DCN No. 86-203-024-41-10
Radian No. 203-024-41
EPA Contract No. 68-02-3889
Work Assignment No. 41
SUMMARY OF TRACE EMISSIONS FROM AND
RECOMMENDATIONS OF RISK ASSESSMENT METHODOLOGIES
FOR COAL AND OIL COMBUSTION
FINAL REPORT
Prepared for:
Warren D. Peters
Technical Project Officer
Pollutant Assessment Branch
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Prepared by:
R. C. Mead, B. K. Post, and G. W. Brooks
Radian Corporation
3200 Progress Center
Post Office Box 13000
Research Triangle Park, North Carolina 27709
July 1986
-------
DISCLAIMER
This report has been reviewed by the Office of Air Quality Planning and
Standards, U. S. Environmental Protection Agency, and has been approved for
publication as received from Radian Corporation. Approval does not signify
that the contents necessarily reflect the views and policies of the Agency.
Neither does mention of trade names or commercial products constitute
endorsement or recommendation for use.
ii
-------
EXECUTIVE SUMMARY
The results of a program to investigate and summarize trace pollutant
emissions data and risk assessment methodologies for coal and oil combustion
sources are presented in this document. The program was performed under the
U. S. Environmental Protection Agency (EPA) contract no. 68-02-3889, work
assignment 41 for the Pollutant Assessment Branch, Strategies and Air
Standards Division, Office of Air Quality Planning and Standards. The
Project Officer was Mr. Warren D. Peters.
The objectives of this program were two-fold. The first objective was
to develop a comprehensive data base of information on emission factors for
trace pollutants emitted from coal and oil combustion sources in the utility,
industrial, commercial/institutional, and residential sectors. The trace
pollutants of concern are arsenic, beryllium, cadmium, copper, chromium,
lead, mercury; manganese, nickel, formaldehyde, polycyclic organic matter
(POM), and radionuclides. Polycyclic organic matter emissions were assessed
in total as a group of compounds. Assessments of individual POM compounds
were not specifically made; however, results for individual POM's may be
reported if a particular test only examined a limited number of POM species
or if only one POM was identified in an analysis. Similarly, not all
radionuclides were included in the combustion source emissions assessment.
Only uranium-238 and thorium-232 were focused on because they have the
longest half-lives of all radionuclides and generally are used as indicators
of the severity of radionuclide emissions.
All 12 pollutants were examined for each combustion sector except for
radionuclides. Radionuclides were only evaluated in connection with
coal-fired utility sources. The consideration of lead as a trace pollutant
from coal and oil combustion was added to this project by EPA after the
submittal of the draft final report. For this reason, the treatment of lead,
including the availability of emission factor data, is very abbreviated
compared to the other trace pollutants in the document. Only a limited
number of the references listed in the report bibliography in Appendix C were
iii
-------
evaluated for lead data. It is acknowledged that this approach does not
provide for a thorough analysis of lead; however, the approach is sufficient
to achieve the objectives of this study.
Emission factors were summarized for each pollutant and each combustion
sector combination according to fuel type (e.g., bituminous, subbituminous,
or lignite coal), boiler type (e.g., pulverized, cyclone, stoker), and
control device type (e.g., ESP, baghouse, scrubber). A slate of emission
factors was developed for each pollutant and combustion sector that are
available for use in subsequent risk assessments. This slate of available
emission factors has been termed "recommended factors" in this report. The
term recommended factors is intended to mean that the presented averages or
ranges of emission factors appear to be those that reasonably could be used
in subsequent risk assessment analyses, considering the overall availability
of data. The recommended factor term does not imply that a particular factor
is endorsed by the U. S. EPA or the authors of this report to be a fully
characterized or representative emission rate for the given combustion source
situation. Extensive data quality assurance procedures, necessary to
reasonably characterize a data set as representative of a particular source,
were not performed in this study because of time and budgetary constraints.
Instead, the recommended factors are simply straightforward calculations of
emission factor averages and ranges based on data presented in the
literature. The recommended factors are not to be considered as suggested
emission factor values for use in other activities such as regulatory
development or specification of acceptable ambient concentrations.
The second objective of the program was to investigate thoroughly
potential ways to conduct risk assessments of trace metal emissions from
combustion sources and provide recommendations and rationales as to what
methodologies should be used in subsequent EPA risk assessment activities for
coal and oil combustion sources. The recommended risk assessment approach
for residential sources is to conduct a county-by-county area source analysis
using the area source modeling algorithm in EPA's SHEAR model, fuel use data
published by the U. S. Department of Energy, population statistics provided
by the Census Bureau, and emission factors developed as a part of this
overall program. For industrial and commercial/institutional sources, the
iv
-------
recommended risk assessment approach is to conduct a point source analysis
using EPA's Human Exposure Model (HEM) on a statistically representative
subset of boilers selected from the National Emissions Data System (NEDS) and
extrapolate the results for the subset to a national level. The
extrapolation would be performed by determining the average risk from the
boiler subset and multiplying that average risk for that combustion sector
times the total number of sources in the sector. The recommended risk
assessment approach for utility sources involves conducting a point source
risk assessment of all coal and oil utility sources using HEM. Emissions
estimates and source characterization data would be obtained from the
emission factors developed in this program and from the Edison Electric
Institute's POWER STATISTICS data base.
-------
TABLE OF CONTENTS
Section Page
EXECUTIVE SUMMARY iii
LIST OF FIGURES x
LIST OF TABLES xi
1.0 PROJECT INTRODUCTION 1 1
1.1 Background 1 1
1. 2 Pro j ect Description 1-7
2.0 IDENTIFICATION Of PERTINENT RESEARCH 2-1
2.1 Results Of Information Gathering 2-4
2.1.1 Radian Corporation 2-4
2.1.2 Pollutant Assessment Branch (PAB) 2-5
2.1.3 National Air Data Branch (NADB) 2-6
2.1.4 Emission Standards & Engineering Division (ESED) 2-6
2.1.5 Air & Energy Engineering Research Laboratory (AEERL) .... 2-6
2.1.6 Office Of Air Quality Planning & Standards (OAQPS) 2-7
2.1.7 Department Of Energy (DOE) 2-8
2.1.8 Tennessee Valley Authority (TVA) 2-8
2.1.9 Office Of Radiation Programs (ORP) 2-8
2.1.10 Utility Air Regulatory Group (UARG) 2-9
2.1.11 Kilkelly Environmental Associates 2-9
2.1.12 Edison Electric Institute (EEI) and Utility Data
Institute (UDI) 2-9
2.1.13 American Petroleum Institute (API) 2-10
2.1.14 American Boiler Manufacturer's Association (ABMA) 2-10
2.1.15 Council of Industrial Boiler Owners (CIBO) 2-10
2.1.16 American Society of Mechanical Engineers (ASME) 2-11
2.1.17 Electric Power Research Institute (EPRI) 2-11
2.1.18 Other Organizations Performing EPRI-Sponsored Research .. 2-12
3.0 CHARACTERIZATION OF TRACE POLLUTANTS IN COMBUSTION PROCESSES ... 3-1
3 .1 Description of Data Base 3-2
3.2 Fuel Consumption 3-3
3.2.1 Types of Coal and Oil 3-3
3.2.2 Fuel Use by Combustion Sector 3-3
vi
-------
Section
3.3 Concentration of Trace Elements In Fuels 3'°
3.3.1 Arsenic in Fuels ................ 3-7
3.3.2 Beryllium in Fuels ....................... 3"9
3.3.3 Cadmium in Fuels 3'10
3.3.4 Chromium in Fuels 3 ~12
3.3.5 Copper in Fuels 3"13
3.3.6 Mercury in Fuels 3'14
3.3.7 Manganese in Fuels 3-15
3.3.8 Nickel in Fuels 3'17
3.3.9 Thorium in Coal 3"18
3 . 3 .10 Uranium in Coal 3 -19
3.3.11 Lead in Fuels 3 -19
3.4 Behavior of Trace Pollutants During Combustion 3-20
3.4.1 Partitioning and Enrichment Behavior of Trace Metals
During Combustion 3-20
3.4.1.1 Theories Explaining Trace Metal Behavior in
Coal Combustion Systems 3-23
3.4.1.1.1 Volatilization/Condensation
Mechanism ........... 3-23
3.4.1.1.2 Compound Boiling Point 3-24
3.4.1.1.3 Elemental Association in Coal 3-24
3.4.1.2 Theories Explaining Trace Metal Behavior in
Oil Combustion Systems 3-25
3.4.2 Behavior of Radionuclides During Combustion 3-25
3.4.3 Formation and Transformation of POM and Formaldehyde
During Combustion 3-26
3.5 Effects of Boiler Design and Control Technology on Emissions ... 3-31
3.5.1 Characteristics of the Boiler Population 3-31
3.5.2 Trace Metal and Radionuclide Emissions 3-33
3.5.3 Polycyclic Organic Matter Emissions 3-34
3.6 Emission Factors for Oil-Fired Combustion Sources 3-36
3.6.1 Recommended Emission Factors 3-36
3.6.1.1 Derivation of Recommended Trace Metal Emission
Factors 3-36
3.6.1.2 Data Quality for Trace Metal Emission Factors
and Areas for Future Research 3-37
3.6.1.3 Derivation of POM and Formaldehyde Emission
Factors 3-38
vii
-------
Section Page
3.6.1.4 Data Quality for POM and Formaldehyde Emission
Factors and Areas of Further Research 3-38
3.6.2 Arsenic Emission Factors 3-39
3.6.3 Beryllium Emission Factors 3-40
3.6.4 Cadmium Emission Factors 3-41
3.6.5 Chromium Emission Factors 3-41
3.6.6 Copper Emission Factors 3-43
3.6.7 Mercury Emission Factors 3-43
3.6.8 Manganese Emission Factors . 3-44
3.6.9 Nickel Emission Factors 3-45
3.6.10 POM Emission Factors 3-45
3.6.11 Formaldehyde Emission Factors 3-48
3.6.12 Lead Emission Factors 3-49
3.7 Emission Factors for Coal-Fired Combustion Sources 3-49
3.7.1 Trace Metal Emission Factors 3-51
3.7.1.1 Arsenic Emission Factors for Coal-Fired
Boilers 3-51
3.7.1.2 Beryllium Emission Factors for Coal-Fired
Boilers 3-57
3.7.1.3 Cadmium Emission Factors for Coal-Fired
Boilers 3-60
3.7.1.4 Chromium Emission Factors for Coal-Fired
Boilers 3-64
3.7.1.5 Copper Emission Factors for Coal-Fired
Boilers 3-66
3.7.1.6 Mercury Emission Factors for Coal-Fired
Boilers 3-70
3.7.1.7 Manganese Emission Factors for Coal-Fired
Boilers 3-73
3.7.1.8 Nickel Emission Factors for Coal-Fired
Boilers 3-76
3.7.1.9 Trace Metal Emission Factors for Residential
Coal Combustion 3-77
3.7.2 Radionuclide Emission Factors 3-79
3.7.3 POM and Formaldehyde Emission Factors 3-80
3.7.3.1 POM Emission Factors 3-80
3.7.3.2 Formaldehyde Emission Factors 3-82
3.7.4 Lead Emission Factors 3-83
3.7.5 Summary of Emissions from Coal Combustion 3-83
4.0 RECOMMENDATIONS FOR CONDUCTING RISK ASSESSMENTS FOR TRACE
POLLUTANTS FROM COAL AND OIL COMBUSTION 4-1
viii
-------
Section
4.1 Utility Boilers ......................... ... ........ ........... 4"1
4.1.1 Recommended Approach ................... ..... 4~ ^
4.1.2 Limitations of the Recommended Approach ................. 4-18
4.1.3 Options to the Recommended Approach ......... . ...... ..... 4-20
4.1.4 Recommended Approach for Radionuclide Emissions ..... .... 4-21
4. 2 Industrial and Commercial/Institutional Boilers ................ 4-30
4.2.1 Recommended Approach ..................... .... ........... 4-30
4.2.1.1 Point Source Component ......................... 4-31
4.2.1.2 Area Source Component .......................... 4-44
4.2.1.3 Total Risk ... ____ . ..... ....... ............ ..... 4-50
4.2.2 Options to the Recommended Approach ..................... 4-50
4.2.3 Recommended Approach for Radionuclide Emissions ......... 4-51
4.3 Residential Boilers and Furnaces ............. . ......... . ....... 4-54
APPENDIX A - CONTACTS FOR IDENTIFICATION OF PERTINENT RESEARCH ...... A-l
APPENDIX B - DATA BASE DEVELOPMENT B-1
APPENDIX C - BIBLIOGRAPHY C-l
APPENDIX D - FUEL HEATING VALUES D-1
APPENDIX E - EMISSION FACTORS MEASURED AT INDIVIDUAL COAL-FIRED
BOILERS E-l
ix
-------
LIST OF FIGURES
Figure Page
1-1 Sources and Means of Exposure to an Individual from
Combustion Source Atmospheric Trace Pollutant Emissions 1-3
3-1 Coal Fields in the United States (Excluding Alaska) 3-4
D-l Key to the Fuel Oil Regions in Tables D-6 to D-10 D-17
-------
LIST OF TABLES
Table
2-1 Summary of Organizations Contacted and Projects or Types
of Information Available 2-2
3-1 U.S. Fuel Consumption by Sector, 1982 3-5
3-2 Concentration of Arsenic in Coal by Coal Type . 3-86
3-3 Ranges of Arsenic Concentration in Coals by Coal Type 3-86
3-4 Arsenic Concentration in Coal by Region . 3-87
3-5 Concentrations of Arsenic in Oil Reported in Previous
Studies ................ 3-88
3-6 Summary of Data on Arsenic in Oil 3-89
3-7 Concentration of Arsenic in U.S. Versus Foreign Crude
Oils 3-89
3-8 Concentration of Beryllium in Coal by Coal Type 3-90
3-9 Ranges of Beryllium Concentration in Coals by Coal Type ... 3-90
3-10 Beryllium Concentration in Coal by Region 3-91
3-11 Concentrations of Beryllium in Oil Reported in Previous
Studies 3-93
3-12 Summary of Data on Beryllium in Oil 3-94
3-13 Concentration of Cadmium in Coal by Coal Type 3-95
3-14 Ranges of Cadmium Concentration in Coals by Coal Type ..... 3-95
3-15 Cadmium Concentration in Coal by Region 3-96
3-16 Concentration of Cadmium in Oil Reported in Previous
Studies 3-97
3-17 Summary of Data for Cadmium in Oil ........................ 3-98
3-18 Concentrations of Cadmium in U.S. Versus Foreign Crude
Oils , 3-98
xi
-------
Table
3-19
3-20
3-21
3-22
3-23
3-24
3-25
3-26
3-27
3-28
3-29
3-30
3-31
3-32
3-33
3-34
3-35
3-36
3-37
3-38
3-39
3-40
Concentrations of Chromium in Coal by Coal Type
Ranges of Chromium Concentration in Coals by Coal Type ....
Chromium Concentration in Coal by Region
Concentrations of Chromium in Oil Reported in Previous
Studies
Summary of Data for Chromium in Oil
Concentration of Copper in Coal by Coal Type
Ranges of Copper Concentration in Coals by Coal Type
Copper Concentration in Coal by Region .
Concentrations of Copper in Oil Reported in Previous
Studies
Summary of Data for Copper in Oil
Concentration of Copper in U.S. Versus Foreign Crude
Oils
Concentration of Mercury in Coal by Coal Type
Ranges of Mercury Concentration in Coals by Coal Type
Mercury Concentration in Coal by Region
Concentrations of Mercury in Oil Reported in Previous
Studies
Summary of Data for Mercury in Oil
Mercury Concentrations in U.S. Versus Foreign Crude Oils . .
Concentration of Manganese in Coal by Coal Type
Ranges of Manganese Concentration in Coals by Coal Type . . .
Manganese Concentration in Coal by Region
Concentrations of Manganese in Oil Reported in Previous
Studies
Summary of Data for Manganese in Oil
Page
3-99
3-99
3-100
3-102
3-103
3-104
3-104
3-105
3-107
3-108
3-108
3-109
3-109
3-110
3-112
3-113
3-113
3-114
3-114
3-115
3-117
3-118
xii
-------
ldUJ.t=!
3-41
3 A O
-<+Z
0 A 0
7_AA
3-45
3-46
3-47
3-48
3-49
3-50
3-51
3-52
3-53
3-54
3-55
3-56
3-57
3-58
3-59
3-60
3-61
Concentration of Manganese in U.S. Versus Foreign
Pa-ncrac n-F Mi'/^Vol Pnnr1 ont~Tfl t~l on T_n Coals fov CO3.1 TVDG
Concentrations of Nickel in Oil Reported in Previous
Studies . .
Summary of Data for Nickel in Oil
Nickel Concentration in U.S. Versus Foreign Crude Oils ....
Concentration of Thorium in Coal by Coal Type .............
Ranges of Thorium Concentration in Coals by Coal Type
Thorium Concentration in Coal by Region
Concentration of Thorium- 232 in Coal by State or Region . . .
Concentration of Uranium in Coal by Coal Type
Ranges of Uranium Concentration in Coals by Coal Type .....
Uranium Concentration in Coal by Region ...................
Concentration of Uranium- 238 in Coal by State or Region . . .
Population Characteristics of Utility, Industrial and
Commercial Boilers in Terms of Boiler Design and Fuels,
1978
Distribution of Particulate Control Equipment for
Bituminous Coal-Fired Utility Boilers, 1975
Coal Ash Distribution by Boiler Type
Summary of Recommended Trace Pollutant Emission Factors
for Oil Combustion
Calculated Uncontrolled Arsenic Emission Factors for
Residual Oil-Fired Boilers
Measured Arsenic Emission Factors for Residual Oil-Fired
Boilers
3-118
3-119
3-119
3-120
3-122
3-123
3-123
3-124
3-124
3-125
3-126
3-127
3-127
3-128
3-130
3-131
3-132
3-133
3-134
3-135
3-136
xiii
-------
Table Page
3-62 Calculated Uncontrolled Arsenic Emission Factors for
Distillate Oil-Fired Boilers 3-137
3-63 Measured Arsenic Emission Factors for Distillate
Oil-Fired Boilers 3-138
3-64 Calculated Uncontrolled Beryllium Emission Factors for
Residual Oil-Fired Boilers 3-139
3-65 Measured Beryllium Emission Factors for Residual
Oil-Fired Boilers 3-140
3-66 Calculated Uncontrolled Beryllium Emission Factors for
Distillate Oil-Fired Boilers 3-141
3-67 Measured Beryllium Emission Factors for Distillate
Oil-Fired Boilers 3-142
3-68 Calculated Uncontrolled Cadmium Emission Factors for
Residual Oil-Fired Boilers 3-143
3-69 Measured Cadmium Emission Factors for Residual Oil-Fired
Boilers : . . . 3 -144
3-70 Calculated Uncontrolled Cadmium Emission Factors for
Distillate Oil-Fired Boilers 3-145
3-71 Measured Cadmium Emission Factors for Distillate
Oil-Fired Boilers 3-146
3-72 Calculated Uncontrolled Chromium Emissions from Residual
Oil-Fired Boilers 3-147
3-73 Measured Chromium Emission Factors for Residual Oil-Fired
Boilers . 3-148
3-74 Calculated Uncontrolled Chromium Emission Factors for
Distillate Oil-Fired Boilers 3-150
3-75 Measured Chromium Emission Factors for Distillate
Oil-Fired Boilers 3-151
3-76 Calculated Uncontrolled Copper Emissions from Residual
Oil-Fired Boilers 3-152
3-77 Measured Copper Emission Factors for Residual Oil-Fired
Boilers 3-153
xiv
-------
Table
Page
3-78 Calculated Uncontrolled Copper Emission Factors for
Distillate Oil-Fired Boilers 3-155
3-79 Measured Copper Emission Factors for Distillate Oil-Fired
Boilers 3-156
3-80 Calculated Uncontrolled Mercury Emission Factors for
Residual Oil-Fired Boilers 3-157
3-81 Measured Mercury Emission Factors for Residual Oil-Fired
Boilers 3-158
3-82 Calculated Uncontrolled Mercury Emission Factors for
Distillate Oil-Fired Boilers . 3-159
3-83 Measured Mercury Emission Factors for Distillate
Oil-Fired Boilers 3-160
3-84 Calculated Uncontrolled Manganese Emission Factors from
Residual Oil-Fired Boilers 3-161
3-85 Measured Manganese Emission Factors for Residual
Oil-Fired Boilers 3-162
3-86 Calculated Uncontrolled Manganese Emission Factors for
Distillate Oil-Fired Boilers 3-164
3-87 Measured Manganese Emission Factors for Distillate
Oil-Fired Boilers ... 3-165
3-88 Calculated Uncontrolled Nickel Emissions from Residual
Oil-Fired Boilers 3-166
3-89 Measured Nickel Emission Factors for Residual Oil-Fired
Boilers 3-167
3-90 Calculated Uncontrolled Nickel Emission Factors for
Distillate Oil-Fired Boilers 3-169
3-91 Measured Nickel Emission Factors for Distillate
Oil-Fired Boilers 3-170
3-92 Summary of Total POM Emission Factors for Oil
Combustion ................................................ 3-171
3-93 Measured Total POM Emission Factors from Residual Oil
Combustion 3-172
xv
-------
Table Page
3-94 Measured Uncontrolled Total POM Emission Factors from
Distillate Oil Combustion 3-174
3-95 Measured Formaldehyde Emission Factors for Oil-Fired
Boilers and Furnaces 3-175
3-96 Recommended Arsenic Emission Factors for Coal-Fired
Boilers 3-176
3-97 Summary of Measured Arsenic Emission Factors for
Bituminous Coal-Fired Utility Boilers 3-177
3-98 Summary of Measured Arsenic Emission Factors for
Subbituminous Coal-Fired Utility Boilers 3-178
3-99 Summary of Measured Arsenic Emission Factors from
Lignite Coal-Fired Utility Boilers 3-178
3-100 Summary of Measured Arsenic Emission Factors for
Bituminous Coal-Fired Industrial Boilers 3-179
3-101 Summary of Measured Arsenic Emission Factors for
Subbituminous Coal-Fired Industrial Boilers 3-180
3-102 Summary of Measured Arsenic Emission Factors for
Commercial/Institutional Coal-Fired Boilers 3-181
3-103 Calculated Arsenic Emission Factors for Coal Combustion ... 3-182
3-104 Arsenic Removal Efficiency of Controls 3-185
3-105 Recommended Beryllium Emission Factors for Coal-Fired
Boilers 3-186
3-106 Summary of Measured Beryllium Emission Factors for
Bituminous Coal-Fired Utility Boilers 3-187
3-107 Summary of Measured Beryllium Emission Factors for
Subbituminous Coal-Fired Utility Boilers 3-188
3-108 Summary of Measured Beryllium Emission Factors for
Lignite Coal-Fired Utility Boilers 3-189
3-109 Summary of Measured Beryllium Emission Factors for
Bituminous Coal-Fired Industrial Boilers 3-190
3-110 Summary of Measured Beryllium Emission Factors for
Subbituminous Coal-Fired Industrial Boilers 3-191
xvi
-------
Table
Page
3-111 Summary of Measured Beryllium Emission Factors for
Commercial/Institutional Coal-Fired Boilers ...... ......... 3-191
3-112 Calculated Beryllium Emission Factors for Coal
Combustion ........ ..... ......................... .......... 3
3-113 Beryllium Removal Efficiency of Controls .................. 3-195
3-114 Recommended Cadmium Emission Factors for Coal-Fired
Boilers ............................... . .......... . ..... 3-196
3-115 Summary of Measured Cadmium Emission Factors for
Bituminous Coal-Fired Utility Boilers ............... ...... 3-197
3-116 Summary of Measured Cadmium Emission Factors for
Subbituminous Coal-Fired Utility Boilers .................. 3-198
3-117 Summary of Measured Cadmium Emission Factors for Lignite
Coal-Fired Utility Boilers .......... ---- .................. 3-199
3-118 Summary of Measured Cadmium Emission Factors for
Bituminous Coal-Fired Industrial Boilers ..... ............. 3-200
3-119 Summary of Measured Cadmium Emission Factors for
Subbituminous Coal -Fired Industrial Boilers ... .......... . . 3-201
3-120 Summary of Measured Cadmium Emission Factors for
Commercial/Institutional Coal-Fired Boilers . .............. 3-202
3-121 Calculated Cadmium Emission Factors for Coal Combustion . . . 3-203
3-122 Cadmium Removal Efficiency of Controls ... ........ ......... 3-206
3-123 Recommended Chromium Emission Factors for Coal-Fired
Boilers ............. . . ........ . .......... . ....... . ....... 3-207
3-124 Values Used in Calculation of Uncontrolled Chromium
Emission Factors ............................. . ............ 3-208
3-125 Fraction of Coal Ash Emitted as Fly Ash (F) by Boiler
Type [[[ 3-208
3-126 Chromium Removal Efficiency of Controls ......... .......... 3-209
3-127 Summary of Measured Chromium Emission Factors for
Bituminous Coal-Fired Utility Boilers ............... . ..... 3-210
3-128 Summary of Measured Chromium Emission Factors for
-------
Table Page
3-129 Summary of Measured Chromium Emission Factors for
Lignite Coal-Fired Utility Boilers 3-212
3-130 Summary of Measured Chromium Emission Factors for
Bituminous Coal-Fired Industrial Boilers 3-213
3-131 Summary of Chromium Emission Factors for Subbituminous
Coal-Fired Industrial Boilers 3-214
3-132 Summary of Measured Chromium Emission Factors for
Commercial/Institutional Coal-Fired Boilers 3-215
3-133 Previously Calculated Chromium Emission Factors for
Coal Combustion 3 - 216
3-134 Recommended Copper Emission Factors for Coal-Fired
Boilers 3-219
3-135 Summary of Measured Copper Emission Factors for
Bituminous Coal-Fired Utility Boilers 3-220
3-136 Summary of Copper Emission Factors for Subbituminous
Coal-Fired Utility Boilers 3-221
3-137 Summary of Copper Emission Factors for Utility Boilers
Fired with Lignite Coal 3-222
3-138 Summary of Measured Copper Emission Factors for
Bituminous Coal-Fired Industrial Boilers 3-223
3-139 Summary of Measured Copper Emission Factors for
Subbituminous Coal-Fired Utility Boilers 3-224
3-140 Summary of Measured Copper Emission Factors for
Commercial/Institutional Coal-Fired Boilers 3-224
3-141 Calculated Copper Emission Factors for Coal Combustion .... 3-225
3-142 Copper Removal Efficiency of Controls 3-227
3-143 Recommended Mercury Emission Factors for Coal-Fired
Boilers 3-228
3-144 Summary of Measured Mercury Emission Factors for
Bituminous Coal-Fired Utility Boilers 3-229
3-145 Summary of Measured Mercury Emission Factors for
Subbituminous Coal-Fired Utility Boilers 3-230
xviii
-------
Table PaSe
3-146 Summary of Measured Mercury Emission Factors for Lignite
Coal-Fired Utility Boilers ...... 3-231
3-147 Summary of Mercury Emission Factors for Bituminous
Coal-Fired Industrial Boilers - 3-232
3-148 Summary of Measured Mercury Emission Factors for
Subbituminous Coal-Fired Industrial Boilers 3-233
3-149 Summary of Measured Mercury Emission Factors for
Commercial/Institutional Coal-Fired Boilers 3-234
3-150 Calculated Mercury Emission Factors for Coal Combustion ... 3-235
3-151 Recommended Manganese Emission Factors for Coal-Fired
Boilers . 3-236
3-152 Summary of Measured Manganese Emission Factors for
Bituminous Coal-Fired Utility Boilers 3-237
3-153 Summary of Measured Manganese Emission Factors for
Subbituminous Coal-Fired Utility Boilers 3-238
3-154 Summary of Measured Manganese Emission Factors for
Lignite Coal-Fired Utility Boilers 3-239
3-155 Summary of Measured Manganese Emission Factors for
Bituminous Coal-Fired Industrial Boilers 3-240
3=156 Summary of Measured Manganese Emission Factors for
Subbituminous Coal-Fired Industrial Boilers ............... 3-241
3-157 Summary of Measured Manganese Emission Factors for
Commercial/Institutional Coal-Fired Boilers 3-242
3-158 Calculated Manganese Emission Factors for Coal
Combustion 3 - 243
3-159 Manganese Removal Efficiency of Controls 3-245
3-160 Recommended Nickel Emission Factors for Coal-Fired
Boilers 3-246
3-161 Values Used in Calculation of Uncontrolled Nickel
Emission Factors 3- 247
3-162 Nickel Removal Efficiency of Controls 3-248
xix
-------
Table Page
3-163 Summary of Measured Nickel Emission Factors for
Bituminous Coal-Fired Utility Boilers 3-249
3-164 Summary of Measured Nickel Emission Factors for
Subbituminous Coal-Fired Utility Boilers 3-250
3-165 Summary of Measured Nickel Emission Factors for Lignite
Coal-Fired Utility Boilers 3-251
3-166 Summary of Measured Nickel Emission Factors for
Bituminous Coal-Fired Industrial Boilers 3-252
3-167 Summary of Measured Nickel Emission Factors for
Subbituminous Coal-Fired Industrial Boilers 3-253
3-168 Summary of Measured Nickel Emission Factors for
Commercial/Institutional Coal-Fired Boilers ............... 3-254
3-169 Previously Calculated Nickel Emission Factors for
Coal Combustion . 3-255
3-170 Trace Metal Emission Factors for Residential Coal
Combustion by Coal Type 3-257
3-171 Trace Metal Emission Factors for Residential Coal
Combustion by Region of Coal Origin 3-258
3-172 Measured Trace Metal Emission Factors for Bituminous
Coal-Fired Residential Furnaces 3-259
3-173 Summary of Measured Uranium-238 Factors for Coal-Fired
Utility Boilers 3-260
3-174 Summary of Measured Thorium-232 Emission Factors for
Coal-Fired Utility Boilers 3-261
3-175 Summary of Measured Total POM Emission Factors for
Coal-Fired Sources 3-262
3-176 Measured Formaldehyde Emission Factors for Coal-Fired
Boilers and Furnaces 3-263
3-177 Calculated Lead Emission Factors for Coal and Oil
Combustion 3-264
3-178 Summary of Measured Lead Emission Factors for
Bituminous Coal-Fired Utility Boilers 3-268
3-179 Summary of Lead Emission Factors for Utility Boilers 3-269
xx
-------
Table
Page
3-180 Summary of Lead Emission Factors for Bituminous
Coal-Fired Industrial Boilers ............. ...... ........ . . 3-270
3-181 Summary of Lead Emission Factors for Commercial/
Institutional Boilers .............. ............ ---- ....... 3-271
4-1 Parameters Contained in the POWER STATISTICS Data Base .... 4-4
4-2 Risk Estimates from the Radionuclide NESHAP Background
Information Document . . ................ . ..... . ............. 4-25
4-3 Industrial and Commercial Boiler Size Distributions on a
National Basis ..... . ........... . . ..................... .... ^-33
4-4 Summary of Coal and Oil Consumption by the Industrial and
Commercial Sectors ................................... ..... 4-34
4-5 Boiler Size Distributions to be Used for Selecting
Combustion Sector Subsets from NEDS ....................... 4-36
4-6 Sizes of Boiler Subsets to be Selected from NEDS and Used
in the Recommended Point Source Risk Assessment
Approach ............... ......... ..... ..................... 4-38
4-7 Distribution of the Indus trial -Coal Boilers Subset in Fuel
Consumption Groups ................................. . ...... 4-39
4-8 Distribution of the Indus trial -Oil Boilers Subset in Fuel
Consumption Groups ......... ................ ....... ........ 4-39
4-9 Distribution of the Commercial -Coal Boilers Subset in Fuel
Consumption Groups ................. ............. .......... 4-40
4-10 Distribution of the Commercial-Oil Boilers Subset in Fuel
Consumption Groups ... ................. ....._ .............. 4-40
4-11 Source Classification Codes Needed from NEDS for the
Combustion Sector Subsets Selection Process ...... ......... 4-42
4-12 Coal and Oil Consumption in the Industrial Sector
in 1982 ............... . ................................... 4-46
4-13 Coal and Oil Consumption in the Commercial Sector
in 1982 .............. ........ . ____ ........ ..... . ........ .. 4-48
4-14 Parameters of the Prototype Sources Used to Determine
Maximum Individual Risk for Industrial and Commercial
Sources ................... . . .............................. 4-52
xxi
-------
Table Page
4-15 Coal and Oil Consumption in the Residential Sector in 1982 4-56
4-16 State Trace Pollutant Emission Totals to be Used for Risk
Assessment - Oil Combustion 4-58
4-17
A-l
B-l
D-l
D-2
D-3
D-4
D-5
D-6
D-7
D-8
D-9
D-10
E-l
E-2
E-3
E-4
State Trace Pollutant Emission Totals to be Used for Risk
Assessment - Coal Combustion
Individuals Contacted During Identification of Pertinent
Research Task
Data Bases Searched in the Dialog^ System
Classification of Coals .
Typical Heating Values of United States' Coals ............
Mean Coal Heating Values by Geographic Region
Examples of Coal Heat Content Variability
Typical Heating Values of Fuel Oils
Typical Heating Values for Fuel Oils Consumed in the
Eastern Region
Typical Heating Values for Fuel Oils Consumed in the
Southern Region
Typical Heating Values for Fuel Oils Consumed in the
Central Region
Typical Heating Values for Fuel Oils Consumed in the
Rocky Mountain Region
Typical Heating Values for Fuel Oils Consumed in the
Western Region
Measured Arsenic Emission Factors for Utility, Bituminous
Coal, Pulverized Dry Bottom Boilers
Measured Arsenic Emission Factors for Utility Pulverized
Wet Bottom Boilers Fired with Bituminous Coal
Measured Arsenic Emission Factors for Utility Cyclone
Boilers Fired with Bituminous Coal
Measured Arsenic Emission Factors for Utility Stoker
Boilers Fired with Bituminous Coal
4-64
A-l
B-2
D-2
D-3
D-8
D-9
D-ll
D-12
D-13
D-14
D-15
D-16
E-2
E-4
E-5
E-6
xxii
-------
Table
E-5 Measured Arsenic Emission Factors for Utility Boilers
Fired with Subbituminous Coal E-6
E-6 Measured Arsenic Emission Factors for Utility Boilers
Fired with Lignite Coal . E-7
E-7 Measured Arsenic Emission Factors for Bituminous
Coal-Fired Industrial Boilers E-8
E-8 Measured Arsenic Emission Factors for Subbituminous
Coal-Fired Industrial Boilers E-10
E-9 Measured Arsenic Emission Factors for Commercial/
Institutional Coal-Fired Boilers E-ll
E-10 Measured Arsenic Emission Factors for Coal=Fired
Residential Furnaces ...................................... E-12
E-ll Measured Beryllium Emission Factors for Utility
Pulverized Dry Bottom Boilers Fired with Bituminous Coal . . E-13
E-12 Measured Beryllium Emission Factors for Utility
Pulverized Wet Bottom Boilers Fired with Bituminous Coal .. E-15
E-13 Measured Beryllium Emission Factors for Utility Cyclone
Boilers Fired with Bituminous Coal . E-16
E-14 Measured Beryllium Emission Factors for Utility Stoker
Boilers Fired with Bituminous Coal E-16
E-15 Measured Beryllium Emission Factors for Utility Boilers
Firing Subbituminous Coal E-17
E-16 Measured Beryllium Emission Factors for Utility Boilers
Firing Lignite Coal E-17
E-17 Measured Beryllium Emission Factors for Bituminous
Coal-Fired Industrial Boilers E-18
E-18 Measured Beryllium Emission Factors for Subbituminous
Coal-Fired Industrial Boilers E-20
E-19 Measured Beryllium Emission Factors for Commercial/
Institutional Coal-Fired Boilers .......................... E-21
E-20 Measured Cadmium Emission Factors for Pulverized Dry
Bottom Utility Boilers Fired with Bituminous Coal E-22
xxiii
-------
Table Page
E-21 Measured Cadmium. Emission Factors for Utility Pulverized
Wet Bottom Boilers Fired with Bituminous Coal E-24
E-22 Measured Cadmium Emission Factors for Utility Cyclone
Boilers Fired with Bituminous Coal E-25
E-23 Measured Cadmium Emission Factors for Utility Stoker
Boilers Fired with Bituminous Coal E-26
E-24 Measured Cadmium Emission Factors for Utility Boilers
Fired with Subbituminous Coal E-26
E-25 Measured Cadmium Emission Factors for Utility Boilers
Fired with Lignite Coal E-27
E-26 Measured Cadmium Emission Factors for Bituminous
Coal-Fired Industrial Boilers E-28
E-27 Measured Cadmium Emission Factors for Subbituminous
Coal-Fired Industrial Boilers E-30
E-28 Measured Cadmium Emission Factors for Commercial/
Institutional Coal-Fired Boilers E-31
E-29 Measured Cadmium Emission Factors for Coal-Fired
Residential Furnaces E-32
E-30 Measured Chromium Emission Factors for Pulverized Dry
Bottom Utility Boilers Fired with Bituminous Coal E-33
E-31 Measured Chromium Emission Factors for Utility Pulverized
Wet Bottom Boilers Fired with Bituminous Coal E-35
E-32 Measured Chromium Emission Factors for Utility Cyclone
Boilers Fired with Bituminous Coal E-36
E-33 Measured Chromium Emission Factors for Utility Stoker
Boilers Fired with Bituminous Coal E-37
E-34 Measured Chromium Emission Factors for Utility Boilers
Fired with Subbituminous Coal E-38
E-35 Measured Chromium Emission Factors for Utility Boilers
Fired with Lignite Coal E-39
E-36 Measured Chromium Emission Factors for Bituminous
Coal-Fired Industrial Boilers E-40
xxiv
-------
Table PaSe
E-37 Measured Chromium Emission Factors for Subbituminous
Coal-Fired Industrial Boilers E-42
E-38 Measured Chromium Emission Factors for Commercial/
Institutional Coal-Fired Boilers E-43
E-39 Measured Chromium Emission Factors for Coal-Fired
Residential Furnaces E-44
E-40 Measured Copper Emission Factors for Pulverized Dry
Bottom Utility Boilers Fired with Bituminous Coal E-45
E-41 Measured Copper Emission Factors for Utility Pulverized
Wet Bottom Boilers Fired with Bituminous Coal E-47
E-42 Measured Copper Emission Factors for Utility Cyclone
Boilers Fired with Bituminous Coal ........................ E-48
E-43 Measured Copper Emission Factors for Utility Stoker
Boilers Fired with Bituminous Coal E-49
E-44 Measured Copper Emission Factors for Utility Boilers
Fired with Subbituminous Coal E-49
E-45 Measured Copper Emission Factors for Utility Boilers
Fired with Lignite Coal E-50
E-46 Measured Copper Emission Factors for Bituminous
Coal-Fired Industrial Boilers E-51
E-47 Measured Copper Emission Factors for Subbituminous
Coal-Fired Industrial Boilers E-53
E-48 Measured Copper Emission Factors for Coal-Fired
Residential Furnaces E-54
E-49 Measured Copper Emission Factors for Commercial/
Institutional Coal-Fired Boilers E-55
E-50 Measured Mercury Emission Factors for Pulverized Dry
Bottom Utility Boilers Fired with Bituminous Coal E-56
E-51 Measured Mercury Emission Factors for Utility Pulverized
Wet Bottom Boilers Fired with Bituminous Coal E-58
E-52 Measured Mercury Emission Factors for Utility Cyclone
Boilers Fired with Bituminous Coal E-58
XXV
-------
Table Page
E-53 Measured Mercury Emission Factors for Utility Stoker
Boilers Fired with Bituminous Coal E-59
E-54 Measured Mercury Emission Factors for Utility Boilers
Fired with Subbituminous Coal E-59
E-55 Measured Mercury Emission Factors for Utility Boilers
Fired with Lignite Coal E-60
E-56 Measured Mercury Emission Factors for Bituminous
Coal-Fired Industrial Boilers E-61
E-57 Measured Mercury Emission Factors for Subbituminous
Coal-Fired Industrial Boilers E-63
E-58 Measured Mercury Emission Factors for Commercial/
Institutional Coal-Fired Boilers E-64
E-59 Measured Mercury Emission Factors for Coal-Fired
Residential Furnaces E-65
E-60 Measured Manganese Emission Factors for Pulverized Dry
Bottom Utility Boilers Fired with Bituminous Coal E-66
E-61 Measured Manganese Emission Factors for Utility Pulverized
Wet Bottom Boilers Fired with Bituminous Coal E-68
E-62 Measured Manganese Emission Factors for Utility Cyclone
Boilers Fired with Bituminous Coal E-69
E-63 Measured Manganese Emission Factors for Utility Stoker
Boilers Fired with Bituminous Coal E-70
E-64 Measured Manganese Emission Factors for Utility Boilers
Fired with Subbituminous Coal E-70
E-65 Measured Manganese Emission Factors for Utility Boilers
Fired with Lignite Coal E-71
E-66 Measured Manganese Emission Factors for Bituminous
Coal-Fired Industrial Boilers E-72
E-67 Measured Manganese Emission Factors for Subbituminous
Coal-Fired Industrial Boilers E-74
E-68 Measured Manganese Emission Factors for Commercial/
Institutional Coal-Fired Boilers E-75
xxvi
-------
Table
E-69 Measured Manganese Emission Factors for Coal-Fired
Residential Furnaces
E-76
E-70 Measured Nickel Emission Factors for Pulverized Dry
Bottom Utility Boilers Fired with Bituminous Coal E-77
E-71 Measured Nickel Emission Factors for Utility Pulverized
Wet Bottom Boilers Fired with Bituminous Coal E-79
E-72 Measured Nickel Emission Factors for Utility Cyclone
Boilers Fired with Bituminous Coal E-79
E-73 Measured Nickel Emission Factors for Utility Stoker
Boilers Fired with Bituminous Coal E-80
E-74 Measured Nickel Emission Factors for Utility Boilers
Fired with Subbituminous Coal E-80
E-75 Measured Nickel Emission Factors for Utility Boilers
Fired with Lignite Coal E-81
E-76 Measured Nickel Emission Factors for Bituminous
Coal-Fired Industrial Boilers E-82
E-77 Measured Nickel Emission Factors for Subbituminous
Coal-Fired Industrial Boilers E-84
E-78 Measured Nickel Emission Factors for Commercial/
Institutional Coal-Fired Boilers E-85
E-79 Measured Nickel Emission Factors for Coal-Fired
Residential Furnaces E-86
E-80 Measured Uranium-238 Emission Factors for Coal-Fired
Utility Boilers E-87
E-81 Measured Thorium-232 Emission Factors for Coal-Fired
Utility Boilers E-89
E-82 Total POM Emissions from Pulverized Coal-Fired Utility
Boilers E-90
E-83 Total POM Emissions from Cyclone Coal-Fired Utility
Boilers E-92
E-84 Total POM Emissions from Stoker Coal-Fired Utility
Boilers E-94
xxvii
-------
Table Page
E-85 Measured Total POM Emission Factors for Pulverized
Coal-Fired Industrial Boilers E-95
E-86 Measured Total POM Emission Factors for Stoker Coal-Fired
Industrial Boilers E-96
E-87 Measured Uncontrolled Total POM Emission Factors for
Residential and Small Commercial Boilers E-97
xxviii
-------
1.0 PROJECT INTRODUCTION
1.1 BACKGROUND
Trace pollutant emissions to air from coal and oil combustion sources
at all levels is a topic that has undergone considerable study in recent
years as evidenced by the size of the bibliography in this report. Trace
metals, organic compounds, and radionuclides have been assessed from utility
sources down to residential units. One of the main benefits of this work
has been to clearly point out the difficulty in generalizing trace pollutant
emissions from any type of coal or oil combustion source. Trace pollutant
emissions to air from coal and oil combustion sources are highly variable
because:
the pollutants are contained in fuels at levels that vary over
several orders of magnitude;
certain pollutants are enriched, in the combustion environments,
in fine particles which makes predicting control capabilities
difficult;
fuel combustion devices are configured differently and produce
differing levels of trace pollutant emissions; and
trace levels of pollutant compounds may enter into combustion
source emission streams from nonfuel related sources such as
combustion air, boiler material degradation (e.g., chromium
refractory), and control device media (e.g., scrubbing fluids,
limestone).
In recent years, as more national attention has been focused on
so-called toxic air pollutants, trace pollutant emissions from coal and oil
combustion sources have received increased scrutiny. One reason for this is
that although a single combustion source (even a power plant) may be a
relatively small trace pollutant emitter, the sum total of all combustion
1-1
-------
sources may make combustion sources the largest single source category for a
particular pollutant. This situation is certainly the case for many trace
metals. For this reason, and the reason that a large number of people are
exposed to combustion source emissions from sources at all levels (utility,
industrial, commercial, and residential), much research recently has been
geared towards projecting the exposures and risks to the national population
attributable to coal and oil combustion source trace pollutant emissions.
Estimating exposure and risk has been made difficult by the emissions
variability problems mentioned previously, by the large number and
dispersive nature of the sources, by problems in assimilating predicted
pollutant concentrations with the properly affected population, and by
problems in determining the human health effects associated with inhalation
of some combustion source trace emissions. The sources and means of
exposure to an individual from combustion source atmospheric trace pollutant
emissions are illustrated in Figure 1.
In September 1984, a limited study was conducted for EPA by Radian
Corporation to assess exposure and risk to the public from coal and oil
combustion source emissions of arsenic, beryllium, cadmium, chromium, and
nickel. The selection of an assessment methodology in this project was
primarily dictated by the 6-week timeframe imposed on the project to provide
quantitative results. Because of the 6-week schedule and the large number
of combustion sources to be assessed in the utility, industrial, commercial,
and residential sectors, optimal risk assessment methodologies involving
analyses of individual facilities were infeasible.
The approach selected in the September 1984 work to assess risk from
coal and oil combustion trace metal emissions involved treating all emission
sources as area sources. Emissions for each combustion sector were
calculated on an individual State basis using trace metal emission factors
*
Radian Corporation (1984) Methodology for estimating exposure to arsenic,
beryllium, cadmium, chromium, and nickel from coal and oil combustion.
Research Triangle Park, North Carolina: U. S. Environmental Protection
Agency, Pollutant Assessment Branch; EPA Contract No. 68-02-3515, Work
Assignment No. 31.
1-2
-------
* HOT APPLICABLE TO OIL lOUHCEt
Figure 1-1. Sources and means of exposure to an individual from combustion source
atmospheric trace pollutant emissions.
-------
from the literature and State coal and oil consumption statistics obtained
from the Department of Energy. Emissions from each combustion sector within
a State were calculated and distributed equally over the land area and
population of the State to determine an exposure and risk estimate.
Exposure estimates were made using the area source algorithm in the EPA's
SHEAR (Systems Applications Human Exposure and Risk) model. Risk was
determined by applying the Cancer Assessment Group's (CAG) unit risk factors
to the population exposure results.
The SHEAR area source algorithm was used in this assessment because
specific plant or model plant data could not be collected for all the
sources in the analysis. Because the number of residential and commercial
sources is so large and the sources so widely distributed, it was assumed
that these categories function as continuous emissions sources over the
entire area of the analysis (in this case a State). For consistency, it
made sense to treat the utility and industrial sources in the same manner
even though they do not conform well to the definition of area source in the
model. Because their number is less, the emissions of utility and
industrial sources do not equally impact an entire State (in terms of
distribution and population contact) as much as commercial and residential
sources.
Ambient trace metal concentrations resulting from coal and oil
combustion were estimated using the Hanna-Gifford dispersion equation
contained in the SHEAR area source algorithm. This equation is given below.
X - CQ/U
Where: X - ambient concentration,
C - Hanna-Gifford coefficient,
Q - effective emission rate per unit area, and
U - wind speed.
For the purpose of calculating exposure, C was assumed to be equal to
225, based on the EPA guidance and experience of using the model. The
quantity C is a weak function of atmospheric stability and land area and may
1-4
-------
be taken to be approximately constant. The national average wind speed (U)
was assumed to be 4.0 m/sec. The quantity Q was calculated as emissions
9 fi
(lb/yr) divided by land area (mi ) times a factor of 5.552 x 10" to convert
2 2
Ib/yr/mi to ug/sec/m .
The level of State population exposure to each trace metal was obtained
by multiplying the estimated ambient concentrations (calculated by the
Hanna-Gifford equation) times the total State population. This result is in
3
units of people - ug/m . The nationwide aggregate risk to each trace metal
from each combustion sector was determined by multiplying the exposure value
(people - ug/m ) times the unit risk factor for the pollutant being
assessed. The result of this calculation equals the aggregate risk after
70 years of continuous exposure. Annual incidence was calculated by
dividing the aggregate risk by 70.
The approach of using th area source algorithm from the SHEAR model,
together with input data on a LOTUS program, probably underestimated
exposure and risk because it assumed there was an average emission rate and
ambient concentration equally distributed over an entire State. In reality,
the bulk of the emissions from residential heaters, and to a lesser extent
from other combustion sources, would be located in the more highly populated
areas of the State. Thus, higher ambient concentrations, exposure, and risk
would result in these metropolitan areas. The exception to this case might
be utility sources which are often located in remote areas where relatively
few people are affected by their emissions. In this situation, the exposure
predicted by equally distributing emissions Statewide would be overstated.
The use of national average emission factors for trace elements from
the combustion of coal and oil introduces some degree of limitation to the
analysis. The emission factors used were based on published stack test data
and calculations, but emission factors can vary by orders of magnitude from
one plant to another depending on type or coal or oil used, boiler design,
and control equipment. The use of national average factors probably caused
underestimation for some States and overestimation for others, such that the
national exposure and risk estimations will be more accurate than individual
State risks. Over the 70-year exposure time, the fuel type used by
combustion sources and other factors affecting emissions may change in any
given geographic area, thereby altering exposure and risk levels.
1-5
-------
A final drawback to using the SHEAR area source algorithm approach for
estimating risk for all States involves the algorithm's Hanna-Gifford
dispersion equation and its coefficient factor C. The value of 225, which
has been assigned to the coefficient, was primarily designed to be accurate
and applicable to metropolitan areas and not to areas as large as entire
States. The degree of error introduced into the exposure and risk analysis
by applying the value to States in unknown.
As a refinement to the State approach, EPA conducted a risk assessment
for combustion sources at the county level using the emissions estimates
generated by the State-based assessment. The county-based approach was an
attempt to place emissions and people together in areas where they actually
occur rather than distributing them equally across a State. In the
county-by-county approach, emissions were distributed by county within a
State based on the fuel consumption characteristics of each combustion
sector in each county. The allocation of emissions within a county was
based on indexing parameters contained in the 1980 Census of Housing data
base. In the residential combustion sector, emissions were distributed on
the basis of the number of housing units in each county that used coal or
oil as a fuel. In the commercial sector, there were six categories of
employment sources such as hospitals, universities, etc., that people were
listed as being employed by. Emissions were allocated on the basis of the
number of people living in each county and working in the sum of the six
commercial categories. For example, if a State had 100 people employed in
the commercial sector and 25 lived in county X, then 25 percent of the total
State emissions from commercial combustion would be allocated to county X.
This same type of index was used in the industrial sector, except there were
only two categories of employment sources, durable and nondurable goods.
For the utility combustion sector emissions were simply allocated on the
basis of population (i.e., if 10 percent of the population of a State live
in county Y, then 10 percent of utility combustion emissions for that State
were allocated to county Y).
Once emissions were allocated by county, ambient concentrations,
exposure, aggregate risk, and annual incidence were calculated as was
described for the State-based approach except that county land areas and
populations were used instead of State figures.
1-6
-------
Because of the limitations and problems inherent in assessing risk from
combustion sources using the basic methodology applied in the previous
State- and county-based approaches, EPA decided that more detailed research
was needed to determine better, more defensible means of combustion source
risk assessment. The work performed and the results of this additional,
detailed investigation are presented in this document. A basic description
of the investigation's structure and objectives is provided in Section 1.2.
1.2 PROJECT DESCRIPTION
The current, expanded examination of risk assessment for trace air
pollutant emissions from coal and oil combustion sources has the following
primary objectives.
(1) to identify and utilize related research being conducted by other
groups, within and outside EPA, that pertains to atmospheric trace
pollutant emissions from combustion sources and/or risk
assessments for combustion sources or categories with numerous and
dispersive sources;
(2) to expand the trace pollutant emission factor data base used in
the previous State/county-based study and characterize specific
emission factors that can be used in a subsequent risk assessment;
and
(3) to analyze alternative approaches to estimating risks originating
from coal and oil combustion trace pollutant emissions to air, and
to recommend the most feasible assessment methodology considering
available data.
The trace pollutants emitted to air from coal and oil combustion that
are assessed in this study include the following.
arsenic
beryllium
cadmium
1-7
-------
chromium
copper
lead
manganese
mercury
nickel
formaldehyde
polycyclic organic matter (POM)
radionuclides
Polycyclic organic matter emissions are generally assessed in total as a
group. Assessments of individual POM compounds are not specifically made;
however, results for major constituent POMs are reported as percentages of
total POM where data are available. Similarly, not all radionuclides are
included in the combustion source emissions assessment. Only uraniura-238
(U-238) and thorium-232 (Th-232) are assessed, whereas the total list of
radionuclides consists of almost 40 elements. Uranium-238 and thorium-232
are focused on because they have the longest half-lives of all radionuclides
and generally are used as indicators (particularly U-238) of the severity of
radionuclide emissions. Unless otherwise specified in the text, the term
radionuclides applies only to U-238 and Th-232.
The consideration of lead as a trace pollutant from coal and oil
combustion was added to this project by EPA after the submittal of the draft
final report. For this reason, the treatment of lead, including the
availability of emission factor data, is very abbreviated compared to the
other trace pollutants in the document. Only a limited number of the
references listed in the report bibliography in Appendix C were evaluated
for lead data. It is acknowledged that this approach does not provide for a
thorough analysis of lead; however, the approach is sufficient to achieve
the objectives of this study.
The trace pollutant characterization and risk assessment recommendation
efforts are being applied to coal and oil combustion sources in the utility,
industrial, commercial/institutional, and residential combustion sectors for
all nine trace metals, formaldehyde, and POM. The only source category of
radionuclide emissions is being assessed is coal-fired utility boilers.
1-8
-------
The slate of available emission factors that have been developed are
termed "recommended factors" in this report. The term recommended factors
is intended to mean that the presented averages or ranges of emission
factors appear to be those that reasonably could be used in subsequent risk
assessment analyses, considering the overall availability of data. The
recommended factor term does not imply that a particular factor is endorsed
by the U. S. Environmental Protection Agency or the authors of this report
to be a fully characterized or representative emission rate for the given
combustion source situation. Extensive data quality assurance procedures,
necessary to reasonably characterize a data set as representative of a
particular source, were not performed in this study because of time and
budgetary constraints. Instead, the recommended factors are simply
straightforward calculations of emission factor averages and ranges based on
data presented in the literature. The recommended factors are not to be
considered as suggested emission factor values for use in other activities
such as regulatory development or specification of acceptable ambient
concentrations.
The results of the first objective of this project, the identification
of pertinent activities, are discussed in Chapter 2 of the report. The work
in Chapter 2 is important because, through these activities, EPA may be able
to use existing information to aid in characterizing emissions and
conducting risk assessments or they may be able to "piggy-back" onto other
projects that may produce useful risk assessment information such as
emissions estimates, plant location data, risk estimates, or exposure and
risk assessment methodologies.
The results of the project task to characterize levels of trace
pollutants in coal and oil and trace pollutant emissions to air from all
combustion sectors are summarized in Chapter 3. Chapter 4 contains
descriptions of all risk assessment methodologies considered, presents
recommended risk assessment approaches for each combustion sector, and
provides alternatives to each of the recommendations.
1-9
-------
2.0 IDENTIFICATION OF PERTINENT RESEARCH
Several government and private organizations are currently conducting
research related to trace emissions risk assessment from fuel combustion.
Since much information may not be published or may not be widely available at
present, it was felt that telephone contacts would be an efficient way to
identify potentially useful information. Several offices within and outside
of EPA were contacted in order to gather data and to identify pertinent
ongoing research activities. The objectives of the telephone calls were (1)
to identify sources of data and obtain these data where feasible, and (2) to
identify projects which may provide useful information in the future. The
following types of information were solicited:
emission rates or factors for 12 trace pollutants from coal and oil
combustion;
trace metal contents of coal and oil;
number and location of boilers, and other characteristics of the
boiler population such as size ranges, stack parameters, and control
status;
coal and oil consumption data;
exposure and risk methodologies which may be applicable to
combustion sources; and
risk estimates.
Approximately 50 individuals in 25 organizations were contacted.
Table 2-1 lists the offices and organizations contacted along with brief
descriptions of the types of projects or information available from each
office. Appendix A contains a list of the individuals contacted within each
organization and their telephone numbers. The telephone call records
contained in the project files provide detailed information on each phone
call.
2-1
-------
Table 2-1. SUMMARY OF ORGANIZATIONS CONTACTED AND PROJECTS
OR TYPES OF INFORMATION AVAILABLE
Organization
Projects or Types of Information0
Radian Corporation
Pollutant Assessment Branch (PAB).
OAQPS, EPA
National Air Data Branch, OAQPS, EPA
Emission Standards and Engineering
Division (ESED). OAQPS
Air and Energy Engineering Research
Laboratory (AEERL), EPA
Office of Policy, Planning, and
Evaluation (OPPE), EPA
Systems Applications, Inc. (SAI)
Department of Energy (DOE)
Tennessee Valley Authority (TVA)
Office of Radiation Programs (ORP),
EPA
Utility Air Regulatory Group (UARG)
Kilkelly Environmental Associates
Utility Data Institute (UDI)
- Small Boilers NSPS
- Industrial Boilers NSPS
- OPPE Ohio Boiler study
- Various trace emissions reports
- Previous risk assessments for
trace elements from combustion
- NEDS data base
- Chromium NESHAP boiler testing
data
- CCEA and CMEA Report Series
EADS data base
- NAPAP
- HAP research
- Ohio Boilers study
Ohio Boilers study risk assessment
models and procedures
Boiler population and fuel
consumption data
Radionuclide emissions studies
Studies on trace emissions from
utilities
Radionuclides NESHAP and related
studies on radionuclides
emissions from coal combustion
Studies on emissions and risk
from coal utilities
Study on trace emissions for UARG
POWER data base on utilities
2-2
-------
Table 2-1. SUMMARY OF ORGANIZATIONS CONTACTED AND PROJECTS
OR TYPES OF INFORMATION AVAILABLE (Continued)
Organization
Projects or Types of Information0
Edison Electric Institute (EEI)
American Petroleum Institute (API)
American Boiler Manufacturers
Association (ABMA)
American Society of Mechanical
Engineers (ASME)
Council of Industrial Boiler Owners
(CIBO)
Electric Power Research Institute
(EPRI)
Six agencies performing studies
sponsored by EPRI
- POWER data base on utilities
- Oil use information
- Boiler population information
- 1 trace emissions report
- Trace emissions studies
- Boiler population information
- Risk assessment for trace
emissions from coal utilities
using AERAM model
- 10 year study of trace emissions
- Sponsored several applicable
reports listed in EPRI data base
- Trace emissions studies
abbreviations:
- New Source Performance Standard
- National Emissions Data System
- National Emission Standards for Hazardous Air Pollutants
- Conventional Combustion Emissions Assessment
- Combustion Modification Emissions Assessment
- Emissions Assessment Data System
- National Acid Precipitation Assessment Program
- Hazardous Air Pollutants
Atmospheric Exposure and Risk Assessment Model
to
NSPS
NEDS
NESHAP
CCEA
CMEA
EADS
NAPAP
HAP
AERAM
2-3
-------
2.1 RESULTS OF INFORMATION GATHERING
As a result of the telephone survey, various organizations sent Radian
published or draft reports containing trace emissions data. These were
analyzed and used in the development of trace pollutant emission factors
described in Chapter 3. Programs which may provide emissions data in the
future, such as a 10-year testing program planned by EPRI and planned testing
of hexavalent chromium emissions by ESED, were also identified.
Sources of information on boiler numbers, locations, sizes, and stack
parameters were also identified. In particular, the POWER data base
maintained by the Utility Data Institute (UDI) for the Edison Electric
Institute (EEI) is a comprehensive data base on virtually all coal and
oil-fired utility boilers. The contents and potential usefulness of this data
base in conducting a risk assessment is described in Section 2.1.12 and in
Chapter 4.
Two ongoing risk assessment projects were identified through the phone
survey. One is an OPPE study of risks from trace emissions from coal fired
boilers in Ohio. The other is an EPRI project resulting in the development of
the AERAM model for risk assessment from coal-fired utility boilers. The ORP
has also conducted risk assessments for radionuclide emissions from coal-fired
utilities to determine the need for a radionuclides NESHAP. These projects
are briefly discussed in Sections 2.1.6, 2.1.9, and 2.1.17. These risk
assessments were considered in the analysis of alternative risk assessment
methodologies (see Chapter 4).
The following sections present summaries of the information gathered
from each office or organization listed in Table 2-1. The telephone call
records contained in the project files provide more detailed information.
2.1.1 Radian Corporation
Several individuals who have worked on relevant projects were contacted.
Several reports on trace element emissions, including a report on trace
element emission factors and model industrial and utility boilers used for the
OPPE Ohio boiler study, were obtained and reviewed. The small boiler and
2-4
-------
industrial boiler NSPS project teams have developed information on model plant
(boiler) characteristics, but have focused on criteria pollutant rather than
trace pollutant emissions.
2.1.2 Pollutant Assessment Branch (FAB)
The Pollutant Assessment Branch provided information and computer
printouts from their previous risk assessments for trace metals from coal and
oil combustion. These included a risk assessment for coal and oil-fired
utility boilers which was completed in November 1984. Data on boiler
locations and stack characteristics were extracted from the National Emissions
Data System (NEDS), emission factors were applied to estimate trace metal
emissions, and the plants were modeled as point sources using the Human
Exposure Model (HEM).
Personnel at PAB also refined the State-by-State area source modeling
approach used for all four combustion sectors in Radian1s previous study
(described in Section 1.1). Emissions within each State were allocated to
counties based on indexing parameters from the census data base. Utility
combustion emissions within each State were allocated to counties based on
county population. Industrial boiler emissions were allocated based on the
proportion of population in durable and nondurable goods occupation
categories. Commercial/institutional boiler emissions were allocated by the
proportion of population in six occupation categories including hospitals and
universities; and residential heating emissions by the proportion of homes
using coal or oil. The same area source dispersion equation used in the
State-by-State study was applied on a county-by-county basis, and then modeled
county ambient concentrations were matched with county populations to estimate
risk.
In a third study, PAB estimated maximum individual risk in two counties,
one with high coal consumption and one with high oil consumption. The SHEAR
model was used. Utilities were modeled as point sources and industrial,
commercial, and residential boilers and furnaces were modeled as prototype
sources. These three approaches were considered during the formulation of
alternative risk assessment methodologies (see Chapter 4).
2-5
-------
2.1.3 National Air Data Branch (NADB)
The NEDS data base contains records on about 1,400 coal- and oil-fired
utility boilers, 33,800 industrial boilers and 12,800 commercial boilers. Of
the industrial boilers, about 2,500 are coal-fired and 17,500 are oil-fired,
the remainder being fired with natural gas. As of 1983, there were about
1,050 coal-fired commercial boilers and 10,000 oil-fired commercial boilers in
NEDS. Each record ideally includes boiler location, boiler size in terms of
fuel input, stack parameters, and particulate emission rates, although some
records are incomplete. One approach to risk assessment is to use these data
along with trace emission factors as inputs to a point source exposure and
risk model such as HEM. It is possible to get a subset of data from NEDS by
specifying geographic region, boiler type (by SCC code), and/or size cutoffs.
In addition to point source information, NEDS also contains area source fuel
consumption data by combustion sector for each State.
2.1.4 Emission Standards and Engineering Division (ESED)
A major project at ESED is currently developing emission factors for
hexavalent and total chromium in support of the chromium NESHAP development
project. Two coalrfired industrial boilers have been tested, and preliminary
results indicate that 1 to 2 percent of the chromium is emitted in hexavalent
form. Plans exist to also test oil-fired boilers for chromium emissions.
2.1.5 Air and Energy Engineering Research Laboratory (AEERL)
Several programs which are related to the current study are being
performed by AEERL. The Emissions Assessment Data System (EADS) data base
contains test series results for 197 combustion sources. Many of these
include data on trace element content of fuels and concentrations of trace
pollutants in controlled and uncontrolled emission streams. Computer
printouts of about 100 test series reports containing trace element data from
combustion sources were sent to Radian. Each test series report describes the
2-6
-------
source characteristics, the sampling methodology; test conditions, and
pollutant concentrations in the fuels and emissions streams tested. Most of
the test series reports from EADS were duplicates of data available from
published EPA reports. Some of the test series reports, such as tests of
internal combustion engines, were not applicable to this project, and others
did not contain enough information to derive emission factors.
The CMEA and CCEA programs produced series of reports containing measured
emission factors for coal- and oil-fired boilers.
A NEDS-derived data base is being maintained at AEERL as part of the
NAPAP. This data base currently contains criteria pollutant emissions;
however, formaldehyde emissions will be added within a year. Trace metal
emissions may be added at some point in the future, but funding and schedule
for this are uncertain. The formaldehyde emissions information will be
derived using published emission factors rather than by conducting any
additional source testing.
The HAP program at AEERL is currently researching non-combustion sources
and does not seem to relate directly to this project.
2.1.6 Office of Policy. Planning, and Evaluation COPPE")
Individuals in OPPE and Systems Applications, Inc. (SAI) were contacted
for information on OPPE's risk assessment for coal-fired boilers in Ohio.
The study included 403 utility, industrial, and institutional coal-fired
boilers larger than 50 million Btu. Smaller boilers were not included.
Emission factors for trace elements and model plant information were derived
from a Radian report. Emissions information from this report were assessed as
part of the emission summary phase of the current project.
The report on the risk assessment portion of the study has been
finalized. The OPPE risk assessment used SAI's version of SHEAR to model
emissions within 50 km of each boiler. This model is similar to the version
of SHEAR used by PAB, but is more efficient for modeling larger areas. RIVAD
was used to model long-range transport. Officials at OPPE were concerned
that their risk assessment results for Ohio were an order of magnitude lower
than the county-by-county study conducted by PAB in October 1984. Also noted
2-7
-------
by OPPE was the fact that long-range (over 50 km from emission sources) risk
modeled with RIVAD appears to be twice as great as short-range risk modeled
with SHEAR. The risk assessment approaches used by OPPE were considered
during the evaluation of alternative risk assessment methodologies.
2.1.7 Department of Energy (DOE)
Four different groups within DOE were contacted. The Energy Information
Agency (EIA) of DOE has conducted an annual survey of the industrial boiler
sales by census region. However, the survey is not comprehensive and much of
the information submitted by industry is confidential. Emissions information
is not included in the survey.
The DOE Office of Health and Environmental Research provided a report on
flyash composition and toxicity. The Environmental Measurements Lab sent four
papers on radionuclides from coal combustion.
The Morgantown Energy Technology Center of DOE was also contacted;
however, they deal with advanced systems rather than conventional combustion.
2.1.8 Tennessee Vallev Authority (TVA)
Four individuals in TVA were contacted. Several reports were identified
and obtained including a trace element mass balance study of coal-fired power
plants and a draft report on radionuclides in flyash which has not yet been
published.
2.1.9 Office of Radiation Programs (ORP)
This office sent a recent report on radionuclide emissions from
coal-fired utility boilers as well as the Background Information Document
(BID) for the radionuclides NESHAP. During development of this NESHAP, ORP
conducted a risk assessment for radionuclides using the AIRDOS model. This
model is specific to radioactive pollutants and includes complex exposure
pathways such as deposition and persistence in soil, vegetation, and water and
exposure through these pathways in addition to inhalation.
2-8
-------
The Office of Radiation Programs is also sponsoring development of the
CRRIS model, which is being developed at Oak Ridge, Tennessee, and should be
operable within a year. This is a multiple pathway exposure and risk model
for radionuclides which is similar to AERDOS, but has expanded capabilities.
2.1.10 Utility Air Regulatory Group (UARG)
Representatives of UARG and of Hunton & Williams (a law firm representing
UARG) said that the 1983 radionuclide study and other comments on the proposed
radionuclide NESHAP they had sent to the EPA Project Officer include all of
their information on coal-fired boilers. They also sent the Project Officer a
bibliography from a recent literature search done by Kilkelly. They had no
additional information to offer.
2.1.11 Kilkellv Environmental Associates
Kilkelly is under contract to UARG to develop emission rates and factors
for trace metals from utility boilers. They are reviewing about 16 to 20
references to generate these factors and are attempting to correlate emissions
with fuel type, boiler design, control device, etc. A copy of their
bibliography was reviewed by Radian and references were obtained.
2.1.12 Edison Electric Institute (EEI) and Utility Data Institute (UDI)
The Utility Data Institute is a private data base management group under
contract to EEI to manage their "POWER" data base. The data base contains
power plants utilizing coal, oil, and other fuels organized alphabetically by
State. Information included for each plant includes about 300 parameters
including name, location, latitude and longitude, capacity, fuel type, fuel
use, criteria pollutant emissions, control status, and stack parameters. At
present, no data on trace element emissions are included, although some trace
element information may be added in about 5 years.
Most of the data are obtained from DOE/EIA Form 767. The utilities send
UDI a copy of these forms when they return them to DOE. Other data comes from
direct contacts and surveys of utilities.
2-9
-------
Some information from this data base (plant names, latitude and
longitude) is included in a 1983 UARG report. Summary information is
available in an EEI publication which focuses on the air-related information
in the data base. This report contains power plant names, city and state,
plant capacity, fuel type, flyash and bottom ash information, and type of
control device. It does not contain latitude and longitude or stack parameter
information.
The POWER data system can be accessed through subscription ($1,500 per
year) or by having UDI do a search (access fee of at least $800 plus manhour
and computer time costs). Selected data could be output as hard copy or could
be put on machine-readable tapes. One can extract as many or as few
parameters as needed from the data base.
This data base is a potential source of information for use in a risk
assessment of utility boilers.
2.1.13 American Petroleum Institute (API)
API provided some information on the types of oils used in different
combustion sectors and sent one API report. The contact did not believe API
had done any other studies applicable to this project.
2.1.14 American Boiler Manufacturer's Association (ABMA)
The ABMA contributed to a 1981 DOE report on trace metal emissions which
was obtained and reviewed. They have not done any other work on trace
emissions. They have provided some information on the boiler population and
on model plants to Radian's small boilers and industrial boilers NSPS projects
for EPA/ESED.
2.1.15 Council of Industrial Boiler Owners (CIBO)
The CIBO has supplied Radian's small boiler and industrial boiler NSPS
projects with information on the industrial boiler population and model
boilers. Personnel at CIBO are not involved in any work on trace element
emissions.
2-10
-------
2.1.16 American Society of Mechanical Engineers (ASMS)
The only aid ASME could offer would be a literature search, which would
entail considerable costs. It was felt that this would duplicate Radian's
computer literature search and would be unlikely to provide much additional
information.
2.1.17 Electric Power Research Institute (EPRI)
Mr. Paulo Ricci of EPRI sent a report describing a model EPRI has had
developed for trace emissions risk assessment from power plants (the AERAM
model). He also sent a paper describing the use of this model to estimate
risks from arsenic and benzo-a-pyrene [B(a)P] emissions from a power plant.
Due to the amount of detailed user-input data required, the model appears most
appropriate for analysis of individual plants rather than for a national
study. Inputs required include fuel characteristics and boiler and control
device characteristics, meteorology data, population characterization data,
and dose-response data from toxicology studies. The AERAM computes trace
emissions, atmospheric dispersion, exposure, and risk. Trace emissions are
computed by either a mass balance or enrichment factor approach. Atmospheric
dispersion is modeled using the Industrial Source Complex-Long Term (ISCLT)
program. Particle size is considered in the calculation of emissions and
dispersion. User-input population by district is matched to modeled ambient
concentration to determine exposure. Risk is calculated from user-input
animal or human dose-response data by applying any of three low dose-response
extrapolation models: the one-hit, multistage, or log-probit models.
Currently, EPRI is planning a 10 to 15 year study to test trace emissions
from coal-fired power plants. Stack tests and ambient measurements at six
power plants will be initiated in about a year. After the field tests are
finished, it will take about a year before the results are analyzed and
published. Interim reports will be prepared as the project progresses. The
EPRI project officer also noted that they hope to gain information from an
EPA project to test stack emissions and downwind concentrations at a power
plant. The data from this EPA study have not yet been analyzed or
summarized, and will probably not be documented until the end of 1985.
2-11
-------
2.L.18 Other Organizations Performing EPRI-Sponsored Research
Radian contacted six agencies who have performed or are performing
EPRI-sponsored research. These projects were identified through a computer
search of the EPRI data base. The following agencies were contacted:
Southern California Edison Company, Canadian Electrical Association, PSE&G
Research Corporation, Detroit Edison Company, Empire State Electric Energy
Research Corporation, and Public Service Company of Colorado.
Southern California Edison was involved in the development of the AERAM
model described above. They are currently studying trace metal emissions and
risk assessment methodologies for combustion sources. Completed reports on
trace element emissions were sent to Radian.
Two summary reports on trace emissions from coal-fired generating
stations were provided by the Canadian Electrical Associations.
PSE&G had done a study for EPRI ten years ago, but felt it was no longer
current. PSE&G may test trace emissions at some point in the future, but has
not conducted any tests recently.
Empire State Electric Energy Research Corporation sent a report on
emissions from oil-fired boilers. Empire State and EPRI are cofunding another
project on emissions from oil-fired boilers which use lower grade crude oil.
This study will include trace metal emissions data. No time frame was
specified.
The Public Service Co. of Colorado provided a report on radionuclide
emissions from coal fired power plants.
The Detroit Edison contact proved not to be useful because the study had
been dropped.
2-12
-------
3.0 CHARACTERIZATION OF TRACE POLLUTANTS IN COMBUSTION PROCESSES
This chapter characterizes trace pollutant emissions from combustion
processes. Data on the trace pollutant content of coal and oil, literature
on trace pollutant behavior during combustion, and emissions data were
reviewed. The data are summarized in this chapter, and trace pollutant
emission factors available for use in subsequent risk assessment analyses are
derived.
This slate of available emission factors has been termed "recommended
factors" in this report. The term recommended factors is intended to mean
that the presented averages or ranges of emission factors appear to be those
that reasonably could be used in subsequent risk assessment analyses,
considering the overall availability of data. The recommended factor term
does not imply that a particular factor is endorsed by the U. S.
Environmental Protection Agency or the authors of this report to be a fully
characterized or representative emission rate for the given combustion source
situation. Extensive data quality assurance procedures, necessary to
reasonably characterize a data set as representative of a particular source,
were not performed in this study because of time and budgetary constraints.
Instead, the recommended factors are simply straightforward calculations of
emission factor averages and ranges based on data presented in the
literature. The recommended factors are not to be considered as suggested
emission factor values for use in other activities such as regulatory
development or specification of acceptable ambient concentrations.
The chapter is divided into seven major sections. Section 3.1 describes
the data base. Since emissions of trace metals and radionuclides are
dependent on the levels of these materials in fuel, Sections 3.2 and 3.3
characterize typical fuels. Data on the types and quantities of coal and oil
used in each of the four combustion sectors (utility, industrial, commercial/
institutional, and residential) are presented in Section 3.2. Available data
on the levels of trace pollutants present in coal and oil are summarized in
Section 3.3.
3-1
-------
The behavior of trace metals and radionuclides during the combustion
process is discussed in Section 3.4. Behavior such as enrichment of certain
trace metals on small fly-ash particles influences emissions. This section
also discusses the formation of POM and formaldehyde during combustion.
Other factors influencing emissions, including boiler design and control
technologies, are described in Section 3.5.
Emission factors for oil combustion are presented in Section 3.6.
Typical emission factors potentially usable in risk assessment analyses are
calculated based on the information in Sections 3.2 through 3.5, and these
calculated factors are compared with previously calculated and measured
emission factors from the literature. The data on trace pollutant emission
factors for coal combustion are summarized in Section 3.7, and emission
factors potentially usable in risk assessments are derived. Data gaps and
research needs are also identified in Sections 3.6 and 3.7.
Due to the large number of tables referred to in Sections 3.3 through
3.7, all tables for these sections are placed at the end of Chapter 3.
3.1 DESCRIPTION OF DATA BASE
The data base for the characterization of trace elements in fuels and
emissions from combustion sources included over 200 references. These were
identified by a computer literature search and by telephone contacts to
knowledgeable individuals in government agencies, trade associations, and
private industry. Details of the literature search can be found in
Appendix B. The telephone information gathering Is described in Chapter 2.
A complete bibliography for the project is included in Appendix C.
Each reference in the bibliography was reviewed, and fuel composition
data, measured and calculated trace pollutant emission factors, and other
relevant information were recorded on summary data sheets. These are
contained in the project file maintained by the Pollutant Assessment Branch
of the EPA's Office of Air Quality Planning and Standards, located in
Research Triangle Park, North Carolina.
3-2
-------
3.2 FUEL CONSUMPTION
The amount and type of fuel consumed by combustion sources has a direct
bearing on trace element emissions. This section characterizes U. S.
consumption of coal and oil.
3.2.1 Types of Coal and Oil
Coal can be divided into three major types - bituminous, lignite, and
anthracite. Subbituminous coal is sometimes separated out from bituminous
coal as another major type. On a fuel consumption basis, about 95 percent of
all coal combusted in the U. S. is bituminous, 4 percent is lignite, and
1 percent is anthracite (Baig et al., 1981). Figure 3-1 shows the major coal
fields in the U. S. and the type of coal mined in each. The heating value
and trace element content of coal varies by coal type and geographic region.
Appendix D presents typical heating values by coal type, and Section 3.3
discusses the trace element content of the various coals.
Two major categories of fuel oil are burned by combustion sources -
residual and distillate oils. These oils are further distinguished by grade
numbers, with numbers 1 and 2 being distillate oils, numbers 5 and 6
residual, and number 4 either distillate or a mixture of distillate and
residual oils. Typical heating values for fuel oils are presented in
Appendix D.
3.2.2 Fuel Use bv Combustion Sector
Table 3-1 summarizes Department of Energy data on 1982 U. S. coal and
oil use by combustion sector (Energy Information Agency, 1984b). In 1982, a
12
total of over 21,000 x 10 Btu of coal and oil were consumed by the utility,
industrial, commercial/institutional, and residential sectors. As shown in
12
Table 3-1, the utility sector consumed the most fuel (over 14,000 x 10 Btu)
About 89 percent of this fuel consumption (by heat content) was coal, about
10 percent was residual oil, and less than one percent was distillate oil.
Bituminous and lignite coal consumption was far greater than anthracite coal
3-3
-------
Sun I f ancsici
WESTERN
INTERIOR
BASIN
EXPLANATION
aar^.va
fc^Lfl
Anlhrarilr ťm! ťf iniťnlhrťcil*
Low-voBftftiHtf Jbifiuminoua coal
SubbUuminnuk foal
rr"3
tiJiiJ
Lignite
i r
0 200 400 COO KILOMCTRCS
Figure 3-1. Coal fields in the United States (excluding Alaska)
Source: Braunstein et al., 1977
-------
TABLE 3-1. U.S. FUEL CONSUMPTION BY SECTOR, 19821
12
Coal Consumption (10 Btu)
Sector
Utility
Industrial
Commercial/
Institutional
Residential
Total For All
Sectors
Bituminous
and Lignite
12,513.4
2,491.7
97.7
52.6
15,155.4
Anthracite
19.5
16.0
16.7
25.0
77.2
Total Coal
12,532.9
2,507.8
114.3
77.6
15,232.6
Oil
Residual
1,473.9
1 ,046 .6
398.6
0.0
2,919.1
1 2
Consumption (10 Btu)
Distillate
89.3
1,312.8
439.7
1,049.8
2,891.6
Sum of
Residual and
Distillate
1,563.2
2,359.4
838.3
1,049.8
5,810.7
Total Coal
and Oil
Consumption
14,096.1
4,867.2
952.6
1,127.4
21,043.3
Source: Energy Information Administration, 1984
For the utility sector this value includes distillate oil (#2), kerosene, and jet fuel.
sectors it includes distillate oil only.
For the other three
-------
consumption. Pennsylvania is the only State where utilities consume
anthracite coal. Proportions of coal versus oil consumed varied greatly from
State to State, with utilities in some States (California, Connecticut,
Hawaii, Idaho, and Rhode Island) consuming no coal, while utilities in other
States (Alabama, Arkansas, Iowa, Ohio, Pennsylvania, Utah, Washington, and
others) consume very little oil and rely almost exclusively on coal (Energy
Information Agency, 1984b).
12
The industrial sector consumed about 4,870 x 10 Btu of coal and oil in
1982, of which about 52 percent was coal, 22 percent was residual oil and
27 percent was distillate oil. As in the utility sector, some States relied
more heavily on coal while others relied more heavily on oil (Energy
Information Agency, 1984b).
In the commercial sector, total coal and oil consumption was about
12
950 x 10 Btu, with bituminous and lignite coals accounting for 10 percent,
anthracite for 1.8 percent, residual oil for 42 percent, and distillate oil
for 46 percent of this total. Pennsylvania, Ohio, and Indiana consumed large
amounts of coal relative to oil; and Pennsylvania also accounted for most of
the anthracite coal consumption (Energy Information Agency, 1984b).
12
The residential sector consumed about 78 x 10 Btu of coal and
12
1,050 x 10 Btu of distillate oil in 1982. Residual oil is not used in
residential furnaces. Pennsylvania, Ohio, New York, Indiana, and Kentucky
accounted for 58 percent of national residential coal consumption.
Pennsylvania used three times as much anthracite as bituminous coal.
New York consumed roughly equal amounts of bituminous and anthracite coal.
For the other States, bituminous coal predominated.
3.3 CONCENTRATION OF TRACE ELEMENTS IN FUELS
This section summarizes the available data on the trace metal content of
coal and oil. These data were derived from about 50 of the references
reviewed. Where possible, the data are summarized by fuel type and by
geographic region. Ranges, means, and standard deviations for trace element
concentrations found in previous studies are presented. Typical values for
the levels of each element in coals and oils are also presented. These are
based on all of the data reviewed during the current study.
3-6
-------
The most comprehensive source of information on coal composition is the
USGS National Coal Resources Data System (NCRDS). Geochemical and trace
element data are stored within the USCHEM file of NCRDS. As of October 1982,
the file contained information on 7,533 coal samples representing all U. S.
coal provinces. Trace element analysis for about 4,400 coal samples were
included in the data base (White et al., 1984). This computerized data
system was not accessed during the current study due to time and budgetary
constraints; however, a summary of the data presented in White et al. (1984)
was reviewed. Pennsylvania State University also maintains a computerized
data base including trace element content of coal samples. Information from
this data base was published by Spackman (1982a; 1982b).
The most extensive source of published trace element data was produced
by Swanson et al. of the USGS (1976). This report contains data for 799 coal
samples taken from 150 producing mines and includes the most important U. S.
coal seams. Data from the Swanson study was the initial input into the
USCHEM file of NCRDS.
Another significant source of published data on trace metals in coal is
a study by Ruch et al. of the Illinois State Geological Survey (1974). This
report contains trace element data for 82 coal samples from the Illinois
basin and 19 samples from other states. Other data reviewed generally
collaborate the findings reported in White et al. (1984), Swanson et al. (1976)
and Ruch et al. (1974).
The trace element content of oil is not as well characterized as the
trace element content of coal. Since the major sources of oil composition
data vary from element to element, major references are identified in the
sections on each element.
3.3.1 Arsenic in Fuels
Arsenic in Coal
Data on the ranges, means, and standard deviations of arsenic in
bituminous, subbituminous, anthracite, and lignite coals are presented in
Tables 3-2 and 3-3. The concentration of arsenic in coal is highly variable.
From the ranges presented in Table 3-3 it can be seen that arsenic
3-7
-------
concentration in individual coal samples varies over four orders of
magnitude. The large standard deviations, which exceed the mean arsenic
concentrations for each type of coal shown in Table 3-2, are another
indication of the great variability of the data. Despite this variability,
the table indicates that the average arsenic content of bituminous and
lignite coals is higher than the average arsenic content of subbituminous and
anthracite coals. Since the NCRDS data base, the source of the values in
Table 3-2, is the most comprehensive data base currently available, it is
recommended that the arithmetic means shown in the table be used as "typical"
values for the arsenic content of the four types of coal.
Table 3-4 shows the arsenic content of coal by geographic region.
Again, variability within each region is high, and the standard deviations
approach or exceed the means. One noteworthy trend is that the average
concentration of arsenic is greater in Appalachian and Interior coals than in
other coals. This behavior is also noted with other chalcophiles such as
cadmium and nickel (White et al. 1984). The arithmetic mean concentrations
from the White et al. (1984) analysis of the NCRDS may be viewed as
representative values for coals from each geographic region.
Arsenic in Oil
The arsenic content of oil also varies with type of oil and with the
State or country of origin. The arsenic content of crude oils varies over
three orders of magnitude. The variability within residual and distillate
oils appears to be somewhat less (see Tables 3-5 and 3-6). However, previous
studies have produced a wide range of estimates for mean or typical arsenic
concentrations in residual oils, with estimates ranging from 0.055 to
0.8 ppm. In general, the average arsenic content of crude and residual oils
is greater than that of distillate oils. Table 3-6 characterizes the data
reviewed in the current study in terms of the ranges of arsenic concentrations
reported in oils and suggested typical values. The typical arsenic
concentration of residual oil is 0.36 ppm and that of distillate oil is
0.085 ppm. These values were derived by averaging the mean or typical values
reported in the most comprehensive and highest quality studies reviewed.
3-8
-------
While the arsenic content of crude oils varies with country of origin
and with State of origin within the U. S. (Anderson, 1973; PEDCO, 1982; Cato
et al., 1976), the data reviewed show no clear pattern as to whether domestic
or foreign oil has a higher average arsenic content (see Table 3-7).
3.3.2 Beryllium in Fuels
Beryllium in Coal
The concentration of beryllium in coal varies by coal type and region in
which the coal is found. As shown in Table 3-8, bituminous and lignite coals
have a higher mean beryllium concentration than subbituminous and anthracite
coals. In the case of subbituminous and lignite coals, the standard deviation
exceeds the mean for beryllium concentration, indicating great variability in
the data. As seen in Table 3-9, the ranges of beryllium concentration are
similar between the coal types. The range of beryllium concentrations in
bituminous coals is somewhat higher than the other coal types. Because
Table 3-8 is based on the NCRDS data base, the most complete data set
currently available, the arithmetic means in that table may be considered as
typical values for the beryllium content of the four coal types.
Table 3-10 lists the arithmetic mean, standard deviation, and range of
beryllium concentration in coal by geographic region. The mean beryllium
content varies by a factor of three between the eight geographical regions
listed. Again, in some cases, the standard deviation exceeds the mean for
beryllium concentration, indicating variability in the data. Nevertheless,
the mean beryllium concentration in coals from the Illinois Basin,
Appalachian and Interior provinces are the highest among the eight regions
listed. The lowest mean beryllium concentration is found in coals from the
Alaska region. The means shown in Table 3-10, drawn from the White et al.
(1984) study, may be regarded as typical values for beryllium concentration
in the coal-producing regions listed, because the White et al. study is based
on the NCRDS data base.
Beryllium in Oil
The reported concentrations of beryllium in oil vary by type of oil and
between different studies of the same oil type. As shown in Table 3-11, the
reported ranges for beryllium concentration in residual oil vary
3-9
-------
substantially between different investigators. But with one exception, the
means reported agree fairly well. Less data were available with which to
characterize the beryllium concentration in distillate and crude oils. The
two reported mean concentrations of beryllium in distillate oil vary by a
factor of ten. Only one value was found in the literature review identifying
a mean concentration of beryllium in crude oil.
Table 3-12 summarizes the data available to characterize beryllium
concentrations in different types of oil. The typical values shown in the
table are 0.08 ppm for residual oil and 0.05 ppm for distillate. These were
obtained by averaging the mean values found in the studies reported in
Table 3-11. No data were found to allow comparison of the beryllium content
of foreign versus domestic crude oils.
3.3.3 Cadmium in Fuels
Cadmium in Coal
As shown in Table 3-13, the mean cadmium concentration in coal varies by
coal type, with bituminous coals having the highest mean cadmium concentra-
tion. However, the standard deviations for each coal type exceed the means,
indicating substantial variability within the data. Table 3-14 lists the
ranges of cadmium concentration in four coal types. Bituminous coals have
the broadest cadmium concentration range, from less than 0.02 to 100 ppm.
The remaining coal types all have cadmium concentration ranges of 0.1 to less
than 10 ppm. The means listed in Table 3-13 may be used as representative
concentrations of cadmium in each coal type because they were obtained from
the NCRDS data base, which is the most comprehensive currently available for
coal fuels.
The concentration of cadmium in coal varies distinctly by geographic
region. Coals from the Interior Province have a higher (arithmetic) mean
cadmium concentration (5.47 ppm) than coals from any other region. Coals
from the Illinois Basin, the eastern section of the Interior Province, have a
mean cadmium concentration of 2.89 ppm. Goals from other regions have mean
cadmium concentrations of less than 1 ppm. The arithmetic means listed in
Table 3-15 obtained from the White et al. (1984) analysis of the NCRDS may be
3-10
-------
used as typical values for cadmium in coal. However, the standard deviations
of the mean concentration in each region approach or exceed the mean
indicating strong variability within the data.
Cadmium in Oil
The concentration of cadmium in oil varies by oil type. Table 3-16
presents ranges and means of cadmium concentration in residual, distillate,
and crude oil derived from various studies. Table 3-17 summarizes the ranges
of cadmium concentration found in the data base for the current study by oil
type. Residual and distillate oils have similar cadmium concentration
ranges. The mean cadmium concentrations reported for these two oil types are
also similar with two exceptions. Two groups of investigators reported mean
cadmium concentrations in residual oil of 2.27 and 2.00 ppm. Other
researchers reported means of less than 0.4 and 0.3 ppm for residual oil and
0.3 and 0.1 ppm for distillate oil. The mean cadmium concentration of crude
oil has been reported as 0.01, 0.03, and 0.05 ppm. Typical values for
cadmium concentrations in residual, distillate, and crude oil are given in
Table 3-17. The suggested typical cadmium content of residual oil is
0.30 ppm and for distillate oil is 0.21 ppm. The typical values for
distillate and crude oil were obtained by taking the average of the reported
means.
The "typical" value for residual oil, 0.3 ppm, was based on reported
concentrations in Table 3-16, without using the two high values, 2.27 and
2.02 ppm. These two values appear to represent the upper end of the data
range, compared to other ranges of the concentration of cadmium in residual
oil (Table 3-16). An average concentration of 0.3 ppm was reported for
cadmium in oil in a study by Shih (1980b). This study included samples taken
from utility boilers burning residual oil and it also included more actual
data points (11 total) than other studies. Thus, a typical value of 0.3 ppm
cadmium in oil is in agreement with one of the more complete data sets
available.
Some data were available with which to compare the concentration of
cadmium in foreign and domestic crude oils (Table 3-18). Based on these
limited data, it appears that domestic and foreign crude oils have about the
same cadmium concentration.
3-11
-------
3.3.4 Chromium in Fuels
Chromium in Coal
The mean chromium concentrations in the four primary coal types are
shown in Table 3-19. The mean chromium concentration of anthracite coals,
47.2 ppm, is higher than that of the remaining three coal types. Lignite has
the lowest mean chromium concentration, 13.5 ppm. However, the standard
deviations of the mean for each coal type exceeds the arithmetic mean. This
situation indicates that there is a substantial variability in the data.
Table 3-20 shows the ranges of chromium concentration in the four coal types.
The range for anthracite coals is the highest, 15 to 120 ppm. The range for
the three remaining coal types are similar, with maximum chromium
concentrations being 70 ppm. The mean chromium concentrations listed in
Table 3-19 may be used as representative concentrations because they are
based on the most complete data set currently available (White et al., 1984).
The concentration of chromium in coals from different geographic regions
varies by as much as a factor of four. As shown in Table 3-21, coals from
the Alaska Province and Western Interior have the highest mean chromium
concentrations, 39.7 and 36.9 ppm, respectively. Northern Plains coals have
the lowest reported mean chromium concentration, 7.5 ppm. The ranges of
chromium concentration in coals from different geographic regions are also
shown in Table 3-21. Of interest is the fact that the ranges for chromium
concentration in Northern Plains coals extend to 100 ppm while the mean is
about 7 ppm. Similarly, the ranges for chromium concentration in Appalachian
coals are as high as 400 ppm while the mean is 18.2 ppm. As was true of the
analyses of chromium content by coal type, the standard deviations for
chromium content by geographic region exceed the mean in all but two cases.
Again, this indicates extreme variability in the data.
Chromium in Oil
Chromium concentration varies between different types of oil.
Table 3-22 provides means and ranges for chromium concentration of residual,
distillate, and crude oils. Of the three types of oil, distillate oil has
the highest reported mean chromium concentration, 1.6 ppm. The reported mean
3-12
-------
chromium concentrations of residual oil range from 0.070 to 0.9 ppm. The
mean concentrations of chromium in crude oil are reported to be 0.0023 to
0.64 ppm. Typical values for chromium in different oil types are shown in
Table 3-23 along with a summary of concentration ranges. The typical
chromium content of residual oil is 0.40 ppm and the value for distillate oil
is 0.95 ppm. The typical values were obtained by taking the average of the
means for each oil type reported in the several studies listed in Table 3-22.
The apparent conclusion that the typical chromium content of distillate oil
is greater than that of residual oil would not be expected and may be a
result of the fact the that chromium content of oils is highly variable and
few data were available to characterize distillate oil.
3.3.5 Copper in Fuels
Copper in Coal
The mean concentration of copper in coal does not vary significantly
between the four major coal types. Mean copper concentrations range from
14.1 to 18.9 ppm, as shown in Table 3-24. The ranges of copper concentration
vary somewhat between the coal types, but most noticeable is the extent of
the range of each coal type (Table 3-25). Bituminous coals may contain up to
900 ppm copper and lignite may contain up to 289 ppm. The fact that the
standard deviations of the mean copper concentration by coal type approach or
exceed their respective means emphasizes the variability of the data. The
means listed in Table 3-24 may be viewed as typical or representative values
for the concentration of copper in coal because they were derived from the
most complete data set currently available.
The concentration of copper in coals from different geographic regions
varies by up to a factor of three. Coals from the Gulf Province average
about 26 ppm copper, the highest concentration of all regions listed in
Table 3-26. The lowest mean copper concentration is found in coals from the
Northern Plains Province. The arithmetic means listed in Table 3-26 can be
considered as typical values for the concentration of copper in coal from
different regions.
3-13
-------
Copper in Oils
The copper concentrations in oil varies with oil type. As shown in
Table 3-27 and 3-28, the highest mean copper concentrations are found in
residual oil with a range in concentration of up to 79 ppm. The copper
concentration of distillate oil ranges from less than 1 to 11 ppm. Crude oil
has the lowest reported copper concentration, with a single reported mean of
1.32 ppm. Table 3-28 lists typical values for the copper concentration in
oils. The recommended typical values for residual and distillate oil are
5.3 ppm and 5.6 ppm, respectively. These values were determined by taking
the average of the means reported in several studies listed in Table 3-27.
The reason the value for distillate oil is slightly higher than for residual
oil may be that there is a lack of representative data to adequately
characterize distillate oil. In general, distillate oil will have lower
trace metal contents than residual oil.
Some data were available with which to compare the copper concentration
in foreign and domestic crude oils (Table 3-29). Based on this limited set
of data, domestic oils have a higher concentration of copper than do foreign
oils.
3.3.6 Mercury in Fuels
Mercury in Coal
Table 3-30 presents the mean concentration of mercury in coal by coal
type. Bituminous and anthracite coals have the highest mean mercury
concentration, 0.21 ppm and 0.23 ppm, respectively. The standard deviation
of each mean either approaches or exceeds the mean, indicating strong
variations in the data. Table 3-31 shows the ranges of mercury concentration
in each of the four coal types. Subbituminous coals have the greatest
reported range of mercury concentrations (0.01-8.0 ppm). The means reported
by White et al. (1984) in Table 3-30 may be regarded as typical values for
mercury concentration in coals because the data were based on the NCRDS, the
most comprehensive data set available at this time.
The concentration of mercury in coal also varies by the geographic
region from which the coal is obtained. As shown in Table 3-32, coals from
the Appalachian and Gulf Provinces have the highest mean mercury
3-14
-------
concentration, 0.24 ppm for both regions. The lowest mean concentration is
found in coals from the Alaska region. The greatest range of mercury
concentrations is found in coals from the Alaska region with a reported range
of 0.02 ppm to 63 ppm. The means reported by White et al. (1984) may be
regarded as typical concentrations of mercury in coals from each geographic
region.
Mercury in Oil
The concentration of mercury in oil depends on the type of oil. As
shown in Table 3-33, some reported values for the mean mercury concentration
in crude oil are higher than those reported for residual oil. The reported
mercury concentrations in crude oil range from 0.023 ppm to 30 ppm, while the
range of concentrations in residual oil is 0.007 ppm to 0.17 ppm. Only a
single mean value was found in the literature for mercury concentration in
distillate oil; therefore, no conclusions can be drawn about the range of
mercury in distillate oil. Table 3-34 lists typical values for mercury in
oils. These are 0.06 ppm for residual oil and 0.4 ppm for distillate oil.
The typical values were obtained by taking the average of the means shown in
Table 3-34. The value for distillate oil is the single data point found in
the literature and therefore may not be as representative as the values for
residual and crude oils. For a risk assessment, it may be more accurate to
use the value derived for residual oil (0.06 ppm) for both residual and
distillate oils.
Table 3-35 compares the concentrations of mercury in foreign crude and
domestic crude oils. Based on these data, it appears that domestic crude
oils have higher mercury concentrations than foreign crude oils.
3.3.7 Manganese in Fuels
Manganese in Coal
The mean concentration of manganese in bituminous, subbituminous, and
anthracite coals is lower than the concentration in lignite coal. Table 3-36
lists mean values for manganese in these four types of coal based on data
from the NCRDS. Although the reported mean concentration for manganese is
3-15
-------
highest in lignite coals, the range of manganese concentration is higher in
bituminous and subbituminous coals (Table 3-37). Bituminous coals may
contain as much as 4400 ppm manganese and subbituminous coals as much as
3500 ppm. The means listed in Table 3-36 may be considered typical values
for the manganese concentration in the four coal types listed because the
values are drawn from the most complete data set currently available, the
NCRDS. However, the standard deviations about the means approach or exceed
the mean, indicating considerable variability in the data.
Table 3-38 presents mean concentrations and ranges for manganese in coal
by geographic region. Generally, coals from the Gulf Province have a higher
mean manganese concentration (200 to 300 ppm) than coals from other regions.
The upper end of the range of concentrations are highest for coals from the
Interior, Rocky Mountain, and Appalachian regions with coals from these areas
containing as much as 4400 ppm, 3500 ppm, and 1400 ppm manganese,
respectively. Because the mean values in Table 3-38 reported by White et al.
(1984) are based on the most comprehensive data base currently available,
they may be viewed as representative concentrations of manganese in coals for
the geographical regions listed.
Manganese in Oil
Crude oil appears to have a higher mean manganese concentration than
residual or distillate oils. As shown in Table 3-39, the range of manganese
concentrations in crude oil are from 0.63 ppm to 2.54 ppm, with reported mean
concentrations of 1.17 ppm and 1.4 ppm. Residual oils have reported mean
concentrations higher than distillate oils. Representative values for
manganese concentration in residual, distillate, and crude oil are shown in
Table 3-40. The typical manganese content of residual oil is 0.49 ppm and
that of distillate oil is 0.21 ppm. These values were obtained by calculating
the average of the mean concentrations for each oil type shown in Table 3-39.
Some data were available with which to compare the concentration of
manganese in domestic and foreign crude oils. Based on these data, domestic
crude oils may have manganese concentrations two to three times that of
foreign crude oils.
3-16
-------
3.3.8 Nickel in Fuels
Nickel in Coal
The concentration of nickel in coal varies with coal type. Based on
data from the NCRDS, anthracite coals appear to have the highest mean nickel
concentration of the four major coal types (Table 3-42). Subbituminous and
lignite coals have the lowest mean nickel concentrations. Table 3-43 lists
the ranges of nickel concentrations in coal by coal type. Of the four types
of coal, bituminous coal has the highest absolute nickel concentration, with
some samples as high as 300 ppm nickel. The mean nickel concentrations given
in Table 3-42 can be considered as typical values for nickel concentration in
the four coal types. There is great variability in these data; however,
based on the fact that the standard deviations of each mean exceed the mean
itself.
Coals from the Interior Province and some parts of the Appalachian
Province have higher mean nickel concentrations than coals from other
regions. Table 3-44 presents (arithmetic) mean concentrations and ranges of
concentrations of nickel in coals from seven geographical regions. Lowest
mean nickel concentrations are reported for coals from the Northern Plains
and Rocky Mountain Provinces. But coals from these areas also show a wide
range of nickel concentrations, up to 300 ppm for coals from the Northern
Plains and 340 ppm for coals from the Rocky Mountain province. The mean
concentrations shown in Table 3-44 from the White et al. (1984) study can be
viewed as typical or representative values for the nickel concentration in
coal from the geographic regions listed. Again, the standard deviations
about each mean are large, indicating considerable variability in the data.
Nickel in Oil
In relative comparison to the other trace elements under study, fuel
oils contain large amounts of nickel. The concentration of nickel in oil
varies significantly by oil type. Table 3-45 shows that crude oil may
contain over 300 ppm nickel while residual oil usually contains 6 ppm to
70 ppm. Distillate oil contains less nickel, 1 ppm to 18 ppm. Table 3-46
summarizes the range of nickel concentrations in oil by oil type and shows a
3-17
-------
typical mean value. The typical values (24.0 ppm for residual oil and
3.38 ppm for distillate oil) were obtained by taking the average of the means
reported for each oil type in Table 3-45. The typical value for nickel
concentration in crude oil is significantly higher than that for residual and
distillate oils.
Table 3-47 gives mean nickel concentrations for foreign and domestic
crude oils. The data are widely scattered for both foreign and domestic
crudes. The reported means for foreign crudes range from less than 1 ppm to
117 ppm nickel and 2.4 ppm to 165.8 ppm in domestic crudes.
3.3.9 Thorium in Coal
The concentration of thorium in coal does not vary significantly by coal
type. Table 3-48 shows that mean thorium concentrations range from about
3 ppm in bituminous coals to 7 ppm in lignite. The ranges of thorium
concentration do vary by coal type, as seen in Table 3-49. Bituminous coals
can contain as much as 79 ppm thorium while the highest value found (in the
literature reviewed) for anthracite is about 14 ppm. The mean concentrations
listed in Table 3-48 can be regarded as representative of the thorium
concentration in coal by coal type. These values are based on data from the
NCRDS, the most complete data set available.
The concentration of thorium in coals varies somewhat by geographical
region. Table 3-50 shows that coals from the Gulf Province have a somewhat
higher concentration of thorium than do coals from other regions. The means
reported by White et al. (1984) may be regarded as typical values for thorium
concentration in coals from these regions.
Of special interest is the concentration of some radioactive isotopes of
thorium in coal. Table 3-51 lists mean concentrations of thorium-232 in
coals from several States and one region. Of the States for which data were
available, coals from Pennsylvania have the highest mean thorium-232
concentration, 0.4 picoCuries per gram (pCi/g).
3-18
-------
3.3.10 Uranium in Coal
The data presented in Table 3-52 indicate that the uranium content of
the four major coal types does not vary significantly. However, lignite
coals have a slightly higher mean uranium concentration than the remaining
three coal types. Bituminous and subbituminous coals have a wider reported
range of uranium concentrations, up to 59 and 76 ppm for these two coal
types, respectively. The means listed in Table 3-53 may be viewed as typical
values for uranium in coal because they are based on the most complete data
set currently available. However, the standard deviations about the means
are greater than the means themselves, indicating variability in the data
set.
Table 3-54 lists means and ranges of uranium in coal by geographic
region. There is not a large difference in mean uranium concentrations among
coals from these regions. But coal from the Western Interior and the Gulf
Province have higher mean concentrations of uranium than do coals from other
regions. The means listed in the table can be regarded as typical for coal
from each region.
The uranium-238 concentrations in coal from five states and one region
are given in Table 3-55. Highest uranium-238 concentrations are seen in
coals from Kentucky and Colorado, 0.91 and 0.877 pCi/g, respectively.
3.3.11 Lead in Fuels
A limited data base was. used to determine the concentration of lead in
coal and oil. The data are presented in this section in the text, rather
than in summary tables.
The concentration of lead in coal from the U. S. ranges from <1 to
33 ppm, although some coals have been found to contain over 250 ppm lead
(U. S. Environmental Protection Agency, 1985). The weighted average lead
concentration in coal from the U. S. has been reported as 8.3 ppm (U. S.
Environmental Protection Agency, 1985). In the derivation of emission
factors in this report for lead from coal combustion, an average of 8.3 ppm
lead was used for bituminous coal and 8.1 ppm for anthracite coal (U. S.
Environmental Protection Agency, 1985).
3-19
-------
The limited data base used to determine the concentration of lead in oil
reported that the lead content of residual oil averaged about 1 ppm and
ranged from 0.1-0.5 ppm for distillate oil (U. S. Environmental Protection
Agency, 1985). The derivation of emission factors for lead from oil
combustion in this report were based on a lead concentration of 1 ppm in
residual oil. For distillate oil, the average of the reported range of lead
concentrations, 0.3 ppm (0.1-0.5 ppm), was used.
3.4 BEHAVIOR OF TRACE POLLUTANTS DURING COMBUSTION
Trace metals contained in fuels are released during the combustion
process. They may be retained in the bottom ash, or they may be emitted via
the flue gas. Trace elements present in flue gas may be contained in the fly
ash or they may be in vapor form. Polycyclic organic matter (POM) is also
formed during combustion and emitted to the atmosphere. The behavior of
trace metals during the combustion process is described in Section 3.4.1.
Section 3.4.2 describes the behavior of radionuclides, and Section 3.4.3
discusses the formation and transformation of POM and formaldehyde during
combustion.
3.4.1 Partitioning and Enrichment Behavior of Trace Metals during Combustion
The concepts of partitioning and enrichment are frequently used to
characterize the behavior of trace elements in combustion processes.
Partitioning generally refers to the split of the trace element among the
various boiler outlet streams: bottom ash, fly ash, and flue gas.
Enrichment refers to the difference in trace element concentration between
different streams or to the change in trace element concentration of bottom
ash or fly ash as a function of particle size.
One method of describing partitioning behavior is by reporting the
fraction of the total elemental mass input that leaves the boiler via each of
the outlet streams. Another method is to compare the trace element
concentration of one outlet stream to that of another through enrichment
ratios (or enrichment factors). In general, enrichment ratios are calculated
by the following equation:
3-20
-------
Cii/CRi
1J KJ
C. /C_
ic7 Rc
where
ER.. - enrichment ratio for element i in stream j
C.. - concentration of element i in stream j
C . - concentration of reference element R in stream j
C. - concentration of element i in fuel
1C
C_ - concentration of reference element R in fuel
An enrichment ratio greater than 1 indicates that the element is
"enriched" in the given stream, or, expressed another way, that the element
"partitions" to the given stream. Different reference elements commonly used
by various authors are Al, Fe, Sc, and Ti. These elements are chosen because
their partitioning and enrichment behavior is often comparable to that for
the total mass. That is, their concentration by weight in all ash streams
and size fractions is constant.
Various classification schemes have been developed to describe
partitioning or enrichment behavior (Klein, et al., 1975b; Coles et al.,
1979; Baig et al., 1981). The classification scheme used by Baig et al.
(1981) is as follows:
Class 1. Elements which are approximately equally distributed
between fly ash and bottom ash, or show little or no small particle
enrichment.
Class 2. Elements which are enriched in fly ash relative to bottom
ash, or show increasing enrichment with decreasing particle size.
Class 3. Elements which are intermediate between Classes 1 and 2.
Class 4. Elements which are emitted in the gas phase.
Because of factors such as differences in classification schemes used by
different investigators, different and ill-defined dividing lines between the
classes, sampling and analytical errors in the data used to determine
classification, and variations in the behavior of an element in different
3-21
-------
studies, it is not possible to make an absolute classification of the
elements. However, such a classification scheme is useful in indicating
general trends in the behavior of the elements. Several of the elements have
shown behavior characteristics of each of the first three classes in
different studies. These elements were assigned to Class 3, since Classes 1
and 2 represent the extremes in behavior and Class 3 is intermediate between
them.
Based on information in about 20 previous studies, Baig et al. (1981)
classified arsenic and cadmium as Class 2 elements. Beryllium, chromium,
manganese, and nickel were placed in Class 3. Copper was not included in the
Baig et al. (1981) study, but may also be placed in Class 3. Mercury behaved
as a Class 4 element. Brief descriptions of the behavior of each element
follow:
As. Arsenic has exhibited Class 2 behavior in almost every study.
Therefore, As is considered to be a Class 2 element (Baig et al., 1981).
Be. Beryllium has exhibited Class 1 behavior in some studies, Class 2
in others, and Class 3 in others. This difference in classification could be
due in part to differences in criteria used to assign elements to one class
over another, or could be due to differences in the behavior of Be in
different combustion systems. For this study. Be is considered as a Class 3
element (Baig et al., 1981).
Cd. Cadmium has exhibited Class 2 behavior in every study examined, and
is therefore considered to be a Class 2 element (Baig et al., 1981).
Cr. Chromium, like Be, has shown Class 1, 2, and 3 behavior in
different studies, and is considered as a Class 3 element (Baig et al.,
1981).
Cu. Copper has shown Class 2 behavior in most studies (Klein et al.,
1975b; Mann et al., 1978; Radian, 1975a; Cowherd, 1975). However, Class 1
and 3 behavior has also been reported (Davison et al., 1974; Natusch et al.,
1974; Coles et al., 1979). Copper is considered a Class 3 element, but
resembles Class 2 more closely than the other Class 3 elements do.
Mn. Manganese has also shown Class 1, 2, and 3 behavior, and will be
considered as a Class 3 element. However, since it has been reported to show
Class 1 behavior more frequently and Class 2 behavior less frequently than
3-22
-------
the other Class 3 elements, it may come closer to Class 1 behavior than to
Class 2 and resemble Class 1 elements more than the other Class 3 elements
do (Baig et al., 1981).
Ni. Nickel has shown Class 1, 2, and 3 behavior, and will be considered
as a Class 3 element (Baig et al., 1981).
Hg. Mercury is a Class 4 element at normal stack temperature of 150 C
(300 F). Lower temperatures, however, will cause condensation of some of the
gaseous mercury so that it can be considered as Class 2 (Baig et al., 1981).
3.4.1.1 Theories Explaining Trace Metal Behavior in Coal Combustion Systems
3.4.1.1.1 Volatilization/condensation mechanism. One of the most
widely held, fundamental theories that has been proposed to explain the
behavior of trace elements in coal combustion systems is the
volatilization/condensation mechanism (VCM). This theory suggests that
volatile species in the ash are vaporized in the firebox, where peak
temperatures of 1650°C (3000°F) are typical for pulverized coal-fired
boilers. As the flue gas cools to 370-430°C (700-800°F) in the convective
heat transfer section and further to 150 C (300 F) in the air preheater, the
volatilized species condense. These species may condense or adsorb onto
existing particles according to the available surface area or they may
condense homogeneously, forming fine particles. The elements thus
volatilized would be depleted in the bottom ash and concentrated in the fly
ash, since the fly ash has more relative surface area than the bottom ash and
since the bottom ash does not come in contact with the volatilized elements
long enough for the elements to condense on the bottom ash (Baig et al. ,
1981).
The VCM primarily explains the behavior of the Class 2 elements, but it
also explains the behavior of the other classes of elements. The Class 1
elements are the nonvolatile matrix elements that do not vaporize in the
boiler. These elements form the fly ash matrix on which the volatilized
elements condense. The Class 1 elements are thus equally distributed between
bottom ash and fly ash, and show no small particle enrichment. The Class 3
elements apparently are partially vaporized in the boiler, and thus show
behavior intermediate between Classes 1 and 2. The Class 4 elements are
highly volatile. They do not condense or condense only partially as the flue
gas cools to normal stack temperature (Baig et al., 1981).
3-23
-------
The VCM also explains the enrichment of Class 2 elements on small
particle sizes. Because smaller particles have a higher surface area,
relative to their mass, than the larger particles, they have more available
area on which Class 2 and 3 elements can condense. The Class 1 elements are
not vaporized, and thus show no dependence of concentration on particle size.
3.4.1.1.2 Compound boiling points. Kaakinen et al. (1975) have
compared enrichment ratios for several elements to various measures of
element volatility, including melting points, boiling points, and vapor
pressures of elemental and oxide forms, and reported that the oxide
properties generally showed good agreement.
All of the Class 2 and Class 4 elements included in the current study
(As, Cd, and Hg) have elemental or oxide boiling points less than 1650 C
(3000°F). Class 1 elements, such as Al, have boiling points greater than
1650 C (3000 F). The Class 3 elements also generally have elemental and
oxide boiling points greater than 1650 C (3000 F), and so would be expected
to behave like the Class 1 elements.
A simple correlation of the element or oxide boiling points thus does
not explain the behavior of all trace elements. A fraction of these
elements, however, may form compounds other than oxides (such as chlorides or
carbonyls) that are volatile. Reducing conditions can exist during the
initial combustion stage that might contribute to the formation of such
compounds. Moreover, the compounds formed and the fractions of the element
forming the volatile and nonvolatile compounds might vary under different
combustion systems and different conditions of furnace temperature, coal
time/temperature history, excess air, and coal composition. Such variations
could explain the observed variation in the behavior of these elements in
different combustion systems (Baig et al., 1981).
3.4.1.1.3 Elemental association in coal. The association of trace
elements in coal (with the organic fraction or inorganic matrix) has also
been suspected of playing a key role in the fate of elements upon combustion
(Mann et al., 1978; Edwards et al, 1980). The theory is that trace elements
bound in. the organic phase are atomized during combustion, while those
occluded with the mineral matter in the coal are less likely to be vaporized.
Moreover, actual volatilization of the organically associated elements may
3-24
-------
not be necessary for trace element enrichment. Deposition of the
nonvolatilized trace elements associated with the organic fraction, on the
remaining mineral inclusions that form the fly ash, will give a similar
inverse dependence of concentration with size. This theory may explain the
behavior of certain elements, but not all (Baig et al., 1981).
3.4.1.2 Theories Explaining Trace Metal Behavior in Oil Combustion
Systems. Since no bottom ash is formed from oil combustion, it can generally
be assumed that all of the trace elements present in the oil are emitted with
the fly ash or in the gas phase. There are few data on particle size
association of trace metals emitted from oil combustion systems.
Volatilization/condensation mechanisms may play a role in the behavior of
elements in oil combustion systems. However, oil fly ash particles have
irregular, honeycombed surfaces as opposed to coal fly ash particles which
have smooth, round surfaces. Therefore, surface area will not necessarily
have a strong dependence on particle size, and trace metal enrichment on
small particles may not be as pronounced for oil combustion as for coal
combustion (Baig et al., 1981).
3.4.2 Behavior of Radionuclides During Combustion
Naturally occurring radionuclides present in coal include uranium-238
(U-238), uranium-235 (U-235), thorium-232. (Th-232), and potassium-40 (K-40)
as well as their daughter products. Some of these include Th-230, Th-228,
radon-228 (R-228), R-226, lead-210 (Pb-210) and polonium 210 (Po-210). For
the purposes of this study, U-238 and Th-232 will be used as indicators of
radionuclide emissions. These two species have the longest half-lives (4.5 x
a in
10 years for U-238 and 1.4 x 10 years for Th-232) and are the parent
species of the two predominant decay chains. They have been selected as
indicators of radionuclides in previous risk assessments (Environmental
Research and Technology; Inc., 1983; U. S. Environmental Protection Agency,
1984).
Radioactive uranium and thorium contained in the coal feed is
partitioned between the bottom ash and fly ash during combustion. Very
little, if any, radionuclides are emitted to the atmosphere in vapor form
(Roeck et al., 1983)
3-25
-------
Several studies have found that U-238 is enriched in the small (<1 urn
diameter) fly ash particles (Coles et al., 1978; Klein et al., 1975b; Roeck
et al., 1983). Uranium-238 would be termed a Class 2 element using the
terminology developed in Section 3.4.1. It has been postulated that a
portion of the uranium in coal is associated with the silicate (i.e.,
coffinite) and follows the alumino-silicate minerals which melt and drop out
as slag during the combustion process. Another fraction of the U-238 is
dispersed in the coal as uranite and becomes volatile as uranium oxide (UO^)
during combustion and continues along with the flue gas and fly ash. At
normal stack temperatures the U0_ condenses out on the fly ash,
preferentially concentrating on the smaller fly ash particles because of
their larger surface area to mass ratio (Coles et al., 1978).
Some studies have found that for Th-232, there is little preferential
partitioning between the slag and the collected or discharged fly ash (Coles
et al., 1978; Klein et al., 1975b). Other studies have indicated small
particle enrichment in the fly ash (Roeck et al., 1983). Thorium-232 would
be termed a Class 3 element using the terminology developed in Section 3.4.1.
3.4.3 Formation and Transformation of POM and Formaldehyde During Combustion
Formaldehyde. Formaldehyde is formed and emitted during combustion of
hydrocarbon-based fuels such as coal and oil. Formaldehyde is present in the
vapor phase of the flue gas. Since formaldehyde is subject to oxidation and
decomposition at the high temperatures encountered during combustion, large
units with efficient combustion resulting from closely regulated air-fuel
ratios, uniformly high combustion chamber temperatures, and relatively long
retention times should have lower formaldehyde emission rates than do small,
less efficient combustion units (Hangebrauck et al., 1964; Rogozen et al.,
1984b).
Polycyclic Organic Matter. The term polycyclic organic matter (POM)
defines a broad class of compounds which generally includes all organic
structures having two or more fused aromatic rings (i.e., rings which share a
common border). Polycyclic organic matter with up to seven fused rings have
3-26
-------
been identified. Theoretically, millions of POM compounds could be formed;
however, the list of species that have been identified and studied is more on
the order of approximately 100 (U. S. Environmental Protection Agency,
1980b).
Nine major categories of compounds have been defined by the U. S.
Environmental Protection Agency to constitute the class known as POM
(Shih et al., 1980a). The nine categories are as follows.
1. Polycyclic aromatic hydrocarbons (PAHs) - the PAHs include
naphthalene, phenanthrene, anthracene, fluoranthene,
acenaphthalene, chrysene, benzo(a)anthracene,
cyclopenta(c,d)pyrene, the benzpyrenes, indeno(l,2,3-c,d)pyrene,
benzo(g,h,i)perylene, coronene, and some of the alkyl derivatives
of these compounds.
2. Aza arenes - aza arenes are aromatic hydrocarbons containing a ring
nitrogen.
3. Imino arenes - these are aromatic hydrocarbons containing a ring
nitrogen with a hydrogen.
4. Carbonyl arenes - these are aromatic hydrocarbons containing one
ring carbonyl group.
5. Dicarbonyl arenes - also known as quinones, contain two ring
carbonyl groups.
6. Hydroxy carbonyl arenes - these are ring carbonyl arenes containing
hydroxy groups and possibly alkoxy or acyloxy groups.
7. Oxa arenes and thia arenes - oxa arenes contain a ring oxygen atom,
while thia arenes contain a ring sulfur atom.
8. Polyhalo compounds - these include the polychlorinated
dibenzo-p-dioxin (PCDDs), polychlorinated dibenzofurans (PCDFs),
and polychlorinated biphenyls (PCBs), and also brominated analogs of
these compounds such as polybrominated biphenyls (PBBs).
9. Pesticides - including aldrin, chlordane, and DDT.
These categories were developed to better define and standardize the types of
compounds considered to be POM.
3-27
-------
The two POM chemical groups most commonly found in emission source
exhaust and ambient air are PAHs, which contain carbon and hydrogen only, and
the PAH-nitrogen analogs. Information available in the literature on POM
compounds generally pertains to these PAH groups. Because of the dominance ,
of PAH information (as opposed to other POM categories) in the literature,
many reference sources have inaccurately used the terms POM and PAH
interchangeably. The majority of information in this report on POM
physical/chemical properties, formation mechanisms, and emissions pertains to
PAH compounds.
Polycyclic organic compounds are formed in stationary combustion sources
as products of incomplete combustion. The rates of POM formation and
emission are dependent on both fuel characteristics and combustion process
characteristics. Emissions of POM can originate from POM compounds contained
in fuels that are released during combustion or from high temperature
transformations of organic compounds in the combustion zone (Shih et al.,
1980a; National Academy of Sciences, 1972; National Research Council, 1983).
Two important fuel characteristics affecting POM formation in combustion
sources are (1) the carbon to hydrogen ratio and molecular structure of the
fuel and (2) the chlorine and bromine content of the fuel (Shih et al.,
1980a). In general, the higher the carbon to hydrogen ratio, the greater the
probability of POM compound formation. Holding other combustion variables
constant, the tendency for hydrocarbons present in a fuel to form POM
compounds is as follows.
aromatics > cycloolefins > olefins. > paraffins
Based on both carbon to hydrogen ratio and molecular structure
considerations, the tendency for the combustion of various fuels to form POM
compounds is as follows (Shih et al., 1980a).
coal> lignite > wood > waste oil > residual oil > distillate oil
In the formation of chlorinated and brominated POM compounds during
stationary source fuel combustion, the chlorine and bromine content of the
3-28
-------
fuel plays a major role. Based on the chlorine content of fuels, the
tendency to form chlorinated POM compounds during combustion is:
bituminous coal > wood > lignite > residual oil > distillate oil
Similarly, based on the bromine content of fuels, the tendency to form
brominated POM compounds during combustion is:
bituminous coal > lignite > residual oil > distillate oil > wood
The primary combustion process characteristics affecting POM compound
formation and emissions are (Shih et al., 1980a; Hangebrauck et al., 1964;
Barrett et al., 1983):
combustion zone temperature,
residence time in the combustion zones,
turbulence or mixing efficiency between air and fuel,
air/fuel ratio, and
fuel feed size.
With adequate residence time and efficient mixing, temperatures in the
800-1000°C (1472-1832°F) range will cause complete destruction of POM
compounds such as polychlorinated dibenzo-p-dioxins (PCDDs), polychlorinated
dibenzofurans (PCDFs), and polychlorinated biphenyls (PCBs). Concentrations
of polyaromatic hydrocarbons (PAHs) also decrease rapidly with increasing
temperature (Shih et al., 1980a).
The most important reason for incomplete combustion of fuel, thereby
resulting in POM formation, is insufficient mixing between air, fuel, and
combustion products. Mixing is a function of the combustion unit's operating
practices and fuel firing configuration. Hand- and stoker-fired solid fuel
combustion sources generally exhibit very poor air and fuel mixing relative
to other types of combustion sources. Liquid fuel units and pulverized solid
fuel units provide good air and fuel mixing (Shih et al., 1980a;
Hangebrauck et al., 1964; Barrett et al., 1983; Kelley, 1983).
3-29
-------
The air/fuel ratio present in combustion environments is important in
POM formation because certain quantities of air (i.e., oxygen) are needed to
stoichiometrically carry out complete combustion. Air supply is particularly
important in systems with poor air and fuel mixing. Combustion environments
with a poor air supply will generally have lower combustion temperatures and
will not be capable of completely oxidizing all fuel present. Systems
experiencing frequent start-up and shut-down will also have poor air/fuel
ratios. Unburned hydrocarbons, many as POM compounds, can exist in such
systems and eventually be emitted through the source stack. Generally,
stoker and hand-fired solid fuel combustion sources have problems with
insufficient air supply and tend to generate relatively large quantities of
POM as a result (Shih et al., 1980a; Kelley, 1983; Barrett et al. , 1983).
In solid and liquid fuel combustion sources, fuel feed size can
influence combustion rate and efficiency, therefore, POM compound formation
is affected. For liquid fuel oils, a poor initial fuel droplet size
distribution is conducive to poor combustion conditions and an enhanced
probability of POM formation. In most cases, fuel droplet size distribution
is primarily influenced by fuel viscosity. As fuel viscosity increases, the
efficiency of atomization decreases and the droplet size distribution shifts
to the direction of larger diameters. Therefore, distillate oils are more
readily atomized then residual oils and result in finer droplet size
distribution. This behavior combined with distillate oil's lower carbon to
hydrogen ratio means that residual oil sources inherently have a higher
probability of POM formation and emission then distillate oil sources
(Shih et al., 1980a; Hangebrauck et al., 1964; Kelley, 1983).
For solid fuels, fuel size affects POM formation by significantly
impacting combustion rate. Solid fuel combustion involves a series of
repeated steps, each with the potential to form POM compounds. First, the
volatile components near the surface of a fuel particle are burned followed
by burning of the residual solid structure. As fresh, unreacted solid
material is exposed, the process is repeated. Thus, the larger the fuel
particle, the greater the number of times this sequence is repeated and the
longer the residence time required to complete the combustion process. With
succeeding repetitions, the greater the probability of incomplete combustion
3-30
-------
and POM formation. Again, stoker and hand-fired solid fuel combustion units
represent the greatest potential for POM emissions due to fuel size
considerations (Shih et al., 1980a).
Polycyclic organic matter can be emitted from fuel combustion sources in
both gaseous and particulate phases. The compounds are initially formed as
gases, but as the flue gas stream cools, a portion of the POM constituents
adsorb to solid fly ash particles present in the stream. The rate of
adsorption is dependent on temperature, and on fly ash and POM compounds
characteristics. At temperatures above 150 C (302 F), most POM compounds are
expected to exist primarily in gaseous form. In several types of fuel
combustion systems, it has been shown that POM compounds are preferentially
adsorbed to smaller (submicron) fly ash particles because of their larger
surface area to mass ratios. These behavioral characteristics of POM
emissions are important in designing and assessing POM emission control
systems (Shih et al., 1980a; Kelley, 1983; Griest and Guerin, 1979;
Sonnichsen, 1983).
3.5 EFFECTS OF BOILER DESIGN AND CONTROL TECHNOLOGY ON EMISSIONS
3.5.1 Characteristics of the Boiler Population
Boiler Design. Boiler design influences the rate of trace metal and POM
emissions. Types of coal-fired boilers used in the utility, industrial, and
commercial/institutional sectors include pulverized coal-fired, cyclone, and
stoker units. Pulverized units are characterized by ash removal method as
dry bottom or wet bottom. There is little variation in the design of
oil-fired units, and almost all are tangentially fired. Table 3-56 shows the
prevalence of each boiler type (in terms of 1978 fuel use) in the utility,
industrial, and commercial/institutional sectors.
The utility sector is dominated by pulverized dry bottom coal-fired
units. In the future, the percentage of these units is expected to increase.
Coal-fired pulverized wet bottom and cyclone boilers are no longer sold due
to their inability to meet NO standards. Stoker boilers, currently
accounting for less than one percent of the total, are obsolete due to their
inefficiency and are being retired.
3-31
-------
In the industrial sector, more natural gas is used relative to coal and
oil. Pulverized coal-fired units are the most common type of coal-fired
unit; however, stoker units (mainly spreader stokers) also account for a
large percentage of total coal use.
The commercial/institutional sector consumes a greater proportion of oil
and natural gas relative to coal consumption than the other two sectors.
Small underfeed stokers are the predominant type of coal-fired boiler. Some
of the larger institutional sources in this sector are pulverized coal-fired
boilers and spreader stokers.
Control Status. Most coal-fired utility boilers are equipped with
particulate emissions control devices. High efficiency electrostatic
precipitators (ESPs) are the most common. Data on the control status of
bituminous coal-fired utility boilers in 1975 is shown in Table 3-57 (Shih
et al., 1980b). A study of coal-fired utility boilers larger than 100 MW and
placed in service since 1950 showed that in 1980 about 92 percent of the
generating capacity was controlled with ESPs, 2 percent with fabric filters,
1 percent with scrubbers, and the control status of 5 percent was unknown
(Barrett et al., 1983). New units subject to NSPS must control particulate
emissions by about 99 percent, so the control status of coal-fired utility
boilers is expected to improve over time. Current (1984) data on the control
status of utility boilers is contained in the POWER data base (see
Section 2.1.12 and Section 4.1).
In 1984, about 17 percent of the utility coal generating capacity was
equipped with flue gas desulfurization (FGD) systems. The majority of these
were lime or limestone scrubber systems. It is predicted that by 1992, about
31 percent of coal generating capacity will be equipped with FGD systems
(Melia et al., 1984).
Oil-fired utility boilers are often uncontrolled; however some are
equipped with mechanical precipitators, cyclones, or ESPs (Shih et al.s
1980b). The POWER data base contains current information on the control
status of oil-fired utility boilers.
Coal-fired industrial boilers are less well controlled than utility
boilers. Based on a 1976 survey of over 2,500 units, about 14 percent were
controlled with ESPs, 47 percent with cyclones, 4 percent with scrubbers,
3-32
-------
1 percent with fabric filters, and 33 percent were uncontrolled
(Suprenant et al., 1980a). The applicability of these percentages to the
entire industrial boiler population is unknown. In general, larger units are
more likely to be controlled than smaller units, and pulverized coal and
cyclone boilers are more likely to be controlled than stokers (Suprenant
et al., 1980a). The NSPS for industrial boilers (>100 million Btu) and small
boilers (<100 million Btu) will result in improved emissions control in the
future. Oil-fired industrial boilers are typically uncontrolled.
Commercial and residential boilers and furnaces are typically
uncontrolled. However, cyclones are in place at some of the larger
commercial/institutional coal-fired boilers (Suprenant et al., 1980b). A
small boiler NSPS is being developed which will apply to some
commercial/institutional boilers.
3.5.2 Trace Metal and Radionuclide Emissions
Boiler design affects the amount of ash entrained in the flue gas.
Since all of the trace metals and radionuclides reviewed, except mercury, are
emitted predominantly in particulate form, the amount of fly ash emitted will
influence the amount of trace metals emitted. Table 3-58 presents the
fraction of coal ash emitted as fly ash for different combinations of boiler
firing configurations and coal types (Baig et al., 1981). The fractions for
bituminous coal-fired boilers are based on several tests. The values for
lignite and anthracite are much less certain. Further testing is necessary
to determine if the three types of coals generate different ratios of fly ash
to bottom ash when burned in similar boilers.
Boiler configuration may also affect the volatilization/condensation
behavior of trace elements, and hence their emission rates. This is especially
true for Class 3 elements which show enrichment in the fly ash in some
studies and not in others (Baig et al., 1981). Elements may be more likely
to be vaporized in large pulverized coal-fired boilers where combustion is
more efficient due to higher temperatures, longer residence times, and
efficient mixing of air and fuel; and they may be volatilized to a lesser
degree in smaller, less efficient, lower temperature combustion systems. The
3-33
-------
temperature of the stack gas and fly ash characteristics influence the
condensation behavior of volatilized trace metals and their adsorption onto
fly ash particles.
The efficiency of control devices in removing trace elements depends on
whether the elements are in vapor or particulate form and on the size of the
fly ash particles with which the elements are associated. Typical particulate
controls on industrial and utility boilers include multicyclones and ESPs.
Scrubbers are applied to some utilities for S0_ (and particulate) control.
For elements such as manganese, which tend to show an even distribution on
all sizes of particulates, collection efficiency of particulate control
devices should be similar to overall particulate control efficiency. However
other elements such as arsenic, cadmium, copper and U-238 are enriched in the
smaller particulate fractions (<1 urn). Mechanical collection devices such as
cyclones and multicyclones generally show decreasing collection efficiency as
particle size decreases; therefore, the collection efficiency of trace
elements concentrated on small particles will be less than overall particulate
collection efficiency. Although not as severe as for cyclones, this condition
also exists for scrubbers and ESPs. ESPs often show a minimum collection
efficiency in the 0.1 to 1 urn diameter size range (Ondov et al., 1979a).
Furthermore, ESPs and cyclones will not reduce emissions of elements,
such as mercury, emitted in the vapor phase. A portion of the other trace
metals, especially the Class 2 elements identified in Section 3.4.1, may also
remain in vapor form in the flue gas, and may thereby escape collection.
3.5.3 Polycyclic Organic Matter Emissions
Polycyclic organic matter emission rates are also influenced by boiler
design. As noted in Section 3.4.3, POM formation depends on temperature,
residence time, efficiency of air and fuel mixing, air/fuel ratio, and fuel
feed size. Based on these criteria, pulverized dry bottom and wet bottom
coal-fired units would have the lowest POM emission factors of any coal-fired
units. These units are generally large, temperature of the combustion zone
is high [around 1,650 C (3,000°F)], residence time in the combustion zone is
relatively long (0.5 sec), air/fuel ratios are constant and adequate for
3-34
-------
efficient combustion, and the coal feed is pulverized into small particles.
Cyclone-fired boilers would have the next lowest POM emission rates. Stokers
would have higher emission rates, with overfeed and underfeed stokers having
slightly higher emission rates than spreader stokers. Stoker units are
usually smaller, temperatures in the combustion zone are lower due to the 30
to 60 percent excess air present, mixing between air and fuel is less efficient
the on-off cycle results in fluctuations in the air/fuel ratio, and fuel feed
size is larger. These factors lead to increased POM formation. Hand stoked
units would have the highest emission factors of all coal-fired units (Shih
et al., 1980a; Barrett et al., 1983). The trends described above are supported
by test data (see Section 3.7.3).
Oil-fired units have less of a tendency to form POM than coal-fired
units due to fuel characteristics (see Section 3.4.3). Based on fuel
characteristics, residual oil fired units are more likely to form POM than
distillate oil fired units. Based on boiler design characteristics, large
oil-fired utility boilers would have the lowest POM emission rates, followed
by industrial boilers. Based on design, home heating units would have higher
POM emission rates; however, these are usually fired with distillate oil
which would tend to reduce emissions (Shih et al., 1980a).
Polycyclic organic matter is emitted in both vapor and particulate
phases, with the vapor phase generally predominating, and the particulate
phase showing small particle enrichment. Particulate POM, particularly fine
particles, would be controlled most effectively by baghouses or ESPs. No
control of gaseous POMs would be achieved by baghouse and ESP systems. Wet
scrubbers could potentially be effective for controlling particulate and
gaseous POM. Scrubbers would condense the POM compounds existing as vapors
and collect them as the gas stream is saturated in the scrubber.
Multicyclones would be the poorest control system for POM emissions because
they are ineffective on fine particles and would have no control effect on
gaseous POM (Kelley, 1983).
Wet FGD/ESP systems, while providing for the control of POM condensed on
particulate matter at the entrance to the ESP, have been shown to be poor at
controlling vapor phase POM. Tests examining benzo(a)pyrene showed that
condensation of the vapor phase POM compound would occur in the scrubber, but
significant collection of POM particles remaining in the gas flow through the
scrubber was not achieved (Kelley. 1983).
3-35
-------
3.6 EMISSION FACTORS FOR OIL-FIRED COMBUSTION SOURCES
The literature was reviewed for measured and calculated oil emission
factors. Recommended emission factors for the nine trace metals, POM, and
formaldehyde emitted from the combustion of residual and distillate oil are
presented and discussed in Section 3.6.1. The remaining sections of the
chapter discuss the recommended emission factors for each trace pollutant in
greater detail and summarize the results of previous studies.
3.6.1 Recommended Emission Factors
Trace pollutant emission factors for residual and distillate oil
combustion are presented in Table 3-59. These are uncontrolled emission
factors, and are recommended for use in future risk assessments. They are
applicable to all types of oil-fired boilers in all four combustion sectors
(utility, industrial, commercial/institutional, and residential).
3.6.1.1 Derivation of Recommended Trace Metal Emission Factors. The
recommended emission factors for eight of the nine trace metals studied were
calculated from the typical level of these metals in residual and distillate
oil assuming the entire mass of the trace metals entering the boiler in the
oil feed is emitted in the flue gas. Typical values for the trace element
content of residual and distillate oils presented in Section 3.3 were used in
the calculations. These were average values based on a review of several
previous studies of the trace element composition of oil. Typical trace
metal concentrations in the oil feed (expressed in ppm) were converted to
12
emission factors (Ib trace metal emitted per 10 Btu of oil burned) assuming
heating values of 150,000 Btu/gal for residual oil and 141,000 Btu/gal for
distillate oil, and densities of 944 g/1 (7.88 Ib/gal) for residual oil and
845 g/1 (7.05 Ib/gal) for distillate oil. The heating values are documented
in Appendix D.
Since oil combustion generates no bottom ash, the assumption that
100 percent of the trace metals entering the boiler in the oil feed are
emitted in the flue gas is reasonable (see Section 3.4.1). The calculated
uncontrolled emission factors based on this assumption would be independent
of boiler design and combustion sector.
3-36
-------
In general, the emission factors for trace metals generated in this
study are similar to values calculated in previous studies. All previous
studies reviewed used the assumption that all of the trace metals present in
the oil feed were emitted. There is a lack of test data on stack emissions
from oil-fired boilers. The few test data available are in general agreement
with the calculated emission factors. However, mass balances do not exhibit
good closure for many of the test runs. Sections 3.6.2 through 3.6.9 discuss
the results of previous studies for each trace metal in comparison with the
recommended values from the current study.
Limited emission factor data for lead emissions from oil combustion are
presented in Section 3.6.12. As described in Section 1.2, the consideration
of lead as a trace pollutant from coal and oil combustion was added to this
project by EPA after the submittal of the draft final report. For this
reason, the treatment of lead, including the availability of emission factor
data, is very abbreviated compared to the other trace pollutants in the
document. Only a limited number of the references listed in the report
bibliography in Appendix C were evaluated for lead data. It is acknowledged
that this approach does not provide for a thorough analysis of lead; however,
the approach is sufficient to achieve the objectives of this study.
There are very few data available concerning trace metal emissions from
oil-fired boilers equipped with control devices. The U. S. EPA decided that
in order to provide an indication of the approximate emission factors for
these boilers, the control efficiencies for coal-fired boilers would be
applied to emission factors for uncontrolled oil-fired boilers. These values
are given in footnotes in the tables which present the calculated emission
factors for each trace metal. Controlled emission factors for oil-fired
boilers are given for both residual and distillate oil.
3.6.1.2 Data Quality for Trace Metal Emission Factors and Areas for
Future Research. The general agreement between measured and calculated
emission factors from several references lends some confidence to the
recommended values. However, they should be considered in light of the high
variability of trace elements in oil (see Section 3.3). Furthermore, the
data base on distillate oil was much less complete than the data base on
3-37
-------
residual oil and coal. For some metals, there were only two or three
available studies reporting their occurrence in distillate oil. The
representativeness of the distillate oil emission factors is, therefore,
somewhat uncertain. This is one area where further research is needed.
Another data gap is the effects of particulate control technologies on
trace metal emissions from oil-fired boilers. As discussed in Section 3.4,
many trace metals are enriched in the small particle fractions of the fly ash
from coal combustion sources. However, oil fly ash has different
characteristics, and whether the volatilization/condensation theories
predicting small particle enrichment are applicable to oil combustion sources
is uncertain (see Section 3.4.1). There is a lack of literature on the form
of trace emissions from oil combustion (vapor or particulate) and on the
association of trace elements with various size fractions of the oil fly ash.
Without this information, the efficiency of particulate control devices at
removing trace metal emissions cannot be calculated. Almost all of the
calculated and measured emission factors reported in previous studies are
uncontrolled. Since most oil-fired sources in the industrial, commercial,
and residential sectors are uncontrolled, this data gap does not pose a
constraint in conducting risk assessments for these sectors. Since some
oil-fired utilities do have control devices, more research into this question
would allow a more accurate risk assessment for the utility sector.
3.6.1.3 Derivation of POM and Formaldehyde Emission Factors. A
qualitative discussion of theories of POM and formaldehyde formation and
behavior during combustion is presented in Section 3.4.3. No methods for
calculating POM and formaldehyde emission factors were found in the
literature reviewed. The emission factors presented in Table 3-59 are
average values derived from test data contained in the literature.
Sections 3.6.10 and 3.6.11 summarize the data available from previous
studies.
3.6.1.4 Data Quality for POM and Formaldehyde Emission Factors and
Areas of Further Research. More test data are available for POM emission
factors from residual oil than from distillate oil. Reported POM emission
factors for both types of oil vary over two orders of magnitude. The data
3-38
-------
show no clear pattern as to whether boiler type, boiler size, combustion
sector, or oil grade influence POM emissions. Part of the observed variation
may be due to variations in sampling and analytical methodology between
studies. There is a need for more research and testing of POM emissions from
oil combustion sources.
Only four measured formaldehyde emission factors were available in the
literature. While these are in fairly close agreement, the scarcity of data
make the representativeness of the recommended emission factor uncertain.
There are not enough data to derive separate formaldehyde emission factors
for residual versus distillate oil.
The effect of particulate control technologies on POM and formaldehyde
emissions is another area lacking data. There are few measurements of POM in
controlled emission streams, and little data on the distribution of POM and
formaldehyde in the vapor versus particulate phases. Theoretically, a large
portion of POM and formaldehyde should be present in vapor form (see
Section 3.4.3) and would therefore escape collection; however, very limited
test data for residual oil-fired sources appears to indicate lower POM
emission factors for controlled versus uncontrolled boilers. Inconsistencies
such as this point out the level of uncertainty and need for research in the
POM emissions area.
3.6.2 Arsenic Emission Factors
Based on a typical residual oil arsenic content of 0.36 ppm, the
recommended uncontrolled arsenic emission factor for residual oil combustion
12
is 19 lb/10 Btu. This is in the middle range of values calculated in five
12
previous studies, which range from less than 0.5 to 42 lb/10 Btu (see
Table 3-60). Eight measured arsenic emission factors from the literature are
shown in Table 3-61. Uncontrolled emission factors reported by two authors
12
range from 4.2 to 37 lb/10 Btu, and are in good agreement with the
12
recommended value of 19 lb/10 Btu. Since levels in fuels were often below
the detection limit, it is not possible to calculate mass balance closure for
the test runs. Leavitt et al. (1979b) reports higher emission factors,
despite the presence of control devices. The reason for this is unknown.
3-39
-------
The recommended distillate oil arsenic emission factor is
4.2 lb/1012 Btu based on a typical level of 0.085 ppm in distillate oil.
This is in good agreement with previously calculated factors of 3.0 and
8.1 lb/1012 Btu from two studies summarized in Table 3-62. Only four
measured values are reported in the literature, ranging from 1.5 to
3.5 lb/1012 Btu (see Table 3-63).
3.6.3 Beryllium Emission Factors
The suggested uncontrolled beryllium emission factor for residual oil is
12
4.2 lb/10 Btu. This is in general agreement with previously calculated
12
values shown in Table 3-64 which range from 0.05 to 5.57 lb/10 Btu. There
is some uncertainty regarding the calculated values reported in the Suprenant
et al. (1980a, 1980b) studies. The reference stated that emission factors
were calculated assuming all beryllium present in the oil feed is emitted;
however, the numbers presented for beryllium levels in oil and corresponding
emission factors do not agree with this statement (see Table 3r64). The
calculated beryllium factors reported by Tyndall et al. (1978), Shih et al.
(1980b), and Anderson (1973) are in closer agreement with the factor
recommended in the current study than are the values reported by Suprenant
et al. (1980a, 1980b).
Measured beryllium emission factors for residual oil combustion vary
12
over three orders of magnitude, from 0.14 to 250 lb/10 Btu, as shown in
Table 3-65. The causes of this variation are uncertain. Since beryllium
contents of many of the fuels were below the detection, limit, mass balance
closure for the test runs cannot be calculated.
The recommended beryllium emission factor for distillate oil is
12
2.5 lb/10 Btu, as shown in Table 3-66. This is higher than that reported
in previous studies by Suprenant et al. (1980a; 1980b); but as explained in
the preceding paragraph and in Table 3-66, there is a discrepancy between the
values Suprenant et al. (1980b) reported for beryllium content of oil and the
corresponding calculated emission factors reported. The values are not
consistent with the assumptions stated in that reference about the
calculation procedures. Three tests of beryllium emissions from distillate
3-40
-------
oil-fired sources are shown in Table 3-67. Measured beryllium emission
12
factors range from 0.52 to 1.2 lb/10 Btu, which are slightly below the
12
recommended value of 2.5 lb/10 Btu, but much higher than the values
previously calculated by Suprenant et al. (1980a, 1980b).
3.6.4 Cadmium Emission Factors
The recommended uncontrolled cadmium emission factor for residual oil
12
combustion sources is 15.7 lb/10 Btu. Table 3-68 compares this factor with
values calculated in six previous studies. It is in general agreement with
values for domestic residual oil combustion calculated by Shih et al.
(1980b) and Anderson (1973). The validity of emission factors calculated in
Suprenant et al. (1980b) is uncertain because the level of cadmium in oil and
corresponding calculated emission factors reported in this study are
inconsistent with the calculation procedures described in the reference.
Measured cadmium-emission factors from previous studies, shown in
12
Table 3-69, range from 0.048 to 212 lb/10 Btu. Values reported by Leavitt
et al. (1978b) are higher than values reported in the other studies despite
the presence of particulate control devices. The causes of the large
variation in measured cadmium emission factors are unknown.
The recommended cadmium emission factor for distillate oil combustion is
12
10.5 lb/10 Btu. This value is similar to previously calculated factors
shown in Table 3-70 and to three measured emission factors of 4.9 to
12
25.6 lb/10 Btu shown in Table 3-71. Cadmium was not detected in a fourth
test. As described in Table 3-70 and in the preceding paragraph, there is
some question as to the method of derivation and validity of the previously
calculated emission factors reported by Suprenant et al. (1980b).
3.6.5 Chromium Emission Factors
Based on a typical chromium level of 0.4 ppm in residual oil, the
12
recommended chromium emission factor is 21 lb/10 Btu. This is in general
agreement with values calculated in four previous studies ranging from 5 to
12
69.7 lb/10 Btu (see Table 3-72). The fifth study, by Suprenant et al.
3-41
-------
(1980b), reported chromium levels in oil of 0.2 to 0.5 ppm, which are similar
to the recommended value of 0.4 ppm; but the same study reported a calculated
emission factor of 116 lb/1012 Btu. This is inconsistent, since it would
mean that more chromium is emitted from the boiler than is contained in the
oil feed.
Measured chromium emission factors shown in Table 3-73 are generally
higher than calculated emission factors. Several references reporting
emissions tests of coal-fired boilers noted that corrosion of the sampling
train components was suspected to occur causing chromium measurements to be
too high (Baig et al., 1981). Since sampling systems used at oil-fired
sources are similar, contamination due to corrosion of the sampling train
components may partially account for the measured values being higher than
the calculated chromium emission factors. Mass balances for some of the
studies indicate more chromium being emitted than is contained in the oil
feed. Another factor is that the chromium content of oil used at some of the
tested facilities (see Table 3-73) is higher than the typical chromium
content of residual oil (0.4 ppm) derived in Section 3,3.4.
The recommended chromium emission factor for distillate oil is
12
47.5 lb/10 Btu. This is based on an assumed chromium content of 0.95 ppm
for distillate oil. The recommended value is slightly lower than values
calculated in two previous studies shown in Table 3-74, (56.0 and
12
83.7 lb/10 Btu). Measured chromium emission factors from six tests
12
summarized in Table 3-75 range from 2.3 to 370 lb/10 Btu, with five of the
12
six tests reporting emission factors below 67.4 lb/10 Btu. Thus, the
measured values generally support the calculated recommended emission factor
of 47.5 lb/1012 Btu.
Recommended emission factors for hexavalent chromium (Cr ) for
distillate and residual oil combustion are given in Tables 3-72 and 3-74.
The factors were derived by applying a ratio of hexavalent chromium to total
chromium emissions to existing emission factors for oil combustion. The
ratio was obtained through testing a coal-fired spreader stoker boiler and
analyzing emissions for both total chromium and hexavalent chromium. In the
data source for these emission factors, no distinction was made concerning
3-42
-------
the types of oil burned. For this report, it was assumed that utility
boilers burned residual oil and other boilers burn distillate oil. All
emission factors are assumed to be for uncontrolled sources.
3.6.6 Copper Emission Factors
The recommended copper emission factor for residual oil combustion is
12
278 lb/10 Btu. This is in the middle range of values calculated in
previous studies. As shown in Table 3-76, previously calculated values range
12
from 5 to 812 lb/10 Btu depending on the assumed copper content of oil.
The measured copper emission factors listed in Table 3-77 vary over a similar
12
range, from 4.6 to 1,100 lb/10 Btu, and are in general agreement with the
calculated values. The copper content of the fuels where tests were
performed do not correlate directly with measured emission rates. In some
cases, mass balances do not exhibit good closure.
The recommended copper emission factor for distillate oil,
12
280 lb/10 Btu, is essentially the same as the recommended value for
residual oil. It is between the distillate oil emission factors calculated
in the two previous studies shown in Table 3-78. Table 3-79 summarizes
measured emission factors. Five of the six reported measured emission
12
factors are less than 63 lb/10 Btu, well below the recommended value;
however, the mass balances for the Castaldini et al. (1981b, 1982) tests do
not close, with only about 10 to 20 percent of the copper that enters in the
oil feed being emitted.
3.6.7 Mercury Emission Factors
The mercury emission factor for residual oil combustion derived in the
12
present study is 3.2 lb/10 Btu. This is in close agreement with previously
12
calculated values shown in Table 3-80, which range from 0.47 to 6.67 lb/10
Btu. Measured mercury emission factors are well below calculated factors,
12
ranging from 0.052 to 1.4 lb/10 Btu. Mercury is volatile and it is
suspected that a substantial portion of mercury present in the vapor phase
3-43
-------
escaped detection. For those test runs on Table 3-81 where mass balances can
be calculated, only about 3 to 20 percent of the mercury entering in the oil
feed was measured in the emissions.
The recommended emission factor for mercury from distillate oil
combustion is 3.0 lb/1012 Btu. This is based on a level of mercury in oil of
0.06 ppm, the same concentration used for residual oil. As described in
Section 3.3.6, only a single value for the mercury content of distillate oil
(0.40 ppm) was recorded in the literature. It was felt that rather than
using a single data point to represent all distillate oil, it would be more
appropriate to use the same mercury concentration for both residual and
distillate oils. This concentration is based on several tests of residual
oils (see Section 3.3.6). As shown in Tables 3-82 and 3-83, the recommended
12
emission factor of 3.0 lb/10 Btu is in close agreement with previously
calculated and measured values reported in Suprenant et al. (1980b, 1979).
Measured mercury emission factors reported by Castaldini et al. (1981b), are
somewhat higher
oil (0.40 ppm).
12
somewhat higher (14-17 lb/10 Btu) due to the higher mercury content of the
3.6.8 Manganese Emission Factors
12
A manganese emission factor of 26 lb/10 Btu is recommended for
residual oil combustion. This is in the middle range of values calculated in
12
five previous studies (2 to 70.6 lb/10 Btu). The values reported in a
sixth study by Suprenant et al. (1980b), shown in Table 3-84. are
inconsistent. The calculated emission factor shows 2 1/2 times more
manganese being emitted than is input to the boiler in the oil feed.
As shown in Table 3-85, measured manganese emission factors are
generally in agreement with the calculated value, ranging from 1.0 to
12 19
66 lb/10 Btu with the exception of one reported value of 200 lb/10 Btu.
Due to imprecise measurements of manganese in the oil feed, mass balance
closures for the test runs cannot be calculated.
The recommended manganese emission factor for distillate oil is
12
14 lb/10 Btu. This is in close agreement with previously calculated values
shown in Table 3-86. Measured emission factors shown in Table 3-87 range
12
from 0.71 to 50 lb/10 Btu, but mass
test runs where it can be calculated.
12
from 0.71 to 50 lb/10 Btu, but mass balance closure is poor for the two
3-44
-------
3.6.9 Nickel Emission Factors
The nickel content of residual oils is relatively high (typically about
12
24 ppm), and the recommended uncontrolled emission factor is 1,260 lb/10
Btu. This value is in agreement with previously reported values of 500 to
12
2,240 lb/10 Btu shown in Table 3-88. Eleven measured emission factors
12
summarized in Table 3-89 range from 74 to 3,600 lb/10 Btu. These are in
general agreement with calculated factors. For some test runs, mass balances
indicate more nickel being emitted than is input in the oil feed. This may
be due to corrosion of sampling train components. Corrosion has been
suggested as a cause of elevated nickel emissions measurements in similar
tests of coal-fired boilers (Baig et al., 1981).
Distillate oil generally contains less nickel than residual oil
12
(typically about 3.4 ppm), and an emission factor of 170 lb/10 Btu is
suggested. This is in the same range as previously calculated nickel emission
factors reported in the literature (see Table 3-90). Measured emission
12
factors reported in Table 3-91 range from 2.7 to 674 lb/10 Btu, but are
generally lower than calculated values. For some tests, this appears to be
due to lower than average nickel content of the oil feed.
3.6.10 POM Emission Factors
In the evaluation and comparison of POM emission factors for oil
combustion, consideration should be given to:
the methods used to take and analyze samples,
the measurement of particulate POM only or of gaseous and
particulate POM,
the physical phase in which emissions predominantly occur,
the number of POM compounds analyzed for, and
the specific POM compounds analyzed for.
The literature contains POM emission factor data that span from the early
1960s to the present. The methods used in the past source tests to sample
and analyze POM compounds from combustion sources have varied considerably
3-45
-------
with respect to sample collection, preservation, preparation, and component
analysis techniques. Because of this variability, it is often difficult to
make valid comparisons of POM emission results because the forms, species,
and sensitivity of measurements may be grossly different between tests even
though both report a total POM result.
One important factor affecting the comparability of results involves
whether the sample collection technique attempted to collect gaseous as well
as particulate POM. Many of the earlier source tests used only a standard
EPA Method 5 sample collection procedure and thus did a less than adequate
job of collecting many POM compounds emitted in gaseous form. More recently,
a Modified Method 5 approach has become popular for combustion source
testing. The Modified Method 5 approach employs a resin filter to trap
condensible organics including POM. Because gaseous POM have been shown to
often be dominant in total combustion source POM emissions, the inclusion of
a gaseous POM collection procedure is important. Knowing the physical forms
of POM sampled for in a test is crucial to being able to compare one test's
results with those of another test of the same or similar source.
In the evaluation and comparison of any total POM emissions data, some
definition must be known or established as to what constitutes total POM. As
discussed, the number of POM compounds that conceivably may be formed during
combustion processes runs into the hundreds. Few, if any, source tests
analyze for that many compounds. The majority of the combustion source POM
emission tests in the literature analyzed for less than 25 specific POM
compounds. The largest number of compounds analyzed for was 56. When one
test analyzed for only 10 POM compounds and one other for 25 POM compounds,
total POM results will not be comparable between the two tests.
In assessing the number of specific POM compounds analyzed, the specific
compounds analyzed for should also be carefully evaluated. In many
combustion source tests for POM emissions, the 25 POM compounds expected to
occur in the largest quantity are analyzed for. Other tests, however,
analyze for POM compounds on the basis of compound toxicity such that several
compounds that may occur in only minute proportions, but are highly toxic,
are analyzed for at the expense of high volume/low toxicity compounds. A
good example of this situation was seen in several tests where naphthalene
3-46
-------
was and was not analyzed for. Naphthalene generally constituted a sizable
portion of total POM emissions in the tests where it was measured. However,
in terms of other POM compounds [e.g., benzo(a)pyrene], it is viewed as
having a low toxicity. Other tests, more concerned with the quantification
of toxic POM emissions from combustion sources, did not include naphthalene
in the list of analyzed compounds and, therefore, had a significantly lower
total POM value than those that did. The exclusion or inclusion of specific
compounds can therefore be highly important in the evaluation and comparison
of POM emissions data.
Despite the problems and considerations outlined above which influence
the ability to define total POM and compare POM results between different
source tests, the summarized oil combustion POM data in Table 3-92 are
presented without regard to differentiating the POM species tested for, the
test methods used, etc. These differentiations were not possible to make
given the work scope and budgetary constraints of the project. The data in
Table 3-92 are presented to illustrate what has been reported in the
literature as total POM emissions from oil combustion. The reader can judge
the level of inconsistency in the summary total POM data (Table 3-92) by
reviewing the constituent individual source test results given in Tables 3-93
and 3-94.
As discussed in Section 3.6.1.3, recommended POM emission factors for
oil combustion are derived from measured emission factors reported in the
literature. There is no reliable method for quantitatively predicting POM
emissions. POM emission factors from tests of fifteen uncontrolled residual
oil-fired boilers in the utility, industrial, and commercial sectors were
available in the literature. As summarized in Table 3-92, the average POM
12
emission factor for these tests is 8.4 lb/10 Btu, with factors for the 15
12
boilers ranging from 0.07 to 77.3 lb/10 Btu. Information on each test is
recorded in Table 3-93. Based on these limited data, boiler type and
combustion sector did not appear to influence POM emission factors
12
significantly. The average factor of 8.4 lb/10 Btu is recommended for use
in risk assessments, and should be applicable to residual oil-fired boilers
in the utility, industrial, and commercial sectors.
3-47
-------
12
As shown in Tables 3-92 and 3-93, a POM emission factor of 5.8 lb/10
Btu was measured at one utility boiler controlled with a cyclone. Polycyclic
organic matter emissions were not detected from another utility boiler
equipped with a cyclone and from two utility boilers equipped with ESPs.
While test results for these four boilers may indicate lower POM emission
factors for boilers equipped with particulate control devices, this is
uncertain since uncontrolled emission factors for the four boilers are not
available for comparison, and the minimum POM detection limit of the sampling
and analysis methodologies for these test runs is unknown. Based on theoret-
ical considerations (see Section 3.4.3) it is believed that a substantial
portion of POM emissions would be present in vapor form in the flue gas and
would escape collection by particulate control devices. More research on the
form of POM in emissions from oil-fired boilers and on the POM emissions
reduction achievable by various control technologies is needed. Based on
currently available information, it is recommended for risk assessment
12
purposes that the same POM emission factor (8.4 lb/10 Btu) be used for POM
emissions from controlled and uncontrolled residual oil-fired boilers.
Measured emission factors for five distillate oil-fired boilers are
available. Specifics of each test are listed in Table 3-94. Three of the
tests were on residential furnaces. A commercial/institutional boiler and an
industrial boiler were also tested. As shown in Tables 3-92 and 3-94, the
average POM emission factor for these five tests is approximately
12
22.5 lb/10 Btu. Emission factors ranged from less than 0.28 for the
12
industrial boiler to 41.2 lb/10 Btu for the commercial boiler. Emission
factors for the residential furnaces ranged from less than 0.33 to less than
12
35.9 lb/10 Btu. Since the data are so limited, and there is no clear
correlation between POM emission factors and boiler or furnace type or
combustion sector, it is recommended that the average emission factor
(22.5 lb/10 Btu) be used for all distillate oil-fired sources.
3.6.11 Formaldehyde Emission Factors
Formaldehyde emission factors are based on emissions testing since there
is no reliable method for calculating quantitative emission factors. Only
four measured emission factors for oil-fired combustion sources were available
3-48
-------
in the literature. These are summarized in Table 3-95. Reported emission
12
factors ranged from 160 to 640 lb/10 Btu, with the average value being
12
405 lb/10 Btu. It is recommended that this average emission factor be
applied to all boilers and furnaces fired with residual or distillate oil.
Additional emissions testing is needed to broaden the data base for
formaldehyde and to allow analysis of the effects of oil type, boiler design,
and boiler size on formaldehyde emissions.
3.6.12 Lead Emission Factors
Emission factors for lead from oil combustion were taken from an EPA
background document supporting the national ambient air quality standard
(NAAQS) for lead (U. S. Environmental Protection Agency, 1985). In that
document, emission factors for distillate and residual oil combustion were
presented, based on the concentration of lead in oil (either distillate or
residual) and the assumption that 50 percent of the lead in the fuel is
emitted to the atmosphere. Separate emission factors for boiler types by
sector of boiler use were not included in this reference. Therefore, it was
assumed that utility boilers burned residual oil and all other sectors burned
distillate oil. All emission factors assume emissions are uncontrolled.
Heating values of 150,000 Btu/gal and 141,000 Btu/gallon were used for
residual and distillate oil, respectively. Based on these data, the
uncontrolled emission factor for lead from utility oil combustion is
12
28 lb/10 Btu. The uncontrolled emission factor for industrial, commercial,
and residential boilers is 8.9 lb/1012 Btu.
3.7 EMISSION FACTORS FOR COAL-FIRED COMBUSTION SOURCES
Emission factors for coal-fired sources are derived from a combination
of measured data and calculated emission factors. The literature was
reviewed for test data from which trace element emission factors (in terms of
12
pounds emitted per 10 Btu of coal input) could be derived. About 35
references reported measured emission factors for one or more of the trace
pollutants and types of combustion sources under study. Procedures for
3-49
-------
calculating trace element emissions were also reviewed. The utility and
industrial sectors are the best characterized combustions sectors, while
relatively few test data are available for the commercial/institutional and
residential sectors. Trace metal and POM emissions are considerably better
characterized in the literature than radionuclide and formaldehyde emissions.
Section 3.7.1 presents and discusses measured and calculated trace metal
emission factors. Section 3.7.2 describes radionuclide emission factors, and
Section 3.7.3 characterizes POM and formaldehyde emission factors. Limited
emission factor estimates for lead from coal combustion are given in
Section 3.7.4. The consideration of lead as a trace pollutant from coal and
oil combustion was added to this project by EPA after the submittal of the
draft final report. For this reason, the treatment of lead, including the
availability of emission factor data, is very abbreviated compared to the
other trace pollutants in the document. Only a limited number of the
references listed in the report bibliography in Appendix C were evaluated for
lead data. It is acknowledged that this approach does not provide for a
thorough analysis of lead; however, the approach is sufficient to achieve the
objectives of this study.
The trace pollutant emission factors presented for coal combustion
should be viewed as realistic average estimates based on the available data.
It should be recognized that there is considerable uncertainty in these
estimates due to the wide variability in trace element levels in coal (see
Section 3.3), variations in the design and operating parameters of boilers
and control devices, and uncertainty in sampling and analytical methodologies
for detecting trace pollutants.
Also, it may be difficult to compare emission factors for different
control technologies for a given trace element because of the limited data.
In some cases, only a single test result was available from which to report
an emission factor for a particular boiler type/control technique pair (see
summary tables, e.g., Table 3-100). Thus, some values reported in the
summary tables may seem incongruous, when actually, they reflect the data
available in the literature.
3-50
-------
3.7.1 Trace Metal Emission Factors
In general, the sources of data and procedures for deriving emission
factors are similar for the nine trace metals under study. Section 3.7.1.1
through 3.7.1.8 present emission factors for eight of the trace metals from
the utility, industrial, and commercial/institutional combustion sectors.
Factors for lead emissions are presented in Section 3.7.4. Recommended
emission factors are presented and compared with previously measured and
calculated values. Due to the relatively greater availability of test data
for bituminous coal-fired utility and industrial boilers, recommended
emission factors for bituminous coal combustion can generally be derived from
test data. The data indicate that for similar types of boilers and control
devices, emission factors between the utility and industrial sectors are
similar. There is a lack of data on trace metal emissions for the
commercial/ institutional sector. However, the boilers used in this sector
are similar in size and design to the smaller industrial boilers. Therefore,
emission factors for commercial/institutional boilers can be derived from
information on the other combustion sectors. There is also a lack of data on
lignite and anthracite combustion, so emission factors for these types of
coal must be calculated.
Trace metal emission factors for coal-fired residential furnaces are
described in Section 3.7.1.9. A calculation procedure based on the trace
metal content of coal and on partitioning data from a limited number of tests
of residential furnaces is used to derive emission factors for each of the
trace metals (excluding lead). The recommended emission factors for each
trace metal are compared with previously reported emission factors.
3.7.1.1 Arsenic Emission Factors for Coal-Fired Boilers. Table 3-96
presents arsenic emission factors recommended for use in risk assessments for
utility, industrial, and commercial/institutional boilers. Where possible,
these were derived from emissions tests at representative boilers. The data
base is summarized in Tables 3-97 through 3-102. For each sector/coal type/
boiler design/control technology combination, the average arsenic emission
factor and range of emission factors found in the literature are presented.
3-51
-------
The number of boilers and number of test runs from which these averages are
derived are also included in the tables. More detailed information on each
test, including the test references, are included in Appendix E, Tables E-l
through E-9.
Bituminous Coal-Fired Pulverized Dry Bottom Boilers
The recommended arsenic emission factor for uncontrolled pulverized dry
1 9
bottom boilers is 684 lb/10 Btu. This is the average emission factor for
tests of uncontrolled emissions from five utility boilers reported in the
literature (see Table 3-97). This factor is in agreement with the emission
12
factor of 690 lb/10 Btu measured at one uncontrolled industrial pulverized
dry bottom boiler in the data base (Table 3-98). It is also in general
agreement with the previously calculated emission factors shown in
Table 3-103. The only commercial/institutional boiler of this description
tested had a higher emission factor (Table 3-102). The level of arsenic in
the coal was not reported for that test, and the causes of the higher
emissions measurement could not be determined. In the absence of more data,
12
the 684 lb/10 Btu emission factor will be applied to uncontrolled
pulverized dry bottom boilers in all sectors.
Only three pulverized dry bottom boilers with mechanical precipitators
(multiclones) were tested - two utility and one industrial boiler (see
Tables 3-97 and 3-100). A meaningful average cannot be derived from these
tests. One boiler tested had extremely low arsenic emissions (19 to
12
49 lb/10 Btu) and the other two had arsenic emissions which were higher
12
than any of the uncontrolled boilers tested (over 1000 lb/10 Btu). The
industrial boiler which had the highest emission factor was burning high
arsenic coal (137 ppm as opposed to an average of 20.3 ppm for bituminous
coal). However, the two utility boilers were burning coal of similar arsenic
content (13-19 ppm). It is uncertain whether boiler and control design and
operating parameters, sampling methodology, or both, account for the
discrepancy.
Since the data are limited and inconsistent, the recommended emission
factor for bituminous coal-fired pulverized dry bottom boilers was derived by
applying a control percentage to the uncontrolled emission factor. As shown
3-52
-------
on Table 3-104, testing of a mechanical precipitator on a combustion source
showed an average control efficiency of 51 percent. This control efficiency
is consistent with theory. For overall particulate control, multiclones can
achieve greater efficiencies (Shih et al. (1980b) estimated 70.2 percent),
but they are less efficient at controlling smaller particles, and arsenic is
enriched on small fly ash particles. Applying the 51 percent control factor
12
to the uncontrolled emission factor of 684 lb/10 Btu, a recommended
12
emission factor of 335 lb/10 Btu is obtained for pulverized dry bottom
boilers controlled with mechanical precipitators.
The recommended emission factor for ESP-controlled pulverized dry bottom
12
boilers, 40.1 lb/10 Btu, is an average of 37 tests run on 15 utility
boilers (Table 3-97). Tests of industrial boilers (Table 3-100) yield a
similar average. The scrubber controlled emission factor is
12
17.2 lb/10 Btu, based on six tests of four utility boilers. These emission
factors are in agreement with previously calculated values shown in
Table 3-103.
Bituminous Coal-Fired Pulverized Wet Bottom Boilers
Data from five boilers show that the average emission factor for ESP-
12
controlled pulverized wet bottom boilers is 168 lb/10 Btu. There is a lack
of data for pulverized wet bottom boilers controlled by other means. The
percent arsenic control efficiencies of ESPs and multiclones measured in the
literature are presented in Table 3-104. Using these control efficiencies
12
and the 168 lb/10 Btu factor for ESP- controlled boilers, the uncontrolled
12
emission factor would be 1,340 lb/10 Btu and the mechanical precipitator-
12
(or multiclone-) controlled emission factor would be 658 lb/10 Btu.
Calculations support these factors. If all of the arsenic in typical
bituminous coal (20.3 ppm) were emitted during combustion, the maximum
12
uncontrolled emission factor would be 1,560 lb/10 Btu, assuming a heat
content of 13,077 Btu/lb. If arsenic was emitted in the same proportion as
12
total particulates, an uncontrolled emission factor of 1,010 lb/10 Btu
would be expected. This assumes 65 percent of the ash is emitted as fly ash
(Baig et al., 1981). Since arsenic is preferentially concentrated in the fly
ash, an emission factor between these two values would be expected.
3-53
-------
Bituminous Coal-Fired Cyclone Boilers
12
Cyclone boilers controlled with ESPs emit an average of 14.4 lb/10
Btu. The lower emission factor for cyclone boilers as opposed to pulverized
coal boilers is consistent with previously calculated values and with theory.
Cyclone boilers emit a lower proportion of fly ash versus bottom ash than do
pulverized coal-fired boilers. The recommended uncontrolled emission factors
12
are presented as a range (from 115 to 310 lb/10 Btu). Assuming an arsenic
control efficiency of 87.5 percent for ESPs, the uncontrolled emission factor
12 12
corresponding to 14.4 lb/10 Btu would be 115 lb/10 Btu; however, limited
test data and calculations suggest a slightly higher value. The average
12
uncontrolled factor for one boiler tested is 310 lb/10 Btu. Calculations
12
show a minimum uncontrolled emission factor of 210 lb/10 Btu for cyclone
boilers. This calculation assumes arsenic is emitted in the same proportion
as total particulates (13.5 percent of total ash is emitted as fly ash
(Baig et al., 1981)). It also assumes that the typical arsenic content of
bituminous coal is 20.3 ppm, and that the heating value is 13,077 Btu/lb. In
reality, arsenic is concentrated in the fly ash, so a somewhat higher
emission factor would be expected.
Mechanical precipitators, which reduce arsenic emissions by about
51 percent, would produce emission factors for bituminous coal-fired cyclone
boilers of between 56 and 152 lb/1012 Btu.
The only value reported for a cyclone boiler controlled by a scrubber
(see Table 3-97) is much higher than ESP-controlled or uncontrolled emission
factors and is inconsistent with theory. There is not enough information to
derive a reliable emission factor for coal-fired cyclone boilers controlled
with scrubbers.
Bituminous Coal-Fired Stoker Boilers
The most complete data on stoker boilers are for the industrial sector.
Fourteen tests of seven industrial spreader stokers and five tests of four
overfeed stokers are summarized in Tables 3-100 and E-7. It is uncertain
whether these two types of stokers should be combined in determining an
average emission factor. The range and average measured emission factors are
lower for the spreader stokers than for the overfeed stokers (averages of 264
3-54
-------
12
versus 1,030 lb/10 Btu, respectively). Weighting all eleven boilers
12
equally, regardless of type, the average emission factor of 542 lb/10 Btu
can be derived for all industrial stoker boilers.
Recommended emission factors for spreader stokers in Table 3-96 are
presented as a range, with the average for spreader stokers at the lower end
of the range and the average for all stokers at the upper end. One of the
utility boilers tested (Table 3-97) falls within this range, the other can be
excluded as an outlier. Applying the control percentages in Table 3-104 to
either end of this range, the recommended emission factors for spreader
12
stokers controlled with multiclones would range from 129 to 265 lb/10 Btu,
12
and for ESPs would range from 33 to 67 lb/10 Btu. These ranges are in
general agreement with the limited test data on controlled spreader stokers
presented in Table 3-100.
For uncontrolled overfeed stokers the recommended range of emission
12
factors is 542 lb/10 Btu (the mean for all stokers tested) to
12
1,030 lb/10 Btu (the mean for overfeed stokers tested). Controlled
emission factors, based on the control efficiencies in Table 3-104, would be
12
265 to 505 lb/10 Btu for multiclone-controlled overfeed stokers and 67 to
12
129 lb/10 Btu for ESP-controlled overfeed stokers.
Based on limited data, about 60 percent of the total ash from stoker
boilers fired with bituminous coal is emitted as fly ash (Baig et al., 1981).
The type of stoker is not specified. This would lead to a minimum calculated
12
arsenic emission rate of 930 lb/10 Btu if arsenic were distributed equally
between fly ash and bottom ash. This calculation does not account for the
enrichment of arsenic on fly ash, which would have the effect of raising the
emission factor. It is uncertain why measured emission factors for spreader
stokers are generally below this calculated value. Further research on the
behavior of coal ash and trace elements in the various types of stoker
boilers is needed to better characterize trace element emissions from stoker
boilers.
Subbituminous Coal-Fired Boilers
Recommended emission factors for subbituminous coal-fired boilers were
not calculated. There is a lack of test data, and much of the available
information does not distinguish between bituminous and subbituminous coals.
3-55
-------
Tables 3-98 and 3-101 summarize the data on emission factors for subbituminous
coal which are available in the literature.
Lignite Coal-Fired Boilers
The only data on lignite coal-fired boilers are for the utility sector
and are presented in Tables 3-99 and E-6. Since there are only one or two
tests of each boiler type/control device combination, representative emission
factors cannot be derived from the test data. The assumption can be made
that the main cause of variability between similar boilers firing bituminous
and lignite coal would be the different average arsenic content of the two
types of coal. Making this assumption, emission factors for lignite
combustion can be calculated from the recommended emission factors for
bituminous combustion by applying a ratio to account for the higher average
arsenic content of lignite coal (22.8 versus 20.3 ppm) and for the difference
in heating values (7,194 Btu/lb for lignite versus 13,077 Btu/lb for
bituminous). Recommended emission factors calculated in this manner are
presented in Table 3-96. There are inadequate data to determine whether
burning lignite as opposed to bituminous coal results in any differences in
the proportion of fly ash to bottom ash generated, or in the characteristics
of the fly ash, or trace element enrichment behavior, so these types of
considerations were not incorporated into the calculations. As can be seen
by comparing the recommended emission factors in Table 3-96 with the test
data for lignite combustion summarized in Table 3-99, there is general
agreement between the two sets of factors.
Anthracite Coal-Fired Boilers
The only data for anthracite combustion is testing of three commercial/
institutional stoker boilers summarized in Table 3-102. Recommended emission
factors for anthracite combustion can be calculated from recommended
bituminous coal factors by applying a ratio to account for the different
arsenic content of the two types of coal (7.67 ppm for anthracite and
20.3 ppm for bituminous) and for the different heat contents (12,700 for
anthracite versus 13,077 for bituminous). These calculated values are shown
3-56
-------
in Table 3-96. The measured arsenic emission factor for uncontrolled stoker
12
boilers (137 lb/10 Btu) is in good agreement with the calculated values for
spreader stokers (103-210 lb/1012 Btu).
3.7.1.2 Beryllium Emission Factors for Coal-Fired Boilers. Table 3-105
presents beryllium emission factors recommended for use in risk assessments
for utility, industrial, and commercial/institutional boilers. Where possible
these were derived from emissions test data. The data base is summarized in
Tables 3-106 through 3-111. Ranges and average measured emission factors
along with the number of boilers tested and the number of test runs are
presented for each combination of sector, coal type, boiler design, and
control technology. More detailed information on individual tests, including
references, is presented in Appendix E (Tables E-ll through E-19).
Bituminous Coal-fired Pulverized Dry Bottom Boilers
The recommended emission factor for uncontrolled pulverized dry bottom
12
boilers fired with bituminous coal is 81 lb/10 Btu. As shown on
Table 3-106, this is the average of seventeen tests of four utility boilers.
This is in agreement with previously calculated values shown in Table 3-112.
One industrial and one commercial boiler were also tested. The measured
emission factor for the industrial boiler was lower than for any of the
utility boilers tested, and the commercial boiler was higher than any of the
utility boilers (see Tables 3-109 and 3-111). However, since these are only
single data points, it is believed that the recommended average emission
12
factor of 81 lb/10 Btu for utility boilers is more representative of
emissions from boilers in all three sectors.
There are insufficient data to derive a meaningful average emission
factor for multiclone-controlled pulverized dry bottom boilers. Although the
coals for the two utility boilers tested contained the same amount of
beryllium (1.4 to 1.7 ppm for both boilers), emission factors for one boiler
12 12
averaged 52 lb/10 Btu, and for the other boiler averaged 154 lb/10 Btu.
12
A recommended emission factor of 51 lb/10 Btu was calculated by applying a
control efficiency of 37 percent to the uncontrolled emission factor of
3-57
-------
81 lb/1012 Btu. This control efficiency is specific to beryllium, and was
determined from tests of control device efficiency found in the data base
(see Table 3-113).
The recommended emission factor for ESP-controlled pulverized dry bottom
boilers is 3.0 lb/1012 Btu. This is an average of tests of 12 utility
boilers and five industrial boilers, with each boiler weighted equally. Only
12
one boiler with a scrubber was tested and it was found to emit 0.11 lb/10
Btu (see Table 3-106).
Bituminous Coal-Fired Pulverized Wet Bottom Boilers
Tests of five ESP-controlled pulverized wet bottom boilers yielded an
12
average emission factor of 3.5 lb/10 Btu. Data are lacking on uncontrolled
wet bottom boilers and boilers controlled by other technologies. Since the
measured ESP-controlled emission factors for pulverized wet bottom and dry
bottom boilers are the same, it is recommended that the emission factors
developed for dry bottom boilers may also be applied to wet bottom boilers.
Bituminous Coal-Fired Cyclone Boilers
The average measured emission factor for four cyclone boilers controlled
12
with ESPs is 0.52 lb/10 Btu. The lower emission factor for cyclone boilers
in contrast to pulverized coal-fired boilers is consistent with previously
calculated emission factors and may be explained by the fact that cyclone
boilers emit less fly ash than pulverized coal-fired boilers (Baig et al.,
1981).
There are no emissions tests of uncontrolled cyclone boilers or of
multiclone-controlled cyclone boilers in the literature. The emission
factors for pulverized coal-fired boilers may be used as an upper estimate of
beryllium emissions from cyclone boilers. In reality, emissions may be
somewhat lower because less fly ash is emitted, but the volatilization/
condensation behavior of beryllium has not been well enough characterized to
calculate a precise emission factor for cyclone boilers.
Bituminous Coal-Fired Stoker Boilers
Several tests of industrial boilers (summarized in Table 3-109) were
used to characterize bituminous coal-fired stoker boiler emissions. For
eleven uncontrolled stoker boilers (four overfeed and seven spreader stokers)
3-58
-------
the average beryllium emission factor, weighting each boiler equally, is
12
73 lb/10 Btu. Two utility, two industrial, and one commercial spreader
stoker controlled with multiclones were tested (see Tables 3-106, 3-109, and
12
3-111). The average emission factor for these five boilers is 9.8 lb/10
12
Btu. This is lower than the value of 46 lb/10 Btu which may be calculated
by applying a beryllium control efficiency of 37 percent (see Table 3-113) to
the recommended uncontrolled emission factor for stoker boilers. The
recommended emission factor for multiclone-controlled stokers is therefore
12
presented as a range, from 9.8 to 46 lb/10 Btu.
Assuming a control efficiency of 91.9 percent (Table 3-113), the
12
emission factor for ESP-controlled stokers would be 5.9 lb/10 Btu.
Subbituminous Coal-Fired Boilers
Much of the literature does not distinguish between bituminous and
subbituminous coals. Due to a lack of data, recommended emission factors
specific to subbituminous coal are not presented. Measured emission factors
for subbituminous coal combustion available in the literature are summarized
in Tables 3-107 and 3-110, and in Appendix E.
Lignite and Anthracite Coal-Fired Boilers
Data on lignite-fired boilers are limited. Table 3-107 summarizes the
measured emission factors found in the literature. The only measured
emission factors available for anthracite coal are from tests of three
commercial/institutional stokers. These are summarized in Table 3-110.
Due to the lack of data, recommended beryllium emission factors for
lignite and anthracite coal were calculated from the factors recommended for
bituminous coal. These were proportioned to account for the differences in
beryllium content and heating values of the three coals. From Table 3-8, the
average beryllium content of bituminous coal is 2.22 ppm, the average
beryllium content of lignite is 1.98 ppm, and that of anthracite is 1.32 ppm.
Heating values for the three coals are 13,077 Btu/lb for bituminous, 7,194
for lignite, and 12,700 for anthracite. The factors determined by this
procedure are given in Table 3-105. Emission factors calculated for lignite
are somewhat higher than bituminous coal emission factors, and emission
factors for anthracite are lower.
3-59
-------
3.7.1.3 Cadmium Emissions from Coal-Fired Boilers. Table 3-114
contains typical emission factors for cadmium derived from the data and
information available in the literature. These emission factors may be used
in risk assessments of the utility, industrial, and commercial/institutional
combustion sectors. The data base is summarized in Tables 3-115 through
3-120. For each sector/coal type/boiler design/control device combination,
the number of boilers tested, the number of test runs made, and the average
and range of emission factors measured are reported. A summary of each test,
including references, is contained in Appendix E, Tables E-20 through E-29.
Bituminous Coal-Fired Pulverized Dry Bottom Boilers
Pulverized dry bottom boilers in the utility, industrial, and
commercial/institutional sectors have been tested. Results are summarized in
Tables 3-115, 3-118, and 3-120. The results of the industrial boiler test
were excluded because the mass balance suggested more cadmium being emitted
than was input to the boiler. Testing of five uncontrolled utility boilers
12
yielded an average cadmium emission factor of 44.4 lb/10 Btu. This is in
agreement with previously calculated values shown in Table 3-121. Using the
average cadmium content of bituminous coal (0.91 ppm). the predicted cadmium
12
emissions would be between 55 and 70 lb/10 Btu. The lower value assumes
80 percent of the total ash generated is emitted as fly ash (Baig et al.,
1981) and that cadmium is emitted in the same proportion as total particu-
lates. The upper value assumes all cadmium present in the coal feed is
emitted. Since cadmium is enriched in the fly ash, the actual value should
be between the two. Since calculated and measured values are in close
12
agreement, the measured value (44.4 lb/10 Btu) may be viewed as a typical
cadmium emission factor for uncontrolled pulverized dry bottom boilers.
However, as noted in Section 3.3, some coals from the Interior region have
much higher than average cadmium contents, which would result in higher
cadmium emissions.
Only three sources with multiclones were tested, one of which had
relatively low emissions, while the other two had extremely high emissions.
A meaningful average cannot be derived from these tests. The recommended
emission factor shown on Table 3-114 was derived from the recommended
3-60
-------
12
uncontrolled emission factor (44.4 lb/10 Btu) by assuming multiclones are
28.9 percent efficient for cadmium control. This efficiency for cadmium was
derived from test data at the inlet and outlet of a multiclone applied to a
combustion source (see Table 3-122). The multiclone-controlled emission
12
factor calculated by this method is 31.6 lb/10 Btu.
The ranges of measured cadmium emission factors for utility and
industrial pulverized dry bottom boilers were similar, but the average for
industrial boilers was somewhat higher. The data are summarized in
Tables 3-115 and 3-118. The cadmium control efficiencies for the ESPs in the
data base also varied greatly (see Table 3-122). For this reason, the
recommended emission factor is expressed as a range, with the average utility
12
boiler emission factor (5.0 lb/10 Btu) being the low end of the range and
12
the average industrial boiler factor (20 lb/10 Btu) being the high end. An
average of all 18 utility and industrial boilers yields a cadmium emission
factor of 9.2 lb/1012 Btu.
A utility boiler and a commercial/institutional boiler, both controlled
with scrubbers, were tested and found to have cadmium emissions of 1.6 and
12
0.35 lb/10 Btu, respectively. These measurements were used to derive the
range of recommended cadmium factors shown in Table 3-114.
Bituminous Coal-Fired Pulverized Wet Bottom Boilers
Based on tests of five boilers, ESP-controlled wet bottom boilers may
emit less cadmium than ESP controlled dry bottom boilers as shown in
Table 3-115. The cadmium contents of the coals burned during these tests
were not reported. Based on these tests, the recommended emission factor for
12
ESP-controlled pulverized wet bottom boilers is 1.4 lb/10 Btu.
Since no tests of uncontrolled or multiclone-controlled wet bottom
boilers were reported in the literature, emission factors were calculated
based on cadmium levels in coal. Based on an average cadmium content of
0.91 ppm for bituminous coal, uncontrolled cadmium emissions would range from
12
45 to 70 lb/10 Btu. The lower end of this range assumes that 65 percent of
total ash is emitted as fly ash (Baig et al., 1981) and that cadmium is
emitted in the same proportion as total particulates. The upper end of the
3-61
-------
range assumes all cadmium present in the coal feed is emitted. Since cadmium
is preferentially concentrated in the fly ash, the actual value should be
between these two.
The range of emission factors for multiclone-controlled boilers is
derived from the uncontrolled emission factors by assuming 28.9 percent
cadmium control (see Table 3-122).
Bituminous Coal-Fired Cyclone Boilers
Based on the testing of five sources, average cadmium emissions for
bituminous coal-fired cyclone boilers controlled by ESPs are estimated to be
12
1.3 lb/10 Btu. The lower cadmium emissions for cyclone boilers versus
pulverized coal-fired boilers may be due to the fact that less fly ash is
emitted from cyclone boilers (Baig et al., 1981).
12
The only uncontrolled boiler tested emitted 28 lb/10 Btu. This is the
recommended emission factor shown in Table 3-114. It is supported by
calculations. Calculated values, which range from a minimum of 9.4 to a
12
maximum of 70 lb/10 Btu, support this recommended value. The minimum
factor is calculated assuming cadmium is emitted in the same proportion as
total particulates and that 13.5 percent of the total ash is emitted as fly
ash (Baig et al, 1981). The maximum value is calculated assuming all cadmium
in the coal is emitted. The actual value should fall between these two
extremes.
Assuming multiclones have a cadmium removal efficiency of 28.9 percent
Le 3-122), the average emission factor of 20
for cyclone boilers controlled with multiclones.
(Table 3-122), the average emission factor of 20 lb/10 Btu can be derived
Bituminous Coal-Fired Stoker Boilers
Test results for eleven uncontrolled industrial stoker boilers were
identified. Although the ranges of measured emission factors overlap, the
average cadmium emission factor for the overfeed stokers was higher than the
average for spreader stokers (see Table 3-118). The combined average for all
eleven stokers (both spreader and overfeed) is 43 lb/1012 Btu. Recommended
typical emission factors are presented as a range. Fpr spreader stokers, the
12
range is from 21 lb/10 Btu (the average for seven spreader stokers tested)
3-62
-------
12
to 43 lb/10 Btu (the average for all stokers). For overfeed stokers the
range is 43 lb/1012 Btu to 82 lb/1012 Btu (82 lb/1012 Btu is the average
emission factor for the four overfeed stokers tested). The average emission
12
factor for multiclone-controlled spreader stokers is 6.6 lb/10 Btu based on
tests of two utility boilers, two industrial boilers, and one commercial
boiler. This factor is somewhat lower than expected. Based on average
12
uncontrolled emissions of 21 lb/10 Btu and a control efficiency of
28.9 percent for multiclones (Table 3-122), the calculated emission factor
12
would be between 15 and 30 lb/10 Btu. The recommended emission factor is,
12
therefore, presented as a range from 6.6 to 30 lb/10 Btu.
There is a lack of test data on multiclone-controlled overfeed stokers.
Based on uncontrolled emission factors and 28.9 percent cadmium control, the
range of cadmium emission factors for multiclone-controlled overfeed stokers
would be 30 to 58 lb/1012 Btu.
Assuming ESPs result in 74.6 percent cadmium emissions control (see
Table 3-22), typical cadmium emission factors for ESP-controlled spreader
12
stokers would range from 5.3 to 11 lb/10 Btu. This is in agreement with
the measured emission factor for an ESP-controlled spreader stoker fired with
subbituminous coal shown in Table 3-119. The calculated emission factor for
12
overfeed stokers controlled with ESPs ranges from 11 to 21 lb/10 Btu.
Subbituminous Coal-Fired Boilers
The available emission factor data for subbituminous coal-fired boilers
are presented in Tables 3-116 and 3-119. There are insufficient data to
derive recommended emission factors. In the literature, subbituminous coal
often is not differentiated from bituminous coal. As discussed in
Section 3.3, the average cadmium content of subbituminous coal is less than
the average cadmium content of bituminous coals, so emission factors for
subbituminous coal combustion would generally be expected to be below the
emission factors for bituminous coal. The coal feed for the utility cyclone
boiler test summarized in Table 3-116 had an abnormally high cadmium level
(24 ppm versus an average of 0.38 ppm) which may account for the large
measured cadmium emission factors.
3-63
-------
Lignite and Anthracite Coal-Fired Boilers
All available cadmium test data for lignite coal-fired boilers are
summarized in Table 3-117. The available data for anthracite coal-fired
boilers are presented in Table 3-120. Since there are not enough measured
data to characterize emissions from lignite and anthracite combustion,
typical emission factors are calculated from the recommended bituminous coal
emission factors. For these calculations, it is assumed that for similar
boiler designs and control techniques, the main difference in emissions is
due to the cadmium content of the three types of coal. Based on typical
cadmium contents of the three coals shown in Table 3-13 and heating values in
Appendix D, cadmium emission factors for lignite coals would be higher than
those for bituminous coal by a factor of 1.10. Anthracite coal emission
factors would be lower by a factor of 0.249. The calculated recommended
emission factors for anthracite and lignite coals are presented in
Table 3-114. The measured cadmium emission factors for lignite-fired boilers
shown in Table 3-117 are generally similar to the calculated emission
factors.
3.7.1.4 Chromium Emission Factors for Coal-Fired Boilers. Table 3-123
shows recommended chromium emission factors for boilers in the utility,
industrial, and commercial/institutional sectors. These values are
calculated from the average chromium content of bituminous, lignite, and
anthracite coal. Maximum and minimum uncontrolled emission factors are
calculated using the equations:
EF - C/H x 106, and
max '
EFmin " WW x 10
12
Where: EF - emission factor (lb/10 Btu)
C - concentration of chromium in coal (ppm)
H - heating value of coal (Btu/lb)
f - fraction of coal ash emitted as fly ash
The minimum value assumes that chromium is emitted in the same proportion as
total particulates. The maximum emission factor assumes all chromium in the
coal feed is emitted. The values substituted into the equations are shown in
3-64
-------
Tables 3-124 and 3-125. As described in Section 3.4, some studies have shown
enrichment of chromium in the fly ash. If this occurs, the actual emission
factor would be between the minimum and maximum calculated values. Observed
enrichment behavior varies between studies and may be a function of coal
type, boiler design, and control technology. In general, there are not
enough data to develop reliable quantitative enrichment ratios. Therefore,
chromium emission factors cannot be calculated precisely and are expressed as
a range.
Controlled emission factors are calculated from the uncontrolled
emission factors using the control percentages in Table 3-126. These were
derived from measurements of control device efficiency for chromium reported
in the literature reviewed. Tests where the mass balance around the control
device was clearly in error were excluded from the calculations of typical
chromium control efficiencies.
Measured chromium emission factors are summarized in Tables 3-127
through 3-132 and in Appendix E (Tables E-30 through E-39). In general, the
measured values are much higher than the maximum calculated values. The
discrepancy is probably due to corrosion of the sampling train components,
which would result in artificially high measured chromium emission factors
(Baig et al., 1981). For all boilers where chromium content of the coal was
reported, the coal contained between 10 and 40 ppm chromium, with most tests
being near the average value for bituminous coal (20.5 ppm). Therefore, high
measured chromium emission factors were not caused by the combustion of high-
chromium coals. Some references do not contain enough information to perform
mass balance calculations; however, mass balances for several of the boilers
indicate more chromium being emitted than was present in the coal feed.
Corrosion of sampling train components would explain these results. Since
measured chromium emission factors appear to be unreliable, it is suggested
that the calculated values be used in risk assessments.
A few emission factors were available for estimating the emissions of
hexavalent chromium from coal-fired boilers. The data were based on test
results of a pulverized coal boiler (fabric filter control) and a
spreader-stoker boiler controlled by two mechanical collectors in series
(Ajar and Cuffe, 1985). For utility boilers and industrial boilers, the
3-65
-------
measured emission factors were used (Tables 3-123, 3-126, 3-127, 3-130, and
3-133). For commercial boilers, the ratio of hexavalent chromium to total
chromium emissions (obtained from the test results) were applied to an
existing total chromium emission factor. These emission factors represent a
limited number of actual data points, but are presented to provide the most
data possible.
3.7.1.5 Copper Emission Factors for Coal-Fired Boilers. Table 3-134
presents recommended copper emission factors applicable to utility,
industrial, and commercial/institutional boilers. Where possible, these were
derived from emissions test data. Tables 3-135 through 3-140 summarize
measured emission factors reported in the literature. For each combination
of combustion sector/coal type/boiler design/control technology, the range
and average emission factors are presented. The number of boilers tested and
number of test runs are also included on the tables. Information on each
copper emissions test, including references, are contained in Appendix E,
Tables E-40 through E-49.
Bituminous Coal-Fired Pulverized Drv Bottom Boilers
Seven uncontrolled pulverized dry bottom boilers were tested: 5 utility
boilers, 1 industrial boiler, and 1 commercial boiler. Results are summarized
in Tables 3-135, 3-138, and 3-140. The industrial boiler had a higher copper
emission factor than any of the other boilers, probably due to the fact that
the coal it consumed had more than twice the average copper content of
bituminous coals. The average emission factor for the other six boilers is
12
848 lb/10 Btu. Emission factors calculated in other prior studies and
presented in Table 3-141 are higher than this measured value; however, the
data base for the current study indicates that previous calculations were
based on overly conservative (high) estimates of copper content in coal.
Bituminous coal contains an average of 17.8 ppm copper (see Section 3.3).
Assuming all copper in the coal feed is emitted, the maximum emission factor
for a boiler burning typical coal would be 1,360 lb/1012 Btu. Since not all
copper would be emitted, this calculated value is in fair agreement with the
average measured emission factor of 848 lb/1012 Btu.
3-66
-------
A meaningful average emission factor could not be derived from the three
data points on pulverized dry bottom boilers controlled with multiclones.
12
Testing of one boiler reported relatively low emissions (210-290 lb/10 Btu)
while tests of the other two showed emission factors greater than those for
any of the uncontrolled boilers. The coal consumed in one of these boilers
had four times the average copper concentration. Since a representative
average could not be derived from test data, the recommended emission factor
shown in Table 3-134 was calculated from the recommended uncontrolled emission
factor. Based on test data summarized in Table 3-142, it was assumed that
multiclones are 40.7 percent efficient for copper removal. The calculated
emission factor for pulverized dry bottom boilers controlled with multiclones
is 503 lb/1012 Btu.
Nine pulverized dry bottom boilers controlled with ESPs have been tested
(see Tables 3-135 and 3-138). There is good agreement between measurements
at utility and industrial boilers. The average emission factor, weighting
12
each boiler equally, is 194 lb/10 Btu. Four boilers controlled with
scrubbers in the utility, industrial, and commercial sectors have been
tested. From these tests, the recommended average copper emission factor is
12
24 lb/10 Btu for scrubber-controlled units.
Bituminous Coal-Fired Pulverized Wet Bottom Boilers
Testing of five pulverized wet bottom boilers controlled with ESPs
12
resulted in an average copper emission factor of 86 lb/10 Btu, as shown in
Table 3-135. This factor is somewhat lower than that for pulverized dry
bottom boilers. This may be due to different levels of copper in the coal
feed or to the effects of boiler design. Generally, pulverized wet bottom
boilers emit less fly ash than dry bottom boilers.
There are no test data for uncontrolled pulverized wet bottom boilers.
Through a review of the literature, it was found that ESPs are about
85 percent efficient for copper removal from combustion source emissions
(Table 3-142). Using this percentage and an ESP-controlled emission factor
1 9
of 86 lb/10 Btu, the uncontrolled copper emission factor for wet bottom
12
boilers would be 573 lb/10 Btu. A realistic upper estimate for copper from
3-67
-------
wet bottom units would be represented by the uncontrolled copper emission
12
factor for pulverized dry bottom boilers (848 lb/10 Btu). This range is
presented in Table 3-134.
The recommended emission factor for wet bottom boilers controlled with
multiclones is derived from the uncontrolled emission factor by assuming
40.7 percent copper control (see Table 3-142). The resulting emission factor
range is 340 to 503 lb/1012 Btu.
The only tested pulverized wet bottom boiler, controlled by a scrubber,
was found to emit 2.3 lb/1012 Btu. As shown in Table 3-142, scrubbers in the
data base controlled copper with from 83 to 99.8 percent efficiency. Using
an average control efficiency of 91.4 percent and the uncontrolled emission
12
range of 573 to 848 lb/10 Btu, the calculated copper emission factor for
12
scrubber control would range from 49 to 71 lb/10 Btu. However, given that
some scrubbers may be 99.8 percent efficient, the measured emission factor
(2.3 lb/1012 Btu) is plausible.
Bituminous Coal-Fired Cyclone Boilers
The recommended emission factor for cyclone boilers controlled with
12
ESPs, 22 lb/10 Btu, is based on tests of five boilers. These tests are
summarized in Table 3-135. Since cyclone boilers generate less fly ash than
pulverized coal-fired boilers, it is reasonable that measured emission
factors are lower.
Due to a lack of data, uncontrolled emission factors are calculated from
the ESP-controlled factors. A control efficiency of 85 percent is assumed
for ESPs, based on test data in Table- 3-142. The uncontrolled emission
12
factor calculated using this assumption is 147 lb/10 Btu. Based on the
average copper content of bituminous coal (17.8 ppm) and on the assumption
that 13.5 percent of total ash from cyclone boilers is emitted as fly ash,
12
the calculated minimum emission factor would be 184 lb/10 Btu. This
assumes copper is emitted in the same proportion as total particulates. In
reality, copper is often enriched in the fly ash. A realistic upper estimate
of uncontrolled copper emissions from cyclone boilers would be the emission
12
factor for pulverized coal-fired boilers (848 lb/10 Btu). Therefore, a
12
range of emission factors (147 to 848 lb/10 Btu) is presented in
Table 3-134.
3-68
-------
Assuming 40.7 percent of the copper present in an uncontrolled emission
stream can be controlled with a multiclone, the emission factor for
12
multiclone-controlled cyclone boilers would range from 87 to 503 lb/10 Btu.
Bituminous Coal-Fired Stoker Boilers
Eleven uncontrolled stoker boilers (seven spreader stokers and four
overfeed stokers) were tested. Results are summarized in Table 3-138. The
12
average emission factor for spreader stokers is 448 lb/10 Btu. The average
12
for all eleven stokers, weighting each boiler equally, is 987 lb/10 Btu. A
range of emission factors for uncontrolled spreader stokers, 448 to
12
987 lb/10 Btu is recommended for use in risk assessments.
The average measured uncontrolled overfeed stoker emission factor,
12
1,930 lb/10 Btu, is higher than would be expected given the typical levels
of copper in coal. The typical copper content of bituminous coal is 17.8 ppm
(Table 3-24). Assuming all of this is emitted, the maximum emission factor
12
would be 1,360 lb/10 Btu. The recommended uncontrolled emission factor for
12
overfeed stokers is presented as a range, from 987 lb/10 Btu (the measured
12
average for all stokers) to 1,360 lb/10 Btu (the calculated maximum
emission factor for combustion of typical bituminous coal). The measured
12
average emissions level of 1,930 lb/10 Btu is not considered
representative.
The average measured emission factor for five utility, industrial, and
commercial/institutional spreader stokers controlled with multiclones is
12
458 lb/10 Btu. This is within the range that would be calculated from the
uncontrolled emission factor by assuming 40.7 percent copper control
(Table 3-142). The calculated range is 265 to 590 lb/1012 Btu. This range
is recommended for use in risk assessments. The calculated range for
12
multiclone-controlled overfeed stokers is 590 to 806 lb/10 Btu.
Tests of two spreader stokers controlled with ESPs are summarized in
Table 3-138. There was a wide variation in measured emission factors.
Testing of nine combustion sources controlled with ESPs showed that ESPs are
about 85 percent efficient for copper removal. Applying this efficiency to
the recommended uncontrolled emission factors, ESP-controlled spreader
12
stokers would emit from 67 to 148 lb/10 Btu. Overfeed stokers would emit
from 148 to 204 lb/1012 Btu.
3-69
-------
Subbituminous Coal-Fired Boilers
The available emissions test data for subbituminous coal combustion are
presented in Tables 3-136 and 3-139. Many studies do not distinguish between
bituminous and subbituminous coal. Emission factors specific to
subbituminous coal are not presented, but based on the typical copper content
of subbituminous and bituminous coals, emission factors for the two types of
coal should be similar.
Lignite and Anthracite Coal-Fired Boilers
Emission factors for lignite-fired boilers are summarized in
Table 3-137. Testing of three anthracite-fired stoker boilers is summarized
in Table 3-140. There are too few data to derive representative emission
factors. Emission factors for lignite and anthracite combustion may be
derived from the recommended bituminous coal emission factors presented in
Table 3-134. The bituminous coal emission factors are multiplied by ratios
to account for the differing copper contents and heating values of the three
types of coal. Typical copper contents of the coals are shown in Table 3-24,
and heating values are summarized in Appendix D. The calculated emission
factors are presented in Table 3-134. Calculated lignite and anthracite
copper emission factors are higher than bituminous coal emission factors.
3.7.1.6 Mercury Emission Factors for Coal-Fired Boilers Behavior of
Mercury in Combustion Systems. Mercury is the most volatile of the trace
elements studied (see Section 3.4). Essentially 100 percent of the mercury
contained in the coal feed is volatilized during combustion and emitted to
the atmosphere (Baig et al., 1981). Much of the mercury is emitted in vapor
form, although some mercury condenses in the stack and is associated with the
fine particulate fractions of the fly ash (Klein et al., 1975b) . The
literature indicates that the majority of mercury is emitted in the vapor
phase, however, the proportion of mercury measured in particulate versus
vapor phase varies greatly between tests, and often mass balances do not
close well. The form of mercury present in the flue gas is dependent on
temperature and on fly ash characteristics. Some literature references also
3-70
-------
indicate that there have been large margins of error in sample collection and
analysis of vapor phase mercury. These factors account for some of the
differences in measured mercury emissions between tests.
Effect of Control Devices on Mercury Emissions
The distribution of mercury between the vapor and particulate phases
determines whether particulate control devices will be effective for mercury
control. The available test data indicated in some tests that ESPs resulted
in an average of about 50 percent mercury control; however, some tests
indicated no, or very little, reduction in mercury emissions. Many of the
tests reporting higher mercury control efficiencies for ESPs are suspect due
to mass balance closure of less than SO percent around the boiler and/or
control device. It is likely that mercury in the vapor phase escaped
detection in some of these tests. There were no test data on the mercury
removal efficiency of multiclones, but since multiclones are less efficient
than ESPs at small particle collection, very little mercury control would be
expected.
Two scrubbers tested resulted in 54 and 94 percent mercury control.
Scrubbing reduces stack gas temperatures from about 150 C (300 F) to about
52 C (125 F), causing mercury to condense and be removed more effectively
(Baig et al., 1981).
Mercury Emission Factors
Recommended mercury emission factors are presented in Table 3-143.
These are derived from measured emissions tests and from calculations based
on the mercury content of typical coals. Tests of mercury emissions are
summarized in Tables 3-144 through 3-149, and previously calculated emission
factors are summarized in Table 3-150. Appendix E (Tables E-50 through E-59)
contains more information on mercury emissions test results.
Bituminous Coal-Fired Boilers
Bituminous coal contains an average of about 0.21 ppm mercury. Assuming
all mercury is volatilized during combustion and emitted, an uncontrolled
12
emission factor of 16 lb/10 Btu would be expected. Since mercury is highly
3-71
-------
volatile and leaves the boiler in vapor phase, boiler design would have
little effect on the expected mercury emissions. As discussed previously,
multiclones would not significantly reduce mercury emissions. Thus the
16 lb/1012 Btu emission factor would apply to multiclone-controlled as well
as uncontrolled boilers. As discussed in previous paragraphs, ESPs may
result in up to 50 percent mercury control. Therefore, the suggested
emission factor for ESP-controlled boilers is expressed as a range, from 8 to
16 lb/1012 Btu. Scrubbers were shown to result in 54 to 94 percent mercury
control, so emission factors for scrubber-controlled boilers would range from
0.96 to 7.4 lb/1012 Btu.
In general, measured bituminous coal emission factors summarized in
Tables 3-144, 3-147, and 3-149 support the calculated values. Average
emission factors for uncontrolled and multiclone-controlled boilers of
12
various designs range from 1.3 to 35 lb/10 Btu. (One industrial boiler and
12
one utility boiler tested emitted over 180 lb/10 Btu, but these appear to
be outliers. The mercury content of the coals for these two tests were not
reported, so mass balance calculations are not possible.) The data show no
significant differences in mercury emissions between different boiler types
or different combustion sectors. The average measured emission factors for
12
various types of ESP-controlled boilers range from 2.9 to 11 lb/10 Btu, and
emission factors for scrubber controlled boilers ranged from undetectable
12
amounts to 4.9 lb/10 Btu. (There was one scrubber-controlled boiler
12
emitting 86 lb/10 Btu, but this is an outlier. The mercury content of the
coal feed was not reported.) These measured values are in general agreement
with the calculated values shown in Table 3-143.
Subbituminous Coal-Fired Boilers
Emission factors for subbituminous coal-fired boilers were not
calculated because much of the literature does not distinguish between
bituminous and subbituminous coals. Based on mercury content and heating
values of the two coals, it would be expected that emission factors for
subbituminous coal would be slightly lower than for bituminous coal. The
available test data for subbituminous coal combustion are summarized in
Tables 3-145 and 3-148.
3-72
-------
Lignite and Anthracite Coal-Fired Boilers
Lignite contains about 0.15 ppm and anthracite about 0.23 ppm mercury.
Emission factors for lignite and anthracite combustion are presented in
Table 3-143. These were calculated using the same procedures
that were used to calculate bituminous coal emission factors. The lignite
and anthracite emission factors are slightly higher than bituminous coal
emission factors. Measured emission factors derived from the available test
data on lignite and anthracite fired combustion sources are summarized in
Tables 3-146 and 3-149.
3.7.1.7 Manganese Emission Factors for Coal-Fired Boilers. Recommended
manganese emission factors for coal-fired boilers are presented in
Table 3-151. These are based on measurements of manganese emissions and on
theoretical calculations. They are applicable to utility, industrial, and
commercial/institutional boilers. Tables 3-152 through 3-157 summarize the
available manganese emissions data. For the various combustion sector/coal
type/boiler design/control technology scenarios, the average and range of
measured manganese emission factors are presented. Tables E-60 through E-69,
in Appendix E, provide additional information on each emissions test,
including references. Previously calculated manganese emission factors are
listed in Table 3-159.
Bituminous Coal-Fired Pulverized Drv Bottom Boilers
Six uncontrolled, pulverized dry bottom boilers were tested. Measured
emission factors are summarized in Tables 3-152 and 3-157. The average
12
emission factor, weighting each boiler equally is 2,980 lb/10 Btu. This
recommended emission factor is similar to previously calculated emission
factors listed in Table 3-158.
Data on boilers controlled with multiclones, summarized in Tables 3-152
and 3-155, are highly variable. According to the emissions tests reviewed,
multiclones remove about 54.3 percent of the manganese present in the flue
gas. Applying this control efficiency to the recommended uncontrolled
12
emission factor yields the recommended emission factor of 1,390 lb/10 Btu
for bituminous coal-fired pulverized dry bottom boilers controlled with
multiclones.
3-73
-------
Measured emission factors for 11 pulverized utility boilers and 4
industrial boilers controlled with ESPs are summarized in Tables 3-152 and
3-155. The average emission factor, weighting each boiler equally, is
642 lb/1012 Btu. This is the recommended emission factor given in
Table 3-151.
A total of five pulverized dry bottom boilers controlled with scrubbers
were tested. These include utility, industrial, and commercial/
institutional boilers. The average emission factor from these tests,
12
36 lb/10 Btu, is recommended for use in risk assessments.
Bituminous Coal-Fired Pulverized Wet Bottom Boilers
The literature contains less data on pulverized wet bottom boilers. The
average measured emission factor for five utility boilers controlled with
12
ESPs is 177 lb/10 Btu. This is lower than the factor for dry bottom
boilers. In general, pulverized wet bottom boilers emit less fly ash than
dry bottom boilers.
There are no data on uncontrolled pulverized wet bottom boilers. A,
review of tests of eight ESP-controlled boilers indicates an average
manganese control efficiency of 78.1 percent. By applying this control
12
efficiency to the measured ESP-controlled emission factor of 177 lb/10 Btu,
12
the corresponding uncontrolled emission factor would be 808 lb/10 Btu. A
reasonable maximum estimate of uncontrolled manganese emissions from
pulverized wet bottom boilers would be the measured uncontrolled emission
12
factor for pulverized dry bottom boilers (2,980 lb/10 Btu). This range of
emission factors is suggested in Table 3-151.
Multiclones can result in a 54.3 percent reduction in manganese
emissions (Table 3-159). Based on the recommended uncontrolled emission
12
factors of 808 to 2,980 lb/10 Btu, the multiclone-controlled emission
12
factors would range from 377 to 1,390 lb/10 Btu. Assuming scrubbers result
in 89.1 percent manganese control (Table 3-159), emission factors for boilers
12
controlled with scrubbers would range from 88 to 324 lb/10 Btu. However,
the one measured value (Table 3-152) is well below this range. Data are
insufficient to recommend an emission factor for scrubber-controlled
pulverized wet bottom boilers.
3-74
-------
Bituminous Coal-Fired Cyclone Boilers
Emission factors measured at five cyclone boilers controlled with ESPs
are summarized in Table 3-152. The average measured emission factor,
12
151 lb/10 Btu, is recommended for use in risk assessments. Based on this
emission factor and a manganese control efficiency of 78.1 percent for ESPs
(from Table 3-159), an uncontrolled emission factor of 690 lb/10 Btu can be
12
calculated. One uncontrolled cyclone boiler tested emitted 1,300 lb/10 Btu
The recommended uncontrolled emission factor is, therefore, expressed as a
12
range, from 690 to 1,300 lb/10 Btu. The recommended multiclone-controlled
12
emission factor of 322 to 607 lb/10 Btu is calculated based on a control
efficiency of 54.3 percent for multiclones (Table 3-159). Assuming
89.1 percent manganese control efficiency, an emission factor of 70 to
12
131 lb/10 Btu is estimated for cyclone boilers controlled with scrubbers.
This is in agreement with the single measured emission factor available.
Bituminous Coal-Fired Stoker Boilers
Since measured manganese emission factors for spreader and overfeed
stokers in all three combustion sectors were similar, they were combined to
calculate average emission factors applicable to all stokers. The average
measured emission factor for eleven uncontrolled stokers (Table 3-155) is
2,170 lb/1012 Btu.
The average emission factor for six tests of mechanical precipitator-
(or multiclone-) controlled stokers summarized in Tables 3-152, 3-155, and
12
3-157 is 196 lb/10 Btu. This emissions level is considerably lower than
what would be expected based on the uncontrolled emission factor. Assuming
54.3 percent control, the calculated multiclone-controlled emission factor is
12
1,010 lb/10 Btu. A range of emission factors is presented in Table 3-151
for use in risk assessments to illustrate this apparent variability in
manganese emissions.
Two stokers controlled with ESPs were found to emit an average of
12
31 lb/10 Btu. However, the ESP-controlled stoker manganese emissions level
that can be calculated, using the determined control efficiency of
12 12
78.1 percent and uncontrolled emissions of 2,170 lb/10 Btu, is 475 lb/10
Btu. Because of the degree of variability between the measured and
calculated factors, the range of these factors is presented for use in
subsequent risk assessments.
3-75
-------
Subbituminous Coal-Fired Boilers
Much of the literature does not distinguish between subbituminous and
bituminous coals, so recommended emission factors for subbituminous coal have
not been calculated. The two coals contain similar amounts of manganese
(Table 3-36), and emissions would be expected to be similar. The available
test data for subbituminous coal-fired utility and industrial boilers are
summarized in Tables 3-153 and 3-156.
Lignite and Anthracite Coal-Fired Boilers
As discussed in Section 3.3 and shown in Table 3-36, lignite contains
more manganese than bituminous coal. The recommended emission factors for
lignite and anthracite combustion shown in Table 3-151 are calculated from
the recommended factors for bituminous coal. The lignite emission factors
are higher than those for bituminous coal by a factor of 5.45. This factor
accounts for the higher average manganese content of lignite (300 ppm versus
100 ppm) and for the difference in heating values (7,194 Btu/lb for lignite
and 13,077 Btu/lb for bituminous). The anthracite emission factors are
essentially the same as the bituminous coal emission factors since the
typical manganese content of the two coals is the same (100 ppm), and heating
values are similar (12,700 Btu/lb for anthracite and 13,077 Btu/lb for
bituminous).
Measured emission factors for lignite and anthracite coal are summarized
in Tables 3-154 and 3-157. Few test data are available, but in general, the
measured emission factors are below the recommended values. One reference
reported the level of manganese in the lignite fuel as 79 ppm, which is well
below the average of 300 ppm and would account for the relatively low
measured emission factor. The other references did not report the level of
manganese in the coal feed. More testing is needed to enable better
characterization of manganese emissions from lignite combustion.
3.7.1.8 Nickel Emission Factors for Coal°Fired Boilers. Table 3-160
presents recommended nickel emission factors for boilers in the utility,
industrial, and commercial/institutional sectors. The uncontrolled emission
factors are calculated from the average nickel content of coal using the
3-76
-------
equations developed in Section 3.7.1.4. The nickel content of coal (C) and
heating values (H) substituted into the equations are given in Table 3-161.
The fraction of coal ash emitted as fly ash (f) is taken from Table 3-125.
For each type of boiler, maximum and minimum emission factors are calculated.
The maximum emission factor assumes all nickel input to the boiler in the
coal feed is emitted. The minimum assumes nickel is emitted in the same
proportion as total particulate. Since some studies indicate nickel is
enriched in the fly ash, the actual emission factor should be between the
two calculated values.
Controlled nickel emission factors are calculated from the uncontrolled
emission factors using the average control efficiencies presented in
Table 3-162. These control efficiencies are specific to nickel and are
derived from tests of controlled coal-fired boilers reported in the
literature.
Measured nickel-emission factors are summarized in Tables 3-163 through
3-168 and in Appendix E, Tables E-70 through E-79. Previously calculated
nickel emission factors are listed in Table 3-169. In general, measured
uncontrolled and controlled emission factors are higher than the maximum
calculated emission factor for the combustion of typical coals. The nickel
content of the coal feed (for tests where this was reported) was generally
between 10 and 25 ppm, which is similar to the average nickel content of
bituminous coal (16.9 ppm). Thus, the high measured average emission factors
are not due to the combustion of high-nickel coals. For many tests, mass
balances indicate more nickel being emitted than is input in the coal feed.
Some references noted that corrosion of sampling train components was
suspected to cause the high measured emission factors (Baig et al., 1981).
Since it appears that measured nickel emission factors are questionable, the
recommended values given in Table 3-160 are based on calculations involving
fuel content data, element partitioning assumptions, and control efficiency
assumptions.
3.7.1.9 Trace Metal Emission Factors for Residential Coal Combustion.
Recommended emission factors for eight of the nine trace metals are presented
in Tables 3-170 and 3-171. The literature reported only three tests of
3-77
-------
residential furnaces from which trace metal emission factors could be
derived. These were tests of automatic furnaces equipped with stokers, and
each was burning bituminous coal. The measured emission factors are
summarized in Table 3-172. As can be seen from the table, there is great
variability in trace metal emission factors for the three furnaces. This may
be due to variations in the trace metal content of the coals and to
variations in combustion and sampling conditions. It was not felt that the
average measured emission factor of just three coal samples burned in three
furnaces would be representative of residential combustion in general.
Therefore, the recommended emission factors in Tables 3-170 and 3-171 are
calculated according to the methodology of DeAngelis and Reznik (1979).
The equation is:
EFi - (C1/H)(Fi) x 106
12
Where: EF. - emission factor for trace element i (lb/10 Btu) ,
C. - concentration of trace element i in coal (ppm) ,
H - typical heating value of coal (Btu/lb), and
F. - fraction of trace element input in the coal feed which
is emitted to the atmosphere.
Values for C. are taken from Section 3.3. Tables in Section 3.3 report
average trace metal contents of different types of coal (bituminous,
subbituminous, anthracite, and lignite) as well as averages for each coal-
producing region of the country (Appalachian, Interior, Northern Plains, and
Rocky Mountains). These average trace metal contents represent hundreds of
coal samples.
Heating values (H) by coal type and geographic region are summarized in
Appendix D. Footnotes in Tables 3-170 and 3-171 also document the heating
values assumed for the calculations.
The fraction of each metal emitted to the atmosphere (F.) was developed
by DeAngelis and Reznik (1979). Values for F. were based on the observed
partitioning behavior of each trace element in two tests of residential
furnaces. Where information from these tests was inconsistent, partitioning
behavior of the element in larger (utility and industrial) coal-fired boilers
was also considered in estimating F.. DeAngelis and Reznik (1979)
3-78
-------
recommended F. values of 1.0 for mercury, 0.75 for arsenic and cadmium, and
0.10 for the other metals. The more volatile the element, the larger the
proportion emitted.
It is recommended that the emission factors presented in Tables 3-170
and 3-171 be used in risk assessments for the residential sector. In
general, the average measured emission factors (Table 3-172) are similar to
the calculated emission factors. The high measured value for nickel may be
due to corrosion of sampling train components.
3.7.2 Radionuclide Emission Factors
As discussed in Section 3.4.2, uranium-238 (U-238) and thorium-232
(Th-232) were chosen to represent radionuclide emissions. Measured U-238
emission factors for twenty-one utility boilers were reported in the
literature. These data are summarized in Table 3-173. Information on each
test, including the type of coal burned and the literature reference, is
included in Appendix E (Table E-80). Thorium emission factors for fourteen
boilers were reported in the literature. These data are summarized in
Table 3-174 and in Appendix E (Table E-81).
Pulverized dry bottom boilers controlled with ESPs are the most common
type of utility boiler and are also the best characterized in terms of
uranium and thorium emissions. The average U-238 emission factor for eight
boilers of this type is 6.55 picoCuries per gram of particulate emissions
(pCi/g), and the average thorium emission factor is 3.0 pCi/g. For those
tests where coal heating values and input rates were reported, radionuclide
emissions can also be expressed in terms of pCi/10 Btu heat input. The
average emission factors for U-238 and Th-232 are 295 and 170 pCi/10 Btu,
respectively. Uranium-238 emissions expressed in this manner vary over 2
orders of magnitude for the eight sources tested. This is a function of the
wide variation in total particulate (including uranium) emissions between
boilers. The ratio of uranium to total particulate emissions (pCi/g) is much
less variable between tests.
Measured U-238 and Th-232 emission factors for pulverized dry bottom
boilers controlled with scrubbers are also summarized in Tables 3-173 and
3-174. From the limited data available, it appears that radionuclide
3-79
-------
emission factors for boilers controlled with scrubbers are similar to
emission factors for boilers controlled with ESPs.
Data on cyclone and stoker boilers controlled with ESPs, scrubbers, and
fabric filters are also included in Tables 3-173 and 3-174. The data base is
too limited to draw conclusions about representative U-238 and Th-232
emission factors for cyclone and stoker boilers. In general emission factors
are on the same order of magnitude as emission factors for pulverized dry
bottom boilers.
Very few data were available concerning uncontrolled emission factors
for radionuclides from coal-fired boilers. An estimate of 30,000 pCi/10 Btu
(for U-238 only) was developed for utility boilers by back calculating from
the controlled emission factors for five utility boilers. The boiler types
included one stoker, one cyclone, two pulverized coal-dry bottom and one
pulverized coal tangentially-fired boiler. One boiler burned subbituminous
coal and the remaining boilers burned lignite coal. The high and low ends of
the range of amount of radioactivity in the coal were averaged in back
calculating the uncontrolled emission factor.
There is a potential that the type of coal burned may affect U-238 and
Th-232 emission factors. Tables 3-48 and 3-52 indicate that lignite coal has
higher average total uranium and thorium concentrations than bituminous coal.
However, the standard deviations around the mean values are larger than the
means themselves, indicating great variability in the data. Emissions test
data for four lignite boilers and several bituminous coal boilers are shown
in Tables E-80 and E-81. These data do not show a strong correlation between
type of coal burned and measured radionuclide emission factors.
3.7.3 POM and Formaldehyde Emission Factors
3.7.3.1 POM Emission Factors. The measurement of POM emissions from
combustion sources has been a focus of recent research. Factors affecting
the formation and emission of POM are discussed in Section 3.4.3. Based on
theoretical considerations, it is predicted that pulverized coal-fired
boilers would emit less POM than cyclone boilers, which in turn would emit
3-80
-------
less POM than stoker boilers. It was also postulated that larger boilers
would emit less POM per unit of heat input than smaller boilers. Measured
emission factors reported in the literature support these conclusions.
The same consideration given in Section 3.6.10 for evaluating POM
emissions data from oil combustion apply equally to the evaluation of POM
emissions from coal combustion. In assessing total POM emission factors for
coal combustion, the following factors should be analyzed.
the methods used to take and analyze samples
the measurement of particulate POM only or of gaseous and
particulate POM
the physical phase in which emissions predominantly occur
the number of POM compounds analyzed for
the specific POM compounds analyzed for
The individual source POM emissions data given in Appendix E, Tables E-82
through E-87, are characterized according to the evaluation criteria listed
above. However, as with the oil combustion results in Section 3.6.10, the
summary total POM data for coal combustion in Table 3-175 does not
distinguish total POM according to the number of compounds analyzed for, the
test methods used, etc. The reader can consult Tables E-82 to E-87 to
determine the level of inconsistency among the summarized reported total POM
emission results.
Measured POM emission factors for about 90 coal-fired boilers and
furnaces are summarized in Tables E-82 through E-87 in Appendix E. Based on
the available data, it does not appear that coal type or particulate control
technology have a significant effect on measured emission factors.
Therefore, data have been summarized by sector and by boiler type regardless
of control technology. Table 3-175 presents the average measured emission
factor and range of emission factors for each sector and type of boiler.
Table 3-175 shows that pulverized coal-fired utility boilers have the
12
lowest POM emission factors, averaging 3.9 lb/10 Btu. Cyclone boilers have
higher emission factors; and utility stoker boilers emit more POM per unit of
heat input than other types of utility boilers.
3-81
-------
Measured POM emission factors for industrial pulverized coal-fired
12
boilers are also relatively low, averaging 35.3 lb/10 Btu. A large number
of industrial, commercial, and residential stoker boilers have been tested.
As shown in Table 3-175, measured POM emissions for stoker boilers are highly
variable. Reported emission factors vary over three orders of magnitude.
Average POM emission factors for stokers in the industrial, commercial, and
12
residential sectors are quite high (-100 to 3000 lb/10 Btu). The reasons
for the extreme variability in the data are unknown. Sources of variation
would include sampling and analytical methodology, type of coal, boiler
design (spreader versus underfeed), boiler size, and operating parameters.
Most commercial and residential boilers tested were underfeed stokers, and
were probably smaller than the industrial stokers tested. These factors may
partially explain the higher average POM emission factor for small
commercial/residential stokers compared to industrial stokers.
Data on three hand stoked residential units are highly variable, but
indicate that hand stoked combustion sources may have significantly higher
POM emissions than automatic stokers.
3.7.3.2 Formaldehyde Emission Factors. There are insufficient data on
formaldehyde to characterize emissions by boiler type or combustion sector.
Only one reference was identified which contained measured formaldehyde
emission factors. The seven individual tests are summarized in Table 3-176.
12
Emission factors range from 63 to 2,100 lb/10 Btu, with an average of
12
446 lb/10 Btu. The fact that a hand stoked unit had the lowest emission
factor is inconsistent with theory (see Section 3.4.3). The two tests of
pulverized coal-fired boilers indicate that these units may have slightly
lower emission factors than stoker boilers; however, the number of tests is
too few to make this conclusion with certainty. The recommended formaldehyde
emission factor for coal-fired sources, for risk assessment purposes, is
12 12
170.5 lb/10 Btu. The 170.5 lb/10 Btu factor is the average of the
available coal-fired source formaldehyde data with the apparent outlier of
12
2100 lb/10 Btu not included in the calculation.
3-82
-------
3.7.4 Lead Emission Factors
Emission factors for lead from coal combustion are presented in this
section. As discussed previously, a limited data base was used to obtain
emission factors for lead. They were taken directly from an EPA background
document for support of the national ambient air quality standard (NAAQS)
(U. S. Environmental Protection Agency, 1985). The emission factors were
based on the type of coal burned, bituminous and anthracite. The reference
used the premise that utility, industrial, and commercial boilers burned
bituminous coal and residential boilers burned anthracite coal. Heating
values of 13,077 Btu/lb coal and 12,648 Btu/lb coal were used for bituminous
and anthracite coal, respectively to convert the emission factors to a
12
Ib lead emitted/10 Btu basis. Uncontrolled and controlled emission factor*
for lead from coal combustion were calculated to be:
Uncontrolled Emission Controlled Emission
-Sector Factor flb/101Z Btut Factor (lb/10IZ BtuY
Utility 507.4 25.37
Industrial 507.4 223.3
Commercial 507.4 223.3
Residential 510.0 510.0
The efficiency of controls were provided in the reference (U. S.
Environmental Protection Agency, 1985). For utility boilers, an average
control efficiency of 95 percent was applied to coal-fired utility boilers.
Control efficiencies for industrial and commercial boilers were reported as
56 percent and no control was assumed for residential boilers.
Additional data concerning measured and calculated emission factors for
lead from coal and oil combustion are shown in Tables 3-177 through 3-181.
3.7.5 Summary of Emissions from Coal Combustion
Trace pollutant emissions from coal combustion are highly variable.
Emission factors are dependent on coal composition, boiler design and
operating parameters, and control technologies. Sampling and analytical
3-83
-------
uncertainty also contribute to the variability in measured emission factors.
Due to the complexity of the interactions between these factors, derivation
of typical emission factors for trace pollutants is difficult. While trace
emissions from many boilers have been tested, the quality of the data base is
variable, and there are significant data gaps.
The data on trace metal emission factors are summarized in Section 3.7.1.
Emission factors for each of the eight trace metals which can be used in risk
assessments are presented in summary tables (Tables 3-96, 3-105, 3-114,
3-123, 3-134, 3-143, 3-151, 3-160, 3-170, 3-171). Significant data gaps were
encountered in summarizing the emission data base. There are fewer test data
on cyclone boilers and on pulverized wet bottom boilers than on pulverized
dry bottom boilers. More data are required to determine whether trace metal
emissions from wet bottom boilers are significantly different than emissions
from dry bottom boilers. There are several tests of stoker boilers, but more
data are needed to characterize emissions from the various types of stokers.
The commercial and residential sectors are less well characterized than
the utility and industrial sectors. Based on the limited data available, it
was concluded that for similar types of boilers, emission factors were
independent of combustion sector. More testing of industrial and commercial
boilers would help support or refute this conclusion.
The great majority of sources tested burn bituminous coal. Little data
on lignite and anthracite combustion are available. Emission factors for
these types of coal had to be calculated, since there were insufficient
measured data.
Regarding control technologies, the trace metal control efficiency of
ESPs is fairly well characterized. There is a lack of data on the efficiency
of multiclones and scrubbers in reducing trace metal emissions.
Finally, better methods for sampling chromium and nickel emissions must
be used in future tests. Measured emission factors for these two elements
were highly variable and unreliable due to corrosion of sampling train
components.
Measured radionuclide emission factors are discussed in Section 3.7.2.
Radionuclide emissions from ESP-controlled pulverized dry bottom boilers are
fairly well characterized. However, there are a lack of data on radionuclide
3-84
-------
emissions from other types of boilers and on the effects of control devices
on radionuclide emissions.
Polycyclic organic matter emissions from coal-fired combustion sources
have been extensively tested but poorly characterized. Part of the reason
for the poor characterization is the lack of standardization that exists in
defining, testing, and analyzing POM compounds. The extreme variability
present in total POM emissions data for coal combustion makes selection of
typical or representative values difficult. Significant room for improvement
exists in the area of characterizing POM emissions from coal combustion.
Combustion source formaldehyde emissions data are severely limited.
Representative or typical source emissions cannot adequately be determined
with the currently available level of information.
3-85
-------
TABLE 3-2. CONCENTRATION OF ARSENIC IN COAL BY COAL TYPE8
Coal Type
Bituminous
Subbituminous
Anthracite
Lignite
Number of
Samples
3527
640
52
183
Arsenic Concentration (ppm)
Mean
20.3
6.17
7.67
22.8
Standard Deviation
41.8
15.5
19.6
138
3Data presented in White et al.. (1984); based on data in the USGS National
Coal Resources Data System (NCRDS) as of 1982. Arithmetic means from this
study may be used as typical values for arsenic content of these types of
coals.
TABLE 3-3. RANGES OF ARSENIC CONCENTRATION IN COALS BY COAL TYPE
Arsenic Concentration
Coal Type Range (ppm)a
Bituminous 0.02-357
Subbituminous 0.1-16
Anthracite NA
Lignite 0.1-45
Q
Lowest and highest values reported in any of the literature reviewed.
Note: The White et al.. (1984) study does not list the range of values in
the NCRDS. The Swanson et. aU_s (1976) study, which is a subset of the NCRDS
describing about 800 coal samples does include ranges for bituminouss
Subbituminous, and lignite coals from certain geographic regions.
NA = not available.
3-86
-------
TABLE 3-4. ARSENIC CONCENTRATION IN COAL BY REGION
oo
Region
Appalachian
Interior
Illinois Basin
Gulf Province
Northern Plains
Rocky Mountains
Alaska
Number of
Samples
2749
331
592
155
82
38
34
371
490
512
124
107
18
Range
0.5-357
< 1-240
1.7-93
1-16
-------
TABLE 3-5. CONCENTRATIONS OF ARSENIC IN OIL REPORTED IN PREVIOUS STUDIES
Number of Arsenic Concentration (ppm)
Type of Oil Samples Range Mean
Residual #6 11 <0. 15-1.0 0.51
13 0.011-0.150 0.055
30 0.069-0.28 0.16
0.42
0.8a
V 5 0.087-0.4 0,24
oo
oo
Distillate 0.04
3 0.1-0.21 0.13
Crude 0.046-1.11 0.263
Standard Deviation Reference
Shih et al. , 19805
0.040 Gordon et al . ,
0.02 Mroe, 1976
Vouk and Piver ,
Tyndall et al. ,
Suprenant et al
Slater and Hall
Suprenant et al
0.007 Yen, 1975
1974
1983
1978
., 1980b
, 1974
., 1980b
Based on weighted average of crude oils used in the U.S.
-------
TABLE 3-6. SUMMARY OF DATA ON ARSENIC IN OIL
Type of Oil
Arsenic Concentration (ppm)
Range
Typical Value
Residual #6
Distillate
Crude
0.011-0.8
0.04-0.9
0.0024-1.11
0.36d
0.0851
0.26°
a
'Average of the six studies reported in Table 3-5.
Average of two studies reported in Table 3-5.
n
Arithmetic mean for oils used in U.S., reported in Yen (1975)
TABLE 3-7. CONCENTRATION OF ARSENIC IN U.S. VERSUS FOREIGN CRUDE OILS
Foreign
Domestic
Range (ppm)
0.01-0.34
0.0024-0.284
0.007-0.61
0.65a
0.007-0.05
Mean (ppm)
0.13
0.12
0.14
0.65a
0.02
Reference
Anderson, 1973
Filby and Shaw,
Anderson, 1973
Filby and Shaw,
Cato, 1976
1975
1975
aBased on one sample of California crude oil.
3-89 ,
-------
TABLE 3-8. CONCENTRATION OF BERYLLIUM IN COAL BY COAL TYPE*
Number of Beryllium Concentration (pptn)
Coal Type
Bituminous
Subbituminous
Anthracite
Lignite
^
Data presented
Samples
3527
640
52
183
in White et al . ,
Mean
2.22
1.30
1.32
1.98
(1984); based on data
Standard Deviation
1.66
1.77
0.85
2.71
in the USGS National
Coal Resources Data System (NCRDS) as of 1982. Arithmetic means from this
study may be used as typical values for beryllium content of these type of
coal So
TABLE 3-9. RANGES OF BERYLLIUM CONCENTRATION IN COALS BY COAL TYPE
Coal Type
Beryllium Concentration
Range (ppm)a
Bituminous
Subbituminous
Anthracite
Lignite
0.05-25
0.05-13
NAb
0.2-15
a
Lowest and highest values reported in the literature reviewed. Note: The
White et al.. (1984) study does not list ranges of values in the NCRDS.
Valkovic (1983a) provides ranges for bituminous, Subbituminous and lignite
coals.
NA
not available.
3-90
-------
TABLE 3-10. BERYLLIUM CONCENTRATION IN COAL BY REGION
Number of
Region Samples
Appalachian 2749
331
29-87
Interior 592
155
47-253
OJ
1
M Illinois Basin6 82
Gulf Province 38
34
Northern Plains 371
490
Rocky Mountains 184
124
174
Range
0.3-7
0.1-31
0.7-12
0.5-4
0.2-15
0.07-3
0.1-31
Beryllium Concentration (ppm)
Arithmetic Standard
Mean Deviation
2.27a 1.68
2
2.29a 1.6
o
1.72
2.08a 2.85
2
1.23a 1.86
0.7
1.37a 1.72
0.7
Reference
White et al., 1984. NCRDSb
Swanson et al., 1976
Valkovic, 1983ad
White e^ al.., 1984, NCRDS
Swanson et al., 1976
Valkovic, 1983a
Ruch et al. , 1974
White et al.. 1984. NCRDS
Swanson et al., 1976
White et al.. 1984. NCRDS
Hatch and Swanson, 1977
White et al.. 1984. NCRDS
Swanson et al., 1976
Valkovic, 1983a
-------
TABLE 3-10. BERYLLIUM CONCENTRATION IN COAL BY REGION (Continued)
Beryllium Concentration (ppm)
Region
Alaska
Number of
Samples
107
18
Arithmetic
Range Mean
0.78a
0.2-3 0.7
Standard
Deviation Reference
0.74 White et al., 1984, NCRDS
.Swanson et al . , 1976
a
Values are based on most comprehensive data set available and may be used as typical values for beryllium in coal
from these regions.
NCRDS = National Gaol Resource Data System maintained by USGS.
V Data from Swanson et al. . (1976) are included in NCRDS. Arithmetic means from the entire NCRDS are more
15 representative then those from Swanson et al.. because NCRDS contains data on many more samples. The Swanson data
are given to provide an indication of the range of values for beryllium content of coal.
Source reported values for specific states, therefore the number of samples by region is presented as a range.
This is the eastern portion of the Interior province.
-------
TABLE 3-11. CONCENTRATIONS OF BERYLLIUM IN OIL REPORTED IN PREVIOUS STUDIES
Number of Beryllium Concentration (ppm)
Type of Oil Samples Range Mean Standard Deviation
Residual #6 3 <0.2-<0.15
2 0.1
4 <0. 0042 -0.38 <0.10
11 <0.0023-<0.4 0.10 1.03
0.09
V 0.0004
CO
0.08
0.08a
Distillate #2 3 <0 .0076-<0 .01 <0 .0092
1 0.100
Crude 0.002
Reference
Carter et al. , 1978
Anderson, 1973
Suprenant et al., 1980b
Shih et al., 1980b
Slater and Hall, 1974
Vouk and Fiver, 1983
Anderson, 1973
Tvndall et al. , 1978
Suprenant et al . , 1980b
Castaldini et al., 1981b
Vouk and Fiver, 1983
1Based on weighted average of crude oil used in U.S.
-------
TABLE 3-12. SUMMARY OF DATA ON BERYLLIUM IN OIL
Beryl1ium Concentration (ppm)
Type of Oil Range Typical Value
Residual #6 <0.0023-0.38 0.08a
Distillate #2 <0.0076-0.1 0.05b
Crude 0.002
Average of six means reported in Table 3-11 .
Average of two studies reported in Table 3-11.
3-94
-------
TABLE 3-13. CONCENTRATION OF CADMIUM IN COAL BY COAL TYPE3
Coal Type
Bituminous
Subbituminous
Anthracite
Lignite
Number of
Samples
3527
640
52
83
Cadmium Concentration (ppm)
Mean
0.91
0.38
0.22
0.55
Standard Deviation
7.3
0.47
0.30
0.61
aData presented in White et al.. (1984); based on data in the USGS National
Coal Resources Data System (NCRDS) as of 1982. Arithmetic means from this
study may be used as typical values for arsenic content of these types of
coals.
TABLE 3-14. RANGES OF CADMIUM CONCENTRATION IN COALS BY COAL TYPE
Cadmium Concentration
Coal Type Range (ppm)3
Bituminous <0.02-100
Subbituminous 0.04-3.7
Anthracite 0.1-0.3
Lignite <0.11-5.5
aLowest and highest values reported in any of the literature reviewed.
Note: The White et al.. (1984) study does not list the range of values in
the NCRDS. The Swanson et al.. (1976) study, which is a subset of the NCRDS
describing about 800 coal samples does include ranges for bituminous, and
lignite coals. Valkovic, (1983a) provides a range for cadmium concentration
in Subbituminous coal.
3-95
-------
TABLE 3-15. CADMIUM CONCENTRATION IN COAL BY REGION
OJ
Region
Appalachian
Interior
Illinois Basin
Gulf Province
Northern Plains
Rocky Mountains
Alaska
Number of
Samples
2749
331
592
155
82
38
34
371
490
512
124
107
18
Cadmium Concentration
Arithmetic
Range Mean
0.13a
0.03-6.8 0.7
5.47a
<0. 02-100 7.1
0.1-65 2.89
0.50a
<0.11-5.5 1.3
0.30a
0.02-2.7 0.08
0.353
<0 ,,03-0.5 <0.5
0.283
<0.1-0.7 Ť0.2
(ppm)
Standard
Deviation
0.21
18.5
0.49
0.48
0.38
0.59
Reference
White et al.. 1984. NCRDSb
/Ť
Swanson et al., 1976
White et al . . 1984. NCRDS
Swanson et al., 1976
Ruch, 1974
White et al.. 1984. NCRDS
Swanson et al., 1976
White et al., 1984. NCRDS
Hatch and Swanson, 1977
White et al.. 1984. NCRDS
Swanson et al., 1976
White et al., 1984. NCRDS
Swanson et al., 1976
aValues are based on the most comprehensive data set currently available and may be used as typical values for
cadmium in coal from these regions.
NCRDS = National Coal Resource Data System maintained by USGS.
Data from the Swanson eŁ al_-_, (1976) study are included in the NCRDS. Arithmetic means from the entire NCRDS are
more representative than means from Swanson, since the NCRDS contains many more coal samples. The Swanson data
are included here to give an idea of the range of values for cadmium content in individual coal samples from each
region.
This is the eastern portion of the Interior province.
-------
TABLE 3-16. CONCENTRATION OF CADMIUM IN OIL REPORTED IN PREVIOUS STUDIES
VO
-j
Type of Oil
Residual #6
Distillate #2
Crude
Number of Cadmium Concentration (ppm)
Samples Range Mean Standard Deviation
5 0.02-<0.94 <0.41
11 <0. 01-0. 83 0.30 0.57
3 <0.2-<0.3
2.27a
2.02
0.4-0.5
3 <0.01-<0.95 <0.32
1 0.10
0.01
0.03
0.05
Reference
Suprenant et al . , 1980b
Shin et al., 1980b
Carter et al . , 1978
Tyndall et al.. 1978
Slater and Hall, 1974
Anderson, 1973
Suprenant et al., 1980b
Castaldini, et al., 1981b
Vouk and Piver , 1983
Yen, 1975
Hofstader et al. , 1976
*Based on weighted average of crude oil in U.S.
-------
TABLE 3-17. SUMMARY OF DATA FOR CADMIUM IN OIL
Cadmium Concentration (ppm)
Type of Oil
Range
Typical Value
Residual #6
Distillate #2
Crude
(0.01-2.27
<0.01-<0.95
0.3d
0.21b
0.03C
See text for discussion of this value (Section 3.3.3)
Average of two studies in Table 3-16.
"Average of three studies in Table 3-16.
TABLE 3-18. CONCENTRATION OF CADMIUM IN U.S. VERSUS FOREIGN CRUDE OILS
Range (ppm)
Mean (ppm)
Reference
Foreign
Domestic
0.027'
0.017Ł
0.0015
0.01
0.03
0.05
a
Valkovic, 1978a
Valkovic, 1978a
Valkovic, 1978a
Youk and Piver, 1983
Yen, 1975
Hofstader e_t al. . 1976
Uncertainty ranges from 10-30 percent.
3-98
-------
TABLE 3-19. CONCENTRATION OF CHROMIUM IN COAL BY COAL TYPEa
Coal Type
Bituminous
Subbituminous
Anthracite
Lignite
Number of
Samples
3527
640
52
183
Chromium Concentration (ppm)
Mean
20.5
14.9
47.2
13.5
Standard Deviation
27.5
25.6
60.9
18.2
aData presented in White et al., 1984. Based on data in the USGS National
Coal Resources Data System (NCRDS) as of 1982. Arithmetic means from this
study may be used as typical values for chromium content of these types of
coal.
TABLE 3-20. RANGES OF CHROMIUM CONCENTRATION IN COALS BY COAL TYPE
Chromium Concentration
Coal Type Range (ppm)a
Bituminous <0-5-70
Subbituminous 0.54-70
Anthracite 15-120
Lignite 3-70
aLowest and highest values reported in the literature reviewed. Note: the
White et al.. (1984) study does not list ranges of values in the NCRDS. The
Swanson et al.. (1976) study, a subset of NCRDS containing about 800 samples,
does list ranges for bituminous and lignite coals. Valkovic, (1983a) lists
ranges for Subbituminous.
3-99
-------
TABLE 3-21. CHROMIUM CONCENTRATION IN COAL BY REGION
o
o
Region
Appalachian
Interior
Illinois Basin
Gulf Province
Northern Plains
Number of
Samples
2749
331
592
155
82
38
34
371
490
Range
<0.5-70
8.4-400
1.5-220
2-70
4-54
3-70
0.5-10
0.54-60
Chromium Concentration (ppm)
Arithmetic Standard
Mean Deviation
18. 2a 13.6
20
18
27 .2a 54.1
15
14.1 7.5
21 .2a 10.9
20
7.53a 12.9
5
6.7
Reference
White et al . , 1984, NCRDSb
f>
Swanson et al., 1976
PedCo, 1982
Valkovic, 1983a
White et al., 1984, NCRDS
Swanson et al . , 1976
Ruch et al. , 1974
White et al . , 1984, NCRDS
Swanson et al., 1976
White et al., 1984, NCRDS
Hatch and Swanson, 1977
Valkovic, 1983a
-------
TABLE 3-21. CHROMIUM CONCENTRATION IN COAL BY REGION (Continued)
u>
Region
Rocky Mountains
Alaska
Number of
Samples
512
124
107
18
Chromium Concentration
Arithmetic
Range Mean
19. 7a
0.5-70 5
0.54-70 11
39. 7a
5-70 15
(ppm)
Standard
Deviation Reference
27.4 White et al.. 1984,
Swan son, 1976
Valkovic, 1983a
46.9 White et al.. 1984,
Swanson, 1976
NCRDS
NCRDS
a
Values are based on the most comprehensive data set currently available and may be used as typical values for
chromium in coal from these regions.
NCRDS = National Coal Resources Data System maintained by USGS.
Data from Swanson et al., (1976) study are included in the NCRDS. Arithmetic means from the NCRDS are more
representative than those from Swanson, since the NCRDS contains data on many more coal samples. The Swanson data
are included here to provide an indication of the range of values for chromium concentration in coals from these
regions.
This is the eastern portion of the Interior province.
-------
TABLE 3-22. CONCENTRATIONS OF CHROMIUM IN OIL REPORTED IN PREVIOUS STUDIES
o
NJ
Number of
Type of Oil Samples
Residual #6 4
5
11
16
9
6
15
3
Distillate #2 3
1
Crude 1
1
1
Range
0.0019-0.073
0.2-0.5
0.09-<1.9
0.026-0.16
0.45-1.6
0.33-0.39
0.068-0.77
0.4-<5
0.8-2
0.0016-0.017
Chromium Concentration (ppm)
Mean Standard Deviation
0.037 0.040
0.33
0.9 0.46
0.070 0.050
0.79
0.36
0.32
1.6
0.048
1 .2
0.43
0.008
0.64
0.0023
Reference
Gordon et al. , 1974
Suprenant et al., 1980b
Shih et al., 1980b
Mroe, 1976
Mroe, 1976
Mroe, 1976
Mroe, 1976
Carter et al. , 1978
Suprenant et al., 1980b
Cato et al. , 1978
Castaldini et al., 1981b
PedCo, 1982
Yen, 1975
PedCo, 1982
PedCo, 1982
-------
TABLE 3-23. SUMMARY OF DATA FOR CHROMIUM IN OIL
Chromium Concentration (ppm)
Type of Oil Range Typical Value
Residual 0.0019-<5 0.40a
Distillate 0.048-2 0.95b
Crude 0.0016-0.64 0.27C
a
Average of seven studies in Table 3-22.
Average of three studies in Table 3-22.
Average of four studies in Table 3-22.
3-103
-------
TABLE 3-24. CONCENTRATION OF COPPER IN COAL BY COAL TYPE3
Coal Type
Bituminous
Subbituminous
Anthracite
Lignite
Number of
Samples
3527
640
52
183
Copper
Mean
17.8
14.1
18.9
17 .2
Concentration (ppm)
Standard Deviation
17.8
14.3
16.4
21.2
aData presented in White et al.. (1984); based on the USGS National Coal
Resources Data System (NCRDS) as of 1982. Arithmetic means reported in
this study may be used as typical values for copper content of these coals,
TABLE 3-25. RANGES OF COPPER CONCENTRATION IN COALS BY COAL TYPE
Copper Concentration
Coal Type Range (ppm)a
Bituminous 1.2-911
Subbituminous 0.16-120
Anthracite NA
Lignite 3.3-289
Lowest and highest values reported in the literature reviewed. Note:
White et, .al^, (1984) study does not list ranges of values in the NCRDS.
The Swanson et al., (1976) data set is a subset of NCRDS containing data on
about 800 samples and provides ranges for bituminous and lignite coals.
Valkovic (1983a) provides ranges for Subbituminous coals.
NA = not available.
3-104
-------
TABLE 3-26. COPPER CONCENTRATION IN COAL BY REGION
Number of
Region Samples
Appalachian 2749
331
Interior 592
155
w Illinois Basin 82
i
t-1
*-" Gulf Province 38
34
Northern Plains 371
Rocky Mountains 512
Arithmetic
Range Mean
18. 2a
1.2-911 24
17. 5a
3.7-158 20
5-44 14.09
26. 5a
3.3-289 28
9 .82a
0.34-76 10.5
13. 8a
1.5-100 9.1
Standard
Deviation Reference
18.2 White et al., 1984, NCRDSb
Ł
Swanson et al., 1976
14.6 White et al., 1984, NCRDS
Swanson et al., 1976
Ruch et al. , 1974
16.1 White et al . , 1984, NCRDS
Swanson et al., 1976
10.2 White et al., 1984, NCRDS
Hatch and Swanson, 1977
16.0 White et al., 1984, NCRDS
Swanson et al., 1976
-------
TABLE 3-26. COPPER CONCENTRATION IN COAL BY REGION (Continued)
Region
Number of
Samples
Arithmetic
Range Mean
Standard
Deviation
Reference
Alaska 107 20.13 16.6 White eŁ al^, 1984, NCRDS
8.2-48.8 16.8 Swanson et al.. 1976
&
Values are based on the most comprehensive data set currently available and may be used as typical values for copper
in coal from these regions.
NCRDS = National Coal Resources Data System maintained by USGS.
Data from Swanson et al.. (1976) study are included in the NCRDS. Arithmetic means from the NCRDS are more
representative than those from Swanson, since the NCRDS contains data on many more coal samples. The Swanson data
are included here to provide an indication of the range of values for copper concentration in coals from these
regions.
This is the eastern portion of the Interior province.
-------
TABLE 3-27. CONCENTRATIONS OF COPPER IN OIL REPORTED IN PREVIOUS STUDIES
Number of
Type of Oil Samples
Residual #6 12
5
11
3
8
^ Distillate #2 3
o
""^J Ť
2
Crude
24
Range
ND-0.019a
0.8-9.5
0.1-79
0.040-1.7
5.5-11
11
0.056-0.2
0.03-1.7
0.19-0.93
0.17-0.1
0.1-2.4
0.4
0.13-6.33
Copper Concentration (ppm)
Mean Standard Deviation
0.45
3 .06
15 1.17
2.8b
11
0.13
1 .3
1.32
Reference
Gordon e_t al._. 1974
Vouk and Piver, 1983
Suprenant et al . , 1980b
Shih et al.. 1980b
Carter et al., 1978
Tyndall et al . , 1978
Cato et al., 1978
Suprenant et al., 1980b
Castaldini et al., 1981b
Cato et al. , 1978
Vouk and Piver, 1983
Spait and Devitt, 1979
Filby and Shah, 1975
Valkovik, 1978
Valkovik, 1978
Yen, 1975
Yen, 1975
a
ND = not detectable.
Based on weighted average of crude oil used in U.S.
-------
TABLE 3-28. SUMMARY OF DATA ON COPPER IN OIL
Type of Oil
Copper Concentration (ppm)
Range
Typical Value
Residual #6
Distillate #2
Crude
ND-79
0.056-11
0.03-6.33
5.3'
5.61
1.3C
Average of Your studies reported in Table 3-27.
Average of the two studies where means were reported in Table 3-27.
Based on two means reported in Table 3-27.
TABLE 3-29. CONCENTRATION OF COPPER IN U.S. VERSUS FOREIGN CRUDE OILS
Foreign
Domestic
Range (ppm) Mean (ppm)
0.19
0.21
0.93a
0.40b
0.13-6.33 1.32
Reference
Filby and Shahs
Filby and Shah,
Filby and Shah,
Yen, 1975
Yen, 1975
1975
1975
1975
Based on single sample of California crude oil
Based on 23 domestic crude oils.
3-108
-------
TABLE 3-32. MERCURY CONCENTRATION IN COAL BY REGION (Continued)
Mercury Concentration (ppm)
Region
Alaska
Number of
Samples
107
18
Arithmetic
Range Mean
0.08a
0.02-63 4.4
Standard
Deviation
0.07
Reference
White et al . ,
Swan son et al
1984, NCRDS
., 1976
a
Values are based on the most comprehensive data set currently available and may be used as typical values for
mercury in coal from these regions.
NCRDS = National Coal Resource Data System maintained by USGS.
^
Data from the Swanson et al.. (1976) study are included in the NCRDS. Arithmetic means from the entire NCRDS are
more representative than means from Swanson, since the NCRDS contains many more coal samples. The Swanson data are
included here to give an idea of the range of values for mercury content in individual coal samples from each region.
j
Eastern section of Interior Province.
-------
TABLE 3-33. CONCENTRATIONS OF MERCURY IN OIL REPORTED IN PREVIOUS STUDIES
Number of Mercury Concentration (ppm)
Type of Oil Samples Range Mean Standard Deviation Reference
Residual #6 3 <0.1
0.02
10
0.04a
11 0.007-0.17 0.066 0.50
Distillate #2 1 0.40
Crude 0.007-0.2
1 23.1
1 0.27
1 0.84
43 0.023-30 3.24
Carter et al . , 1
Slater and Hall,
Vouk and Piver,
Suprenant et al .
978
1974
1983
, 1980b
Shin et al. , 1980a
Castaldini et al
Anderson, 1973
PedCo, 1982
PedCos 1982
PedCo, 1982
Yen, 1975
., 1981b
Based on weighted average of crude oils in U.S.
-------
TABLE 3-34. SUMMARY OF DATA FOR MERCURY IN OIL
Mercury Concentration (ppm)
Type of Oil
Range
Typical Value
Residual #6
Distillate #2
Crude
0.007-10
0.007-30
0.06'
0.40
6.86'
Average of four studies in Table 3-33; disregarded 10 ppm concentration as
an outlier.
Based on single study in Table 3-33. May not be representative.
Ł
Average of four studies in-Table 3-33.
TABLE 3-35. MERCURY CONCENTRATIONS IN U.S. VERSUS FOREIGN CRUDE OILS
Range (ppm) Mean (ppm)
Foreign 0.027
0.084
0.05
0.025
0.006
0.01
0 .09
Domestic 0.023-30 3.24
0.007-0.2
0.84
0.27
23.1
Reference
PedCo, 1982
PedCo, 1982
Anderson, 1973
Anderson, 1973
Anderson, 1973
Anderson, 1973
Anderson, 1973
Yen, 1975
Anderson, 1973
PedCo, 1982
PedCo, 1982
PedCo, 1982
3-113
-------
TABLE 3-36. CONCENTRATION OF MANGANESE IN COAL BY COAL TYPE3
Coal Type
Bituminous
Subbituminous
Anthracite
Lignite
Number of
Samples
3527
640
52
183
Manganese Concentration (ppm)
Mean
100
100
100
300
Standard Deviation
100
200
200
200
aData presented in White et. al^, (1984); based on data in the USGS National
Coal Resources Data System (NCRDS) as of 1982. Arithmetic means from this
study may be used as typical values for manganese content of these types of
coals.
TABLE 3-37. RANGES OF MANGANESE CONCENTRATION IN COALS BY COAL TYPE
Manganese Concentration
Coal Type Range (ppm)a
Bituminous <3.9-4400
Subbituminous 1.4-3500
Anthracite 20-182
Lignite 7.4-690
a
Lowest and highest values reported in any of the literature reviewed.
Note: The White et al., (1984) study does not list the range of values in
the NCRDS. The Swanson et al.. (1976) study, containing about 800 coal
samples does list ranges for bituminous and lignite coals. Valkovic, 1983a
provides a range for manganese in Subbituminous coals.
3-114
-------
TABLE 3-38. MANGANESE CONCENTRATION IN COAL BY REGION
Number of
Region Samples
Appalachian 2749
331
Interior 592
V 155
H1
H
01 d
Illinois Basin 82
113
Gulf Province 38
34
Northern Plains 371
490
Manganese
Range
<3. 9-1 000
0.75-1400
4.4-4400
6-181
6-210
7.4-690
<90-440
7.3-660
Concentration (ppm)
Arithmetic Standard
Mean Deviation
100a 100
620
27
100a 300
138
53.2
53 41
300a 100
240
iooa 100
50
75
Reference
White et al., 1984, NCRDSb
Swanson et al., 1976c
Valkovic, 1983a
White et. aU., 1984, NCRDS
Swanson et al., 1976
Ruch, 1974
Gluskoter et al. , 1977
White et al.. 1984, NCRDS
Swanson et al., 1976
White et. al_._, 1984, NCRDS
Hatch and Swanson, 1977
Valkovic, 1983a
-------
TABLE 3-38. MANGANESE CONCENTRATION IN COAL BY REGION (Continued)
OJ
I
Manganese Concentration (ppm)
Region
Rocky Mountains
Alaska
Number of
Samples
512
124
107
18
Arithmetic
Range Mean
iooa
3-492 36
1 .4-3500 57
200a
<16-132 61
Standard
Deviation Reference
200 White et al . , 1984, NCRDS
Swanson et al., 1976
Valkovic, 1983a
200 White et al . , 1984, NCRDS
Swanson et al . , 1976
Values are based on the most comprehensive data set currently available and may be used as typical values for
manganese in coal from these regions.
NCRDS = National Coal Resource Data System maintained by USGS.
CData from the Swanson et al.. (1976) study are included in the NCRDS Arithmetic means from the entire NCRDS are
more representative than means from Swansora9 since the NCRDS contains many more coal samples. The Swanson data are
included here to give an idea of the range of values for manganese content in individual coal samples from each
region.
-------
TABLE 3-39. CONCENTRATIONS OF MANGANESE IN OIL REPORTED IN PREVIOUS STUDIES
Number of
Type of Oil Samples
Residual #6 13
5
11
9
6
15
UJ 16
i
M
M
W
Distillate #2 3
2
Crude
Manganese Concentration (ppm)
Range
ND-2.3
0.1-0.98
<0. 0095-27
0.24-0.30
0.35-0.63
<0.1-0.79
<0. 060-2. 3
0.25-0.3
0.052-0.2
0.63-2.54
0. 013-1 .45b
Mean
0.36
0.47
0.57
0.28
0.48
0.41
0.36
1.33a
0.16
0.28
0.13
1.17
1.4
Standard Deviation Reference
0.65 Gordon, 1974
Suprenant et al ,
. , 1980b
0.58 Shih et al., 1980b
0.06 Mroe, 1976
Mroe, 1976
Mroe, 1976
0.65 Mroe, 1976
Tyndall et al. ,
Anderson, 1973
Suprenant et al,
1978
. , 1980b
Cato et al. , 1974
Yen, 1975
Vouk and Piver,
Anderson, 1973
1983
Based on weighted average of crude oil used in U.S.
Values are means of crude oil from ten states.
-------
TABLE 3-40. SUMMARY OF DATA FOR MANGANESE IN OIL
Manganese Concentration (ppm)
Type of Oil
Residual #6
Distillate #2
Crude
Range
ND-273
0.015-1.45
0.63-2.54
Typical Value
0.49b
0.21C
1.3d
o
ND = not detectable.
Average of nine studies in Table 3-39.
Ł
Average of two studies reported in Table 3-39
Average of two studies in Table 3-39.
TABLE 3-41. CONCENTRATION OF MANGANESE IN U.S. VERSUS FOREIGN CRUDE OILS
Range (ppm)
Mean (ppm)
Reference
Foreign
___
Domestic 0.63-2.54
0. 013-1 .45a
0.79
0.21
0.048
1.17
1.4
Valkovic, 1983a
Valkovic, 1983a
PedCo, 1982
Yen, 1975
Vouk and Piver, 1983
Anderson, 1973
Values are means for crude oils from ten states,
3-118
-------
TABLE 3-42. CONCENTRATION OF NICKEL IN COAL BY COAL TYPE3
Coal Type
Bituminous
Subbitumious
Anthracite
Lignite
Number of
Samples
3527
640
52
183
Nickel
Mean
16.9
7.02
28.5
8.35
Concentration (ppm)
Standard Deviation
19.2
8.44
32.0
19.7
aData presented in White et al.. (1984); based on data in the USGS National
Coal Resources Data System (NCRDS) as of 1982. Arithmetic means from this
study may be used as typical values for nickel content of these types of
coals.
TABLE 3-43. RANGES OF NICKEL CONCENTRATION IN COALS BY COAL TYPE
Nickel Concentration
Coal Type Range (ppm)
Bituminous 1.5->300
Subbituminous 0.32-69
Anthracite 17-50
Lignite 3-70
a
Lowest and highest values reported in any of the literature reviewed.
Note: The White et al.. (1984) study does not list the range of values in
the NCRDS. The Swanson et al.. (1976) study, which is a subset of the
NCRDS describing about 800 coal samples, does include ranges for bituminous
and lignite coals from certain geographical regions. Valkovic (1983a) lists
ranges for nickel concentration in subbituminous coals.
3-119
-------
TABLE 3-44. NICKEL CONCENTRATION IN COAL BY REGION
OJ
I
NJ
O
Region
Appalachian
Interior
Illinois Basin
Gulf Province
Northern Plains
Rocky Mountains
Number of
Samples
2749
331
592
155
82
38
34
371
490
184
124
Nickel Concentration (ppm)
Arithmetic Standard
Range Mean Deviation
15. 4a 14.7
1.5->300 15
26. 7a 32.6
1-200 30
0.87-580 26
8-68 22.4 10.8
14. Oa 13.0
3-70 20
5.33a 9.67
<0. 5-300 5
6.71a 8.19
0.7-20 3
0.35-340 6.5
Reference
White et al . , 1984, NCRDSb
Swanson et al., 1976c
White et al . , 1984. NCRDS
Swanson et al . , 1976
Valkovic, 1983a
Ruch9 1974
White et al.. 1984. NCRDS
Swanson et al., 1976
White et al . , 1984, NCRDS
Hatch and Swanson, 1977
White et al . , 1984. NCRDS
Swanson et al., 1976
Valkovic, 1983
-------
TABLE 3-44. NICKEL CONCENTRATION IN COAL BY REGION (Continued)
Njckel Concentration (ppm)
Region
Alaska
Number of
Samples
107
18
Arithmetic
Range Mean
11. 2a
2-30 10
Standard
Deviation
8.8
Reference
White et al. ,
Swan son et al
1984, NCRDS
., 1976
fl
Values are based on the most comprehensive data set currently available and may be used as typical values for nickel
in coal from these regions.
NCRDS = National Coal Resource Data System maintained by USGS.
i \ f*
i Data from the Swanson et al.. (1976) study are included in the NCRDS. Arithmetic means from the entire NCRDS are
li "- - *
N> more representative than means from Swanson, since the NCRDS contains many more coal samples. The Swanson data are
included here to give an idea of the range of values for nickel content in individual coal samples from each region.
Eastern segment of Interior Basin.
-------
TABLE 3-45. CONCENTRATIONS OF NICKEL IN OIL REPORTED IN PREVIOUS STUDIES
Co
I
Number of
Type of Oil Samples
Residual #6 5
9
6
15
11
Distillate #2 3
1
2
Crude 24
1
1
1
1
__
Range
10-73
14-21
10-20
13-24
6-51
1-18
0.15-1.7
0.3-35
49.1-344.5
1.4-4.3
Nickel Concentration (ppm)
Mean Standard Deviation
26.2
17
15
17
19 0.54
50.07
6.67
0.09
165.8
98.4
49.1
117
0.6
2.4-
Reference
Suprenant et al . ,
Mroe, 1976
Mroe, 1976
Mroe, 1976
Shih et al., 1980b
1980b
Slater and Hall, 1974
Suprenant et al . ,
Castaldini et al.,
Cato et al. , 1974
Spait and Devitt,
Yen, 1975
PedCo, 1982
PedCo, 1982
PedCo, 1982
PedCo, 1982
Anderson, 1973
1980b
1981b
1979
-------
TABLE 3-46. SUMMARY OF DATA FOR NICKEL IN OIL
Type of Oil
Nickel Concentration (ppm)
Range
Typical Value
Residual #6
Distillate #2
Crude
6-73
0.15-18
0.3-344.5
24 .Oa
3.381
72.2C
Average of six studies in Table 3-45.
Average of two studies in Table 3-45.
Q
Average of six studies in Table 3-45.
TABLE 3-47. NICKEL CONCENTRATION IN U.S. VERSUS FOREIGN CRUDE OILS
Range (ppm) Mean (ppm)
Foreign 44.1
8.8
59
117
0.609
Domestic 0.3-35
49.1-344.5 165.8
1.4-4.3 2.4
93.5
Reference
Anderson, 1973
Anderson, 1973
Anderson, 1973
PedCo, 1982
PedCo, 1982
Spait and Devitt, 1979
Yen, 1975
Anderson, 1973
Filby: 1975
3-123
-------
TABLE 3-48. CONCENTRATION OF THORIUM IN COAL BY COAL TYPE1
Coal Type
Bituminous
Subbituminous
Anthracite
Lignite
Number of
Samples
3527
640
52
183
Thorium Concentration (ppm)
Mean
3.03
5.13
6.09
7.13
Standard Deviation
3.15
4.64
2.92
5.70
aData presented in White ej, al.. 1984; based on data in the USGS National
Coal Resources Data System (NCRDS) as of 1982. Arithmetic means from this
study may be used as typical values for thorium content of these types of
coals.
TABLE 3-49. RANGES OF THORIUM CONCENTRATION IN COALS BY COAL TYPE
Thorium Concentration
Coal Type Range (ppm)a
Bituminous 2.2-79
Subbituminous <3-18
Anthracite 2.8-14.4
Lignite <3-28.4
a
Lowest and highest values reported in any of the literature reviewed.
Note: The White et al.. (1984) study does not list the range of values in
the NCRDS. The Swanson e_t aJL_._, (1976) study, a subset of the NCRDS
describing about 800 coal samples, does include ranges. This table is based
on the Swanson work.
3-124
-------
TABLE 3-50. THORIUM CONCENTRATION IN COAL BY REGION
10
I-1
10
Thorium Concentration
Region
Appalachian
Interior
Illinois Basin
Gulf Province
Northern Plains
Rocky Mountains
Alaska
Number of
Samples
2749
331
592
56
38
34
371
93
512
134
107
18
Range
2.2-47.8
0.71-5.1
<3-28.4
<2-8.0
O-34.8
<3-18
Arithmetic
Mean
2.98a
4.9
3.73a
2.1
8.96a
8.3
4.30a
2.7
5.13a
3.6
3.49a
4.4
a
Values are based on the most comprehensive data set currently available
thorium in coal from these regions.
NCRDS = National Coal Resource Data System maintained by USGS.
CData from the Swanson et al., (1976) study are included in the NCRDS.
(ppm)
Standard
Deviation
2.33
6.60
0.87
6.33
3.74
4.65
2.54
and may be used
Arithmetic means
Reference
White et al., 1984. NCRDSb
Q
Swanson et al., 1976
White e_t al_._, 1984, NCRDS
Gluskoter et al . , 1977
White et al., 1984, NCRDS
Swanson et al., 1976
White et al . . 1984. NCRDS
Swanson et al., 1976
White et al . , 1984. NCRDS
Swanson et al., 1976
White et al . , 1984. NCRDS
Swanson et al., 1976
as typical values for
from the entire NCRDS
contains data for many more coal samples. The Swanson data are included here to give a indication of the range of
values for thorium content in individual coal samples from each region.
Eastern portion of Interior Basin.
-------
TABLE 3-51. CONCENTRATION OF THORIUM-232 IN COAL BY STATE OR REGION
u>
t-1
K>
O>
State/Region
Illinois
Wyoming
Colorado
Kentucky
Pennsylvania
Appalachian
Number of Thorium-232 Concentration (pli/g)
Samples Range Mean Reference
910 0.1-5.3 0.50 Beck and Miller, 1980
3 0.11-0.21 0.15 Beck et al., 1980
1 0.291 Office of Radiation Programs, 1979
3 0.385-0.493 0.423 Office of Radiation Programs, 1979
2 0.198-0.402 0.3 Office of Radiation Programs, 1979
0.40 Beck et al . , 1980
0.43 Beck et al., 1980
Q
A comprehensive data set of thorium-232 concentrations in coal by region or coal type was not found in the
literature searched. The data presented here provides an indication of the concentration of thorium-232 in coal
samples in different states.
-------
TABLE 3-52. CONCENTRATION OF URANIUM IN COAL BY COAL TYPE3
Coal Type
Bituminous
Subbituminous
Anthracite
Lignite
Number of
Samples
3527
640
52
183
Uranium Concentration (ppm)
Mean
1.85
2.13
1.94
3.37
Standard Deviation
2.71
3.84
3.38
10.3
aData presented in White et. al.. 1984; based on data in the USGS National
Coal Resources Data System (NCRDS) as of 1982. Arithmetic means from this
study may be used as typical values for uranium in coal.
TABLE 3-53. RANGES OF URANIUM CONCENTRATION IN COALS BY COAL TYPE
Uranium Concentration
Coal Type Range (ppm)a
Bituminous <0.2-59
Subbituminous 0.4-76
Anthracite 0.3-25.2
Lignite 0.5-16.7
aLowest and highest values reported in the literature reviewed. Note: The
White et al.. (1984) study does not list the range of values in the NCRDS.
The Swanson et al.. (1976) study, a subset of the NCRDS containing data on
about 800 coal samples does provide ranges. This table is based primarily
on the Swanson et al.. (1976) study and Valkovic, (1983a).
3-127
-------
TABLE 3-54. URANIUM CONCENTRATION IN COAL BY REGION
Region
Appalachian
Interior
Illinois Basin
Gulf Province
Northern Plains
Rocky Mountains
Number of
Samples
2749
331
592
56
38
34
371
93
512
134
Uranium Concentration (ppm)
Arithmetic Standard
Range Mean Deviation
1.66a 1.87
<0.2-10.5 1.4
0.1-19 1.6
2.98a 5.07
0.20-59 3.2
0.31-4.6 1.5
3.07a 2.64
0.5-16.7 3.2
1.59a 2.24
<0,2-2.9 0.9
2.40a 4.40
<0.2-23.8 1.6
0.06-76 2.8
Reference
White et al . . 1984, NCRDSb
Ł
Swanson et al . , 1976
Valkovic, 1983a
White et al., 1984, NCRDS
Valkovic , 1983a
Swanson et al . , 1976
White et al., 1984. NCRDS
Swanson et al., 1984
White et al., 1984, NCRDS
Swanson et al., 1976
White et al . , 1984, NCRDS
Swanson et al., 1976
Valkovic, 1983a
-------
TABLE 3-54. URANIUM CONCENTRATION IN COAL BY REGION (Continued)
Uranium Concentration (ppm)
Region
Alaska
Number of
Samples
107
18
Arithmetic
Range Mean
1 .28a
0.4-5.2 1.2
Standard
Deviation
1.43
Reference
White et al. ,
Swan son et al
1984, NCRDS
., 1976
o
Values are based on the most comprehensive data set currently available and may be used as typical values for
uranium in coal from these regions.
NCRDS = National Coal Resource Data System maintained by USGS.
Ł
Data from the Swanson et al.. (1976) study are included in the NCRDS. Arithmetic means from the entire NCRDS are
more representative than means from Swanson, since the NCRDS contains many more coal samples. The Swanson data are
included here to give an idea of the range of values for uranium content in individual coal samples from each
region.
-------
TABLE 3-55. CONCENTRATION OF URANIUM-238 IN COAL BY STATE OR REGION
OJ
o
State/Region3
Wyoming
Montana
Illinois
Colorado
Kentucky
Appalachian Region
Number of
Samples
910
4
3
3
2
Uranium-238 Concentration
(pCi/K)
Range Mean
0.1-15 0
0
<0
0
0.780-0.983 0
0.660-1.16 0
0
.60
.42
.1
.61
.877
.91
.80
Reference
Beck and Miller, 1980
Beck et al. , 1980
Beck et
Beck et
Office
Office
Beck et
al.. 1980
al.. 1980
of Radiation Programs,
of Radiation Programs,
al.. 1980
1979
1979
aA comprehensive data set providing information on uranium-238 concentrations in coal by region or coal type was
not found in the literature searched. The data presented here provide an indication of the uranium-238
concentrations in coals from different states in the U.S.
-------
TABLE 3-56. POPULATION CHARACTERISTICS OF UTILITY, INDUSTRIAL AND
COMMERCIAL BOILERS IN TERMS OF BOILER DESIGN AND FUELS, 1978
Boiler Type
Coal-Fired Boilers
Pulverized Dry Bottom
Pulverized Wet Bottom
Cyclone
Stoker
Oil -Fired Boilers
Gas-Fired Boilers
Otherd
Percent
Utility3
49.6
7.2
7.4
0.7
21.6
13.6
-
of Total Fuel Use
for Each Sectc
Industrial
7.1
1.7
0.4
7.1
19.6
57.4
0.01
(Heat Input)
)r
Commercial/
Institutional
0.4
0.02
-
2.4
51.6
43.6
0.04
Total fuel consumption
by external., combustion
sources (10 Btu)
16,761
8,236
4,777
Source: Shih et al., 1980b
'Source: Suprenant et al., 1980a
"Source: Suprenant et al., 1980b
Other includes wood and refuse.
3-131
-------
TABLE 3-57. DISTRIBUTION OF PARTICULATE CONTROL EQUIPMENT FOR
BITUMINOUS COAL-FIRED UTILITY BOILERS, 1975*
OJ
(-1
u>
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
Percent
ESP
60
79
83
52
66
77
61
83
89
8
29
44
Distribution of
Centrifugal
Separator
17
10
11
20
11
9
5
8
5
36
32
25
Particulate Control
Other5
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: Shih et al., 1980b.
3Wet scrubbers, fabric filters, gravitational separators.
-------
TABLE 3-58. COAL ASH DISTRIBUTION BY BOILER TYPEa
Percent Fly Ash/Percent Bottom Ash
Furnace Type
Pulverized dry bottom
Pulverized wet bottom
Cyclone
Stoker
Bituminous
Coa?
80/20
65/35
13.5/86.5
60/40
Lignite
Goal0
35/65
30/70
35/65
Anthracite
Goal0
85/15
5/95
aSource: Baig et al., 1981
Based on several studies of coal ash from large and intermediate size coal-
fired boilers.
c
Based on an analysis of uncontrolled particulate emissions.
3-133
-------
TABLE 3-59. SUMMARY OF RECOMMENDED TRACE POLLUTANT
EMISSION FACTORS FOR OIL COMBUSTIONa'b
12
Emission Factor (lb/10 Btu)
Pollutant
Arsenic
Beryllium
Cadmium
Chromium
Copper
Mercury
Manganese
Nickel
POM
Formaldehyde
Residual Oil
19
4.2
15.7
21
280
3.2
26
1260
8.4C
405
Distillate Oil
4.2
2.5
10.5
48
280
3.0
14
170
22.5
405
All emission factors are uncontrolled, and are applicable to oil-fired
boilers and furnaces in all combustion sectors. The Derivation of
these factors is presented in Section 3.6.1.1.
See definition of recommended factors in Section 1.2.
This value was calculated using all available residual oil data given
in Table 3-93. If the upper end of the range of available data is
excluded when calculating an average value (which could be used in this
table), the average factor for POM from residual oil combustion becomes
4.1 lb/10 BTU.
3-134
-------
TABLE 3-60. CALCULATED UNCONTROLLED ARSENIC EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS
Recommended
.. b,c,d
Value '
Tyndall
et al., 1978
Previous Studies
Shih
et al., 1980b
Suprenant
et al., 1980a
Suprenant
et al., 1980b
Leavitt
et al., 1980b
Emission Factor
(lb/1012 Btu)
Concentration
in Fuel (ppm)
19
0.36
42
0.8
28
0.51
2.8
21.1
.087-0.4
<0.5
<0.01
OJ
Ui
Calculated assuming all arsenic present in the oil feed is emitted through the stack.
Based on typical level of arsenic in residual oil derived in Section 3.3.1. Emission factor assumes all arsenic
present in oil feed is emitted through the stack. A density of 944 g/1 and a heating value of 150,000 Btu/gal are
assumed.
"See definition of recommended factors in Section 1.2.
j 12
Calculated arsenic emission factors (lb/10 Btu) foi
ESP, 2.28; scrubber, 1.90. See text for discussion.
Calculated arsenic emission factors (lb/10 Btu) for controlled residual oil-fired boilers are: multiclone, 9.31;
-------
TABLE 3-61. MEASURED ARSENIC EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS
Fuel Characteristics
(Arsenic
Emission Factor Content
(lb/10 Btu) Type ppm)
7.0b 1:1 Residual/ Ť1.0)
Crude Oil
27C 1:1 Residual/ Ť2.0)
Crude Oil
6.3d 1:1 Residual/ Ť2.0)
Crude Oil
4.2e #6 Oil Ť2.0)
34f #6 Oil (<2.0)
37f #6 Oil Ť2.0)
1148 #6 Oil Ť2.0)
22h #6 Oil (2.0)
, Control
Status Sectors8 Boiler Type
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Multiclone
(tested at
scrubber inlet)
Multiclone/
Scrubber
U Wall-fired
U Wall-fired
U Wall-fired
I Water tube
I Water tube
I Water tube
I Integral Coal/
Oil Furnace
I Integral Coal/
Oil Furnace
Reference
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Carter e^ al.. 1978
Carter et al . , 1978
Carter et al . , 1978
Leavitt et al. , 1978b;
Fischer et al. , 1979
Leavitt et al., 1978b;
Fischer et al. , 1979
1981b
1981b
1981b
SU = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
Tested under baseline (design) operating conditions.
°Low-NO operating conditions - flue gas is recirculated, top row of burners admit air only while lower burners admit
fuel at greater than baseline rates.
Low-NO operating conditions - flue gas is recirculated, all burners in service.
6Tested under baseline (design) conditions. Arsenic determined by atomic absorption.
Tested under low-NO operating conditions - reduced excess air and maximum flue gas recirculation. Arsenic
determined by atomic absorption.
^Tested at scrubber inlet of the same boiler as in footnote h.
Tested at scrubber outlet.
-------
TABLE 3-62. CALCULATED UNCONTROLLED ARSENIC EMISSION FACTORS
FOR DISTILLATE OIL-FIRED BOILERS3
Previous Studies
Recommended Suprenant Suprenant
Valueb'c'd et al., 1980b et al., 1980a
Emission Factor 4.2 3 .Oe 8.1
(lb/1012 Btu)
Concentration 0.085 0.1-0.216
in Fuel (ppm)
aCalculated assuming all arsenic present in oil feed is emitted through the
stack.
Calculated from typical level of arsenic in distillate oil derived in
Section 3.3.1. Emission factor assumes all arsenic present in oil feed is
emitted through the stack. A density of 7.05 Ib/gal and heating value of
141,000 Btu/gal are assumed.
Q
See definition of recommended factors in section 1.2.
j 1Ť
Calculated arsenic emission factors (lb/10 Btu) for controlled distillate
oil-fired boilers are: multiclone, 2.06; ESP, 0.50; scrubber, 0.42. See
text for discussion.
6There is an apparent discrepancy between the calculated emission factor and
the values measured for arsenic in the fuel as reported in this reference.
The reference states the assumption that all arsenic measured in the oil
feed is emitted through the stack, but the numbers presented do not agree
with this statement. This discrepancy could not be resolved from the
information given in the reference.
3-137
-------
TABLE 3-63. MEASURED ARSENIC EMISSION FACTORS FOR DISTILLATE OIL-FIRED BOILERS
U)
oo
Fuel Characteristics
Emission Factor
(lb/10 Btu)
3.5b
2.5C
2.0d
1.5
Type
Distillate
Distillate
Distillate
Distillate
(Arsenic
Content, ppm)
Ť0.9)
Ť0.9)
(0.019)
Control
Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Sector3 Boiler Type
R Conventional High
Pressure
R Blueray Low NO
R Blueray Low NO
R Hot Water Condensing
Heating System
Reference
Suprenant et al . ,
Castaldini et al .
Castaldini et al .
Castaldini et al.
1979
, 1981b
, 1981b
, 1982
u
Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
Average of eight tests run on seven units.
CUnit operating in a cycling mode, 10 minutes on, 10 minutes off.
Unit operating continuously.
-------
TABLE 3-64. CALCULATED UNCONTROLLED BERYLLIUM EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS*
Recommended
Value
b,c
Previous Studies
Tyndall Shih
et al, 1978 et al, 1980b
Suprenant
et al, 1980a
Suprenant
et al, 1980b
Leavitt
et al, 1980b
Anderson,
1973
Emission Factor 4.2
(lb/1012 Btu)
Concentration in 0.08
Fuel (ppm)
4.2
0.08
5.57
0.10
0.05 0.15 <0.5
0.0042-0.038 <0.01
5.3
0.1
CO
<Ł>
Calculated assuming all beryllium present in the oil feed is emitted through the stack.
Based on typical level of beryllium in residual oil derived in Section 3.3.2. Emission factor assumes all
beryllium present in the oil feed is emitted through the stack. A density of 944 g/1 and a heating value of
150,000 Btu/gal are assumed.
c 12
Calculated beryllium emission factors (lb/10 Btu) for controlled residual oil-fire boilers are:
ESP, 0.59; scrubber, 0.25. See text for discussion.
multiclone, 2.65;
There is an apparent discrepancy between the calculated emission factor and the values measured for beryllium in
the fuel as reported in the reference. The reference states the assumption that all beryllium measured in the
oil feed is emitted through the stack, but the numbers presented do not agree with this statement. This
discrepancy could not be resolved from the information given in the reference.
-------
TABLE 3-65. MEASURED BERYLLIUM EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS
!
M
O
Fuel Characteristics
Emission Factor
(lb/1012 Btu)
1.3
0.27b
250C
0.14d
4.0e
5.3f
3.7f
0.78
0.78
Type
#6 Oil
1:1 Residual
Crude
1:1 Residual
Crude
1:1 Residual/
Crude
#6 Oil
#6 Oil
#6 Oil
#6 Oil
#6 Oil
(Be Content, Control
ppm) Status Sectors
(0.024)
Ť2.0)
Ť2.0)
Ť3.0)
Ť3.0)
Ť3.0)
Ť0.05)
Ť0.05)
ESP U
Uncontrolled U
Uncontrolled U
Uncontrolled U
Uncontrolled I
Uncontrolled I
Uncontrolled I
Multiclone (tested I
at Scrubber Inlet)
Multiclone/FGD I
Scrubber
Boiler Type
NR
Wall -Fired
Wall -Fired
Wall-Fired
Watertube Boiler
Watertube Boiler
Watertube Boiler
Integral Coal/
Oil Furnace
Integral Coal/
Oil Furnace
Reference
Anderson, 1973
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Carter et al., 1978
Carter et al . , 1978
Carter et al. , 1978
Leavitt et al . , 1978b;
Fischer et al . , 1979
Leavitt et al . . 1978b;
Fischer et al. , 1979
1981b
1981b
1981b
aU = Utility, I = Industrial, C = Commercial/Institutional, R = Residual.
Tested under baseline (design) operating conditions.
Tested under low-NO operating conditions - flue gas is recirculated, top row of burners admit air only while lower
burners admit fuel at greater than baseline.
Tested under low-NO operating conditions - flue gas is recirculated, all burners in service.
A
eTested under baseline (design) conditions.
Tested under low-NO operating conditions - reduced excess air and maximum flue gas recirculation. Beryllium
determined by atomic absorption.
^Tested at scrubber inlet of the same boiler as in footnote h.
^Tested at scrubber outlet.
-------
TABLE 3-66. CALCULATED UNCONTROLLED BERYLLIUM EMISSION FACTORS
FOR DISTILLATE OIL-FIRED BOILERSa
Previous Studies
Recommended Suprenant Suprenant
Valueb)C>d et al., 1980b et al., 1980a
Emission Factor 2.5 0.096 0.05
(lb/1012 Btu)
Concentration 0.05 <0.0076e
in Fuel (ppm)
Calculated assuming all beryllium present in oil feed is emitted through the
stack.
Calculated from typical level of beryllium in distillate oil derived in
Section 3.3.2. Emission factor assumes all beryllium present in oil feed is
emitted through the stack. A density of 7.05 Ib/gal and heating value of
141,000 Btu/gal are assumed.
/Ť
See definition of recommended factor is Section 1.2.
j 19
Calculated beryllium emission factors (lb/10 Btu) for distillate oil-fired
boilers are: multiclone, 1.58; ESP, 0.35; scrubber, 0.15. See text for
discussion.
eThere is a discrepancy between the calculated emission factor and the values
measured for beryllium in the fuel as reported in this reference. The
reference states the assumption that all beryllium measured in the oil feed
is emitted through the stack, but the numbers presented do not agree with
this statement. This discrepancy could not be resolved from the information
given in the reference.
3-141
-------
TABLE 3-67. MEASURED BERYLLIUM EMISSION FACTORS FOR DISTILLATE OIL-FIRED BOILERS
Fuel Characteristics
Emission Factor
(lb/1012 Btu) Type
0.64 Distillate
0.52b Distillate
1.2C Distillate
(Beryllium
Contents ppm)
(0.1)
(0.1)
(0.19)
Control
Status
Uncontrolled
Uncontrolled
Uncontrolled
Q
Sectors Boiler Type
R Bluer ay Low NO
R Blueray Low NO
R Hot Water Condensing
Heating Systems
Reference
Castaldini et al . , 1981b
Castaldini et al . , 1981b
Castaldini et al . , 1982
U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
Unit operating in a cycling mode, 10 minutes on, 10 minutes off.
C
Unit operating continuously.
-------
TABLE 3-68. CALCULATED UNCONTROLLED CADMIUM EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS
Recommended
Valueb>e
Tyndall
et al, 1978
Previous Studies
Shih
et al 1980b
Suprenant
et al 1980a
Suprenant
et al, 1980b
Anderson,
1973
Anderson,
1973
Emission Factor
(lb/1012 Btu)
Concentration
in Fuel (ppm)
15.7
0.3
121
2.27
16
0.30
1.5
0.46
130-270
20-27
0.02-0.94° 3.0-5.Od 0.4-0.5
Calculated assuming all cadmium present in oil feed is emitted through the stack.
Based on typical level of cadmium in residual oil derived in Section 3.3.3. Emission factor assumes all cadmium
present in oil feed is emitted through the stack. A density of 944 g/1 and a heating value of 150,000 Btu/gal are
assumed.
c
There is an apparent discrepancy between the calculated emission factor and the values measured for cadmium in the
oil as reported in this reference. The reference states the assumption that all cadmium measured in the fuel is
emitted through the stack, but the numbers presented do not agree with this statement. This discrepancy could not
be resolved from the information given in the reference.
Number 6 oil from the Virgin Islands, Trinidad, and Curacao.
Calculated cadmium emission factors (lb/10 Btu) for controlled residual oil-fire boilers are: multiclone, 46.86;
ESP, 9.90; scrubber, 3.96. See text for discussion.
-------
TABLE 3-69. MEASURED CADMIUM EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS
Fuel Characteristics
Emission Factor (Cadmium Control
(lb/10 Btu) Type Content, ppm) Status
33b
8.2C
0.048d
8.6e
3.0f
0.69f
21 28
49h
1:1 Residual/
Crude
1:1 Residual/
Crude
1:1 Residual/
Crude
#6 Oil
t 6 Oil
#6 Oil
# 6 Oil
#6 Oil
Ť0.5)
Ť0.7)
Ť0.7)
Ť3.0)
Ť3.0)
Ť3.0)
Ť3.5)
Ť3.5)
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Multiclone
Multiclone/
Scrubber
0
Sector Boiler Type
U Wall -Fired
U Wall-Fired
U Wall-Fired
I Water tube
I Watertube
I Watertube
I Integral Coal/
Oil Furnace
I Integral Coal/
Oil Furnace
Reference
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Carter et al. , 1978
Carter et al . , 1978
Carter et al. , 1978
Leavitt et al., 1978b;
Fischer et al . , 1979
Leavitt et al . , 1978b;
Fischer et al. , 1979
1981b
1981b
1981b
aU = Utility, I = Industrial, C = Commercial/Industrial, R = Residential.
Tested under baseline (design) operating conditions.
C
Tested under low-NO operating conditions - flue gas is recirculated, top row of burners admit air only while lower
burners admit fuel at greater than baseline rates.
Tested under low-NO operating conditions - flue gas recirculated, all burners in service.
6Tested under baseline (design) operating conditions. Beryllium determined by atomic absorption.
Tested under low-NO operating conditions - reduced excess air and maximum flue gas recirculation. Beryllium
analyzed by atomic absorption.
^Tested at scrubber inlet of the same boiler as in footnote h,
Tested at scrubber outlet.
-------
TABLE 3-70. CALCULATED UNCONTROLLED CADMIUM EMISSION
FACTORS FOR DISTILLATE OIL-FIRED BOILERS3
Previous Studies
Recommended Supre riant Suprenant
Valueb)C'd et al., 1980b et al., 1980a
Emission Factor 10.5 5.8e 3.0
(lb/1012 Btu)
Concentration 0.21 0.95e
in Fuel (ppm)
Calculated assuming all cadmium present in oil feed is emitted through the
stack.
Calculated from typical level of cadmium in distillate oil derived in
Section 3.3.3. Emission factor assumes all cadmium present in oil feed is
emitted through the stack. A density of 7.05 Ib/gal and heating value of
141,000 Btu/gal are assumed.
See definition of recommended factors in Section 1.2.
d 12
Calculated cadmium emission factors (lb/10 Btu) for controlled distillate
oil-fired boilers are: multiclone, 7.45; ESP, 1.58; scrubber; 0.63. See
text for discussion.
ethere is an apparent discrepancy between the calculated emission factor and
the values measured for cadmium in the fuel as reportrd in this reference.
The reference states the assumption that all arsenic measured in the oil
feed is emitted through the stack, but the numbers presented do not agree
with this statement. This discrepancy could not be resolved from the
information given in the reference.
3-145
-------
TABLE 3-71. MEASURED CADMIUM EMISSION FACTORS FOR DISTILLATE OIL-FIRED BOILERS
u>
Fuel Characteristics
Emission Factor
(lb/10 Btu)
25. 6b
4.9C
7.5d
NDe
Type
Distillate
Distillate
Distillate
Distillate
(Cadmium
Content, ppm)
(0.10)
(0.10)
(0.19)
Control
Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Sector3
R
R
R
R
Boiler Type
Conventional High
Pressure
Blueray Low NO
Blueray Low NO
Hot Water Condensing
Heating System
Reference
Suprenant et al . ,
Castaldini et al .
Castaldini et al.
Castaldini et al .
1979
, 1981b
, 1981b
, 1982
U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
Average, of eight tests run on seven units.
Unit operating in a cycling mode, 10 minutes on, 10 minutes off.
iJnit operating continuously.
eND = not detectable.
-------
TABLE 3-72. CALCULATED UNCONTROLLED CHROMIUM EMISSIONS FROM RESIDUAL OIL-FIRED BOILERS3
Previous Studies
Recommended Tyndall Suprenant Shih Suprenant Leavitt
Value >C> et al, 1978 et al, 1980b et al, 1980b et al, 1980a et al, 1980b
Emission Factor 21 (0.15)e 69.7 116f 48.7
(lb/1012 Btu)
Concentration 0.40 1.3 0.2-0.5f 0.90
in Fuel (ppm)
68 5
0.09
a
Calculated assuming all chromium in oil feed is emitted through the stack.
b
Based on typical level of chromium in residual oil derived in Section 3.3.4. Emission factor assumes all chromium
present in oil feed is emitted through the stack. A density of 944 g/1 and a heating value of 150,000 Btu/gal are
assumed.
c
See definition of recommended factors in Section 1.2.
j 10
Calculated chromium (total) emission factors (lb/10 Btu) for controlled residual oil-fired boilers are:
multiclone, 12.18; ESP, 6.09; scrubbers, 1.68. The calculated hexavalent chromium emission factors (lb/10 Btu)
for controlled residual oil-fired boilers are: multiclone, 0.04; ESP, 0.02; scrubber, 0.01. See text for
discussion.
The value in parentheses is for hexavalent< chromium (Cr ). It was derived by applying the ratio of hexavalent
chromium to total chromium emissions to an existing emission factor for utility boilers burning residual oil
(see text, Section 3.6.5).
There is an apparent discrepancy between the calculated emission factor and the values measured for chromium in the
fuel as reported in this reference. The reference states the assumption that all arsenic measured in the oil feed
is emitted through the stack, but the numbers presented do not agree with this statement. This discrepancy could
not be resolved from the information given in the reference.
-------
TABLE 3-73. MEASURED CHROMIUM EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS
-p-
oo
Fuel Characteristics
Emission Factor (Chromium
(lb/10 Btu) Type Content, ppm
22.6
4.6
2.0
93 c
80d
120e
500C
560f
330f
#6 Oil
#5 Oil
#4 Oil
1:1 Residual/ (5.0)
Crude Oil
1:1 Residual/ (3.0)
Crude Oil
1:1 Residual/ (4.0)
Crude Oil
#6 Oil Ť5.0)
#6 Oil Ť5.0)
#6 Oil Ť5.0)
Control
) Status Sector3 Boiler Type
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
C Scotch with
Rotary Burner
C Scotch with Air
Atomizing Burner
C Scotch with Air
Atomizing Burner
U Wall-fired
U Wall -fired
U Wall-fired
I Watertube
I Watertube
I Watertube
Levy et
Levy et
Levy et
Sawyer
Sawyer
Sawyer
Carter
Carter
Carter
Reference
al.. 1971
al. , 1971
al. , 1971
and Higginbotham,
and Higginbotham,
and Higginbotham,
et al.. 1978
et al.. 1978
et al. . 1978
1981b
1981b
1981b
-------
TABLE 3-73. MEASURED CHROMIUM EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS (Continued)
Fuel Characteristics
Emission Factor (Chromium Control
(lb/10 Btu) Type Content, ppm) Status Sector3 Boiler Type
128g #6 Oil (2.2) Multi clone I
(tested at
scrubber inlet)
13h #6 Oil (2.2) Multiclone/ I
Scrubber
Integral Coal/
Oil Burner
Integral Coal/
Oil Burner
Leavitt
Fischer
Leavitt
Fischer
Reference
et al. , 1978b;
et al.. 1979
et al.. 1978b;
et..al, 1979
n
U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
Calculations assume 146,000 Btu/gal for #4 oil; 148,000 Btu/gal for #5 oil; and 150,000 Btu/gal for #6 oil.
CO
I C
i-* Operating under design (baseline) conditions.
* j
Operating under high level of NO control - flue gas is recirculated, top row of burners admit air only (no fuel),
lower burner admit fuel at greater than baseline rates.
g
Flue gas recirculation, all burners in service.
Unit operating under low-NO conditions - reduced excess air and maximum flue gas recirculation. Sample analyzed
by atomic absorption.
or
Tested at scrubber inlet of the same boiler in footnote h.
Tested at scrubber outlet.
-------
TABLE 3-74. CALCULATED UNCONTROLLED CHROMIUM EMISSION
FACTORS FOR DISTILLATE OIL-FIRED BOILERS3
Previous Studies
Recommended Suprenant Suprenant
Valueb)C'd et al., 1980b et al., 1980a
Emission Factor 47.5 (0.17-0.23)6 83.7 56.0
(lb/1012 Btu)
Concentration 0.95 0.8-2.0
in Fuel (ppm)
Calculated assuming all chromium present in oil feed is emitted through
the stack.
Based on typical level of chromium in distillate oil derived in
Section 3.3.4. Emission factor assumes all chroium present in oil feed
is emitted through the stack. A density of 7.05 Ib/gal and heating value
of 141S000 Btu/gal is assumed.
Q
See definition of recommended factor in Section 1.2.
Calculated total chromium emission factors (lb/10 Btu) for controlled
distillate oil-fired boilers are: multiclone, 27.8; ESP, 13.92; scrubber;
3.84. The calculated hexavalent chromium emission factors (lb/10 Btu)
for controlled distillate oil-fired boilers are: multiclone, 0.08;
ESP, 0.04; scrubber; 0.01. See text for discussion.
The range of values in parentheses are for hexavalent chromium. They were
derived by applying the ratio of hexavalent chromium to total chromium
emissions (obtained from tests of a coal-fired boiler) to existing
emission factors for distillate oil-fired boilers. By sector, the
hexavalent chromium emission factors are: industrial boilers, 0.17;
commercial boilers, 0.23; residential boilers, 0.20. See text for
discussion (Section 3.6.5).
3-150
-------
TABLE 3-75. MEASURED CHROMIUM EMISSION FACTORS FOR DISTILLATE OIL-FIRED BOILERS
u>
Fuel Characteristics
Emission Factor (Chromium Control
(lb/10 Btu) Type Content, ppm) Status Sector3 Boiler Type
2.3-2.5b #2 Oil
6.1-9.1b #2 Oil
26 Distillate
370e Distillate
67.4 Distillate
3.0 Distillate
Uncontrolled R
Uncontrolled R
(1.2) Uncontrolled R
(1.2) Uncontrolled R
Uncontrolled R
(0.38) Uncontrolled R
Cast Iron
Cast Iron
Bluer ay Low NO
Blueray Low NO
Conventional High
Pressure
Hot Water Condensing
Heating System
Reference
Levy et al., 1971
Levy et al. , 1971
Castaldini et al.
Castaldini et al .
Suprenant et al . ,
Castaldini, 1982
, 1981b
, 1981b
1979
U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
Two tests. Calculations assume heating value of 141,000 Btu/gal for #2 oil.
"Conversion burner in cast iron boiler - high pressure gun type.
Unit operating in a cycling mode, 10 minutes on, 10 minutes off.
"Unit operating continuously.
Eight tests were run for seven units.
-------
TABLE 3-76. CALCULATED UNCONTROLLED COPPER EMISSIONS FROM RESIDUAL OIL-FIRED BOILERS8
Previous Studies
Recommended Tyndall Suprenant Shih Suprenant Leavitt
Value >C> et al. 1978 et al. 1980b et al. 1980b et al. 1980a et al. 1980b
Emission Factor 278 149 216 812 67.9 5
(lb/1012 Btu)
Concentration 5.3 2.8 0,8-9.5 15 0.1
in Fuel (ppm)
a
Calculated assuming all copper in oil feed is emitted through the stack.
K
Based on typical level in residual oil derived in Section 3.3.5. Emission factor assumes all copper present in oil
feed in emitted through the stack. A density of 944 g/1 and a heating value of 150,000 Btu/gal are assumed.
See definition of recommended factors in Section 1.2.
j 12
Calculated copper emission factors (lb/10 Btu) for controlled residual oil-fired boilers are: multiclone, 165.2;
ESP, 42.0; scrubber, 25.2. See text for discussion.
-------
TABLE 3-77. MEASURED COPPER EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS
Ui
U)
Fuel Characteristics
Emission Factor (Copper Control
(lb/10 Btu) Type Content, ppm) Status Sector3 Boiler Type
13.3
7.4
9.6
48C
490d
1100e
21°
24f
59f
#6 Oilb
#5 Oilb
#4 Oilb
1:1 Residual/ (23.0)
Crude Oil
1:1 Residual/ (53.0)
Crude Oil
1:1 Residual/ (16.0)
Crude Oil
#6 Oil Ť3.0)
#6 Oil Ť3.0)
#6 Oil Ť3.0)
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
C Scotch with
Rotary Burner
C Scotch with Air
Atomizing Burner
C Scotch with Air
Atomizing Burner
U Wall -fired
U Wall-fired
U Wall-fired
I Water tube
I Water tube
I Water tube
Levy et
Levy et
Levy et
Sawyer
Sawyer
Sawyer
Carter
Carter
Carter
Reference
al., 1971
al., 1971
al., 1971
and Higginbotham,
and Higginbotham,
and Higginbotham,
et al., 1978
et al.. 1978
et al., 1978
1981b
1981b
1981b
-------
TABLE 3-77. MEASURED COPPER EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS (Continued)
Fuel Characteristics
Emission Factor (Copper Control
(lb/10 Btu) Type Content, ppm) Status Sector3 Boiler Type
418g #6 Oil (1.4) Multiclone I
(tested at
scrubber inlet)
4.6h #6 Oil (72) Multiclone/ I
Scrubber
Integral Coal/
Oil Burner
Integral Coal/
Oil Burner
Leavitt
Fischer
Leavitt
Fischer
Reference
et al. , 1978b;
et al. , 1979
et al. , 1978b;
e_t al, 1979
rt
U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
Calculations assume 146,000 Btu/gal for #4 oil; 148,000 Btu/gal for #5 oil; and 150,000 Btu/gal for #6 oil.
c
Operating under design (baseline) conditions.
d
Operating under high level of NO control - flue gas is recirculated, top row of burners admit air only (no fuel),
lower burner admit fuel at greater than baseline rates.
o
Flue gas recirculation, all burners in service.
Unit operating under low-NO conditions - reduced excess air and maximum flue gas recirculation. Sample analyzed
by atomic absorption.
^Tested at scrubber inlet of the same boiler as in footnote h.
Tested at scrubber outlet.
-------
TABLE 3-78. CALCULATED UNCONTROLLED COPPER EMISSION
FACTORS FOR DISTILLATE OIL-FIRED BOILERS'
Recommended
Value*>C
Previous Studies
Suprenant,
1980b
Suprenant
et al., 1980a
Emission Factor
(lb/1012 Btu)
280
476
87.3
Concentration
in Fuel (ppm)
5.6
5.5-11.0
Calculated assuming all copper present in oil feed is emitted through
the stack.
See definition of recommended factors in Section 1.2.
c 12
The calculated copper emission factors (lb/10 Btu) for controlled
distillate oil-fired boilers are: multiclone, 165.2; ESP, 42;
scrubber, 25.2. See text for discussion.
Based on typical level of copper in distillate oil derived in Section 3.3.5.
Emission factor assumes all copper present in the oil feed is emitted
through the stack. A density of 7.05 Ib/gal and a heating value of
141,000 Btu/gal are assumed.
3-155
-------
TABLE 3-79. MEASURED COPPER EMISSION FACTORS FbR DISTILLATE OIL-FIRED BOILERS
Fuel Characteristics
Emission Factor
(lb/10 Btu) Type
6.9-9.2b #2 Oil
15. 6-17. 7b #2 Oil
53 Distillate
63e Distillate
371 .8f Distillate
U)
i
<Ł 5.1 Distillate
(Copper Control
Content, ppm) Status
Uncontrolled
Uncontrolled
(11.0) Uncontrolled
(11.0) Uncontrolled
Uncontrolled
(0.47) Uncontrolled
Q
Sector Boiler Type
R Cast Iron
R Cast Ironc
R Bluer ay Low NO
R Bluer ay Low NO
R Conventional High
Pressure
R Hot Water Condensing
Heating System
Reference
Levy et al. , 1971
Levy et al . , 1971
Castaldini et al . ,
Castaldini et al .
Suprenant et al.,
Castaldini, 1982
, 1981b
, 1981b
1979
aU = Utility, I = Industrial, C = Commercial/Institutional;, R = Residential.
Two tests. Calculations assume heating value of 141,000 Btu/gal for #2 oil.
C
Conversion burner in cast iron boiler - high pressure gun type.
Unit operating in a cycling mode, 10 minutes on, 10 minutes off.
Q
Unit operating continuously.
Eight tests were run for seven units.
-------
TABLE 3-80. CALCULATED UNCONTROLLED MERCURY EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS'
Recommended
,6,c,d
Value ' '
Tyndall
et al. 1978
Previous Studies
Suprenant
et al. 1980b
Shih
et al. 1980b
Leavitt
et al. 1980b
Anderson,
1973
Anderson,
1973
Emission Factor
(lb/1012 Btu)
3.2
2.1
4.4s
3.5
6.67
0.47
Concentration
in Fuel (ppm)
0.06
0.04
0.26
0.066
0.07
0.13
0.009
CO
I-"
Ul
Calculated assuming all mercury present in oil feed is emitted through the stack.
Calculated from typical level of mercury in residual oil derived in Section 3.3.6. Emission factor assumes all
mercury present in oil feed is emitted through the stack. A density of 944 g/1 and heating value of 150,000 Btu/gal
are assumed.
See definition of recommended factors in Section 1.2.
10
Calculated mercury emission factors (lb/10 Btu) f
ESP, 2.4; scrubber, 0.83. See text for discussion.
j 10
Calculated mercury emission factors (lb/10 Btu) for controlled residual oil-fired boilers are: multiclone, 3.2;
There is an apparent discrepancy between the calculated emission factor and the values measured for mercury in the
fuel as reported in this reference. The reference states the assumption that all arsenic measured in the oil feed
is emitted through the stack, but the numbers presented do not agree with this statement. This discrepancy could
not be resolved from the information given in the reference.
-------
TABLE 3-81. MEASURED MERCURY EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS
Fuel Characteristics
Emission Factor (Mercury Control
(lb/10 Btu) Type Content, ppm) Status Sector8 Boiler Type
0.23b #6 Oil
1 .4b #6 Oil
1.1° #6 Oil Ť0.1)
l.ld #6 Oil Ť0.1)
0.037d #6 Oil Ť0.1)
i
G 0.13C 1:1 Residual/ (0.04)
00 Crude
0.0726 1:1 Residual/ (0.03)
Crude
0.052f 1:1 Residual/ (0.04)
Crude
Mul tic lone/
Scrubber
Multiclone
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
I Integral Coal/
Oil Burner
I Integral Coal/
Oil Burner
I Watertube
I Watertube
I Watertube
U Wall -fired
U Wall-fired
U Wall-fired
Reference
Leavitt et al . , 1978b;
Fischer et al . , 1979
Leavitt et al. , 1978b;
Fischer et al. , 1979
Carter et al. , 1978
Carter et al . , 1978
Carter et al . , 1978
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
1981b
1981b
1981b
3U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
Tested at scrubber inlet and outlet of the same boiler.
CTested under normal or baseline conditions.
Tested under low-NO conditions (reduced excess air and flue gas recirculation).
e
Operated under low-NO conditions (flue gas recirculation, top row of burners admit only air, lower burners admit
fuel at greater than Baseline rates.
Using flue gas recirculation.
-------
TABLE 3-82. CALCULATED UNCONTROLLED MERCURY EMISSION
FACTORS FOR DISTILLATE OIL-FIRED BOILERS3
Previous Studies
Suprenant
Recommended Value >C> et al., 1980b
Emission Factor 3.0 4.0
(lb/1012 Btu)
Concentration 0.06
in Fuel (ppm)
Calculated assuming all mercury present in oil feed is emitted through
the stack.
Calculated from typical level of mercury in distillate oil derived in
Section 3.3.6. Emission factor assumes all mercury present in oil feed is
emitted through the stack. A density of 7.05 Ib/gal and heating value of
141,000 Btu/gal are assumed.
See definition of recommended factors in Section 1.2.
j 19
Calculated mercury emission factors (lb/10 Btu) for controlled distillate
oil-fired boilers are: multiclone, 3; ESP, 2.25; scrubber; 0.78. See text
for discussion.
3-159
-------
TABLE 3-83. MEASURED MERCURY EMISSION FACTORS FOR DISTILLATE OIL-FIRED BOILERS
Emission Factor
(lb/1012 Btu)
2.8b
14C
17d
w aU = Utility, I =
^ Average of eight
o
Fuel Characteristics
Type (Hg Content ,. ppm)
Distillate
Distillate (0.40)
Distillate (0.40)
Control
Status
Uncontrolled
Uncontrolled
Uncontrolled
Industrial, C = Commercial/Institutional
tests run on seven units.
rt
Sector Boiler Type
R Conventional High
Pressure
R Blueray Low NO
R Blueray Low NO
, R = Residential .
Reference
Suprenant et al . , 1979
Castaldini et al., 1981b
Castaldini et al . , 1981b
Unit operating in a cycling mode, 10 minutes on, 10 minutes off.
Unit operating continuously.
-------
TABLE 3-84. CALCULATED UNCONTROLLED MANGANESE EMISSIONS FROM RESIDUAL OIL-FIRED BOILERS3
Previous Studies
Recommended Tyndall Suprenant Shih Suprenant Anderson, Leavitt
Value 'C> et al, 1978 et al, 1980b et al, 1980b et al, 1980a 1973 et al, 1980b
Emission Factor
(lb/1012 Btu)
26
70.6
120.8
30.2
19.5
6.7
Concentration
in Fuel (ppm)
0.49
1.33
0.1-0.98
0.57
0.16
0.04
to
Calculated assuming all manganese in oil feed is emitted through the stack.
Based on typical level of manganese in residual oil derived in Section 3.3.7. Emission factor assumes all manganese
present in oil feed is emitted through the stack. A density of 944 g/1 and a heating value of 150,000 Btu/gal are
assumed.
c
See definition of recommended factors in Section 1.2.
Calculated manganese emission factors (lb/10 Btu) for controlled residual oil-fired boilers are: multiclone, 11.96;
ESP, 5.72; scrubber, 2.86. See text for discussion.
e
There is an apparent discrepancy between the calculated emission factor and the values measured for manganese in the
fuel as reported in this reference. The reference states the assumption that all arsenic measured in the oil feed
is emitted through the stack, but the numbers presented do not agree with this statement. This discrepancy could
not be resolved from the information given in the reference.
-------
TABLE 3-85. MEASURED MANGANESE EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS
r
Fuel Characteristics
Emission Factor (Manganese Control
(lb/10 Btu) Type Content, ppm) Status Sector3 Boiler Type
2.7-3.5
2.7-4.0
1.0-2.3
44C
66d
200e
46C
64f
40f
#6 Oilb
#5 Oilb
#4 Oilb
1:1 Residual/ Ť1.0)
Crude Oil
1:1 Residual/ Ť2.0)
Crude Oil
1:1 Residual/ Ť2.0)
Crude Oil
#6 Oil (1.4)
#6 Oil Ť0.5)
#6 Oil Ť0.5)
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
C Scotch with
Rotary Burner
C Scotch with Air
Atomizing Burner
C Scotch with Air
Atomizing Burner
U Wall-Fired
U Wall-Fired
U Wall -Fired
I Watertube
I Watertube
I Watertube
Levy et
Levy et
Levy et
Sawyer
Sawyer
Sawyer
Carter
Carter
Carter
Reference
al.. 1971
al.. 1971
al., 1971
and Higginbotham,
and Higginbotham,
and Higginbotham,
et al. , 1978
et al., 1978
et al., 1978
1981b
1981b
1981b
-------
TABLE 3-85. MEASURED MANGANESE EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS (Continued)
Fuel Characteristics
Emission Factor (Manganese Control
(lb/10 Btu) Type Content, ppm) Status Sector3 Boiler Type
238 #6 Oil Multi clone I
(tested at
scrubber inlet)
3.0h #6 Oil Multiclone/ I
Scrubber
Integral Coal/
Oil Furnace
Integral Coal/
Oil Furnace
Reference
Leavitt et al . ,
Fischer et al . ,
Leavitt et al . ,
Fischer et al.,
1978b;
1979
197 8b;
1979
U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
V Calculations assume 146,000 Btu/gal for #4 oil; 148,000 Btu/gal for #5 oil; and 150,000 Btu/gal for #6 oil.
C
oj Operating under design (baseline) conditions.
Operating under high level of NO control - flue gas is recirculated, top row of burners admit air only (no fuel),
lower burners admit fuel at greater than baseline rates.
Flue gas recirculation, all burners in service.
Unit operating under low-NO conditions - reduced excess air and maximum flue gas recirculation. Sample analyzed
by atomic absorption.
Tested at scrubber inlet of same boiler as in footnote h.
Tested at scrubber outlet.
-------
TABLE 3-86. CALCULATED UNCONTROLLED MANGANESE EMISSION
FACTORS FOR DISTILLATE OIL-FIRED BOILERS3
Previous Studies
Recommended Suprenant Suprenant
Valueb'C>d et al., 1980b et al., 1980a
Emission Factor 14 14.2 9.8
(lb/1012 Btu)
Concentration 0.28 0.25-0.3
in Fuel (ppm)
Calculated assuming all manganese present in oil feed is emitted through
the stack.
Based on typical level of manganese in distillate oil derived in
Section 3.3.7. Emission factor assumes all manganese present in oil feed is
emitted through the stack. A density of 7.05 Ib/gal and heating value of
141,000 Btu/gal is assumed.
Q
See definition of recommended factors in Section 1.2.
Calculated manganese emission factors (lb/10 Btu) for controlled distillate
oil-fired boilers are: multiclone, 6.44; ESP, 3.08; scrubber, 1.54. See
text for discussion.
3-164
-------
TABLE 3-87. MEASURED MANGANESE EMISSION FACTORS FOR DISTILLATE OIL-FIRED BOILERS
Fuel Characteristics
i
M
ON
Emission Factor
(lb/10 l Btu)
0.71-1.8b
0.92-2.4b
12d
50e
Type
#2 Oil
#2 Oil
Distillate
Distillate
(Manganese Control
Content, ppm) Status
Uncontrolled
Uncontrolled
(17.0) Uncontrolled
(17.0) Uncontrolled
Sector3 Boiler Type
R Cast Iron
R Cast Iron0
R Blueray Low NO
R Blueray Low NO
Reference
Levy et al. , 1971
Levy et al. . 1971
Castaldini et al . , 1981b
Castaldini et al., 1981b
U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
Two tests. Calculation assumes heating value of 141,000 Btu/gal for #2 oil.
Conversion burner in cast iron boiler - high pressure gun type.
Unit operating in a cycling mode, 10 minutes on, 10 minutes off.
Unit operating continuously.
-------
TABLE 3-88. CALCULATED UNCONTROLLED NICKEL EMISSIONS FROM RESIDUAL OIL-FIRED BOILERS'
Previous Studies
Recommended Tyndall
Suprenant
Shih
Suprenant Anderson, 1973; Leavitt
Value >C> et al, 1978 et al, 1980b et al, 1980b et al, 1980a Levy, 1971 et al, 1980b
Emission Factor
(lb/1012 Btu)
1260
2240
1870
1004
1690
2000
500
Concentration
in Fuel (ppm)
24.0
42.2
10-73
19
36.3
u>
cr\
Calculated assuming all nickel in oil feed is emitted through the stack.
Based on typical level of nickel in residual oil derived in Section 3.308. Emission factor assumes all nickel
present in oil feed is emitted through the stack. A density of 944 g/1 and a heating value of 150,000 Btu/gal are
assumed.
"See definition of recommended factors in Section 1.2.
i 12
Calculated nickel emission factors (lb/10 Btu) for i
ESP, 352.8; scrubber, 50.4. See text for discussion.
j 12
Calculated nickel emission factors (lb/10 Btu) for controlled residual oil-fired boilers are: multiclone, 642.6;
-------
TABLE 3-89. MEASURED NICKEL EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS
Fuel Characteristics
Emission Factor (Nickel Control
(lb/10 Btu) Type Content, ppm) Status Sector8 Boiler Type
554
438
329
74C
ioood
3600e
86 0C
1000f
1300f
#6 Oilb
#5 Oilb
#4 Oilb
1:1 Residual/ (26)
Crude Oil
1:1 Residual/ (35)
Crude Oil
1:1 Residual/ (20)
Crude Oil
#6 Oil (14)
#6 Oil Ť10)
#6 Oil Ť10)
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
C Scotch with
Rotary Burner
C Scotch with Air
Atomizing Burner
C Scotch with Air
Atomizing Burner
U Wall-Fired
U Wall -Fired
U Wall -Fired
I Water tube
I Water tube
I Watertube
Levy et
Levy et
Reference
al., 1971
al., 1971
Levy .elt al. . 1971
Sawyer
Sawyer
Sawyer
Carter
Carter
Carter
and Higginbotham,
and Higginbotham,
and Higginbotham,
et al.. 1978
et al., 1978
et al., 1978
1981b
1981b
1981b
-------
TABLE 3-89. MEASURED NICKEL EMISSION FACTORS FOR RESIDUAL OIL-FIRED BOILERS (Continued)
Fuel Characteristics
Emission Factor (Nickel Control
(lb/10 Btu) Type Content, ppm) Status Sector3 Boiler Type
8368 #6 Oil (16) Multiclone I
(tested at
scrubber inlet)
146h #6 Oil (16) Multiclone/ I
Scrubber
Integral Coal/
Oil Furnace
Integral Coal/
Oil Furnace
Reference
Leavitt et al. , 1978b;
Fischer et al. , 1979
Leavitt et al . , 1978b;
Fischer et al . , 1979
oo d
a
U = Utilitys I = Industrials C = Commercial/Institutional, R = Residential.
Calculations assume 146,000 Btu/gal for #4 oil; 148,000 Btu/gal for #5 oil; and 150,000 Btu/gal for #6 oil.
Operating under design (baseline) conditions.
Operating under high level of NO control - flue gas is recirculated, top row of burners admit air only (no fuel),
lower burners admit fuel at greater than baseline rates.
fi
Flue gas recirculation, all burners in service.
Unit operating under low-NO conditions - reduced excess air and maximum flue gas recirculation. Sample analyzed
by atomic absorption.
^Tested at scrubber inlet of same boiler as in footnote h.
Tested at scrubber outlet.
-------
TABLE 3-90. CALCULATED UNCONTROLLED NICKEL EMISSION
FACTORS FOR DISTILLATE OIL-FIRED BOILERSa
Previous Studies
Recommended Suprenant
Valueb'C'd Suprenant, 1980b et al., 1980a
Emission Factor 170 260.3 106
(lb/1012 Btu)
Concentration 3.4 1-18
in Fuel (ppm)
Calculated assuming all nickel present in oil feed is emitted through the
stack.
Based on typical level of nickel in distillate oil derived in Section 3.3.8,
Emission factor assumes all nickel present in oil feed is emitted through
the stack. A density of 7.05 Ib/gal and heating value of 141,000 Btu/gal
is assumed.
c
See definition of recommended factors in Section 1.2.
j 19
Calculated nickel emission factors (lb/10 Btu) for controlled distillate
oil-fired boilers are: mutliclone, 86.7; ESP, 47.6; scrubber, 6.8. See
text for discussion.
3-169
-------
TABLE 3-91. MEASURED NICKEL EMISSION FACTORS FOR DISTILLATE OIL-FIRED BOILERS
Fuel Characteristics
Emission Factor (Nickel Control
(lb/10 Btu) Type Content, ppm) Status
2.7-2.9b
3.1-3.4b
22d
36e
uť 67^
I
H
° 7.6
#2 Oil
#2 Oil
Distillate (0.09)
Distillate (0.09)
Distillate
Distillate (0.93)
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
a
Sector Boiler Type
R Cast IronC
R Cast Iron
R Bluer ay Low NO
R Blueray Low NO
R Conventional
High Pressure
R Hot Water Condensing
Heating System
Reference
Levy et al. , 1971
Levy et al. , 1971
Castaldini et al . ,
Castaldini et al.
Suprenant et al . ,
Castaldini, 1982
, 1981b
, 1981b
1979
aU = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
Two tests. Calculation assumes heating value of 141,000 Btu/gal for #2 oil.
"Conversion burner in cast iron boiler - high pressure gun type.
Unit operating in a cycling mode, 10 minutes on, 10 minutes off.
"Unit operating continuously.
Eight tests were run on seven units.
-------
TABLE 3-92. SUMMARY OF TOTAL POM EMISSION FACTORS FOR OIL COMBUSTION
Emission,.Factor Number of
Type of Oil/ fib/10 Btu) Boilers
Control Status Average Range Tested
Residual Oil:
Uncontrolled 8.4a 0.07-77.3a 17
Cyclones 5.8 1
Distillate Oil:
Uncontrolled <22.5 <0.28-41.2 5
_ _
The upper end of the range, 77.3 lb/10 Btu, could be considered an outlier
from the rest of the range; however, nothing in the test report suggested
this to be the case. If this value is excluded when calculating an average
emission factor, the average factor is only 4.1 lb/10 Btu.
3-171
-------
TABLE 3-93. MEASURED TOTAL POM EMISSION FACTORS FROM RESIDUAL OIL COMBUSTION
Boiler Type
Boiler Application
Controls Used
Total POM Emission Factor
lb/10 Btu-heat Input
Reference
Tangential-Fired
Wall-Fired
Wall-Fired
Wall-Fired
Hall-Fired
Face-Fired
Not Reported
Face-Fired
Face-Fired
Tangential-Fired
Not Reported
Steam Atomized Watertube
Water tube
Scotch Marine
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Electric Utility
Industrial Heating
Industrial Heating
Commercial Heating
None
None
None
None
None
None
None
None
None
Cyclones
None
None
None
None
77.3
a,b
a,d
a,f
28.6
1.0"
5.9
4.8*
10.2*
0.75*
0.98J
5.8"'k
0.066 - 2.11
5.41"
1.5
2.2°
a,n
Shih et. al.. 1980b
Shih et. al. 19BOb
Shih et al.. 1980b
Shih si ai,. 1980b
Shih e_t al.. 1980b
DeAngelie and Piper, 1981
DeAngel is and Piper, 1981
DeAngel is and Piper, 1981
DeAngelie and Piper, 1981
Shih e_t al.. 1980b
Zelenski et al.. 1980
Hangebrauck e_t al_._, 1964
Suprenant et. al. . J980a
Suprenant et_ al. . 1980a
aFactor represents both participate and gaseous POM emissions. Fifty-six specific POM compounds were analyzed for during these tests.
Test operated under low-NO conditions (off-stoichiometric firing and flue gae recirculation).
L *
Specific compounds identified vere naphthalene and biphenyl. Naphthalene accounted for 96 percent of total POM emissions.
""Specific compounds identified vere 2-ethy 1-1,1-bipheny 1 and naphthalene. 2-Ethy 1-1,1-bipheny 1 accounted for 64 percent of total POM
emissions and naphthalene 36 percent.
Specific compounds identified were naphthalene and biphenyl. Naphthalene constituted 94 percent of total POM emissions and biphenyl
6 percent.
6Specific compounds identified were 2-ethy 1-1,1-bipheny 1 and 1,2 ,3-trimethy 1-4-propeey 1 naphthalene, each of which constituted
50 percent of total POM emissions.
Specific compounds identified were naphthalene, phenanthridine, dibenzothiophene, anthracene/phenanthrene, fluoranthene, pyrene,
chrysene/benz(a)anthracene, benzopyrene/peryleues, and tetramethyl phenanthrene. The primary constituents of total POM emissions were
naphthalene (67 percent), anthracene/phenanthrene (6 percent), f luoranthene (7 percent), pyrene (7 percent), and tetramethyl
phenanthrene (4 percent).
^Factor represents primarily particulate POM emissions. Specific compounds identified were phenanthrene, anthracene, methyl anthracenes/
phenanthrenes, f luoranthrene, pyrene, methyl pyrene/f luoranthene, benzo(c )phenanthreneg benzo(a)anthracene, chrysenes, methyl chrysenes,
benzofluoranthenes, benzo(e)pyrene, benzo(a)pyrene, perylene, indeno-pyrene, coroneme, and benzo(g,h,i)perylene. The primary
constituents of total POM emissions were phenanthrene (16 percent), methyl anthrscenea/phenanthrenes (13 percent), fluoranthene
(8 percent), and pyrene (7 percent).
-------
TABLE 3-93. MEASURED TOTAL POM EMISSION FACTORS FROM RESIDUAL OIL COMBUSTION (Continued)
Factor represents primarily particulate POM em lesions. Specific compounds identified were phenanthrene, anthracene, methyl anthracenes/
phenanthrenes, fluoranthene, pyrene, methyl pyrene/fluoranthene, benzo(c)phenanthrene, benzo(a)anthracene, chrysenes, benzofluor-
anthenes, benzo(e)pyrene, and benzo(a)pyrene. The primary constituents of total POM emissions were phenanthrene (51 percent),
fluoranthene (14 percent), benzo(g,h,Dperylene (9 percent), and methyl anthracenes/phenanthrenee (7 percent).
Factor represents both particulate and gaseous POM emissions. Specific compounds identified were phenanthrene, anthracene,
fluoranthene, pyrene, benzo(a)anthracene, and chrysene. The primary constituents of total POM emissions were phenanthrene
(35 percent), anthracene (31 percent), fluoranthene (14 percent.), and pyrene (14 percent). Approximately 63 percent of total POM
emissions were measured in the gaseous phase.
Factor represents both particulate and gaseous POM emissions. Specific compounds identified were phenanthrene, anthracene,
fluoranthene, pyrene, benzo(a)anthracene, and chrysene. The primary constituents of total POM emissions were phenanthrene
(34 percent), anthracene (31 percent), fluoranthene (15 percent), and pyrene (12 percent). Approximately 65 percent of total FOM
emissions were measured in the gaseous phase. Test was conducted under low-NO burn conditions.
fc x
Specific compounds identified were naphthalene and biphenyl. Naphthalene conatituted 72 percent of total POM emissions and biphenyl
28 percent.
Factor represents both particulate and gaseous POM emissions. Twenty-one specific POM compounds were analyzed for during these tests.
The principal constituents of total POM emissions were anthracene/phenanthrene (53 percent), fluoranthene (17 percent), pyrene
(15 percent), and methyl anthracenes (5 percent).
factor represents primarily particulate POM emissions. Specific compounds identified were benzo(a)pyrene, pyrene, phenanthrene, and
fluoranthene. Phenanthrene constituted about 75 percent of total POM emissions, pyrene 12 percent, and fluoranthene 11 percent.
Co
' This factor is for biphenyl emissions only. No other POM compounds were measured during these tests. This is an average emission
-j factor for five boilers, four of which are uncontrolled and one which is controlled by a cyclone/scrubber combination.
1>J o
This factor is for benzo(a)pyrene only. No other POM compounds were measured during these tests.
-------
TABLE 3-94. MEASURED UNCONTROLLED TOTAL POM EMISSION FACTORS FROM DISTILLATE OIL COMBUSTION
Boiler Type
Water tube
Scotch Marine
Cast Iron
Sectional
Boiler
Application
Process Heating
Hospital Heating
Home Heating
Total POM Emission Factor
lb/10 Btu-heat input3
<0.28b
41. 2C
<34.6d
Reference
Hangebrauck et al . ,
Hangebrauck et al.,
Hangebrauck et al.,
1964
1964
1964
Hot Air Furnace
Hot Air Furnace
Home Heating
Home Heating
<0.33'
<35.9f
Hangebrauck et al-.., 1964
Hangebrauck et al., 1964
Factors represent primarily particulate POM emissions. Eleven specific POM compounds were analyzed for
during these tests.
Specific compounds identified were benzoCa)pyrene, pyrene, and fluoranthene. Fluoranthene accounted for
45 percent of total POM emissions, pyrene 39 percent, and benzoCa )pyrene 16 percent.
CSpecific compounds identified were benzoCa)pyrene, pyrenes benzo(g,h,i)perylene, coronene, anthracene,
phenanthrene, and fluoranthene. Primary constituents of total POM emissions were pyrene (33 percent),
anthracene (21 percent), phenanthrene (19 percent), and coronene (11 percent).
Specific compounds identified were benzo(a)pyrene, pyrene, and phenanthrene, and fluoranthene. Phenanthrene
constituted 57 percent of total POM emissions, fluoranthene 32 percent, and pyrene 11 percent.
6Specific compounds identified were benzo(a)pyrene, pyrene, and fluoranthene. Fluoranthene constituted
50 percent of total POM emissions, benzo(a)pyrene 40 percent, and pyrene 10 percent.
Specific compounds identified were benzo(a)pyrene, pyrene, and fluoranthene. Fluoranthene accounted for
92 percent of total POM emissions, pyrene 7 percent, and benzo(a)pyrene 1 percent.
-------
TABLE 3-95. MEASURED FORMALDEHYDE EMISSION FACTORS FOR OIL-FIRED BOILERS AND FURNACES
1
(-Ť
Ui
Emission Factor
(lb/1012 Btu)
240
640
580
160
aU = Utility, I
Fuel
Characteristics
#2 Oil
#2 Oil
#1 Oil
#6 Oil
= Industrial , C =
a
Control Status Sectors
Uncontrolled I
Uncontrolled R
Uncontrolled R
Uncontrolled I
Commercial/Institutional, R =
Boiler Type
Steam Atomized
Centrifugal Atomized
Vaporized
Steam Atomized
Residential .
Reference
Hangebrauck
Hangebrauck
Hangebrauck
Hangebrauck
et al . .
et al . ,
et al. ,
et al.,
1964
1964
1964
1964
-------
TABLE 3-96. RECOMMENDED ARSENIC EMISSION FACTORS FOR COAL-FIRED BOILERS
a,b
12
Fmicsirm Factor Clb/10 Btu)
Boiler Type/Control Status
Pulverized Dry Bottom:
Uncontrolled
Multiclone
ESP
Scrubber
Pulverized Wet Bottom:
Uncontrolled
Multiclone
ESP
Scrubber
Cyclone :
Uncontrolled
Multiclone
ESP
Spreader Stoker:
Uncontrolled
Multiclone
ESP
Overfeed Stoker:
Uncontrolled
Multiclone
ESP
Bituminous
684
335
40.1
17.2
1340
658
168
76.7
115-310
56-152
14.4
264-542
129-265
33-67
542-1030
265-505
67-129
Lignite
1390
683
82
35
2730
1340
343
156
235-632
114-310
29
538-1100
263-540
67-137
1100-2100
540-1030
137-263
bv Coal Type
Anthracite
266
130
15.6
6.7
521
256
65
29.8
45-121
22-59
5.6
103-210
50-103
13-26
210-401
103-196
26-50
The derivation of these factors is documented in Section 3.7.1.1. They are
applicable to the utility, industrial, and commercial/institutional sectors,
See definition of recommended factors in Section 1.2.
3-176
-------
TABLE 3-97. SUMMARY OF MEASURED ARSENIC EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
Emission Factor
(lb/1012 Btu)
Boiler Type/Control Status
Pulverized Dry Bottom:
Uncontrolled
Mechanical Precipitator
ESP, or Mechanical Ppt.
followed by ESP
Mechanical Ppt/ 2 ESPs
in Series
Scrubber
ESP /Scrubber
Pulverized Wet Bottom:
ESP or Mechanical Ppt.
followed by ESP
Scrubber
Cyclone :
Uncontrolled
ESP
Scrubber
Stoker:
Mechanical Ppt. or
Multiclone
Fabric Filter
Average
684
653
40.1
6.1
17.2
14.9
168
76.7
310
14.4
813
3006
0.77
Range
62-1360
19-1980
0.35-242
<0. 29-13 .2
3.95-31.4
15.3-572
130-490
6.3-27.9
432-5580
Number of
Boilers
Tested
5
2
15
1
4
1
5
1
1
5
1
2
1
Number of
Data Points
20
10
37
5
6
1
5
1
2
6
1
2
1
Each boiler tested was weighted equally in determining this average. An
arthmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-177
-------
TABLE 3-98. SUMMARY OF MEASURED ARSENIC EMISSION FACTORS
FOR SUBBITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Coal-Fired :
ESP
Scrubber
Cyclone :
Uncontrolled
Scrubber
Unspecified Boiler Type:
ESP
Emission Factor
fib/10 Btu)
Average Range
0.17
11
860
810
6.2 2.4-10
Number of
Boilers
1
1
1
1
2
Number of
Data Points
1
1
1
1
2
TABLE 3-99. SUMMARY OF MEASURED ARSENIC EMISSION FACTORS
FROM LIGNITE COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Multiclone
ESP
Cyclone^
Multiclone
ESP
ESP/Scrubber
Spreader Stoker:
Multiclone
ESP
Emission Factor
(lb/10 Btu)
Average Range
382 367-397
<2.3
270
5.8
11.2
265
<5.3
Number of
Boilers
2
1
1
1
1
1
1
Number of
Data Points
2
1
1
1
1
1
1
3-178
-------
TABLE 3-100. SUMMARY OF MEASURED ARSENIC EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Uncontrolled
Multiclone
Multiclone /Scrubber
ESP
Emission Factor
(lb/1012 Btu)
a
Average Range
690
7900
214
44.6 15.8-120
Number of
Boilers
1
1
1
5
Numbe r
of
Data Points
2
1
1
6
Pulverized Wet Bottom:
Multiclone
Spreader Stoker:
32.5
Uncontrolled
Multiclone
Multiclone/ESP
Overfeed Stoker:
Uncontrolled
Economizer /Dust
Collector
264
478
43.4
1030
395
0.27-835
102-853
31-53.7
60-2600
370-420
7
2
2
4
1
14
2
3
5
2
Each boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-179
-------
TABLE 3-101. SUMMARY OF MEASURED ARSENIC EMISSION FACTORS FOR
SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Spreader Stoker:
Uncontrolled
Mechanical Ppt/ESP
Emission Factor
(lb/1012 Btu) Number of
Average3 Range Boilers
217 68-490 2
4.4 3.0-5.8 1
Number of
Data Points
4
2
Each boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-180
-------
TABLE 3-102. SUMMARY OF MEASURED ARSENIC EMISSION FACTORS FOR
COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Coal Type/
Boiler Type
Bituminous Coal :
Pulverized Dry
Bottom
Underfeed Stoker
Spreader Stoker
Overfeed Stoker
Anthracite Coal:
Stoker
Emission
Factor
(lb/1012 Btu) Number of
Control Status
Uncontrolled
Multiclone/
Scrubber
.Uncontrolled
Mechanical Ppt
Mechanical Ppt
Uncontrolled
a
Average
4470
51.1
4.2
11.6
25.6
137
Range Boilers
1
1
1
1
1
5.3-235 3
Numbe r
of Data
Points
1
1
1
1
1
3
3-181
-------
TABLE 3-103. CALCULATED ARSENIC EMISSION FACTORS FOR COAL COMBUSTION
Coal Type
Boiler Type
Control Status
Sectors
Emission Factor
(lb/10 Btu)
Reference
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Cyclone
Cyclone
Cyclone
Cyclone
Uncontrolled
Uncontrolled
Mechanical Ppt,
Cyclone
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt,
Multiclone
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt,
ESP
Wet Scrubber
U, I, C
I, C
U
I
U, I
U
U, I
U
U, I
U, I
U
U
U
U
630-670
2790
823
813
58.8
48.8
510-790
669
150
48.8
44.2
110-790
139
10
8.1
Baig e_t al. . 1981
Suprenant ejt
Suprenant et
Shih et al. .
Suprenant et
Baig et al . .
Shih e_t al. .
Shih e_t al. .
Baig et al . .
Shih e_Ł al. .
Baig e_t al. .
Baig e_t al . .
Shih e_t al. .
Shih e al.
Baig et al . .
Shih el al. .
Baig et al . .
Shih et al. ,
al. . 1980b
al. . 1980a
1980b
al.. 1980a
1981;
1980b
1980b
1981
1980b
1981
1981;
1980b
1980b
1981
1980b
1981;
1980b
Shih et al.. 1980b
-------
TABLE 3-103. CALCULATED ARSENIC EMISSION FACTORS FOR COAL COMBUSTION (Continued)
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Boiler Type
Stoker
Stoker
Spreader Stoker
Spreader Stoker
Underfeed Stoker
Automatic Coal-Fired
Furnace
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
Cyclone
Cyclone
Stoker
Control Status
Uncontrolled
Multiclone
Uncontrolled
Cyclone
Uncontrolled
Uncontrolled
Uncontrolled
Multiclone
Mechanical Ppt .
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Ť
Sectors
U, I, C
U, I, C
I
I
C
R
0, I, C
U, I, C
U
U
U
U
U
U
U
U, I, C
Emission Factor
(lb/10 Btu) Reference
460-790
140
2140
627
232
1550
200-580
53
34.9
8.1
34.9
170-580
216
4.4
19.3
200-580
Baig et al . ,
Baig et al . ,
Suprenant et
Suprenant et
Suprenant et
DeAngelis and
Baig et al . .
Bale et al . ,
Shih et al. ,
Shin et al . ,
Shih et al. ,
Bale et al . ,
Shih et al.,
Shih et al. ,
Shih et al. ,
Baig et al . ,
1981
1981
al.,
al.,
al . ,
19 80 a
19 80 a
1980b
Reznik, 1979
1981
1981
1980b
1980b
1980b
1981
1980b
1980b
1980b
1981
-------
TABLE 3-103. CALCULATED ARSENIC EMISSION FACTORS FOR COAL COMBUSTION (Continued)
00
-p-
Coal Type
Lignite
Lignite
Anthracite
Anthracite
Anthracite
Anthracite
Boiler Type Control Status
Stoker Multiclone
Automatic Coal-Fired Uncontrolled
Furnace
Pulverized Dry Bottom Uncontrolled
Stoker Uncontrolled
Stoker Uncontrolled
Automatic Coal-Fired Uncontrolled
Furnace
Emission Factor
Sectors3 (lb/10 Btu) Reference
U, I, C 53
R 696
U, I, C 440-510
U, I, C 25-510
C 116
R 391
Baig et al
DeAngelis
Baig et al
Baig et al
Suprenant
DeAngelis
., 1981
and Reznik, 1979
., 1981
., 1981
et al. , 1980b
and Reznik, 1979
*U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
-------
TABLE 3-104. ARSENIC REMOVAL EFFICIENCY OF CONTROLS'
Control Device
Mechanical Ppt .
ESP
FGD Scrubber
ESP/Scrubber
2 ESPs in Series
% Control
Average
51.0
87.5
98.9
99.6
Efficiency
Range
25.8-70.8
50.0-97.6
5.8-97.3
99.2-99.97
Number of
Boilers
1
7
2
1
1
Number of
Test Runs
3
21
2
1
5
a ...
the literature. They may or may not be indicative of the long-term
performance of these types of controls on arsenic emissions from combustion
sources. The average values should not be construed to represent an EPA-
recommended efficiency level for these devices.
Each emission test weighted equally -
3-185
-------
TABLE 3-105. RECOMMENDED BERYLLIUM EMISSION
FACTORS FOR COAL-FIRED BOILERS
a,b
12
Emission Factor (lb/10 Btu)
Boiler Type/Control Status Bituminous
Pulverized (Dry or Wet
Bottom) :
Uncontrolled
Multiclone
ESP
Scrubber
Cyclone Boilers :
Uncontrolled
Multiclone
ESP
Stoker Boilers :
Uncontrolled
Multiclone
ESP
81
52
3.0
0.11
<81
<52
0.52
73
9.8-46
5.9
Lignite
131
84
4Ť9
0.18
<130
<84
0.84
118
16-74
9.5
by Coal Type
Anthracite
50
32
1.8
0.07
<50
<32
0.32
45
6-28
3.6
a_ . . .
Derivation of these factors is documented in Section 3.7.1.2. Factors are
applicable to the utility, industrial, and commercial/institutional sectors,
See definition of recommended factors in Section 1.2.
3-186
-------
TABLE 3-106. SUMMARY OF MEASURED BERYLLIUM EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Uncontrolled
Mechanical Ppt.
ESP or Mech. Ppt /ESP
Mech. Ppt/2 ESPs in
series
Scrubber
Pulverized Wet Bottom:
ESP or Mech. Ppt /ESP
Scrubber
Emission
(lb/1012
Average
80.9
93.5
3.8
0.082
0.11
3.5
0.086
Factor
Btu)
Range
41-140
26-171
<0. 11-32
0.007-0.209
0.88-10.2
__ _
Number of
Boilers
Tested
4
2
12
1
1
5
1
Number
of Data
Points
17
10
25
5
1
5
1
ESP or Mech. Ppt /ESP
Scrubber
Cyclone :
ESP
Scrubber
Stoker :
Mech. Ppt or Multiclone
Fabric Filter
3.5 0.88-10.2
0 .086
0.52 0.19-1.05
0.86
12.8 5.6-20.0
0.13
5
1
4
1
2
1
5
1
4
1
2
1
Each boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-187
-------
TABLE 3-107. SUMMARY OF MEASURED BERYLLIUM EMISSION FACTORS
FOR SUBBITUMINOUS COAL-FIRED UTILITY BOILERS
12
Boiler Type/ (lb/10 Btu) Number of Number of
Emission Factor
(lb/1012 Btu)
Control Status Average Range Boilers Data Points
Pulverized Coal Fired:
ESP 1.0 1 1
Scrubber 0.60 1 1
Cyclone:
Uncontrolled 18.0 1 1
Scrubber 1.6 1 1
Unspecified Boiler Type:
ESP 0.63 0.38-0.88 2 2
3-188
-------
TABLE 3-108. SUMMARY OF MEASURED BERYLLIUM EMISSION FACTORS
FOR LIGNITE COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Emission Factor
(lb/1012 Btu)
Average
Range
Number of
Boilers
Number of
Data Points
Pulverized Dry Bottom:
Multiclones 2.4
ESP <2.3
Cyclone :
Cyclone 6.8
ESP 0.70
Spreader Stoker:
Multiclone 13.7
ESP 0.26
2.3-2.6
2
1
1
1
1
1
2
1
1
1
1
1
3-189
-------
TABLE 3-109. SUMMARY OF MEASURED BERYLLIUM EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Uncontrolled
Mul tic lone
Mul tic lone /Scrubber
ESP
Emission Factor
(lb/1012 Btu)
Average Range
15
93
2.3
1.1 0.19-2.0
Number of
Boilers
1
1
1
5
Number of
Data Points
2
1
1
6
Pulverized Wet Bottom:
Multiclone
Spreader Stoker:
0.21
Uncontrolled
Multiclone
Multiclone /ESP
Overfeed Stoker:
Uncontrolled
Economizer /Dust
Collector
106
7.7
32
16.6
4.3
0.30-780
3.3-12.1
0.2-120
3.9-39
3.7-4.9
7
2
2
4
1
14
2
3
5
2
Each boiler tested was weighted equally in determining this average. An
arithmetic value was calculated for each boiler; and then a means of these
means was calculated.
3-190
-------
TABLE 3-110. SUMMARY OF MEASURED BERYLLIUM EMISSION FACTORS
FOR SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Spreader Stoker:
Uncontrolled
Mechanical Ppt/ESP
Emission
(lb/1012
Average
41.3
2.0
Factor
Btu) Number of
Range Boilers
6.2-70 2
0.77-3.3 1
Number of
Data Points
4
2
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
TABLE 3-111. SUMMARY OF MEASURED BERYLLIUM EMISSION FACTORS FOR
COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Coal Type/
Boiler Type
Bituminous Coal:
Pulverized Dry
Bottom
Spreader Stoker
Overfeed Stoker
Anthracite Coal :
Stoker
Control Status
Uncontrolled
Multiclone/
Scrubber
Mechanical Ppt
Mechanical Ppt
Uncontrolled
Emission Factor
(lb/1012 Btu)
Average Range
307
0.95
7 .9
0.77
11.1 0.93-21.8
Number
of
Boilers
1 '
1
1
1
3
Number
of Data
Points
1
1
1
1
3
3-191
-------
TABLE 3-112. CALCULATED BERYLLIUM EMISSION FACTORS FOR COAL COMBUSTION
VO
NJ
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Boiler Type
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Cyclone
Cyclone
Cyclone
Emission Factor
Control Status Sectors3 (lb/10 Btu) Reference
Uncontrolled U, I, C
Uncontrolled I, C
Mechanical Ppt. U, I
ESP U, I
Wet Scrubber U
Uncontrolled U, I
Mechanical Ppt, U
Multiclone U, I
ESP U
Wet Scrubber U
Uncontrolled U
Mechanical Ppt. U
ESP U
70-90
232
72
5.1
0.42
58-90
58
17
4.2
0.42
12-88
12
0.86
Baig et al . ,
Suprenant et
Suprenant et
Shih et al . ,
Suprenant et
Baig et al . ,
Shih et alo ,
Shih et al. ,
Baig et al . ,
Shih et al. ,
Baig et al ,
Baig et al . ,
Shih et al. ,
Shih et al. ,
Baig et al . ,
Shih et al. ,
Shih et al. ,
Baig et al. ,
1981
al. , 1980a;
al., 1980b
1980b;
al.. 1980b
1981;
1980b
1980b
1981
1980b
1981
1981;
1980b
1980b
1981
1980b
1980b;
1981
Bituminous
Cyclone
Wet Scrubber
0.07
Shih
al., 1980b
-------
TABLE 3-112. CALCULATED BERYLLIUM EMISSION FACTORS FOR COAL COMBUSTION (Continued)
U)
U>
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Boiler Type
Stoker
Stoker
Spreader Stoker
Spreader Stoker
Underfeed Stoker
Automatic Coal-Fired
Furnance
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
Cyclone
Cyclone
Stoker
Control Status
Uncontrolled
Multiclone
Uncontrolled
Cyclone
Uncontrolled
Uncontrolled
Uncontrolled
Multiclone
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Emission Factor
Sectors* (lb/10 Btu) Reference
U, I, C
U, I, C
I
I
C
R
U, I, C
U, I, C
U
U
U
U
U
U
U
U, I, C
53-88
16
179
56
23
16
51-150
14
37
1.4
0.63
44-150
35
0.72
0.33
51-150
Baig et al
Baig et al
Suprenant
Suprenant
Suprenant
DeAngelis
Baig et al
Baig et al
Shih et al
Shih et al
Shih et al
Baig et al
Shih et al
Shih et al
Shih et al
Baig et al
., 1981
., 1981
et al. , 1980a
et al. , 1980a
et al. , 1980b
and Reznik, 1979
., 1981
., 1981
., 1980b
., 1980b
. , 1980b
., 1981
., 1980b
., 1980b
., 1980b
., 1981
-------
TABLE 3-112. CALCULATED BERYLLIUM EMISSION FACTORS FOR COAL COMBUSTION (Continued)
Coal Type
Lignite
Lignite
Anthracite
Anthracite
Anthracite
Anthracite
Boiler Type
Stoker
Automatic Coal-Fired
Pulverized Dry Bottom
Stoker
Stoker
Automatic Coal-Fired
Fur nance
Control Status
Multiclone
Uncontrolled
Uncontrolled
Uncontrol led
Uncontrolled
Uncontrolled
Emission Factor
Sectors3 (lb/10 Btu) Reference
U. I. C 14 Baig et al. ,
R 2 i8 DeAngelis and
U. I. C 74-88 Baig et al..
U. I. C 4.4-88 Baig et al. .
C 16 Suprenant et
R 16 DeAngelis and
1981
Reznik, 1
1981
1981
al., 1980b
Reznik , 1
979
979
*U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
-------
TABLE 3-113. BERYLLIUM REMOVAL EFFICIENCY OF CONTROLSa
Control Device
Mechanical Ppt .
ESP
FGD Scrubber
2 ESPs in Series
% Control
Average
37.0
82.4
91 .9d
94.3
99.94
Efficiency
Range
34.6-40.9
b
22.0-99.95
86.7-99.95°
91.1-97.5
99.91-99.995
Number of
Boilers
1
b
6°
5C
2
1
Number of
Test Runs
3
b
19°
16C
2
5
These control efficiencies represent measured control levels reported
in the literature. They may or may not be indicative of the long-term
performance of these types of controls on beryllium emissions from
combustion sources. The average values should not be construed to
represent an EPA-recommended efficiency level for these devices.
Each emission test weighted equally.
Average and range represent data from all six ESP-controlled boilers
in the data set for which controlled and uncontrolled data are available.
Average and range represent data for five out of six ESP-controlled boilers
in the data set. The other boiler was excluded as an outlier. Control
efficiency for the outlier was 34.4 percent, while for the other five
boilers, control efficiencies were over 86 percent.
3-195
-------
a b
TABLE 3-114. RECOMMENDED CADMIUM EMISSION FACTORS FOR COAL-FIRED BOILERS '
12
Emission Factor (lb/10 Btu
Boiler Type/Control Status
Pulverized Dry Bottom:
Uncontrolled
Multiclone
ESP
Scrubber
Pulverized Wet Bottom:
Uncontrolled
Multiclone
ESP
Cyclone :
Uncontrolled
Multiclone
ESP
Spreader Stoker:
Uncontrolled
Multiclone
ESP
Overfeed Stoker:
Uncontrolled
Multiclone
ESP
Bituminous
44.4
31.6
9.2 (5.0-20)°
0.35-1.6
45-70
32-50
1.4
28
20
1.3
21-43
6.6-30
5.3-11
43-82
30-58
11-21
Lignite
48.8
34.8
10 (5.5-22)
0.38-1.8
49-77
35-55
1.5
31
22
1.4
23-47
7.3-33
5.8-12
47-90
33-64
12-23
) by Coal Type
Anthracite
11
7.9
2.3 (1.2-5.0)
0.09-0.40
11-17
8.0-12
0.35
7.0
5.0
0.32
5.2-11
1.6-7.5
1.3-2.7
11-20
7.5-14
2.7-5.2
a
See definition of recommended factors in Section 1,2=
The derivation of these factors is documented in Section 3.7.1.3. Factors
are applicable to the utility, industrial, and commercial/institutional
sectors.
9.2 is the average bituminous coal emission factor for all boilers tested.
The lower end of the given range is the average factor for 13 utility
boilers tested, and the upper end is the average of 5 industrial boilers
tested.
3-196
-------
TABLE 3-115. SUMMARY OF MEASURED CADMIUM EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Uncontrolled
Mechanical Ppt.
ESP or Mech. Ppt /ESP
2 ESPs in Series
Scrubber
Pulverized Wet Bottom:
ESP or Mech. Ppt /ESP
Scrubber
Cyclone :
Uncontrolled
ESP
Wet Scrubber
Stoker:
Emission Factor
(lb/1012 Btu)
Average Range
44.4 9.2-167
161 15-487
5.0 0.22-52.8
46
1.6 1.2-1.95
1.4 0.56-2.6
0 .086
28 22-35
1.3 0.35-3.0
488
Number of
Boilers
Tested
5
2
13
1
2
5
1
1
5
1
Number of
Data Points
17
10
26
1
2
5
1
2
6
1
Mechanical Ppt. or
Multiclone
Fabric Filter
13.2
0.33
4.2-22.1
1
Each boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-197
-------
TABLE 3-116. SUMMARY OF MEASURED CADMIUM EMISSION FACTORS
FOR SUBBITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Coal Fired:
ESP
Scrubber
Emission Factor
(lb/1012 Btu) Number of Number of
Average Range Boilers Data Points
<0.40 1 1
4.0 1 1
Cyclone:
Uncontrolled
Scrubber
Unspecified Boiler Type:
ESP
4400
490
1.04 0.39-1.7
3-198
-------
TABLE 3-117. SUMMARY OF MEASURED CADMIUM EMISSION FACTORS
FOR LIGNITE COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Multiclone
ESP
Cyclone Boilers:
Cyclone
ESP
ESP/Scrubber
Spreader Stoker:
Multiclone
ESP
Emission Factor
(lb/1012 Btu)
Average Range
15.4 5.1-25.6
<3.5
16
1 .2
30.6 1.8-59
5.3
1.9
Number of
Boilers
2
1
1
1
1
1
1
Number of
Data Points
2
1
1
1
2
1
1
3-199
-------
TABLE 3-118. SUMMARY OF MEASURED CADMIUM EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Uncontrolled
Multiclone
ESP
Multiclone/ Scrubber
Emission Factor
(lb/1012 Btu)
a
Average Range
290
465
20 0.49-39
0.98
Number of
Boilers
1
1
5
1
Number of
Data Points
1
1
5
1
Pulverized Wet Bottom:
Multiclone
Spreader Stoker:
1.5
Uncontrolled
Multiclone
ESP
Overfeed Stoker:
Uncontrolled
Economizer /Dust
Collector
21
0.56
1.36
82
56
4.1-65
Ool9-0o93
0,009-4.2
12-300
44-67
7
2
2
4
1
14
2
3
5
2
Each boiler was weighted equally in determining this average. An arithmetic
mean value was calculated for each boiler, and then a mean of these means
was calculated.
3-200
-------
TABLE 3-119. SUMMARY OF MEASURED CADMIUM EMISSION FACTORS FOR
SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Spreader Stoker:
Uncontrolled
Mechanical Ppt/ESP
Emission Factor
(lb/1012 Btu) Number of
a
Average Range Boilers
99 4.9-290 2
9.8 5.7-14 1
Number of
Data Points
4
2
a
Each boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-201
-------
TABLE 3-120. SUMMARY OF MEASURED CADMIUM EMISSION FACTORS FOR
COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Coal Type/
Boiler Type
Bituminous Coal:
Pulverized Dry
Bottom
Spreader Stoker
Overfeed Stoker
Anthracite Coal :
Stoker
Emission Factor
(lb/1012 Btu)
Control Status Average Range
Uncontrolled 12.8
Multiclone/Scrubber 0.35
Mechanical Ppt. 5.6
Mechanical Ppt. 1.2
Uncontrolled 2.4 1.4-3.5
Number
of
Boilers
1
1
1
1
3
Number
of Data
Points
1
1
1
1
3
3-202
-------
TABLE 3-121. CALCULATED CADMIUM EMISSION FACTORS FOR COAL COMBUSTION
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Boiler Type
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Cyclone
Cyclone
Cyclone
*s
Control Status Sectors
Uncontrolled U, I, C
Uncontrolled I, C
Mechanical Ppt . U, I
ESP U, I
Wet Scrubber U
Uncontrolled V, I
Mechanical Ppt. U
Multiclone U, I
ESP U, I
Wet Scrubber U
Uncontrolled U
Mechanical Ppt. U
ESP U
Emission Factor
(lb/1012 Btu) Reference
49-60
186
56
3.9
6.5
39-60
44.2
12
3.2
6.0
8.1-60
9.3
0.67
Baig et al . ,
Suprenant et
Suprenant et
Shih et al. ,
Suprenant et
Baig et al . ,
Shih et al. ,
Shih et al. ,
Baig et al. ,
Shih et al. ,
Baig et al . ,
Baig et al . ,
Shih et al. ,
Shih et al. ,
Baig et al . ,
Shih et al. ,
Baig et al . ,
Shih et al. ,
1981
al., 1980a;
al.. 1980b
1980b;
al., 1980a
1981;
1980b
1980b
1981
1980b
1981
1981;
1980b
1980b
1981
1980b
1981;
1980b
Bituminous
Cyclone
Wet Scrubber
U
1.1
Shin e_t al .. 1980b
-------
TABLE 3-121. CALCULATED CADMIUM EMISSION FACTORS FOR COAL COMBUSTION (Continued)
Co
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lienite
Boiler Type
Stoker
Stoker
Spreader Stoker
Spreader Stoker
Underfeed Stoker
Automatic Coal-Fired
Furnace
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
Cyclone
Cyclone
Stoker
Control Status
Uncontrolled
Multiclone
Uncontrolled
Cyclone
Uncontrolled
Uncontrolled
Uncontrolled
Multiclone
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Sectors3
U, I, C
U, I, C
I
I
C
R
U, I. C
U, I, C
U
U
U
U
U
U
U
U, I. C
Emission Factor
(lb/1012 Btu) Reference
37-60
11
142
42
23
39
15-42
3.9
14
0.49
4.2
12-42
14
0.28
2.3
15-42
Baig et al . , 1981
Baig et al. , 1981
Suprenant et al . , 1980a
Suprenant et al . , 1980a
Suprenant et al . , 1980a
DeAngelis and Reznik,
Baig et al. , 1981
Baig et al . , 1981
Shih et al. , 1980b
Shih et al. , 1980b
Shih et al. , 1980b
Baig et al. , 1981
Shih et al., 1980b
Shih et al. , 1980b
Shih et al. , 1980b
Baig et al . , 1981
1979
-------
TABLE 3-121. CALCULATED CADMIUM EMISSION FACTORS FOR COAL COMBUSTION (Continued)
V
N>
O
(Ji
Coal Type
Lignite
Lignite
Anthracite
Anthracite
Anthracite
Anthracite
Q
Boiler Type
Stoker
Automatic Coal-Fired
Furnace
Pulverized Dry Bottom
Stoker
Stoker
Automatic Coal-Fired
Furnace
Control Status
Multiclone
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
l ' *
Emission Factor
Sectorsa (lb/1012 Btu)
U, I, C 3.9
R 11
U, I, C 11-13
U, I, C 0.65-13
C 2.3
R 16
.
Reference
Baig et al. , 1981
De Angel is and Reznik,
Baig elt al.. 1981
Baig et al. , 1981
1979
Suprenant et al . , 1980b
DeAngelis and Reznik,
1979
-------
TABLE 3-122. CADMIUM REMOVAL EFFICIENCY OF CONTROLS3
Control Device
ESP
Mechanical Ppt.
ESP/Scrubber
2 ESPs in Series
Scrubber
Percent
Average
74.6
28.9
>67
90.5
94.4
Control
Range
18.3-99.7
24.3-37.5
>54->67
88.9-99.8
Number of
Boilers
8
1
1
1
2
Number of
Data Points
21
3
2
1
2
a
These control efficiencies represent measured control levels reported
in the literature. They may or may not be indicative of the long-term
performance of these types of controls on cadmium emissions from
combustion sources. The average values should not be construed to
represent an EPA-recommended efficiency level for these devices.
Each emission test weighted equally-
3-206
-------
TABLE 3-123. RECOMMENDED CHROMIUM EMISSION FACTORS FOR COAL-FIRED BOILERS
a,b
Boiler Type/Control Status
Pulverized Dry Bottom:
Uncontrolled
Multiclone
ESP
Scrubber
Fabric Filter
Pulverized Wet Bottom:
Uncontrolled
Multiclone
ESP
Scrubber
Cyclone :
Uncontrolled
Multiclone
ESP
Scrubber
Stoker :
Uncontrolled
Multiclone
ESP
2 Mechanical Ppt in series
Emission Factor
Bituminous
1250-1570
721-906
356-447
102-129
0.0034C
1020-1570
588-906
291-447
84-129
212-1570
122-906
60-447
17-129
942-1570
544-906
268-447
1.5-5.5a
(lb/1012 Btu)
Lignite
1500-1880
866-1080
428-536
123-154
1220-1880
704-1080
348-536
100-154
253-1880
146-1080
72-536
21-154
1130-1880
767-1080
379-536
by Coal Type
Anthracite
2970-3720
1710-2150
846-1060
244-305
2420-3720
1400-2150
690-1060
198-305
502-3720
290-2150
143-1060
41-305
2230-3720
1290-2150
636-1060
Derivation of emission factors is documented in Section 3.7.1.4. Factors
are applicable to the utility, industrial, and commercial/institutional
sectors unless otherwise noted.
See definition of recommended factors in Section 1.2.
This value is for hexavalent chromium (Cr ) and is applicable to utility
boilers.
These values are for hexavalent chromium (Cr ) and are applicable to
industrial and commercial boilers.
3-207
-------
TABLE 3-124. VALUES USED IN CALCULATION OF UNCONTROLLED
CHROMIUM EMISSION FACTORS
Coal Type
a
Source: Table 3-19,
Source: Appendix D,
Concentration of
Chromium in
Coal, ppm (C)a
Heating Value,
Btu/lb (H)
b
Bituminous
Lignite
Anthracite
20.5
13.5
47.2
13,077
7,194
12,700
TABLE 3-125. FRACTION OF COAL ASH EMITTED AS
FLY ASH (F) BY BOILER TYPE
Boiler Type
Percent Fly Ash (F)c
Pulverized Dry Bottom
Pulverized Wet Bottom
Cyclone
Stoker
80
65
13.5
60
These factors are derived from studies of large and intermediate size
bituminous coal-fired boilers (Baig et al.. 1981; Shih et al. . 1980b).
3-208
-------
TABLE 3-126. CHROMIUM REMOVAL EFFICIENCY OF CONTROLS'
Control Device
Mechanical Ppt .
ESP or Mech. Ppt /ESP
2 ESPs in Series
ESP/Scrubber
Scrubber
2 Multicyclones in series
Fabric Filter
Percent
Average
42.3
71.5
93.7
92.9
91.8
50 .Oc
99. 1C
Control
Range
38.9-49.0
46.7-98.6
82.4-99.4
90.0-95.2
Number of
Boilers
1
5
1
1
2
1
1
Number of
Data Points
3
9
4
1
3
3
3
a
in the literature. They may or may not be indicative of the long-term
performance of these types of controls on chromium emissions from
combustion sources. The average values should not be construed to
represent an EPA-recommended efficiency level for these devices.
Each emisson test weighted equally in determining average.
c +6
These control efficiencies are for hexavalent chromium (Cr ); the
remaining values are for total chromium.
3-209
-------
TABLE 3-127. SUMMARY OF MEASURED CHROMIUM EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Uncontrolled
Mechanical Ppt.
ESP or Mech. Ppt /ESP
2 ESPs in Series
Scrubber
ESP/ Scrubber
Fabric Filter
Pulverized Wet Bottom:
ESP or Mech. Ppt/ESP
Scrubber
Cyclone :
Uncontrolled
ESP
Scrubber
Stoker:
Mech. Ppt or Multiclone
Fabric Filter
Emission
(lb/1012
Average
1880
8980
2860
740
21.3
17.3
0.0034b
1770
0.60
1150
1810
107
1440
153
Factor
Btu)
Range
244-7900
510-29,700
1.6-7970
<74-1740
4.5-290
86-3320
1000-1300
18-5340
455-2420
Number of
Boilers
4
2
12
1
3
1
1
5
1
1
5
1
2
1
Number of
Data Points
11
10
20
4
5
1
3
5
1
2
6
1
2
1
a_ , , . , .
Each boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
b +6
This factor is for hexavalent chromium (Cr ). The average factor was
reported in the reference, but the range of values was not.
3-210
-------
TABLE 3-128. SUMMARY OF MEASURED CHROMIUM EMISSION FACTORS
FOR SUBBITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Coal Fired:
ESP
Scrubber
Cyclone :
Uncontrolled
Scrubber
Unspecified Boiler Type:
ESP
Emission Factor
(lb/1012 Btu) Number of Number of
fl
Average Range Boilers Data Points
140 1 1
390 1 1
1100 1 1
100 1 1
18.4 8.8-28 2 2
Ł1
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-211
-------
TABLE 3-129. SUMMARY OF MEASURED CHROMIUM EMISSION FACTORS
FOR LIGNITE COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Emission Factor
(lb/1012 Btu)
Average
Range
Number of
Boilers
Number of
Data Points
Pulverized Dry Bottom:
Multiclone
ESP
Cyclone Boiler:
Cyclone
ESP
ESP/Scrubber
Spreader Stoker:
70.9 67.4-74.4
20.0
1000
<7.7
4.6 3.1-5.9
2
1
1
1
1
2
1
1
1
2
Multiclone
ESP
30.2
<5.3
1
1
1
1
3-212
-------
TABLE 3-130. SUMMARY OF MEASURED CHROMIUM EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Multiclone
ESP
Multiclone/Scrubber
Emission
(lb/1012
a
Average
2,560
1,130
126
Factor
BttO
Range
5.8-1,500
*
Number of
Boilers
1
4
1
Number of
Data Points
1
4
1
Pulverized Wet Bottom:
Multiclone
Spreader Stoker:
12.3
Uncontrolled
Multiclone
Multiclone/ESP
2 Mechanical
Collectors in series
Overfeed Stoker:
Uncontrolled
Economizer/Dust
Collector
3,880
194
16.6
1.5b
9,380
15,400
30-8,400
62-325
16-17.2
1,400-49,000
8,800-22,000
7
2
2
1
4
1
13
2
2
3
5
2
Each boiler was weighted equally in determining the average. An arithmetic
mean value was calculated for each boiler, and then a mean of these means
was calculated.
This factor is for hexavalent chromium (Cr ). The average emission factor
was given in the reference, but the range of values was not.
3-213
-------
TABLE 3-131. SUMMARY OF CHROMIUM EMISSION FACTORS FOR
SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Spreader Stoker:
Uncontrolled
Mechanical Ppt/ESP
Emission
(lb/106
Average
1750
68
Factor
Btu) Number of
Range Boilers
280-3500 2
15-120 2
Number of
Data Points
4
2
a
Each boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-214
-------
TABLE 3-132. SUMMARY OF MEASURED CHROMIUM EMISSION FACTORS
FOR COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Coal Type/
Boiler Type
Bituminous Coal;
Pulverized Dry
Bottom
Underfeed Stoker
Spreader Stoker
Overfeed Stoker
Anthracite Coal:
Stoker
Control Status
Uncontrolled
Multi clone /Scrubber
Uncontrolled
Mechanical Fpt.
Mechanical Ppt.
Uncontrolled
Emission Factor
(lb/1012 Btu)
Average Range
1920
18.1
18.8
100
1840
875 240-1510
Number
of
Boilers
1
1
1
1
1
3
Number
of Data
Points
1
1
1
1
1
3
3-215
-------
TABLE 3-133. PREVIOUSLY CALCULATED CHROMIUM EMISSION FACTORS FOR COAL COMBUSTION
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
i Bituminous
Ni
M
CT>
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Boiler Type
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Cyclone
Cyclone
Cyclone
Control Status Sectors8
Uncontrolled U, I, C
Uncontrolled I, C
Mechanical Ppt. U, I
ESP U, I
Wet Scrubber U
Uncontrolled U, I
Mechanical Ppt. U
Multiclone U, I
ESP U, I
Wet Scrubber U
Uncontrolled U
Mechanical Ppt. U
ESP U
Emission Factor
(lb/1012 Btu) Reference
1800-2300
6040
1790
128
198
1500-2300
1460
460
105
184
320-2300
302
22
Baig et al_2_ť
Suprenant et
Suprenant et
Shih et al. ,
Suprenant et
Shih et al= ,
BaiR et al. ,
Shih et al. ,
BaiR et al. ,
Shih et al. ,
BaiR et al. ,
Shih et al. ,
BaiR et al ,
Shih et al. ,
BaiR et al . ,
Shih et al. ,
Shih et al. ,
BaiR et al . .
1981
al. , 1980a;
al. . 1980b
1980b;
al. . 1980a
1980b;
1981
1980b
1981
1980b
1981
1980b;
1981
1980b
1981
1980b
1980b;
1981
Bituminous
Cyclone
Wet Scrubber
U
32
Shih e_t al. . 1980b
-------
TABLE 3-133. PREVIOUSLY CALCULATED CHROMIUM EMISSION FACTORS FOR COAL COMBUSTION (Continued)
co
N)
!-
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Boiler Type
Stoker
Stoker
Spreader Stoker
Spreader Stoker
Underfeed Stoker
Automatic Coal-Fired
Furnace
Pulverized
Pulverized
Pulverized
Pulverized
Pulverized
Cyclone
Cyclone
Dry Bottom
Dry Bottom
Dry Bottom
Dry Bottom
Dry Bottom
Control Status
Uncontrolled
Multiclone
Uncontrolled
Cyclone
Uncontrolled
Uncontrolled
Controlled
Controlled
Uncontrolled
Multiclone
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt.
Sectors4
U, I, C
U, I, C
I
I
C
R
C
R
U, I, C
U, I, C
U
U
U
U
U
Emission Factor
(lb/1012 Btu)
1400-2300
420
4650
1370
697
155
0.49
800-2300
220
588
21.4
174
700-2300
569
Reference
Baig et al. .
Baig et al. .
Suprenant et
Supr<
Suprc
DeAnj
Ajax
Ajax
Baig
Baig
Shih
Shih
Shih
Baig
Shih
ťnant et
jnant et
jelis and
and Cuff
and Cuff
et al . .
et al. ,
et al. ,
et. al. .
et al. ,
et al. ,
et al. ,
1981
1981
al.. 1980a
al., 1980a
al.. 1980b
Reznik, 1979
e, 1985
e, 1985
1981
1981
1980b
1980b
1980b
1981
1980b
-------
TABLE 3-133. PREVIOUSLY CALCULATED CHROMIUM EMISSION FACTORS FOR COAL COMBUSTION (Continued)
u>
I
oo
Coal Type
Lignite
Lignite
Lignite
Lignite
Lignite
Anthracite
Anthracite
Anthracite
Anthracite
Boiler Type
Cyclone
Cyclone
Stoker
Stoker
Automatic Coal-Fired
Furnace
Pulverized Dry Bottom
Stoker
Stoker
Automatic Coal-Fired
Furnace
Control Status
ESP
Wet Scrubber
Uncontrolled
Multiclone
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Sectors3
U
U
U, I, C
U, I, C
R
U, I, C
U, I, C
C
R
Emission Factor
(lb/1012 Btu) Reference
12
93
800-2300
220
28
2000-2300
120-2300
465
156
Shih et al
Shih et al
Baig et al
Baig et al
DeAngelis
Baig et al
Baig et al
Suprenant
DeAngelis
. , 1980b
. , 1980b
. , 1981
., 1981
and Reznik,
_._, 1981
. , 1981
1979
et alo , 1980b
and Reznik,
1979
*U = Utility, I = Industrial, C = Commericai/Institutionals R = Residential.
These values are for hexavalent chromium. The boiler type was not given in the reference.
-------
TABLE 3-134. RECOMMENDED COPPER EMISSION FACTORS FOR COAL-FIRED BOILERS
a,b
1 2
Emission Factor (lb/10 Btu) by Coal Type
Boiler Type/Control Status
Pulverized Dry Bottom:
Uncontrolled
Multiclone
ESP
Scrubber
Pulverized Wet Bottom:
Uncontrolled
Multiclone
ESP
Cyclone:
Uncontrolled
Multiclone
ESP
Spreader Stoker;
Uncontrolled
Multiclone
ESP
Overfeed Stoker:
Uncontrolled
Multiclone
ESP
Bituminous
848
503
194
24
573-848
340-503
86
147-848
87-503
22
448-987
265-590
67-148
987-1360
590-806
148-204
Lignite
1490
884
341
42
1010-1490
597-884
151
258-1490
153-884
39
787-1730
465-1040
118-260
1730-2390
1040-1420
260-358
Anthracite
927
550
212
26
626-927
372-550
94
161-927
95-550
24
490-1080
290-645
73-162
1080-1490
645-881
162-223
aThe derivation of these factors is documented in Section 3.7.1.5. They are
applicable to the utility, industrial, and commercial/institutional sectors.
See definition of recommended factors in Section 1.2.
3-219
-------
TABLE 3-135. SUMMARY OF MEASURED COPPER EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Uncontrolled
Mechanical Ppt.
ESP or Mech. Ppt /ESP
Scrubber
2 ESPs in Series
ESP/ Scrubber
Pulverized Wet Bottom:
ESP or Mech. Ppt /ESP
Scrubber
Cyclone :
Uncontrolled
ESP
Stoker:
Mechanical Ppt.
Fabric Filter
Emission Factor
(lb/1012 Btu)
Average
735
1490
205
24
34.5
14.1
85.6
2.3
980
22
265
5.8
Range
380-1500
210-3140
34-974
10-54
1.6-71
12.3-225
610-1350
0.05-44.2
188-342
Number of
Boilers
5
2
7
2
1
1
5
1
1
5
2
1
Number of
Data Points
19
10
24
3
. 5
1
5
1
2
6
2
1
a
Each boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-220
-------
TABLE 3-136. SUMMARY OF COPPER EMISSION FACTORS FOR
SUBBITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Coal-Fired;
ESP
S crubber
Cyclone:
Uncontrolled
Scrubber
Unspecified Boiler Type:
ESP
Emission Factor
(lb/1012 Btu)
Average Range
30
29
1000
170
66 50-82
Number of Number of
Boilers Data Points
1 I
1 1
1 1
1 1
2 2
3-221
-------
TABLE 3-137. SUMMARY OF COPPER EMISSION FACTORS FOR
UTILITY BOILERS FIRED WITH LIGNITE COAL
Boiler Type/
Control Status
Pulverized Dry Bottom:
Multiclone
ESP
Cyclone Boiler :
Cyclone
ESP
Spreader Stoker:
Multiclone
ESP
Emission Factor
(lb/1012 Btu)
Average Range
286 195-376
<69.7
480
30.2
193
46.5
Number of
Boilers
2
1
1
1
1
1
Number of
Data Points
2
1
1
1
1
1
3-222
-------
TABLE 3-138. SUMMARY OF MEASURED COPPER EMISSION FACTORS FOR
BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Pulverized Wet Bottom:
Multiclone
Spreader Stoker:
Emission Factor
(lb/1012 Btu)
Control Status
Pulverized Dry Bottom:
Uncontrolled
Multiclone
ESP
Multiclone/Scrubber
a
Average Range
3150
9530
155 80.6-230
19.5
Boilers
1
1
2
1
Data Points
1
1
2
1
45.1
Uncontrolled
Multiclone
ESP
Overfeed Stoker:
Uncontrolled
Economizer/Dust Collector
448
790
171
1930
4550
5.2-1100
411-1170
0.04-309
200-3500
4200-4900
7
2
2
4
1
14
2
3
5
2
Each boiler was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-223
-------
TABLE 3-139.
SUMMARY OF MEASURED COPPER EMISSION FACTORS
FOR SUBBITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Emission Factor
(lb/1012 Btu)
a
Average Range
Number of
Boilers
Number of
Data Points
Spreader Stoker:
Uncontrolled
Mechanical Ppt/ESP
2070
46
280-3000
18-74
2
1
4
2
Each boiler tested was weighted equally in determining this average. An
arithmetic mean was calculated for each boiler; and then a mean of these
means was calculated.
TABLE 3-140. SUMMARY OF MEASURED COPPER EMISSION FACTORS FOR
COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Coal Type/
Boiler Type
Bi_tumi.nou.s_Coal;
Pulverized Dry
Bottom
Underfeed Stoker
Spreader Stoker
Overfeed Stoker
Anthra^cite Coal:
Stoker
Control Status
Uncontrolled
Multiclone/
Scrubber
Uncontrolled
Mechanical Ppt.
Mechanical Ppt.
Uncontrolled
Emission
(lb/101:
Average
1410
28
5.1
184
153
241
Factor Number
1 Btu) of
Range Boilers
1
1
1
1
1
232-723 3
Number
of Data
Points
1
1
1
1
1
3
3-224
-------
TABLE 3-141. CALCULATED COPPER EMISSION FACTORS FOR COAL COMBUSTION
U>
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Boiler Type
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Cyclone
Cyclone
v Cyclone
Spreader Stoker
Spreader Stoker
Underfeed Stoker
Automatic Coal-Fired
Control Status
Uncontrolled
Mechanical Ppt.
ESP
Wet Scrubber
Mechanical Ppt.
ESP
Wet Scrubber
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Cyclone
Uncontrolled
Uncontrolled
a
Sectors
I, C
U, 1
U
t
U
U
U
U
U
U
U
I
I
C
R
Emission Factor
(lb/1012 Btu)
2560
740
54
11.2
604
42
10.5
126
42
1.9
1950
558
232
155
Reference
Suprenant et al.. 1980a;
Suprenant et al., 1980b
Shih e_t al. . 1980b;
Suprenant et al.. 1980a
Shih et al. . 1980b
Shih et al.. 1980b
Shih et al. , 1980b
Shih et al. , 1980b
Shih et al.. 1980b
Shih e^ al. . 1980b
Shih et al., 1980b
Shih et al., 1980b
Suprenant et al., 1980a
Suprenant et al.. 1980a
Suprenant et al., 1980b
DeAngelis and Reznik, 1979
Furnace
Lignite
Pulverized Dry Bottom
Mechanical Ppt.
U
516
Shih et. al. . 1980b
-------
TABLE 3-141. CALCULATED COPPER EMISSION FACTORS FOR COAL COMBUSTION (Continued)
U)
Coal Type
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Anthracite
Anthracite
Boiler Type
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
Cyclone
Automatic Coal-Fired
Furnace
Stoker
Automatic Coal-Fired
Furnace
Control Status
ESP
Wet Scrubber
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Uncontrolled
Uncontrolled
Sectors8
U
U
U
U
U
R
C
R
Emission Factor
(lb/1012 Btu) Reference
18.8
21.1
500
10.0
11.4
70
93
235
Shih e_t al. .
Shih et al. ,
Shih et al. ,
Shih et al. ,
Shih et al. ,
DeAngelis and
Suprenant et
DeAngelis and
1980b
1980b
1980b
1980b
1980b
Reznik, 1979
al.. 1980b
Reznik, 1979
Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
-------
TABLE 3-142. COPPER REMOVAL EFFICIENCY OF CONTROLS3
Percent Control
Control Device
Mechanical Ppt.
ESP
ESP /Scrubber
2 ESPs in Series
Scrubber
Average
40.7
85.0
97.4
98.7
91.4
Range
35.6-44.7
28.6-99.2
97.4-99.94
83.0-99.8
Number of
Boilers
1
9
1
1
2
Number of
Data Points
3
29
1
5
2
aThese control efficiencies represent measured control levels reported
in the literature. They may or may not be indicative of the long-term
performance of these types of controls on copper emissions from combustion
sources. The average values should not be construed to represent an
EPA-recommended efficiency level for these devices.
3-227
-------
TABLE 3-143. RECOMMENDED MERCURY EMISSION FACTORS FOR COAL-FIRED BOILERSa>b
Boiler Type/Control Status
All Types of Boilers0:
Uncontrolled
Multiclone
ESP
Scrubber
Emission Factor
Bituminous
16
16
8-16
0.96-7.4
(lb/1012 Btu)
Lignite
21
21
10-21
1.2-9.6
by Coal Type
Anthracite
18
18
9-18
1.1-8.3
a
Derivation of emission factors is documented in Section 3ť7.1.6. They are
applicable to the utility, industrial, and commercial/institutional sectors,
See definition of recommended factors in Section 1ť2.
c
Boiler types include pulverized coal-fired, cyclone-fired, and stoker
boilers.
3-228
-------
TABLE 3-144. SUMMARY OF MEASURED MERCURY EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type
Control Status
Pulverized Dry Bottom:
Uncontrolled
Mechanical Ppt.
ESP or Mech. Ppt /ESP
2 ESPs in Series
Scrubber
Pulverized Wet Bottom;
ESP or Mech. Ppt /ESP
Scrubber
Cyclone :
Uncontrolled
ESP
Scrubber
Stoker;
Mech. Ppt. or Multiclone
Fabric Filter
Emission Factor
(lb/1012 Btu)
a
Average Range
35 3.9-308
8.5 3.7-21.2
11.0 0.41-22.3
0.20 0.011-0.56
NDb
4.7 2.6-6.3
0.16
10
8.5 3.95-17.7
4.9
14.2 2.5-26
4.6
Number of
Boilers
3
1
13
1
1
5
1
1
5
1
2
1
Number of
Data Points
12
7
42
5
1
5
1
1
5
1
2
1
Each boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler and then a mean of
these means was calculated.
Not detectable.
3-229
-------
TABLE 3-145. SUMMARY OF MEASURED MERCURY EMISSION FACTORS
FOR SUBBITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Emission Factor
(lb/1012 Btu)
Average
a
Range
Number of
Boilers
Number of
Data Points
Pulverized Coal Fired:
ESP
Scrubber
Cyclone:
Uncontrolled
Scrubber
Unspecified Boiler Type:
ESP
4.1
11
81
4.9
1.8
1.7-2.0
Each boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-230
-------
TABLE 3-146. SUMMARY OF MEASURED MERCURY EMISSION FACTORS
FOR LIGNITE COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Emission Factor
(lb/1012 Btu)
Average
Range
Number of
Boilers
Number of
Data Points
Pulverized Dry Bottom:
Multiclone
ESP
Cyclone Boilers:
Cyclone
ESP
Spreader Stoker:
Multiclone
ESP
5.4
<0.23
22
0.46
5.6
0.53
4.4-6.5
2
1
1
1
1
1
2
1
1
1
1
1
3-231
-------
TABLE 3-147. SUMMARY OF MERCURY EMISSION FACTORS FOR
BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Multiclone
ESP
Multiclone /Scrubber
Emission Factor
(lb/1012 Btu)
Average Range
180
4.25 4.2-4.4
86
Number of
Boilers
1
4
1
Number of
Data Points
1
4
1
Pulverized Wet Bottom:
Multiclone
Spreader Stoker:
6.7
Uncontrolled
Multiclone
ESP
Overfeed Stoker:
Uncontrolled
Economizer/Dust Collector
3.4
15.4
2.95
1.3
0.8
0.76-12
5.8-25.1
1.0-4.2
0.011-2.1
0.39-1.2
7
2
2
4
1
14
2
3
5
2
Each boiler was weighted equally in determining this average. An arithmetic
mean value was calculated for each boiler, and then a mean of these means
was calculated.
3-232
-------
TABLE 3-148. SUMMARY OF MEASURED MERCURY EMISSION FACTORS
FOR SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
Boiler Type/
Control Status
Spreader Stoker:
Uncontrolled
Mechanical Ppt/ESP
(lb/1012
a
Average
4.8
0.50
Btu) Number of
Range Boilers
0.64-17 2
0.37-0.64 1
Number of
Data Points
4
2
aEach boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-233
-------
TABLE 3-149. SUMMARY OF MEASURED MERCURY EMISSION FACTORS
FOR COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Coal Type/
Boiler Type
Bituminous Coal :
Pulverized Dry
Bottom
Underfeed Stoker
Spreader Stoker
Overfeed Stoker
Anthracite Coal :
Stoker
Control Status
Uncontrolled
Multi clone /Scubber
Uncontrolled
Mechanical Ppt .
Mechanical Ppt.
Uncontrolled
Emission Factor
(lb/1012 Btu)
Average Range
5.8
1.1
0.42
1 ,4
13,0
5.3 3.5-7.0
Number
of
Boilers
1
1
1
1
1
3
Number
of Data
Points
1
1
1
1
1
3
3-234
-------
TABLE 3-150. CALCULATED MERCURY EMISSION FACTORS FOR COAL COMBUSTION
U)
Ui
Coal Type
Bituminous
Lignite
Lignite
Lignite
Lignite
Lignite
Anthracite
Anthracite
Anthracite
Anthracite
Boiler Type
All Types
(Pulverized Dry Bottom,
Pulverized Wet Bottom,
Cyclone, Stoker,
Residential Furnaces)
Pulverized Dry Bottom
or Stoker
Pulverized Dry Bottom
or Stoker
Cyclone
Pulverized Dry Bottom
or Cyclone
Automatic Coal-Fired
Furnace
Pulverized Dry Bottom
Stoker
Stoker
Automatic Coal-Fired
Furnace
a
Control Status Sectors
Uncontrolled U, I, C, R
Mechanical Ppt. U, I, C
ESP U, I
Wet Scrubber U
Uncontrolled U, I, C
Multiclone U, I, C
Uncontrolled U
Multiclone, ESP, U
or Wet Scrubber
Uncontrolled R
Uncontrolled U, I, C
Uncontrolled U, I, C
Uncontrolled C
Uncontrolled R
Emission Factor
(lb/1012 Btu) Reference
16
16
16
3.3
9.0-26
2.3
7 .6-26
23
14
9-11
0.53-11
4.6
16
Baig et al . .
Shih et al. .
Suprenant et
Suprenant et
DeAngelis and
Baig et al. ,
Bale et al. ,
Baig et al . ,
Shih et al. .
DeAngelis and
Baig et al . .
Baig et al. ,
Suprenant et
DeAngelis and
1981;
1980b;
al. , 1980a;
al.. 1980b;
Reznik, 1979
1981
1981
1981
1980b
Reznik, 1979
1981
1981
al.. 1980b
Reznik, 1979
*U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential
-------
TABLE 3-151.
RECOMMENDED MANGANESE EMISSION FACTORS
FOR COAL-FIRED BOILERS*>b
Boiler Type/Control Status
Pulverized Dry Bottom:
Uncontrolled
Multiclone
ESP
Scrubber
Pulverized Wet Bottom:
Uncontrolled
Multiclone
ESP
Cyclone:
Uncontrolled
Multiclone
ESP
Scrubber
Stoker:
Uncontrolled
Multiclone
ESP
Emission
Bituminous
2,980
1,390
642
36
808-2,980
377-1,390
177
690-1,300
322-607
151
70-131
2,170
196-1,010
31-475
Factor (lb/1012 Btu)
Lignite
16,200
7,580
3,500
196
4,410-16,250
2,050-7,580
965
3,760-7,090
1,760-3,310
823
382-714
11,800
1,070-5,510
169-2,590
by Coal Type
Anthracite
3,070
1,430
661
37
832-3,070
388-1,430
182
710-1,340
332-625
155
72-135
2,230
202-1,040
32-489
a
Derivation of emission factors is documented in Section 3.7.1.7. They are
applicable to utility, industrial, and commercial/institutional sectors.
See definition of recommended factors in Section 1.2.
3-236
-------
TABLE 3-152. SUMMARY OF MEASURED MANGANESE EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Uncontrolled
Mechanical Ppt.
ESP or Mech. Ppt /ESP
2 ESPs in Series
ESP/Scrubber
Scrubber
Pulverized Wet Bottom:
ESP or Mech. Ppt /ESP
Scrubber
Cyclone ;
Uncontrolled
ESP
Scrubber
Stoker:
Mech. Ppt or Multi clone
Fabric Filter
Emission
(lb/101
a
Average
3040
2250
635
149
28
46
177
0.95
1300
151
126
246
18
Factor
2 Btu)
Range
300-9300
460-4750
1 .0-9240
8.05-463
4.6-318
7.4-418
1300-1300
11-314
188-304
Number of
Boilers
5
2
11
1
1
3
5
1
1
5
1
2
1
Number of
Data Points
20
10
35
5
1
6
5
1
2
6
1
2
1
a
arithmetic mean value was calculated for each boiler- then a mean of these
means was calculated.
3-237
-------
TABLE 3-153. SUMMARY OF MEASURED MANGANESE EMISSION FACTORS
FOR SUBBITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/ (Ib/lQ12 Btu) Number of Number of
Emission Factor
(lb/1012 Btu)
Control Status Average Range Boilers Data Points
Pulverized Coal:
ESP 43 1 1
Scrubber 110 1 1
Cyclone:
Uncontrolled 600 1 1
Scrubber 120 1 1
Unspecified Boiler Type:
ESP 27 19-35 2 2
3-238
-------
TABLE 3-154. SUMMARY OF MEASURED MANGANESE EMISSION FACTORS
FOR LIGNITE COAL-FIRED UTILITY BOILERS
Emission Factor
Boiler Tvue/ (lb/1012 Btu) Number of
Control Status Average
Pulverized Dry Bottom:
Multiclone 1620
ESP 17
Cyclone Boiler:
Cyclone 1600
ESP 11
ESP/Scrubber 2,94
Spreader Stoker:
Multiclone 1790
ESP <10
Range Boilers
1560-1680 2
1
1
1
2.92-2.96 1
1
1
Number of
Data Points
2
1
1
1
2
1
1
3-239
-------
TABLE 3-155. SUMMARY OF MEASURED MANGANESE EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Multiclone
ESP
Multiclone/ Scrubber
Emission Factor
(lb/1012 Btu)
Average Range
790
661 274-790
15
Number of
Boilers
1
4
1
Number of
Data Points
1
4
1
Pulverized Wet Bottom:
Multiclone
Spreader Stoker:
15
Uncontrolled
Multiclone
ESP
Overfeed Stoker:
Uncontrolled
Economizer /Dust
Collector
2310
103
31
1930
2050
16-14,000
23.9-183
10.6-51.4
230-6700
1100-3000
7
2
2
4
1
14
2
3
5
2
Each boiler weighted equally in determining this average. An arithmetic
mean value was calculated for each boiler, and then a mean of these means
was calculated.
3-240
-------
TABLE 3-156. SUMMARY OF MEASURED MANGANESE EMISSION FACTORS
FOR SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Spreader Stoker:
Uncontrolled
Mech. Ppt/ESP
Emission Factor
(lb/1012 Btu) Number of
Average3 Range Boilers
10,560 1,300-17,000 2
45 28-62 1
Number of
Data Points
4
2
aEach boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-241
-------
TABLE 3-157. SUMMARY OF MEASURED MANGANESE EMISSION FACTORS
FOR COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Coal Type/
Boiler Type
Emission Factor Number Number
of of Data
(lb/1012 Btu)
Control Status
Average Range Boilers Points
Bituminous Coal:
Pulverized Dry
Bottom
Underfeed Stoker
Spreader Stoker
Overfeed Stoker
Anthracite Coal:
Stoker
Uncontrolled 2680
Multiclone/Scrubber 26
Uncontrolled 3.5
Mechanical Ppt. 188
Mechanical Ppt. 290
Uncontrolled 114
40-163
3-242
-------
TABLE 3-158. CALCULATED MANGANESE EMISSION FACTORS FOR COAL COMBUSTION
U)
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Boiler Type
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Cyclone
Cyclone
Cyclone
Cyclone
Stoker
Stoker
Spreader Stoker
Spreader Stoker
Control Status
Uncontrolled
Uncontrolled
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt.
Multiclone
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Multiclone
Uncontrolled
Cyclone
a
Sectors
U, I, C
I, C
U, I
U, I
U
U, I
U
U, I
U, I
U
U
U
U
U
U, I, C
U, I, C
I
I
Emission Factor
(lb/1012 Btu)
2500-3200
4180
1260
90
20
2100-3200
1030
650
72
19
440-3200
214
15
3.5
1900-3200
580
3210
953
Reference
Baig et al . . 1981
Suprenant et al.. 1980a:
Suprenant et al.. 1980b
Shih et al. , 1980b:
Suprenant et al._. 1980a
Shih et al. . 1980b:
Baig et al. . 1981
Shih et al. . 1980b
Baig et al. , 1981
Shih et al. . 1980b
Baig et al. , 1981
Shih et al., 1980b;
Baig et al. , 1981
Shih et al.. 1980b
Baig et al. , 1981
Shih et al. . 1980b
Shih et al. . 1980b:
Baig e_t al. . 1981
Shih et al. , 1980b
Baig et al. , 1981
Baig et al. . 1981
Suprenant et al. . 1980a
Suprenant et al^, 1980a
-------
TABLE 3-158. CALCULATED MANGANESE EMISSION FACTORS FOR COAL COMBUSTION (Continued)
Coal Type
Bituminous
Bituminous
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
U)
K> Lignite
.p~
*~ Lignite
Lignite
Lignite
Lignite
Lignite
Anthracite
Anthracite
Anthracite
Anthracite
Boiler Type
Underfeed Stoker
Automatic Coal-Fired
Furnace
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
Cyclone
Cyclone
Stoker
Stoker
Automatic Coal-Fired
Furnace
Pulverized Dry Bottom
Stoker
Stoker
Automatic Coal-Fired
Furnace
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Multiclone
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt.
ESP
Wet Scrubber
Uncontrolled
Multiclone
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
.Uncontrolled
a
Sectors
C
R
U, I, C
U, I, C
U
U
U
U
U
U
U
U, I, C
U, I, C
R
U, I, C
U, I, C
C
R
Emission Factor
(lb/1012 Btu)
465
4650
4900-14,000
1300
1620
58
70
4200-14,000
1570
32.5
37
4900-14,000
1300
696
2000-2300
120-2300
186
156
Reference
Suprenant et al., 1980b
DeAngelis and Reznik, 1979
Baig e_t al. . 1981
Baig et al. , 1981
Shih et al. . 1980b
Shih et al.. 1980b
Shih et al. , 1980b
Baig et al. , 1981
Shih et al., 1980b
Shih et alo , 1980b
Shih et al. , 1980b
Baig et al. , 1981
Baig e_t al. . 1981
DeAngelis and Reznik, 1979
Baig e_t al. . 1981
Baig e_t al. . 1981
Suprenant et al., 1980b
DeAngelis and Reznik, 1979
"U
Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
-------
TABLE 3-159. MANGANESE REMOVAL EFFICIENCY OF CONTROLS3
Control Device
Mechanical Ppt.
ESP
ESP/Scrubber
2 ESPs in Series
Scrubber
Percent
Average
54.3
78.1
97.7
96.4
89.1
Control
Range
40.6-63.2
9.4-99.7
90.2-99.8
80.0-98.2
Number of
Boilers
1
8
1
1
2
Number of
Data Points
3
27
1
5
2
aThese control efficiencies represent measured control levels reported
in the literature. They may or may not be indicative of the long-term
performance of these types of controls on manganese emissions from
combustion sources. The average values should not be construed to
represent an EPA-recommended efficiency level for these devices.
Each emission test weighted equally.
3-245
-------
TABLE 3-160. RECOMMENDED NICKEL EMISSION FACTORS FOR COAL-FIRED BOILERS3'
Boiler Design/Control Status
Pulverized Dry Bottom:
Uncontrolled
Multiclone
ESP
Scrubber
Pulverized Wet Bottom:
Uncontrolled
Multiclone
ESP
Scrubber
Cyclone :
Uncontrolled
Multiclone
ESP
Scrubber
Stoker:
Uncontrolled
Multiclone
ESP
Emission Factor
Bituminous
1030-1290
522-654
280-352
37-46
840-1290
425-654
228-352
30-46
174-1290
88-654
47-352
6.3-46
775-1290
392-654
211-352
(lb/1012 Btu)
Lignite
928-1160
470-587
252-316
33-42
154-1160
382-587
205-316
27-42
157-1160
79-587
43-316
5.6-42
696-1160
352-587
189-316
by Coal Type
Anthracite
1790-2240
906-1140
487-610
64-81
1460-2240
739-1140
397-610
53-81
303-2240
153-1140
82-610
11-81
1350-2240
683-1140
367-610
Derivation of emission factors is documented in Section 3.7.1.8. Factors
are applicable to the utility, industrial, and commercial/institutional
sectors.
See definition of recommended factors in Section 1.2.
3-246
-------
TABLE 3-161. VALUES USED IN CALCULATION OF UNCONTROLLED
NICKEL EMISSION FACTORS
Coal Type
Bituminous
Lignite
Anthracite
Concentration of Nickel
in Coal, ppm (C)a
16.9
8.35
28.5
Heating Value
Btu/lb (H)b
13,077
7,194
12,700
Source: Table 3-42.
Source: ' Appendix D.
3-247
-------
TABLE 3-162. NICKEL REMOVAL EFFICIENCY OF CONTROLS3
Control Device
Mechanical Ppt .
ESP
2 ESPs in Series
ESP/Scrubber
Scrubber
Percent
Average
49.4
79.1
96.6
97.2
96.4
Control
Range
34.5-64.4
48.8-99.5
91.5-99.2
95.6-97.3
Number of
Boilers
1
5
1
1
2
Number of
Data Points
3
14
5
1
2
fl
These control efficiencies represent measured control levels reported
in the literature. They may or may not be indicative of the long-term
performance of these types of controls on nickel emissions from
combustion sources. The average values should not be construed to
represent an EPA-recommended efficiency level for these devices.
Each emission test weighted equally.
3-248
-------
TABLE 3-163. SUMMARY OF MEASURED NICKEL EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
Emission Factor
Boiler Type/
Control Status
Pulverized Dry Bottom:
Uncontrolled
Me chani cal Ppt .
ESP or Mech. Ppt /ESP
2 ESPs in Series
ESP/Scrubber
Scrubber
(lb/10
Average
1480
7870
2780
360
12.2
68
12 Btu)
Range
690-5000
260-23,500
520-5760
132-724
12-104
Number of
Boilers
4
2
11
1
1
2
Number of
Data Points
10
10
20
4
1
5
Pulverized Wet Bottom:
ESP or Mech. Ppt/ESP
Scrubber
Cyclone:
1260
1.1
74-2550
5
1
Uncontrolled
ESP
Scrubber
Stoker:
Mech. Ppt. or Multiclone
Fabric Filter
960
907 4.6-2020
46
3260 1330-5180
165
1
5
1
2
1
1
5
1
2
1
aEach boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-249
-------
TABLE 3-164. SUMMARY OF MEASURED NICKEL EMISSION FACTORS
FOR SUBBITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Coal Fired:
ESP
Scrubber
Emission Factor
(lb/1012 Btu)
Average Range
70
50
Number of
Boilers
1
1
Number of
Data Points
1
1
Cyclone:
Uncontrolled
Scrubber
Unspecified Boiler Type:
ESP
1700
46
13.2
5.4-21
3-250
-------
TABLE 3-165. SUMMARY OF MEASURED NICKEL EMISSION FACTORS
FOR LIGNITE COAL-FIRED UTILITY BOILERS
Boiler Type/ (lb/10 Btu) Number of Number of
Emission Factor
(lb/1012 Btu)
Control Status Average Range Boiler Data Points
Pulverized Dry Bottom:
Multiclone 439 267-611 2 2
ESP <158 1 1
Cyclone Boiler:
Cyclone 740 1 1
ESP <109 1 1
Spreader Stoker:
Multiclone 641 1 1
ESP <88 1 1
3-251
-------
TABLE 3-166. SUMMARY OF MEASURED NICKEL EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Emission Factor
(lb/1012 Btu)
Control Status
Pulverized Dry Bottom:
Multiclone
ESP
Multiclone /Scrub her
Average Range
1S390
470 10-930
60
Boilers
1
2
1
Data Points
1
2
1
Pulverized Wet Bottom:
Multiclone
Spreader Stoker:
1.5
Uncontrolled
Multiclone
ESP
Overfeed Stoker:
Uncontrolled
Economizer /Dust
Collector
5,770
130
1,020
4,610
22,200
32-20,600
31-230
840-23,000
16,500-28,000
6
2
1
4
1
12
2
1
5
2
Each boiler was weighted equally in determining this average. An arithmetic
mean value was calculated for each boiler, and then a mean of these means
was calculated.
3-252
-------
TABLE 3-167. SUMMARY OF MEASURED NICKEL EMISSION FACTORS FOR
SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Spreader Stoker:
Uncontrolled
Mech. Ppt/ESP
Emission
Factor
(lb/1012 Btu) Number of
Average
2370
30
Range Boilers
840-6500 2
1
Number of
Data Points
3
1
aEach boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-253
-------
TABLE 3-168. SUMMARY OF MEASURED NICKEL EMISSION FACTORS FOR
COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Coal Type/
Boiler Type
Control Status
Emission Factor Number Number
(lb/1012 Btu) of of Data
Average Range Boilers Points
Bituminous Coal:
Pulverized Dry
Bottom
Underfeed Stoker
Spreader Stoker
Overfeed Stoker
Anthracite Coal:
Stoker
Uncontrolled 2430
Multiclone/Scrubber 309
Uncontrolled 30
Mechanical Ppt. 91
Mechanical Ppt. 1530
Uncontrolled 825
314-1090
3-254
-------
Coal Type
Boiler Type
Control Status
Sectors
Emission Factor
(lb/1012 Btu)
Reference
co
K>
Cn
Cn
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Pulverized Dry Bottom
Pulverized Dry Bottom
Uncontrolled
Uncontrolled
Pulverized Dry Bottom Mechanical Ppt.
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Pulverized Wet Bottom
Cyclone
Cyclone
Cyclone
Cyclone
Stoker
Stoker
Spreader Stoker
Spreader Stoker
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt,
Multiclone
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt,
ESP
Wet Scrubber
Uncontrolled
Multiclone
Uncontrolled
Cyclone
U, I, C
I, C
U, I
U, I
1300-1600
6740
2020
144
U
U, I
U
U, I
U, I
U
U
U
U
U
U, I, C
U, I, C
I
I
528
1100-1600
1650
300
116
495
220-1600
342
26
88
970-1600
300
5110
1560
Baig et. al. . 1981
Suprenant et al.. 1980a;
Suprenant et al.. 1980b
Shih e_t al.. 1980b;
Suprenant et al.. 1980a
Shih e_t al, 1980b;
Baig e_t al. . 1981
Shih e_t al.. 1980b
Baig et. al. . 1981
Shih e_t al.. 1980b
Baig e_t al. . 1981
Shih e^ al.. 1980b;
Baig e_t al. . 1981
Shih e_t al. . 1980b
Baig e_t al. . 1981
Shih e_t al. . 1980b
Shih e_t al. . 1980b
Shih ejt al. . 1980b
Baig e_t al. . 1981
Baig e_t al. . 1981
Suprenant et al.. 1980a
Suprenant et al.. 1980a
-------
TABLE 3-169. PREVIOUSLY CALCULATED NICKEL EMISSION FACTORS FOR COAL COMBUSTION (Continued)
Coal Type
Bituminous
Bituminous
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
*f Lignite
t-o
*Ł Lignite
Lignite
Li-gnite
Lignite
Lignite
Anthracite
Anthracite
Anthracite
Anthracite
Boiler Type
Underfeed Stoker
Automatic Coal-Fired
Furnace
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
Cyclone
Cyclone
Stoker
Stoker
Automatic Coal-Fired
Furnace
Pulverized Dry Bottom
Stoker
Stoker
Automatic Coal-Fired
Furnace
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Multiclone
Mechanical Ppt,
ESP
Wet Scrubber
Uncontrolled
Mechanical Ppt .
ESP
Wet Scrubber
Uncontrolled
Multiclone
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
_ a
Sectors
C
R
U, I, C
U, I, C
U
U
U
U
U
U
U
U, I, C
U, I, C
R
U, I, C
Us I, C
C
R
Emission Factor
(lb/1012 Btu) Reference
930
155
490-1400
130
530
19
374
420-1400
514
10.5
202
490-1400
130
28
1000-1200
58-1200
465
156
Suprenant et al., 1980b
DeAngelis and
Baig et al . .
Baig et al. .
Shih et al. ,
Shih et al. ,
Shih et al . ,
Baig et al. ,
Shih et al. ,
Shih et al. ,
Shih et al. ,
Baig; et al. ,
Baig et al. ,
DeAngelis and
Baig et al . .
Baig e_t. al. .
Suprenant et
DeAngelis and
Reznik ,
1981
1981
1980b
1980b
1980b
1981
1980b
1980b
1980b
1981
1981
Reznik,
1981
1981
1979
1979
al.. 1980b
Reznik,
1979
Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
-------
TABLE 3-170. TRACE METAL EMISSION FACTORS FOR RESIDENTIAL COAL COMBUSTION BY COAL TYPE*
Trace Element
Arsenic
Beryllium
Cadmium
Chromium
Copper
Mercury
Manganese
Nickel
Bituminous
1160
17.0
52.2
157
136
20.7
760
129
o
Calculated emission factors based on
Section 3.3 (White et al., 1984). It
Emission Factor
Subbituminous
484
13.6
29.8
156
148
12.8
1000
73.5
average trace element content
is assumed 100 percent of the
(lb/1012 Btu) by Coal Type
Anthracite
453
10.4
13.0
372
129
12.2
790
224
of each type of coal presented in
mercury input in the coal feed is
Lignite
2380
27.5
57.3
188
239
10.0
4200
116
emitted, 75 percent of the arsenic and cadmium is emitted, and 10 percent of the other trace metals is
emitted (DeAngelis and Reznik, 1979). Heating values assumed are 13,077 Btu/lb for bituminous coal,
9,554 Btu/lb for subbituminous, 12,698 Btu/lb for anthracite, and 7,194 Btu/lb for lignite (see Appendix D).
-------
TABLE 3-171. TRACE METAL EMISSION FACTORS FOR RESIDENTIAL COAL COMBUSTION BY REGION OF COAL ORIGIN3
t_n
00
Trace Element
Arsenic
Beryllium
Cadmium
Chromium
Copper
Mercury
Manganese
Nickel
Appalachian
1440
19.5
8.4
157
157
16.0
860
133
1 2
Emission Factor (lb/10
Interior
1120
20.9
375
248
160
10.5
910
244
Btu) by Region of Coal
Northern Plains
525
13.6
24.9
83.3
109
18.1
1100
107
Origin
Rocky Mountains
392
15.2
29.0
218
153
20.8
2200
90.6
aCalculated emission factors based on average trace element content of coal from these regions presented in
Section 3.3 (White et al. . 1984). It is assumed that 100 percent of the mercury input in the coal feed is
emitted, 75 percent of the arsenic and cadmium is emitted, and 10 percent of the other trace metals is
emitted (DeAngelis and Reznik9 1979). Heating values assumed are 11,590 Btu/lb for Appalacian coal;
10,950 Btu/lb for Interior coal; and 9,040 Btu/lb for coal from the Northern Plains and Rocky Mountains.
-------
TABLE 3-172. MEASURED TRACE METAL EMISSION FACTORS FOR
BITUMINOUS COAL-FIRED RESIDENTIAL FURNACES
Trace Element
Arsenic
Cadmium
Chromium
Copper
Mercury
Manganese
Nickel
Emission Factor
Average
813
71
233 (0.49)b
179
19.2
1290
1110
(lb/1012 Btu)a
Range
31-2400
8.9-155
44.5-387
38.7-356
7.7-26.7
44-3640
3.9-3030
Based on testing of three furnaces.
The factor in parentheses is for hexavalent chromium. See text for
discussion (Section 3.7.1.9).
3-259
-------
TABLE 3-173. SUMMARY OF MEASURED URANIUM-238 EMISSION FACTORS FOR COAL-FIRED UTILITY BOILERS
I
K>
(^
o
Boiler Type/
Control Status
Pulverized Dry Bottom:
ESP
ESP/Scrubber
Scrubber
Pulverized Slag Bottom:
Mechanical Ppt/ESP
Cyclone :
ESP
Scrubber
Stoker:
Fabric Filter
ESP
Unspecified:
ESP
Emission Factor (pCi/g)a
Average Range
6.55 3.3-9.2
7.1
5.6
0.004
1.5 0.005-3.0
13.9 0.017-37.5
0.003
0.5
16.1 7-34.2
Emission Factor (pCi/10 Btu)
Average Range
295.3 6.3-675.9
22.5
73.7
,
68. Od
1757. 8e 301. 2-3214. 3e
13.8
294e 101. 6-486. 5e
Number of
Boilers Tested
8
1
1
1
2
3
1
1
3
aPicoCuries per gram of particulate emissions.
PicoCuriee emitted per 10 Btu input.
f
Each boiler tested was weighted equally in determining this average. An arithmetic mean was calculated for
each boiler, and then a mean of these means was calculated.
Average value from one unit. No heating value was available for the other unit, so emission factor could not
be expressed in terms of pCi/10 Btu.
6Average value from two units. No heating value was available for the other unit, so emission factor could not
be expressed in terms of pCi/10 Btu.
-------
TABLE 3-174. SUMMARY OF MEASURED THORIUM-232 EMISSION FACTORS FOR COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Pry Bottom:
ESP
ESP/Scrubber
Scrubber
Cyc lone;
Ł ESP
i-1
Scrubber
Stoker:
ESP
Emission Factor (pCi/g)a
Average Range
3.0 0.6-5.3
7.14
2.78
1 .8
2.09 1.5-2.68
0.5
Emission Factor (pCi/10 Btu) Number of
Average Range Boilers Tested
170.0 50.3-180.7 8d
22.7 1
36.5 1
40.8 1
170.0 110.2-229.7 2
13.8 1
PicoCuries per gram of particulate emissions.
PicoCuries emitted per 10 Btu heat input.
n
Each boiler tested was weighted equally in determining this average. An arithmetic mean value was
calculated for each boiler, and then a mean of these means was calculated.
Data from 7 of 8 boilers tested were used for calculations. The reference for the excluded test noted that
the error may be2-30 percent.
-------
TABLE 3-175.
SUMMARY OF MEASURED TOTAL POM EMISSION FACTORS
FOR COAL-FIRED SOURCES
Emission Factor
(lb/1012 Btu)
Sector/Boiler Type
Average
Range
Number of
Boilers Tested
Utility:
Pulverized Coal
Cyclone
Stoker8
Industrial:
Pulverized Coal
Stoker5
Residential/Commercial :
Stoker
Hand Stoked
Magazine Feed
3.9C
9.0
29.6
35.3
96.0
3,046
26,095
2,717
0.03-18.6
0.11-57.2
0.13-114
2.8-121
2.7-413
13.8-18,000
57.5-84,600
9.7-8.1771
24
10
8
6
17
25
5
4
Each boiler tested was weighted equally in calculating these averages.
Six boilers were controlled with ESPs, four with combination multicyclone/
ESP systems, three with cyclones, two with wet scrubbers, one was
uncontrolled, and the control status of ten was not reported.
c 12
One boiler with a POM emission factor of 565 lb/10 Btu was excluded from
these calculations because it was an outlier to the 4sta set. If this
boiler was included, the average would be 23.9 lb/10 Btu.
Eight boilers were controlled with ESPs and one with a wet scrubber; the
control status of the other boiler was not reported.
Four boilers were controlled with cyclones, one with a fabric filter, and
control status of the other -three was not reported.
Three boilers were controlled with multicyclone/ESP systems, two with ESPs,
and one with a multicyclone.
CT
One boiler was controlled with an ESP, one with a multicyclone, and the
remaining 15 were uncontrolled.
Category includes residential and small commercial boilers. All were
uncontrolled.
i 12
The range for bituminous coal is 2,632 to 8,177 lb/10 Btu, with the average
being-5,404 lb/10 Btu. The range for anthracite coal is 9.7 to 49.4
lb/10 Btu, with the average being 29.6 lb/10 Btu.
3-262
-------
TABLE 3-176. MEASURED FORMALDEHYDE EMISSION FACTORS FOR COAL-FIRED BOILERS AND FURNACES
CO
NJ
CTť
CO
Emission Factor
(lb/1012 Btu)
130
90
140
220
2100
380
63
Boiler Type
Pulverized Dry Bottom
Pulverized Dry Bottom
Chaingrate Stoker
Spreader Stoker
Underfeed Stoker
Underfeed Stoker
Hand Stoked
ft
Sectors
U
I
U
I
I
C
R
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Reference
Hangebrauck et al..
Hangebrauck et al.,
Hangebrauck et al.,
Hangebrauck et al.,
Hangebrauck et al.,
Hangebrauck et al.,
Hangebrauck et al.,
1964
1964
1964
1964
1964
1964
1964
U = Utility, I = Industrial, C = Commercial/Institutional, R = Residential.
-------
TABLE 3-177. CALCULATED LEAD EMISSION FACTORS FOR COAL AND OIL COMBUSTION
Coal/Oil
Type
Boiler Type
Control Status
Sectors
Emission Factors
(lb/10 Btu)
References
CO
K>
Bituminous Pulverized Dry Bottom Uncontrolled
Bituminous Pulverized Dry Bottom Uncontrolled
Bituminous Pulverized Dry Bottom Wet Scrubber
Bituminous
Pulverized Wet Bottom
Uncontrolled
Bituminous Pulverized Wet Bottom Mechanical Ppt.
Bituminous Pulverized Dry Bottom Multiclones
Bituminous Pulverized Wet Bottom ESP
U, I, C
I, C
Bituminous Pulverized Dry Bottom Mechanical Ppt. U
Bituminous Pulverized Dry Bottom ESP U, I
U
Us I
U
U, I
U, I
3 - 1249
2
130
70 - 91
2.8 - 24.2
39 - 60
1.1 - 183.8
12
1.1 - 183.8
Shih et. al.. 1980b
Shih e_t al. . 1980b;
Krishnan and
Hellwig, 1982
Shih e_t al. . 1980b
Shih et al.. 1980b;
Krishnan and
Hellwig, 1982
Shih e_t al. . 1980b;
Krishnan and
Hellwig, 1982
Shih e_t al. . 1980b;
Krishnasi and
Hellwig, 1982
Shih et. al. . 1980b;
Goldberg and
Higgenbotham, 1981
Shih e_t al. . 1980b;
Krishnan and
Hellwig, 1982
Shih et_ al^, 1980b;
Krishnan and
Hellwig, 1982
Bituminous Pulverized Wet Bottom Wet Scrubber
6.0
Shih et al.. 1980b
-------
TABLE 3-177. CALCULATED LEAD EMISSION FACTORS FOR COAL AND OIL COMBUSTION (Continued)
KJ
Coal/Oil
Type
Bituminous
Bituminous
Bituminous
Bituminous
Bituninous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Boiler Type
Cyclone
Cyclone
Cyclone
Cyclone
Tangential
Wall-fired
Stoker
Stoker
Stoker
Spreader Stoker
Spreader Stoker
Control Status
Uncontrolled
Mechanical Ppt.
ESP
Wet Scrubber
Multiclone +2
ESP
Multiclone +2
ESP
Uncontrolled
Multiclone
Fabric Filter
Uncontrolled
Cyclone + ESP +
Sectors8
U
U
U
U
U
U
U, I, C
U, I, C
I
I
I
Emission Factors
(lb/10 Btu) References
4.0 - 191 Shih et al..., 1980b
9.3 Shih e_t al.. 1980b
4 - 191 Shih et al., 1980b;
Krishnan and
Hellwig, 1982
2559 Shih e_t al. , 1980b
163 Baie et al.. 1981;
Goldberg and
Higginbotham, 1981
98 Baig et al. , 1981;
Goldberg and
Higginbotham, 1981
37 - 60 BaiR et al. , 1981
1154 - 1663 Krishnan and
Hellwig, 1982
2.6 Shih et al. , 1980b
142 Shih et al., 1980b
50 Shih et al. . 1980b
Lignite
Pulverized Dry Bottom
Scrubber
Uncontrolled
U, I, C
15 - 42 Suprenant et al..
1980a
-------
TABLE 3-177. CALCULATED LEAD EMISSION FACTORS FOR COAL AND OIL COMBUSTION (Continued)
,
Coal/Oil
Type
Lignite
Lignite
Lignite
Lignite
oj
N3
Lignite
Anthracite
Emission Factors
Boiler Type Control Status Sectors3 (lb/10 Btu) References
Pulverized Dry Bottom Multiclone U, I, C 42.1 Suprenant et al . ,
1980a
Pulverized Dry Bottom ESP U 5.8 Suprenant et al.,
1980a; Shih et al. ,
1980b; Krishnan and
Hellwig, 1982
Pulverized Wet Bottom ESP U 4.7 Suprenant et al.,
1980a
Cyclone Multiclone U, I 165 - 358 Suprenant et al.,
1980a; Shih et al. ,
1980b; Krishnan and
Hellwig, 1982
Cyclone ESP U 2.6 Suprenant et al.,
1980a; Shih et al. ,
1980b; Krishnan and
Hellwig, 1982
Pulverized Dry Bottom ESP I 91 Suprenant et al.,
Anthracite Stoker
Anthracite Stoker
Anthracite Stoker
Uncontrolled
Multiclone
Uncontrolled
U, I, C
1980a; Krishnan and
Hellwig, 1982
0.65 - 13 Krishnan and
Hellwig, 1982
1419 Krishnan and
Hellwig, 1982
2.3 Krishnan and
Hellwig, 1982
-------
TABLE 3-177. CALCULATED LEAD EMISSION FACTORS FOR COAL AND OIL COMBUSTION (Continued)
Coal/Oil
Type
Boiler Type
Control Status
Sectors
Emission Factors
(lb/10 Btu)
References
Residual
Residual
Residual
N>
Residual
Tangential
Tangential
Wall
Wall
Distillate Tangential
Distillate Wall
ESP
Uncontrolled
ESP
Uncontrolled
Uncontrolled
Uncontrolled
U, I
U, I
U, I
U, I
9.3
46.5
9.3
46.5
46.5
46.5
Goldberg and
Higginbotham, 1981;
Krishnan and
Hellwig, 1982
Goldberg and
Higginbotham, 1981;
Krishnan and
Hellwig, 1982
Goldberg and
Higginbotham, 1981;
Krishnan and
Hellwig, 1982
Krishnan and
Hellwig, 1982
Krishnan and
Hellwig, 1982
Krishnan and
Hellwig, 1982
*U = Utility, I = Industrial, C = Commercial/Institutional
-------
TABLE 3-178.
SUMMARY OF MEASURED LEAD EMISSION FACTORS
FOR BITUMINOUS COAL-FIRED UTILITY BOILERS
Boiler Type/
Control Status
Pulverized Dry Bottom:
Uncontrolled
ESP or Mechanical
Ppt./ESP
Scrubber
Tangential Cyclone +
2 ESP
Wall Fired Cyclone +
2 ESP
Pulverized Wet Bottom:
ESP
Mechanical Ppt./ESP
Scrubber
Cyclone :
ESP
Mechanical Ppt.
Wet Scrubber
Stoker:
Mechanical Ppt. or
Multiclone
Fabric Filter
Cyclone + ESP +
Scrubber
Emission Factor
(lh/10 ^ Etui
Average* Range
316 2.8 - 1249
49 7.0-90.9
16.8 2.8 - 24.2
163 95 - 282
98 76 - 107
63.8 1.1 - 183.8
646
22.3 22.3
15.3 4.0 - 19.2
213
4
1408 1154 - 1663
2.6
50 0.2-149
Number of
Boilers
Tested
4
2
3
1
1
7
1
1
6
1
1
3
1
2
Number of
Data Points
5
26
2
4
4
7
1
1
6
1
1
3
1
4
Each boiler tested was weighted equally in determining this average. An
arithmetic mean value was calculated for each boiler, and then a mean of
these means was calculated.
3-268
-------
TABLE 3-179. SUMMARY OF LEAD EMISSION FACTORS FOR UTILITY BOILERS
Coal/
Oil Type
Boiler Type/
Control Status
Emission,, Factor
db/10 Btu)
Average
Range
Number of
Boilers
Tested
Anthracite
Lignite
Residual Oil
Pulverized Dry Bottom:
ESP 91
Stoker:
Multiclones 1419
Pulverized Dry Bottom:
ESP
Multicyclones
Pulverized Wet Bottom:
ESP
Cyclone :
ESP
Multicyclones
Stoker:
ESP
Multicyclones
Tangential:
ESP
Uncontrolled
9.7 5.8-13.5
154 42.1 - 256
4.7
18 9.0-26.1
358
6
217 153.5 - 281
9.3
47 16.0-112.0
3
3
1
1
1
1
1
2
Wall:
ESP
Uncontrolled
9.3
47 16.0-112.0
3-269
-------
TABLE 3-180. SUMMARY OF LEAD EMISSION FACTORS FOR BITUMINOUS
COAL-FIRED INDUSTRIAL BOILERS
Boiler Type/
Control Status
Emission-Factor
fib/10 Btu)
Average
Range
Number of
Boilers
Tested
Number of
Data Points
Pulverized Dry Bottom:
Uncontrolled
Multiclone
ESP
Multiclone/Scrubber
2
0.65
91
24
1
1
6
1
1
1
6
1
Spreader Stoker:
Uncontrolled
Multiclone
ESP
1.6
0.49
1.2
3-270
-------
TABLE 3-181. SUMMARY OF MEASURED LEAD EMISSION FACTORS
FOR COMMERCIAL/INSTITUTIONAL BOILERS
Coal Type/
Boiler Type
Bituminous Coal :
Pulverized Dry
Bottom
Stoker
Residual Oil1
Tangential
Wall
Distillate Oil:
Tangential
Wall
Control
Status
Multiclone
Scrubber
Multiclone
Uncontrolled
Uncontrolled
Scrubber
Uncontrolled
Scrubber
Uncontrolled
Uncontrolled
Emission,-Factor
fib/10 Btu}
Average Range
374
20
281
656
52 16.0 - 186.0
7.1 4.7 - 9.5
52 16.0 - 186.0
7.1 4.7 - 9.5
85 47 - 112.0
85 47 - 112.0
Number
of
Boilers
1
1
2
2
4
2
2
2
3
3
Number
of Data
Points
1
1
2
2
4
2
2
2
3
3
Source: Suprenant et al.. 1980b; Goldberg and Higginbotham, 1981.
3-271
-------
4.0 RECOMMENDATIONS FOR CONDUCTING RISK ASSESSMENTS
FOR TRACE POLLUTANTS FROM COAL AND OIL COMBUSTION
The objectives of this chapter are to present recommendations on how
national risk assessments may be performed for trace pollutant emissions from
coal and oil combustion sources in the utility, industrial, commercial/
institutional, and residential sectors. All pollutant emissions data, boiler
population characterization data, and risk assessment methodology information
generated and learned from activities presented in Chapters 2 and 3 are
combined to formulate recommendations on the most feasible ways to assess
risks for trace pollutant emissions from fossil fuel combustion sources. In
addition to the recommended approaches, optional, and generally less precise
(than the recommended approach), means of conducting risk assessments for
combustion sources are described. The optional procedures may warrant
consideration in cases where time or budgetary constraints limit the detail
to which a required risk assessment can be performed.
The recommended approaches provided here (or their options) have been
performed by the Pollutant Assessment Branch of EPA, Research Triangle Park,
North Carolina, for the purpose of obtaining preliminary estimates of risk
from coal and oil combustion sources. The Pollutant Assessment Branch should
be contacted to obtain details on the results of the preliminary risk
assessment analyses and on planned future activities in this area.
4.1 UTILITY BOILERS
4.1.1 Recommended Approach
Of the four coal and oil combustion sectors assessed in this project,
the utility sector is the smallest (in number) yet it generally contains the
largest (in size) individual point source emitters. There are roughly 2000
units in the utility sector, 1400 coal and 600 oil. Because the number of
sources is relatively (compared to other combustion sectors) low, the
4-1
-------
emissions of individual sources are significant, and the sector is the best
characterized of all combustion sectors, it was determined that a point
source risk assessment of all coal and oil utility boilers should be
conducted. To conduct this point source assessment, an organized data base
providing boiler locations by longitude/latitude and boiler stack
characteristics is required. The POWER STATISTICS data base developed by the
Edison Electric Institute (EEI) appears to best provide the location and
stack data required. The recommended risk assessment approach for utility
boilers involves conducting a point source assessment of all boilers using
the POWER data base (for source data) and EPA's Human Exposure Model (HEM)
for exposure and risk calculations.
The POWER data base is a completely computerized, comprehensive
statistical data system containing unit-specific design and operating data
for all planned and operating utility-owned steam electric generating
stations in the United States. The system has been designed to:
identify steam electric power plants with similar design or
operating characteristics,
develop baseline data on industry-wide practices such as chlorine
use, ash disposal, pollution control, etc., and
calculate such values as annual fuel consumption, installed
capacity, design water usage, etc.
Currently, the data base coverage is approximately as follows.
1015 steam electric plants (sites)
2885 steam electric units
171 projected units
343 operating utilities
Coverage of the utility industry by fuel type is as follows.
1415 coal and lignite units
550 oil units
4-2
-------
707 gas units
130 nuclear units
37 geothermal units
25 combined cycle units
POWER STATISTICS is organized into three major dates files, "Site", "Air",
and "Water and Ash", containing more than 6500 records or more than
1.3 million data elements. The Site file contains information about an
entire power plant, including geographic location, ownership, cooling water
sources, plant fuel consumption, gross and net operating capacities, ash
disposal methods, and more. The Air file contains data describing individual
generating units within a power plant, including the steam generating system,
stack design, air pollution control equipment, fuel characteristics,
consumption rates, and generating capacity. The Water and Ash file contains
data on individual generating units, including cooling systems, biocide
types, condenser flow rates, intake velocities, heat rejection rates,
National Pollutant Discharge Elimination System (NPDES) permits, Clean Water
Act Section 316 (a) and (b) data, ash handling and disposal practices, and
more. The parameters contained in POWER are listed in Table 4-1 (Farrell,
1985). Items identified as being pertinent to a risk assessment analysis are
marked.
Much of the information contained in the POWER data base originates from
the U. S. Department of Energy - Energy Information Administration (DOE/EIA)
Form 767. These forms, which are filed annually by all steam electric power
plants over 100 megawatts (MW) in size, provide information in the following
areas.
fuel consumption
operating characteristics
boilers
stacks
pollution control equipment
combustion by-product handling and disposal
cooling systems
4-3
-------
TABLE 4-1. PARAMETERS CONTAINED IN THE POWER STATISTICS DATA BASE
PLANT GENERAL DATA
PLANT NAME*
OPERATOR
STATE*
ZIPCODE
COUNTY*
TOWN*
CONGRESSIONAL DISTRICT (CD)
OPR SITE CAP
PROJ SITE CAP
OPR COAL CAP*
LATITUDE
LONGITUDE*
NERC
POWER POOL
WATER1
Official name of plant. Two-letter state
abbreviations appear after plants that
have the same name as plants in other
states, e.g. Riverside (MN).
Operating utility.
State in which plant is located.
ZIPCode of plant mailing address.
County in which plant is located.
Town or city nearest to plant site.
U. S. Congressional District in which
plant is located.
Total steam-electric site capacity (gross
rating of MWe).
Projected additional steam-electric site
capacity.
Operating coal-fired capacity.
Latitude and longitude of generating
facilities.
North America Electric Reliability Council
region in which plant is located.
Power Pool to which plant belongs (if
applicable).
Cooling water source (and recipient of
cooling water discharge, if the same).
May be the name of a lake, river, creek,
well, municipal, sewage effluent, etc. If
intake water source is different from
receiving water, intake water source is
listed here. The following abbreviations
may be used: (I) for once through intake
or (M) for closed cycle makeup.
4-4
-------
TABLE 4-1. (Continued)
WATER2
WATERBODY3
WATERBODY TYPE
SEVEN Q TEN
AVG FLOW
EPA REGION
NPDES PERMIT AGENCY
NPDES PERMIT
NPDES ISSUE
NPDES EXPIRATION
CHLORINE USE 1974
CHLORINE USE 1976
CHLORINE USE 1978
CHLORINE USE 1980
CHLORINE USE 1982
If receiving waterbody is different from
intake water source, receiving waterbody
is listed here. The following abbrevia-
tions may be used: (D) for once through
discharge or (B) for closed cycle blowdown.
This field may also include other major
waterbodies within 20 miles of the plant
site or other descriptors such as "Great
Lakes", "Pacific Ocean", etc.
Additional listing for major waterbodies
within 20 miles of plant site or other
descriptors listed above. Also lists ZERO
DISCHARGE for applicable plants.
Characterization of cooling water source
as L (lacustrine), R (riverine), M (marine
if greater than 28 ppt salinity), E
(estuarine if between 1-18 ppt salinity),
or 0.(other, for wells, municipal, etc.).
Ten-year, seven-day low flow associated
with riverine or estuarine waters which
receive cooling water discharge or
blowdown (CFS).
Average flow associated with riverine or
estuarine waters receiving cooling water
discharge or blowdown (cfs).
U. S. EPA region in which plant is located.
U. S. EPA region (number) or two-letter
state abbreviation denoting administrator
of NPDES permit.
NPDES permit number for plant. The word
NONE is used to indicate "Not Applicable"
for zero discharge facilities.
Dates for current permit
(year-month-day).
Total onsite chlorine use (for all
purposes) in given year (tons).
4-5
-------
TABLE 4-1. (Continued)
PLANT FUEL DATA
(Available for 1979-1983)
TOTAL GEN
COAL GEN
OIL GEN
GAS GEN
NUCLEAR GEN
OTHER GEN
COAL CONSUMPTION (1,000 tons)*
OIL CONSUMPTION (1,000 bbls)*
GAS CONSUMPTION (1,000 mcf)
PLANT ASH DATA
(Available for 1979-1983)
FLY ASH TOTAL
BOTTOM ASH TOTAL
FGD SLUDGE TOTAL
FLY ASH SOLD
BOTTOM ASH SOLD
FGD SLUDGE SOLD
FLY ASH PAID DISPOSAL
BOTTOM ASH PAID DISPOSAL
FGD SLUDGE DISPOSAL
FLY ASH LANDFILLED
BOTTOM ASH LANDFILLED
FGD SLUDGE LANDFILLED
FLY ASH PONDED
BOTTOM ASH PONDED
FGD SLUDGE PONDED
Total steam-electric electric generation
(net MWhrs).
Total steam-electric generation by fuel
type (net MWhrs).
Total plant fuel consumption on an annual
basis.
Total quantity of fly ash, bottom ash/
slag, and FGD sludge collected on an
annual basis (1000 tons).
Total quantity of ash and sludge sold
on an annual basis (1000 tons).
Total quantity of ash and sludge removed
by contractor on an annual basis
(1000 tons).
Total quantity of ash and sludge
landfilled on an annual basis
(1000 tons).
Total quantity of ash and sludge ponded
on an annual basis (1000 tons).
FLY ASH COSTS
BOTTOM ASH COSTS
FGD SLUDGE COSTS
Total costs of ash and sludge collection
and disposal on an annual basis ($1000).
FLY ASH REVENUES
BOTTOM ASH REVENUES
FGD SLUDGE REVENUES
Total revenues resulting from sale of fly
ash, if applicable ($1000).
4-6
-------
TABLE 4-1. (Continued)
UNIT GENERAL DATA
UNIT NAME*
CAPACITY
STATUS*
YEAR
RETIRE
LOAD TYPE
STEAM SEND
CAPACITY FACTOR*
HOURS*
BOILER NUMBER*
BOILER MANUFACTURER
BURNER CONFIG*
BOTTOM TYPE*
BOILER TYPE
STEAM CAP
COAL RATE
OIL RATE
GAS RATE
Plant name plus unit number--usually
refers to a boiler-turbine-generator
series. Individual boiler or generator
numbers may be used on occasion.
Maximum nameplate generator capacity
(MWe).
OPR (commercial operation); CON (under
construction); PLN (planned); STN
(standby, shutdown, or economic reserve).
Actual or projected year of commercial
operation.
Projected retirement date (year).
Design unit loading BASELOAD, CYCLING,
PEAKING.
Is unit used to supply steam for heating
or for industrial users? Y or N.
Capacity factor on an annual basis (%).
Total number of hours of unit operation on
an annual basis.
Number of boilers used by unit.
Two letter abbreviation. If nuclear,
reactor manufacturer is listed.
Describes burner configuration, front-
fired, tangential, etc.
WET or DRY bottom.
Once through (supercritical or drum).
Maximum continuous steam capacity
(1000 Ibs/hr).
Fuel consumption rate at full load.
4-7
-------
TABLE 4-1. (Continued)
BOILER ORDER
UNIT FUEL DATA
UNIT FUEL*
ALTERNATE FUEL
FUEL SOURCE*
AVERAGE PERCENT SULFUR
PERCENT SULFUR HIGH
PERCENT SULFUR LOW
AVERAGE PERCENT ASH
PERCENT ASH HI
PERCENT ASH LO
Boiler order date (month/year)
Fuel used to produce over 50% of the
unit's output during most recent year.
Specifies coal rank or oil type, and
sulfur content. If unit is PLN or CON,
projected fuel is described.
Other fuels used for generation. Does not
list fuel used for start-up or flame
stabilization.
Origin of primary fuel. Two-letter state
abbreviations are given for states,
foreign countries are specified if known.
Actual supplier names are not listed.
Fuel characteristics are listed for
primary fuel only. Average value is
yearly average as fired (if available,
otherwise as received). High and low
values are for monthly averages.
Percent is percent by weight.
AVERAGE PERCENT MOISTURE
PERCENT MOISTURE HI
PERCENT MOISTURE LO
AVERAGE HEAT CONTENT*
HEAT CONTENT HI*
HEAT CONTENT LO*
COAL CONSUMPTION*
OIL CONSUMPTION*
GAS CONSUMPTION
Fuel consumed per generating unit on an
annual basis.
UNIT AIR DATA
STACK NUMBER*
STACK HT*
Number of stacks used or shared by unit.
Does not list stack number designation
(e.g., stack number 3, etc.).
Stack height above plant grade, in feet.
4-8
-------
TABLE 4-1. (Continued)
STACK DIAM*
FLUE TYPE*
UNITS PER STACK*
REHEAT
EXIT TEMP*
EXIT VELOCITY*
GAS FLOW*
PARTIC REMOVAL*
PARTIC REMOVAL MFR
PARTICULATE EFFICIENCY*
SCA
AIR CLOTH
BYPASS
S02 CONTROL*
SO. MFR
S02 EFFICIENCY
Effective stack diameter at exit, in feet.
If multiple liners, individual diameters
may be listed in comment line.
M (multiple) or S (single).
Stacks are designated as unique to unit
(UNIQUE UNIT ) or shared with other
units (SHARED ).
Is stack gas reheated prior to discharge?
Y or N.
Stack gas exit temperature, design value
at 100% load, in degrees Fahrenheit.
Stack gas exit velocity, design value at
100% load (fps).
Flue gas flow rate per boiler at full load
(ACFM/Min).
Type of control equipment is described
(cold side ESP, baghouse, etc.).
Manufacturer of particulate removal
device(s).
' Design high efficiency of primary
particulate control device.
SCA for electrostatic precipitators;
design value (square feet/1000 ACFM).
Design parameter for baghouses; may be
ratio or range of ratios.
Bypass of pollution-control equipment
available? Y or N.
Type of sulfur dioxide control is described
(scrubber, compliance fuel, etc.).
Scrubber manufacturer.
Design S00 removal efficiency of scrubber.
4-9
-------
TABLE 4-1. (Continued)
NO CONTROL*
x
UNIT WATER DATA
COOLING SYSTEM
CONDENSER TUBE MAT
CONDENSER FLOW
INTAKE FLOW
DISCHARGE FLOW
EVAP RATE
INTAKE VELOCITY
DISCH VELOCITY
INTAKE SYSTEM
DISCHARGE SYSTEM
FISH PROTECT
INFO 316
STATUS 316(A)
STATUS 316(B)
REQUEST 316(A)
REQUEST 316(B)
DECISION 316(A)
DECISION 316(B)
Type of NO control is described (over
fire air, flue gas recirculation, etc.)
Cooling system (once through or closed
cycle, cooling lakes, mechanical draft
tower, etc.).
Primary and secondary (if applicable)
condenser tube material is listed.
Design rate for cooling water flow across
condensers (cfs).
Design intake flow rate; Lf closed cycle
cooling, design makeup flow rate goes here
(cfs). If cooling pond or lake, enter
design intake flow from lake.
Design discharge flow rate; if closed
cycle cooling, design blowdown flow rate
goes here (cfs). If cooling pond or lake,
enter design discharge flow to lake.
Design evaporation loss in closed cycle
system (cfs).
Design intake velocity (fps).
Design discharge velocity (fps).
Intake and discharge system are described
(shoreline, surface, canal, etc.).
Fish protection devices are described
(travel screens, velocity caps, etc.).
Is unit involved in 316 process? Y or N.
Current status of unit's 316
Demonstrations.
Date 316 Demonstrations submitted to EPA.
Date 316 Demonstrations approved.
4-10
-------
TABLE 4-1. (Continued)
COOLING WATER TYPE
BIOCIDE
INJECT POINT
SUMMER TREATMENT
WINTER TREATMENT
MECH TREAT
HEAT TREATMENT
MAX FAC
AVG FAC
AMAX TRC
AVG TRC
CL SAMPLE POINT
BIOCIDE MOD
MINIMIZATION
MIN STATUS
UNIT ASH DATA
TRANSPORT WATER
Cooling water type is characterized
(fresh, saline, etc.).
Lists primary biocide used in main section
of cooling water system. May list other
biocides with specific applications in
cooling system (e.g., cooling tower,
etc.).
Describes biocide injection point.
Cooling system biocide treatment is
described as CONTINUOUS OR INTERMITTENT.
If INTERMITTENT, number of treatment
cycles is specified as X DAY, X
WEEK, X MONTH, as needed, etc.
Describes on-line, mechanical tube
cleaning treatment. Treatment schedule is
also specified.
Describes biocidal heat treatment
operation.
Cooling water effluent limitations for
chlorine (as specified in current NPDES
permit) (MG/L).
Chlorine sample point (as specified in
NPDES Permit) nearest to natural waterbody.
Biocide treatment modifications. If
cooling water discharge is chemically
dechlorinated, name of chemical is listed.
Have chlorine minimization studies been
done or are they planned at this unit?
Y or N.
Current status of chlorine minimization
studies: OPR; PLN; DISC (discontinued);
GPL (completed).
Lists sources(s) of transport water for
ash and sludge sluice systems.
4-11
-------
TABLE 4-1. (Continued)
FA TRANSPORT Classifies ash and sludge transport as:
BA TRANSPORT DRY: WOT (wet once through); WR (wet
FGD TRANSPORT recirculating); NA (not applicable).
FA PCT RECYCLE If FA transport is WR, lists percentage of
BA PCT RECYCLE water recycle.
Describ
sludge.
BA PCT RECYCLE water recycle.
FGD TREAT Describes pre-disposal treatment of FGD
c 1 iirtcro
FA FINAL DISPOSAL Describes final fly ash disposal. If pond
BA FINAL DISPOSAL or landfill, gives location (on or off
FGD FINAL DISPOSAL site), size (acres) and volume (acre-ft),
liner (if any), and number of units
sharing facility. May describe other
disposal methods.
*
Parameters that would be useful in a risk assessment conducted using HEM.
4-12
-------
The facilities falling below the 100 MW cutoff of the EIA Form 767 are amply
characterized by EEI through direct contact with the utilities involved. The
utility industry surveys they conduct includes facilities as small as 1 MW.
Other sources of information for the POWER data base are licensing documents
for new power plants, utility air and water quality studies, and
environmental impact statements and reports.
Statistical analyses and graphing are also an integral part of the POWER
data base. Seven types of statistical analysis are available.
Elementary (for means, standard deviations, etc.)
Basic (for medians, quartiles, sextiles, etc.)
Correlation (for correlation matrices, cross and auto correlation)
Regressions (for least square regressions)
Trend Curves (for fitting trend lines to your data)
Forecasting (for forecasting and analysis of time series)
Tests (to look for patterns between data)
Graphics capabilities include plots, surface charts, histograms, tower
charts, and pie charts.
Although EEI owns the data base and pays for its development and
maintenance, a private company, Utility Data Institute (UDI), does all
programming of the data base and is responsible for providing data to
customers. Data can be provided in hard copy or on magnetic tape by UDI or
customers can become subscribers to the system and access it directly. The
annual fee for a subscription is currently $1500. Subscribers can download
any or all of the data base to their own computer systems. The prime contact
for the data base at EEI is Ms. Susan Farrell (202/828-7622) and at UDI it is
Mr. Chris Bergesen (202/466-3660). Non-technical or procedural questions
should be directed to Ms. Farrell, while Mr. Bergesen should be contacted for
technical, data base specific questions.
The data on completed Form 767, received from utilities, are also
available from DOE-EIA in a computerized form. However, the DOE-EIA
computerized files are not as current or as complete as the EEI POWER
STATISTICS system, and therefore, are not recommended for use in the proposed
4-13
-------
utility source risk assessment. The DOE-EIA system only has the data
computerized through 1982. The POWER data base currently has 1983 data and
will be updated with 1984 information in the fall/winter of 1985. In
addition, the DOE-EIA system only has units of 100 MW or greater, while the
POWER data base covers down to the smallest unit. The DOE-EIA has
information on about 700 units total (includes coal, oil, gas, nuclear),
while POWER STATISTICS contains approximately 2000 coal and oil units.
Because the U. S. EPA is a co-sponsor and partially funds the EIA Form 767
data collection effort, EPA can access the existing data files at no charge
by sending DOE-EIA blank computer tapes suitable for copying. All inquiries
concerning the DOE-EIA computerized files of EIA Form 767 should be directed
to:
Mr. Al Beruel
Energy Information Administration
Forrestal Building
Room 2F-049
1000 Independence Avenue, S.W.
Washington, D. C. 10585
(202/252-6541)
Using HEM and the POWER data base, the recommended risk assessment
procedure for coal and oil sources in the utility sector would contain the
following major steps.
1. Extract longitude/latitude location and stack parameters for each
boiler from POWER and input the data to HEM.
2. Determine annual heat input of each boiler from the POWER data
base.
3. Calculate an emissions rate for each boiler using a unit emission
12
factor of 1 lb/10 Btu and the annualized heat input values.
4. Input all emission rates to HEM and run the model assuming a unit
potency or unit risk factor of 1.
5. Correct the results of the run for each boiler to actual conditions
by multiplying the risk obtained from the "unitized" modeling run
times the product of the applicable emission factor (from
Section 3) and the actual unit risk of the pollutants.
4-14
-------
6. Sum the results for each boiler by pollutant to obtain the national
aggregate risk from each pollutant.
This approach requires conducting a complete HEM analysis for 2000
sources only once (the "unitized" analysis). Once the unitized results are
available, risk from the utility boilers for each pollutant would be
determined simply by a series of multiplications. Aggregate risk for any
given pollutant is assumed to be equal to the sum of all the individual
boiler calculations for that pollutant.
To begin the risk assessment process, access to the POWER data base will
have to be established. Once this condition is achieved, boiler location and
stack parameters can be extracted. Necessary programming steps would need to
be designed to input the location and stack data to HEM from the POWER system
by computer linkage. The annual heat input of each boiler can be calculated
using the fuel use and average heat content data found in POWER (i.e., tons/yr
coal x 10 Btu/lb). If fuel heat content data are missing from a POWER data
base record, the typical fuel heating values provided in Appendix D can be
used to calculate annual boiler heat input. The results of these calculations
can be stored in a computer file or recorded on hard copy for later use.
To avoid having to run the HEM on approximately 2000 sources for each of
seven pollutants (copper, manganese, and mercury have no unit risk factors
and radionuclides are being handled separately by another approach in
Section 4.1.4), a "unit risk assessment" process is recommended that involves
ratioing "unitized" HEM results using actual pollutant emission factors and
unit risk factors. In this approach, only one unitized HEM run is made. All
2000 sources are assessed using the POWER data base source characteristics,
12
emission rates calculated using a unit emission factor of 1 lb/10 Btu, and
a unit risk or potency factor of 1. Site-specific HEM exposure results for
each source would be determined that were applicable to an emission factor of
12
1 lb/10 Btu and a unit risk of 1. Because of the assumptions and design of
the HEM and the unit risk factors, these unitized results can be ratioed by
the specific" pollutant emission factors and unit risk factors to extrapolate
each boiler's actual exposure and risk levels. The specific emission
factors, developed in Chapter 3, that would be applicable to each boiler can
4-15
-------
easily be selected because the POWER data base contains a description of the
boiler's fuel and its source (e.g., bituminous coal from Kentucky), boiler
type (e.g., dry bottom pulverized coal), and boiler air emissions control
device (e.g., baghouse, scrubber, cyclone). A series of 2000 calculations
(one for each boiler) would be made for each pollutant. These individual
boiler calculations for each pollutant would be summed to determine the
national aggregate risk of a particular pollutant from utility boilers.
Making these calculations can be expedited using the sorting capabilities of
POWER. The data base can be used to group all boilers of a specific
configuration (e.g., dry bottom pulverized bituminous coal controlled by a
cyclone) that would require the same emission factor. This feature would
speed up the calculation process by not having to go through the list of 2000
boilers and individually identify and group like configurations together.
This entire procedure should be computerized to avoid an excessive number of
manual calculations and the need for extensive hard copy data management.
The recommended utility boiler risk assessment methodology is best
explained through the use of a simple example. Assume a pulverized
bituminous coal dry bottom boiler controlled by a scrubber has been selected
for assessment from the POWER data base . The longitude/latitude location and
stack parameters of the unit are available directly from POWER and are input
to HEM. The annual heat input to the unit is calculated as follows from data
contained in POWER.
annual coal consumption is 100,000 tons
average heat input is 12,500 Btu/lb
yr ton Ib
Annual boiler heat input - 25 x 10 Btu/yr
An annual emission rate for the boiler for the HEM analysis would be
calculated as follows.
(25 x 1011 Btu/yr) x (1 lb/1012Btu)
Annual boiler emissions - 2.5 Ib/yr - 1.13 kg/yr
4-16
-------
For this particular boiler, the value of 1.13 kg/yr would be input to HEM and
an exposure and risk assessment conducted.
Assume that the total exposure predicted by HEM under these conditions
is 500 people - ug/m . Aggregate risk would be determined by multiplying
total exposure by the unit risk factor; however, under the recommended
approach the unit risk factor is first assumed to be 1 such that total
exposure and aggregate risk are the same. To determine the actual exposure
and risk from the boiler for each pollutant (e.g., arsenic), the value 500 is
multiplied by the ratio of the actual emission factor for arsenic from a
pulverized bituminous coal dry bottom boiler controlled by a scrubber
(2.5'lb/lO Btu) to the assumed unit emission factor, i.e., 1 lb/10 Btu.
. 2.5 lb/10*2 Btu
500 people-ug/m x 1 lb/10'1"' Btu - 1250 people-ug/m
The actual total exposure for the boiler for arsenic is 1250 people-ug/m .
Actual aggregate risk for the boiler from arsenic emissions is calculated as
follows.
total exposure x unit risk factor - incidences
Since the unitized HEM assumes unit risk to be 1, actual aggregate risk can
3
be calculated by multiplying unitized total exposure- (500 people-ug/m in the
12
example) times the actual arsenic emission factor (2.5 lb/10 Btu) times the
actual arsenic unit risk factor. Generically, the equation that would be
used to determine aggregate risk for all boilers is:
(total exposure \ /actual pollutant \ /actual pollutant 1
from the unitized I x I emission factor 1 x [unit risk factor I
HEM analysis I \ / \ /
The specific pollutant emission factors that would be needed for this
approach are provided in Section 3.
4-17
-------
4.1.2 Limitations of the Recommended Approach
One limitation of the recommended risk assessment approach for utility
boilers is related to the pollutant dispersion modeling algorithm contained
in the HEM. Utility boilers typically have tall stacks which are not modeled
accurately by the algorithms in HEM as compared to modeling results from more
sophisticated systems such as ISC-LT. All boilers cannot be modeled by
ISC-LT because of the extensive data required and the cost that would be
involved. However, to compensate for the HEM deficiencies during the
performance of a risk assessment, it might be appropriate to modify the tall
stack heights of certain boilers or stack height related variables such as
plume height.
A limited sensitivity analysis could be performed to estimate a factor
that would be used to modify the tall stack heights for the purposes of the
utility boiler HEM analysis. This sensitivity analysis would involve running
ISC-LT and HEM on several boiler scenarios with varying stack heights (but
with all other variables constant). By comparing the results of the two
models, the point at which predicted concentrations become markedly sensitive
to stack heights can be determined. An adjustment factor can be developed
from these experimental data to modify actual tall stack heights during HEM
runs.
A second limitation of the recommended approach is that a true value of
the risk to the most exposed individual is not obtained because overlapping
sources and exposure grids are not considered. For many of the coal-fired
units this situation does not present a significant problem because they are
typically located in rural areas and not generally near one another.
Therefore, the potential for overlapping emissions exposure is reduced.
Depending on the importance of defining risk to the most exposed individual
from coal boilers, the maximum individual risk predicted by HEM for a single
boiler may suffice. For oil-fired boilers, the situation is different,
particularly in the metropolitan Northeast, where there are several boilers
in relatively close proximity with overlapping exposure grids. In these
cases, the maximum individual risk for a single plant from the HEM analysis
would not suffice in the determination of the risk to the most exposed
individual.
4-18
-------
One means of estimating a value for the risk to the most exposed
individual (for coal or oil plants) would be to select an area that had
several (4-6) power plants in close proximity to each other, assume that is
the worst exposure scenario, and run a multiple source exposure model like
SHEAR or ISC-LT on these plants. Source input data for the models would
still be obtained from the POWER data base and the emission factors in
Chapter 3. Because of the small number of plants, there would not be a need
to apply the "unitized" approach presented in Section 4.1.1. Instead boiler
specific emission factors could be applied and risk determined using actual
pollutant unit risk factors. For either coal- or oil-fired plants, the POWER
data base would be an efficient means of identifying the number and location
of units in a State. This list of information and an atlas would enable the
selection of plants in close enough proximity (<50 km) to each other to have
overlapping exposure patterns.
A potentially good area to concentrate such an analysis for oil-fired
plants is in the southeastern New York (New York City)/northeastern
New Jersey area. In the event a similar analysis was needed for coal-fired
units, Ohio may be a reasonable choice from which to pick plants because it
consumes the most coal in the utility sector, it contains the most coal-fired
power plants, and it is not of an overly large size. If Ohio is viewed as a
probable source for the most exposed individual, the risk to the most exposed
may also be determined from the results of the recent EPA Ohio boilers, study
(Anderson et al., 1985). In the Ohio study, site-specific source data were
developed for practically all coal-fired power plants in Ohio. Trace metal
emission factors were developed from the literature and applied to the
site-specific data to estimate emissions. All the power plants were modeled
using Super SHEAR, an extended version of EPA's SHEAR model. One measure of
risk to the most exposed individual for each pollutant would be to use the
highest individual risk values generated in the Ohio study SHEAR analysis,
but modify them by the ratio of the emission factors developed in the current
study (Chapter 3) to those used in the Ohio study. Alternatively, the Ohio
boilers could be rerun in SHEAR using the emission factors generated in this
study.
4-19
-------
4.1.3 Options to the Recommended Approach
Because the total number of utility sources is relatively small
(compared to the numbers in the other combustion sectors) and relatively
well-developed data are available to characterize utility sources and their
emissions, a point source risk assessment approach appears to be the best way
to reasonably estimate risk from utility sources. Potential national
aggregate risk assessment options that would involve procedures other than
direct point source assessments of all plants (e.g., area source approaches,
extrapolations from a subset, etc.) do not appear to be warranted for utility
sources given the magnitude of their trace pollutant emissions and the
individual uniqueness of each utility source.
Given these considerations, the only optional national aggregate risk
assessment approach for the utility sector that appears appropriate entails
using NEDS information on utility boilers, trace pollutant emission factors
from the literature, and the HEM to conduct a point source exposure/risk
assessment. This same approach was used by EPA's Pollutant Assessment Branch
(PAB) in November 1984 to assess the risks presented by several trace metals
emitted from utility sources. In the PAB program, NEDS information was used
to obtain stack parameter data, location data, control device data, and
boiler size/fuel use data. Stack parameters and source location was used
directly in the HEM. Using emission factors from the literature and NEDS
boiler size/fuel use data and control device data, emission rates needed for
the HEM were calculated. The NEDS utility boiler data, augmented by trace
metal emissions estimates, were run through the HEM to predict national
aggregate risk. One deficiency of this approach is that NEDS does not
contain information on every utility source. Roughly 70 percent coverage of
sources is provided by NEDS. However, the coverage of emissions and potential
exposure/risk by NEDS is expected to be higher than 70 percent because NEDS
contains the major emission sources. One means of assessing the extent of
NEDS would be to calculate the total fuel consumption of all units in NEDS
and compare this total to the national utility fuel consumption statistics
published by DOE (Energy Information Administration, 1984b).
4-20
-------
As for the options, the exposure/risk results of the PAB study can be
accepted without change and used to represent risks to the population from
utility source" trace metal emissions (POM, formaldehyde, and radionuclides
were not covered). Alternatively, the PAB approach of using NEDS information
can be repeated using the trace pollutant emission factors that have been
generated in the current study (Section 3). The computer programming steps
needed to integrate NEDS information to HEM already exist as a result of the
first PAB assessment.
4.1.4 Recommended Approach for Radionuclide Emissions
Radionuclide emissions are being assessed separately from the other
fossil fuel combustion trace pollutants because their radioactive properties
and decay patterns, exposure pathways, and health risk characteristics do not
conform to the more classical pollutant exposure/risk assessment models such
as HEM. Radionuclide contact occurs through either external exposure to
radioactive air, water, and ground surfaces or internal exposure from
inhaling or ingesting radioactive air, water, or food. With radionuclides
the term exposure denotes physical contact with radioactive material. The
term dose refers to the amount of energy absorbed per gram of absorbing
tissue as a result of the exposure.
The mechanism of damage from radionuclide doses is quite different than
that from trace metal or trace organics doses. The primary mechanism for
radiation damage is the transfer of kinetic energy from the moving alpha and
beta particles and photons (gamma rays) to living tissue. This transfer
leads to the rupture of cellular constituents resulting in electrically
charged fragments (ionization). Although the amount of energy transferred is
small in absolute terms, it is enough to disrupt the molecular structure of
living tissue, and, depending on the amount and location of the energy
release, lead to the risk of radiation damage.
An extensive search of the literature (see Appendix B) identified only a
limited amount of information pertaining to exposure and risk assessments for
radionuclides from coal and oil combustion sources. The majority of the
relevant information identified was associated with EPA1s background
4-21
-------
information development program on a NESHAP for radionuclides from coal-fired
utility sources. In this work, EPA calculated doses and risks due to coal-
fired utilities emitting radionuclides to the air using a combination of three
computer models: AIRDOS-EPA, RADRISK, and DARTAB. These models calculate,
respectively, the resulting concentrations of radionuclides in the
environment, the dose and risk to persons resulting from a given quantity of
each of these radionuclides, and the total lifetime risk to individuals and
the total health impact on populations.
The AIRDOS-EPA computer model estimates radionuclide concentrations in
the air, rates of deposition on the ground, concentrations on the ground, and
the amounts of radionuclides taken into the body via inhalation of air and
ingestion of meat, milk, and fresh vegetables. A Gaussian plume equation
predicts the atmospheric dispersion of radionuclides released from stacks or
area sources. The amounts of radionuclides that are inhaled are calculated
from these air concentrations and a knowledge of how much air is inhaled by
an average person. The amounts of radionuclides ingested in the meat, milk,
and fresh produce that people consume are estimated by coupling the output of
the atmospheric transport models with the same terrestrial food chain models
used by the U. S. Nuclear Regulatory Commission in Regulatory Guide 1.109.
The AIRDOS-EPA model calculates atmospheric dispersion for radionuclides
released from one to six stacks or area sources. Radionuclide concentrations
for specified distances and directions are determined for the following
exposure pathways: (1) immersion in air containing radionuclides,
(2) exposure to ground surfaces contaminated by deposited radionuclides,
(3) inhalation of radionuclides in air, and (4) ingestion of food from the
area. The model can be used to determine either annual individual exposures
or annual population exposures at each grid location. Releases for up to 36
radionuclides may be specified for AIRDOS-EPA; however, there is no explicit
method for calculating radionuclide ingrowth during atmospheric dispersion in
the model. AIRDOS-EPA models both dry and wet deposition processes.
Resuspension of deposited material, building wake effects, and downwash are
not considered in the model.
The RADRISK model computes dose rates to organs resulting from a given
quantity of a radionuclide that is ingested or inhaled. These dose rates are
then used to estimate the risk of fatal cancers in an exposed cohort of
4-22
-------
100,000 persons. All persons in the cohort are assumed to be born at the
same time and to be at risk of dying from competing causes (including natural
background radiation). Estimates of potential health risk due to exposure to
a known quantity of approximately 500 different radionuclides are tabulated
and stored until needed. These risks are summarized in terms of the
probability of premature death for a member of the cohort due to a given
quantity of each radionuclide that is ingested or inhaled.
RADRISK calculates the radiation dose and risk resulting from an annual
unit, e.g. 1 picoCurie/yr, intake of a given radionuclide or the risk
3 2
resulting from external exposure to a unit, e.g., 1 picoCurie/m or m ,
concentration of radionuclide in air or on a ground surface. Since both dose
and risk models are linear, the unit dose and risk results can be scaled to
reflect the conditions associated with a specific source.
The DARTAB computer model then provides estimations of the impact of
radionuclide emissions from a specific facility by combining the information
on the amounts of radionuclides that are ingested or inhaled (as provided by
AIRDOS-EPA) with dosimetric and health effects data for a given quantity of
each radionuclide (as provided by RADRISK). The DARTAB model estimates dose
and risk for individuals at user-selected locations and for population
groups. Radiation doses and risks can be broken down by radionuclide,
exposure pathway, and organ; or they can be summarized by direction and
distance from the facility.
The exposure/risk assessment approach recommended for radionuclide
emissions in this current study involves using the AIRDOS-EPA, RADRISK, and
DARTAB models as described; however, their application would be slightly
modified from that used in the EPA radionuclide NESHAP work. In the NESHAP
work, risk to the population was assessed using a model coal-fired utility
boiler. The results of assessments of the single model boiler were
extrapolated to determine the national aggregate risk from radionuclides
emitted by coal-fired power plants. The model plant was defined to have a
U-238 emission rate of 100 milliCuries/yr, which EPA considered to be
representative of the upper range of potential emissions. This emission rate
was deemed to be representative of large, well-controlled boilers burning a
4-23
-------
high uranium content coal, or of large, less-controlled boilers burning a
coal of average or less than average uranium content. The model was assumed
to have a stack height of 185 m (607 ft) and a plume rise of 50 m (164 ft).
Using AIRDOS-EPA, four scenarios of exposure were investigated, urban,
suburban, rural, and remote. The number of people located within an 80 km
(49.7 mi) radius of a source in each of these population scenarios is as
follows.
Urban - 17,200,000
Suburban - 2,490,000
Rural - 589,000
Remote - 11,900
The risks from radionuclides emitted by the model facility under each of the
assumed population distributions were estimated using the AIRDOS-EPA results
and the RADRISK and DARTAB models. The lifetime risk to individuals and the
risk to the regional population under each exposure scenario are summarized
in Table 4-2. Using the data in Table 4-2 and assumptions that total
national U-238 emissions from coal-fired utility boilers are 8 curies/yr and
that the majority of U. S. generating capacity from coal units is located in
areas classified as suburban or rural, an estimate of national aggregate risk
from coal-fired utility boiler radionuclide emissions was prepared.
The currently recommended radionuclide assessment approach actually
contains three alternatives. The first alternative is simply to accept the
results of the existing EPA analysis performed for the purposes of the
radionuclides NESHAP. The results of this analysis were an integral part of
EPA's decision not to propose radionuclide emission limitation standards for
coal-fired utility boilers. This analysis and its results can be viewed as
sufficient to assess coal-fired utility radionuclide risks because the
analysis was conducted using a significantly higher than average emissions
estimate and the incremental risks to the public that were estimated were
deemed to be reasonable.
The second alternative for radionuclides involves using the basic
approaches of the radionuclide NESHAP analysis (i.e., alternative 1) with
some slight modifications. These modifications primarily involve the design
4-24
-------
TABLE 4-2. RISK ESTIMATES FROM THE RADIONUCLIDE NESHAP
BACKGROUND INFORMATION DOCUMENT
Regional Population
Lifetime Risk to . (Fatal Cancers/yr
Site Nearby Individuals*' of Operation) '
Urban
Suburban
Rural
Remote
2 x 10"6
4 x
3 x
3 x
10
10
10
-6
-5
-6
(3
(1
(2
x 10"
x 10"
x 10"
6
5)
6
1 x 10"1
1 x 10"2
5 x 10"3 (3 x 10"
3 x 10"5
3>
Represents risks calculated using the model coal-fired facility.
The risk estimates in parentheses include a dose rate reduction factor of
2.5 for low-linear energy transfer radiations.
SOURCE: U. S. Environmental Protection Agency, 1984.
4-25
-------
of the model plant used and the number of exposure scenarios considered. For
the second alternative, EPA desired to consider potential risks from a
utility combustion source with stacks less than 185 m (607 ft) in height.
Therefore, the model boiler for the second alternative only has a stack
height of 92 m (302 ft). In addition to a 92 m (607 ft) stack height, the
model boiler for alternative 2 has a stack diameter of 4 m (13.1 ft), an exit
gas velocity of 18 m/s (59 ft/s). and a heat release rate of 54.4 million
joules/s (13 million calories/s). A U-238 emission rate of
100 milliCuries/yr would also be used in alternative 2.
One less exposure scenario is included in alternative 2 than is included
in the radionuclide NESHAP approach (alternative 1). Alternative 2 contains
no remote exposure scenario, only urban, suburban, and rural scenarios. The
number of people assumed to be in the urban, suburban, and rural scenarios for
alternative 2 is the same as that used in alternative 1. ;
If desired, under alternative 2, the impacts of radionuclide emissions
from industrial and commercial coal-fired boilers could also be estimated.
The only difference between assessing industrial and commercial sources and
the utility sector previously described, would be the configuration and
radionuclide (i.e., U-238) emission rate of the model plants. The
recommended model plants for the industrial and commercial coal boilers are
as follows.
Industrial Commercial
U-238 Emissions 10 milliCuries/yr 10 milliCuries/yr
Stack Height 46 m (151 ft) 41 m (134 ft)
Stack Diameter 2.0 m (6.5 ft) 1.9 m (6.3 ft)
Exit Velocity 11.5 m/s (37.7 ft/s) 5.4 m/s (17.8 ft/s)
Heat Release Rate 11.3 x 10j? J/s 5.0 x 106,J/s
(2.7 x 10& cal/s) (1.2 x 105 cal/s)
The urban, suburban, and rural exposure scenarios would also be applicable for
industrial and commercial boiler sources.
The third alternative would be to use AIRDOS-EPA, RADRISK, and DARTAB to
perform a greatly expanded analysis that would not be limited to a single
model facility. Conceivably, these radionuclide risk assessment models could
4-26
-------
be run for the majority of the coal-fired utility units in the United States
using the POWER data base (see Section 4.1.1) or the NEDS data base (see
Section 4.1.3) as sources of plant-specific data. Based on data from POWER
and NEDS, source-specific radionuclide emission rates could be estimated from
the emission factors developed in the current study (see Chapter 3).
Extrapolations, of the type required under the single model plant approach,
would not be required to estimate national aggregate risk from radionuclides
emitted by coal-fired power plants. Given the variability of the utility
sector and its emissions, a plant specific analysis, or something closely
approaching it, would be preferable to the single model plant concept.
If time or monetary constraints do not permit the assessment of all
sources using AIRDOS-EPA, RADRISK, and DARTAB, then an expanded model plant
analysis should be considered. Instead of having a single model plant,
several models could be developed that better represent the variety of boiler
types and emission configurations, emission controls, and radionuclide
emission levels found in the utility sector. The POWER data base or the NEDS
data base could be used for model plant development to provide summary
information on the proportions of sources of certain types, in certain
control device groups, of certain emission configurations (e.g., tall
stacks), and in certain geographical areas. AIRDOS-EPA, RADRISK, and DARTAB
would be used to provide risk estimates for the multiple model plants in the
>
same manner as for the single model plant in the EPA NESHAP analysis. Using
the risk estimates from the multiple model plants analysis and an estimate of
the proportion of radionuclides (i.e., U-238) emitted by each model plant
category, an extrapolation can be made of the national risk from coal-fired
utility boiler radionuclide emissions. However, given the upper end emission
estimate used for the single model plant analysis and the resultant risks
which were judged to be acceptable, an expanded model plant analysis may be
more precise and detailed than is required, depending on the level of
acceptable risk.
The literature search identified another radionuclide exposure/risk
assessment tool, that although not currently available, should be used
instead of AIRDOS-EPA/RADRISK/DARTAB (when it is operational) because it
contains all of the features of the presently used models, but also
4-27
-------
incorporates several new features that will make it more comprehensive and
adaptable to individual user needs. The more advanced model is known as the
Computerized Radiological Risk Investigation System (CRRIS). The CRRIS model
consists of six fully integrated computer codes which calculate environmental
transport and resulting doses and risks to individuals or populations
exposed to atmospheric radionuclide releases. The individual codes may be
used alone for various assessment applications or may be run as a system
(Baes and Miller, 1983).
Radionuclides are handled by CRRIS either in terms of the released
radionuclides or in terms of "exposure" radionuclides which consist of both
the released nuclides and all (or a subset of) the decay daughters that grow
in during environmental transport. The capability of CRRIS to handle
radionuclide chains is accomplished through PRIMUS, which serves as a
preprocessor by accessing a library of radionuclide decay data and sets up
matrices of decay constants which are used by the other CRRIS codes in all
calculations involving transport and decay. PRIMUS may also be run
independently by the user to define the decay chains, radionuclide decay
constants, and branching ratios (Baes and Miller, 1983).
Atmospheric dispersion calculations are performed by ANEMOS for
distances up to 100 km (62 mi) and by RETADD-II for regional-scale distances.
Both codes output annual-average air concentrations and ground deposition
rates by location. ANEMOS employs an implementation of the Gaussian plume
atmospheric dispersion model with both dry and wet deposition parameter
options. The code accommodates both ground level and elevated multiple point
and area sources, and adjustments may be made for surface roughness, building
wake effects, terrain height, wind speed adjustment for height of release,
and variation of plume rise as a function of downwind distance (Baes and
Miller, 1983).
RETADD-II offers regional-scale atmospheric dispersion calculations
based on wind trajectories calculated from upper-air wind data for the
continental U. S. RETADD-II calculates dispersion from either a ground-level
or elevated source assuming emission of a puff every six hours and
determining the trajectory followed by each puff. This process can be
repeated for a month, a season, or a year, and average ground-level air
4-28
-------
concentrations and deposition rates can be determined over these time
periods. As with ANEMOS, RETADD-II considers both dry and wet plume
depletion effects together with decay and ingrowth of daughter radionuclides.
Terrestrial transport of radionuclides from ground level deposition is
calculated by the code TERRA. Output from TERRA consists of radionuclide
concentrations in several categories of vegetable produce, beef, and cow's
milk. TERRA is based on equilibrium models for foodchain transport modified
to account for leaching of radionuclides from root-zone soil; resuspension of
deposited material; input of site-specific information; and explicit
calculation of ingrowth of daughter radionuclide chains of varying length and
complexity. Input and output of calculated concentrations may be specified
for a point location or rectangular or circular grids of variable size. The
code automatically accesses SITE, a computerized data base of default site-
specific agricultural, climatological, land use, and demographic parameters
organized on a 0.5 x 0.5 degree longitude-latitude basis for the conterminous
United States. A second data base of transport parameters for radionuclide
soil-water distribution, plant uptake, weathering removal from plants,
transfer to beef and milk, and metabolic turnover rates for beef and milk is
also automatically accessed by TERRA.
The computer code ANDROS is used to calculate individual or population
exposures via pathways of immersion in the plume, standing on contaminated
ground, and inhalation and ingestion of radionuclides. ANDROS uses as input
the air, ground surface, and food concentrations output by ANEMOS, RETADD-II,
or TERRA. ANDROS accesses SITE to estimate population and food production.
Options in ANDROS allow for estimates of the fraction of non-contaminated
food imported to the assessment area to be input by the user or to be
calculated by the code from a mass balance of food supply and population
need. The RADRISK dosimetric and risk data file used in connection with
AIRDOS-EFA is accessed by ANDROS, and exposures are combined with dose and
risk factors to calculate individual or population impacts. These doses and
risks may be summarized by nuclide (released or exposure), geographic
location, pathway, organ, or various combinations of these items.
By its modular structure, ORRIS provides an alternative to assessment
codes which incorporate all calculations into a single program. Thus,
assessments may be tailored to the user's needs. Each code of CRRIS contains
4-29
-------
well documented default parameters for each of operation. Currently, CRRIS
is scheduled to be operational by mid-1986. Point source risk assessments of
radionuclide emissions from coal-fired power plants performed during this
time period should be conducted using CRRIS.
The CRRIS model is being developed for the U. S. EPA's Office of
Radiation Programs by Oak Ridge National Laboratory, Oak Ridge, Tennessee.
Further information on CRRIS can be obtained from:
Dr. Charles Miller
P. 0. Box X
Building 4500 N
Oak Ridge, TN 37831
(615)/850-6136
4.2 INDUSTRIAL AND COMMERCIAL/INSTITUTIONAL BOILERS
4.2.1 Recommended Approach
Industrial and commercial/institutional (hereafter referred to as
commercial) boilers are described together because the recommended risk
assessment approach for each category is the same. The risk assessment
approaches for the categories are the same because both have a large number
of individual sources, their sources are widely dispersed, and no complete
data base exists for either category that characterizes all or the majority
of individual sources. As described in Chapter 1, these source categories
were assessed as area sources in the 1984 PAB/Radian program to determine
risk attributable to combustion source trace metal emissions. An area source
assessment approach does not conform well to the physical configuration and
emission characteristics of the industrial and commercial categories. For
these reasons, point source risk assessment approaches are preferable for the
industrial and commercial source categories, and thus were concentrated on
during this study.
Radian Corporation (1984) Methodology for estimating exposure to arsenic,
beryllium, cadmium, chromium, and nickel from coal and oil combustion.
Research Triangle Park, North Carolina: EPA Contract No. 68-02-3515, Work
Assignment No. 31.
4-30
-------
The recommended risk assessment approach for industrial and commercial
coal and oil combustion sources involves conducting a combination point
source risk analysis and an area source risk analysis. The point source risk
analysis would be conducted using the HEM on a statistically representative
subset of boilers and extrapolating the results of the subset analysis to the
total boiler population.. The representative subset approach would only be
used on boilers >2.0 million Btu/hr input in size because of limitations
imposed by NEDS, the source of boilers for the subset.
Boilers with heat input capacities <2.0 million Btu/hr would be assessed
using an area source approach identical to that described previously in
Section 1.1 and in Radian Corporation (1984). An area source approach is
needed for these small boilers because NEDS does not contain enough records
on units <2.0 million Btu/hr to satisfy the number of sources that would be
required for a statistically representative subset analysis.
The recommended point source and area source analyses would be applied
to four categories of boilers: coal-fired industrial, oil-fired industrial,
coal-fired commercial, and oil-fired commercial. The derivation of the
combined point source/area source risk assessment approach for industrial and
commercial boilers is discussed below.
4.2.1.1 Point Source Component. The recommended point source risk
assessment component for industrial and commercial boilers contains the
following primary operations.
the selection of the boiler subset from NEDS
the estimation of risk for the subset using HEM
the extrapolation of the subset results to the nation
Boilers would be selected from NEDS using proportionate stratified
random sampling. Boilers are to be stratified according to two parameters:
1) boiler size and 2) boiler location as a function of State fuel consump-
tion. Using these two stratification parameters, boilers would be selected
from NEDS in proportions that are approximately equal to those existing
nationally for the source category. For example, if nationally 60 percent of
4-31
-------
the oil-fired commercial boilers are from 5-10 million Btu/hr in size and 25
percent of the oil consumption for commercial boilers is in New York and
Pennsylvania, then the subset selected from NEDS for oil-fired commercial
boilers should contain roughly 60 percent in the 5-10 million Btu/hr size
category and have 25 percent of those in New York and Pennsylvania. An
estimate of boiler size breakdowns nationally for industrial and commercial
coal and oil sources is presented in Table 4-3. Coal and oil fuel
consumption patterns for industrial and commercial sources are summarized in
Table 4-4. For each combustion sector, the range of fuel consumption has
been divided in four groups. These groupings contain States that have
relatively similar fuel consumption levels. Boilers should be allocated to
States to correspond to these consumption groupings. For example, when
selecting the subset for industrial coal-fired sources, 36.9 percent of the
subset for each boiler size category should be located in Indiana, Ohio, and
Pennsylvania because these three States consume 36.9 percent of the coal used
for industrial purposes. Since the selection process would be random, the
sources that were chosen could be in all three States or all in one State.
To better represent the boiler size distributions in NEDS, the ten
boiler size categories in Table 4-3 have been compressed into five categories
for the purposes of the recommended point source risk assessment approach.
The revised boiler size categories that would be used in the recommended
approach for boilers >2.0 million Btu/hr are given in Table 4-5. Table 4-5
would be interpreted and used in the following manner. For example, when a
subset of industrial oil-fired sources is being selected from NEDS,
68 percent must be greater than or equal to 2.0 and less than or equal to
10 million Btu/hr, and so on. The data in Table 4-5 would be integrated with
the consumption percentages and State groupings in Table 4-4 to select a
subset of >2.0 million Btu/hr boilers from NEDS for risk assessment purposes.
To illustrate the integration, the industrial oil sources example could be
used again. Of the 68 percent of the sources in the greater than or equal to
2.0 million Btu/hr and less than or equal to 10 million Btu/hr size category,
18.1 percent should be located in States associated with Boiler Location
Group I under Industrial-Oil. Similarly 24.4 percent of the 68 percent
4-32
-------
TABLE 4-3. INDUSTRIAL AND COMMERCIAL BOILER SIZE DISTRIBUTIONS ON A NATIONAL BASIS
Ul
Boiler Size Categories
(10b Btu/hr)
<0.4
0.4 - 1.5
>1.5 - 10
>10 - 25
> 25 - 50
>50 - 100
>100 - 250
>250 - 500
>500 - 1500
>1500
Industrial Coal
44
30
13.3
3
4
2.5
2.3
0.6
0.2
0.03
Percent by
Industrial Oil
35
37
19
4.5
2.7
1.0
0.6
0.15
0.03
<0.005
a
Size Category
Commercial Coal
55.5
31.4
12
0.55
0.48
0.16
0.04
0.007
0
0
Commercial Oil
60
28.7
10
0.7
0.48
0.15
0.05
0.01
0.002
0
a
Due to rounding not all totals precisely equal 100.
SOURCE: Devitt et al., 1979.
-------
TABLE 4-4. SUMMARY OF COAL AND OIL CONSUMPTION BY THE INDUSTRIAL AND COMMERCIAL SECTORS
Combustion
Sector
Consumption/Boiler
Location Group
Fuel,Consumption
12 Btu/yr)a
Percent of ,
National Consumption
States Included
in Each Group
Industrial-Coal
Industrial-Oil
II
III
IV
I
II
II
>0-12.0
>12.0-51.6
>51.6-200.0
>200.0
>0-28o7
>28.7-52.0
>52.0-105-6
4.4
12.9
45.8
36.9
18.1
24.4
29.5
AR, CTS BE, FL, ID,
KS, LA, MS, MA, ME,
MT, NDt NE, NH, NJ,
NM, NV, OKS OR, RI,
SD, VT, WA, WDCC
AZ, C08 GA, IA, MO,
MN, NC, SC, UT, WY
AL, CA8 IL, KY, MI,
MD, NY, TNS TX, VA,
WV, WI
IN, OH, PA
NU, Rl, SC, SU, TN,
UT, VT, WV, WY, WI,
WDCC
AL, AR, FL, GA, KY,
MN, MA8 MI, MS, MO,
NC, OK, ORS VA
IL, IN, ME, NJ, NY,
OH, PA, WA
IV
>105,6
28.0
CA, LA, TX
-------
TABLE 4-4. SUMMARY OF COAL AND OIL CONSUMPTION BY THE INDUSTRIAL AND COMMERCIAL SECTORS (Continued)
i
i*>
in
Combustion Consumption/Boiler Fuel. Consumption Percent of , States Included
Sector Location Group (10 Btu/yr)a National Consumption in Each Group
Commercial-Coal I > 0-2.0 14.4 AL,
DE,
LA,
MO,
NV,
XX,
II >2. 0-3.0 25.6 IA,
TN,
III >3. 0-7.0 18.1 IL,
IV >7.0 45.1 IN,
Commercial-Oil I ">0-10.0 15.2 AL,
DE,
ID,
MT,
NE,
RI,
VT,
II > 10 .0-25.0 17.2 CT,
OH,
III > 25 .0-80.0 31.4 CA,
IV >80.0 36.2 LA,
AR,
FL,
MT,
NE,
OR,
VT,
MN,
UT,
KY,
NY,
AR,
FL,
IN,
MN,
NM,
SD,
WI,
IL,
OR,
MA,
NY
CA,
GA,
ME,
NH,
OK,
WI,
NC,
WA,
MI,
OH,
AK,
GA,
KS,
MO,
ND,
SC,
WV,
ME,
VA,
NJ,
CO,
ID,
MD,
NM,
RI,
WY
ND,
WV,
VA
PA
AZ,
HA,
KY,
NH,
NV,
TN,
WY,
MD,
WA
PA,
CT,
KS,
MA,
NJ,
SD,
SC,
WDCC
CO,
IA,
MS,
NC,
OK,
UT
WDC
MI,
TX
These values represent the range of fuel consumption by an individual state in that particular region.
.The fuel consumption values represent 1982 data.
For a given combustion sector, these values equal the percent of national fuel consumption represented
by the total fuel consumption of all states in a particular region.
CWDC = Washington, D. C.
SOURCE: Energy Information Administration (1984b).
-------
TABLE 4-5. BOILER SIZE DISTRIBUTIONS TO BE USED FOR SELECTING COMBUSTION SECTOR SUBSETS FROM NEDS
Boiler Size Categories
(10 Btu/hr)
^2.0 and <10
>10 and <50
>50 and Ł250
>250
Industrial Coal
51
27
18
4
Percent by
Industrial Oil
68
26
5.7
0.1
Size Category
Commercial Coal
92
7
1
0.05
Commercial Oil
88
10
1
0.1
Boilers <2.0 x 10 Btu/hr are being assessed as area sources.
Due to rounding not all totals precisely equal 100.
-------
should be located in States associated with Boiler Location Group II, etc.
This same integration scheme would be followed for each boiler size category
>2.0 million Btu/hr.
The size of the subsets to be used in the point source analysis have
been fixed by EPA at a specified level for two reasons. The first reason
relates to the number and completeness of available boiler records in NEDS
that could be used to develop a subset. Although NEDS contains a relatively
large number of records on industrial and commercial boilers, not all of the
records are complete enough to be used for risk analysis purposes.
Therefore, by limiting the subset to a relatively small percentage of the
total in NEDS, the chances of getting complete records that meet the
approach's unit size and location criteria are improved. It basically allows
for greater flexibility during the subsequent random selection process. A
second reason for limiting the size of the boiler subsets involves keeping
computer computational requirements at a reasonable level (i.e., analyze a
few hundred sources as opposed to tens of thousands). The boiler subset
sizes for the point source risk assessment approach (i.e., for boilers
>2.0 million Btu/hr) have been defined by EPA to be:
industrial coal - 216 boilers
industrial oil - 443 boilers
commercial coal - 100 boilers
commercial oil - 400 boilers
With the subsets for the four sectors fixed at the above levels, the
necessary distributions of the boiler subset size categories in each of the
fuel consumption groups can be calculated using the information in Tables 4-4
and 4-6. These distributions are presented in Tables 4-7 through 4-10.
Once the framework for determining the combustion sector subsets has
been established (primarily Tables 4-6 through 4-10), the next step in the
subset selection procedure would involve having NEDS full point source
records printed for each boiler in the industrial coal, industrial oil,
commercial coal, and commercial oil sectors. The Source Classification Codes
4-37
-------
TABLE 4-6. SIZES OF BOILER SUBSETS TO BE SELECTED FROM NEDS AND USED
IN THE RECOMMENDED POINT SOURCE RISK ASSESSMENT APPROACH
Boiler Size Categories
(10b Btu/hr)
1 . >2.0 and <10
2. >10 and Ł50
3. >50 and Ł250
4. >250
Ł TOTAL
oo
Number of Boilers in the Subsets
Industrial Coal
110
59
39
8
216
Industrial Oil
299
115
25
4
443
Commercial Coal
91
8
1
0
100
Commercial Oil
358
38
4
0
400
-------
TABLE 4-7. DISTRIBUTION OF THE INDUSTRIAL-COAL BOILERS
SUBSET IN FUEL CONSUMPTION GROUPS
Boiler Size
Categories
(10 Btu/hr)
1. >2.0 and <10
2. >10 and <50
3. >50 and <250
4. >250
TOTAL
aSee Table 4-4 for a
TABLE 4-8
Total Boilers/
Category
110
59
39
8
216
definition of the
. DISTRIBUTION OF
Number of
I II
5 14
3 8
2 5
1 1
11 28
States in each group
a
Boilers /Group
III
50
27
18
3
98
IV
41
21
14
3
79
THE INDUSTRIAL- OIL BOILERS
SUBSET IN FUEL CONSUMPTION GROUPS
Boiler Size
Categories
(10b Btu/hr)
1. >2.0 and <10
2. >10 and <50
3. >50 and <250
4. >250
TOTAL
Total Boilers/
Category
299
115
25
4
443
Number of
I II
54 73
21 28
4 6
1 1
80 108
Boilers /Group
III
88
34
8
1
131
IV
84
32
7
1
124
See Table 4-4 for a definition of the States in each group.
4-39
-------
TABLE 4-9. DISTRIBUTION OF THE COMMERCIAL-COAL BOILERS
SUBSET IN FUEL CONSUMPTION GROUPS
Boiler Size
Categories
(10 Btu/hr)
1. >2.0 and <10
2. >10 and <50
3. >50 and <250
4. >250
TOTAL
aSee Table 4-4 for a
TABLE 4-10
Total Boilers/
Category
91
8
1
0
100
definition of the
Number of
I II
13 22
1 2
0 0
0 0
14 24
States in each group.
Boilers /Group3
III
16
2
0
0
18
IV
40
3
1
0
43
. DISTRIBUTION OF THE COMMERCIAL- OIL BOILERS
SUBSET IN FUEL CONSUMPTION GROUPS
Boiler Size
Categories
(10 Btu/hr)
1. >2.0 and <10
2. >10 and <50
3. >50 and <250
4. >250
TOTAL
Total Boilers/
Category
358
38
4
0
400
Number of Boilers/Grout)
I II
55 61
6 7
1 1
0 0
62 69
III
113
62
1
0
126
IV
129
13
1
0
143
See Table 4-4 for a definition of the States in each group.
4-40
-------
(SCC's) from NEDS that would need to be retrieved are given in Table 4-11.
Using NEDS sorting capabilities, the records could be broken down by boiler
size and location (e.g., print all records of boilers larger than 10 million
Btu/hr in Texas, New York, and Maine) at the time of printing or a complete
list of all units under a sector could be generated and the desired
distributions achieved through manual sorting.
Once all sources within a sector have been placed into the proper size/
location groups, the desired subsets can be selected using a statistically
random process. One simple means to randomly select boilers within a sector
would be to number all distinct source records obtained from NEDS, generate
random numbers using canned statistical programs that are available (hand-
held calculators can be used), and select sources on the basis of the random
numbers and their corresponding boiler from the NEDS source records list.
Following the delineation of the four analysis boiler subsets from NEDS,
the next step in the recommended risk assessment approach would be to conduct
risk assessments for the subsets using the HEM. Stack parameter data and
source longitude/latitude data can be obtained from NEDS and input directly
to the HEM using the proper computer programming procedures. Longitude/
latitude data would first have to be transformed from the UTM coordinates
that it exists in in NEDS. Trace pollutant emission rates needed for the HEM
analysis would be determined using the heat input data for each boiler and
the emission factors generated in the current study. The exercise of
calculating emissions should be computerized to effect an efficient and rapid
transference of the data into the HEM.
The HEM would be run to determine the aggregate risk attributable to
each boiler for each pollutant and would determine aggregate risk for the
subset as a whole. For the HEM analysis for each subset (i.e., industrial
coal, industrial oil, commercial coal, and commercial oil), the minimum and
maximum risks for individual boilers would be specified and a mean aggregate
risk for the subset would be determined. Variability of risk within the
subset should be assessed by calculating the variance and standard deviation
of the data set. The mean aggregate risk value for a given pollutant is
assumed to represent the typical mean risk resulting from emissions of an
average boiler in that combustion sector subset. This assumption is made
4-41
-------
TABLE 4-11. SOURCE CLASSIFICATION CODES NEEDED FROM NEDS FOR
THE COMBUSTION SECTOR SUBSETS SELECTION PROCESS
Combustion
Sector
Fuel
Code/Boiler Type
Industrial
Subbituminous Coal
Industrial
Lignite Coal
Industrial
Industrial
Commercial
Commercial
Residual Oil
Distillate Oil
Anthracite Coal
Bituminous Coal
1-02-002-21/Pulverized coal: wet bottom
1-02-002-22/Pulverized coal: dry bottom
1-02-002-23/Cyclone
1-02-002-24/Spreader Stoker
1-02-002-25/Traveling grate stoker
1-02-002-26/Pulverized coal: dry bottom
(tangential firing)
1-02-003-01/Pulverized coal
1-02-003-02/Pulverized coal: tangential firing
1-02-003-03/Cyclone
1-02-003-04/Traveling grate stoker
1-02-003-06/Spreader stoker
1-02-004-01/Grade 6 oil
1-02-004-04/Grade 5 oil
1-02-005-01/Grade 1 and 2 oil
1-02-005-04/Grade 4 oil
1-03-001-01/Pulverized Coal
1-03-001-02/Traveling grate stokers
1-03-001-03/Hand-fired
1-03-002-05/Pulverized coal:
1-03-002-06/Pulverized coal:
1-03-002-07/Overfeed stoker
1-03-002-08/Underfeed stoker
1-03-002-09/Spreader stoker
wet bottom
dry bottom
-------
TABLE 4-11.
SOURCE CLASSIFICATION CODES NEEDED FROM NEDS FOR
THE COMBUSTION SECTOR SUBSETS SELECTION PROCESS (Continued)
Combustion
Sector
Fuel
Code/Boiler Type
Commercial
(continued)
Commercial
Bituminous Coal
Subbituminous Coal
.p-
I
U)
Commercial
Commercial
Commercial
Lignite
Residual Oil
Distillate Oil
1-03-002-14/Hand-fired
1-03-002-16/Pulverized coal: dry bottom
(tangential firing)
1-03-002-17/Atmospheric fluidized bed
1-03-002-21/Pulverized coal: wet bottom
1-03-002-22/Pulverized coal: dry bottom
1-03-002-23/Cyclone
1-03-002-24/Spreader stoker
1-03-002-25/Traveling grate stoker
1-03-002-26/Pulverized coal: dry bottom
(tangential firing)
1-03-003-05/Pulverized coal
1-03-003-06/Pulverized coal: tangential firing
1-03-003-07/Traveling grate stoker
1-03-003-09/Spreader stoker
1-03-004-01/Grade 6 oil
1-03-004-41/Grade 5 oil
1-03-005-01/Grades 1 and 2 oil
1-03-005-04/Grade 4 oil
SOURCE: U. S. Environmental Protection Agency, 1982.
-------
because the subsets of boilers were designed to reflect, as accurately as
possible, the national boilers structure (both in size and location)
occurring in each combustion sector.
Aggregate risk for the whole United States would be extrapolated from
the subset results by multiplying the mean risk for each subset by the total
number of boilers nationally in that combustion sector. For example, if the
mean aggregate risk for a selected subset is 0.00005 (for a particular
pollutant) and there are in total 100,000 sources nationally of the type
defined by that subset, then total aggregate risk nationally for that type of
combustion sector is 5.
4.2.1.2 Area Source Component. Risks from industrial and commercial
boilers with heat input capacities less than 2.0 million Btu/hr would be
assessed using a county-level area source approach. The basic components of
an area source risk assessment approach are described in Section 1.1. The
area source modeling/risk assessment approach being recommended for
industrial and commercial boilers contains the following major elements.
1. Determine what percentage of fuel (of the national total) do
boilers less than 2.0 million Btu/hr consume in each of the
applicable source/fuel sectors. These percentages were taken from
Devitt et al. (1979) and are shown below.
industrial coal - 3 percent
commercial coal - 29 percent
industrial oil (residual) - 6.2 percent
commercial oil (residual) - 21 percent
industrial oil (distillate) - 12.6 percent
commercial oil (distillate) - 31 percent
For example, 3 percent of the total national consumption of coal by
industrial boilers is accounted for by boilers less than
2.0 million Btu/hr in size.
4-44
-------
Calculate the State fuel consumption totals for each sector using
the percentages in Number 1 and the total State fuel consumption
data given in Tables 4-12 and 4-13.
Determine total trace pollutant emissions from coal and oil burning
industrial and commercial sources in each State using State fuel
consumption estimates calculated in Number 2 and the emission
factors presented in Section 3 of this document.
Allocate each State's total trace pollutant emissions to each
county within the State based on the fuel consumption
characteristics of each combustion sector in each county. The
allocation of emissions within a county could be based on indexing
parameters contained in the 1980 Census of Housing data base. In
the commercial sector, there are six categories of employment
sources such as hospitals, universities, etc., that people are
listed as being employed by. Emissions are allocated on the basis
of the number of people living in each county and working in the
sum of the six commercial categories. For example, if a State had
100 people employed in the commercial sector and 25 lived in
county X, then 25 percent of the total State emissions from
commercial combustion would be allocated to county X. This same
type of index would be used in the industrial sector, except there
are only two categories of employment sources, durable and
nondurable goods.
Once the emissions are allocated by county, use the SHEAR area
source dispersion modeling equation, county emission levels, county
geographical areas, and mean national wind speed to project ambient
pollutant concentrations.
Integrate county specific pollutant concentrations with county
population data to determine exposure and risk levels. Sum for all
counties to obtain a national estimate of exposure and risk for
industrial and commercial coal and oil boilers less than
2.0 million Btu/hr in size.
4-45
-------
TABLE 4-12. COAL AND OIL CONSUMPTION IN THE
INDUSTRIAL SECTOR IN 1982
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
CA11
Bituminous and
Lignite Coal
124.5
0.0
33.2
6.9
70.8
22.9
0.1
4.2
0.0
6.8
17.1
0.0
8.5
97.1
332.3
33.3
7.9
59.6
8.6
5.1
79.2
2.3
166.3
20.4
2.3
33.8
4.2
Units are 10
Anthracite
Coal
0.2
0.0
0.0
0.0
0.0
a
0.2
a
a
0.0
0.0
0.0
0.0
0.1
a
0.1
a
0.3
0.0
0.1
0.1
0.4
0.1
a
0.0
0.0
0.0
Btu/vr)
Distillate
Oil
22.5
14.1
12.7
26.4
120.5
15.8
8.9
2.4
1.1
17.2
13.8
7.6
8.4
44.8
31.1
26.7
22.9
28.6
87.3
5.3
13.6
12.2
25.8
30.9
28.4
35.0
8.1
Residual
Oil
22.9
0.0
0.1
9.4
51.8
0.1
19.8
8.8
0.3
27.9
18.8
13.4
1.2
45.5
28.7
1.8
4.6
7.2
65.1
69.3
8.7
34.7
16.3
8.8
16.7
3.5
10.1
4-46
-------
TABLE 4-12. COAL AND OIL CONSUMPTION IN THE
INDUSTRIAL SECTOR IN 1982 (Continued)
State
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
TOTAL
(All
Bituminous and
Lignite Coal
5.5
4.3
0.1
2.3
3.0
102.4
42.2
8.9
313.5
11.4
3.1
266.5
0.0
51.5
5.3
68.3
88.7
41.8
0.1
99.9
8.0
135.6
53.7
28.3
2491.7
Units are
Anthracite
Coal
0.0
0.0
0.1
0.8
0.0
2.0
0.0
0.0
0.2
0.0
0.0
10.8
a
0.1
0.0
0.1
a
0.0
0.1
a
0.0
0.1
a
0.0
16.0
10 Btu/vr1)
Distillate
Oil
19.5
3.1
2.8
48.9
9.5
35.6
18.5
16.4
63.5
27.0
17.0
52.0
1.9
8.7
10.1
19.5
158.9
12.2
2.4
22.3
26.0
13.3
19.2
32.3
1312.8
Residual
Oil
0.6
0.1
3.7
56.7
3.9
64.0
33.5
3.8
13.3
4.2
21.9
51.5
3.9
12.7
0.2
3.8
168.8
5.1
1.5
17.6
49.6
8.7
13.0
8.7
1046.6
Represents small, non-zero value.
SOURCE: Energy Information Administration (1984b)
4-47
-------
TABLE 4-13. COAL AND OIL CONSUMPTION IN THE
COMMERCIAL SECTOR IN 1982
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
(All
Bituminous and
Lignite Coal
1.7
0.0
0.0
a
a
2.0
0.0
0.2
2.2
0.1
0.2
0.0
1.1
4.9
9.4
2.6
0.2
6.7
a
0.5
1.6
1.3
4.1
2.1
0.0
1.4
0.1
Units are
Anthracite
Coal
0.2
0.0
0.0
0.0
0.0
a
0.2
a
a
0.0
0.0
0.0
0.0
0.1
a
0.1
a
0.3
0.0
0.2
0.1
0.5
0.1
a
0.0
0.0
0.0
10 Btu/vrl
Distillate
Oil
1.4
2.8
0.1
0.8
25.6
0.9
17.3
2.4
2.6
3.8
6.1
0.3
2.7
18.2
8.4
3.8
0.8
2.9
2.0
8.3
10.3
32.1
12.4
5.8
0.7
6.1
1.1
Residual
Oil
1.0
a
1.0
0.9
34.5
a
4.8
7.6
0.7
2.4
a
0.7
0.1
6.5
0.6
0.2
a
a
104.5
4.0
2.8
26.6
1.4
1.1
0.2
0.2
a
4-48
-------
TABLE 4-13.
COAL AND OIL CONSUMPTION IN THE
COMMERCIAL SECTOR IN 1982 (Continued)
State
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
TOTAL
(All
Bituminous and
Lignite Coal
0.4
0.1
a
a
0.2
6.1
2.8
2.1
12.2
0.3
0.1
10.3
0.0
2.1
0.3
2.6
0.1
3.0
0.0
4.4
2.8
2.8
0.6
1.9
97.7
Units are
Anthracite
Coal
0.0
0.0
0.1
0.8
0.0
2.1
0.0
0.0
0.2
0.0
0.0
11.2
a
0.1
0.0
0.1
a
0.0
0.1
a
0.0
0.1
a
0.0
16.7
10 Btu/vrl
Distillate
Oil
1.7
0.4
3.4
41.0
3.3
79.2
5.2
1.2
12.3
0.9
5.8
27.5
2.5
2.4
1.7
6.5
28.4
2.2
3.0
8.6
11.6
1.8
7.4
2.0
439.7
Residual
Oil
0.6
0.1
3.9
29.1
0.0
118.0
1.2
1.3
1.1
0.0
9.4
7.0
1.4
0.2
0.1
0.6
11.4
0.2
0.7
3.3
5.8
a
0.2
1.1
398.6
Represents small, non-zero value.
SOURCE: Energy Information Administration (1984b)
4-49
-------
4.2.1.3 Total Risk. Total aggregate risk to the population from trace
pollutant emissions from industrial and commercial coal and oil boilers would
be expressed as the sum of the risk estimated by the point source component
(4.2.1.1) and the area source component (4.2.1.2).
4.2.2 Limitations of the Recommended Approach
The principal limitation or disadvantage of the recommended risk
assessment approach for industrial and commercial combustion sectors is that
it does not provide a true estimate of maximum individual risk (i.e., risk to
the most exposed). However, for the industrial and commercial sectors, no
true estimate of maximum individual risk can be determined because it is not
possible to assess the combined exposure effects of all sources. The only
means to estimate maximum individual risk for the industrial and commercial
sectors is to artificially define a set of conditions and procedures for
assessing the risk and by definition the result of performing these
procedures is the maximum individual risk.
For the industrial and commercial sectors, the EPA has developed the
following approach as a means to assessing maximum individual risk, which it
views as reasonable considering the data limitations and magnitude of the
sources.
The approach recommended by EPA involves the use of several assessment
tools including the NEDS data base, the HEM/SHEAR model, national fuel
consumption data, and prototype boiler units. The first step in the approach
is to determine which areas of the United States would be likely to have the
highest ambient concentrations of trace pollutants resulting from coal and
oil combustion in industrial/commercial sources. To determine those areas,
the national coal and oil consumption (in the industrial and commercial
sectors) was apportioned according to residential census data at the county
level and to employment statistics on a county level. Consumption data were
apportioned according to employment or county business activity patterns as a
check against the residential apportionment because not everyone lives in the
same county where they work. Both apportionments indicated that the same
four areas, Chicago, New Orleans, New York City, and Philadelphia, had the
highest consumption in the industrial and commercial sectors.
4-50
-------
Once the areas of highest consumption were identified, the HEM/SHEAR
model would be used as a tool to determine maximum individual risk. For the
larger boiler sources in the counties of interest, NEDS information would be
used to determine source location and source emission parameters. The larger
boilers would be modeled as point sources. The fuel consumption of these
larger sources (reported in NEDS) could then be totalled (on a county basis)
and subtracted from the apportioned county totals determined previously.
The remaining fuel consumption in the counties would be allotted to
prototype boiler sources. The configurations of the prototype sources are
characterized in Table 4-14. Emissions would be calculated using the
recommended emission factors generated in the current study and the prototype
size data in Table 4-14. HEM/SHEAR analyses would then be conducted with the
prototypes to estimate maximum individual risks from potential sources not
listed in NEDS. Because HEM/SHEAR allows prototypes to be assigned as single
double, triple, and quadruple locations (i.e., more than one boiler per
site), co-location of sources was assumed on about 30 percent of the total
number of sources to reduce computer run time and cost. The proportionment
scheme that would be used in each of the four geographic areas of interest is
as follows.
Percentage of sites with single boilers - 67.5 percent
Percentage of sites with double (2) boilers - 22.5 percent
Percentage of sites with triple (3) boilers - 7.5 percent
Percentage of sites with quadruple (4) boilers - 2.5 percent
The outputs of the HEM/SHEAR run would be multiplied by the relevant
pollutant unit risk factor to determine the maximum individual risk for a
particular pollutant from the prototype sources. The prototype results and
the NEDS-based results for the counties would be compared to determine the
source constituting maximum individual risk.
4.2.3 Options to the Recommended Approach
Three options to the recommended risk assessment approach for industrial
and commercial sources have been developed. Because of the uncertainties
4-51
-------
TABLE 4-14. PARAMETERS OF THE PROTOTYPE SOURCES USED TO DETERMINE MAXIMUM
INDIVIDUAL RISK FOR INDUSTRIAL AND COMMERCIAL SOURCES
*-
1
Ul
Category
Industrial
Industrial
Industrial
Commercial
Commercial
Commercial
Fuel
Coalb
Residual Oil
Distillate Oil
Coalc
Residual Oil
Distillate Oil
Size
(Btu/yr)a
19.1 x 109
6.4 x 109
4.2 x 109
8.1 x 108
3.9 x 109
5.2 x 109
Stack
Height (m)
29
16
16
22
16
16
Stack
Diameter (m)
1.2
0.7
0.7
1.1
0.8
0.8
Gas
Velocity (m/s)
5.4
11.5
11.5
6.5
9.6
9.6
Gas
Temp (°K)
482
474
474
435
466
466
aDerived from Devitt et al., 1979.
Cyclone furnace with multiclone controls is assumed. Bituminous coal is being burned.
Cyclone furnace with no controls is assumed. Bituminous coal is being burned.
-------
inherent in these options, none are strongly recommended for use in
industrial and commercial source risk assessment unless the recommended
approach cannot be carried out for whatever reasons. The size and logistical
characteristics of the industrial and commercial sectors are responsible for
the inability to specify optional risk assessment approaches that are closely
comparable to the recommended approach.
The first option involves conducting analyses of all boilers in each
combustion sector that are contained in NEDS using the SHEAR version of the
HEM. The maximum individual risk that is estimated by the SHEAR analysis of
NEDS data would be assumed to be the maximum individual risk nationally for
that particular combustion sector. The general position that NEDS contains
records for the larger boilers in the industrial and commercial sectors helps
reinforce the assumption that an analysis an NEDS boilers can approximate the
maximum emissions/exposure situation. By using SHEAR, overlapping exposures
and their resultant risks would be accommodated.
The second optional risk assessment approach is the simplest in design
and the simplest to implement. This option involves conducting a county-by-
county area risk assessment approach of the industrial and commercial
sectors, including all boiler sizes, following the same procedures used in
*
the 1984 PAB/Radian combustion source risk assessment project. The
procedures used in the 1984 study are summarized in Section 1.1. The only
modifications to the previously used approach would be to use updated
emission factors developed in the current study (see Chapter 3) and to use
state-specific wind speeds available in U. S. Department of Commerce (1979).
The county-by-county level approach would be implemented, not the grosser
state-by-state approach. Although this approach is relatively easily
performed, the applicability of its results is questionable because
industrial and commercial boilers do not typically operate in the manner of
area sources.
Radian Corporation (1984) Methodology for estimating exposure to arsenic,
beryllium, cadmium, chromium, and nickel from coal and oil combustion.
Research Triangle Park, North Carolina. EPA Contract No. 68-02-3515, Work
Assignment No. 31.
4-53
-------
A third optional risk assessment approach for the industrial and
commercial sectors, including all boiler sizes, would be to conduct a point
source risk analysis using the SHEAR model's prototype source algorithm. The
geographical areas that would be defined for the model are presumably all 50
states and the District of Columbia. Within each of these areas, the number
of industrial and commercial sources that exist would have to be
approximated. One or more model plants would have to be designed for the
industrial and commercial sectors to represent the typical emissions of the
sectors. The SHEAR model would be used to locate the specified number of
model facilities within each state. The model location procedure may be
either random (since all actual source locations are unknown) or the
facilities may be proportioned to certain areas of a state based on
population distributions and concentrations. National aggregate risk and
maximum individual risk would be obtained from the performance of the SHEAR
routines. The drawbacks to this option are: 1) it would be costly in terms
of time and money to perform a SHEAR analysis for all industrial and
commercial sources in all states, 2) a significant number of model facilities
would have to be developed to adequately characterize the broad spectrum of
boilers in these sectors, and 3) the methods of associating boiler emissions
with the properly exposed populations are not precise and large
misrepresentations of risk (positive and negative) could result.
4.3 RESIDENTIAL BOILERS AND FURNACES
Residential heating units as a category are probably the largest
emission source category in the country, numbering in the tens of millions.
The source category is also the most widely dispersed in all geographical
areas, with its occurrence being directly related to population. Because of
the number and dispersion, no source data base exists on residential sources
and a point source-by-source risk assessment approach is infeasible. More
typically, residential sources are treated as area emission sources because
of their logistics characteristics. Also, the physical characteristics of
residential sources, low stack heights and low emission velocities, tends to
initially contain emissions to the area of release and reinforce the
treatment of these sources as area sources.
4-54
-------
Because residential sources can be treated as area sources reasonably
well, it allows them to be effectively assessed using an area source risk
assessment model. Therefore, the recommended risk assessment approach for
residential sources involves modeling them as area sources in a manner very
similar to that employed in a previous EPA study (Radian Corporation, 1984).
The area source modeling approach being recommended contains the following
maj or elements.
1. Determine total trace pollutant emissions from coal and oil burning
residential sources in each State using State fuel consumption data
and the emission factors presented in Chapter 3 of this document.
2. Allocate each State's total emissions to each county within the
State based on the proportion of housing units using coal or oil as
fuel.
3. Use an area source dispersion modeling equation, county emissions
levels, county geographical areas, and mean wind speeds to project
ambient pollutant concentrations.
4. Integrate county specific pollutant concentrations with county
population data to determine exposure and risk levels. Sum to
obtain a national estimate of exposure and risk.
Each of these elements, their components, and the interactions necessary to
yield a national risk assessment for residential coal and oil burning sources
is described below.
The process of assessing national risks from residential sources would
start by calculating total emissions of each of the subject 11 trace
pollutants from each State. State-by-State (including the District of
Columbia) emissions would be determined by multiplying the appropriate
emission factors in Chapter 3 for residential sources by State coal and oil
fuel consumption information developed by the U. S. Department of Energy
(Energy Information Administration, 1984b). Table 4-15 contains the fuel
consumption data that would be used. Using this procedure, the State
emission totals given in Tables 4-16 and 4-17 would result. All emissions
from residential sources are assumed to be uncontrolled. Note that even
4-55
-------
TABLE 4-15. COAL AND OIL CONSUMPTION IN THE
RESIDENTIAL SECTOR IN 1982
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
(All Units
Bituminous and
Lignite Coal
0.9
0.0
0.0
a
a
1.1
0.0
0.1
1.2
a
0.1
0.0
0.6
2.7
5.0
1.4
0.1
3.6
a
0.3
0.9
0.7
2.2
1.2
0.0
0.7
0.1
0.2
a
a
a
0.1
3.3
1.5
1.1
6.6
0.1
a
5.6
0.0
are 1012 Btu/vr)
Anthracite
Coal
0.3
0.0
0.0
0.0
0.0
a
0.2
a
a
0.0
0.0
0.0
0.0
0.2
0.1
0.2
a
0.4
0.0
0.2
0.1
0.7
0.1
a
0.0
0.0
0.0
0.0
0.0
0.1
1.3
0.0
3.1
0.0
0.0
0.4
0.0
0.0
16.8
0.1
Distillate
Oil
0.3
6.6
0.0
0.1
0.4
0.3
71.3
5.2
3.0
4.2
0.9
0.0
1.6
15.5
24.6
12.3
1.0
3.8
0.5
28.8
35.9
105.4
36.8
36.1
0.0
6.6
2.1
2.1
0.9
18.8
112.4
0.1
184.4
28.6
5.3
26.1
a
12.3
120.6
14.4
4-56
-------
TABLE 4-15. COAL AND OIL CONSUMPTION IN THE
RESIDENTIAL SECTOR IN 1982 (Continued)
State
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
TOTAL
(All Units
Bituminous and
Lignite Coal
1.1
0.1
1.4
a
1.6
0.0
2.3
1.5
1.5
0.3
1.0
52.2
are 10 Btu/vr")
Anthracite
Coal
0.2
0.0
0.2
a
0.0
0.2
0.1
0.0
0.1
a
0.0
25.1
Distillate
Oil
6.6
5.1
2.3
0.2
0.7
8.1
29.3
18.9
5.0
44.1
0.2
1049 . 8
Represents small, non-zero value.
SOURCE: Energy Information Administration (1984b).
4-57
-------
TABLE 4-16. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - OIL COMBUSTION
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
u<
00
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
As
0.6
12.6
0.0
0.2
0.8
0.6
135.8
9.9
5.7
8.0
1.7
0.0
3.0
29.5
46.9
23.4
1.9
7.2
1.0
(1
(27
(0
(0
(1
(1
(299
(21
(12
(17
(3
(0
(6
(65
(103
(51
(4
(16
(2
.3)
.7)
.0)
.4)
.7)
.3)
.5)
.8)
.6)
.6)
.8)
.0)
.7)
.1)
.3)
.7)
.2)
.0)
.1)
0.3
7.5
0.0
0.1
0.5
0.3
80.9
5.9
3.4
4.8
1.0
0.0
1.8
17.6
27.9
14.0
1.1
4.3
0.6
Pollutants
Be
(0.8)
(16.5)
(0.0)
(0.3)
(1.0)
(0.8)
(178.3)
(13.0)
(7.5)
(10.5)
(2.3)
(0.0)
(4.0)
(38.8)
(61.5)
(30;8)
(2.5)
(9.5)
(1.3)
[units of ke (lb)/vr]a
1.4
31.4
0.0
0.5
1.9
1.4
339.6
24.8
14.3
20.0
4.3
0.0
7.6
73.8
117.2
58.6
4.8
18.1
2.4
Cd
(3.2)
(69.3)
(0.0)
(1.1)
(4.2)
(3.2)
(748.7)
(54.6)
(31.5)
(44.1)
(9.5)
(0.0)
(16.8)
(162.8)
(258.3)
(129.2)
(10.5)
(39.9)
(5.3)
Cr
6.5
142.2
0.0
2.2
8.6
6.5
1536.2
112.0
64.6
90.5
19.4
0.0
34.5
334.0
530.0
265.0
21.5
81.9
10.8
(14.3)
(313.5)
(0.0)
(4.8)
(19.0)
(14.3)
(3386.8)
(247.0)
(142.5)
(199.5)
(42.8)
(0.0)
(76.0)
(736.3)
(1168.5)
(584.3)
(47.5)
(180.5)
(23.8)
38.4
844.2
0.0
12.8
51.2
38.4
9120.4
665.2
383.7
537.2
115.1
0.0
204.7
1982.7
3146.7
1573.4
127.9
486.1
64.0
Cu
(84.6)
(1861.2)
(0.0)
(28.2)
(112.8)
(84.6)
(20106.6)
(1466.4)
(846.0)
(1184.4)
(253.8)
(0.0)
(451.2)
(4371.0)
(6937.2)
(3468.6)
(282.0)
(1071.6)
(141.0)
-------
TABLE 4-16. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - OIL COMBUSTION (Continued)
Pollutants [units of ke
State
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
*-
> Nevada
Ln
vo
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
As
54
68
200
70
68
0
12
4
4
1
35
214
0
351
54
10
49
0
23
229
27
.9
.4
.8
.1
.8
.0
.6
.0
.0
.7
.8
.1
.2
.3
.5
.1
.7
.0
.4
.8
.4
(121.0)
(150.8)
(442.7)
(154.6)
(151.6)
(0.0)
(27.7)
(8.8)
(8.8)
(3.8)
(79.0)
(472.1)
(0.4)
(774.5)
(120.1)
(22.3)
(109.6)
(0.0)
(51.7)
(506.5)
(60.5)
Be
32.7
40.7
119.5
41.7
40.9
0.0
7.5
2.4
2.4
1.0
21.3
127.5
0.1
209.1
32.4
6.0
29.6
0.0
14.0
136.8
16.3
(72.0)
(89.8)
(263.5)
(92.0)
(90.3)
(0.0)
(16.5)
(5.3)
(5.3)
(2.3)
(47.0)
(281.0)
(0.3)
(461.0)
(71.5)
(13.3)
(65.3)
(0.0)
(30.8)
(301.5)
(36.0)
137.2
171.0
502.0
175.3
171.9
0.0
31.4
10.0
10.0
4.3
89.5
535.3
0.5
878.3
136.2
25.2
124.3
0.0
58.6
574.4
68.6
Cd
(302.4)
(377.0)
(1106.7)
(386.4)
(379.1)
(0.0)
(69.3)
(22.1)
(22.1)
(9.5)
(197.4)
(1180.2)
(1.1)
(1936.2)
(300.3)
(55.7)
(274.1)
(0.0)
(129.2)
(1266.3)
(151.2)
(lb)/vrla
Cr
620.5
773.5
2271.0
792.9
778.0
0.0
142.2
45.2
45.2
19.4
405.1
2421 .8
2.2
3973.1
616.2
114.2
562.4
0.0
265.0
2598.4
310.3
(1368.0)
(1705.3)
(5006.5)
(1748.0)
(1714.8)
(0.0)
(313.5)
(99.8)
(99.8)
(42.8)
(893.0)
(5339.0)
(4.8)
(8759.0)
(1358.5)
(251.8)
(1239.8)
(0.0)
(584.3)
(5728.5)
(684.0)
Cu
3684.0
4592.2
13482.3
4707.3
4617.7
0.0
844.2
268.6
268.6
115.1
2404.8
14377.7
12.8
23587 .6
3658.3
678.0
3338.6
0.0
1573.4
15426.6
1842.0
(8121.6)
(10123.8)
(29722.8)
(10377.6)
(10180.2)
(0.0)
(1861.2)
(592.2)
(592.2)
(253.8)
(5301.6)
(31696.8)
(28.2)
(52000.8)
(8065.2)
(1494.6)
(7360.2)
(0.0)
(3468.6)
(34009.2)
(4060.8)
-------
TABLE 4-16. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - OIL COMBUSTION (Continued)
Pollutants [units of ke
State
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
As
12.6
9.7
4.4
0.4
1.3
15.4
55.8
36.0
9.5
84.0
0.4
(27.7)
(21.4)
(9.7)
(0.8)
(2.9)
(34.0)
(123.1)
(79.4)
(21.0)
(185.2)
(0.8)
Be
7.5
5.8
2.6
0.2
0.8
9.2
33.2
21.4
5.7
50.0
0.2
(16.5)
(12.8)
(5.8)
(0.5)
(1.8)
(20.3)
(73.3)
(47.3)
(12.5)
(110.3)
(0.5)
Cd
31.4
24.3
11.0
1.0
3.3
38.6
139.6
90.0
23.8
210.0
1.0
(69.3)
(53.6)
(24.2)
(2.1)
(7.4)
(85.1)
(307.7)
(198.5)
(52.5)
(463.1)
(2.1)
(lb)/vrla
Cr
142.2
HO.O
49.6
4.3
15.1
174.5
631.3
407.2
107.7
950.2
4.3
(313.5)
(242.3)
(109.3)
(9.5)
(33.3)
(384.8)
(1391.8)
(897.8)
(237.5)
(2094.8)
(9.5)
844
652
294
25
89
1036
3747
2417
639
5641
25
Cu
.2
.4
.2
.6
.5
.1
.9
.6
.6
.1
.6
(1861.2)
(1438.2)
(648.6)
(56.4)
(197.4)
(2284.2)
(8262.6)
(5329.8)
(1410.0)
(12436.2)
(56.4)
TOTAL
2000.0 (4409.2)
1190.5 (2624.5)
5000.0 (11022.9) 22619.0 49865.5
134285.4 (296043.6)
-------
TABLE 4-16. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - OIL COMBUSTION (Continued)
Pollutants [units
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Hg
0.4
9.0
0.0
0.1
0.5
0.4
97.0
7.1
4.1
5.7
1.2
0.0
2.2
21.1
33.5
16.7
1.4
5.2
0.7
(0
(19
(0
(0
(1
(0
(213
(15
(9
(12
(2
(0
(4
(46
(73
(36
(3
(11
(1
.9)
.8)
.0)
.3)
.2)
.9)
.9)
.6)
.0)
.6)
.7)
.0)
.8)
.5)
.8)
.9)
.0)
.4)
.5)
1.9
41.9
0.0
0.6
2.5
1.9
452.8
33.0
19.1
26.7
5.7
0.0
10.2
98.4
156.2
78.1
6.4
24.1
3.2
Mn
(4.2)
(92.4)
(0.0)
(1.4)
(5.6)
(4.2)
(998.2)
(72.8)
(42.0)
(58.8)
(12.6)
(0.0)
(22.4)
(217.0)
(344.4)
(172.2)
(14.0)
(53.2)
(7.0)
23.1
508.9
0.0
7.7
30.8
23.1
5498.1
401.0
231.3
323.9
69.4
0.0
123.4
1195.2
1897 .0
948.5
77.1
293.0
38.6
of kK (lb)/vrla
Hi
(51.0)
(1122.0)
(0.0)
(17.0)
(68.0)
(51.0)
(12121.0)
(884.0)
(510.0)
(714.0)
(153.0)
(0.0)
(272.0)
(2635.0)
(4182.0)
(2091.0)
(170.0)
(646.0)
(85.0)
Total POM
3.1
67.4
0.0
1.0
4.1
3.1
727.7
53.1
30.1
42.9
9.2
0.0
16.3
158.2
251.1
125.5
10.2
38.8
5.1
(6.8)
(148.5)
(0.0)
(2.3)
(9.0)
(6.8)
(1604.3)
(117.0)
(67.5)
(94.5)
(20.3)
(0.0)
(36.0)
(348.3)
(553.5)
(276.8)
(22.5)
(85.5)
(11.3)
Formaldehyde
55.1
1212.5
0.0
18.4
73.5
55.1
13098.4
955.3
551.1
771.6
165.3
0.0
293.9
2847 .5
4519.2
2259.6
183.7
698.1
91.9
(121.5)
(2673.0)
(0.0)
(40.5)
(162.0)
(121.5)
(28876.5)
(2106.0)
(1215.0)
(1701.0)
(364.5)
(0.0)
(648.0)
(6277.5)
(9963.0)
(4981.5)
(405.0)
(1539.0)
(202.5)
-------
TABLE 4-16. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - OIL COMBUSTION (Continued)
Pollutants [units of kn
State
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
a
JjJJ Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
Hg
39
.2
48.9
143
50
49
0
9
2
2
1
25
153
0
250
38
7
35
0
16
164
19
.4
.1
.1
.0
.0
.9
.9
.2
.6
.0
.1
.9
.9
.2
.2
.0
.7
.1
.6
(86.4)
(107.7)
(316.2)
(110.4)
(108.3)
(0.0)
(19.8)
(6.3)
(6.3)
(2.7)
(56.4)
(337.2)
(0.3)
(553.2)
(85.8)
(15.9)
(78.3)
(0.0)
(36.9)
(361.8)
(43.2)
182.9
228.0
669.3
233.7
229.2
0.0
41.9
13.3
13.3
5.7
119.4
713.7
0.6
1171.0
181.6
33.7
165.7
0.0
78.1
765.9
91.4
Mn
(403.2)
(502.6)
(1475.6)
(515.2)
(505.4)
(0.0)
(92.4)
(29.4)
(29.4)
(12.6)
(263.2)
(1573.6)
(1.4)
(2581.6)
(400.4)
(74.2)
(365.4)
(0.0)
(172.2)
(1688.4)
(201.6)
2220.8
2768.3
8127.6
2837.7
2783.7
0.0
508.9
161.9
161.9
69.4
1449.7
8667.4
7.7
14219.5
2205.4
408.7
2012.6
0.0
948.5
9299.7
1110.4
Hi
(4896.0)
(6103.0)
(17918.0)
(6256.0)
(6137.0)
(0.0)
(1122.0)
(357.0)
(357.0)
(153.0)
(3196.0)
(19108.0)
(17.0)
(31348.0)
(4862.0)
(901.0)
(4437.0)
(0.0)
(2091.0)
(20502.0)
(2448.0)
(lb)/vrla
Total POM
293.9
366.4
1075.7
375.6
368.4
0.0
67.4
21.4
21.4
9.2
191.9
1147.2
1.0
1882.0
291.9
54.1
266.4
0.0
125.5
1230.8
147.0
(648.0)
(807.8)
(2371.5)
(828.0)
(812.3)
(0.0)
(148.5)
(47.3)
(47.3)
(20.3)
(423.0)
(2529.0)
(2.3)
(4149.0)
(643.5)
(119.3)
(587.3)
(0.0)
(276.8)
(2713.5)
(324.0)
Formaldehyde
5290.8
6595.1
19362.8
6760.5
6631.9
0.0
1212.5
385.8
385.8
165.3
3543.7
20648.8
18.4
33875.8
5254.0
973.7
4794.8
0.0
2259.6
22155.2
2645 .4
(11664.0)
(14539.5)
(42687.0)
(14904.0)
(14620.5)
(0.0)
(2673.0)
(850.5)
(850.5)
(364.5)
(7614.0)
(45522.0)
(40.5)
(74682.0)
(11583.0)
(2146.5)
(10570.5)
(0.0)
(4981.5)
(48843.0)
(5832.0)
-------
TABLE 4-16. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - OIL COMBUSTION (Continued)
Pollutants [units of ke
State
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
TOTAL
Hg
9.0
6.9
3.1
0.3
1.0
11.0
39.9
25.7
6.8
60.0
0.3
1428.6
(19.8)
(15.3)
(6.9)
(0.6)
(2.1)
(24.3)
(87.9)
(56.7)
(15.0)
(132.3)
(0.6)
(3149.4)
41.9
32.4
14.6
1.3
4.4
51.4
186.1
120.0
31.8
280.1
1.3
6666.6
Hn
(92
(71
(32
(2
(9
(113
(410
(264
(70
(617
(2
(14697
Hi
.4)
.4)
;2)
.8)
.8)
.4)
.2)
.6)
.0)
.4)
.8)
.2)
508.9
. 393 .3
177.4
15.4
54.0
624.6
2259.4
1457 .4
385.6
3400.6
15.4
80952.2
(1122.0)
(867.0)
(391.0)
(34.0)
(119.0)
(1377.0)
(4981.0)
(3213.0)
(850.0)
(7497.0)
(34.0)
(178466.0)
(lb)/vrla
Total POM
67.4
52.1
23.5
2.0
7.1
82.7
299.0
192.9
51.0
450.1
2.0
10714.3
(148.5)
(114.8)
(51.8)
(4.5)
(15.8)
(182.3)
(659.3)
(425.3)
(112.5)
(992.3)
(4.5)
(23620.5)
Formaldehyde
1212.5
936.9
422.5
36.7
128.6
1488.0
5382.6
3472.1
918.5
8101.5
36.7
192856.7
(2673.0)
(2065.5)
(931.5)
(81.0)
(283.5)
(3280.5)
(11866.5)
(7654.5)
(2025.0)
(17860.5)
(81.0)
(425169.0)
Bniesion totals for lead were not able to be included due to time constraints.
-------
TABLE 4-17. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - COAL COMBUSTION
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
f Florida
er>
r>
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
649.5
0.0
0.0
0.0
0.0
160.0
41.1
65.3
783.8
0.0
65.3
0.0
142.9
1412.8
2560.7
752.3
50.8
2433.7
0.0
As
(1431
(0
(0
(0
(0
(352
(90
(144
(1728
(0
(144
(0
(315
(3114
(5645
(1658
(112
(5365
(0
.9)
.0)
.0)
.0)
.0)
.8)
.6)
.0)
.0)
.0)
.0)
.0)
.0)
.6)
.3)
.6)
.0)
.2)
.0)
9.4
0.0
0.0
0.0
0.0
7.6
0.9
0.9
10.6
0.0
0.9
0.0
4.1
26.5
47.8
14.2
1.0
33.7
0.0
Pollutants
Be
(20.7)
(0.0)
(0.0)
(0.0)
(0.0)
(16.7)
(2.1)
(2.0)
(23.4)
(0.0)
(2.0)
(0.0)
(9.1)
(58.5)
(105.5)
(31.3)
(2.1)
(74.4)
(0.0)
[units
5.2
0.0
0.0
0.0
0.0
14.5
1.2
0.4
4.6
0.0
0.4
0.0
7.9
460.5
851.1
239.3
17.0
16.1
0.0
of kŤ (lb)/vrla
Cd
(11.5)
(0.0)
(0.0)
(0.0)
(0.0)
(31.9)
(2.6)
(0.8)
(10.1)
(0.0)
(0.8)
(0.0)
(17.4)
(1015.1)
(1876.3)
(527.6)
(37.5)
(35.4)
(0.0)
114.7
0.0
0.0
0.0
0.0
108.8
33.8
7.1
85.5
0.0
7.1
0.0
59.3
337.5
579.3
191.2
11.3
323.9
0.0
Cr
(252.9)
(0.0)
(0.0)
(0.0)
(0.0)
(239.8)
(74.4)
(15.7)
(188.4)
(0.0)
(15.7)
(0.0)
(130.8)
(744.0)
(1277.2)
(421.6)
(24.8)
(714.0)
(0.0)
Cu
81.7
0.0
0.0
0.0
0.0
76.3
11.7
7.1
85.5
0.0
7.1
0.0
41.6
207.7
368.7
113.3
7.3
279.8
0.0
(180.0)
(0.0)
(0.0)
(0.0)
(0.0)
(168.3)
(25.8)
(15.7)
(188.4)
(0.0)
(15.7)
(0.0)
(91.8)
(457.8)
(812.9)
(249.8)
(16.0)
(616.8)
(0.0)
-------
TABLE 4-17. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - COAL COMBUSTION (Continued)
Pollutants [units of kŤ
State
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
As
237.1
608.4
601.1
1138.2
609.6
0.0
355.6
23.8
47.6
0.0
20.6
267.1
17.8
2792.5
979.8
262.0
3435.2
50.8
0.0
7109.9
20.6
(522
(1341
(1325
(2509
(1344
(0
(784
(52
(105
(0
(45
(588
(39
(6156
(2160
(577
(7573
(112
(0
(15674
(45
.6)
.3)
.1)
.3)
.0)
.0)
.0)
.5)
.0)
.0)
.3)
.9)
.2)
.3)
.0)
.5)
.2)
.0)
.0)
.4)
.3)
Be
3.6
8.4
9.5
21.3
11.4
0.0
6.6
0.7
1.2
0.0
0.5
6.1
0.7
43.8
13.3
6.8
64.5
1.0
0.0
128.8
0.5
(7.9)
(18.6)
(20.9)
(47.0)
(25.1)
(0.0)
(14.6)
(1.5)
(2.7)
(0.0)
(1.0)
(13.5)
(1.5)
(96.6)
(29.3)
(15.0)
(142.1)
(2.1)
(0.0)
(283.9)
(1.0)
2.3
4.0
6.8
374.8
204.1
0.0
119.1
1.1
2.3
0.0
0.6
7.7
1.3
30.9
5.7
12.4
1125.0
17.0
0.0
120.4
0.6
Cd
(5.1)
(8.9)
(15.0)
(826.3)
(450.0)
(0.0)
(262.5
(2.5)
(5.0)
(0.0)
(1.30)
(16.9)
(2.9)
(68.0)
(12.6)
(27.4)
(2480.2)
(37.5)
(0.0)
(265.4)
(1.3)
(lb)/vrla
55.1
81.0
168.0
264.4
135.0
0.0
78.7
3.8
7.6
0.0
16.9
219.4
9.9
758.1
106.8
41.6
810.0
11.3
0.0
3233.6
16.9
Cr
(121.50)
(178.5)
(370.3)
(582.8)
(297.6)
(0.0)
(173.6)
(8.3)
(16.7)
(0.0)
(37.2)
(483.6)
(21.8)
(1671.3)
(235.5)
(91.6)
(1785.6)
(24.8)
(0.0)
(7128.8)
(37.2)
33.1
70.0
90.8
165.5
87.1
0.0
50.8
4.9
9.9
0.0
5.9
76.1
6.9
416.4
106.8
54.4
502.4
7.3
0.0
1381.9
5.9
Cu
(72.9)
(154.2)
(200.2)
(364.9)
(192.0)
(0.0)
(112.0)
(10.9)
(21.8)
(0.0)
(12.9)
(167.7)
(15.3)
(918.0)
(235.5)
(119.9)
(1107.6)
(16.0)
(0.0)
(3046.4)
(12.9)
-------
TABLE 4-17. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - COAL COMBUSTION (Continued)
Pollutants [units of kg
State
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
As
759
23
955
0
284
41
1522
266
1000
152
177
.6
.8
.6
.0
.5
.1
.8
.7
.3
.4
.8
(1674.6)
(52.5)
(2106.6)
(0.0)
(627.2)
(90.6)
(3357.3)
(588.0)
(2205.3)
(336.0)
(392.0)
Be
10.7
0.6
13.3
0.0
11 .0
0.9
20.8
10.3
13.7
2.8
6.9
(23.5)
(1.4)
(29.4)
(0.0)
(24.3)
(2.1)
(45.9)
(22.8)
(30.3)
(6.3)
(15.2)
5.4
1.1
6.5
0.0
21.2
1.2
9.4
19.7
6.3
51.0
13.2
Cd
(11.8)
(2.5)
(14.4)
(0.0)
(46.4)
(2.6)
(20.6)
(43.5)
(13.9)
(112.5)
(29.0)
(lb)/vrla
Cr
112.1
3.8
133.5
0.0
158.2
33.8
180.7
148.3
123.7
33.8
98.9
(247.1)
(8.3)
(294.2)
(0.0)
(348.8)
(74.4)
(398.3)
(327.0)
(272.7)
(74.4)
(218.0)
Cu
90.0
4.9
111.4
0.0
111.0
11.7
169.7
104.1
112.7
21.8
69.4
(198.5)
(10.9)
(245.6)
(0.0)
(244.8)
(25.8)
(374.0)
(229.5)
(248.4)
(48.0)
(153.0)
TOTAL
32880.6 (72488.0)
57?.6 (1273.3)
3788.9 (8353.1)
8903.8 (19629.3)
5170.4 (11398.6)
-------
TABLE 4-17. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - COAL COMBUSTION (Continued)
0\
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Hg
8.2
0.0
0.0
0.0
0.0
10.4
1.1
0.7
8.7
0.0
0.7
0.0
5.7
14.0
24.4
7.8
0.5
28.3
0.0
(18
(0
(0
(0
(0
(22
(2
(1
(19
(0
(1
(0
(12
(30
(53
(17
(1
(62
(0
.1)
.0)
.0)
.0)
.0)
.9)
.4)
.6)
.2)
.0)
.6)
.0)
.5)
.8)
.7)
.1)
.1)
.5)
.0)
458.6
0.0
0.0
0.0
0.0
1097 .7
71.7
39.0
468.1
0.0
39.0
0.0
598.8
1186.2
2099.7
649.6
41.3
1547 .7
0.0
Pollutants
Mn
(1011.0)
(0.0)
(0.0)
(0.0)
(0.0)
(2420.0)
(158.0)
(86.0)
(1032.0)
(0.0)
(86.0)
(0.0)
(1320.0)
(2615.0)
(4629.0)
(1432.0)
(91.0)
(3412.0)
(0.0)
[units
84.8
0.0
0.0
0.0
0.0
45.2
20.3
6.0
72.4
0.0
6.0
0.0
24.7
319.2
563.6
175.3
11.1
257.8
0.0
of kg (lb)/vrla
Hi
(186.9)
(0.0)
(0.0)
(0.0)
(0.0)
(99.7)
(44.8)
(13.3)
(159.6)
(0.0)
(13.3)
(0.0)
(54.4)
(703.6)
(1242.4)
(386.4)
(24.4)
(568.4)
(0.0)
POM
1992.2
0.0
0.0
0.0
0.0
1826.2
332.0
166.0
1992.2
0.0
166.0
0.0
996.1
4814.5
8466.9
2656.3
166.0
6640.7
0.0
(4392.0)
(0.0)
(0.0)
(0.0)
(0.0)
(4026.0)
(732.0)
(366.0)
(4392.0)
(0.0)
(366.0)
(0.0)
(2196.0)
(10614.0)
(18666.0)
(5856.0)
(366.0)
(14640.0)
(0.0)
Formaldehyde
242.8
0.0
0.0
0.0
0.0
222.5
40.5
20.2
242.8
0.0
20.2
0.0
121.4
586.7
1031.8
323.7
20.2
809.2
0.0
(535.2)
(0.0)
(0.0)
(0.0)
(0.0)
(490.6)
(89.2)
(44.6)
(535.2)
(0.0)
(44.6)
(0.0)
(267.6)
(1293.4)
(2274.6)
(713.6)
(44.6)
(1784.0)
(0.0)
-------
TABLE 4-17. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - COAL COMBUSTION (Continued)
Pollutants [unite of ka
State
Maine
Mary land
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
*- Nebraska
Oi
oo Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
Hg
3.3
7.1
9.0
11.0
5.7
0.0
3.3
0.8
1.9
0.0
0.6
7.2
0.9
41.1
10.9
9.0
33.7
0.5
0.0
133.6
0.6
(7.2)
(15.6)
(19.7)
(24.3)
(12.6)
(0.0)
(7.4)
(1.8)
(4.2)
(0.0)
(1.2)
(15.9)
(2.1)
(90.6)
(24.0)
(19.9)
(74.2)
(1.1)
(0.0)
(294.6)
(1.2)
188.7
386.9
523.9
943.9
495.3
0.0
288.9
49.9
99.8
0.0
35.8
465.9
99.8
2398.2
585.1
548.9
2867.7
41.3
0.0
8204.7
35.8
Mn
(416.0)
(853.0)
(1155.0)
(2081 .0)
(1092.0)
(0.0)
(637.0)
(110.0)
(220.0)
(0.0)
(79.0)
(1027.0)
(220.0)
(5287.0)
(1290.0)
(1210.0)
(6322.0)
(91.0)
(0.0)
(18088.0)
(79.0)
38.4
64.5
113.4
253.7
132.8
0.0
77.5
4.9
9.7
0.0
10.2
132.1
4.1
514.1
90.5
53.4
771.1
11.1
0.0
2044.8
10.2
Hi
(84.7)
(142.1)
(249.9)
(559.2)
(292.8)
(0.0)
(170.8)
(10.7)
(21.4)
(0.0)
(22.4)
(291.2)
(9.1)
(1133.3)
(199.5)
(117.7)
(1700.0)
(24.4)
(0.0)
(4508.0)
(22.4)
(lb)/vrla
830
1660
2324
3818
1992
0
1162
166
332
0
166
2158
166
10625
2490
1826
11621
166
0
37187
166
.1
.2
.3
.4
.2
.0
.1
.0
.0
.0
.0
.2
.0
.1
.3
.2
.2
.0
.0
.9
.0
POM
(1830.0)
(3660.0)
(5124.0)
(8418.0)
(4392.0)
(0.0)
(2562.0)
(366.0)
(732.0)
(0.0)
(366.0)
(4758.0)
(366.0)
(23424.0)
(5490.0)
(4026.0)
(25620.0)
(366.0)
(0.0)
(81984.0)
(366.0)
Formaldehyde
101.2
202.3
283.2
465.3
242.8
0.0
141.6
20.2
40.5
0.0
20.2
263.0
20.2
1294.8
303.5
222.5
1416.1
20.2
0.0
4531.7
20.2
(223.0)
(446.0)
(624.4)
(1025.8)
(535.2)
(0.0)
(312.2)
(44.6)
(89.2)
(0.0)
(44.6)
(579.8)
(44.6)
(2854.0)
(669.0)
(490.6)
(3122.0)
(44.6)
(0.0)
(9990.4)
(44.6)
-------
VO
TABLE 4-17. STATE TRACE POLLUTANT EMISSION TOTALS TO BE USED
FOR RISK ASSESSMENT - COAL COMBUSTION (Continued)
Pollutants [units of kg (lb)/vrla
State
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
TOTAL
Hg
9
0
11
0
15
1
17
14
11
1
9
481
.1
.8
.3
.0
.1
.1
.3
.2
.4
.4
.4
.6
(20.0)
(1.8)
(24.8)
(0.0)
(33.3)
(2.4)
(38.0)
(31.2)
(25.2)
(3.2)
(20.8)
(1061.8)
500.8
49.9
617.8
0.0
1596.7
71.7
933.1
1496.9
621.0
123.8
997.9
33567.3
Hn
(1104.0)
(110.0)
(1362.0)
(0.0)
(3520.0)
(158.0)
(2057.0)
(3300.0)
(1369.0)
(273.0)
(2200.0)
(74002.0)
86.7
4.9
104.8
0.0
65.8
20.3
148.9
61.6
100.7
33.2
41.1
6590.4
Ni
(191.1)
(10.7)
(231.0)
(0.0)
(145.0)
(44.8)
(328.3)
(135.9)
(221.9)
(73.2)
(90.6)
(14529.1)
POM
2158.2
166.0
2656.3
0.0
2656.3
332.0
3984.4
2490.3
2656.3
498.1
1660.2
128331.6
(4758.0)
(366.0)
(5856.0)
(0.0)
(5856.0)
(732.0)
(8784.0)
(5490.0)
(5856.0)
(1098.0)
(3660.0)
(282918.0)
Formaldehyde
263.0
20.2
323.7
0.0
323.7
40.5
485.5
303.5
323.7
60.7
202.3
15638.2
(579.8)
(44.6)
(713.6)
(0.0)
(713.6)
(89.2)
(1070.4)
(669.0)
(713.6)
(133.8)
(446.0)
(34475.8)
Emission totals for lead-were not able to be included due to time constraints.
-------
though emission totals are presented for copper, manganese, and mercury, risk
assessments would not be performed for these pollutants because no unit risk
factors are available.
The next element in the residential source risk assessment process would
involve allocating the Statewide emissions totals (Tables 4-16 and 4-17) to
counties within each State. Information contained in the Census Bureau's
Census of Housing data base would be used to perform the allocations.
Emissions for a State would be distributed on the basis of the number of
homes in each county that used coal or oil as a fuel. For example, if a
State had 1000 homes using coal as a fuel and county A has 68 homes using
coal, county A would be allocated 6.8 percent of that State's total emissions
from coal combustion. This allocation procedure can be performed by computer
as EPA did in its prior residential risk assessment study (Radian
Corporation, 1984).
Once emissions are allocated by county within each State, ambient
pollutant concentrations can be estimated and population exposure levels
determined. It is recommended that ambient concentrations be estimated using
the Area Source Module (ASM) of EPA's SHEAR model (Anderson and Lundberg,
1983). The ASM uses the relatively simple Hanna-Gifford dispersion equation
(shown below) to calculate ambient pollutant concentrations.
x - coyu
X - ambi
C - Hanna-Gifford coefficient
Q - effective emissi
U - wind speed (m/s)
Where: X - ambient concentration (ug/m )
2
Q - effective emission rate per unit area (ug/sec/m )
For the purpose of calculating exposure C has been determined by EPA to be
equal to 225. The coefficient C is a weak function of atmospheric stability
and land area and may be taken to be approximately constant (Andersen and
Lundberg, 1983) . The mean wind speed that would be used in the equation is
4.2 m/s (9.3 mph), which represents the mean national wind speed (U. S.
Department of Commerce, 1979). The quantity Q presents county emissions
2 o
(Ib/yr) divided by county land area (mi ) to give units of Ib/yr/mi . The
4-70
-------
2 2
units of Ib/yr/mi can be converted to ug/sec/m using the conversion factor
of 5.52 x 10 . By executing the Hanna-Gifford equation for all counties,
ambient pollutant concentrations in terms of ug/m can be obtained. All
calculations involving the Hanna-Gifford equation are best handled by using a
computerized data management program such as LOTUS 1-2-3*^ or an equivalent.
To determine exposure and risk in each county, the county populations
and EPA unit risk factors are used in conjunction with the ambient
3
concentrations (ug/m ) projected by the Hanna-Gifford equation. County
populations would be obtained from census data files. Exposure is expressed
as follows:
Ambient concentration (ug/m ) x people in the county.
3
The units of exposure would be people - ug/m . Aggregate risk, or risk
after an assumed 70 years of continuous exposure, is calculated by
multiplying exposure times the appropriate unit risk factor. The annual
incidence of cancer is determined by dividing the aggregate risk by 70. If
this exercise is repeated for all counties in a State and the incidences
summed, a risk level for the State can be obtained. Summing all the State
values would yield the national risk to the population from residential coal
and oil burning sources' trace pollutant emissions. Because of the volume of
data involved (roughly 3,000 counties in the U. S. and 7 pollutants of
concern for both coal and oil), the analysis would need to be computerized in
order to avoid a lengthy manual calculation procedure.
4-71
-------
APPENDIX A
CONTACTS FOR IDENTIFICATION OF PERTINENT RESEARCH
The following table is a list of the individuals and organizations
contacted in order to identify pertinent research. The individuals are
listed by organization in the same order that the activities of these
organizations are described in Chapter 2.
TABLE A-l. INDIVIDUALS CONTACTED DURING
IDENTIFICATION OF PERTINENT RESEARCH TASK
Name
Telephone Number
Organization
Bill Thomas
Kevin Johnson
Ed Aul
Mike Dusetzina
Warren Peters
Chuck Mann
Ron Myers
Joe McSorley
Gary Johnson
Bob Hall
David Mobley
Bill Plyler
Julian Jones
Gene Durman
Gerald Anderson
Paul Duhamel
Harold Beck
Ralph Scott
John Moens
Dan Malhoney
(512) 454-4797
(919) 541-9100
(919) 541-5645
(919) 541-5694
(919) 541-5601
(919) 541
(919) 541
(919) 541
(919) 541
(919) 541
(919) 541
2920
7612
2477
2612
2918
2489
(202) 382-2753
(415) 472-4011
(301) 353-3251
(212) 620-3632
(304) 291-4094
(202) 252-1176
(304) 291-4314
Radian Corporation
Radian Corporation
Pollutant Assessment Branch,
OAQPS, EPA
National Air Data Branch,
OAQPS, EPA
Emissions Standards and
Engineering Division,
OAQPS, EPA
Air and Energy Engineering
Research Laboratory, ORD, EPA
Office of Policy, Planning,
and Evaluation, EPA
Systems Applications, Inc.
Department of Energy
A-l
-------
TABLE A-l. INDIVIDUALS CONTACTED DURING
IDENTIFICATION OF PERTINENT RESEARCH TASK (Continued)
Name
Telephone Number
Organization
Jerry Hollinden
H. B. Flora
Joe Johnson
Ken Chen
Thomas Reevey
Jim Hardin
Barry Park
Philip Bauman
William Brownell
Ralph Roberson
Chris Bergesen
Liz Hannen
Sue Farrell
Angela Waldorf
Alby Modiano
Walter Retvsch
Ed Crockett
Russ Mosher
Bill Marx
Engineering Societies
Library
Walter Weyzen
John Cuertin
Paolo Ricci
Mark Saperstein
Rick Richardson
(615) 751-3584
(615) 751-0011
(615) 751-5678
(615) 751=5645
(202) 557-8927
(202) 557-8977
(202) 557-8977
(214) 979-4821
(202) 955-1500
(919) 781-3150
(202) 466-3660
(202) 828-7622
(919) 828-5439
(202) 682-8228
(202) 682-8153
(202) 882-8318
(703) 522-7350
(203) 250-9042
(212)705-7610
(415) 855-2175
(415) 855-2018
(415) 855-2627
(818) 302-2218
(818) 302-2052
Tennessee Valley Authority
Office of Radiation Programs,
EPA
Utility Air Regulatory Group
Hunton and Williams law firm
representing UARG
Kilkelly Environmental
Associates
Utility Data Institute
Edison Electric Institute
American Petroleum Institute
American Boiler Manufacturers
Association
Council of Industrial Boiler
Owners
American Society of Mechanical
Engineers
Electric Power Research
Institute
Southern California Edison Co.
A-2
-------
TABLE A-l. INDIVIDUALS CONTACTED DURING
IDENTIFICATION OF PERTINENT RESEARCH TASK (Continued)
Name
Telephone Number
Organization
E. A. Kingsley
Carlos Guerra
Peter Coffey
Robert Pearson
Harry Williams
Ken Hutchinson
(514) 937-6181
(201) 430-6642
(518) 381-2124
(301) 571-7580
(313) 897-1301
Canadian Electrical
Association
PSE&G Research Corp.
Empire State Electric Energy
Research Corp.
Public Service Co. of
Colorado
Detroit Edison Co.
A-3
-------
APPENDIX B
DATA BASE DEVELOPMENT
The trace pollutant emissions and risk assessment methodology data base
for this project was developed through manual and computerized literature
searching and through telephone contacts with individuals knowledgeable in
the areas of combustion sources, trace emissions from combustion, and risk
assessment strategies. The methodology and results of the telephone survey
are described in detail in Chapter 2.0.
The literature search effort consisted of searching the Radian library
and relevant company project files for combustion source trace emissions
data that either were developed by the company or were obtained through
projects related to this topic, and searching computerized data bases of the
Ž
Dialog^ information system. The in-house search proved successful in that
approximately 100 documents were identified as potentially being useful to
the objectives of the project. These were obtained and evaluated.
The Dialog^ search consisted of searching nine data bases that were
identified as having the highest probability of containing information
relating to combustion source trace emissions and risk assessment
methodologies. These data bases, the dates back to which each was searched,
and any exclusions/restrictions applied to a data base search are summarized
in Table B-l.
The computerized search of these nine data bases identified
1,808 citations that potentially could be useful to the objectives of the
project. Abstracts of these 1,808 citations were evaluated and a list of
506 citations were specified from this review that appeared to warrant a
full review to extract their trace emissions and risk assessment methodology
data. During the review of the abstracts approximately 240 references were
discounted on the basis of being of only marginally applicable or of
B-l
-------
TABLE B-l. DATA BASES SEARCHED IN THE DIALOG4* SYSTEM
DATA BASE
Chemical Abstracts (CA) Search
NTIS
Compendex
DOE Energy
Electric Power Database
Pollution Abstracts
Environmental Bibliography
Enviroline
Federal Research in Progress
DATES SEARCHED13
1972 -
1964 -
1970 -
1974 -
1972 -
1970 -
1974 -
1970 -
Current
1985
1985
1985
1985
1985
1985
1985
1985
RESTRICTIONS
a
a
a
a
a
a
a
a
a
limited to references available in English; all patent literature was
excluded.
The search strategy performed in all data bases for risk assessment
literature was limited to the period 1980 - 1985.
B-2
-------
containing data that applies to foreign sources. References containing
emissions data on combustion sources located outside the United States were
not specified by EPA to be obtained; however, references thought to contain
information on useful risk assessment methodologies were obtained regardless
of origin. Another 105 were discarded on the basis that they were exact
duplicates with a reference previously identified or they were duplicates of
work that had been published or presented in another source.
In total, 161 references were obtained from the computerized literature
search and evaluated for this study. These references, along with the
others that were originally identified as potentially useful but were not
obtained for the reasons previously given, are listed in the project
bibliography in Appendix C.
The final source of data for the project was the Emissions Assessment
Data System (EADS) which is maintained by the Air and Energy Engineering
Research Laboratory (AEERL) of the U. S. EPA at Research Triangle Park,
North Carolina. The EADS contained computerized summaries of 197 reports of
tested trace metal emissions from combustion sources. Upon a review of the
summaries, most of the test reports were found to be duplicates of
references previously identified and analyzed or were not directly
applicable for reasons of being concerned with wood or organic waste fuels
and unapplicable sources such as internal combustion engines.
B-3
-------
APPENDIX C
BIBLIOGRAPHY
Abbott, D. T.; Styron, C. E.; Casella, V. R. (1983) Radionuclides in
western coal. Miamisburg, OH: U. S. Department of Energy, Mound Laboratory;
DOE report no. MLM-3026.
Ackerman, D. G.; Haro, M. T.; Richard, G.; Takata, A. M.; Weller, P. J.;
Bean, D. J.; Cornaby, B. W.; Mihlan, G. J.; Rogers, S. E. (1980) Health
impacts, emissions, and emission factors for noncriteria pollutants subject
to de minimis guidelines and emitted from stationary conventional combustion
processes. Research Triangle Park, NC: U. S. Environmental Protection
Agency, Office of Air Quality Planning and Standards; EPA report no.
EPA-450/2-80-074.
Agreda, V. H.; Felder, R. M.; Ferrell, J. K. (1979) Devolatilization
kinetics and elemental release in the pyrolysis of pulverized coal. Research
Triangle Park, NC: U. S. Environmental Protection Agency, Industrial
Environmental Research Laboratory; EPA report no. EPA-600/7-79-241.
Ajax, R. L.; Cuffe, S. T. (1985) Information memorandum to J. R. Farmer,
Director, ESED. Research Triangle Park, NC: U. S. Environmental Protection
Agency. September 30, 1985.
Allen, J. M.; Levy. A.; Jones, W.; Freudenthal, I. (1978) Polycyclic
organic materials and the electric power industry. Palo Alto, CA: Electric
Power Research Institute; EPRI report no. EA/787-SY.
Alvin, M. A.; O'Neill, E. P.; Yannopoulis, L. N.; Keairns, D. L. (1978)
Evaluation of trace element release from fluidized-bed combustion systems.
Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-78-050.
American Boiler Manufacturers Association. (1981) Emissions and efficiency
performance of industrial coal stoker fired boilers. Washington, DC: U. S.
Department of Energy, Office of Coal Utilization and Extraction; DOE report
no. DOE/ET/10386-T1 (Vol. 2).
Anderson, D. (1973) Emission factors for trace substances. Research
Triangle Park, NC: U. S. Environmental Protection Agency, Office of Air
Quality Planning and Standards; EPA report no. 450/2-73-001.
Anderson, G. E.; Lundberg, G. W. (1983) Users manual for SHEAR. Research
Triangle Park, NC: U. S. Environmental Protection Agency, Office of Air
Quality Planning and Standards; EPA contract no. 68-02-3066.
C-l
-------
Anderson, G. E.; Moore, G. E.; Moezzi, M. (1985) Cost benefit analysis of
reducing trace hazardous pollutants from coal-fired boilers in Ohio. EPA
contract no. 68-01-7033. Washington, DC: U. S. Environmental Protection
Agency, Office of Policy Analysis.
Anonymous. (1985) Risk assessment: air emissions from coal-fired power
plants. EPRI J. 10: 53-55.
Babcock and Wilcox (1978) Steam, its generation and use. Babcock and
Wilcox Company. New York, NY.
Babu, P., ed. (1975) Trace elements in fuel: a symposium sponsored by the
Division of Fuel Chemistry at the 166th national meeting of the American
Chemical Society; August 1973; Chicago, IL. Washington, DC: American
Chemical Society; Adv. Chem. Ser. no. 141.
Baes, C. F.; Sharp, R. D. (1981) A directory of parameters used in a series
of assessment applications of the AIRDOS-EPA and DARTAB computer codes.
Oak Ridge, TN: U. S. Department of Energy, Oak Ridge National Laboratory;
ORNL report no. ORNL-5710.
Baes, C. F.; Miller, C. W. (1983) CRRIS: a methodology for assessing the
impact of airborne radionuclide releases. Summary of a presentation for the
American Nuclear Society annual meeting, June 12, 1983, Detroit, MI.
Oak Ridge, TN: Oak Ridge National Laboratory.
Baig, S.; Haro, M.; Richard, G.; Sarro, T.; Wolf, S.; Hurley, T.;
Morrison, D.; Parks, R. (1981) Conventional combustion environmental
assessment. Draft report; EPA contract no. 68-02-3138. Research Triangle
Park, NC: U. S. Environmental Protection Agency, Industrial Environmental
Research Laboratory.
Baria, D. N. (1975) A survey of trace elements in North Dakota lignite and
effluent streams from combustion and gasification facilities. Grand Forks,
ND: University of North Dakota, Engineering Experiment Station.
Barrett, R. E.; Miller, S. E.; Lockin, D. W. (1973) Field investigation of
emissions from combustion equipment for space heating. Research Triangle
Park, NC: U. S. Environmental Protection Agency, Control Systems Laboratory;
EPA report no. EPA-R2-73-084a; API publication 4180.
Barrett, W. J.; Gooch, J. P.; Dahlin, R. S.; Riggin, R. M.; Carver, J. H.;
Dennis, A. H.; Fisher, G. L. ; Howes, J. E.; Mays, D. C.; Miller, S. E.;
Roth, H. D.; Pechan, E. H. (1983) Planning studies for measurement of
chemical emissions in stack gases of coal-fired power plants. Palo Alto, CA:
Electric Power Research Institute; EPRI report no. EA-2892.
Beck, H. L.; Miller, K. M. (1980) Some radiological aspects of coal
combustion. IEEE Trans. Nucl. Sci. NS-27: 689-694.
C-2
-------
Beck, H. L.; Gogolak, C. V.; Miller, K. M.; Lowder, W. M. (1980)
Perturbations on the natural radiation environment due to the utilization of
coal as an energy source. In: Gesell, T. F.; Lowder, W. M., eds. Natural
radiation environment III: conference; April 1978; Houston, TX. Oak Ridge,
TN: U. S. Department of Energy, Technical Information Center; DOE report no.
CONF-780422 (Vol. 2); pp. 1521-1558.
Bennett, R. L.; Knapp, K. T. (1976) Chemical characterization of
particulate emissions from oil-fired power plants. In: Theodore, L.;
Rolinski, E. J.; McCarthy, W. N., Jr.; Buonicore, A. J.; Barley, D. E.;
Servais, R. A., eds. Energy and the environment; proceedings of the fourth
national conference; October; Dayton, OH. Dayton, OH: American Institute of
Chemical Engineers, Dayton Section; pp. 501-506.
Bennett, R. L.; Knapp, K. T. (1979) Particulate sulfur and trace metal
emissions from oil fired power plants. In: Licht, W.; Engel, J.; Slater,
M., eds. Control of emissions from stationary combustion sources: pollutant
detection and behavior in the atmosphere. New York, NY: Amercian Institute
of Chemical Engineers; AIChE Symp. Ser. no. 188; pp. 174-180.
Billings, C. E.; Matson, W. R. (1972) Mercury emissions from coal
combustion. Science 176(4040): 1232-1233.
Billings, C. E.; Sacco, A. M.; Matson, W. R.; Griffin, R. M.; Coniglio,
W. R.; Harley, R. A. (1973) Mercury balance on a large pulverized
coal-fired furnace. J. Air Pollut. Control Assoc. 23: 773-777.
Bowen, J. S.; Hall, R. E. (1976) Proceedings of the stationary source
combustion symposium; Volume 3: Field testing and surveys; June 1975;
Atlanta, GA. Research Triangle Park, NC: U. S. Environmental Protection
Agency, Industrial Environmental Research Laboratory; EPA report no.
600/2-76-152c.
Boyer, J. F.; Costantino, J. P.; Ford, C. T.; Gleason, V. E.; Rosnick, K. A.
(1981) Evaluation of the effect of coal cleaning on fugitive elements.
U. S. Department of Energy; DOE report no. DOE/EV/04427-53.
Braunstein, H. M.; Copenhaver, E. D.; Pfuderer, H. A. eds. (1977)
Environmental, health, and control aspects of coal conversion: an
information overview; Vol. I. Oak Ridge, TN: U. S. Department of Energy,
Oak Ridge National Laboratory; ORNL report no. ORNL/EIS-94.
Burlingame, J. 0.; Gabrielson, J. E.; Langsjoen, P. L.; Cooke, W. M. (1981)
Field tests of industrial coal stoker fired boilers for inorganic trace
element and polynuclear aromatic hydrocarbon emissions. Research Triangle
Park, NC: U. S. Environmental Protection Agency, Industrial Environmental
Research Laboratory; EPA report no. EPA-600/7-81-167.
Campbell, J. A.; Laul, J. C.; Nielson, K. K.; Smith, R. D. (1978)
Separation and chemical characterization of finely-sized fly-ash particles.
Anal. Chem. 50: 1032-1040.
C-3
-------
Carter, W. A.; Buening, H. J.; Hunter, S. C. (1978) Emission reduction on
two industrial boilers with major combustion modifications. Research
Triangle Park, NC: U. S. Environmental Protection Agency. Industrial
Environmental Research Laboratory; EPA report no. EPA-600/7-78-099a.
Castaldini, C. (1982) Environmental assessment of a low-emission oil-fired
residential hot water condensing heating system; Vol. I: Technical results.
Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-82-038a.
Castaldini, C.; Brown, R. A.; Lim, K. J. (1981a) Combustion modification
controls for residential and commercial heating systems; Vol. I:
Environmental assessment. Research Triangle Park, NC: U. S. Environmental
Protection Agency, Industrial Environmental Research Laboratory; EPA report
no. EPA-600/7-81-123a.
Castaldini, C.; Brown, R. A.; Lim, K. J. (1981b) Combustion modification
controls for residential and commercial heating systems; Vol. II: Oil-fired
residential furnace field test. Research Triangle Park, NC: U. S.
Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/7-81-123b.
Castaldini, C.; Waterland, L. R.; Mason, H. B. (1982) Emissions and
performance of a low-NO residential hot water condensing heating system
burning distillate oil. Presented at: 75th annual meeting of the Air
Pollution Control Association; June; New Orleans, LA. Pittsburgh, PA: Air
Pollution Control Association; paper no. 82-19.4.
Cato, G. A. (1976) Field testing: trace element and organic emissions from
industrial boilers. Research Triangle Park, NC: U. S. Environmental
Protection Agency, Industrial Environmental Research Laboratory; EPA report
no. EPA-600/2-76-086b.
Cato, G. A.; Venezia, R. A. (1976) Trace element and organic emissions from
industrial boilers. Presented at: 69th annual meeting of the Air Pollution
Control Association; June; Portland, OR. Pittsburgh, PA: Air Pollution
Control Association; paper no. 76-27.8.
Cato, G. A.; Buening, H. J.; DeVivo, C. C.; Morton, B. G.; Robinson, J. M.
(1974) Field testing: application of combustion modifications to control
pollutant emissions from industrial boilers--phase I. Research Triangle
Park, NC: U. S. Environmental Protection Agency, Control Systems Laboratory;
EPA report no. EPA-650/2-74-078a.
Chenini, A.; Koslin, M. ; Malaviya, B. K.; White, F. A. (1979) Trace element
analysis of radiological effluents from coal-burning power plants. Trans.
Am. Nucl. Soc. 32: 136-137.
Cherry, S. S. (1983) Analysis of low NO operation of two pulverized-coal
fired utility boilers. Research TriangleXPark, NC: U. S. Environmental
Protection Agency, Industrial Environmental Research Laboratory; EPA report
no. EPA-600/7-83-056.
C-4
-------
Christiansen, C. S.; Ledbetter, J. 0.; Miksad, R. W. (1979) Radioactive
emissions from a lignite-fired power plant. Presented at: 72nd annual
meeting of the Air Pollution Control Association; June; Cincinnati, OH.
Pittsburgh, PA: Air Pollution Control Association; paper no. 79-19.5.
Cohen, B. L. (1981) Applications of ICRP 30, ICRP 23, and radioactive waste
risk assessment techniques to chemical carcinogens. Health Phys.
42: 753-757.
Coles, D. G.; Ragaini, R. C.; Ondov, J. M. (1978) Behavior of natural
radionuclides in western coal-fired power plants. Environ. Sci. Technol.
12: 442-446.
Coles, D. G.; Ragaini, R. C.; Ondov, J. M.; Fisher, G. L.; Silberman, D.;
Prentice, B. A. (1979) Chemical studies of stack fly ash from a coal-fired
power plant. Environ. Sci. Technol. 13: 455-459.
Conzemius, R. J.; Welcomer, T. D.; Svec, H. J. (1984) Elemental
partitioning in ash depositories and material balances for a coal burning
facility by spark source mass spectrometry. Environ. Sci. Technol.
18: 12-18.
Cooper, R. D. (1983) Assessment of health and environmental effects of
energy sources. U. S. Department of Energy; DOE report no. DOE/EV/10340-1.
Cowherd, C., Jr.; Marcus, M.; Guenther, C. M.; Spigarelli, J. L. (1975)
Hazardous emission characterization of utility boilers. Research
Triangle Park, NC: U. S. Environmental Protection Agency, Control Systems
Laboratory; EPA report no. EPA-650/2-75-066.
Cuddihy, R. G. (1983) Risk assessment, relationships for evaluating
effluents from coal industries. Sci. Total Environ. 28: 479-492.
Currier, E. L.; Neal, B. D. (1984) Fugitive emissions from coal-fired power
plants. Palo Alto, CA: Electric Power Research Institute; EPR1 report
no. CS-3455.
Davison, R. L.; Natusch, D. F. S.; Wallace, J. R.; Evans, C. A., Jr. (1974)
Trace elements in fly ash: dependence of concentration on particle size.
Environ. Sci. Technol. 8: 1107-1113.
DeAngelis, D. G. (1979) Emissions from coal-fired residential combustion
equipment. Presented at: 72nd annual meeting of the Air Pollution Control
Association; June; Cincinnati, OH. Pittsburgh, PA: Air Pollution Control
Association; paper no. 79-60.3.
DeAngelis, D. G.; Reznik, R. B. (1979) Source assessment: residential
combustion of coal. Research Triangle Park, NC: U. S. Environmental
Protection Agency, Industrial Environmental Research Laboratory; EPA report
no. EPA-600/2-79-019a.
C-5
-------
DeAngelis, R. ; Piper, B. (1981) Particulate emissions characteristics of
oil fired utility boilers--phase II. Prepared for Consolidated Edison Co. of
NY Inc. and Empire State Electric Energy Research Corp. Elmsford, NY: KVB;
KVB report no. 1-21610-1107.
Delleney, R. D.; Edwards, L. 0.; James, S. N. (1981) Methodology for the
evaluation of non-criteria pollutants from coal technologies. Prepared for
State of California Energy Resources Conservation and Development Commission.
Austin, TX: Radian Corporation; Radian report no. DCN 81-202-329-03-08.
Demski, R. J.; Yeh, J. T.; Joubert, J. I. (1982) Control of sulfur dioxide,
chlorine and trace element emissions from coal-fired boilers by fabric
filtration. In: Third symposium on the transfer and utilization of
particulate control technology; Vol. I: Control of emissions from coal fired
boilers. Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/9-82=005a.
Devitt, T.; Spalte, P.; Gibbs, L. (1979) Population and characteristics of
industrial/commercial boilers in the U. S. Research T-riangle Park, NC:
U. S. Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/7-79-178a.
Diehl, R. C.; Hattman, E. A.; Schultz, H.; Haren, R. J. (1972) Fate of
trace mercury in the combustion of coal. Pittsburgh, PA: U. S. Department
of the Interior, Bureau of Mines; technical progress report no. 54.
Dienstfrey, S. J.; Preston, J. L. (1983) Report on the 1980 manufacturing
industries energy consumption study and survey of large combustors.
Washington, DC: U. S. Department of Energy, Energy Information
Administration; DOE report no. DOE/EIA-0358.
Dietz, R. N.; Wieser, R. F. (1983) Sulfate formation in oil-fired power
plant plumes; Vol. I: Parameters affecting primary sulfate emissions and a
model for predicting emissions and plume opacity. Palo Alto, CA: Electric
Power Research Institute; EPRI report no. EA-3231.
Edwards, L. 0.; Muela, C. A.; Sawyer, R. E.; Thompson, C. M.; Williams,
D. H.; Delleney, R. D. (1980a) Trace metals and stationary conventional
combustion sources (SCCP's). EPA contract no. 68-02-2608. Research Triangle
Park, NC: U. S. Environmental Protection Agency, Industrial Environmental
Research Laboratory.
Edwards, L. 0.; Muela, C. A.; Sawyer, R. E.; Thompson, C. M.; Williams,
D, H.; Delleney, R. D. (1980b) Trace metals and stationary conventional
combustion sources (SCCP's); bibliography. EPA contract no. 68-02-2608.
Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory.
C-6
-------
Edwards, L. 0.; Muela, C. A.; Sawyer, R. E.; Thompson, C. M.; Williams,
D. H.; Delleney, R. D. (1980c) Trace metals and stationary conventional
combustion sources (SCCP's); technical summary. EPA contract no. 68-02-2608.
Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory.
Edwards, L. 0.; Muela, C. A.; Sawyer, R, E.; Thompson, C, M.; Williams,
D. H.; Delleney, R. D. (1981) Trace metals and stationary conventional
combustion sources (SCCP's); project summary. Research Triangle Park, NC:
U. S. Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/S7-80-155.
Energy Information Administration (1984a) Inventory of power plants in the
United States 1983. Washington, DC: U. S. Department of Energy; DOE report
no. DOE/EIA-0095(83).
Energy Information Administration (1984b) State energy data report,
consumption estimates, 1960-1982. Washington, DC: EIA report no.
DOE/EIA-0214(82).
Ensor, D. S.; Cowen, S.; Hooper, R.; Markowski, G.; Scheck, R.; Farrell, J.
D.; Burnham, J. (1979) Evaluation of the George Neal No. 3 electrostatic
precipitator. Palo Alto, CA: Electric Power Research Institute; EPRI report
no. EPRI FP-1145.
Ensor, D. S.; Cowen, S.; Shendrikar, A.; Markowski, G.; Woffinden, G.;
Pearson, R.; Scheck, R. (1981) Kramer Station fabric filter evaluation.
Palo Alto, CA: Electric Power Research Institute; EPRI report no. CS-1669.
Ensor, D. S.; Markowski, G.; Woffinden, G.; Legg, R.; Cowen, S.; Murphy, M.;
Shendrikar, A. D.; Pearson, R. ; Scheck, R. (1983) Evaluation of
electrostatic precipitator performance at San Juan Unit No. 1. Palo Alto,
CA: Electric Power Research Institute; EPRI report no. CS-3252.
Environmental Research and Technology, Inc. (1983) The behavior and impacts
of radionuclides from western coal-fired power plants. Prepared for Western
Energy Supply and Transmission Associates Air Quality Task Force.
Fort Collins, CO; ER&T report no. B828.
Eschenroeder, A. Q.; Magil, G. C.; Woodruff, C. R. (1985) Assessing the
health risks of airborne carcinogens. Palo Alto, CA: Electric Power
Research Institute; EPRI report no. EA-4021.
Evers, R.; Vandergriff, V. E.; Zielke, R. L. (1980) Field study to obtain
trace element mass balances at a coal-fired utility boiler. Research
Triangle Park, NC: U. S. Environmental Protection Agency, Industrial
Environmental Research Laboratory; EPA report no. EPA-600/7-80-171.
Ewing, R. A.; Cornaby, B. W.; Van Voris, P.; Zuck, J. C.; Raines, G. E.;
Min, S. (1979) Criteria for assessment of environmental pollutants from
coal cleaning processes. Research Triangle Park, NC: U. S. Environmental
Protection Agency, Industrial Environmental Research Laboratory; EPA report
no. EPA-600/7-79-140.
C-7
-------
Farrell, S. F. (1985) [Letter to Mr. Garry Brooks] August 7. Available
from: Radian Corporation, Research Triangle Park, NC; project no.
203-024-41.
Filby, R. H.; Shah, K. R. (1975) Neutron activation methods for trace
elements in crude oil. In: Yen, T. F. The role of trace metals in
petroleum. Ann Arbor, MI: Ann Arbor Science Publishers, Inc. pp. 89-110.
Fischer, W. H.; Ponder, W. A.; Zaharchuk, R. (1979) Environmental
assessment of the dual alkali FGD system applied to an industrial boiler
firing coal and oil. In: Ayer, F. A., ed. Proceedings: symposium on flue
gas desulfurization; Vol. II; March; Las Vegas, NV. Research Triangle Park,
NC: U. S. Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/7-79-167b.
Folsom, B. A.; Nelson, L. P-; Abele, A. R.; Reese, J. L.; Vatsky, J. (1984)
Evaluation of low emission coal burner technology on industrial boilers:
second annual report, 1980; project summary. Research Triangle Park, NC:
U. S. Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/S7-84-024b.
Ford, C. T. (1977) Coal cleaning to remove trace elements prior to
utilization. In: NCA/BCR coal conference and exposition IV: fourth
symposium on coal utilization; October; Louisville, KY. Washington, DC:
National Coal Association, pp. 146-191.
Ford, C. T.; Price, A. A. (1982) Evaluation of the effect of coal cleaning
on fugitive elements. Pittsburgh, PA: U. S. Department of Energy; DOE
report no. DOE/EV/04427-62.
Freedman, B. (1982) Trace elements and organics associated with coal
combustion in power plants: emissions and environmental impacts. In:
Al Taweel, A. M., ed. Coal: phoenix of the '80's: proceedings of the 64th
CIC coal symposium; May/June 1981; Halifax, Nova Scotia. Ottawa, Canada:
Canadian Society of Chemical Engineers; pp. 616-631.
Gasper, J. R.; Dauzvardis, P. A. (1979) Body burdens--an integrated
approach to health risk assessment. In: Hazardous material, risk
assessment, disposal and management: national conference; April;
Miami Beach, FL. Silver Spring, MD: Information Transfer, Inc.; pp. 73-77.
Gasper, J. R.; Dauzvardis, P. A.; Surles, T. G. (1979) Projection of body
burdens to assess the relative risk from exposure to trace elements from coal
combustion emissions, drinking water, and diet. Argonne, IL: U. S.
Department of Energy, Argonne National Laboratory; ANL report no. ANL/AA-23.
Giammar, R. D.; Engdahl, R. B.; Barrett, R. E. (1976) Emissions from
residential and small commercial stoker-coal-fired boilers under smokeless
operation. Research Triangle Park, NC: U. S. Environmental Protection
Agency, Industrial Environmental Research Laboratory; EPA report
no. EPA-600/7-76-029.
C-8
-------
Gladney, E. S.; Owens, J. W. (1976) Beryllium emissions from a coal-fired
power plant. J. Environ. Sci. Health All(4&5): 297-311.
Gladney, E. S.; Small, J. A.; Gordon, G. E.; Zoller, W. H. (1976)
Composition and size distribution of in-stack particulate material at a coal-
fired power plant. Atmos. Environ. 10: 1071-1077.
Gladney, E. S.; Gordon, G. E.; Zoller, W. H. (1978) Coal combustion:
source of toxic elements in urban air? J. Environ. Sci. Health A13(7):
481-491.
Gluskoter, H. J.; Ruch, R. R.; Miller, W. G.; Cahill, R. A.; Dreher, G. B.;
Kuhn, J. K. (1977) Trace elements in coal: occurrence and distribution.
Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-77-064.
Goldberg, P. M.; Higginbotham, E. B. (1981) Industrial boiler combustion
modification NO control; Vol. II: Stoker coal-fired boiler field test--
Site A. Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-81-126b.
Gordon, G. E.; Davis, D. D.; Israel, G. W.; Landsberg, H. E.; O'Haver, T. C.;
Staley, S. W.; Zoller, W. H. (1974) Study of the emissions from major air
pollution sources and their atmospheric interactions; two-year progress
report, 1 Nov. 1972 - 31 October 1974. National Science Foundation grant
no. GI-36338x. College Park, MD: University of Maryland, Department of
Chemistry and Institute for Fluid Dynamics and Applied Mathematics.
Greiner, N. R.; Wagner, P. (1983) Radioactive emissions from coal
production and utilization: the typical case put into perspective.
Los Alamos, MM: U. S. Department of Energy, Los Alamos National Laboratory;
LANL report no. LA-9747-PR.
Greiner, N. R.; Williams, M. D.; Wagner, P. (1983) Estimation of
radionuclide releases from specific large coal-fired industrial and utility
boilers. Los Alamos, NM: U. S. Department of Energy, Los Alamos National
Laboratory; LANL report no. LA-9845-MS.
Griepink, B.; Colinet, E.; Guzzi, G.; Haemers, L.; Muntau, H. (1983)
Certification of trace element contents (As, Cd, Co, Cu, Fe, Mn, Hg, Na, Pb,
and Zn) in a fly ash obtained from the combustion of pulverised coal.
Fresenius Z. Anal. Chem. 315: 20-25.
Griest, W. H. ; Guerin, M. R. (1979) Identification and quantification of
polynuclear organic matter (POM) on particulates from a coal-fired power
plant. Palo Alto, CA: Electric Power Research Institute; EPRI report
no. EA-1092.
C-9
-------
Gustaferro, J. F. (1983) U. S. energy for the rest of the century. 1983
edition. Washington, DC: U. S. Department of Commerce, Office of
Competitive Assessment; DOC report no. DOC/OEA/OCA-5.
Haile, C. L.; Stanley, J. S.; Lucas, R. M.; Melroy, D. K.; Nulton, C. P.;
Yauger, W. L. (1983) Pilot study of information of specific compounds from
combustion sources. Washington, DC: U. S. Environmental Protection Agency,
Office of Pesticides and Toxic Substances; EPA report no. EPA-560/5-83-004.
Haile, C. L.; Stanley, J. S.; Walker, T.; Cobb, G. R. ; Boomer, B. A. (1983)
Comprehensive assessment of the specific compounds present in combustion
processes. Washington, DC: U. S. Environmental Protection Agency, Office of
Pesticides and Toxic Substances; EPA report no. EPA-560/5-83-006.
Hall, R. E.; Cooke, W. M.; Barbour, R. L. (1983) Comparison of air
pollutant emissions from vaporizing and air atomizing waste oil heaters. J.
Air Pollut. Control Assoc. 33: 683-687.
Hangebrauck, R. P.; Von Lehmden, D. J.; Meeker, J. E. (1964) Emissions of
polynuclear hydrocarbons and other pollutants from heat-generation and
incineration processes. J. Air Pollut Control Assoc. 14: 267-278.
Hangebrauck, R. P.; Von Lehmden, D. J.; Meeker, J. E. (1967) Sources of
polynuclear hydrocarbons in the atmosphere. Cincinnati, OH: U. S. Public
Health Service; Public Health Service report no. AP-33.
Harris, F.; Andren, A.; Henderson, G. (1975) Trace elements from coal-fired
plants. Oak Ridge Nat. Lab. Rev. 8(2): 20-24.
Hatch, J. R.; Swanson, V. E. (1977) Trace elements in Rocky Mountain coals.
In: Murray, O.K., ed. Geology of Rocky Mountain coal: proceedings of the
1976 symposium; April 1976, Golden, CO. Colorado Geological Survey and the
Colorado School of Mines; C.G.S. resource series 1; pp. 143-163.
Hee, S. S. Q.; Finelli, V. N.; Fricke, F. L.; Wolnick, K. A. (1982) Metal
content of stack emissions, coal and fly ash from some eastern and western
power plants in the U.S.A. as obtained by ICP-AES. Intern. J. Environ. Anal.
Chem. 13: 1-18.
Heit, M. (1977) A review of current information on some ecological and
health related aspects of the release of trace metals into the environment
associated with the combustion of coal. New York, NY: U. S. Energy Research
and Development Administration, Health and Safety Laboratory; report
no. HASL-320.
Henry, W. M.; Knapp, K. T. (1980) Compound forms of fossil fuel fly ash
emissions. Environ. Sci. Technol. 14: 450-456.
Higginbotham, E. B. ; Goldberg, P. M. (1981) Combustion modification NO
controls for utility boilers; Vol. I: Tangential coal-fired unit field lest.
Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no
EPA-600-7-81-124a.
C-10
-------
Higginbotham, E. B.; Waterland, L. R.; Mason, H. B.; Hall, R. E. (1980)
Environmental assessment field testing: effects of NO controls applied to a
tangential coal-fired utility boiler. In: Engel, A. 5.; Slater, S. M.;
Gentry, J. W., eds. Emission control from stationary power sources:
technical, economic and environmental assessments. New York, NY: American
Institute of Chemical Engineers; AIChE Symp. Ser. no. 201; pp. 67-79.
Hileman, B. (1984) Formaldehyde: assessing the risk. Environ. Sci.
Technol. 18: 216A-221A.
Hobbs, C. H. (1983) Status of research on physical, chemical and biological
characterization of particulate and organic emissions from conventional and
fluidized bed combustion of coal: 1976 to the present. Washington, DC:
U. S. Department of Energy; DOE report no. DOE/ER-0162.
Hodgson, A. T.; Pollard, M. J.; Brown, N. J. (1984) Mercury emissions from
a modified in-situ oil shale report. Atmos. Environ. 18: 247-253.
Hofstader, R. A.; Milner, 0. I.; Runnels, J. H., eds. (1976) Analysis of
petroleum for trace metals: a symposium sponsored by the Divisions of
Analytical Chemistry and Petroleum Chemistry at the 169th national meeting of
the American Chemical Society; April 1975; Philadelphia, PA. Washington, DC:
American Chemical Society; Adv. Chem. Ser. no. 156.
Holland, W. F.; Wilde, K. A.; Parr, J. L.; Lowell, P. S.; Pohler, R. F.
(1975) Environmental effects of trace elements from ponded ash and scrubber
sludge. Palo Alto, CA: Electric Power Research Institute; EPRI research
project no. 202; NTIS order no. PB-252090.
Holtberg, P. D.; Woods, T. J.; Ashby, A. B. (1984) 1984 GRI baseline
projection of U. S. energy supply and demand 1983-2010. Chicago, IL: Gas
Research Institute, Strategic Analysis and Energy Forecasting Division.
Holton, G. A.; Little, C. A.; O'Donnell, F. R.; Etnier, E. L.; Travis, C. C.
(1982) Initial atmospheric-dispersion modeling in support of the multiple-
site incineration study. Oak Ridge, TN: U. S. Department of Energy, Oak
Ridge National Laboratory; ORNL report no. ORNL/TM-8181.
Hulett, L. D.; Carter, J. A.; Cook, K. D.; Emery, J. F.; Klein, D. H., Lyon,
W. S.; Nyssen, G. A.; Fulkerson, W.; Bolton, N. E. (1974) Trace element
measurements at the coal-fired Allen steam plant--particle characterization.
In: Coal utilization symposium--focus on SO- emission control; October;
Louisville, KY. Washington, DC: National Coal Association; pp. 207-213.
Hulett, L. D., Jr.; Weinberger, A. J.; Northcutt, K. J.; Ferguson, M. (1980)
Chemical species in fly ash from coal-burning power plants. Science
210(4476): 1356-1358.
Hutton, M. (1983) Sources of cadmium in the environment. Exotoxicol.
Environ. Saf. 7: 9-24.
C-ll
-------
Interagency Task Force on Acid Precipitation (1982) National acid
precipitation assessment plan. Washington, DC.
Jacko, R. B. (1974) Industrial source sampling for trace metals. In:
Fulkerson, W.; Shults, W. D.; Van Hook, R. I., eds. NSF trace contaminants
conference: proceedings of the first annual conference; August 1973; Oak
Ridge, TN. Oak Ridge, TN: U. S. Department of Energy, Oak Ridge National
Laboratory; pp. 146-164.
Joensuu, O.I. (1971) Fossil fuels as a source of mercury pollution.
Science 172(3987): 1027-1028.
Jones, P. W. ; Wilkinson, J. E-. ; Strup, P- E. (1977) Measurement of
polycyclic organic materials and other hazardous organic compounds in stack
gases: state of the art. Research Triangle Park, NC: U. S. Environmental
Protection Agency, Environmental Sciences Research Laboratory; EPA report
no. EPA-600/2-77-202.
Junk, G. A.; Ford, C. S. (1980) A review of organic emissions from selected
combustion processes. Chemosphere 9: 187-230.
Kaakinen, J. W.; Jorden, R. M. (1974) Determination of a trace element mass
balance for a coal-fired power plant. In: Fulkerson, W.; Shults, W. D.;
Van Hook, R. I., eds. NSF trace contaminants conference: proceedings of the
first annual conference; August 1973; Oak Ridge, TN. Oak Ridge, TN: U. S.
Department of Energy, Oak Ridge National Laboratory; pp. 165-184.
Kaakinen, J. W.; Jorden, R. M.; Lawasani, M. H.; West, R. E. (1975) Trace
element behavior in coal-fired power plant. Environ. Sci. Technol.
9: 862-869.
Kalb, G. W. (1975) Total mercury mass balance at a coal-fired power plant.
In: Babu, S. P., ed. Trace elements in fuel: symposium sponsored by the
Division of Fuel Chemistry at the 166th national meeting of the American
Chemical Society; August 1973; Chicago, IL. Washington, DC: American
Chemical Society; Adv. Chem. Ser. no. 141; pp. 154-187-
Kalvins, A. (1983) Trace inorganic element and particulate deposition
model--part I. Ontario Hydro Research Division Report no. 83-316-K.
Kelley, M. E. (1983) Sources and emissions of polycyclic organic matter.
Research Triangle Park, NC: U. S. Environmental Protection Agency; EPA
report no. EPA-450/5-83-010b.
Kelly, M. E.; Parks, R. M.; Stalling, J. H. E. (1983) Control of criteria
and non-criteria pollutants from coal/oil mixture combustion. Research
Triangle Park, NC: U. S. Environmental Protection Agency, Industrial
Environmental Research Laboratory; EPA report no. EPA-600/7-83-040.
Klein, D. H.; Andren, A. W.; Bolton, N. E. (1975a) Trace element discharges
from coal combustion for power production. Water, Air, Soil Pollut. 5:
71-77.
C-12
-------
Klein, D. H.; Andren, A. W.; Carter, J. A.; Emery, J. F.; Feldman, C.;
Fulkerson, W.; Lyon, W. S.; Ogle, J. C.; Talmi, Y.; Van Hook, R. I.;
Bolton, N. (1975b) Pathways of thirty-seven trace elements through
coal-fired power plant. Environ. Sci. Technol. 9: 973-979.
Klusek, C. S.; Miller, K. M.; Heit, M. (1983) Trace element and
radionuclide mass balances at a coal-fired electric generating station.
Environ. Int. 9: 139-144.
Koester, P. A.; Zieger, W. H. (1978) Analysis for radionuclides in SRC and
coal combustion samples. Washington, D. C.: U. S. Environmental Protection
Agency; EPA report no. EPA-600/7-78-185.
Kothny, E. L., ed. (1973) Trace elements in the environment: a symposium
sponsored by the Division of Water, Air, and Waste Chemistry at the 162nd
national meeting of the Americal Chemical Society; September 1971;
Washington, DC. Washington, DC: American Chemical Society; Adv. Chem.
Ser. no. 123.
Kowalczyk, G. S. (1984) Emission and atmospheric impact of trace elements
from a reconverted coal-fired power plant. Presented at: 77th annual
meeting of the Air Pollution Control Association; June; San Francisco, CA.
Pittsburgh, PA: Air Pollution Control Association; paper no. 84-12.6.
Krishnan, E. R.; Hellwig, G. V. (1982) Trace emissions from coal and oil.
Environ. Prog. 1: 290-295.
Leavitt, C.; Arledge, K.; Hamersma, W.; Maddalone, R.; Beimer, R.;
Richard, G.; Yamada, M. (1978a) Environmental assessment of coal- and
oil-firing in a controlled industrial boiler; Vol. I: Executive summary.
Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-78-164a.
Leavitt, C.; Arledge, K.; Hamersma, W.; Maddalone, R.; Beimer, R.;
Richard, G.; Yamada, M. (1978b) Environmental assessment of coal- and
oil-firing in a controlled industrial boiler; Vol. II: Comparative
assessment. Research Triangle Park, NC: U. S. Environmental Protection
Agency, Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-78-164b.
Leavitt, C.; Arledge, K.; Hamersma, W.; Maddalone, R.; Beimer, R.;
Richard, G.; Yamada, M. (1978c) Environmental assessment of coal- and
oil-firing in a controlled industrial boiler; Vol. Ill: Comprehensive
assessment. Research Triangle Park, NC: U. S. Environmental Protection
Agency, Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-78-164c.
C-13
-------
Leavitt, C.; Shih, C.; Orsini, R.; Arledge, K.; Saur, A.; Peters, W. D.
(1979) Utility conventional combustion comparative environmental assessment
--coal and oil. In: Ayer, F. A., ed. Proceedings: symposium on flue gas
desulfurization; March; Las Vegas, NV. Research Triangle Park, NC: U. S.
Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/7-79-167b_
Leavitt, C.; Arledge, K.; Shih, C.; Orsini, R.; Saur, A.; Hamersma, W.;
Maddalone, R.; Beimer, R.; Richard, G.; Unger, S.; Yamada, M. (1980a)
Environmental assessment of a coal-fired controlled utility boiler. Research
Triangle Park, NC: U. S. Environmental Protection Agency, Industrial
Environmental Research Laboratory; EPA report no. EPA-600/7-80-086.
Leavitt, C.; Arledge, K.; Shih, C.; Orsini, R.; Saur, A.; Hamersma, W.;
Maddalone, R.; Beimer, R.; Richard, G.; Unger, S.; Yamada, M. (1980b)
Environmental assessment of an oil-fired controlled utility boiler. Research
Triangle Park, NC: U. S. Environmental Protection Agency, Industrial
Environmental Research Laboratory; EPA report no. EPA-600/7-80=087.
Levy, A.; Miller, S. E.; Barrett, R. E.; Schultz, E. J.; Melvin, R. H.;
Axtman, W. H.; Locklin, D. W. (1971) A field investigation of emissions
from fuel oil combustion for space heating. American Petroleum Institute
Project SS-5, Phase I. Columbus, OH: Battelle-Columbus Laboratories.
Lim, K. J.; Castaldini, C.; Milligan, R. J.; Lips, H. I.; Merrill, R. S.;
Goldberg, P. M.; Higginbotham, E. B.; Waterland, L. R. (1982) Industrial
boiler combustion modification NO controls; project summary. Research
Triangle Park, NC: U. S. Environmental Protection Agency, Industrial
Environmental Research Laboratory; EPA report no. EPA-600/S7-81-126.
Lim, M. Y. (1979) Trace elements from coal combustion--atmospheric
emissions. London, United Kingdom: IEA Coal Research; IEA report no.
ICTIS/TR05.
Lindberg, S. E. (1980) Mercury partitioning in a power plant plume and its
influence on atmospheric removal mechanisms. Atmos. Environ. 14: 227-231.
Lindberg, S. E. (1984) Emission and deposition of atmospheric mercury
vapor. Presented at: United Nations International Council of Scientific
Unions meeting on biogeochemical cycling; September; Toronto, Canada; NTIS
report no. DE8500634.
Lips, H. I.; Higginbotham, E. B. (1981) Industrial boiler combustion
modification NO control; Vol. Ill: Stoker coal-fired boiler field test--
Site B. Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-81-126c.
Lyon, W. S. (1977) Trace element measurements at the coal-fired steam
plant. Cleveland, OH: CRC Press, Inc.
C-14
-------
McBride, J. P.; Moore, R. E.; Witherspoon, J. P.; Blanco, R. E. (1977)
Radiological impact of airborne effluents of coal-fired and nuclear power
plants. Oak Ridge, TN: U. S. Department of Energy, Oak Ridge National
Laboratory; ORNL report no. ORNL-5315.
McCurley, W. R.; Moscowitz, C. M.; Ochsner, J. C.; Reznik, R. B. (1979)
Source assessment: dry bottom industrial boilers firing pulverized
bituminous coal. Research Triangle Park, NC: U. S. Environmental Protection
Agency, Industrial Environmental Research Laboratory; EPA report no.
EPA-600/2-79-019e.
Malte, P. C. (1977) Inorganic pollutants from pulverized coal combustion (a
review). Presented at: 1977 Fall meeting of the Western States Section of
the Combustion Institute; October; Stanford, CA. Pittsburgh, PA: Combustion
Institute; paper no. 77-48.
Mann, R. M.; Magee, R. A.; Collins, R. V.; Fuchs, M. R.; Mesich, F. G.
(1978) Trace elements of fly ash: emissions from coal-fired steam plants
equipped with hot-side and cold-side electrostatic precipitators for
particulate control. Denver, CO: U. S. Environmental Protection Agency,
Region VIII; EPA report no. EPA-908/4-78-008.
Markowski, G. R.; Filby, R. (1985) Trace element concentration as a
function of particle size in fly ash from a pulverized coal utility boiler.
Environ. Sci. Technol. 19: 796-804.
Matthews, T. G.; Reed, T. J.; Tromberg, B. J.; Daffron, C. R.; Hawthorne,
A. R. (1984) Formaldehyde emissions from combustion sources and solid
formaldehyde resin containing products: potential impact on indoor
formaldehyde concentrations. Presented at: 187th national meeting of the
American Chemical Society; April; St. Louis, MO. Washington, DC: American
Chemical Society.
Melia, M. T.; McKibben, R. S.; Pelsor, B. W. (1984) Utility FGD survey:
October 1983-September 1984; Vol. I: Categorized summaries of FGD systems.
EPRI contract no. RP982-32. Cincinnati, OH: PEI Associates, Inc.
Meserole, F. B.; Schwitzgebel, K.; Magee, R. A.; Mann, R. M. (1979) Trace
element emissions from coal-fired power plants. Trans. ASME 101: 620-624.
Moore, G. T.; Elia, V. J. (1978) Evaluation of arsenic and selenium
emissions from a coal fired power plant. Presented at: 71st annual meeting
of the Air Pollution Control Association; June; Houston, TX. Pittsburgh, PA:
Air Pollution Control Association; paper no. 78-34.2.
Moore, R. E. (1978) AREAS: a computer code fot estimating air pollutant
concentrations from dispersed sources. Oak Ridge, TN: U. S. Department of
Energy, Oak Ridge National Laboratory; ORNL report no. ORNL/TM-6364.
C-15
-------
Morrison, W. W.; Schock, M. R. ; Christiansen, G. A. (1979) The long-term
effects of trace elements emitted by energy conversion of lignite coal; Vol.
II: Technical appendices. Billings, MT: Old West Regional Commission; NTIS
report no. PB80-168875.
Mount, D. I. (1980) Environmental effects of western coal combustion; Part
IV: Chemical and physical characteristics of coal fly ash. Duluth, MN:
U. S. Environmental Protection Agency, Environmental Research Laboratory; EPA
report no. EPA-600/3-80-094.
Mroe, E. J. (1976) The study of the elemental composition of particulate
emissions from an oil-fired power plant. College, MD: University of
Maryland. Ann Arbor, MI: University Microfilms International; publication
no. 77-10,408.
Muela, C. A. (1979) Control technologies for non-criteria pollutants.
Prepared for State of California Energy Commission. Austin, TX: Radian
Corporation; Radian report no. DCN 79-202-329-03-06.
Nader, J. S. (1978) Field measurements and characterization of emissions
from coal-fired combustion sources. Presented at: 71st annual meeting of
the Air Pollution Control Association; June; Houston, TX. Pittsburgh, PA:
Air Pollution Control Association; paper no. 78-42.6.
Nadkarni, R. A. (1982) Comprehensive elemental analysis of coal and fly
ash. In: Fuller, E. L., Jr., ed. Coal and coal products: analytical
characterization techniques. Washington, DC: American Chemical Society;
Adv. Chem. Ser. no. 205; pp. 147-162.
National Academy of Sciences. (1972) Particulate polycyclic organic matter,
committee on biologic effects of atmospheric pollutants. Washington, DC.
National Institute for Occupational Safety and Health (1981) Health hazard
evaluation: Colorado Springs public utilities. Cincinnati, OH; Health
Hazard Evaluation Report no. HETA 81-034,035-934.
National Research Council. (1983) Polycyclic aromatic hydrocarbons:
evaluation of sources and effects. Washington, DC: National Academy Press.
Natusch, D. F. S. (1978a) Characterization of fly ash from coal combustion.
In: Workshop proceedings on primary sulfate emissions from combustion
sources; August; Research Triangle Park, NC: U. S. Environmental Protection
Agency, Environmental Sciences Research Laboratory; EPA report
no. EPA-600/9-78-020b.
Natusch, D. F. S. (1978b) Formation and transformation of polycyclic
organic matter from coal combustion. U. S. Department of Energy; DOE report
no. COO-4347-1.
Natusch, D. F. S. (1978c) Potentially carcinogenic species emitted to the
atmosphere by fossil-fueled power plants. Environ. Health Perspect.
22: 79-90.
C-16
-------
Natusch, D. F. S. (1984) Formation and transformation of particulate
polycyclic organic matter emitted from coal fired power plants and oil shale
retorting. U. S. Department of Energy; DOE report no. DOE/EV/04960-T1.
Natusch, D. F. S.; Wallace, J. K.; Evans, C. A., Jr. (1974) Toxic trace
elements: preferential concentration in respirable particles.
Science 183(4121): 202-204.
Natusch, D. F. S.; Korfmacher, W. A.; Miguel, A. H.; Schure, M. R.;
Tomkins, B. A. (1978) Transformation of POM in power plant emissions. In:
Process measurements for environmental assessment: symposium proceedings;
February; Atlanta, GA. Research Triangle Park, NC: U. S. Environmental
Protection Agency, Industrial Environmental Research Laboratory; EPA report
no. EPA-600/7-78-168.
Novak, K. M.; Medeiros, W. H.; Coveney, E. A., eds. (1981) Health and
environmental risk analysis program workshop: potential public health
impacts of airborne organic combustion products; August; Upton, NY. Upton,
NY: U. S. Department of Energy, Brookhaven National Laboratory; BNL report
no. BNL 51542.
Office of Air Quality Planning and Standards. (1980) Energy data system
(EDS) terminal users manual. Research Triangle Park, NC: U. S.
Environmental Protection Agency.
Office of Air Quality Planning and Standards. (1984) Locating and
estimating air emissions from sources of formaldehyde. Research Triangle
Park, NC: U. S. Environmental Protection Agency; EPA report no.
EPA-450/4-84-007e.
Office of Radiation Programs (1979) Radiological impact caused by emissions
of radionuclides into air in. the United States. Washington, D.C.: U. S.
Environmental Protection Agency; EPA report no. EPA-520/7-79-006.
Office of Radiation Programs (1983) Proposed standards for radionuclides:
draft background information document. Washington, D.C.: U. S.
Environmental Protection Agency; EPA report no. EPA-520/1-83-001.
Office of Radiation Programs (1984) Radionuclides: background information
document for final rules; Vol. II. Washington, D.C.: U. S. Environmental
Protection Agency; EPA report no. EPA 520/1-84-022-2.
Ondov, J. M.; Biermann, A. H. (1979) Effects of particle-control devices on
atmospheric emissions of minor and trace elements from coal combustion.
Preprint for presentation at: Second symposium for the transfer and
utilization of particulate control technology; August; Denver, CO.
Livermore, CA: University of California, Lawrence Livermore Laboratory; UCRL
report no. UCRL-82558 preprint.
Ondov, J. M.; Biermann, A. H. (1980) Physical and chemical characterization
of aerosol emissions from coal-fired power plants. In: Singh, J. J.;
Deepak, A., eds. Environmental and climactic impact of coal utilization.
New York, NY: Academic Press; pp. 1-20.
C-17
-------
Ondov, J. M.; Ragaini, R. C,; Biermann, A. H. (1978a) Characterization of
trace element emissions from coal-fired power plants. Preprint for
presentation at: Third international conference on nuclear methods in
environmental and energy research; October 1977; Columbia, MO. Livermore,
CA: University of California, Lawrence Livermore Laboratory; UCRL report no
UCRL-80412 preprint.
Ondov, J. M.; Ragaini, R. C.; Biermann, A. H. (1978b) Evaluation of two
particulate collection alternatives for trace element removal at coal-fired
power plants. Presented at: 71st annual meeting of the Air Pollution
Control Association; June; Houston, TX. Pittsburgh, PA: Air Pollution
Control Association; paper no. 78-34.6.
Ondov, J. M.; Ragaini, R. C.; Biermann, A. H. (1979a) Elemental emissions
from a coal-fired power plant: comparison of a venturi wet scrubber system
with a cold-side electrostatic precipitator. Environ. Sci. Tech.
13: 598-607.
Ondov, Jo M.; Ragaini, R. C.; Biermann, A. H. (1979b) Emissions and
particle-size distributions of minor and trace elements at two western
coal-fired power plants equipped with cold-side electrostatic precipitators.
Environ. Sci. Technol. 13: 946-953.
Ondov. J. M. ; Biermann, A. H. ; Heft, R. E. ; Koszykowski, R. F. (198,0)
Elemental composition of atmospheric fine-particles emitted from coal burned
in a modern electric power plant equipped with a flue-gas desulfurization
system. Preprint for presentation at: American Chemical Society meeting;
December; Las Vegas, NV. Livermore, CA: Lawrence Livermore Laboratory,
UCRL report no. UCRL-85035.
Owen, M. L.; Jarvis, J. B.; Behrens, G. P. (1983) Boiler radionuclide
emissions control:, the feasibility and costs of controlling coal-fired
boiler particulate emissions. EPA contract no. 68-02-3513.
U. S. Environmental Protection Agency, Office of Air Quality Planning and
Standards and Office of Radiation Programs.
Pacyna, J. M.; Sivertsen, B. (1981) Determination of human exposure using
measured data of Cd, As, and Pb. Lillestrom, Norway: Norwegian Institute
for Air Research; teknisk rapport 15/81.
Parker, S. P., ed. (1981) Encyclopedia of energy, 2nd edition.
McGraww-Hill Book Company. New York, New York.
PEDCo Environmental, Inc. (1982) Assessment of trace and toxics emissions
from coal and oil combustion. EPA contract no. 68-02-3173. Research
Triangle Park, NC: U. S. Environmental Protection Agency. Office of Air
Quality Planning and Standards.
PEDCo Environmental, Inc. (1983) Update of Ohio coal-fired boiler
inventory. Preliminary draft report; EPA contract no. 68-01-6543.
Washington, DC: U. S. Environmental Protection Agency, Office of Policy
Resource Management.
C-18
-------
Ponder, W. H.; Fischer, W. H. ; Zaharchuk, R. (1980) Environmental
assessment of the dual alkali FGD system applied to an industrial boiler
firing coal and oil. In: Engel, A. J.; Slater, S. M.; Gentry, J. W., eds.
Emission control from stationary power sources: technical, economic and
environmental assessments. New York, NY: American Institute of Chemical
Engineers; AIChE Symp. Ser. no. 201; pp. 80-95.
Prast, W. G., ed. (1983) Proceedings: Fuel supply seminars; October 1982;
St. Louis, MO. Palo Alto, CA: Electric Power Research Institute; EPRI
report no. EA-2994.
Quann, R. J.; Neville, M.; Janghorbani, M.; Mims, C. A.; Sarofim, A. F.
(1982) Mineral matter and trace-element vaporization in a laboratory-
pulverized coal combustion system. Environ. Sci. Technol. 16: 776-781.
Radian Corporation (1975a) Coal fired power plant trace element study;
Vol. I: A three station comparison. EPA contract no. 68-01-2663. Denver,
CO: U. S. Environmental Protection Agency, Region VIII.
Radian Corporation (1975b) Coal fired power plant trace element study;
Vol. II: Station I. EPA contract no. 68-01-2663. Denver, CO:
U. S. Environmental Protection Agency, Region VIII.
Radian Corporation (1984) Methodology for estimating exposure to aresenic,
beryllium, cadmium, chromium, and nickel from coal and oil combustion.
Research Triangle Park, NC: EPA contract no. 68-02-3515, work assignment 31
Ragaini, R. C.; Ondov, J. M. (1976) Trace contaminants from coal-fired
power plants. In: International conference on environmental sensing and
assessment; September 1975; Las Vegas, NV. New York, NY: Institute of
Electrical and Electronic Engineers; paper no. 17-2.
Ray, S. S.; Parker, F. G. (1977) Characterization of ash from coal-fired
power plants. Research Triangle Park, NC: U. S. Environmental Protection
Agency, Industrial Environmental Research Laboratory; EPA report no.
EPA 600/7-77-010.
Roberson, R. L.; Eggleston, T. E. (1983) Characterization of radionuclide
emissions from coal-fired utility boilers. Raleigh, NC: Kilkelly
Environmental Associates, Inc.; Kilkelly report no. 83-180-06f.
Roeck, D. R.; White, M. 0.; Kiddie, A. M.; Young, C. W. (1983) Survey of
five utility boilers for radionuclide emissions. Bedford, MA: GCA
Corporation; GCA report no. GCA-TR-83-56-G.
Rogers, S. E.; Lemmon, A. W., eds. (1979) Proceedings: symposium on coal
cleaning to achieve energy and environmental goals; September 1978;
Hollywood, FL. Research Triangle Park, NC: U. S. Environmental Protection
Agency, Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-79-098a.
C-19
-------
Rogozen, M. B.; Maldonado, G.; Grosjean, D.; Shochet, A.; Rapoport, R.
(1984a) Formaldehyde: a survey of airborne concentrations and sources;
executive summary. Contract no. A2-059-32. Sacramento, CA: State of
California, Air Resources Board.
Rogozen, M. B.; Maldonado, G.; Grosjean, D.; Shochet, A.; Rapoport, R.
(1984b) Formaldehyde: a survey of airborne concentrations and sources.
State of California, Air Resources Board; ARE report no. ARB/R-84-231.
Rohlack, L. A. (1982) Emissions characterization of a combined cycle oil-
fired combustion turbine. Prepared for Southern California Edison Co.
Austin, TX: Radian Corporation; Radian report no. DCN 82-216-006-07.
Rowe, M. D. (1981a) Estimating public-health risks of air pollution at the
national level. Presented at: Workshop on assessing health impacts of
energy technologies at the regional or national level; December; Upton, NY.
Upton, NY: U. S. Department of Energy, Brookhaven National Laboratory;
BNL report no. BNL 30750.
Rowe, M. D. (1981b) Human exposure to particulate emissions from power
plants. Upton, NY: U. S. Department of Energy, Brookhaven National
Laboratory; BNL report no. BNL 51305.
Ruch, R. R.; Gluskoter, H. J.; Shimp, N. F. (1974) Occurrence and
distribution of potentially volatile trace elements in coal. Research
Triangle Park, NC: U. S. Environmental Protection Agency, Control Systems
Laboratory; EPA report no. EPA-650/2-74-054.
Saltzman, B. E.; Cholak, J.; Schafer, L. J.; Yeager, D. W.; Meiners, B. G.;
Svetlik, J. (1985) Concentrations of six metals in the air of eight cities.
Environ. Sci. Technol. 19: 328-333.
Salvesen, K. G.; Wolfe, K. J.; Chu, E.; Herther, M. A. (1978) Emission
characterization of stationary NO sources; Volume 1: Results. Washington,
DC: U. S. Environmental Protection Agency; EPA report no. EPA-600/7-78-120a.
Santhanam, C. J.; Lunt, R. R.; Cooper, C. B.; Klimschmidt, D. E.; Bodek, I.;
Tucker, W. A.; Ullrich, C. R. (1980) Waste and water management for
conventional coal combustion assessment report--1979; Vol. Ill: Generation
and characterization of FGC wastes. Research Triangle Park, NC: U. S.
Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/7-80-012c.
Sawyer, J. W.; Higginbotham, E. B. (1981a) Combustion modification NO
controls for utility boilers; Vol. II: Pulverized-coal wall-fired unitxfield
test. Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-81-124b.
C-20
-------
Sawyer, J. W. ; Higginbotham, E. B. (1981b) Combustion modification NO
controls for utility boilers; Vol. Ill: Residual oil wall-fired unit field
test. Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-81-124c.
Schock, M. R.; Morrison, W. W.; Christiansen, G. A. (1979) The long-term
effects of trace elements emitted by energy conversion of lignite coal;
Vol. I. Billings, MT: Old West Regional Commission; NTIS report no.
PB80-168867.
Schure, M. R.; Natusch, D. F. S. (1982) The effect of temperature on the
association of POM with airborne particles. In: Cooke, M.; Dennis, A. J.;
Fisher, G. L., eds. Polynuclear aromatic hydrocarbons: sixth international
symposium. Columbus, OH: Battelle Press; New York, NY: Springer-Verlag;
pp. 713-724.
Schwitzgebel, K.; Meserole, F. B.; Oldham, R. G.; Magee, R. A.;
Mesich, F. G.; Thoem, T. L. (1977) Trace element discharge from coal-fired
power plants. In: Hutchinson, T. C., ed. International conference on heavy
metals in the environment: symposium proceedings; vol. II, part 2; October
1975; Toronto, Canada. Toronto, Canada: University of Toronto, Institute
for Environmental Studies; pp. 533-551.
Scinto, L. L.; Maddalone, R. F.; NcNeil, D. K.; Wilson, J. A. (1981) Source
test and evaluation report: Cane Run Unit no. 6, Louisville Gas and Electric
Co. Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-81-134.
Selle, S. J. (1984) High fouling western coals: unit evaluation and role
of additives. In: 12. Lignite Conference; May 1983; Grand Forks, ND;
DOE/METC-84-13 (Vol. 2); pp. 522-556.
Shelton, E. M. (1982) Heating oils, 1982. Bartlesville, OK: U. S.
Department of Energy, Bartlesville Energy Technology Center; DOE report
no. DOE/BETC/PPS-82/4.
Shen, T. T.; Cheng, R. J.; Mohneu, V. A.; Current, M.; Hudson, J. B. (1977)
Characterization of differences between oil-fired and coal-fired power plant
emissions. In: Kasuga, S.; Suzuki, N.; Yamada, T.; Kimura, G.; Inagaki, K.;
Onoe, K., eds. Proceedings of the fourth international clean air congress;
May; Tokyo, Japan. Tokyo, Japan: Japanese Union of Air Pollution Prevention
Associations; pp. 386-391.
Shih, C. C.; Takata, A. M. (1981) Emissions assessment of conventional
stationary combustion systems; summary report. Research Triangle Park, NC:
U. S. Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/7-81-003d.
C-21
-------
Shih, C.; Ackerman, D.; Scinto, L.; Moon, E.; Fishman, E. (1980a) POM
emissions from stationary conventional combustion processes, with emphasis on
polychlorinated compounds of dibenzo-p-dioxin (PCDD's), biphenyl (PCB's), and
dibenzofuran (PCDF's). EPA contract no. 68-02-3138. Research Triangle Park,
NC: U. S. Environmental Protection Agency, Industrial Environmental Research
Laboratory.
Shih, C. C.; Orsini, R. A.; Ackerman, D. G.; Moreno, R. ; Moon, E.; Scinto,
L. L.; Yu, C. (1980b) Emissions assessment of conventional stationary
combustion systems; Vol. Ill: External combustion sources for electricity
generation. Draft report; EPA contract no. 68-02-2197. Research Triangle
Park, NC: U. S. Environmental Protection Agency, Industrial Environmental
Research Laboratory.
Silberman, D.; Harris, W. R. (1984) Determination of arsenic (III) and
arsenic (V) in coal and oil fly ashes. Intern. J. Environ. Anal. Chem.
17: 73-83.
Singer, J. G., ed. (1981) Combustion - fossil power systems. Combustion
Engineering, Inc. Windsor, Connecticut.
Singh, J. J.; Khandelwal, G. S. (1978) Elemental characteristics of
aerosols emitted from a coal-fired heating plant. Hampton, VA: NASA Langley
Research Center; NASA report no. NASA-TM-78749.
Singh, J. J.; Sentell, R. J.; Khandelwal, G. S. (1976) An investigation of
size-dependent concentration of trace elements in aerosols emitted from the
oil-fired heating plants. Hampton, VA: NASA Langley Research Center; NASA
report no. NASA-TM-X-3401.
Slater, S. M.; Hall, R. M. (1977) Electricity generation by utilities:
1974 nationwide emissions estimates. In: Dispersion and control of
atmospheric emissions: new energy source pollution potential. New York, NY:
American Institute of Chemical Engineers; AIChE Symp. Ser. no. 165;
pp. 291-311.
Smith, R. D. (1980) The trace element chemistry of coal during combustion
and the emissions from coal-fired plants. Prog. Energy Combust. Sci.
6: 53-119.
Smith, R. D.; Campbell, J. A.; Nielsen, K. K. (1979a) Characterization and
formation of submicron particles in coal-fired plants. Atmos. Environ.
13: 607-617.
Smith, R. D.; Campbell, J. A.; Nielson, K. K. (1979b) Concentration
dependence upon particle size of volatilized elements in fly ash. Environ.
Sci. Technol. 13: 553-558.
Smith, R. D.; Campbell, J. A.; Felix, W. D. (1980) Atmospheric trace
element pollutants from coal combustion. Min. Eng. 32: 1603-1613.
C-22
-------
Sonnichsen, T. W. (1983) Measurements of POM emissions from coal-fired
utility boilers. Palo Alto, CA: Electric Power Research Institute; EPRI
report no. CS-2885.
Sorenson, J. R.; Kober, T. E.; Petering, H. G. (1974) The concentration of
Cd, Cu, Fe, Ni, Pb, and Zn in bituminous coals from mines with differing
incidences of coal workers' pneumoconiosis. Am. Ind. Hyg. Assoc. J.
35: 93-98.
Spackman, W. (1982a) The characteristics of American coals in relation to
their conversion into clean energy fuels; Appendix VIII-A: Representative
compositional data on full seam samples (PSOC-357 to PSOC-794). U. S.
Department of Energy; DOE report no. DOE/ET/10615-17 (App. 8A).
Spackman, W. (1982b) The characteristics of American coals in relation to
their conversion into clean energy fuels; Appendix VIII-B: Representative
compositional data on full seam samples (PSOC-798 to PSOC-1198). U. S.
Department of Energy; DOE report no. DOE/ET/10615-17 (App. 8B).
Spaite, P. W.; Devitt, T. W. (1979) Overview of pollution from combustion
of fossil fuels in boilers of the United States. Research Triangle Park, NC:
U. S. Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/7-79-233.
Stalling, J. H. E.; Call, S. J. (1984) Control of criteria and non-criteria
pollutants from coal/liquid mixture combustion. Research Triangle Park, NC:
U. S. Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/7-84-001.
Stephens, N. T.; Furr, A. K.; Thompson, C. R.; Charter, R. L. (1974) Trace
metals in effluents from coal-fired furnaces. Presented at: Fourth annual
environmental engineering and science conference; March; Louisville, KY.
Louisville, KY: University of Louisville; pp. 701-717.
Styron, C. E. (1977) Preliminary assessment of the impact of radionuclides
in western coal on health and environment. Miamisburg, OH: U. S. Department
of Energy, Mound Laboratory; DOE report no. MLM-2497(OP).
Styron, C. E. (1980) An assessment of natural radionuclides in the coal
fuel cycle. DOE Symp. Ser. 51; Nat. Radiat. Environ. Ill, vol. 2:
pp. 1511-1520.
Styron, C. E.; Robinson, B. (1978) A preliminary radiological impact
assessment of western coal utilization. In: Fourth joint conference on
sensing of environmental pollutants: conference proceedings; November 1977;
New Orleans, LA. Washington, DC: American Chemical Society; pp. 336-338.
Surprenant, N. (1976) Preliminary emissions assessment of conventional
stationary combustion systems; Vol. Ill: Update (12/75-6/76). Research
Triangle Park, NC: U. S. Environmental Protection Agency, Industrial
Environmental Research Laboratory; EPA report no. EPA-600/2-76-046c.
C-23
-------
Suprenant, N.; Hall, R.; Seale, L. M. (1976a) Preliminary emissions
assessment of conventional stationary combustion systems; Vol. I: Executive
summary. Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/2-76-046a.
Suprenant, N.; Hall, R.; Slater, S.; Susa, T.; Sussman, M.; Young, C.
(1976b) Preliminary emissions assessment of conventional stationary
combustion systems; Vol. II: Final report. Research Triangle Park, NC:
U. S. Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/2-76-046b.
Suprenant, N. F.; Hall, R. R.; McGregor, K. T.; Werner, A. S. (1979)
Emissions assessment of conventional stationary combustion systems; Vol. I:
Gas- and oil-fired residential heating. Research Triangle Park, NC: U. S.
Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/2-79-029b.
Suprenant, N. F.; Battye, W.; Roeck, D. ; Sandberg, S. M. (1980a) Emissions
assessment of conventional stationary combustion systems; Vol. V: Industrial
combustion sources. Draft report; EPA contract no. 68-02-2197. Research
Triangle Park, NC: U. S. Environmental Protection Agency, Industrial
Environmental Research Laboratory.
Suprenant, N. F.; Hung, P.; Li, R.; McGregor, K. T.; Piispanen, W.;
Sandberg, S. M. (1980b) Emissions assessment of conventional stationary
combustion systems; Vol. IV: Commercial/industrial combustion sources.
Draft report; EPA contract no. 68-02-2197. Research Triangle Park, NC:
U. S. Environmental Protection Agency, Industrial Environmental Research
Laboratory.
Suta, B. E. (1980) Human exposures to atmospheric arsenic. EPA contract
nos. 68-01-4314 and 68-02-2835. Research Triangle Park, NC: U. S.
Environmental Protection Agency, Office of Air Quality Planning and
Standards.
Swanson, V. E.; Medlin, J. H.; Hatch, J. R.; Coleman, S. L.;
Wood, G. H., Jr.; Woodruff, S. D.; Hildebrand, R. T. (1976) Collection,
chemical analysis and evaluation of coal samples in 1975. U. S. Department
of the Interior, Geological Survey; USGS report no. 76-468.
Tanner. R. L.; Meng, Z. (1984) Seasonal variations in ambient atmospheric
levels of formaldehyde and acetaldehyde. Environ. Sci. Technol. 18: 723-726.
Thoem, T. L. (1978) Coal fired power plant trace element study. In:
Nichols, D. G.; Rolinski, E. J.; Servais, R. A.; Theodore, L.; Buonicore,
A. J., eds. Energy and the environment: proceedings of the fifth national
conference; October/November 1977; Dayton, OH. Dayton, OH: American
Institute of Chemical Engineers, Dayton Section, pp. 223-229.
C-24
-------
Thomas, W. C. (1984) Analysis of hazardous air pollution emission rates
from Ohio coal-fired boilers. Draft final report; EPA contract
no. 68-01-6558. U. S. Environmental Protection Agency, Office of Policy and
Resource Management.
Torrey, S., ed. (1978) Trace contaminants from coal. Park Ridge, NJ:
Noyes Data Corporation.
Trace elements in coals and other fuels: all Toxic Materials Information
Center files merged; Part 1. (1975a) From: Toxic Materials Information
Center, Ecological and Environmental Sciences Section. Printout. Oak Ridge,
TN: U. S. Department of Energy, Oak Ridge National Laboratory.
Trace elements in coals and other fuels: all Toxic Materials Information
Center files merged; Part 2. (1975b) From: Toxic Materials Information
Center, Ecological and Environmental Sciences Section. Printout. Oak Ridge,
TN: U. S. Department of Energy, Oak Ridge National Laboratory.
Tyndall, M. F.; Kodras, F. D.; Puckett, J. K.; Symonds, R. A.; Yu, W. C.
(1978) Environmental assessment for residual oil utilization: second annual
report. Research Triangle Park, NC: U. S. Environmental Protection Agency,
Industrial Environmental Research Laboratory; EPA report no.
EPA-600/7-78-175.
U. S. Congress, Office of Technology Assessment (1980) The direct use of
coal: prospects and problems of production and combustion. Detroit, MI:
Grand River Books.
U. S. Department of Commerce (1979) Climatic atlas of the United States.
Asheville, NC; p. 74.
U. S. Environmental Protection Agency (1978) Low-sulfur western coal use in
existing small and intermediate size boilers. Research Triangle Park, NC;
EPA report no. 600/7-78-153a.
U. S. Environmental Protection Agency (1977) Preliminary evaluation of
sulfur variability in low-sulfur coals from selected mines. Research
Triangle Park, NC; EPA report no. EPA-450-3-77-044.
U. S. Environmental Protection Agency (1980a) Effect of physical coal
cleaning on sulfur content and variability. Research Triangle Park, NC;
EPA report no. EPA-600/7-80-107.
U. S. Environmental Protection Agency (1980b) POM source and ambient
concentration data: review and analysis. Washington, DC; EPA report
no. EPA-600/7-80-044.
U. S. Environmental Protection Agency (1982) AEROS manual series volume V:
AEROS manual of codes. Research Triangle Park, NC: National Air Data
Branch; EPA report no. EPA-450/2-76-005; OAQPS no. 1.2-042-5; p. 9-12.
C-25
-------
U. S. Environmental Protection Agency (1984) Radionuclides, background
information document for final rules, volume II. Washington, DC: Office of
Radiation Programs; EPA report no. EPA-520/1-84-022-2.
U. S. Environmental Protection Agency (1985) Control techniques for lead
air emissions from stationary sources - volume I, chapters 1-3. Preliminary
Draft. Research Triangle Park, NC; pp. 67-88.
U. S. National Committee for Geochemistry, Panel on the Trace Element
Geochemistry of Coal Resource Development Related to Health (1980) Trace-
element geochemistry of coal resource development related to environmental
quality and health. Washington, DC: National Academy Press.
Valkovic, V. (1978) Trace elements in petroleum. Tulsa, OK: PPG Books.
Valkovic, V. (1983a) Trace elements in coal; Vol. I. Boca Raton, FL:
CRC Press, Inc.
Valkovic, V. (1983b) Trace elements in coal; Vol. II. Boca Raton, FL:
CRC Press, Inc.
Vaughan, B. E.; Abel, K. H.; Cataldo, D. A.; Hales, J. M.; Hane, C. E.;
Rancitelli, L. A.; Routson, R. C.; Wildung, R. E.; Wolf, E. G. (1975)
Review of potential impact on health and environmental quality from metals
entering the environment as a result of coal utilization Richland, WA:
Battelle Pacific Northwest Labs; NTIS report no. PB-289658.
Vouk, V. B.; Piver, W. T. (1983) Metallic elements in fossil fuel
combustion products: amounts and form of emissions and evaluation of
carcinogenicity and mutagenicity. Environ. Health Perspect. 47: 201-225.
Wangen, L. E.; Dreesen, D. R. (1981) Environmental assessment of trace
elements from coal combustion in the semi-arid west. Progress summary report
for FY 1976-1979; DOE contract no. W-7405-ENG.36. Los Alamos, NM:
University of California, Los Alamos Scientific Laboratory; LA report
no. LA-8660-MS.
Wangen, L. E.; Wienke, C. L. (1976) A review of trace element studies
related to coal combustion in the four corners area of New Mexico. Los
Alamos, NM: University of California, Los Alamos Scientific Laboratory;
LA report no. LA-6401-MS.
Wangen, L. E.; Williams, M. D. (1978) Elemental deposition downwind of a
coal-fired power plant. Water, Air, Soil Pollut. 10: 33-44.
Waterland, L. R.; Lim, K. J.; Higginbotham, E. B.; Evans, R. M.; Mason, H. B.
(1982) Environmental assessment of stationary source NO control
technologies; project summary. Research Triangle Park, ^C: U. S.
Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/S7-82-034.
C-26
-------
Western, R. F., Inc. (1983) Characterization of particulate emissions from
refinery process heaters and boilers. Washington, DC: American Petroleum
Institute; API publication no. 4365.
White, D. M.; Edwards, L. 0.; Eklund, A. G.; DuBose, D. A.; Skinner, F. D.
(1984) Correlation of coal properties with environmental control technology
needs for sulfur and trace elements. Research Triangle Park, NC: U. S.
Environmental Protection Agency, Industrial Environmental Research Laboratory;
EPA report no. EPA-600/7-84-066.
Yen, J. T.; McCann, C. R.; Demeter, J. J.; Bienstock, D. (1976) Removal of
toxic trace elements from coal combustion effluent gas. Pittsburgh, PA:
Pittsburgh Energy Research Center; PERC report no. PERC/RI-76/5.
Yen, T. F. (1975) The role of trace metals in petroleum. Ann Arbor, MI:
Ann Arbor Science Publishers, Inc.
Zelenski, S. G.; Pangaro, N.; Hall-Enos, J. M. (1980) Inventory of organic
emissions from fossil fuel combustion for power generation. Palo Alto, CA:
Electric Power Research Institute; EPRI report no. EA-1394.
Zielke, R. L.; Bittman, R. M.; Flora, H. B. (1982) Field study to obtain
trace element mass balances at Kingston steam plant. Research Triangle Park,
NC: U. S. Environmental Protection Agency, Industrial Environmental Research
Laboratory; EPA report no. EPA-600/7-82-042.
Zoller, W. H.; Gladney, E. S.; Gordon, G. E.; Bors, J. J. (1974) Emissions
of trace elements from coal fired power plants. In: Hemphill, D. D., ed.
Trace substances in environmental health-VIII: proceedings of the 8th annual
conference; June; Columbia, MO. Columbia, MO: University of Missouri,
pp. 167-171.
C-27
-------
APPENDIX D
FUEL HEATING VALUES
The information presented in this appendix on fuel heating values is
intended to supplement the emission factors provided in Chapter 3.0 in the
calculation of trace emissions for a combustion source. Fuel heating values
are useful in calculating trace pollutant emissions when available emission
factors are expressed in terms of mass of emissions/mass of fuel burned
(e.g., Ib As/ton coal) and only the source's total energy input level
(10 Btu/yr) is known or when the emission factor is expressed in terms of
mass of emissions/unit heat energy input (Ib Ni/10 Btu) and only the total
quantity of fuel burned (tons/yr) is known. Heating content values are
provided in this appendix for coal and oil fuels.
Coal is a general term used to describe a wide range of materials that
are burned to produce heat, which in turn in some combustion sectors, is
used to generate energy. Four recognized classes containing a total of
13 component groups are used to classify different types of coal. The
parameters predominantly used to classify coals are:
- the amount of volatile matter contained in the coal;
- the amount of fixed carbon contained in the coal;
- the amount of inherent moisture contained in the coal; and
- the amount of oxygen contained in the coal.
The four coal classes and their component groups are presented in Table D-l
(Babcock and Wilcox, 1978; Singer, 1981). Typical heating values of
domestic coals are illustrated in Table D-2. Mean heating values, by coal
group, based on the data in Table D-2 are given below.
D-l
-------
TABLE D-l. CLASSIFICATION OF COALS
COAL CLASS
COMPONENT GROUPS
I. Anthracitic
II. Bituminous
III. Subbituminous
IV. Lignitic
1.
2.
3.
1.
2.
3.
4.
5.
1.
2.
3.
1.
2.
Met a- anthracite
Anthracite
Semianthracite
Low volatile bituminous
Medium volatile bituminous
High volatile A bituminous
High volatile B bituminous
High volatile C bituminous
Subbituminous A
Subbituminous B
Subbituminous C
Lignite A
Lignite B
Sources: Babcock and Wilcox (1978); Singer (1981)
D-2
-------
TABLE D-2. TYPICAL HEATING VALUES OF UNITED STATES' COALS
COAL CLASS
COMPONENT
GROUP
COAL
SOURCE
HEATING VALUE
Btu/lb
Anthracitic
V
OJ
Bituminous
Al
Al
A2
A2
A2
A2
A2
A2
A2
A3
A3
A3
A3
A3
Bl
Bl
Bl
Bl
Bl
PA
RI
PA
PA
PA
PA
PA
CO
NM
AR
VA
AR
PA
VA
AR
MD
OK
WV
WV
Group Average
Group Average
Group Average
Class Average
12,745
9,313
11,029
12,925
11,950
13,540
12,820
13,130
13,720
13,340
13,061
13,360
11,925
13,700
13,450
11,850
12,857
12,698
13,700
13,870
13,800
14,730
14,715
-------
TABLE D-2. TYPICAL HEATING VALUES OF UNITED STATES' COALS (Continued)
COAL CLASS
COMPONENT
GROUP
COAL
SOURCE
HEATING VALUE
Btu/lb
a
Bl
Bl
B2
B2
B2
B2
B2
B3
B3
B3
B3
B3
B3
B3
B3
B3
B3
B3
B3
B3
B3
B3
B3
PA
MD
PA
PA
VA
PA
AL
KY
KY
OH
PA
AL
CO
KS
KY
MO
NM
OH
OK
PA
TN
TX
UT
Group Average
Group Average
13,800
13,220
13,976
14,310
14,030
13,720
13,800
13,530
13,878
14,090
14,480
12,850
13,325
14,210
13,210
12,670
14,290
12,990
12,650
12,990
13,630
13,610
13,890
12,230
12,990
-------
TABLE D-2. TYPICAL HEATING VALUES OF UNITED STATES' COALS (Continued)
COAL CLASS
COMPONENT
GROUP
COAL
SOURCE
HEATING VALUE
Btu/lb
o
B3
B3
B3
B4
B4
B4
B4
B4
B4
B4
B4
B5
B5
B5
B5
B5
B5
VA
WA
WV
OH
IL
UT
IL
KY
MO
OH
WY
IL
IL
IL
IN
IA
MI
Group Average
Group Average
Group Average
Class Average
Subbituminous
SI
SI
MT
WA
14,510
12,610
14,350
13,451
13,150
11,910
12,600
12,130
12,080
11,300
12,160
12,960
12,286
11,340
10,550
11,480
11,420
10,720
11,860
11,228
13,077
11,140
10,330
Group Average
10,735
-------
TABLE D-2. TYPICAL HEATING VALUES OF UNITED STATES' COALS (Continued)
G
I
COMPONENT
COAL CLASS GROUP
S2
S2
S3
S3
Lignitic LI
LI
LI
LI
COAL
SOURCE
WY
WY
CO
WY
ND
ND
TX
ND
HEATING VALUE
Btu/lb
9,345
9,610
Group Average 9,478
8,580
8,320
Group Average 8,450
Class Average 9,554
7,255
7,210
7,350
6,960
Group Average 7,194
Al
A2
A3
Bl
B2
B3
B4
B5
SI
S2
S3
LI
= Meta-anthracite
= Anthracite
= Semianthracite
= Low volatile bituminous
= Medium volatile bituminous
= High volatile A bituminous
= High volatile B bituminous
= High volatile C bituminous
= Subbituminous A
= Subbituminous B
= Subbituminous C
= Lignite A
Source: Singer (1981); Parker (1981); Babcock and Wilcox (1978)
-------
Meta-anthracite: 11,029 Btu/lb
Anthracite: 13,061 Btu/lb
Semianthracite: 12,857 Btu/lb
Low volatile bituminous: 13,976 Btu/lb
Medium volatile bituminous: 13,878 Btu/lb
High volatile A bituminous: 13,451 Btu/lb
High volatile B bituminous: 12,286 Btu/lb
High volatile C bituminous: 11,228 Btu/lb
Subbituminous A: 10,735 Btu/lb
Subbituminous B: 9,478 Btu/lb
Subbituminous C: 8,450 Btu/lb
Lignite A: 7,194 Btu/lb
The mean heating value of each major class of coal, calculated from the data
in Table D-2, is as follows.
Anthracitic - 12,698 Btu/lb
Bituminous - 13,077 Btu/lb
Subbituminous - 9,554 Btu/lb
Lignitic - 7,194 Btu/lb (lignite A only)
More information on coal heating values, expressed by the geographical
source of the coal, is provided in Table D-3.
The heating value of coal, like the trace metal content, varies between
coal regions, between mines within a region, between seams within a mine,
and within a seam. The variability is minimal compared to that found with
trace metal levels, but nevertheless it may be important when attempting to
use fuel heat content as a factor in source emission calculations. Data
presented in Table D-4 illustrate coal heat content variability. Heat
content among coals from several different mines within a region appears to
exhibit greater variability than either variability within a mine or within
a seam. For the sample points in Table D-4, intermine variability averaged
15 percent, intramine variability 7 percent, and intraseam variability
D-7
-------
TABLE D-3. MEAN COAL HEATING VALUES BY GEOGRAPHIC REGION
REGION HEATING VALUE, Btu/lb
Northern Appalachia
Maryland 11,344
Pennsylvania 11,825
Ohio 10,909
Northern West Virginia 11,975
Central Appalachia
Eastern Kentucky 11,326
Virginia 11,802
Southern West Virginia 11,975
Central
Indiana 10,811
Illinois 10,710
Western Kentucky 11,326
Northwest (Powder River Basin)
Montana 8,987
Wyoming 9,169
Southwest
New Mexico 8,966
Source: U. S. National Committee for Geochemistry (1980) .
D-3
-------
TABLE D-4. EXAMPLES OF COAL HEAT CONTENT VARIABILITY
VO
Intermine
Variability
Intramine
Variability
Intraseam
Variability
COAL SOURCE
Eastern U. S.
Central U. S.
Western U. S.
Eastern U. S.
Central U. S.
Western U. S.
Eastern U. S.
Central U. S.
Western U. S.
COAL HEAT
MEAN
12,320
10,772
11,227
12,950
10,008
12,000
12,480
10,975
10,351
12,230
10,709
11,540
CONTENT, Btu/lb
STANDARD
RANGE DEVIATION
10,750 - 13,891 NAa
9,147 - 12,397 NA
9,317 - 13,134 NA
NA 624
9,182 - 10,834 NA
11,335 - 12,665 NA
NA 708
9,667 - 12,284 NA
9,791 - 10,911 NA
NA 371
10,304 - 11,113 NA
NA 291
PERCENT
VARIANCE ABOUT
THE MEAN
12.7
15
17
4.8
8.0
5.5
5.7
12.0
5.4
3.0
3.7
2.5
= Not Available.
Source: Pedco Environmental (1982); U. S. Environmental Protection Agency (1977);
U. S. Environmental Protection Agency (1978); U. S. Environmental Protection Agency (1980)
-------
3 percent. Since few combustion sources burn coal from just one seam or one
mine, coal heat content variability may significantly affect emissions
estimates that are being calculated using emission factors, coal use data,
and coal heat content data, even if the source gets all its coal from the
same area of the country.
The term fuel oil is conveniently applied to cover a wide range of
petroleum products, including crude petroleum, lighter petroleum fractions
such as kerosene, and heavier residual fractions left after distillation.
To provide standardization and a means for comparison, specifications have
been established that separate fuel oils into various grades. .Fuel oils are
graded according to specific gravity and viscosity, with No. 1 Grade being
the lightest and NoŤ 6 the heaviest. The heating value of fuel oils is
expressed in terms of Btu/gal of oil at 16°C (60°F) or Btu/lb of oil. The
heating value per gallon increases with specific gravity because there is
more weight per gallon. The heating value per pound of oil varies inversely
with specific gravity because lighter oil contains more hydrogen.
For an uncracked distillate or residual oil, heating value can be
approximated by the following equation.
Btu/lb = 17,660 + (69 x API gravity)
For a cracked distillate, the relationship becomes,
Btu/lb = 17,780 + (54 x API gravity).
Typical heating values of predominantly used fuel oils are presented in
Tables D-5 and D-6 through D-10. Tables D-6 to D-10 represent a summary of
an extensive assessment of fuel oils that has been conducted by the U. S.
Department of Energy's Bartlesville Energy Technology Center. Figure D-l
provides a key to the fuel oil regions as presented in Tables D-6 to D-10.
D-10
-------
TABLE D-5. TYPICAL HEATING VALUES OF FUEL OILS
No. 1
No. 2
FUEL OIL GRADES
No. 4
No. 5
No. 6
Type
Color
Heating Value"
Btu/gal
Btu/lb
Distillate
Light
137,000
19,670 - 19,860
Distillate
Amber
141,000
19,170 - 19,750
Very Light Residual Light Residual Residual
Black Black Black
146,000
18,280 - 19,400
148,000 150,000
18,100 - 19,020 17,410 - 18,900
The samples analyzed for Btu/gal and Btu/lb heating values are different; therefore, the heating
values presented do not directly correspond to one another.
Source: Babcock and Wilcox (1978); Singer (1981).
-------
TABLE D-6. TYPICAL HEATING VALUES FOR OILS CONSUMED IN THE EASTERN REGION3
0
H
No.
No.
No.
No.
No.
No.
FUEL OIL GRADE
1
2
4
5 (light)
5 (heavy)
6
NUMBER OF SAMPLES
ANALYZED
33
56
1
1
0
17
HEATING VALUE, Btu/gal
RANGE MEAN
132,500 - 135,700 134,200
133,100 - 146,600 139,500
146,000
148,400
_
147,000 - 157,600 151,900
K>
a
See Figure D-l for key to the regions.
Source: Shelton (1982).
-------
TABLE D-7. TYPICAL HEATING VALUES FOR OILS CONSUMED IN THE SOUTHERN REGION'
No
No
No
No
No
0 No
FUEL OIL GRADE
. 1
. 2
. 4
. 5 (light)
. 5 (heavy)
. 6
NUMBER OF SAMPLES
ANALYZED
13
19
0
0
0
14
HEATING VALUE, Btu/gal
RANGE MEAN
132,900 - 135,400 134,300
136,400 - 141,500 139,400
146,000
148,400
-
150,500 - 156,500 152,900
See Figure D-l for key to the regions.
Source: Shelton (1982).
-------
TABLE D-8. TYPICAL HEATING VALUES FOR OILS CONSUMED IN THE CENTRAL REGION3
FUEL OIL GRADE
I
M
4N
No.
No.
No.
Ho.
No.
No.
1
2
4
5 (light)
5 (heavy)
6
NUMBER OF SAMPLES
ANALYZED
27
35
2
4
0
10
HEATING VALUE, Btu/gal
RANGE MEAN
132,500 - 135,700 134,000
135,900 - 146,600 139,200
146,000 - 150,100 148,050
148,400 - 151,500 149,900
_
150,600 - 158,900 152,900
Q
See Figure D-l for key to the regions.
Source: Shelton (1982).
-------
TABLE D-9. TYPICAL HEATING VALUES FOR OILS CONSUMED IN THE ROCKY MOUNTAIN REGION'
O
M
tn
FUEL OIL GRADE
No.
No.
No.
No.
No.
No.
1
2
4
5 (light)
5 (heavy)
6
NUMBER OF SAMPLES
ANALYZED
14
17
2
2
1
7
HEATING VALUE, Btu/gal
RANGE MEAN
133,100 - 135,100 134,200
136,100 - 140,400 139,000
150,100 - 150,500 150,300
153,900 - 156,500 155,200
150,000
151,900 - 159,200 154,600
See Figure D-l for key to the regions.
Source: Shelton (1982).
-------
TABLE D-10. TYPICAL HEATING VALUES FOR OILS CONSUMED IN THE WESTERN REGION3
No.
No.
No.
No.
No.
No.
FUEL OIL GRADE
1
2
4
5 (light)
5 (heavy)
6
NUMBER OF SAMPLES
ANALYZED
16
' 18
0
0
1
12
HEATING VALUE, Btu/gal
RANGE MEAN
131,700 - 136,200 134,600
136,100 - 140,500 139,000
-
_
152,100
149,900 - 163,500 154,400
-j
See Figure D-l for key to the regions.
Source: Shelton (1982).
-------
CENTRAL .J REGION
Figure D-l. Key to the fuel oil regions in Tables D-6 to D-10.
-------
APPENDIX E
EMISSION FACTORS MEASURED AT INDIVIDUAL COAL-FIRED BOILERS
This Appendix summarizes the data base for measured emission factors
from coal-fired boilers. It was compiled from a review of the literature
included in the bibliography (Appendix C). The summary tables are organized
by pollutant. The tables for the eight trace metals, arranged in
alphabetical order, are first. Tables for radionuclides are next, followed
by tables for POM. Within each pollutant, tables are organized by combustion
sector, coal type, and boiler design. Each table lists the average measured
emission factor for each boiler tested. The range of emission factors
measured at each boiler is also listed if results of more than one test run
were reported. For each test, the tables also list the control status of the
boiler, and the reference for the information. Data contained in Appendix E
are summarized in Section 3.7 of this report.
E-l
-------
TABLE E-l. MEASURED ARSENIC EMISSION FACTORS FOR UTILITY,
BITUMINOUS COAL, PULVERIZED DRY BOTTOM BOILERS
Emission Factor
db/1012 BttO
a
Mean Range
48.8
30.2
3.95
26b
138C 62-242
886C 792-924
54
61
43
820
910
500
68
70
110
430
330
140
620
310
1360
9.4
14 . 9
1274f 890-1980
192f 17-290
Control Status
Mech. Ppt/ESP
Mech. Ppt/ESP
Wet Scrubber
ESP
ESP
Uncontrolled
ESPd
ESP6
ESP6
Uncontrolled
Uncontrolled
Uncontrolled
Low Effic. ESP8
Low Effic. ESP6
Low Effic. ESP6
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
ESP
ESP/Scrubber
Mech. Ppt.
Mech. Ppt/lst ESP
in Series of 2
Reference
Shih et al. . 1980b
Shih et al. , 1980b
Shih et al. . 1980b
Baig et al . . 1981
Evers et al . . 1980
Evers e_t al . . 1980
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Higginbotham and Goldberg
Higginbotham and Goldberg
Higginbotham and Goldberg
Higginbotham and Goldberg
Higginbotham and Goldberg
Higginbotham and Goldberg
Higginbotham and Goldberg
Higginbotham and Goldberg
Scinto e_t al . . 1981
Scinto et al. . 1981
Scinto et al. . 1981
Zielke and Bittman, 1982
Zielke and Bittman, 1982
1981a
1981a
1981a
1981a
1981a
1981a
, 1981
, 1981
, 1981
, 1981
, 1981
, 1981
, 1981
, 1981
E-2
-------
TABLE E-l. MEASURED ARSENIC EMISSION FACTORS FOR UTILITY, BITUMINOUS
COAL, PULVERIZED DRY BOTTOM BOILERS (Continued)
Emission Factor
(lb/1012 Btu)
Mean
Range
Control Status
Reference
6.16
31.4
12.2
21.4
0.46*
64*
32h
<0.29-13.2
8.19-24.6
0.35-0.51
13.4-35.51
62-66
19-49
Mech. Ppt/2 ESPs
in Series
Venturi Scrubber
Venturi Scrubber
Venturi Scrubber
ESP
ESP
Uncontrolled
Mech. Ppt.
Zielke and Bittman, 1982
Ondov et al.. 1979a
Ondov et al.. 1979a
Ondov et al.. 1979a
Ondov et al.. 1979b
Ondov et al.. 1979b
Cowherd et al.. 1975
Cowherd et al.. 1975
This column gives arithmetic mean values for each boiler tested. Footnotes
indicate how many measurements each mean represents, if this information was
included in the reference. If only a single measurement was reported, it is
included in this column.
Average of tests of six different boilers.
Q
Average of eight tests of the same boiler.
Boiler operating under baseline (design) conditions.
Boiler operating under low-NO conditions - certain burners admit only air
rather than fuel, or different fuel/air ratios are admitted than under
design operating conditions.
Average of seven tests of the same boiler.
SAverage of five tests of the same boiler.
Average of three tests of the same boiler.
Range for six tests of the same boiler.
E-3
-------
TABLE E-2. MEASURED ARSENIC EMISSION FACTORS FOR UTILITY PULVERIZED
WET BOTTOM BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu) Control Status
15.3 Mech. Ppt/ESP
44.2 ESP
44.2 ESP
76.7 Venturi Scrubber
165 ESP
572 ESP
Reference
Shih,
Shih,
Shih,
Shih,
Shih,
Shih,
et al. .
et al. .
et al. .
et aj^,
et al,.,
e_t al. .
1980b
1980b
1980b
1980b
1980b
1980b
E-4
-------
TABLE E-3. MEASURED ARSENIC EMISSION FACTORS FOR UTILITY
CYCLONE BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Mean Range
813
6.3
11.4
27.9
12 . 8
310b 130-490
13. 5b 12-15
Control Status
Wet Scrubber
ESP
ESP
ESP
ESP
Uncontrolled
High Efficiency ESP
Reference
Shih,
Shih,
Shih,
Shih,
Shih,
Klein
Lyon,
Klein
Lyon,
et al^,
et al^,
et al,.,
eŁ al^,
et al^,
, et al^.,
1977
, et a]^,
1977
1980b
1980b
1980b
1980b
1980b
1975b;
1975b;
This column gives the arithmetic mean values for each boiler tested.
Footnotes indicate how many measurements each mean represents, if this
information was included in the reference. If only a single measurement was
reported, it is included in this column.
Averge of two tests of the same boiler.
E-5
-------
TABLE E-4. MEASURED ARSENIC EMISSION FACTORS FOR UTILITY
STOKER BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
0.77
5580
432
Control Status Reference
Fabric Filter Shih, et al. . 1980b
Mechanical Ppt. Shih, et al. . 1980b
Multiclone Shih, et al. . 1980b
TABLE E-5. MEASURED ARSENIC EMISSION FACTORS FOR UTILITY
BOILERS FIRED WITH SUBBITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Boiler Type
Control Status
Reference
860
810
11
0.17
2.4
10
Cyclone
Cyclone
Pulverized
Pulverized
NRa
NR
Uncontrolled
FGD Scrubber
Venturi Scrubber
ESP (hot side)
ESP (cold side)
ESP (hot side)
Leavitt, et al.. 1979
Leavitt, et al.. 1979
Radian, 1975a
Radian, 1975a
Mann, et al.. 1978
Mann, et al.. 1978
aNR - not reported.
E-6
-------
TABLE E-6. MEASURED ARSENIC EMISSION FACTORS FOR
UTILITY BOILERS FIRED WITH LIGNITE COAL
Emission Factor
(lb/1012 Btu)
Boiler Type
Control
Status
Reference
397
367
<2.3
5.8
11.2
270
265
<5.3
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
Cyclone
Spreader Stoker
Spreader Stoker
Multiclone
Multiclone
ESP
ESP
ESP/Wet
Scrubbers
Multiclone
Multiclone
ESP
Shih et al.. 1980b
Shih. et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Schock et al.. 1979
Radian, 1975a
Shih et al.. 1980b
Shih et al.. 1980b
E-7
-------
TABLE E-7. MEASURED ARSENIC EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
Mean
29b
15.8
7900
214
Range Boiler Type
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Control Status
ESP
ESP
Multiclone
Multiclone/Scrubber
Reference
Baie et al.. 1981
Suprenant et al.. 1980a
Leavitt et al. , 1978b;
Fischer ejt al. . 1979
Leavitt et al.. 1978b;
690
w
00
120
32.5
53.7
102
853
0.32C
81e
835
59l
70°
190C
350
1300
0.27-0.37
60-93
35-83
65-74
120-260
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Overfeed Stoker
Overfeed Stoker
Uncontrolled
ESP
Multiclone
Multiclone/ESP
Multiclone
Multiclone
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
_
Fischer e_t al. . 1979
McCurley et. al. . 1979
McCurley et. al.. 1979
Suprenant et al.. 1980a
Suprenant e_t. al.. 1980a
Suprenant et al.. 1980a
Suprenant et al.. 1980a
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et. &!_.ť 1981
Burlingame et. al.. 1981
Burlingame et al.. 1981
Burlingame e_t al. . 1981
Burlingame et al.. 1981
-------
TABLE E-7. MEASURED ARSENIC EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS (Continued)
Emission Factor
(lb/1012 Btu)
w
VO
Meana
2400C
60
395C
740
35
490
31
Range Boiler Type
2200-2600 Overfeed Stoker
Overfeed Stoker
370-420 Overfeed Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Control Status
Uncontrolled
Uncontrolled
Economizer, Dust Collector
Uncontrolled
Mechanical Ppt/ESPf
Uncontrolled^
Mechanical Ppt/ESPg
Reference
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al. . 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
This column gives arithmetic mean values for each boiler tested. Footnotes indicate how many measurements each
mean represents, if this information was included in the reference. If only a single measurement was reported, it
is included in this column.
Average for three boilers.
Average of two tests of the same boiler.
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of control device.
6Average of three tests of the same boiler.
Boiler operated under baseline (design) conditions.
^Boiler operated with low excess air level for NO control.
-------
TABLE E-8. MEASURED ARSENIC EMISSION FACTORS FOR SUBBXTUMINOUS COAL-FIRED INDUSTRIAL BOILERS
RJ
I-1
O
Emission Factor
(lb/10
Mean
340b
120
3.0
68
5.8
12 Btu)
Range Boiler
190-490 Spreader
Spreader
Spreader
Spreader
Spreader
Type
Stoker
Stoker
Stoker
Stoker
Stoker
Control Status
c
Uncontrolled
Uncontrolled
Mechanical Ppt/ESPd
Uncontrolled
Mechanical Ppt/ESPe
Reference
Burlingame et al . . 1981
Goldberg
Goldberg
Goldberg
Goldberg
and Higginbotham,
and Higginbotham,
and Higginbotham,
and Higginbotham,
1981
1981
1981
1981
This column gives arithmetic mean values for each boiler tested. Footnotes indicate how many measurements each
mean represents, if this information was included in the reference,, If only a single measurement was reported, it
is included in this column.
Mean of two tests of the same boiler.
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of controls.
Tested while operating under baseline (design) conditions.
6Tested while operating under low-NO operating conditions - overfire air rate set at maximum level.
-------
TABLE E-9. MEASURED ARSENIC EMISSION FACTORS FOR COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Emission Factor
(lb/1012 Btu)
Type of Coal
Boiler Type
Control Status
Reference
w
4470
51.1
4.2
11.6
25.6
5.3
235
170
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Anthracite
Anthracite
Anthracite
Pulverized Dry Bottom
Pulverized Dry Bottom
Underfeed Stoker
Spreader Stoker
Overfeed Stoker
Stoker
Stoker
Stoker
Uncontrolled
Multiclone/Scrubher
Uncontrolled
Mechanical Ppt.
Mechanical Ppt.
Uncontrolled
Uncontrolled
Uncontrolled
Suprenant et al.. 1980b
Suprenant e_t al. . 1980b
Suprenant et al.. 1980b
Suprenant et al.. 1980b
Suprenant e_t al. . 1980b
Suprenant et al. . 1980b
Suprenant et al., 1980b
Suprenant e_t al.. 1980b
-------
TABLE E-10. MEASURED ARSENIC EMISSION FACTORS FOR COAL-FIRED RESIDENTIAL FURNACES
Emission Factor
(lb/1012 Btu)
31.0
77.5
2400b
ŤŤŤ
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous-washed
Furnace Type
N.R.a
N.R
Warm Air Furnace
with Stoker
Warm Air Furnace
with Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Reference
DeAngelis and Reznik,
DeAngelis and Reznik,
DeAngelis, 1979
DeAngelis, 1979
1979
1979
b
a
N.R. = not reported.
Average of two tests of the same boiler.
°Average of two tests of the same boiler. Both were less than the detection limit of 445 lb/101Z Btu.
12
-------
TABLE E-ll. MEASURED BERYLLIUM EMISSION FACTORS FOR UTILITY PULVERIZED
DRY BOTTOM BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
Qb/1012 Btu}
a
Mean Range
0.11
0.44
<0 . 11
0.60b
0.89° 0.62-1.89
102° 92-114
14
12
9.5
140
140
100
21
31
32
42
45
41
154f 141-171
Control Status
Wet Scrubber
Mech. Ppt/ESP
Mech. Ppt/ESP
ESP
ESP
Uncontrolled
ESPd
ESP6
ESPS
Uncontrolled
6
Uncontrolled
Uncontrolled
Low Effic. ESPd
Low Effic. ESP6
Low Effic. ESPŽ
Uncontrolled
Uncontrolled
6
Uncontrolled
Mech. Ppt.
Reference
Shih et al. , 1980b
Shih et al. , 1980b
Shih et al. , 1980b
Baig et al. , 1981
Evers et al. , 1980
Evers. e_t al. , 1980
Sawyer and Higginbotham, 19 8 la
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Zielke and Bittman, 1982
E-13
-------
TABLE E-ll. MEASURED BERYLLIUM EMISSION FACTORS FOR UTILITY PULVERIZED
DRY BOTTOM BOILERS FIRED WITH BITUMINOUS COAL (Continued)
Emission Factor
Clb/1012 Btu)
Mean
Range
Control Status
Reference
19.4
18.1-22.1
Mech. Ppt/lst ESP
in series of 2
Zielke and Bittman, 1982
0.082s 0.007-0.209
0.97-1.7h
521 44-59
331 26-38
Mech. Ppt/2 ESPs
in series
ESP
Uncontrolled
Mechanical Ppt.
Zieklke and Bittman, 1982
Ondov et a]
Cowherd et
Cowherd et
L.,
al.
al.
1979b
, 1975
, 1975
This column gives arithmetic mean values for each boiler tested. Footnotes
indicate how many measurements each mean represents, if this information
was included in the reference. If only a single measurement was reported,
it is included in this column.
Average of tests of six different boilers.
Q
Average of eight tests of the same boiler.
Boiler operating under baseline (design) conditions.
Boiler operating under low-NO conditions - certain burners admit only air
rather than fuel, or different fuel/air ratios are admitted than under
design operating conditions.
Average of seven tests of the same boiler.
"Average of five tests of the same boiler.
K.ange for three tests of the same boiler.
Average of three tests of the same boiler.
E-14
-------
TABLE E-12. MEASURED BERYLLIUM EMISSION FACTORS FOR UTILITY PULVERIZED
WET BOTTOM BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Control Status
Reference
0.88
1.7
1.0
0.086
3.7
10.2
Mechanical Ppt/ESP
ESP
ESP
Venturi Wet Scrubber
ESP
ESP
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
E-15
-------
TABLE E-13. MEASURED BERYLLIUM EMISSION FACTORS FOR UTILITY
CYCLONE BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
0.86
0.60
1.05
0.19
0.23
Control Status
Wet Scrubber
ESP
ESP
ESP
ESP
Reference
Shih
Shih
Shih
Shih
Shih
et al. .
et al. .
et al. .
et al. .
et al,.,
1980b
1980b
1980b
1980b
1980b
TABLE E-14. MEASURED BERYLLIUM EMISSION FACTORS FOR UTILITY
STOKER BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
12
(lb/10 Btu) Control Status Reference
0.13 Fabric Filter Shih e_t al. . 1980b
5.6 Mechanical Ppt Shih et al^, 1980b
20.0 Multiclone Shih et al.. 1980b
E-16
-------
TABLE E-15. MEASURED BERYLLIUM EMISSION FACTORS FOR UTILITY
BOILERS FIRING SUBBITUMINOUS COAL
Emission Factor
(lb/1012 Btu) Boiler Type
Control Status
Reference
18.0
1.6
0.60
1.0
0.38
0.88
Cyclone
Cyclone
Pulverized
Pulverized
Unspecified
Unspecified
Uncontrolled
Venturi Scrubber
Venturi Scrubber
ESP (hot side)
ESP (cold side)
ESP (hot side)
Leavitt et al.. 1979
Leavitt et al.. 1979
Radian 1975a
Radian 1975a
Mann et al.. 1978
Mann et al.. 1978
TABLE E-16. MEASURED BERYLLIUM EMISSION FACTORS FOR
UTILITY BOILERS FIRING LIGNITE COAL
Emission Factor
(lb/1012 Btu)
Boiler Type
Control
Status
Reference
2.3
2.6
<2.3
0.70
6.8
13.7
0.26
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
Spreader Stoker
Spreader Stoker
Multiclone
Multiclone
ESP
ESP
Cyclone
Multiclone
ESP
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Radian 1975a
Shih et al.. 1980b
Shih et al.. 1980b
E-17
-------
TABLE E-17. MEASURED BERYLLIUM EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
Mean
Range
Boiler Type
Control Status
Reference
w
H>
00
1.1"
0.19
2.3
93
15C
2C
0.21
4.0
3.3
12.1
1.8C
38.3e
65
c
15C
0.30-3.2
11-72
4.2-8.8
8.1-2.2
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
ESP
ESP
Multiclone/Scrubber
Multiclone
Uncontrolled
ESP
Multiclone
Multiclone/ESP
Multiclone
Multiclone
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
d
Baig et al.. 1981
Suprenant et al.. 1980a
Leavitt et^ al. . 1978b;
Fischer 1979
Leavitt e_t aJL_, 1978b;
Fischer et al.. 1979
McCurley e_t al.. 1979
McCurley e_t aK_, 1979
Suprenant e_t al. . 1980a
Suprenant e_t a_l_. , 1980a
Suprenant et al.. 1980a
Suprenant e_t al. . 1980a
Burlingame et aK_, 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et. al. . 1981
-------
Emission Factor
(lb/1012 Btu)
Meana
7.2C
7.0
39
16. 5C
3.9
4.3C
w 780
^ 120
430
0.20
Range Boiler Type
6.7-7.6 Spreader Stoker
Overfeed Stoker
Overfeed Stoker
14-19 Overfeed Stoker
Overfeed Stoker
3.7-4.9 Overfeed Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Economizer, Dust
Collector
Uncontrolled
Mechanical Ppt/ESP
Un control led*
Mechanical Ppt/ESP8
Reference
Burlingame et al . . 1981
Burlingame e_t al. . 1981
Burlingame et al. . 1981
Burlingame et al., 1981
Burlingame et al., 1981
Burlingame et al., 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Q
each mean represents, if this information was included in the reference. If only a single measurement was
reported, it is included in this column.
Average of tests of three different boilers.
Average of two tests of the same boiler.
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of control device,
6Average of three tests of the same boiler.
Boiler operating under baseline (design) conditions.
^Boiler operating with low excess air level for NO control.
-------
TABLE E-18. MEASURED BERYLLIUM EMISSION FACTORS FOR SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
Mean3
51b
57
3.3
6.2
0.77
Range Boiler Type
32-70 Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Control Status
Uncontrolled
Uncontrolled
Mechanical Ppt/ESPd
Uncontrolled
Mechanical Ppt/ESPe
Reference
Burlingame et al. . 1981
Goldberg and
Goldberg and
Goldberg and
Goldberg and
Higgenbotham, 1981
Higgenbotham, 1981
Higgenbotham, 1981
Higgenbotham, 1981
(VJ
° SThis column gives arithmetic mean values for each boiler tested. Footnotes indicated how many measurements
each mean represents, if this information was included in the reference. If only a single measurement was
reported, it is included in this column.
Mean of two tests of the same boiler.
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of controls.
Tested while operating under baseline (design) conditions.
A
Tested while operating under low-NO operating conditions - overfire air rate set at maximum level.
-------
TABLE E-19. MEASURED BERYLLIUM EMISSION FACTORS FOR COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Emission Factor
(lb/1012 Btu)
Coal Type
Boiler Type
Control Status
Reference
w
i
307.0
0.95
7.9
0.77
21.8
10.7
0.93
Bituminous
Bituminous
Bituminous
Bituminous
Anthracite
Anthracite
Anthracite
Pulverized Dry Bottom
Pulverized Dry Bottom
Spreader Stoker
Overfeed Stoker
Stoker
Stoker
Stoker
Uncontrolled
Multiclone/Scrubber
Mechanical Ppt.
Mechanical Ppt.
Uncontrolled
Uncontrolled
Uncontrolled
Suprenant et al.. 1980b
Suprenant et al.. 1980b
Suprenant et al.. 1980b
Suprenant e_t al, . 1980b
Suprenant e_t_ al. . 1,980b
Suprenant et al.. 1980b
Suprenant et al.. 1980b
-------
TABLE E-20. MEASURED CADMIUM EMISSION FACTORS FOR PULVERIZED DRY
BOTTOM UTILITY BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu1)
Mean Range
2.6b
1.2
1.9
1.4
26.5° 11.4-52.8
137C 114-167
6.6
9.8
3.8
41
12
11
4.5
7.1
10
9.2
10-14
<4 . 6
<4 . 6
Control Status
ESP
Wet Scrubber
Mechanical Ppt/ESP
Mechanical Ppt/ESP
ESP
Uncontrolled
ESPd
ESPe
ESP6
Uncontrolled
Uncontrolled
Uncontrolled
Low Effic. ESPd
Low Effic. ESP6
Uncontrolled
Uncontrolled
Uncontrolled
ESP
ESP/Scrubber
Reference
Baig et al. . 1981
Shih et al. . 1980b
Shih et al. . 1980b
Shih et al. . 1980b
Evers et al. . 1980
Evers et al. . 1980
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Scinto et al. . 1981
Scinto et al . . 1981
Scinto et al. . 1981
E-22
-------
TABLE E-20.
MEASURED CADMIUM EMISSION FACTORS FOR PULVERIZED DRY BOTTOM
UTILITY BOILERS FIRED WITH BITUMINOUS COAL (Continued)
Emission Factor
(lb/1012 Btu)
Mean
1.95
42
Range
Control Status
Reference
291f
46
136-487 Mechanical Ppt.
Mech. Ppt/2 ESPs
Zielke and Bittman, 1982
Zielke and Bittman, 1982
in Series
Venturi Scrubber
0.22-0.6s ESP
15-56 Mechanical Ppt.
24-74
Uncontrolled
Ondov e_t al. . 1979a;
Hobbs et al.. 1983
Ondov et al.. 1979b
Cowherd et al.. 1975
Cowherd et al.. 1975
This column gives arithmetic mean values for each boiler tested. Footnotes
indicate how many measurements each mean represents , if this information
was included in the reference. If only a single value was reported, it is
included in this column.
Average of tests of six boilers.
Q
Average of eight tests of the same boiler.
Tested while boiler was operating under baseline (design) conditions.
Tested while boiler was operating under low-NO conditions - certain
burners admit air rather than fuel, or different fuel/air ratios are
admitted than under design operating conditions.
Average of seven tests of the same boiler.
for four tests of the same boiler.
'Average of three tests of the same boiler.
E-23
-------
TABLE E-21. MEASURED CADMIUM EMISSION FACTORS FOR UTILITY PULVERIZED
WET BOTTOM BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Control Status
Reference
1.9
0.56
0.63
0.086
1.4
2.6
Mechanical Ppt/ESP
ESP
ESP
Venturi Scrubber
ESP
ESP
Shih et al. .
Shih et al. .
Shih et al. .
Shih et al. .
Shih et al. .
Shih et al. ,
1980b
1980b
1980b
1980b
1980b
1980b
E-24
-------
TABLE E-22. MEASURED CADMIUM EMISSION FACTORS FOR UTILITY
CYCLONE BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
Clb/1012 Btu1)
Mean Range
488
3.0
1.1
0.35
1.1
28. 5b 22-35
0.8b 0.7-0.9
Control Status
Wet Scrubber
ESP
ESP
ESP
ESP
Uncontrolled
ESP
Reference
Shih et al. .
Shih et al. .
Shih et al. .
Shih et al. .
Shih et al. .
Klein et al. .
Klein et al . .
1980b
1980b
1980b
1980b
1980b
1975b; Lyon, 1977
1975b; Lyon, 1977
aThis column gives the arithmetic mean values for each boiler tested.
Footnotes indicate how many measurements each mean represents, if this
information was included in the reference. If only a single value was
reported, it is included in this column.
Average of two tests of the same boiler.
E-25
-------
TABLE E-23. MEASURED CADMIUM EMISSION FACTORS FOR UTILITY
STOKER BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Control Status
Reference
0.33
4.2
22.1
Fabric Filter
Mechanical Ppt.
Multiclone
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
TABLE E-24. MEASURED CADMIUM EMISSION FACTORS FOR UTILITY
BOILERS FIRED WITH SUBBITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Boiler Type
Control Status
Reference
4400
490
4.0
<0.40
0.39
1.7
Cyclone
Cyclone
Pulverized
Pulverized
NR
NR
Uncontrolled
Scrubber
Venturi Scrubber
ESP (hot side)
ESP (cold side)
ESP (hot side)
Leavitt et al.. 1979
Leavitt et al.. 1979
Radian, 1975a
Radian, 1975a
Mann et al.. 1978
Mann et al.. 1978
NR - not reported.
E-26
-------
TABLE E-25. MEASURED CADMIUM EMISSION FACTORS FOR
UTILITY BOILERS FIRED WITH LIGNITE COAL
Emission Factor
db/1012 Btu)
Mean
25.6
5.1
<3.5
1.2
16
30. 6b
5.3
1.9
Range Boiler Type
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
1.8-59 Cyclone
Spreader Stoker
Spreader Stoker
Control Status
Multiclone
Multiclone
ESP
ESP
Cyclone
ESP/Scrubbers
Multiclone
ESP
Reference
Shih et al. .
Shih et al. .
Shih et al. .
Shih et al. .
Radian, 1975a
Schock et al.
Shih et al. .
Shih et al. .
1980b
1980b
1980b
1980b
, 1979
19 8 Ob
1980b
This column gives arithmetic mean values for each boiler tested. Footnotes
indicate how many measurements each mean represents, if this information
was included in the reference. If only one value was reported, it is
included in this column.
Average of two tests of the same boiler.
E-27
-------
TABLE E-26. MEASURED CADMIUM EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
Mean
Range
Boiler Type
Control Status
Reference
PI
oo
20
0.49
465
0.98
290
39
1.5
0.009
0.19
0.93
c
20
35
4.8
e
8.7'
c
22
45C
4.1-5.6
16-23
7.4-10
20-25
25-65
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
ESP
ESP
Multiclone
Multiclone/Scrubher
Uncontrolled
ESP
Multiclone
Multiclone/ESP
Multiclone
Multiclone
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Baig e_t. al. . 1981
Suprenant et al.. 1980a
Leavitt et al.. 1978b;
Fischer et al.. 1979
Leavitt et al.. 1978b;
Fischer e_t al. . 1979
McCurley e_t al. . 1979
McCurley et. al. . 1979
Suprenant e_t. &!_._, 1980a
Suprenant et al.. 1980a
Suprenant et al.. 1980a
Suprenant et al.. 1980a
Burlingame et. al_.. 1981
Burlingame et. al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
-------
Emission Factor
(lb/1012 Btu)
w
N>
Mean
37
12
180C
100
56C
13
1.3
11
4.2
Range Boiler Type
Overfeed Stoker
Overfeed Stoker
60-300 Overfeed Stoker
Overfeed Stoker
44-67 Overfeed Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Economizer/Dust Collector
Uncontrolled
ESPf
Uncontrolled**
ESPg
Reference
Bur 1 ing am e et al . . 1981
Burl in game et al. . 1981
Burlingame et al . . 1981
Burlineame et al., 1981
Burlineame et al., 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
This column gives arithmetic mean values for each boiler tested. Footnotes indicate how many measurements each
mean represents, if this information was included in the reference. If only a single measurement was reported, it
is included in this column.
Average of three boilers.
^
Average of two tests of the same boilers.
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of control device.
eAverage of three tests of the same boiler.
Boiler operated under baseline (design) conditions.
^Boiler operated with low excess air level for NO control.
-------
TABLE E-27. MEASURED CADMIUM EMISSION FACTORS FOR SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
w
I
Emission Factor
(lb/1012 Btu)
Mean
14b
78
5.7
290
14
Range Boiler
4.9-23 Spreader
Spreader
Spreader
Spreader
Spreader
Type
Stoker
Stoker
Stoker
Stoker
Stoker
Control Status
Uncontrolled
Uncontrolled
Mechanical
Ppt/ESPd
Uncontrolled6
Mechanical
Ppt/ESPe
Reference
Burlingame et al., 1981
Goldberg
Goldberg
Goldberg
Goldberg
and
and
and
and
Higginbotham,
Higginbotham,
Higginbotham,
Higginbotham,
1981
1981
1981
1981
This column gives arithmetic mean values for each boiler tested. Footnotes indicate how many measurements each
mean represents, if this information was included in the reference. If only a single measurement was reported,
it is included in this column.
Mean of two tests of the same boiler.
**
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of controls.
Tested while operating under baseline (design) conditions.
6
Tested while operating under low-NO operating conditions - overfire air rate set at maximum level.
A
-------
TABLE E-28. MEASURED CADMIUM EMISSION FACTORS FOR COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Emission Factor
12
(lb/10 Btu) Type of Coal Boiler Type Control Status Reference
12.8 Bituminous Pulverized Dry Bottom Uncontrolled Suprenant et al.. 1980b
0.35 Bituminous Pulverized Dry Bottom Multiclone/Scrubber Suprenant et al.. 1980b
5.6 Bituminous Spreader Stoker Mechanical Ppt. Suprenant et al.. 1980b
1.2 Bituminous Overfeed Stoker Mechanical Ppt. Suprenant et al.. 1980b
2.3 Anthracite Stoker Uncontrolled Suprenant et al.. 1980b
M 3.5 Anthracite Stoker Uncontrolled Suprenant et al.. 1980b
i
CO
M 1.4 Anthracite Stoker Uncontrolled Suprenant e_t al.., 1980b
-------
TABLE E-29. MEASURED CADMIUM EMISSION FACTORS FOR COAL-FIRED RESIDENTIAL FURNACES
Co
NJ
Emission Factor
(lb/1012 Btu) Coal Type
155 Bituminous
31 Bituminous
8.9 Bituminous
c
<44.5 Bituminous-washed
Furnace Type Control Status
NRa Uncontrolled
NR Uncontrolled
Warm Air Furnace Uncontrolled
with Stoker
Warm Air Furnace Uncontrolled
with Stoker
Reference
DeAngelis and Reznik,
DeAngelis and Reznik,
DeAngelis, 1979
DeAngelis, 1979
1979
1979
NR = not reported.
12
Average of two tests of the same boiler. Both were less than the detection limit of 44.5 lb/10 Btu
-------
TABLE E-30. MEASURED CHROMIUM EMISSION FACTORS FOR PULVERIZED DRY
BOTTOM UTILITY BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Mean
Range
Control Status
Reference
3000 ' --- ESP
12.3 --- Wet Scrubber
7970b --- Mechanical Ppt/ESP
3930b --- Mechanical Ppt/ESP
7900 --- Uncontrolled
3700 --- ESPd
2300 .--- Uncontrolled6
380 --- Uncontrolled6
2400 --- Uncontrolled
2800 --- Uncontrolled6
2000 --- Uncontrolled6
2500 --- Uncontrolled6
390 --- ESP6
1000 --- ESP6
244 Uncontrolled
17.3 --- ESP/Scrubber
17,200f 8200-29,700 Mechanical Ppt.
3780s 1520-7210 Mech. Ppt/lst ESP
in Series of 2
740h <74-1740 Mech. Ppt/2 ESPs
in Series
Baig et al.. 1981
Shih et al.. 1980b
Shih eŁ al.. 1980b
Shih eŁ al.. 1980b
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Scinto et al.. 1981
Scinto et al.. 1981
Zielke and Bittman, 1982
Zielke and Bittman, 1982
Zielke and Bittman, 1982
E-33
-------
TABLE E-30. MEASURED CHROMIUM EMISSION FACTORS FOR PULVERIZED DRY BOTTOM
UTILITY BOILERS FIRED WITH BITUMINOUS COAL (Continued)
Emission Factor
(lb/1012 Btu)
Mean
Range
Control Status
Reference
48
31
12
1.9
770
1320
4.5-290
1.6-2.3
7.1-70.8J
510-1120
1000-1840
0.0034
Venturi Scrubber
Venturi Scrubber
Venturi Scrubber
ESP
ESP
Mech. Collector
Uncontrolled
Controlled
Ondov et al.. 1979a
Ondov et al.. 1979a
Ondov et al.. 1979a
Ondov eŁ al.. 1979b
Ondov et al.. 1979b
Cowherd e^ al.. 1975
Cowherd e_t al. . 1975
Ajax and Cuffe, 1985
aThis column gives arithmetic mean values for each boiler tested. Footnotes
indicate how many measurements each mean represents, if this information was
included in the reference. If only a single value was reported, it is
included in this column.
Suspected corrosion of sampling train components may account for higher than
expected measured values.
Ł
Average of tests of six boilers.
tested while boiler was operating under baseline (design) conditions.
Tested while boiler was operating under low-NO conditions - certain burners
admit air rather than fuel, or different fuel/air ratios are admitted than
under design operating conditions.
Average of seven tests of the same boiler.
"Average of six tests of the same boiler.
Average of four tests of the same boiler.
Average of three tests of the same boiler.
j
Range for six tests of the same boiler.
tc
Average reported for three tests of the same boiler. This value is for
hexavalent chromium (Cr+6).
E-34
-------
TABLE E-31. MEASURED CHROMIUM EMISSION FACTORS FOR UTILITY PULVERIZED
WET BOTTOM BOILERS FIRED WITH BITUMINOUS COAL
a
Emission Factor
12
(lb/10 Btu) Control Status Reference
86 Mechanical Ppt/ESP Shih et al.. 1980b
339 ESP Shih et al.. 1980b
2040 ESP Shih et al.. 1980b
0.60 Venturi Scrubber Shih et al.. 1980b
3320 ESP Shih et al.. 1980b
3070 ESP Shih et al.. 1980b
aThe reference notes that suspected corrosion of the sampling train may
account for higher than expected values.
E-35
-------
TABLE E-32. MEASURED CHROMIUM EMISSION FACTORS FOR UTILITY
CYCLONE BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btul
Mean
Range
Control Status
Reference
107
1820
5340b
6741
1170*
1150
32<
c
1000-1300
18-46
Wet Scrubber
ESP
ESP
ESP
ESP
Uncontrolled
ESP
Shih et al.. 1980b
Shih Łt al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Klein et al.. 1975b; Lyon, 1977
Klein et al.. 1975b; Lyon, 1977
This column gives the arithmetic mean values for each boiler tested.
Footnotes indicate how many measurements each mean represents, if this
information was included in the reference. If only a single value was
reported, it is included in this column.
Reference notes that suspected corrosion of sampling train may account for
higher than expected values.
Average of two tests of the same boiler.
E-36
-------
TABLE E-33. MEASURED CHROMIUM EMISSION FACTORS FOR UTILITY
STOKER BOILERS FIRED WITH BITUMINOUS COAL
a
Emission Factor
12
(lb/10 Btu) Control Status Reference
153 Fabric Filter Shin et al.. 1980b
2420 Mechanical Ppt. Shih et al.. 1980b
455 Multiclone Shih et al.. 1980b
Reference notes that suspected corrosion of the sampling train may account
for higher values than expected.
E-37
-------
TABLE E-34. MEASURED CHROMIUM EMISSION FACTORS FOR UTILITY
BOILERS FIRED WITH SUBBITUMINOUS COAL
Emission Factor
(lb/1012 Btu) Boiler Type
1100
100
390
140
8.8
28
Cyclone
Cyclone
Pulverized
Pulverized
NR
NR
Control Status
Uncontrolled
Scrubber
Venturi Scrubber
ESP
ESP
ESP
Reference
Leavitt
Leavitt
Radian,
Radian,
Mann et
Mann et
et al. . 1979
et al. . 1979
1975a
1975a
al., 1978
al. . 1978
NR - Not Reported.
E-38
-------
Mean
TABLE E-35. MEASURED CHROMIUM EMISSION FACTORS FOR
UTILITY BOILERS FIRED WITH LIGNITE COAL
Range
Boiler Type
Control Status
Reference
74.4 Pulverized Dry Bottom Multiclone
67.4 Pulverized Dry Bottom Multiclone
20.0 --- Pulverized Dry Bottom ESP
<7.7 --- Cyclone ESP
1000 Cyclone Cyclone
4.6b 3.1-5.9 Cyclone ESP/Scrubbers
30.2 --- Spreader Stoker Multiclone
<5.3 Spreader Stoker ESP
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Radian, 1975a
Schock et al.. 1979
Shih et al.. 1980b
Shih et al., 1980b
This column gives arithmetic mean values for each boiler tested. Footnotes
indicate how many measurements each mean represents, if this information
was included in the reference. If only one value was reported, it is
included in this column.
Average of two tests of the same boiler.
E-39
-------
TABLE E-36. MEASURED CHROMIUM EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
Mean
Range
Boiler Type
Control Status
Reference
i
*-
O
1500bťC
5.8
2560
126
12..3
17.2
325
62
58d
4800f
6500
3200d
5150d
7450d
15-100
3500-7200
390-6000
2600-7700
6500-8400
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
ESP
ESP
Multiclone
Multiclone/Scrubber
Multiclone
Multiclone/ESP
Multiclone
Multiclorae
Uncontrolled6
Uncontrolled6
Uncontrolled6
Uncontrolled
Uncontrolled
Uncontrolled
Baig e_t al.. 1980
Suprenant et al.. 1980a
Leavitt e_t al. 1978b;
Fischer et, al. . 1979
Leavitt ejt al. . 1978b;
Fischer et. jj_._, 1979
Suprenant e_t al. . 1980a
Suprenant e_t al. . 1980a
Suprenant e_t al. . 1980a
Suprenant e_t al.. 1980a
Burlingame et. al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et. al. , 1981
Burlingame et. al.. 1981
Burlingame et al.. 1981
-------
TABLE E-36. MEASURED CHROMIUM EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS (Continued)
Emission Factor
(lb/1012 Btu)
Mean8 Range
2300
1400
31,500d 14,000-49,000
2300
15,400d 8,800-22,000
30
16
1.5h
Boiler Type
Overfeed Stoker
Overfeed Stoker
Overfeed Stoker
Overfeed Stoker
Overfeed Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Economizer/Dust
Collector
Uncontrolled8
Mechanical Ppt/ESP8
2 Mechanical Ppt
in Series
Reference
Burlingame et al., 1981
Burlingame et al., 1981
Burlingame et al. . 1981
Burlingame et al, . 1981
Burlingame et al. . 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Ajax and Cuffe, 1985
This column gives arithmetic mean values for each boiler tested. Footnotes indicate how many measurements each
mean represents, if this information was included in the reference. If only a single measurement was reported,
it is included in this column.
Suspected corrosion of the sampling train components may account for higher than expected values.
CAverage for three boilers.
Average of two tests of the same boiler.
6Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of control device.
Average of three tests of the same boiler.
8Boiler operated with low excess air level for N0x control.
Average of three tests of the same boiler. This value is for hexavalent chromium (Cr+6).
-------
TABLE E-37. MEASURED CHROMIUM EMISSION FACTORS FOR SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
i
.0
KJ
Meana
3050b
640
15
280
120
Range Boiler
2600-3500 Spreader
Spreader
Spreader
Spreader
Spreader
Type
Stoker
Stoker
Stoker
Stoker
Stoker
Control
Status
c
Uncontrolled
Uncontrolled
Mechanical
Ppt/ESPd
Uncontrolled
Mechanical
Ppt/ESPe
Reference
Bur 1 ingau
Goldberg
Goldberg
Goldberg
Goldberg
ae et al. , 1981
and
and
and
and
Higginbotham,
Higginbotham,
Higginbotham,
Higginbotham,
1981
1981
1981
1981
This column gives arithmetic mean values for each boiler tested. Footnotes indicate how many measurements each
mean represents, if this information was included in the reference. If only a single measurement was reported,
it is included in this column.
Mean of two tests of the same boiler.
"ť
"Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of controls.
Tested while operating under baseline (design) conditions.
STested while operating under low-NO operating conditions - overfire air rate set at maximum level.
<&
-------
TABLE E-38. MEASURED CHROMIUM EMISSION FACTORS FOR COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Emission Factor
(lb/1012 Btu)
Type of Coal
Boiler Type
Control Status
Reference
M
U>
1920
18.1
18.8
100
1840
240
1510
876
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Anthracite
Anthracite
Anthracite
Pulverized Dry Bottom
Pulverized Dry Bottom
Underfeed Stoker
Spreader Stoker
Overfeed Stoker
Stoker
Stoker
Stoker
Uncontrolled
Multiclone/Scrubber
Uncontrolled
Mechanical Ppt.
Mechanical Ppt.
Uncontrolled
Uncontrolled
Uncontrolled
Suprenant et al.. 1980b
Suprenant e_t al.. 1980b
Suprenant et. al.. 1980b
Suprenant et al.. 1980b
Suprenant et al.t 1980b
Suprenant et. al.. 1980b
Suprenant et al.. 1980b
Suprenant et al.. 1980b
-------
TABLE E-39. MEASURED CHROMIUM EMISSION FACTORS FOR COAL-FIRED RESIDENTIAL FURNACES
I
-P-
Emission Factor
(lb/1012 Btu)
387
155
44.5b
267b
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous-washed
Furnace Type
NRa
NR
Warm Air Furnace
with Stoker
Warm Air Furnace
with Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Reference
De Angel is and Reznik,
DeAngelis and Reznik,
DeAngelis, 1979
DeAngelis9 1979
1979
1979
SNR = Not Reported.
Average of two tests of the same boiler.
-------
TABLE E-40. MEASURED COPPER EMISSION FACTORS FOR PULVERIZED DRY
BOTTOM UTILITY BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
Clb/1012 Btu>
Mean Range
13.5
177
48.8
268b 92.4-660
896b 792-1010
1000
680
780
100
48
82
1100
830
490
1500
240
290
220
541
34
Control Status
Wet Scrubber
Mechanical Ppt/ESP
Mechanical Ppt/ESP
ESP
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
ESPC
ESPd
ESPd
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
ESPC
ESPd
ESPd
Uncontrolled
ESP
Reference
Shih et al. . 1980b
Shih et al. . 1980b
Shih et al. . 1980b
Evers eŁ al. . 1980
Evers et al. . 1980
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Scinto et al. . 1981
Scinto et al. . 1981
E-45
-------
TABLE E-40. MEASURED COPPER EMISSION FACTORS FOR PULVERIZED DRY BOTTOM
UTILITY BOILERS FIRED WITH BITUMINOUS COAL (Continued)
Emission Factor
Clb/1012 Btu)
Mean
Range
Control Status
Reference
14.1
e
2720
580
34.5
2380-3140
440-974
1.6-71.0
ESP/Scrubber
Mechanical Ppt.
Mech. Ppt/lst ESP
in Series of 2
Mech. Ppt/2 ESPs
in Series
Scinto et al.. 1981
Zielke and Bittman, 1982
Zielke and Bittman, 1982
Zielke and Bittman, 1982
27
20
440g
260s
10.1-54
380-480
210-290
Venturi Scrubber
Venturi Scrubber
Uncontrolled
Mechanical Ppt.
Ondov et al. . 1979a
Ondov et al. . 1979a
Cowherd ejt al . . 1975
Cowherd et al. . 1975
This column gives arithmetic mean values for each boiler tested. Footnotes
indicate how many measurements each mean represents, if this information was
included in the reference. If only a single value was reported, it is
included in this column.
Average of eight tests of the same boiler.
Tested while boiler was operating under baseline (design) conditions.
Tested while boiler was operating under low-NO conditions - certain burners
admit air rather than fuel, or different fuel/air ratios are admitted than
under design operating conditions.
Ł
Average of seven tests of the same boiler.
Average of five tests of the same boiler.
c?
Average of three tests of the same boiler.
E-46
-------
TABLE E-41. MEASURED COPPER EMISSION FACTORS FOR UTILITY PULVERIZED
WET BOTTOM BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/10 Btu) Control Status Reference
23.2 Mechanical Ppt/ESP Shih et al.. 1980b
12.3 ESP Shih et al.. 1980b
30.2 ESP Shih et al^, 1980b
2.3 Venturi Scrubber Shih et al.. 1980b
137 ESP Shih et al.. 1980b
225 ESP Shih et al.. 1980b
E-47
-------
TABLE E-42. MEASURED COPPER EMISSION FACTORS FOR UTILITY
CYCLONE BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
db/1012 Btul
Mean
167
19.5
22.8
44.2
23.2
10. 8b
0.26b
Range Control Status
Wet Scrubber
ESP
ESP
ESP
ESP
7.0-14.5 Uncontrolled
0.05-0.48 ESP
Reference
Shih
Shih
Shih
Shih
Shih
et al^,
et aL,,
et al. .
e_t al. .
et al,.,
Klein et al .
Klein et al . .
1980b
1980b
1980b
1980b
1980b
1975b;
1975b;
Lvon, 1977
Lyon, 1977
This column gives the arithmetic values for each boiler tested. Footnotes
indicate how many measurements each mean represents, if this information
was included in the reference. If only a single value was reported, it is
included in this column.
Average of two tests of the same boiler.
S-48
-------
TABLE E-43. MEASURED COPPER EMISSION FACTORS FOR UTILITY
STOKER BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Control Status
Reference
5.8
342
188
Fabric Filter
Mechanical Ppt.
Multiclone
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
TABLE E-44. MEASURED COPPER EMISSION FACTORS FOR UTILITY
BOILERS FIRED WITH SUBBITUMINOUS COAL
Emission Factor
(lb/1012 Btu) Boiler Type
1000
170
29
30
82
50
Cyclone
Cyclone
Pulverized
Pulverized
NR
NR
Control Status
Uncontrolled
Scrubber
Venturi Scrubber
ESP
ESP
ESP
Reference
Leavitt
Leavitt
Radian,
Radian ,
Mann et
Mann et
et al.. 1979
et al. . 1979
1975a
1975a
al.. 1978
al.. 1978
NR - Not Reported.
E-49
-------
TABLE E-45. MEASURED COPPER EMISSION FACTORS FOR
UTILITY BOILERS FIRED WITH LIGNITE COAL
Emission Factor
(lb/1012 Btu)
Boiler Type
Control Status
Reference
376
195
<69.7
30.2
480
193
46.5
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
Spreader Stoker
Spreader Stoker
Multiclone
Multiclone
ESP
ESP
Cyclone
Multiclone
ESP
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Radian, 1975a
Shih et al.. 1980b
Shih et al.. 1980b
E-50
-------
TABLE E-46. MEASURED COPPER EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
Mean*
Range
Boiler Type
Control Status
Reference
M
in
80.6
19.5
9530
3150
230
45.1
309
411
1170
32b
1100d
600
192b
180b
880b
3500
17-46
1100-1100
63-320
130-230
760-1000
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Overfeed Stoker
ESP
Multiclone/Scrubber
Multiclone
Uncontrolled
ESP
Multiclone
Multiclone/ESP
Multiclone
Multiclone
Ł
Uncontrolled
Uncontrolled0
Ł
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Suprenant et al.. 1980a
Leavitt, 1978b; Fischer, 1979
Leavitt, 1978b; Fischer, 1979
McCurley et al.. 1979
McCurley et. al.. 1979
Suprenant et al.. 1980a
Suprenant e_t al.. 1980a
Suprenant e_t al.. 1980a
Suprenant e_t al. . 1980a
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
-------
TABLE E-46. MEASURED COPPER EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS (Continued)
Emission Factor
(lb/1012 Btu)
M
1
Cn
N>
Mean
720
3300b
200
4550b
300
66
5.2
0.040
Range Boiler Type
Overfeed Stoker
1300-5300 Overfeed Stoker
Overfeed Stoker
4200-4900 Overfeed Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Economizer/Dust
Collector
6
Uncontrolled
Mechanical Ppt/ESPe
Uncontrolled
Mechanical Ppt/ESP
Reference
BurlinEame et al.. 1981
Burlingame et al., 1981
Burlingame et al., 1981
Burlingame et al., 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham 8 1981
This column gives arithmetic mean values for each boiler tested. Footnotes indicate how many measurements each
mean represents, if this information was included in the reference. If only a single measurement was reported,
it is included in this column.
Average of two tests of the same boiler.
CTraveling grate spreader stoker with re-injection from the dust collector. Measured upstream of control device.
Average of three tests of the same boiler,
eBoiler operated under baseline (design) conditions.
Boiler operated with low excess air level for NO control.
-------
TABLE E-47. MEASURED COPPER EMISSION FACTORS FOR SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
w
Ui
w
Mean8
2900b
2200
18
280
74
Range Boiler
2800-3000 Spreader
Spreader
Spreader
Spreader
Spreader
Type
Stoker
Stoker
Stoker
Stoker
Stoker
Control
Status
Uncontrolled0
Uncontrolled
Mechanical
Ppt/ESPd
Uncontrolled
Mechanical Ppt/ESPe
Reference
Burlingame ej
Goldberg and
Goldberg
Goldberg
Goldberg
and
and
and
t al., 1981
Higginbotham,
Higginbotham,
Higginbotham,
Higginbotham,
1981
1981
1981
1981
This column gives arithmetic mean values for each boiler tested. Footnotes indicate how many measurements each
mean represents, if this information was included in the reference. If only a single measurement was reported,
it is included in this column.
Mean of two tests of the same boiler.
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of controls.
Tested while operating under baseline (design) conditions.
ft
Tested while operating under low-NO operating conditions - overfire air rate set at maximum level.
-------
TABLE E-48. MEASURED COPPER EMISSION FACTORS FOR COAL-FIRED RESIDENTIAL FURNACES
Emission Factor
(lb/1012 Btu)
Coal Type
Furnace Type
Control Status
Reference
w
38.7
232
356b
178b
Bituminous
Bituminous
Bituminous
Bituminous-washed
NR"
NR
Warm Air Furnace with Stoker
Warm Air Furnace with Stoker
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
DeAngelis and Reznik, 1979
DeAngelis and Reznik, 1979
DeAngelis, 1979
DeAngelis, 1979
NR = not reported.
Average of two tests of the same boiler.
-------
TABLE E-49. MEASURED COPPER EMISSION FACTORS FOR COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Emission Factor
(lb/1012 Btu)
Type of Coal
Boiler Type
Control Status
Reference
w
Ui
Ul
1410
28
5.1
184
153
265
723
232
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Anthracite
Anthracite
Anthracite
Pulverized Dry Bottom
Pulverized Dry Bottom
Underfeed Stoker
Spreader Stoker
Overfeed Stoker
Stoker
Stoker
Stoker
Uncontrolled
Multiclone/Scrubher
Uncontrolled
Mechanical Ppt.
Mechanical Ppt.
Uncontrolled
Uncontrolled
Uncontrolled
Suprenant et al.. 1980b
Suprenant et al,. 1980b
Suprenant et al.. 1980b
Suprenant et al.. 1980b
Suprenant ejt al.. 1980b
Suprenant e_t al.. 1980b
Suprenant e_t al.. 1980b
Suprenant e_t al.. 1980b
-------
TABLE E-50. MEASURED MERCURY EMISSION FACTORS FOR PULVERIZED DRY
BOTTOM UTILITY BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Mean
Range
Control Status
Reference
ND
22.1
22.3
5.9C
5.8{
72e
23
18
10
3.9
16
1.5
2.6
2.0
3.1
8.5*
3.6-8.2
1.32-9.68
11.4-308
3.7-21.2
ESP
Wet Scrubber
Mechanical Ppt/ESP
Mechanical Ppt/ESP
Mechanical Ppt/ESP
ESP
Uncontrolled
Uncontrolled
ESPf
Uncontrolled*'
Uncontrolled
Uncontrolled
ESPS
ESPf
ESPf
ESPf
Mechanical Ppt.
Baig et al.. 1981
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Kalb, 1975
Evers et al.. 1980
Evers et al.. 1980
Sawyer and Higginbotham, 1981a
Sawyer and Higginbotham, 1981a
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Higginbotham and Goldberg, 1981
Zielke and Bittman, 1982
E-56
-------
TABLE E-50. MEASURED MERCURY EMISSION FACTORS FOR PULVERIZED DRY BOTTOM
UTILITY BOILERS FIRED WITH BITUMINOUS COAL (Continued)
Emission Factor
db/1012 BtvO
Mean Range Control Status Reference
0.75h 0.41-2.0 Mech. Ppt/lst ESP Zielke and Bittman, 1982
in Series of 2
0.201 <0.Oil-0.561 Mech. Ppt/2 ESPs Zielke and Bittman, 1982
in Series
This column gives arithmetic mean values for each boiler tested. Footnotes
indicate how many measurements each mean represents, if this information
was included in the reference. If only a single value was reported, it is
included in this column.
Average of tests of six boilers.
ND - not detected.
Average of 14 tests of the same boiler.
Average of eight tests of the same boiler.
Tested while boiler was operating under low-NO conditions - certain
burners admit air rather than fuel, or different fuel/air ratios are
admitted than under design operating conditions.
"Tested while boiler was operating under baseline (design) conditions.
Average of seven tests of the same boiler.
Average of five tests of the same boiler.
E-57
-------
TABLE E-51. MEASURED MERCURY EMISSION FACTORS FOR UTILITY PULVERIZED
WET BOTTOM BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Control Status
Reference
5.3
2.6
4.2
0.16
5.1
6.3
Mechanical Ppt/ESP
ESP
ESP
Venturi Scrubber
ESP
ESP
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
TABLE E-52. MEASURED MERCURY EMISSION FACTORS FOR UTILITY
CYCLONE BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu) Control Status
4.9 Wet Scrubber
3.95 ESP
5.1 ESP
9.5 ESP
17.7 ESP
10 Uncontrolled
6.1 ESP
Reference
Shih et al. .
Shih et al. .
Shih et al . r
Shih et al. .
Shih et al. .
Klein et al. .
Klein et al . .
1980b
1980b
1980b
1980b
1980b
1975b; Lyon,
1975b; Lyon,
1977
1977
E-58
-------
TABLE E-53. MEASURED MERCURY EMISSION FACTORS FOR UTILITY
STOKER BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Control Status
Reference
4.6
26
2.5
Fabric Filter
Mechanical Ppt.
Multiclone
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
TABLE E-54. MEASURED MERCURY EMISSION FACTORS FOR UTILITY
BOILERS FIRED WITH SUBBITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
81
4.9
11
4.1
2.0
1.7
Boiler Type
Cyclone
Cyclone
Pulverized
Pulverized
NRa
NR
Control Status
Uncontrolled
Scrubber
Venturi Scrubber
ESP
ESP
ESP
Reference
Leavitt et al. .
Leavitt et al. .
Radian, 1975a
Radian, 1975a
Mann, 1978
Mann, 1978
1979
1979
wR - not reported.
E-59
-------
TABLE E-55. MEASURED MERCURY EMISSION FACTORS FOR
UTILITY BOILERS FIRED WITH LIGNITE COAL
Emission Factor
(lb/1012 Btu)
Boiler Type
Control Status
Reference
4.4
6.5
<0.23
0.46
22
5.6
0.53
Pulverized Dry Bottom Multiclone
Pulverized Dry Bottom Multiclone
Pulverized Dry Bottom ESP
Cyclone ESP
Cyclone Cyclone
Spreader Stoker Multiclone
Spreader Stoker ESP
Shih et al.. 1980b
Shih et aLu, 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Radian, 1975a
Shih et al.. 1980b
Shih et al.. 1980b
E-60
-------
TABLE E-56. MEASURED MERCURY EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
ON
I-1
Meana Range
4
4
180
.2b
.4
Boiler
Pulverized
Pulverized
Pulverized
Type
Dry
Dry
Dry
Bottom
Bottom
Bottom
Control Status
ESP
ESP
Multiclone
Reference
Baig et al . .
Suprenant et
Leavitt et jj.
1981
al..
1980a
j., 1978b;
86
6.7
4.2
5.8
25.1
0.77C
3.9e
2.3
1.6C
3.2C
4.0C
0.76-0.78
2.5-5.1
1.3-2.0
2.5-3.9
1.6-6.5
Pulverized Dry Bottom
Pulverized Wet Bottom
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Multiclone/Scrubher
Multiclone
Multiclone/ESP
Multiclone
Multiclone
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Fischer et al.. 1979
Leavitt et al.. 1978b;
Fischer et al.. 1979
Suprenant et al.. 1980a
Suprenant et al,. 1980a
Suprenant et al.. 1980a
Suprenant et al.. 1980a
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
-------
TABLE E-56. MEASURED MERCURY EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS (Continued)
M
I
cr>
N>
Emission Factor
(lb/1012 Btu)
g
Mean Range
0.011
Io7
1.3C 0,74-1.9
2.1
0.80C 0.39-1.2
4.1
2.4
12
1 .0
Boiler Type
Overfeed Stoker
Overfeed Stoker
Overfeed Stoker
Overfeed Stoker
Overfeed Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Economizer/Dust Collector
Uncontrolled
Mechanical Ppt/ESPf
Uncontrolled8
Mechanical Ppt/ESP8
Reference
Burlingame et al . . 1981
Burlingame et al., 1981
Burlingame et al . . 1981
Burlingame et al., 1981
Burlingame et al . . 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
This column gives arithmetic mean values for each boiler tested. Footnotes indicate how many measurements each
mean represents, if this information was included in the reference. If only a single measurement was reported, it
is included in this column.
Average for three boilers.
CAverage of two tests of the same boiler.
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of control device.
SAverage of three tests of the same boiler,,
Boiler operated under baseline (design) conditions.
Boiler operated with low excess air level for NO control.
-------
TABLE E-57. MEASURED MERCURY EMISSION FACTORS FOR SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
Meana Range
w
ON
U>
8
0
0
0
0
a,
,9b 0.86-17
.64
.64
.91
.37
Boiler
Spreader
Spreader
Spreader
Spreader
Spreader
f
Type
Stoker
Stoker
Stoker
Stoker
Stoker
Control
Status
Uncontrolled
Uncontrolled
Mechanical
Ppt/ESPd
Uncontrolled6
Mechanical
Ppt/ESP6
f
Reference
Burlingame e\
Goldberg and
Goldberg
Goldberg
Goldberg
f
and
and
and
t al., 1981
Higginbotham,
Higginbotham,
Higginbotham,
Higginbotham,
1981
1981
1981
1981
.1-
mean represents, if this information was included in the reference. If only a single measurement was reported, it
is included in this column.
Mean of two tests of the same boiler.
c
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of controls.
Tested while operating under baseline (design) conditions.
A
Tested while operating under low-NO conditions - overfire air rate set at maximum level.
A
-------
TABLE E-58. MEASURED MERCURY EMISSION FACTORS FOR COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Emission Factor
12
(lb/10 Btu) Type of Coal Boiler Type Control Status Reference
5.8 Bituminous Pulverized Dry Bottom Uncontrolled Suprenant et al.. 1980b
1.1 Bituminous Pulverized Dry Bottom Multiclone/Scrubber Suprenant et al. . 1980b
0.42 Bituminous Underfeed Stoker Uncontrolled Suprenant et al. . 1980b
1ť4 Bituminous Spreader Stoker Mechanical Ppt. Suprenant et al.. 1980b
13,0 Bituminous Overfeed Stoker Mechanical Ppt. Suprenant et al. . 1980b
7.0 Anthracite Stoker Uncontrolled Suprenant et al. . 1980b
3ť5 Anthracite Stoker Uncontrolled Suprenant et al. . 1980b
5.3 Anthracite Stoker Uncontrolled Suprenant et al.. 1980b
-------
TABLE E-59. MEASURED MERCURY EMISSION FACTORS FOR COAL-FIRED RESIDENTIAL FURNACES
w
CT>
Ui
finis sion Factor
(lb/1012 Btu)
7.7
23.2
26 .7b
5$0. 89°
Coal Type
Bituminous Coal
Bituminous Coal
Bituminous Coal
Bituminous-washed
Furnace Type
NRa
NR
Warm Air Furnace
with Stoker
Warm Air Furnace
with Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Reference
De Angel is and Reznik,
DeAngelis and Reznik,
DeAngelis, 1979
DeAngelis, 1979
1979
1979
= not reported.
Average of two tests of the same boiler.
c 12
Average of two tests of the same boiler. Both were less than the detection limit of 0.89 lb/10 Btu.
-------
TABLE E-60. MEASURED MANGANESE EMISSION FACTORS FOR PULVERIZED DRY
BOTTOM UTILITY BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
Clb/1012 Btu)
Mean
420b
30.2
886
393
2450°
3820°
9300
7000
7700
1300
920
740
800
458f
160g
68
28
3790h
Range Control Status
ESP
Wet Scrubber
Mechanical Ppt/ESP
Mechanical Ppt/ESP
286-9240 ESP
2900-5280 Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
ESPd
ESP6
ESP6
Uncontrolled
300-640 Uncontrolled6
110-240 ESPe
1180-1280 Uncontrolled
ESP
ESP/Scrubber
2570-4750 Mechanical Ppt.
Reference
Baig et al . . 1981
Shih et al. , 1980b
Shih et al. . 1980b
Shih et al. . 1980b
Evers et al. . 1980
Evers et al . . 1980
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Higginbotham and Goldberg
Higginbotham and Goldberg
Higginbotham and Goldberg
Scinto et al . . 1981
Scinto et al. . 1981
Scinto et, al. . 1981
Zielke and Bittman, 1982
1981a
1981a
1981a
1981a
1981a
1981a
, 1981
, 1981
, 1981
E-66
-------
TABLE E-60. MEASURED MANGANESE EMISSION FACTORS FOR PULVERIZED DRY BOTTOM
UTILITY BOILERS FIRED WITH BITUMINOUS COAL (Continued)
Emission Factor
rib/1012 Btu)
Mean
Range
Control Status
Reference
793
149
570-1040
8.05-463
88
53J
36.5
1.0s
1630s
710s
4.6-318
0.97-1.1
21.0-95.6l
960-2690
460-1100
Mech. Ppt/lst ESP
in Series of 2
Mech. Ppt/2 ESPs
in Series
Venturi Scrubber
Venturi Scrubber
Venturi Scrubber
ESP
ESP
Uncontrolled
Mechanical Ppt.
Zielke and Bittman, 1982
Zielke and Bittman, 1982
Ondov et al.. 1979a
Ondov et al.. 1979a
Ondov et al.. 1979a
Ondov et al.. 1979b
Ondov et al.. 1979b
Cowherd e_t al. . 1975
Cowherd §t al.. 1975
This column gives arithmetic mean values for each boiler tested. Footnotes
indicate how many measurements each mean represents, if this information
was included in the reference. If only a single value was reported, it is
included in this column.
Average of six boilers.
Average of eight tests of the same boiler.
Tested while boiler was operating under baseline (design) conditions.
Tested while boiler was operating under low-NO conditions - certain
burners admit air rather than fuel, or different fuel/air ratios are
admitted than under design operating conditions.
Average of four tests of the same boiler.
SAverage of three tests of the same boiler.
Average of seven tests of the same boiler.
Average of five tests of the same boiler.
-'Same boiler tested at two different times.
llange of six tests of the same boiler.
E-67
-------
TABLE E-61. MEASURED MANGANESE EMISSION FACTORS FOR UTILITY PULVERIZED
WET-BOTTOM BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
12
(lb/10 Btu) Control Status Reference
7.4 Mechanical Ppt/ESP Shih et al.. 1980b
62.7 ESP Shih et al.. 1980b
181 ESP Shih et al.. 1980b
0.95 Venturi Wet Scrubber Shih et al.. 1980b
214 ESP Shih et al.. 1980b
418 ESP Shih et al.. 1980b
E-68
-------
TABLE E-62. MEASURED MANGANESE EMISSION FACTORS FOR UTILITY
CYCLONE BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
db/1012 Btu~)
Ł
Mean Range
126
170
314
53.5
182
1300b 1300-1300
36b 11-60
Control Status
Wet Scrubber
ESP
ESP
ESP
ESP
Uncontrolled
ESP
Reference
Shih et al. .
Shih et al . .
Shih et al . .
Shih et al. .
Shih et al. .
Klein et al. .
Klein et al . .
1980b
1980b
1980b
1980b
1980b
1975b
1975b
This column gives the arithmetic mean values for each boiler tested.
Footnotes indicate how many measurements each mean represents, if this
information was included in the reference. If only a single value was
reported, it is included in this column.
Average of two tests of the same boiler.
E-69
-------
TABLE E-63. MEASURED MANGANESE EMISSION FACTORS FOR UTILITY
STOKER BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Control Status
Reference
17.9
304
188
Fabric Filter
Mechanical Ppt.
Multiclone
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
TABLE E-64. MEASURED MANGANESE EMISSION FACTORS FOR UTILITY
BOILERS FIRED WITH SUBBITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
600
120
110
43
19
35
Boiler Type
Cyclone
Cyclone
Pulverized
Pulverized
NRa
NR
Control Status
Uncontrolled
Scrubber
Venturi Scrubber
ESP
ESP
ESP
Reference
Leavitt et al . . 1979
Leavitt et al. . 1979
Radian, 1975a
Radian, 1975a
Mann et al. . 1978
Mann et al . . 1978
wR - not reported.
E-70
-------
TABLE E-65. MEASURED MANGANESE EMISSION FACTORS FOR
UTILITY BOILERS FIRED WITH LIGNITE COAL
Emission Factor
rib/1012 Btu}
Mean
1680
1560
17.2
10.9
1600
Range Boiler Type
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
Control
Status
Multiclone
Multiclone
ESP
ESP
Cyclone
Reference
Shih et
Shih et
Shih et
Shih et
Radian,
al. . 1980b
al. . 1980b
al., 1980b
al. . 1980b
1975a
2.94 2.92-2.96 Cyclone
1790 Spreader Stoker
<10 Spreader Stoker
ESP/Scrubber Schock et al.. 1979
Multiclone Shih et al.. 1980b
ESP Shih et al.. 1980b
This column gives arithmetic mean values for each boiler tested. Footnotes
indicate how many measurements each mean represents, if this information
was included in the reference. If only one value was reported, it is
included in this column.
Average of two tests of the same boiler.
E-71
-------
TABLE E-66. MEASURED MANGANESE EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
Mean
a
Range
Boiler Type
Control Status
Reference
790"
274
790
14.6
14.6
" 51.4
Is)
23.9
183
44C
767e
14,000
135C
345C
87 0C
_.__
30-58
530-1100
100-170
230-460
790-950
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
ESP
ESP
Multiclone
Multiclone/Scrubher
Multiclone
Multiclone/ESP
Multiclone
Multiclone
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
d
Baig et_ al., 1981
Suprenant et al. . 1980a
Leavitt e_t aJL., 1978b;
Fischer et al.. 1979
Leavitt et al.. 1978b;
Fischer e_t al. . 1979
Suprenant et al.. 1980a
Suprenant et. al. . 1980a
Suprenant et al.. 1980a
Suprenant et al,. 1980a
Burlingame et al.. 1981
Burlingame et_ al. . 1981
Burlingame et al.. 1981
Burlingame et_ al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
-------
TABLE E-66. MEASURED MANGANESE EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS (Continued)
w
Bnission Factor
(lb/1012 Btu)
Mean Range
600
880
6,000C 5300-6700
230
2,050C 1100-3000
16
12
58
9.1
Boiler Type
Overfeed Stoker
Overfeed Stoker
Overfeed Stoker
Overfeed Stoker
Overfeed Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Economizer/Dust Collector
Uncontrolled
Mechanical Ppt/ESPf
Uncontrolled8
Mechanical Ppt/ESP8
Reference
Burlingame et al . , 1981
Burlingame et al., 1981
Burlingame et al . , 1981
Burlingame et al., 1981
Burlingame et al . . 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
Lips and Higginbotham, 1981
fl
mean represents, if this information was included in the reference. If only a single measurement was reported,
it is included in this column.
Average for three boilers.
c
Average of two tests of the same boiler.
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of control device.
6Average of three tests of the same boiler.
Boiler operated under baseline (design) conditions.
^Boiler operated with low excess air level for NO control.
-------
TABLE E-67. MEASURED MANGANESE EMISSION FACTORS FOR SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
w
I
Emission Factor
(lb/1012 Btu)
Mean3 Range Boiler Type
15,500b 14,000-17,000 Spreader Stoker
9,950 Spreader Stoker
28 Spreader Stoker
1 ,300 Spreader Stoker
62 Spreader Stoker
Control Status
Uncontrolled
Uncontrolled
Mechanical Ppt/ESP
Uncontrolled
Mechanical Ppt/ESPe
Reference
Burlingame et al., 1981
Goldberg
Goldberg
Goldberg
Goldberg
and Higginbotham,
and Higginbotham,
and Higginbotham,
and Higginbotham,
1981
1981
1981
1981
A
mean represents, if this information was included in the reference. If only a single measurement was reported, it
is included in this column.
Mean of two tests of the same boiler.
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of controls.
Tested while operating under baseline (design) conditions.
Tested while operating under low-NO operating conditions - overfire air rate set at maximum level.
-------
TABLE E-68. MEASURED MANGANESE EMISSION FACTORS FOR COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Emission Factor
(lb/1012 Btu)
Type of Coal
Boiler Type
Control Status
Reference
w
i
Ui
2680
25.6
3.5
188
290
39.5
163
138
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Anthracite
Anthracite
Anthracite
Pulverized Dry Bottom
Pulverized Dry Bottom
Underfeed Stoker
Spreader Stoker
Overfeed Stoker
Stoker
Stoker
Stoker
Uncontrolled
Multiclone/Scrubher
Uncontrolled
Mechanical Ppt.
Mechanical Ppt.
Uncontrolled
Uncontrolled
Uncontrolled
Suprenant et al., 1980b
Suprenant et. al. . 1980b
Suprenant ejt al.. 1980b
Suprenant e_t al.. 1980b
Suprenant e_t al. . 1980b
Suprenant et al.. 1980b
Suprenant e_t al.. 1980b
Suprenant et al.. 1980b
-------
TABLE E-69. MEASURED MANGANESE EMISSION FACTORS FOR COAL-FIRED RESIDENTIAL FURNACES
O\
Emission Factor
(lb/1012 Btu)
155
3640
44.5b
89b
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous-washed
Furnace Type
NRa
NR
Warm Air Furnace
with Stoker
Warm Air Furnace
with Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Reference
De Angel is and Reznik,
DeAngelis and Reznik,
DeAngelis, 1979
DeAngelis, 1979
1979
1979
NR = not reported.
Average of two tests of the same boiler.
-------
TABLE E-70. MEASURED NICKEL EMISSION FACTORS FOR PULVERIZED DRY
BOTTOM UTILITY BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
fib/1012 Btu)
Mean Range
2,600b'°
104
5,760°
4,480°
1,600
1,100
5,000
1,500
700
1,400
913f 520-1,400
l,400f 1,100-1,600
430
12.2 12.1-12.4
15,300s 8,030-23,500
2,550h 1,010-4,870
Control Status
ESP
Wet Scrubber
Mechanical Ppt/ESP
Mechanical Ppt/ESP
ESPd
ESP6
Uncontrolled
Uncontrolled
ESPd
Uncontrolled
ESPe
Uncontrolled
Uncontrolled
ESP/Scrubber
Mechanical Ppt.
Mech. Ppt/lst ESP
Reference
Baig et al. . 1981
Shih et al.. 1980b
Shih et al. . 1980b
Shih et al.. 1980b
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Sawyer and Higginbotham,
Higginbotham and Goldberg
Higginbotham and Goldberg
Higginbotham and Goldberg
Higginbotham and Goldberg
Scinto et al^. 1981
Scinto et aL . 1981
Zielke and Bittman, 1982
Zielke and Bittman, 1982
1981a
1981a
1981a
1981a
, 1981
, 1981
, 1981
, 1981
360
35J
in Series of 2
132-724 Mech. Ppt/ 2 ESPs
in Series
Venturi Scrubber
Zielke and Bittman, 1982
Ondov, 1979a
E-77
-------
TABLE E-70. MEASURED NICKEL EMISSION FACTORS FOR PULVERIZED DRY BOTTOM
UTILITY BOILERS FIRED WITH BITUMINOUS COAL (Continued)
Emission Factor
db/1012 Btu)
Meana Range Control Status Reference
30J 12-94 Venturi Scrubber Ondov, 1979a
840f 690-1,100 Uncontrolled Cowherd et al.. 1975
440f 260-720 Mechanical Ppt. Cowherd et al.. 1975
a
This column gives arithmetic mean values for each boiler tested. Footnotes
indicate how many measurements each mean represents, if this information
was included in the reference. If only a single value was reported, it is
included in this column.
Average of tests of six boilers.
Ł
Reference noted that corrosion of sampling train components may account for
higher than expected nickel emissions measurements.
Tested while boiler was operating under baseline (design) conditions.
Tested while boiler was operating under low-NO conditions - certain
burners admit air rather than fuel, or different fuel/air ratios are
admitted than under design operating conditions.
Average of three tests of the same boiler.
^Average of seven tests of the same boiler.
Average of six tests of the same boiler.
Average of four tests of the same boiler.
JTests of the same boiler during two different time periods.
E-78
-------
TABLE E-71. MEASURED NICKEL EMISSION FACTORS FOR UTILITY PULVERIZED
WET BOTTOM BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Control Status
Reference
74.4
a
372
1470
a
1850
2550e
1.1
a
Mechanical Ppt/ESP
ESP
ESP
Venturi Scrubber
ESP
ESP
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Reference noted that corrosion of sampling train components may account for
higher than expected nickel emissions measurements.
TABLE E-72. MEASURED NICKEL EMISSION FACTORS FOR UTILITY
CYCLONE BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
46.5
997a
2000a
2020a
1330a
960
4.6
Control Status
Wet Scrubber
ESP
ESP
ESP
ESP
Uncontrolled
ESP
Reference
Shih et al. .
Shih et al. .
Shih et al. .
Shih et al. .
Shih et al. .
Klein et al . .
Klein et al. .
1980b
1980b
1980b
1980b
1980b
1975b; Lyon,
1975b; Lyon,
1977
1977
Reference noted that corrosion of sampling train components may account for
higher than expected nickel emissions measurements.
E-79
-------
TABLE E-73. MEASURED NICKEL EMISSION FACTORS FOR UTILITY
STOKER BOILERS FIRED WITH BITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
Control Status
Reference
165
5180C
1330C
Fabric Filter
Mechanical Ppt.
Multiclone
Shih et al._. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Reference noted that corrosion of sampling train components may account for
higher than expected nickel emission measurements.
TABLE E-74. MEASURED NICKEL EMISSION FACTORS FOR UTILITY
BOILERS FIRED WITH SUBBITUMINOUS COAL
Emission Factor
(lb/1012 Btu)
1700
46
50
70
5.4
21
Boiler Type Control Status
Cyclone Uncontrolled
Cyclone Scrubber
Pulverized Scrubber
Pulverized ESP
NRa ESP
NR ESP
Reference
Leavitt, 1979
Leavitt, 1979
Radian, 1975a
Radian, 1975a
Mann et al . . 1978
Mann et al . . 1978
IJR - not reported.
E-80
-------
TABLE E-75. MEASURED NICKEL EMISSION FACTORS FOR
UTILITY BOILERS FIRED WITH LIGNITE COAL
Emission Factor
(lb/1012 Btu)
Boiler Type
Control
Status
Reference
611°
267s
<158
<109
740
641*
<88
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Cyclone
Cyclone
Spreader Stoker
Spreader Stoker
Multiclone
Multiclone
ESP
ESP
Cyclone
Multiclone
ESP
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Shih et al.. 1980b
Radian, 1975a
Shih et al.. 1980b
Shih et al.. 1980b
reference noted that corrosion of sampling train components may account for
higher than expected nickel emissions measurements.
E-81
-------
TABLE E-76. MEASURED NICKEL EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
Mean
Range
Boiler Type
Control Status
Reference
i
oo
M
b,c
930
10.0
1,390
60
36
1S020C
31
230
70d
16,300f
10,200
775d
4,100d
3,200d
32-107
14,200-20,600
650-900
2,200-6,000
2,000-4,400
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Dry Bottom
Pulverized Wet Bottom
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
ESP
ESP
Multiclone
Multiclone/Scrubber
Multiclone
Multiclone/ESP
Multiclone
Multiclone
Uncontrolled6
Uncontrolled6
f)
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Baig et al.. 1981
Suprenant et al.. 1980a
Leavitt ej; al. . 1978b;
Fischer e_t al. 1979
Leavitt et al.. 1978b;
Fischer et. al. . 1979
Suprenant e_t al. . 1980a
Suprenant et^ al.. 1980a
Suprenant et al.. 1980a
Suprenant et. al. . 1980a
Burlingame et al.. 1981
Burlingame et. aK., 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
Burlingame et al.. 1981
-------
TABLE E-76. MEASURED NICKEL EMISSION FACTORS FOR BITUMINOUS COAL-FIRED INDUSTRIAL BOILERS (Continued)
M
I
oo
LJ
Emission Factor
(lb/1012 Btu)
Mean8
840
3,000
12,300d
2,300
22,200d
Range Boiler Type
Overfeed Stoker
Overfeed Stoker
1,600-23,000 Overfeed Stoker
Overfeed Stoker
16,500-28,000 Overfeed Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Economizer/Dust
Collector
Reference
Burlingame et al.,
Burlingame et al. .
Burlingame et al . .
Burlingame et al.,
Burlingame et al..
1981
1981
1981
1981
1981
This column gives arithmetic mean values for each boiler tested. Footnotes indicate how many measurements each
mean represents, if this information was included in the reference. If only a single measurement was reported,
it is included in this column.
Average for three boilers.
Ł
Reference noted that corrosion of sampling train components may explain higher than expected nickel emissions
measurement s.
Average of two tests of the same boiler.
f*
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of control device.
Average of three tests of the same boiler.
-------
TABLE E-77. MEASURED NICKEL EMISSION FACTORS FOR SUBBITUMINOUS COAL-FIRED INDUSTRIAL BOILERS
Emission Factor
(lb/1012 Btu)
Mean
3900b
840
30
Range Boiler Type
1300-6500 Spreader Stoker
Spreader Stoker
Spreader Stoker
Control Status
Uncontrolled
Uncontrolled
Mechanical Ppt/ESP
Reference
BurlinRame et al . , 1981
Goldberg and Higginbotham,
Goldberg and Higginbotham,
1981
1981
rt
This column gives arithmetic mean values for each boiler tested. Footnotes indicate how many measurements each
i mean represents, if this information was included in the reference. If only a single measurement was reported,
P- it is included in this column.
Mean of two tests of the same boiler.
c
Traveling grate spreader stoker with re-injection from the dust collector. Measured upstream of controls.
-------
TABLE E-78. MEASURED NICKEL EMISSION FACTORS FOR COMMERCIAL/INSTITUTIONAL COAL-FIRED BOILERS
Emission Factor
(lb/1012 Btu)
Type of Coal
Boiler Type
Control Status
Reference
w
i
00
Ol
2430
309
30
91
1530
314
1070
1090
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Anthracite
Anthracite
Anthracite
Pulverized Dry Bottom
Pulverized Dry Bottom
Underfeed Stoker
Spreader Stoker
Overfeed Stoker
Stoker
Stoker
Stoker
Uncontrolled
Multiclone/Scrubher
Uncontrolled
Mechanical Ppt.
Mechanical Ppt.
Uncontrolled
Uncontrolled
Uncontrolled
Suprenant et al.. 1980b
Suprenant e_t al.. 1980b
Suprenant e_t. al.. 1980b
Suprenant ejt al.. 1980b
Suprenant et al.. 1980b
Suprenant e_t al.. 1980b
Suprenant e_t aL^. 1980b
Suprenant e_t al,. 1980b
-------
TABLE E-79. MEASURED NICKEL EMISSION FACTORS FOR COAL-FIRED RESIDENTIAL FURNACES
w
CD
C^
Emission Factor
(lb/1012 Btu)
3.9
1550
534b
303 Ob
Coal Type
Bituminous
Bituminous
Bituminous
Bituminous-washed
Furnace Type
NRa
NR
Harm
with
Warm
with
Air Furnace
Stoker
Air Furnace
Stoker
Control Status
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Reference
De Angel is
DeAngelis
De Angel is
DeAngelis
and Reznik,
and Reznik,
, 1979
, 1979
1979
1979
NR = not reported.
Average of two tests of the same boiler.
-------
TABLE E-80. MEASURED URANIUM-238 EMISSION FACTORS FOR COAL-FIRED UTILITY BOILERS
Emission Factor*
pCi/g
37.5
5.6
4.2
7.1
0.5
9.2
w
oo 7.6
-vl
7
4.4
3.0
3.3
4.1
7.2
7
8.6d
8.1
pCi/106 Btu
3214
73
350
22
13
675
210
6
227
68
248
301
486
101
511
482
.3
.7
.5
.5
.8
.9
.4
.3
.5
.0
.4
.2
.5
.6
.5d
.5
Coal Type
Subbituminous
Lignite
Lignite
Lignite
Lignite
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
.
b
b
b
b
b
b
b
b
b
b
b
Boiler
Cyclone
Pulverized
Pulverized
Pulverized
Stoker
Pulverized
Pulverized
Pulverized
Pulverized
Cyclone
Pulverized
Cyclone
NRC
NR
Pulverized
Pulverized
Type
Dry Bottom
Dry Bottom
Dry Bottom.
Dry Bottom
Dry Bottom
Dry Bottom
Dry Bottom
Dry Bottom
Dry Bottom
Dry Bottom
Control Status
Scrubber
Cyclone/ Scrubber
ESP
ESP/Scrubber
Cyclone /ESP
ESP
ESP
ESP
ESP
ESP
ESP
Scrubber
ESP
ESP
ESP
ESP
Roeck et
Roeck et
Roeck et
Roeck et
Roeck et
Roberson
Robe r son
Roberson
Roberson
Roberson
Roberson
Roberson
Roberson
Roberson
Roberson
Roberson
al.
al.
al.
al.
al.
and
and
and
and
and
and
and
and
and
and
and
Reference
, 1983
, 1983
, 1983
, 1983
, 1983
Eggleston,
Eggleston,
Eggleston,
Eggleston,
Eggleston,
Eggleston,
Eggleston,
Eggleston,
Eggleston,
Eggleston,
Eggleston,
1983
1983
1983
1983
1983
1983
1983
1983
1983
1983
1983
-------
TABLE E-80. MEASURED URANIUM-238 EMISSION FACTORS FOR COAL-FIRED UTILITY BOILERS (Continued)
o
Emission Factor
pCi/g pCi/10 Btu
34.2
0.017
0.005
0 .004
0.003
Coal Type
NR
NR
NR
NR
NR
Boiler Type
Cyclone
Cyclone
Pulverized, Slag Bottom
Stoker
Control Status
ESP
Scrubber
ESP
Mech. Ppt/ESP
Fabric Filter
Reference
Coles
Office
Office
Office
Office
et al., 1978
of Radiation
of Radiation
of Radiation
of Radiation
Programs ,
Programs ,
Programs ,
Programs ,
1979
1979
1979
1979
oo where heating values were available from the reference, emission factors expressed as pCi/g were converted to
pCi/10 Btu heat input.
Reference specified that all plants tested were burning bituminous and/or subbituminous coals.
NR = not reported.
Average of three tests on one unit.
-------
TABLE E-81. MEASURED THORIUM-232 EMISSION FACTORS FOR COAL-FIRED UTILITY BOILERS
Emission Factor8
w
oo
vp
pCi/g
2.8b
2.8b
2.68
2.78
0.60
7.14
0.5
1.9
5.3
12e
2.2
1.8
2.4
1.5
pCi/106 Btu
171.2b
167 .8b
229.7
36.5
50.3
22.7
13.8
360
146.6
10.9
113.7
40.8
180.7
110.2
Coal Type
NRC
NR
Subbituminous
Lignite
Lignite
Lignite
Lignite
d
Bituminous
Bituminous
Bituminous
d
Bituminous
Bituminous
Bituminous
Bituminous
Boiler Type
Pulverized
Pulverized
Cyclone
Pulverized
Pulverized
Pulverized
Stoker
Pulverized
Pulverized
Pulverized
Pulverized
Cyclone
Pulverized
Cyclone
Dry
Dry
Dry
Dry
Dry
Dry
Dry
Dry
Dry
Dry
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
Control Status
ESP
ESP
Scrubber
Cyclone/ Scrubber
ESP
ESP/Scrubber
Cyclone /ESP
ESP
ESP
ESP
ESP
ESP
ESP
Scrubber
Reference
Roberson
Roberson
Roeck e_t
Roeck et
Roeck et
Roeck et
Roeck et
Roberson
Roberson
Roberson
Roberson
Roberson
Roberson
Roberson
and
and
al.
al.
al.
al.
JLU
and
and
and
and
and
and
and
Eggleston,
Eggleston,
, 1983
, 1983
, 1983
, 1983
, 1983
Eggleston,
Eggleston,
Eggleston,
Eggleston,
Eggleston,
Eggleston,
Eggleston,
1983
1983
1983
1983
1983
1983
1983
1983
1983
aWhere heating values were available from the reference, emission factors expressed as pCi/g participate emissions
o
were converted to pCi/10 Btu heat input.
Average of three tests on one unit.
NR = not reported.
Reference specified that all plants tested were burning bituminous and/or subbituminous coal.
"Reference noted that error may be >30 percent. Not used in calculation of mean or range.
-------
TABLE E-82. TOTAL POM EMISSIONS FROM PULVERIZED COAL-FIRED UTILITY BOILERS
Boiler Characteristics
Coal Type
Controls Used
Total POM fin ission Factor
lb/1012 Btu-Heat Input
Reference
M
I
Horizontally Opposed a
Front Hall-Fired a
Corner Fired a
Vertically-Fired a
Dry Bottom a
Tangentially-Fired Subbituninous
Vertically-Fired Bituninous
Front Hall-Fired Bituminous
Dry Bottom Bituninous
Dry Bottom Bituminous
Dry Bottom Bituminous
Het Bottom Bituminous
Wet Bottom Bituminous
Dry Bottom, Front Hall-Fired Lignite
Dry Bottom, Front Hall-Fired Lignite
Dry Bottom, Front Hall-Fired Lignite
Dry Bottom, Vertically-Fired a
Dry Bottom, Vertically-Fired a
Dry Bottom, Front Hall-Fired a
Dry Bottom, Tangentially-Fired a
Het Bottom, Opposed-Fired &
a
a
a
ESP
ESP
ESP
Het Scrubber
Hulticyclone/ESP
Hulticyclone/ESP
ESP
Het Scrubber
Hulticyclones
Multicyclones
ESP
None
Multicyclone/ESP
ESP
Hulticyclone/ESP
Multicyclones
0.03 - 4.5
b.c
1.1
b,d
b.e
2.2 - 2.7
0.32 - 1.6b
0.88
0.7h
6.5h
1.71
8.55j'K
0.033
j.l
18.6j'n
565j>°
18.3j>p
2.6J-P
0.75 - 9.7q'r
0.7 - 1.6q>8
0.4 - 1.4q>t
2.2<ť'u
0.8 - 4.6q>v
Barrett et. al. . 1983
Barrett et. al. . 1983
Barrett e_t al. . 1983
Barrett ej. al.. 1983
Hangebrauck e_t al. . 1964
Haile et al.. 1983
Haile si al.. 1983
Haile et al.. 1983
Shih Łt. al.. 1980b
Shih et. al.. 1980b
Shih et. al.. 1980b
Shih e_t. al.. 1980b
Shih et, al.. 1980b
Shih el al.. 1980b
Shih e_t al.. 1980b
Shih e_t al.. 1980b
Hangebrauck et_ al. . 1967
Hangebrauck et al.. 1967
Hangebrauck et al.. 1967
Hangebrauck e_t al.. 1967
Hangebrauck et al.. 1967
flData not reported in available literature.
Factor represents only particulate POM emissions.
-------
TABLE E-82. TOTAL POM EMISSIONS FROM PULVERIZED COAL-FIRED UTILITY BOILERS (Continued)
Specific POM compounds identified in these emissions include benzo(a)pyrene, benzo(g ,h, i)pery lene, coronene, 7 ,12-dimethy 1 benz(a )anthracene,
fluoranthene, 3-methylcholanthrene, benzo(e)pyrene, and pyrene.
The primary constituents of total POM emissions were benzoCe )pyrene (45 percent), pyrene (35 percent), fluoranthene (16 percent), benzoCa )pyrene
(4 percent), and benzo(g,h,i)perylene (1 percent).
eSpecific POM compounds identified in these emissions include anthanthrene, anthracene, benz(a)anthracene, benzo(a)pyrene, benzo(e)pyrene,
benzo(g,h,i)perylene, coronene, fluoranthene, perylene, phenanthrene, and pyrene. The primary constituents of total POM emissions were
fluoranthene (33-40 percent), benzo(g,h,i)perylene (12-15 percent), pyrene (12-14 percent), and benzo(a)pyrene (12-14 percent).
Specific POM compounds identified in these emissions include benz(a)anthracene, benzo(a)pyrene, benzo(e )pyrene, benzo(g,h, i)pery lene,
fluoranthene, perylene, phenanthrene, and pyrene. The principal constituents of total POM emissions were fluoranthene (36-53 percent), pyrene
(22-42 percent), and benzo(a)pyrene (3-17 percent).
Factor represents predominantly particulate POM. Eleven specific POM compounds were analyzed for during these tests. Specific compounds
identified were pyrene, benzo(a)pyrene, benzo(e)pyrene, fluoranthene, and benz(a)anthracene. Pyrene and fluoranthene accounted for 90 percent
of total POM emissions.
Factor represents both particulate and gaseous POM. Nine specific POM compounds were analyzed for during these tests. Specific compounds
identified were naphthalene, acenaphthylene, fluorene, phenanthrene, fluoranthene, pyrene, chrysene, and benzo(a)pyrene. Naphthalene and
phenanthrene accounted for 85 percent of total POM emissions. Factor represents average of five tests of the same boiler.
1Factor represents both particulate and gaseous POM. Nine specific POM compounds were analyzed for during these tests. Specific compounds
identified were naphthalene, fluorene, phenanthrene, fluoranthene, and chrysene. Naphthalene and phenanthrene accounted for about 91 percent
of total POM emissions. Factor represents average of five tests of the same boiler.
^Factor represents both particulate and gaseous POM. Fifty-six specific POM compounds were analyzed for during these tests.
Specific compounds identified were biphenyl, benzo(g,h,i)perylene, o-phenylenepyrene, dibenz(a,h)anthracene, picene, and dibenz(a,c)anthracene.
Benzo(g,h,i)perylene, o-phenylenepyrene, and dibenz(a,h)anthracene accounted for about 82 percent of total POM emissions.
1
Specific compounds identified were phenyl naphthalene and biphenyl, with phenyl naphthalene constituting 66 percent of total POM emissions.
""Specific compounds identified were naphthalene and biphenyl, with naphthalene constituting 90 percent of total POM emissions.
DSpecific compounds identified were naphthalene and phenanthrene, with naphthalene constituting 73 percent of total POM emissions.
"Specific compounds identified were naphthalene, biphenyl, phenanthrene, pyrene, fluoranthene, chrysene, benzo(a)pyrene, benzo(e)pyrene,
benzo(b)f luoranthene, benzo(g,h,i)perylene, and indenod ,2,3-c,d)pyrene. Total POM emissions consisted primarily of naphthalene (26 percent),
phenanthrene (23 percent), pyrene (16 percent), and chrysene (10 percent).
PReported value is for trimethyl propenyl naphthalene.
^Factor represents predominantly particulate POM. Ten specific POM compounds were analyzed for during these tests.
Specific compounds identified were benzo(a)pyrene, pyrene, benzo(g,h,i)perylene, anthanthrene, fluoranthene, benzo(e)pyrene, perylene, coronene,
anthracene, and phenanthrene. Fluorene, phenanthrene, and pyrene were generally the predominant POM compounds measured.
Specific compounds identified were benzo(a)pyrene, pyrene,. fluoranthene, benzo(e)pyrene, perylene, and benzo(g ,h, i)pery lene. Pyrene and
fluoranthene were generally the dominant POM compounds measured. However, in one test, total POM emissions consisted of the following
distribution: benzo(a )pyrene (27 percent), fluoranthene (18 percent), benzo(e )pyrene (17 percent), benzo(g,h,i)pery lene (18 percent), and
pyrene (16 percent).
Specific compounds identified were benzo(a)pyrene, pyrcne, benzo(e )pyrene, benzo(g ,h, i)pery lene, phenanthrene, and fluoranthene. Pyrene,
phenanthrene, and fluoranthene accounted for the majority of total POM emissions.
Specific compounds identified were benzo(a )pyrene, pyrene, benzoCe )pyrene, perylene, benzo(g,h, i )pery lene, anthanthrene, coronene, phenanthrene,
and f luoranthrene. Fluoranthene, pyrene, benzo(a )pyrene, and benzo(g,h, Operylene accounted for 80 percent of total POM emissions.
Specific compounds identified were benzo(a )pyrene, pyrene, fluoranthene, coronene, benzo(g ,h, Opery lene , and benzo(e )pyrene. Benzo(g ,h, i)-
perylene, fluoranthene, and benzoCe)pyrene were the compounds generally constituting the majority of total POM emissions.
-------
TABLE E-83. TOTAL POM EMISSIONS FROM CYCLONE
COAL-FIRED UTILITY BOILERS
Coal Type
a
a
Bituminous
Bituminous
Bituminous
Bituminous
Lignite
Lignite
Bituminous
Bituminous
Controls Used
ESP
a
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Wet Scrubber
Total POM
Emission.. Factor
lb/101^
Btu-heat Input
1.2 - 7.4b
4.3C
2.04d
0.46d
57.2Ž'f
2.7e,g
O.lle'h
i.e6-1
5.6e'j
16.2e>k
Reference
Hangebrauck et al. . 1967
Barrett et al. . 1983
Haile et al. . 1983
Haile et al. . 1983
Shih et al. . 1980b
Shih et al. . 1980b
Shih et al. . 1980b
Shih et al. . 1980b
Shih et al.. 1980b
Shih et al. . 1980b
Data were not reported in the available literature.
Factor represents predominantly particulate POM emissions. Ten specific
POM compounds were analyzed for during these tests. Specific compounds
identified were benzo(a)pyrene, pyrene, benzo(e)pyrene, perylene,
benzo(g,h,i)perylene, coronene, and fluoranthene. Pyrene, benzo(e)pyrene,
benzo(a)pyrene, and benzo(g,h,i)perylene accounted for the majority of
total POM emissions.
Factor represents only particulate POM emissions. The principal
constituents of total POM emissions were pyrene (53 percent), benzo(e)pyrene
(20 percent), benzo(a)pyrene (11 percent), benzo(g,h,i)perylene (10 percent),
and fluoranthene (4 percent).
Factor represents both particulate and gaseous POM emissions. Nine specific
POM compounds were analyzed for during these tests. Specific compounds
identified were naphthalene, fluorene, phenanthrene, and chrysene.
Naphthalene constituted from 90 to 99 percent of total POM emissions. Factor
represents the mean of five tests of the same boiler.
Factor represents both particulate and gaseous POM emissions. Fifty-six
specific POM compounds were analyzed for during these tests.
E-92
-------
TABLE E-83.
TOTAL POM EMISSIONS FROM CYCLONE
COAL-FIRED UTILITY BOILERS (Continued)
Reported value is for naphthalene. No other POM compounds were detected.
"Reported value is for phenyl naphthalene. No other POM compounds were
detected.
Reported value is for biphenyl. No other POM compounds were detected.
Reported value is for trimethyl propenyl naphthalene. No other POM
compounds were detected.
^Specific compounds identified were ethyl biphenyl, phenanthrene, and
methylphenthrene. Methylphenthrene constituted 84 percent of total POM
emissions.
Specific compounds identified were biphenyl, decahydronaphthalene, ditert-
butyl naphthalene, dimethyl isopropyl naphthalene, hexamethyl biphenyl,
hexamethyl hexahydro indacene, dihydronaphthalene, C-~ substituted
naphthalene, C.Q substituted decahydronaphthalene, methyl naphthalene,
anthracene/phenanthrene, 9,10-dihydronaphthalene/1-1' diphenylethene,
1,1'-bis (p-ethylphenyl)-ethane/tetramethyl biphenyl, 5-methyl-benz-c-
acridine, and 2,3-dimethyl decahydronaphthalene. Biphenyl, l,l-bis(p-
ethylphenyl)-ethane/tetramethyl biphenyl, and methyl naphthalene constitute
almost 80 percent of total POM emissions.
E-93
-------
TABLE E-84. TOTAL POM EMISSIONS FROM STOKER COAL-FIRED UTILITY BOILERS
Boiler Characteristics
Coal Type Controls Used
Total POM Emission Factor
lb/10 Btu-heat Input
Reference
Spreader, Traveling Grate
Chain Grate
Spreader
Chain Grate
a
a
Spreader
a
a
a
a
Bituminous
Bituminous
Lignite
Multicyclones
a
a
a
Baghouse
Multicyclones
Multicyclones
0.13 - 0.47'
114C
0.46d
e
2.7
92.1
12.0
14.6J
f,h
Hangebrauck et al.. 1967
Barrett e_t al. . 1983
Barrett e_t al^, 1983
Hangebrauck et al.. 1964
Shih et_ al., 1980b
Shih et_ al. . 1980b
Shih e_t al. . 1980b
w
Data not reported in the available literature.
Factor represents primarily particulate POM emissions. Ten specific POM compounds were analysed for during
these tests. Specific compounds identified were benzo(a)pyrene, pyrene, benzo(e)pyrene, coronene, and
fluoranthene. Pyrene, fluoranthene, and benzole)pyrene constitute the majority of total POM emissions.
ft ^^
Factor represents only particulate POM emissions. The primary constituents of total POM emissions were
fluoranthene (30 percent), pyrene (22 percent), phenanthrene (22 percent), benzo(a)pyrene (15 percent),
benzophenanthrene (5 percent), and 1,2-benzofluorene (4 percent).
Factor represents only particulate POM emissions. The primary constituents of total POM emissions were pyrene
(50 percent), fluoranthene (24 percent), benzo(e)pyrene (14 percent), benzo(a)pyrene (<10 percent), and
coronene (3 percent).
A f
Factor represents primarily particulate POM emissions. Eleven specific POM compounds were analyzed for during
these tests. Specific compounds identified were benzo(a)pyrene, pyrene, benzo(e)pyrene, and fluoranthene.
Fluoranthene and pyrene accounted for about 87 percent of total POM emissions.
Factor represents both particulate and gaseous POM emissions. Fifty-six specific POM compounds were analyzed
for during these tests.
^Specific compounds identified were naphthalene and a mixture of 3,8-dimethyl-5-(l-methyl ethy1)-1s2-naphthalene
dione and trimethyl naphthalene. The naphthalene mixture constituted 97 percent of total POM emissions.
Specific compounds identified were naphthalene, phenyl naphthalene, and 2-ethyl-l,1'-bipheny1. Phenyl
naphthalene and 2-ethyl-l,1'-bipheny constituted 96 percent of total POM emissions.
1Reported value is for trimethyl propenyl naphthalene. No other POM compounds were detected.
-------
TABLE E-85. MEASURED TOTAL POM EMISSION FACTORS FOR PULVERIZED COAL-FIRED INDUSTRIAL BOILERS
w
VO
ur
Boiler
Characteristics
Coal Type
Controls Used
Total POM Emission Factor
lb/10 Btu-heat Input
Reference
Dry Bottom,
Water tube
Bituminous
Multicyclones
2.8a
Range brauck et
al . ,
1964
Watertube
Wet Bottom
Dry Bottom,
Horizontally-Fired
Bituminous
Bituminous
Bituminous
ESP
Cyclones/ESP
ESP
68.0
121
6.6
d
Suprenant et al.. 1980a
Suprenant et al.. 1980a
McCurley e_t aK., 1979
aFactor represents primarily particulate POM emissions. Eleven specific POM compounds were analyzed for
during these tests. Specific compounds identified were benzo(a)pyrene, pyrene, benzo(e)pyrene, anthracene,
and fluoranthene. Fluoranthene, anthracene, and pyrene accounted for 90 percent of total POM emissions.
Factor represents both particulate and gaseous POM emissions. Specific compounds identified were anthracene/
phenanthrene, fluoranthene, dibenzothiophene, methylanthracenes/phenanthrenes, dimethyIanthracenes/
phenanthrenes, methylfluoranthenes/pyrenes, benzo(c)phenanthrene, dimethylbenz(a)anthracenes, methylchol-
anthrenes, indenod,2,3-c,d)pyrene, benzofluoranthenes, dibenz(a,h)anthracene, dibenzopyrenes, and
methylchrysenes. The primary constituents of total POM emissions are benzofluoranthenes (38 percent),
fluoranthene (18 percent), anthracene/phenanthrene (18 percent), and methylcholanthrenes (10 percent).
CFactor represents both particulate and gaseous POM emissions. Fifty-six specific POM compounds were analyzed
for during these tests. Specific compounds identified were biphenyl, phenanthrene, pyrene, naphthalene, and
benzo(g,h,i)perylene. Phenanthrene and naphthalene constituted 93 percent of total POM emissions.
Factor represents both particulate and gaseous POM emissions. Specific compounds identified were dibenzo-
thiophene, anthracene/phenanthrene, methylanthracenes/phenanthrenes , dimethylanthracenes/phenanthrenes,
fluoranthene, pyrene, methyl fluoranthenes/pyrenes, benzo(c)phenanthrene, chrysene/benz(a)anthracene,
dimethylbenz(a)anthracenes, benzofluoranthenes, benzopyrenes/perylene, methylcholanthrenes, indenod ,2 ,3-c,d)-
pyrene, dibenz(a,h)anthracene, dibenzo(c,g)carbazole, dibenzopyrenes, methylchrysenes, anthracene/
benzo(g,h,i)perylene. The primary constituents of total POM emissions are chrysene/benz(a)anthracene
(41 percent), benzofluoranthenes (22 percent), fluoranthene (11 percent), and anthracene/phenanthrene
(11 percent).
-------
TABLE E-86. MEASURED TOTAL POM EMISSION FACTORS FOR STOKER COAL-FIRED INDUSTRIAL BOILERS
Characteristics
vo
Coal Type
Controls Used
Total POM Emission Factor
lb/10 Btu-heat Input
Reference
Spreader Stoker
Underfeed Stoker
Chain Grate Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Maes-Fired Overfeed
Stoker
a
a
a
Bituninous
Bituminous/
Subbituminous
Bituminous
Bituminous
Multicyclones
None
None
Cyclones/ESP
None
None
None
2.97b'c
197b,d
2.7b'e
413f
13.7g'h
10.0E>1
32 9g,j
Hangebrauck et al . . 1964
Hangebrauck e_t al . . 1964
Hangebrauck et al . . 1964
Suprenant e_t al. . 1980
Burlingame et al . . 1981
Burlingame et al. . 1981
Burlingame e_t_ al . . 1981
Data not reported in the available literature.
Factor represents primarily particulate POM emissions. Eleven specific POM compounds were analyzed for during these
tests.
'Specific compounds identified were benzo(a)pyrene, pyrene, benzo(e)pyrenet coronene, and fluoranthene. Pyrene,
benzo(e)pyrene, and fluoranthene constitute 96 percent of total POM emissions.
Specific compounds identified were beaso(a )pyrene, pyrene, benzo(e)pyrenes perylene, coronene, fluoranthene,
phenanthrene, anthracene, anthanthrene,, and benzo(g,h,i)perylene. The primary constituents of total POM emissions are
fluoranthene (42 percent), pyrene (18 percent), benzo(a)pyrene (11 percent), phenanthrene (11 percent), and benzo(e)-
pyrene (9 percent).
eSpecific compounds identified were benzo(a )pyrene, pyrene, benzo(e)pyrene, and fluoranthene. Fluoranthene and pyrene
accounted for 87 percent of total POM emissions.
Factor represents both particulate and gaseous POM emissions. Fifty-six specific POM compounds were analyzed for during
these tests. Specific compounds identified were naphthalene, phenanthrene, fluoranthene, pyrene, chrysene, benzo(a)-
pyrene, o-phenylene pyrene, and benzo(g,h, Operylene. The primary constituents of total POM emissions were phenanthrene
(31 percent), pyrene (30 percent), chrysene (16 percent), and naphthalene (11 percent). Factor represents the average
of three tests.
^Factor represents both particulate and gaseous POM em lesions. Twenty-one specific POM compounds were analyzed for
during these tests. Generally, the majority of POM was measured in a gaseous as opposed to particulate phase.
This factor is the average of single emission tests on three boilers. The range of emissions was 1.28 to 31.3 lb/10
Btu. For the three tests, total POM factors ranged from 0.55 to 13.5 pg/J (1.28 to 31.3 lb/10 Btu). The primary
constituents of total POM emissions were phenanthrene (64 percent), fluoranthene (17 percent), and pyrene (6 percent).
1This factor is the average of single emission tests on three boilers. The range of emissions was 1.21 to 43.4 lb/10
Btu. For the three tests, total POM factors ranged from 0.52 to 18.7 pg/J (1.21 to 43.4 lb/10 Btu). The primary
constituents of total POM emissions were phenanthrene (51 percent), me thyIanthracenes/phenanthrenes (23 percent), and
fluoranthene (11 percent).
^This factor is the average of single emission tests on five boilers. The range of emjgGions was 1.3 to 210 lb/10 Btu.
For the five tests, total POM factors ranged from 0.56 to 90.3 pg/J (1.3 to 210 lb/10 Btu). The primary constituent!,
of total POM emissions were phenanthrene (32 percent), anthraceme (3O percent), and fluoranthene (30 percent).
-------
TABLE E-87. MEASURED UNCONTROLLED TOTAL POM EMISSION FACTORS FOR
RESIDENTIAL AND SMALL COMMERCIAL BOILERS
Boiler Type
Coal Type
Total POM Emission Factor
lb/10 Btu-heat Input
Reference
W
.vo
Underfeed Stoker
Cast Iron Underfeed Stoker
Hand Stoked Hot Air Furnace
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker Hot Air Furnace
Underfeed Stoker Hot Air Furnace
Hand Stoked Hot Air Furnace
Hand Stoked Hot Air Furnace
Underfeed Stoker
Underfeed Stoker
Underfeed 'Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Underfeed Stoker
Bituminous
Bituminous
High-Volatile Bituminous
High-Volatile Bituminous
High-Volatile Bituminous
High-Volatile Bituminous
High-Volatile Bituminous
High-Volatile Bituminous
Subbi t urn inou s
Subbituminous
Subbituminous
Subbituminous
Subbituminous
low-Volatile Bituminous
Processed Lignite Char
Anthracite
Anthracite
Bituminous
Bituminous
13.8
,b.c
210
8,780
,b.d
,b,e
3,285b'f
2,076
1,881
432*
32,800
84,561
3,480
b.g
b.h
,b,j
b.k
1
Pl
395'
13.4001'*
12.8001'111
3,6001>m
1.9201'"
l,3801>m
8441>n
1.9701'"
2.1501'"
6581'1"
1.6101'"
1.4101''
4,0501>n
374
159
l.o
l.o
22.2
18,000P
2 ,000P
l.o
Hangebrauck et. al.. 1964
Hangebrauck et. al.. 1964
Hangebrauck et. al.. 1964
Hangebrauck e_t al. . 1967
Hangebrauck et al.. 1967
Hangebrauck e_t al. . 1967
Hangebrauck et. al.. 1967
Hangebrauck et al.. 1967
Hangebrauck et al.. 1967
Suprenant et_ al. . 1980b
Suprenant e_t al,. 1980b
Giammar et, al. . 1976
Giammar e_t al.. 1976
Giammar et. al.. 1976
Giammar et al. . 1976
Giaromar et. ai... 1976
Giammar et. al. . 1976
Giammar et. al.. 1976
Giammar e_t al.. 1976
Giammar et. al.. 1976
Giammar ej. al.. 1976
Giammar et_ al.. 1976
Giammar et. al. . 1976
Giammar e_t al.. 1976
Giammar et. al.. 1976
Giammar et. al. . 1976
DeAngelis and Reznik, 1979
DeAngel is and Reznik, 1979
-------
TABLE E-87. MEASURED UNCONTROLLED TOTAL POM EMISSION FACTORS FOR
RESIDENTIAL AND SMALL COMMERCIAL BOILERS (Continued)
Total POM Emission Factor
Boiler Type Coal Type lb/10 Btu-heat Input Reference
Magazine Feed
Magazine Feed
Hand Stoked
Magazine Feed
Magazine Feed
Hand Stoked
Anthracite
Anthracite
Anthracite
Bituminous
Bituminous
Bituminous
49.4q>r
9.7q'8
57. 5"'1
8.177"'"
2.632"'v
4.274<>'w
Sanborn et al. ,
Sanborn et al . .
Sanborn et al .
Sanborn et al . ,
Sanborn et al . ,
Sanborn et al . .
1983
1983
1983
1983
1983
1983
Data not reported in the available literature.
Factors represent primarily particulate POM emissions. Ten specific POM compounds were analyzed for during these tests.
Specific compounds identified were benzo(a )pyrene, pyrene, benzo(e )pyrene, phenanthrene, and f luoranthene. The primary constituents of
total POM emissions were fluoranthene (51 percent), pyrene (27 percent), and phenanthrene (16 percent).
Specific compounds identified were benzo(a )pyrene, pyrene, benzo(e )pyrene, benzo(g,h,i)pery lene, coronene, phenanthrene, and
fluoranthene. The primary constituents of total POM emissions were fluoranthene (50 percent), phenanthrene (31 percent), and pyrene
(8 percent).
Specific compounds identified were benzo(a )pyrene, pyrene, benzo(e)pyrene, benzo(g,h, i)pery lene, coronene, perylene, anthanthrene,
anthracene, phenanthrene, and fluoranUiene. The primary constituents of total POM emisisons were phenanthrene (25 percent),
fluoranthene (25 percent), pyrene (15 percent), anthracene (10 percent), and benzo(x )pyrene (10 percent).
All ten POM compounds listed in footnote e were also identified in these emissions. The primary constituents of total POM emissions
were phenanthrene (41 percent), fluoranthene (22 percent), pyrene (20 percent), and anthracene (5 percent).
8A11 ten POM compounds listed in footnote e except coronene were also identified in these emissions. The primary constituents of total
POM emissions were phenanthrene (37 percent), pyrene (20 percent), fluoranthene (16 percent), and benzo(a)pyrene (9 percent).
All ten POM compounds listed in footnote e were also identified in these emissions. The primary constituents of total POM emissions
were fluoranthene (37 percent), phenanthrene (20 percent), pyrene (19 percent), and benzo(a)pyrene (8 percent).
XA11 ten POM compounds listed in footnote e except coronene and anthanthrene were also identified in these emissions. The primary
constituents of total POM emissions were fluoranthene (39 percent), phenanthrene (26 percent), and pyrene (23 percent).
All ten POM compounds listed in footnote e were also identified in these emissions. The primary constituents of total POM emissions
were fluoranthene (29 percent), pyrene (18 percent), phenanthrene (15 percent), benzo(a)pyrene (11 percent), and benzo(g,h, Dperylene
(9 percent).
All ten POM compounds listed in footnote e were also identified in these emissions. The primary constituents of total POM emissions
were fluoranthene (29 percent), pyrene (24 percent), phenanthrene (20 percent), and benzo(a)pyrene (9 percent).
Factor represents both particulate and gaseous POM emissions. Twenty-two specific POM compounds were analyzed for during these tests.
The compounds analyzed for included anthracene, phenanthrene, methyl anthracenes, fluoranthene, benzo(c)phenanthrene, chrysene,
benzta )anthracene, methyl chrysenes, 7 ,12-dimethy lbenz(a)anthracene, benzof luoranthenes, benzo(a)pyrene, benzo(e)pyrene, perylene,
3-nethylcholanthrene, indenod ,2 ,3-c,d)pyrene, benzo(g,h, Dperylene, dibenzo(a,h)anthracene, dibenzo(c,g)carbazole, dibenzo(a, Opyrene,
and dibenzo(a,h)pyrene.
-------
TABLE E-87. MEASURED UNCONTROLLED TOTAL POM EMISSION FACTORS FOR
RESIDENTIAL AND SMALL COMMERCIAL BOILERS (Continued)
The predominant POM compounds occurring during high-volatile bituminous coal combustion were anthracene, phenanthrene. methyl
anthracenes, fluoranthene, pyrene, and methyl pyrene/fluoranthene.
The predominant POM compounds occurring during low-volatile bituminous coal combustion were anthracene, phenanthrene, methyl
anthracenes, fluoranthene, chrysene/benz(a)anthracene, methyl chrysenes, pyrene, and methyl pyrene/fluoranthene.
The predominant POM compounds occurring during processed lignite char and anthracite coal combustion were anthracene, phenanthrene,
methyl anthracenes, fluoranthene, pyrene, chrysene/benz(a)anthracene, and benzofluoranthenes.
''Factor represents both particulate and gaseous POM emissions. Individual POM compounds measured were not identified.
''Factor represents both particulate and gaseous POM emissions. Eighteen specific POM compounds were analyzed for during these tests.
rThe primary constituents of total POM emissions were phenanthrene (23 percent), fluoranthene (18 percent), pyrene (13 percent),
chrysene (12 percent), benzo(a)anthracene (11 percent), and naphthalene (11 percent). The test was conducted under high burn rate
conditions.
SThe primary constituents of total POM emissions were fluoranthene (26 percent), phenanthrene (25 percent), pyrene (15 percent),
chrysene (6 percent), acenaphthene (4 percent), acenaphthylene (A percent), benzo(a)anthracene (4 percent), and benzo(k)fluoranthene
(4 percent). The test was conducted under low burn rate conditions.
The primary constituents of total POM emissions were naphthalene (31 percent), phenanthrene (20 percent), acenaphthylene (14 percent),
fluoranthene (10 percent), pyrene (8 percent), and chrysene (3 percent). The test was conducted under moderate burn rate conditions.
UThe primary constituents of total POM emissions were acenaphthylene (24 percent), naphthalene (18 percent), phenanthrene (17 percent),
fluoranthene (8 percent), anthracene (5 percent), pyrene (5 percent), fluorene (5 percent), and benzo(k)fluoranthene (4 percent). The
test was conducted under high burn rate conditions.
VThe primary constituents of total POM emissions were naphthalene (19 percent), phenanthrene (16 percent), anthracene (9 percent),
benzo(k)fluoranthene (8 percent), fluorene (8 percent), fluoranthene (7 percent), pyrene (6 percent), benzo(a)pyrene (5 percent), and
benzo(a)anthracene (4 percent). The test was conducted under low burn rate conditions.
VThe primary constituents of total POM emissions were naphthalene (11 percent), acenaphthylene (11 percent), phenanthrene (11 percent),
benzo(k)fluoranthene (9 percent), fluoranthene (9 percent), fluorene (7 percent), pyrene (6 percent), benzo(a )anthracene (6 percent),
anthracene (5 percent), indeno(l,2,3-c,d)perylene (5 percent), and chrysene (5 percent). The test was conducted under moderate burn
rate conditions.
------- |