal
Separator
17
10
11
20
11
9
5
8
5
36
32
25
Other*
15
10
5
16
9
7
18
5
3
25
20
14
Equipment
NO
Control
8
1.6
1.0
11
14
7
7
4
3
32
19
16
Source: Reference 16.
Wet scrubbers, fabric filters, gravitational separators.
-------
TABLE 29. TOTAL MASS EFFICIENCY OF PARTICULATE CONTROL DEVICES
FOR COAL-FIRED UTILITY BOILERS - 1978
Boiler Type
Bituminous Coal
Pulverized
Cyclone
Stoker
Lignite
Pulverized
Cyclone
Stoker
Control
Device
Efficiency
Cc
0.94
0.92
0.80
0.98
0.95
0.80
Application
of
Control
Ca
0.98
0.98
0.81
1.0
1.0
0.81
Average
Efficiency
Cm a VCa
0.92
0.90
0.65
0.98
0.95
0.65
For bituminous and lignite coal-fired boilers, projections on the average
efficiency of particulate control devices for 1985 have been made and are
presented in Table 30. These projections are based on an average particulate
collection efficiency of 99.4 percent (19) for coal-fired utility boilers that
will be on stream between 1978 and 1985. Thus, the added capacities for pul-
verized bituminous coal-fired boilers, pulverized lignite-fired boilers, and
lignite-fired cyclone boilers will all be associated with the average 99.4
percent particulate collection efficiency. As a consequence, there will be
an overall improvement in particulate collection efficiency for these three
boiler types. Since there will be no increase in the installed capacity for
bituminous coal-fired cyclone boilers and stokers and for lignite-fired
stokers, the average efficiency of particulate control devices for these
boiler types in 1985 will be the same as in 1978.
67
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TABLE 30. TOTAL MASS EFFICIENCY OF PARTICIPATE CONTROL DEVICES
FOR COAL-FIRED UTILITY BOILERS - 1985
Boiler Type
Bituminous Coal
Pulverized
Cycl one
Stoker
Lignite
Pulverized
Cyclone
Stoker
Control
Device
Efficiency
Cc
0.95
0.92
0.80
0.99
0.96
0.80
Application
of
Control
Ca
0.99
0.98
0.81
1.0
1.0
0.81
Average
Efficiency
Cm - VCa
0.94
0.90
0.65
0.99
0.96
0.65
Only a small fraction of oil-fired utility boilers are equipped with
particulate control devices. GCA estimated that approximately 20 percent of
oil-fired utility boilers have particulate controls, with an average effi-
ciency of 50 percent (1). Gas-fired utility boilers have no particulate
controls.
To reduce emissions of sulfur oxides to the atmosphere, emphasis and
major efforts have been directed at the development of flue gas desulfuriza-
tion (FGD) processes. To date, the five F6D processes that have been suffi-
ciently developed for full-scale commercial application are: lime/limestone
scrubbing, magnesium oxide scrubbing, sodium carbonate scrubbing, the double
alkali process, and the We11man-Lord process that involves the absorption of
sulfur dioxide into a solution of sodium sulfite, bisulfite and sulfate. In
addition, the aqueous carbonate and the citrate processes are being tested
on full-scale coal-fired boilers. By the end of 1978, there were 51 operating
68
-------
FGD systems on utility boilers totaling 17,888 MW in generating capacity
(20), 14,309 MW of which were on bituminous coal-fired boilers and the re-
mainder on lignite coal-fired boilers. Thus, only approximately 7.7 percent
of the utility coal-fired capacity is equipped with FGD systems.
A summary list of the operating FGD systems is presented in Table 31,
along with the individual scrubbing process types and S02 removal efficien-
cies. Of the operating systems, forty three are lime- or limestone-based,
one is magnesium oxide scrubbing, three are sodium carbonate, one is double
alkali, and three are Wellman-Lord. On generating capacity basis, 91.6 per-
cent of the operating FGD systems utilize lime/limestone scrubbing. By 1985,
the FGD systems scheduled for operation will increase significantly, to a
total representing 52,572 MW in generating capacity (20). Of this total,
42,575 MW will be on bituminous coal-fired boilers and 9,997 MW will be on
lignite coal-fired boilers. Thus, approximately 16 percent of the projected
utility coal-fired capacity will be equipped with FGD systems by the end of
1985.
The primary techniques for reducing NO emissions from utility boilers
/*
include: low excess air firing (LEA), flue gas recirculation (FGR), off-
stoichiometric combustion, reduced air preheat, and burner or furnace modi-
fication. Low excess air firing reduces oxygen availability at the burner,
thus reducing both thermal and fuel NO formation. It is the most widely
A
used NOV control technique for utility boilers, and firing with excess air
A
below 5 percent is now standard practice on many large oil- and gas-fired
boilers (21). Recirculation of flue gas externally into the primary combus-
tion air reduces thermal N0¥ formation, primarily by lowering the flame zone
/\
temperature, but also by reducing the local oxygen concentration. Off-
stoichiometric combustion involves mixing of fuel with combustion air such
that fuel-rich conditions prevail in the primary combustion zone, followed
by complete combustion downstream. This can be accomplished by the use of
over-fire air (OFA) ports, firing with some burners out of service, or biased
firing, i.e., operating burners in staggered configurations of fuel rich and
either fuel lean or air only. Off-stoichiometric combustion is effective in
reducing both thermal and fuel NO formation by lowering oxygen availability
•^
and flame temperatures in the primary combustion zone, and by lowering
effective temperatures in the secondary zone where combustion is completed.
69
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TABLE 31. PROCESS TYPE AND EFFICIENCY OF OPERATING FGD SYSTEMS
FOR UTILITY BOILERS IN 1978
Company DM*
Alabama Electric Coop.
Arizona Electric Power Coop.
Arizona Public Service
Arizona Public Service
Central Illinois Light
Columbus I Southern Ohio Elec.
Columbus 1 Southern Ohio dec.
Duquetne Light
Ouquesne Light
Gulf Power
Indianapolis Power ( Light
Kansas City Power 1 Light
Until City Power i Light
Kansas City Power 1 Light
Kansas Power 1 Light
Kansas Power a Light
Kansas Power 1 Light
Kentucky Utilities
Louisville Gat Electric
Louisville Gas Electric
Louisville Gat Electric
Louisville Gas Electric
Louisville Bis Electric
Mlnnkota Power Cooperative
Montana Power
Montana Power
Nevada rower
Nevada Power
Nevada Power
Northern Indiana Public Service
Northern States Power
Northern States Power
Pennsylvania Power
Pennsylvania Power
Philadelphia Electric
Public Service of New Mexico
Public Service of New Mexico
South Carolina Public Service
Southern Illinois Power Coop.
Southern Mississippi Electric
Southern Mississippi Electric
Springfield City Utilities
Tennessee Valley Authority
Tennesiee Valley Authority
Tennessee Vallty Authority
Texas Utilities
Texas Utilities
Te«as Utilities
Texas Utilities
Utah Power 1 Light
Utah Power » Light
Unit KM*
Tomblgbee 2
Apache t
CNolla 1
Cholla 2
Duck Creek 1
Conesvllle S
Conesvllle 6
Elrama
Philips
Scholi IB * 28
Petersburg 3
Hawthorn 3
Hawthorn 4
La Cygne 1
Jeffrey 1
Lawrence 4
Lawrence 5
Green River 1,213
Cine Run 4
Cane Run 5
Cane Dun t
Mill Creek 3
Paddy's Run 6
"11 ton R. Young 2
Col strip 1
ColstHp 2
Reid Gardner 1
Reid Gardner 2
Reid Gardner 3
Dean N. Mitchell 11
Sherburne 1
SNerbcirne 2
Bruce Mansfield 1
Iruce Mins field 2
Eddys tone 1A
San Juan 1
San Juan 2
Hlnyan 2
Marlon 4
R. D, Morrow 1
R. D. Morrow 2
Southwest 1
Shawiwe KM
Shawnee 108
Widows Creek 8
Kit-tin Lake 1*
Martin Lake 2*
Martin Lake 3*
Nontlcello 3*
Bury 1
Huntlngton 1
FSB Systems
Design Capacity
m
225
220
115
250
400
400
400
510
410
23
530
100
100
820
680
125
400
64
17B
183
27?
425
65
450
360
360
125
125
125
115
710
710
625
825
120
314
306
280
184
180
180
200
10
10
550
793
793
793
750
400
415
F6D Process Type
Limestone
Limestone
Limestone
Limestone
Limestone
Line (ThlosorbU)
Line (Thiosorbtc)
Lime (Thtosorbtc)
Line (Thlosorblc)
Limestone
Limestone
Lime
Line
Limestone
Limestone
Limestone
Limestone
L1me
Line (Carbide)
L1me (Carbide)
Double Alkali
Line (Carbide)
Lime (Carbide)
Lime/Alkaline Flyash
Lime/Alkaline Flyash
Line/Alkaline Flyash
Sodium Carbonate
So dim Carbonate
Sodium Carbonate
well nan Lord
Limestone/Alkaline Flyash
Limestone/Alkaline Flyash
Lime (Thlosorblc)
Line (Thlosorblc)
Magnesium Oxide
Hell nan Lard
tollman Lord
Limestone
Limestone
Limestone
Limestone
Limestone
Lime/Limestone
Line/Limestone
Limestone
Limestone
Limestone
Limestone
Limestone
Line
Line
% Sulfur
In Coal
1,15
0.7
0.55
0.55
3.3
4.7
4,7
2.0
2.0
5.0 IMX
3,25
2.0
2.0
5.0
0.3
0.5
0.5
3.7
3.75
3.75
3.75
3.75
3.75
0.7
0.8
0.8
0.5
0.5
0.5
3.5
o.e
0.8
4.7
4.7
2.5
0.8
0.8
1.0
3.0
1.0
1.0
3.5
2.9
2.9
3.7
0.9
0.9
0.9
1.5
0.5
0.5
SO? Removal
Efficiency**
t
80.0
85.0
55.0
75.0
91.6
89,5
89.5
75.0
75.0
t
80.0
70.0
70.0
80.0
60.0
73.0
5!.0
85.0
87.5
85.0
88.0
85.0
89.5
75.0
75.0
75.0
87.5
87.5
87.5
91.0
52.5
52.5
95.0
95.0
96.0
85.0
85.0
85.0
t
85.0
85.0
92.0
*
t
89.5
73.9
70.5
70.5
74.0
80.0
80.0
Source: Reference 20.
• Lignite coal-fired boilers.
t S02 rwmjval efficiency data for these newly Installed FSO systems are not yet available.
+ SO? removal efficiencies at Shawnee are experimentally controlled.
"Bated on actual efficiencies when test data are available, and design efficiencies when data are
not available.
-------
Reduction of combustion air preheat reduces thermal NO formation by effecti-
A
vely lowering the combustion zone peak temperature. This NO control tech-
rt
nique, however, also has an adverse impact on thermal efficiency. Burner or
furnace modification involves the optimization of burner parameters such as
burner geometry, fuel injection method, primary to secondary air ratio, and
swirl level. A number of low NO burners with modified air and fuel injec-
tion, for example, have been recently developed.
Low excess air firing is the only NO control implemented on a large
•rV
scale on utility boilers. A summary of different boiler types that have
either retrofit or factory-installed NO controls is presented in Table 32.
•&
As indicated in this table, use of overfire air and installation of new
burner or furnace design are the next two most commonly employed NO control
A
techniques for utility boilers. The generating capacity of utility boilers
equipped with NOX controls amounted to 43,756 MW in 1978, representing
approximately 10.9 percent of the total utility fossil fuel-fired boiler
generating capacity.
4.2.2 Wastewater EffluentsandControl Technology
Water usage in steam electric plants is complex and results in waste-
water streams from a number of operations. The wastewater streams associated
with a coal-fired utility plant are depicted schematically in Figure 5 {!}.
The volumes of the wastewater streams, as presented in Figure 5, are typical
for a 1000 MW coal-fired plant, but are subject to plant-to-plant variations,
depending on the operating practices employed. Also, some of the wastewater
streams shown, such as flyash and bottom ash transport water, are not appli-
cable to oil- and gas-fired utility plants.
A number of wastewater streams from steam electric plants are produced
more or less continuously, while others are produced on an intermittent
basis. Wastewater streams that are produced relatively continuously include:
discharge from once-through cooling systems or blowdown from cooling towers,
ash transport water, wastewater from wet-scrubber systems for particulate and
S02 removal, and boiler blowdown. Wastewater streams that are produced inter-
mittently include: wastewater from water treatment processes such as clari-
fication, softening and ion exchange, wastewater from chemical cleaning of
71
-------
TABLE 32. SUMMARY OF NOX CONTROL METHODS AND GENERATING
CAPACITY FOR UTILITY BOILERS IN 1978
Fuel
Pulverized
bituminous
coal
Pulverized
lignite
coal
Oil
Gas
Oil /Gas
Hethod of Firing
Tangential
Front-wall
Hor1 zontally-opposed
Subtotal
Tangential
Hor1 zonta lly-opposed
Subtotal
Tangential
Front-wal 1
Horizontally-opposed
Subtotal
Horl zontal ly-opposed
Subtotal
Tangential
Front-wall
Horizontally-opposed
Subtotal
NOX Control Method
Overflre air
New burner or furnace design
Overflre air
Burner out of service
New burner design + overfire air
New burner or furnace design
Overflre air
New burner design + overfire air
New burner design + FGR
Overflre air
Hew burner or furnace design
Overflre air + FGR
Overflre air
FGR
Overflre air + FGR
New burner design + overfire air + FGR
New burner or furnace design
FGR
Overflre air + FGR
New burner design + overfire air
New burner or furnace design
Burner out of service
Overflre air + FGR
Overflre air
FGR
Burner out of service
Overflre air
FGR
Burner out of service
Reduced air preheat
Overflre air + FGR
Burner out of service + overfire air
Overflre air
Overflre air + reduced air preheat
Reduced air preheat
Burner out of service + overfire air
Burner out of service + FGR
Burner out of service + overfire air +
Generating
Capacity
HH
1,400
85
350
125
375
7,480
2,061
3,251
450
15,577
750
775
1,525
735
705
125
2,650
800
1,160
750
3,695
1,200
11,820
1,350
135
750
2,235
220
1,950
270
842
297
?,659
140
238
780
440
198
140
945
1,920
FGR 1 ,570
12,599
Source: Reference 22.
72
-------
12-6
3, 620 (WITH COOLING
TOWER)
121,290 (WITH ONCE
THROUGH COOLING)
630
3.2
16
229
520
2,210
BOILER
1.6
(FLUE GAS)
FLUE GAS
DESULFURIZATION
315
METAL
EQUIPMENT
CLEANING
7.9
OTHER
LOW- VOLUME
SOURCES
BOTTOM ASH
TRANSPORT
FLY ASH
TRANSPORT
630
3.2
315
79
789
252
1.6
3,2
BLOWDOWN 7.9
ASH SETTLING
BASINS
16
COOLING
TOWER
SLOWDOWN 32
GLAND AND
MISC. LOSSES
SOOT
BLOWERS
3.2
1460
OVERFLOW
TREATMENT
1460
DRIFT 1.6
EVAPORATION 2,160
119,870
CONDENSERS
119,870
Figure 5. Water Flows (m /hr) for a Typical 1000 MM Coal-Fired Power Plant at Full Load (1)
-------
equipment (boiler tubes, condenser, air preheater), rainfall runoff from
coal storage piles, and miscellaneous low volume wastes such as sanitary
wastes, floor drains, and laboratory drains. The nature and characteristics
of these wastewater streams will be discussed later in Section 6.
The two principal methods of wastewater treatment at steam electric
plants are controlled release to a waterway to achieve a dilution ratio of
5000:1 to 10000:1, and retention in a holding pond for sedimentation and/or
neutralization before controlled release (23). Other options include the use
of evaporation ponds at locations with sufficient land and favorable climatic
conditions, ocean dumping, disposal by a commercial disposal firm in land-
fills, waste solidification with reagents supplied by outside vendors, and
waste incineration. With the exception of evaporation ponds, all the latter
options are only suitable for the disposal of concentrated waste streams such
as metal cleaning wastes.
4.2.3 SolidWastes and Disposal/Recovery Practices
Solid wastes are generated in fossil fuel-fired steam electric plants
from the ash handling system, the FGD system, and water treatment processes.
The solid wastes generated are therefore principally:
t Fly ash
• Bottom ash (bottom slag)
• Spent scrubber sludge
t Water treatment sludges.
The characteristics of these solid wastes will be discussed in Section 7.
Fly ash is generally collected in air pollution control devices such as
electrostatic precipitators and multiple cyclones. Disposal of fly ash and
bottom ash involves either mechanically conveying the dry ash to a landfill
area, or by water sluicing and piping the ash transport water to a settling
pond. In ash disposal by water sluicing, an intermediate stage of ash de-
watering in bins is sometimes involved, with subsequent disposal of the wet
ash in landfills.
In a study conducted by the National Ash Association (24), it was esti-
mated that 61,900 Gg of coal ash were produced in 1978. Of the coal ash
74
-------
produced, the breakdown was 44,300 Gg fly ash, 12,900 Gg bottom ash, and
4,700 Gg boiler slag. Data on ash disposal practices show that (24):
t 49 percent of the ash is trucked to landfill disposal area
and 51 percent of the ash is sluiced.
t 28 percent of the fly ash and bottom ash is separated
before disposal and 72 percent is disposed together.
§ 68 percent of the power plants have dry collecting and
loading facilities for fly ash.
The current trend is away from ash disposal and towards increased ash utili-
zation. Appreciable quantities of coal ash are used currently as partial
replacement of cement in concrete and blocks, as fill material for roads and
other construction projects, and as blast grit and roofing granules. A
complete breakdown of commercial utilization of coal ash is presented in
Table 33. For 1978, utilization estimates were 6,800 Gg for fly ash, 5,000
Gg for bottom ash, and 3,300 Gg for boiler slag (24). The overall utiliza-
tion factor was 24.3 percent. By 1985, the estimated ash production will be
81,600 Gg, with an ash utilization factor of 40 percent.
Spent scrubber sludges from nonrecovery FGD systems are currently dis-
posed of by use of ponds, landfills and mines. Of the FGD plant capacity in
1978, approximately 48 percent utilized unlined wet ponds for ultimate dis-
posal, 14 percent utilized lined wet ponds, 21 percent utilized landfills,
and 17 percent utilized surface mines (25), These disposal methods are being
utilized with or without sludge stabilization. Sludge stabilization methods
used prior to ultimate disposal include ash addition, forced oxidation, and
the IUCS and Dravo processes involving the addition of proprietary chemical
fixation agents. Co-disposal of FGD scrubber sludge with ash is practiced in
over 90 percent of the FGD plant capacity.
Sludges from water treatment processes are disposed of by direct dis-
charge to waterways or sewer systems, and by sending to settling ponds before
discharge. The other option is disposal in landfill sites after sludge de-
watering by filtration, thickening, and drying operations.
75
-------
TABLE 33, ASH COLLECTION AND UTILIZATION IN 1977
Utilization Percentage
Ash Utilization
Commercial Utilization
• Mixed with raw material before
forming cement clinker
• Mixed with cement clinker or mixed
with cement (Type 1-P cement)
• Partial replacement of cement in
concrete and blocks
• Lightweight aggregate
• Fill material for roads, construction
sites, land reclamation, ecology
dikes, etc.
• Stabilizer for road bases, parking
areas, etc.
• Filler in asphalt mix
• Ice control
• Blast grit and roofing granules
• Miscellaneous
Ash Removed from Plant Sites at No Cost
to Utility
Ash Utilized from Disposal Sites After
Disposal Costs
Ash Utilized, 6g
Total Ash Collected, Gg
Fly
Ash
7
5
25
2
20
3
2
___
3
7
26
100
5,700
44,000
Bottom
Ash
___
2
—
3
20
5
—
22
-__
9
17
22
100
4,200
12,800
Boiler
Slag*
3
—
—
—
8
2
13
48
22
4
___
100
2,800
4,700
Source: Reference 24.
*
If separated from bottom ash.
76
-------
5. AIR EMISSIONS
5.1 SOURCE AND NATURE OF AIR EMISSIONS
Flue gas from fuel combustion is the largest source of air pollution in
fossil fuel-fired steam electric plants. Pollutants contained in flue gas
streams include nitrogen oxides, sulfur oxides, carbon monoxide, particulate
matter, sulfates, trace elements, and a variety of organic species. Emissions
of nitrogen oxides result from the oxidation of nitrogen compounds present in
the fuel and the nitrogen component of combustion air. Sulfur oxides and
sulfates are formed from the oxidation of fuel sulfur. Carbon monoxide and
organic compounds such as hydrocarbons and polycyclic organic matter are all
products of incomplete combustion. Particulate matter emitted is comprised
of combustion products of mineral compounds present in the fuel, condensate
droplets, as well as incomplete combustion products such as soot. For coal
combustion, the major constituents of particulate matter are silicon, aluminum,
iron and calcium, which often add up to over 90 percent of the total composi-
tion. Particulates emitted from oil combustion, on the other hand, contain
high concentrations of vanadium, nickel, aluminum, calcium, and iron. Minor
and trace elements present in the fuel are mostly emitted as particulates.
The notable exceptions are the volatile elements mercury, chlorine, and
bromine, which are emitted in gaseous form.
Two other sources of air emissions considered to have measurable impacts
on the environment are cooling tower emissions and emissions from coal storage
piles. Plumes from evaporative cooling towers contain water vapor and liquid
water, the latter as both condensed and drift or carryover droplets. Water
droplets resulting from condensation, and up to about 20 wm in size, are
considered as fog. These droplets consist of relatively pure water. In
contrast to fog, drift droplets are relatively larger (>20 pm), and contain
dissolved and suspended solids present in the recirculating cooling water.
The visible fog plumes from evaporative cooling towers may cause reduction in
visibility, ice formation on surfaces, and cloud initiation. The drift, which
77
-------
is eventually deposited on surfaces downwind from the cooling tower, may
cause damage to the biota in surrounding areas as well as corrosion to nearby
structures.
Coal storage piles are open sources of atmospheric emissions. The
pollutants emitted include particulates as fugitive dusts, gaseous hydro-
carbons, and carbon monoxide. The emission rates of these pollutants are
dependent primarily on wind conditions, precipitation, humidity, temperature,
coal pile geometry, and the bulk density of coal.
Detailed characterization data on flue gas emissions, cooling tower
emissions, and coal storage pile emissions are discussed in the following
sections. Air emissions from other sources, such as ash handling and storage,
are considered to be insignificant and will not be discussed here.
5.2 CRITERIA FOR EVALUATING THE ADEQUACY OF EMISSIONS DATA
A major task in this project has been the identification of gaps and
inadequacies in the existing emissions data base for combustion sources. The
results of this effort determine the extent of the sampling and analysis task
required to complete an adequate emissions assessment for each of the combus-
tion-source types. In addition, the data acquired during the sampling and
analysis task, in combination with the existing data, also need to be
assessed. Data inadequacies identified at the completion of the current
project will require further study.
The principal criteria for assessing the adequacy of emissions data were
their reliability, consistency, and variability. A detailed presentation
of the procedures used to identify and evaluate emissions data is given in
Appendix A. Briefly, a three-step process was used. In the first step, the
available data were screened for adequate definition of process and fuel
parameters that may affect emissions as well as for validity and accuracy of
sampling and analysis methods. This is the main step for judging the relia-
bility of data. In the second step of the data evaluation process, emission
data deemed acceptable in Step 1 were subjected to further engineering and
statistical analysis to determine the internal consistency of the test results
and the variability in emission factors. The third and final step in the
process used a method developed by Monsanto Research Corporation (MRC) which
78
-------
was based on both the potential environmental risks associated with the emis-
sion of each pollutant and the quality or variability of the data. The
potential environmental risks associated with pollutant emissions were deter-
mined by the use of a source severity factor , which was defined as the ratio
of the calculated maximum ground level concentration of the pollutant species
for an isolated typical source to the level at which a potential environmental
hazard exists. If the variability of emission factor data was <70 percent,
the data were deemed adequate. However, if the variability of the emissions
data >70 percent, the determination of data adequacy and the need for further
measurement were based on calculated severity factors for each pollutant.
The data were considered adequate if the upper bound of the source severity
factor was I0.05f.
In addition to the general approach described above, fuel analysis, mass
balance, and physico-chemical considerations can often be used to estimate
emission levels and to establish the adequacy of the data base. For example,
flue gas emissions of trace elements from oil-fired utility boilers can be
determined from the trace element content of fuel oil by mass balance. Thus,
an adequate characterization of the trace element content of fuel oil will
provide an adequate characterization of trace element emissions from oil-fired
utility boilers. If Level II analysis data were used as the basis for
estimates, the estimated emission levels can often be considered to be more
reliable than measured emission levels utilizing Level I sampling and analysis
methodology.
5.3 EVALUATION OF EXISTING EMISSIONS DATA
5.3.1 Flue Gas Emissions
5.3.1.1 Emissions of Cr iteria Pol 1 u tants
Emission Data Sources
Although there appears to be numerous sources of emissions data for
fossil fuel-fired utility boilers, few are well documented to provide adequate
In current EPA IERL-RTP terminology, the source severity factor is called
ambient severity.
The 0.05 criterion reflected an uncertainty factor of 20 in the calculation
of source severity factor (160).
79
-------
definition of fuel parameters, boiler category, and boiler operating charac-
teristics. In this study, nine were considered as principal and reliable
sources for baseline data compilation. Crawford et al and Bartok et al of
Exxon Research and Engineering reported NO , CO, and participate emissions
A
for pulverized coal-fired wet- and dry-bottom units (26, 27, 28, and 39).
These data are from field tests to determine the effects of combustion modi-
fication on NO emissions. Data from one dry-bottom boiler fired with
^.
pulverized lignite were also reported. A Standards Support and Environmental
Impact Statement prepared in 1976 reported NO and CO emissions from dry-
A>
bottom boilers fired with pulverized bituminous coal and lignite (30). NOX
emissions from four boiler/fuel types were reported by Surprenant et al (1):
pulverized, cyclone, and stoker units fired with bituminous coal; and a
horizontally-opposed lignite-fired boiler. Ctvrtnicek and Rusek (8) reported
data from cyclone units: NO , CO, SOp, and SO., emissions from bituminous-
coal-fired boilers and NO and CO emissions from lignite-fired boilers. A
J\
Standards Support and Environmental Impact Statement (31) and a report by
Gronhovd and Kube of the Bureau of Mines (32) provided most of the NO and
&
SQy data from lignite-fired boilers.
There are fewer sources of emissions data for oil- and gas-fired utility
boilers than for coal-fired units. Surprenant et al (1) and Bartz et al (33)
reported NO emissions from oil and gas firing. Habelt and Selker (34) also
i\
reported NOX data for a gas-fired unit. Bartok et al reported CO emissions
from oil and gas firing (39).
In some cases when data were not found from the above sources, the EPA
\ AP-42 emission factors are presented (36). The data base for EPA AP-42
emission factors is analyzed for some pollutant/fuel/boiler type categories
in a report by PEDCo (35). Data provided in the PEDCo report were used to
provide estimates of the adequacy of AP-42 emission factor data.
Statistical Treatment of Emission Data
Emissions of NOY, S09, CO, particulates, and hydrocarbons from utility
j
boilers fired with bituminous, lignite and anthracite coal, oil, and gas are
presented in the following subsections. Average emission factors in ng/J of
energy input have been calculated using the following fuel heating values:
80
-------
bituminous coal - 25,586 kJ/kg* (11,000 Btu/lb); lignite coal - 15,352 kO/kg
(6,600 Btu/lb); anthracite coal - 34,500 kJ/kg (14,833 Btu/lb); residual oil -
43,760 kJ/kg (146.000 Btu/gal); and natural gas - 38,153 kJ/m3 (1,024 Btu/SCF),
N
S02 and particulate emission factors for bituminous, lignite, and anthracite
coal are expressed in terms of the sulfur or ash content of the fuel on a
moist (as-fired) basis. Average sulfur and ash contents assumed for the
calculation of severity factors were: bituminous - 1.92 percent sulfur,
14.09 percent ash; and lignite - 0.64 percent sulfur, 13.49 percent ash.
Severity factors were not calculated for anthracite firing. In calculation
of the S02 severity factor for lignite firing, the average weight ratio of
in the ash was assumed to be 0.197.
Variabilities of emission factors were determined in two ways. In the
first method, when the number of data points, n, and the standard deviation,
s(x), were known, the variability was calculated as described in Appendix A.
The second method was used when n and s(x) were not known, e.g., when average
emission factors were obtained from other data compilations. The assumption
was made that the coefficients of variation, s(x)/x, for average emission
factors of the same pollutant from different emission sources would tend to
average. For example, the variability of the CO emission factor for bitumi-
nous coal-fired stokers was estimated by averaging s(x)/x for CO emissions
from bituminous coal-fired pulverized wet- and dry-bottom and cyclone boilers
and making the worst case assumption that n = 2.
Amounts of Emissions
Bituminous Coal Firing--
NOX, CO, S02f particulate, and total hydrocarbon emissions data from
bituminous coal-fired utility boilers are presented in Tables 34 through 38.
The number of data points, average emission factor, variability of the emis-
sion factor, severity factor, and evaluation of the data base adequacy are
presented by boiler type in these tables.
According to Le Systeme International d'Unites (SI), prefixes should not
be used in the denominator of compound units, except for the kilogram (kg).
Since the kilogram is a base unit of SI, it should be used in place of the
gram in the denominator. Thus, heating values should be expressed as
kJ/kg, and not as J/g.
81
-------
TABLE 34. SUMMARY OF NOX DATA FROM BITUMINOUS
COAL-FIRED ELECTRICITY GENERATION SOURCES
Combustion
System
Pulverized Dry,
Tangent1! ally F1rtd
Pulverized Dry,
Wall Fired
Pulverized Wet
Cyclone
All Stokers
No. of
Data
Points
17
12
4
11
9
Emission
Factor
ng/J
259
379
380
678
241
Variability
0.073
0.156
0.467
0.153
0.250
Mean
Severity
Factor
1.95
2.81
1.70
6.36
0.132
Data Base
Adequacy*
A
A
A
A
A
References
26,27,28,30,
37,38,39
1.26.28,39.
40,41
26.27
1,8,32,39
1
NOX data are from full load operation and are expressed as NO-.
Adequate data base 1s Indicated by A and inadequate data base 1s Indicated by I.
TABLE 35. SUMMARY OF CO DATA FROM BITUMINOUS
COAL-FIRED ELECTRICITY GENERATION SOURCES
Combustion
System
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
No. of
Data
Points
14
4
2
NR*
Emission Variability
Factor
ng/J
18.4
11.7
28.2
39.1
0.709
0.908
8.10
B.I**
Mean Data Base References
Severity Adequacy*
Factor
S
0.0005
0.0002
0.001
0.00008
s *
u
0.0009
0.0004
0.009
0.0008
A
A
A
A
26,27
26,27
8,32
35,36
,28,30
The upper Unit severity factor, Su, Is computed from xu - I «• U(K], where x 1s the average
emission factor and t Is based on a 95 percent confidence Unit.
Adequate data base 1s Indicated by A and Inadequate data base 1s Indicated by I.
HR • Not Reported.
*
Estimated using Hethod 2 (see previous subsection) and coefficients of variation for CO
emissions from bituminous-coal-fired pulverized dry-bottom, wet-bottom, and cyclone units.
82
-------
TABLE 36. SUMMARY OF S02 DATA FROM BITUMINOUS
COAL-FIRED ELECTRICITY GENERATION SOURCES
Combustion
System
All Firing Types
Pulverized Dry
Pulverized Met
Cyclone
All Stokers
No. of Emission Variability
Data Factor*
Points ng/J
18 733 S 0.067
—
--
—
Mean
Severity
Factor1"
2.64
1.57
3.29
0.192
Data Base References
Adequacy*
8,37.38,41,42,
43,44,45,46
A
A
A
A
Emission factors for S0£ are presented In terms of percent sulfur In the feed coal on a moist
(as-fired) basis.
Severity factors are based on a national average of 1,92 percent sulfur in coal.
Adequate data base Is Indicated by A and Inadequate data base 1s Indicated by I.
TABLE 37. SUMMARY OF PARTICULATE DATA FROM BITUMINOUS
COAL-FIRED ELECTRICITY GENERATION SOURCES
Combus t 1 on
System
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
t
No. of
Data
Points
48
91
44
17
Emission
Un-
controlled
31 5A
254A
S3A
235A
Factor . ng/J
Control! edT
18. 9A
15. 2A
4.2A
47. OA
Variability
0.125
0.058
0.134
0.290
Mean
Severity
Factor,
Controlled*
0.64
0.34
0.19
0.13
Data
Base
Adequacy*
A
A
A
A
References
26.28,35,37.
41.42.47.
48,49*50
26.35 .!
•f \
8,35,50
8,35
Emission factors for particulates are presented 1n terms of percent and 1n the feed coal on a
moist (as-fired) basis.
+ Efficiencies of particulate control used to calculate controlled emissions are 94% for
pulverized coal-fired boilers, 92* for cyclone coal-fired boilers, and 80S for stokers.
* Severity factors are based on a national average of 14.09 percent ash 1n the feed coal.
Adequate data base 1s Indicated by A and Inadequate data base 1s indicated by I.
83
-------
TABLE 38. SUMMARY OF TOTAL HYDROCARBON DATA FROM BITUMINOUS
COAL-FIRED ELECTRICITY GENERATION SOURCES*
Combustion
System
Pulverized Coal
Dry- bottom
Wet- bottom
Cycl one
Spreader Stokers
No. of
Data
Points
11
—
--
NR**
**
NR
Emission
Factor
ng/o
3.6
3.6
3.6
5.9
19.5
Variability
1.07
1.07
1.07
14tt
14tt
Mean
Severity
Factor
S S t
u
..
0.020 0.041
0.013 0.027
0.044 0.68
0.0087 0.13
Data Base
Adequacy*
-
A
A
I
I
References
26,35
36
36
Hydrocarbon data are tabulated as CH..
Tabulated severity factor 1s the upper limit Sy computed from xu " x + ts(5), where x Is the
average emission factor and t 1s based on a 95 percent confidence limit.
Adequate data base 1s Indicated by A and Inadequate data base 1s Indicated by I.
**NR - Not Reported.
tt
Estimated using Method 2 (see previous subsection) and coefficient of variation for hydro-
carbon emissions from pulverf zed-bituminous-coal-fired units.
Uncontrolled N0¥ emissions data from base load operation were found for
/\
all categories. Variabilities of NO emission factors were less than 0.70
A
for all five applicable categories. Therefore, the NO data base for bitu-
<&
mi nous coal-fired utility boilers is judged to be adequate.
Carbon monoxide data were found for all bituminous categories except
stokers. For pulverized and cyclone coal-fired utility boilers, the extremely
low severity factors for carbon monoxide emissions indicate there is little
environmental concern. For stokers, the AP-42 value was taken as an estimate
of carbon monoxide emissions. The variability for carbon monoxide emissions
from stokers was estimated by using Method 2 described in the previous sub-
section and the coefficients of variation for CO emissions from bituminous
coal-fired pulverized dry- and wet-bottom and cyclone units. For all boiler
types, variabilities were greater than 0.7, and the upper limit severity fac-
tors (S ) were computed. Since the S are all considerably less than 0.5,
the data base for CO emissions from bituminous coal-fired utility boilers is
adequate.
84
-------
Sulfur dioxide data for uncontrolled sources were found for pulverized
dry- and wet-bottom and cyclone units. As S!^ emissions are not expected to
vary with boiler type, these data were combined to yield a common SOp emis-
sion factor in terms of coal sulfur content on a moist basis. This value
corresponds to the conversion of 94 percent of the coal sulfur to SOo. Since
the variability of the SOp emission factor is less than 0.7, the data base is
considered adequate for all boiler types. Severity factors calculated for
individual boiler types for uncontrolled S02 emissions range from 0.19 for
stokers to 3.29 for cyclone units, based on a national average of 1.92 per-
cent sulfur in bituminous coal.
Controlled and uncontrolled particulate emissions data are presented in
Table 37. For all boiler types, source specific emissions data were combined
with AP-42 emission factors (based on additional information provided in
Reference 35) to yield the tabulated particulate emissions factors. These
are expressed in terms of percent ash in the feed coal on a moist basis, and
correspond to emission of 81 percent, 65 percent, 14 percent, and 60 percent
of the coal ash for pulverized dry-bottom, pulverized wet-bottom, cyclone,
and stoker units, respectively, for uncontrolled firing. Since the variabili-
ty is less than 0.7 in all cases, the data base for particulate emissions
from bituminous coal-fired utility boilers is considered to be adequate.
Average efficiencies of particulate removal presented in Section 4.2.1 of this
report were used to calculate controlled emissions. Severity factors calcu-
lated for controlled emissions are based on a national average of 14.09 per-
cent ash in the feed coal. For bituminous coal-fired utility boilers, the
mean severity factors for controlled particulate emissions range from 0.13
for stokers to 0.64 for pulverized dry bottom units.
In addition to the computation of controlled particulate emissions
based on average control efficiencies, particulate emission test data are
also available for bituminous coal-fired utility boilers equipped with high
efficiency ESP, fabric filters, and wet scrubbers (58). These test data are
summarized in Table 39. For pulverized bituminous coal-fired utility boilers
equipped with high efficiency ESP, particulate emissions ranged from 4 to 21
ng/J, and the average emission factor was 13.6 ng/J. Little correlation was
found between ESP specific collection area and effectiveness for hot side or
85
-------
TABLE 39. SUMMARY OF PARTICIPATE DATA FROM BITUMINOUS COAL-FIRED
ELECTRICITY GENERATION SOURCES EQUIPPED WITH HIGH-EFFICIENCY
PARTICULATE CONTROL DEVICES
Combustion
System
Pulverized
Pulverized
Pulverized
Stokers
Particulate
Control
Device
High efficiency ESP
Fabric filter
Wet scrubber
Fabric filter
No. of
Data
Points
22
2
7
6
Emission
Factor
ng/J
13.6
18.8
17.8
8.5
Variability
0.155
2.230
0.258
0.582
Source: Reference 58.
cold side ESP, mainly because of the differences in the characteristics of
coal fly ash. For utility boilers equipped with fabric filters (baghouses),
the average particulate emission factor was 18.8 ng/J for pulverized coal-
fired units and 8.5 ng/J for stokers. The average particulate emission factor
for pulverized coal-fired utility boilers equipped with wet scrubbers was
17.8 ng/J. These particulate emission factors for high-efficiency collection
devices are an order of magnitude lower than the controlled particulate
emission factors based on average collection efficiencies, as presented in the
previous table.
Limited source data for total hydrocarbon emissions were obtained. As
Indicated by Smith (51), most published data on organic emissions from station-
ary combustion sources were obtained before 1967 and must be examined critically
with respect to the sampling and analysis techniques employed. More recent
data are 11mited principally to total hydrocarbon measurements obtained by flame
ionization detection (FID) as a secondary effort associated with NOX emission
studies. As such, the frequency of data point acquisition and the total data
obtained have been substantially less than for NO emission data. Four source-
A
specific data points for hydrocarbon (as CHJ emissions were found. The
average of these data, 0.61 ng/J, was combined with the AP-42 average for 7
data points, yielding the tabulated emission factor of 3.6 ng/J for pulverized
86
-------
units. Data presented by Smith for unspecified coal-fired utility boilers
Indicate a similar average emission rate in the range of approximately 2 to 3
ng/J. The variability of 1.07 requires calculation of the upper limit severity
factor for pulverized dry-bottom and wet-bottom units. Since Su is less than
0.05, the data base for hydrocarbon emissions from pulverized bituminous coal-
fired boilers 1s adequate. For cyclone and spreader stoker units, the AP-42
emission factors are presented due to the lack of source-specific data. No
hydrocarbon emission factor was available for other stoker units. The varia-
bility for these firing modes was estimated by Method 2 (see previous subsection)
using the coefficient of variation for hydrocarbon emissions from the pulverized
bituminous coal-fired boilers. For the cyclone and stoker categories, the data
base for hydrocarbon emissions is inadequate.
Lignite Coal Firing--
Average emission factors for criteria pollutant from lignite firing are
presented in Tables 40 to 44. Adequate data were found for uncontrolled full-
load NO emissions from pulverized dry-bottom and cyclone boilers. Only one
data point was found for stokers. However, lignite-fired stoker units are
being phased out of usage. Therefore, there is little need for acquiring addi-
tional emissions data from these sources.
Emissions of SO, depend upon the alkali content of the lignite ash and are
not expected to vary with boiler type. An expression for SQ2 emissions in
terms of weight percent sulfur, CaO, AlpO.., Na20, and S1Q2 in the feed has been
developed using the data of Gronhovd and Kube (32):
Percent of fuel sulfur emitted as S02 B
Na?° CaO
89.97 - 68.64 •- . Q.619 •£*-
J2 23
\
or
Emission factor, ng S02/J =
Na?0 r n
(ii7i - 893.4 «4-- e.oe^S-) s
87
-------
TABLE 40. SUMMARY OF NOX DATA FROM LIGNITE-FIRED
ELECTRICITY GENERATION SOURCES*
Coabustlon
System
Pulverized Dry
Cyclone
All Stokers
No. of
Data
Points
6
3
1
Emission
Factor
ng/J
260
333
55
Variability
0.225
0.348
..
Mean
Severity
Factor
4.28
5.33
0.039
Data Base
Adequacy!
A
A
I
References
26,30,31
8,31 ,32
32
,32
NOX data are from full-load operation and are expressed as NO,.
Adequate data base Is Indicated by A and Inadequate data base Is Indicated by I.
TABLE 41. SUMMARY OF S0£ DATA FROM LIGNITE-FIRED
ELECTRICITY GENERATION SOURCES
Combustion
System
All Firing Types
Pulverized Dry
Cyclone
All Stokers
No. of Emission Variability
Data Factor*,
Points ng/0
Na90
46 1157(1 - 0.772 «r|-)S 0.045
51 °2
—
—
—
Mean
Severity
Factor t
2.57
2.50
0.11
Data Base
Adequacy*
A
A
A
References
32
The emission factor for 502 1s presented In terms of percent sulfur and the weight ratio of
NajO to S102 1n the feed coal on a moist (as-fired) basis.
Average values of S « 0.64 percent and Na-O/SIQ- • 0.1967 were assumed for severity factor
calculations.
Adequate data base 1s Indicated by A and Inadequate data base Is Indicated by I.
88
-------
TABLE 42. SUMMARY OF CO DATA FROM LIGNITE-FIRED
ELECTRICITY GENERATION SOURCES
Combustion
System
Pulverized Dry
Cyclone
All Stokers
No, of
Data
Points
NRf
NR
NR
Emission
Factor
ng/J
32.6
32.6
65.1
Variability Mean
Severity
Factor
0.002
O.OOZ
0.0002
Data Base
Adequacy*
A
A
A
References
36
36
36
Adequate data base Is Indicated by A and Inadequate data base 1s Indicated by I.
fNR - Not Reported.
TABLE 43. SUMMARY OF PARTICULATE DATA FROM
LIGNITE-FIRED ELECTRICITY GENERATION SOURCES
Combustion
System
Pulverized Dry
Cyclone
Spreader Stoker
Other Stokers
No. of
Data
Points
NR**
NR
NR
NR
Emission Factor, ng/J Vi
Un-
controlled
228A
19SA
228A
98A
*
Control 1 ed
4.6A
9.8A
45. 6A
19.6A
trl ability Mean
Severl ty
Factor
Control ledt
0.35
0.74
0.15
0.06
Data Base References
Adequacy*
I
I
I
1
36
36
36
36
Efficiencies of participate control used to calculate controlled parti cut ate emissions are
98X for pulverized boilers, 95% for cyclone boilers and 80% for stokers.
Based on a national average of 13.49 percent ash In lignite on an as-fired basis.
Adequate data base 1s Indicated by A and Inadequate data base Is Indicated by I.
**NR « Not Reported.
89
-------
TABLE 44. SUMMARY OF HYDROCARBON DATA FROM
LIGNITE-FIRED ELECTRICITY GENERATION SOURCES
Combustion
System
Pulverized Dry
Cyclone
All Stokers
Mo. of
Data
Points
NR*
NR
NR
Emission Variability
Factor
ng/J
<33
<33
33
Mean
Severity
Factor
<0.43
<0.42
0.018
Data Base
Adequacy?
I
I
I
References
36
36
36
Hydrocarbon data are tabulated as CH,.
Adequate data base Is Indicated by A and Inadequate data base Is Indicated by I.
*KR « Hot Reported.
As S0? emissions have only a slight dependence on CaO/Al9Q-,, an average
*" £. «5
value for CaO/A^Og of 1.74 (32) was inserted, simplifying to the expression
for all boiler types as presented in Table 41. Since the variability is less
than 0.05, the data base for S02 emissions from lignite-fired utility boilers
is adequate. An average sulfur content of 0.64 percent and Na20/Si02 value
of 0.197 were used for severity factor calculations for each boiler type.
Data sources for emissions of carbon monoxide, particulates, and hydro-
carbons from lignite firing were not available. AP-42 emission factors for
these pollutants are presented in Tables 42 to 44. Although data variability
cannot be estimated for any of these emission factors, the CO data base may be
considered adequate because of the very low severity factors associated with
CO emissions from bituminous coal-fired utility boilers. Particulate emission
factors for both controlled and uncontrolled lignite firing are presented.
Particulate removal efficiencies were obtained from Section 4.2.1 of this
report. Since data variability cannot be estimated and the mean severity
factors are greater than 0.05, the particulate data base is inadequate.
Hydrocarbon emission factors from AP-42 are estimates based on limited experi-
mental data and on the assumption that hydrocarbon emissions per unit mass of
fuel from lignite and bituminous coal firing are similar (36). Again, since
data variability cannot be estimated and the severity factors are not negligi-
bly low, the data base is inadequate.
90
-------
Anthracite Coal Firing-
Emission factors of criteria pollutants from anthracite firing are pre-
sented 1n Table 45 using AP-42 values, as no Individual data sources were found.
The AP-42 emission factors are based on the assumption that NOX» SOg, CO, and
particulate emissions per unit mass of fuel fired from anthracite and bitumi-
nous coal firing should be similar, and substantiated by limited data (36).
Hydrocarbon emissions were assumed to be negligible because anthracite has a
much lower volatile matter content than bituminous coal. Variabilities and
severity factors for anthracite firing have not been estimated, but because
anthracite combustion represents only a small fraction of the coal used 1n the
United States for power generation, these data gaps are not considered to be
significant.
TABLE 45. SUMMARY OF CRITERIA POLLUTANT EMISSIONS DATA FROM
ANTHRACITE-FIRED ELECTRICITY SENERATION SOURCES
Combustion System Pollutant AP-42 Emission
Factor*, ng/J
Pulverized Dry NO
SOgl"
CO
Parti culates
Hydrocarbons
260
550S
14
250A
Negligible
Traveling-Grate Stokers NOX 140
S0f 550S
CO 14
Particulates* 14A
Hydrocarbons Negligible
*
Reference 36.
Emission factors for S02 are presented in terms of percent sulfur in the
anthracite feed.
Particulate emission factors are presented in terms of percent ash 1n the
anthracite feed.
91
-------
011 Firing--
Emission factors for oil firing, except for NOX, have not been categorized
Into tangential and non-tangential firing modes, because only NOX emissions
are strongly dependent upon the firing mode. NO , CO, S09, particulate, and
A £f
total hydrocarbon emission factors for oil firing are presented in Table 46.
Severity factors have been calculated for tangential and non-tangential firing
modes for each pollutant.
Uncontrolled NO emissions data from base load operations were found for
both tangentlally- and non-tangent1ally-fired boilers. Since the variability
1s less than 0.7 for N0tf and CO emission factors, the data base for NO and
A «
CO emissions from oil-fired utility boilers is adequate. The S02 emission
factor 1s expressed in terms of percent sulfur present in the fuel oil, and
corresponds to conversion of 95 percent of fuel sulfur to sulfur dioxide.
Based on the variability of the S02 and particulate emission factors, the data
base for S02 and particulate emissions from oil-fired utility boilers is also
adequate. Emissions of hydrocarbons were estimated by using the AP-42 value
(36). Since data needed to compute the variability for this average value were
not available, the assumption was made that the hydrocarbon variability for
oil-fired utility boilers is the same as that for oil-fired industrial and
commercial/institutional boilers. The latter value is available from Reference
35. This is a reasonable assumption since the variability in hydrocarbon emis-
sion factor for well-maintained, oil-fired utility boilers is expected to be
lower than or equal to that for industrial and commercial/institutional boilers.
As the estimated variability in the hydrocarbon emission factor is less than
0.7, the data base for hydrocarbon emissions from oil-fired utility boilers is
considered to be adequate.
Natural Gas Firing—
Emission factors for NOX, CO, SO-, particulate, and hydrocarbon from gas-
fired utility boilers are presented in Table 47. Average NO emissions are
presented for tangential and non-tangential modes of operation. All other
*
Includes front wall firing and horizontally opposed firing.
92
-------
oo
TABLE 46, SUMMARY OF CRITERIA POLLUTANT EMISSIONS DATA FROM
OIL-FIRED UTILITY BOILERS
Pollutant
NO
CO
SO,
Partlculates
Hydrocarbons
Firing Type
Tangential
Non-Tangential
All Types
Tangential
Non-Tangential
All Types
Tangential
Non-Tangential
All Types
Tangential
Non-Tangential
All Types
Tangential
Non-Tangential
No. of
Data
Points
43
57
20
19
53
NRf
Emission
Factor
ng/J
114
190
67.4
435Sf
31.6
2.9
Variability Mean
Severity
Factor
0.088 1.90
0.093 1.17
0.595
0.0042
0.0016
0.0133
1.79
0.66
0.203
0.18
0.066
**
0.15
0.038
0.014
Data Base References
Adequacy*
A 1,33,34,39,52
A 1,8,33,52
8,26,33,39
A
A
44,45,46,53
A
A
56,57
A
A ,/,' /
!35,36;,39 / £
A - - -./
A
**
Adequate data base Is Indicated by A and Inadequate data base 1s Indicated by I.
Emission factors are presented 1n terms of S, the percent sulfur in oil. Severity factors are based
on a national average oil sulfur content of 1.03 percent w/a (19).
NR » Not Reported.
The hydrocarbon variability for oil-fired utility boilers has been assumed to be the same as for
industrial and commercial/institutional oil-fired boilers (35).
-------
TABLE 47. SUMMARY OF EMISSIONS FROM GAS-FIRED
UTILITY BOILERS
Pollutant
NO
X
CO
so2
E>
Parti culates
Hydrocarbons
Firing Type
Tangential
Other
AH Types
Tangential
Non-Tangential
All Types
Tangential
Non-Tangential
All Types
Tangential
Non-Tangential
All Types
Tangential
Non-Tangential
No. of
Data
Points
56
49
11
NR*
NR
NR
Emission
Factor
ng/J
124
233
14.6
0.25
2-6
0.42
Variability Mean Severity
S
0.124 3.21
0.194 2.94
0.836
0.0014
0.0007
•>«.
0.0015
0.0007
**
5.6
0.02 -0.05 0.
0.009-0.03 0.
12.4ft
0.0082
0.0040
Factor
*;
0.0025
0.0012
12-0.35
06-0.17
0.11
0.05
Data Base References
Adequacy*
A 1,33,34,39,52
A 1,33.39.52
33.39
A
A
36
* cjg
A '
(jf®~ h
I
I
35.36
I
A
Adequate data base Is Indicated by A and Inadequate data base Is Indicated by I.
*Th1s upper limit severity factor Su 1s computed from xu - x + ts(x), where x 1s the average emission factor and t Is
based on a 95 percent confidence limit.
*NR • Not Reported.
This variability was estimated using Method 2 (see previous subsection) and the coefficient of variation for partlculate
emissions from natural-gas-flred domestic and commercial heating units (35).
This variability was estimated using Method 2 (see previous subsection) and the coefficient of variation for hydrocarbon
emissions from natural-gas-flred domestic and commercial heating units (35).
tt
-------
emission factors are averages for all firing modes. Severity factors are cal-
culated in each case for tangential and non-tangential modes. For NO emis-
s\
sions, the variability is less than 0,7 and the data base is considered to be
adequate. For CO emissions, data variability required calculation of the
upper limit severity factor, Su. Since S is less than 0.05, the CO data base
is also adequate. Emission factors for SQ^. participates, and hydrocarbons
were taken from the EPA estimates (AP-42). Data were not available to directly
compute the variabilities for these average values. For particulate and
hydrocarbon emissions, variabilities in emission factors were estimated by
using Method 2 (see previous subsection) and emissions data from gas-fired
domestic and commercial heating units. The upper limit severity factors Su
were computed for these emissions since the estimated variabilities are greater
than 0.7. Based on the calculated S values, the data base for particulate
emissions from gas-fired utility boilers is considered to be inadequate. For
hydrocarbon emissions, the data base is inadequate for tangentially fired
units and adequate for non-tangentially fired units. Data were not available
for estimation of the variability of the AP-42 S0« emission factor, but the
sulfur content of natural gas and the resultant source severity factors are
too low to merit any significant concern. On this basis, the data base for
S02 emissions from gas-fired utility boilers can be considered adequate.
5.3.1.2 Emissions of Fine Particulates
Emission Data Sources
The data sources for fine particulate emissions are rather limited. Four
sources were used for this compilation. The Fine Particle Emissions Information
System (FPEIS) (59), a computerized data base maintained by the Environmental
Protection Agency, provided data on particulate size distributions from pul-
verized coal-fired dry-bottom, stoker, and oil-fired units. Shannon et al (60)
and Weast et al (61). of Midwest Research Institute (MRI) reported efficiencies
of particulate control devices as a function of particle size, and particulate
size distributions for stoker, cyclone, and pulverized dry-bottom units fired
with bituminous coal. Cato et al (62) reported particulate size distributions
for pulverized coal-fired, stoker, and oil-fired boilers. Crawford et al (28)
reported particulate size distributions for three pulverized coal-fired
boilers: two tangential and one horizontally opposed.
95
-------
Calculation of EmissionFactors
For five types of utility boilers, the participate emission factors for
four size fractions (less than 1 pm, 1-3 pm, 3-10 pm and greater than 10 pm,
where the participate sizes represent the aerodynamic particle diameters) are
presented In Table 48. The total uncontrolled partlculate loadings have been
taken from Table 37 of the previous section, assuming a national average of
14.09 percent ash 1n the feed coal, except for the spreader stoker with fly
ash reinjectlon. This value was calculated usinq the AP-42 emission factor.
These total particulate loadinas were multiplied by the size distributions for
each category to obtain the emission factor for each size fraction. The size
distributions were taken from the following sources.
For pulverized bituminous coal-fired dry-bottom boilers, three sets of
data on particulate size distributions were obtained from the FPEIS. Data
from the MRI reports were not used because the over 300 data points for pul-
verized coal-fired boilers were from tests conducted before 1970 for which the
main particle sizing techniaue was the Bahco classifier. The range of appli-
cable particle diameter measurement for the Bahco instrument is 6 to 60 pm.
As a result of the extensive use of the Bahco method, most pre-1970 particle
size distribution data would not be considered to be of acceptable quality.
Also, two sets of particulate size distribution data from Cato et al were not
included because of the inadequate description of sampling methodology.
For other types of utility boilers, the quantity of data available is
even more meager. Data for spreader stokers with fly ash relnjection were
obtained from the FPEIS, as data from the MRI reports were pre-1970 and not
considered acceptable. For spreader stokers without fly ash reinjection, the
only set of data available was from Cato et al. For coal-fired cyclone
boilers, the only set of data available was from the MRI reports. Data for
oil-fired utility boilers were obtained from Cato et al.
Uncontrol1ed Particulate Emi ssions
Particulate emissions from pulverized dry-bottom and stoker units have
similar size distributions, with about 1 percent by weiaht of the particulates
in the less than 1 pm size fraction and the bulk (78-90 percent) of the parti-
culates in the greater than 10 pm fraction. For the cyclone boiler, a greater
96
-------
TABLE 48. SIZE DISTRIBUTIONS FOR CONTROLLED AND UNCONTROLLED
PARTICULATE EMISSIONS FROM UTILITY BOILERS
Combustion
System
Pulverized Bituminous
Coal -fired Dry- bottom
Boiler
Bituminous Coal-fired
Spreader Stoker With
Fly Ash Reinjection
Bituminous Coal -fired
Spreader Stoker
Without Fly Ash
Reinjection
Bituminous Coal -fired
Cyclone Boiler
Residual 01l-f1red
Boiler
Partlculate
Control Device
None
Cyclone
Multiple Cyclones
Scrubber
Electrostatic Preclpltator (ESP)
Venturl Scrubber
Fabric Filter
None
Cyclone
Multiple Cyclones
Scrubber
Electrostatic Preclpltator (ESP)
Venturl Scrubber
Fabric Filter
None
Cyclone
Multiple Cyclones
Scrubber
Electrostatic Preclpltator (ESP)
Venturl Scrubber
Fabric Filter
None
Cyclone
Multiple Cyclones
Scrubber
Electrostatic Preclpltator (ESP)
Venturl Scrubber
Fabric Filter
None
Cyclone
Multiple Cyclones
Scrubber
Electrostatic Preclpltator (ESP)
Venturl Scrubber
Fabric Filter
Emission Factor
10iim
3737
1121
187
15
19
<8
<1.S
4017
1205
201
16
20
<8.0
<2
2963
889
148
12
15
<6
<1.5
254
76
13
1.0
1.3
<0.51
<0.13
4.2
1.2
0.2
0.02
0.02
<0.008
<0.002
total
4438
1548
371
94
28
15-24
2-5
5157
1874
467
112
33
13-23
2.2-4.7
3311
1131
268
74
20
13-19
2-3.5
747
414
182
88
8.7
18-19
2.8-3.1
32
24
15
10
0.6
3.2
0.4
-------
proportion of fine participates 1s emitted - 8 percent by weight are in the
less than 1 pm fraction and only 34 percent by weight are in the greater than
10 pm fraction. Oil firing produces much fewer and finer particulates than
coal firing, with 35 percent by weight in the less than 1 pm fraction and only
13 percent by weight in the over 10 pm fraction.
The variabilities of the average emission factors were calculated only
for the pulverized bituminous coal-fired dry-bottom boilers. Variabilities
for the <1 pm, 1-3 pm, 3-10 pm and >10 pm size fractions were 0.85, 0.41,
0.44, and 0.065, respectively. The data base for fine particulate emissions
from this combustion source category is therefore considered marginally
adequate. Bituminous coal-fired cyclone boiler is the only other combustion
source category with data from more than one site; however, individual data
points were not available from the data source to calculate data variability.
For the other three categories, only one data point was available. The data
bases for the spreader stoker, cyclone, and oil-fired categories are therefore
inadequate. No data were found for the pulverized bituminous coal-fired wet-
bottom boilers or for lignite-fired boilers.
Controlled Fine Particulate Emissions
Emission factors from boilers equipped with particulate removal devices
(cyclones, multiple cyclones, scrubbers, electrostatic precipitators (ESP),
Venturi scrubbers, and fabric filters) were calculated by using average
efficiencies of particulate removal for each size fraction as presented in
Table 49. The controlled emission factors for particulates by size fraction
are also presented in Table 48. By comparing total particulate loadings from
one boiler type with various emission control devices, it is clear that fabric
filters have the greatest removal efficiency. In terms of the health effects
of particulate emissions, the size fractions with aerodynamic diameter less
than 1 pm may be considered the most important, since these particles are not
removed by the upper respiratory tract (60 and 63). For this size fraction,
the high efficiency electrostatic precipitators and the fabric filters are
the most efficient particulate removal devices.
98
-------
TABLE 49. EFFICIENCIES OF PARTICIPATE REMOVAL BY
CONTROL DEVICES FOR VARIOUS SIZE FRACTIONS
Participate Efficiencies of Particulate Removal. %
Control Device <1 urn" 1-3ii'ni 3-10 ym>1Q v
Medium Efficiency 0.25 12 50 70
Cyclone
Multiple Cyclones 11 54 85 95
Medium Efficiency 26 77 98.0 99.6
Scrubber
Hiqh Efficiency 96.5 98.25 99.1 99.5
ESP
Venturi Scrubber
Fabric Filter
71
96
99.5
99.75
>99.8
>99.95
>99.8
>99.95
Source: Reference 61.
5.3.1.3 Emissions of S03 and Participate Sulfate
Emission Data Sources
A review of the literature indicated that there are ten primary data
sources for SOn and particulate sulfate emissions from coal- and oil-fired
utility boilers. Existing data from coal-fired units are limited to those
utilizing bituminous coal; no data were found for lignite or anthracite coal-
fired units. Ctvrtnicek and Rusek presented S03 data for cyclone furnaces
(8). Cuffe and Gerstle reported SOg data for coal-fired units with tangential,
single wall, horizontally opposed, and vertical, firing configurations as well
as cyclone and stoker units (50). Hillenbrand, Engdahl and Barrett reported
S03 data from a vertically fired utility boiler utilizing bituminous coal (43).
Howes presented S03 and particulate sulfate data from coal- and oil-fired
units (46). Hunter and Engel presented SO, data from six utility boilers
firing number 6 residual oil (64). Doyle and Booth presented S03 and water
soluble particulate sulfate data for oil-fired units (54).
99
-------
Although very limited particulate sulfate data were found In the litera-
ture, considerable amount of sulfate data have been reported 1n terms of prima-
ry sulfate emissions (S03 expressed as sulfate, metallic sulfates, and ammonium
sulfate). Primary sulfate emissions data have been presented by researchers
affiliated with the U.S. Environmental Protection Agency. Homolya, Barnes,
and Fortune, and Homolya and Cheney have presented primary sulfate emission
data from coal- and oil-fired utility boilers (44 and 45). Similarly. Barnes
et al, and Nader and Conner have also presented primary sulfate emissions data
(53 and 55).
Emissions Data from Coal-fired Utility Boilers
Emissions data for S03 from bituminous coal-fired utility boilers are
presented in Table 50. Included in the table are data from tangentially fired,
single wall fired, front and back wall fired (horizontally opposed) and verti-
cally fired units as well as stoker and cyclone units. Due to the lack of data
for some firing types, notably pulverized coal-fired wet bottom units and
stokers, the data were combined for evaluation. This approach is consistent
with the result of F tests performed on data groupings by firing type to deter-
mine the significance of differences between group data averages.
Test measurements of S03 have sometimes indicated that the percent con-
version of sulfur to S03 increases as fuel sulfur content decreases. However,
the reaction kinetics of SCL are such that formation rates are directly
proportional to S02 concentration (64). Hence, the rate of S03 formation
would be expected to increase in direct proportion with increasing fuel sulfur,
other parameters being equal. Kinetic analysis and experimental data also indi-
cated that S03 formation increases with increasing combustion oxygen, although
no attempt was made to correlate data from the different units for which data
were available.
In the analysis of data, the three data points for vertical firing, stoker
and cyclone units from Reference 50 were eliminated from the data base as
outliers by the Method of Dixon during averaging of percentage S03 conversions.
The average conversion of fuel sulfur to S03 was thus determined to be 0.74
percent. The variability associated with this parameter is 0.187. Hence, the
100
-------
TABLE 50. S03 DATA FROM BITUMINOUS COAL-FIRED
ELECTRICITY GENERATION SOURCES
Firing Type Percent
Sul fur
in Coal
Tangential,
dry bottom
Tangential ,
dry bottom
Vertical ,
dry bottom
Vertical,
dry bottom
Vertical ,
dry bottom
Wall fired,
dry bottom
Horizontally
opposed,
wet bottom
Stoker
Cyclone
Cycl one
Cyclone
Cycl one
Cyclone
Mean x
Standard Deviation
of the Mean s(X)
Variability ts(x)/
3.5
1.0
3.24
2.65
2.3
2.3
2.3
2.5
2.4
3.8
2.9
ND
ND
X
Flue Gas
$
7-10
4.7
8.5-9
6.8-7.5
6.2
5.3
5.9
6.6
6.4
9.4
3.4
, 2.6
3.5
Emission
Factor
ng/J
20.4
8.9
15.4
17.3
81.3
12.8
12.1
73.5
26.2
39.6
10.7
13.9
14.6
26.7
6.64
0.542
Percent of
Fuel Sulfur
1nS03
0.60
1.05
0.54
0.77
3.89
0.65
0.65
3.46
1.42
0.80
0.86
ND
ND
0.740*
0.0584
0.187
Reference
46
50
43
43
50
50
50
50
50
46
•8
8
8
The mean value of percent of feed sulfur in S03 was computed after the
values 3.89, 3.46, and 1.42 were eliminated by the Method of D1xon.
101
-------
existing data base for SO, emissions from bituminous coal-fired utility boilers
is adequate. Corresponding data from lignite-fired units were not found and
these data bases are, therefore, inadequate.
Two particulate sulfate data points were found for bituminous coal-fired
utility boilers, a tangentially fired furnace and a cyclone furnace, both equipped
with particulate control devices (46). The percentages of fuel sulfur converted
to particulate sulfate (presumably aerosol HgSO. and metallic sulfates, including
ammonium sulfate) are 0.1 and 0.4 percent for the tangential and cyclone furnaces,
respectively. However, seven primary sulfate data points were found in the
literature for uncontrolled emission sources. The term primary sulfates refers
to SO, (as vapor or acid mist) expressed as sulfate, metallic sulfates, and
ammonium sulfate which are present in the exhaust gas prior to emission to the
atmosphere. Primary sulfate emission data from uncontrolled sources are presented
in Table 51. As in the case of S03 data, percentage conversion of fuel sulfur
to primary sulfate is considered to be a more significant parameter than the
measured emission factor alone. Indeed, fuel sulfur conversion data in Table 51
show lower variability than do the measured emission factors. The mean percent-
age of fuel sulfur converted to primary sulfates was found to be 1.41 percent.
Data presented in Tables 50 and 51 indicate that particulate sulfate emissions
correspond to approximately 0,7 percent of the fuel sulfur during combustion
of pulverized bituminous coal in dry and wet bottom units. Because the
variabilities of SO, and primary sulfate data for pulverized bituminous coal-
fired dry and wet bottom units are less than 0.7, the particulate sulfate data
base for these categories is considered adequate. However, due to the lack of
data for bituminous coal-fired cyclone boilers and stokers and for lignite-
fired boilers, the data bases for these categories are considered inadequate.
Particulate samples collected during coal firing were extracted with
water by Howes (46). Particulates from a cyclone unit contained 0.5 to 1.7
percent water soluble sulfate while particulates from a tangentially fired
unit contained 6 to 8 percent. Both units were sampled downstream of a
particulate control device.
Emission and mean source severity factors for SO, and primary sulfate
emissions from bituminous coal-fired utility boilers are presented in Table 52.
Emission factors are presented in terms of S, the fuel sulfur content on an
102
-------
TABLE 51. PRIMARY SULFATE DATA FOR BITUMINOUS COAL-FIRED
ELECTRICITY GENERATION SOURCES
Firing Percent
Type Sul fur
1n Coal
Dry bottom
Dry bottom
Dry bottom
Dry bottom
Dry bottom
Met bottom
ND
Mean x
Standard Deviation
the Mean s(x)
Variability
1.7
1.7
1.9
2.0
3.6
3.3
1.70
of
Flue Gas Emission
Og Factor
% ng/J
4 18.3
6 34.0
5 13.1
4 19.9
4 97.3
5 71.2
5* 32.8
40.9
11.89
0.711
Percent of
Fuel Sulfur
in Primary
Sul fate
0.94
1.75
0.60
0.87
2.36
1.88
1.45
1.41
0.240
0.417
Reference
45
45
45
45
45
45
44
Estimated from data indicating 20 percent excess air.
as-fired basis, and were computed from percentage fuel sulfur conversion data
and an estimated national average higher heating value of 25,586 kJ/kg (11,000
Btu/lb) for bituminous coal. Severity factors were computed from the emission
factors using an average bituminous coal sulfur content of 1.92 percent.
imissions Data from Oil-fired Utility Boilers
Emissions data for S03 from residual oil-fired utility boilers are pre-
sented in Table 53. Existing data are presented primarily 1n terms of the
percent of fuel sulfur converted to SOg. The percent conversion of fuel sulfur
to SOn ranged from 1.2 to 5.3 and the mean conversion was 2.86 percent. No
designation regarding burner type (i.e., tangential or other) was provided in
103
-------
TABLE 52. EMISSION FACTORS AND MEAN SOURCE SEVERITY
FOR S03 AND PRIMARY SULFATE EMISSIONS
FROM COAL-FIRED UTILITY BOILERS
Combustion System
Bituminous Coal
Pulverized Dry Bottom
Pulverized Wet Bottom
Cycl one
All Stokers
so3
Emission Mean
Factor*. Severity
ng/J Factor
7.23 S
3.50
2.09
4.38
0.26
Primary
Emission
Factor*,
ng/J
16.5 S
Sul fates
Seven' ty
Factor
6.67
3.97
NDf
NDf
Emission factors are presented in terms of S, the percent sulfur in the
feed coal on a moist (as-fired) basis, and are based on the percentage
of fuel sulfur converted to SO, and primary sulfates.
ND indicates no data are available.
the literature, although there is no indication that firing configuration
affects sulfur oxide emissions. The variability of the percent conversion of
fuel sulfur to SO, 1s 0.352 and, as such, the SO, data base for oil-fired
utility boilers is considered adequate.
A single particulate sulfate data point was reported by Howes (46). This
data point indicated 0.34 percent conversion of fuel sulfur to particulate sul-
fate at 5.5 percent 02- However, considerable amount of primary sulfate data
have been published for oil-fired utility boilers. Primary sulfate data are pre-
sented in Table 54. These data indicate an average conversion of fuel sulfur
to primary sulfates of 4.45 percent. Because the primary sulfate measurement
includes S03 (as SO,"), metallic sulfate and ammonium sulfates, the difference
between primary sulfate emissions and SO, emissions should be the particulate
104
-------
TABLE 53. S03 DATA FOR OIL-FIRED ELECTRICITY GENERATION SOURCES
Fuel Sulfur
0.21-0.40
0.19-0.45
0.19-0.34
0.19-0.34
0.21-0.27
0.21-0.34
2.3
2.3
2.3
2.5
Mean x
Flue Gas
*
ND
ND
ND
ND
ND
ND
2.5-9.4
4.9
3.4-5.7
5.5
Fuel V
ppm
ND
ND
ND
ND
ND
ND
260
260
260
ND
Standard Deviation
of the Mean s(x)
Variability
ts(x)/x
Emission
Factor
ng/J
ND
ND
ND
ND
ND
ND
16.1
22.7
19.9
44.6
25.8
6.40
0.789
Percent of
Fuel Sulfur
in S03
3.45
2.16
2.73
2.49
5.05
5.31
1.20
1.69
1.49
3.05
2.86
0.445
0.352
Reference
64
64
64
64
64
64
54
54
54
46
Data not available.
sulfate emissions. Data presented in Tables 53 and 54 indicate that 1.6
percent of the fuel sulfur is converted to particulate sulfate. This average
conversion value is nearly five times larger than the data point reported by
Howes. The variabilities of the S03 and primary sulfate data bases are less
than 0.7. Hence, the particulate sulfate data base, the average value of
which may be determined by difference, is considered adequate.
105
-------
TABLE 54. PRIMARY SULFATE DATA FOR OIL-FIRED
ELECTRICITY GENERATION SOURCES
Fuel
Sul fur
%
2.5
2.5
1.0
1.2
0.3
1.0
1.2
1.8
1.8
2.2
2.2
2.2
2.5
2.5
2.4
2.6
1.2
2.4
Mean x
Standard
of the
Variabili
Boiler
Excess
°2* *
0.25-1.04
*
4
*
7
*
5
1.8
3
3-6
2.5
2,5
1.8
1.9
2
1.2
0.3-1.0
0.2-0.6
0.1-0.5
3.0
0.2
Deviation
Mean s(x)
ty ts(x)/x
Fuel V,
ppm
120-135
140
70
190
50
80
16
135
135
500
500
447
300
140
593
292
15
590
Emission
Factor
ng/J
99.1
60.3
43.1
28.9
10.0
58.0
22.6
34.0
42.6
41.5
52.0
73.3
47.2
77.3
103.6
52.1
26.3
123
55.3
7.09
0.271
Percent of
Fuel Sulfur
in Primary
Sul fate
5.69
3.46
6.18
3.46
4.78
8.33
2.70
2.71
3.39
2.70
3.39
4.78
2.70
4.40
6.19
2.87
4.10
8.2
4.45
0.427
0.203
Reference
53
44
44
44
45
45
45
45
45
45
45
45
45
45
45
45
55
55
Estimated from excess air data.
106
-------
Howes extracted oil firing participate samples with both water and HC1.
Water extraction of a single sample indicated 33 percent water soluble sulfate
while 0.1N HC1 extraction of a separate sample indicated 46 percent acid
soluble sulfate. However, variation among samples cannot be determined from
available data and the significance of the difference between these values
is not known.
Emission factors and mean source severity factors for SO, and primary
sulfate emissions from oil-fired utility boilers are presented 1n Table 55.
Emission factors are computed from fuel sulfur conversion data utilizing an
average residual oil heating value of 43,760 kJ/kg (146,000 Btu/gal) and are
expressed in terms of S, the fuel sulfur content. Mean source severity factors
were computed from the indicated emission factors using an average fuel sulfur
content of one percent.
TABLE 55. EMISSION FACTORS AND MEAN SOURCE SEVERITY FACTORS
FOR S03 AND PRIMARY SULFATE EMISSIONS FROM
OIL-FIRED UTILITY BOILERS
Combustion
System
Tangential firing
Other firing
Emission
Factor*,
ng/J
16.3 S
16.3 S
S03
Mean
Severity
Factor
8.81
3.27
Primary
Emission
Factor*,
ng/J
30.5
30.5
Sul fates
Mean
Severity
Factor
13.7
5.08
Emission factors are presented in terms of S, the percent sulfur 1n fuel oil
107
-------
5.3.1.4 Emissions of Trace Elements
Emission Pita Sources forCoal-fired Utility Boilers
To characterize air emissions of trace elements from coal*f1red utility
boilers, It was necessary to examine the existing data base from two aspects:
1) .the trace element content of various coals consumed by electric utilities,
and 2) the fate of trace elements during the combustion process and through
different pollution control devices.
The data base for trace element characterization of the major coal types
was developed from a large number of reference sources. The bituminous coal
trace element data base was found to contain Information on 74 trace elements,
the lignite data base 73, and the anthracite data base 69. The most Important
of these references is the large, computerized National Coal Resources Data
System (65), which provides published coal analyses from both the U.S. Geological
Survey (USGS) and U.S. Bureau of Mines, identifiable on an area! basis over the
United States. This data base was used to provide the Texas lignite and Penn-
sylvania anthracite data. The bituminous coal and North Dakota lignite data
were taken in part from published USGS data 1n the report by Magee et al (66),
and supplemented by many other reference sources (67-96).
Data that characterize trace element emissions from various types of
coal-fired utility boilers were found to be relatively abundant for pul-
verized bituminous coal-fired furnaces, with some data also available for
cyclone furnaces. Of the pulverized bituminous coal-fired furnace data, only
one source was clearly identified as a wet bottom furnace. Many of the remain-
ing sources were identified as various firing modes of dry bottom furnaces.
Also, very little data have been reported on the fate of trace elements from
lignite combustion. Emission factors calculated for lignite are based on a
combination of the trace element behavior of bituminous coal and the trace
element content of lignite coal. The data base for trace element emissions
from lignite combustion is, therefore, clearly inadequate.
The principal reference sources used In developing trace element emissions
data base for bituminous coal-fired utility boilers include the following:
• A study conducted by Schwitzgebel et al of the Radian Corporation
to characterize trace element emissions from three coal-fired
utility boilers (49) - The units sampled include a tangentially-
fired 330-MW boiler with three venturi scrubbers, a tangentially-
108
-------
fired 350-MW boiler with a hot side electrostatic precipitator,
and a 250-MW cyclone boiler with a mechanical cyclone for parti-
culate control. The first two plants were fired with Wyoming
subbituminous coal and the third plant with lignite coal. A
material balance approach for 27 elements was used to charac-
terize the effluents around the power plants.
• A study conducted by Bolton et al of the Oak Ridge National
Laboratory on the Allen Steam plant (97) - The boiler sampled
was a 290-MW cyclone unit burning coal from Kentucky and Southern
Illinois, and equipped with an electrostatic precipitator.
Determinations were made for concentrations and mass balances of
54 elements.
• A study conducted by Kaakinen et al of the University of Colorado
on the Valmont Power Station (98) - The boiler sampled was a
180-MW unit, equipped with a mechanical collector followed by
an electrostatic precipitator in parallel with a wet scrubber.
The samples collected were for all input streams and all outfall
streams. Chemical analysis data were available for 18 elements,
including three radionuclides.
t A study conducted by Mann et al of the Radian Corporation (48) -
The units sampled were two 350-MW tangentially-fired boilers
using Wyoming subbituminous coal and equipped with electrostatic
precipitators. Mass balance data for 15 elements were available.
• A study conducted by Klein et al of Oak Ridge National Laboratory,
also for the Allen Steam plant (99) - The concentrations and mass
flow rates of 37 elements were followed through the cyclone
boiler.
• A study conducted by Hillenbrand et al of Battelle Columbus
Laboratories for the Edgewater Power plant (43) - The unit sampled
was a pulverized coal-fired boiler equipped with an electrostatic
precipitator. Enrichment factors for 27 trace elements across
the electrostatic precipitator were reported.
• A study conducted by Gorden et al of the University of Maryland
on the Chalk Point Station (100) - Two 355-MW units firing
pulverized coal were sampled. The samples collected included
coal, bottom ash, fly ash from the economizer, fly ash from the
electrostatic precipitator, and fly ash suspended in the stack
gas. Analysis for 35 elements were performed. The enrichment
of an element in the suspended fly ash relative to its concentra-
tion in the coal was determined.
• A report by Curtis of the Ontario Hydro on trace element emissions
from the R.L. Hearn, Lakeview, Lambton and Manticoke stations (101)
The four stations sampled have a total of 24 boilers firing
pulverized coal and a generating capacity of 9,200 MW. Data
presented were based on a continuing program for the measurement
109
-------
of 44 trace elements 1n coal, ash, and stack gas. The boilers
sampled were equipped with electrostatic precipitators of 98.6
percent average efficiency.
t A study conducted by Cowherd et al of the Midwest Research Ins-
titute on the Widows Creek Power Plant (102) - The unit sampled
was a 125-MW, tangent1ally-f1red boiler equipped with a mechanical
fly ash collector. Analysis and mass balances for 22 trace
elements were reported.
t A study conducted by Lee et al of the U.S. Environmental Protection
Agency (103) - The unit sampled was 105-MW coal-fired power plant
1n Illinois. Changes in concentrations of 12 trace elements
across the electrostatic precipitator were reported.
9 A study conducted by Ragaini and Ondov of the Lawrence Livermore
Laboratory (104) - The plant tested was a single tangentially-
fired unit fed with western coal and operating at 430 MW. The
unit used a cold side electrostatic precipitator with between
99.5 and 99.85 efficiency. Enrichment factors for 20 trace
elements were determined.
In addition to the above studies, two reports of a survey nature provided
an extensive review of trace element emissions from coal combustion. These
are the reports prepared by Ray and Parker of the Tennessee Valley Authority
(67) and Oglesby and Teixerira of the Southern Research Institute (105).
Enrichment Mechanism for Trace Elements in Coal-ftred Utility Boilers
Analysis of trace element emissions from coal-fired utility boilers has
indicated that for certain of the trace elements, there are definite differences
1n the concentrations of these elements between the fly ash and bottom ash
fractions, and between the fly ash at the inlet to control devices and the
suspended particles in the stack gas. Most of the studies agreed that trace
elements are distributed into the various fractions of coal combustion residue
according to definite partitioning patterns. The three main classes of
partitioning behavior observed are (99):
Class I. Elements which are approximately equally concentrated
in the fly ash and bottom ash.
Class II. Elements which are enriched in the fly ash relative
to their concentrations in the bottom ash.
Class III. Elements which are discharged to the environment
in the gas phase.
110
-------
According to Klein et al (99), results from the study conducted at
Tennessee Valley Authority's Allen Steam Plant Indicated partitioning of the
elements into the three classes as discussed above and shown in Table 56. Of
38 elements analyzed, 20 elements were found to belong to Class I, 9 elements
were found in Class II, and 3 elements in Class III. Six other elements -
chromium, cesium, sodium, nickel, uranium, and vanadium - could not be defini-
tely assigned to a class but appeared intermediate between Class I and Class
II. In examining the results from other studies (43, 48, 49, 97, 98, 100-106),
it is noted that the enrichment behavior of the trace elements are generally
consistent, despite the differences in the furnace and coal types, sampling and
analysis procedures.
TABLE 56. PARTITIONING OF ELEMENTS IN
COAL COMBUSTION RESIDUES
Classes
Class I
Concentrated
fly ash and
Class II
Enriched in
equally between
bottom ash
fly ash
Al
Ba
Ca
Ce
As
Cd
Cu
Elements
Co
Eu
Fe
Hf
Ga
Mo
Pb
K
La
Mg
Mn
Sb
S
Zn
Rb
Sc
Si
Sm
Sr
Ta
Th
Ti
Class III
Discharged in the gas phase
Hg
Cl
Br
Source: Reference 99.
The enrichment behavior of trace elements can generally be explained by
a volatilization-condensation or adsorption mechanism. The following scheme
has been proposed by Klein et al. (99):
1) Trace elements in coal are present in aluminosilicates, as
inorganic sulfides, or as organic complexes.
Ill
-------
2) On combustion, the aluminosilicates melt and coalesce to form
fly ash and bottom ash or slag, whereas the inorganic sulfides
and organic complexes decompose and lead to the evolution of
volatile element species.
3) The elements Initially volatilized or dispersed in the flue
gas stream may then be oxidized to form less volatile species
which may then condense or be absorbed on the fly ash as the
temperature of the flue gas drops.
4) Because of the condensation-adsorption mechanism and the higher
surface-to-volume ratio of the smaller fly ash particles, the
volatile element species associated with the inorganic sulfides
and organic complexes are more concentrated in the finer
particulates. As a result, these elements are also more con-
centrated in the particulates suspended in stack gas emissions,
due to the lower removal efficiency for the fine particulates
by the control devices.
5) Since the bottom ash (or slag) is in contact with the flue gas
for a short time and at a higher temperature, condensation of
volatile species on the bottom ash or slag is minimal.
There is some geochemical support to the trace element enrichment mechanism
proposed by Klein et al. Elements have been classified as lithophiles or chal-
cophiles based on their tendency to be associated with aluminosilicate minerals
or sulfide minerals, respectively. According to the proposed partioning scheme,
the lithophiles should correspond to the Class I elements, the chalcophlles
should correspond to the Class II elements. Class III elements may not be
classified as either lithophiles or chalcophiles. These geochemical classifi-
cations are in reasonably good agreement with the partioning behavior of trace
elements during the combustion process.
CalculationofTrace Element Emission Factors for Coal-fired Utility Boilers
In the calculation of trace element factors, it is more convenient to use
the concept of enrichment factors. This is because trace element emissions are
dependent on the trace element content of coal, the boiler firing configuration,
size of the boiler, as well as the efficiency of particulate control devices,
among other factors. The use of enrichment factors enables direct comparison
and compilation of trace element emission data on a normalized basis, and
facilitates the computation process. For the purpose of this report, the
enrichment factor (ER) is defined as the ratio of the concentrations of an
element and aluminum in stack fly ash, divided by the corresponding ratio in
coal. Thus,
112
-------
ER, . /c >
1 Al c
where: c.. = concentration of element i, mg/kg
c^-| = concentration of aluminum, mg/kg
subscript s = stack fly ash
subscript c = coal
Aluminum is selected as the reference element because it is known to parti-
tion equally between fly ash and bottom ash, and as a minor element is also
approximately equally partitioned among fly ash particles of different sizes.
Thus, the fraction of aluminum in coal ash as fly ash is equal to the fraction
of total coal ash as fly ash, and the collection efficiency for aluminum in
each particulate size fraction is equal to the overall collection efficiency
for that particulate size fraction. As shown in the equation below, the use
of aluminum as the reference element facilitates the calculation of emission
factors for other trace elements because of its equal partitioning behavior.
Also, defined in this manner, the value of the enrichment factor readily in-
dicates when an element is more concentrated in the finer particulates (ER^
> 1.0), equally partitioned (ER. = 1.0), or depleted in the finer particulates
(ER.j < 1.0). Enrichment factors are dependent on the collection efficiency of
control devices. Since enrichment for the volatile species is more pronounced
in the finer particulates, enrichment factors for boilers equipped with high
efficiency control devices are correspondingly higher.
With the use of enrichment factors, trace element emission factors can
be calculated from the trace element content of coal, the heating value of
coal, the fraction of coal ash produced as fly ash, and the efficiency of the
control device for particulate removal. In equation form, the emission fac-
tor EF. for trace element i is calculated as:
/ - \
• f (1 - E) • ER1 x 103
where: EF^ = emission factor for element i, ng/J
(c.) = concentration of element i in coal, mg/kg
HC = higher heating value of coal, kJ/kg
113
-------
f = fraction of coal ash as fly ash
E = fractional participate collection efficiency
of control device
ER. » enrichment factor for element i
The average concentrations of trace elements for bituminous coal and for
lignite coal were used in the computation of emission factors. These average
concentrations are given in Table 57 for eastern bituminous coal, western
bituminous coal, bituminous coal (combined eastern and western bituminous
coal, in proportion to their consumption by electric utilities), North Dakota
lignite, Texas lignite, and anthracite. The average values for eastern
bituminous coal, western bituminous coal, and North Dakota lignite are weighted
averages in accord with annual coal production by county (107). The average
values for Texas lignite and anthracite are averages of the trace element data
provided by U.S. Geological Survey and unweighted by county.
The fraction of coal ash produced as fly ash has been discussed in Section
5.3.1 of this report in relation to partlculate emissions. On the average,
the distribution of coal ash for bituminous coal-fired utility boilers is: 80
percent fly ash for pulverized dry bottom boilers, 65 percent fly ash for
pulverized wet bottom boilers, 13.5 percent fly ash for cyclone boilers, and
60 percent fly ash for stokers.
The collection efficiency of particulate control devices is dependent on
the particulate loading, partlculate size distribution, and other parameters
such as the resistivity of fly ash. In the calculation of trace element
emissions from bituminous coal-fired utility boilers, average particulate
collection efficiencies used were: 97.87 percent for electrostatic precipi-
tators, 70.2 percent for mechanical precipitators (multiple cyclones) and 99.6
percent for wet scrubbers.
Enrichment factors for trace elements are presented 1n Table 58 for three
types of particulate control devices - electrostatic precipitators, mechanical
precipitators, and wet scrubbers. The enrichment factors presented represent
average values reported by the reference sources. In computation of the
average values, outliers have been removed from the electrostatic preclpitator
and mechanical precipitator data base using the method of Dixon (Appendix A)
at the 90 percent confidence level on logarithms of the enrichment factor.
114
-------
TABLE 57. AVERAGE TRACE ELEMENT CONCENTRATIONS IN COAL
tn
Trace Element
Silver (Aq)
Aluminum (Al )
Arsenic (As)
Sold (Au)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bismuth (11)
Bromine (»r)
Calcium (Ca)
Cadmium (Cd)
Cerium (Ce)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Cesium (Cs)
Copper (Cu)
Dysprosium (Dy)
Erbium (Er)
EuropiM (Eu)
Fluoride (F)
Iron (Fe)
Gallium (Ga)
Gadolinium (Gd)
Germanium (Se)
Hafnium (Hf )
Mercury (BoJ
Holmlum (Ho)
Iodine (I)
Indium (In)
Irldium (Ir)
Potassium (K)
Lanthanum (La)
Lithium (LI)
Lutetium (Lu)
Eastern Bituminous
Mean Standard «
ppm Deviation N
of the
Mean, ppm
0.74
11,023
11.4
0.1
41.9
87.7
1.00
1.95
10.1
3,428
0.42
18.2
1,064
8.79
31.2
2.34
15.2
1.55
0.55
0.51
87.3
10,623
4.21
1.44
4.26
1.09
0.21
0.20
1.45
0.20
0.20
1,662
10.1
33.2
0.14
.00
267
1.8
.10
1.2
8.9
.07
.00
1.1
152
.01
1.00
92
.37
2.0
.08
1.0
.09
.11
.01
7.4
173
.31
.43
.37
.07
.01
.01
,29
.05
.20
109
.55
9.5
.01
37
34
69
6
75
64
78
13
29
36
38
24
30
72
80
23
79
21
9
24
52
37
69
10
68
23
45
9
19
11
6
35
64
49
20
Western Bituminous
Mean
ppm
0.1B
15,916
1.94
0.10
95.0
305
0.86
0.42
4.82
16,762
1.28
20.2
294
4.34
11.8
0,79
14.8
1.18
0.51
6.99
141
8,858
3.81
0.75
2.43
0.82
0.099
0.18
0.64
0.12
0.20
1,111
7.06
15.0
0.066
Standard
Deviation
of the
Mean, ppm
.32
485
.21
NC+
3.3
27
.17
.00
.26
1,2p2
.01
2.9
19
.48
.78
.12
1.9
.02
.00
,23
4.3
266
.21
.00
.14
.11
.00
.00
.00
.01
NC
47
.47
2.3
.00
N
19
29
41
2
50
40
50
4
IB
29
27
17
18
48
SO
14
52
14
4
19
34
29
48
4
42
14
30
4
14
10
2
28
41
28
12
Bituminous
""Mean Standard
ppm Deviation
of the
Mean, ppm
0.58
12,370
8.82
0.10
56.5
148
0.96
1.53
8.61
7,101
0.66
18.7
852
7.57
25.9
1.92
15.1
1.4S
0.54
2.29
102
10,137
4,10
1,25
3.76
1.01
0.18
0.20
1.23
0.18
0.20
1,510
9.28
28.2
0.12
.00
264
1.8
.00
1.2
8.9
.07
.00
1.1
151
.01
.99
91
.37
2.0
.08
1.0
.08
.10
.01
7.4
171
.31
.42
.37
.06
.01
.05
.28
.05
.00
108
.55
9.5
.01
North Dakota Llanite
N
56
63
125
8
125
104
128
17
47
65
65
41
48
120
130
37
131
35
13
43
86
66
117
14
no
37
75
13
33
21
8
63
105
77
32
Mean
ppm
0.049
4,476
5.24
0.062
64.2
501
0.31
0.40
0.77
11,702
0.35
13.3
63.5
1.14
7.52
1.23
11.3
0.50
0.11
0,17
27,5
4,299
1.87
0.31
0.76
0.24
0.094
0,14
0.36
0.072
0.062
345
3.79
3.68
0.049
Standard
Deviation
of the
Mean, ppm
0.01
522
0,19
0.00
10
86
0.08
0.23
0.42
1,895
0.18
5.6
32
0.09
3.7
0.86
0.04
0.06
0.03
0.05
6.4
566
0.14
0.13
0,07
0.12
0.02
0.07
0.19
0.00
0.00
121
0.84
2.2
0.01
N
10
9
7
2
10
10
10
3
7
9
7
7
7
10
10
7
10
7
3
7
7
9
10
3
9
7
7
3
7
4
2
9
10
3
7
Texas lignite
Mean
ppm
0.18
13,736
3.0
--
214
124
1.34
—
-..
9,447
0.26
.49
<290
7.9
20.4
—
24.5
.-
~-
-.
46.9
4,190
7.31
—
3.94
--
0.22
--
--
-.
,.
512
20.9
11.7
"*
Standard
Deviation
of the
Mean, ppm
0.02
866
0.6
—
13
13
0.11
..
mm
520
0.03
—
—
0.5
1.5
..
1.8
--
..
—
6.5
751
0.62
—
0.95
.-
0.03
..
..
—
»-
96
1 .6
1.7
*"
N
9
27
24
--
29
27
26
—
..
27
24
24
24
29
29
--
29
.-
--
--
18
27
29
—
13
--
24
--
—
--
--
27
28
24
~~
Anthracite
Mean
ppm
0.13
20,722
7.65
<0.87
8.84
88.8
1.37
0.75
--
1,047
0.19
46.8
404
9.13
35.6
--
10.4
2.02
1.21
0.88
81.5
4,781
5.57
1.77
1.49
<102
0.16
0.34
—
<0.41
-------
TABLE 57 (Continued)
Eastern Bituminous
Trace Element
Magnesium (Mg)
Manganese (Mn)
Molybdenum (No)
Sodium (Ha)
Niobium (Nb)
Neodynlum (Nd)
Nickel (HI)
Osnlum (Os)
Phosphorus (f»)
Lead (Pb)
Palladium (Pd)
Praseodymium (Pr)
Platinum (Pt)
Rubidium (Rb)
Rhenium (Re)
Rhodium (Rh)
Ruthenium (Ru)
Antimony (Sb)
Scandium (Sc)
Selenium (Se)
Silicon (SI)
Samarium (Sm)
Tin (Sn)
Strontium (Sr)
Tantalum (T«)
Terbium (Tb)
Tellurian (Te)
Thorium (Th)
Titanium (T1)
Thallium (Tl)
Thulium (1m)
Uranium (U)
Vanadium (V)
Tungsten (H)
Yttrium (Y)
Ytterbium (Tb)
Zinc (Zn)
Zirconium (Zr)
Mean
ppm
605
30.7
5.73
470
5.79
5.12
19.1
•0.2
115
6.43
0.1
2.26
0.3
30.4
0.2
0.1
0.1
1.47
5.14
3.01
19,800
2.34
3.11
77.9
0.20
0.31
0.91
2.45
711
0.17
0.12
1.11
37.2
0.66
8.85
0.5Z
38.9
51.8
Standard
Deviation
of the
Mean, ppm
30
1.1
.57
15
3.4
2.2
1.2
.20
36
.46
.10
.00
.30
13
.20
.to
.10
.07
.45
.12
662
.10
.44
3.4
.01
.02
.02
.20
27
.00
.00
.16
4.0
.24
.18
.02
1.5
2.9
*
N
35
77
59
36
37
38
37
6
41
78
6
10
6
52
6
6
6
39
63
41
35
24
75
63
24
22
10
24
40
10
9
25
79
21
49
33
79
66
Western Bituminous
Mean
PP"
2,474
12.9
4.01
1,105
4.10
12.9
14,8
0.2
253
8.47
0.021
4.89
0.3
6.46
0.2
0.1
0.1
0.51
2.90
1.54
28,258
1.40
5.78
35J
0.54
0.41
0.089
1.90
898
0.42
0.082
1.59
23.7
2.18
8.50
0.62
34.8
47.8
Standard
Deviation
of the
Mean, ppm
28
4.1
.79
20
.35
.00
.18
NCt
26
.31
NC
.00
NC
.49
NC
NC
NC
.03
.22
.06
922
.06
.45
13
.02
.04
.00
.58
35
,02
.00
.55
1.3
.03
.54
.03
1.6
7.1
N
28
47
45
28
25
20
51
2
30
47
2
4
2
29
2
2
2
25
41
27
29
13
43
42
11
14
10
14
31
10
4
24
48
14
36
26
52
45
Bituminous
Mean
ppm
1,120
36.8
5.25
645
5.33
7.27
17.9
0.2
153
6.99
0.078
2.99
0.3
23.8
0.2
0.1
0.1
1.21
4.53
2.60
22,129
2.08
3.84
154
0.30
0.34
0.68
2.30
708
0.24
0.11
1.24
33.5
1.08
8.76
0.55
37.8
SO. 6
Standard
Deviation
of the
Mean, ppm
29
1.1
.57
14
3.4
2.1
1.2
.00
36
.46
.00
.00
.00
13
.00
.00
.00
.07
.45
.12
657
.10
.44
3.3
.01
.02
.02
.20
26
.00
.00
.16
4.0
.24
.18
.02
1.5
2.9
N
62
124
104
64
62
58
130
8
71
125
8
14
8
81
8
8
8
64
104
68
64
37
118
105
35
36
20
38
71
20
13
49
127
35
85
59
131
111
North Dakota Lignite
Mean
ppm
2,283
46.7
2.52
3,491
2.58
6.01
3.60
0.062
105
2.31
0.062
2.06
0.062
2.63
0.062
0.062
0.062
0.29
2.24
0.59
8,185
0.50
6.69
469
0.08
0.25
0.13
1.87
203
0.089
0.066
1.76
7.23
0.68
4.66
0.22
3.84
22.1
Standard
Deviation
of the
Mean, ppm
54
12
0.02
607
0.07
3.0
0.96
0.00
28
0.02
0.00
0.86
0.00
1.1
0.00
0.00
0.00
0.08
0.23
0.24
1,450
0.13
3.4
110
0.00
0.11
0.02
0,42
28
0.02
0,00
0.50
1.2
0.42
0.23
0.04
0.28
3.1
N
9
10
7
9
3
3
10
2
7
10
2
3
2
7
2
Z
2
7
10
7
9
7
10
10
5
5
3
7
9
3
3
7
10
7
6
10
9
10
Texas lignite
Mean
ppm
2,043
116
2.93
381
657
23.9
11.9
--
<620
8.06
—
—
--
—
—
—
--
0.85
6.31
8.66
23,458
--
36.7
93.5
--
--
—
6.31
1,068
--
--
2.35
46.9
—
10.25
1.12
8.90
34.4
Standard
Deviation
of the
Mean, ppm
135
16
0.29
38
0.76
5.1
0.7
--
—
0.65
—
—
--
—
—
—
—
0.07
0.47
0.63
3,138
--
11.0
8.5
--
—
--
0.70
115
--
—
0.23
5.1
»-
0.79
0.08
1.52
2.8
N
27
27
27
27
24
4
29
--
1
24
--
—
--
—
-.
--
..
24
27
24
?6
—
7
27
.-
-.
—
23
30
--
--
24
29
—
28
26
28
27
Anthracite
Mean
ppm
251
29.1
2.40
365
3.45
13.4
17.3
<0.59
222
5.01
<0.87
1.90
<0.59
—
<1.66
<0.06
<0.06
1.08
6.68
3.35
25,684
2.88
6.70
81.57
<40.5
<3.75
<40.5
6.22
1,482
<0.41
0.23
1.78
24.4
<0,87
9.36
1.37
7.38
39.5
Standard
Deviation
of the
Mean, ppm
30
7.3
0.32
108
0.33
1.6
1.4
--
28
0.80
—
0,18
--
.-
—
—
—
0.25
1,47
0.36
738
0.85
2.97
13.3
--
--
-.
0.45
80
..
0.01
0.46
1.80
*-
0.64
0.34
1.5R
3.3
N
53
53
53
53
47
20
51
50
43
53
50
33
50
—
50
50
50
51
53
51
53
32
10
53
50
50
50
4?
53
50
2
53
53
50
53
53
53
53
* N is the number of sets of data. A set of data may represent an average of a number of data points or sometimes a single data point,
depend!"ng on the reference source.
f NC - not computed because the only data available are all for coals from the same county.
-------
TABLE 58. TRACE ELEMENT ENRICHMENT FACTORS FOR COAL-FIRED UTILITY BOILERS
EQUIPPED WITH ELECTROSTATIC PRECIPITATORS, MECHANICAL
PRECIPITATORS, AND WET SCRUBBERS
Tract
Elomt
*9
As
1*
Bt
81
Ca
Cd
Ce
Ce
Cr
Cs
Cu
0*
Ey
Ft
to
fid
Ge
Hf
Ho
K
u
11
"9
*
NO
Hi
Nil
IM
111
f
H>
Pr
M>
St>
Se
sa
51
$•
Sn
Sr
T«
Tb
Tt
Tb
Tt
Tl
U
»
H
»
Tb
In
Zr
Electrostatic Prectpltator
Mean
EnrlcNntnt
Factor
It
4, as
4,3*
2.23
,BS
3.37
.06
1.10
3.64
1.10
1.56
3.21
1.91
2.22
.54
1.35
1.23
1,68
„
1.69
0.27
2.3
Ml
.83
1.29
1.53
1.52
2.J5
1.13
.70
,18
5.14
.99
8.08
.07
1.07
12.48
.98
1C.O
1.0
1.10
4,95
1,36
.94
.64
3.55
.88
1.11
2.29
.98
1,22
0.22
1.10
0.47
1.69
0,61
5(5}
3.37
1.4S
1.50
.24
1.51
„
.41
1.31
.49
.38
1.28
1.10
.80
.
,4S
.41
.45
_
0.71
0.12
„
.32
.25
1.12
.29
.21
1,18
.33
,32
fc
2.47
.22
2.77
.
.23
4.93
.27
8,17
„
.10
3.17
.43
.46
.45
.55
.34
.21
2.22
.18
.29
0.08
0
0.28
0.34
0.0»
No. or
Oati
Points
4
12
4
8
10
1
7
11
3
13
11
3
10
1
2
12
3
_
2
3
1
6
5
2
6
14
9
7
3
1
12
2
13
1
e
8
7
8
1
2
8
6
4
2
2
4
9
2
6
12
2
2
2
13
3
Reftrences
43,98,49,97
43,50,48,98,101 ,49,97.99
43,49,100,97
90,43,101,49,99,97
50,43,37,48,101,49,97
97
43,101,49,100.99.97
50,37,48.101,49,99,97
49,100,99
50,43,37,99,97,98,101 ,49,100
50,43,99,97,48,37,101,49,100
101,49,99.97
50,43,37,98,101,97,49,100
101
101,99
50.43,98, 101 ,49,99,97,100
101,49,97
49,97
101,49,99
101
43,101,49,100,99,97
101.49,99,97
49,97
100,99,97
50,100,37,43,48,98,97,101,49
50,43,37,98,101,49,97
43,101,49.100,99,97
98,49,97
97
50,43,97,37,98,101,49,100
99,97
50,49,43.100,37,99,97,98,101
49
98,101,49,100,99,97
50,43,98,101 ,49,100,99
37.101.49.100.99,97
48,98,101,49,100,99,97
99
101.99
50,43,37,49,97
43,98,101.49,100,97
101,49,100,97
101 ,49
49,97
49,99
50,43.48,101 ,49,99.97
37.49,97
48,101,49,99,97
50,43,99,97,100,37,101,49
49.97
98.49
50.49,43,100,37,99,48,98,97,101
101,49,99
Mechanical Predpltator
Hean
Enrichment
Factor
St
3.23
.
,48
.82
_
.21
3.40
.
.90
1.2
.
.86
-
-
.87
.46
„
„
,
„
.
.
„
.
.43
2.55
.
1.2
.
1.1
„
1.45
«
.95
6.03
-
1.23
.
,.
.63
.99
.
.
.14
.
-
-
-
1.Z6
«
0.94
1.54
1.54
0.66
$(J)
.
2.34
_
.35
.01
.
,
Z.30
.
,37
.
,
.06
-
*
.23
„
_
_
_
_
.
-
_
.35
,35
.
.
_
0
_
.15
.
_
3.15
.
.87
_
.
.48
,
-
-
-
-
-
-
-
.34
.
.
0.58
0.58
No. of
Data
Points
3
_
2
2
_
1
2
.
3
1
„
2
»
~
2
1
-
-
-
.
,
»
«
.
2
2
~
1
*
2
H
2
.
1
3
-
2
»
.
2
1
.
-
1
-
-
-
.
2
..
1
3
3
1
References
102,98,50
102,50
102,50
102
102,50
102,98,50
102
102,50
102,98
50
102,50
98,50
98
102,50
102,50
98
102,98,50
102,98
102,50
98
102
102,50
98
102.98,50
102,98,50
98
Wet
Hem
Enrictwwnt
Factor
X
10.34
19,05
18.3
2.75
1.55
~
2.53
31.35
.53
5.00
26.15
1.46
2.50
-
~
2,05
17.90
21.3
1.3
.
12.4
1.33
2.15
.12
4.4
1.80
65.7
60-. 6
3.55
.48
99.7
10.4
11.40
.55
6.52
8.75
-
12.9
1.0
-
70.3
6.70
-
-
-
.14
1
79.6
6.1
11.3
2.5
3.79
9.90
9.90
0.61
Scrubber
5(5)
9.87
17.05
»
1.65
.35
~
1.97
29.65
.
3.80
24.25
.64
.10
"
-
.85
16.30
~
-
~
-
.37
.95
-
-
-
58.3
.
1.95
~
~
-
5.30
-
5.88
4.45
-
2.40
-
.
5.60
-
-
-
-
-
-
-
~
.
3.01
4.50
4. SO
0.20
No. of
Data
Points
2
2
1
2
2
-
2
2
1
2
2
2
2
-
-
2
2
1
1
-
1
2
2
1
1
2
1
2
1
1
1
2
1
2
2
-
2
1
~
1
2
~
.
-
1
2
2
2
2
Msed aa data fro* references 49 and 101.
-------
The enrichment factors for electrostatic precipltators include data reported
for pulverized coal-fired boilers as well as cyclone boilers, as no significant
difference could be found between the two groups of data. Enrichment factor
data for mechanical precipltators are limited; however, the electrostatic
precipitator data base consistently reports higher enrichment factors. This
observation was used to justify the application of the electrostatic preci-
pitator enrichment factors to conservatively estimate trace element emissions
*
from boilers equipped with mechanical precipitators . The enrichment factor
data base for wet scrubbers is also very limited, but in most cases indicates
higher trace element enrichment than electrostatic precipitators, because of
the higher average particulate collection efficiency for wet scrubbers.
Based on the average enrichment factors presented in Table 58, the Class
I elements include aluminum, barium, calcium, cerium, cobalt, europium, iron,
potassium, lanthanum, lithium, magnesium, manganese, sodium, phosphorus, rubi-
dium, scandium, silicon, samarium, strontium, tantalum, thorium, titanium,
uranium, vanadium, and ytterbium. These are the elements that form part of
the ash matrix which are not surface concentrated after combustion, and are
therefore equally distributed among all ash fractions and have enrichment
factors close to unity. The Class II elements are those enriched In the stack
fly ash and include silver, arsenic, beryllium, cadmium, chromium, copper,
holmium, molybdenum, nickel, lead, antimony, selenium, tin, tellurium, and
thallium. The classification of trace elements, based on average enrichment
factors, is in good agreement with the classification by Klein et al (99)
based on data from the Allen steam plant.
Enrichment factors for mercury and the halogens are not presented 1n
Table 58, Mercury and the halogens are discharged to the atmosphere primarily
in the gas phase. In the calculation of emission factors for these trace
elements, it is reasonable to assume that all quantities present 1n the coal
Note that the particulate collection efficiency used to estimate trace
element emissions for this case corresponds to the average value reported
for mechanical precipitators.
118
-------
feed are emitted through the stack, if mechanical or electrostatic precipitators
are used to control participate emissions. For coal-fired boilers equipped
with wet scrubbers, limited amount of data available has indicated removal
efficiencies in the 70 to 95 percent range for mercury and the halogens. An
80 percent removal efficiency for these elements by wet scrubbers was
assumed for calculation purposes.
Trace ElementEmission Factors for Coal-fired Utility Boilers
Emission factors for 33 trace elements from bituminous coal-fired utility
boilers are presented in Tables 59 to 67. These 33 trace elements were selected
based on either their higher concentration levels in coal or their environmental
significance (i.e., elements with low TLV or MATE values). The emission factors
presented in these tables are for the following boiler/control device combina-
tions:
t Pulverized dry bottom boiler/electrostatic precipitator
• Pulverized dry bottom boiler/mechanical precipitator
t Pulverized dry bottom boiler/wet scrubber
\ t Pulverized wet bottom boiler/electrostatic precipitator
t Pulverized wet bottom boiler/mechanical precipitator
• Pulverized wet bottom boiler/wet scrubber
t Cyclone boiler/electrostatic precipitator
* Cyclone boiler/mechanical precipitator
t Cyclone boiler/wet scrubber
Emission factors for stokers are not presented because enrichment factors for
trace element emissions from bituminous coal-fired stokers are not available.
In Tables 59 to 67, the variation for the emission factors include the
variation of weighted average trace element content of coal, the variation
1n heating value of coal, the variation in the fraction of coal ash produced
as fly ash, the variation in the collection efficiency of control devices,
and the variation in trace element enrichment factors. The greatest variation
among these components is the variation in trace element enrichment factors.
119
-------
TABLE 59. EMISSION FACTORS AND SOURCE SEVERITIES OF TRACE ELEMENT EMISSIONS
FROM PULVERIZED BITUMINOUS COAL-FIRED DRY BOTTOM BOILERS
EQUIPPED WITH ELECTROSTATIC PRECIPITATORS
Trace Element
Aluminum (Al 5
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (LI)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (SI)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Emission
Factor x
P9/J
8,516
25.3
88.3
89.2
2.2
343
5,628
1.7
33,910
7.9
55
23
4,060
8,430
7.1
1,127
24
1,227
39
10
511
62
106
39
10
28
15,230
13
150
1.4
0.84
27
43
s(x)
X
0.183
0.411
0.697
0.343
0.489
0.205
0.419
0.404
0.198
0.307
0.442
0.409
0.189
0.380
0.189
0.345
0.919
0.264
0.232
0.449
0.345
0.516
0.333
0.391
0.437
0.543
0.184
0.671
0.366
0.439
0.305
0.311
0.273
ts(x)
X
0.583
0.905
2.219
0.810
1.106
0.410
1.024
0.899
0.396
0.669
0.985
0.924
0.379
0.837
0.377
0.887
1.168
0.678
0.502
1.034
0.844
1.136
4.229
0.852
1.033
1.285
0.585
1.588
0.941
1.396
0.784
0.685
0.595
Mean
Severity
Factor
0.338
0.010
0.006
0.037
0.227
0.007
0.116
0.002
1.028
0.016
0.023
0.023
0.335
0.224
0.029
0.004
0.227
0.042
0.002
<0.001
0.002
0.128
0.218
0.053
0.004
0.029
0.314
0.001
0.010
<0.001
<0.001
o.on
0.002
Upper Limit
Severity
Factor,* Su
0.534
0.020
0.019
0.067
0.477
0.010
0.235
0.003
1.435
0.027
0.045
0.045
0.461
0.411
0.040
0.008
2.877
0.071
0.002
<0.001
0.004
0.273
1.139
0.099
0.008
0.066
0.497
0.004
0.019
0.002
0.002
0.019
0.004
S is computed using x
= x (1 + ts(x)/x).
120
-------
TABLE 60. EMISSION FACTORS AND SOURCE SEVERITIES OF TRACE ELEMENT EMISSIONS
FROM PULVERIZED BITUMINOUS COAL-FIRED DRY BOTTOM BOILERS
EQUIPPED WITH MECHANICAL PRECIPITATORS
Trace Element
Aluminum (Al }
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl )
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (N1)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Emission
Factor,
pg/J
119,200
354
1,236
1,249
31
343
78,790
24
33,910
no
772
318
4,060
118,000
7.1
15,770
339
17,170
543
146
7,155
870
1,480
278
48
104
213,200
153
2,102
19
12
384
605
Mean
Severi ty
Factor
4.725
0.146
0.082
0.515
3.171
0.007
1.624
0.025
1.027
0.227
0.318
0.328
0.334
3.129
0.029
0.061
3.177
0.590
0.022
0.006
0.028
1,792
3.050
0.382
0.020
0.107
4.394
0.016
0.140
0.009
0.012
0.158
0.031
121
-------
TABLE 61. EMISSION FACTORS AND SOURCE SEVERITIES OF TRACE ELEMENT EMISSIONS
FROM PULVERIZED BITUMINOUS COAL-FIRED DRY BOTTOM BOILERS
EQUIPPED WITH WET SCRUBBERS
Trace Element
Emission
Factor x
pg/J
s(x)
tslxj Mean
- Severity
x Factor
Upper Limit
Severity
Factor,* S
Aluminum (Al)
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)*
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)+
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)f
Iron (Fe)
Mercury (Hg)t
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
1
603
21
136
54
0.19
69
2,436
2.8
6,782
4.8
85
4.8
812
2,645
1.4
254
0.42
664
8.6
44
5,159
227
209
10
1.3
4.2
2,867
35
139
0.04
0.98
48
48
0.376
0.981
0.375
0.711
0.444
0.866
1.017
0.848
1.002
0.382
0.559
0.470
0.445
0.376
0.377
0.968
0.375
0.378
0.411
0.599
0.633
0.420
0.376
0.385
0.917
0.388
0.408
0.385
0.590
4.771
12.460
NCt
9.030
5.635
11.000
12.930
10.780
12.730
4.854
7.106
5.969
NC
NC
NC
12.290
NC
NC
NC
7.613
8.045
5.337
NC
NC
650
NC
NC
NC
7.497
11
0,
0,
0.064
0.009
0.009
0.022
0.020
.001
.050
0.003
0.206
0.010
0.035
0.005
0.067
0.070
0.006
<0.001
0.004
0.023
<0.001
0.002
<0.020
0.467
0.431
0.014
<0.001
0.004
0.059
0.004
0.009
<0.001
0.001
0.020
0.002
0.367
0.115
NC
0.225
0.130
0.602
0.040
0.115
0.479
0.029
0.568
<0.001
NC
NC
NC
0.024
NC
NC
NC
0.122
0.005
0.028
NC
NC
0.117
NC
NC
NC
0.021
S is computed using x
x (1 + ts(x)/x).
NC - not computed because only one data point for enrichment factor is
available.
An 80% removal efficiency for these elements by wet scrubbers 1s assumed.
No variability data are available for the computation of S .
122
-------
TABLE 62. EMISSION FACTORS AND SOURCE SEVERITIES OF TRACE ELEMENT EMISSIONS
FROM PULVERIZED BITUMINOUS COAL-FIRED WET BOTTOM BOILERS
EQUIPPED WITH ELECTROSTATIC PRECIPITATORS
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Emission
Factor x
P9/J
6,913
21
72
72
1.8
343
4,568
1.4
33,910
6.4
45
18
4,060
6,843
7.1
915
20
996
31
8.5
415
50
86
31
8.1
23
12,360
11
122
1.1
0.68
22
35
s(x)
X
0.175
0.407
0.695
0.338
0.486
0.198
0.415
0.400
0.190
0.302
0.439
0.405
0.181
0.376
0.180
0.341
0.917
0.258
0.226
0.445
0.340
0.513
0.328
0.387
0.433
0.541
0.176
0.669
0.362
0.435
0.300
0.307
0.268
ts(x)
X
0.557
0.897
2.212
0.800
1.099
0.395
1.015
0.891
0.381
0.658
0.977
0.916
0.363
0.828
0.361
0.876
1.166
0.663
0.487
1.027
0.833
1.130
4.171
0.844
1.025
1.278
0.559
1.583
0.931
1.385
0.771
0.675
0.583
Mean
Severity
Factor
0.163
0.005
0.003
0.018
0.110
0.004
0.056
<0.001
0.612
0.008
o.on
0.011
0.199
0.108
0.017
0.002
0.110
0.020
<0.001
<0.001
0.001
0.062
0.105
0.026
0.002
0.014
0.152
<0.001
0.005
<0.001
<0.001
0.005
0.001
Upper Limit
Severity
Factor,* S
0.254
0.010
0.009
0.032
0.229
0.006
0.113
0.002
0.845
0.013
0.022
0.022
0.271
0.197
0.024
0.004
1.388
0.034
0.001
<0.001
0.002
0.132
0.545
0.047
0.004
0.032
0.236
0.002
0.009
<0.001
<0.001
0.009
0.002
S is computed using x = x (1 + ts(x)/x).
123
-------
TABLE 63.
EMISSION FACTORS AWLSOURCC SEVERITIES OF TRACE ELEMENT EMISSIONS
FROM PULVERIZED BITUMINOUS COAL-FIEED-WET
EQUIPPED WITH *|CHANICAL PRECIPITATORSJ
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (N1)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Emission
Factor,
pg/J
97,190
288
1,007
1,018
25
343
64,220
19
33,910
90 -
629
260
4,060
96,200
7.1
12,860
277
14,000
443
119
5,833
709
1,207
278
48
104
173,800
151
1,713
16
9.6
313
494
BOTTOM BOILERS
Mean
Severi ty
Factor
2.293
0.071
0.040
0.250
1.539
0.004
0.788
0.012
0.612
0.110
0.154
0.159
0.199
1.518
0.017
0.030
1.542
0.286
0.011
0.003
0.014
0.870
1.480
0.227
0.012
0.064
2.132
0.009
0.068
0.005
0.006
0.077
0.015
124
-------
TABLE 64. EMISSION FACTORS AND SOURCE SEVERITIES OF TRACE ELEMENT EMISSIONS
FROM PULVERIZED BITUMINOUS COAL-FIRED WET BOTTOM BOILERS
EQUIPPED WITH WET SCRUBBERS
Trace Element
Aluminum (AT )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)*
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)+
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluoride (F)t
Iron (Fe)
Mercury (Hg)*
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (S1)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Z1nc (Zn)
Emission
Factor x
pg/J
1,503
19
128
51
0.18
69
2,284
2.6
6,782
4.5
79
4.5
812
2,479
1.4
238
0.40
623
8.1
41
4,837
213
196
9.6
1.2
4.0
2,687
33
131
0.04
0.92
45
45
s(x)
X
0.367
0.978
0.367
0.706
0.437
_
0.862
1.014
-
0.845
0.999
0.374
_
0.554
-
0.463
0.438
0.367
0.369
0.964
0.367
0.370
0.403
0.594
0.628
0.413
' 0.368
0.377
0.913
0.380
0.401
0.376
0.585
ts(x)
X
4.665
1.242
NCt
8.974
5.546
_
10.960
12.890
-
10.730
12.690
4.750
-
7.035
-
5.885
NC
NC
NC
12.250
NC
NC
NC
7.547
7.982
5.243
NC
NC
11.600
NC
NC
NC
7.430
Mean
Severity
Factor
0.035
0.005
0.005
0.013
0.011
0.001
0.028
0.002
0.122
0.005
0.019
0.003
0.040
0.039
0.003
<0.001
0.002
0.013
<0.001
0.001
o.on
0.261
0.240
0.008
<0.001
0.002
0.033
0.002
0.005
<0.001
<0.001
o.on
0.001
Upper Limit
Severity
Factor,* S
0.201
0.064
NC
0.125
0.072
-
0.335
0.022
.
0.064
0.266
0.016
-
0.314
-
0.004
NC
NC
NC
0.013
NC
NC
NC
0.067
0.003
0.015
NC
NC
0.065
NC
NC
NC
0.012
Su is computed using x » x (1 + ts(x)/x).
NC - not computed because only one data point for enrichment factor is
available.
An 80% removal efficiency for these elements by wet scrubbers is assumed.
No variability data are available for the computation of S .
125
-------
TABLE 65. EMISSION FACTORS AND SOURCE SEVERITIES OF TRACE ELEMENT EMISSIONS
FROM BITUMINOUS COAL-FIRED CYCLONE BOILERS EQUIPPED WITH
ELECTROSTATIC PRECIPITATORS
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (C1)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (N1)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (In)
Emission
Factor x
pg/J
1,443
4.3
15
15
0.37
343
953
0.29
33,910
1.3
9.3
3.9
4,060
1,428
7.1
191
4.1
208
6.6
1.8
87
11
18
6.6
1.7
4.7
2,580
2.2
25
0.23
0.14
4.6
7.3
Mil
X
0.185
0.412
0.698
0.344
0.490
0.206
0.419
0.404
0.200
0.308
0.443
0.409
0.191
0.381
0.190
0.346
0.919
0.265
0.234
0.449
0.346
0.517
0.334
0.392
0.438
0.544
0.186
0.672
0.307
0.439
0.306
0.312
0.274
Mil
X
0.589
0.906
2.220
0.812
1.107
0.413
1.026
0.901
0.399
0.671
0.987
0.926
0.382
0.839
0.380
0.889
1.168
0.681
0.505
1.036
0.846
1.137
4.241
0.854
1.035
1.286
0.591
1.589
0.943
1.398
0.787
0.688
0.598
Mean
Severity
Factor
0.071
0.002
0.001
0.008
0.048
0.009
0.025
<0.001
1.282
0.004
0.003
0.005
0.417
0.047
0.036
<0.001
0.048
0.009
<0.001
<0.001
<0.001
0.027
0.046
o.on
<0.001
0.006
0.066
<0.001
0.002
<0.001
<0.001
0.002
<0.001
Upper Limit
Severity
Factor,* Sy
0.113
0.004
0.004
0.014
0.101
0.013
0.050
<0.001
1.794
0.005
0.005
0.010
0.577
0.087
0.050
0.002
0.608
0.015
<0.001
<0.001
<0,001
0.058
0.241
0.021
0.002
0.014
0.106
<0.001
0.004
<0.001
<0.001
0.004
<0.001
S is computed using x - x (1 + ts(x)/x).
126
-------
TABLE 66. EMISSION FACTORS AND SOURCE SEVERITIES OF TRACE ELEMENT EMISSIONS
FROM BITUMINOUS COAL-FI^ED CYCLONE BOILERS EQUIPPED WITH
'MECHANICAL PRECIPITATORS
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (N1)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tim (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Emission
Factor,
pg/J
20,140
60
209
211
5.2
343
13,310
4.0
33,910
19
130
54
4,060
19,930
7.1
2,664
57
2,900
92
25
1,209
147
250
92
24
66
36,010
31
355
3.2
2.0
65
102
Mean
Severity
Factor
0.006
0.031
0.017
0.109
0.668
0.009
0.342
0.005
1.282
0.048
0.067
0.069
0.417
0.659
0.036
0.013
0.669
0,124
0.005
0.001
0.006
0.378
0.643
0.157
0.012
0.085
0.926
0.004
0.029
0.002
0.003
0.033
0.007
127
-------
TABLE 67. EMISSION FACTORS AND SOURCE SEVERITIES OF TRACE ELEMENT EMISSIONS
FROM BITUMINOUS COAL-FIRED CYCLONE BOILERS EQUIPPED WITH
WET SCRUBBERS
Trace Element
Aluminum (Al }
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)+
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)t
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)*
Iron (Fe)
Mercury (Hg)*
Potassium (K)
Lithium (LI)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Emission
Factor x
pg/J
271
3.5
23
9.2
0.03
69
411
0.46
6,782
0.80
14
0.81
812
446
1.4
43
0.07
112
1.5
7.4
871
38
35
1.7
0.22
0.71
484
6.0
23
0.007
0.17
8.1
8.0
s(x)
X
0.352
0.972
0.353
0.699
0.424
_
0.856
1.009
-
0.839
0.993
0.359
_
0.544
-
0.452
0.426
0.352
0.354
0.959
0.352
0.355
0.390
0.585
0.620
0.400
0.353
0.362
0.907
0.366
0.387
0.362
0.576
Mil
X
4.477
12.350
NCt
8.878
5.389
_
10.880
12.820
-
10.650
12.620
4.566
-
6.912
-
5.737
NC
NC
NC
12.180
NC
NC
NC
7.432
7.874
5.076
NC
NC
11.530
NC
NC
NC
7.314
Mean
Seven" ty
Factor
0.013
0.002
0.002
0.005
0.004
0.002
0.011
<0.001
0.256
0.002
0.007
0.001
0.083
0.015
0.007
<0.001
<0.001
0.005
<0.001
<0.001
0.004
0.098
0.091
0.003
<0.001
<0.001
0.012
<0.001
0.002
<0.001
<0.001
0.004
<0.001
Upper Limit
Severity
Factor,* Sy
0.073
0.024
NC
0.047
0.026
_
0.126
0.008
-
0.024
0.100
0.006
-
0.117
-
0.001
NC
NC
NC
0.005
NC
NC
NC
0.025
0.001
0.006
NC
NC
0.024
NC
NC
NC
0.004
Sy is computed using x = x (1 + ts(x)/x).
NC - not computed because only one data point for enrichment factor 1s
available.
An 80% removal efficiency for these elements by wet scrubbers Is assumed.
No variability data are available for the computation of Su-
128
-------
As a measure of data adequacy, the t value for the degrees of freedom associated
with the estimate of the trace element enrichment factor was used to calculate
the variability ts(x)/x for each element. The variability ts(x)/x as well as
the mean source severity factor S and the upper bound of the mean source
severity factor Su are presented along with the emission factor x in Tables 59
to 67. For bituminous coal-fired boilers equipped with mechanical precipitators,
the variability ts(x)/x and hence the upper limit source severity factor S
were not computed because actual enrichment data across mechanical precipitators
were not available. Instead, emission factors for these sources were computed
using enrichment data across electrostatic precipitators.
The emissions data presented indicate that of the trace elements present
in bituminous coal, aluminum, calcium, chlorine, fluorine, iron, potassium,
magnesium, and silicon are emitted in the largest quantities from bituminous
coal-fired utility boilers. Based on mean source severity factor S > 0.05,
emissions of aluminum, beryllium, calcium, chlorine, fluorine, iron, lithium,
nickel, phosphorus, lead, and silicon are of environmental significance, even
for bituminous coal-fired utility boilers equipped with electrostatic precipi-
tators. For trace element emissions for which variability data are available,
the upper limit S for the mean severity factors have also been calculated from
x * x + ts(x). The emissions data base for a trace element is judged to be
adequate if the variability ts(x)/x < 0.7 or if S < 0.05. The evaluation of
the data presented in Tables 59 to 67 has led to the following conclusions
concerning the adequacy of the existing emissions data base:
The existing trace element emissions data base for bituminous
coal-fired stokers is inadequate since no data are available.
The existing trace element emissions data base for bituminous
coal-fired boilers equipped with mechanical precipitators is
inadequate because emission factors for these sources were
calculated using enrichment factors based on boilers equipped
with electrostatic precipitators.
For pulverized bituminous coal-fired dry bottom boilers
equipped with electrostatic precipitators, the existing data
base is inadequate for barium, beryllium, calcium, iron,
lithium, nickel, phosphorus, lead, and selenium, and adequate
for all the other trace elements.
129
-------
• For pulverized bituminous coal-fired wet bottom boilers
equipped with electrostatic precipitators, the existing data
base is inadequate for beryllium, calcium, iron, lithium,
nickel, phosphorus, and adequate for all the other trace
elements.
t For bituminous coal-fired cyclone boilers equipped with
electrostatic precipitators, the existing data base is in-
adequate for beryllium, iron, lithium, nickel, and phosphorus,
and adequate for all the other trace elements.
• The existing data base characterizing trace element emissions
from any type of bituminous coal-fired boilers equipped with
wet scrubbers is generally inadequate. Among the trace
elements, the existing data base is only adequate for cadmium,
copper, potassium, molybdenum, antimony, selenium, and zinc.
Emission factors for the same 33 trace elements from lignite coal-fired
pulverized dry bottom boilers and cyclone boilers are presented in Tables 68
and 69. These emission factors were computed based on the trace element content
of lignite coal and the trace element enrichment factors for bituminous coal.
The variability of the emission factors was not computed because of the lack
of actual lignite enrichment data. For pulverized dry bottom boilers, the
fraction of lignite ash produced as fly ash is approximately 35 percent, and
the average particulate removal efficiencies are 99.14 percent for electro-
static precipitators or wet scrubbers and 76.4 percent for mechanical precipi-
tators. For cyclone boilers, the fraction of lignite ash produced as fly ash
is approximately 30 percent, and the average particulate removal efficiencies
are 99.46 percent for electrostatic precipitators or wet scrubbers and 73.3
percent for mechanical precipitators. These particulate removal efficiencies
are capacity averages using actual plant data. However, since trace element
enrichment factors for lignite coal were not available, the existing data base
for trace element emissions from lignite coal-fired utility boilers must be
considered to be inadequate.
Trace ElementEmission Factorsfor Oil-fired Utility Boilers
The data base on the trace element content of residual oil is limited.
The most comprehensive data base is the one developed by Tyndall et al (108),
for which a composite oil analysis based on a weighted average of U.S. crudes
(domestic and imported) was used to characterize the trace element content of
130
-------
TABLE 68. TRACE ELEMENT EMISSION FACTORS FOR
PULVERIZED LIGNITE COAL-FIRED DRY BOTTOM BOILERS
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (LI)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Electrostatic
Precipitator
1,885
3.5
64
49
0.58
51
2,266
0.21
9,146
1.5
9.2
8.1
1,866
1,022
10
94
0.95
654
25
1.6
379
8.3
76
8.7
1.5
16
3,265
23
69
0.75
0.4
6.4
2.2
Emission Factor, pg/J
Mechanical
Precipitator
51 ,740
96
1,768
1,352
16
51
62,184
5.9
9,146
41
253
222
1,866
28,057
10
2,592
26
17,935
696
43
10,403
228
2,081
239
41
438
89,593
623
1,889
20
11
176
61
Wet
Scrubber
1,885
15
529
159
0.27
51
5,212
1.8
9,146
4.8
75
9.1
1,866
1,704
10
113
0.09
1,880
30
35
20,329
161
797
12
10
13
3,265
322
339
0.12
2.5
59
13
131
-------
TABLE 69. TRACE ELEMENT EMISSION FACTORS FOR
LIGNITE COAL-FIRED CYCLONE BOILERS
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Electrostatic
Precipitator
1,015
1.9
35
27
0.31
51
1,220
0.12
9,146
0.81
5.0
4.3
1,866
550
10
51
0.51
352
14
0.85
204
4.5
41
4.7
0.80
8.6
1,757
12
37
0.40
0.21
3.5
1.2
Emission Factor^ M/J
Mechanical
Precipitator
50,174
93
1,714
1,311
15
51
60,302
5.7
9,146
40
245
215
1,866
27,208
10
2,514
25
17,392
675
42
10,088
221
2,018
232
40
425
86,884
604
1,832
20
11
171
59
Wet
Scrubber
1,015
8.3
284
86
0.14
51
2,805
0.99
9,146
2.6
40
4.9
1,866
917
10
61
0.05
1,012
16
19
10,941
87
429
6.6
0.56
6.9
1,757
173
183
0.06
1.3
32
7.0
132
-------
representative residual oil feedstock. Average trace element concentrations
of residual oil obtained from this data base are presented in Table 70; however,
the variations in these average concentration values are not known.
Emissions of trace elements from oil-fired utility boilers can generally
be computed from the trace element concentrations of the oil feed, by assuming
that all trace elements present in the oil feed are emitted through the stack.
In Table 71, average emission factors and mean source severity factors of trace
element emissions from oil-fired utility boilers are presented. Based on these
calculations, it is seen that emissions of nickel, vanadium, beryllium, lead,
cobalt, copper, and phosphorus are associated with mean source severities of
greater than 0.1 and of environmental concern. Other elements with mean source
severities between 0.01 and 0.05 include selenium, uranium, tin, lithium,
chromium, barium, iron, magnesium, chlorine, arsenic, and calcium. Since the
data provided by Tyndall et al do not contain information needed to compute
data variability, the data base for trace element emissions from oil-fired
utility boilers must be considered to be inadequate.
5.3.1.5 Emissions of Specific Organic and POM
Organic compounds present 1n the flue gas streams from utility boilers
*
include hydrocarbons, oxygenated hydrocarbons, and polycycllc organic matter
(POM). Specific compounds that have been identified Include aliphatics,
aldehydes, alky! benzenes, naphthalenes, substituted naphthalenes, phenolics,
phthalates, organic acids, and over 20 POM compounds, among others. Quanti-
tative data on the emissions of these compounds, however, are extremely limited.
In a recent EPA report summarizing organic emissions data from conventional
stationary combustion sources (51), the following conclusions were reached:
• Available data on the emissions of individual organic
species were all acquired before 1967.
• Since 1967, essentially no reliable organic measurements
have been reported except for a few total hydrocarbon
and total polycyclic aromatic hydrocarbon (PAH) values.
The POM classification encompasses all organic matter with two or more
benzene rings and includes polycyclic or polynuclear aromatic hydrocarbons
(PAH or PNA}, aza arenes, imino arenes, carbonyl arenes, dicarbonyl arenes,
hydroxy carbonyl arenes, oxo and thia arenes, polychloro compounds, and
pesticides.
133
-------
TABLE 70. AVERAGE TRACE ELEMENT CONCENTRATIONS OF RESIDUAL OIL
Trace
Element
Vanadium
Nickel
Potassium
Sodium
Iron
Silicon
Calcium
Magnesium
Chlorine
Tin
Aluminum
Lead
Copper
Cad mi urn
Cobalt
Rubidium
Titanium
Manganese
Chromi urn
Barium
Zinc
Phosphorus
Molybdenum
Arsenic
Selenium
Uranium
Antimony
Boron
Concentration,
ppm
160
42.2
34
31
18
17.5
14
13
12
6.2
3.8
3.5
2.8
2.27
2.21
2
1.8
1.33
1.3
1.26
1.26
1.1
0.90
0.8
0.7
0.7
0.44
0.41
Trace
El ement
Gallium
Indium
Silver
Germanium
Thallium
Zirconium
Strontium
Bromi ne
Fluorine
Ruthenium
Tellurium
Cesium
Beryl 1 1 urn
Iodine
Lithium
Mercury
Tantal urn
Rhodium
Gold
Platinum
Scandium
Bismuth
Ceri urn
Tungsten
Hafnium
Yttrium
Niobium
Concentration,
ppm
0.4
0.3
0.3
0.2
0.2
0.2
0.15
0.13
0.12
0.10
0.1
0.09
0.08
0.06
0.06
0.04
0.04
0.03
0.02
0.02
0.02
0.01
0.006
0.004
0.003
0.002
0.001
Source: Reference 108.
134
-------
TABLE 71. EMISSION FACTORS AND MEAN SOURCE SEVERITIES OF
TRACE ELEMENT EMISSIONS FROM OIL-FIRED UTILITY BOILERS
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hq)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (N1)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Concentration,
ppm
3.8
0.8
0.41
1.26
0.08
0.13
14
2.27
12
2.21
1.3
2.8
0.12
18
0.04
34
0.06
13
1.33
0.9
31
42.2
1.1
3.5
0.44
0.7
17.5
6.2
0.15
<0.001
0.7
160
1.26
Emission
Factor,
pg/*J
87
18
9.4
28.8
1.8
3.0
320
51.9
274
50.5
30
64
2.7
411
0.9
777
1.4
297
30.4
21
708
964
25
80
10
16
400
142
3.4
<0.02
16
3656
28.8
Mean Severity Factor
Tangentlally-
fired Boilers
0.0074
0.016
0.0013
0.025
0.40
0.0001
0.014
o.n
0.018
0.22
0.026
0.14
0.0005
0.023
0.0079
0.0064
0.028
0.022
0.0027
0.0018
0.0059
4.2
0.11
0.23
0.0088
0.035
0.018
0.031
0.0005
<0.0001
0.035
3.2
0.0032
Wall -fired
Boilers
0.0027
0.0059
0.0005
0.0094
0.15
<0.0001
0.0052
0.042
0.0066
0.082
0.0098
0.052
0.0002
0.0086
0.0029
0.0024
0.010
0.0081
0.0010
0.0007
0.0022
1.6
0.041
0.087
0.0033
0.013
0.0065
0.012
0.0002
<0.0001
0.013
1.2
0.0012
135
-------
• Only a selected few PAH compounds have been measured,
• Quantitative and original source test data for PAH
emissions are practically limited to the 1967 review by
Hangebrauck et al (109).
In Table 72, the available data for emissions of individual organic species
from coal-fired utility boilers are summarized. These data are compiled by
Smith (51) from previous studies conducted by Cuffe et al (110), Gerstle et al
(111), Hangebrauck et al (109,112) and Thompson et al (113). Similar data for
oil-fired and gas-fired utility boilers are not available. Even for the coal-
fired data, it will be difficult to compare these previously published POM
values with those acquired in this study, due to the differences in sampling
and analysis techniques.
TABLE 72. AVERAGE EMISSIONS OF ORGANIC SPECIES
FROM COAL-FIRED UTILITY BOILERS
Organic Species Emission Factor
(pg/J)
o
Organic Acids (as acetic) 2.7 x 10
4
Formaldehyde 4.6 x 10
Fluoranthene 210
Pyrene 340
Benzo(e)pyrene 110
Anthanthrene 1.2
Benzo(ghi)perylene 82
Coronene 3.0
Anthracene 1.2
Phenanthrene 7.8
Perylene 22
Benzo(a)pyrene 96
Benzo(a)anthracene 63
Total PAH* 4.1 x 104
Source: Reference 51.
Polycyclic aromatic hydrocarbons (PAH) are a subset of
POM compounds. Total PAH represents determinations of
total emitted PAH and not the sum of the individual PAH
species listed in the table.
136
-------
In Table 73, POM emission factors based on recent sampling measurements
made at an industrial boiler by Monsanto Research Corporation are presented
(114), The industrial boiler sampled was fired with pulverized bituminous coal,
at an energy input of 130 SJ/hr. Since these POM values were determined using
sampling and analysis techniques similar to those in the current study, they
may provide a better basis for data comparison.
Based on the above discussions, it may be concluded that the existing data
base for specific organics and POM emissions is totally inadequate.
TABLE 73. POM EMISSION FACTORS FOR AN INDUSTRIAL BOILER
FIRING PULVERIZED BITUMINOUS COAL
POM Compounds Emission Factor
(pg/J)
Dibenzothiophene 0.16
Anthracene/phenanthrene 6.21
Methylanthracenes/phenanthrenes 0.39
Dimethylanthrencene 0.12
Fluoranthene 6.41
Methylfluoranthenes/pyrenes 0.74
Benzo(c)phenanthrene 0.20
Chrysene/benz(a)anthracene 24.1
Dimethylbenz(a)anthracenes 1.13
Benzofluoranthenes 12.9
*
Benzopyrenes (and perylene) ND
Methylcholanthrenes 3.32
Indeno(l,2,3-c,d)pyrene 0.12
Dibenz(a»h)anthracene (or isomers) 0.51
Dibenzopyrenes 0.86
Methylchrysenes (or isomers) 1.45
Total POM 58.6
Source: Reference 114.
ND - not detected. The detection limit was 0.03 pg/J.
137
-------
5.3.2 Cooling Tower Emissions
Once-through cooling has been historically the preferred method of waste
heat rejection for power plants. However, because of the widespread concern
with thermal pollution and the limited availability of large supplies of
cooling water, closed-cycle cooling has become the primary cooling option In
recent years. The trend away from once-through cooling 1s clearly Indicated
1n Table 74.
Closed-cycle cooling systems 1n current use Include man-made cooling
lakes, spray ponds, wet (evaporative} cooling towers, and wet-dry cooling
towers. Man-made cooling lakes are similar to the once-through cooling system,
except that the cooling water 1s redrculated. Spray ponds or canals operate
on the same principle as cooling ponds, where heat 1s transferred to the
atmosphere by convection, evaporation and radiation. The major advantage Is
that the evaporation process 1s greatly enhanced by spraying the warm water
Into the air above the ground.
As shown in Table 74, the favored closed-cycle cooling system used by
steam-electric power plants Is the wet cooling tower of either the mechanical
or natural draft type. In both types of towers, the water 1s continually re-
distributed Into fine droplets while falling through the height of the tower
to provide a large air-water surface area. Heat 1s transferred from the water
to the air by convection and radiation. While mechanical draft towers utilize
fans to provide the air flow through tower, natural draft towers depend
primarily on the tower height to produce a pressure difference effect to move
the air. In physical dimension, natural draft cooling towers are tall hyper-
bolic chimneys ranging In size from 75 to over 140 m 1n diameter, and from 100
to about 160 m 1n height.
The wet-dry cooling tower Is a relatively new design which combines air-
cooled heat exchangers and evaporative cooling sections Into a configuration
utilizing a common fan. The overall effect 1s the reduction of water loss
through evaporation and drift. There are only a limited number of wet-dry
cooling towers 1n existence because of the substantially higher capital
investment and maintenance costs.
138
-------
TABLE 74. DISTRIBUTION OF COOLING SYSTEM TYPES
FOR STEAM-ELECTRIC POWER PLANTS
Type of Cooling
Once-through, fresh
Once-through, saline
Cooling ponds
Cooling towers
Combined systems
Total
Percent of Total Installed Capacity
1970
50.1
22.8
6.7
11.2
9.2
100.0
1971
47.1
21.5
7.3
12.9
10.6
100.0
1972
45.4
20.9
8.0
13.4
12.3
100.0
1973
43.1
20.1
8.6
14.4
13.8
100.0
1974
41.1
18.9
8.5
16.1
15.4
100.0
Source: Reference 19.
In terms of atmospheric environmental effects, the wet cooling tower has
significantly greater impact than the other cooling systems, because of the
high drift water emission rates, the concentrations of biocides and corrosion-
inhibiting chemical additives used 1n the reclrculatlng water, and the height
of the plume rise. Spray cooling ponds produce higher drift rates than the
wet cooling towers, but the maximum radial distance of discharge is substan-
tially reduced. The composite of a number of tests at various spray cooling
sites indicates that measurable drift rarely exceeds 200 m from the source
under a variety of meteorological conditions (115).
As discussed previously, drift losses are the principal environmental
concern for air emissions from wet cooling towers. In contrast to wet cooling
tower fog, the drift droplets contain the same chemicals as the recirculating
water, and often at high concentration levels. The design and operational
characteristics of wet cooling towers that affect drift rates include the
following (116)-
139
-------
t Volume of recirculating water In the system per unit time.
• Tower features - height, diameter, and characteristics of
drift eliminators for natural draft tower; height, cell
diameter, characteristics of drift eliminator, and number
of cells for mechanical draft tower.
t Drift flux and droplet size distribution.
• Exit temperature.
* Efflux velocity.
Wet cooling tower drift losses may vary from less than 0.002 percent to
0.2 percent of the recirculating water flow. As late as June 1971, cooling
tower manufacturers were guaranteeing a drift level not to exceed 0.2 percent
of water circulating rate (117). Recent direct measurements of drift rates,
however, have indicated that actual drift losses are considerably lower than
the guaranteed 0.2 percent.
The experimental methods used for drift measurements cover a variety of
techniques, as described 1n Table 75. Some of these techniques measure both
drift rates and drift droplet size distribution, while other methods only
measure drift rates. Drift losses obtained by these various techniques are
summarized in Table 76. Most of the data presented are for recently constructed
cooling towers. Mechanical draft towers typically operate with drift losses
of approximately 0.05 percent (122), although drift losses in modern designs
average only 0.005 percent (123). Natural draft towers operate with less drift,
probably due to the taller tower height and lower rising air velocities in
comparison with mechanical draft towers. In modern natural draft towers,
drift losses typically average only 0.002 percent (123). Also, drift rates
from fresh water cooling towers are often higher than those from salt water
cooling towers, because of the simpler and less effective drift eliminator
design in most fresh water towers.
Wistrom and Ovard, when using the cyclone separator technique, have
found that the concentration of chemicals in the drift samples is sometimes
higher by a factor of two or three, over that found in the circulating water
(124). In Table 77, the salt mass emission fraction data from three cooling
towers are compared with the drift fraction data from the same towers. The
140
-------
TABLE 75. DESCRIPTION OF COOLING TOWER
DRIFT MEASUREMENT TECHNIQUES
Techniques
Description
Sensitive piper
Coated slide
Impactlon sampling
method
Cyclone separator
Light scattering
method
High volume sampling
method
Chemical balance
Calortmetric method
Filter paper Is treated chemically with a solution
of potassium ferrlcyanlde and ground ferrous ammo-
nium sulfate. The Impinged droplets dissolve the
chemicals forming Insoluble blue stains which
clearly are Identifiable on the pale yellow filter
background. Their number 1s related to the droplet
population and their size 1s related to the droplet
diameter.
A coating material (a mixture of oil and vaseline,
magnesium oxide, gelatin, and sensitive Indicators
such as methyl red or naphthol green B mixed with
gelatin) serves as a droplet capturer. The cap-
tured droplets leave small craters of rings whose
size and number can be related to the original
droplet size and their original number.
A glass tube filled with small glass beads serves
as the drift droplets and particles collector. The
flow through the tube 1s 1sok1net1c and electric
resistance wire surrounding the tube provides enough
heat to completely evaporate all water droplets
flowing 1n the tube.
The entrained liquid or solid particles are sepa-
rated from the air stream lines by means of the
centrifugal force created 1n the vortex flow, and
are drained toward a collection jar located at the
bottom of the cyclone by the axial component of the
vortex flow a>id the force of gravity.
The system consists of a laser diode, apertures.
Interference filter, photo detector, and suitable
electronic components to provide the appropriate
output as drift rate and droplet size distribution.
The light scattered by the droplets 1s detected by
the photo detector which yields pulses proportional
to the cross section of the droplets 1n the scatter-
ing volume.
The dissolved solids In the drift droplets are
collected on a filter mounted In an Inlet tube of
the air sampler. To maintain high collection
efficiency, the filter 1s kept dry during the
sampling period by heating 1t with Infrared lamps.
Measurements of the rate of decrease 1n concentra-
tion of a known tracer chemical added to the
circulating water with time yield estimations of
drift rate when blowdown Is stopped and evaporation
rate 1s known.
Drift droplets passing the throttle point 1n the
calorimeter evaporate due to the pressure drop and
remove heat from the surrounding air. The tempera-
ture change 1s used as an Indication of the amount
of evaporation taking place.
Source: Reference 118.
141
-------
TABLE 76. DRIFT RATES FROM MECHANICAL AND
NATURAL DRAFT COOLING TOWERS
PO
Percent of Drift Rate
Investigator
Balcke Company
Ecodyne Company
Environmental Systems Corp.
Fish and Duncan
CPU Corporation
Hamon-Sobelco Company
The Mar ley Company
Research-Cottrell , Inc.
Method
Cyclone Separator
Cyclone Separator
Light Scattering
Impactlon
Sensitive Paper
Cyclone Separator
Impactlon
Cyclone Collector
High Volume Sampling
Impactlon and Light
Scatter! ng
High Volume Sampling
Natural
Draft Tower
0.002*
0.012-0.07%
0.001-0.008
0.0012f
0.00033
0.0025
0.0011
0.003-0.006
0.002-0.004
0.0021-0.0032
0.00167-0.00171
0.002*
0.02
0.002*
0.02*
Mechanical
Draft Tower
0.002*
0.012-0.07%
0.001-0.008
0.005f
0.00034
0.0076
0.002*
0.02*
0.003*
0.02*
Remarks
Hood drift eliminators
Plastic convolute
eliminators
Salt water
Fresh water
Fresh water
Salt water
Fresh water
Salt water
Fresh water
Source: References 118, 119, 120, and 121.
Manufacturer's guarantee.
For droplets above 50 UK In diameter.
-------
TABLE 77. DRIFT FRACTION AND SALT MASS EMISSION FRACTION FOR
MECHANICAL AND NATURAL DRAFT COOLING TOWERS
Tower Location
Type
Drift
Fraction
Salt Mass
Emission
Fraction
Salt Fraction
Drift Fraction
Turkey Point Plant
of Florida Power
& Light Company
Chalk Point Unit 3
of Potomac Electric
Power Company
K-31 Tower of Oak
Ridge Gaseous
Diffusion Plant
Mechanical draft,
cross flow, salt
water
Natural draft,
cross flow, salt
water
Mechanical draft,
cross flow, fresh
water
0.00034%
0.00033%
0.1X
0.000841
0.00135%
0.1%
2.47
4.05
1.0
co
Source: References 119, 120, and 125.
-------
salt mass emission fraction 1s the rate of emission of any chemical element
or compound as a fraction of the same element or compound circulating as
solute 1n the basin water. Most salt mass emission fractions reported are
based on the sodium or magnesium emission and circulating rates, or the
average of the sodium and magnesium mass emission fractions. As shown 1n
Table 77, the measured salt mass emission fraction 1s often 2 to 4 times the
drift fraction. The only exceptions are cooling towers with high drift
fractions, such as the K-31 cooling tower of the Oak Ridge Gaseous Diffusion
Plant. For these older towers, the drift fraction and the salt mass emission
fraction are the same. The higher salt concentrations observed 1n most cases
are the result of partial evaporation of the drift droplets prior to their
discharge to the atmosphere.
Based on the above discussions, the emission of any chemical element or
compound from cooling towers may be calculated as follows:
Emission factor (pg/J) =Wxdxcxf
where: W = water redrculatlon rate, mg/J heat Input
d = drift fraction
c = concentration of element or compound 1n basin water, yg/kg
f = ratio of salt mass emission fraction to drift fraction
For cooling towers 1n steam-electric power plants, the average water recir-
culatlon rate is approximately 138 kg/kwh. With a thermal efficiency of 33.3
percent, the average water recirculation rate is 12.8 mg/J, on heat Input
basis. Using the fresh water cooling tower blowdown data presented In Section
6.3 of this report and the above equation, the air emission factors for various
chemical constituents are computed. In Table 78, these estimated air emission
factors are presented for mechanical draft cooling towers with drift losses of
*
0.05 percent and 0.005 percent , and for natural draft cooling towers with
drift losses of 0.002 percent. Comparison of these emission factors with those
from the boiler stack shows that emissions of sodium, magnesium and sulfate
*
High drift losses are associated with mechanical draft cooling towers of
pre-1971 design.
144
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TABLE 78. AIR EMISSION FACTORS FOR FRESH WATER COOLING TOWERS
Emission Factor,
Chemical
Constituent
Sodi urn
Chromium
Copper
Iron
Magnesium
Nickel
Zinc
Sul fate
Chloride
Ammonia - N
Nitrate - N
Phosphate - P
Total Cyanide
B1 owdown
Concentration,
mg/1
2409
0.82
0.25
0.57
870
0.03
0.94
1704
600
0.19
2.79
3.74
0.02
Mechanical
Draft Tower
With 0.05%
Drift Loss
15,400
5.2
1.6
36
5,500
0.19
6.0
10,900
3,800
1.2
18
24
0.13
Mechanical
Draft Tower
With 0.005%
Drift Losst
4,600
1.6
0.48
1.1
1,700
0.06
1.8
3,300
1,100
0.36
5.3
7.2
0.04
pg/J
Natural
Draft Tower
With 0.002%
Drift Loss*
1,800
0.63
0.19
0.44
670
0.02
0.72
1,300
460
0.15
2.1
2.9
0.02
The salt mass emission fraction 1s assumed to be the same as the drift
fraction for mechanical draft towers with high drift losses.
The salt mass emission fraction is assumed to be 3 times the drift fraction
for these cooling towers.
145
-------
from the cooling tower and stack are of the same order of magnitude. Emissions
of other chemical constituents from the cooling tower, however, are consider-
ably less than those from the stack. Nevertheless, the data base for air
emissions from cooling towers must be considered to be inadequate. This is
because: 1) direct measurements of chemical constituents present in cooling
tower exhausts have not been made, except for a limited number of trace
elements such as sodium and magnesium; and 2) the data base characterizing
cooling tower blowdown, useful for estimation of air emissions, are limited
to a few inorganic constituents.
The dispersion and deposition of cooling tower plumes are highly depen-
dent on the drift droplet size distribution. The cumulative mass distribution
of drift droplets for three mechanical draft cooling towers 1s shown in
Figure 6 (119). One 1s the Ecodyne drift mass distribution which was measured
on a cooling tower equipped with Ecodyne's H1-V drift eliminators. The total
drift fraction was stated as 0.001 percent. The second drift distribution
was measured at the K-31 tower of the Oak Ridge Gaseous Diffusion Plant. The
drift eliminators were 1n poor repair at the time of the measurements, and
consequently the drift fraction was 0.1 percent. The Turkey Point tower
utilized salt water and had a measured drift fraction of only 0.00034 percent
(119). Data for fresh water and salt water cooling towers are presented
together because it has been shown that differences 1n circulating water salt
concentration have little effect on drift droplet size distribution or drift
rates, as long as the towers and drift eliminators are of analogous designs
(121). The median drift droplet diameter for these three towers varies from
125 to 1150 ym. This large variation indicates that more drift droplet size
distribution data are needed to characterize drift transport from mechanical
draft cooling towers.
In Figure 7, the cumulative mass distribution of drift droplets for six
natural draft cooling towers are shown, based on drift data obtained by the
Environmental Systems Corp. (120,121), Fish and Duncan (118), Research-Cottrell
(118), and GPU Corp. (118). Data reported by the Environmental Systems Corp.
are for the Chalk Point Plant of Potomac Electric Power Company, the Hornaing
plant in France, and the Homer City plant of General Public Utilities. The
146
-------
50001
4000
3000
2000
1000
E
21
ECODYNE X*
(1973) X*
K-31 TOWER
OF OAK RIDGE
(1973)
<
o
a.
O
CXL
a
500
400
300
200
/TURKEY POINT
S (1974)
100
50
40
30
20
1 I I 1 I I
1
I
I
10 20 30 40 50 60 70 80 90 95
PERCENTAGE LESS THAN STATED DIAMETER
98 99
Figure 6. Cumulative Drift Droplet Size Distributions
of Three Mechanical Draft Cooling Towers
147
-------
5000
4000
3000
2000
Z
<
o
H-
LJU
O.
O
Of
Q
1000
500
400
300
200
100
50
40
30
20
10
CHALK POINT
HORNAING
HOMER CITY
CHALK POINT
CURVE 1 FISH AND DUNCAN DATA
CURVE 2 RESEARCH-COTTRELL DATA
CURVE 3 GPU DATA
_L
I
I
I
I
1
10 20 30 40 50 60 70 80 90 95
PERCENTAGE LESS THAN STATED DIAMETER
98 99
Figure 7. Cumulative Drift Droplet Size Distributions
of Six Natural Draft Cooling Towers
148
-------
median drift droplet diameter for these six towers varies from 78 to 130 vtm,
with a mean value of about 120 pm. The drift droplet size distribution for
the Homer City tower represents approximately the average distribution for
the six towers measured, and may be used to characterize drift transport from
natural draft cooling towers.
5.3.3 Emissions from Coal Storage Piles
Coal storage piles at steam-electric power plants are open sources of
atmospheric emissions of fugitive dust and gaseous hydrocarbons. In order to
ensure continuous operation, a 90- to 100-day supply of coal 1s usually main-
tained at coal-fired generating plants. The exception is for mlnemouth plants,
which may maintain a reserve of only 50 days.
The area required for coal storage depends on the coal consumption rate,
height and spread of the coal piles, characteristics of the coal consumed,
and land availability. In a study conducted by Blackwood and Wachter (126),
it was estimated that the average coal pile height is 5.8 m, the average bulk
density of coal is 800 kg/m , and the average coal storage at electric utility
plants is 93 days. For a 1000 MW coal-fired generating plant with average
coal consumption of 2,000 Gg per -year, the coal storage area required would
2
be 110,000 m (27.2 acres). In Table 79, the coal storage requirement for
each utility coal-fired combustion source category is presented.
Data on air emissions from coal storage piles is extremely scarce.
Partlculate emissions from coal piles, as a result of wind erosion, are in-
fluenced by wind speed, pile surface area, bulk density of coal, and the
precipitation-evaporation index computed from the monthly precipitation and
monthly mean temperature. The mean particulate emission factor determined
by Blackwood and Watcher was 6.4 mg/kg-yr (126). This is equivalent to
763,400 kg/yr of coal dust emission in 1978, based upon a total of 119,285
Gg of coal stored at electric utility plants. In the Blackwood and Watcher
study, four sampling runs were performed during two different periods, and
the results were considered as four separate samples at one coal pile. On
this basis, the estimated ts(x)/x value for the particulate emission factor
1s 0.63, and within the acceptable 0.7 value for data adequacy. Also, a
sensitivity analysis performed in the study his indicated that the variation
149
-------
TABLE 79. COAL STORAGE REQUIREMENT FOR
COAL-FIRED UTILITY BOILERS - 1978
Combustion System Coal Storage Requirement
Category Vie1! ght Area Volume
Gg km* kn?3
Electricity Generation
External Combustion
Coal
Bituminous
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
Anthracite
Pulverized Dry
All Stokers
Lignite
Pulverized Dry
Cyclone
All Stokers
119,285
111,073
84,926
12,845
12,348
954
292
102
190
7,920
6,376
1,378
166
25,694
23,938
18,303
2,768
2,661
206
59
21
38
1,707
1,374
297
36
149,080
138,840
106,157
16,056
15,435
1,192
340
119
221
9,900
7,970
1,723
207
in emission rate of a coal pile, as a result of normal fluctuation in ambient
conditions, is greater at a specific rate than it normally-would be from one
site to another. Thus, the mean particulate emission factor determined from
the one coal pile sampled may be used to estimate emissions from other coal
piles.
In the same study, the concentrations of carbon monoxide and hydrocarbons
were found to be three orders of magnitude below ambient air quality criteria
at a distance of 50 m from the coal pile. This indicates that carbon monoxide
and hydrocarbon emissions from coal storage piles are environmentally in-
150
-------
significant. No direct measurements of POM emissions were made. However,
two samples from coal storage piles were selected for analysis of POM by
chemical ionization mass spectroscopy. The first sample was from a coal
storage pile where the coal had been aged for about 10 days at the most. The
coal seam where this coal originated is typical of western bituminous coal.
The second sample was from an Indiana coal seam typical of interior region
bituminous coal. This sample had aged for approximately 60 days. As shown
in Table 80, both samples contained measurable quantities of POM compounds,
including benzo(a)pyrene. These POM concentrations can be used to estimate
POM emissions from coal storage piles, assuming that the POM concentrations in
the fugitive coal dust emissions and the coal samples analyzed are the same.
In assessing the potential environmental risks associated with emissions
from coal storage piles, Blackwood and Wachter (126) used the source severity
factor S, which for ground level sources is calculated as follows:
S =
316 Q
(TLV) D U814
where Q = emission rate, g/s -
TLV » threshold limit value, g/mj
D « distance from emission source, m
For a representative coal storage pile of 95 Gg» the average particulate
emission rate is 19 mg/s, and the minimum distance to the plant boundary 1s
86 m. Using the POM concentration data for the Indiana coal sample in Table
80, the estimated emissions for benzo(c)phenanthrene, benzo(a)pyrene, and
3-methylcholanthrene would be 0.0095, 0.0057, and 0.0076 wg/s, respectively.
For particulate emissions, the source severity factor was calculated to be
0.93, based on a TLV of 2 mg/m for coal dust. For POM compounds, TLV's are
not available, and Minimum Acute Toxiclty Effluent (MATE) values based on
health effects were used in place of TLV's in the calculation of source
severity factors. The source severity factors calculated for the POM emis-
sions are considerably lower than the severity for coal dust emissions.
Even for benzo(a)pyrene, with a MATE value of 0.02 ug/m , the calculated
severity is 0.028 for a representative coal pile, which is only 3 percent of
the severity for coal dust emissions.
151
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TABLE 80. CONCENTRATIONS OF POM COMPOUNDS IN COAL SAMPLES
Polycyclic Organic Matter
Benzo (c ) phenanthrene
7 ,1 2-D1methyl benz (a )anthracene
Benzo(a)pyrene
3-Methyl chol anthrene
D1benz(a,h)anthracene
D1benzo(c,g)carbazole
Dibenzo(a,h)pyrene
D1benzo(a,1)pyrene
Concentration,
Western
Subbi luminous
Coal Sample
ND* (<0.2)
ND (<0.2)
M).2
<0.2
ND (<0.2)
ND (<0.2)
ND (<2)
ND (<2)
pg/g
Interior
Bituminous
Coal Sample
0.5 ± 0.1
<0.2
0.3 ± 0.1
0.4 ± 0.1
ND (<0.2)
ND (<0.2)
ND (<2)
ND (<2)
Source: Reference 126.
*
ND - No signal was detected for the molecular weight plus one atomic mass
unit Ions of these compounds at their respective retention times.
Based on the above discussions, 1t may be concluded that fugitive coal
dust emissions from coal storage piles are of environmental concern within
and near the plant boundary. POM emissions appear to be a lesser concern
because of the lower severity factors, but no direct measurements of POM
emissions from coal storage piles have been made. Additionally, the mean
coal dust emission factor of 6.4 mg/kg-yr 1s based on measurements from only
one coal storage pile and may be biased. Thus, the data base for fugitive
air emissions from coal storage piles 1s considered to be inadequate.
5.3.4 Status of Existing Emissions Data Base
As a result of the evaluation of existing emissions data for external
combustion electricity generation sources, a significant number of data in-
adequacies has been identified. For flue gas emissions, the status of the
existing data base is presented in Table 81 and can be summarized as follows:
• For bituminous coal-fired utility boilers, the existing data
base for NOx, CO, S02, particulate, total hydrocarbon, 50$,
and primary sulfate emissions is generally adequate, with the
exception that emissions of total hydrocarbons and primary
sulfates from cyclone boilers and stokers have not been
adequately characterized. The existing data base for emissions
152
-------
TABLE 81. SUMMARY OF STATUS OF EXISTING DATA BASE FOR
FLUE GAS EMISSIONS FROM UTILITY BOILERS
en
Combustion System
Category
Bituminous Coal
Pulverized dry bottom
Pulverized wet bottom
Cyclone
All stokers
Lignite Coal
Pulverized dry bottom
Cyclone
All stokers
Residual 011
Tangential firing
Mall firing
Natural Gas
Tangential firing
Mall firing
Criteria Pollutants
N0x
*
A
A
A
A
A
A
I
A
A
A
A
CO
A
A
A
A
A
A
A
A
A
A
A
SO^ Parti cul ate
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
I
I
I
A
A
I
I
Total
Hydrocarbons
A
A
I
I
I
I
I
A
A
I
A
Participate
by Size SO,
Fraction
I A
I A
I A
I A
I I
I I
I I
I A
I A
A A
A A
Primary Trace
Sul fates Elements
A I
A I
I I
I I
I I
I I
I I
A I
A I
A A
A A
Specific
Organics
& POH's
I
I
I
I
I
I
I
I
I
I
1
Adequate data base 1s Indicated by A.
fInadequate data base 1s Indicated by I.
-------
of participates by size fraction, trace elements, specific
organics and POM is inadequate. Inadequacies in the trace
element data base are largely caused by the need to provide
better characterization for emissions of barium, beryllium,
calcium. Iron, lithium, nickel, phosphorus, lead, and selenium
from boilers equipped with electrostatic precipitators. There
is also lack of enrichment data for emissions of trace elements
from boilers equipped with wet scrubbers and mechanical
precipitators.
• For lignite coal-fired utility boilers, the existing data base
for NOX, CO, and S02 emissions is adequate, with the exception
that NOX emissions from stokers have not been adequately
characterized. The existing data base for emissions of
particulates, total hydrocarbons, particulates by size fraction,
S03, primary sulfates, trace elements, and specific organics
and POM is inadequate. \
• For residual oil-fired utility boilers, the existing data base
for NOX, CO, S02» particulate, total hydrocarbon, SOa, and
primary sulfate emissions is adequate. The existing data base
for emissions of particulates by size fraction, trace elements,
and specific organics and POM is inadequate.
• For gas-fired utility boilers, the existing data base for NOXi
CO, and S02 emissions is adequate. Total hydrocarbon emissions
have been adequately characterized for wall-fired boilers but
not for tangentially-fired boilers. Additionally, the existing
data base for emissions of SOs, primary sulfates, and trace
elements can be considered to be adequate since these emissions
should not be of environmental concern as the sulfur and trace
element contents of natural gas are low. Similarly, particulate
emissions from gas-fired boilers can all be reasonably assumed
to be submicron in size and there is no need to acquire particu-
late size distribution data. For emissions of total particulates,
specific organics, and POM, however, the existing data base is
inadequate.
The two other major sources of air emissions of environmental concern are
cooling tower emissions and emissions from coal storage piles. The existing
data base for air emissions from cooling towers is considered to be inadequate
because direct measurements of chemical constituents present in cooling tower
exhausts have not been made, except for a limited number of trace elements
such as sodiym and magnesium. For coal storage piles, no direct measurements
of POM emissions have been made and the mean coal dust emission factor of 6.4
mg/kg-yr is based on limited data from one coal storage pile. The existing
data base characterizing fugitive air emissions from coal storage piles is,
therefore, inadequate.
154
-------
5.4 EMISSIONS DATA ACQUISITION
5.4.1 Selection of Test Facilities
In the evaluation of existing emissions data for electricity generation
sources, it has been determined that the existing data bases for flue gas
emissions, air emissions from cooling towers, and fugitive dust emissions from
coal storage piles are generally inadequate. To correct for these deficiencies,
46 sites were selected for sampling and analysis of flue gas emissions, and 6
sites were selected for sampling and analysis of air emissions from cooling
towers. For several of the electric utility plants selected for flue gas
measurements, liquid and solid waste samples were also collected and analyzed,
as described in Sections 6 and 7 of this report. For the 6 cooling towers
tested, cooling tower blowdown samples were acquired and analyzed. The selec-
tion of test facilities for flue gas measurements and for cooling towers is
described in the following subsections. Measurements of fugitive dust emissions
from coal storage piles are not within the scope of the current program and
no tests were planned.
5.4.1.1 Selection of TestFacilities for FlueGasMeasurements
In general, the assignment of number of test sites to each combustion
source category was based on consideration of two factors: potential signifi-
cance of air pollution impact caused by flue gas emissions, and the inadequate
characterization of flue gas emissions. Thus, more bituminous coal-fired sites
were selected for testing than other source types because of the known high
NO , S09, and particulate emissions from these sources, and the inadequate
X £-
characterization but likelihood of higher fine particulate, trace element and
organic emissions from these same sources. For bituminous coal-fired sources,
three pulverized dry bottom boilers, seven pulverized wet bottom boilers, six
cyclone boilers, and three stokers were selected for testing. A lesser number
of pulverized dry bottom boilers was selected because of the amount of existing
emissions data available, and the conduct of concurrent test programs by
Monsanto Research Corporation and Acurex which will provide additional data
for this source category. For lignite coal-fired sources, three pulverized
dry bottom boilers, two cyclone boilers, and two stokers were selected for
testing. For oil-fired sources, four of the twelve boilers selected for
testing were tangentially-fired and the remaining eight wall-fired. For gas-
155
-------
fired sources, three of the eight sites selected were tangentially-fired and
the remaining five wall-fired.
The rated capacity, ages, and pollution control method for the 46 test
sites selected are presented in Tables 82 to 85. The choice *>f specific sites
was based on the representativeness of the sites as measured against the
important characteristics of systems within each source category. For example,
as discussed in Section 4, the average capacity of a lignite coal-fired cyclone
boiler is 430 MW and the average age is 4 years. By comparison, one of the
two lignite coal-fired cyclone boilers selected for testing was rated at 437 MW
and 4 years old, and the other was rated at 440 MW and 6 years old. On the
other hand, when up to six or seven test sites were assigned to a source cate-
gory, a range of capacity and age and different pollution control devices may
be selected for investigation. For example, the bituminous coal-fired cyclone
boilers selected for testing ranged from 135 to 874 MW in capacity, 10 to 24
years old in age, and were equipped with either an electrostatic precipitator
or a wet scrubber. There is, however, a major deficiency with the sites se-
lected for the pulverized lignite coal-fired dry bottom category. Boilers
firing Texas lignite were found to constitute almost all the newly added
capacity, but none of these boilers were available during the testing phase of
this program.
5.4.1.2 Selection of Test Facilities for Cooling Towers
Because direct measurements of chemical constituents present in cooling
tower exhausts have not been made except for a limited number of trace elements,
*
six cooling towers were selected for testing in the current program . Since
effective sampling of natural draft cooling towers with typical diameters of
75 to 140 m can only be conducted with specially designed instrumentation
package, only mechanical draft cooling towers were considered for testing. In
the selection of cooling tower sites, the following criteria were considered:
* Source of cooling water - include sources with high and low solids.
• Type of tower - include both crossflow and counterflow.
• Age of tower - less than 30 years old to exclude obsolete designs.
*
Cooling tower emissions are independent of combustion sources and can be
considered as a separate source category. Because of the number of source
categories requiring characterization in this program, the maximum number
of test sites assigned to each source category was typically six.
156
-------
TABLE 82. CHARACTERISTICS OF BITUMINOUS COAL-FIRED
UTILITY BOILERS SELECTED FOR TESTING
in
Combustion
Source Type
Pulverized
Dry Bottom
Pulverized
Met Bottom
Cyclone
Stoker
Sfte No,
154
205-1
205-2
206
212
213
215
218
336
338
133-136
20?
208
209
330
331
137
204
332
Rated
Capacity,
m
3S8
91
77
128
14S
137
128
825
360
360
874
643
360
643
135
135
12.65
12.65
7.5
Age as
of 1979,
Tears
4
22
21
17
21
21
17
3
9-10
9
10
11
16
12
24
20
22
18
21
•fl
Pollution Control Device
Met scrubber utilizing lime/alkaline fly ash with tested efficiencies
participate removal and 70-75% for SO? removal.
Mechanical preeipltator of 20t design efficiency In series with ESP.
efficiency: 90-99.5%. Combined tested efficiency: 98.6%.
Mechanical preelpitator of 20% design efficiency In series with ESP.
efficiency: 90-99.5%. Combined tested efficiency: 98.61.
Mechanical precipitator of 83.5-841 design efficiency in series with
design efficiency: 99. 61. Combined estimated efficiency: 99.6%.
ESP with 99. 9% design and 99. 9% estimated efficiency.
ESP with 99.91 design and 99.9% estimated efficiency.
Mechanical precipitator of 83.5-84* design efficiency In series with
design efficiency: 99.6%. Combined estimated efficiency: 99.61.
of 99.51 for
Combined design
Combined design
ESP. Combined
ESP. Combined
Venturi wet scrubbing system utilizing thlosorblc line, with 99.9% tested participate
removal efficiency and 95. OJ tested SO? removal efficiency.
ESP with 99.0% design and 94.51 tested efficiency.
ESP with 99.0% design and 94. 5* tested efficiency.
Wet scrubber utilizing limestone with design efficiency of 98.75% for
and 76.0% for SO? removal; tested efficiency 98.2% for paniculate
80.141 for SO? removal .
ESP with 98% design and 94.30% tested efficiency.
ESP with 96.0-98.0X design and 96. 70-98. 70S tested efficiency.
ESP with 98% design and 94.30% tested efficiency.
ESP with 99.65X design and 96.08% tested efficiency.
ESP with 99.65% design and 98.55% tested efficiency.
Baghouses with 99.92% tested efficiency.
paniculate removal
removal and 76.2-
Mechanical precipitator with 94.9% design and 85. 5-85.61 tested efficiency.
Hulttclone with 92% design and 75.0-83.5% tested efficiency.
Efficiencies apply to paniculate removal unless otherwise stated.
-------
in
oo
TABLE 83. CHARACTERISTICS OF LIGNITE-FIRED
UTILITY BOILERS SELECTED FOR TESTING
Combustion
Source Type
Pulverized
Dry Bottom
(Front- fired)
Cyclone
Spreader Stoker
Site
No.
314
315
318
155
316
317
319
Rated
Capacity,
MW
20
20
66
437
440
8
15
Age as
of 1979,
Years
29
27
15
4
6
31
30
*
Pollution Control Device
Multi clones with 84% design efficiency.
Multlclones with 84% design efficiency.
ESP with 98.5% design efficiency.
ESP with 98.8% design and 99.8% test efficiency.
ESP with 99.05% design and 99.53% test effi-
ciency.
Multiclones with 89.5% design efficiency.
ESP with 99.82% design efficiency.
Listed efficiencies are for particulate removal.
-------
TABLE 84. CHARACTERISTICS OF RESIDUAL OIL-FIRED
UTILITY BOILERS SELECTED FOR TESTING
to
Combustion
Source Type
Tangentially
Fi red
Wall Fired
Site No.
210
211
322
323
1
105
109
118
119
141-144
305
324
Rated
Capacity,
m
75
158
637
40
156
44
170
750
345
350
560
40
Age as
of 1979,
Years
24
14
7
26
21
21
24
11
17
14
11
29
*
Pollution Control Device
Mechanical precipitators.
ESP.
Cyclone separators with 85% design
None.
Dust collectors, off-stoichiometric
None.
None.
Off-stoichiometric firing and flue
culation for NOX control .
None.
Off-stoichiometric firing/flue gas
tion for NOX control .
ESP with 99% design efficiency.
None.
efficiency.
firing.
gas recir-
recircula-
Efficiencies listed are for particulate removal. Particulate removal efficiencies for the control
devices associated with Sites 210, 211, and 1 are not available. For Sites 322 and 305, the stated
design efficiencies for particulate removal may be for coal firing and not for oil firing.
-------
TABLE 85. CHARACTERISTICS OF GAS-FIRED
UTILITY BOILERS SELECTED FOR TESTING
Combustion
Source Type
Tangentially
Fi red
Wall Fired
Site
No.
113
114
115
106
107
108
116
117
Rated
Capacity,
m
113.6
80
180
42
30
170
50
75
Age as
of 1979,
Years
13
23
15
21
26
24
19
17
Pollution Control Device
None.
None.
None.
None.
None.
None.
Over fire air for NO control.
Over fire air for NO^ control.
-------
• Size of utility plant - exclude very small plants.
The make and model, type, make-up water source, design characteristics and
installation date for the six cooling tower sites selected are presented in
Table 86. The choice of the specific sites represents a large variation in
the source of the cooling water, including treated sewage, municipal water,
river water, and well water. Of the cooling towers selected, four were cross-
flow and two were counterflow. With the exception of Site 400, all the re-
maining cooling towers were constructed in the 1960's. The utility boilers
associated with the selected cooling tower sites ranged in size from 35 to 130
MW in generating capacity. The Marley towers (600 series, Sites 400 and 406)
tested were considered to be representative of crossflow cooling tower instal-
lations throughout the United States. The other crossflow cooling towers
tested were similar in design to the Marley towers. Also, the two Foster-
Wheeler towers tested were considered to be representative of counterflow
cooling tower designs. Newer and larger cooling towers were not included in
the test plan because they are unavailable for testing during the course of
the program.
5.4.2 Field Testing
5.4.2.1 Field Testing for Flue Sas^Hgasyrements
Field testing procedures were based on Level I environmental assessment
methods (2). The Source Assessment Sampling System (SASS) was used to collect
particulates, organic and trace metal samples. The SASS train (Figure 8) is
a high volume (*v5 SCFM) system. The system is designed to extract particulates
and gases from the effluent stream, separate particulates into four size
fractions, trap organics in an adsorbent and collect volatile trace metals in
liquid solutions. The high volume is required to collect adequate quantities
of trace materials for subsequent laboratory analysis. The train is constructed
in such a manner that all sample contacting surfaces are type 316 stainless
steel, teflon, or glass.
The combustion tests were carried out with or without the cyclones in the
SASS train in accordance with the modified procedures given in the Methods and
Procedures Manual for Sampling and Analysis prepared for this program (127).
Cyclones were removed from the SASS train in some tests due to low concentrations
of particulates and their characteristic small particle diameters for some fuels.
161
-------
TABLE 86, CHARACTERISTICS OF COOLING TOWER SITES
SELECTED FOR TESTING
Site
No.
400
401
402
403
406
407
Make
Marley
Foster-
Wheeler
Fluor
Marley
Marley
Foster-
Wheel er
Model
644-3-05
5-cells
LD-52-17
8-cells
3-cells
10-24EZ
ID-cells
654-0-18
10-cells
57-C-6-10-H
10-cells
Type
Cross-Flow
Counter-
Flow
Cross- Flow
Cross- Flow
Cross-Flow
Counter-
Flow
Source of
Cooling Water
Treated water from
sewage plant
Municipal water
Colorado river via the
American Canal
Well water
Well water
Well water
Design
Recirculatlon
Rate
i/mln
128,700
120,000
155,200
266,700
288,700
166,600
Design
AT of
System
•c
53-44
53-44
63-51
57-48
56-43
56-44
Design A1r
Flow Rate
m /ml n
N/A
91 ,290
N/A
147,000
N/A
120,070
Design
Evap.
Loss
1.6
1.6
N/A
1.4
2.32
1.96
Design
Drift
Loss
0.2
0.1
0.2
0.2
0.2
0.2
Approx.
Install.
Date
1955
1953
1963
1965
1961
1963
-------
STACK
THERMOCOUPLE
cr»
GAS COOLER
GAS
TEMPERATUR
THERMOCOUPLE
CONDENSATE
COLLECTOR
DRY GAS METER ORIFICE METER
CENTRALIZED TEMPERATURE
AND PRESSURE READOUT
CONTROL MODULE
IMP/COOLER
TRACE ELEMENT
COLLECTOR
10 CFM VACUUM PUMPS
IMPINGER
THERMOCOUPLE
Figure 8. Schematic of Source Assessment Sampling System (SASS)
-------
*
The particulates were collected on Spectrograde v ' glass fiber filters in
the heated oven. The sample stream was then cooled and the organic material
collected by adsorption on XAD-2 (a styrene, divinyl benzene copolymer). The
gas then passed through an impinger containing hydrogen peroxide to collect
oxidizable constituents. A second impinger with ammonium peroxydisulfate and
silver nitrate and a third impinger with ammonium peroxydisulfate and silver
nitrate were used to collect volatile trace elements. A fourth impinger con-
taining silica gel was used to remove the remaining moisture.
A flue gas sample was collected for on-site analyses using a stainless
steel probe, condenser, diaphragm pump and gas sampling bags. The gas in the
bag was injected into the gas chromatograph through a heated gas sampling
valve. The resulting peaks were measured for retention times and areas and
compared against a known series of C,-Cg standards for qualitative and quanti-
tative analysis.
Low molecular weight hydrocarbons were measured in the field using a flame
ionization detector gas chromatograph. The sample gas was compared to C-j-Cg
N-alkanes. CO-, 02, N2, and CO were measured using a thermal conductivity
detector gas chromatograph. Standard mixes of the gases were used for cali-
bration.
Samples of the flue gas were obtained at a single traverse point approxi-
mating the average flow rate of the flue gas, as determined by a multi-point
traverse. Sample time was from 4 to 6 hours as required to obtain a total
sample volume of 30 cubic meters or greater.
Wastewater, solid waste and fuel samples were collected according to
Level I procedures, as required. Limited water analyses were carried out in
the field as specified in the procedures manual. Sampling and analysis for
wastewater and solid waste samples are described in Sections 6 and 7 of this
report.
Sample recovery was carried out in a clean environment according to Level
I procedures. All sample containers were pre-cleaned and handled according to
the Level I specifications.
Current Level I procedures call for the use of Reeve Angel 934 AH filters.
164
-------
Modified Level I field tests were conducted at the stack for 46 external
combustion sources for electricity generation. Tests at two of the sites,
Sites Nos. 215 and 107, were not completed due to operation problems with the
boilers at the time of testing. Test results from these two sites are there-
fore not available. Site No. 1, the first site tested, was considered as a
training site for both the TRW field team and the GCA field team to coordinate
sampling procedures. Test results from this training site were not included
in the evaluation of emissions data. The operating load and fuel feed rates
for the remaining 43 sites tested are presented in Tables 87 to 90. Twenty
six of the sites were tested under either base load conditions or close to
base load conditions (at over 90 percent of base load). The other sites were
tested under moderately derated conditions, with all but two sites at over
75 percent of base load.
In addition to the modified Level I tests, comprehensive Level II tests
were also conducted at a bituminous coal-fired cyclone boiler (Site No. 132-
136) and an oil-fired boiler (Site No. 141-144). The coal test site was an
874 MV/ boiler equipped with wet limestone scrubbers for S0£ and particulate
control. The oil test site was a 350 MW boiler using off-stoichiometric firing
and flue gas recirculation for NO control. Level II sampling and analysis
conducted for the bituminous coal-fired cyclone boiler included: the Goksoyr-
Ross Controlled Condensation System (CCS) to determine SOg emissions, polatized
light microscopy (PLM) analyses to determine particulate size distribution at
the scrubber inlet, a MRI cascade impactor to determine particulate size dis-
tribution at the scrubber outlet, atomic absorption spectroscopy (AAS) to
determine trace element concentrations at both the scrubber inlet and the
scrubber outlet, gas chromatography/mass spectrometry (GC/MS) to identify and
quantify organic compounds present, and specific analytical techniques such as
electron spectroscopy for chemical analysis (ESCA) and X-ray diffraction (XRD)
where applicable. Level II sampling and analysis conducted for the oil-fired
boiler included: continuous monitoring of NO emissions by chemiluminescent
A
instrumentation, continuous monitoring of SOp emissions by pulsed fluorescent
analyzer, the Goksoyr-Ross CCS to determine SOg emissions, and GC/MS analyses
to identify and quantify organic compounds present. Important findings from
these comprehensive Level II tests are discussed in this report along with
results from the modified Level I tests. More detailed discussions on Level
165
-------
TABLE 87. OPERATING LOAD AND FUEL FEED RATES OF
BITUMINOUS COAL-FIRED UTILITY BOILERS
en
Combustion
Source Type
Pulverized
Dry Bottom
Pulverized
Wet Bottom
Cyclone
Stoker
*
Based on a plant
Five-test average
Site No.
154
205-1
205-2
206
212
213
218
336
338
132-136
207
208
209
330
331
137
204
332
heat rate of
>
Operating
Load, MW
282
91
77
110
135
130
830
356
324
694f
440
310
450
119
119
11-2**
9.9
6.5
11,310 Btu/kwh (19).
in TOO 04... /L....U (Tn\
% Of
Base Load
79
100
100
86
99
95
100
99
90
79f
68
86
70
85
85
89**
78
87
Fuel Feed
Rate, kg/hr
159,500
33,680
25,630
*
47,000
38,520
37,100
240,360
126,550
129,500
284,200*
213,000*
126,530.
210,000*
60,200
53,928
5,800
5,570..
4,060TT
Energy Input
GJ/hr
3,175
930
710
*
1,300
1,050
1,030
7,120
3,790
3,900
6,830.
5,000*
2,900.
5,120*
1,540
1,330
166,,
148tt
10
<
** a , ,
Based on a plant heat rate of 14,271 Btu/kwh (19),
Based on a plant heat rate of 14,572 Btu/kwh (19),
-------
TABLE 88. OPERATING LOAD AND FUEL FEED RATES OF
LIGNITE-FIRED UTILITY BOILERS
Combustion
Source Type
Pulverized
Dry Bottom
(Front fired)
Cyclone
Spreader Stoker
Site No.
314
315
318
155
316
317
319
Operating
Load, MW
20
20
68
420
383
7.5
12.3
% of
Base Load
100
100
103
96
87
94
82
Fuel Feed
Rate, kg/hr
19,200
17,700
54,000
336,500
372,900
8,230
13,000
Energy Input
GJ/hr
292
290
855
4,780
5,420
91
187
-------
TABLE 89. OPERATING LOAD AND FUEL FEED RATES OF
RESIDUAL OIL-FIRED UTILITY BOILERS
01
oo
Combustion
Source Type
Tangentlally
Fired
Wall Fired
Site No.
210
211
322
— > 323
— s 105
- >109
118
__..->119
141-144
305
— -> 324
Operating
Load, MW
79
152
548
42
44
171
702
281
**
296
560
43
% of
Base Load
105
96
86
105
100
100
94
81
84
100
108
Fuel Feed
Rate, kg/hr
18,500*
35,600*
111,800
12,200
13,000
40,800
165,100
61,700
63,000
116,100
12,500
Energy Input
GJ/hr
860f
1 ,650f
4,780
520*
580
1,830
7,010*
2,920ft
**
2,770
5,100
530*
Based on density of 959 kg/m (8 Ib/gal).
. Estimated from steam generation rates under the assumption of 90% thermal efficiency,
^Assuming an average fuel heating value of 146,131 Btu/gal (19).
..Four-test average.
Based on an average plant heat rate of 9,856 Btu/kwh (19).
-------
at
TABLE 90. OPERATING LOAD AND FUEL FEED RATES OF
NATURAL SAS-FIRED UTILITY BOILERS
Combustion
Source Type
Tangentially
Fired
Wall Fired
Site No.
113
114
115
106
107
108
116
117
Operating
Load, MM
90
76
193
36
19.5
162
48
70
* of
Base Load
79
95
107
82
65
95
96
93
Fuel Feed
Rate, m^/hr
22,710
22,650
50,970
13,310
7,500
40,210
14,050
20,400
Energy Input
GJ/hr
870
870
1,950
510
290
1,540
540
780
-------
II test results, however, could be found in a separate report on comparative
environmental assessment of coal and oil firing in controlled utility boilers
by Leavitt, et al. (128,161).
5.4.2.2 Field Testing for Cooling Towers
Various sampling trains and methods for sampling cooling tower emissions
were evaluated, including the Ecodyne Corporation high volume sampler, a
sampler designed by Environmental Systems using a heated probe containing glass
beads for salt precipitation, and a high volume EPA Method 5 train. Based on
technical and cost considerations, the decision was made to use a modified EPA
Method 5 sampling train without the filter assembly, as illustrated in Figure
9.
The probe, sampling lines, pump and meter box were designed at a higher
capacity than the Method 5 train to shorten sampling time required for testing.
A 321 grade 3/4" stainless steel probe and nozzle were machined using SS Swage
Lock fittings for connections. A 3/4" Teflon line was attached extending 15 m
to the impinger box "Y" and the flow was then separated into two sets of four
impingers, in order to enlarge sample capacity. Each gas stream then passed
through two ionized water impingers, followed by a blank impinger, then a
•?
silica gel filled impinger. All connections in the impinger train were either
glass to glass or glass to stainless steel balls using Teflon tape as a sealant.
The flow then went through a rubber hose to the meter box. The meter box con-
tained a check valve, vacuum gage, main valve, a Gast 10 cfm capacity oil ess
pump, a Singer 13 cmh dry gas meter, inlet and outlet thermometers in the meters,
an orifice and two manometers; one for the pitot and one attached to the
orifice. The pi tot tube was attached to the probe and detached when taking
a pitot traverse. In order to suspend the probe across the cooling tower fan
outlet a 23 meter cable was used and was fastened on either side of the fan
housing using cable clamps (Figure 10). The cable was kept fairly taut so that
the probe would lie at the same angle as the air flow.
In sampling air emissions from cooling towers, a pitot traverse was
taken using twenty-four traverse points on two perpendicular diameters. The
pitot, probe and line were measured and marked with tape and the traverse was
then taken. The eight highest pitot readings were then selected as sampling
170
-------
-5 CFI IH-TIINT
P1WP
Figure 9. Cooling Tower Sampling Train
-------
PO
Will I PI TIT LINES
run t mm mi
1/4" MILE
ClllE
*B" liLT
r~
PROSE I flTOT TUIE
1/4" ClllE
TEFLON
LIKE
TOP VIEl
SIDE VIEI
Figure 10. Cooling Tower Sampling Train Suspension System
-------
points except where the readings exceeded the capacity of the sampling train.
The pitot was then attached to the probe and sampling commenced. Sampling
time was approximately four hours with one-half hour at each sampling point to
sample at least 30 m of air emission. A pltot reading was taken at each point
and calculations made to sample isokinetically. Readings were taken every 15
minutes and the valve readjusted if wind speed or other factors had caused
the pi tot reading to increase or decrease. Ambient temperature was taken prior
to the test along with wet-dry bulb readings and barometric pressure. Each of
these readings was also taken at each point and a wet-dry bulb reading inside
the fan housing.
The train was then dismantled at the end of four hours. The impinger box
was sealed with teflon tape along with the probe and teflon line. The sample
was transferred into cleaned bottles (using the same washing procedure as
stated above) with teflon lined lids. The sample was contained In one bottle,
the Impinger wash in another bottle and the probe and teflon line wash in a
third bottle. The entire sample train was then washed and sterilized for the
next test. Each bottle was labeled and sent for laboratory analysis.
Air emissions from cooling towers were sampled at six sites. The rated
generation capacity of the boilers associated with the cooling towers and the
operating loads at the time of testing are shown in Table 91. Data on the
cooling tower operations at time of testing are presented in Table 92. Included
in this table are cooling tower recirculation rates, make-up rates, blowdown
rates, and ambient temperatures and relative humidity at the time of tests.
In Table 93, the cooling tower additives for corrosion and bacterial growth
inhibition, and for limiting salt deposition are listed. These cooling tower
additives have a significant impact on both air emissions and quality of the
blowdown from cooling towers, as will be discussed in the analysis of test
results.
5.4.3 Laboratory Analysis Procedures
The procedures described in this section are designed to be an integral
part of the phased environmental assessment approach and apply primarily to
Level I. The purpose of the initial phase is to obtain preliminary environ-
mental assessment information, identify problem areas and provide the basis
173
-------
TABLE 91. POWER PLANT DESIGN SPECIFICATIONS
AND OPERATIONS DURING TEST
Site No.
400
401
402
403
406
407
Rated Generation
Capacity
MW
35
50
80
108
130
75
Generation at
Time of Test
MW
25
40
61
34
130
71
Heat Rate
of Plant
Btu/kw-hr
11,500
12,538
10,715
10,600
8,878
10,600
Thermal
Efficiency
30%
27%
32%
31%
38X
32%
for the prioritization of streams, components and classes of materials for
further testing by more stringent techniques and procedures. As such, the
results of the sampling and of the corresponding analysis procedures are
quantitative within a factor of 3. A detailed discussion of the approach,
along with the criteria used for method selection, is given in the IERL-RTP
Document # EPA-60Q/2-76-160a, IERL Procedures Manual: Level I. Environ-
menta1 Assessment (2), which has been the guideline for preparation of the
Methods and Procedures Manual (127) and by reference, is made an integral
part of it.
The analysis procedures described below and the sampling procedures in
Section 5.4.2 have been published in a Methods and Procedures Manual (127).
The manual is designed to fit the specific sampling and analysis for this
Program and to be as consistent as possible with basic Level I procedures.
Project-related changes are listed in Table 94. In addition, changes in
methods and procedures have occurred during the course of the Program to
reflect experience, changing data needs, and official EPA-directed Level I
changes. These changes are listed in Table 95.
174
-------
TABLE 92. COOLING TOWER OPERATION DURING TEST
Site
No,
400
401
402
403
406
Reclrculatlon
Rate
i/nln
128,700
120,000
(Design)
155,700
266,700
288,700
Recirculation
Rate/MW
Rated
t/min/MW
3,680
2,400
1,940
2,470
2,220
At Test
5,150
3,000
2,550
8,890
2,220
Make-Up
Rate
t/day
2,953,000
1,973,000
3,558.000
N/A
N/A
Bl owdown
Rate
i/day
1,817,000
491 ,000
2,025,000
N/A
N/A
TDS
Maintained
ng/1
1900 Max
1800
4000 Max
N/A
N/A
Ambient
Conditions
TempeC
26.7
21.1
37.8
37.8
37.8
R.H.I
50
65
35
50
50
01
407
166,600
2,220 2,350
4,164,000 1,022,000
900
41.7
30
-------
TABLE 93. COOLING TOWER ADDITIVES
Site
No.
400
401
402
403
406
407
Trade Name
SulfuHc Acid
Olln 2102
01 In 2602
Chlordloxide
Foantrol
SulfuHc Acid
Chlorine
Calgon. They occasionally
use an ant 1 foam reagent
and a strong bloclde
Sulfurle Acid
Chlorine
Nalco 82 "Balls"
Nalco 30604
Nalco 8101
Nalco Cu prose
Sulfuric Acid
Chlorine
Calgon
Sulfuric Acid
Chlorine
Sulfailc Acid
Soda Ash
Hal co 82 "Balls'
Nalco 51 9L
Sulfuric Acid
Chlorine
Nalco 7315
Nalco 30B04
Additives
Generic
H2S04
Phosphate
Poly Aqualade
Chlordloxide
SI U cone Base
H2S04
Cl
Sodium Hexanetaphosphate
VO,
Cl
Organic/non organic compound
Proprietary information
Proprietary Information
Proprietary Infomatlon
V°4
Cl
Sodium HexaMtaphosphate
H2S04
Cl
NH2S03H
Na2COj
Proprietary Infomatlon
Proprietary Information
H2S04
Cl
Poly- Phosphate
Proprietary Information
Amount
318 kg/d
1800 ce/d
1400 cc/d
19 t/d
4 t/d
76 t/d
11 kg/d
4.5 kg/d
20 76 t/d
341 l/d
65 'balls'
2.8 t/«J
170 kg/no.
6.8 kg/d
189 l/d
27 kg/d
2 l/d
2 l/d
20 kg/d
189 t/d
317 kg/mo.
19 t/d
38 t/d
Purpose
To adjust make-up pH to 7.1-7.4
Holds solids In suspension
Holds solids 1n suspension
Chlorine with a precursor — bloclde
Keeps foam levels down
To adjust pH to 7.1-7.4 1n make-up to maintain Rlznar
index of .6
Bacteriocide and algaecide
Crystal growth Inhibitor for calcium carbonate and
calcium sulphate
Adjust pH
Algaecide/Bacterloclde
Keeps solids in suspension
Prevents corrosion (zinc)
Coagulant — aids in settling out solids— added to
settling pond that supplies make-up water to 4
cooling towers
Algaec1de--added to settling pond that supplies make-
up water to 4 cooling towers
Adjust pH
Bacteriocide/Algaecide
Crystal inhibitor (CaCOj, CaS04)
Adjust pH
Bacteriocide/Algaecide
Prolong chlorine life
Neutralizes sulfamic acid
Bmilsifler
Used when tower is drained to coat condenser tubes.
-272 kg.
Adjust pH
Bacteriocide/Algaecide
Prevents carbonate deposits
Zinc ant1-corrosl»e by electrolytes
-------
TABLE 94. PROGRAM RELATED ADDITIONS AND/OR DELETIONS TO LEVEL 1 PROCEDURES
Parameter/Analysls
of Interest
Change and Reason
Polynuclear Organic Material
Polychlorlnated Blphenyls
Controlled Condensation
System (CCS)
Bacharach Smoke Spot Test
Cyclone Deletion Guidelines
Duty Cycle Testing
Chloride and Fluoride
600 and COD
Fugitive Emission Studies
Analysis for Individual
TCO Components
Hater Sampling and Analysis
Ash Sampling and Analysis
Computation of Inorganic
Emissions from Oil and Gas
Fired Units
Deletion of SASS Inorganic
Analysis on Gas and Oil
Fired Sites
Combination of All Organic
Samples for a Single Analysis
for Oil and Gas Fired Site
Inorganic (Field) Sas
Analysis
Combination of SASS Samples
for Inorganic Analysis
Probe, Cyclone, and XAD-2
Module Rinses
Batch IRHS on LC Fractions
Added as program requirement.
Added as program requirement, deleted from this revision because of uniformly negative results
on other programs.
and SO, information unavailable from Level
Added to obtain participate sulfate, aerosol H,SO,,
1 procedures.
procedures.
Added as program requirement.
Added to save leak check and clean-up time in field when previous data indicates a cyclone
catch will be nil. Updated to increase capability with EPA's fine particulate data bank
1n September 1978.
Added to answer questions on the effect of the duty cycle and emissions level in residential
sources.
Added - these elements are often difficult to analyze by SSHS.
to check SSHS data 1n selected cases.
A set of analysis was developed
Dropped for cooling and ash quenching stream because of known problems in interpreting results.
Reduced because sufficient data input 1s being generated by other EPA programs.
Added to provide data concerning Individual C^-C^g species for OAQPS.
Reduced to fit actual data needs of program. Directed change June 1978.
Reduced to fit actual data needs of program. Directed change June 1978.
Modified to assume that Inorganic emissions are nil from gas-fired sites and to assume that all
Inorganics In fuel are emitted from the stack. Directed change June 1978.
Deleted because very low particulate loadings did not give technically acceptable results.
Directed change June 1978.
Modified so that the XAO-2 extract and all rinses are combined into a single sample because of
very low levels of organlcs in all samples except XAD-2 extract. Directed change June
1978.
Modified to a two column Molecular Sieve 13X and Chromosorb 102 system so that all species of
interest can be analyzed properly.
Change scheme to combine XAD-2, condensate, nitric acid rinse, and first impinger prior to
SSMS. Allows for more realistic blank sample and improves detection limits. Directed
change February 1979.
Acetone was substituted for methanol because water could not be removed from methanol easily
and TCO loss during concentration.
Official EPA change not implemented because of cost impact and the procedure was not in
original scope of work. Original Level 1 criteria retained.
-------
TABLE 95. HODIFICATION AND EPA DIRECTED CHANGES TO LEVEL 1 PROCEDURES
oo
Parameter/ Analyst s
of Interest
Impinge rs
SASS Train Passiva-
tion Procedure
First H202 Iraplnger
NOX Analysis
As and Sb Analysis
SSMS Analysis
Slurry Sampling
Total Chromatograph-
able Organlcs (TCO)
Liquid Chroma tography
(LC)
Liquid Chroma tography
XAO-2 Module Conden-
sate
Parr Bomb Combustion
Hg, As, Sb Met
Change and Reason
The use of Isopropyl alcohol to wash out implnger bottles was dropped because
excessive amounts sometimes interfered with AA analysis.
Changed to a 15% HN03 soak for 30 minutes to reduce SASS train corrosion.
HgO, content reduced for sites using low sulfur fuel to save reagent and reduce
analysis problem.
Changed to EPA Method 7 because NQ2 deteriorates In bag used to take and transport
sample for analysis.
Wet methods deleted, SSMS method of choice.
Level I change from thrte to four SASS train samples for SSMS analysis.
Original procedure modified. No samples taken by original method.
~ Dropped for all SASS train samples except XAD-2 resin extract and condensate
extract.
Dropped Fraction 8.
Original Level 1 procedure retained when TCO is less than 10% of total organics.
Sample not analyzed if it is less than 102 of the organics in the XAD-Z extract.
Only methylene chloride extraction performed.
Modified by addition of a quartz liner to reduce blanks.
Modified or method changed when reduced to practice.
Date
8/77
6/77
6/77
8/78
6/78
9/78
6/78
8/78
7/77
7/77
7/77
6/77
6/77
Chemical Analysis
-------
5.4.3.1 Inorganic Laboratory Analysis Procedures
Level I inorganic analysis consisted of a Spark Source Mass Spectrometric
(SSMS) elemental survey along with specific analyses for mercury, arsenic,
antimony, and sulfate. Analyses for nitrate, fluoride, and chloride were
performed on selected samples. The initial analytical scheme followed is
shown in Figure 11, and the current analytical scheme is shown in Figure 12.
The changes in the analytic scheme included:
• Performing all As, Sb, Cl, and F analysis by SSMS where
possible.
• Eliminating hot water extraction procedures for solid waste
samples.
• Eliminating all nitrate analysis.
• Combining XAD-2, XAD-2 module condensate, nitric acid
rinse, and first impinger solutions for SSMS analysis.
• Adding proximate and ultimate analyses for coal feed and
ultimate analysis for oil feed.
Both liquid and solid samples were received in the laboratory for analy-
sis. Aqueous liquids required only minor preparations which are described in
each analytical procedure (2). Organic materials, both liquid and solid,
were combusted in a Parr oxygen bomb in preparation for inorganic analyses.
Solids that were primarily inorganic, except glass fiber particulate filters,
were analyzed directly by SSMS; they were digested with aqua regia for other
analyses. Particulate filters generally were acid digested for SSMS analysis
because of the cohesion and sparking problems that are associated with having
glass filters in the graphite electrodes. It is still preferable, however,
to run all particulate samples for SSMS neat, and this was done whenever
possible. Samples for chloride and nitrate analysis were prepared by extrac-
tion with hot water. These hot water extract solutions were also the preferred
sample for sulfate analysis.
The prepared samples were aliquoted and disbursed by the Sample Bank
Manager, Mercury was analyzed by a cold vapor technique, and both arsenic
and antimony were determined by hydride generation and Atomic Absorption Spec-
trometry (AAS) detection. The sulfate determination was a turbidimetric
179
-------
00
o
APS - ammonium persulfate
Figure 11. Level I Inorganic Analysis Plan
-------
—CO
i!
•fiLJ
c
ro
r—
O-
VI
*r~
CO
O
-------
procedure. Nitrate was measured colorimetrically after reaction with brucine.
Specific ion electrodes were used to analyze both fluoride and chloride. These
analyses are described further in the following paragraphs.
Spark Source Mass Spectrometry (SSMS) —
SSMS was used to perform a semi quantitative elemental survey analysis on
the Level I samples taken. The analysis was performed using a JEOL Analytical
Instruments, Inc. Model JHS-01BM-2 Mass Spectrometer. The OMS-01BM-2 is a
high resolution, double focusing mass spectrometer with Hattauch-Herzog ion
optics. The instrument is specially designed to carry out high sensitivity
trace element analysis with the aid of an RF spark ion source and photoplate
detection. An aliquot of each sample to be analyzed is incorporated into two
electrodes which are then mounted in the ion source of the mass spectrometer.
These electrodes are "sparked" with a high voltage discharge which decomposes
and ionizes the electrode material. Because of the high energy of the elec-
trical discharge, most of the material is reduced to its elemental form. The
ions formed are collected with focusing plates and subsequently measured in
the mass spectrometer. Spark source mass spectrometry can be used to detect
q
elemental concentrations down to 10 g (one nanogram). Although the sensiti-
vity may vary somewhat from sample to sample, practically all elements (except
H, C, N, 0, and the inert gases) in the periodic table can be detected.
Interferences can result from the formation of multiple charged ions,
ion clusters, and molecular ions such as oxides, hydrides, hydroxides, and
carbides. These interferences, coupled with the fact that the discharge con-
ditions in the ion source are not easily reproduced, limit the accuracy of
the technique. Spark source mass spectrometry, however, is very useful as a
survey tool and is capable of providing semiquantitative results (i.e.,
accurate to within a factor of 2 or 3).
Mercury - Cold Vanor --
The cold vapor mercury analysis is based on the reduction of mercury
species in acid solution with stannous chloride and the subsequent sparging
of elemental mercury, with nitrogen, through a quartz cell where its absorp-
tion et 253.7 nni is monitored.
182
-------
Arsenic - Hydride Evolution —
The procedure entails the reduction and conversion of arsenic to its
hydride in acid solution with either stannous chloride and metallic zinc or
sodium borohydride (NaBH^). The volatile hydride is swept from the reaction
vessel by a stream of argon into an argon-hydrogen flame in an atomic absorp-
tion spectrometer. There, the hydride is decomposed and its concentration
monitored at the resonance wavelength 193.7 nm. Some interferences with the
Level I samples have been reported for this arsenic procedure. In particular,
it has been found that excess hydrogen peroxide and nitric acid must be
removed prior to the addition of either the zinc slurry or sodium borohydride
used to generate the arsenic hydride.
Antimony - Hydride Evolution --
Antimony-containing compounds are decomposed by adding sulfuric and
nitric acids and evaporating the sample to fumes of sulfur trioxide. The
antimony liberated is subsequently reacted with potassium iodide and stannous
chloride and finally with sodium borohydride to form stibine (SbH-J. The
stibine is removed from solution by aeration and swept by a flow of nitrogen
into a hydrogen diffusion flame in an atomic absorption spectrometer. The
gas sample absorption is measured at 217.6 nm. Interferences in the flame
are minimized because the stibine is freed from the original sample matrix.
Sulfate - Turbidimetric —
The basis of the analysis is the formation of a barium sulfate precipitate
in a hydrochloric acid medium with barium chloride in such a manner as to form
barium sulfate crystals of uniform size. The absorbance of the barium sulfate
suspension was measured by a transmission photometer, and the sulfate ion
concentration determined bv comparison of the reading with a standard curve.
Nitrate - Brucine Colon'metric ~
Nitrate analysis was performed on hot water extracts of particulate
samples from selected sites using the standard brucine nitrate colorimetric
procedure. The reaction between nitrate and brucine sulfate produces a yellow
color which can be used for the colorimetric estimation of nitrate. The
intensity of the color is measured at 410 nm. To each sample aliquot to be
183
-------
analyzed, sodium chloride and sulfuric acid solutions are first added. If any
color or turbidity are present at this point, the absorbance is measured for
a blank correction. The brucine-sulfanilic acid reagent is then added, and
the samples are kept in a bath of boil ing water for 20 minutes. They are then
cooled and their absorbance measured.
Fluoride - Specific Ion Electrode —
Fluoride was determined potentiometrically using a selective ion fluoride
electrode in conjunction with a standard single junction sleeve-type reference
electrode and a pH meter having an expanded millivolt scale. Sample pH was
between 5 and 9. Polyvalent cations of Si , Fe » and Al interfere by
forming complexes with fluoride. The addition of a pH 5 total ionic strength
adjuster buffer (TISAB II) containing a strong, chelating agent preferentially
complexes aluminum (the most common interference), silicon, and iron and
eliminates the pH problem.
The addition of TISAB II also provides a high total ionic strength back-
ground to help mask the difference in total ionic strengths between samples
and standards. However, the TISAB II cannot entirely compensate for this
difference due to the very high and variable level of ionic strength in the
Level I SASS samples. Thus a known addition technique is employed to eliminate
the necessity of drawing different calibration curves for different types of
samples.
Chloride - Specific Ion Electrode —
Chloride was determined potentiometrically using a solid state selective
ion chloride electrode in conjunction with a double junction reference elec-
trode and a pH meter having an expanded millivolt scale. The solid state
electrode is used because it is not sensitive to the higher levels of nitrate,
sulfate or bicarbonate which could be present in many of the samples. This
method does require that the sample and standards have the same total ionic
strength. A known addition technique is employed to eliminate the necessity
of drawing different calibration curves for different types of samples because
samples can have a very high and variable level total ionic strength.
184
-------
5.4.3.2 Detection Limits
The determination of a system's detection limits for different chemical
species must include a discussion of three interrelated Items. The first Item
is the determination of the analytical detection limit for each species as
listed in the first part of Table 96. The second item is the determination of
the species quantities needed in each type of SASS sample (particulate filters,
XAD-2 module, impingers, etc.) to meet these analytical detection limits. The
analytical detection limits together with the average volume, weight, or
amount of the collected sample are used to calculate the quantities of species
needed in each of the SASS train components in order to be detectable. This
3
data when divided by the average volume of gas sampled, 30 m , yields the
3
detectable species concentration in the gas stream (yg/m ). These data appear
in the second section of Table 96.
The third item, shown in the last section of Table 96, is the determina-
tion of the species concentrations needed in the fuel to meet these gas stream
detectable concentration values. This 1s derived by multiplying the volume
of gas created by the combustion of one gram of fuel and the gas stream concen-
tration values. This yields (in ppm) the species concentrations in the fuel
required to produce detectable species quantities in the gas stream. The
volume of gas per gram of fuel is obtained by using the stack emission formula
(Appendix B) given below.
"FG " 1 - 4.762 (°2 )
TW
where:
npg = gram-moles of dry effluent/grim, of fuel
F » gm-moles of dry effluent/gram of fuel under stolchiometric
combustion (Appendix B)
02 s volumetric 0£ concentration, in percent, as determined from
field gas analysis.
The value "npG" is then used in the Nernst equation to yield the volume of gas
per gram of fuel, assuming 1 atm. and EO°C.
The values obtained for SASS train detection limits and corresponding
fuel concentration levels necessary to meet these limits will vary for each
185
-------
TABLE 96. ANALYTICAL SASS TRAIN DETECTION LIMITS
I. Analytical Procedure
Detection Limit (ppm)
II. Average SASS Train ,
Detection Limits (mg/m )
a) Parti cul ate on Filter
b) XAD-2 Resin
*
c) Composite
d) Ammonium Persulfate
impinger
III. Necessary Fuel Concentration
to Meet Calculated SASS
Train Detection Limits (ppm)
a) Parti cul ate on Filter
b) XAD-2 Resin
c) Composite
d) Ammonium Persulfate
impinger
Hg
0.0001
0.0008
0.013
0.005
0.003
0.00006
0.001
0.0004
0.0003
As
0.005
0.08
1.3
0.5
0.3
0.003
0.07
0.02
0.01
Sb
0.005
0.07
1.2
0.4
0.2
0.003
0.07
0.02
0.01
S0= NO"
1.0 0.1
62 1.6
1000
390
_
0.6 0.06
14 1
4 .4
.
F" cr
0.2 0.5
3.1 9.1
50 125
20 50
_
0.01 0.03
0.3 0.7
0.1 0.2
Composite - H»0« impinger + condensate + module rinse.
-------
site approximately i one order of magnitude. This fluctuation is due to
variations in field sample liquid and solid volumes and weights, and exit gas
oxygen content.
5.4.3.3 Level I OrganicAnalysis Methodology
An overview of the sources of the samples and the appropriate combinations
of the samples for analysis is shown in Figure 13. The overview of the
methodology and decision criteria used for the Level I organic sample prepara-
tion and analysis is shown in Figure 14.
As indicated in these two figures, the extent of sample preparation
required varied with sample type. Organic liquids did not need pretreatment.
The majority of the samples, including SASS train components, aqueous solu-
tions, bottom ashes, and other solids required an initial solvent extraction
to separate the organic and inorganic portions of the samples before the
analyses could be continued.
Both the extracts and the neat organic liquids were concentrated in
Kuderna-Oanish evaporators to 10 ml volumes. Two 1-ml aliquots were then
taken from each concentrate for the following analyses:
• Total chromatographable organic material (GC-TCO) and, should
Level II efforts have been required, SC/MS analysis.
t Gravimetric determination of non-volatile organic material and
an infrared analysis on the residue from the gravimetric
determination.
The data provided by performing the TCO and the gravimetric analyses were
used to make the decision as to the analysis path to be followed for all other
determinations. The TCO analysis provided quantitative information on the
bulk amount of semi-volatile organic material in the boiling range of the Cj
to C.j6 alkanes ~ 90°C to 300°C. The gravimetric analysis provided quantita-
tive results on the amount of non-volatile organics in the sample. These two
values combined give an estimate of the total organic content of the sample.
Whenever the total organic content of the sample was equivalent to a stack
concentration of 500 yg/m or less, the organic analysis was terminated.
2
Whenever the value was greater than 500 yg/m stack concentration, the direction
of the analyses depended on the TCO results.
187
-------
oo
00
nl FROM FH tO
Figure 13. Level I Organic Analysis Flew Chart
-------
<
'
LIQUID SAMPLES
^
SASS TRAIN
SOLVENT RINSES
i
i
AQUEOUS
SOLUTIONS
4
V
1 ML ALIQUOT
FOR GC-TCO,
SECTION 7.7 AND
GC/MS SECTION
7.10
CONCENTRATE
SECTION 7.4
TCO INW .ik
jfc,3 j?r ^*"^s^
SOLID SAMPLES
*
SOLID
MATERIALS
WUtTICULATI
OR ASH
Y i
GRAV 1NPU1
• 1
EXTRACTION
SECTION 7.3
i
'
4
XAO-J
RESIN
*
ALIQUOT fOK
GRAVIMETRIC, SECTION 7.5
AND lit SECTION
7.6
^ QUANTITY
Of TOTAL
OtGANICS AND
TCO,
I 1C.
| SECTION 7.8
1
II rim i
L
TCO
3
«
4 5
I
G«AV«
«
IR
7
at
8
8AV. «
>.
It
t
III
^ ^ 2 3
1
4
GRAV.
*
1
5
i
I
6
IR
1 1
7 8 „
HtACTION
OS OF
SPECIAL INTEREST,
SECT ON
.0
LOW RESOLUTION
MASS SKCTROSCOPY,
SECTION 7.9
Section numbers in
this figure correspond
to those in thfl Methods
and Procedures Manual
(127).
Figure 14. Level I Organic Analysis Methodology
189
-------
If the TCO was less than 10% of the total organic material, the analy-
tical pathway labeled "Method 2" in Figure 15 was followed. A suitably sized
sample aliquot was taken for liquid chromatographic fractfonation, evaporated
to dryness and transferred to an LC column. Each separated fraction was sub-
sequently subjected to gravimetric and infrared analyses. If the TCO was
greater than 1Q% of the total organ!cs, an aliquot for LC was prepared by
solvent exchange to preserve the volatile species. In this "Method 1"
procedure, each fraction separated still underwent gravimetric and infrared
analyses", however, in addition, the first seven LC fractions were first
analyzed for TCO.
The GC-TCO analysis has been used to obtain information on the quantity
of material boiling within discrete ranges corresponding to the boiling points
of the n-alkanes C^ through C,g as well as on the total amount of material in
the overall n-alkane boiling range. Materials were classified solely on the
basis of their retention time relative to the n-alkane and were quantitated
as n-alkanes. This means any compounds containing oxygen, nitrogen, sulfur,
or halogens would also be reported as alkanes.
The infrared analyses provide information on the major functional groups
(I.e., chemical compound classes) present 1n a sample. Data obtained by the
GC-TCO and IR analyses are interrelated: many compounds detected in the GC
analysis are too volatile to remain when sample is evaporated for IR analysis;
and many compounds Identified in the IR analysis have volatilities too low to
be detected by the GC-TCO procedure. In a similar manner, the results of GC
analyses of the LC fractions complement the IR analyses of these samples.
Low resolution mass spectrometric (LRMS) analysis is a survey technique
used to determine organic compound types. For any LC fraction with a source
3
concentration which exceeded 0.5 mg/m , LRMS analysis was performed.
The remaining paragraphs of this section briefly describe the analytical
techniques used in conducting the Level I organic analysis.
Extraction of Aqueous Samples for Organics—
Typical liquid samples that have been generated in this program include
aqueous condensates, settling pond samples, and ambient water samples. These
190
-------
liquid extractions were performed with standard separatory funnels. The
sample volume was measured and the sample was transferred to the separatory
funnel. Whenever necessary, the pH of the sample was adjusted to neutral
with either a saturated solution of sodium bicarbonate or ammonium chloride.
The sample was extracted three times with a volume of high-purity methylene
chloride equal to approximately 5 percent of the sample volume. The resulting
extract was measured, dried with anhydrous sodium sulfate, and then concen-
trated to 10 rnl.
Extraction of Solid Samples for Organics —
Typical solid samples that have been generated in this program include
cyclone catches, particulate filters, XAD-2 resin samples, bottom ashes, and
electrostatic precipitator dusts. These extractions were performed in
appropriately sized Soxhlet extractors. Each sample was placed or weighed
ID)
into a glass thimble and extracted for 24 hours with Distilled-in-Glassv '
purity methylene chloride. The resulting extracts were then concentrated.
Concentration of Organic Extracts —
Solvent extracts of solid and liquid samples and solvent rinses of
sampling hardware were concentrated in Kuderna-Danish evaporators. Heat
provided by a steam bath was sufficient to volatilize the solvents. All
samples were concentrated to a volume between 5 ml and 10 ml and then, when
cool, transferred to a volumetric flask and diluted to a final volume of 10 ml,
Gravimetric Determinations for-Organics —
The weight of non-volatile organic species in samples for Level I organic
analyses was determined on the concentrates obtained from the Kuderna-Danish
concentrations of solvent extract and rinse samples. The samples were trans-
ferred to either small glass beakers (for LC fractions) or tared aluminum
weighing dishes. The samples were then evaporated at ambient temperature to
a constant weight. The dry samples were always stored in a desiccator.
Weights of organic residues down to 0.1 mg were measured.
Infrared Analysis —
Infrared analysis was used to determine the functional groups present in
an organic sample or LC fraction of a partitioned sample. The interpreted
191
-------
spectra provide Information on functionality (e.g., carbonyl, aromatic hydro-
carbon, alcohol, amine, aliphatic hydrocarbon, halogenated organic, etc.).
Compound identification is possible only when that compound is known to be
present as a dominant constituent 1n the sample.
The minimum sample amount required for this analysis has been 0.5 mg.
A compound must be present in the sample at 5%-103» (w/w) at least for the
characteristic functional groups of a compound to appear sufficiently strong
for interpretive purposes. Organic solvents, v/ater and some inorganic
materials cause interferences. Water, in particular, can cause a decrease in
the quality (i.e., resolution of a spectrum, sensitivity) of the analysis.
The initial organic sample or LC fraction, after evaporation, was either
(1) taken up in a small amount of carbon tetrachloride or methylene chloride
and transferred to a NaCl window, or (2) mixed with powdered KBr, ground to a
fine consistency, and then pressed into a pellet. A grating IR spectrophoto-
meter was used to scan the sample in the IR region from 2.5 to 15 um.
Cy-C,g Total Chromatographable Organic Material Analysis —
Gas chromatography 1s used to determine the quantity of lower boiling
hydrocarbons (boiling points between 90°C and 300°C) 1n the concentrates of
all neat organic liquids, organic extracts and LC fractions 1 through 7 (when
LC Method 1 is used) encountered in Level I environmental sample analysis.
Data were used to first determine the total quantity of the lower boiling
hydrocarbons in the sample. Whenever the total of C^-C,, hydrocarbons
exceeded 75 yg/m , the chromatographic results were reported as quantities in
each of the Cj-C-jg boiling point ranges rather than as .a total.
The extent of compound identification is limited to representing all
materials as normal alkanes based upon comparison of boilinq points. Also,
the analysis is semi quantitative because calibrations are prepared using only
one hydrocarbon, n-decane. The differences in instrument response, or sensi-
tivity, to other alkanes are well within the desired accuracy limits for
Level I analysis and are not taken into consideration in data interpretation.
192
-------
Liquid Chromatographlc Separations —
This procedure Is designed to give a separation of a sample Into eight
reasonably distinct classes of compounds and 1s applied to Level I analyses
of SASS train samples which contain a minimum of 15 mg of non-volatile organlcs.
Sample weights from bulk liquids and solids were evaluated on a case-by-case
basis. A sample weighing from 9 mg to 100 mg was placed on a silica gel liquid
chromatographic column, A series of eight eluents were employed to separate
the sample Into nominally eight distinct classes of compounds for further
analyses.
The use of HC1 in the final eluent results in a partial degradation of
the column material. Thus, the eighth fraction has silica contaminants present
1n variable amounts. Filtration was attempted to separate silica gel from the
organics, but silica was still often observed, particularly in Infrared spectra.
As indicated in Figure 15, two distinct analytical procedures can be used
in the performance of LC fractlonations and subsequent analyses. The selection
of the pathway "Method 1" or "Method 2" was based on the results of gravimetric
and TCO determinations on the concentrated organic sample. For a LC separation
to be required, the total organic content of the total, original sample must
3
exceed 500 vg/m . Method 21s used whenever the volatile hydrocarbon content
determined by the TCO analysis 1s low — less than 101 of the total. Method
1 1s used whenever the volatile material content 1s 1n excess of 10% of the
total.
The first difference between Method 1 and Method 2 1s 1n the method of
preparing the sample for Introduction onto the LC column. In Method 2, where
there are few volatile substances, a simple, direct solvent evaporation step
1s sufficient. In Method 1, however, care must be taken to preserve the
lower boiling components through the LC separation and subsequent analyses.
Therefore, a solvent exchange step has been Incorporated to transfer the sample
from methylene chloride to the non-polar solvent hexane. In addition, when-
ever Method 1 was used, a TCO analysis was performed on the first seven
fractions for Information on the mass and types of volatile compounds present
in each fraction. These data supplemented the gravimetric and Infrared ana-
lyses which were performed on all fractions.
193
-------
Low Resolution Mass Spectrometric Analysis —
This procedure 1s a survey analysis used to determine compound types 1n
an organic sample or 1n an LC fraction of a sample. The analyst Is specifically
searching for hazardous compounds or compounds which may be generally considered
toxic, e.g., aromatic hydrocarbons and chlorinated organlcs. Analysis using
different sample Ionizing parameters results In molecular weight data, which,
combined with IR and sample source data, can provide specific compound Identi-
fications on a "most probable" basis.
The mass spectrometer (MS) used in this procedure has sufficient sensi-
tivity such that 1 nanogram or less presented to the ionizing chamber results
in a full spectrum with a signal ratio of 10:1. A dynamic range of 250,000
is achievable. The detection limit for a specific compound related to the size
of an air sample or liquid sample varies widely depending on the types and
quantities of the species in the mixture. This is because of interfering
effects in the spectrum caused by multiple compounds. The impact of this
interference 1s reduced by lowering the ionization voltage to produce spectra
4C%ntain1ng relatively more intense molecular ions.
Solid samples are placed in a sample cup or capillary for introduction
via the direct insertion probe. The probe is temperature programmed from
ambient temperature to 300°C. Periodic MS scans are taken with a 70 eV Ionizing
voltage as the sample is volatilized during the program. A lower ionizing
voltage range (10-15 eV) can be used at the discretion of the operator if the
70 eV data are complex. Spectra are interpreted using reference compound
spectral libraries, IR data, andother chemical information available on the
sample. The results of LRMS analysis give qualitative Information on compound
types, homologous series and, in some cases, identification of specific com-
pounds. This information is then used to assess the hazardous nature of the
sample.
Polycyclic Organic Compound Analysis by Gas Chromatography/Mass Spectrometry —
This is a combined gas chromatography/mass spectrometry (GC/MS) method for
qualitative and quantitative polycyclic organic material (POM) determinations.
Microliter quantities of concentrated sample extracts derived from the sampling
activity are used for this analysis.
194
-------
Micro!1ter sized samples are Injected onto a gas chromatographlc column
and are separated by the differences 1n the retention characteristics between
the sample components and the column material. As the components elute from
the column, they are transported via an Instrument Interface to the mass
spectrometer (MS), which 1s being operated in a Total Ion Monitoring (TIM) mode.
In the MS, the various compounds are Ionized, and all 1on fragments in
the mass range of 40 to 400 AMU are monitored. The resulting mass spectra are
stored by the computerized data system. All compounds eluting from the GC in
detectable quantities could be identified, including aromatic compounds con-
taining heteroatoms, depending upon the desired scope of the analysis. At this
time, the computer is used to search the stored spectra for the specific mass
fragments shown in Table 97.
The spectra of POM are quite distinctive because they yield very strong
molecular Ions with little fragmentation. Using molecular Ions to find POM
1n a mixture Involves reconstructing the GC trace from the stored data using
only a single mass to charge (m/e) value. Any Inflection in this mass chroma-
togram indicates the possibility of a POM of that molecular weight. The
spectrum is then displayed and the operator judges if the spectrum 1s consis-
tent with a POM. The GC retention time and the spectrum are used to make this
Identification although it is often difficult to confirm which isomer is
causing a peak without standards for the specific material.
Using this technique, a large number of POM compounds can be screened 1n a
short period of time, and good identification of POM type is possible. More time
is required for exact Identification. Table 98 lists POM compounds which are
sought in all samples; any POM with a molecular weight on this 11st will be de-
termined. If other POM with different molecular weights are desired, all that is
needed for their identification is the molecular weight and a relative reten-
tion time or a standard. During the search of the data for POM compounds,
non-POM compounds may Interfere especially if they coelute with a POM.
Computer data interaction techniques, such as ion mapping, keep these inter-
ferences to a minimum. If a POM is confirmed, the peak is quantltated using
an Internal standardization method.
195
-------
TABLE 97. MASS TO CHARGE VALUES MONITORED*
128
154
162f
166
178
179
180
184
192
202
216
228
242
252
256
278
300
302
Mass to charge values have units 1n (gm/gm mole)/
(electron/molecule).
Internal standard 1s chloronapathalene.
The 6C/MS sensitivity varies with several parameters Including the type
of compound, Instrument internal cleanliness, resolution of closely eluting
peaks, etc. Under "everyday" operating conditions 20 nanograms (ng) eluting
in a peak about 5 seconds wide yields an MS signal with a usable signal to
noise ratio. Typically, this represents at least 100 yg of any single POM
compound 1n a concentrated extract of a sample.
5.4.4 Test Results
5.4.4.1 Field Measurement Res.u-1 ts
Oxygen concentration data and data on sulfur dioxide, carbon monoxide,
particulate, and hydrocarbon emissions for the tests conducted are presented
in Tables 99, 100, 101, and 102 for bituminous coal-fired, lignite-fired,
residual oil-fired, and gas-fired utility boilers, respectively. The C-j-Cg
gaseous hydrocarbon measurements were made in the field, but the C^-C-jg* and
>C^g hydrocarbon emissions were determined in the laboratory. These labo-
ratory determinations are included here so that emissions of the C,-C,g and
C-j-Cg denotes hydrocarbons in the -160 to 90°C boiling range; Cj-Cjg denotes
hydrocarbons 1n the 90 to 300°C boiling point range; >C]§ denotes hydro-
carbons with boiling points >300°C.
196
-------
TABLE 98. MINIMUM LIST OF POM COMPOUNDS MONITORED
Compound Name Molecular Weight
Naphthalene
Biphenyl
Fluorene
9,10 Dihydro-phenanthrene
9, 10-Di hydro-anthracene
2-Methyl-fluorene
1 -Methyl -f 1 uorene
9-Methyl-fluorene
Phenanthrene
Anthracene
Benzoquinol ine
Acridine
3-Methyl -phenanthrene
2 -Me thy! -phenanthrene
2-Methyl -anthracene
Fluoranthene
Pyrene
Benzo[a]fl uorene or 1,2-benzofl uorene
Benzo[b]fluorene or 2,3-benzofluorene
Benzo[c]fl uorene or 3,4-benzofluorene
2-Methyl -f luoranthene
4 -Methyl -pyrene
3-Methyl -pyrene
1 -Methyl -pyrene
Benzo[c]phenanthrene
Benzo[ghi]f luoranthene
Benzo[a]anthracene
Chrysene
Triphenylene (9,10 Benzo phenanthrene)
128
154
166
180
180
180
180
180
178
178
179
179
192
192
192
202
202
216
216
216
216
216
216
216
228
228
228
228
228
MATE Value*,
Air, yg/m3
5.0 x
1.0 x
1.4 x
N
N
N
N
N
104
103
104
1.59 x 103
5.6 x
N
9.0 x
3.0 x
3.0 x
3.0 x
9.0 x
2.3 x
N
N
N
N
N
N
N
2.73
N
4.5 x
2.2 x
N
104
104
104
104
104
104
105
x 104
101
103
These are health based Minimum Acute Toxicity Effluent (MATE)
obtained from Reference 129.
(Continued)
values
197
-------
TABLE 98. (Continued)
Compound Name
4-Methyl -benzo[a]anthracene
1 -Methyl -chrysene
6-Methyl -chrysene
7,12-Dimethyl-benzo[a]anthracene
9,10-Dimethyl-benzo[a]anthracene
Benzo[f]fluoranthene
Benzo[k]f 1 uoranthene
Benzo[b]fluoranthene
Benzo[a]pyrene
Benzo[e]pyrene
Perylene
1 ,2,3,4-Dibenzanthracene
2 , 3 , 6 , 7 -Di benzan thracene
Benzo[b]chrysene
Picene
Benzo[c]tetraphene
Benzo[ghi]perylene
Coronene
1 ,2,3,4-Dibenzpyrene
1,2,4, 5-Di benzpyrene
Alkyl substituted naphthalenes
Dibenzothiophene
Methyl Dibenzothiophene
Dimethyl phenanthrenes
Trimethyl phenanthrenes
Alkyl substituted biphenyl
Ethyl f 1 uorene
Molecular Weight
242
242
242
256
256
252
252
252
252
252
252
278
278
278
278
256
302
300
302
302
N/A
182
196
206
220
N/A
195
MATE Value,
Air, yg/m3
N
1.79 x 103
1,79 x 103
2.6 x 10"1
2.96 x 101
N
1.63 x 103
9.0 x TO2
2.0 x 10"2
3.04 x 103
N
1.0 x 104
N
N
2.5 x 103
N
5.43 x 102
N
N
N
2.0 x ID5
2.3 x 104
N
N
N
N
N
N - Not Available
198
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The sources of information and the evaluation of these existing discharge
data are described below.
6.3.1 Waste Streams from Cooling Systems
Two primary sources of discharge data were available for cooling
tower blowdown data. The first source is the Technical Report for Revision
of Steam Electric Effluent Limitations Guidelines (137) which presented
the findings of an extensive study of that section of the power generating
industry discharging industrial wastes to publicly owned treatment works
(POTW). This document provided data for six cooling towers. Parameters
mainly identified were metals such as iron, nickel, chromium, zinc and
copper. Also characterized were such gross parameters as BOD, COD, TDS,
TSS and TS. The second source of data is the Development Document For
Proposed Effluent Limitation Guidelines And New Source Performance
Standards For The Steam Electric Power Generating Point Source Category
(138). This document was prepared for the purpose of developing effluent
limitation guidelines, standards of performance for new sources, and pre-
treatment standards for the industry. Cooling tower blowdown data were
compiled for five major power plants. In addition to those parameters
identified in the first document, additional data on other constituents
were also reported (138). Table 174 is a compilation of data from these
two sources showing the mean, the number of data points (N), and the
variability of emissions data.
In Table 175, the mean and upper limit cooling tower blowdown concen-
tration values are compared with the health based water MATE values. From
the data presented in Tables 174 and 175, the existing data base character-
izing trace element concentrations in cooling tower blowdown is inadequate.
This is because data variability for trace element concentrations is large,
and data are totally lacking for the majority of the trace elements. When
compared with health based water MATE values, concentrations of sodium,
magnesium, and chromium in cooling tower blowdown appear to warrant envi-
ronmental concern. Also, the existing data base characterizing organic
concentrations in cooling tower blowdown is inadequate due to the total
lack of data.
326
-------
TABLE TOO. FLUE GAS EMISSIONS OF S02» CO, PARTICULATES AND HYDROCARBONS FROM
LIGNITE-FIRED UTILITY BOILERS TESTED
IN3
Combustion
Source
Type
Pulverized
Dry Bottom
Cyclone
Stoker
*
Site
No.
314
315
318
155
316
317
319
ased on c
V S02*
% ppm
4.94 380
4.7 210
11.92 460
7.3 850
7.0 600
10.9 770
t 670
onverslon of (89
ng/J ppm
350 <500
190 <500
760 <500
910 19
620 <500
1130 <500
980 C1g Total
mg/m3
9.800
6.930
0.064
0.490
2.410
1.745
0.332
for *«
mg/m3
52.84-54.84
13.21-16.54
4.48- 6,48
7.99- 9.27
13.47-16.80
4.17- 7.51
CaO _w«
T0r wt% A1203 """ WtS
ng/J
18.19-18.88
4.45- 5.58
2.75- 3.98
3.23- 3.77
5.28- 6.59
2.30- 4.14
JaoO
Si 62
were assumed to be 1.74 and 0.197, respectively. Data presented are for uncontrolled
Oxygen concentration assumed to be the same as for Site 317.
Data presented are for controlled participate emissions.
emissions.
-------
TABLE 101. FLUE GAS EMISSIONS OF S02, CO, PARTICULATES AND HYDROCARBONS FROM
RESIDUAL OIL-FIRED UTILITY BOILERS TESTED
PO
o
Combustion
Type
Tangentially-
fired
—
Wall -fired -
.-
Site
No.
210
211
322
> 323
-:.-105
-> 109
na
j 119
141-144
JO'J -•
324
02.
%
9.34
-^T-iWi*
7.6
10.3
7.03
8.35
5.09
10.93
5.94t
Tl5
8.3
so2-
ppm
280
270
980
880
190
130
210
91
87t
1060
ng/J
330
290
990
1120
130
140
180
120
78t
3/0
1130
CO
ppm
<20
<20
<100
<100
<500
<500
<50
<50
16. 2t
C16 Total
mg/m3
0.839
0.806
2.149
2.216
— tt
15.800**
0,375
0.790
0.438
2.074
mg/m
4.24- 7.58
1.64- 1.976
5.21- 8,55
29.96-32.63
20.50-24.80**
2.95- 6.29
0.89- 4.90
0.82- 1.67
3.49- 6,83
ng/J
1.84- 3.30
0.66- 0.80
1.98- 3.24
14.23-15.49
8.23- 9.96**
0.94- 2.01
0.45- 2.47
0.28- 0.58
1.40- 2.73
Calculated based on conversion of 95.22% of fuel sulfur to S02-
f Four-test average.
* Average of tests 142 and 143.
Data unreliable because of unusually high levels of organics in the resin blanks..
t*0rgan1cs in blank exceed those in sample.
**Data unreliable because of unusually high levels of organics in the resin and solvent blanks.
-------
TABLE 102. FLUE GAS EMISSIONS OF CO, PARTICULATES, AND HYDROCARBONS FROM
NATURAL GAS-FIRED UTILITY BOILERS TESTED
no
o
Combustion
Source Type
Tangentially-Fired
Wall -Fired
Site
No.
113
114
115
106
108
116
117
Q~,% CO
4.81
4.62
8.64
5.85
9,08
7,88
6.47
ppm
<10
311
481
<500
<500
42
31
ng/J
<3.5
107
220
<190
<240
18
12
Total
Particulates
mg/m3
0.268
0.148
0.036
4.38
<0.032
0.445
<0.003
ng/J
0.080
0.044
0.014
1.40
<0.013
0.164
<0.001
C1 - C6
mg/nr
0-2.001
0-4.002
0-4.002
34.361-37.029
No Data
21 ;509-24. 844
0-3.336
c, - c16
v
mg/m3
0.040
0.038
0.421
No Data
8.423*
1.704
0.056
Hydrocarbons
>C16
i
mg/nr
1.618
0.789
1.987
No Data
7.352*
0.569
0.322
mg/m-
1.66
0.83
2.41
23.78
0.38
Total
3
- 3.66
- 4.83
- 6.41
_«*
--
- 27.12
- 3.71
0.50
0.24
0.94
8.79
0.13
ng/J
- 1.10
- 1.43
- 2.52
— _
-«.
- 10.02
- 1.24
+ Data unreliable because of unusually high levels of organics in the resin blank samples.
-------
>C-,g hydrocarbons can be directly compared with emissions of C-i-Cg hydro-
carbons, and to facilitate calculation of total hydrocarbon emissions. The
sulfur dioxide emission data presented were computed from the fuel sulfur
content and not based on field measurements. Also, all sulfur dioxide emis-
sion data presented are uncontrolled sulfur dioxide emissions. The bituminous
coal-fired and lignite-fired utility boilers tested were all equipped with
particulate control devices. Therefore, all particulate emission data
presented for these boilers are controlled particulate emissions. As dis-
cussed previously in Section 5.3, the existing data base for NO emissions
*v
from utility boilers is generally adequate. Additional NO measurements
(T\
were therefore not necessary.
As the data indicated, particulate emissions from gas-fired and oil-fired
utility boilers are generally lower than emissions from bituminous coal-fired
and lignite-fired utility boilers. Particulate emissions from bituminous
coal-fired Site No. 207 and lignite-fired Site Nos. 314 and 315 were excessive
and showed that the particulate control devices on these three boilers were
malfunctioning. In fact, new electrostatic precipitators have been installed
on the two lignite-fired boilers since the conduct of TRW tests.
The data reduction procedure for converting emission concentrations
•3
(ppm or mg/m) to emission factors (ng/J) 1s based on calculations of the
combustion of fuel with air, as described in Appendix B. The test results
presented will be discussed in detail in Section 5,5.
Field data for cooling towers tested are discussed in Section 5.5.
5.4.4.2 Laboratory Analysis Results
This section presents results of laboratory analyses of samples taken at
the utility boilers tested. The analytical methodology used was described in
Section 5.4.3.
Cooling Tower Emissions Results
Emissions from the cooling towers tested on this program are discussed
in Section 5.5.
Inorganic Analys isResults
Normalized inorganic results are described in Section 5.5 of this report.
203
-------
Laboratory Analysis Results
This section presents results of laboratory analyses of organic compound
emissions from the flues of the utility boilers tested. Both quantitative
and qualitative results are presented. Organic compounds are grouped into
three general categories for analytical purposes. These categories are:
• Gaseous - Compounds boiling at less than 90°C, reported as
r -r
Ll V
• Volatile - Compounds boiling between 90 and 300°C, reported
as CrC16.
• Nonvolatile - Compounds boiling above 300°C, reported as >C-jg.
The gaseous (C-|-Cg) hydrocarbons are determined in the field, while all other
organic analyses are performed in the laboratory. The gaseous (C-i-Cg) field
determinations are presented here in order to give an overview of total
hydrocarbon emissions.
Four summary tables will present quantitative organic analysis results.
These presentations are conservative. When nothing was detected in a re-
porting point, e.g., Cj (boiling point range of 90-110°C}, a "less than"
character, "<", and the detection limit was entered. When quantities in a
reporting range, e.g. C7-C,g (boiling point range 90-300°C), were summed, a
range was entered. The lower value of a range was obtained by treating any
less than values as zero, and the higher value of a range was obtained by
treating any less than values as the detection limit. The actual organic
emission value, of course, lies between the upper and lower bounds of a range.
Organic compound emission results presented in this section are not
normalized to heat input. Thus, considerable variation is expected because
dilution of the flue gas by air in leakage has not been taken into account.
Additionally, the units tested varied greatly in size, age, operating con-
ditions, control device technology, and fuel. Emission results for organic
compounds are analyzed in Section 5.5.
Summary of Organic Emissions
Tables 103 through 106, respectively, present summaries of organic
emissions from bituminous coal-fired, lignite coal-fired, residual oil-fired,
204
-------
TABLE 103. FLUE GAS EMISSIONS FRO!! BITUMINOUS COAL-FIRED UTILITY BOILERS,
SUMMARY OF ORGANIC ANALYSIS RESULTS
ro
O
on
Pulverized, Dry Bottom
Orqanics
Gaseous Qrganics,
Field, wg/ro
a
C2
C3
C4
C5
C6
Total Gaseous
Organics, vg/m3
Volatile Ornanics
TCO, *g'/m3
C7
C8
C9
CIO
C11
C12
C13
C14
CIS
C16
Total Volatile
Organics, ug/ra
Nonvolatile Organics,
Grav, >C16, »9/m3
Total Organics, pn/si
Site
154
3,337
< 334
< 334
« 334
3,301
< 334
6,638-
7,974
22
68
44
4
16
6
8
4
8
< 1
180-
181
336
7,154-
8,491
Site
205-1
« 867
« 667
< 667
< 667
< 667
< 667
0
4,002
38
207
70
75
< 1
205
32
14
2
4
647-
648
1,973
2,620-
6,623
Site
205-2
< 667
< 66?
< 667
< 667
< 667
< 667
0
4,002
16
133
73
307
42
192
73
46
83
4
969
15,463
16,432
20,434
Site
206
10,540
838
« 334
< 334
34,301
< 334
45,679-
46,681
76
96
82
78
« 1
447
20
14
26
37
876-
877
3,301
49,856-
50,859
Pulverized,
Site
212
1,267
< 67
« 67
« 67
« 67
« 87
1,267
1,602
« 1
77
43
1
1
5
7
4
1
« 1
139-
141
636
2,042-
2,379
Site
213
4,872
250
< 334
< 334
< 334
< 334
5,122-
6.45S
3
31
40
< 1
< 1
2
3
< 1
2
< 1
81-
85
306
5,509-
6,849
Hot Bcttom
Site
218
1,602
< 334
< 334
< 334
< 334
< 334
1,602-
3,272
21
41
39
< 1
18
39
< 1
12
« 1
0
179-
182
655
2,436-
4,109
Site
336
734
876
« 334
< 334
< 334
« 334
1,610-
2,946
« 1
98
< 1
94
0
< 1
< 1
18
< 1
U
231-
236
1.8T6
3,657-
4,998
Site
338
1,000
1,626
« 334
< 334
< 334
< 334
2,626-
3,962
104
203
3
272
8
126
52
14
4
35
821
2,961
6,408-
7,744
Site
1 34-Out
56?
< 6?
« 67
« 67
< 67
< 67
667-
1,002
< 1
50
40
19
14
12
2
t \
1
7
145-
147
1,295
2,107-
2,444
Site
207
< 6?
< 67
< 67
< 67
< 67
< 6?
0
67
31
43
12
27
4
108
7
4
< 1
1
237-
238
2,947
3,184-
3,252
Cyclone
Site Site
208 209
* « 67
* « 67
* < 67
* « 67
* < 67
* « 67
* 0
67
< 1 10
< 1 26
« 1 26
1 52
< 1 6
5 35
2 12
< i g
« i < 1
< T 20
8- 195-
15 196
446 1,144
> 454- 1,339-
> 461 1,407
Stoker
Site
330
187
< 67
< 67
9,865
< 67
56,714
66,766-
66,967
28
< 1
< 1
2
24
31
< 1
< I
< 1
3
88-
93
793
67,64?-
67,853
Site
331
1.068
< 667
< 667
< 667
* 667
12,404
13,472-
16,140
1,080
2,290
83
1,127
70
2
50
110
318
794
5,924
3,304
22,700-
25,368
Site
137
734
< 6?
« 67
« 67
< 67
« 67
734-
1,069
4
74
5
33
< 1
< 1
10
3
< 1
11
140
143
2,508
3,382-
3,720
Site
204
< 667
< 667
« 667
* 667
« 667
« 667
0-
4,002
76
32
1
305
2
31
4
12?
27
93
698
4,327
5,0!5-
9,027
Site
332
1,201
11,508
< 667
< 667
« 66?
« 667
12,709
15,377
14,776
400
47
330
214
42
43
57
9
JO
15,938
11 ,203
39.S50-
42.518
*Instrument failed during test.
-------
TABLE 104. FLUE GAS EMlSSIi-!:$ FROM LIf-MTE COAl.-RP£:J LT
TCILCRS. SUGARY OF ORGANIC ANALYSIS RESULTS
Organics
Gaseous Organics,
Field, pg/m3
Cl
C2
C3
C4
C5
C6
Total Gaseous
Organics, yg/m3
Volatile Organics,
o TCO, ug/m3
* C7
C8
C9
CIO
Cll
C12
C13
C14
C15
C16
Total Volatile
Organics, wg/nr
Nonvolatile Organics
GRAV, >C16, wg/m3
Total Organics mg/m3
Cyclone
Site
155
2,202
<334
<334
<334
5,102
<334
7,304-
8,640
14
29
30
23
5
10
6
6
8
7
138
490
7.932-
9.268
Site
316
10,677
<667
<667
<667
<667
<667
10,677-
14,012
<1
<1
<1
143
<1
75
<1
3
36
123
382-
387
2,410
13.469-
16.809
Stoker
Site
317
1,782
<667
<667
<667
<667
<667
1,782
5,117
<1
<1
<1
164
202
104
<1
22
12
34
642-
646
1,745
4.169-
7.508
Site
319
*
*
*
*
*
*
*
<1
<1
16
60
<1
68
34
37
12
19
259^
272
332
>0.601-
>0.604
Pulverized Dr^f Bottom
Site
314
1,340
<667
<667
<667
9,004
32,263
42,607-
44,608
<1
<1
14
82
37
132
<1
2
15
40
427^
430
9,800
52.834-
54.838
Site
315
5,339
<667
<667
<667
<667
<667
5,339
8,674
<1
<1
4
74
133
97
314
3
291
7
936^
938
6,930
13.205-
16.542
Site
318
1,034
1,751
1,211
<667
<667
<667
3,996-
5,997
5
139
71
56
<1
94
43
64
36
33
558-
559
64
4.618-
6.620
*!nstrument failed at start of test.
-------
TABLE 105. FLUE GAS EMISSIONS FROI1 RESIDUAL OIL-FIRED UTILITY BOILERS,
SUMMARY OF QRGAiJIC ANALYSIS RESULTS
ro
o
Tangential ly-F ired
Organics
Gaseous Organics,
Field, pg/nt3
Cl
C2
C3
C4
C5
C6
Total Gaseous
Organics, ug/m^
Volatile Organics,
TCO, yg/m3
C7
C8
CS
CIO
Cll
C12
C13
C14
CIS
C16
Total Volatile
Organics, jig/ro
Nonvolatile Organics,
Gray, >C16, jjg/m3
Total Organics, ug/r?r
Site
210
-. 667
< 667
< 667
•• 667
3,301
< 667
3,301-
6,fi36
18
63
13
3
< 1
3
2
< 1
< 1
2
104-
107
839
4,244-
7,582
S i te
;>n
734
- 67
< 67
-- 67
< 67
< 67
734-
1,069
23
1
1
46
< 1
5
16
6
< 1
3
101-
103
806
1,641-
1,978
Si te
322
2,4fi9
< 667
< 667
< 667
< 667
< 667
2,469-
5,804
< 1
44
36
< 1
< 1
58
47
< 1
< 1
< 1
185-
191
2,149
4,803-
8,144
Site
323
2,?69
-. 667
< 667
21,903
< 667
< 667
27,172-
27,440
< 1
16
-. 1
< 1
< 1
< 1
1
< 1
< 1
< 1
17-
25
2,126
29,315-
29,591
Site
105
16,684
< 657
< 667
< 667
< 667
< 667
16,684-
17,019
< 1
3,400
2,100
4,900
8,500
4,200
5,500
800
< 1
< 1
29,400-
29,403
979
47,063-
47,401
Site
109
*
*
4
*
*
*
*
300
800
200
< 1
400
1,800
< 1
200
200
800
4,700-
4,702
5,686
>10,386-
>10,388
Site
118
< 667
2,502
< 6G7
< fiC7
< 667
< 667
2,502-
5,837
8
17
4
18
< 1
4
1
4
6
5
67-
68
375
2,944-
6,280
Wall-fired
Site
119
-- 667
-. 667
< 667
< 667
•• 667
< 667
0
4,002
10
20
10
< 1
5
12
< 1
< 1
2
< 1
59-
63
790
849-
4,855
Site
142
850
67
< 67
< 67
< 67
< 67
850-
1,185
1
27
9
4
8
15
3
1
1
2
71
478
1,399-
1,734
Site
305
22,423
< 667
< 667
< 667
< 667
< C67
22,422-
22, 757
< 1
< 1
< 1
15
5
12
3
< 1
3
< 1
52-
57
1,589
24,063-
24,403
Site
324
400
< 67
< 67
< 67
- 67
< 67
400-
735
1
95
62
- 1
< 1
< 1
< 1
< 1
< 1
1
157-
165
2,074
2,631-
2,974
Site
143
327
< 67
< 67
-- 67
< 67
< 67
327-
662
1
29
11
4
8
1
3
4
1
1
63
397
0.787-
1,122
*Analyzer failed during test.
-------
TABLE 106. FLUE GAS EMISSIONS FROT GAS-FIRED UTILITY BOILFRS, SUMMARY OF ORGANIC ANALYSIS RESULTS
Organics
Gaseous Organics,
Field, pg/m3
Cl
C2
C3
C4
C5
C6
Total Gaseous
Organics, yg/m
Volatile Organics,
g TCO, pg/m3
oo C7
C8
C9
CIO
cn
C12
C13
C14
C15
C16
Total Volatile
Organics, yg/rtr
Tangent i al 1^-Fi red
Site
113
<33
<33
<33
<33
<33
<33
0-
198
3
18
11
<1
<1
<1
<1
3
2
<1
37-
42
Site
114
<667
<667
<667
<667
<667
<667
0-
4,002
<1
17
5
11
<1
<1
<1
1
2
<1
36
41
Site
115
<667
<667
<667
<667
<667
<667
0-
4,002
13
32
5
23
36
16
34
57
108
99
423
Site
106
24,692
9,669
<667
<667
<667
<667
34,361-
37,029
1
400
1,300
900
23,900
1,800
3,000
1,700
1
1
33,003
Wall-Fired
Site
108
*
*
*
*
*
*
<1
200
100
300
1,200
1,100
1,500
1,000
1,300
1,600
8,300-
8,301
Site
116
<667
<667
<667
<667
18.000
<667
18,000-
21 ,335
1
38
1
15
562
253
157
167
208
305
1,707
Site
117
<667
<667
<667
<667
<334
<334
0-
3,336
4
30
<1
2
2
<1
13
<1
7
<1
64-
69
Nonvolatile Organics,
6RAV, >C16, ug/m3 1,618
789
1,987
LB
3,680
569
322
Total
mg/m3
Organics,
1
3
.655-
.664
0.825
4.827
2.410
6.412
67.364-
70.032
>n
>n
.980-
.981
20
23
.276
.611
0.386
3.727
Instrument failed during test.
LB - less than blank.
-------
and gas-fired utility boilers. For bituminous coal-fired utility boilers,
emissions of gaseous hydrocarbons ranged from 0 to 67 mg/m , volatile hydro-
3
carbons from 0.008 to 16 mg/m , nonvolatile hydrocarbons from 0.3 to 15
3 3
mg/m » and total organics from >0,45 to 51 mg/m , For lignite coal-fired
utility boilers, emissions of gaseous hydrocarbons ranged from 1.8 to 45
3 3
mg/m , volatile hydrocarbons from 0.14 to 0.94 mg/m , nonvolatile hydrocarbons
3 3
from 0.06 to 9.8 mg/m , and total organics from >0.6 to 55 mg/m . For resi-
dual oil-fired utility boilers, emissions of gaseous hydrocarbons ranged
from 0 to 22.7 mg/m » volatile hydrocarbons from 0.2 to 29.4 mg/m , nonvola-
3
tile hydrocarbons from 0.38 to 5.7 mg/m , and total organics from >0.85 to
47.4 mg/m . For gas-fired utility boilers, emissions of gaseous hydrocarbons
3 3
ranged from 0 to 37 mg/m , volatile hydrocarbons from 0.036 to 33 mg/m ,
3
nonvolatile hydrocarbons from 0.90 to 3.68 mg/m , and total organics from
0.94 to 70 mg/m3.
Results of LiquidChromatographic Separations
As described in Section 5.4.3, if a flue gas sample had an organic
content of 0.5 mg/m or greater, then it was separated into seven fractions
by liquid chromatography in order to simplify interpretations of subsequent
analyses. Gravimetry and IR spectroscopy are used to analyze each fraction
for the amounts of >C-,g hydrocarbons and compound classes, respectively.
If the volatile organic content of a sample exceeds 10 percent of the total
organics, then a solvent exchange is performed before the separation to
preserve volatile organics, and volatile organics are measured in each
fraction.
Figure 15 describes the sample control numbering system used for the
EACCS program and is used with tables presented in this section.
Tables 107 through 110 present results of the liquid chromatographic
separations for bituminous coal-, lignite coal-, residual oil-, and gas-
fired utility boilers tested, respectively. These results (TCO, grav, and
total organics) are presented as emission concentrations in order to give
an impression of the amounts of organic compounds determined in each frac-
tion. The XAD-2 resin module was designed to trap the bulk of organics, and
it is seen in Tables 107-110 that virtually all of the samples were XM or XR
209
-------
xxx-xx-xx-xxx-xx-x
I ' ' -*-— — jr • ^^^V ^"~"~""~~——— ^SECOND LEVEL ' 1
SITE IDENTIFICATION . SAMPLE TYPE SAMPLE PREPARATION FIRST LEVEL ANALYSIS ANALYSIS THIRD LEVEL ANALYSIS
Consecutively numbered
by sampling team:
•
100-199, TRW West Coast
201-299, TRW East Coast
300-399, GCA
Numbers and corresponding
sample types are as
follows:
1-bulk liquid
(separated from a
slurry)
2-bulk liquid
(separated from a
slurry)
3- bulk liquid
1-bulk liquid
FF- liquid fuel feed
CO-condcnsate from
XAD-2 module
PR-solvent probe/
cyclone rinse
HR-solvent XAD-2
module rinse
HM-HNOj XAQ-2 module
rinse
HI-H202 iinpinger
A I -APS impingers
XR-XAD-2 resin
PF-filter(s)
1C-1-3M cyclone
3C- 3-1 On cyclone
10C->10ii cyclone
XH-XR extract plus MR
CH-HM plus CD plus HI
FC-PF plus 1C
CC-3C olus IOC
CF.-solid fuel feed (coal)
S-bulk solids
6-bulk solids
7-buH. solids (separated
fron: a slurry)
B-bulk solids (separated
from » slurry)
Numbers and corresponding
preparation steps are
as follows:
0-no preparation
LE-liquid-liquid extraction
SE-Soxhlet extraction
A-acidified alitjuot
B-basified aliquot
PB-Parr bomb combustion
HVi-hot water extraction
AR-aqua regia extraction
Numbers and corresponding
procedures are as
follows;
Organic
0-no cone
required
GC-C7-Ci7 fiC
KD-K-0 Cone
Inorqanic
SS-SSMS
AAS-Hq,As,Sb
S04-S04
N03-H03
CF-C1 ,F
Organic analyses on
cone samples Mill
be coded as
follows:
GH-GC/MS for PAHs
GI-Grav..IR
MS-LRHS
LC-LC separation
Resulting LC fractions
for grav./IR/LRW
analyses will be
numbered In order,
1-8
- *
Figure 15. EACCS Sample Control Numbers
-------
TABLE 107. FLUE SAS EMISSIONS FROM BITUMINOUS COAL-FIRE?.UTILITY BOILERS
SUMMARY OF LC SEPARATION RESULTS ••£,.-•
INS
S i te-Sarapl e
Pulverized
154-XH*
205-1-XM
205-2-XR
Pulverized,
206- XR
212-XH
213-XM
218*
336- XM
338- XM
Cyclone
134-JN-XR
Dry Bottom
TCO, mg/m3
GRAY, mg/m3
Total, mg/m3
TCO, mg/m3
6RAV, mg/m3
Total , mg/m3
Wet Bottom
TCO, mg/m3
GRAV, mg/m3
Total , mg/m3
TCO, nig/m3
GRAV, mg/m3
Total , mg/m3
TCO, mg/m3
GRAV, mg/m3
Total, mg/m3
TCO, mg/m3
GRAV, mg/mj
Total, mg/m3
TCO, mg/m3.
GRAV, mg/m3
Total, mg/m3
TCO, mg/m3
GRAV, mg/m3
Total, mg/m3
LCI
-
0.065
0.179
0.244
<0.001
0.095
0.095
0.072
6.198
0.270
<0.001
0.040
0.040
0.001
0.109
0,110
_
0.012
0.018
0.030
0.137
0.095
0.232
0.044
0.095
0.139
LC2
...
0.006
0.011
0.017
<0.001
<0.001
<0.001
0.043
0.031
0.074
<0.001
<0.001
<0.001
<0.001
0.008
0.008
_
0.038
0.010
0.048
0.125
0.017
0.142
0.026
0.034
0.060
LC3
-
0.008
0.031
0.039
0.019
0.031
0.050
0.037
0.098
0.135
<0.001
0.018
0.013
<0.001
0.018
0.018
_
<0.001
0.026
0.026
0.031
0.036
0.067
0.006
0.019
0.025
LC4
-
0.051
0.141
0.192
0.018
0.022
0.040
0.027
0.101
0.128
<0.001
0.009
0.009
<0.001
<0.001
<0.001
_
0.003
0.034
0.037
0.008
0.073
0.081
0.010
0.026
0.036
LC5
.
0.028
0.398
0.426
0.055
0.042
0.097
0.040
0.164
0.204
0.003
0.109
0.112
0.003
0.024
0.027
-
<0.001
0.055
0.055
0.006
0.144
0.150
0.042
0.202
0.244
LC6
_
0.044
1.176
1.220
0.018
0.706
0.724
0.104
0.353
0.457
0.006
0.162
0.168
<0.001
0.097
0.097
_
1.287
0.754
2.041
1.627
1.207
2.834
<0.001
0.148
0.148
LC7
_
0.001
0.224
0.225
<0.001
0.249
0.249
0.012
0.410
0.422
<0.001
0.141
0.141
<0.001
0.096
0.096
—
0.012
0.198
0.210
0.005
0.158
0.163
0.011
0.059
0.070
Total
_
0.204
2.165
2.369
0.110
1.145
1.255
0.335
1.3S5
1.690
0.009
0.474
0.483
0.004
0.352
0.356
«.
1.352
1.095
2.447
1.939
1.730
3.669
0.139
0.583
0.722
- Continued -
-------
TABLE 107 (Continued)
Site-Sample
134-OUT-XR
207-XM+PR
208- XM
209- XM
330-XM
331 -XH
Stoker
137-XN
204-XR+PR
332-XM+PR
TOO, mg/ra3
6RAV, mg/m3
Total , mg/m3
TCO, mg/m3
GRAV, mg/m3
Total, mg/m3
TCO, mg/m3.
SRAV, mg/m3
Total, mg/m3
TCO, mg/m3.
6RAV, mg/m3
Total , mg/m3
TCO, mg/m3
SRAV, mg/m3
Total, mg/m3
TCO, mg/m3
GRAV, mg/m3
Total , mg/m3
TCO, mg/m3
GRAV, mg/m3
Total , mg/m3
TCO, mg/m3
6RAV, mg/m3
Total , mg/m3
TCO, mg/m3
GRAV, mg/m3
Total , mg/m3
LCI
<0.001
0.009
0.009
0.113
0.602
0.715
0.038
0.089
0.127
0.001
0.260
0.261
0.029
0.110
0.139
0.079
LB
0.079
0.022
0.018
0.040
0.006
0.114
0.120
<0.001
1.412
1.412
LC2
0.002
0.001
0.003
0.012
0.040
0.052
0.009
<0.001
0.009
0.006
0.004
0.010
0.018
0.046
0.064
0.146
LB
0.146
0.001
0.009
0.010
0.027
LB
0.027
0.002
0.037
0.039
LC3
0.003
0.006
0.009
0.010
0.036
0.046
<0.001
0.005
0.005
<0.001
0.020
0.020
0.073
0.037
0.110
0.310
0.283
0.593
0.002
0.018
0.020
0.017
LB
0.017
0.033
0.067
0.100
LC4
0.010
0.016
0.026
0.026
0.143
0.169
0.010
0.044
0.054
0.002
0.091
0.093
0.042
0.056
0.098
0.010
0.228
0.238
0.109
0.085
0.194
0.004
0.018
0.022
0.013
0.140
0.153
LC5
0.031
0.589
0.620
0.050
1.054
1.104
0.025
0.178
0.203
0.029
0.187
0.216
0.008
0.089
0.097
0.030
0.459
0.489
0.203
0.045
0.248
0.061
0.003
0.064
0.038
0.436
0.474
LC6
0.001
0.201
0.202
0.023
0.285
0.308
<0.001
0.154
0.154
<0.001
0.212
0.212
0.008
0.354
0.362
2.665
1.358
4.023
0.008
0.360
0.368
0.029
0.765
0.794
3.695
2.666
6.361
LC7
0.002
0.052
0.054
<0.001
0.111
o.m
<0.001
0.063
0.063
<0.001
0.384
0.384
0.102
0.066
0.168
0.142
0.268
0.410
<0.001
1.796
1.796
0.018
1.481
1.499
0.071
0.665
0.736
total
0.049
0.874
0.923
0.234
2.271
2.505
0.082
0.533
0.615
0.038
1.158
1.196
0.280
0.758
1.038
3.382
2.596
5.978
0.345
2.331
2.676
0.162
2.381
2.543
3.852
5.423
9.275
+ Sample lost in analysis.
* Did not meet criterion for LC separation.
LB indicates less than blank.
-------
TABLE 108. FLUE GAS EMISSIONS FROM LIGNITE COAL-FIRED UTILITY BOILERS,
SUMMARY OF LC SEPARATION RESULTS
OJ
Site-Sample
LCI
LC2
LC3
LC4
LC5
LC6
LC7
Total
Pulverized Dry Bottom
314-XM
315-XM
318-XM
Cyclone
155-XMCO
316-XM
Stoker
317-XM
319-XM
TCO ,mg/m3
GRAV, mg/m3
Total, mg/m3
TCO, mg/m3
SRAV, mg/m3
Total, mg/m3
TCO, ma/m3
GRAV, mg/m3
Total, mg/m3
TCO, mg/m3
GRAV, mg/m3
Total, mg/m3
TCO, mg/m3
GRAV, mg/m3
Total, mg/m3
TCO, mg/m3
GRAV, mg/m3
Total, mg/m3
TCO, mg/m3
GRAV, mg/m3
Total , mg/m3
0.265
0.492
0.757
0.011
0.149
0.160
0.003
0.154
0.157
LB
LB
LB
0.050
0.014
0.064
0.189
0.047
0.236
0.020
LB
0.020
0.012
0.020
0.032
0.003
<0.001
0.003
LB
LB
LB
0.003
0.007
0.010
0.018
0.029
0.047
0.001
0.005
0.006
0.053
0.284
0.337
0.002
0.012
0.014
0.002
<0.001
0.002
0.062
0.330
0.392
0.001
0.020
0.021
0.007
0.190
0.197
LB
0.024
0.024
0.002
0.193
0.195
0.015
0.187
0.202
0.004
LB
0.004
0.003
0.053
0.056
0.022
0.028
0.050
0.018
01087
0.105
LB
0.053
0.053
0.002
0.028
0.030
0.002
0.040
0.042
0.002
0.134
0.136
LB
0.016
0.016
0.019
0.047
0.066
LB
0.034
0.034
LB
0.051
0.051
0.001
0.060
0.061
0.003
0.182
0.185
0.003
0.459
0.462
0.002
LB
0.002
0.040
0.331
0.371
0.004
0.116
0.120
0.005
0.217
0.222
0.002
LB
0.002
0.001
<0.001
0.001
0.004
0.046
0.050
0.003
0.271
0.274
LB
0.181
0.181
<0.001
0.395
0.395
<0.001
0.056
0.056
<0.001
0.004
0.004
0.300
0.933
1.233
0.029
0.788
0.817
0.073
0.824
0.897
0.085
0.614
0.699
0,097
0.865
0.962
0.195
0.453
0.648
0.080
0.569
0.649
LB Indicates less than blank.
-------
TABLE 109. FLUE GAS EMISSIONS FROM RESIDUAL OIL-FIRED UTILITY BOILERS,
SUM1ARY OF LG SEPARATION RESULTS
\l
IN3
S ^ ', X % / \
Site-Sample
/ LCI /'
LC2
LC3
LC4
LC5
l/LC6 ]
( U7 )
Total
Tangential ly Fired
21Q-XM*
211-XM*
322-XM
323- XM
ML Fired
105**
109- XR*
118-XR*
119-XR*
141-144**
3QI-XM*
324-XH
GRAV, mg/m3
TCO, mg/m3
SRAV, mg/m3
Total, ng/m3
TCO, mg/»3
GRAV, mg/m3
Total, mg/»3
TCO, mg/in3
SRAV, mg/m3
Total , mg/m3
-
SRAV, mg/m3
TCO, mg/m3
GRAV, mg/m3
Total , rag/m^
TCO, »g/»3
SRAV, mg/m3
Total, mg/m3
-
SRAV, mg/ro3
TCO, »g/»3
GRAV, mg/m3
Total, mg/m3
0.052
LB
0.096
0.096
LB
2.480
0.349
2.829
-
2.094
<0.0004
0.014
0.014
0.016
0.005
0.021
-
0.126
0.345
0.510
0,855
LB*
LB
LB
LB
0.004
LB
<0.001
0.086
0,086
-
0.708
0.001
0.010
0.011
0.005
0.002
0.007
-
<0.001
<0.001
0.002
0,002
0.010
LB
0.013
0.013
0.125
0.204
0.124
0.111
0.235
-
1.158
0.0004
0.013
0.013
0.001
0.012
0.013
-
0.118
<0.001
0.001
0.001
0.044
LB
0.016
0.016
0.005
0.153
<0.001
0.432
0,432
-
0.271
<0.0004
0.001
0.001
O.OOl"
0.010,
0.011
-
0.003
•cO.QOl
0.077
0.077
0.117
0.007
0.090
0.097
<0.001
0.223
<0.001
0.006
0.006
-
0.123
0.0004
0.016
0.016
LB
0.001
0.001
-
0.003
<0.001
0.012
0.012
0.633
0.003
0.166
0.169
0.009
1.393
0.262
1.962
2,224
-
0.807
0.012
0.296
0.308
0.002
0.419
0.421
-
<0.001
-------
TABLE 110. FLUE GAS EMISSIONS FROM GAS-FIRED UTILITY BOILERS,
SUMMARY OF LC SEPARATION RESULTS
rv»
—j
en
Site-Sample
LCI
LC2
LC3
LC4
LC5
LC6
LC7
Total
Tangenti ally-Fired
113-XR+PR
114-XR
115-XR+PR
Wall-Fired
106,108
116-XR
116-1
117-XE
TCO, mg/m3
GRAV, mg/m3
Total, rag/m3
TCO, mg/m3
GRAV, mg/m3
Total, rag/m3
TCO, mg m3
GRAV, mg/m3
Total, mg/m3
TCO, mg/ra3
GRAV, mg/m3
Total, mg/m3
TCO, mg/m3
GRAV, mg/m3
Total, mg/m3
0.897
0.092
0.989
1.169
0.614
1.783
2.057
0.247
2.304
•f
2.905
0.076
2.981
0.672
0.104
0.776
0.011
0.008
0.019
LB
<0.006
<0.006
0.017
0.008
0,025
4-
0.015
0.006
0.021
0.028
0.028
0.056
0.072
0.015
0.087
LB
<0.006
<0»006
<0.002
LB
<0.002
+
0.094
LB
0.094
0.104
0.021
0.125
0.019
0.019
0.038
LB
0.012
0.012
LB
0.008
0.008
+
0.006
0.018
0.024
0.035
0.007
0.042
0.019
0.062
0.081
LB
0.006
0.006
0.002
0.029
0.031
+
0.021
0.027
0.048
0.056
0.048
0.104
0.015
0.293
0.308
0.018
0.313
0.331
0.002
1.360
1.362
+
0.027
0.151
0.178
0.021
0.298
0.319
LB*
0.177
0.177
LB
0.229
0.229
LB
0.270
0.270
•f
0.006
0.124
0.130
0.014
0.173
0.187
1.033
0.666
1.699
1.187
1.174
2.361
2.078
1.922
4.000
3.074
0.402
3.476
0.930
0.679
1.609
*LB - less than blank.
+Did not meet criterion for LC separation.
-------
(XAD-2 extract plus module rinse or XAD-2 extract). There is no apparent
trend among the samples as to relative amounts of material appearing in
given fractions, but fractions 1, 6, and 7 appear to predominate. Fraction
1 should contain aliphatic and some halogenated aliphatic compounds. Frac-
tion 6 should contain alcohols, phenols, esters, ketones, amines, alky!
sulfur compounds, and some carboxylic acids. Fraction 7 should contain
sulfonic acids, sulfoxides, carboxylic acids, and phosphates.
Infrared Analys1s Results
Infrared (IR) spectroscopy was used to determine organic compound
classes by functional group analysis in neat sample concentrates and LC
fraction residues. Tables 111 through 114 present results of the IR analyses
of samples and LC fractions from bituminous coal-, lignite coal-, residual
oil-, and gas-fired utility boilers tested, respectively. Aliphatic hydro-
carbons, aromatics, esters, ketones, and carboxylic acids are the compound
classes typically found. Benzoates and phthalates are common contaminants,
and their presence in the spectra of the samples should be discounted.
Low Resolution Mass Spectral Results
As described in Section 5.4.3, low resolution mass spectrometric (LRMS)
analysis for compounds and compound classes was performed on any LC fraction
3
of a flue gas sample, the concentration of which exceeds 0.5 mg/m as a
source concentration. Tables 115 through 118, respectively, present results
of LRMS analyses of fractions from bituminous coal-, lignite coal-, residual
oil-, and gas-fired utility sites tested.
Results of GC/MS Analyses for Polycycllc Organic Matter (POH)
All samples subjected to TCO and/or gravimetric analyses were also
analyzed by GC/MS for POM. Tables 119 through 121, respectively, present
the results of POM analyses for the bituminous coal-, lignite coal-, and
residual oil-fired boilers tested. POM was not detected in any sample
from the gas-fired utility boilers tested.
216
-------
TABLE 111. FLUE GAS EMISSIONS FROM BITUMINOUS COAL-FIRED UTILITY BOILERS,
COMPOUND CLASSES IDENTIFIED BY INFRARED SPECTROMETRY
Sample
Number
Pulv. Dry
154-XM
205-1-XR
205-2-XR
206-XR
Pul*., Net
212-W
213-XK
218- m
336-XH
338-XM
Original Lcl
Bottom
Aliphatic compounds, *
esters, aromatlcs,
ether
Esters, glycols. Aliphatic?
adds, aroma tics,
hetere-aro»at1c,
alkanes
Esters, glycols. Allphatlcs
heterecyellcs,
alkanes
Acid, sulfane esters, Alkyl compounds,
Heterocyllcs, trace aromatics
aldehydes, a Iky Is
Bottom
Esters, glycol/ Alkyl compounds
ether, adds,
alkyTs and aryls
Alkylj, aryls, esters, Alkyl compounds
glycol or ether, acid
Alkyls, fused *
aroMtlcs, ketones
Alkyls and aromatic +
esters, ethers,
ketones; alcohols;
subst aranattcs
and olefins
Alkyl and aryl »
esters, ethers,
ketones; subst.
aromatlcs;
aliphatic;
LC2 IC3 LC4 LC5 LC6
* * * * *
* Esters, nitro- Esters, nitre- Esters, ketones, Phthalates, acids,
compound compound. n1t re-compounds nitre-compound,
aro»at1cs» hetero-aromatics
unsaturates
* Aryl and alkyl Esters, sulfonic Esters, ketones, Esters, carboxyMc
compounds acid, nitro- nitre-compound, acid, alcohol
compound alkyl phosphate
Aryl and alkyl Aroma tics, cyelo- Benzoates and Esters, aroma tics Aromatics, carboxylic
compounds hexyl derivatives other aroma tics acids
heterocyclics
* * + Phthalates Aryl esters, mainly
phthalates
4- + 4- Phthalates Esters, alcohols or
glycols
* * * * *
+ + + +• Alkyl and aryl esters,
ethers, ketones;
alcohols; subst aroma-
tics and olefins
* * * * Alkyl and aryl esters,
ethers, ketones;
subst. aromatics;
alcohols, amines, or
amides
1C?
*
Esters, acids, nitro-
compound, glycols
t
Sulfonfc and
carboxylic adds,
aromatics
Carboxylic acids,
alcohols/glycols
Esters, alcohols or
glycols, carboxylie
acids, nitro
compound
*
Alkyl and aryl esters,
ethers, ketones;
amides; subst aroma-
tics and olefins
Alkyl and aryl esters,
ethers, ketones;
subst. tromatics;
alcohols, amines, or
amides
*Did not meet erittrlan for It separation.
+Did not meet weight criterion for IR analysis,
tSample was lost during analysis,
Continued
-------
TABLE 111 (Continued)
ro
oo
Sample
Number
Cyclone
134-In-XR
134-In-C¥R
134-ln-i>R
134-Out-
XR
134-Out-
PF
207-XM
208- XM
209- XH
°$lllTe LC1 LC2 LC3
Esters, aldehydes/ Alkyl compounds Alkyl and aryl *
ketones, ethers, su1- compounds
time, alkyls, aryls
Alkyls, aryls, esters, * « *
phenol/alcohol
Alkyls, umit. * + +
aldehyde or ketone
Alkyls, aryls, * * *
car boxy tic acid,
esters
Alkyls, aryls, esters, * + *
aldehydes, ketones,
covalent sulfate
Alkyls, aryls, acids Alkyl compounds * Aryl ester
benzoate, sulfone,
sulfoxide
Alkyls, aryls, ether No activity * *
Alkyls, aryls,- Alkyl compounds * *
phthalate
LC4 LC5
* Subst. aromatics;
alcohols, esters,
ketones
* Ester, ketone, ether,
acid, alcohol
+ +
* Subst. aronatics,
esters
+ +
Phthalates Carboxylic acid,
aryl compounds
Phthalate Aromatic esters
Phthalates Phthalates
LC6
Subst. trematics;
aryl or unsat ether;
ketone, acid
Alkyl ester, ketone,
alcohols, ether
*
Aryl and alkyl esters,
alcohol, acid,
carboxylic acid salt
+
Esters, carboxylic
acids
Alcohol /jlycol, esters,
carboxylic acid and
salt, nitro compound
Phthalates, aldehydes/
ketones, carboxylic
LC?
Carboxylic acid
salt, esters
No activity
+
Aryl and alkyl esters,
alcohols, ether
+
No activity
Alcohol/glycol , ester
carboxylic acid
and salt
Esters
330-XR Alkyl ketones, esters; Alkyl compounds
aryl esters; alkyl
and aryl ethers;
alkenes; subst.
aromatics
*D1d not meet weight criterion for IR analysis.
+Did not meet weight criterion for LC separatior
Alkyl ketones, esters,
ethers; aryl esters,
ethers; subst,
aromatics; phthalates
acid salt
Alkyl and aryl ketones,
esters, aldehydes,
subst. aronatics',
alkenes; acids
331-XR Alkyl and aryl esters; *
ethers, ketones;
unsat. esters; subst.
aromatics; alcohols
* * Alkyl esters.
ethers, ketones;
aryl esters.
ethers; alkenes,
subst. aromatics;
Phthalates
Alkyl esters, ethers.
ketones; aryl esters.
ethers; subst. aroma-
tics; phthalates
Alky! and aryl esters,
ethers, ketones;
subst. aronatics;
alcohols/ phenols;
phthalates
Alkyl and aryl esters,
ketones, ethers;
subst. aromatics;
Phthalates
Alkyl and aryl esters,
ethers, ketones;
subst'. aromatics;
alcohols/phenols;
amines or amides
Continued
-------
TABLE 111 (Continued)
S»*ile
Number
Stoker
137-XH
204-XH
204-PR
204-HR
204-3
ro
10 332-XR
332-HR
332-PR
*£»' LCI LC2
Alkyl *nd aryl * *
confounds, glycols,
benzoates
Alkyl tnd aryl * *
compounds, phenol
or sulfonic acfd
ester, amide
Alkyl compounds, Alkyl confounds, *
esters, amide possible cMoro
coipound
Alkyl confounds Alkyl confounds *
Alkyl compounds. Aliphatic compounds *
subst. aroma tics aromatles
Alkyl and aryl ethers, * *
esters, ke tones;
subst, aroMtlcs;
alcohols, mines,
amides
Alkyl and aryl esters, * *
ethers, ketones
Alkyl and aryl esters, Alkyl and aryl esters, *
LC3 LC4 LC5
* Phthalates, Phtha1»tes, other
amide esters
* * *
* Alkyl ester, *
Sulfonic acid
* * *
* Subst. arooiatlcs Subst. iromatlcs
* Alkyl and aryl Alkyl and aryl esters,
esters, ethers, ethers, ketones;
ketones, phthalates
phthalates
* * *
* * *
LC6
Esters, alcohol/glycol,
ether, aromatlcs
Esters, sulfonic
acids, carboxylic
adds, subst. arotiwtics
Alkyl amides, esters,
carboxyllc acids,
alcohol
Aliphatic ester
Aromatic esters
Alky] and aryl esters,
ethers, ketones;
alcohols, amines, or
amides
A
*
LC7
Esters, alcohol/
glycol, subst.
aromatics
Esters, sulfonic
acids, carboxylic
acids
Carboxylic acid
and salts, amides
Esters, carboxylic
adds and salts
No activity
Alkyl and aryl esters,
ethers, ketones;
alcohol, amines, or
amides
*
t
332-CC
ethers, kttonesi
subst. aromaties
Alkyl esters and
ethers, aryl ethers
ethers, ketonesj
subst. aromatics;
alcohols, mines or
amides
*Did not meet wight criterion for 1C separation.
*01d not meet weight criterion for IR analysts.
-------
TABLE 112. FLUE GAS EMISSIONS FROM LIGNITE COAL-FIRED UTILITY BOILERS,
COMPOUND IDENTIFIED BY INFRARED SPECTROMETRY
Sample
Number
314-XM
314-CDS
314-PR
314-PF
314-CC
315-XM
315-PR
315-CC
315-FC
315-COS
318-XM
318-PR
318-CO
Original
Sample
Alkyl compounds,
esters, ketones,
ami nes
Alkyl compounds,
alkyl ketones
Alkyl compounds;
alkyl, aryl, unsat.
ketonts
Alkyl and aryl
compounds, ketones,
aryl or unsat.
ketones
Ketones, aryl or
unsat, esters,
alkyl compounds
Esters, alkyl and
aryl compounds,
alcohols
Alkyls; sat., unsat.
and aryl esters,
alcohols
Alkyl compounds
Alkyl compounds,
ketones, esters,
alcohols
Alkanes
Alkanes; alkyl
esters, ketones;
aramaticsi nltro
compounds; amides;
alcohols
Trace alkyl esters
Alkanes; sit. and
aryl esters; sat.
ketones
LCI
Alkyl compounds
LC2
LC3
IC4
LC5
IC6
LC?
Alkyl esters
Alkyl esters, aryl
or unsat, esters,
alkyl ketones
Alkyl compounds, unsat.
and aryl compounds
Esters, sat, and
unsat. ketones
BR
Alkanes; esters;
anomalies; sat,,
unsat., aryl
ketones; nltro
compounds
BR
Sat., unsat., aryl
ketones and esters
Esters, alky! ketones,
possible amines, amides
alcohols
Esters, nitro
compounds, possible
alcohols, phenols
Esters, nitro compounds,
possible acids,
alcohols
BR: Blank removes, same compounds present in blank.
*l)id not meet weight criterion for IR analysis.
+Did not meet neight criterion for LC separation
- Continued -
-------
TABLE 112 (Continued)
ro
Sample
Number
318-PF
Cyclone
155-XHCD
316-XM
316-PR
Stoker
317-XM
317-PR
317-CD
31 7-FC
317-CC
319-XM
Original lrl
Sample
Alkanes; sat., unsat., *
aryl esters and ketones
Traces alkanes and *
alkyl esters
Alkanes; sat., unsat., Alkanes
aryl esters and
ketones i subst.
aronattcs
Alkyl esters, alcohols, +
di-subst. aronatlcs
Alkanes; sat., unsat., *
aryl esters; alcohols
Sat., unsat, and *
aryl esters
Sat. and unsat. *
hydrocarbons
Alkanes; sit., unsat., *
and aryl ethers'
Alkanes *
Alkyl and aryl Aryl and unsat,
compounds, subst. compounds
aroma tics, ketones
esters, alcohols,
acids
LC2 LC3 LC4 LC5 LC6 LC7
-f -f ' + -f •*- -f
* * Aryls; sat. and Aryls; sat. and aryl Aryls; unsat. and aryl Aryls; ether; esters
aryl esters esters esters, ethers
* Sat., unsat., and Sat., unsat., Sat., unsat., and Sat., unsat., and aryl Sat., unsat., and
aryl hydrocarbons and aryl esters, aryl esters, and esters and ketones aryl esters and
ketones; nltro ketones ketones
compounds
•f -f + + 4 +
* * Sat., unsat., Sat., unsat., and Sat., unsat., and aryl *
and aryl esters aryl esters, and esters and ketones,
and ketones ketones alcohols
* * * * * *
* * * * * *
* * * * * *
* * • * * *
Sat. and subst. Subst. aroraatics; Sat., unsat,. Sat. esters BR Alcohols, carboxyllc
aromatks; sat., esters, ketones; and aryl ketones; acids; sat., unsat.,
unsat., aryl nltro compounds nltro compounds aryl esters, ethers
ketones and
esters
Did not meet criterion for 1C separation.
* Did not meet weight criterion for IR analysis.
-------
TABLE 113. FLUE GAS EMISSIONS FROM RESIDUAL OIL-FIRED UTILITY BOILERS,
COMPOUND CLASSES IDENTIFIED BY INFRARED SPECTROMETRY
Sample
Number
Original ... ... ._,
Sample LC< LC2 LC3
LC4 ICS LC6
LC7
Tangent i ally-Fired
Z10-XM
211 -KM
212-XRB
322-KR
322-OR
322-FC
322-3C
323-XR
323-DR
323-FC
323-CC
Alkyl and aryl Aliphatic compounds * *
compounds, esters,
alcohols/glycols,
acids
Alkyl and aryl Aliphatic compounds * *
compounds , esters ,
alconols/glycols,
acids
Esters, glycols, * , » *
carboxylic acids
Alkyl and aryl Aliphatic compounds * Alkyl or aryl
esters and ketones, esters, subst,
alcohols, subst. aromatics
aromatics, acids
Alkyl and aryl + + +
ketones, esters,
ethers; subst.
aromatics
Alkyl ketones; + + *
alkyl and aryl
ethers; subst.
aromatics
Subst. aromatics + + +
Alkyl or aryl Alkyl compounds, * *
esters and subst. aromatics
ketones, subst.
aronatics
Alkyl and aryl * + +
esters; subst.
aromatics
Subst. aronatics + + +
Subst. aromatics + + *
* Phthalates (aryl Aryl esters, alcohol/
ester) glycol, carboxylic
ester
* Phthalates (aryl Aryl esters, alcohol/
ester) glycol
* * *
* Alkyl and aryl ketones. Alcohols; acids; alkyl
esters, and ethers; and aryl ketones,
subst. aromatics esters, and ethers,
subst. aronatics
*• •*• 4
44 +
* 4 *
* * Subst. aromatics; alkyl
and aromatic ethers,
esters, and ketones
+ + +
* 4 •*•
+ » *
Esters, ethers,
Alcohol/glycol ,
carboxylic acid,
nitre compound
Esters, alcohol/
glycol, carboxylic
acids
*
Subst. arooatics; aryl
ethers, esters, and
ethers; acids,
alcohols
*
•*•
+
Subst. araMtics
*
+
*
•Did not meet weight criterion for IR spectra.
*Did not meet criterion for LC separation.
- Continued -
-------
ro
ro
to
TABLE 113 (Continued)
Sample
Number
Original
Sample
IC1
LC2
LC3
LC4
LC5
LC6
LC7
Nail-Fired
105-XR Alkyl and aromatic
compounds; phthalates
109-XR Alkyl and try!
compounds; glycols;
phthalates
118-XR Alkyl and aryl
compounds, benzoates;
acids; subst.
dramatics
Alkyl compounds,
subst. aromatics
Alkyl compounds,
benzoates
Subst. arosia- Subst, arosatics Benzoate
tics
Benzoate
Aryl esters
119-XR
324-XR
324-PR
3Z4-CD
324- 3C
Alkyl compounds, * * *
aryl esters
Aryl or alkyl ethers, Subst aromatics; * *
esters, or ketones; aryt or alkyl
subst. aromatics ethers or esters
Alcohols; alkyl or + + +
aryl esters,
ketones, subst,
aromatics
Alkyl and »ryl ethers, + * +
subst. aromatics
Subst. aromatics + + +
Benzoate, glycols,
aldehydes
Carboxylic acid;
alcohols; esters
Esters, carboxylic
acid
Glycols, carboxylic
acid» esters
Esters, glycols,
carboxylic acids
Aryl esters, alcohols
or carboxylic acid
Ketones, esters, Alkyl or aryl esters. Alcohol; aryl or Alcohol, subst.
subst. aramatics ethers, ketones; unsat. ketones, ethers, aromatfcs
sgbst. aromatics esters; subst. aromatics
*Did not meet weight criterion for IR spectra,
+Did not meet criterion for LC separation.
-------
TABLE 114. FLUE GAS EMISSIONS FROM GAS-FIRED UTILITY BOILERS,
COMPOUND CLASSES IDENTIFIED BY INFRARED SPECTROMETRY
r-o
ro
Sample Original
Number Sample
Tangential Ij-Fi red
113-W benzoate, glycol
chlorinated species
di substituted benzene
compounds
114-XR benzoate, glycol,
carboxylic acid
1H-XR benzoate, glycol,
chlorinated compound
earboxylic acid
Hall -Fired
106 alky] benzenes, acetates,
carboxylic acids
108 phthalates, benzoates,
glycol s, benzene
derivatives
116-XR esters, benzoates,
tjlycol , carboxylic
acid, other aromatics
aliphatics
117-XR aliphatic, aromatic,
esters, glycols
KRO benzoates , glycol ,
chlorocompound
LCI LC2
aliphatic and *
aromatic hydrocarbons
aliphatic and aromatic *
hydrocarbons
esters *
* *
aliphatics, benzene benzene derivatives
derivatives
aliphatic compounds *
aliphatic and *
aromatic compounds
aliphatic and *
aromatic compounds
LC3 LC« LC5 LC6
aliphatic and aromatic * benzoate, other ester alxture.
hydrocarbons and esters aronatic esters, carboxylic acids,
chlorinated compound chlorinated species,
aromatic;
* * * esters, carboxylic
acid, alcohol /glycol,
nl tro-co»pound ,
chlorinated compound
* * * aromatic esters,
alcohol/glycol
nitro- compound
* * * *
benzene derivatives benzoates benzoates benzoates, glycols,
aldehydes
* esters benzoates, other esters, alcohol/
esfers glycol
alky la ted aromatics * esters, alkyl-aryl esters, carboxylic
ether, sulfoxide acids, glycol/alcohol.
trace nitro species
alkylated aromatics * * alkyl-aryl esters,
glycol, carboxylic
acid, chloro and
nitro compounds
LC7
esters, alcohol or
glycol, carboxylic
acid, nitro conpound
esters, carboxylic
acid, alcohol/glycol,
nitro- compound,
chlorinated species
aromatic esters,
alcohol /glycol,
carboxylic acid,
nitro- compound
*
glycols, esters
esters, cirboxylic
adds, glycol,
aliphatic nitro
compound
esters, carboxylic
acids, glycols,
ary! ketone,
nitro compound
esters, carboxylic
acids, glycols,
ketones, chloro and
nitro compounds
Did not neet weight criterion for IR analysis
-------
TABLE 115. FLUE GAS EMISSIONS FROM BITUMINOUS COAL-FIRED UTILITY BOILERS,
RESULTS OF LRMS ANALYSES
ro
isa
in
Site-Sample
Pulv. , Dry
205-1-XR
205-2-XR
205-2-MR
205-2-PR
206
154
LCI LC2
Bottom
* *
* *
* *
* Polymeric
* *
t t
LC3 LC4 LC5
* * *
* * *
* * *
Polymeric Polymeric Dioctyl- **
phthalate ,
Other esters
* * *
t t t
LC6
**
Dioctyl phthalate ,
Nitro aromatics
LC7
*
Subst. nitro aromatics, *
Terephthalates
Fatty acids,
C02 at high temp
NOX at high temp
Phthalates
N and/or 0-
compounds
*
t
Phthalates
Fatty acids
Phthalates
Other esters
Fatty acids/
esters
*
t
Pulv., Wet Bottom
212
213-XM
218-XM
336-XM
* *
* *
t t
* *
* * *
* * Benzoic acid,
phthalate,
fatty acids
t t t
* * *
*
*
t
Benzoic acid,
Dioctyl phthatate,
subst. benzoic
acids
*
*
t
*
- Continued -
-------
TABLE 115 (Continued)
PO
IS5
Site-Sample LCI LC2
338-XM * *
Cyclone
134-IN * *
134-OUT- * *
XR
207-XM * *
207-PR Alkanes *
Dioctyl-
phthalate
208,209 * *
330
331 -XM * *
LC3 LC4
* *
* *
* *
* *
* *
* *
* To! ual dehyde ,
Benzoates ,
Phthalates,
Subst.
aromati c
al dehydes
LC5
*
*
Phthalates,
Benzole acid,
Aromati cs
Benzoic acid,
Phthalates,
Fatty acids
*
*
*
LC6
Benzoic acid,
subst. benzoic
acids, **
Dioctylphthalate ,
Phenol , subst.
Phenols & biphenyls
*
*
*
*
*
Dioctylphthalate**
LC7
*
*
*
*
*
*
*
- Continued -
-------
TABLE 115 (Continued)
Site-Sample
LCI
LC2
LC3
LC4
LC5
LC6
LC7
331-XMB
Stoker
137-XM
§ 204-XR
Tolualdehyde,
Benzoates,
Phenanthrene,
Subst.
aromatic
aldehydes
**
Dioctylphthalate
Benzoic acid,
Alkyl & aryl acids
S02 at high
temp., Nitro
aromatics
Phthalate, High
Wrf alcohol,
Sulfate or
sulfuric acid
S02 at high temp.
332-MX
332-PR Dioctylphthalate *
Aryl & alkyl
alcohols,
Benzoic acid,
Aromatic diacids
High MW alkyl
acids,
Dioctylphthalate
Subst. glycols
Benzoic acid,
Dioctylphthalate**,
Branched benzoic
acids
**
*Did not meet criterion for LRMS analysis.
tsample lost during analysis.
*Did not meet weight criterion for LC separation.
**Possibly from pump oil contamination.
-------
TABLE 116. FLUE GAS EMISSIONS FROM LIGNITE COAL-FIRED UTILITY BOILERS,
RESULTS OF LRMS ANALYSES
Site-Sample
Pulv., Dry Bottom
314,315,318
Cyclone
316,155
Stoker
317,319
LCI LC2 LC3 LC4 LC5 LC6 LC7
*******
*******
*******
00
*Did not meet criterion for LRMS analysis.
-------
TABLE 117. FLUE GAS EMISSIONS FROM RESIDUAL OIL-FIRED UTILITY BOILERS,
RESULTS OF LRMS ANALYSES
Site-Sample LCI LC2 LC3 LC4 LC5
Tangenti ally- Fired
142, 143, * * * * *
210, 211
LC6 LC7
* *
322-XM
K 323-XM
323-XMB
Wall-Fired
105, 109, 118,
119, 305
324
Sat. and unsat.
hydrocarbons ,
elemental sulfur,
Dioctyl phthalatet
Dioctyl phthalatet
High MW sat. and
unsat. hydrocarbons
Phthalic and
benzoic acids;
C]-C4 benzoic
acids; aliphatic
acids
*Did not meet criterion for LRMS analysis.
tPossibly from pump oil contamination.
-------
CO
O
TABLE 118. FLUE GAS EMISSIONS FROM GAS-FIRED UTILITY BOILERS,
RESULTS OF LRMS ANALYSES
Site-Sample LCI LC2 LC3 LC4
Tangenti ally-Fired
113, 114 * * * *
115-PR * * * *
Wall-Fired
106 * * * *
108-5CR * * Methyl benzophenone, Ethyl benzoate,
LC5 LC6
* *
* Butyl phthal ate,
styrene, alkane
* *
* *
LC7
*
*
*
108-XRB
116, 117
Ami no-ethylcarbazole,
Di hydroxydlmethyl-
benzaldehyde
Aromatics,
Methylbenzil
Aromatics,
Di-(methylpheny1)-
dodecane
Ami no-ethylcarbazole
Phenylpropionaldehyde,
Dimethylbenzoic acid,
glycols,
Aromatics
Aromatics, glycols
Tetramethylbi pheny1,
Amino-ethylcarbazole
Aromatics
*Did not meet criterion for LRMS analysis.
-------
TABLE 119. FLUE GAS EMISSIONS FROM BITUMINOUS COAL-FIRED
UTILITY BOILERS, POM CONCENTRATIONS
Site-Sample
Pulv. , Dry Bottom
154
205-1-XR
205-1 -PR
205-2-XR
205-2-MR
206- XR
Pulv. , Wet Bottom
212
213
218-PR
218-FC
218- XM
336
338- XM
Cyclone
1 34-out-XM
134-in-XM
POM Compound (
Biphenyl
0-phenylenepyrene
Benzo(ghi)perylene
Dibenzo(ah)anthracene
Picene
Dibenzo(ac)anthracene
Phenyl naphthalene
1,1 '-biphenyl
1,1 '-biphenyl
Naphthalene
1,1 '-biphenyl
1,1 '-biphenyl
9, 10-di hydrophenanthrene
No POM detected
No POM detected
Naphthalene
Naphthalene
Naphthalene
Biphenyl
Phenanthrene
Pyrene
Fluoranthene
Chrysene
Benzo(a) or benzo(e)pyrene
Benzol b)fl uoranthene
Indeno(l ,2,3-cd)pyrene
Benzo(ghi )perylene
No POM detected
Naphthalene
Phenanthrene
No POM detected
Decahydronaphthalene
Di-tertbutyl naphthalene
:oncentrniSn, «„/.'
<0.017
1.77
3.06
1.39
0.39
0.99
0.02
0.01
1.6
15
0.03
0.11
0.15
0.6
1.2
166
13
148
108
49
62
56
20
18
12
13.3
0.5
0.1
0.3
- Continued -
231
-------
TABLE 119 (Continued)
Site-Sample
POM Compound
Emission
Concentration,
Cyclone (continued)
207-XM
208
209
330
331-XM
Stoker
137-XM
204-FC
204-FA
332
Di methyli sopropy1naphtha!ene 0.3
Hexamethylbiphenyl 0.6
Hexamethy1hexahydroi ndacene 1.0
Dihydronaphthalene 0.03
C-jQ-substituted naphthalene 0.06
C-|Q-substituted decahydro-
naphthalene 1.0
Methyl naphthalene 1.6
Anthraeene/phenanthrene 0.3
Biphenyl 4.0
9»10-d i hydronaphthalene/1,V -
diphenylethene 0.2
l,l-bis(p-ethylphenyl)-ethane/
tetramethylbiphenyl 9.0
5-methyl-benz-c-acrid1ne 0.2
2,3-dimethy1decahydronaphthalene <0.03
Ethylbiphenyl or diphenylethane 0.3
Phenanthrene or diphenylacetylene 0.3
Methylphenanthrene 3.2
No POM detected
No POM detected
Naphthalene 59.5
Phenylnaphthalene 2.2
Naphthalene 1.9
Mixture of 3,8-dimethyl-5- 70.3
(1-methylethyl)-1,2-naphthalene
dione and trimethyl naphtha!ene
Naphthalene 0.27
Phenylnaphtha!ene 2.7
Naphthalene > 1.0 pg/g
No POM detected
232
-------
TABLE 120. FLUE GAS EMISSIONS FROM LIGNITE-FIRED UTILITY BOILERS, '
POM CONCENTRATIONS
Site-Sample
Pulv. Dry Bottom
314- XM
315-XM
318-XM
Cyclone
155-XM
316-XM
Stoker
317-XM
319-XM
Emission 3
POM Compound Concentration, vg/m
Trimethyl propenyl naphthalene
Trimethyl propenyl naphthalene
Trimethyl propenyl naphthalene
Biphenyl
Trimethyl propenyl naphthalene
Trimethyl propenyl naphthalene
No POM detected
22.9
2.3
1.8
<0.11
17.4
11.4
5.5 ANALYSIS OF TEST AND DATA EVALUATION RESULTS
5.5.1 Flue Gas Emissions
5.5.1.1 Emissions of Criteria Pollutants
The particulate, CO, and total organics emission data collected in this
sampling and analysis program are presented in this subsection for bituminous
coal-fired, lignite-fired, residual oil-fired, and gas-fired utility boilers.
In addition, 502 em''ssion data calculated from the weight percent of sulfur
in fuel are also presented for all but gas-fired utility boilers.
Bituminous Coal-fired Utility Boilers
As shown in Table 122, data variability for particulate, CO, and total
organic emissions is large for the bituminous coal-fired utility boilers
tested. The large variability for particulate emissions are the result of
inherent variability in the ash content of coal and the differences in
particulate collection efficiency of control devices.
233
-------
TABLE 121. FLUE GAS EMISSIONS FROM RESIDUAL OIL-FIRED UTILITY BOILERS,
POM CONCENTRATIONS
Site-Sample
Tangent 1 ally Fired
210
211
322-XR
322-PR
322-3C
323-XR
322-3C
Wall Fired
105
109
118-XM
119-XM
142-XM
143-XM
324-XR
Emission
POM Compound Concentration, yg/m
No POM detected
No POM detected
Naphthalene
Biphenyl
Biphenyl
Naphthalene
Naphthalene
Biphenyl
Naphthalene
No POM detected
No POM detected
2-ethyl-l,l-biphenyl
1,2, 3- tri methyl -4-propenyl naphtha! ene
Naphthalene
2-ethyl-l,1-biphenyl
Naphthalene
Phenanthridine
Trimethyl propenyl naphthalene
Phenanthrene
Fluoranthene
Pyrene
Chrysene i;
Benzo(a) or Benzo(e)pyreni
Naphthalene
Trimethyl propenyl naphthalene
Anthracene or phenanthrene
Naphthalene
Biphenyl
4.6
1.4
0.43
0.15
67.0
3.1
0.068
0.7
0.7
0.4
0.7
10
0.3
2
1
1
1
0.1
0.04
3
0.6
0.2
29
1.8
234
-------
I <-f
r.- >V^^^ TABLE 122,
v \* \,
\ \^
Combustion
Source
Type
Pulverized
Dry Bottom
>-"" ,
Pul veH zed
Met Bottom
Cyclone
All Stokers VM^-.'
J^v"
Pulverized
Dry Bottom
and Wet Bottom
/ Boilers
y
, SUMMARY OF EMISSION FACTOR DATA FOR FLUE GAS EMISSIONS
OF PARTICULATE, SO?, CO, AND TOTAL ORGAN ICS FROM
BITUMINOUS COAL-FIRED UTILITY BOILERS TESTED
Vsite)
'• 154
/ 205-1
205-2
Mean x
*(51
t$(x)/x
206
212
213
218
336
338
Mean x
t»(x)/x
132-136
207
208
209
330
331
Mean x
ts(x)/x
137
204
332
Mean x
ts(x)/x
Mean x
tt(x)/x
Mean x
Parti culatev
<"(Controlled) ^
31 Is
9.5
19.4
6.4
1.43
7.72
39.1
41.9
14.1
265
791
25.7* 193t
8.7* 126t
1 .07* 1 .68t
80.0
832
52.1
31.7
10.5
9.67
36.8* 169+
13.3* 133t
1.01* 2.02t
6.97
601
200
6.97* 269t
175t
2.80t
23.0* 135t
5.3B* 86+
0.55* . 1.47+
27.1* 169+
6.08* 65+
0.49 0.81+
Emission Factor,
SQ2
(Uncontrolled)
1090
711
768
856
118
0.59
2230
689
541
1480
877
1010
1138
255
0.58
4250
3200
376
3150
2510
3280
2794
535
0.49
616
929
1980
1175
413
1.51
1044
175
0.39
1649
278
0.36
ng/J
CO
6.2
9.4
1.6
0.73
214
<5
<5
210
39
43
136
81
1.54
«520+
8.1
400
<300+
109
97
2.04
^300
157
144
11.65
60
29
1.11
86
33
0.83
Total
Organic*
3.43 - 4.08
1.25 - 3.15
7.01 - 9*84
3.90 - 5.69
2.09
1.58
23.42 - 23.89
0.99 - 1.15
2.68 - 2.82
0.88 - 0.94
2.62 - 3.18
3.61 - 4.20
5.70 - 6.03
3.61
1.54
1.72 - 2.72
2.01 - 2.26
0.55 - 0.71
28.01 - 28.43
13.85 - 14.54
9.23 - 9.73
5.29
1.51
1.90- 2.09
9.58 - 11.76
18.98 - 19.62
10.15 - 11.16
5.07
1.96
5.10 - 5.92
2.41
0.94
7.21 - 7.96
2.11
0.56
Participate mission factor computed for boilers equipped with high-efficiency control devices only; participate
emissions greater than 100 ng/J were not Included 1n the computation.
Participate emission factor computed using all data points.
These CO data shouted large "less than" values and Mere not used 1n the computation of the mean emission factor
for CO.
235
-------
High participate emissions were associated with Site Nos. 336, 338, 207,
204, and 332. For Site Nos. 336 and 338, the pulverized wet bottom boilers
were equipped with electrostatic precipltators (ESP) designed at 99.0 percent
and previously tested at 94.5 percent efficiency. Particulate emissions from
these two sites, at 265 ng/J and 791 ng/J» indicated that the ESP for Site
No. 336 was operating near its previous tested efficiency, whereas the ESP
for Site No. 338 was operating at a particulate collection efficiency of
approximately 66 percent. For Site No. 207, the cyclorte boiler was equipped
with an ESP designed at 98 percent and previously tested at 94.3 percent
efficiency. However, particulate emissions from Site No. 207 were measured
at 832 ng/J, indicating practically no particulate removal and malfunctioning
of the ESP at the time of testing. Thus, this data point should not be in-
cluded in computing the average particulate emissions from bituminous coal-
fired cyclone boilers. For Site Nos. 204 and 332, the stokers were equipped
with multiple cyclones previously tested at 85.5 percent and 75.0-83.5 per-
cent efficiency, respectively. Particulate emissions from these two sites,
measured at 601 ng/J and 200 ng/J, showed that the multiple cyclones at
Site No. 204 were operating near the previously tested efficiency, whereas
those at Site No. 332 were operating at approximately the design efficiency
of 92 percent.
For the remaining thirteen bituminous coal-fired utility boilers tested,
particulate emissions ranged from 7 to 80 ng/J, with an average emission
factor of 27 ng/J. Particulate emissions from five of the boilers tested
were below the New Source Performance Standard (NSPS) of 13 ng/J. The
lowest particulate emission level of 7 ng/J was for Site No. 137, a stoker
unit equipped with baghouses.
Examination of the CO emission data for bituminous coal-fired utility
boilers showed that measured CO emissions varied between 6 to 400 ng/J.
High CO emissions from some of the boilers tested could be attributed to
small maladjustments in air/fuel mixing. Average organic emissions from
stokers and cyclone boilers appeared to be higher than those from pulverized
dry bottom and wet bottom boilers.
It may also be recalled that for bituminous coal-fired utility boilers,
the existing data base for criteria pollutants is generally adequate, with
236
-------
the exception that emissions of total hydrocarbons from cyclone boilers and
stokers have not been adequately characterized. Further, no source-specific
hydrocarbon emission data for these two combustion categories were available
from the existing data base. Using emission data acquired in the current
study, the variability for emissions of total hydrocarbons was calculated
to be 1.51 for cyclone boilers and 1.96 for stokers. Calculation of the
upper limit source severity factor (S ) showed that S is 0.18 for cyclone
boilers and 0.014 for stokers. Thus, the data base for emissions of total
hydrocarbons is now considered to be adequate for bituminous coal-fired
stokers but still inadequate for bituminous coal-fired cyclone boilers.
Lignite-fired Utility Boilers
Emission data for lignite-fired utility boilers are presented in Table
123. Data variability for particulate, SO.,, and total organic emissions is
again large. Variability in SOg emissions is due to differences in the
sulfur content of lignite. Variability in CO emissions was not computed
as all but cne data point for CO emissions was reported as "less than"
values.
For particulate emissions, data from Site Nos, 314 and 315 indicated
that the multiple cyclones for either pulverized dry bottom boilers removed
no particulates at the time of sampling. Both boilers have now been equipped
with ESP's. For Site No. 316, the multiple cyclones were found to be opera-
ting at near 53 percent efficiency instead of the 89.5 percent design effi-
ciency. Particulate emissions, from all three lignite-fired utility boilers
equipped with multiple cyclones were therefore relatively high. However, the
other four lignite-fired utility boilers tested were equipped with high-
efficiency ESP's. Particulate emissions from these four boilers ranged from
0.45 to 1.74 ng/J, all substantially below the current NSPS of 13 ng/J.
Organic emissions were between 2.4 to 18.9 ng/J, but there are insufficient
data to determine whether emissions were higher for any particular boiler type.
As discussed in Section 5.1, the existing data base for emissions of
particulates and total hydrocarbons from lignite-fired utility boilers is
inadequate, as no source-specific data were available. Since only a limited
number of lignite-fired utility boilers have been tested, data variability
237
-------
TABLE 123. SUMMARY OF EMISSION FACTOR DATA FOR FLUE GAS EMISSIONS OF PARTICULATES, SO,,,
CO, AND TOTAL ORGANICS FROM LIGNITE-FIRED UTILITY BOILERS TESTED C
ro
CO
O>
Combustion
Source
Type
Pulverized
Dry Bottom
Cycl one
All Stokers
All Lignite-
fired
Boilers
Site
No.
314
315
318
Mean x
s(x} .
ts(x)/x
155
316
Mean x
s(x}
ts(x)/x
317
319
Mean x
s(x} .
ts(x)/x
Mean x
s(x)
ts(x)/x
Parti culates
(Controlled)
2920
1509
1.74
1.74* 1494t
843t
2.43t
1.20
0.45
0.83
0.38
5.78
897
0.66
0.66* 449t
448t
12.69t
1.01* 769t
0.29* 426t
0.91* 1.36t
Emission
S02
(Uncontrolled)
350
190
760
6p3
nro'
1.69
910
620
/765>
S*5'
2.41
1130
980
fl055~7
— I*/
0.90
706
129
0.45
Factor, nfl/J
CO
<200
<200
<360
<253
9.0
<230
120
<320
<320
<320
<234
Total
Organi cs
18.19 - 18.88
4.45 - 5.58
2.75 - 3.98
8.46 - 9.48
4.72
2.14
3.23 - 3.77
5.28 - 6.59
4.26 - 5.18
1.41
3.46
2.39 - 4.14
No data
2.30 - 4.14
6.03 - 7.16
2.39
0.86
Particulate emission factor computed for boilers equipped with high-efficiency control devices
only; particulate emissions greater than 100 ng/J were not included in the computation.
Particulate emission factor computed using all data points.
-------
for emissions of particulates and total hydrocarbons is large. Therefore,
the data base characterizing the emissions of these two criteria pollutants
1s still inadequate. For the other criteria pollutants, the existing data
base for NOX, CO, and SOg emissions has been determined to be adequate
(Section 5.1), with the exception that NO emissions from stokers have not
r\
been adequately characterized. The latter 1s not considered to be a serious
deficiency as lignite-fired stoker units are being phased out of usage.
Residual Oil-fired Utility Boilers
For residual oil-fired utility boilers, emission data for particulates,
SOg, CO, and total organics from tangentlally-fired and wall-fired units
have been grouped together in Table 124 for evaluation, as there is no
statistical difference between the mean emission factors of the two boiler
types.
Of the eleven residual oil-fired utility boilers tested, particulate
emissions from seven were below the NSPS of 13 ng/J, and the mean emission
factor is 19.3 ng/J. S02 emissions, calculated from the fuel sulfur con-
tent, ranged from 78 to 1130 ng/J. The mean SOg emission factor is 448 ng/J,
corresponding to an average sulfur content of 1.03 weight percent in
residual oil. The mean emission factors for CO and total hydrocarbons are
28 ng/J and 4.64 ng/J, respectively. Data variability for emissions of
particulates, SOg, and CO 1s below 0.7, whereas data variability for total
organic emissions is 0.71. Although the existing data base for emissions
of criteria pollutants from residual oil-fired utility boilers has been
judged to be adequate, emission data collected in the current study can be
combined with existing data to provide better estimates of mean emission
factors.
Gas-fired Utility Boilers
For gas-fired utility boilers, emission data for particulates, CO, and
total organics from tangentlally-fired and wall-fired units have been
grouped together in Table 125 for evaluation, because the two sets of emis-
sion data are not statistically different. Particulate emissions from all
the gas-fired utility boilers tested were well below the NSPS of 13 ng/J,
as would be expected. Emissions of CO from two of the boilers tested,
239
-------
TABLE 124. SUMMARY OF EMISSION FACTOR FOR FLUE GAS EMISSIONS OF PARTICULATES, S0«» CO,
AND TOTAL ORGANICS FROM RESIDUAL OIL-FIRED UTILITY BOILERS TESTED *
ro
•js.
O
Combustion Site
Source No.
Type
Tangent! ally- 210
fired 211
322
323
Wall -fired 105
109
118
119
141-144
305
324
Mean x
s(x)
ts(x)/x
Parti culates
7.39
24.3
57.1
45.4
6.87
6.65
3.93
9.44
7.5
1.99
42.1
19.3
5.9
0.68
Emission Factor,
S02
(Uncontrolled)
330
290
990
1120
180
140
180
120
78
370
1130
448
126
0.63
ng/J
CO
<10
< 9.4
<44
<55
<210*
<230*
<19
<29
6.6
<250*
<47
28
6.8
0.58
Total
Organl cs
1.84 - 3.30
0.66 - 0.80
1.98- 3.24
14.23 - 15.49
No Data
8.23 - 9.96
0.94 - 2.01
0.45 - 2.47
0.28 - 0.58
10.35 - 11.79
1.40 - 2.73
4.04 - 5.24
1.65
0.71
These CO data showed large "less than" values and were not used 1n the computation of the mean
emission factor for CO.
-------
TABLE 125. SUMMARY OF EMISSION FACTOR DATA FOR FLUE SAS EMISSIONS OF PARTICIPATES,
CO, AND HYDROCARBONS FROM GAS-FIRED UTILITY BOILERS TESTED
Combustion
Source Type
Tangentl ally-
fired
Wall -fired
Site
No.
113
114
115
106
106
116
117
Mean x
s(xl
ts(x)/x
Parti culates
0.080
0.044
0.014
1.40
6r Al !3
.01 3"
0.164
-------
however, were relatively high. The mean emission factors for participates,
CO, and total hydrocarbons are 0.25 ng/J, 72 ng/J, and 2.69 ng/J, respect-
ively.
Since data variability for emissions of participates and total hydro-
carbons all exceeds 0.7, upper limit source severity factors (Su) were
calculated to determine adequacy of the data base. Using emission data
acquired 1n the current study, S was calculated to be 0.007 for particulate
emissions and 0.076 for total hydrocarbon emissions from tangentially-fired
boilers. For wall-fired boilers, Su was calculated to be 0.003 for particu-
late emissions and 0.037 for total hydrocarbon emissions.
In Section 5.1, the existing data base for emissions of NOX, CO, and
SOg from both tangentially-fired and wall-fired boilers has been judged to
be adequate. On the other hand, the existing data base for emissions of
particulates from both boiler types and total hydrocarbons from tangentially-
fired boilers has been judged to be inadequate. With the inclusion of
current data, the data base characterizing emissions of particulates from
both boiler types is now considered to be adequate as S < 0.05. The data
base for emissions of total hydrocarbons from tangentially-fired boilers,
however, is still inadequate.
Comparison of Criteria Pollutant Emission Factors
In Table 126, the emission factors for bituminous coal-fired utility
boilers calculated from data collected in this program and the emission
factors derived from existing data are compared with the EPA AP-42 emission
factors (36). Whenever reference information on number of observations and
standard deviation of observations is available for EPA AP-42 emission
factors (35), the AP-42 data have been incorporated into the existing data
base. Thus, the existing data base compiled contains all AP-42 data that
are properly referenced as well as other available source test data. The
most extensive data base is obtained, of course, when existing data are
combined with the emission data from the current study. Emission factors
from combined existing data and current study should generally be considered
more reliable than the EPA AP-42 emission factors.
242
-------
TABLE 126. COMPARISON OF CRITERIA POLLUTANT EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
ro
CO
Combustion
Source
Type
Pulverized
Dry Bottom
Pul verl zed
Wet Bottom
Cyclone
All Stokers
Emission Factorj
Data Source
Current Study
Existing Data
Combined Existing Data & Current Study
EPA
Current Study
Existino Data
Combined Existing Data & Current Study
EPA
Current Study
Existing Data
Combined Existing Data & Current Study
EPA
Current Study
Existing Data
Combined Existing Data & Current Study
EPA
NO
X
No Data
259*. 379t
259*. 379t
352
No Data
380
380
586
No Data
678
678
1075
No Data
241
241
293
Hydrocarbons
5.5
3.6
4.5
5.9
5.5
3.6
4.5
5.9
9.5
No Data
9.5
5.9
10.7
No Data
10.7
19.5
CO
ng/J
Parti culates
SO?
(Controlled) (Uncontrolled)
9.4
18.4
16.8
19.5
136
11.7
86.3
19.5
109
28.2
82
19.5
157
No Data
157
39.1
19.4
- 266+
251
281+
25.7**, 193tt
214+
213
215*
36.8
59.2+
56.9
44+
6.97**, 269tt
662*
603
716+
16 49+*
1407+*
1407+*
1424
1649++
1407++
140 7++
1424
1649++
1407++
1407+*
1424
1649++
1407+*
1407**
1424
For tangentially-fired boilers.
f For wall-fired boilers.
by applying average partlculate control efficiencies presented in Section 3 for different types of boilers; also,
emission factors are based on a national average of 14.09 percent ash in bituminous coal.
Partlculate emission factor computed for boilers equipped with high-efficiency control devices.
Partlculate emission factor computed using all data points.
** S02 emission factors for both current study and existing data were computed by assuming conversion of 93.86 percent of fuel
sulfur to SOg. The only difference between the SOg emission factors is due to the difference in fuel sulfur content. The
combined SOg emission factor is therefore the same as the existing data S02 emission factor, which was calculated based on
a national average of 1.92 percent sulfur in bituminous coal.
-------
The EPA and existing data emission factors for N0¥ are In reasonably
3\
good agreement for bituminous coal-fired pulverized dry bottom boilers and
stokers. However, the existing data NO emission factors for bituminous
"
coal-fired pulverized wet bottom and cyclone boilers are lower than the
corresponding EPA emission factors. For emissions of total hydrocarbons and
S02» there 1s good agreement among the current study, existing data, and EPA
emission factors for all bituminous coal-fired source categories. CO emis-
sion factors determined using data from the current study are generally
higher than the existing data and EPA CO emission factors, probably because
all current study emission data were acquired during normal boiler operation
and the boilers sampled were not readjusted to achieve optimum combustion
efficiency. The current study particulate emission factors are lower than
the existing data and EPA particulate emission factors. This 1s because
controlled particulate emissions are highly dependent on the collection
efficiency of control devices, and a greater proportion of the boilers
sampled were equipped with high-efficiency control devices.
In Table 127, the emission factors for Hgnite-flred utility boilers
calculated from data collected in this program and the emission factors
derived from existing data are compared with the EPA AP-42 emission factors
(36). The existing data NO emission factor for pulverized dry bottom
J\
boilers is in good agreement with the EPA emission factor, but the existing
data NO emission factors for cyclone boilers and stokers are lower than
^>
the corresponding EPA NO emission factors. The existing data NO emission
X A
factor of 55 ng/J for lignite stokers is based on only one data point, and
appears to be too low. For this case, the EPA emission factor should be
considered more representative.
No existing data for hydrocarbon emissions from lignite-fired utility
boilers were located. The EPA hydrocarbon emission factors are based on
the similarity of lignite combustion to bituminous coal combustion and
very limited data, and hence should be considered less reliable than the
emission factors determined in the current study. Similarly, no existing
data for CO and particulate emissions were located. In these cases,
however, CO emissions from the current study were reported as "less than"
values, whereas particulate emission data from the current study appear to
244
-------
TABLE 127. COMPARISON OF CRITERIA POLLUTANT EMISSION FACTORS
FOR LIGNITE-FIRED UTILITY BOILERS
Combustion
Source Data Source
Type
Pulverized Current Study
Dry Bottom Existing Data
Combined Existing Data &
EPA
Cyclone Current Study
Existing Data
Combined Existing Data &
EPA
All Stokers Current Study
Existing Data
Combined Existing Data &
EPA
Eor tangential ly-fl red boilers.
f For wall-fired boilers.
* EPA AP-42 emission factors were the
**
Participate emission factor computed
ft Partlculate emission factor computed
Emission Factor,
Current
Study
NO
No Data
260
260
Hydrocarbons
8.97
No Data*
8.97
261*. 456t <33
Current
Current
Study
Study
only source of
No Data
333
333
554
No Data
55
55
195
4.72
No Data*
4.72
<33
4.37
No Data*
4.37
33
CO
<253 1
No Data*
<253
32.6
<120
No Data*
<120
32.6
<320 0
No Data*
<320
65.1
ng/J
Participates
(Controlled)
.74**, 1494tt
No Data*
1.74, 1494
62**
0.83
No Data*
0.83
132**
.66**, 449tt
No Data*
0.66, 449
615**
S02
(Uncontrolled)
706***
628***
628***
625ttt
706***
628***
628***
625ttt
706***
628***
628***
625ttt
existing data.
for boilers equipped with
high-efficiency control devices.
using all data points.
Calculated by applying average participate control
also, emission factors are based on
efficiencies
a national average of 13.49
SO? emission factors for both current study
Na20
presented 1n Section
3 for different types of boilers;
percent ash In lignite. „. n
and existing data were computed by using
S02 (ng/J) -
1157 (1 - 0.772
*4>s
factors 1s due to difference 1n fuel sulfur content. The combined SOg emission factor 1s therefore the same as the existing
data S0£ emission factor, which was calculated based on a national average of 0.64 percent sulfur 1n lignite.
m Calculated by assuming 0.64 percent sulfur and 15,352 kJ/kg (6,600 Btu/lb) heating value for lignite.
-------
be highly biased. The control devices at two of the 11gn1te-f1 red boilers
tested, for example, exhibited no particulate removal at the time of
sampling. For these reasons, the EPA CO and particulate emission factors
sh0.tild P«*"viriP hPttPr* estimates pf ..avqrj£L* JgHlSllfin*^ trg_llgflift>-flf.Af<
-u±<11fly hn1kr^_Tho current study, existing data, and EPA S02 emission
factors are 1n good agreement because they were all computed using essen-
tially the same fuel sulfur to S02 conversion factor. The only difference
between the current study and existing data SOg emission factors 1s due to
difference in average fuel sulfur content.
For residual oil-fired and gas-fired utility boilers, the emission
factors calculated using data acquired in the current study and the emis-
sion factors derived from existing data are compared with the EPA AP-42
emission factors in Table 128. Except for residual oil wall-fired boilers,
there is generally good agreement between the existing data and EPA NO
X
emission factors. The existing data N0¥ emission factor for residual oil
A
wall-fired boilers, estimated to be accurate within t 10 percent, 1s based
on 57 data points and should be considered better than the EPA emission
factor.
Hydrocarbon emission data for residual oil-fired or gas-fired utility
boilers are not available from existing information sources. The current
study hydrocarbon emission factors for both oil- and gas-fired boilers are
higher than the corresponding EPA emission factors. Since the quality of
the data sources for the EPA hydrocarbon emission factors cannot be readily
assessed, the current study hydrocarbon emission factors should be consi-
dered more reliable.
For emissions of CO and particulates from oil- and gas-fired boilers,
the emission factors based on combined existing and current study data
should again be considered more reliable than the EPA emission factors.
This is because the data base for CO and particulate emissions 1s now
adequate and the basis for the EPA emission factors is not well documented.
The current study and existing data S0« emission factors for oil-fired
boilers were computed by assuming conversion of 95.2 percent of fuel sulfur
to SOg, and agree well with the EPA SQo emission factor. SOg emission data
246
-------
TABLE 128. COMPARISON OF CRITERIA POLLUTANT EMISSION FACTORS
FOR RESIDUAL OIL- AND GAS-FIRED UTILITY BOILERS
Combustion
Source
Type
Residual
Oil-fired
Gas-fired
•
Data Source
Current Study
Existing Data
Combined Existing Data & Current Study
EPA
Current Study
Existing Data
Combined Existing Data & Current Study
EPA
NOX
No Data
. 114*. 190t
ii4*. asot
147*. 3Wt
No Data
124*. 233t
124*. 233t
126*. 294t
Emission Factor,
Hydrocarbons CO
4.64*-"" 28
No Data* 67.4
4.64 56
2.9 15
SM? 72
No Daw 14.6
£*%? 32.6
0,42 17
ng/J
Partlculates
19.3
31.6
29.5
39.2
0.245
No Data*
0.245
2-6
so2
448**
448**
448**
476
No Data
No Data*
No Data
0.25
For tangentl ally-fired boilers.
f For wall-fired boilers.
* ran no At
SO? emission factors for both current study and existing data were computed by assuming conversion of 95.22 percent of
fuel sulfur to SOg. The average sulfur content for the 11 residual oil-fired boilers tested was 1,03 percent, Identical
to the national average residual oil sulfur content.
-------
for gas-fired boilers are not available from either the current study or
existing information sources. However, the EPA S02 emission factor of 0.25
ng/J should provide an adequate estimate, as the sulfur content of natural
gas is too low to merit any significant concern.
The above discussion shows that in most cases, emission factors based
on combined existing and current study data provide the best estimate of
average emissions from any combustion source category. The best estimates
of average emission factors for criteria pollutants are summarized in Table
129. By comparison, the New Source Performance Standards (NSPS) for NO
/\
emissions are: 260 ng/J for bituminous coal-fired boilers, 260 ng/J for
lignite-fired dry bottom boilers and stokers, 340 ng/J for lignite-fired
cyclone boilers, 130 ng/J for residual oil-fired boilers, and 86 ng/J for
gas-fired boilers (162). Thus, average NO emissions from bituminous coal
rt
tangentially-flred dry bottom boilers, bituminous coal-fired stokers, all
lignite-fired boilers, and residual oil tangentially-fired boilers are lower
than the NSPS, whereas average N0¥ emissions from the other types of utility
"
boilers are all greater than the NSPS. The NSPS for particular matter limits
emissions to 13 ng/J. Average emissions of particulate matter from bituminous
coal-, lignite-, and residual oil-fired utility boilers all exceed the NSPS.
The exception is gas-fired utility boilers with average emissions of parti-
culate matter of 0.25 ng/J. Average emission factors for S0£i as presented
in Table 129, are for uncontrolled emissions. For bituminous coal-fired
utility boilers, a 90 percent reduction in the average uncontrolled S02
emissions is required to meet the NSPS. For lignite-fired utility boilers,
an 88 percent reduction in the average uncontrolled SOp emissions is required
to meet the NSPS. Average uncontrolled SOp emissions from residual oil-fired
boilers, at 448 ng/J, would have to be reduced to 86 ng/J to meet the NSPS.
No reduction in SOg emissions is required for gas-fired utility boilers, as
the average SQy emission factor for these sources is only 0.25 ng/J.
Source Severity
The significance of the emissions of criteria pollutants from utility
boilers can be assessed using the source severity concept. The source
severity concept has been discussed in Section 5.2, and detailed methods
for the calculation of source severity factors are described in Appendix A.
248
-------
TABLE 129. BEST ESTIMATES OF AVERAGE EMISSION FACTORS FOR CRITERIA POLLUTANTS
to
Combustion
Source
Type
Bituminous Coal
Pulverized Dry Bottom
Pulverized Wet Bottom
Cyclone
All Stokers
Lignite
Pulverized Dry Bottom
Cyclone
All Stokers
Residual Oil
Tangenti ally-fired
Wall -fired
Natural Gas
Tangenti ally- fired
Wall -fired
NOX
259*. 379t
380
678
241
260
333
195
114
190
124
233
Emi
Hydrocarbons
4.5
4.5
9.5
10.7
8.97
4.72
4.37
4.64
4.64
2.43
2.43
ssion Factor,
CO
16.8
86.3
82
157
32.6+
32.6+
65.1 +
56
56
32.6
32.6
ng/J
*w
Participates
251
213
57
603
62+
132+
615+
29.5
29.5
0.245
0.245
S02
(Uncontrolled)
1407
1407
1407
1407
628
628
628
448
448
0.25
0.25
**
For tangentlally-fired boilers.
For wall-fired boilers.
Based on EPA AP-42 emission factors.
k
Controlled for bituminous coal-fired and lignite-fired sources, uncontrolled for residual
oil-fired and aas-fired sources.
-------
Basically, the source severity factor is defined as the ratio of the calcu-
lated maximum ground level concentration of the pollutant species to the
level at which a potential environmental hazard exists. Source severity
factors below 0.05 are deemed insignificant.
Source severity factors for the criteria pollutants have been calculated
using the recommended emission factors. The calculated source severity
factors, as presented in Table 130, indicate that nitrogen oxides and sulfur
dioxide (except for gas-fired boilers) are principal pollutants of concern
requiring control. For bituminous coal-fired and lignite-fired utility
boilers, source severity factors for controlled particulate emissions range
from 0.12 to 0.66, indicating that evaluation of additional control needs
for particulate emissions may be required. The source severity factor for
uncontrolled particulate emissions from residual oil-fired boilers is 0.17
for tangentially-fired units and 0.06 for wall-fired units. It may also be
noted that source severity factors calculated using the NSPS of 13 ng/J for
particulate emissions are all below 0.1. In general, comparison of source
severity factors shows that the environmental impacts of emissions of
criteria pollutants are greater for bituminous coal-fired and lignite-fired
boilers, lesser for residual oil-fired boilers, and much less for gas-fired
boilers.
5.5.1.2 Size Distribution of Particulate Emissions
Size distribution data for particulate emissions from bituminous coal-
fired sites with particulate control devices are presented in Table 131.
Data are presented in terms of four aerodynamic size fractions: 1} larger
than 10 ym; 2) 3 pm to 10 pm; 3} 1 urn to 3 um; and 4} less than 1 pm.
The predominant type of control device utilized by the boilers tested is
the ESP. Seven of the nine pulverized coal-fired sites tested utilized ESP's.
Only one of the six cyclone sites tested employed a wet scrubber while the
other five used ESP's. Of the three stoker fired sites tested, one employed
a baghouse while two used mechanical collectors. Hence, tabulated emission
data are strongly biased with respect to control device type; stoker emission
data are biased toward mechanical control device behavior while all other
emission data are biased toward ESP behavior. This is an important fact to
note since data presented in Section 5.3.1.2 (Table 49} indicate that the
250
-------
TABLE 130. MEAN SOURCE SEVERITY FACTORS FOR CRITERIA POLLUTANTS
ro
01
Combustion
Source
Type
Bituminous Coal
Pulverized Dry Bottom
Pulverized Wet Bottom
Cyclone
All Stokers
Lignite
Pulverized Dry Bottom
Cycl one
All Stokers
Residual 011
Tangential ly-f 1 red
Wall -fired
Natural Gas
Tanaentl ally- fired
Wall-fired
Hean Severity Factor
NOX
1.95*, 2.85t
1.70
6.36
0.13
4.28
5.33
0.14
1.90
1.17
3.21
2.94
Hydrocarbons
0.027
0.016
0.072
0.0048
0.12
0.061
0.002
0.060
0.022
0.052
0.026
CO
0.0005
0.0015
0.0030
0.0003
0.002
0.002
0.0002
0.0035
0.0013
0.0031
0.0015
Particulates
0.66
0.33
0.19
0.12
0.36
0.74
0.15
0.17
0.061
0.0021
0.0010
S02
(Uncontrolled)
2.64
1.57
3.29
0.19
2.57
2.50
0.11
1.79
0.66
0.0015
0.0007
For tangentially-fired boilers.
For wall-fired boilers.
Controlled for bituminous coal-fired and lignite-fired sources, uncontrolled for residual
oil-fired and gas-fired sources.
-------
TABLE 131. CONTROLLED PARTICULATE EMISSIONS SIZE DISTRIBUTION DATA
FROM BITUMINOUS COAL-FIRED UTILITY BOILERS TESTED
l\3
tn
Site Control
No. Device
Bituminous Pulverized Dry
205-1 ESP
205-2 ESP
154 Wet scrubber
Mean x
Standard deviation of
the mean s(x)
Variability ts(x)/x
Bituminous Pulverized Wet
206 ESP
212 ESP
213 ESP
336 ESP
338 ESP
218 Wet scrubber
Mean x
Standard deviation of
the mean s(x)
Variability ts(x)/x
Bituminous Cyclone Boilers
134 Wet scrubber
207 ESP (not working)
208 ESP
209 ESP
330 ESP
331 ESP
Mean x
Standard deviation of
the mean s(x)
Variability ts(x)/x
Bituminous Stokers
1 37 Baghouse
204 Mechanical
332 Mechanical
Mean x
Standard deviation of
the mean s(x)
Variability ts(x)/x
Participate Emissions, ng/J (!)+
>10 psi 3-10 ysi
1-3
MB
<1 tin Total
Bottom Boilers
25.7
5.27
...
15.5
10.2
8.26
Bottom Boilers
0.108
8.67
3.81
137
510
132
98.0
2.06
4.8
* 421
10.5
12.5
2.07
0
6.0
2.4
1.11
0
193
75.3
89.4
56.2
2.70
(81.7)+
(56.5)
(68.6)
(13.1)
(2.43)
(1.4)
(22.2)
(9.1)
(51.7)
(64.5)
(29.8)
(12.2)
(1.14)
(6)
(50.6}
(20.1)
(39.5)
(19.7)
(17.1)
(6.83)
(1.11)
(32.1)
(37.7)
(23.3)
(11.7)
(2.16)
3.74
1.03
- —
2.39
1.35
7.18
0.958
11.5
13.5
102
235
...
72.6
44.5
1.70
0.8
302
14.3
9.37
2.34
2.01
5.8
2.6
1.26
0
253
81.6
111.5
74.6
2.88
(11.9)*
(10. B)
(11.3)
(0.550)
(0.618)
(12.4)
(29.4)
(32.2)
(38.5)
(29.7)
(28.4)
(4-33)
(0.423)
(1)
(36.3)
(27.5)
(29.6)
(22.3)
(20.8)
(20.2)
(5.07)
(0,70)
(42.0)
(40.8)
(27.6)
(13.8)
(2.15)
0.490
2.34
1.41
0.925
8.33
4.99
15.7
22. 1
20.7
38.2
—
20.3
5.28
0.736
8.8
93.3
14.2
6.21
2.76
1.09
6.6
2.3
0.98
3,10
74.2
17.1
31.5
21.7
2.97
(1.5)+
(24.6)
(13.1)
(11.5)
(11-1)
C64.7)
(40.2)
(52.8)
(7.8)
(4.8)
(34.1)
(12.0)
(0.977)
(11)
(11.2)
(27.3)
(19.6.)
(26.3)
(11.3)
(19.1)
(3.51)
(0.51)
(44.5)
(12.4)
(8.6)
(21.8)
(11.4)
(2.25)
1.54
0.866
—
1.16
0.292
3.20
1.66
3.22
2.47
5.25
8.15
...
4.15
1.16
0.776
65.6
15.4
13.1
3,59
3.34
6.57
18.4
11.9
1.79
3.87
81.2
25.8
37.0
23.0
2.68
(4.9)+
(9.1)
(7.00)
(2.10)
(3.81)
(21.5)
(8.2)
(5.9)
(2.0)
(1.0)
(7.72)
(3.68)
(1.32)
(82)
(1.9)
(25.1)
(11.3)
(31.8)
(67.9)
(43.6)
(13.4)
(0.85)
(55.5)
(13.5)
(12.9)
(27.3)
(14.1)
(2.22)
31.47
9.50
17.3
7.72
39.1
41.9
265
791
14.1
80.0
832
62.1
31.7
10.5
9.67
6.97
601
200
(100)+
(100)
(100)
(100)
(100)
(100)
(100)
(100)
(100)
(100)
(100)
(100.1)
(100)
(100)
(100)
(100)
Data from this site were not used tn the computation of x and s(x).
^Nunber shorn tn the brackets refers to the percentage of total partlculate emissions
found in that site fraction.
-------
various participate control devices exhibit distinct removal characteristics
with respect to different size fractions. Owing to the limited variety of
control devices tested, average data presented in Table 131 have been ob-
tained without regard to the type of control device used. Emissions data
are presented in terms of a ng/J emission factor as well as the percentage
of total particulate emissions.
Data variability generally exceeds 0.7 for either the emission factor
data or the percentage of total emissions. Hence, the particulate size
distribution data base for bituminous coal-fired units is considered in-
adequate. The principal reason for the large variabilities observed appears
to be the large variation in collection efficiencies of the control devices
utilized. Removal efficiencies were estimated based upon total particulate
emission factors for uncontrolled units (Section 5.5.1.1), controlled
emission measurements, and coal ash analyses. Control efficiencies of ESP's
appeared to vary from zero to 99.8 percent. Sites exhibiting markedly low
control efficiencies are Site 207 (essentially no removal), Site 338
(approximately 66 percent), Site 208 (approximately 85 percent), and Site
336 (approximately 89 percent). Under normal operating conditions, an ESP
should yield approximately 99 percent removal. The wet scrubber at Site 134
had an efficiency of 91 percent, which is somewhat lower than anticipated
on the basis of data presented in Section 5.3.1.2.
Particulate emission data for bituminous coal-fired stoker tested also
show a substantial range of collection efficiencies. The mechanical collec-
tion devices at Sites 204 and 332 had efficiencies of approximately 73 and
91 percent, respectively. On the other hand, the baghouse at Site 137
appeared to have a collection efficiency in excess of 99 percent.
Data presented in Table 131 indicate that sites with lower efficiency
control devices (i.e., wet bottom Sites 336 and 338, cyclone Site 207, and
stoker Sites 204 and 332) tend to have a larger portion of the particulate
material In the coarser size fractions than do sites with higher efficiency
devices for the same furnace type. This would be expected since uncontrolled
particulate emission size distributions are substantially weighted toward
the coarse fractions (Table 48, Section 5.3.1.2). As a result of this
observation, it is apparent that data variances will increase as the range
of efficiencies increases for a specified control device.
253
-------
Participate size distribution data were also evaluated after grouping
data with respect to control device efficiency and after grouping data with
respect to total emissions. Furnace firing type was disregarded during
these evaluations. The result of these approaches was to reduce data
variability somewhat because, in general, the percentage of particulates
in the coarse size fractions will increase with increasing total particu-
lates. However, despite the simplifying assumptions which eliminated the
variable of furnace firing type, these evaluations both indicated that the
particulate size distribution data base is inadequate. Therefore, it
appears that additional data are required for ESP's as well as other control
devices for each firing type in order to provide an adequate data base.
Size distribution data for particulate emissions from controlled
lignite-fired sites are presented in Table 132. Mechanical control devices
were used at the three sites for which fine particulate emissions were
measured. Variability of the lignite-fired dry bottom data generally
exceeds 0.7 and the data base is, therefore, inadequate. No data were
obtained for lignite-fired cyclones and only one set of data was obtained
for lignite-fired stokers. Hence, data bases for these categories are also
inadequate.
Size distribution data for particulate emissions from uncontrolled
oil-fired sites are presented in Table 133. As would be expected due to
normalization, variability is lower for percentage emissions data than for
emission factor data. However, data variability generally exceeds 0.7 and,
consequently, the data base for residual oil-fired utility boilers is consi-
dered inadequate. It should be noted that the data base for particulates
known to exhibit the greatest penetration into the pulmonary air spaces, name-
ly those smaller than 1 pm, is adequate in terms of both the emission factor
data and the percentage of total particulates. The emission factor for
this size fraction is 11.2 ng/J which corresponds to 61 percent of the total
particulates from oil firing.
In Table 134, size distribution data for particulate emissions from the
current study are compared with existing data. It may be recalled that
from the existing data base (Section 5.3.1.2), only limited particulate size
distribution data are available for bituminous coal-fired pulverized dry
254
-------
TABLE 132. CONTROLLED PARTICULATE EMISSIONS SIZE DISTRIBUTION DATA
FROM LIGNITE COAL-FIRED UTILITY BOILERS TESTED
Site
No.
Lignite
314
315
318
Mean x
Standard
of the
Variabil
Lignite
316
155
Lignite
317
319
Control
Device
Pulverized Dry
Mechanical
Mechanical
ESP
deviation
mean s(x)
ity ts(x)/x
Cyclone Boilers
ESP
ESP
Stokers
Mechanical
ESP
>10 vm
Bottom Boil
1630
(56.5)*
794
(50.9)
___
1222
(53.7)
428
(2.80)
4.45
(0.663)
—
...
531
(59.2)
Participate
3-10 ym
ers
1016
(34.8)*
614
(39.4)
---
815
(37.1)
201
(2.30)
3.13
(0.788)
...
-__
122
(13.6)
Emissions,
1-3 ym
193
(6.6)*
134
(8.6)
___
163
(7.6)
29.5
(1.00)
2.30
(1.67)
...
___
43.5
(4.9)
nq/J («)*
<1 pm
61.3
(2.1)*
17.2
(1.1)
---
39.3
(1.6)
22.1
(0.50)
7.15
(3.97)
...
...
200
(22.3)
Total
2920
(100)*
1559
(100)
1.74
(100)
0.45
(100)
1.20
(100)
897
(100)
0.66
(100)
*
Number shown in the brackets refers to the percentage of total participate
emissions found in that size fraction.
255
-------
TABLE 133. PARTICULATE EMISSIONS SIZE DISTRIBUTION DATA FROM
RESIDUAL OIL-FIRED UTILITY BOILERS TESTED
Site
No.
210
211
322
323
141-144
105
109
118
119
305
324
Mean x
Standard deviation
of the mean s(x)
Variability ts(x)/x
>10 pm
0
7.13
(29.4)
0
0
—
0.267
(3.9)
0.251
(3.8)
—
___
0
0
0.956
(4.6)
0.883
(3.6)
2.18
(1.85)
Partlculate
3-10 pm
0
3.24
(13.4)
20.9
(36.6)
25.8
(56.8)
<0.581
(8.5)
0.925
(13.9)
—
0.115
(5.8)
25.0
(59.3)
9.57
(24.3)
4.24
(8.3)
1.05
(0.808)
Emissions^
1-3 pin
0.579
(7.9)*
3.79
(15.6)
10.7
(18.7)
0.939
(2.07)
—
0
0.264
(4.0)
—
_-_
0.571
(28.7)
1.04
(2.5)
2.23
(9.9)
1.28
(3.6)
1.36
(0.860)
ng/J (*)*
<1 pm
6.81
(92.1)*
10.1
(41.6)
25.5
(44.7)
18.7
(41.1)
--_
6.02
(87.6)
5.21
(78.3)
—
—
1.30
(65.5)
16.1
(38.2)
11.2
(61.1)
2.88
(8.0)
0.608
(0.310)
Total
7.39
(100)*
24.3
(100)
57.1
(100)
45.4
(100)
7.5
(100)
6.87
(100)
6.65
(100)
3.93
9,44
1,99
(100)
42.1
(100)
Number shown in the brackets refers to the percentage of total participate
emissions found in that size fraction.
256
-------
TABLE 134. COMPARISON OF CURRENT STUDY AND EXISTING SIZE DISTRIBUTION
DATA FOR PARTICULATE EMISSIONS
tn
-xl
Combustion
Source Type
Pulverized
Bituminous
Dry Bottom
B1 tuml nous
Cycl one
B1 tuml nous
Stoker
Residual
on
Control
Device
ESP
ESP
ESP
ESP
Wet Scrubber
Wet Scrubber
Multlclone
Multl clone
Fabric Filter
Fabric Filter
None
None
Data Source
Current Study
Existing Data
Current Study
Existing Data
Current Study
Existing Data
Current Study
Existing Data
Current Study
Existing Data
Current Study
Existing Data
Particulate Emissions
>10 ym
15.5
19
6.3
1.3
4.8
<0.51
134
148
0
<1.5
4.2
0.96
3-10 vm
2.39
4.6
7.0
2.4
0.8
<0.54
167
27
0
<0.1
9.0
9.57
1-3 ym
1.41
2.5
6.1
2.9
8.8
0.8
45.7
58
3.1
0.3
7.7
2.23
, ng/J
<1 pm
1.16
1.7
6.7
2.1
65.6
17
53.5
35
3.87
1.6
11
11.2
Total
20.5
27.8
26.1
8.7
80.0
19
400
268
6.97
2-3.5
32.0
24.0
-------
bottom boilers, cyclone boilers and stokers, and for residual oil-fired
boilers, and no data are available for other combustion source categories.
Comparison of emission data shows that there is reasonably good agreement
between current study and existing particulate size distribution data for
pulverized bituminous coal-fired dry bottom boilers equipped with ESP's, and
for residual oil-fired boilers. For bituminous coal-fired cyclone boilers
and stokers, particulate emissions in each of the four size fractions deter-
mined in the current study appear to be generally higher than those indicated
by existing data.
5.5.1.3 Emissions of ParticulateSulfate and S03
Particulate sulfate emissions were measured at nearly all bituminous
coal, lignite, and oil-fired sites tested during this program. Measurements
of SOg emissions were made at a limited number of sites only (coal-fired
Sites 135-136 and oil-fired Sites 143 and 322-324). Detailed descriptions
of the analytical procedures are presented in Section 5.4.3. However, it
should be noted that particulate sulfate analyses involve a hot concentrated
aqua regia extract of the particulate catch. Hence, reported sulfate values
include adsorbed and aerosol JUSQ., metallic sulfates and ammonium sulfate.
Coal Firing Emission Data
Data for particulate sulfate emissions, mostly collected after control
devices from coal-fired sources, are presented in Table 135. Included in the
table are fuel sulfur and ash contents, excess oxygen concentration, parti-
culate sulfate emission factor and the percentage of fuel sulfur converted
to particulate sulfur. As discussed in Section 5.3.1.3, the average percent-
age conversion of fuel sulfur to particulate sulfur is the parameter which
will be utilized for discussion purposes and for computing mean emission
factors. However, the physical significance of this parameter is somewhat
diminished by the fact that these are mostly emissions data acquired at the
outlet of various control devices.
The emission control devices used at these sites are primarily ESP's
although wet scrubbers were utilized at Site 218, a wet bottom site, and at
Site 135, a cyclone site. Of the three stoker sites tested, Site 137 utilized
a baghouse while Sites 204 and 332 utilized mechanical control devides.
Particulate emission data from Site 207 indicate that, although equipped
258
-------
TABLE 135. PARTICULATE SULFATE EMISSION DATA FROM
BITUMINOUS COAL-FIRED UTILITY BOILERS TESTED
tn
10
Site
No.
Bituminous Pulverized Dry
205-1
205-2
154
Mean x
Standard deviation of the
Variability ts(x)/J
Bituminous Pulverized Met
206
212
213
336
338
218
Mean I
Standard deviation of the
Variability ts(I)/x
Bituminous Cyclone Boilers
135
135
207
208
209
330
331
Mean I
Standard deviation of the
Variability ts(x)/x
Bituminous Stokers
J37
204
332
Mean x
Standard deviation of the
Variability ts{*)/x
Fuel
S,
%
Bottom Boilers
1.14
1.23
--
mean s(x}
Bottom Boilers
3.39
1.00
0.80
1.40
1.63
2,33
mean s(x)
5.45
5.45
4.01
0.46
4.09
3.44
4.31
mean s(x)
0.94
1.42
2.60
mean s{I)
Fuel
Ash,
V
14.0
13.4
—
14.4
14.0
12,9
9.76
9.19
10. B
26.56
26.56
14.10
6.72
11.50
13.66
17,00
7.72
10.0
9.50
Control Device
ESP
ESP
—
ESP
ESP
ESP
ESP
ESP
Het Scrubber
None
ESP
ESPt
ESP
ESP
ESP
ESP
Baghouse
Mechanical
Mechanical
0,,
c
1,
8,58
8.72
9.60
9.46
9.76
9.81
8.0
8.4
6.23
6.0
6,0
12.2
10.5
7.4
7.3
10,1
11.1
10,0
9.19
Emission
Factor,
ng/J
0.581
0.156
-r
0.369
0.213
7.33
0.278
0.316
0.317
4.49
4.16
—
1.91
0.986
1.43
22.2*
3.8
3.8*
13.3
0.297
0.743
5.7!
4.77
2.35
1.36
0.176
13.0
16.2
9.79
4.90
2.15
Percent of
Fuel Sulfur in
Partlculate
Sul fate
0.0510
0.0127
--
0.0319
0.0191
7,61
0.00777
0.0287
0.0367
0.320
0.256
--
0.130
0.0655
1.40
0.326*
0.0558
1.63*
2.21
0.00590
0.0185
0,109
0,480
0,433
2.50
0.0178
0.873
0.510
0.467
0.24B
2.29
Uncontrolled emissions data from sites 135 and 207 are not Included in averages.
Particulate emission data indicate that ESP was actually removing little or no participates during the test period.
-------
with an ESP, little or no participate removal occurred during the test
period. Because of this apparent control device malfunction, data from Site
207 have not been included in the computation of average emissions from con-
trolled sources.
Controlled particulate sulfate emissions from pulverized bituminous
coal-fired dry bottom units were 0.369 ng/J which correspond to 0.0319 per-
cent of the sulfur in the fuel feed. Emissions from wet bottom units were
1.91 ng/J which correspond to 0.130 percent of the fuel sulfur. Mean con-
trolled emissions from cyclone and stoker units were somewhat higher at 4.77
ng/J and 9.57 ng/J, respectively. These emissions correspond to 0.480 percent
and 0.467 percent of the fuel sulfur, respectively. The higher controlled
emissions from stokers is due to the fact that two of the three sites tested
utilize mechanical particulate control devices which have a relatively low
collection efficiency when compared to ESP's or baghouses.
Emission data variability exceeds 0.7 for all bituminous coal-fired
source categories. High data variability may result from several factors,
including differences in collection efficiencies among the various control
devices and varying excess oxygen levels. Differences in fuel sulfur contents
could also be a factor, especially if particulate sulfate is not derived
primarily from reaction between SOg and ash components. However, the existing
data base for uncontrolled particulate sulfate emissions from pulverized
bituminous coal-fired dry bottom and wet bottom boilers is adequate. Con-
trolled particulate sulfate emissions from these two source categories may be
estimated by assuming equal removal efficiencies for particulate and parti-
culate sulfate emissions. For bituminous coal-fired cyclone boilers and
stokers, both the existing data base for uncontrolled particulate sulfate
emissions and the current study data base for controlled emissions are in-
adequate.
Data for controlled particulate sulfate emissions from pulverized coal-
fired sites compare reasonably well with existing emission data when an
*
average particulate sulfate collection efficiency of 94 percent is assumed .
*
1978 data indicate a national average particulate collection efficiency of
94 percent for pulverized bituminous coal-fired units (Section 4). It is
further assumed that the average particulate sulfate collection efficiency
is equal to the average particulate collection efficiency of 94 percent.
260
-------
In making the comparison, average uncontrolled particulate sulfate emissions
were first computed from division of the average controlled emissions by
(1 - fractional collection efficiency). On uncontrolled basis, the data
presented in Table 135 indicate 0.53 percent conversion of fuel sulfur to
particulate sulfate for dry bottom units while existing data indicate 0.67
percent conversion. With the same assumptions, data in Table 135 indicate
2.17 percent conversion in wet bottom boilers while existing data indicate
0.67 percent conversion. It should be noted that exact agreement between
measured and existing data for uncontrolled emissions from wet bottom units
would imply an average collection efficiency of 81 percent. Based upon
measured particulate emission data and uncontrolled particulate emission
data from AP-42, the average efficiency of control devices utilized at wet
bottom boiler sites appear to be approximately 88 percent. An average effi-
ciency of 88 percent would indicate 1.08 percent conversion and would agree
with existing data within a factor of two.
No existing particulate sulfur emission data were found for bituminous
coal-fired cyclones or stokers. The measured emission factor for cyclone
units, however, appears to be high. An average collection efficiency of 92
percent in conjunction with cyclone data in Table 135 would imply six per-
cent conversion of fuel sulfur to particulate sulfate (uncontrolled basis),
which is excessive. Such a high measured emission factor is the result of
inclusion of the data point from Site 208. Exclusion of this data point,
which could be justified by the method of Dixon applied to the percent con-
version data, would yield an average controlled emission factor corresponding
to 0.047 percent conversion of the fuel sulfur to particulate sulfate. This
emission factor in conjunction with an average collection efficiency of 92
percent would imply 0.59 percent conversion of fuel sulfur to particulate
sulfate (uncontrolled basis), which appears reasonable based on existing and
measured data from pulverized coal-fired sites.
Average emission factors and mean source severity factors for particu-
late sulfate emissions from controlled bituminous coal-fired sites are pre-
sented in Table 136. Tabulated data are based on average values of percent
1978 data indicate a national average collection efficiency of 92 percent
for cyclone units (Section 4).
261
-------
TABLE 136. EMISSION AND SOURCE SEVERITY FACTORS FOR PARTICIPATE SULFATE
EMISSIONS FROM BITUMINOUS COAL-FIRED UTILITY BOILERS
1
Firing Type Emission Factor Mean Severity
(Controlled), ng/J Factor
Pulverized Coal
Dry bottom
Wet bottom
Cyclone
Stoker
0.374S
1.52 S
5.63 S
5.47 S
0.15
0.37
2.84
0.161
*
Emission factors are expressed 1n terms of S, the percent sulfur In
fuel on a moist (as-fired) basis. A higher heating value of 25,587
kJ/kg (11,000 Btu/lb) has been assumed.
fuel sulfur 1n controlled emissions as presented In Table 135. Emission
factors are presented in terms of S, the percent sulfur in coal on an as-fired
basis. An average higher heating value of 25,587 kJ/kg was assumed for bitu-
minous coal. Based on the national average bituminous coal sulfur content
of 1,92 percent, mean source severity factors exceed 0.05 for all categories.
This appears to justify concern regarding particulate sulfate emissions from
these sources and indicates a need for further evaluation of emission control
methods.
SOg data were obtained at one bituminous coal-fired cyclone site (Site
135-136). The fuel sulfur content during testing was 5.45 percent and a six
percent excess 02 level was maintained. An average emission factor (uncon-
trolled basis) of 48.5 ng/J was measured, which corresponds to 0.85 percent
conversion of fuel sulfur to S03. This compares well with the existing SO-,
data base which indicates 0.74 percent conversion of fuel sulfur to SOg. A
summary of SQg emission factor data and severity factors for bituminous coal-
fired units is presented in Table 137. The variability of the combined SO?
data base is less than 0.7 indicating that the data is adequate. The high
severity factors presented in the table indicate that SO., emissions from
these units present a potential environmental hazard.
262
-------
TABLE 137. S03 EMISSION DATA FROM BITUMINOUS COAL-FIRED CYCLONE BOILERS
Data
Source
Existing
data
Current
study
Combined
data
Percent of
Fuel Sulfur
in §03,
X
0.740
0.855
0.753
Standard
Deviation
of the mean
s(x)
0.0584
>_
0.0530
Variability
ts(x)/x
0.187
—
0.162
Emission
Factor*,
ng/J
7.23 S
8.35 S
7.36 S
Mean
Severity
Factor
4.38
5.05
4.45
k
Emission factors are presented in terms of S, the percent sulfur in coal on
a moist (as-fired) basis. An average higher heating value of 25,587 kJ/kg
(11,000 Btu/lb) has been assumed.
Data for particulate sulfate emissions from lignite-fired utility
sites are presented in Table 138. Particulate emission control devices were
either ESP's or multiple cyclones. Variabilities of emission data from pul-
verized dry bottom and stoker units are substantially higher than 0.7. There-
fore, these data bases are inadequate. The data base for lignite-fired cyclones
consists of a single point and is also Inadequate. The principal reasons for
the large data variabilities observed are the limited number of data points
for each firing type category and the difference between particulate collec-
tion efficiencies achieved with ESP's and multiple cyclones. Additional
data are needed for all lignite-fired source categories.
Particulate sulfate emission factors and mean source severity factors
based upon available lignite firing data are presented in Table 139. Emission
factors are presented 1n terms of S» the fuel sulfur content on an as-fired
basis and an average higher heating value of 15,352 kJ/kg for lignite.
Severity factors for all lignite-fired furnace categories exceed 0.05,
indicating that particulate sulfate emissions from these sources pose a
potential problem. However, it should be noted that the emissions data base
263
-------
TABLE 138. PARTICIPATE SULFATE EMISSION DATA FROM LIGNITE COAL-FIRED UTILITY BOILERS TESTED
Site Fuel Fuel Control Flue Gas
No. S, Ash, Device 0?»
% % %
Lignite Pulverized Dry Bottom Boilers
314 0.35 7.13 Multiple cyclone 4.94
315 0.21 6.02 Multiple cyclone 4.7
318 0.97 8.81 ESP 11.9
Mean x
Standard deviation of the mean s(x)
Variability ts(x)/x
Lignite Cyclone Boilers
316 0.60 9.87 ESP 7.0
155 NO
Mean x
Standard deviation of the mean s(x)
Variability ts(x)/x
Lignite Stokers
317 1.18 8.37 Multiclone 10.9
319 0.94 7.97 ESP *
Mean x
Standard deviation of the mean s(x)
Variability ts(x)/x
Emission
Factor
ng/J
3.21
3.78
0.989
2.66
0.851
1.38
0.486
ND
0.486
__
--
170
0.439
85.2
84.8
12.7
Percent of
Fuel Sulfur 1n
Parti cul ate
Sul fate
0,466
0.985
0.0657
0.506
0.266
2.26
0.0392
ND
0.0392
—
--
7.57
0.0225
3.80
3.77
12.6
concentration assumed to be the same as at Site 317.
-------
TABLE 139. EMISSION AND SOURCE SEVERITY FACTORS FOR
PARTICIPATE SULFATE EMISSIONS FROM
LIGNITE FIRED UTILITY BOILERS
Firing Type Emission Factor* Mean Severity
(Controlled), ng/J Factor
Pulverized Coal
Dry Bottom t
Cyclone
Stoker
1.28 S
0.766 S
74.3 S
0.378
0.219
0.932
*
Emission factors are expressed 1n terms of S, the percent sulfur in
fuel on a moist (as-fired) basis. A higher heating value of 15,352
kJ/kg is assumed.
fBased on Site 318 data only.
must be improved before valid conclusions can be drawn based upon severity
factor computations.
011 F_1 ri ng Emi s s 1 on Data
Data for uncontrolled particulate sulfate emissions from oil-fired sites
are summarized in Table 140. A mean emission factor of 3.43 ng/J was measured
which corresponds to 0.480 percent conversion of fuel sulfur to particulate
sulfate. Variability of the data is less than 0.7 indicating the adequacy
of the data base. Agreement between the measured and existing data bases is
only fair; the existing data base indicates 1.59 percent conversion of fuel
sulfur to particulate sulfate. However, it should be noted that oil burned
at the sites tested contained an average of only 20 ppm vanadium while oil
burned during acquisition of data for the existing data base contained 240
to 260 ppm vanadium. Since vanadium is known to catalyze fuel sulfur oxida-
tion, this order-of-magnitude difference in average vanadium content is
probably responsible for the observed differences in conversion of fuel sulfur
to particulate sulfate.
265
-------
TABLE 140. PARTICULATE SULFATE EMISSION DATA FROM
RESIDUAL OIL-FIRED UTILITY BOILERS TESTED
Site
No.
10S
109
118
119
143
30S
322
323
324
Mean x
Standard
Variabil
Flue Gas
02.
%
7.03
8.35
5.09
10.93
5.66
9.19
7.10
10.3
8.15
deviation of
ity ts(x)/x
Fuel
Sulfur,
%
0.42
0.33
0.41
0.28
0.18
0.86
2.27
2.57
2.60
the mean s(x)
Fuel
V,
ppm
3.4
1.1
4.4
3.0
1
43
67
30
25
Emission
Factor
ng/J
3.64
0.884
<0.042
<0.074
1.30
0.989
>7.75
8.64
7.53
3.43
1.19
0.800
Percent of
Fuel Sulfur in
Parti cul ate
Sul fate
1.26
0.391
0.00167
0.0386
1.05
0.168
>0.498
0.490
0.423
0.480
0.143
0.687
Emission factors and mean source severity factors for oil-fired utility
boilers are presented in Table 141. Emission factors are computed from percent-
age conversion data presented in Table 140 assuming a national average higher
heating value of 43,760 kJ/kg for residual oil. Mean source severity factors
for oil-fired utility boilers exceed 0.05 indicating that particulate sulfate
emissions represent a potential environmental problem. Data measured during
this program and existing data indicate a need for evaluation of particulate
sulfate (i.e., particulate) emission controls applicable to oil-fired units.
S03 emission data from oil-fired units are presented in Tabla 142. These
data indicate SO^ emissions of 15.3 ng/J which corresponds to 1.32 percent
conversion of fuel sulfur to SO.,. Variability of the data is less than 0.7,
266
-------
TABLE 141. EMISSION AND SOURCE SEVERITY FACTORS FOR PARTICULATE
SULFATE EMISSIONS FROM OIL-FIRED UTILITY BOILERS
*
Firing Type Emission Factor Mean Severity
ng/J Factor
Tangentially-fired
Wall -fired
3.29 S
3.29 S
1.48
0.548
*
Emission factors are expressed in terms of St the percent sulfur in
fuel. A higher heating value of 43,760 kJ/kg is assumed.
TABLE 142. S03 EMISSION DATA FROM RESIDUAL OIL-FIRED UTILITY BOILERS TESTED
Site
No.
322
323
324
143
Mean x
Standard
Variabil
o2,
7.6
10.3
8.3
5.66
deviation of
ity ts(x)/x
Fuel
Sul fur
2.27
2.57
2.60
0.18
the mean s(x)
Fuel
V,
ppm
67
30
25
1
Emission
Factor
ng/J
11.8
20.7
27.5
1.14
15.3
5.71
1.19
Percent of
Fuel Sulfur
in S03
?>!$ 0.910
-05 1.41
l0-6' 1.85
£*>$ i.n
7^( 1.32
0.204
0.492
267
-------
Indicating adequacy of the data base. Existing data indicate 2.86 percent
conversion of fuel sulfur to SCU. As with particulate sulfate data, the
difference between measured and existing S03 emission data bases is probably
the result of the factor of ten difference in average fuel vanadium concen-
trations.
A summary of SOg emissions data from this program and from the existing
data base is presented in Table 143. The combined data base represents an
improvement over the individual data bases in that it reflects S03 emissions
with fuels of widely varying vanadium concentrations (1 to 260 ppm). More-
over, the variability of the combined data base is less than 0.7. As such,
the SO, data base for oil-fired utility boilers is considered adequate.
Mean source severity factors presented in Table 143 substantially exceed
0,05 indicating that S03 emissions from residual oil-fired utility toilers
constitute a serious health hazard.
TABLE 143.
FROM RESIDUAL OIL-FIRED UTILITY BOILERS
Data
Source
Existing
Data
Current
Study
Combined
Data
Percent of
Fuel Sulfur
in S03
2.86
1.32
2.42
Variability
ts(x)/x
0.352
0.492
0.332
Emission
Factor*
ng/ J
16.3 S
7.54S
13.8 S
Mean Severity
Tangentially-
fired
8.81
4.06
7.43
Factor
Wall-
fired
3.27
1.51
2.76
Emission factors are presented in terms of S, the percent sulfur in fuel on
an as-fired basis. A national average higher heating value of 43,760 kJ/kg
was assumed for residual oil.
268
-------
5-5.1.4 Emissions of Trace Elements
Emissions of trace elements were measured at all bituminous coal-fired,
lignite-fired, residual oil-fired, and gas-fired utility boilers sampled in
this project. Detailed descriptions of the analytical procedures employed
are presented in Section 5.4.3. In general, with the exception of mercury,
arsenic, antimony, fluoride and chloride determinations, all trace element
analyses were performed using spark source mass spectrometry (SSMS). SSMS
is a semiquantitative elemental survey analysis technique based on Level I
procedures, and is on the average only accurate to within a factor of 2 to
3. As such, data acquired using SSMS are not suited for enrichment factor
and mass balance calculations, and mean emission factors determined using
SSMS data are less accurate than emission factors determined using more
reliable techniques such as atomic absorption spectrometry.
Bituminous Coal-fired Utility Boilers
Trace element emissions data for the bituminous coal-fired sources
tested are presented in Tables 144, 145, 146, and 147 for pulverized dry
bottom boilers, pulverized wet bottom boilers, cyclone boilers, and stokers,
respectively. All trace elements that were emitted at any single site in
amounts above 50 yg/m are Included in these tables. Trace elements that
2
are particularly hazardous (defined here as those with TLV < 1 mg/m ) are
also included.
As shown in these tables, data variability for trace element emissions
is large for all bituminous coal-fired source categories. This is not
surprising because of the differences in trace element contents of various
coals and differences 1n the efficiency of particulate control devices.
In the evaluation of data and calculation of mean emission factors, emission
data from each source category have been subgrouped according to control
device type. For example, one of the cyclone boilers tested was equipped
with a wet scrubber while the other five tested were equipped with electro-
static precipitators, and mean trace element emission factors were calculated
for each control device type.
Analysis of the data Indicated that of the trace elements present 1n
bituminous coal, aluminum, calcium, chlorine, fluorine, iron, potassium,
269
-------
TABLE 144. SUMMARY OF EMISSION AND SOURCE SEVERITY FACTORS OF TRACE ELEMENT EMISSIONS
FROM PULVERIZED BITUMINOUS COAL-FIRED DRY BOTTOM UTILITY BOILERS TESTED
IN3
•xl
o
Emission Factor,
Trace Element
Aluminum (AT)
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorint (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Ma)
Nickel (Hi)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Site
154
40
1.7
38
200
0.048
<0.92
4,400
0.53
ND
0.39
5.3
5.8
1.5
110
0
100
0.77
720
13
1.7
NO
45
120
1.2
0.14
3.6
<430
0.92
240
0.24
0.34
4.2
360
Site
205-1
233
21
76
11
0.19
40
no
0.80
66,000
45
3,430
76
2,280
10,000
9.5
67
0.81
857
381
171
309
2,480
57
3.3
0.48
12
1,480
4.1
8.1
<1.3
<0.76
8.6
22
pg/J
Site
205-2
111
13
1.1
5.3
<0.048
5.1
154
0.62
56,600
37
1,690
21
3,320
7,700
9.6
72
0.17
226
169
202
255
1,930
79
2.6
3.4
10
260
59
2.2
<1.0
<0.72
6.3
30
Mean
Emission
Factor x.
pg/J
128
12
38
72
0.095
21
1,550
0.65
61,300
27
1,700
34
1,870
5,900
6.4
80
0.58
601
188
125
282
1,490
85
2.4
1.3
8.5
720
21
83
0.85
0.61
6.4
139
Boilers Equipped
With Met Scrubber
Mean Emission
Factor x, pg/J
40
1.7
38
200
0.048
<0.92
4,400
0.53
—
0.39
5.3
5.8
1.5
100
0
100
0.77
720
13
1.7
—
45
120
1.2
0.14
3.6
<430
0.92
240
0.24
0.34
» 4.2
360
Mean Severity
Factor
0.002
<0.001
0.003
0.071
0.005
<0.001
0.100
<0.001
—
<0.001
0.002
0.006
<0.001
0,003
0
<0.001
0.008
0.025
<0.001
<0.001
..
0.093
0.249
0.002
<0.001
0.004
<0.009
<0.001
0.017
<0.001
<0.001
0.002
0.025
Boilers Equipped H1th ESP
Mean Emission
Factor x,
pg/J
172
17
39
8.4
0.12
23
132
0.71
61,300
41
2,560
48
2,800
8,850
9.6
69
0.49
541
275
187
282
2,200
68
3.0
1.9
11
868
32
5.1
1.2
0.74
7.5
29
ts(x)
X
4.526
3.336
12.34
4.641
7.581
9.832
2.150
1.611
0.975
1.336
4,330
7.319
2.353
1.646
0.067
0.513
8.298
7.398
4.911
1.051
1.222
1.586
2.076
1.507
9,561
1.073
8.900
11.05
7.278
1.657
0.343
1.961
3.106
Hean
Severi ty
Factor
0.007
0.007
0.003
0.003
0.012
<0.001
0.003
< 0.001
1.859
0.084
1.053
0.050
0.231
0.235
0.039
<0.001
0.005
0.019
0.011
0.008
0.001
4.534
0.141
0.004
<0.001
0.012
0.018
0.003
<0.001
<0.001
<0.001
0.003
0.002
Upper Limit
Severity
Factor Sy
0.038
0.030
0.0)4
0.019
0.105
0.005
0.009
0.002
3.671
0.197
5.615
0.041
0.774
0.621
0.042
< 0.001
0.043
0.156
0.067
0.016
0.002
1.173
0.433
0.010
0.008
0.024
0.177
0.039
0.003
0.001
0.001
0.009
0.006
-------
TABLE 145. SUMMARY OF EMISSION AND SOURCE SEVERITY FACTORS OF TRACE ELEMENT EMISSIONS FROM
PULVERIZED BITUMINOUS COAL-FIRED WET BOTTOM UTILITY BOILERS TESTED
IV)
Trace Element
Aluminum (A1)
Arsenic (As)
Boron (B)
Barium (Ba)
Beryl Hun (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (CD*
Cobalt (Co)
Chrowlwi (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (L1)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Ho)
Sodium (Na)
Nickel (N1)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (u)
Vanadium (V)
Zinc (Zn)
Emission Factor, pg/J
Site
206
160
6.6
4.1
2.3
0,38
16
58
0.80
12,800*
1.5
37
10
8.0
658
2.3
75
1.4
108
3.2
3.0
56
32
40
1.9
<0.47
2.4
188
1.6
1.8
<1.4
<1.0
1.0
4.7
Site
212
NO
19
29
41
0.73
0.49
374
0.24
ND
4.7
146
5.3
28
175
1.1
447
8.3
121
27
31
418
160
92
3.8
0.15
3.19
1,460
1.6
16
0.49
0.29
7.8
6.8
Site
213
ND
19
20
42
0.44
1.1
434
0.27
ND
8.3
877
13
27
3,120
1.8
536
6.8
463
78
88
385
634
88
3.3
0.19
4.5
828
3.0
18
0.54
0.36
7.8
9.3
Site
218
48
33
3.1
45
<0.037
o.n
149
0.037
4.8
<0.037
0.26
1.0
4.5
74
0.067
12
0.26
16
0.41
1.2
4.5
0.48
26
<0.48
0.074
5.2
8.9
0.074
1.1
<0.15
-------
TABLE 146. SUMMARY OF EMISSION AND SOURCE SEVERITY FACTORS OF TRACE ELEMENT EMISSIONS FROM
BITUMINOUS COAL-FIRED CYCLONE UTILITY BOILERS TESTED
ro
^4
ro
Emission Factor, pg/J
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Ha)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (ho)
Sodium (Na)
Nickel (Hi)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Site
135
1,100
350
0.67
120
0.37
ND
730
210
77
4.7
46
72
23
4,900
2.1
3,800
4.1
ND
54
58
ND
20
230
1,100
99
33
15,300
9.3
14
ND
34
30
7,700
Site
207*
ND
63
2,270
208
11
3.5
12,000
3.5
ND
42
2,400
120
246
20,200
12.6
2,650
70
7,580
366
259
884
1,330
2,080
82
3.0
5.3
36,600
11
152
6.3
4.8
114
505
Site
208
575
2.7
575
319
0.26
<3.2
5,750
1.3
ND
26
784
8.4
73
4,130
1.7
272
6.3
518
73
28
ND
429
225
3.1
0.63
1.1
1,150
2.4
194
<4.1
<2.8
12
17
Site
209
275
4.9
172
6.1
0.45
2.7
451
0.49
ND
27
2,300
9.8
13
6,150
2.2
156
2.8
107
135
156
170
861
45
2.2
0.37
3.0
1,350
4.1
4.9
0.63
0.64
14
31
Site
330
no
12
91
12
0.083
2.1
95
0.15
ND
13
290
19
7
2,320
4.1
99
0.83
58
23
116
NO
869
70
2.2
0.083
0.91
621
1.3
2.8
0.15
<0,11
3.5
41
Site
331
ND
5.5
57
2.1
0.10
1.3
21
0.47
ND
16
503
10
2
2,390
7.6
37
ND
23
78
51
ND
571
34
1.7
<0.052
6.2
363
2.7
0.67
<0.31
<0.21
1.4
15
Mean
Emission
Factor x
pg/J
650
75
179
92
0.25
2.3
1,410
42
77
17
784
24
24
3,980
3.5
873
3.5
176
73
82
170
550
121
222
20
8.8
3,760
4.0
43
1.3
7.6
12
1,560
Boilers Equipped
With Met Scrubbers*
Mean Emission
Factor x,
pg/J
1,100
350
0.67
120
0.37
ND
730
210
77
4.7
46
72
23
4,900
2.1
3,800
4.1
ND
54
58
ND
20
230
1,100
99
33
15,300
9.3
14
ND
34
30
7,700
Mean
Severity
Factor
0.054
0.180
<0.001
0.062
0.048
ND
0.019
0.270
0.003
0.012
0.024
0.093
0.002
0.162
0.011
0.018
0.048
NO
0.003
0.003
ND
0.051
0.591
1.885
0.051
0.042
0.393
0.001
0.001
ND
0.044
0.015
0.495
Boilers Equipped with ESP
Mean
Emission
Factor x
pg/J
425
6.4
224
85
0.22
2.3
1,580
0.60
ND
20
968
12
24
3,750
3.9
141
3.3
176
77
88
170
682
94
2.3
0.28
2.8
872
2.6
50
1.3
0.94
7.7
26
x
4.497
1.045
1.699
2.926
1.218
0.560
2.808
1.293
ND
0.533
1.491
0.646
2.237
0.768
1.104
1.124
2.079
2.076
0.942
1.061
ND
0.510
1.512
0.406
1.523
1.394
0.837
0.699
3.007
2.307
2.138
1.285
0.718
Mean
Severity
Factor
0.021
0.003
0.019
0.044
0.029
<0.001
0.041
<0.001
ND
0.053
0.498
0.015
0.002
0.124
0.020
<0.001
0.039
0.008
0.004
0.005
<0.001
1.754
0.240
0.004
<0.001
0.004
0.022
<0.001
<0.001
<0.001
0.001
0.004
0.002
Upper Limit
Severity
Factor
Su
0.116
0.007
0.050
0.171
0.064
<0.001
0.155
0.002
ND
0.081
1.240
0.025
0.008
0.219
0.042
0.001
0.119
0.023
0.008
0.009
ND
2.649
0.604
0.006
<0.001
0.009
0.041
<0.001
0.017
0.003
0.004
0.009
0.003
NO - Hot determined.
Data from Site 207 were not included 1n the computation of mean emission factors because the ESP at Site 207 was malfunctioning
at the time of sampling and no particulate removal was effected.
The boiler at Site 135 was equipped with wet scrubber for particulate and $03 removal. The boilers at other sites were
equipped with ESP.
-------
TABLE 147. SUMMARY OF EMISSION AND SOURCE SEVERITY FACTORS OF TRACE ELEMENT EMISSIONS
FROM BITUMINOUS COAL-FIRED UTILITY STOKERS TESTED
ro
«M
to
Trace Element
AlurffiM (Al)
Arsenic (As)
Boron (6)
Barium (Ba)
Beryl HUB (Be)
Broil ne (Br)
Calclup (Ca)
CuMw (Cd)
Chlorine (Cl)
Cobalt (Co)
Chrmlwi (Cr)
Copper (Cu)
Fluorine (F)
Iron (ft)
Mercury (Ho)
Potutlw (K)
Llthlw (LI) .
NNMslM Hj)
Manganese (Nn)
Molybdenum (No)
Sodlw (ta)
Ntcfctl (HI)
Phosphorus '(P)
Lead (tt>)
Antimony (Sb)
Stlenlu* (Se)
Silicon (SI)
Tin (Sn)
StrontlMi (Sr)
Thorium (Th)
Uranium (U)
Vamdiw (V)
Zinc (Zn)
Emission Factor,
Site
137
35
0.33
40
2.9
0.055
0.30
49
0.14
ND
1.0
66
2.5
10
247
2.0
<14
<0.055
«16
7.7
9.9
214
71
4.8
1.1
0.08
<1.4
25
0.77
0.38
<0.49
<0.33
0.27
3.1
Site
204
2,620
2,400
240
153
2.4
4.8
3,540
1.B
73.900
98
1,040
147
6,970
28,900
11
1,850
8.7
202
131
229
1,200
2.230
872
496
29
23
8,720
13
104
6.5
6.0
65
926
pg/J
Site
332
ND
186
524
30
8.6
1.4
1,720
9.5
NO
22
196
81
114
12.900
1.07
2,670
13
906
81
81
NO
572
234
715
30
19
ND
12
31
0.91
0.72
72
954
Stokers Equipped with Baghouses
rib' an Bean
Emission Severity
Factor x factor,
P9/J
35
0.33
40
2.9
0.055
0.30
49
0.14
ND
1.0
66
2.5
10
247
2.0
14
0.055
16
7.7
9.9
214
71
4.8
1.1
0.08
1.4
25
0.77
0.38
0.49
0.33
0.27
3.1
•cO.OOl
<0.001
<0.001
<0.001
•eO.001
<0.001
<0.001
<0.001
ND
<0.001
0.002
<0.001
<0.001
<0.001
0.001
<0.001
<0.001
<0.001
<0.001
<0.001
<0.001
0.011
0.001
<0.001
•tO.001
<0.001
<0.001
<0.001
<0.001
<0.001
<0.001
< 0.001
<0.001
Stokers Equipped with
Mean
Emission
Factor x
P9/J
2,620
1,290
382
91
5.5
3.1
2,630
5.7
73,900
60
615
114
3,540
20,900
6.2
2,260
11
554
106
155
1.200
1.400
553
605
30
21
8,720
13
67
3.7
3.4
68
940
ts(i)
I
NO
10.880
4.734
8.529
7.162
6.936
4.410
8.658
ND
7.982
8.669
3.675
12.304
4.870
10.53
2.298
2.657
8.080
2.976
6.056
ND
7.524
7.335
2.303
0.128
1.286
ND
0.610
6.922
9.585
9.983
0.566
0.185
Mechanical Pr«dp1Utors
lean
Severity
Factor,
0.008
0.039
0.002
0.003
0.041
<0.001
0.004
<0.001
0.164
0.009
0.019
0.009
0.021
0.040
0.002
<0,001
0.008
0.001
<0.001
<0.001
<0.001
0.211
0.083
0.061
<0.001
0.002
0.013
<0.001
<0.001
<0.001
<0.001
0.002
0.004
Upper
Limit
Severity
Factor, S
ND
0.462
0.011
0.026
0.338
<0.001
0.021
0.004
ND
0.081
0.179
0.040
0.283
0.237
0.022
0.002
0.028
0.013
0.001
0.003
ND
1.799
0.693
0.201
0.001
0.004
ND
<0.001
0.003
0.001
0.003
0.003
0.004
NO - Not Determined.
The stoker at Site 137 was equipped with baghouses. The other tow stokers tested were equipped with Multiple cyclone*.
-------
magnesium, and silicon are emitted 1n the largest quantities from bituminous
coal-fired utility boilers. In addition, chromium and nickel are also
emitted 1n large quantities frwrto1^e*s_equ1 pped with ESP's.
Average emissions ofQuromlum and nickel from boilers equipped with
ESP's were 760 to 2,560 pg/Jand 540~to~l7209^pg/J, respectively, depending
on boiler type. By comparison, average emissions of chromium and nickel
from boilers equipped with wet scrubbers, based on limited data, were a
factor of 10 to 1000 lower. Further, average chromium and nickel emissions
from all sampled bituminous coal-fired sites with ESP's were 4.1 and 1.6
times greater than the average amount of chromium and nickel present in the
coals used at these sites, as shown 1n Table 148. This implies either the
addition of chromium and nickel from the erosion of the ESP's and/or the
SASS train, or problems with SSMS in the analysis of these two elements.
Examination of the data also indicated that trace element emissions
are more dependent on the efficiency of the particulate control device and
the control device type than on the combustion source type. Total amount
of trace elements emitted from Site 137, a stoker equipped with baghouses,
was less than 1000 pg/J. For wet scrubbers designed for high-efficiency
particulate removal, such as those at Site 218, the total amount of trace
elements emitted was also less than 1000 pg/J. Source severity factors of
trace element emissions from both Sites 137 and 218 are extremely low
(<0.001 for most trace elements), Indicating that trace element emissions
from bituminous coal-fired utility boilers can be well controlled with
efficient collection devices. Another observation is that chloride emis-
sions from boilers equipped with ESP's were considerably greater than
chloride emissions from boilers equipped with v/et scrubbers. This is
because chlorides in the flue gas are present in the vapor form as hydrogen
chloride, which can be effectively removed by wet scrubbers but not by ESP's.
Based on mean source severity factor of S > 0.05, emissions of aluminum,
beryllium, chlorine, cobalt, chromium, iron, nickel, phosphorus, lead, and
silicon from most coal-fired boilers are of environmental significance.
Upper limit source severity factors Su were also calculated using xy = x +
ts(x) where x is the mean emission factor, t is the student t value, and
274
-------
TABLE 148. EMISSIONS OF CHROMIUM AND NICKEL FROM
BITUMINOUS COAL-FIRED BOILERS EQUIPPED
WITH ELECTROSTATIC PRECIPITATORS
Site No.
205-1
205-2
206
212
213
336
338
208
209
330
331
Mean x
s(x)
Measured
Chromium
Emissions
(pg/J)
3,430
1,690
37
146
877
1,430
1,320
784
2,300
290
503
1,160
309
Chroml urn
Present
in Coal
(pg/J)
200
82
25
685
685
227
143
262
698
62
45
283
82
Measured
Nickel
Emissions
(pg/J)
2,480
1,930
32
160
634
797
1,100
429
861
869
571
896
220
Nickel
Present
1n Coal
(pg/J)
2,330
283
439
404
404
1,140
179
44
657
< 136
< 73
553
201
s(x) is the standard deviation of the mean. For 12 of the 33 trace elements
listed in the tables for detailed Investigation, Sy < 0.05 for all bituminous
coal-fired source categories. These 12 trace elements, considered to be
environmentalTy insignificant, are: boron, bromine, mercury, potassium,
molybdenum, sodium, selenium, tin, strontium, thorium, uranium, and
vanadium.
275
-------
In Tablas 149, 150, and 151, the trace element emission factors for
bituminous coal-fired utility boilers calculated from data collected 1n
this program are compared with the corresponding trace element emission
factors derived from existing data. No comparisons for bituminous coal-
fired utility stokers were made because trace element emissions data for
this source category are not available from the existing data base. In
general, there 1s poor agreement between the existing data and current
study trace element emission factors. Again, this is not surprising because
of the differences in trace element contents of various coals and differences
1n the efficiency of particulate control devices. It is noteworthy, however,
that there is good agreement between the existing data and current study
data in identifying trace elements that are emitted in largest quantities,
and in identifying trace elements that are of environmental significance.
From this standpoint, the Level I SSMS analysis employed has served its
purpose as a valuable survey and screening technique.
It may be recalled that the existing data base for trace element
emissions from bituminous coal-fired utility boilers is based on average
nationwide concentrations of trace elements 1n bituminous coal, average
collection efficiency of particulate control devices, and trace element
data determined using more reliable techniques such as atomic absorption
spectrometry. Thus, trace element emission factors for bituminous coal-
fired boilers from the existing data base should be considered more reliable
than trace element emission factors from the current study.
With the combination of current study and existing data, the adequacy
of the trace element emissions data base for bituminous coal-fired utility
boilers can be summarized as follows:
• For pulverized bituminous coal-fired dry bottom boilers
equipped with electrostatic precipitators, the trace element
emissions data base is inadequate for barium, beryllium,
calcium, iron, lithium, nickel, phosphorus, lead, and
selenium, and adequate for all the other trace elements.
• For pulverized bituminous coal-fired wet bottom boilers
equipped with electrostatic precipitators, the trace element
emissions data base is inadequate for beryllium, calcium,
Iron, lithium, nickel, phosphorus, and adequate for all the
other trace elements.
276
-------
TABLE 149. COMPARISON OF TRACE ELEMENT EMISSION FACTORS FOR
PULVERIZED BITUMINOUS COAL-FIRED DRY BOTTOM BOILERS
Trace Element
Aluminum (Al)
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br
Calcium (Ca
Cadmium (Cd
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F).
Iron (Fe)
Mercury (Hg
Potassium (K)
Lithium (L1)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Emission Factor
for Boilers with
Wet Scrubbers, pg/0
Existing
Data
1,600
21
136
54
0.19
69
2,440
2.8
6,780
4.8
85
4.8
812
2,650
1.4
254
0.42
664
8.6
44
5,160
227
209
10
1.3
4.2
2,870
35
139
0.04
0.98
48
48
Current
Data
40
1.7
38
200
0.048
<0.92
4,400
0.53
—
0.39
5.3
5.8
1.5
no
0
100
0.77
720
13
1.7
~
45
120
1.2
0.14
3.6
<430
0.92
240
0.24
0.34
4.2
360
Emission Factor
for Boilers
with ESP, pg/J
Existing
Data
8,520
25
88
89
2.2
343
5,630
1.7
33,910
7.9
55
23
4,060
8,430
7.1
1,130
24
1,230
39
10
511
6.2
106
39
10
28
15,230
13
150
1.4
0.84
2.7
43
Current
Data
172
17
39
8.4
0.12
23
132
0.71
61 ,340
41
2,560
48
2,800
8,850
9.6
69
0.49
541
275
187
282
2,200
68
3.0
1.9
11
868
32
5.2
1.2
0.74
7.5
29
277
-------
TABLE 150. COMPARISON OF TRACE ELEMENT EMISSION FACTORS FOR
PULVERIZED BITUMINOUS COAL-FIRED WET BOTTOM BOILERS
Trace Element
Aluminum (Al)
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Caj
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (LI)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Emission Factor
for Boilers with
Wet Scrubbers, pg/J
Existing
Data
1,500
19
128
51
0.18
69
2,280
2.6
6,780
4.5
79
4.5
812
2,480
1.4
238
0.40
623
8.1
41
4,840
213
196
9.6
1.2
4.0
2,690
33
131
0.04
0.92
45
45
Current
Data
48
33
3.1
4.5
<0.037
0.11
149
0.037
4.8
<0.037
0.26
1.0
4.5
74
0.067
12
0.26
16
0.41
1.2
4.5
0.48
26
<0.48
0.074
5.2
8.9
0.74
1.1
<0.15
-------
TABLE 151. COMPARISON OF TRACE ELEMENT EMISSION FACTORS FOR
BITUMINOUS COAL-FIRED CYCLONE BOILERS
\
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (N1)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Emission Factor
for Boilers with
Wet Scrubbers, pg/J
Existing
Data
271
3.5
23
9.2
0.03
69
411
0.46
6,780
0.80
14
0.81
812
446
1.4
43
0.07
112
1.5
7.4
871
38
35
1.7
0.22
0.71
484
6.0
23
0.007
0.17
8.1
8.0
Current
Data
1,100
350
0.67
120
0.37
MD
730
210
77
4.7
46
72
23
4,900
2.1
3,800
4.1
ND
54
58
ND
20
230
1,100
99
33
15,300
9.3
14
ND
34
30
7,700
Emission Factor
for Boilers
with ESP, pg/J
Existing
Data
1,440
4.3
15
15
0.37
343
953
0.29
33,910
1.3
9.3
3.9
4,060
1,430
7.1
191
4.1
208
6.6
1.8
87
11
18
6.6
1.7
4.7
2,580
2.2
25
0.23
0.14
4.6
7.3
Current
Data
425
6.4
224
85
0.22
2.3
1,580
0.60
ND
20
968
12
24
3,750
3.9
141
3.3
176
77
88
170
682
94
2.3
0.28
2.8
872
2.6
50
1.3
0.94
7.7
26
279
-------
• For bituminous coal-fired cyclone boilers equipped with
electrostatic precipitators, the trace element emissions
data base is inadequate for beryllium, iron, lithium,
nickel, and phosphorus, and adequate for all the other trace
elements.
• The data base characterizing trace element emissions from
any type of bituminous coal-fired boilers equipped with wet
scrubbers is generally inadequate because of the limited
amount of source test data available.
• For bituminous coal-fired stokers equipped with mechanical
precipitators, the trace element emissions data base is
inadequate for arsenic, beryllium, cobalt, chromium,
fluorine, iron, nickel, phosphorus, and lead, and adequate
for all the other trace elements.
t The trace element emissions data base for bituminous coal-
fired stokers equipped with electrostatic precipitators is
inadequate because no data are available.
t The trace element emissions data base for bituminous coal-
fired pulverized dry bottom boilers, pulverized wet bottom
boilers, and cyclone boilers equipped with mechanical
precipitators Is inadequate because no emission data
are available. This is not considered a serious
deficiency since very few of the bituminous coal-fired
utility boilers, with the exception of stokers, use
mechanical precipitators for particulate control.
To correct the inadequacies in the trace element emissions data base,
it is important that future source tests and analysis be conducted
using Level II techniques, with the objective that mass balance closures
can be attained and meaningful enrichment factors can be calculated.
Analysis of the test data has also indicated that a number of trace elements
emitted from bituminous coal-fired utility boilers are not of environmental
concern, and efforts should be concentrated on characterizing the emissions
of the following 21 trace elements: aluminum, arsenic, barium, beryllium,
calcium, cadmium, chlorine, cobalt, chromium, copper, fluorine, iron,
lithium, magnesium, manganese, nickel, phosphorus, lead, antimony, silicon,
and zinc.
280
-------
Lignite-fired Utility Boilers
Trace element emissions data for the lignite-fired sources tested are
presented in Tables 152, 153, and 154 for pulverized dry bottom boilers,
cyclone boilers, and stokers, respectively. As in the case of bituminous
coal-fired utility boilers, data variability for trace element emissions is
large for all lignite-fired source categories.
Of the trace elements present in lignite, aluminum, calcium, chlorine,
fluorine, iron, potassium, magnesium, sodium, and silicon are emitted in
the largest quantities from lignite-fired utility boilers. In addition,
barium and strontium are also emitted in large quantities from lignite-fired
boilers equipped with multiple cyclones. This is partly due to malfunctioning
of the multiple cyclones at the time of sampling, and partly due to the
relatively high concentrations of barium and strontium in lignite. As dis-
cussed previously, emission data from Site Nos. 314 and 315 have indicated
that the multiple cyclones for either pulverized dry bottom boilers removed
no particulates. For Site No. 317, the multiple cyclones were found to be
operating at a low particulate collection efficiency of approximately 50
percent. Also, the average concentrations of barium, magnesium, sodium, and
strontium in lignite are several times higher than the average concentrations
of these elements in bituminous coal (Section 5.3.1.4).
As two of the three pulverized dry bottom boilers tested (Site Nos. 314
and 315) were equipped with malfunctioning multiple cyclones, only data from
Site No. 318 would be representative of trace element emissions from this
source category . The data presented showed that with an efficient ESP
(98.5 percent design efficiency, measured emissions of total particulates
less than Z ng/J), emissions of most trace elements were associated with
source severity factors S « 0.05 and not of environmental concern. The
major exceptions are emissions of beryllium, copper, nickel, and phosphorus.
Also, all new lignite-fired dry bottom boilers will be equipped with high
efficiency ESP's.
281
-------
TABLE 152. SUMMARY OF EMISSION AND SOURCE SEVERITY FACTORS OF TRACE ELEMENT EMISSIONS
FROM PULVERIZED LIGNITE-FIRED DRY BOTTOM UTILITY BOILERS TESTED
TV
00
fO
Emission Factor, pg/J
Trace Element
Aluminum (Al)
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Kg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Hi)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Site
314
<6,040
171
414
7,220
1.2
72
<85,400
11
265
5.8
32
162
<860
< 19, 700
1.9
4,600
17
<27.6QO
722
8.5
<23,600
263
919
110
3.6
<1.2
<1 1,200
6.6
2,490
<4.6
<3.2
37
303
Site
315
5,600
158
384
6,700
1.1
78
< 79, 200
2.2
845
5.4
29
84
<315
13,800
2.8
4,050
16
25,600
670
7.9
7,420
115
853
71
3.2
<1.2
10,400
6.1
2,310
<4.3
<2.9
34
94
Site
318
68*
<1
6.8
<20
<1
<17
387
<1.5
337
<0.6
8.6
<30
243
<86
<0.1
104
0.2
<215
<7.4
<0.9
400t
<68
<34
<5,8
<0.5
<3.7
130*
<4.5
<33
<1.8
<1.2
0.6
42
Boilers Equipped with ESP
Mean
Emission
Factor x
P9/ J
68
<1
6.8
<25
<1
<17
387
<1.5
337
<0,6
8.6
<30
243
<86
<0.1
104
0.2
<215
<7.4
<0.9
400
<68
<34
<5.8
<0,5
<3.7
130*
<4.5
<33
<1.8
<1.2
0.6
42
Mean
Severity
Factor
0.006
<0.001
<0.001
<0.023
<0.23
<0.001
0.017
<0.003
0.022
<0.003
0.008
<0.068
0.044
<0.005
<0.001
<0.001
0.004
<0.016
<0.001
<0.001
0.003
<0.305
<0.155
<0.017
<0.001
<0.008
0.006
<0,001
<0.005
<0.002
<0.003
<0.001
0.005
Boilers Equipped with
Mean
Emission
Factor x
P9/J
5,820
164
399
6,960
1.15
75
<82,300
6.8
555
5.6
30
123
<588
16,800
2.4
4,330
16.5
26,600
696
8.2
15,510
1.89
886
91
3.4
1.2
10,800
6.4
2,400
<4.5
<3.1
35
199
ts(x)
X
0.480
0.475
0.477
0.475
0.552
0.449
0.479
0.860
0.664
0.454
0.481
4.001
5.895
2.238
2.433
0.808
0.502
0.478
0.476
0.465
6.627
4.981
0.476
2.766
0.747
0
0.471
0.500
0.477
0.428
0.625
0.484
6.670
Mechanical Preci pi tators
Mean
Severl ty
Factor
0.504
0.148
0.058
6.273
0.259
0.003
3.709
0.015
0.037
0.025
0.027
0.277
0.106
0.971
0.021
0.037
0.337
1.998
0.063
0.001
0.132
0.850
3.993
0.272
0.003
0.003
0.487
0.001
0.349
0.005
0.007
0.032
0.022
Upper
Limit
Severl ty
Factor, Su
0.747
0.219
0.086
S.251
0.402
0.005
5.484
0.147
0.281
0.037
0.041
1.387
0.730
3.144
0.073
0.066
0.506
2.952
0.093
0.001
1.006
5.085
5.894
1.024
0.005
0.003
0.716
0.002
0.515
0.007
0.011
0.047
0.172
Estimated from design efficiency for particulate removal.
Estimated from Na and Ca concentrations in fuel and measured Ca emissions.
*The boiler at Site 318 was equipped with ESP. The boilers at Sites 314 and 315 were
equipped with multiclones.
-------
TABLE 1S3. SUMMARY OF EMISSION AND SOURCE SEVERITY FACTORS OF TRACE ELEMENT EMISSIONS
FROM LIGNITE-FIRED CYCLONE UTILITY BOILERS TESTED
oo
Trace Element Emission Factor, pg/J
Site 155 Site 3l6
Aluminum (Al) '
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
k <67
2.5
110
<37
<0.30
<20
<1,530
0.50
71
<0.40
<3.3
13
Fluorine (F) z 799
Iron (Fe) ° <110
Mercury (Ha) g> 0.20
Potassium (K) £ <114
Lithium (L1) * NO
Magneslun (Ng)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (N1)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (S1)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
<157
<4.7
<0.50
227
<47
<13
<3.9
<0.20
1.8
278
2.5
<43
<1.1
<0.80
<0.30
Zinc (Zn) * 9.4
Mean Emission
Factor, pg/J
<67
2.5
no
<37
<0.30
<20
<1,530
0.50
71
<0.40
<3.3
13
799
<110
0.20
<114
ND
<157
<4.7
<0.50
227
<47
<13
<3.9
<0.20
1.8
278
2.5
<43
<1.1
<0.80
<0.30
9.4
Mean Severity
Factor
<0.006
0.002
0.016
<0.032
<0.066
<0.001
<0.067
0.001
0.005
0.002
<0.003
0.029
0.140
0.006
0.002
<0.001
ND
<0.011
<0.001
<0.001
0.002
<0.207
<0.055
<0.011
<0.001
0.004
0.012
<0.001
<0.006
<0.001
<0.002
<0.001
0.001
ND - not determined.
Trace element analysis not performed because of extremely low level of particulate
emissions.
-------
TABLE 154. SUMMARY OF EMISSION AND SOURCE SEVERITY FACTORS OF TRACE ELEMENT EMISSIONS
FROM LIGNITE-FIRED UTILITY STOKERS TESTED
CO
•t*
Emission Factor, pg/J
Trace Element
Aluminum (Al }
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (rig)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (In)
Site
317
15,200
114
2,260
1,970
5.9
88
< 139 ,000
2.3
1,100
7.7
13
83
423
19,300
2.4
2,920
9.4
< 26 ,600
772
4.2
<17,800
276
1 ,540
66
3.3
51
18,200
7.2
3,740
7.7
4.0
66
552
Site
319
34
<2.3
35
<15
0.11
<24
117
0.82
288
<0.44
<2.3
<20
638
<93
0.23
306
<0.16
87
<4.3
0.44
371
<38
25
2.6
<0.27
5.3
98
4.7
<5.5
<0.93
<0.66
<0.60
12
Stokers Equipped
with Multi clones
Mean Severity
Factor
0.056
0.004
0.014
0.076
0.057
<0.001
<0.267
<0.001
0.003
0.001
<0.001
0.008
0.003
0.048
0.001
0.001
0.008
<0.085
0.003
<0.001
<0.006
0.053
0.296
0.008
<0.001
0.005
0.035
<0.001
0.023
<0.001
<0.001
0.003
0.003
Stokers Equipped
with ESP
Mean Severity
Factor
<0.001
<0.001
<0.001
<0.001
0.001
<0.001
<0.001
<0.001
<0.001
<0.001
<0.001
0.002
0.005
<0.001
<0.001
<0.001
<0.001
<0.001
<0.001
<0.001
<0.001
<0.007
0.005
<0.001
<0.001
<0.001
<0.001
<0.001
<0,001
<0.001
<0.001
<0.001
<0.001
-------
Emissions of these trace elements from Site No. 318 were reported as "less
than" values, resulting in source severity factors of relatively large
(<0.05) "less than" values. The environmental significance of the emissions
of these elements is not known at this point. Additionally, emissions of
aluminum, barium, calcium, chlorine, fluorine, magnesium, lead, and silicon
from Site No. 318 are associated with source severity factors S between
0.01 and 0.05. Because only one set of representative data is available
for pulverized lignite-fired dry bottom boilers, it is clear that emissions
of the trace elements listed above require further characterization.
For lignite-fired cyclone boilers equipped with ESP's, emissions of
most trace elements were also found to be associated with source severity
factors S « 0.05. Emissions of trace elements from cyclone boilers that
may pose a potential environmental problem and require further characteriza-
tion are the same as those listed for pulverized lignite-fired dry bottom
boilers.
Because of the small capacity of lignite-fired stokers, source severity
factors for trace element emissions from units equipped with ESP's (e.g.,
Site No. 319) are all less than 0.01. Thus, additional work to characterize
trace element emissions from these sources does not appear to be warranted.
For lignite-fired stokers equipped with multiple cyclones, data from Site No.
317 indicated that source severity factors for emissions of aluminum, barium
beryllium, calcium, magnesium, nickel, and phosphorus all exceed 0.05.
However, lignite-fired stokers are limited 1n number and being phased out
of usage. The Inadequate characterization of trace element emissions from
lignite-fired stokers should not be considered as a major concern.
Trace element emissions data for lignite-fired utility boilers are
generally not available from the existing data base. No comparisons between
the current study and existing data could therefore be made. Analysis of
the data acquired 1n this program Indicated the need for additional emission
characterization studies. This need is of low priority for I1gn1te-f1red
stokers, with a total generating capacity of only 185 MW, or for lignite-
fired cyclone boilers, for which two out of a total of four boilers have
already been sampled. The most serious data deficiency 1s the characteriza-
tion of trace element emissions from pulverized lignite-fired dry bottom
285
-------
boilers. The Installed generating capacity for this source category is
expected to increase from 7,800 MW to 25,100 VM during the 1979-1985 period.
Over 85 percent of the current generating capacity are located in Texas,
as will be most of the new additions. Since all three pulverized lignite-
fired dry bottom boilers sampled in this program burned North Dakota
lignite, there is a clear need to characterize trace element emissions from
boilers burning Texas lignite.
Residual Oil-fired Utility Boilers
In Table 155, the trace element concentrations of the residual oils
used in the boilers tested in this program are presented. Average trace
element concentrations of residual oil, as well as the variability in trace
element concentrations, were computed from the analysis results of the
eleven residual oil samples. These were then used to calculate mean
emission and source severity factors of trace element emissions from resi-
dual oil-fired utility boilers, by assuming that all trace elements present
in the oil feed were emitted through the stack. All calculated emission
and source severity factors are also presented in Table 155.
The calculated variability ts(x)/x indicated that the emissions data
base is adequate for aluminum, barium, bromine, cadmium, cobalt, chromium,
iron, mercury, lithium, manganese, nickel, phosphorus, antimony, tin,
thorium, uranium, and zinc. Examination of the upper limit source severity
factors showed that for those trace elements with ts(x)/x > 0.7, Su < 0.05
for arsenic, boron, potassium, molybdenum, sodium, silicon, and strontium.
The emissions data base is therefore also adequate for these trace elements.
Trace elements for which the emissions data base appears to be inadequate
include beryllium, calcium, chlorine, copper, fluorine, magnesium, lead,
selenium, and vanadium. These are the trace element with both the variabi-
lity ts(x)/x > 0,7 and Su > 0.05. The emissions data base for these trace
elements can be improved by analysis of additional residual oil samples.
The mean source severity factors indicate that among the trace elements,
emissions of beryllium, chlorine, copper, magnesium, nickel, phosphorus,
lead, selenium, and vanadium warrant special concern. These are the trace
286
-------
TABLE 155. SUMMARY OF EMISSION AND SOURCE SEVERITY FACTORS OF
TRACE ELEMENT EMISSIONS FROM OIL-FIRED UTILITY BOILERS TESTED
Trice
Element
Aluminum (Al)
Arsenic {As}*
Boron (B)
Barium (Ba)t
Beryllium (Be)
Bromine {Ir)+
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)**
Cobalt (Co)
Chromium (Cr)
Copper (Cy)
Fluorine (F)tt
Iron (Fe}«+
Ntrcury (Hfl.)"»
Potassium (X)
Lithium (11)
Magnesium (Mg)
Minoaneie (Hijttt
ro Molybdenum (Mo)
QQ Sodium {Mi}
*j Nickel (HI)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (SlJm
Tin (Sn)
Strontium (Sr)
Thorium {Til}
Uranium (U)
Vanadium (V)
Zinc (Z»}m
Site
105
5.9
<0.015
4.9
0.82
0,22
9.6
14
0.83
100
1.5
1.7
79
20
2,200
0.03
82
0.27
71
27
«0.57
130
51
IB
1.2
<0.33
4.2
720
«0,47
0.36
<1 .2
<0.82
3.4
6.1
Site
109
5.7
<0.015
0.069
2.0
0.086
0.12
5.2
< 0.046
<25
0.16
0.51
54
20
7.5
0.17
15
0.10
11
0.25
0.36
24
7.9
1.9
<0.24
< 0.026
O.OS2
47
<0.098
0.12
10.0
<0.01
0.5
0.5
<0.01
<0.01
>10
<0.01
0.1
0.5
0.09
0.1
<0.01
2
0.07
3.0
0.02
>10
0.04
<0.01
.10
8
1.0
<0.2
<0.01
0,02
4.0
-------
elements with S > 0.05 for residual oil tangentlally-fired utility boilers .
The existing data and current study trace element emission factors are
compared in Table 156. There is good agreement between 21 of the 33 trace
elements compared. For the remaining 12 trace elements, the agreement
between existing data and current study emission factors is relatively poor
(greater than a factor of 3). The current study data predict higher average
emissions for calcium, chlorine, copper, fluorine, magnesium, phosphorus,
strontium, and thorium, and lower average emissions for cadmium, tin,
uranium, and vanadium. The discrepancy in vanadiumDemission factors is
because none of the boilers sampled in this program burned residual oils
containing high levels of vanadium, such as those imported from Venezue^a_.___
The current study emission factor for vanadium 1s therefore biased towards
predicting lower vanadium emissions. With this single exception, trace
element emission factors from the current study are generally considered to
be more reliable, primarily because of the unknown quality of the existing
data base,
Gas-fired Utility Boilers
Trace element emissions in the stack gases from gas-fired utility
boilers were measured in this program. For five of the trace elements
measured, source severity factors based on average emissions exceed 0.05
for tangentially-fired boilers. These five trace elements are: chlorine,
copper, mercury, nickel, and phosphorus. Emission factor data for these
five trace elements are summarized in Table 157.
When compared with stack emissions from oil-fired and well-controlled
coal-fired utility boilers, emissions of chlorine, copper, mercury, nickel,
and phosphorus from gas-fired utility boilers are of the same order of
magnitude as either one of these sources, as shown in Table 158. This is
a surprising result as emissions of all trace elements from gas-fired
boilers were previously considered to be insignificant. For the five trace
*
The same emission factors are used for tangent!ally-fired and wall-fired
boilers. The differences in source severity factors are due to the larger
average capacity of tangenti ally-fired units.
288
-------
TABLE 156. COMPARISON OF TRACE ELEMENT EMISSION FACTORS
FOR RESIDUAL OIL-FIRED UTILITY BOILERS
Trace
El ement
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (L1)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (N1)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (In)
Emission
Existing Data
87
18
9.4
28.8
1.8
3.0
320
51.9
274
50.5
30
64
2.7
411
0.9
777
1.4
297
30.4
21
708
964
25
80
10
16
400
142
3.4
<0.02
16
3,656
28.8
Factor, pg/J
Current Study
132
12
16
31
2.4
6.1
1,428
6.9
3,108
9.7
21
350
149
453
1.5
392
1.7
2,384
13
12
1,276
433
129
34
<4.3
25
595
<7.4
32
10
<8.7
714
66
289
-------
TABLE 157. SUMMARY OF EMISSION AND SOURCE SEVERITY FACTORS
OF TRACE ELEMENT EMISSIONS FROM GAS-FIRED
UTILITY BOILERS TESTED
Trace
Element
Chlorine (C1)
Copper (Cu)
Mercury (Hg)
Nickel (N1)
Phosphorus (P)
ISS
0 ,
Site
113
250
<18.8
0.68
17.1
<78.6
Site
114
2,740
<12.2
0.67
19,3
<47.4
Emission
Site
115
188
22.2
0.44
16.8
<71.0
Factor, pg/J
Site
106
3,420
32.0
13.8
35.2
<17.3
Site
108
2,840
819*
18.0
111
<115
Site"
116
7,810
16.4
<0.44
66.3
106
S"f te
117 x
3,360 2,940
23.8 20.9
<0,39 4.9
29.0 42
55.5 70
Mean Severity
Factor
tsjx)
X
0.802
0.343
1.43
0.767
0.446
Tangentlally-
F1red
Boilers
0.285
0.069
0.064
0.277
0.462
Wall-
Flred
Boilers
0.139
0.034
0.031
0.135
0.225
Upper Limit Severity
Factor Sp
TangentlaTiy-
Fired
Boilers
0.514
0.093
0.157
0.489
0.668
Wall-
F1red
Boilers
0.251
0.045
0.076
0.239
0.325
Discarded as an outlier by the method of D1xon.
-------
TABLE 158. COMPARISON OF TRACE ELEMENT EMISSION FACTORS
FOR GAS-, OIL-, AND COAL-FIRED UTILITY BOILERS
Trace
Element
Chlorine (Cl)
Copper (Cu)
Mercury (Hg)
Nickel (N1)
Phosphorus (P)
Emission Factor, pfl/J
Gas-Fired
Boiler
2,940
21
4.9
42
70
Residual
Oil-fired
Boiler
3,110
350
1.5
433
129
Pul veri zed B1 tumi nous
Coal -fired Boiler
with ESP
33,910
23
7.1
62
106
elements identified to be of concern 1n this program, additional emission
characterization studies employing Level II analysis techniques appear to be
warranted.
5.5.1.5 Emissions of Organics and POM
Analysis of organic emissions from utility sites indicates that the
principal constituents are glycols, ethers, ketones, and saturated and
aliphatic hydrocarbons. The most prevalent species appear to be the glycols
and ethers which have MATE values in the range of 10 to 1100 mg/m (129).
Mean source severity based on these MATE values indicated that emissions
of specific organics (excluding POM) from bituminous coal-fired units,
lignite-fired stokers, and oil- and gas-fired units are not of concern with
respect to human health. However, lignite-fired dry bottom and cyclone
units may have mean source severity factors exceeding 0.05, depending on
which glycols and ethers are being generated. More detailed organic spe-
ciation would be required to conclusively determine whether a hazard is
posed by these lignite-fired units.
POM emissions data for coal- and oil-fired utility sites are presented
1n Tables 159 through 164. Compounds which were emitted at the highest concen-
trations from bituminous coal-fired units include naphthalene, phenanthrene,
MATE values were used in place of TLV's for the calculation of source
severity factors when TLV's were not available.
291
-------
TABLE 159. SUMMARY OF POM EMISSION DATA FROM PULVERIZED
BITUMINOUS COAL-FIRED DRY BOTTOM UTILITY BOILERS
ro
10
Emission Factor, jxj/0
Compound
Naphthalene
Phenyl naphthalene
Biphenyl
Benzo(g,hti)perylene
o- phenyl enepy rene
Dibenz(a,h)anthracene
Picene
Dibenz(a,c)anthracene
Site
205-1
BD1"
0.0095
0.0048
BD
BD
BD
BD
BD
Site
205-2
7.22
BD
0.785
BD
BD
BD
BD
BD
Site
154
BD
BD
<0.0082
1.48
0.854
0.671
0.188
0.478
Mean
Emission
Factor x»
P9/J
2.41
0.0032
0.266
0.493
0.285
0.224
0.0627
0.159
s(x),
pg/J
2.41
0.0032
0.259
0.493
0.285
0.224
0.0627
0.159
t^ii
4.303
4.303
4.19
4.303
4.303
4.303
4.303
4.303
_ *
xu
pg/J
12.8
0.017
1.38
2.61
1.51
1.19
0.333
0.843
xu = x (1 + ts(x")/x).
BD - below detection limit. Detection limit depends on sample complexity. For most of
the samples analyzed, the detection level was considerably lower than the anticipated
0.3 pg/m3 (approximately equal to 0.1 pg/J).
-------
TABLE 160. SUMMARY OF POM EMISSION DATA FROM PULVERIZED
BITUMINOUS COAL-FIRED WET BOTTOM UTILITY BOILERS
Emission Factor, pg/J
Compound
Naphthalene
Blphenyl
9 , 1 0-d1 hy drophenanthrene
Phenanthrene
Pyrene
Fluorantnene
Chrysene
Benzo(a)pyrene or
benzo(e)pyrene
Benzo(b)fl uoranthene
Indeno(l»2,3-c,d)pyrene
Benzo(g»h,1)perylene
Site
206
NDf
0.052
0.071
ND
ND
ND
ND
ND
ND
ND
ND
Site
212
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
Site
213
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
Site
218
62.4
4.83
ND
55.0
40.2
18.2
23.1
20.8
7.44
6.69
4.46
Site
336
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
Site
338
5.83
ND
ND
2.19
ND
ND
ND
ND
ND
ND
ND
Mean
Emission
Factor x
pg/J
11.4
0.814
0.012
9.53
6.70
3.03
3.85
3.47
1.24
1.11
0.743
s(x)
pg/J
10.3
0.803
0.012
9.10
6.70
3.03
3.85
3.47
1.24
1.11
0.743
ts(x)
*
2.32
2.54
2.57
2.45
2.57
2.57
2.57
2.57
2.57
2.57
2.57
_ *
xu
pg/J
37.7
2.88
0.042
32.9
23.9
10.8
13.7
12.4
4.43
3.98
2.65
*«
X.
x (1 + ts(x)/x).
ND - Not detected. Detection limit depends on sample complexity. For most of
the samples analyzed, the detection level was considerably lower than the anticipated
0.3 pg/mj (approximately equal to 0.1 pg/J).
-------
TABLE 161. SUMMARY OF POM EMISSION DATA FROM BITUMINOUS
COAL-FIRED CYCLONE UTILITY BOILERS
vo
Compound
Naphthalene
Phenyl naphthalene
Biphenyl
Ethyl blphenyl or
diphenyl ethane
Phenanthrene or
diphenyl acetylene
Methylphenthrene
Decahydronaphthalene
Dltert-butyl naphthalene
Dimethyl Isopropyl
naphthalene
Hexamethyl blphenyl
Hexamethyl hexahydro
Indacene
01 hydro naphthalene
CIQ substituted naphthalene
CIQ substituted decahydro-
naphthalene
Methyl naphthalene
Anthracene/phenanthrene
9, 10-d1hydro naphthalene/
1-T dlphenylethene
1,l'-b1s(p-ethylphenyl)-
ethane/tetramethyl
blphenyl
5- methyl -beni-c-acrl dine
2,3-dlrnethyl decahydro-
naphthalene
*xu = x (1 + ts(x)/i)
fNO - Not detected. Detectior
Emission Factor, pg/J
Stte
134
NDf
NO
1.50
ND
ND
ND
0.0374
0.112
0.112
0.224 .
0.374
0.0112
0.0225
0.374
0.599
0.112
0.0749
3.37
0.0749
<0.0112
i limit depen
Site
207
ND
ND
ND
0.189
0.189
2.02
ND
NO
ND
NO
NO
ND
ND
NO
NO
NO
ND
NO
ND
NO
ds on sai
Site
208
NO
NO
ND
ND
ND
ND
ND
ND
ND
ND
NO
NO
ND
ND
NO
ND
ND
ND
NO
ND
mple comi
Site
209
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
NO
ND
ND
ND
plexity.
Site
330
24.6
ND
ND
ND
ND
NO
ND
ND
ND
ND
ND
NO
ND
ND
ND
ND
ND
ND
ND
ND
For mo:
Site
331
NO
1,14
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
NO
NO
ND
ND
ND
ND
st of
Mean
Emission
Factor x
pg/J
4.10
0.190
0.250
0.0315
0.031S
0.337
0.00623
0.0187
0.0187
0.0373
0.0623
'0.00187
0.00375
0.0578
0.0998
0.0187
0.0125
0.562
0.0125
0.0019
s(x)
pg/J
4.10
0.190
0.250
0.031S
0.0315
0.337
0.00623
0.0187
0.0187
0.0373
0.0623
0.00187
0.00375
0.0578
0.0998
0.0187
0.0121
0.562
0.0125
0.00187
Mil
X
2.57
2.57
2.57
2.57
2.57
2.57
2.67
2.57
2.57
2.57
2.57
2.57
2.57
2.57
2.57
2.57
2.57
2.57
2.57
2.57
. *
V
pg/J
14.6
0.679
0.893
0.113
0.113
1.20
0.0223
0.0667
0.0667
0.133
0.223
0.0067
0.0134
0.207
0.357
0.0667
0.0446
2.01
0.0446
0.0067
the samples analyzed, the detection level MIS considerably lower than the anticipated
0.3 ui/m3 (approximately equal to 0.1 P9/0).
-------
TABLE 162. SUMMARY OF POM EMISSION DATA FROM BITUMINOUS COAL-FIRED STOKER
ro
Emission Factor, pg/J
Compound
Naphthalene
Phenyl naphthalene
Mixture of 3t8-d1methyl-
5-0-methyl ethyl)-!, 2-
naphthalene dlone and
trimethyl naphthalene
2-ethyl-l ,1 '-blphenyl
Site
137
1.04
ND
38,6
ND
Site
204
0.202
2.02
ND
2.96
Site
332
NDf
ND
ND
ND
Mean
Emission
Factor x
pg/J
0.414
0.673
12.9
0.987
s(x}»
pg/J
0.318
0.673
12.9
0.987
ts(x)
-
X
3.31
4.303
4.303
4.303
*
x ,
pg/J
1.78
3.57
68.2
5.23
* x, = x (1 * ts(x)/x)
ND - Not detected. Detection limit depends on sample complexity. For most of
the samples analyzed, the detection level was considerably lower than the anticipated
0.3 i»g/m3 (approximately equal to 0.1 pg/J).
-------
TABLE 163. SUMMARY OF POM EMISSION DATA FROM
LIGNITE-FIRED UTILITY BOILERS
Combustion
Source
Type
Pulverized
Dry Bottom
Cyclone
Stokers
Site
No.
314
315
318
X
s(x}
ts(x)/x
xu*
155
316
X
s(x)
ts(x)/x
xu*
317
319
X
s(x]
ts(x)/x
X *
POM Emission Factor
Trlmethyl propenyl
naphthalene
7.89
0.776
1.11
3.29
2.35
3.07
13.4
BD
0.682
0.341
0.341
12.7
4.67
6.29
BD
3.15
3.15
12.7
43.2
, pg/J
B1 phenyl
BDf
BD
BD
BD
BD
BD
BD
0.0445
BD
0.0223
0.0223
12.7
0.305
BD
BD
BD
BD
BD
BD
* .
X.
x (1 + ts(x)/x)
BD - below detection limit. Detection limit depends on sample complexity.
For most of the samples analyzed, the detection level was considerably
lower than the anticipated 0.3 vg/m3 (approximately equal to 0.1 pg/J)*
296
-------
TABLE 164. SUMMARY OF POM EMISSION DATA FROM OIL-FIRED UTILITY BOILERS
Compound
2-ethy1-l,1-b1phenyl
l,2,3-trl!fiethy1-4-
propenyl naphthalene
Naphthalene
Phenanthridine
Oibenzothiophene
Anthracene/phenanthrene
ro F1 uoran thene
vo
Pyrene
Chrysene/
benz( a) anthracene
Benzopyrene and
perylenes
Tetramethyl-
phenanthrene
Blphenyl
Emission Factor,
Tangential ly-Fi red
Site Site Site
210 211 322
NDf
ND
1.80
o o ND
3 3 ND
o o NO
— » — i
ND
m m ND
<" " ND
o o
— t — I
m m ND
o o
ND
0.694
Site
323
ND
ND
31.8
' ND
ND
ND
ND
ND
ND
ND
ND
1.47
Site Site
105 109
_
10 -O 3
0" -»
3 O 3
-J.T3 5
n it if
S'x'S'
< tf
B> *»
3 D.
Q.
m i
3 Q
S3
O>
zr g
IO I
S3
v> a>
a •+•
3I
pp/4
Site
118
0.223
0.223
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
THall -Fired
Site
119
0.353
ND
0.202
ND
ND
ND
ND
ND
ND
ND
ND
ND
Site Site
142/143 305
ND
ND
1.72
0.0516 °
0.103 3
0.206 0
0.172 ~*
o.i" °
0.0172 "i
o
— <
0.00688 m
0.103
ND
Site
324
ND
ND
11.6
ND
ND
ND
ND
ND
ND
ND
ND
0.720
Mean
Emission
Factor x
pg/J
0.0524
0.0203
4.28
0.00469
0.00936
0.0187
0.0156
0.0156
0.0156
0.000625
0.00936
0.262
s(x)
pg/J
0.0362
0.0203
2.94
0.00469
0.00936
0.0187
0.0156
0.0156
0.0156
0.000625
0.00936
0.148
Mil
X
1.54
2.23
1.53
2.23
2.23
2.23
2.23
2.23
2.23
2.23
2.23
1.26
*
pg/J
0.133
0.0655
10.8
0.0151
0.0302
0.0604
0.0504
0.0504
0.0504
0.00202
0.0302
0.592
u
fND - Not detected. Detection limit depends on sample complexity. For most of
the samples analyzed, the detection level wis considerably lower than the anticipated
0.3 wg/m3 (approximately equal to 0.1 pg/J).
-------
and pyrene, all of which are included in the NIOSH list of suspected
carcinogens. Naphthalene was also a major constituent of POM emissions from
oil-fired utility sites. The principal POM found in emissions from lignite-
fired sites was trimethyl propenyl naphthalene. Active carcinogens detected
at a limited number of bituminous coal-fired sites are dibenz(a,h)anthracene
and possibly benzo(a)pyrene. Additionally, benzo(g»h,i)perylene and
dibenz(a,c)anthracene, the carcinogenicity of which are currently the
subject of disagreement, were detected. A benzopyrene, possibly benzo(a)-
pyrene, was also detected at an oil-fired site. No POM compounds were
detected above blank levels at gas-fired utility sites.
Test emissions data for coal-fired sites differ substantially from
published data (Table 72) with respect to species emitted and magnitude of
emissions. However, as discussed previously, differences in sampling and
analysis techniques make data comparison difficult.
5.5.2 Coo1in g Tower Jmissions
Air emission rates from the cooling towers tested, calculated using
measured air flow rates during the pretest pitot traverse and the water
collected during the four-hour test, are presented in Table 165. These measured
air emission rates, in combination with data on the generation rates and heat
rates of the power plants associated with the cooling towers (Table 108), were
used to calculate emission factors for cooling towers based on thermal energy
input to the associated power plants. Cooling tower emission factors computed
in this manner can be readily compared with emission factors for fossil fuel-
fired utility boilers in terms of their relative impacts. Also, the cooling
towers tested are all specified with design drift losses in the 0.1 to 0.2
percent range. These are drift losses representative of mechanical draft
towers of pre-1970 design. Thus, emissions from these cooling towers are
expected to be higher and the data acquired should not be used to estimate
emissions from mechanical draft cooling towers of newer design or natural
draft cooling towers.
During the current program, trace element emissions from three cooling
tower sites were measured. In Table 166, trace element emission data from
these sites are presented. As noted in this table, the variability ts(x)/x in
298
-------
TABLE 165. MEASURED AIR FLOW RATES AND WATER EVAPORATION
AND DRIFT RATES FOR COOLING TOWER TESTED
fNS
*o
Site
No.
400
401
402
403
406
407
Measured
Stack Flow
Rate
m3/hr (CFM)
7,736,000
(4,550,000)
8,826,000
(5,192,000)
4,802,000
(2,825,000)
9,706,000
(5,713,000)
14,720,000
(8,660,000)
7,600,000
(4,474,000)
Sample
Volume
m3 (ft3)
33.0
(1163)
34.6
(1222)
31.0
(1096)
42.2
(1465)
42.3
(1493)
36.8
(1298)
Collected
Water
Vapor
£
.518
1.251"
.581
.55
.723
.636
Water *
Emission ,
1/hr
121,000
319,000
90,000
126,000
251 ,000
1 31 ,000
Emissions j
Load
at Test
1/MW-hr
4,858
8,000
1,470
3,700
1,930
1,845
3er MW-hr
Rated
Load
1/MW-hr
3,470
6,400
1,125
1,166
1,930
1,747
Water emission 1s the sum of evaporation and drift rates.
Possible leak in drift eliminator at this cell.
-------
TABLE 166. SUMMARY OF TRACE ELEMENT EMISSION FACTORS FOR
AIR EMISSIONS FROM COOLING TOWERS TESTED
Trace Element
Aluminum (AT )
Antimony (Sb)
Arsenic (As)
Barium (Ba)
Beryllium (Be)
Boron (B)
Bromine (Br)
Cadmium (Cd)
Calcium (Ca)
Chlorine (Cl)
Chromium (Cr)
Cobalt (Co)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Lead (Pb)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Mercury (Hg)
Molybdenum (Mo)
Nickel (Ni)
Phosphorus (P)
Potassium (K)
Selenium (Se)
Silicon (Si)
Sodium (Na)
Strontium (Sr)
Thorium (Th)
Tin (Sn)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Emission Factor,
Site
400
<8.56
<3,42
<3.42
<1.71
<1
15.4
<6.85
<5.14
1284
5992
5.14
<1.71
22.3
<68.5
37.7
<6.85
3.42
907
3.42
<0.14
<5.14
18.8
616
702
<15.4
668
9415
8.56
<10.3
<3.42
<6.85
<1.71
205
Site
401
8.85
<1.22
<2.43
3.76
<1
1.70
7.89
2.91
1490
201
0.848
2.55
4.13
<1.22
41.1
<2.43
<1
596
3.76
<0.097
<1.22
15.4
7.15
97.7
<1.22
128
828
19.8
<2.91
<1.22
<2.06
<1
54.1
Site
402
0.895
<3.42
<1.33
3.04
<0.4
2.87
7.75
<6.07
342
861
1.53
42.9
18.0
91.6
386
<7.97
0.382
167
11.3
ND*
5.89
14.0
25.5
85.7
<3.42
80.8
745
2.22
<12.3
<4.94
<8.54
0.961
52.0
P9/J
X
6.10
<2.70
<2.40
2.84
<0.8
6.66
7.50
4.71
1039
2351
2.51
15.7
14.8
53.8
155
<5.75
1.60
557
6.16
<0.12
4.08
16.1
216
295
<6.68
292
3663
10.2
<8.50
<3.20
<5.82
1.22
104
ts(x)
X
1.84
1.17
1 .09
0.91
1.08
2.83
0.19
0.86
1.46
3.35
4.27
4.24
1.59
2.17
3.21
1.27
2.49
1 .66
1.80
2.31
1.53
0.38
3.98
2.97
2.84
2.77
3.38
2.17
1.45
1.45
1.44
0.86
2.10
ND - No Data.
300
-------
the trace element emission factors is greater than 0.7 in almost all cases.
This can be attributed to differences in the trace element content of the
cooling water source, the type and quantities of cooling tower additives used,
the efficiency of drift eliminator designs, and to a lesser extent, differences
1n cooling water rates on per unit thermal energy input basis for the boilers.
The average trace element emission factors for the cooling towers can be
compared with corresponding emission factors for coal-fired and oil-fired
utility boilers. When compared with controlled stack emissions from bituminous
coal-fired utility boilers, emissions of calcium, potassium, sodium, magnesium,
lithium, chlorine, phosphorus, and zinc from cooling towers are of the same
order of magnitude as those from coal-fired boilers, while emissions of other
trace elements from cooling towers are considerably less. When compared with
stack emissions from oil-fired utility boilers, emissions of 17 trace elements
from cooling towers are of the same order of magnitude as those from oil-fired
boilers, while emissions of other trace elements are considerably less. These
17 trace elements are boron, bromine, cadmium, calcium, chlorine, cobalt,
fluorine, iron, lithium, magnesium, manganese, molybdenum, phosphorus, potassium,
sodium, strontium, and zinc. However, among these 17 trace elements, only
emissions of chlorine, magnesium, and phosphorus from oil-fired utility boilers
are of environmental concern, based on source severity factors greater than
0.05. Thus, it can be argued that only emissions of these same three trace
elements are of environmental concern for cooling towers.
The high emission rates of selected trace elements from cooling towers
can be reasonably explained based on knowledge of the source of cooling water
and the type and quantity of cooling tower additives used. High emission
rates for calcium, potassium, sodium, magnesium, and lithium from cooling
towers were mainly due to the presence of these trace elements 1n the source
of cooling water. High emission rates for chlorine, phosphorus, and zinc
from cooling towers were mainly due to the use of additives containing these
trace elements such as 01 In 2102 (a phosphate additive to hold sol Ids in sus-
pension), chlorine (algaecide/bacteriodde), and Nalco 30B04 (a zinc additive
to prevent corrosion). Cooling tower additives used for each of the sites
tested have been described previously in Section 5.4.2.2.
301
-------
Air emissions of chlorine, phosphorus, and magnesium from cooling towers
were analyzed in some detail as these are the trace elements of principal
concern. As shown in Table 167, there is a definite correlation between the
blowdown concentrations of these elements and the additives used or source of
cooling water. Additives containing chlorine and phosphate were used for
Sites 400, 401, 402, resulting in relatively high concentrations of chlorine
and phosphorus in the blowdown from these sites. The concentration of magnesium
in the blowdown from Site 402 was considerably higher than those from Sites
400 and 401, because Colorado river water with high solids content was used
for Site 402 whereas treated sewage water was used for Site 400 and municipal
water was used for Site 401. Actual air emissions of these trace elements
from the cooling towers, however, also depended on the physical and chemical
form of these elements as well as efficiency of the various drift eliminator
designs.
The drift fraction for each of these three trace elements, defined as the
ratio of air emission rate of an element to the cooling tower recirculation
rate for the same element, was computed and the results are also presented in
Table 167. For Site 400, the drift fraction for either chlorine, phosphorus,
or magnesium was approximately 0.09 percent. This is a reasonable measured
drift fraction for a cooling tower with design drift losses not to exceed
0.2 percent. The good agreement among the drift fractions calculated using
chlorine, phosphorus, and magnesium data indicates that the distributions of
these elements among drift droplets of different sizes were probably similar,
resulting in equal collection efficiencies for these elements by the cooling
tower drift eliminator. For Site 401, the drift fractions calculated using
chlorine, phosphorus, and magnesium data ranged from 0.0056 to 0.0675 percent.
Since the cooling tower was specified with design drift losses not to exceed
0.1 percent, it appears that the drift fraction of 0.0675 percent for magnesium
was in good agreement with the design value. The reasons for the lower drift
fractions for chlorine and phosphorus are not known, but could conceivably be
the result of using data obtained by semi-quantitative Level I analysis tech-
niques. For Site 402, the drift fractions calculated using chlorine, phosphorus
and magnesium data ranged from 0.00037 to 0.012 percent. By comparison, the
cooling tower was specified with design drift losses not to exceed 0.2 percent.
302
-------
to
o
OJ
TABLE 167. AIR EMISSIONS OF CHLORINE, PHOSPHORUS, AND MAGNESIUM
FROM COOLING TOWERS TESTED
Site
No.
400
401
402
Trace
Element
Cl
P
Mg
Cl
P
Mg
Cl
P
A1r Emissions
(yg/m3)
235
24.2
35.6
12
0.43
35.8
124
3.66
(ng/J)
5,992
616
907
201
7.15
596
861
25.5
Bl owdown
Concentration
(mg/1 )
283
26
39
265
4.2
65
536
67
Drift
Fraction
(«)
0.083
0.093
0.091
0.0056
0.0117
0.0675
0.0119
0.00282
Additives/Water Source
Contributing to
High Emission Rates
Chlordioxide
01 in 2102 (phosphate additive)
Treated sewage water
Chlorine
Calgon sodium hexametaphosphate
Municipal water
Chlorine
Nalco 82 (probably contains
Mg
23.9
167
3,300
phosphate)
0.00037 Colorado river water via
American canal, high solids
content
-------
Possible explanations for the discrepancies are the installation of improved
mist eliminator designs because of the high solids content of the makeup
water, and the presence of chlorine and phosphorus (as an organic phosphate)
in vapor phase, resulting in lower collection efficiencies and relatively
higher drift fractions than magnesium. Thus, analysis of the drift data has
shown that the emission mechanisms for the individual elements are not well
understood at this point.
In addition to emissions of trace elements, emissions of sulfates from
cooling towers are also of concern because sulfuric acid is a common additive
to cooling water for pH adjustment. All six cooling towers tested employed
sulfuric acid as an additive. In Table 168, air emission rates of sulfates
from the cooling towers tested are presented. On emission factor basis, it
is seen that sulfate emissions from these cooling towers ranged from 3 to 41
ng/J. By comparison, controlled sulfate emissions from coal-fired utility
boilers and sulfate emissions from oil-fired utility boilers are typically in
the 20 to 30 ng/J range. Thus, sulfate emissions from mechanical drift cooling
towers employing sulfuric acid as an additive, and with design drift losses
in the 0.1 to 0.2 percent range, are of the same magnitude as sulfate emissions
from coal-fired and oil-fired utility boilers.
In Table 168, the calculated drift fractions for sulfates are also pre-
sented. For Sites 400 and 401, the sulfate drift fractions were approximately
equal to the design drift losses, but higher than the drift fractions for
chlorine, phosphorus, or magnesium. For Site 402, the sulfate drift fraction
was lower than the design drift losses, but again higher than the drift
fractions for chlorine, phosphorus, or magnesium. The relatively higher
sulfate drift fraction is an indication that sulfates emitted from cooling
towers are probably in the form of fine aerosols or in the vapor phase.
In Table 169, the inorganic emission factors determined in the current
study are compared with the emission factors calculated for cooling towers
with 0.05 percent drift loss and using existing blowdown concentration data.
For emissions of chromium, chloride, and sulfate from cooling towers, results
from the current study are in good agreement with estimates bases on existing
data. For sodium and magnesium, emission factors from the current study are
lower than the existing data emission factors. For copper, iron, nickel,
zinc, and phosphorus, emission factors from the current study are higher than
304
-------
TABLE 168. AIR EMISSIONS OF SULFATES FROM COOLING TOWERS TESTED
Site
No.
400
401
402
403
406
407
Air
(yg/m3)
1,624
670
505
*
989
941*
4,143*
Emissions
(ng/J)
41.4
11.2
3.5
*
25.2
11.4
*
39.7
Bl owdown
Concentration
(mg/1 )
700
825
1,475
300
400
1,575
Drift
Fraction
0.23
0.10
0.018
4-
0.2T
0.2f
0.21"
Air emissions of sulfates from these sites were computed assuming a drift
fraction of Q.2%.
The drift fraction for sulfates was assumed to be equal to the design drift
loss.
TABLE 169. COMPARISON OF INORGANIC EMISSION FACTORS FOR COOLING TOWERS
Chemical
Constituent
Sodium
Chromium
Copper
Iron
Magnesium
Nickel
Zinc
Phosphorus
Chloride
Sul fate
Emission Factor, pg/J
Mechanical Draft
Tower with 0.05%
Drift Loss*
15,400
5.2
1.6
36
5,500
0.19
6.0
24
3,800
10,900
Site
400
9,415
5.1
22.3
37.7
907
18.8
205
616
5,992
41 ,400
Site
401
828
0.85
4.13
41.1
596
15.4
54
7.2
201
11,200
Site
402
745
1.5
18.0
386
167
14.0
52
25.5
861
3,500
Average
of Current
Study
3,663
2.51
14.8
155
557
16.1
104
216
2,351
18,700
Calculated from water recirculation rate, drift fraction, and blowdown
concentrations based on existing data (Section 5.3.2).
305
-------
the existing data emission factors. Again, the differences in emission fac-
tors are probably mainly due to differences in the source of cooling water,
the type and quantity of additives used, and drift eliminator design.
Data for organic emissions from cooling towers are summarized in Table
170. The data presented indicate an average organic emission factor of 31.9
ng/J. This is a higher emission level of total organics than those from coal-,
oil-, or gas-fired utility boilers. Most of the organics emitted were in the
-160 to 90°C boiling point (reported as C,-Cg) range, and field tests per-
formed have shown that C-,-Cg emissions were mainly in the form of methane.
Although methane emissions appear to be reasonable for Site 401, which uti-
lized treated sewage wastewater, it is not clear whether methane emissions
from the other cooling towers tested were caused by decomposition of organic
additives or by dispersion of organics present in stack emissions from oil-
and gas-fired boilers within the plant boundary. Emissions of volatile (90
to 300°C boiling point range, reported as C,-C,g) and nonvolatile (boiling
points >300°C, reported as >Cig) organics from the cooling towers averaged
0.093 and 0.168 ng/J, respectively. These emissions were considerably less
than emissions from coal-, oil-, or gas-fired utility boilers. The only com-
pounds identified awong the >Cg fraction were esters, including phthalates,
for samples from Site 401. Emissions of the >Cg organics could be due to
volatilization or drift losses of the organic additives present in the recir-
culating cooling water. Also presented in Table 170 are the calculated
fractions of combined evaporation and drift losses from Cj-C-ig organics and
>C,g organics. It is seen that the average evaporation and drift fraction for
Cj-C-ig organics was 12.7 percent whereas that for >C-ig organics was 0.74 per-
cent. Thus, evaporation and drift losses for the >Cg organics appear to be
substantially higher than those for inorganics, and also related to the
volatility of the different organic fractions. These organic emissions data
must be interpreted with caution, as air emissions of lighter organics could
be the result of decomposition of heavier organics, and not necessarily due
to only evaporation or drift losses.
In summary, the sampling and analysis effort conducted during the current
study has led to the identification of chlorine, phosphorus, magnesium, and
sulfates as potential problem pollutants discharged by cooling towers to the
atmosphere. Emissions of these pollutants from the cooling towers tested were
306
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TABLE 170. AIR EMISSIONS OF OR6ANICS FROM COOLING TOWERS TESTED
o
•xl
Site
No.
400
401
402
403
406
407
Mean x
s(x)
t,(x)/x
Organic A1r Emissions, ng/J
crce
44.3-61.3
30.1-41.2
18.1
34.1-60.5
18.4-30.5
10.2-13.4
31.7
6.7
0.54
C7"C16
0.337
0.118
0.003
0
0.042
0.055
0.093
0.094
2.62
>C16
0.051
0.267
0.018
0.186
0.317
0.167
0.168
0.048
0.73
Total
44.7-61.7
30.4-41.6
18.1
34.3-60.7
18.8-30.9
10.4-13.6
31.9
6.7
0.54
Bl owdown
Concentration
(yg/1 )
54
29
5
12
27
0
21
7.9
0.96
>C16
(mg/1 )
2.56
1.42
1.76
0.51
1.24
0.94
1.41
0.33
0.61
Fraction of Combined
Evaporation & Drift
Losses, %
C7-C16
24.5
30.0
5.2
0
3.8
*
NC
12.7
6.1
1.33
>C16
0.078
1.38
0.076
0.87
0.62
1.41
0.74
0.24
0.84
NC - Cannot be computed because bl owdown concentration for
apparently zero.
organlcs was determined to be
-------
of the same magnitude as emissions from oil-fired utility boilers. However,
all the cooling towers tested are of the older mechanical draft type asso-
ciated with high drift losses in the 0.1 to 0.2 percent range. Emissions of
the same pollutants from mechanical draft cooling towers of more modern design
or natural draft cooling towers, with typical design drift losses of 0.005
percent and 0.002 percent, should be at least an order of magnitude lower and
of much less environmental concern. Organic emissions from the cooling towers
tested were primarily in the form of methane of unknown origin.
5.6 DATA RELIABILITY
As discussed in Section 5.2 and Appendix A, data reliability is one of
the primary considerations in assessing the adequacy of emissions data. In
the current study, several steps were taken to assure the reliability of
all emissions data admitted into the data base. These steps included:
1) Screening of emissions data for adequate definition of
process and fuel parameters that may affect emissions.
Data from non-representative sources (e.g., old data
applicable only to obsolete designs) were excluded.
2) Screening of emissions data for validity and accuracy
of sampling and analysis methods employed. For example,
most pre-1970 particle size distribution data were con-
sidered to be of unacceptable quality because of the
extensive use of the Bahco classifier during the period.
Another example is NOX emissions data determined from
analysis of bag samples were considered to be unacceptable
because of sample degradation problems.
3) Engineering examination to eliminate erroneous data. An
example is the use of mass balance calculations to eliminate
trace element emission values that are greater than the
amounts of trace elements present in fuel input.
The quality of the emissions data presented in this report generally
depends on the pollutants and waste streams characterized. Without extensive
replicate sampling and analysis, which is beyond the scope of this work, the
accuracy of the data acquired cannot be firmly established using error pro-
pagation analysis. Estimates of the quality of the emissions data, however,
can be made based on knowledge of the sampling and analysis methods employed
and limited data from quality assurance audits. The estimated quality of
the data can be summarized as follows:
308
-------
• Reported NOX emissions data were obtained with on-line
chemi luminescence measurements or EPA Method 7 (phenol -
disulfonic acid procedure). Accuracy for these measure-
ments was within 10 to 20 percent.
• Existing total hydrocarbon emissions data were acquired
using gas chromatographs equipped with flame ionization
detectors (FID). Gaseous hydrocarbon emissions were
measured in the current program using gas chromatographs
equipped with thermal conductivity detectors (TCD).
Accuracy for both measurement methods was within 10 to
20 percent.
• Existing CO emissions data are very limited. In the current
program, CO emissions were measured using gas chromatographs
equipped with TCD. Accuracy for these measurements was
expected to be within 10 to 20 percent.
emissions data reported in the literature were obtained
using a variety of methods, including continuous monitoring
by pulsed fluorescent analyzer and EPA Method 6. Accuracy
for these measurements is typically within 10 percent. In
the current program, S0£ emissions were computed from fuel
sulfur values. Accuracy for fuel sulfur determinations was
typically t 0.1 percent sulfur.
• Existing parti cul ate emissions data were obtained using EPA
Method 5. In the current program, particulate emissions
were determined using the SASS train. The results of a
previous study evaluating Level I procedures indicated that
particulate emissions determined by the SASS train compared
very well with Method 5 data, the largest difference being
within 20 percent (158).
» The expected error limits for Level I organic analysis have
been established by Research Triangle Institute (159). Error
limits for TCO, gravimetric, and TCO + gravimetric analyses
are to be within t 15 percent of the expected value. For low
resolution mass spectrometric (LRMS) analyses, expected
error limits for LRMS category quantisations are to be within
t 1 standard deviation of the mean value for a category.
• The accuracy of GC/MS analysis for POM compounds depends on
several parameters, including the type of compound, instrument
internal cleanliness, resolution of closely eluting peaks,
and availability of standards. Error limits are typically
i 30 percent of the expected value.
• Determinations of inorganic emissions by SSMS analysis were
generally unsatisfactory. In Table 171, SSMS analysis
results from Site 135 are presented for the 17 elements which
309
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TABLE 171. SPARK SOURCE MASS SPECTROMETRIC ANALYSES OF
TRACE ELEMENT EMISSIONS FOR SITE 135
Element
Al
As
Be
Ca
Cd
Co
Cr
Cu
Fe
Mn
Ni
Pb
Sb
Se
Sr
V
Zn
Concentration
Scrubber
Inlet
1.94
> 95.1
0.0034
179.6
0.862
0.088
> 0.975
> 1.958
>134.9
> 1.62
> 1.03
>100.4
0.888
0.376
> 1.658
1.008
>134.9
, mg/m
Scrubber
Outlet
> 0.139
> 9.00
0.001
>44.0
0.316
0.007
>26.0
>26.0
>62.6
0.02
0.036
>90.0
0.117
0.130
0.047
0.128
>76.00
Scrubber
Inlet
0.015
>97
0.16
3.7
0.17
0.46
> 0.75
> 1.6
> 0.34
> 2.3
> 0.52
> 9.1
1.1
1.0
> 3.6
1.3
> 1.3
SSMS/AAS
Scrubber
Outlet
> 0.05
> 9.6
0.56
22
0.54
0.54
>220
>140
> 4.8
0.13
0.67
> 31
0.43
1.5
1.2
1.5
> 3.6
were also analyzed by AAS. Comparison of SSMS/AAS analysis
results shows poor agreement (different by more than a factor
of 3) for 13 of the 17 elements analyzed. In previous Level
I method evaluation studies conducted by Research Triangle
Institute (158, 159), it was shown that over half of the SSMS
results for the elements analyzed may be outside the factor
of 3 range and unacceptable. Thus, inorganic emissions data
obtained using SSMS analysis are of questionable quality.
Existing inorganic emissions data, acquired mostly using atomic
absorption spectroscopy (AAS), neutron activation analysis
(NAA), and inductively coupled plasma optical emission spectro-
metry (ICP), are associated with typical error limits of - 20
percent of the expected value.
310
-------
On the basis of the above discussion, most of the emissions data in-
cluded in this report should be considered to be highly reliable. There
are, however, two areas of data uncertainty. The principal area of data
uncertainty is any trace element emissions data determined using SSMS.
Level I SSMS is a semiquantitative technique valuable in providing trace
element survey and screening data, and less useful for estimation of emission
rates or emission factors. A second area of data uncertainty is related to
reported organic emissions from cooling towers. At the present time, it is
not clear whether the organic emissions from the cooling towers tested were
caused by decomposition of organic additives, or by dispersion of organics
present in stack emissions from the boilers within the plant boundary.
311
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6. WASTEWATER EFFLUENTS
In the production of electrical power, the steam-electric power
industry requires large quantities of water for many of its processes.
The most significant use is in the cooling system. Other processes which
also use water include boiler feed processes and industrial applications
such as chemical cleaning, ash handling, air pollution control, etc. The
external combustion coal-fired power plant is most notable for the signi-
ficant quantities of wastewater generated from its processes. The waste-
water emissions emanating from coal-fired plants will be the focus of this
section.
6.1 SOURCES AND NATURE OF WASTEWATER EFFLUENTS
The collection, segregation, combustion, recycling, and discharge of
the various wastewater streams are highly specific to each steam-electric
plant. It may be useful to examine the major sources as shown below:
• Cooling water systems
• Water treatment processes
• Boiler blowdown
• Chemical cleaning
• Ash handling
* Wet scrubber systems
• Coal storage pile.
Wastewater discharges from steam-electric plants can either be con-
tinuous or intermittent. Continuous discharges are produced by cooling
water systems, boiler blowdown, ash handling systems and wet scrubber sys-
tems. Intermittent discharges are produced on a regular basis by water
treatment processes, miscellaneous equipment cleaning operations, and
sanitary and laboratory wastes. Intermittent streams, such as chemical
cleaning waste streams, are usually generated during periods of shutdown or
312
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startup of a boiler or generating unit. Streams emanating from coal storage
piles are produced during and after storm events.
The following is a more detailed discussion of the sources and nature
of these wastewater effluents.
6.1.1 Cool ing Water Systems
In a steam-electric plant, the steam produced in the boiler is expended
in the turbine generator to produce electricity. The spent steam then
proceeds to the condenser where the heat of vaporization is transferred to
the condenser's cooling system. The cooling systems employed, either once-
through or recirculatory, are described below.
Once-Through Cooling System
A once-through cooling system is the simplest and most common means
of transferring heat from the spent steam of a generating turbine. The
influent water can be withdrawn from an ocean, river, lake or estuary and
usually discharged back to the same body of water.
The chemical composition of the effluent water is essentially that of
the influent water except for slight changes due to: 1) products of corro-
sion and/or 2) chemical additives to the incoming water.
Corrosion products (i.e., metal oxides) are the result of corrosion
from direct contact of water with the main condenser. A condenser material
is usually selected that will minimize the problem.
Of particular concern with a once-through cooling water system is the
growth and accumulation of bacterial and algal slimes which attach them-
selves to the walls of the cooling equipment. A buildup of these organisms
can result in a great reduction in the efficiency of the condenser, thus
reducing the efficiency of the generating unit. To minimize and control
this problem, chlorine or hypochlorite 1s generally added to the cooling
systems.
For cooling systems using marine waters, two simultaneous types of
chlorination systems are applied: continuous and intermittent. Continuous
chlorination is administered at low levels to control the hard-shelled
313
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organisms, while intermittent chlorination is applied as a shock treatment
to control the soft forms. For a typical once-through cooling system,
chlorine is introduced continuously to provide a free oxidant residual of
0.25 to 0.50 mg/1 at the condenser tailpipes. For intermittent chlorina-
tion, chlorine is introduced to give 1.0 mg/1 free oxidant residual at the
end of 1 hour contact time. The combined applications should produce a
free oxidant residual of 0.3 mg/1 at the discharge point (130).
For those systems using fresh waters, the average chlorine treatment
is from two to three cycles per day, for a duration of 30 to 60 minutes per
cycle. This is done to achieve a free oxidant residual in the condenser
tailpipe of 0.5 mg/1 (130).
In short, the pollutants associated with a once-through cooling
system are corrosion products and biofouling control agents with the latter
being more significant.
Recirculatory Cooling System
A recirculatory cooling system is the other alternative used to dissi-
pate heat from the spent steam in the condenser. In this system the bulk
of the warm water, returning from the condenser to a cooling tower or pond,
discharges its heat by evaporation and/or convective heat transfer. In the
process of dissipating heat, certain amounts of water losses are encountered
due to evaporation, drift, and blowdown.
Evaporation losses generally are comprised of 2 to 3 percent of the
recirculatory water flow. In addition, a small quantity (drift) is lost
to the atmosphere by the entrainment of water droplets in the passing air
current through a cooling tower. The drift loss from either the mechanical
or the natural draft cooling tower usually ranges from 0.005 to 0.01 per-
cent of the recirculatory water flow.
The third and most significant water loss is from blowdown. In the
process of evaporation, all constituents (dissolved and suspended) tend to
concentrate. The degree of concentration is limited by the solubility of
one or more constituents at the prevailing temperature and pH. Certain
constituents will exceed their solubility product from concentration, thus
precipitating out of the solution. The result is deposition of salts as
314
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scales on condenser tubes which hinders heat transfer. To maintain the
chemical characteristics of the recirculating water within acceptable limits
and to minimize scale deposition on condenser tubes, certain quantities of
water must be discharged as blowdown. The contaminants in this discharge
are generally derived from the following sources:
t Makeup water
t Chemical additives
• Air contaminants
0 Corrosion products
The constituents found in makeup water are typically carbonates and
sulfates of calcium and magnesium. Although these components are innocuous
in their normal concentrations, they may cause environmental concern in the
higher concentration found in the blowdown.
The second source of contamination is the chemical additives that are
used. These chemicals are added to control scale formation, corrosion,
and/or biofouling in the cooling system. Chemicals commonly used include
sulfuric acid, hydrochloric acid, sodium hydroxide, chlorine, sodium hypo-
chlorite, calcium hypochlorite, and proprietary inhibitors. Table 172
summarizes some of the chemical treatment methods employed and also presents
their impact on the quality of the blowdown stream.
The third source of contamination is the scrubbing of certain consti-
tuents from air, which passes through the cooling tower. During the intimate
contact which occurs between air and water, particulate matter and soluble
gases are scrubbed from the air stream. It is estimated that, in certain
dusty regions, up to 80 percent of the suspended solids in recirculatory
systems may originate from airborne particulates (131). Water soluble
particulates can also increase the concentration of dissolved species, upon
dissolution. In addition, the dissolution of gases will increase the con-
centration of certain species originally found in the cooling water. For
example, carbon dioxide (C09), nitrogen oxides (NOV), and sulfur oxides (SO )
_£. X _ X
will yield carbonates (C03~ and HC03"), nitrates (N03~) and sulfates (S04~)
as they are scrubbed from the passing air.
315
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TABLE 172. CHEMICAL TREATMENT SUMMARY FOR RECIRCULATING
COOLING SYSTEMS
Treatment Objective
Chemical Additive
Typical Additive
Concentrations in Slowdown
Corrosion Inhibition
Scale Control
Biological Fouling
(algae, slimes,
fungi) Control
Suspended Solids
Dispersion
Chromate
Zinc
Phosphate
Silicates
Proprietary Organics
Acid Treatment
Inorganic Polyphos-
phates
Chelating Agents
Polyelectrolyte
Antiprecipitants
Organic/Polymer
Dispersants
Chlorine
Hypochlorite
Chlorophenates
Thiocyanates
Organic Sulfur
Compounds
Tannins
Lignins
Proprietary Organics/
Polymers
Polyelectrolytes/Non-
ionic Polymers
10-50 mg/1 as CrO,
8-35 mg/1 as In
15-60 mg/1 as P04
3-10 mg/1 as organic
Cooling water pH is
maintained between 6.5
and 8.0
2-5 mg/1
1-2 mg/1
20-50 mg/1
<0.5 mg/1 residual Cl»
30 mg/1 residual
concentrations
20-50 mg/1
1-2 mg/1
316
-------
To a lesser degree, a fourth possible source of contamination is
corrosion products associated with the cooling system components. In most
cases, these cooling system components are constructed of material with
minimum corrosive effects.
6.1.2 Mater Treatment Processes
The use of water supplies as makeup water for various processes
usually requires some form of treatment. This treatment is primarily used
for boiler feedwater. The type and degree of treatment will necessarily
depend on the quality of feedwater required. The quality and quantity of
this makeup water is primarily a function of boiler operating procedures
and heat transfer rates.
For those boilers with intermediate pressures ranging between 500 and
2000 psi, the treatment may require clarification followed by filtration.
In these cases where the raw water is hard, a softening stage may be in-
cluded prior to clarification.
In the softening process, lime and soda ash are used to precipitate
out calcium and magnesium. The sludge produced will consist mainly of
calcium carbonates and magnesium hydroxide.
Clarification is used for removing suspended solids and some dis-
solved impurities. Chemical coagulants such as alum, ferrous sulfate,
ferric sulfate, sodium aluminate, and polyelectrolytes are often added to
the water to improve agglomeration of colloidal material into larger,
heavier particles. These particles are then allowed to settle and the
clarified water is drawn off. The settled solids, consisting mainly of
alum and iron salts, are withdrawn from the clarifier basin as sludges.
After clarification, the water may pass through a filter to remove
those particles that are carried over with the clarified water. Deep-bed
filters, which incorporate sand or anthracite coal as the filter media, may
be used. During backwashing, these filters will produce a waste consisting
mainly of suspended solids. In certain cases, the backwash water is
returned to the clarifier inlet to minimize wastewater production.
317
-------
For high pressure boilers operating at 13.8 to 34.5 MPa (2000 to 5000
psi), the makeup water must be of a higher quality. To meet this requirement,
more thorough demineralization of the water is necessary. This can be accom-
plished by either ion exchange, reverse osmosis or distillation. Regardless
of the demineralization method utilized, concentrated waste streams will be
generated containing two to ten times the concentrations of constituents found
in the original feed water.
6.1.3 Boiler Slowdown
For the purpose of this section, boilers will be classified as of
either the once-through or the drum-type design. Once-through boilers are
generally employed where high pressures and supercritical conditions are
desired. Furthermore, these types of boilers generally have no wastewater
streams directly associated with their operations. Therefore, they will not
be considered further.
Drum-type boilers, on the other hand, operate at subcritical conditions,
where the steam is in equilibrium with the liquid phase. Under such con-
ditions, the impurities in the feedwater will concentrate in the liquid
phase and must ultimately be removed as blowdown. This blowdown is the
result of an internal boiler water treatment practice which is designed to
prevent scale formation and to minimize corrosion.
Scale formation is usually the result of contacts with hot surfaces at
high temperatures, which decrease the solubility of the scale forming salts.
To combat this problem, the internal boiler treatment consists of precipita-
ting the calcium and magnesium salts with inorganic phosphate compounds to
form soft sludges. Chelating agents (ethylene diamine tetracetic acid -
EDTA, or nitrilotriacetic acid - NTA) may also be used to complex the calcium
and magnesium as well as other metallic ions. In this case, the metallic
ions are kept in solution instead.
Corrosion is usually caused by dissolved oxygen and carbon dioxide
which enters the boiler via the feedwater or through leaks in the system.
As a preventive measure, oxygen scavenging chemical additives and pH con-
trol chemicals are usually added. Sodium sulfite and/or hydrazine are
318
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added to the system to scavenge the corrosive gases. Sodium sulfite reacts
with oxygen according to the following reaction:
2Na2 S03 + 02—»*2 Na2 S04
The dissolved solids produced are undesirable in high pressure boilers.
Hydrazine is a reducing agent which reacts with oxygen according to the
following reaction:
N2 H4 + °2—*"2H2° * N2
The excess hydrazine decomposes by heat to ammonia and nitrogen.
Another means of reducing corrosion is by controlling the pH of the
boiler water. This is accomplished by the addition of alkaline compounds
which maintain the pH between 8 and 11. At this pH range, any acidic
species present will be neutralized before causing corrosion. Chemi-
cals which may be used for this purpose are neutralizing amines such as
cyclohexalamine and other alkaline additives such as caustic soda, sodium
carbonate, or ammonia (131),
As a result of this internal treatment, the blowdown from drum-type
boilers will generally contain soluble inorganic species (i.e., Na , K ,
Cl~, etc.), precipitated solids containing calcium/magnesium salts, soluble
and insoluble corrosion products, and a variety of chemical additives
(131). In addition, the boiler blowdown will have a pH in the range of
9.5 to 10 when treated with hydrazine and a pH of 10 to 11 when treated
with phosphates. Boilers in the medium pressure range will produce total
dissolved solids in the range of 100 to 500 mg/1 while high pressure
boilers will produce total dissolved solids in the range of 10 to 100
mg/1. Those plants using phosphate treatment will contain 5 to 50 mg/1
of phosphate and 10 to 100 mg/1 of hydroxide alkalinity, while those
plants using hydrazine treatment will contain 0.2 mg/1 ammonia (132).
6.1.4 Chemical Cleaning
Operational cleaning of boiler tubes is required periodically to re-
move the accumulation of scale and corrosion products. The frequency of
this operation varies from plant to plant with a range of once in 7 months
to once in 100 months (132).
319
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Basically, there are two types of methods employed in chemical clean-
ing: the soaking method and the circulation method. With the soaking
method, the boiler tubes are filled with the cleaning solution and left in
a stagnant state until the desired degree of cleaning is accomplished. With
the circulation method, the solution is pumped continuously throughout
the tubes.
Acidic and/or alkaline active reagents are used in the cleaning opera-
tions. Acidic mixtures are generally employed to dissolve all forms of
alkaline scale (i.e., CaCO-, Mg (OHK, etc.), silica scale, and corrosion
deposits containing iron (131). Where copper is found in the corrosion
deposits, a copper removing solvent may be added to the mixture. The
acidic mixtures can be either inorganic or organic acids. Table 173 is a
summary of the various combinations of acidic mixtures used in chemical
cleaning.
TABLE 173, COMMON ACIDS USED IN CHEMICAL CLEANING
Inorganic
Hydrochloric
Sulfuric
Sulfamic
Phosphoric
Hydrofluoric
Acids
(HC1)
(H2S04)
(NH2S03H)
(H3P04)
(HF)
Organic
Citric [HOC(CH
Formic (HC02H)
Hydro xyacetic
Acids
2C02H)2C02H]
(HOCH2C02H)
The inorganic acids are used primarily for the drum-type boilers while the
organic acids are applied more commonly to the once-through type. Addi-
tives, including base metal surface inhibitors, wetting agents, and complex
chelates, are often added to the acid mixture to facilitate the cleaning
process.
Alkaline cleaning solutions are used to provide additional stripping
of deposits which are passive to acidic solutions and to neutralize acid
residuals. These solutions may contain ammonium salts (sulfate or
320
-------
carbonate), oxidizing agents such as bromates, chlorates, persulfates,
nitrates, nitrites, and possibly caustic soda.
Alkaline rinses are also commonly used to neutralize or passivate
acid residuals remaining after acid cleaning. These formulations contain
ammonia, caustic soda or soda ash, EDTA, NTA, citrates, gluconates, or
other chelating agents, and may also contain certain phosphates, chromates,
nitrates or nitrites as corrosion inhibitors (131).
Frequently, power plants may purchase chemicals for chemical cleaning
operations. Although the precise composition may not be available, most
of these processes and the chemical solutions employed are similar to the
ones described above.
The resulting waste streams from these operations will vary depending
on the type of cleaning employed. The pH of the spent solution, in gen-
eral, will vary from 1.0 to 11.0 depending on the cleaning reagents used.
The waste streams generated usually have significant oxygen demand (BOD
and/or COD) and high dissolved solids.
6.1.5 Ash Handling
During the combustion of coal and oil, an ash residue is produced. The
ash residue is distributed between bottom ash and fly ash. Bottom ash falls
to the bottom of the furnace and forms a fused, clinker-type material. This
ash is usually removed by water sluicing in which the mixture of ash and
water passes through a clinker grinder and is piped to a settling pond. Fly
ash leaves the furnace with the flue gas and is collected either in dry form
from cyclones, fabric filters, and/or dry electrostatic precipitators, or
as water slurries from wet scrubbers or wet electrostatic precipitators.
After collection, the fly ash is usually sluiced to ash ponds for sedimen-
tation of solids.
Total quantities of ash produced will vary from plant to plant depend-
ing on the ash content and the quantity of coal burned (133). Coal ash
contents vary between 5 and 30 percent; more typically between 11 and 15
percent. Oil fuels also contain ash, generally in much lower content than
those found in coal. The heaviest residual fuel oil has an ash content
that rarely exceeds 0.2 wt. percent with typical values in the order of
0.1 to 0.15 wt. percent.
321
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The quantities of sluice water required for ash handling will also
vary depending on the particular plant design, location, and operating
conditions. Minimum design values range from about 1,200 to 3,000 gallons
per ton of fly ash and 2,400 to 4,400 gallons per ton of bottom ash pro-
duced, with actual quantities varying from 1,200 to 40,000 gallons per ton
of fly ash and 2,400 to 44,000 gallons per ton of bottom ash (134).
The characteristics of an ash pond effluent are primarily affected by
the ash material, the quality and quantity of sluice water and the perfor-
mance of the settling pond. Factors that affect the ash characteristics
include: the source of the coal; the method of firing; the ash fusion
temperature; and the efficiency of equipment for collecting fly ash (134).
During contact between ash and sluice water, certain salts from the
ash will be dissolved resulting in an increase of total dissolved solids
in the effluent sluice water. Common values of TDS for ash pond effluents
are 200 to 400 mg/1 above that found in the transport water where recycling
is not practiced (133). In general, total ash consists of metal oxides
such as Si02, CaO, MgO, Fe^Og, and AlpOg, and other constituents such as
S03* P2°5' and carbon residuals (135).
Oil ash contains similar constituents as coal ash, with compounds of
sodium and vanadium being the most common elements found. Some of the con-
stituents are oxides and salts of nickel, chromium and iron plus organic
metallic compounds and carbon (soot). In the effluent, the dissolution of
the sodium compounds will significantly contribute to the TDS of the sluice
water; at low pH vanadium and other heavy metals will also be present as
metal sulfates. The suspended solids are primarily silica and carbonaceous
particles.
The quality of the sluice water is also a determining factor in the
quality of the ash pond effluent. Clear effluent can be achieved at pH
above 7.0 for sluice water containing virtually no settleable solids and
20-40 mg/1 of suspended solids (133). If the sluice water contains excess
suspended solids, the clarity of the ash pond effluent will be affected.
322
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6.1.6 Wet Scrubber Systems
Currently, flue gas desulfurization (FGD) is the most common process
available for fuel sulfur removal. In the United States, lime and limestone
are the most widely used systems. The fundamental process involves the in-
jection of finely ground limestone (CaCCU) or dolomite (CaCCU-MgCO^) into
the furnace or into the hot flue gas. Approximately 20 percent of the
sulfur dioxide (SO^) will react with the limestone to form CaSCL. The re-
mainder of the S02 and the suspended calcined solids flow with the flue gas
and fly ash into a scrubbing unit where the gas is met by a counter recir-
culating liquid solution and slurry of hydrated calcium oxide and calcium
sulfate (136). During this contact between the flue gas and the liquid
solution, HSOg" and S03~ ions are formed which ultimately oxidize to S0^~
and precipitate as
Wastewater streams discharged from the scrubber system may include wash
water for the mist eliminator, moisture occluded with the sludge, and occa-
sional bleedoff. The constituents commonly found are dissolved ions contain-
ing Ca++, Mg++, S03~, S04" and solids including CaS03*0.5 H20, CaS04'2H20,
CaCCU and CaSQA (136). The wastewater streams may be routed to a settling
*3 *t
pond where the solids are allowed to settle or may be sent to a thickener
where a sludge is produced.
6.1.7 Coal Storage Piles
To assure continuous plant operation, coal-fired power plants maintain
a 75- to 90-day coal supply in active and/or inactive coal storage piles.
The inactive piles are commonly sprayed with a tar to seal their outer sur-
faces, while active sites are generally open and exposed to all ambient
conditions. Runoffs from active piles are an important waste stream dis-
charge. The waste stream contains sulfuric acid as a result of contact
between moisture, oxygen and coal, which induces the oxidation of metal sul-
fides present in the coal. The runoff has pH as low as 2 to 3.
In coal, the principal sulfide bearing minerals are pyrite and mar-
casite, where marcasite readily converts to pyrite. The acidic character-
istics of the runoff will also drive inorganic salts, present in the coal,
323
-------
into solution creating a high concentration of IDS. Specifically, high
concentrations of iron, aluminum and manganese are found with traces of
cadmium, beryllium, nickel, chromium, vanadium, zinc and copper. Consti-
tuents such as coal fines and other insoluble matter will also appear as
suspended solids in the runoff.
6.2 CRITERIA FOR EVALUATING THE ADEQUACY OF EFFLUENT DATA
The criteria for assessing the adequacy of wastewater effluent data
were developed by considering the reliability, consistency, and variability
of data. As was the case with air emissions, wastewater effluent data
were evaluated by a three-step process. In the first step, the available
data were screened for adequate definition of process and fuel parameters
that may affect wastewater discharges as well as for validity and accuracy
of sampling and analysis methods. This was the main step for judging the
reliability of data. In the second step of the data evaluation process,
effluent data deemed acceptable in Step 1 were subjected to further en-
gineering and statistical analysis to determine the internal consistency
of the test results and the variability in wastewater pollutant concentra-
tions. The mean value x of the pollutant concentration was calculated
along with the variability ts(x)/x for each pollutant/unit operation pair.
At this stage of the data evaluation process, the data base was judged to
be adequate if the variability ts(x)/x < 0.7. On the other hand, a third
data evaluation step was necessary if the variability ts(x)/x > 0.7. In
this third step, the wastewater pollutant concentration x
xu = x + ts(x)
was compared with the water MATE value based on health effects (129). x
can be considered as the upper bound for the pollutant concentration x. The
data base was judged to be adequate if x 1 MATE value, and inadequate if
x > MATE value. Since discharge severity is defined as the ratio of dis-
charge concentration to MATE value, an equivalent statement is that the data
base was adequate if the upper limit discharge severity DS 1 1 and in-
adequate if DS > 1.
In contrast to the data evaluation process for air emissions, the
ratio of the pollutant concentration to MATE value, instead of the source
324
-------
severity factor, was used here as an indicator of environmental significance,
This was because of the difficulties involved in applying the concept of
source severity factor to wastewater effluents. For wastewater discharges,
the source severity factor is defined as follows:
VD CD + S6 fl f2
VRD
3
where VD = discharge flow rate, m /s
CD = discharge concentration, g/m
SG = Teachable solid waste generation, g/sec
f, - fraction of the solid waste to water
f~ = fraction of the material in the solid waste
VR = river flow rate, m /s
3
D = drinking water standard, g/m
Of the parameters listed above, the leaching characteristics of most solid
wastes are not well known, the river flow rate is highly site dependent,
and there is no established drinking water standard for all but a few
pollutants. Thus, the use of source severity factors 1n the evaluation of
wastewater effluent data becomes impractical.
6.3 EVALUATION OF EXISTING DATA
As was discussed in Section 6.1 of this report, the major sources of
wastewater streams requiring evaluation include the following:
• Cooling water systems (cooling tower blowdown)
• Water treatment processes (ion exchange and clarification ,
waste streams)
• Boiler blowdown
• Chemical cleaning (acid phase composite, alkaline phase
composite and neutralization drain waste streams)
t Ash handling (bottom ash, fly ash and combined ash pond
overflow streams)
• Wet scrubber systems (scrubber sludge liquor)
• Coal storage piles (pile runoff)
325
-------
The sources of information and the evaluation of these existing discharge
data are described below.
6.3.1 Waste Streams from Cooling Systems
Two primary sources of discharge data were available for cooling
tower blowdown data. The first source is the Technical Report for Revision
of Steam Electric Effluent Limitations Guidelines (137) which presented
the findings of an extensive study of that section of the power generating
industry discharging industrial wastes to publicly owned treatment works
(POTW). This document provided data for six cooling towers. Parameters
mainly identified were metals such as iron, nickel, chromium, zinc and
copper. Also characterized were such gross parameters as BOD, COD, TDS,
TSS and TS. The second source of data is the Development Document For
Proposed Effluent Limitation Guidelines And New Source Performance
Standards For The Steam Electric Power Generating Point Source Category
(138). This document was prepared for the purpose of developing effluent
limitation guidelines, standards of performance for new sources, and pre-
treatment standards for the industry. Cooling tower blowdown data were
compiled for five major power plants. In addition to those parameters
identified in the first document, additional data on other constituents
were also reported (138). Table 174 is a compilation of data from these
two sources showing the mean, the number of data points (N), and the
variability of emissions data.
In Table 175, the mean and upper limit cooling tower blowdown concen-
tration values are compared with the health based water MATE values. From
the data presented in Tables 174 and 175, the existing data base character-
izing trace element concentrations in cooling tower blowdown is inadequate.
This is because data variability for trace element concentrations is large,
and data are totally lacking for the majority of the trace elements. When
compared with health based water MATE values, concentrations of sodium,
magnesium, and chromium in cooling tower blowdown appear to warrant envi-
ronmental concern. Also, the existing data base characterizing organic
concentrations in cooling tower blowdown is inadequate due to the total
lack of data.
326
-------
TABLE 174. MEAN AND VARIABILITY OF EXISTING
DATA FOR COOLING TOWER SLOWDOWN
Constituent
Flow
Alkalinity
(as CaC03)
BOD
COD
TDS
TSS
T5
Total Hardness
(as CaC03)
Oil & Grease
Sodium
Chromium
Copper
Iron
Magnesium
Nickel
Zinc
Sulfate
Chloride
Ammonia-N
Nitrate-N
Phosphate-P
Total Cyanide
Units
I/ sec
mg/1
mg/i
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Mean x
5.0
65.9
18.3
93.5
1900
38.2
3200
1800
2.96
2400
0.82
0.25
0.57
870
0.03
0.94
1700
600
0.19
2.79
3.74
0.02
No. of Data
Points
5
4
8
8
8
10
7
4
6
1
7
5
5
2
5
9
5
5
3
3
7
4
Variability
ts(x)/x
1.16
1.37
1.43
1.27
0.75
1.25
0.71
0.49
0.87
—
1.88
1.42
1.30
10.38
0.17
0.84
1.69
1.32
1.60
3.29
1.67
0.86
Source: References 137 and 138.
327
-------
TABLE 175. COMPARISON OF MEAN AND UPPER LIMIT COOLING TOWER
SLOWDOWN CONCENTRATIONS WITH MATE VALUES
Constituent
Sodium
Magnesium
Ammonia
Chloride
Chromium
Nickel
Copper
Zinc
Iron
Mean Concentrations x
mg/1
2400
870
0.19
600
0.82
0.03
0.25
0.94
0.57
X
u
mg/1
9900
0.49
1400
0.04
0.61
1.73
1.31
Health
MATE Value, mg/1
800
480
270
1200
0.25
0.22
5.0
25
1.5
ts(x)
6.3.2 Waste Streams from Water Treatment Processes
The Development Document For Proposed Effluent Limitations Guidelines
And New Source Performance Standards For The Steam Electric Power Genera-
ting Point Source Category was the primary source of information for waste-
water discharge from water treatment processes. The more commonly used
water treatment processes are ion exchange and clarification. In this
document, ion exchange waste data have been compiled for eighteen plants;
and clarification waste data were gathered for seven plants (138).
Ion exchange and clarification waste concentration data are sum-
marized in Tables 176 and 177, respectively. The mean and upper limit
waste concentrations are compared with the health based water MATE values
in Tables 178 and 179. For both waste streams, data variability for
trace element concentrations exceeds 0.7. Further, the upper limit con-
centrations of most trace elements are in excess of their health based
water MATE values. Existing data are also limited to seven trace
328
-------
TABLE 176. MEAN AND VARIABILITY OF EXISTING DATA FOR
BOILER WATER PRETREATMENT (ION EXCHANGE WASTE)
Constituent
Flow
Alkalinity
(as CaCO.)
BOD
COD
TDS
TSS
TS
Turbidity
Total Hardness
(as CaCO~)
Oil & Grease
Phenols
Sodium
Chromium
Copper
Iron
Lead
Magnesium
Nickel
Zinc
Sulfate
Chloride
Ammonia-N
Nitrate-N
Phosphate-P
Units
I/sec
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
JTU
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Mean x
2.54
560
36.4
47.6
6370
32.2
6500
57.2
1000
24.8
0.01
3200
0.27
0.55
4.24
0.160
89.0
0.16
0.38
1540
1800
18.6
9.55
6.14
No. of Data
Points
17
14
14
15
18
14
18
9
16
3
5
16
15
9
10
1
13
4
17
17
17
17
17
17
Variability
ts(x)/x
1.13
1.01
1.48
0.81
0.66
0.96
0.65
0.62
1.03
2.50
2.23
0.87
1.25
0.77
1.98
-
1.37
2.75
0.77
0.83
1.08
1.54
1.51
1.75
Source; Reference 138
329
-------
TABLE 177, MEAN AND VARIABILITY OF EXISTING DATA FOR
BOILER WATER PRETREATMENT (CLARIFICATION WASTE)
Constituent
Flow
Alkalinity
(as CaC03)
BOD
COD
TDS
TSS
TS
Turbidity
Total Hardness
(as CaC03)
Sodium
Al umi num
Chromium
Copper
Iron
Magnesium
Nickel
Zinc
Sulfate
Chloride
Ammonia-N
Nitrate-N
Phosphate-P
Units
I/sec
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/i
mg/1
mg/l
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Mean x
3.25
338
20.2
1160
3180
25200
24800
1300
3300
40.4
160
0.61
0.66
350
275
0.32
-1.47
39.1
92.5
0.57
1.27
2.79
No. of
Data Points
7
5
5
5
7
6
7
6
6
5
1
5
4
5
5
2
6
6
6
6
6
6
Variability
ts(x)/x
1.86
1.53
1.60
2.02
2.30
2.21
2.14
1.75
2.49
1.01
—
2.71
1.83
2.02
2.71
12.30
1.35
1.11
1.34
1.00
0.74
2.47
Source: Reference 138
330
-------
TABLE 178. COMPARISON OF MEAN AND UPPER LIMIT ION EXCHANGE
WASTE CONCENTRATIONS WITH MATE VALUES
Constituent
Phenols
Sodium
Chromium
Copper
Iron
Lead
Magnesium
Nickel
Zinc
Chloride
Ammonia
Mean Concentration x
mg/1
0.01
3200
0.27
0.55
4.24
0.16
89.0
0.16
0.38
1800
18.6
V
mg/1
0.03
6000
0.61
0.97
12.6
210
0.60
0.67
3800
47.2
Health MATE
Values, mg/1
0.005
800
0.25
5.0
1.5
0.25
480
0.22
25
1200
270
• x
ts(x)
TABLE 179. COMPARISON OF MEAN AND UPPER LIMIT CLARIFICATION
WASTE CONCENTRATIONS WITH MATE VALUES
Constituent
Sodium
Aluminum
Chromium
Copper
Iron
Magnesium
Nickel
Zinc
Chloride
Ammonia
Mean Concentration x
mg/1
40.4
160
0.61
0.66
350
275
0.32
1.47
92.5
0.57
V
mg/1
81.1
2.26
2.49
1060
1020
4.3
3.45
216
1.14
Health MATE
Values, mg/1
800
150
0.25
5.0
1.5
480
0.22
25
1200
270
x, = x + ts(x)
331
-------
elements. Thus, the existing data base characterizing trace element concen-
trations appears to be inadequate. However, the inorganic constituents of
water treatment wastes can often be estimated using mass balance calculations,
if the source of new water and the treatment processes involved are well
characterized. On this basis, the existing inorganic data base for water
treatment wastes can be considered to be adequate.
6.3.3 Waste Streams From Boiler_Slowdown
The sources of data for boiler blowdown were the same as those given for
cooling tower blowdown (137,138). The first reference source (137) contains
data from four plants while the second reference source (138) includes data
from twenty-one plants.
Data on boiler blowdown parameters and concentrations are presented in
Table 180. In spite of the larger data base, data variability for almost
all the trace elements and anions still exceeds 0.7. The concentrations of
the inorganic constituents of boiler blowdown, however, are considerably
lower than those of cooling tower blowdown or water treatment wastes. As
shown in Table 181, the mean concentrations of all the inorganic constituents
(for which data are available) in boiler blowdown are less than their health
based MATE values. Thus, the boiler blowdown stream is considered to be of
lesser environmental significance than the other wastewater discharge streams,
although the existing trace element data base for this waste stream is still
inadequate.
6.3.4 Haste Streams From Chemical Cleaning
The primary source of data for chemical cleaning waste streams is a
report by Chu et al. (139). This document provides data on waste streams
from acid phase composites, alkaline phase composites, and neutralization
drain wastes. For the acid phase composite and the neutralization drain
waste streams, data were acquired from six power plants; while for alkaline
phase composite waste streams, data were acquired from five power plants.
Data on acid phase composite, alkaline phase composite, and neutralization
drain parameters and concentrations are summarized in Tables 182, 183, and
184, respectively. Additionally, the mean and upper limit concentrations of
the inorganic constituents present in these waste streams are compared with
the health based water MATE values in Tables 185, 186, and 187, respectively.
332
-------
TABLE 180. MEAN AND VARIABILITY OF EXISTING
DATA FOR BOILER SLOWDOWN
Constituent
Flow
Alkalinity
(as CaCOg)
BOD
COD
TDS
TSS
TS
Turbidity
Total Hardness
(as CaCOj
Oil & Grease
Phenols
Sodium
Chromium
Copper
Iron
Magnesium
Nickel
Zinc
Total Cyanide
Sulfate
Chloride
Ammonia-N
Nitrate-N
Phosphate-P
Units
I/sec
mg/i
mg/1
mg/1
mg/1
mg/i
mg/1
JTU
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Mean x
2.64
110
3.01
53.3
1600
106
1800
16.1
460
1.6
0.026
460
0.03
0.07
0.17
88.8
0.04
0.15
0.01
66
130
0.13
0.88
6.36
No. of Data
Points
22
17
20
20
23
22
22
8
11
4
5
15
16
10
11
7
10
21
2
17
18
18
17
20
Variability
ts(x)/x
1.73
0.63
6.60
1.54
1.45
1.39
1.36
0.82
1.28
3.37
2.65
1.54
0.67
0.86
1.50
2.14
0.75
1.23
6.02
0.42
0.99
1.76
1.24
0.67
Source: References 137 and 138
333
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TABLE 181. COMPARISON OF MEAN AND UPPER LIMIT
BOILER SLOWDOWN CONCENTRATIONS WITH
MATE VALUES
Constituent
Mean Concentration x
mg/1
mg/1
Health MATE
Values, mg/1
Phenols
Sodium
Chromium
Copper
Iron
Magnesium
Nickel
Zinc
Chloride
Ammonia
0.026
460
0.03
0.07
0.17
88.8
0.04
0.15
130
0.13
1160
0.05
0.13
0.43
190
0.07
0.33
260
0.37
0.005
800
0.25
5.0
1.5
480
0.22
25
1200
270
x, , « x + ts(x)
By considering both data variability and upper limit discharge seventy
factors, the existing data base is judged to be Inadequate for the follow-
ing inorganic constituents: cadmium, chromium, copper, lead, and zinc in
acid phase composite; ammonia, phosphorus, fluoride, iron, and nickel in
alkaline phase composite; and copper, iron, sodium, and hydrazine in
neutralization drain. Thus, the inorganic data base for chemical cleaning
wastes is inadequate. There is also total lack of organic characteriza-
tion data for these waste streams, even though it is known that hydro-
acetic acid, formic acid, citric acid, and Vertan 675® (an ammoniated
salt of ethylenediaminetetracetic acid) are among the common chemical
cleaning solvents used (23).
Upper limit discharge severity, DSU, is defined as the ratio of the upper
limit concentration x., * x + ts(x) to the health based water MATE value.
334
-------
TABLE 182. MEAN AND VARIABILITY OF EXISTING DATA FOR
CHEMICAL CLEANING WASTEWATER (ACID PHASE COMPOSITE)
Constituent
Volume per cleaning
pH, units
TSS
TOC
COD
Oil & Grease
Phenols
Silica
Ammonia-N
Organic Nitrogen
Nitrate & Nitrite-N
Phosphorus
Sulfate
Aluminum
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Potassium
Selenium
Silver
Sodium
Tin
Zinc
Units
Liters
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
No.
Mean x
490,000
1.1
45.2
1180
2870
14.9
0.044
95.2
200
220
0.025
35.2
3.25
7.07
0.033
0.23
0.01
0.03
53.2
2.90
14.8
2880
2.05
7.43
19.2
0.0002
178
1.75
0.003
0.035
48.5
3.0
48.0
of Data
Points
6
6
6
6
6
6
6
5
6
6
4
6
4
4
6
4
4
6
6
6
6
6
5
4
6
4
6
4
4
4
4
4
6
Variability
ts(x)/x
0.54
1.01
0.93
1.60
1.27
0.57
0.49
1.17
0.49
1.57
1.91
0.55
2.20
0.18
0.69
1.06
0
1.24
0.43
1.32
1.22
0.46
1.29
0.34
0.50
0
0.51
0.37
0.64
0.87
0.61
1.56
1.37
Source: Reference 139
335
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TABLE 183. MEAN AND VARIABILITY OF EXISTING DATA FOR
CHEMICAL CLEANING WASTEWATER (ALKALINE PHASE COMPOSITE)
Constituent
Volume per cleaning
IDS
TSS
COD
Oil & Grease
Silica
Ammom'a-N
Organic Nitrogen
Nitrate & Nitrite-N
Phosphorus
Bromide
Chloride
Fluoride
Sulfate
Aluminum
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Potassium
Selenium
Silver
Sodium
Tin
Zinc
Units
Liters
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/i
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Mean x
575,000
1,330
66.6
89.8
5
21.1
2,740
1,300
0.305
143
30.7
175
4.8
5.25
0.28
0.02
0.1
0.01
0.001
2.33
0.005
534
2.35
0.01
1.05
0.04
0.0004
1.57
156
0.002
0.02
7.70
1
0.26
No. of Data
Points
5
5
5
5
4
4
5
5
4
5
3
4
4
4
4
5
4
4
4
4
4
5
5
4
4
4
4
5
5
4
4
4
4
5
Variability
ts(x)/S
0.31
0.55
1.48
0.72
0
1,48
0.75
1.60
1.00
1.58
3.26
1,00
0.73
2.58
0.56
1.05
0
0
0
1.40
0
0.61
0.93
0
1.92
0.41
0.92
0.98
0.91
0
1.13
1.44
0
0,88
Source: Reference 139
336
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TABLE 184. MEAN AND VARIABILITY OF EXISTING DATA
FOR CHEMICAL CLEANING WASTEWATER
(NEUTRALIZATION DRAIN)
Constituent
Volume per cleaning
pH, units
TDS
TSS
COD
Oil & Grease
Ammonia-N
Organic Nitrogen
Nitrate S Nitrite-N
Phosphorus
Copper
Iron
Sodium
Hydrazine
Units
Liters
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Mean x
195,000
11.4
3630
46.7
69.7
5.0
28.4
32.5
0.12
755
5.11
7.30
1060
0.013
No. of Data
Points
6
6
6
6
6
3
6
6
5
4
6
6
5
2
Variability
ts(x)/x
0.67
0.09
0.59
1.23
0.22
0
1.00
1.59
2.30
0.50
2.01
1.47
1.21
11.72
Source: Reference 139
Comparison of the discharge concentrations with health based water
MATE values indicated a number of chemical cleaning waste stream consti-
tuents which are of environmental concern. These constituents are: phenols,
phosphorus, chromium, copper, iron, lead, manganese, nickel, and zinc in
acid phase composite; ammonia, phosphorus, copper, iron, and nickel in
alkaline phase composite; and phosphorus, copper,' iron, sodium, and hydra-
zine in neutralization drain.
337
-------
TABLE 185. COMPARISON OF MEAN AND UPPER LIMIT CHEMICAL
CLEANING WASTE (ACID PHASE COMPOSITE) CONCENTRATIONS
WITH MATE VALUES
Constituent
Phenols
Ammonia
Phosphorus
Sulfate
Arsenic
Barium
Beryllium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Cadmium
Manganese
Mercury
Nickel
Selenium
Silver
Sodium
Tin
Zinc
Mean Concentration x,
mg/1
0.044
200
35.2
3.25
0.033
0.23
0.01
53.2
2.90
14.8
2880
2.05
7.43
0.03
19.2
0.0002
178
0.003
0,035
48.5
3.0
48.0
x *
u
mg/1
0.066
299
54.6
10.4
0.056
0.46
0.01
76.0
6.70
32.7
4200
4.69
9.96
0.07
28.7
0.0002
269
0.005
0.065
78.1
7.7
114
Health MATE
Values, mg/1
0.005
270
1.5
1300
0.25
5.0
0.03
1900
0.25
5.0
1.5
0.25
480
0.05
0.25
0.01
0.22
0.05
0.25
800
30
25.0
» x
ts(x)
338
-------
TABLE 186. COMPARISON OF MEAN AND UPPER LIMIT CHEMICAL
CLEANING WASTE (ALKALINE PHASE COMPOSITE)
CONCENTRATIONS WITH MATE VALUES
Constituent
Ammonia
Phosphorus
Chloride
Fluoride
Sulfate
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Selenium
Silver
Sodium
Tin
Zinc
Mean Concentration x
mg/1
2740
143
175
4.8
5.25
0.02
0.1
0.01
0.001
2.33
0.005
534
2.35
0.01
1.05
0.04
0.004
1.57
0.002
0.02
7.7
1.0
0.26
li,
4800
370
350
8.3
18.8
0.04
0.1
0.01
0.001
5.59
0.005
860
4.53
0.01
3.07
0.06
0.0008
3.11
0.04
0.04
18.8
1.0
0.49
Health MATE
Values, mg/1
270
1.5
1200
7.0
1300
0.25
5.0
0.03
0.05
1900
0.25
5.0
1.5
0.25
480
0.25
0.01
0.22
0.05
0.25
800
30
25.0
= x
ts(x)
339
-------
TABLE 187. COMPARISON OF MEAN AND UPPER LIMIT CHEMICAL CLEANING WASTE
(NEUTRALIZATION DRAIN) CONCENTRATIONS WITH MATE VALUES
Constituents
Ammonia
Phosphorus
Copper
Iron
Sodium
Hydrazine
Mean Concentration x,
mg/1
28.4
755
5.1
7.3
1060
0.013
*«,*
mg/1
56.7
1130
15.4
18.0
2350
0.17
Health MATE
Values, mg/1
270
1.5
5.0
1.5
800
0.0023
* x, « x + ts(x)
6.3.5 Waste Streams from Ash Handling
Effluent data for ash handling facilities were obtained primarily from
a report by Chu et al (139). These data were compiled from grab samples
taken during 1973 and 1974. Data for fly ash pond and bottom ash pone dis-
charges were taken from two power plants, while data for combined ash pond
discharges were obtained by sampling ten plants.
Fly ash pond discharge, bottom ash pond discharge, and combined ash
pond discharge data are summarized in Tables 188, 189, and 190, respectively.
Also, the mean and upper limit concentrations of the inorganic constituents
present in these waste streams are compared with the health based water MATE
values in Tables 191, 192, and 193, respectively.
Again, by considering both data variability and upper limit discharge
severity factors, the existing data base is judged to be inadequate for the
following inorganic constituents: cadmium, chromium, iron, lead, and
nickel in fly ash pond overflow; iron, manganese, nickel, and selenium in
bottom ash pond overflow; beryllium and mercury in combined ash pond over-
flow. There are no organic characterization data.
340
-------
TABLE 188. MEAN AND VARIABILITY OF EXISTING DATA FOR
ASH HANDLING (FLY ASH POND DISCHARGE)
Constituent
Flow
Total Alkalinity
(as CaC03)
Conductivity
Total Hardness
(as CaC03)
pH, units
TDS
TSS
Aluminum
Ammonia-N
Arsenic
Barium
Beryl 1 i urn
Cadmi urn
Calcium
Chloride
Chroml urn
Copper
Cyanide
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Total Phosphate-P
Selenium
Silica
Silver
Sulfate
Zinc
Units
I/sec
mg/1
uhmos/em
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Mean x
390
54
526
185
6.20
325
63.3
4.50
0.25
0.02
0.20
0.01
0.019
139
6.5
0.043
0.17
0.01
1.68
0.035
8.95
0.305
0.0007
0.58
0.05
0.0085
10.30
0.01
284
0.79
No. of Data
Points
1
1
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
Variability
ts(x)/x
__
6.86
5.24
3.69
7.15
0.15
7.61
9.15
6.35
4.94
0.64
9.03
0.27
0.96
6.94
11.16
0
1.85
7.98
7.19
0.57
6.35
11.55
8.00
9.79
2.83
0
3.33
11.73
Source: Reference 139
341
-------
TABLE 189. MEAN AND VARIABILITY OF EXISTING DATA FOR
ASH HANDLING (BOTTOM ASH POND DISCHARGE)
Constituent
Flow
Total Alkalinity
(as CaC03)
Conductivity
Total Hardness
(as CaC03)
pH, units
TDS
TSS
Aluminum
Ammonia-N
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chloride
Chromium
Copper
Cyanide
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Total Phosphate-P
Selenium
Silica
Silver
Sulfate
Zinc
Units
I/sec
mg/1
umhos/cm
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Mean x
1020
81.5
486
222
8.5
346
72.5
3.15
0.11
0.012
0.14
0.01
0.002
51.3
7.88
0.0095
0.053
0.01
5.63
0.02
6.4
0.37
0.00085
0.089
0.077
0.0065
7.55
0.01
94.0
0.12
No. of Data
Points
1
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
Variability
ts(x)/x
—
0.55
4.29
4.59
1.94
6.56
2.19
1.39
1.73
6.35
1.15
0
6.03
2.77
0.80
0.66
2.87
0
0.77
0.31
1.08
7.21
2.24
4.35
0.57
8.79
0.24
0
6.11
2.76
Source: Reference 139
342
-------
TABLE 190. MEAN AND VARIABILITY OF EXISTING DATA FOR
ASH HANDLING (COMBINED ASH POND DISCHARGE)
Constituent
Flow
Alkalinity
(as CaC03)
Conductivity
Total Hardness
(as CaC03)
pH, units
TDS
TSS
Aluminum
Ammonia-N
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chloride
Chromium
Copper
Cyanide
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Total Phosphate-P
Selenium
Silica
Silver
Sulfate
Zinc
Units
I/sec
mg/1
umhos/cm
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Mean x
770
89.0
494
196
9.51
281
34.5
1.91
0.17
0.027
0.18
<0.01
0.0014
76.5
7.17
0.015
0,041
0.01
0.80
0.013
4.16
0.079
0.0056
0.052
0.045
0.016
6.03
0.01
no
0.053
No. of Data
Points
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
Variability
ts(x)/x
0.51
0.32
0.30
0.25
0.14
0.23
0.80
0.15
0.71
0.76
0.13
0.84
0.64
0.31
0.39
0.59
0.35
0
0.69
0.18
0.61
1.14
1.56
0.13
0.50
0.82
0.15
0
0.22
0.37
Source: Reference 139
343
-------
TABLE 191. COMPARISON OF MEAN AND UPPER LIMIT FLY ASH POND
DISCHARGE CONCENTRATIONS WITH MATE VALUES
Constituent
Aluminum
Ammoni a
Arsenic
Ban" urn
Beryllium
Cadmium
Calcium
Chloride
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Phosphorus
Selenium
Silver
Zinc
Sulfate
Mean Concentration x
mg/1
4.50
0.25
0.02
0.20
0.01
0.019
139
6,5
0.043
0.17
1.58
0.035
8.95
0.31
0.0007
0.58
0.05
0.0085
0.01
0.79
284
V
mg/1
38.7
2.5
0.15
1.2
0.02
0.19
177
12.7
0.34
2.1
4.79
0.31
73
0.48
0.005
7.3
0.45
0.092
0.01
10
1230
Health MATE
Values, mg/1
150
270
0.25
5.0
0.03
0.05
1900
1200
0.25
5.0
1.5
0.25
480
0.25
0.01
0.22
1.5
0.05
0.25
25.0
1300
= x
ts(x)
Discharge concentrations of inorganic constituents in ash pond overflow
are relatively low when compared with health based water MATE values. Only
iron, manganese, and nickel in fly ash pond overflow, and iron and manganese
in bottom ash pond overflow have been identified as potential problems
because of discharge severities exceeding unity. Discharge severities of
all inorganic constituents in combined ash pond overflow are below unity.
344
-------
TABLE 192. COMPARISON OF MEAN AND UPPER LIMIT BOTTOM ASH POND
DISCHARGE CONCENTRATIONS WITH MATE VALUES
Constituent
Al umi num
Ammoni a
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chloride
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Phosphorus
Selenium
Silver
Zinc
Sulfate
Mean Concentration x
mg/1
3.15
0.11
0.012
0.14
0.01
0.002
51.3
7.88
0.0095
0.053
5.63
0.02
6.4
0.37
0.00085
0.089
0.077
0.0065
0.01
0.115
94
"V
mg/1
7.53
0.30
0.088
0.29
0.01
0.014
193
14.2
0.016
0.21
9.97
0.026
13.3
11.2
0.0028
0.48
0.12
0.064
0.01
0.43
670
Health MATE
Values, mg/1
150
270
0.25
5.0
0.03
0.05
1900
1200
0.25
5.0
1.5
0.25
480
0.25
0.01
0.22
1.5
0.05
0.25
25.0
1300
= x
ts(x)
345
-------
TABLE 193. COMPARISON OF MEAN AND UPPER LIMIT COMBINED ASH POND
DISCHARGE CONCENTRATIONS WITH MATE VALUES
Constituent
Aluminum
Ammoni a
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chloride
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Phosphorus
Selenium
Silver
Zinc
Sulfate
Mean Concentration x
mg/1
1.91
0.17
0.027
0.18
0.037
0.0014
76.5
7.17
0.015
0.041
0.80
0.013
4.16
0.079
0.0056
0.052
0.045
0.016
0.01
0.053
no
&
2.20
0.29
0.048
0.20
0.068
0.0023
100
9.97
0.024
0.055
1.4
0.015
6.70
0.17
0.014
0.059
0.068
0.028
0.01
0.073
134
Health MATE
Values, mg/1
150
270
0.25
5.0
0.03
0.05
1900
1200
0.25
5.0
1.5
0.25
480
0.25
0.01
0.22
1.5
0.05
0.25
25
1300
*xu = x + ts(x)
346
-------
6.3.6 Waste Streams from Wet Scrubber Effluents
The primary reference source for effluent data on wet scrubber systems
Is a report by Bornstein et al on reuse of power plant desulfurization waste-
water (140). Included in this report are characterization data from four
different plants using a lime or limestone wet scrubbing system.
Data on FGD system wastewater at the point of discharge to settling
ponds or disposal area are presented in Table 194. In Table 195, the mean
and upper limit discharge concentrations of the inorganic constituents
present in this waste stream are compared with the health based water MATE
values. Evaluation of the data presented indicated that the existing data
base is inadequate for the following inorganic constituents: beryllium,
calcium, chromium, iron, magnesium, manganese, nickel, selenium, sodium,
vanadium, fluoride, and sulfate. Also, similar data for waste streams
from other types of FGD systems, such as sodium carbonate and double-alkali
processes, are generally unavailable.
Discharge severities of nine Inorganic constituents in lime-limestone
scrubbing system wastewater were found to exceed unity. These nine consti-
tuents of environmental concern are: beryllium, magnesium, manganese,
mercury, nickel, selenium, sodium, chloride, and sulfate.
6.3.7 WasteStreams from Coal Storage Piles
Effluent data for coal oile runoff were obtained from a report by Cox
et al (141). In this report, two coal-fired steam plants each with a
90-day coal supply were surveyed. Plant J received its coal from eastern
Tennessee and Kentucky while plant E received its coal from western
Kentucky. The coal analyses for both plants were basically similar except
for their sulfur contents and percent of CaO in ash. Plant J had 2,1% total
sulfur while plant E had 3.9%; plant J had 1.4% CaO ash while plant E
had a 4.2% CaO ash. Data on coal pile runoff parameters and concentrations
are presented in Tables 196 and 197 for these two plants.
Since the existing data base is limited to these two plants, with no
available data characterizing runoff from western coal, the data base must
be considered to be inadequate. Examination of the data presented also
showed that among the inorganic constituents in coal pile runoff, dis-
charge severities of iron, manganese, nickel, aluminum, and beryllium
347
-------
TABLE 194. MEAN AND VARIABILITY OF EXISTING DATA FOR FSD
(LIME-LIMESTONE) SYSTEM: SCRUBBER SLUDGE LIQUOR
Constituent
Flow
pH, units
Total Alkalinity
(as CaCQ,)
IDS
COD
Total Nitrogen
Phosphate
Aluminum
Antimony
Arsenic
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Potassium
Selenium
Silicon
Silver
Sodium
Tin
Vanadium
Zinc
Chloride
Fluoride
Sulfite
Sulfate
Units
I/sec
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
rng/1
mg/1
mg/1
mg/1
Mean x
2.03
7.47
108
10150
185
0.004
0.17
0.91
0.95
0.082
0.04
27
0.026
1080
0.11
0.23
0.078
1.11
0.21
580
0.85
0.044
3.60
0.50
19.1
0.59
2.18
0.025
1100
3.5
0.34
0.15
2500
4.3
460
4700
No. of
Data Points
4
4
2
4
3
4
4
3
3
4
4
2
4
4
4
3
4
4
4
4
2
4
2
3
4
4
2
3
3
1
2
4
4
4
4
4
Variability
ts{x)/x
1.24
0.19
4.98
0.40
2.15
0.75
1.73
2.64
1.83
1.85
1.40
8.94
1.15
1.01
1.86
2.14
1.48
3.00
0.39
2.05
8.52
0.52
9.51
1.82
0.73
1.04
6.49
1.79
2.14
—
12.5
1.14
0.51
0.95
2.97
1.25
Source: Reference 140
348
-------
TABLE 195. COMPARISON OF MEAN AND UPPER LIMIT FGD SCRUBBER
(LIME-LIMESTONE) SLUDGE LIQUOR CONCENTRATIONS
WITH MATE VALUES
Constituent
Al umi num
Antimony
Arsenic
Beryllium
Boron
Cadmi urn
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silicon
Silver
Sodium
Vanadi urn
Zinc
Chloride
Fluoride
Sulfate
Mean Concentration x,
mg/1
0.91
0.95
0.082
0.04
27
0.026
1080
0.11
0.23
0.078
1.11
0.21
580
0.85
0.044
3.6
0.50
0.59
2.2
0.025
1100
0.34
0.15
2500
4.3
4700
mg/1
3.31
2.69
0.23
0.10
270
0.056
2170
0.31
0.72
0.19
4.44
0.30
1770
8.09
0.067
37.8
1.4
1.2
16.3
0.070
3500
4.6
0.32
3780
8.4
10600
Health
MATE Values,
mg/1
150
7.5
0.25
0.03
1400
0.05
1900
0.25
0.75
5.0
1.5
0.25
480
0.25
0.01
75
0.22
0.05
150
0.25
800
2.5
25.0
1200
7.0
1300
= x
ts(x)
349
-------
TABLE 196. MEAN AND VARIABILITY OF EXISTING
DATA FOR COAL PILE RUNOFF
(3.91 TOTAL SULFUR)
Constituent
Flow
pH, units
Acidity (as CaC03)
Sulfate
TDS
TSS
Iron
Manganese
Copper
Zinc
Cadmium
Aluminum
Nickel
Chromium
Mercury
Arsenic
Selenium
Beryllium
Units
I/sec
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Mean x
—
2.67
1360
2780
3600
190
380
4.13
0.23
2.18
0.002
43.3
0.33
0.007
0.004
0.02
0.001
0.014
No. of
Data Points
-
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Discharge
Severity
--
—
«• *•
—
—
250
16.5
0.046
0.085
0.04
0.29
1.5
0.028
0.4
0.08
0.02
0.47
Source: Reference 141
350
-------
TABLE 197. MEAN AND VARIABILITY OF EXISTING
DATA FOR COAL PILE RUNOFF
(2,11 TOTAL SULFUR)
Constituent
Flow
pH
Acidity (as CaCO.)
Sulfate
TDS
TSS
Iron
Manganese
Copper
Zinc
Cadmium
Aluminum
Nickel
Chromium
Mercury
Arsenic
Selenium
Beryl 1 i urn
Units
I/ sec
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Mean x
56.6
2.79
3400
5160
7900
470
940
28.7
0.86
6.68
0,001
260
2.59
0.007
0.0004
0.17
0.006
0.044
No. of
Data Points
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Discharge
Severity
__
—
~ —
—
630
115
0.17
0.27
0.02
1.73
11.8
0.028
0.04
0.68
0.1
1.5
Source: Reference 141
351
-------
exceeded unity for at least one of the two streams sampled. Thus, addi-
tional field sampling and analysis studies to characterize coal pile runoff
appear to be warranted.
6.4 WASTEWATER DATA ACQUISITION
Concurrent with field tests conducted under this study, there were a
number of projects with specific objectives of characterizing wastewater
discharges from conventional steam electric plants. These projects included
TVA studies to characterize coal pile drainage, ash pond discharges, chlo-
rinated once-through cooling water discharge, and chemical cleaning wastes
from periodic boiler-tube cleaning to remove scales, and studies conducted
by the Aerospace Corporation to provide data on the characteristics of
wastewater discharges from flue gas desulfurization systems. To minimize
duplication of efforts, only a selected number of wastewater streams were
sampled and analyzed in this program. For cooling tower blowdown, the sites
selected were the same as those for sampling of cooling tower air emissions.
For boiler blowdown and once-through cooling water, the sites selected were
the first utility sites with accessibility for sample collection. For ash
pond overflow, the sites selected were the only sites tested that utilized
settling ponds for ash disposal. The wastewater streams sampled and analyzed
included the following:
• Cooling tower blowdown - Sites 400, 401, 402, 403, 406, 407.
• Boiler Blowdown - Sites 109, 113, 114, 115.
* Once-through cooling water - Sites 206, 207, 209, 210,
211, 212, 316, 317, 318, 319.
• Fly ash pond overflow - Site 205.
* Bottom ash pond overflow - Sites 205, 208, 207/209.
• Combined ash pond overflow - Site 206.
A limited number of FGD wastewater streams were sampled and analyzed as
part of detailed Level II tests at selected sites. Results from these tests,
however, will be discussed in separate special reports. The chemical cleaning
waste stream and coal pile runoff were not sampled in this program because
these waste streams are only generated periodically, which prevented the
planning of a sampling effort into a fixed schedule. An extensive program
with specific objectives of characterizing these wastewater streams will be
needed to provide additional data.
352
-------
6.4.1 Field Testing
Field testing procedures were based on Level 1 environmental assessment
methods.
Water samples were generally taken by one or more of the following 3
methods: 1) tap sampling, 2) heat exchange sampling, and 3) dipper sampling.
A decision matrix relating stream condition to sampling procedures for
liquids and slurries is presented in Figure 16. Since all of the samples
taken were at temperatures much lower than 50°C, the heat exchange method
of sampling was not used. Detailed sampling procedures are described in the
Methods and Procedures Manual for Sampling and Analysis prepared for this
program (127).
Prior to sampling any liquid stream, available plant data concerning
the stream were recorded on a sample log sheet. Data which were required
(if available) from the plant engineer were:
t temperature
t pressure
• flow rate
• stream identification (blowdown, cooling tower, etc.)
t solid contents
Data required from the sampler were:
* temperature
t sample volume
• sampling methods used, and
• observations (sample is cloudy, has odor, etc.)
In all cases, samples were withdrawn from a point or area which provided
the most representative sample.
Tap samples were obtained on contained liquids in motion or static
liquids in tanks or drums. This sampling method was generally applicable
to cooling tower blowdown and boiler blowdown. The method involved the
fitting of the valve or stop cock used for sample removal with a length of
pre-cleaned Teflon tubing long, enough to reach the bottom of the container.
These containers were made of either high density polyethylene or polypro-
pylene. The sample line was first flushed at a high rate to remove all
353
-------
LIQUID AND
SLURRY SAMPLES
UJ
en
LIQUID
<5X
PIPES
L50°C
(HOT)
OT EX-
CHANGE
SAMPLE
<50°C
TAP
SAMPLE
SAMPLES
SOLIDS
!
SLURRY SAMPLE
>_ 5% SOLIDS
TANKS PONDS 5* TVpiPKLIDS
>50BC
(HOT)
HEAT EX-
CHANGE
SAMPLE
OPTION B
OPTION A
<50°C
TAP
SAMPLE
HTPPFR TAPPING SAMPLE
clUm ? ONLY IF A 600D
SAMPLE MIXING BEND IS
.„, .,_ flVflTI ARI T
DIPPER
SAMPLE AT 1
OUTFALL
:s
10% SOLIDS I
IN SLUICES 1
DIPPER SAMPLE
WST BE TAKEN
FIND OPENING
Figure 16. Decision Matrix for Liquid/Slurry Sampling
-------
sediments and gas pockets. The container was then rinsed with sample prior
to filling.
The dipper sampling procedure is applicable to sampling ponds or open
discharge streams. This method was used in obtaining the ash pond discharge
samples. The method involved the use of a dipper with a flared bowl and
attached handle, long enough to reach discharge areas. The apparatus was
constructed of high density polyethylene. Samples were obtained by insert-
ing the dipper into the free flowing stream so that a portion could be col-
lected from the full cross-section of the stream.
After sample recovery, certain water analyses were carried out in the
field as specified in the procedures manual. For the lab analysis of the
remaining parameters, the samples were preserved, packaged and sent air
freight. Table 198 gives general information on: 1) parameters to be
analyzed, 2) location of analysis (field or lab), 3) volume of samples
required, 4) method of analysis, and 5) sample preservation required.
6.4.2 LaboratoryAnalysisProcedures
Wastewater samples received in the laboratory were typically 10 liters
in volume. After measurement of the exact volume, wastewater samples were
extracted three times with methylene chloride. The volume of methylene
chloride used in each extraction was 5 percent of the waste sample volume.
The exact volume was measured, and the extract was then dried and concen-
trated. Analyses proceeded as described in Section 5.4.3.
Wastewater samples intended for inorganic analysis were typically 500
ml in volume. They were acidified in the field by addition of concentrated
HN03 to lower the pH to about 6. Samples thus stabilized were shipped in
acid washed Nalgene® containers. After receipt in the laboratory,
analyses proceeded as described in Section 5.4.3.
6.5 ANALYSIS OF TEST AND DATA EVALUATION RESULTS
Wastewater analysis data obtained in the current study are presented
in the following sections for:
• Waste Streams from Cooling Systems
• Waste Streams from Boiler Slowdown
• Waste Streams from Ash Ponds
355
-------
TABLE 198. LIQUID STREAM SAMPLING AND ANALYSIS PROTOCOL
General Information
Parameters to
be Analyzed
Flow
pH
Cond
TSS
Hardness
Alk. or Acid
NH3 N
Cyanide
N03-N
P04-P
S03
so4
Cl
F
Ca
Mg
K
Ka
Other Trace
Elements
Total Organics
PAH
PCB
Other Organics
.1=11=1.;.. . 3 ; J—l...........
Analysis
Location
Field
F
F
F
F
F
F
F
F
F
F
F
F
Lab
L
L
L
L
L
L
L
L
L
L
L
Vol ume
Sample Required
1 liter
,
i
200
1
800
U Orga
nl
ml
•
ic
CH2C12 Extract
Method
of Analysis
Plant
Meter
or
Bucket/Stopwatch
Portable Meter
Hach Kit
Hach Kit
Hach Kit
Hach Kit
Hach Kit
Hach Kit
Hach Kit
Hach Kit
Hach Kit
Hach Kit
Specific ion
Electrode
SSMS
GC-TCO and
Gravimetric
GC/MS
GC/MS
Sample
Preservation
Required
^T
1
•m*
None
0.
N
HN03
to
pH 2
QH2Clg Ext
Amber Bottle
with Teflon
c .- , 1
bea t
Analysis data are grouped into four categories; gross parameters, anions
and nutrients, organics , and trace elements. These data are then summarized
and compared to the existing data base for wastewater effluents presented in
Section 6.3.
Organics are subdivided into volatile (boiling range 90°-300°C) and non-
volatile (boiling above 300°C).
356
-------
6.5.1 Waste, Streams from Cooling Systems
Once-Through Cool 1ng Systems
Chemical analyses for Inlet and outlet cooling water streams are
presented in Tables 199 and 200. Variations in inlet concentration of the
constituents reported is due to the variation in makeup water quality.
Inlet and outlet analyses for gross parameters and anions show little
change for most sites. However, at Site 212, unexpected increases in
outlet pH, conductivity, alkalinity, phosphate, sulfite, sulfate, and
nitrate were recorded relative to the values of these parameters in the
inlet water. The reason for these increases is unknown. Changes in
organic levels in inlet and outlet streams at Sites 316, 317, and 318
showed no clear trend. Both increases and decreases were recorded.
Based on analysis of variabilities, the data base for inlet and outlet
once-through cooling water streams is considered adequate for pH, cyanide,
nitrate, and ammonia. For outlet cooling water, conductivity, hardness,
alkalinity, and TSS are considered adequately characterized, but are
subject to large variations. None of the parameters for which MATE con-
centrations have been established have a mean or upper limit discharge
severity exceeding unity.
Reclrculatory Cooling Systems
Cooling tov/er blowdown analyses are presented in Tables 201 and 202.
Variations in the parameters reported arise partly from the source of
cooling water (see Section 5.4.1.2). The high levels of TSS and trace
elements recorded at Site 402 is largely the result of using Colorado
River water for cooling. However, the extremely high arsenic level cannot
be explained by this reasoning. Another major source of site-to-site
variations is the additive used to control scaling, corrosion, and bio-
fouling in the cooling system (see Section 5.4.2.2). Site 400 has a high
level of phosphate in cooling tower blowdown because a phosphate additive
is used to keep solids in suspension. Add extracts of the blowdown
water samples from Sites 400 and 402 showed the highest levels of organic
compounds. Aliphatic hydrocarbons, phthalates, glycols, carboxylic
adds, and hiqh molecular weight amides were Identified 1n both samples.
357
-------
TABLE 199. INLET ONCE-THROUGH COOLING WATER ANALYSES
Constituent 206 207 209
Sross Parameters'
Flow, 1/s
pH 7.40 7.50 7.55
Conductivity, 58 510 500
Hardness 10 250 220
(as C«C03), ng/l
Alkalinity 5.0 120 100
(as CaCOj), nig/1
TSS, mg/1 0 <1 «1
,n Anlons and Nutrients
CD
Cyanide, ng/1 000
Phosphate-P. mg/1 1 0.02 0.01
Sulfite, nig/1 0 0
Sulfate, mg/1 14 5 4
Nltrate-N, nig/1 0.2 0.05 0.06
Amnonla-N, mg/1 0.32 <0.05 <0.05
Organlcs
Total Volatile,
Total Nonvolatile,
mg/1
Effluwit Characteristic*
Site
210 211 212 316 317 318 319
63 63 117,054
6.95 6.95 7.65 8.05
162 162 58 675
70 70 600 240
30 160
15 15 15 0
000 0
0.12 0.12 0.01 0.45
0 0 1.0 0
1.0 1.0 4.5 180
0.2 0.2 0.4 0.5
0.19 0.19 0.2
0.65 0.04 0.03
0 81.7 0
Environmental Impact
Mean
X
39,100
7,44
304
209
83
6.4
0
0.42
0.17
29.9
0.23
0.17
0.24
27.2
Variability Upper Limit of x MATE,
ts(x)/x x + ts(x) mg/1
4.30
0.05
0.77
0.88
0.96
1.15
0
1.78
2.57
2.05
0.67
0.65
3.68
4.30
207,000
7.80
536
391
163
13.8
0 75
1.16
0.60 53
91.3 1,300
0.38 50*
0.27 220*
1.12
144
Discharge Severity
Mean Upper Limit
0 0
0.003 0.011
0.023 0.070
0.005 0.008
0.001 0.001
"MATE concentrations for HO, and MHj are 220 and 270 nig/1, respectively. Tabulated data are for nitrate nitrogen and ammonia nitrogen,
to be compatible with analysis results.
-------
TABLE 200. OUTLET ONCE-THROUGH COOLING WATER ANALYSES
Constituent 206 207
Gross Parameters
Flow, 1/s
pH 6.45 7.65
Constructivlty, 62 510
Hardness 15 230
ias CaC03), mg/1
Alkalinity 5.0 100
(as CaC03), ngl
TSS, mg/1 5.0 <1
£S* Anioni and Nutrients
w 1 ,
Cyanide, ng/1 0 0
Phosphate-P, mg/1 2.3 0.01
Sulfite, mg/1 0
Su1f«te, m<)/1 16 4
Nitrage-H, mj/1 0.2 0.01
Aramnia-N, mg/1 0.34 <0.05
Organic:
Total Volatile,
«9/l
Total Nonvolatile,
mg/1
Efflu.
Site
209 210 211 212 316
63 63 117,054
7.65 7.45 7.45 8.25 8.05
500 165 165 245 675
220 70 75 500 240
100 60 60 60 150
<1 15 15 18 0
0000 0
0.01 0.13 0.13 0.195 0.10
0 0 18 0
4 1.0 1.0 80 180
0.06 0,4 0.4 0.8 0.1
<0.05 0.22 0.28 0.3
0
0
nt Charatctwlitlci
317
8.3
400
190
190
25
0
0.35
0
0
0,8
0.1
0.01
45.8
318
1,733
9.05
375
210
170
0
0
0.53
0
9
0.02
0.25
0.1
24.2
319
567
7.81
1,325
680
250
15
0
0.50
20
24
0.3
0.275
0
7.83
Mean
X
23,900
7.81
440
240
120
9.5
0
0.43
4.75
32
0.31
0.21
0.03
19.5
Variability
ts(i<)/5
2.71
0.062
0.051
0.60
0.46
0.69
0
1.20
1.56
1.29
0.67
0.41
2.B
1.67
Environmental
Impact
Discharge Severity
Upper Limit of x MATE,
x » ts(ii) ng/1 mean
95,600
8.30
700
390
170
16
0 75 0
9.92
12.1 53 0.090
72.9 1,300 0.025
0.52 50* 0.006
0.29 220* <0.001
0.10
51.7
Upper Limit
0
0.23
0.056
0.010
0.001
•MATE concentrations for NQ3 and NH, are 220 and 270 mg/1, respectively. Tabulated data are for nitrate nitrogen and ammonia nitrogen, to be compatible
with analysis results.
-------
TABLE 201. COOLING TOWER SLOWDOWN ANALYSES
Effluent Ch«r»ct«rlttics
Site
OJ
Ov
O
Constituent
Gross Parameters
Flow, 1/s
PH
Conductivity,
Hardness
(as CaC03), nig/1
Alkalinity
(as CaC03), Mg/1
Acidity, mg/1
TSS, mg/1
Anians and Nutrients
Cyanide, mg/1
Phosphate-P, mg/1
Sulfite, mg/1
Sulfate, mg/1
Nitrate-N, mg/1
Anmonia-N, rag/1
Organic?
Total Volatile,
mg/1
Total Nonvolatile,
400
21
6.7
2,400
600
50
150
<0.005
69.4
9
840
7.0
30
0.054
2.56
401
5.7
7.4
2,500
790
40
30
7.00
<0.005
-------
TABLE 202. COOLING TOWER SLOWDOWN TRACE ELEMENT ANALYSES
Concentration, mg/1
Trace Element
Aluminum (A1)
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Calcium (Ca)
Cadmium (Cd)
Cobalt (Co)
Chromium (Cr)
0> Cesium (Cs)
Copper (Cu)
Iron (Fe)
Potassium (K)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Vanadium (V)
Zinc (Zn)
400
0,13
0.029
1.50
0,067
160
0.012
0.056
0,13
0.001
2.0
0.36
24
39
0.047
0.011
0.061
26
0.015
0.002
0.039
22
0,018
0.004
0.55
401
0.038
0.12
0.37
0.067
0.001
130
0.006
0.021
0.004
0.001
0.10
0.13
5.4
65
0.009
0.022
0.045
4.2
0.015
0.003
0.019
17
0.005
0.009
0.027
Site
402
0.96
180*
3.3
3.0
9,700
0.53
0.011
0.32
0.012
3.3
16
240
3,300
1.7
1,5
0.18
67.00
0.22
0.041
0.42
430
0.020
0.28
42
403
0.013
0.026
0.063
0.096
0.001
32
0.001
0.001
0.003
0.13
0.042
1,6
2.7
0.002
0.003
0.052
1.4
0.001
0.001
0.001
12
0.001
0.011
0.012
406
0.15
1.2
0.044
0.096
0.001
140
0.009
0.016
0.023
0.12
6.8
61
0.006
0.004
0.11
1.5
0.001
0.002
0.006
12
0.001
0.022
0.008
407
0.16
0.001
0.19
0.006
0.001
0.44
0.003
0.009
0.001
0.003
0.092
0.073
0.006
0.006
0.003
0.011
0.023
0.004
0.002
0.002
13.00
0.013
0.001
0.045
Mean Variability
x ts(5i)/I
0.24
0.28
0.91
0,56
0.001
1,700
0.094
0.022
0.080
0.004
0.93
2.8
46
580
0.30
0.26
0.077
17
0.043
0.009
0.081
84
0.010
0.055
7.1
1.6
2.3
1.5
2.3
0
2.4
2.4
1.7
1.7
2.3
1.6
2.4
2.2
2.4
2.4
2.5
0.82
1.7
2.1
2.0
2.2
2.1
0.92
2.1
2.5
Upper Limit
of x
x+ts(x)
0.62
0.92
2.3
1.8
0.001
5,800
0,32
0.060
0.21
0.013
2.4
9.6
150
2,000
1.0
0.90
0.14
45
0.13
0.025
0.26
260
0.019
0.17
25
Environmental Impact
MATE
mg/1
150
0.25
1,400
5.0
0.03
1,900
0.05
0.75
0.25
860
5.0
1.5
230
480
0.25
75
0.22
1.5
0.25
7.5
0.05
150
30
15
25
Discharge Severity
Mean Upper Limit
0.002
1.1
0.001
0.11
0.033
0.89
1.9
0.030
0.32
<0.001
0.19
1.9
0.20
1.2
1.2
0.003
0.35
11
0.17
0.001
1.6
0.56
<0.001
0.004
0.28
0.004
3.7
0.002
0.36
0.033
3.1
6.40
0.080
0.86
<0.001
0.48
6.4
0.64
4.1
4.1
0.012
0.63
30
0.52
0.003
5.1
1.7
0.001
0.011
1.0
This data point was eliminated using the Method of Olxon, and was not used in computing the mean.
-------
Additionally, silicones were identified in the sample from Site 400. Again,
the presence of contaminants can be traced to either specific additives or
the makeup water.
Based on variabilities, the data for pH, conductivity, hardness,
alkalinity, cyanide, sulfate, and nonvolatile organics are considered
adequate. With the possible exception of beryllium, all trace element
data are considered inadequate.
flean discharge .severities equal or exceed unity for seven species in
cooling tower blowdown, while eleven upper limit discharge severities meet
this criterion. High levels of sulfate and phosphorus in the discharges
are due to cooling tower additives, hean trace element concentrations are
heavily influenced by the high values recorded at Site 402, thus high mean
discharge severities may be biased due to the small number of samples (six
in most cases).
6.5.2 Uaste Streams from Boiler Blowdown
Boiler blowdown analyses are presented in Tables 203 and 204. Based
on variabilities, data for pH, TSS, cyanide, sulfite, barium, and vanadium
are considered adequate.
The mean discharge severity for phosphorus 1s quite high, probably
due to the addition of phosphate complexing agents to prevent scale forma-
tion. The upper limit discharge severity for iron also exceeds unity,
most likely due to the presence of corrosion products in the blowdown.
6-5.3 V.'aste Streams from Ash Ponds
Wastewater analyses of overflows from coal ash ponds are presented in
Tables 205 and 206. Sites 205-4, 207, and 208 are bottom ash ponds; Site
2Q5-3 is a fly ash pond; and Site 206 is a combined pond. The character-
istics of ash pond effluents are affected by the ash material itself, the
quantity and quality of water used for sluicing, and the performance of
the settling pond. In addition, Chu et al (135) have shown that large
seasonal variations in the values of gross parameters occur In individual
ash ponds.
362
-------
TABLE 203. BOILER SLOWDOWN ANALYSES
OJ
ot
u>
Efflu»nt ChvKtwisttcs
Constituent
gross Parameter?
Flow, 1/s
pK
Conductivity,
unho/on
Hardness
(as CaC03), mg/1
Alkalinity
(as CaCOs), mg/1
TSS, mg/1
An Ions and Nutrients
Cyanide, mg/1
Wiospnate-P, mg/1
Sulfite, mg/1
Sulfate, mg/1
NUrate-N, mg/1
Amnonla-N, mg/1
Organ Ics
Total Volatile,
Total Nonvolatile,
Total Organlcs,
mg/1
Site
109 113 114
0.132 0.22 0.54
10.90 10.65 11.0
425 70 80
<1 .0 50 <1 .0
30 10 30
<5.0 <5.0 <5.0
<0.1 <0.1 <0.1
255 75 26
<1.0 •d.O <1.0
115 <1.0 d.O
<0.1 0.005 0.275
<0.02 <0.0t <0.02
0.06 0.9 2.2
18.6 0 0
18.7 0.9 2.2
Hear
115 x
0.54 0.36
9.45 10.50
19 150
<1.0 13
<5.0 19
<5.0 <5.0
<0.1 <0.1
5.5 90
<1.0 «1.0
<1 .0 29
0.75 0.28
0.1, 0.04
2.0 1.3
<0.1 4.7
2.0 6.0
Variability
0.95
0.108
2.0
2.9
1.1
0
0
2.0
0
3.2
1.9
1.6
1.2
3.2
2.3
Environmental Impact
Upper Limit of x MATE,
x + ts(x) mg/1
0.70
11.6
440
52
40
5
0.1 75
270
1.0 53
120 1,300
0.81 50*
0.1 220*
2.9
19
20
Discharge Severity
Mean Upper Unit
<0.001 0.001
<0.019 0.019
0.22 0.92
0.006 0.016
<0.001 <0.001
•MATE concentrations for N03 and NH3 are 220 and 270 mg/1, respectively. Tabulated data are for nitrate nitrogen and amonla
nitrogen, to be compatible with analysis results.
-------
TABLE 204. BOILER SLOWDOWN TRACE ELEMENT ANALYSES
OJ
tft
Concentration, mg/1
Site
Trace Element
Aluminum (Al)
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Calcium (Ca)
Cadmium (Cd)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Iron (Fe)
Potassium (K)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na) .
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (SI)
Tin (Sn)
Vanadium (V)
Zinc (In)
109
0,022
0.18
0.075
0.014
< 0.001
0.058
< 0.003
0.003
0.046
0.45
0.75
0.12
0.14
0.038
0.15
15.0
0.045
7.4
0.05
< 0.002
0.097
0.40
0.005
0.003
0.24
113
0.16
0.003
0.009
0.017
< 0.0001
0.69
0.017
< 0.004
0.002
0.40
0.67
0.15
1.0
0.034
< 0.003
1.8
0.029
22.0
0.021
< 0.002
< 0.019
0.26
< 0.009
< 0.002
0.26
114
0.15
0.005
0.009
0.017
0.001
0.051
< 0.004
< 0.002
0.035
0.12
0.73
0.21
0.047
0.006
< 0.004
12.0
0.023
30.0
0.021
< 0.002
< 0.002
0.70
0.037
0.002
0.20
115
0.31
< 0.003
0,018
< 0.006
0.001
0.59
0.012
< 0.001
0.073
0.075
2.7
1.7
0.27
0.036
< 0.011
12.0
0.092
4.90
< 0.015
< 0.007
< 0.006
0.76
0.009
0.004
< 6.002
• Mean
ST
0.16
0.048
0.028
0.014
0.0008
0.35
0.009
0.003
0.028
0.26
1.2
0.55
0.36
0.029
0.042
10
0.047
16
0.027
< 0.003
0.031
0.53
0.015
0.003
0.18
Variability
ts(x)/x
1.17
2.9
1.8
0.61
1.1
1.6
1.2
0.8
1.5
1.2
1.3
2.3
1.9
0.84
2,9
0.90
1.1
1.2
0.94
1.2
2.3
0.72
1.6
0.55
1.1
Upper Limit
Of X
x+ts(x)
0.348
0.19
0.078
0.022
0.002
0.89
0.020
0.005
0.070
0.57
2.8
1.8
1,1
0.053
0.16
19
0.097
35
0.052
0.007
0.102
0.91
0.039
0.004
0.36
Environmental
MATE
mg/1
150
0.25
1,400
5.0
0.03
1,900
0.05
0.75
0.25
5.0
1.5
230
480
0.25
75
800
0.22
1.5
0.25
7.5
0.05
150
30
15
25
Impact
Discharge Severity
Mean
0.001
0.19
0.001
0.003
0,03
< 0,001
0.18
0.003
0.11
0.052
0.81
0.002
0.001
0.11
0.001
0.013
0.22
11
0.11
< 0.001
0.62
0.004
< 0,001
< 0.001
0.007
Upper Limit
0.002
0.75
< 0.001
0,004
0.05
< 0.001
0.39
0.006
0.28
0.11
1,9
0.008
0.002
0.21
0.002
0.024
0.44
23
0.21
0.001
2.0
0.006
0.001
< 0.001
0.015
-------
TABLE 205. ASH POND OVERFLOW ANALYSES
Effluent CtW*ct*ristlcs
Constituent
Gross Parameters
Flow, 1/s
pH
Conductivity, pmho/cir
Hardness (as CaK^J, rng/1
Alkalinity (as CaO>33, mg/1
TSS, mg/1
52 Anions and Nutrients
Cyanide, mg/1
Phosphate-P, mg/1
Sulflte, rug/1
Sulfate, rng/1
Nitrate-N, mg/1
Ammonia-N, mg/1
Organics
Total Volatile, mg/1
Total Nonvolatile, mg/1
205-3
17.96
5.0
30,000
2,350
5
<20
<0.005
0.05
<0.5
0.016
3.3
1.22
0
0.056
205-4
3.07
6.8
28,000
230
30
<20
< 0.005
0.03
<0.5
750
4.4
0.122
0
0.121
Site
206-3
189.5
5.7
350
75
5
< 20
<0.005
0.05
<0.5
62.5
1.1
0.0244
0
0.070
208-3
126. 2
7.5
250
105
85
< 20
<0.005
0.04
<0.5
16.6
2.2
0.005
0.02
0.049
207/9-3
3,049
5.9
550
245
30
<20
<0.005
0
<0.5
83
4.4
0
0
0.080
Mean Variability
x" ts(x)/x
677
6.2
12,000
600
31
<20
<0.005
0.03
'0.05
180
3.1
0.27
0.0004
0.075
2.44
0.20
1.6
2.0
1.3
0
0
0.76
0
2.2
0.58
2.4
2.8
0.47
Environmental Impact
Upper
Limit
of x MATE
x+ts(x) mg/1
2,330
7.4
31 ,000
1,800
72
20
0.005 75
0.06
0.05 53
580 1,300
4.9 50*
0.93 220*
0,02
0.11
Discharge Severity
Upper
Mean Limit
<0.001 <0.001
<0.001 0.001
0.14 0.45
0.062 0.097
0.001 0.004
-------
TABLE 206. ASH POND OVERFLOW TRACE ELEMENT ANALYSES
Concentration, mg/1
Trace Element
Aluminum (Al)
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Calcium (Ca)
Cadmium (Cd)
Cobalt (Co)
w Chromium (Cr)
§} Cesium (Cs)
Copper (Cu)
Iron (Fe)
Potassium (K)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (SI)
Tin (Sn)
Vanadium (V)
Zinc (Zn)
205-3
0.31
26
0.52
0.086
0
91
<0.004
0.005
0.005
0.014
0.082
0.16
54
260
0.13
0.17
0.029
0.011
<0.005
<0.002
0.013
8.6
<0.003
0.023
0.035
205-4
0.11
11
1.0
0.066
<0.001
190
<0.012
0.94
0.003
0.011
0.070
0.37
220
2,000
0.017
0.35
0.12
0.032
< 0.016
0.027
0.019
1.1
<0.010
< 0.001
0.028
Site
206-3
0.055
0.007
0.031
0.17
0
11
< 0.001
0.002
0.001
0
0.002
0.015
4.6
1.4
0.023
0.042
4.0
0.005
0.008
< 0.001
0.002
0.014
1.1
< 0.00
0.008
0.005
208-3
0.11
0.027
0.008
0.018
< 0.001
17
< 0.002
< 0.001
0.001
< 0.001
< 0.001
0.059
1.6
5.7
0.001
< 0.002
11
< 0.001
0.005
< 0.003
< 0.001
< 0.001
0.52
< 0.002
< 0.001
< 0.001
207/9-3
1.1
0.11
0.26
0.096
<0.001
34
< 0.002
0.005
0.002
<0.001
0.008
0.91
6.5
29
0.19
0.010
30
0.041
0.043
<0.003
<0.001
0.002
8.6
<0.002
0.001
0.015
Mean Variability
x ts(x)/x
0.34
7.4
0.36
0.087
<0.0006
69
<0.004
0.19
0.002
0.005
0.033
0.30
62
460
0.072
0.11
15
0.039
0.020
<0.006
0.007
0.010
4.0
<0.004
0.007
0.017
1.6
1.9
1.4
0.79
1.1
1.4
1.3
2.7
0.87
1.5
1.5
1.5
1.8
2.3
1.4
1.6
2.2
1.5
1.1
1.3
2.1
1.0
1.3
1.3
1.7
1.1
Upper Limit
of X
x+ts(x)
0.88
22
0.87
0.16
0.001
160
0.01
0.71
0.004
0.014
0.082
0.76
170
1,500
0.18
0.30
48
0.099
0.041
0.013
0.021
0.020
9.2
0.008
0,019
0.035
Environmental
MATE
mg/1
150
0.25
1,400
5.0
0.03
1,900
0.05
0.75
0.25
860
5.0
1.5
230
480
0.25
75
800
0.22
1.5
0.25
7.5
0.05
150
30
15
25
Impact
Discharge Severity
Mean
0.002
30
< 0.001
0.017
0.02
0.036
« 0.08
0.25
0.01
< 0.001
0.007
0.20
0.27
0.96
0.29
0.002
0.019
0.18
0.013
< 0.022
0.001
0.20
0.027
< 0.001
< 0.001
0.001
Upper Limit
0.006
86
0.001
0.031
0.04
0.085
0.2
0.95
0.02
< 0.001
0.016
0.50
0.76
3.2
0.70
0.004
0.061
0.45
0.027
0.052
0.003
0.39
0.061
<0.001
0.001
0.001
-------
Of all constituents and trace elements analyzed, only the data for pH,
cyanide, sulfite, nitrate, and nonvolatile organics show variabilities less
than 0.7, and can be considered adequate. However, since no highly alkaline
ponds were sampled, the pH data base may be somewhat inadequate. Because
pH is an important parameter in determining ash pond chemistry, the limita-
tions of the data base for other measured parameters become apparent.
Arsenic was the only trace element exhibiting a mean discharge severity
of greater than unity. The upper limit discharge severity for magnesium
was also greater than one.
6.5.4 Other Waste Streams
No data were collected during the current study on the following liquid
effluents streams:
§ Waste Streams from Water Treatment Processes
• VJaste Streams from Equipment Cleaning
• Waste Streams from Wet Scrubber Effluents
* Waste Streams from Coal Storage Piles
Some analysis data on scrubber sludge are presented in Section 7.5.2.
6.5.5 Summary of Hastewater Effluents
In general, data obtained in this study for gross parameters, anions,
nutrients, organics, and trace elements are subject to large plant-to-plant
variations. Comparing data from the present study to the existing data
bases for wastewater discharges, it is apparent that many discrepancies
exist. This may reflect both highly variable nature of wastewater discharges
and the small number of samples obtained relative to the entire utility
boiler population. While combination of the present data with existing
data may result in a more meaningful data base, even the new data base may
have major inadequacies. The present study has been instrumental in
applying Level I techniques to identification of wastewater constituents
which pose potential environmental problems. Further studies using Level
II techniques will be required to adequately characterize wastewater
effluents from utility boilers.
367
-------
Cooling Systems
For once-through cooling water, no data base exists for comparison to
the results of this study. No trace element analyses were performed.
Therefore, the data base for once-through cooling water is considered in-
adequate.
Figures 17 and 18 show the mean concentrations of wastewater constituents
in cooling tower blowdown for the existing data base ("old data"), the data
from the present study ("new data"), and the combined data base ("combined").
Numbers above the bars indicate the number of data points used in the
computation of means. The figures only compare mean discharge concentra-
tions for which "old" and "new" data were available. Of all parameters
compared, only data for hardness (as CaCOg) are considered adequate for
both the "old" and "new" data bases. The "new" mean values for 6 of the 13
parameters compared differ by more than a factor of three from the "old"
means.
Based on the combined data base, three species of environmental concern
in cooling tower blowdown are sulfate, phosphate, and iron. These species
-2 3
are present either as additives (SO* and PO. ) or corrosion products
(iron). New data (from the current study only) also indicate that arsenic,
cadmium, magnesium, manganese, and selenium have mean discharge severities
greater than one, while calcium, zinc, and silicon have upper limit dis-
charge severities greater than one. Previous studies indicate chloride has
an upper limit discharge severity greater than one.
Bo Her Blowdown
Figures 19 and 20 compare data from the existing data base and the
present study for mean concentrations of wastewater constituents 1n boiler
blowdown. None of the data for these parameters are considered adequate
for both "old" and "new" data bases. The "new" rcean values for 11 of the
14 parameters compared differ by more than a factor of three from the "old"
means.
Based on the combined data base, phosphate (from additives) and iron
(a corrosion product) are of environmental concern in boiler blowdown.
New data (fron; the present study only) also indicate that selenium has an
368
-------
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10 Hardness Alkalinity TSS Phosphate-? Sulfate N1trate-N Ammonla-N
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Figure 17. Comparison of Cooling Tower Slowdown Data
from Present Stu4y to Existing Data Base
Numbers above bars indicate data sets used in calculating means.
Old data = existing data base. New data = results of this study,
369
-------
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Figure 18. Comparison of Trace Element Data from Present Study
to Existing Data for Cooling Tower Slowdown
Numbers above bars indicate data sets used in calculating means.
Old data = existing data base. New data = results of this study,
370
-------
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Figure 19. Comparison of Boiler Slowdown Data from
Present Study to Existing Data Base
Numbers above bars indicate data sets used in calculating means.
''"Old data = existing data base. New data = results of this study,
371
-------
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Figure 20. Comparison of Trace Element Data from Present Stucly
to Existing Data for Boiler Slowdown
Numbers above bars indicate data sets used in calculating means.
Old data = existing data base. New data = results of this study,
372
-------
upper limit discharge severity greater than one. Previous studies indicate
sodium has an upper limit discharge severity greater than one.
Ash Pond Overflow
For ash pond overflow, present results and existing data can be com-
pared for 25 parameters. This has been done for each pond type: bottom
ash, fly ash, and combined ash ponds.
Three sets of data for bottom ash pond overflow were obtained during
this study. They supplement the existing data base, which consisted of two
data sets. With the exception of a few of the gross parameters, the
variabilities for data in the combined data base are greater than 0.7,
thus, the data base is considered inadequate. Neither cyanide nor beryllium
was detected at concentrations above the detection liinit during the present
or previous studies. The "new" mean values for 15 of the 25 parameters
compared differ by more than a factor of three from the "old" means. Figure
21 shows the mean values for trace element concentrations in bottom ash
pond overflow computed by combining "old" and "new" data bases.
Based on examination of the combined data base for bottom ash ponds,
iron has a mean discharge severity greater than one, and could be of
environmental concern. Upper limit discharge severities for magnesium and
manganese exceed one. Using the combined data base, mean arsenic concen-
tration in bottom ash pond overflow exceeds Its MATE* value. However,
arsenic concentrations found in the present study are about two orders of
magnitude higher than those from previous studies. Thus, the combined
data base for arsenic may be biased on the high side.
Only one set of data for fly ash pond overflow was obtained during
this study. Two data sets comprised the existing data base. For the com-
bined data base, only the data for calcium exhibits variability less than
0.7, and Is considered adequate. The "new" mean values for 18 of the 25
parameters compared differ by more than a factor of three from the "old"
means. Figure 22 shows the mean values for trace element concentrations in
fly ash pond overflow computed by combining "old" and "new" data bases.
Mean concentrations of manganese and nickel exceed their MATE values
in fly ash pond overflow and are, therefore, of environmental concern.
373
-------
i AS .
S
KTHN CONtrNTRflTION, MICROGRB
o o o o c
~
I
I
Al As Ea
P
Be
\
I
I
I
Ca Cd
I
1
I
7?
%
I
P
I
\
I
I
I
I
I
_,
I
RN VRLUC*
%
i
\
Cr Cu Fe Hg MB N1 fb Se Zn
L"Lt"ML"NT
Figure 21. Mean Trace Element Concentrations In Bottom Ash Pond Overflow
Obtained by Combining Data from Present and Past Studies
Means are based on five data sets. Value for Be Is a maximum concentration,
374
-------
or
or
u
I
• i fit ,
t-
-------
Upper limit discharge severities for cadmium and iron are greater than one,
indicating that these elements may also pose environmental problems upon
discharge. Arsenic appears to be present in concentrations well above its
MATE value. However, as noted above, arsenic concentrations reported in
this study may bias the results.
A single set of data for combined ash pond overflow was obtained during
the present study. This data set was combined with the ten existing data
sets for combined ash pond overflow. The resulting data base is considered
adequate for 18 of the 25 parameters compared, based on variabilities.
Beryllium was never present above its detection limit in any of the 11
samples, and cyanide was reported only twice above its detection limit.
None of the 25 parameters compared have mean or upper limit discharge
severities greater than one. Figure 23 shows the mean values for trace
element concentrations in combined ash pond overflow computed by combining
"old" and "new" data bases.
In terms of total discharge severity for the measured ash pond cons-
tituents, the ordering of pond types from highest to lowest severity is as
follows:
Bottom ash ponds > Fly ash ponds > Combined ash ponds
6.6 DATA RELIABILITY
As is the case with air emissions, the quality of the data character-
izing wastewater discharges depends on the parameters and waste streams
sampled and analyzed. Estimates of the data quality can be made based on
the sampling and analysis techniques employed, and data from round robin
tests conducted. In the current program, parameters analyzed by the Hach
kit included pH, acidity, alkalinity, conductivity, hardness, TSS, NO,",
S 2S S.
PO^", SOj , SO^ , CN~, and NH^-N, The estimated precision and accuracy of
the Hach kit analyses results are presented in Table 207. Based on the
normal concentrations of wastewater discharges from conventional steam-
electric power plants, accuracy for the parameters measured was typically
within 30 percent.
In wastewater characterization, the principal area of data uncertainty
is again any trace element data determined using SSMS. SSMS data are semi-
376
-------
or
t
z" !0> '
§ I0« •
'0' •
1C" -
1
I
1
I
A] As
1
Ba
1
Be
1
!
773
1
Ca Cd
573
1
1
I
i
1
1
1
1
1
I
Cr Cu Ft Mg Hn
ELEMENT
1
I
MEftN
1
N1 Pb
i
VflLUC*
1
Se
1
1
In
Figure 23. Mean Trace Element Concentrations in Combined Ash Pond Overflow
Obtained by Combining Data from Present and Past Studies
Means are based on eleven data sets. Value for Be is a maximum
concentration.
377
-------
TABLE 207. ESTIMATED PRECISION AND ACCURACY OF
HACH KIT ANALYSES RESULTS*
Wastewater Parameter standlrdle^tion Bias
Acidity 10 mg/1 Unknown
Alkalinity 5 mg/1 -10%
Specific conductance 10 I - 51
Total hardness 10 mg/1 - 3%
pH 0.2 units -0.01 to 0.07 units
Nitrate nitrogen 0.3 mg/1 -0.07 to 0.1 mg/1
Phosphate phosphorus 0.1 mg/1 -0.008 to 0.023 mg/1
Sulfite 9 % -1 to 1 mg/1
Sulfate 12 mg/1 -4.1 to 0.1 mg/1
*
Source; Reference 127. Data are unavailable on the precision and accura-
cy of Hach kit analyses for TSS, cyanide, and ammonia nitrogen.
quantitative and should be considered useful only for screening purposes.
For example, ash pond overflow arsenic concentrations found in the present
study determined by SSMS are about two orders of magnitude higher than those
from previous studies determined by AAS. Confirming analysis will be needed
to determine whether these differences in arsenic concentrations are due to
variations in coal arsenic concentrations and plant operating practices, or
the results of errors in SSMS analysis.
Accuracy for organic analysis was discussed previously in Section 5.6.
Typically, error limits for TCO (volatile organics), gravimetric (non-
volatile organics), and TCO + gravimetric analyses are within ± 15 percent
of the expected value. Error limits for 6C/MS analysis are typically ± 30
percent of the expected value.
378
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7. SOLID WASTES
7.1 SOURCE AND NATURE OF SOLID WASTES
Fly ash and bottom ash from coal combustion are the principal solid
wastes generated by fossil fuel-fired steam electric plants. During the com-
bustion of coal, an ash residue is produced which consists of inorganic
mineral constituents and trace amounts of incompletely burned organic matter.
The ash residue is distributed between fly ash and bottom ash. The heavier
particles fall to the bottom of the furnace as bottom ash. The fly ash is
entrained in the flue gas stream, and is subsequently collected in particulate
control devices such as electrostatic precipitators. Only a small fraction
of the fly ash, as a result of control device inefficiency, is released to
the atmosphere. It was estimated that 45,500 Gg of fly ash, 13,200 Gg of
bottom ash, and 4,900 Gg of boiler slag (for wet bottom furnaces) were pro-
duced in 1978.
For oil combustion, the magnitude of the ash disposal problem is much
less significant when compared to coal combustion. Ash content 1n fuel oil
generally ranges between 0.10 and 0.15 percent, as compared to 11-15 percent
for coal. For a typical 1,000 MW oil-fired steam electric plant, the ash
produced per year amounts to approximately 2 Gg versus the 320 Gg per year
for a 1,000 MW coal-fired steam electric plant. Additionally, most of the
oil ash generated is entrained in the flue gas stream and emitted to the
atmosphere.
Two other major solid wastes generated by fossil fuel-fired steam elec-
tric plants are scrubber sludges from flue gas desulfurization (FGD) systems
and sludges from water treatment processes. Scrubber sludges are generated
by boilers equipped with nonrecovery FGD processes, Including lime/limestone
scrubbing, alkaline fly ash scrubbing, sodium carbonate scrubbing, and the
double alkali process. The principal components of the solid phase of FGD
sludges are calcium sulfate and/or calcium sulfite hydrates, along with vary-
ing amounts of calcium carbonate, unreacted lime, and fly ash. The ratio of
379
-------
calcium sulfate to calcium sulfite 1n F6D sludges depends primarily on the
extent of oxidation occuHng within the system, and the sulfur content of the
fuel (25). For high sulfur coals, the calcium-sulfur salts 1n the FGD sludge
Is consisted mostly of calcium sulfite. However, it 1s possible to remove
S02 under forced oxidation conditions to produce FGD wastes with high ratios
of calcium sulfate to calcium sulfite, with essentially all the calcium
sulfate present as gypsum (CaS04*2H20). The amount of fly ash 1n the FGD
sludge depends on whether the scrubber is used as the principal particulate
control device in addition to S02 removal, and whether separately removed fly
ash is admixed with the FGD sludge to Improve its physical characteristics
(dewaterbiHty, shear and compression strength).
Makeup water is required in the condensate-feedwater cycle of fossil fuel-
flred steam electric plants to compensate for boiler blowdowns, steam soot-
blowing, steam atomlzation of fuel oil, venting losses and boiler tube leakage.
The required quality of the water makeup 1s primarily a function of boiler
operating pressure and heat transfer rates (23). Modern supercritical boilers
require ultra pure water as makeup, whereas a reasonably good quality municipal
water may be used without prior treatment for very low pressure boilers.
A variety of water treatment techniques is used in power plants to meet
the makeup water quality requirements. These include screening, sedimentation,
filtration, clarification with chemical coagulants, softening precipitation,
1on exchange, reverse osmosis, distillation, and electrodlalysls. The wastes
generated from these water treatment processes depend on the raw water quality,
the degree of treatment required, and the process employed. The general
characteristics of these wastes are summarized in Table 208. The largest
quantities of solid wastes are produced by clarification with chemical coa-
gulants and by softening precipitation. Wastes from these two processes are
discussed in detail in Section 7.3.2.
7.2 CRITERIA FOR EVALUATING THE ADEQUACY OF EMISSIONS DATA
The criteria for assessing the adequacy of emissions data were developed
by considering the reliability, consistency, and variability of data. As was
the case with air emissions, solid waste data were evaluated by using a three-
step process. In the first step, the available data were screened for
380
-------
TABLE 208. CHARACTERISTICS OF WASTES GENERATED
BY WATER TREATMENT PROCESSES
Treatment Process
Waste Characteristics
Screening
Sedimentation
Filtration
Clarification
Softening
Sodium Cation Exchange
Reverse Osmosis
Distillation
Electrodialysls
Demineral1zat1on
(Complete 1on exchange)
Bulk solids such as wood, timber, rags, paper
products and other organic debris.
Settleable wastes consisting of organic and
inorganic soil constituents and other debris.
Sludge of suspended fines and miscellaneous
organic matter.
Chemical sludge and settled matter. Solids
content of 3,000 to 15,000 mg/1. Chemical com-
position is dependent on type of coagulant
used.
Chemical sludge and settled matter. Major
constituent is calcium carbonate 1n Hrne soda
softening.
Dissolved calcium, magnesium and sodium
chlorides.
Raw water with concentrated quantities of raw
water solubles. Chelating agents utilized to
prevent calcium sulfate and calcium carbonate
deposition on the membranes.
Raw water with concentrated quantities of raw
water solubles.
Rejected cations and anlons. Small quantities
of colloidal and suspended solids.
Dissolved sol Ids from feed plus excess rege-
nerants
Source; References 23 and 142.
381
-------
adequate definition of process and fuel parameters that may affect solid
waste generation as well as for validity and accuracy of sampling and analysis
methods. This was the main step for judging the reliability of data. In
the second step of the data evaluation process, emission data deemed accept-
able in Step 1 were subjected to further engineering and statistical analysis
to determine the internal consistency of the test results and the variability
in solid waste pollutant concentrations. The mean value x of the pollutant
concentration was calculated along with the variability ts(x)/x for each
pollutant/unit operation pair. At this stage of the data evaluation process,
the data base was judged to be adequate if the variability ts(x)/x < 0.7. On
the other hand, a third data evaluation step was necessary if the variability
ts(x)/x > 0.7. In this third step, the solid waste pollutant concentration
*u
xu = x + ts(x)
was compared with the MATE value for land disposal of solid wastes based on
health effects, x can be considered as the upper bound for the pollutant
concentration x. The data base was judged to be adequate if x < MATE value,
and inadequate if xy > MATE value. A corollary to this third step was when
leachate data were available, the leachate pollutant concentration x can be
compared with the water MATE value based on health effects. Again, the data
base for the solid waste was judged to be adequate if xy (leachate) S MATE
value (water) and inadequate if x (leachate) > MATE value (water).
In addition to the general approach outlined above, fuel analysis, mass
balance, and physico-chemical considerations can often be used to establish
the adequacy of data base for solid waste emissions. For example, with the
exception of a few volatile elements, the concentrations of the inorganic
constituents of coal ash can be determined from coal trace element analysis
by mass balance. For these elements, an adequate characterization of the
coal feed will in turn provide an adequate characterization of the coal ash.
Another example is the characterization of sludges generated from water treat-
ment process. The quantity, as well as the concentrations of the sludge
components, can be determined by mass balance from the quality of the raw
water, the desired purity of the treated water, and the amount of process
382
-------
additives and/or regenerants used. In this case, the data base for water
treatment sludges is considered to be adequate 1f the water treatment process
1n utility applications is sufficiently well characterized.
In contrast to the data evaluation process for air emissions, the ratio
of the pollutant concentration to MATE value, instead of the source severity
factor, is used here as an indicator of environmental significance. This
was because of the difficulties involved in applying the concept of the
source severity factor to solid waste discharges. For solid wastes, the
source severity factor is defined as follows:
VRD
where SG - solid waste generation, g/sec
f, s fraction of the solid waste to water
f0 « fraction of the material in the solid waste
3
VD s river flow rate, m /s
3
D * drinking water standard, g/m
Of the parameters listed above, the leaching characteristics of most solid
wastes are not well known, the river flow rate is highly site dependent, and
there is no established drinking water standard for all but a few pollutants.
Thus, the use of source severity factors in the evaluation of solid waste
emission data becomes impractical.
7.3 EVALUATION OF EXISTING DATA
7.3.1 Fly Ash and Bottom Ash
The ash content of coal varies between 3 to 32 percent, and more typi-
cally between 10 and 15 percent. During the combustion process, the coal ash
is distributed between fly ash and bottom ash. The distribution of the ash
between the fly ash and bottom ash fractions is a function of the boiler
firing method, the type of coal (ash fusion temperature), and the type of
boiler bottom (dry or wet) (67). The relative distribution of fly ash and
bottom ash by boiler firing method is presented in Table 209. The ash pro-
duced by pulverized dry bottom coal -fired boilers is usually distributed as
70 to 90 percent fly ash and 10 to 30 percent bottom ash. Pulverized wet
bottom coal-fired boilers are designed to handle coal with low ash fusion
383
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TABLE 209. DISTRIBUTION OF COAL ASH BY BOILER TYPE
Furnace Type
Pulverized Dry Bottom
Pulverized Wet Bottom
Cyclone
Stoker
Percent of Ash
Fly Ash
80
65
13.5
60
Produced
Bottom Ash
20
35
86.5
40
Source: References 23, 35, 36, and 67.
temperature and process a much larger proportion of the bottom ash (in the
form of slag) than the dry bottom boilers. In cyclone fired boilers, the
melting point for the ash 1s exceeded 1n the furnace section, and therefore
80 to 90 percent of the ash is melted and collected as slag. Stokers emit a
smaller proportion of fly ash than the pulverized coal-fired boilers, and
this fly ash is relatively coarse.
The fly ash discharged from the furnace generally consists of spherical
partlculates ranging in diameter from 0.5 to 100 ym (67), Cenospheres, which
are silicate glass spheres filled with nitrogen and carbon dioxide, have been
found to comprise as much as 5 percent by weight or 20 percent by volume of
the fly ash (143). These are very lightweight particles that float on ash
pond surfaces.
In dry bottom boilers, the bottom ash 1s composed of gray to black,
angular particles with porous surfaces (67). In wet bottom boilers, the
bottom ash fraction, 1n the form of slag, 1s consisted of angular black par-
ticles with a glassy appearance.
The chemical composition of coal ash depends largely on the geology of
the coal deposit. Coal ash is primarily an Iron-aluminum silicate with
calcium, magnesium, sodium, potassium, titanium, phosphorus, and sulfate as
the other major (>1 percent) and minor (0.1 to 1 percent) constituents. The
384
-------
variation 1n coal ash composition according to coal rank for these major and
minor constituents 1s shown In Table 210. For all coal types, the major and
minor constituents make up 95 to 99 percent of the coal ash. Additionally, as
shown In Table 211, analysis of various coal ashes Indicates that the distri-
bution of these major and minor constituents 1s approximately the same in the
fly ash and bottom ash fractions.
The trace element concentrations for various types of coal are described
1n Section 5.3.1. With the exception of the volatile elements, the other trace
elements present 1n coal are distributed into the fly ash and bottom ash frac-
tions. The volatile elements, which are primarily discharged to the atmosphere
1n the vapor phase, include chlorine, bromine, mercury, and sulfur. For certain
of the other trace elements, there 1s definite partioning between the fly ash
and the bottom ash. In Table 212, 1t Is shown that arsenic, boron, cadmium,
copper, fluorine, mercury, nickel, lead, selenium, and zinc are preferentially
concentrated in the fly ash as compared with the bottom ash. Nevertheless,
because fly ash and bottom ash are usually combined and disposed together, there
1s no need to provide Individual characterization for these two ash fractions.
Further, characterization of the feed coal will in turn provide adequate
characterization of the Inorganic constituents of the combined coal ash, with
the exception of the volatile elements. For the volatile elements, the concen-
tration levels present 1n the coal ash are below their MATE values, and no
longer of environmental concern. Thus, the inorganic data base for coal ash
can be considered to be adequate because of the adequate characterization of
the Inorganic content of coal, as indicated 1n Section 5.3.1.
Data on the organic components present 1n the coal ash are extremely
limited. Van Hook has analyzed coal ash for hydrocarbon content, and reported
a total detected concentration of about 9 ppm (144). The concentrations for the
individual hydrocarbon compounds are presented in Table 213, which Indicates
that the C17 to C32 hydrocarbons were all in the 300 to 820 ppb range. The
lighter (C15, Clg) and heavier (C33, C34) hydrocarbons were found to be in
lower concentrations. For the same ash, Van Hook also analyzed for the presence
of POM compounds. As summarized 1n Table 214, the total POM concentration was
estimated to be a maximum of about 0.2 ppm. Also, POM compounds known to be
carcinogenic, such as benzo(a)pyrene, were not detected.
385
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TABLE 210. VARIATIONS IN CHEMICAL COMPOSITION OF COAL ASH
WITH RANK FOR THE MAOOR AND MINOR CONSTITUENTS
*
Constituent ,
S102
A12°3
Fe2°3
CaO
MgO
Na20
K20
so3
P2°5
Ti02
Ash
Anthracite
48-68
25-44
2-10
0.2-4
0.2-1
—
—
0.1-1
--
1.0-2
4-19
Coal
Bituminous
7-68
4-39
2-44
0.7-36
0.1-4
0.2-3
0.2-4
0.1-32
-------
TABLE 211. HAJOR AND MINOR CONSTITUENTS IN FLY ASH AND
BOTTOM ASH FRACTIONS FROM COAL-FIRED UTILITY BOILERS
*
Constituent ,
Si02
A1203
FC2°3
CaO
MgO
Na20
*2°
so3
P2°5
Ti02
Plant 1
Fly
Ash
53.
27.
3.8
3.8
0.96
1.88
0.9
0.4
0.13
0.43
Bottom
Ash
58,.
25.
4.0
4.3
0.88
1.77
0.8
0.3
0.06
0.62
Plant 2
Fly
Ash
57.
20.
5.8
5.7
1.15
1.61
1.1
0.8
0.04
1.17
Bottom
Ash
59.
18.5
9.0
4.8
0.92
1.01
1.0
0.3
0.05
0.67
Plant 3
Fly
Ash
43.
21.
5.6
17.0
2.23
1.44
0.4
1.7
0.70
1.17
Bottom
Ash
50.
17.
5.5
13.0
1.61
0.64
0.5
0.5
0.30
0.50
Plant 4
Ash
54.
28,
3.4
3.7
1.29
0.38
1.5
0,4
1.00
0.83
Bottom
Ash
59.
24.
3.3
3.5
1.17
0.43
1.5
0.1
0.75
0.50
Plant
5
Fly Bottom
Ash Ash
NR
NR
20.4
3.2
NR
NR
NR
NR
NR
NR
NR
NR
30.4
4.9
NR
NR
NR
0.4
NR
NR
Plant 6
Fly
Ash
42,
17.
17.3
3.5
1.76
1.36
2.4
NR
NR
1.00
Bottom
Ash
49.
19.
16.0
6.4
2,06
0.67
1.9
NR
NR
0.68
Source: Reference 67.
Analysis is performed for the Individual elements and reported as their oxides. This is not meant to indicate that
the actual compounds present are oxides.
NR - Not reported.
-------
TABLE 212. TRACE ELEMENT CONSTITUENTS IN FLY ASH AND
BOTTOM ASH FRACTIONS FROM COAL-FIRED UTILITY BOILERS
Trace Element
Arsenic (As), ppm
Beryllium (Be), ppm
Boron (8), ppm
Cadmfum (Cd), ppm
Chromium (Cr), ppm
Cobalt (Co), ppm
oo Copper (Cu), ppm
00
Fluorine (F), ppm
Mercury (Hg), ppm
Manganese (Nn ) , ppm
Nickel (Ni), ppm
Lead (Pb), ppm
Selenium (Se), ppm
Vanadium (V), ppm
Zinc (Zn), ppm
Plant
Fly
Ash
12.
4.3
266.
0.5
20.
7.
54.
140.
0.07
267.
10.
70.
6.9
90.
63.
1
Bottom
Ash
1.
3.
143.
0.5
15.
7.
17.
50.
0.01
366.
10.
27.
0.2
70.
24.
ny
Ash
8.
7.
200.
0.
50.
20.
128.
100.
0,
150.
50.
30.
7.
150.
50.
Plant 2
Bottom
Ash
1.
7.
125.
5 0,5
30.
12.
48.
50.
01 0.01
700.
22.
30.
9 0.7
85.
30.
Plant 3
ny
Ash
15.
3.
300.
. 0.5
150.
15.
69.
610.
0.03
150.
70.
30.
18.0
150.
71.
Bottom
Ash
3.
2,
70.
0.5
70.
7.
33.
100.
0.01
150.
15.
20.
1.0
70.
27.
Plant
Fly
Ash
6.
7.
700.
1.0
30.
15.
75.
250.
0.08
100.
20.
70.
12.0
100.
103.
4
Bottom
Ash
2.
5.
300.
1.0
30.
7.
40.
85.
0.01
100.
10.
30.
1.0
70.
45.
Plant
Fly
Ash
8.4
8.0
NR
i.44
206.
6.0
68.
624.
20.0
249.
134.
32.
26.5
341.
352.
5
Bottom
Ash
5.8
7.3
NR
1.08
124.
3.6
48.
10.6
0.51
229.
62.
8.1
5.6
353.
150.
Plant
Fly
Ash
110.
NR
NR
8.0
300.
39.
140.
NR
0.05
298.
207.
8.0
25.
440.
740.
6
Bottom
Ash
18.
NR
NR
1.1
152.
20.8
20.
NR
0.028
295.
85.
6.2
0.08
260.
100.
Source: Reference 67.
NR - Not reported.
-------
TABLE 213. ESTIMATED HYDROCARBON
CONCENTRATIONS IN COAL ASH
Component
C15
C16
C17
C18
C19
C20
c21
C22
C23
C24
C25
C26
C27
C28
C29
C30
C31
C32
C33
C34
Total
Concentration, ppb
Trace
192
608
740
383
308
528
548
480
308
319
366
516
664
816
660
596
344
199
66
8,6 ppm
Source: Reference 144.
389
-------
TABLE 214. ESTIMATED POM CONCENTRATIONS IN COAL ASH
POM Compound
Concentration,
ppb
Naphthalene
2-Methylnaphthalene
1-Methyl naphtha!ene
Blphenyl
1,6- and/or 1,3-D1methyl naphtha!ene
2,6-01methyl naphthalene
1,5- and/or 2,3-D1methylnaphtha!ene
9,10-D1hydroanthracene
Phenanthrene
2-Methylanthracene
1-Methylphenanthrene
Fluoranthene
Pyrene
1,2-Benzofluorene
2,3-Benzof1uorene
1-Methylpyrene
Pi cene
Total
8.3
5.0
5.2
10.3
Trace
Trace
Trace
12.6
17.6
9.1
<24.8
<13.4
<19.0
36.8
11.8
Trace
Trace
<0.2 ppm
Source: Reference 144.
ash can exceed its MATE value, and the concentration of 7»12-dimethy!benz(a}-
anthracene in both fly ash and bottom ash can be of the same order of magnitude
as Its MATE value. Because of the limited amount of data and the potential
presence of organic compounds at levels of environmental concern, the organic
data base for coal ash is considered to be inadequate.
390
-------
7.3.2 wastes from Water Treatment Proces ses
Solid wastes generated by water treatment processes include residues
from chemical coagulation, precipitates from softening, filter backwash water,
oxides from iron and manganese removal, and spent brines from regeneration
of ion exchange and reverse osmosis units. Of the above, sludges produced
by chemical coagulation and softening precipitation are the largest sources
of water treatment wastes. For this reason, wastes from these two processes
will be the focus of this section.
7.3.2.1 Residues from Chemical Coagulation
The coagulants that are most commonly used in water treatment are: 1}
those based on aluminum, such as aluminum sulfate, ammonia and potash alum,
and sodium aluminate; and 2) those based on iron, such as ferric sulfate,
ferrous sulfate, chlorinated copperas, and ferric chloride. Since these
aluminum and iron salts are used to accomplish coagulation, hydrated aluminum
and iron oxides, often referred to as aluminum and ferric hydroxides, are the
chief constituents of sludges from chemical coagulation processes. In addi-
tion, these residues contain entrained particulate matter. The entrained
particulate matter is mostly inorganic in nature and consists of fine sands,
silts, and clay. The absorbed organic fraction of the residue is small and
fairly stable.
In review of the literature, no specific data on solid wastes generated
by water treatment processes in power plants were available. As a result,
sludge characteristics from water treatment plants, using the same processes,
were assumed similar to that produced by power plants and presented here.
Table 215 shows some of the characteristics of alum sludge produced by four
different plants. Normally, the pH of the slurry is near neutral, in the
range of 6 to 8. The high COD to BODg ratio is a further indication of the
stability of the organic matter present. As shown in the table, the solid
concentration is generally between 0.5 to 2 percent.
Data from two reference sources (137, 145) were used to determine the
quantities of water treatment sludges produced. In Table 216, data on
average turbidities, coagulant dosages, and the estimated solids production
of selected United States water supplies are summarized.
391
-------
TABLE 215. CHARACTERISTICS OF ALUM SLUDGE
Plant
A
B
C
D
BOD,
mg/1
41 (5-day)
72(7-day)
144 (27-day)
90 (5- day)
108( 5-day)
44(5-day)
COD,
mg/1
540
2,100
15,500
—
pH
7.1
7.1
6.0
7.1
Total
Sol i ds
mg/1
1,159
10,016
16,830
—
Volatile
Sol i ds
mg/1
571
3,656
10,166
—
Total
Suspended
Solids
mg/1
1,110(0.11)
5,105(0.5%)
19,044(1.9%)
15,790(1.6%)
Volatile
Suspended
Solids
mg/1
620
2,285
10,722
4,130
TABLE 216. AVERAGE TURBIDITIES AND ESTIMATED SOLIDS PRODUCTION OF
SELECTED UNITED STATES WATER SUPPLIES EMPLOYING COAGULATION
Average
Location Raw Hater
Turbidity
Baltimore, Maryland (Liberty
Reservoir)
Patterson, New Jersey (Wanaque
Reservoi r)
Albany, New York (Alcove Reservoir)
Erie, Pennsylvania (Lake Erie)
Buffalo, New York (Lake Erie)
Akron, Ohio (Reservoirs)
Washington, D.C, (Potomac River)
Philadelphia, Pennsylvania
Torresdale (Delaware River)
Belmont (Schuykill River)
Cincinnati, Ohio (Ohio River)
Columbus, Ohio (Reservoirs)
Dublin Road
Morse Road
3
10
5
9
12
5
49
126
32
70
no
63
Precipitated
Coagulant,
mg/1
5(A1)
5(A1)
5(A1)
5(A1)
5(A1)
5(A1)
5(A1)
5(A1)
5(A1)
7(Fe)
5(A1)
5(A1)
Estimated
Solids
Production,
mg/1
8
15
10
14
17
10
55
132
37
78
216
68
Source: Reference 145.
392
-------
The quantities of sludge solids produced were calculated from the tur-
bidity of the water and the alum dosage applied. The turbidity values
corresponding to the intake water from various power plants were obtained
from Reference 137. Coagulant dosages usually range between 5 and 50 mg/1,
with 30 mg/1 being the most common. While the turbidity of different and
individual surface waters may vary greatly with time and season, the coagu-
lant dosages applied are relatively constant. Thus, a value of 30 mg/1 of
coagulant dosage was used throughout in the calculations. With these two
parameters, the quantities of sludge solid, as presented in Table 217, were
estimated by using the following relationship (146):
Sludge soHds, mg/l . (Alum dosage. „,/! , rawwate^ ^
From Tables 216 and 217, the quantities of alum sludge produced are shown
to be between 8 and 216 mg/1 of throughput, with an average value of 30 mg/1.
Using an average intake flow rate of 1,100 m /hr for a 1000 MW power plant
(19), the total sludge solids produced per day should range between 77 and
680 Mg/yr. While the data presented here are for those sludges based on
aluminum, similar equations could be applied to those sludges based on iron.
7.3.2.2 Residues From Softening by Chemical Precipitation
The softening of hardwaters yields a sludge free of extraneous inorganic
and organic matter consisting mainly of calcium carbonate, magnesium hydrox-
ide, and unreacted lime. The composition of the sludge varies with the
characteristics of the raw water and the dosages of chemicals used. Table
218 shows the results of the chemical analysis of dry solids from three
water-softening plants.
Jackson turbidity units (JTU) - When visual methods involving measurement
of the interference to the passage of light are used to determine turbidity,
the values obtained are expressed in JTU.
393
-------
TABLE 217. ESTIMATED SLUDGE SOLIDS PRODUCED BY ALUM COAGULATION
Plant No.
1
2
3
4
5
6
7
8
9
10
11 .
12
13
14
15
16
17
18
19
20
21
22
Intake water*
turbidity (JTU)t
' 1
9
14
13
18
15
5
13
34
0.9
62
15
5
2
0.3
3
5
1
17
23
4.0
1.8
Alum dosage
rag/1
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
Sludge solids
rag/1
9
17
21
21
26
23
12
21
42
8
70
23
12
9
7
11
12
9
24
30
12
9
*
Source: Reference 137.
JTU - Jackson turbidity units. These are units used when turbidity is
determined by visual methods in instruments such as the Jackson candle
turbidimeter.
394
-------
TABLE 218. CHEMICAL COMPOSITION OF DRV SOLIDS FROM WATER SOFTENING
Constituent
Silica, iron and aluminum
oxi des
Calcium oxide, CaO
Magnesium oxide, MgO
Loss on ignition or C00
L.
Equivalent CaCO.,
Boulder Ci
Nevada
2.6
48.8
7.0
38.4
87.2
Percent by Weight
ty, Miami,
Florida
1.5
52.1
2.8
43.8
93.0
Cincinnati ,
Ohio
4.4
49.3
2.2
40.2
88.1
Source: Reference 145.
For these waters, the precipitates are about 90 percent calcium carbon-
ate plus 2 to 7 percent magnesium oxides. These results are, however, not
entirely typical, since many softening plants produce residues with much
higher proportions of magnesium oxides.
Data from two reference sources (145, 147) were used to estimate the
quantities of sludge produced by softening precipitation. In Table 219,
data on plants capacities, quantities of lime fed, and quantities of sludge
produced for five different plants are presented. While these data are from
water treatment plants, it can be assumed that power plants treating boiler
feedwater by softening precipitation will produce similar quantities of
sludge per water throughput.
Sludge solids production was also estimated by using the analyses of
typical surface waters and groundwaters in the United States, and applying
the lime-soda ash equations (147). In this case, the excess lime treatment
method was employed. This method calls for lime addition as defined in the
equations, plus the addition of excess lime in the amount of 35 mg/1 CaO
above the stoichiometric requirements. In addition, the practical limits
395
-------
TABLE 219. ESTIMATED SOFTENING SLUDGE PRODUCTION
Location
Pontlac, Michigan
Miami, Florida
Lansing, Michigan
Dayton, Ohio
St. Paul , Minnesota
Water Plant
Rated Capacity,
million gallons/day
10
180
20
96
120
Lime Fed,
mg/1
264
216
264
257
119
Sludge Solids
Produced,
mg/1
659
475
599
634
285
Source: Reference 145.
of precipitation softening were assumed to be 30 mg/1 of CaCOg and 10 mg/1
of MgCQHk as CaCOj (146). The results of these calculations are presented
in Table 220, with breakdown of the quantities of CaCOg and Mg(OH)2 sludges
produced. As in Table 218, the sludges are 90 percent or greater CaCOj
with 10 percent or less Mg(OH)2- From Tables 219 and 220, the expected
quantities of sludge produced will range somewhere between 84 and 659 mg/1,
with an average of around 408 mg/1. Using the average intake flow rate of
o
1,100 m/hr for a 1000 MW power plant (19), the total sludge solids produced
should range between 800 and 6,400 Mg/yr. Thus, softening processes should
produce quantities of sludge greater than chemical coagulation by more than
an order of magnitude.
While the quantities of sludge from chemical coagulation are less than
those from softening precipitation, these coagulation sludges are more
difficult to handle. For example, aluminum hydroxide sludges are gelatinous
in consistency, which makes them difficult to dewater. The settled sludges
396
-------
TABLE 220. QUANTITIES OF SOLIDS PRODUCED IN WASTE SLUDGE
FROM LIME-SODA ASH SOFTENING
Surface Water and/or
Groundwater in U.S.
Samples*
1
2
3
4
5
6
7
8
CaC03
mg/1
84
202
268
475
437
144
578
215
Mg(OH)2
mg/1
0
8
15
61
49
9
70
10
Total Solids
mg/1
84
210
283
536
487
152
648
224
*
Source: Reference 147.
have low solids concentrations, usually between 0.2 and 2.0 percent, with
iron precipitates being slightly denser than alum sludges. In contrast,
calcium carbonate from softening precipitation provides a compact sludge
easy to handle while magnesium hydroxide, like aluminum hydroxide, is gel-
atinous and does not consolidate well by gravity settlings. However, since
magnesium hydroxide constitutes a small percentage of the total softening
sludge, coagulation sludges are more difficult to handle and dewater than
those produced by softening precipitation.
7.3.3 Wastesfrom Flue Gas Desulfurization Systems
Flue gas desulfurization systems currently in full scale commercial
application are either throwaway, dual alkali, or regenerable type systems.
Throwaway systems employ direct contact of the flue gas with a lime- or
limestone-based reagent resulting in a calcium sulffte/calcium sulfate
(generally dihydrate) product slurry. Dual alkali systems differ from
throwaway type systems in that the reagent is based on a soluble sodium
397
-------
salt; a reagent bleed stream is reacted with lime to yield a calcium sulfite/
sulfate product slurry. Throwaway and dual alkali type systems comprise
the majority of full scale commercial units in use. Regenerate processes,
such as Hellman-Lord, produce directly usable byproducts such as sulfur or
sulfuric acid and, therefore, do not generate sludges for disposal. Hence,
the throwaway and dual alkali type systems are of principal interest in
terms of the sludge disposal problem.
Sludge production rates vary significantly among units due to a number
of variables influencing sludge characteristics. Important variables that
affect sludge production include the following:
t Coal consumption rate
t Coal sulfur and ash contents
• Upstream particulate removal efficiency
§ Scrubber S00 and particulate removal efficiencies
• Reagent type and purity
• Percentage excess reagent
t Sulfite-to-sulfate ratio
t Efficiency of dewatering
General approaches for estimating FGD sludge production rates have been
presented in several publications. Approximation data as well as a detailed
approach for specific sites have been presented by EPRI for lime-based
scrubber systems (148). Dry sludge production rate estimates for lime and
limestone systems have been presented by Slack and Potts (149). Dry sludge
production rates depend primarily upon fuel sulfur content, fly ash loading
and stoichiometric excess of reagent. Fuel sulfur and ash levels vary wide-
ly depending upon the source seam and the extent of cleaning prior to
utilization. Although fuel sulfur concentrations may exceed 6 percent,
typical concentrations are on the order of 2 percent for bituminous coal
and 0.6 percent for lignite. Typical fuel ash contents range from 11 to 15
percent and, as discussed in Sections 4.2 and 5.3, the particulate loading
at the scrubber inlet will additionally depend upon the type of furnace and
particulate control device employed. Stoichiometric excess is generally
398
-------
from 10 to 15 percent in newer lime-based FGD systems but can range from 5
to 30 percent. Limestone-based FGD systems generally employ a somewhat
greater stoichiometric reagent excess than do lime-based units. Wet sludge
generation rates additionally depend on sulfite/sulfate production ratio.
The chemical composition of FGD sludges is largely dependent upon the
same variables influencing sludge production rates and, as such, is also
subject to a wide range of variation. Solid phase sludge components consist
primarily of calcium-sulfur salts, calcium carbonate, unreacted lime, inerts
and/or fly ash. The ratio of calcium sulfite to calcium sulfate will depend
principally upon the extent to which reagent oxidation occurs. Available
data indicate that naturally oxidized lime-based sludges have sulfite/sulfate
molar ratios ranging from 2.6 to 8.6 with an average of 4.5 while ratios for
limestone-based sludges range from 2.1 to 8.5 with an average of 3.3 (150).
Other things being equal, high sulfite sludges are more difficult to dewater
than sludges with high sulfate contents. This is a result of the platelet
type structure of sulfite crystals which tends to entrap water. On the other
hand, sulfate crystals are blocky and elongated, and dewater readily. For
this reason, forced oxidation of scrubber sludges is being studied at several
utility FGD units (151, 152, 153). Analyses of major solid phase FGD sludge
components are presented in Table 221 for nine sludge samples. These data
illustrate the compositional variation among scrubber sludges.
Trace elements in FGD sludges are primarily input with fly ash and/or
lime or limestone. The quantity of trace elements contributed by makeup
water is generally insignificant in comparison. Sludge fly ash concentra-
tions are highly variable, depending upon the extent of particulate removal
prior to scrubbing. Systems utilizing ESP's or efficient mechanical collec-
tion devices may have little, if any, fly ash in the FGD sludge. However,
fly ash thus collected may ultimately be admixed with sludge to effect
dewatering and improve sludge handling properties. On the other hand, SOg
scrubbers which also function as particulate control devices may produce
sludges containing 20-60 percent fly ash. Highly volatile trace elements
present in coal such as arsenic, mercury, and selenium may be present in
flue gas as vapors. Concentrations of these volatile elements in sludge
depend primarily on their concentrations in the fuel and on the efficiency
399
-------
TABLE 221. IDENTIFICATION OF CHEMICAL PHASES OF FGD SLUDGE
o
o
Facility
Kansas City Power 4 Light
Hawthorn 4
Commonwealth Edison
Will County 1
City of Key West
Stock Island
Kansas City Power & Light
La Cygne
Arizona Public Service
Choi la
Arizona Public Service
Choi la
Tennessee Valley Authority
Shawnee - Turbulent Contact
Absorber 3 dates
Southern California Edison
Mohave
Louisville Gas and Electric
Paddy's Run 6
Southern California Edison
Hohave 2
Tennessee Valley Authority
Shawnee
Duquesne Light Company
Phillips
Utah Power and Light
Gadsby
General Motors
Parma
Gulf Power
SchoU
Coal
Source
Eastern
Eastern
Eastern
Eastern
Western
Western
Eastern
Eastern
Eastern
Western
Eastern
Western
Eastern
Eastern
Western
Eastern
Eastern
Absorbent
Limestone
Limestone
Limestone
Limestone
Limestone
Limestone
Limestone
Limestone
Limestone
Limestone
L1me
Lime
L1me
Lime
Double
Alkali
Double
Alkali
Double
Alkali
Method of
Parti culate
Control
Marble bed
Venturi
Mechanical
Collector
Venturi
Flooded Disc
Scrubber
Electrostatic
Precipltator
El ectrostati c
Precipltator
CaSO,«%!,0
17
50
20
40
15
10.8
18.5
21.4
21.8
8.0
94
2
48.8
12.9
0.2
12.9
65-90
Weight
'G'aSd .fN.O
23
IS
5
15
20
17.3
21.9
15.4
31.2
84.6
2
95
6.3
19.0
63.8
48.3
5-25
Percent 01
CaCOj
15
20
74
30
0
2.5
38.7
20.2
4.5
6.3
0
0
2.5
0.2
10.8
7.7
2-10
F Chemical
Fly Ash
45
Ib
1
15
65
58.7
20.1
40.9
40.1
3.0
4
3
40.5
59.7
8.6
7.4
Nil
Phase
Other
14.3CaS20-6H,0
4.6 MgSQ.-6H_Q
3.7 MgSO^»6HfO
K9 MgS04-6H|o
1.5 NaCl
1.9 MgS04'6H?Q
9.8 CaSj010
17.7 CaS04
19.2 Ca$04«*jH20
6.9 Na?S04'7HzO
Source: Reference 150.
-------
with which they are captured in the scrubber. Sludge concentrations of
highly volatile trace elements are essentially independent of the efficiency
of participate removal prior to scrubbing.
Trace element data for FGD waste solids are provided by Rossoff et al
(154) and Weir et al (155). Ranges of trace element concentrations indi-
cated by these sources are presented in Table 222. These data cover a total
of seven utility sites. Average trace element concentrations and data
variability based on the combined data are presented in Table 223.
TABLE 222. TRACE ELEMENT RANGES IN FGD WASTE SOLIDS
Constituent
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Germanium
Lead
Manganese
Mercury
Molybdenum
Nickel
Selenium
Sodium
Vanadium
Zinc
Chloride
Fluoride
Sulfate
Sulfite
*
Aerospace Corp.
Data (ppm)
...
0.6 - 52
...
0.05 - 6
___
0.08 - 4
105,000 - 268,000
10 - 250
8-76
...
0.23 - 21
...
0.001 - 5
—
___
2-17
(4.8)
...
45 - 430
(0.9)
...
35,000 - 473,000
1,600 - 302,000
EPRI Data1"
(ppm)
4.3
4.0
20
1.5
41.8
.4
1.6
38.9
1.0
1.6
56
.01
8.0
13
2.1
50
13.9
266
- 7.5
- 12
- 4400
- 2.0
- 211
- 25
...
- 5.2
- 104
- 5.9
- 290
- 340
- .101
- 81
- 75.2
- 4.1
—
- 100
- 2050
...
- 1017
...
...
Data from a 4 utility site survey (154).
Data is from a 3 utility site survey (155).
401
-------
TABLE 223. MEAN TRACE ELEMENT CONCENTRATION IN FGD SLUDGES*
Element
Sb
As
Ba
Be
B
Cd
Cr
F
Ge
Hg
Pb
Mn
Mo
Ni
Se
V
Zn
Cu
Mean Concentration
ppm
6.2
10.7
—
2.5
107.2
6.2
33
744.3
3.1
.81
58.2
181.0
32.9
38,0
6.8
83.3
415.8
47.6
No. of
Data Points
3
7
3
7
3
7
7
7
3
7
7
3
3
3
7
3
7
7
Variability
.67
.95
3.64
.97
2.11
1.46
1.39
1.39
2.02
1.66
1.69
1.99
3.15
2.14
.68
.86
1.62
.69
Combined EPRI and Aerospace data.
Due to the limited quantity of published data, the existing inorganic
and organic data bases for FGD sludges are inadequate. However, extensive
sludge characterization efforts are in progress under the direction of EPA
and EPRI. These efforts will ultimately produce an adequate data base.
For this reason, no attempt was made during this program to acquire suffi-
cient sludge data to upgrade the existing data base to an adequate quality.
402
-------
7.4 SOLID WASTE DATA ACQUISITION
7.4.1 Samples Acquired
The evaluation of existing emissions data indicated the inadequacy of
the organic data base for coal fly ash and bottom ash, and the inadequacy
of the inorganic and organic data bases for FGD sludges. The inorganic data
base for coal ash, on the other hand, is considered to be adequate because
of the adequate characterization of the inorganic content of coal. Similar-
ly, the inorganic data base for water treatment wastes is considered to be
adequate, because the inorganic constituents can be calculated from mass
balances based on knowledge of the source of raw water and the treatment
processes involved.
To correct for deficiencies in the data base, a selected number of
solid waste streams were sampled and analyzed in this program. The primary
objective was to collect coal fly ash and bottom ash samples for organic
analysis. Only a limited effort was made to characterize scrubber sludge
wastes. This was because: 1) only three sites tested during this program
utilized FGD systems, and 2} extensive scrubber sludge characterization
studies are in progress under the direction of EPA and EPRI. Solid waste
samples were mostly acquired from test sites with accessibility for fly ash
and bottom ash collection. The solid waste streams sampled include the
following:
• Fly ash from bituminous coal combustion - Sites 205-1,
205-2, 206, 137, and 204.
* Bottom ash from bituminous coal combustion - Sites 132,
137, and 206.
• Fly ash from lignite combustion - Sites 314, 315, 318,
316, 317, and 319.
• Bottom ash from lignite combustion - Sites 314, 315, 318,
316, 317, and 319.
• Scrubber .sludge - Site 135.
7.4.2 Laboratory Analysis Procedures
Samples of solid wastes were desiccated upon receipt. Typically, 100
gram allquots were weighed for soxhlet extraction for organic analysis. Five
to 10 grams aliquots were weighed for aqua regia digestion. After these
403
-------
sample preparation steps, organic and inorganic analyses proceeded as des-
cribed in Section 5.4.3. If the sample was not finely divided, e.g., a slag,
it was grounded and riffled prior to desiccation,
7.5 ANALYSIS OF TEST AND DATA EVALUATION RESULTS
7.5.1 Fly Ash and Bottom Ash
Inorganic Data
Elemental analyses of fly ash and bottom ash from bituminous coal-fired
utility boilers sampled are presented in Tables 224 and 225. Analyses of the
trace elements were principally performed by SSMS. Mercury was determined
by cold vapor analysis and fluoride analyses, as noted, were performed with a
selective ion electrode. Although furnace firing type is noted in the table,
the data have been averaged with regard to this parameter.
SSMS analyses of some elements indicate only that the element is present
as a major component (MC). However, upper detection limits are not available
and these data cannot be included in data averages.
Aluminum and silicon concentrations presented in Table 224 appear to be
substantially low. Typical Al concentrations in coal ash range from 5 to 19
percent while average tabulated data indicate less than one percent in the
samples tested. Similarly, typical Si concentrations in coal ash range from
9 to 28 percent while average tabulated data indicate less than 4 percent.
This discrepancy may result from the difference between temperatures at which
fuel samples are ashed for analysis and boiler flame temperatures. The
typical fuel ashing temperature prior to trace element analysis is 750°C
while flame temperatures at which bottom ash and fly ash are produced may be
twice as high. This higher temperature exposure during combustion may result
in physical or chemical changes in the ash which could affect analyses.
Based on available data, it is not known whether any trace or minor elements
are subject to the same analytical problems encountered with SSMS analyses
of Al and Si. However, this issue appears to warrant further consideration
and could be resolved through the use of a reliable referee technique such
as inductively coupled plasma optical emission spectroscopy (ICP).
A comparison of mean elemental concentrations in fly ash and bottom ash
with elemental MATE values for solid waste is presented in Table 226. A MATE
404
-------
TABLE 224. SUMMARY OF FLY ASH TRACE ELEMENT DATA FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
o
en
Concentration In Fly Ash, ppm
Trace Element
Aluminum (Al)
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Ho)*
Potassium (K)
Lithium (Li)
Magnesium (Ng)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Hi)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Dry Bottom
Site
205-1
0.43%
240
50
370
3.1
25
o.m
0.34
—
36
53
67
28. 3t
6.4*
27.7
0.57S
86
820
130
7.3
290
120
850
no
6.1
<6.2
4.2%
7.7
380
13
4.6
63
no
Site
205-2
130
170
29
440
5.0
<7.6
0.41%
0.65
—
42
46
69
28. 3t
3.2*
14.2
0.51%
46
0.15%
120
4.8
0.24*
130
790
90
7.2
7.9
1.7S
4.0
370
15
3.7
0.022
130
Met Bottom
Site
206
0.62S
no
100
380
3.1
9.9
0.58%
0.93
_.
26
19
61
15t
5.6%
0.08
0.29S
—
0.151
130
2.7
210
120
0.15%
34
2.2
9.9
2.3%
5.1
390
4.7
1.6
65
79
Stoker
sTti SW
137 204
MC
28
25
640
3
5
MC
4
8
11
30
540
84
NC
—
MC
56
MC
200
17
MC
25
82
43
9
32
MC
22
380
100
52
100
52
2.8%
3.0
160
280
1.7
<1.2
0.79S
0.40
..
57
41
47
9.5t
14%
0.488
0,691
<110
0.16%
170
3.2
320
250
o.m
6.8
3.4
3.7
6.8S
2.7
280
<5.0
<1.7
140
65
X
0.966%
no
72.8
422
3.18
9.74
0.473%
1.26
8
34.4
37.8
157
33.0
7.30%
10.6
0.515%
74.5
0.1 36X
150
7.00
805
129
864
56.8
5.58
11.9
3.75S
8.30
360
27.5
12.7
73.6
87.2
s(x)
0.624
44.0
25.6
60.2
0.527
4.08
0.144
0.692
—
7.71
6.01
95.9
13.3
2.33
6.57
0.0838
14.6
0.0180
15.2
2.63
532
35.8
232
18.9
1.24
5.12
1.15
3.52
20.2
18.2
9.84
23.1
14.4
ts(x)
X
2.06
1.11
0.978
0.396
0.460
1.16
0.967
1.52
—
0.622
0.441
1.70
1.11
1 .02
1.97
0.518
0.622
0.422
0.281
1.04
2.10
0.770
0.745
0.924
0.517
1.19
0.974
1.13
0.156
1.84
2.15
0.873
0.459
Major component is indicated by MC when concentration exceeds SSMS range.
"'"Fluoride was determined by selective ion electrode analysis.
Mercury was determined by cold vapor analysis.
-------
TABLE 225. SUMMARY OF BOTTOM ASH TRACE ELEMENT DATA
FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
Concentration in Bottom Ash, ppm
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)+
Potassium (K)
Lithium (Li)
Magnesium (Kg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (N1)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Wet Bottom
Site
206
0.37X
3.2
5.5
220
<0.063
<11
0.31*
0.63
—
31
16
26
11. 3t
4.7%
0.115
0.16%
7.5
0.13%
37
1.6
52
96
120
6.2
0.66
<1.0
0.75%
1.5
330
<2.0
<0.48
42
36
Cyclone
Site
132
MC
4
8
MC
0.6
6
MC
0.6
..
9
220
120
—
MC
--
MC
8
MC
>860
24
MC
<0.3
580
120
4
5
MC
0.8
MC
81
240
260
MC
Stoker
Site
137
MC
1
25
450
2
4
MC
2
26
4
30
32
37
MC
--
MC
60
MC
no
8
MC
11
120
5
2
3
MC
1
340
90
37
64
170
X
0.37X
2.73
12.8
335
0.888
7.00
0.311
1.08
26
14.7
88.7
59.3
24.1
4.7%
0.115
0.16%
25.2
0.13%
336
11.2
52
35.8
273
43.7
2,22
3.00
0.75%
1.10
335
57.7
92.5
122
103
5(5)
-_
0.897
6.13
115
0.577
2.08
—
0.462
—
8.29
65.8
30.4
12.9
--
-.
__
17.4
--
263
6.66
—
30.3
153
38.1
0.970
1.15
—
0.208
5.00
28.0
74.5
69.3
67.0
ts(x)
_
X
«»
1.41
2.05
4.36
2.80
1.28
—
1.85
—
2.43
3.19
2.20
6.76
--
--
—
2.98
—
3.37
2.56
—
3.64
2.41
3.75
1.88
1.S6
—
0.814
0.190
2.09
3.47
2.44
8.27
Major component is indicated by MC when concentration exceeds SSMS range.
Fluoride was determined by selective ion electrode analysis.
*Mercury was determined by cold vapor analysis.
-------
TABLE 226. DISCHARGE SEVERITY OF TRACE ELEMENTS IN FLY ASH AND
BOTTOM ASH FROM BITUMINOUS COAL-FIRED UTILITY BOILERS
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Hg)
Manganese (Mn)
Molybdenum (Ho)
Sodium (Na)
Nickel (Nt)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
MATE,
Health
16,000
50
9,300
1,000
6
NA
48,000
10
260,000
150
50
1,000
7,500
300
2
4,200
70
18,000
50
15,000
160,000
45
3,000
50
1,500
10
30,000
236
9,200
130
12,000
500
5,000
ppm
Ecology
200
10
5,000
500
11
NA
3,200
0.2
NA
50
50
10
NA
50
50
4,600
75
17,000
20
1,400
NA
2
0.1
10
40
5
NA
NA
NA
NA
100
30
20
Concentration
in Fly Ash,
ppm
0.9661
110
72.8
422
3.18
9.74
0.473X
1.26
at
34.4
37.8
157
33.0
7.30J
10,6
0.5155
74.5
0.1 36X
150
7.00
805
129
864
56.8
5.85
11.9
3,75*
8.30
360
27,5
12.7
73.6
87.2
Discharge
Health
i.at
2.2
O.OlSt
0.6t
o.at
--
0.2t
0.3t
0.00003
0.4t
1.1 +
0.4t
O.Olt
243
5.3
1.2
1.1
O.lt
3
O.OOlt
0.02t
5. It
0.5+
1.1
o.ooet
1.2
1.3
o.ost
0.04t
0.6+
0.003+
0.1 +
0.02t
*
Severity
Ecology
48
11.0
o.ost
1.2t
0.4t
—
1.5
63
—
1.1 +
1.1 +
16
—
1,460
0.6+
11
1.0
O.lt
7.5
0.01 +
—
65
8,640
5.7
0.2+
2.4
—
—
—
—
0.4+
2.5
4.4
Concentration
in Bottom Ash
PPM
0.37J*
2.73
12.8
335
0.888
7.00
0.31*
1.08
26*
14.7
88.7
59.3
24.1
4.7**
0.115*
0.16X*
25.2
0.13S*
336
11.2
52*
35.8
273
43.7
2.22
3.00
0.75X*
1.10
335
57.7
92.5
112
103
Discharge
Health
0.2
O.lt
0.004+
1.8+
0.6+
—
0.07
0.3+
0.0001
0.3+
1.8
0.2+
0,03t
157
0.06
0.4
1.4+
0.07
6.7
0.003+
0.0003
3.6+
0.3+
4.1 +
0,004t
0.8t
0.3
0.009t
0.04t
1 .4+
0.03t
0.8+
0.2t
Severity
Ecology
19
0.7+
O.OOSt
3.6t
0.3+
..
1.0
5.4
--
1.0+
1.8
5.9
._
940
0.002
0.3
1.3+
0.08
17
0.03+
—
18
2,730
44
O.Zt
1.6+
—
--
—
--
4.13+
3.7
5.1
Discharge severity is defined as the ratio of mean elemental concentration to elemental MATE value.
Discharge severity is computed from the upper limit element concentration, x .
Concentration based on a single data point.
-------
value based on health effects was not available for Br and MATE values based
on ecological considerations were not available for Br, Cl, F, Na, Si, Sn,
Sr, and Th, MATE values for K are based on KOH for health effects and on K
for ecological effects. The health MATE value for Sn is based on Sn02.
Discharge severity, the ratio of elemental concentration to MATE value,
is the criterion used to evaluate the significance of fly and bottom ash
generated. A discharge severity exceeding one is considered to warrant
concern regarding the impact of emissions on health/ecology. As indicated
in Table 226, concentrations of most elements did not exceed their respective
health based MATE value but did exceed ecology based MATE values. Fly ash
elements which exceeded health MATE concentrations are Al, As, Cr, Fe, Hg,
K, Li, Mn, Ni, Pb, Se, and Si. Elements in fly ash which exceeded ecological
MATE concentrations are Al, As, Ba, Ca, Cd, Co, Cr, Cu, Fe, K, Li, Mn, Ni,
P, Pb, Se, V, and Zn, Bottom ash elements which exceeded health MATE con-
centrations are Ba, Cr, Fe, Li, Mn, Ni, Pb, and Th, while Al, Ba, Ca, Cd,
Co, Cr, Cu, Fe, Li, Mn, Ni, P, Pb, Se, U, V, and Zn exceeded ecological MATE
concentrations. These ash constituents, therefore, pose a potential hazard
to human health and/or the environment.
The data base has been evaluated in terms of data variability and
discharge severity to determine its adequacy. Results of this evaluation,
presented in Table 227, indicate that the trace element data base for fly ash
and bottom ash is largely adequate. The trace element data base for fly ash
is inadequate for 9 elements with respect to health considerations and for
12 elements with respect to ecological considerations. The trace element
data base for bottom ash is inadequate for 15 elements with respect to health
considerations and for 22 elements with respect to ecological considerations.
Elemental analyses of fly ash and bottom ash from lignite-fired utility
boilers are presented in Tables 228 and 229, respectively. Fluoride and
chloride values were determined by selective ion electrode analyses while
mercury was determined by cold vapor analyses. All other elements were
analyzed by SSMS.
As was observed for ash from bituminous coal firing, Al and Si concen-
trations determined by SSMS appear to be substantially low with average
408
-------
TABLE 227. ADEQUACY OF TRACE ELEMENT DATA BASE FOR FLY ASH AND *
BOTTOM ASH FROM BITUMINOUS COAL-FIRED UTILITY BOILERS
Trace Element
Aluminum (A! )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mg)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Health
I
I
A
A
A
-
A
A
I
A
A
A
A
I
I
A
A
A
A
A
A
I
A
I
A
I
I
A
A
A
A
A
A
Fly Ash
Ecology
I
I
A
A
A
-
I
I
I
A
A
I
-
I
A
A
A
A
A
A
-
I
I
I
A
I
-
-
A
-
A
I
A
Bottom
Health
I
A
A
I
A
-
I
A
I
A
I
A
A
I
I
I
I
I
I
A
I
I
A
I
A
A
A
A
A
I
A
A
A
Ash
Ecology
I
A
A
I
A
-
I
I
I
A
I
I
-
I
I
I
I
I
I
A
I
I
I
I
A
I
I
-
A
-
I
I
I
A indicates adequate data base and I indicates inadequate data base.
409
-------
TABLE 228. SUMMARY OF FLY ASH TRACE ELEMENT DATA FOR
LIGNITE-FIRED UTILITY BOILERS
Trace Element
Aluminum (Al }
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)*
Cobalt
Chromium (Cr)
Copper (Cu)
Fluorine (F)*
Iron (Fe)
Mercury (Hg)t
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead {PbJ
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (In)
Concentration, ppm
Site
314
1.82
250
0.132
1.5%
0.71
34
MC
3.8
20.6
8.4
9.2
39
72
MC
0.163
0.583
16
3.22
800
3.9
0.292
36
490
27
1.0
<2.1
MC
2.3
0.582
17
6.0
35
860
Dry Bottom
Site
315
2.4%
620
320
0.12?
0.18
16
2.7%
1.5
45
0.122
8.6
20
77
MC
0.086
0.582
1.3
3.02
200
1.7
1.1:;
0.162
120
9.3
<1 .4
<4.1
MC
1.1
0.102
1.5
1.5
22
210
Site
318
3.5%
130
1.32
0.552
9.9
7.7
MC
1.2
152
14
16
48
428
0.282
0.092
0.342
51
1.72
410
4.1
1.62
46
0.462
20
3.3
*?.!
MC
4.3
: 0.222
<7.3
<3.6
61
51
Cyclone
Site
316
MC
830
0.812
0.94%
11
64
MC
1.2
62
32
64
150
128
MC
0.212
3.02
17
2.32
450
36
5.02
95
0.292
160
15
<31
MC
6.0
0.442
11
22
170
190
Stoker
Site
317
1.0S
79
0.912
0.28%
17
4.7
13S
0.70
354
9.1
8.1
29
263
0.1002
0.021
0.122
62
1.7S
500
1.7
0.942
29
0.26%
4.7
2.1
<2.9
3.42
3.4
0.272 .
<4.2
<3.0
37
89
Site
319
0.352
250
0.212
0.522
2.4
150
MC
3.1
224
7.1
15
130
293
1.12
1.96
0.172
14
2.02
0.135
3.1
0.332
21
440
87
6.6
19
5.32
7.5
0.382
27
4.9
81
52
X
1.81%
360
0.5652
0.652?,
6.87
46.1
7.85
1 .92
143
212
20.2
69.3
210
0.4932
0.422
0.7982
26.9
2.322
610
8.42
1.542
305
1858
51.3
4.90
11.0
4.352
4.10
0.3322
11.3
6.83
67.7
242
s(x)
0.547
122
0.210
0.204
2.78
22.6
5.15
0.504
52.4
198
8.88
2.28
57.9
0.308
0.309
0.447
9.75
0.265
159
5.53
0.720
259
732
24.9
2.18
4.73
0.950
0.965
0.0697
3.84
3.10
22.2
127
ts(x)
X
0.839
0.870
0.953
0.806
1 .04
1.26
8.34
0.676
0.942
2.40
1.13
8.46
0.709
2,68
1.88
1.44
0.932
0.294
0.670
1.69
1.20
2.19
1.01
1.25
1.14
1.10
2.77
0.605
0.540
0.870
1.17
0.844
1.35
.
Chloride and fluoride are determined by selective ion electrode analyses.
4-
'Mercury is determined by cold vapor analysis.
-------
TABLE 229. SUMMARY OF BOTTOM ASH TRACE ELEMENT DATA
FOR LIGNITE-FIRED UTILITY BOILERS
Concentration, ppm
Trace Element
Aluminum (A1 )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)*
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)*
Iron (Fe)
Mercury (Hg)t
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (Pj
Lead (Pb)
Antimony (Sb)
Selenium (Sej
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
Site
314
1.07-
99
0.10%
0.66%
1.9
62
MC
0.87
49.3
11
5.1
36
40
2.7%
0.089
0.45%
12
0.97%
310
2.5
0.47%
140
0.12%
25
2.6
1.3
MC
3.0
0.15%
11
7.8
46
84
Dry Bottom
Site
315
1.1%
400
0.63%
0.85%
3.8
17
>13%
1.8
86
6.0
18
52
71
5.4%
0.094
1.5%
79
3.5%
640
3.6
0.51%
70
0.13%
25
<3.8
5.5
MC
2.1
0.52%
<22
<16
67
41
Site
318
0.92%
36
0.46%
0.29«
5.6
<5.8
12%
<0.91
14
11
21
27
221
7.1%
0.017
660
31
1.3*
460
1.6
0.31%
98
0.52%
4.3
0.94
<5.6
3.1%
1.1
0.25%
<3.9
<2.0
96
41
Cyclone
Site
316
2.7%
160
490
2.0?
1.8
22
MC
1.2
11
11
22
31
34
MC
0.043
0.47%
5.6
0.60J
510
8.6
0.55
46
0.10%
150
4.9
<2.6
4.2%
3.2
1.2%
15
15
74
91
Stoker
Site
317
1 .11,
22
0.31%
0.21?
3.4
5.0
12S
0.78
102
7.4
18
23
137
MC
<0.017
0.45%
38
0.46*
330
5.6
1.3%
85
0.11%
6.7
0.56
<2.3
4.8%
1.8
0.19%
<4.7
<3.4
41
19
Site
319
0.81%
110
0.10%
0.21%
0.61
57
6.3%
0.20
19
7.2
7.3
33
1580
HC
<0.017
0.25%
3.8
1.3%
0.10%
1.4
0.25%
44
110
3.4
0.60
<7.0
5.0%
0.97
820
7.1
1.8
30
16
X
1 .37%
138
0.275%
0.703%
2.85
28.1
>10.8%
0.960
46.9
8,93
15.2
33.7
347
5.07%
0.0462
0.531%
28.2
1.35%
542
3.88
0.565%
80.5
0.165S
35.7
2.23
4.05
4.27%
2.03
0.399%
10.6
7.67
59.0
48.7
s(5)
0.295
56.4
0.0955
0.281
0.725
10.3
—
0.215
16.0
0.945
2.94
4.11
248
1.28
0.0149
0.204
11.6
0.452
104
1.13
0.155
14.7
0.0731
23.2
0.749
0.930
0.427
0.381
0.172
2.84
2.63
9.99
13.1
ts(x)
X
0.553
1.05
0.893
1.03
0.654
0.942
..
0.576
0.877
0.272
0.497
0.313
1.84
1.09
0.829
0.988
1.06
0.861
0.493
0.749
0.705
0.469
1.14
1.67
0.863
0.590
0.318
0.483
1.11
0.689
0.882
0.435
0.692
Chloride and fluoride are determined by selective ion electrode analyses.
Mercury is determined by cold vapor analysis.
-------
values of 1.8 percent and 4.3 percent, respectively. In addition, the Fe
concentrations of 0.3 to 1.1 percent in fly ash appear low. Typical ash Fe
concentration ranges from 4 to 25 percent with lignites tending toward the
lower end of this range. Furthermore, since Fe is not generally enriched
in either the fly ash or bottom ash, it is unclear why concentrations in
bottom ash appear reasonable while fly ash concentrations are rather low.
These results and those from analyses of ash from firing bituminous coal
indicate that SSMS analyses are not reliable for Al, Fe, and Si. Moreover,
the validity of SSMS analyses of fly ash and bottom ash may be open to
question and appears to require verification by a reliable referee method.
A comparison of elemental concentrations with MATE concentrations is
presented in Table 230. Elements in fly ash which exceeded their respective
health based HATE concentrations are Al, As, B, Ba, Co, Fe, K, Mg, Mn, Ni,
P, Pb, Se, and Si. With the exception of Si, concentrations of these
elements also exceeded ecological HATE values for fly ash as did Cd, Cu, V,
and Zn. Bottom ash elements which exceeded health based MATE concentrations
are Al» As, Ba, Ca, Fe, K, Mg, Hn, Ni, P, Pb, and Si. With the exception of
Si, concentrations of these elements also exceeded ecological MATE values as
did concentrations of B, Cd, Cu» Se, V, and Zn. These elements, therefore,
represent a potential hazard to human health and/or the environment.
The elemental data base for fly ash and bottom ash from lignite-fired
utility boilers has been evaluated with respect to data variability and
discharge severity. Results of this evaluation are presented in Table 231.
The fly ash data base is adequate for 19 elements with respect to health
considerations and for 12 elements with respect to ecological considerations.
The bottom ash data base is inadequate for 23 elements with respect to health
considerations and for 19 elements with respect to ecological considerations.
It should be noted, however, that fly ash and bottom ash are generally
combined for ultimate disposal, obviating the need for individual ash
fraction characterization. With the exception of a few volatile elements
which are discharged to the atmosphere in vapor phase, characterization of
the coal feed will therefore provide adequate characterization of the in-
organic constituents of the combined coal ash. Thus, because there are
412
-------
TABLE 230. SUMMARY OF DISCHARGE SEVERITY OF TRACE ELEMENTS IN FLY ASH AND
BOTTOM ASH FROM LIGNITE-FIRED UTILITY BOILERS
OJ
Trace Element
Aluminum (Al )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (FeJ
Mercury (Ho)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Sickel (HI)
Phosphorus (P)
Lead (Pt»)
Antimony (Sb)
Selenium (Se)
Selicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (Zn)
MATE,
Health
16,000
50
9,300
1,000
6
NA
48,000
10
260,000
150
50
1,000
7,500
300
20
4,200
70
18,000
50
15,000
160,000
45
3,000
50
1,500
10
30,000
236
9,200
130
12,000
500
5,000
ppm
Ecology
200
10
5,000
500
11
NA
3,200
0.2
NA
50
50
10
NA
50
50
4,600
75
17,000
20
1,400
NA
2
0,1
10
40
5
NA
NA
NA
NA
100
30
20
Concentration
in Fly Ash,
ppm
1.81%
360
0.565%
0.652%
6.87
46.1
7.85
1.92
143
212
20.2
69.3
210
0.493X
0.422
0.7981
26.9
2.32%
610
8.42
1.54*
305
1,858
51.3
4.90
11.0
4.35%
4.10
0.332%
11.3
6.83
67.7
242
Discharge
Health
1.1
7.2
1.2t
6.5
1.1
__
O.OOlt
0.3t
O.OOlt
1.4
0.9t
0.07t
O.OSt
16
0.06t
1.9
0.7t
1.3
12
O.OOlt
0.2t
6.8
0.62
1.0
0.07t
1.1
1.5
0.03t
0.6t
0.2t
0.001 +
0,3t
O.lt
Seven" ty
Ecology
91
36
1 .1
13
1 .3t
_.
0.02+
9.6
—
4.2
0.9*
6.9
—
99
0.02t
1.7
0.7t
1.4
31
0.02+
--
153
18,580
5.1
0.3+
2.2
—
—
—
--
0.1 +
4.2+
12
Concentration
in Bottom Ash
ppm
1 .37%
138
0.275%
0.703%
2.85
28.1
>10.8S
0.960
46.9
8.93
15.0
33.7
347
5.07%
0.0462
0.531%
28.2
1.35%
542
3.88
0.565%
80.5
0.165%
35.7
2.23
4.05
4.27X
2.03
0.399*
10.6
7.67
59.0
48.7
Discharge
Health
1.3+
2.8
0.6*
7.0
0.8+
—
>2.3
0.1 +
0.0003+
0.08+
0.5+
0.04+
O.lt
169
0.004+
1.3
0.8+
1.4+
11
0.0005+
0.06+
18
55 1
1.9+
0.003+
0.6+
1.4
0.01 +
0.9+
0.1 +
0.001+
0.2+
0.02+
Severity* ••
Ecology
69
14
1.0+
14
0.4+
—
>34
4.8
--
0.2t
0.5+
3.4
—
1,014
0.002+
1.1
0.8t
1-5t
27
0.005+
—
40
6,500
3.6
0.1 +
1.3+
_-
—
—
--
0.1 +
2.0
2.4
Discharge severity is defined as the ratio of mean elemental concentration to the elemental MATE value,
Discharge severity has been computed from the upper limit element concentration x.
-------
TABLE 231. ADEQUACY OF TRACE ELEMENT DATA BASE FOR FLY ASH
AND BOTTOM ASH FROM LIGNITE-FIRED UTILITY BOILERS
Trace Element
Aluminum (A! )
Arsenic (As)
Boron (B)
Barium (Ba)
Beryllium (Be)
Bromine (Br)
Calcium (Ca)
Cadmium (Cd)
Chlorine (Cl)
Cobalt (Co)
Chromium (Cr)
Copper (Cu)
Fluorine (F)
Iron (Fe)
Mercury (Hg)
Potassium (K)
Lithium (Li)
Magnesium (Mg)
Manganese (Mn)
Molybdenum (Mo)
Sodium (Na)
Nickel (Ni)
Phosphorus (P)
Lead (Pb)
Antimony (Sb)
Selenium (Se)
Silicon (Si)
Tin (Sn)
Strontium (Sr)
Thorium (Th)
Uranium (U)
Vanadium (V)
Zinc (In)
Health
I
I
I
I
I
-
A
A
A
I
A
A
A
I
A
I
A
A
A
A
A
I
I
I
A
I
I
A
A
A
A
A
A
Fly Ash
Ecology
I
I
I
I
I
-
A
A
-
I
A
I
-
I
A
I
A
A
A
A
-
I
I
I
A
I
-
A
A
-
A
I
I
Bottom
Health
A
I
A
I
A
-
I
A
A
A
A
A
A
I
A
I
A
I
A
A
A
A
I
I
A
A
A
A '
A
A
A
A
A
Ash
Ecology
A
I
I
I
A
-
I
A
-
A
A
A
-
I
A
I
A
I
A
A
-
A
I
I
A
A
A
A
-
A
A
A
A
If
A indicates adequate data base and I indicates inadequate data base.
414
-------
adequate data characterizing the trace element contents of coal (Section
5.3.1), the inorganic data base for coal ash may be considered adequate.
Comparison of test data with the limited existing fly ash and bottom ash
analyses (i.e., Tables 211 and 212) is not meaningful since data regarding
coal rank and furnace type are not available for existing analyses. Further,
because fly ash and bottom ash compositions are dependent upon the respective
coal inorganic contents and furnace types, ash analyses from different sites
would be expected to differ significantly. Combining the test data and
existing data (assuming coal rank and furnace type data were available) would
generally tend to improve the inorganic data base for fly ash and bottom ash.
However, as discussed previously, no substantial need exists for individual
fly ash and bottom ash data bases.
Organic Data
Selected fly ash and bottom ash samples from bituminous coal-fired uti-
lity boilers were analyzed for total chromatographable organics (TCO, 90 to
300°C boiling point range, reported as volatile organics or C,-C,g) and non-
volatile organics (boiling points >300°C) which are determined gravimetrical-
ly. TCO fractions are reported in terms of the normal alkanes of corres-
ponding carbon number. The analytical detection limit for TCO in ash samples
is approximately 1.4 ppm for each fraction. Results of TCO and gravimetric
analyses are presented in Table 232. As indicated in the table, TCO were
not detected in most ash samples. Average measured TCO concentrations in fly
ash and bottom ash are less than 31 ppm and 55 ppm, respectively. The average
concentrations of TCO in fly and bottom ash are statistically identical owing
to the relatively large standard deviation for available data. These concen-
trations may be compared with MATE values for alkanes, alkenes, and alkynes
which are >11,000 ppm based on health and >200 ppm based on the ecology.
Gravimetric data presented in Table 232 indicate that the non-volatile
organic fractions are generally present in significantly larger quantities
than the volatile organics, as would be expected for combustion byproducts.
Average measured concentrations of gravimetric fractions in fly and bottom
ash were 186 ppm and 290 ppm, respectively. These concentrations do not
differ statistically due to the large standard deviation of the data.
415
-------
TABLE 232. TCO AND GRAVIMETRIC ORGANIC DATA FOR FLY ASH AND
BOTTOM ASH FROM BITUMINOUS COAL-FIRED UTILITY BOILERS
CTi
Site No.
205-1
205-2
206
212
213
207
208
209
132-6
137
204
Mean x
Standard
Variabil
Firing Type
Pulv. Dry Bottom
Pulv. Dry Bottom
Pulv. Met Bottom
Pulv. Wet Bottom
Pulv. Met Bottom
Cyclone
Cyclone
Cyclone
Cyclone
Stoker
Stoker
Deviation of the Mean s(x)
ity ts(x)/x
Volatile
Fly Ash
*
<14
<17.2f
*
<14
NA
NA
NA
NA
NA
**
<96.0
NA
14*
<31.0
16.3
1.45
(TCO), ppm
Bottom Ash
NA*
NA
<14*
NA
NA
NA
NA
NA
**
<96.0
NA
NA
<55.0
41.0
9.47
Non-Volatile
Fly Ash
420
240
80
216
194
76.0
198
268
0
118
240
186
34.5
0.413
(Grav), ppm
Bottom Ash
NA*
NA
900
248
840
142
57.9
16.0
0
118
NA
290
130
1.06
Organics were not detected. However, the detection limit for TCO's is approximately 1.4 ppm for
each carbon number. The TCO detection limit is, therefore, 14 ppm.
Composed of 2 ppm C,. and 4 ppm C,5. The remaining fractions were below detection limits.
An NA indicates that no analysis was performed.
.>
Composed of 33 ppm C«, 28.8 ppm Cg and 24.4 ppm C<|g. Other fractions are below detection limits.
Bottom and fly ash are combined during collection at site 132-6.
**
-------
Bottom ash samples from Sites 206 and 213 were further analyzed by
liquid chromatography and subsequently by low resolution mass spectrometry
(LRMS). Results presented in Table 233 show that sulfur was the only material
identified in the bottom ash sample from Site 206. However, a variety of
organic compound types were identified in the Site 213 bottom ash sample.
Compound types of particular interest and environmental concern are the nitro
aromatics, the high molecular weight aromatics and the brominated materials,
polycyclic oxygenated compounds and amines which are possibly present.
Similar results were obtained by infrared analyses of LC fractions presented
in Table 234.
Analyses of fly and bottom ash for POM are presented in Table 235. POM
was not detected in most samples although a variety of POM compounds were
detected in bottom ash from Site 213 and naphthalene was detected in fly ash
from Site 204. A comparison of detected POM and MATE concentrations is
presented in the table. Detected POM compounds do not appear to pose a
hazard to health or ecology. Moreover, it should be noted that the POM de-
tection limit for these analyses was approximately 2 ppm. Several fused
polycyclic hydrocarbons with health based MATE values below 2 ppm are as
follows: 7,12 dimethylbenz{a)anthracene» 0.8 ppm; dibenz(a,h)anthracene,
0.3 ppm; and benzo(a)pyrene, 0.06 ppm. Hence, while no POM compounds were
detected at concentrations equal to or greater than their respective health
based MATE values, additional analyses at higher GC/MS sensitivity would be
required to conclusively preclude the presence of certain POM compounds at
concentrations in excess of health based MATE values.
Results of TCO and gravimetric analyses of fly and bottom ash samples
from lignite-fired utility boilers are presented in Table 236, The average
concentration of TCO from fly and bottom ash is approximately 5 ppm. Again,
the quantity of non-volatile organics substantially exceeds the level of
TCO. The average concentration of the non-volatile organics (boiling point
>300eC) is approximately 200 ppm in fly and bottom ash.
IR analyses of fly and bottom ash, presented in Table 237, primarily
indicate the presence of minor or trace amounts of saturated hydrocarbons,
ethers and esters. Also identified were aliphatic hydrocarbons and sili-
cones, the later of which may indicate contamination.
417
-------
TABLE 233. SUMMARY OF LOW RESOLUTION MASS SPECTROMETRIC ANALYSES RESULTS
FOR SELECTED LC FRACTIONS FROM ASH SAMPLES*
Site Sample Fraction
206 Bottom Ash LC-1
213 Bottom Ash LC-1
LC-2 + LC-3
LC-4 + LC-5
LC-6 + LC-7
Compounds Identified
Sulfur.
Hydrocarbons; Brominated compounds (possible).
Substituted high molecular weight aromatics.
Esters (high molecular weight); Nitro
aromatics.
Phthalates; Fatty acids (possible); Amines
(possible).
LC fractions containing more than 1 ppm nonvolatile material and any fractions of special interest
to the analyst were selected for LRMS analysis.
-------
TABLE 234. SUMMARY OF INFRARED ANALYSIS RESULTS OF LC FRACTIONS OF
ASH SAMPLES FROM BITUMINOUS COAL-FIRED UTILITY BOILERS
Site Sample
No.
WET BOTTOM UNITS
212 Fly Ash
213 Bottom Ash
LC-1
--
Aliphatic
and aromatic
hydrocarbons;
brominated
compounds
LC-2
—
Aliphatic
and aromatic
hydrocarbons;
polycyclic
oxygenates
C
LC-3
--
Aliphatic
and aromatic
hydrocarbons
polycyclic
oxygenates
ompounds Identified
LC-4
Aromatic
hydrocarbons;
; aldehydes/
ketones ;
amine (possi-
LC-5
--
Aldehydes/
ketones ;
phenols
and/or
ethers
LC-6
--
Amide;
amines ;
phenols
and/or
ethers
LC-7
Carboxylic
acid salt
and un-
identifiable
materials.
Carboxylic
acid salt;
acids
(possible);
esters.
(possible).
(possible).
(possible)
ble); esters;
nitro-
aromatics.
(possible);
sul fates
(possible);
amine
(possible);
esters;
nitro-
aromatics.
(possible);
esters;
fatty adds
(possible).
CYCLONES
208
209
Fly Ash
Fly Ash
Unidentifi-
able.
Inorganic
nitrate;
unidentifi-
able
organics.
-------
TABLE 235. POLYNUCLEAR ORGANIC MATERIALS (POM) IDENTIFIED IN ASH SAMPLES
FROM BITUMINOUS COAL-FIRED UTILITY BOILERS
Site
No.
205-1
205-2
206
212
213
207
209
132-6
204
137
Firing Type
Pul v . Dry Bottom
Pulv. Dry Bottom
Pulv. Met Bottom
Pulv. Wet Bottom
Pulv. Wet Bottom
Cyclone
Cyclone
Cyclone
Stoker
Stoker
Sample
Fly Ash
Fly Ash
Fly Ash
Bottom Ash
Fly Ash
Bottom Ash
Bottom Ash
Bottom Ash
Fly Ash
Fly Ash/Bottom Ash
Fly Ash
Bottom Ash
Bottom Ash
Concentration MATE, ppm Discharge Severity
POM Compound ppm Health tcoloqy Health Ccoleyy
No POM detected
No POM detected
No POM detected
No POM detected
No POM detected
No POM detected
Naphthalene 4.0 150,000 20 0.00003 0.2
Ethyl naphthalene* 14.0 150,000 20 0.00009 0.7
Dimethyl naphthalene 12.0 680,000 — 0.00002
Trimethyl naphthalene or » 1£j Q 150,000 20 0.00007 0.5
Methyl dlbenzofuran 2.0
Methyl phenanthrene 6.0 91,000 — 0.00007
Phenanthrene or anthracene 4.0 4,800 -- 0.0008
No POM detected
No POM detected
No POM detected
Naphthalene 1.0 150,000 20 0.00001 0.05
No POM detected
No POM detected
The MATE values for naphthalene are being applied to ethyl naphthalene and methyl ethyl naphthalene since
MATE values are not available for these compounds.
-------
TABLE 236. SUMMARY OF TCO AND GRAVIMETRIC ORGANIC DATA FOR FLY ASH
AND BOTTOM ASH FROM LIGNITE-FIRED UTILITY BOILERS
Site
No.
314
315
318
316
317
319
Mean x
Standard
of the
Variabll
Firing Type
Dry Bottom
Dry Bottom
Dry Bottom
Cyclone
Stoker
Stoker
deviation
mean s(x)
ity ts(x)/x
Volatile
Fly Ash
2.00
1.55
7.96
*
ND
15.2
0.479
4.53
2.43
1.38
(TCO), ppm
Bottom Ash
2.04
5.76
11.2
8.32
2.60
0.907
5.14
1.65
0.823
Non- Volatile
Fly Ash
200
300
84.0
300
150
43.0
179
44.0
0.630
(Grav), ppm
Bottom Ash
200
300
168
300
150
172
215
27.7
0.331
Organics not detected at detection limits of approximately 10 ppm.
GC/MS analyses of fly and bottom ash from lignite firing did not detect
POM compounds. However, as discussed previously, the POM detection limit
was approximately 2 ppm. As such, additional GC/MS analyses at higher
sensitivity would be required to conclusively preclude the presence of 7,12
dimethylbenz(a)anthracene, dibenz(a,h)anthracene, benzo(a)pyrene, at con-
centrations exceeding health based MATE values.
421
-------
ISJ
r\>
TABLE 237. SUMMARY OF INFRARED ANALYSIS RESULTS OF GRAVIMETRIC RESIDUES (>Clfi)
FOR LIGNITE-FIRED UTILITY BOILERS ID
Site Firing
No . Type
315 Pulverized
coal , dry
bottom
318 Pulverized
coal , dry
bottom
316 Cyclone
31 9 Stoker
Sampl e
Fly Ash
Bottom Ash
Fly Ash
Bottom Ash
Fly Ash
Bottom Ash
Fly Ash
Bottom Ash
Concentration 1n Sample
Major Medium Minor
— Aliphatic Esters;
hydrocarbons ethers
(possible)
— — Aliphatic
hydrocarbons
— — Saturated
hydrocarbons
— — Saturated
hydrocarbons ;
ethers
— - — Saturated
hydrocarbons;
silicones
— — Sill cones
— — —
___ ___ ___
Trace
—
Esters
---
---
Saturated
hydrocarbons
Saturated
hydrocarbons
-------
The one set of existing organic data for coal ash does not specify
coal rank, furnace type or whether the sample is fly ash or bottom ash or a
composite (Tables 213 and 214). However, current study test data indicate
that the non-volatile organic contents of fly ash and bottom ash do not
differ substantially. Further, the non-volatile organic contents of bitumi-
nous coal ash and lignite ash are quite similar with averages ranging from
179 ppm to 290 ppm. By comparison, assuming a negligible concentration of
organics higher than C.,*, existing data indicate 8.4 ppm of non-volatile
organics. Thus, non-volatile organic concentrations from existing data are
lower than non-volatile organic concentrations from average test data by a
factor of at least 20. It should be noted, however, that the standard devia-
tion of current study test data for the non-volatile organic fraction is
rather large and that concentrations below 8 ppm were measured. Comparison
of existing and test POM data is difficult because published POM concentra-
tions are at a ppb level while current study POM detection limits were
approximately 2 ppm. In general, POM was not detected in test samples.
However, compounds which are common to published data and test data are
naphthalene and methyl phenanthrene.
7.5.2 Scrubber Sludge
Three sites tested during this program utilized F6D systems, namely,
Sites 135, 154, and 218. There are currently 51 FGD systems in operation
and nearly as many are under construction in the United States. Because
tested sites would not necessarily be representative of existing FGD systems,
only a limited effort was made to characterize sludge wastes from these
sites. Sludge from Site 135 was characterized in conjunction with a com-
prehensive site assessment. Extensive scrubber sludge characterization
studies are in progress under the direction of EPA and EPRI, and will
ultimately provide detailed physical and chemical data on scrubber sludge.
Hence, the adequacy of the test data base will not be discussed in this
section.
Sludge samples from limestone scrubbers at Site 135 were obtained from
the scrubber discharge slurry prior to settling. The scrubber discharge
slurry is pumped at approximately 23 percent sol Ids to a settling pond from
423
-------
which clarified scrubber liquor is recycled to the scrubber system. Scrubber
sludge 1s periodically dredged from the settling pond for off-site disposal.
Hence, sludge samples obtained by filtration of scrubber discharge slurry
may differ somewhat in composition from dredged sludge because less contact
time is allowed for attainment of solid-liquid equilibrium. However, sludge
samples from the scrubber discharge slurry were more appropriate for use in
overall system mass and trace element balances. Sludge samples thus obtained
were analyzed for inorganic and organic contents.
Inorgani cAnalyses
Concentrations of 18 minor and trace elements detected in limestone
scrubber sludge are presented in Table 238. Analyses were performed utilizing
an atomic absorption spectrometer (AAS), These data Indicate that concen-
trations of 10 elements exceeded their respective health based MATE values
and that concentrations of 12 elements exceeded ecology based MATE values.
Hence, the discharge severity for more than half of the trace elements
analyzed is sufficiently high to warrant disposal of this sludge in a spe-
cially designed landfill.
Analysis of the scrubber sludge by polarized light microscopy (PLM)
indicated the following composition: 45-60 percent limestone; 30-45 percent
CaSQg'1/2 ^0; 5-10 percent fly ash; 5-10 percent magnetite; and <2 percent
partially combusted coal. Although limestone concentrations indicated by
PLM analysis appear to be somewhat high, limestone is certainly a major
component of this scrubber sludge. However, concentrations of trace elements
in limestone are substantially lower than concentrations in the scrubber
sludge. Hence, trace elements in scrubber sludge are derived primarily from
fly ash and vapor phase elements removed from the gas stream by scrubbing.
Inorganic test data for scrubber sludges correspond well with published
data (Tables 221 and 222). Some trace elements were detected at higher
concentrations than are values reported in available published data. These
trace elements are Sb, As, Pb, and Zn. Also, the Ca concentration presented
in Table 238 appears somewhat low by comparison with published data indica-
ting a range of 8 to 27 percent.
424
-------
Organic Analyses
Organics detected in the scrubber sludge sample were limited to approxv
mately 5 ppm of Cg and 2 ppm of Clfl. No other chromatographable organics
were detected and no non-volatile organics were detected.
was detected.
Further, no POM
TABLE 238. TRACE ELEMENT CONTENT OF SCRUBBER DISCHARGE SOLIDS
FROM COAL FIRING - TEST 135
El ement
Al
As
Be
Ca
Cd
Co
Cr
Cu
Fe
Hg
Mg
Mn
Mi
Pb
Sb
Sr
V
Zn
Concentration
yg/9
24,000
111.4
2.48
51 ,000
36
22
52
188
50,000
<1.0
0.487
564
96
1,080
38
994
188
6,492
MATE val
Health
16,000
50
6
48,000
10
150
50
1,000
300
2
18,000
50
45
50
1,500
9,200
500
500
ue, yq/g
Ecology
200
10
11
3,200
0.2
50
50
10
50
50
17,400
20
2
10
40
NO*
30
20
Discharge
Health
1.5
2.2
1.1
1.1
3.6
0.15
1
0.19
170
<0.5
0.000027
11
2.1
22
0.025
0.11
0.38
13
Severity
Ecology
120
11
0.22
16
180
0.44
1
19
1,000
<0.02
0.000028
28
4.8
no
0.95
6.3
320
NO - data not available.
425
-------
7.6 DATA RELIABILITY
In the previous section, it was shown that results of trace element
analyses performed by SSMS for the coal ash samples did not compare well
with known concentrations of trace elements in coal ash. For example, both
aluminum and silicon concentrations in coal fly ash were found to be sub-
stantially lower than expected values. On the average, aluminum concentra-
tions determined by SSMS were lower by a factor of 5 to 19 when compared
with typical values. Silicon concentrations determined by SSMS were lower
by a factor of 2.5 to 7 when compared with typical values. These are serious
deficiencies because in analysis of trace element data for coal-fired boilers,
the concept of enrichment factor (Section 5.3.1.4), with aluminum as the
reference element, is commonly employed. The use of enrichment factors is
necessary to enable direct comparison and compilation of trace element
emission data on a normalized basis. Thus, evaluation of coal ash data
again indicates that a major area of data uncertainty is any trace element
data determined using SSMS.
For organic analysis, solid waste samples were extracted with high
purity methylene chloride. As discussed in Section 5.6, error limits for
TCO, gravimetric, and TCO + gravimetric analyses are typically within i 15
percent of the expected value. Error limits for 6C/MS analysis are typical-
ly t 30 percent of the expected value.
426
-------
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112. Hangebrauck, R.P., D.J. von Lehmden, and J.E. Meeker. Emissions of
Polynuclear Hydrocarbons and Other Pollutants from Heat Generation and
Incineration Processes. Journal of the Air Pollution ControlAssociation
14(7): 267-278. July 1964":
113. Thompson, R.E. and M.W. McElroy. Effectiveness of Gas Recirculation and
Staged Combustion in Reducing NOx on a 560-MW Coal-fired Boiler.
Electric Power Research Institute. EPRI Report FP-257. September 1976.
114. McCurley, W.R., C.M. Moscowitz, J.C. Ochner, and R.B. Reznik. Source
Assessment: Dry Bottom Industrial Boilers Firing Pulverized Bituminous
Coal. Report prepared by Monsanto Research Corporation for the U.S.
Environmental Protection Agency. 1979.
115. Ceramic Cooling Tower Company. PSM Drift Testing. CT-142-1. Revision
A. April 21, 1973.
116. Roffman A. and R.E. Grimble. Drift Deposition Rates from Wet Cooling
Systems ^n_ Cooling Tower Environment - 1974. pp 585-597. Energy
Research and Development Administration. 1975.
117. Holmberg, J.D. and O.L. Kinney. Drift Technology for Cooling Towers.
The Marley Company, Mission, Kansas. 1973.
118. Roffman, A. and L.D. Van Vleck. The State-of-the-art of Measuring and
Predicting Cooling Tower Drift and Its Deposition. Journalof the A1r
Pollution Control Association. 24(9): 856-859. September 1974.
119. Schrecker, G.O. and C.D. Henderson. Salt Water Condenser Cooling:
Measurements of Salt Water Drift from a Mechanical-Draft Wet Cooling
Tower and Spray Modules, and Operating Experience with Cooling Tower
Materials In Proceedings of the American Power Conference. Volume 38.
1976.
436
-------
120. Webb, R.O., G.O. Schrecker, and D.A. Guild. Drift Data from a Large
Natural Draft Brackish Water Cooling Tower and Brackish Water Particulate
Scrubber. Paper presented at the Cooling Tower Institute Annual Meeting,
Houston, Texas. January 31-February 2, 1977.
121. DeVine, J.C. The Forked River Program: A Case Study in Salt Water
Cooling. |£ Cooling Tower Environment - 1974. pp 509-557. Energy
Research and Development Administration. 1975.
122. Macaluso, C.A. Ecological Aspects of Cooling Systems 1n_ Cooling Towers.
pp 111-114. American Institute of Chemical Engineers, New York, New
York. 1972.
123. Rice, J.K. and S.D. Strauss. Water Pollution Control in Steam Plants.
Power 120(4); S1-S20. April 1977.
124. Wistrom, G.K. and J.C. Ovard. Cooling Tower Drift - Its Measurement,
Control and Environmental Effects. Paper presented at the Cooling Tower
Institute Annual Meeting, Houston, Texas. January 29-31, 1973.
125. Hanna, S.R. Meteorological Effects of the Mechanical-Draft Cooling
Towers of the Oak Ridge Gaseous Diffusion Plant. Ij^ Cooling Tower
Environment - 1974. pp 291-306.
126. Blackwood, T.R. and R.A. Wacnter. Source Assessment Coal Storage Piles.
Report prepared by Monsanto Research Corporation for the U.S. Environ-
mental Protection Agency. MRC-DA-504. July 1977.
127. Hamersma, J.W., D.6. Ackerman, M.M. Yamada, C.A. Zee, C.Y. Ung, K.T.
McGregor, J.F. Clausen, M.L. Kraft, J.S. Shapiro, and E.L. Moon.
Emissions Assessment of Conventional Combustion Systems: Methods and
Procedures Manual for Sampling and Analysis. Report prepared by TRW,
Inc. for the U.S. Environmental Protection Agency. EPA-60Q/7-79-029a.
January 1979.
128. Leavitt, C., K. Arledge, C. Shin, R. Orsini, A. Saur, J.W. Hamersma,
R. Maddalone, R. Beimer, G. Richard, S. Unger, and M.M. Yamada.
Environmental Assessment of a Coal-Fired Controlled Utility Boiler.
Report prepared by TRW, Inc., for the U.S. Environmental Protection
Agency. EPA-600/7-8Q-086. April 1980.
129. Cleland, J.G. and G.L. Kingsbury. Multimedia Environmental Goals for
Environmental Assessment, Volume II. Report prepared by the Research
Triangle Institute for the U.S. Environmental Protection Agency.
EPA-600/7-77-136b. November 1977.
130. Yu, H.H.S., G.A. Richardson and W.H. Hedley. Alternatives to
Chlorination for Control of Condenser Tube Bio-Fouling. Report
prepared by Monsanto Research Corporation for the U.S. Environmental
Protection Agency; EPA-600/7-77-030. March 1977.
437
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131. Colley, J.D., C.A. Muela, M.L. Owen, N.P. Meserole, J.B. Riggs, and
J.C. Terry. Assessment of Technology for Control of Toxic Effluents
from the Electric Utility Industry. Report prepared by the Radian
Corporation for the U.S. Environmental Protection Agency.
EPA-600/7-78-90. June 1978.
132. Train, R.E., A.M. Breidenbach and E.C. Beck. Supplement for Pretreat-
ment to the Development Document for the Steam Electric Power
Generating Point Source Category. Report prepared by the Effluent
Guidelines Division of the U.S. Environmental Protection Agency.
EPA-440/1-76-084, November 1976.
133. Non-Thermal Discharges from Electric Power Plants. Report prepared
by the Edison Electric Institute.
134. Chu, J.T., P.A. Krenkel and R.J. Ruane. Characterization and Reuse
of Ash Pond Effluents in Coal-Fired Power Plants. Report prepared by
TVA for presentation at 49th Annual Water Pollution Control Federation
Conference, Minneapolis, Minnesota, October 1976.
135. Chu, J.T. and R.J. Ruane. Wastewater Treatment for Coal-Fired Elec-
tric Generating Stations. Report prepared by TVA for presentation
at the 1978 WWEMA Industrial Pollution Conference. St. Louis,
Missouri, April 1978.
136. Ghassemi, M., K. Crawford and S. Quinlivan. Environmental Assessment
Data Base for High-Btu Gasification Technology. Report prepared by
TRW, Inc. for the U.S. Environmental Protection Agency,
EPA-600/7-78-186C, September 1978.
137. Technical Report for Revision of Steam Electric Effluent Limitations
Guidelines. Draft Report. U.S. Environmental Protection Agency.
September 1978.
138. Nichols, C.R., Project Officer. Development Document for Proposed
Effluent Limitations Guidelines and New Source Performance Standards
for the Steam Electric Power Generating Point Source Category. Report
prepared by the Effluent Guidelines Division, Office of Air and Water
Programs of the U.S. Environmental Protection Agency.
EPA-440/1-73-029, March 1974.
139. Chu, J.T., R.J. Ruane and G.K. Steiner. Characteristics of Waste
Water Discharges from Coal-Fired Power Plants. Paper prepared for
presentation at the 31st Annual Purdue Industrial Waste Conference,
Purdue University, Indiana, May 1976.
140. Bornstein, L.J., R.B. Fling, .F.D. Hess, R.C. Rossi and J. Rossoff.
Reuse of Power Plant Desulfurization Waste Water. Report prepared
by the Aerospace Corporation for the .U.S. Environmental .Protection
Agency. EPA-600/2-76-024. February 1976.
438
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Cox, D.B., J.T. Chu, and R.J. Ruane, Characterization of Coal Pile
Drainage. Report prepared by the Tennessee Valley Authority for the
U.S. Environmental Protection Agency. EPA-600/7-79-051„ February
1979.
142. Hart, F.C, and B.D. Delaney. The Impact of RCRA (PL 94-580} on
Utility Solid Wastes. Report prepared by Fred C. Hart Associates,
Inc., for Electric Power Research Institute. EPRI FP-878, August
1978.
143. Hecht, N.I. and D.S. Duvale, Characterization and Utilization of
Municipal and Utility Sludges and Ashes. Vol. II: Utility Coal Ash.
Report prepared by the University of Dayton for the U.S. Environmental
Protection Agency. EPA-670/2-75-033b. May 1975.
144. Van Hook, R.L. Intra-Laboratory Correspondence. Oak Ridge National
Laboratory, October 11, 1976.
145. Water Quality and Treatment. A Handbook of Public Water Supplies
Report prepared by the American Water Works Association, Inc.;
McGraw-Hill Book Company.
146. Hammer, M.J. Water and Waste-Water Technology. John Wiley and Sons,
Inc., New York, 1975.
147. Ciaccio, L.L., Water and Water Pollution Handbook, Volume 1.
Marcel Dekker, Inc., New York, 1971.
148. Lime F6D Systems Data Book. EPRI Report FP-1030. May 1979.
149. Slack, A.V. and J.M. Potts. Disposal and Use of By-product from
Flue Gas Desulfurization Processes, Introduction and Overview. FGD
Symposium, May 1973. EPA-65Q/2-73-Q38, Part II.
150. Colthrop, W.M., N.P. Meserole, B.F. Jones, K. Schwitzgebel,
R.S. Merrill, G.L. Sellman, C.M. Thompson and D.C. Malish. Review
and Assessment of the Existing Data Base Regarding Flue Gas Cleaning
Wastes. Report prepared by Radian Corporation for EPRI. FP-671.
January 1979.
151. Borgwardt, R.H. Effect of Forced Oxidation on Limestone/S0x Scrubber
Performance. EPA Industrial Environmental Research Laboratory, 1977.
152. Interess, E. Evaluation of the General Motors Double Alkali S0?
Control System. EPA-600/7-77-005. January 1977. c
153. SCS Engineers. Chemical Speciation of Contaminants in FGD Sludge
and Waste Water. Interim report under EPA Contract No. 68-03-2371.
Phase II, March 1978.
154. Rossoff, J., et al., Disposal of By-products from Non-regenerable
Flue Gas Desulfurization Systems: Second Progress Report. Report
prepared by the Aerospace Corporation for the U.S. Environmental
Protection Agency. EPA-600/7-77-052. July 1977.
439
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155. Weir, A. Jr., S.T. Carlisle and J. Norn's. Environmental Effects of
Trace Elements from Ponded Ash and Scrubber Sludge. Report prepared
by Southern California Edison Company, with subcontract to Radian
Corporation for the Electric Power Research Institute. EPRI 202.
September 1975.
156. Jones, B.F., J.S. Sherman, D.L. Jernigan, E.P. Hamilton III, and
D.M. Otlmers. Study of Non-hazardous Wastes from Coal-fired Electric
Utilities. Draft report prepared by Radian Corporation for the U.S.
Environmental Protection Agency. December 15, 1978.
157. Duvel, W.A. Jr., W.R. Gallagher, R.G. Knight, C.R. Kolarz, and R.J.
McLaren. State-of-the-Art of FGD Sludge Fixation. Report prepared
by Michael Baker, Jr., Inc., for the Electric Power Research Institute.
FP-671, Volume 3. January 1978.
158. Estes, E.D., F. Smith, and D.E. Wagoner. Level I Environmental Assess-
ment Performance Evaluation. Report prepared by the Research Triangle
Institute for the U.S. Environmental Protection Agency. 1978.
159. Gaskill, A., W.F. Gutknecht, R.K.M. Jayanty, and D.E. Lentzen. Perfor-
mance Audit of Level I EA Analytical Systems (TRW). Report prepared
by the Research Triangle Institute for the U.S. Environmental Protec-
tion Agency. July 1979.
160. Serth, R.W., T.W. Hughes, R.E. Opferkuch, and E.G. Eimutis. Source
Assessment: Analysis of Uncertainty - Principles and Applications.
Report prepared by the Monsanto Research Corporation for the U.S.
Environmental Protection Agency. EPA-600/2-78-Q04u. August 1978.
161. Leavitt, C., K. Arledge, C. Shih, R. Orsini, A. Saur, W. Hamersma,
R. Maddalone, R. Beimer, G. Richard, S. Unger, and M. Yamada. Environ-
mental Assessment of an Oil-Fired Controlled Utility Boiler. Report
prepared by TRW, Inc., for the U.S. Environmental Protection Agency.
EPA-600/7-80-087. April 1980.
162. New Stationary Sources Performance Standards; Electric Utility Steam
Generating Units. Federal Register, Vol. 44, No. 113. June 11, 1979.
440
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APPENDIX A
CRITERIA FOR EVALUATING THE ADEQUACY
OF EXISTING EMISSIONS DATA FOR
CONVENTIONAL STATIONARY COMBUSTION SYSTEMS
A major task in the present program was the identification of gaps and
inadequacies in the existing emissions data base for conventional stationary
combustion systems. The output from this effort will be used in the planning
and performance of a combined field and laboratory program as required to com-
plete adequate emissions assessment for each of the combustion source types.
The criteria for assessing the adequacy of emissions data are developed
by considering both the reliability of the data and the variability of the
data. The general approach is to utilize a three-step process as described
below. This approach is applicable to the evaluation of the existing emissions
data as well as emissions data collected during the course of this program.
STEP I
In the first step of the evaluation process, the emissions data are
screened for adequate definition of process and fuel parameters that may affect
emissions as well as validity and accuracy of sampling and analysis method.
The screening mechanism is devised to reject emissions data that would be of
little or no use. Acceptance of emissions data in this screening step only
indicates the possibility for further analysis, and in no way suggests that
these data are valid or reliable. As such, the data screening criteria are
often expressed in terms of minimum requirements. These screening criteria
are depicted in Figure A-l and discussed in detail below.
The first criterion that will be applied is that only source test data
will be accepted. A significant portion of the data base, and especially those
contained in the National Emissions Data System (NEDS), were developed by the
use of standard emission factors* and not derived from actual test data. The
inclusion of these estimated emissions data in the data base would lead to the
obviously biased conclusion that the actual emissions were the same as those
predicted by the standard emission factors.
The second criterion that will be applied is an adequate description of
the source. In order to further analyze the emissions data, there must be
sufficient information to designate the combustion source according to the
Mostly by the use of emission factors published in the EPA Publication AP-42
"Compilation of Air Pollutant Emissions Factors."
441
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IMISSIONS DATA
ARE DATA ACQUIRED
»Y SOURCE TESTING?
NO
VIS
IS THERE SUFFICIENT
INFORMATION TO
DESIGNATE THE
COMBUSTION SOURCE
ACCORDING TO GCA
CLASSIFICATION CODE?
NO
YiS
IS THIRE INFORMATION
ON FUEL CONSUMPTION
RATE? FOR NOX EMtSSIONS
DATA, IS THERE INFORMA-
TION ON OPERATING LOAD?
NO
YES
FOR PARTI CULATE
EMISSIONS DATA FROM
COAL iURNING UTILITY
IOIURS, IS THERE IN-
FORMATION ON
PARTI CULATE CONTROL
DEVICE PERFORMANCE?
NO
YES
FO* TRACE ELEMENT EMISSIONS DATA FROM
COAL AND OIL COMSUSTION, ARE THERE
CORRESPONDING DATA ON TRACE ElEMcNT
CONTENT OF THI FUEL?
PC* SOy EMISSIONS DATA FROM COAL AND
OIL A COMIUSTION, A« THERE
CORRESPONDING DATA ON SULFUR CONTENT
OF THE PU£L?
YES
NO
IS THERE INFORMATION
ON THE SAMPLING AND
ANALYSIS METHODS
EMP1OYED?
YES
CAN SAMPLING AND
ANALYSIS METHODS
EMPLOYED MO'/IDE
EMISSION ESTIMATES WITH
AN ACCURACY KTTER THAN
A FACTOR OF 3?
YES
NO
INCLUDE EMISSIONS DATA IN USABLE DATA BASE FOR FURTHER ANALYSIS
PROCEED TO STEP 2
Figure A-1. Step 1 Screening Mechanism for Emissions Data
442
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appropriate GCA classification code. As a minimum, the information provided
should include: the function of the combustion source (electricity generation,
industrial, commercial/institutional, or residential), the type of combustion
(external combustion or internal combustion), the type of fuel used (coal, oil,
gas or refuse), and in the case of coal combustion, the type of furnace (pul-
verized dry bottom, pulverized wet bottom, cyclone, or stoker). For emissions
data that are judged to be valuable* and otherwise acceptable, efforts will be
made to acquire the needed source description information directly from the
investigator or the plant operator.
The third criterion for acceptance of emissions data for further analysis
is an adequate definition of the combustion system operating mode. For example,
operating load has a large effect on NOX emissions from combustion systems. It
is therefore important to have an adequate definition of the test conditions
that may affect emissions. As a minimum, there must be information on the fuel
consumption rate for the emissions data to be accepted. The fuel consumption
rate is necessary for the calculation of emission factors. For NOX emissions
data, field and tests results that do not include information on operating load
will be considered unacceptable because they cannot be used to estimate emis-
sions from a typical combustion system nor could they be used to estimate emis-
sions at any specific load. For other types of emission data, the operating
load information will be considered as a useful parameter for data correlation
but not an absolute requirement for data acceptance.
The fourth criterion for acceptance of emissions data for further analysis
is an adequate definition of the pollution control device performance. Con-
trol device performance will affect not only total emissions but will influence,
for example, the particle size distribution and composition of flue gas emis-
sions. The application of design efficiencies must be approached with caution
in estimating uncontrolled emissions. If a design efficiency of 99 percent is
used and if the control device operating efficiency is only 90 percent, the
calculated uncontrolled emissions would be 10 times larger than the actual case.
Since most coal burning utility boilers are equipped with particulate control
devices, particulate emissions data from the coal burning utility sector will
not be considered acceptable unless accompanied by the particulate control de-
vice performance data. The application of particulate control devices are
lower for the industrial, commercial/institutional and residential sectors,
and also much lower for the oil burning utility sector and nonexistent for the
gas burning utility sector. For these combustion source types, emissions data
will be accepted as uncontrolled emissions data, unless there is information
implying the contrary. As noted in the foregoing discussions, acceptance of
emissions data at this screening step does not suggest that the data are
necessarily valid or reliable. In the second step of the data evaluation pro-
cess, methods for rejecting outlying data points will be defined. Controlled
emissions data that have been mistakenly assumed to be uncontrolled emissions
data due to lack of information will be identified as outlying data points and
be rejected in this second step.
*
In this context, emissions data for trace elements, POM, PCB, and organics
are considered to be more valuable because of the paucity of data.
443
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The fifth criterion that will be employed in judging the usefulness of
the emissions data is the availability of fuel analysis data. This is espe-
cially true for emissions of trace elements, and S0X. The trace element con-
tent of coal can vary by one to two orders of magnitude and emissions are
closely related to the trace element content of the coal. No trace elements
are present in appreciable amounts in gaseous hydrocarbons; however, Ni, V and
Na are present in appreciable amounts in some fuel oil. In order to estimate
trace element emission levels from all sources within a given category, the
fraction of each trace element exiting the system in each effluent stream must
be estimated. Thus, trace element emissions data from coal and oil combustion
that are not accompanied by analysis data on the trace element content of the
fuel will not be accepted. Similarly, SOx emissions are directly related to
the sulfur content of the fuel. SOx emissions data from coal and oil combus-
tion that do not include information on the sulfur content of the fuel will
therefore not be accepted.
The last criterion that will be applied is an evaluation of the accuracy
of the sampling and analysis methods employed. In order to determine emissions
from a given site to within a factor of 3, both the sampling and analysis pro-
cedures employed must be capable of providing an accuracy which is better than
a factor of 3. The list of methods available for the sampling and analysis
of general stream types and chemical classes and species is very extensive,
and has been described in detail in two recent TRW reports (References A-l and
A-2). In general, most of the sampling and analysis procedures recommended in
these two references are adaptations of standard EPA, ASTM, API methods, and
have an accuracy and/or precision of ± 10 to 20 percent or better. Emissions
data obtained by these recommended methods or techniques will be considered
acceptable. Emissions data obtained by methods or techniques not listed in
these two references will be subjected to careful review, and rejected if it
is determined that the sampling or analysis method employed would not be able
to provide emission estimates within an accuracy factor of 3 or better. Special
emphasis will be placed on the review of sampling and analysis methods used for
obtaining PCB, POM, particulate sulfate, and trace elements emissions data.
In cases where information on the sampling and analysis methods employed is
unavailable, the date of testing will be used as the criterion for inclusion or
rejection of the emissions data in the usable data base. Emissions data ob-
tained before 1972 will be generally considered as unacceptable due to the
probable use of unreliable sampling or analysis procedures. The 1972 cut-off
date is selected on the basis that the EPA Method 5, which has been more or
less recognized nationally as the standard method for sampling particulates,
was introduced in late 1971. Furthermore, most of the more sophisticated sam-
pling and analysis techniques for obtaining emissions data, and especially
those for measuring pollutants for which data are lacking (such as trace ele-
ments and particulate sulfate), were not introduced and used before 1972.
STEP 2
In the second step of the data evaluation process, emissions data which
have been identified as usable in the screening step will be subjected to fur-
ther engineering and statistical analysis to determine the internal consis-
tency of the test results and the variability in emissions factors.
444
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Emissions data included in the usable data base will first be categorized
according to the 5 column 6CA combustion system classification code and the unit
operation from which the pollutants are emitted. For NOx, the emissions data
will be further categorized according to the method of NOx control; no control,
staged firing, low excess air, reduced load, or flue gas recirculation. Emis-
sions factors for individual sites, normally expressed in the form of Ib/MM
Btu or Ib/ton, will then be calculated for each pollutant/unit operating pair.
In the case of trace element stack emissions from coal and oil combustion,
these emission factors will be calculated in the form of the fraction of each
trace element emitted to the atmosphere.
The emission factors calculated for each pollutant/unit operation pair will
be evaluated in terms of consistency of test results among sites. All the data
points that lie outside the upper and lower limits of reasonable data will be
subjected to detailed scrutiny, and discarded unless there is additional in-
formation to reclassify the data into the correct category. The decision
whether an outlier is a reasonable result or whether it may be discarded as
being an improbable member of the group will be based on the method of Dixon.
The method of Dixon is a statistical technique applicable to the rejection of
a single outlying point from a small group of data, and is described in detail
in Attachment A.
The t value in statistical analysis can be used to establish confidence
ranges within which the true value lies. The true mean emission factor, u,
can be expressed in terms of estimated mean emission factor x from measurements
and t:
v = x t ts(x)
where s(x) is the estimated standard deviation of the mean. Thus, the variabi-
lity v, defined as
is a measure of precision for the estimated mean emission factor x. The varia-
bility of the emission factors will next be calculated. The value of t depends
on the degree of freedom and the confidence level of the interval containing
the true mean y, and is given in standard statistics texts. For the present
program, that t values at 95 percent confidence level will be used in calcula-
ting the variability of emission factors.
The main thrusts in this second step are: (1) to determine the emission
factors for each pollutant/ unit operation pair and for each combustion source
category; (2) to discard outlying data points using the method of Dixon; and
(3) to calculate the percent variability of the emission factors. The values
calculated in this step will be used in Step 3.
445
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STEP 3
The final step in the data evaluation process involves a method developed
by the Monsanto Research Corporation (MRC) for the evaluation of data adequacy.
This quantitative method will indicate where additional emissions data are
needed. The method is based on both the potential environmental risks asso-
ciated with the emission of each pollutant and the quality of the existing
emissions data. Potential environmental risks are assessed based on whether
the source severity factor exceeds 0,05. The 0.05 criterion reflects an un-
certainty factor of 20 in the calculation of source severity factor (A-4).
The potential environmental risks associated with pollutant emissions are
determined by the use of source severity factors S. For emissions to the at-
mosphere, the source severity S is defined as the ratio of the calculated maxi-
mum ground level concentrations of the pollutant species to the level at which
a potential environmental hazard exists. The simple Gaussian Plume equation for
ground level receptors at the plume centerline is the disperion model used for
determining the ground level concentration. The potential environmental hazard
level is taken to be the Threshold Limit Value {TLV} divided by 300 for non-
criteria pollutants and the ambient air quality standard for the criteria
pollutants. The mean source severity S for noncriteria pollutants is calculated
as follows:
(TLV)hd
where Q « emission rate, g/s
3
TLV = threshold limit value, g/m
h * stack height, m
For the five criteria pollutants, the equations for calculating raean source
severity S is given in the following table:
Pollutant Severity equation
P.nrticulate
S0x
N0x
Hydrocarbons
CO
S =
S =
S »
S =
S «
70Qh~2
50Qh"2
315Qh~2<1
162. 5Qh~2
0.78Qh"2
The emission rate is calculated by thi following equation:
Q • |p (EF) (GPP) (VPS)
446
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where TC = total fuel consumption, tons/year
TNP - total number of plants/sites
EF = emission factor, Ib/ton
GPP = 453.6 g/lb
YPS = 3.1688 x 10"8 yr/s
The mean source severity factor S for each pollutant/unit operation pair
will be used in the evaluation of data adequacy for air emissions. The method
for evaluating data adequacy of air emissions 1s outlined below.
Case 1: When EmissionsDataAre Available and Usable
1. Determine the mean emission factor J. and the variability of
the emission factor ts(x)/x for each pollutant/unit operation
pair, (This will be done in Step 2 of the data evaluation
process.}
2. Determine the mean severity factor S for each pollutant/unit
operation pair by using the mean emission factor x.
3, If the variability in emission factor < 70 percent, there
is no need for additional data.
4. If the variability in emission factor > 70 percent and
S > 0.05, the current data base is Judged to be Inadequate
and there is need for additional data.
5, If the variability in emission factor > 70 percent and
S ^0.05, determine the severity factor S by using the
emission factor x :
xu = x + tsO?)
Su is the upper bound for the severity factor S. The
current data base is judged to be adequate if Su <_ 0.05
and inadequate if Su > 0.05.
Case 2: When Emissions Data Are Not Available
1. Determine, if possible, from fuel analysis, mass balance
and physico-chemical considerations the upper bound xu
of the emission factor x. For trace element stack emissions,
for example, xu can be determined by assuming that all the
trace elements present in the fuel are emitted through the
stack.
2. Determine the upper bound Su of the severity factor S for
each poVlutant/unit operation pair by using the emission
factor x~u.
447
-------
3. The current data base is judged to be adequate if Su £ 0.05
and inadequate if Su > 0.05.
As discussed in a recent Monsanto report (Reference A-3)» an allowable un-
certainty in emission factor of ± 70 percent (factor of 3) would lead to an
uncertainty of less than 10 in S , , which has been defined as the acceptable
uncertainty factor for S.
As 9 result of th« aonllcat.inn nf the ahnve Hata evaluation criteria,
pollutant/unit operation pairs that hav* been inadequately characterized will
be Identified to permit the planning of field tests for acquisition of addi-
tional emissions data.
448
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ATTACHMENT A
METHOD OF DIXON FOR DISCARDING
OUTLYING DATA*
The method of Dixon provides a test for extreme values using range. If
the observations in the sample are ranked, the individual values can be iden-
tified xi, X|, xs, . . ., xn_i, xn. It is immaterial whether the ranking pro-
ceeds from high values to low or from low values to high. The Dixon extreme-
value test gives the maximum ratio of differences between extreme-ranking ob-
servations to be expected at various probability levels and for different sam-
ple sizes. Table A-l gives the test ratios and maximum expected values. For
samples less than about eight observations, the ratio of the difference between
the extreme and the next-to-extreme value to the total range is compared with
the tabulated values for the same sample size. If the observed ratio exceeds
the tabulated maximum expected ratio, the extreme value may be rejected with
the risk of error set by the probability level. For samples between about
9 and 14, test the ratio of the difference between the first and third ranking
observations to the difference between the first and next to last. For samples
of 15 or more, use the ratio of the difference between the first and third
ranking observations to the difference between the first-and the second-from
last observation.
In the evaluation of the emissions data, the 0.05 probability level will
be used as the basis for discarding outlying data.
Volk, W. Applied Statistics for Engineers. New York McGraw-Hill, Inc.
2nd ed. p. 387-388. 1969.
449
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TABLE A-l. MAXIMUM RATIO OF EXTREME RANKING OBSERVATIONS
Maximum ratio
Recommended Rank Sample
for difference size, Probability level
sample size ratio n
0.10 0.05 0.01
n - 8 *2 ~ Xl 3
xn - XT d
n 1 4
5
6
7
ft .- n * 15 ^ - ^ ®
o < n < 13 "
xn-l " xl 9
10
11
12
13
14
— **? ~ X1 IS
n T ic J * 13
n > ID
xn-2 xl 16
17
18
19
20
0.886
0.679
0.557
0.482
0.434
0.650
0.594
0.551
0.517
0.490
0.467
0.448
0.472
0.454
0.438
0.424
0.412
0.401
0.941
0.765
0.642
0.560
0.507
0.710
0.657
0.612
0.576
0.546
0.521
0.501
0.525
0.507
0.490
0.475
0.462
0.450
0.988
0.889
0.780
0.698
0.637
0.829
0.776
0.726
0.679
0.642
0.615
0.593
0.616
0.595
0.577
0.561
0.547
0.535
450
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REFERENCES
A-l. Hamersma, J.W., S.C. Reynolds, and R.F. Maddalone. IERL-RTP Procedures
Manual: Level 1 Environmental Assessment. EPA-600/2-7fi-160a. p. 131.
June 1976.
A-2. Maddalone, R.F. and S.C. Qulnlivan. Technical Manual for Inorganic
Sampling and Analysis. Report prepared by TRW, Inc. for the U.S.
Environmental Protection Agency. EPA-600/2-77-024, January 1977.
A-3. E1mut1s, E.C. Source Assessment: Pr1or1t1zat1on of Stationary A1r
Pollution Sources--Model Description. Report prepared by Monsanto
Research Corporation for the U.S. Environmental Protection Agency,
EPA-600/2-76-032a. February 1976.
A-4. Serth, R.W., T.W. Hughes, R.E. Qpferkuch, and E.C. Eimutis. Source
Assessment: Analysis of Uncertainty - Principles and Applications.
Report prepared by Monsanto Research Corporation for the U.S. Environ-
mental Protection Agency. EPA-6QO/2-78-004u. August 1978.
451
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APPENDIX B
DATA REDUCTION PROCEDURE
Stack emissions data reported from field measurements or laboratory
analyses are often expressed in terms of volume concentration (ppmv) or mass
concentration (mg/m , yg/m }. To convert these emissions data to the emission
factor form, the following data reduction procedure, adopted from Reference
B-l, is used.
The number of gm moles of flue gas per gm of fuel can be computed using
the fuel composition analysis and effluent O concentration:
"FG
4.762 (nc + ns) + .9405 nR. - 3.762nQ F
1 - 4.762 (02/100) 1 - 4.762 (02/100)
where: n^g * gm moles of dry effluent/gm of fuel under
actual operating conditions.
IK « gm moles of element j 1n fuel per gm of fuel.
Og * volumetric Q£ concentration in percent.
F * gm moles of dry effluent/gm of fuel under
stolchlometric combustion.
The average values of F for natural gas and various liquid fuels are given
1n Table B-l. The value of F for coal must be computed on an individual basis
because of the variation in the elemental composition of different coals.
For emission species measured on a volumetric concentration basis (ppmv),
the emission factor expressed as ng/J can be computed using the following
equation:
452
-------
/Volumetric I / _ \ c u
/Emission* .,,, i Concentration^ <•*") * F * "s
t Factor / ("9/J) = 7r~; f X
/Fuel I ,.,.. ,._1% 1 .- 4.762
I Heating Value! IKJ/|C9
where s = subject emission species
MS = molecular weight of species s
For emission species measured on a mass concentration basis (mg/m or
yg/m ) at 20°C, the emission factor expressed as ng/J, can be computed using
the following equation:
/Mass \ i..nfj) x F x 24<04
/Emission* ,no/n _
-------
tn
TABLE B-1. ELEMENTAL COMPOSITION AND
HIGHER HEATING VALUE OF FUELS
Fuel
"c
"s
»H
no
F
Heating
Value
Natural
Gas
0.06221
0
0.23116 -
0.00040
0.51215
53,310 kJ/kg
No. 2
Distillate
Oil
0.06994
0.00006
0.13889
0.001125
0.45983
45,040 kJ/kq
Kerosene
0.06994
0
0.15873
0
0.48234
47,710 kJ/kg
Res id
Oil
0.07160
0.00031
0.10913
0.00125
0.44037
43,760 kJ/kg
*
The composition and heating value data are obtained from Reference B-2.
-------
REFERENCES
B-1. Coppersmith, F. M., R. F. Jastrzebski, D. V, Giovanni and S. Hersh.
Con. Edison's Gas Turbine Test Program: A Comprehensive Evaluation of
Stationary Gas Turbine Emission Levels. Paper presented at the 67th
Annual Meeting of the Air Pollution Control Association, Denver,
Colorado, June 9-13, 1974.
B-2. Steam/Its Generation and Use. Revised 38th Edition. The Babcock and
Wilcox Company, New York, New York. 1975.
455
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METRIC CONVERSION FACTORS AND PREFIXES
CONVERSION FACTORS
To convert from
Degrees Celsius (°C)
Joule (J)
Kilogram (kg)
KHojoule/kflogram (kj/kg)
Megagram (Mg)
Megawatt (MW)
Meter (m)
Meter3 (m3)
Meter3 (m3)
Meter (m )
To
Degrees Fahrenheit (°F)
Btu
Pound-mass (avoirdupois)
Btu/lbm
Ton (2000 lbm)
Horsepower (HP)
Foot (ft)
Barrel (bbl)
Foot3 (ft3)
Gallon (gal)
Multiply by
tCF) •
9.478 x
2.205
4.299 x
1.102
1.341 x
3.281
6.290
3.531 x
2.642 x
1.8 t(°C) + 32
io-4
1Q3
IO1
102
Nanogram/joule (ng/J)
Plcogram/joule (pg/J)
Ib/mil11on Btu
m
Ib /million Btu
m
2.326 x 10
2.326 x 10
-3
-6
PREFIXES
Multiplication
Prefix
Peta
Tera
Glga
Mega
Kilo
mm
Micro
Nano
P1co
Symbol
P
T
G
M
k
m
u
n
P
Factor
ID15
IO12
109
106
103
io-3
io-6
io-9
io-12
Example
1 Pm = 1 x 10 meters
1 Tm = 1 x 10 meters
g
1 Gm = 1 x 10 meters
1 Mm = 1 x 10 meters
1 km - 1 x 10 meters
1 mm = 1 x 10" meter
1 pm * 1 x 10~ meter
_g
1 nm = 1 x 10 meter-
-12
1 pm = 1 x TO meter
456
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