GCA-TR-76-24-G
Screening Study To Obtain Information Necessary For The
Development Of Standards Of Performance For Oil-Fired And Natural
Gas-Fired Boilers < 63 x 106 Kcal/hr Input (±250 x Iff Btu/hr Input)
Final Report
Contract No. 68-02-1316
Task Order No. 22
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Research Triangle Park
North Carolina
September 1976
GCA/TECHNOLOGY DIVISION
BEDFORD, MASSACHUSETTS 01730
-------
GCA-TR-76-24-G
SCREENING STUDY TO OBTAIN INFORMATION
NECESSARY FOR THE DEVELOPMENT OF STANDARDS OF
PERFORMANCE FOR OIL-FIRED AND NATURAL GAS-FIRED
BOILERS <_ 63 x 10& Kcal/hr INPUT
(< 250 x 106 Btu/hr INPUT)
FINAL REPORT
by
Arthur S. Werner
Manuel T. Rei
Robert J. Keeth
Norman F. Surprenant
Paul F. Fennelly
Lawrence A. Gordon
Theodore P. Midurski
GCA CORPORATION
GCA/TECHNOLOGY DIVISION
Bedford, Massachusetts
September 1976
Contract No. 68-02-1316
Task Order No. 22
EPA Project Officer
Bradley W. Smith
Office of Air Quality and Planning
Emissions Standards and Engineering Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Research Triangle Park
North Carolina
-------
This Final Report was furnished to the Environmental Protection Agency by
the GCA Corporation, GCA/Technology Division, Bedford, Massachusetts 01730, in
fulfillment of Contract No. 68-02-1316, Task Order No. 22. The opinions,
findings, and conclusions expressed are those of the authors and not necessarily
those of the Environmental Protection Agency or the cooperating agencies.
Mention of company or product names is not to be considered as an endorsement
by the Environmental Protection Agency.
-------
ABSTRACT
This report contains background information on boiler population, boiler
capacities, emission levels, state and local air pollution regulations,
and control techniques for oil- and gas-fired boilers in the size range
2.5 to 63 x 10 Kcal/hr (input). This background information has been
used in a simple emission projection model to determine the emissions '
reduction (NO , S00, particulates, CO and hydrocarbons) that could be
A £m
achieved by the application of new source performance standards (NSPS)
that require the installation of best available control technology for
the period 1975 to 1985.
iii
-------
CONTENTS
Page
Abstract iii
List of Figures ix
List of Tables xii
Acknow1ed gment s xv
Executive Summary xvi
Sections
I Intermediate Sized Boilers - Background 1
Introduction 1
Population and Characteristics of Oil- and Gas-Fired Boilers 1
Boiler Inventory 1
Geographical Distribution 4
Industrial Boiler and Fuel Use Trends 6
Fuel Use Trends 6
Trends in Boiler Population 7
Significance of Trends 7
Fuel Conservation 9
References 10
II Sources and Types of Emissions 11
Burner Design 11
Boiler Design 18
-------
Sections
CONTENTS (continued)
Page
Factors Affecting Emissions from Oil and Natural 22
Gas Combustion
27
Emission Estimates
00
References
III Applicable Best Systems of Emission Reduction
29
Control of NO Emissions 29
x
Boiler Modifications 32
Excess Air Reduction 32
Two-Staged Combustion 34
Flue Gas Recirculation 40
Boiler Design 42
Water or Steam Injection 42
Burner Modifications 42
Burner Register Adjustment 43
Burner Tune-Up 43
Fuel Atomization Method 45
Fuel Atomization Pressure 45
Delayed Mixing 45
Japanese Low NO Burners 46
X
Effect of Fuel on NO Emissions 47
X
Natural Gas Combustion and NO Control 48
x
Fuel Oil Combustion and NO Control 51
x •L
Scrubbing Technology for NO Control 54
X
VI
-------
CONTENTS (continued)
Sections Page
NO Scrubbing Technology in Japan 56
X
Conclusions - NO Control Technology 60
X
Control of SO Emissions 63
x
Feedstock Desulfurization 63
H2S Removal 64
Glaus Tail Gas Cleanup 66
Beavon Sulfur Removal Process 66
Stretford Process 66
Cleanair Sulfur Process 67
IFF Process 67
Environmental Impacts of Residual HDS 68
Economics of Feedstock Desulfurization 68
Processes
Flue Gas Desulfurization 72
Environmental Impacts of Flue Gas 78
Desulfurization Techniques
Flue Gas Desulfurization Economics 80
Economic Comparison of SO Control Measures 82
X
Control of Particulate Emissions 82
Cyclones 83
Wet Scrubbers 83
Electrostatic Precipitation (ESP) 85
Fabric Filtration 86
vii
-------
Sections
CONTENTS (continued)
Page
Effects of NOX Control Combustion Modifications
on Particulate Emission Rates
Emissions from the Storage of Oil and Natural Gas
89
90
Summary
QO
Control of CO and Hydrocarbon Emissions 7U
92
qo
References
IV State and Local Air Pollution Control Regulations 96
V Estimated Emission Reductions H2
Introduction H2
Model IV - Background Information 113
Installed Boiler Capacity and Fuel Consumption 116
Emission Factors 128
1975 Boiler Sales 131
Model IV Calculations 132
Input Parameters 132
Results of Model IV Calculations 135
References 142
VI Modification and Reconstruction 143
References 145
APPENDIX
A Emission Data A_i
B List of Contacts T, i
D- L
C Reports and Correspondence c_,
D Background Data on Boiler Size Distributions Capacities, D-!
Fuel Consumption and Emissions
viii
-------
LIST OF FIGURES
No.
1 Approximately One-Third of Industrial Oil Consumption
(1973) Occurs in Six States
2 Circular Register Burner with Water-Cooled Throat for 13
Oil Firing
3 Cell Burner Showing Location of C-B Type Natural-Gas 14
Firing Elements
4 Steam (or Air) Oil Atomizer Assembly 16
5 Mechanical Return-Flow Oil Atomizer Assembly 17
6 Horizontal Straight Tube Boilers (Courtesy, the Babcock 19
& Wilcox Co.)
7 Types of Bent Tube Packaged Water-Tube Boilers 21
8 Universal-Pressure Boiler for Natural-Gas Firing 23
9 The Possible Fate of Fuel-Nitrogen Contained in Oil 30
Droplets During Combustion
10 Time-Temperature Profile in a Typical Large Boiler Furnace 33
lla NOX Versus Excess Air for Scotch Fire Tube Boiler, 35
2.52 x 106 Kcal/hr
lib NOx Versus Excess Air for Water Tube Boiler, 35
5.04 x 106 Kcal/hr
12 NO (ppm) Corrected to 12 Percent C02 Versus Excess Air (%) 36
13 Effect of Staged Air on Total Nitrogen Oxides Emissions 38
No. 6 Oil Fuel
14 Two-Stage Combustion, Oil Fuel 39
IX
-------
LIST OF FIGURES (continued)
No, £M£
15 Effect of Flue Gas Recirculation on Total Nitrogen Oxides 41
Emission Level
16 Effect of Secondary Air Register Position on Total Nitrogen 44
Oxides Emissions and Smoke Level, No. 2 Oil Fuel
17 Effect of Staged Air on Total Nitrogen Oxides Emissions, 50
Natural Gas Fuel
18 Effect of Firing Rate on Total Nitrogen Oxides Emissions, 52
Gas-Fired Water Tube Boilers
19 Typical Two-Stage Glaus Sulfur Plant 65
20 Particulate Regulations for Maine 103
21 Particulate Regulations for Mississippi ' 105
22 Particulate Regulations for Montana 106
23 Particulate Regulations for Oklahoma 108
24 Particulate Regulations for Vermont 109
25 Particulate Regulations for Wyoming 110
26 Sulfur Dioxide Regulations for Indiana 111
27 Residual Oil, (Utility) Design Firing Rate Versus 117
% < Stated Size
28 Distillate Oil, (Utility) Design Firing Rate Versus 118
I < Stated Size
29 Natural Gas, (Utility) Design Firing Rate Versus 119
7o < Stated Size
30 Residual Oil, (Industrial) Design Firing Rate Versus 120
% < Stated Size
31 Distillate Oil, (Industrial) Design Firing Rate Versus 121
% < Stated Size
-------
LIST OF FIGURES (continued)
No. Page
32 Natural Gas, (Industrial) Design Firing Rate Versus 122
70 < Stated Size
33 Distillate Oil, (Commercial) Design Firing Rate Versus 123
% < Stated Size
34 Residual Oil, (Commercial) Design Firing Rate Versus 124
% < Stated Size
35 Natural Gas, (Commercial) Design Firing Rate Versus 125
% < Stated Size
xi
-------
LIST OF TABLES
1 Total Capacities of Industrial Boilers, 1973 3
2 Number and Size of Industrial Boilers, 1973 3
3 Capacity of Boilers Between 10 and 250 MM Btu/hr Input 4
and Oil and Gas Consumption by Combustion System, 1973
4 Detailed Industrial Fuel Consumption Trends to 1985 7
5 Flue Gas Emissions from Industrial Oil- and Natural Gas- 12
Fired Combustion Boilers (2.5 - 63 x 106 Kcal/hr Input),
1975
6 NEDS Emission Factors 25
7 Fuel Consumption and Load Factors for Oil- and Natural 27
Gas-Fired Industrial Boilers (2.5 - 63 x 106 Kcal/hr
Input), 1975
8 Range and Average Emissions of Total Nitrogen Oxides at 47
Baseline and Low-N0x Operation
9 Major Plants for Denitrif ication by Selective Catalytic 57
Reduction
10 Major Plants for NO Removal from Flue Gas by Wet Process 58
X
11 NO Reductions by Control Modifications 61
X
12 Process Parameters of High Metals Feedstock Desulfurization 69
Techniques
13 Process Parameters of Residual Oil Feedstock Desulfurization 70
Techniques
14 Economics of Residual Oil Desulfurization Techniques 73
xii
-------
LIST OF TABLES (continued)
No. Page
15 Summary Description of Flue Gas Desulfurization Processes 75
16 Oil-Fired Utility Boilers in the United States Employing 77
Flue Gas Desulfurization
17 FGD Environmental Impact, tons/yr 78
18 Annual Control Costs - External and Operating Costs 81
19 Control of CO by Burner Adjustment 91
20 State Particulate Regulations, Ib/MM Btu 98
21 State S02 Regulations, Ib/MM Btu for Coal-Fired Boilers 99
22 State SO, Regulations, Ib/MM Btu for Oil- and Gas-Fired 100
Boilers
23 State NOX (As N02) Regulations, Ib/MM Btu for Coal-Fired 101
Boilers
24 State NOX (As N02) Regulations, Ib/MM Btu for Oil- and 102
Gas-Fired Boilers
25 Particulate Regulations for Maryland 104
26 Particulate Regulations for New Hampshire 107
27 Particulate Regulations for New Jersey 107
28 Particulate Regulations for West Virginia 110
29 Installed Capacity of Oil and Gas Utility Boilers Between 126
10 and 250 Million Btu/hr Input in the U.S.
30 Installed Capacity of Oil and Gas Industrial Boilers Between 126
10 and 250 Million Btu/hr Input in the U.S.
31 Installed Capacity of Commercial/Institutional Boilers 126
Between 10 and 250 Million Btu/hr Input in the U.S.
32 Sample Data for Determining K Factor 133
xiii
-------
LIST OF TABLES (continued)
33 Relative Results of Model IV Calculations for Particulates 136
34 • Relative Results of Model IV Calculations for Sulfur 136
Dioxide
35 Relative Results of Model IV Calculations for Nitrogen 137
Dioxide
36 Relative Results of Model IV Calculations for Carbon 137
Monoxide
37 Model IV Results for Total of All Gas- and Oil-Fired Boilers 139
38 Summary of Input/Output Variables for Model IV Particulate 140
39 Summary of Input/Output Variables for Model IV SC>2 140
40 Summary of Input /Output Variables for Model IV NO- 141
41 Summary of Input/Output Variables for Model IV CO 141
xiv
-------
ACKNOWLEDGMENTS
The authors thank GCA/Technology Division staff members: Dr. Vladimir
Hampl, Ms. Mary Anne Chillingworth, Mr. John E. Langley, Mr. Stephen K.
Brenan, Mr. Robert E. Engleman and Mr. Eric Garshick for assistance with
this project. Also we would like to thank Mr. William Axtman of the
American Boiler Manufacturers' Association for his valuable assistance.
xv
-------
EXECUTIVE SUMMARY
INTRODUCTION
Oil and gas-fired boilers with fuel-firing capacities between 2.5 and
63 x 106 Kcal/hr (10 to 250 x 106 Btu/hr) are defined as industrial-sized
boilers and are discussed in this report. Industrial-sized boilers con-
sume 2,500 x 1012 Kcal/yr (9,910 x 1012 Btu/yr) which is equivalent to about
29 percent of U.S. fuel consumption. Fuel used in these boilers is
primarily natural gas (49 percent); however, oil (34 percent) and coal
(15 percent) are also used in large quantities. Wood and bagasse repre-
sent the remaining 2 percent of industrial fuel consumption. The major
objective of this report is to estimate the potential change in emissions
which could result over the next 10 years as a result of variations in
fuel use patterns and/or the promulgation of New Source Performance
Standards (NSPS).
POPULATION AND CHARACTERISTICS OF OIL- AND GAS-FIRED BOILERS
Oil- and gas-fired boilers in the industrial-size range are used in the
utility, industrial and commercial/institutional sectors. Tables 1 and 2
present the population of industrial-sized boilers operating in the United
States. About three-quarters of the industrial-sized boiler capacity is
utilized in the industrial sector. Many boilers, especially in the utility
sector, are designed to burn natural gas when available and oil at other
times. Geographically, natural gas-fired boilers are concentrated in Texas,
Louisiana and on the west coast while oil-fired boilers are found primarily
in the east. The six adjacent states from Illinois to New York consume
one-third of the oil used in industrial-sized systems.
xvi
-------
Despite the high price of oil, fuel oil combustion by industrial-sized
boilers is projected to increase 70 to 100 percent in the period between
1975 to 1985 due to easier operating characteristics and smaller capital
investment as compared to coal-fired units. Natural gas consumption is
estimated to remain constant from 1973 to 1985 because of supply
limitations.
SOURCES AND TYPES OF EMISSIONS
The only significant source of air emissions from oil and natural gas
combustion systems is the flue gas stack. Table 5 summarizes the annual
emissions from all industrial-sized boilers located in the U.S. firing
natural gas and oil.
Combustion of oil and gas is carried out in cell or circular burners.
Gas requires no treatment before combustion and can be fed directly to
the combustion area by pressurized lines. Oil requires atomization prior
to combustion to ensure maximum contact with available oxygen in the com-
bustion zone. Air at high pressure or steam are used to produce the re-
quired spray patterns. The hot gases produced in the furnace area are
used to heat water to steam in either fire tube or water tube designs.
Pollutants from gas- and oil-firing consist of NO . S0_, particulates,
X A.
hydrocarbons (HC), and CO along with many trace elements, notably Ni, V,
and Na in oil. Gas combustion produces only minor emissions of SO or
X
particulates, but NO is produced in large quantities due to the high
X
peak flame temperature present in the incandescent gas flame. All the NO
X
formed in gas combustion is the result of thermal fixation; the N~ content
of the fuel feed stream is negligible. Oil combustion, however, has a
significant contribution of fuel-N conversion to NO . Once again, the
X
high temperatures tend to produce large quantities of N0__ by thermal fixa-
X
tion, but the low excess 0~ present at each burner results in lower over-
all NO emissions than for gas firing. Tangential-fired boilers produce
X
less NO emissions because of the lower temperatures found in these units.
X
xvii
-------
It is estimated that 16 percent of oil-fired and 10 percent of gas-fired
industrial boilers use tangential patterns. Uncontrolled particulate
emissions from oil-fired units are low compared to coal, but the particles
produced are small and therefore are very difficult to capture.
The NEDS emission factors for industrial-sized boilers are presented in
Table 6. CO and HC emissions are small for most operating units. Ap-
pearance of these pollutants in significant quantities indicate incomplete
combustion of the fuel and poor efficiency. The quantities released
are therefore monitored and the burners tuned periodically to reduce their
emission rates. SO emissions are primarily from residual oil combustion.
X
Distillate oil contains reduced quantities of sulfur and is used, in many
cases, to meet the local air quality regulations for SO emissions.
X
APPLICABLE BEST SYSTEMS OF EMISSION REDUCTION
NO formed within the boiler flame by thermal fixation and fuel bound
X
nitrogen oxidation is best controlled by alteration of boiler design and
operating characteristics.
Table 11 summarizes the NO reductions that have been demonstrated with
X
the indicated control measures without significant increases in CO or
particulate emissions. Staged combustion also can be used for oil-fired
boilers to obtain average NO reduction of 27 percent for residual oil
X
and 10 percent for distillate fuels from baseline NO emissions of
36 to 101 g/GJ (0.084 to 0.23 lb/106 Btu) and 107 to 196 g/GJ (0.25 to
0.46 lb/10 Btu) respectively (see Table 8). Finally, NO emissions from
X.
gas-fired boilers can be reduced 70 percent by flue gas recirculation.
The baseline rate for gas-fired boilers of 26 to 101 g/GJ (0.06 to 0.23
lb/10 Btu) can therefore be reduced to 7.8 to 57.3 g/GJ (0.02 to 0.13
lb/10 Btu) well below the requirements for new sources greater than
63 x 106 Kcal/hr (250 x 106 Btu/hr).
xviii
-------
Burner redesign has high potential for lowering the emissions from indus-
trial sized boilers. However, the low NO burner technology is still in
X
its infancy as far as application to commercial units is concerned. Wide
scale application could reduce NO emissions by 50 percent or more, but
X
further research and design are necessary.
NO scrubber systems provide excellent removal efficiencies but the cost
X
is prohibitive in all cases. If future advances can bring the initial
investments to reasonable levels, such as packaged units utilizing cheap,
regenerable catalysts while producing useful by-products, these systems
could see wide application. Also, for plants operating in areas requir-
ing very low NO emissions, this may be a viable alternative when the
X
simultaneous removal of SO is also realized. Its use on small boilers
X
will be limited at best in 1985.
The most cost effective technique for NO reduction in 1985 will be the
X
incorporation of all the boiler modifications suggested previously, staged
combustion, flue gas recirculation, excess air control. Installation of
low NO burner designs must also be incorporated into new boiler units.
X
Scrubber costs will be prohibitively expensive well into the future, but
more restrictive emission regulations and further control system improve-
ments may result in their installation.
The alternatives for SO control are reduction of the sulfur content of
X
the fuel prior to combustion or flue gas desulfurization (FGD). Hydro-
desulfurization (HDS) systems are now operating to desulfurize the feed-
stock at refineries. Numerous flue gas desulfurization systems have been
proposed and the six designs outlined in Table 15 have gained acceptance
for utility boiler SO control. However, only two oil-fired plants are
X
currently using one of these systems. Those designs now accepted for coal-
fired units include the limestone slurry process, the lime slurry process,
the magnesia slurry process, and the sodium solution processes. Only the
magnesia-wet scrubbing system at the Boston Edison Mystic Station pro-
vided recent data on oil-fired boiler SO control.
A
xix
-------
Existing economic data on the application of SC>2 control to oil-fired
boilers are inadequate to allow generalizations regarding the best
system of control. Westinghouse25 has developed cost comparisons for
FGD and HDS for utility-size, oil-fired boilers which indicate that
FGD is considerably less expensive than HDS. However, the capital
costs involved in constructing numerous, small FGD units for boilers in
the size range considered in this report may well offset the price ad-
vantage found for utility boilers.
Control of particulate from oil-fired boilers must deal with many signif-
icant problems not faced by coal-fired control systems. Industrial
application of particulate collectors has not been widespread to date and
test data are limited. Bag filtration systems, precoated with dusts to
form the initial filter cake, may be the best design, operating at removal
efficiencies of 85 percent or more.
As more testing of emissions from industrial boilers operating in the low
NO mode become available, the variation of the particulate size distribu-
A.
tion and the total emission rates may be incorporated into the final
designs of the bag filtration units.
The capacity of existing oil- and gas-fired boilers between 2.5 to 63 x 10
Kcal/hr (10 to 250 MM Btu/hr) is very large compared to the amount of
retired and newly installed capacity, on an annual basis. Because df this
basic fact, the emissions from these boilers will not increase dramatically
over the next 10 years.
Results of the Model IV calculations indicate that if the boilers are
currently in compliance with state regulations, and these regulations
are not changed through 1985, then emissions would increase by the fol-
lowing percentages: particulate, 18.13 percent; sulfur dioxide, 18.26 per-
cent; nitrogen dioxide, 17.02 percent; and carbon monoxide; 17.03 percent.
In other words, the emissions will increase by about the same amount that
installed boiler capacity increases.
xx
-------
Again from Model IV we have determined that if the best available control
technology were required on all boilers installed from 1975 to 1985, then
the emissions will increase over 1975 emissions only for nitrogen dioxide
(8.22 percent), and carbon monoxide (17.03 percent). Particulate emis-
sions will actually be reduced by 1.4 percent and sulfur dioxide by
3.76 percent, from 1975 emissions.
The net effect in 1985, of imposing New Source Performance Standards (NSPS)
in 1975, would be to reduce potential emissions of particulate by 16.53
percent; sulfur dioxide by 18.62 percent; nitrogen dioxide by 7.58 per-
cent, and carbon monoxide by 0 percent, of projected 1985 emissions with
current state regulations. This reduction in 1985 emissions (Tg to TN
from Model IV) is the extent of the potential for reducing emissions by the
use of NSPS. While the projected reduction in emissions is not very great
overall, the potential reduction in particulate and sulfur dioxide emis-
sions is substantial and worth further consideration. However, the SC^
reduction calculated using Model IV is large due to the assumption that
many boilers which are currently, and will in the future be utilizing lower
sulfur fuels (e.g., distillate oil) than is required by state regulations,
are just meeting state regulations.
xxi
-------
SECTION I
INTERMEDIATE SIZED BOILERS — BACKGROUND
INTRODUCTION
Almost all of the boilers in the size range to which this project is di-
rected 2.5 to 63 x 106 Kcal/hr (10 to 250 x 106 Btu/hr input) are used in
the industrial sector for generating process steam, electricity or space
heating. It is estimated that these industrial sources consume about
29 percent of the fuel used in this country.1 Currently, this industrial
fuel is primarily natural gas (49 percent), but oil (34 percent) and coal
(15 percent) are used in large quantities. Other fuels such as wood and
bagasse represent the remaining 2 percent of industrial fuel consumption.
This report is concerned primarily with industrial-sized boilers utilizing
oil and natural gas and the potential changes in emissions which could
result over the next 10 years as a result of variations in fuel use pat-
terns and/or the imposition of new source performance standards (NSPS).
POPULATION AND CHARACTERISTICS OF OIL- AND GAS-FIRED BOILERS
Boiler Inventory
Natural gas- and oil-fired boilers are similar to utility boilers and can
be designed for all capacities. The number of industrial boilers is much
greater than the number of utility units. For this reason there have been
-------
to conduct an inventory of all industrial boilers. The most widely
used boiler population data2"5 were originally developed by Battelle
for API and EPA and are based primarily on sales data. A recent
Battelle report states: "Unfortunately, there is no fully satisfactory
source of statistics on the actual number or the installed capacity of
boilers now in field service. Sales records, even if available for
many years, would not be adequate because a field conversion from one
fuel to another is not reflected in sales records."5 In addition,
sales data do not reflect boiler shutdowns due to business failures or
other operational changes.
Despite the uncertainties involved in estimating industrial boiler
populations, such estimates can be useful. The best available
description of industrial boiler size and capacity is presented in
Table 1. The data in the size range 2.5 to 126 x 106 Kcal/hr (10 to
500 x 10^ Btu/hr) are based on an analysis by Battelle Columbus
Laboratories^ of NEDS data, supplemented with sales information from
the American Boiler Manufacturers Association (ABMA)' and the Depart-
Q
ment of Commerce. The number of boilers in each size fuel category
was estimated from the capacity and the average of the size range and
is presented in Table 2. Table 3 presents estimates of boiler capacities
and fuel consumption by detailed combustion system classification for
oil and gas fuels.
About 70 percent of the oil burned in steam-electric boilers is burned
in boilers classified as oil-fired, while most of the remaining was
burned in dual-fired boilers. There was a large difference in the ages
of oil-fired boilers between the less than 126 x 106 Kcal/hr (500 x 106
Btu/hr) groups and each of the other large size groups. Oil-fired boilers
below 126 x 106 Kcal/hr (600 x 106 Btu/hr) had an average age of about
28 years, while larger boilers had an average age of 14 years. Boilers
using opposed firing, although burning only a small fraction of the total
oil, are the newest oil-fired boilers.
-------
Table 1. TOTAL CAPACITIES OF INDUSTRIAL BOILERS, 19734'9
Size,
106 Btu/hr
10-20
20-50
50-100
100-200
200-500
Totals
Capacity ; 109 Btu/hr
Coal
10
20
60
90
150
330
Coal3
and other
10
30
70
130
290
530
Oil
180
110
140
120
160
710
Oil3
and gas
310
160
190
160
210
1,030
Gas
90
60
50
80
100
380
Gasa
and oil
160
310
370
230
200
1,270
All
fuels
480
500
630
520
700
2,830
aincludes boilers designed to burn the primary fuel only, as well as
those capable of burning a secondary fuel.
Table 2- NUMBER AND SIZE OF INDUSTRIAL BOILERS,
Size,
106 Btu/hr
10-20
20-50
50-100
100-200
200-500
Totals
Number of boilers
Coal3
670
860
930
870
830
4,160
Oil3
21,600
4,600
2,500
1,100
600
30,400
Gas
11,000
8,900
4,900
1,500
570
26,870
All
fuels
32,670
14,360
8,330
3,470
2,000
60,830
Includes boilers designed to burn the primary
primary fuel only, as well as those capable of
burning a secondary fuel.
-------
Table 3. CAPACITY OF BOILERS BETWEEN 10 AND 250 MM Btu/hr INPUT AND
OIL AND GAS CONSUMPTION BY COMBUSTION SYSTEM, 1973
Petroleum
Residual oil
Tangential firing
All other
Distillate oil
Tangential firing
All other
Gas
Tangential firing
All other
Approximate
design capacity,
10-*-5 Btu/yr
9.3
7.8
1.3
6.5
1.5
0.2
1.3
6.9
0.7
6.2
Fuel consumed,
1012 Btu/yr
2,570
2,000
320
1,680
570
90
480
3,700
370
3,330
The capacity of oil- and gas-fired boilers using tangential firing was
determined by assuming that boilers larger than 100 x 10 Btu/hr were
similar to utility boilers. Therefore, 16 percent of oil-fired and 10
percent of gas-fired industrial boilers are estimated to use tangential
firing patterns.
Geographical Distribution
Industrial oil and gas fired-boilers are distributed throughout the U.S.
Nevertheless, as shown in Figure 1, one-third of the oil consumed in-
dustrially is concentrated in the six adjacent states from Illinois to
New York.
-------
Figure 1. Approximately one-third of industrial oil consumption (1973)
occurs in six states
-------
INDUSTRIAL BOILER AND FUEL USE TRENDS
Fuel Use Trends
As is the case for the electric utility combustion sector, the forecast-
ing of developments in the industrial combustion sector is extremely
difficult. The changing energy picture, the impact of government regula-
tions and the availability of clean fuels all contribute to the high
degree of uncertainty involved in forecasting future developments. Our
evaluation of industrial fuel consumption trends indicates ah increase
from 1973 to 1985 of 14 percent within the categories discussed in this
project. Project Independence10 predicts that the total industrial energy
consumption (including direct heat, feedstocks and electrical energy)
will increase about 27 percent, with utility generated electrical energy
consumption by the industrial sector increasing nearly 100 percent based
on business as usual and an $ll/barrel price for imported oil. Industrial
oil and gas consumption trends are presented in Table 4, along with trends
for solid fuel as a comparison.
Petroleum consumption by the industrial sector will increase 44 percent.
Within the petroleum category, residual fuel oil usage is expected to in-
crease by from 70 to 100 percent between 1975 and 1985. Despite the
high price of oil, many industrial consumers limited to choosing between
oil and coal will select oil. Oil-fired boilers and auxiliary equipment
are less expensive and easier to operate than coal-fired boilers. Small
energy users will show a particularly strong preference for oil as the
economics will tend to favor oil-fired equipment.
Natural gas resources are limited and a decline in industrial consumption
of 5 percent from 1972 to 1985 was predicted.10 However, consumption
actually declined 5 percent from 1972 to 1973 so for the projections made
for this report it was estimated that gas consumption would remain con-
stant from 1973 to 1985.
-------
Table 4. DETAILED INDUSTRIAL FUEL CON-
SUMPTION TRENDS TO 1985
Industrial
External combustion
Petroleum
Gas
Coal
Bituminous
Anthracite
Lignite
Bagasse
Wood bark
1973
fuel
1012 Btu
9,910
1,700
5,200
1,370
1,320
10
40
20
250
1985
fuel
1012 Btu
11,961
2,448
5,200
1,945
1,899
2
44
23
400
Percent
change
1973-1985
+21
+44
+ 0
+42
+^4
-80
+10
+15
+60
Trends in Boiler Population
The limited projection data available on those boiler characteristics con-
sidered in this project do not show significant trends. We estimate that
boiler characteristics in 1985 will be similar to 1973, and that the
major changes will reflect the fuel use trends presented in Table 4. The
growth of particular boiler types should be the same as the growth of the
overall fuel type.
Significance of Trends
Changes and trends in total energy consumption and fuel use patterns have
the potential to affect the amounts and types of air pollutants. They
will also affect the design and application of combustion equipment, air
pollution control methods (particulate, SOX and NOX), water pollution con-
trol methods, and solid waste practices. The actual future pollutant
quantities will be strongly affected by government regulations.
7
-------
The most significant trend in the overall picture is the large (44 per-
cent) increase in coal consumption. Coal combustion tends to generate
over 50 times as much ash and most trace metals (either as an air pollu-
tants or solid waste), about twice as much NOX, and three times as much
SOX (based on current average levels of 1 percent sulfur oil and 2 percent
sulfur coal) as oil combustion. With the exception of NO , pollutants
X.
generated by gas combustion are insignificant compared to those generated
by coal combustion. The impact of ash emissions can be minimized by
control equipment. NO emissions from coal can be reduced to levels asso-
X
ciated with gas and oil. SO emissions can, of course, be controlled
X
through the use of low sulfur fuels or SO scrubbers. Scrubbers do
X
create potential water pollution and solid waste problems.
The significance of increased coal combustion will be amplified most in
the utility sector where coal consumption is expected to increase 100 per-
cent while oil and gas decline sharply - 10 and 30 percent. In the in-
dustrial sector, to which this report is primarily directed, the use of
both coal and oil will increase 40 to 45 percent while the use of gas will
remain constant. As industrial coal consumption represents only 16 per-
cent of utility consumption, the increase will be less significant.
However, the overall shift from gas (zero growth to 1985) will be very
significant, tending to increase pollutant quantities.
The majority of pollutants generated by the commercial/institutional sector
(i.e., boilers on the order 2.5 x 106 Kcal/hr (10 x 106 Btu/hr) the lower
limit of this study) will decrease because only the use of natural gas will
increase. The large decrease (55 percent) in coal combustion in the com-
mercial sector will be of minimum importance as coal is a very similar
commercial fuel.
-------
Fuel Conservation
One of the best ways of reducing emissions in the intermediate size range
of boilers, where the installation of control equipment is often difficult,
may be simple fuel conservation. A Federal Energy Agency advisory group
has estimated that 1985 national fuel consumption could be halved by in-
tensive energy conservation. Their estimates indicate NOX emissions could
be reduced from 8.2 x 107 Kg/day (90,400 tons/day) to 6.2 x 107 Kg/day
(68,500 tons/day).^ $Q emissions could be reduced from 5.6 x 107 Kg/day
A
(61,700 tons/day) to 4.9 x 107 Kg/day (54,000 tons/day).
-------
REFERENCES
Surprenant, N. F. et al. Preliminary Emissions Assessment of Con-
ventional Stationary Combustion Systems. Prepared by GCA Corporation
for the U.S. Environmental Protection Agency. EPA Report No.
600/2-76-046b. March 1976.
Draft of Source Assessment Document for Coal-Fired Industrial/
Commercial Boilers. Monsanto Research Corporation. U.S. Environ-
mental Protection Agency. EPA Contract No. 68-02-1874. April 1975.
Draft of Source Assessment Document for Oil-Fired Industrial/
Commercial Boilers. Monsanto Research Corporation. U.S. Environ-
mental Protection Agency. EPA Contract No. 68-02-1874. March 1975.
Barrett, R. E., et al. Assessment of Industrial Boiler Toxic and
Hazardous Emission Control Needs. Battelle Columbus Laboratories.
U.S. Environmental Protection Agency. EPA Contract No. 68-02-1323,
Task Order No. 8. October 1974.
Locklin, D. W., et al. Design Trends and Operating Problems in
Combustion Modification of Industrial Boilers. U.S. EPA Report
No. 650/2-74-032. Research Triangle Park, N.C. April 1974.
Barrett, R. E., et al. Field Investigation of Emissions From
Combustion Equipment for Space Heating. U.S. Environmental Protection
Agency. EPA Report No. R2-73-084a. June 1973.
Data Compilation on Water Tube Boilers. Data Compilation on Fire
Tube Boilers. Stationary Water Tube and Hot Water Generating Sales.
American Boiler Manufacturing Association.
Steel Power Boiler Report, Series MA 34-6. U.S. Department of
Commerce, Bureau of Census. 1962-1971.
Paddock, R. E. and D. C. McMann. Distributions of Industrial and
Commercial/Institutional External Combustion Boilers. U.S. EPA
Report No. 650/2-75-021. Research Triangle Park, N.C. February 1975.
10. Federal Energy Administration. Project Independence. Washington,
D.C. November 1974.
11. Monk, J. A., M. M. Merino, E. S. Quackenbush, N. Godley, L. R. Clark,
M. E. Cloyd, I. L. Jashnani and R. P. Stickles. Residuum and
Residual Fuel Oil Supply and Demand in the United States: 1973-1985.
Arthur D. Little. U.S. EPA, Report No. EPA-600/2-76-166. June 1976^
12. Environment Reporter. June 11, 1976. p. 236.
10
-------
SECTION II
SOURCES AND TYPES OF EMISSIONS
The only significant source of air emissions from oil and natural gas
combustion systems is the flue gas stack. Additional contributions are
light hydrocarbon emissions from petroleum storage and handling and
fugitive emissions due to leaks, spills, etc.
Emissions from oil and natural gas combustion sources within the size
category considered in this study, 2.5 to 63 x 10 Kcal/hr input
(10 to 250 x 10 Btu/hr input), are summarized in Table 5. Following a
brief description of oil and natural gas burners and boiler design charac-
teristics, the factors influencin- emissions such as firing pattern and
fuel properties will be discussed. Trend information will be considered
although considerable uncertainties exist with regard to these relatively
short supply clean fuels.
BURNER DESIGN
Two types of burners are used for oil and gas combustion, the cell and
the circular design. Figure 2 shows a circular register burner for oil
firing and Figure 3 diagrams the components of a gas-fired cell burner.
These designs are also applicable to pulverized coal and to the use of
all three fuels in combination. The maximum load capabilities of these
circular and cell burners are 40 x 10 Kcal/hr (159 x 10 Btu/hr) and
125 x 106 Kcal/hr (496 x 106 Btu/hr), respectively.1
11
-------
Table 5. FLUE GAS EMISSIONS FROM INDUSTRIAL OIL- AND NATURAL GAS-FIRED
COMBUSTION BOILERS (2.5 - 63 x 106 Kcal/hr INPUT), 1975
Significant
emission sources
Residual oil
Distillate oil
Natural gas
Gas volume
106 106
SCFM SCFM
310 165
58 31
270 140
Pollutant emission,
rate-lb/hr,
(actual)
Part.
240,000
44,400
7,400
S02
1,750,000
300,000
56
NOX
510,000
89,000
204,00
CO
24,000
5,100
13,000
HC
18,000
3,800
2,300
12
-------
Centering
Support
Air Register Door Oil
(Secondary Air) Atomizer
Lighter
Register
Dry Rod
Impeller
Refractory Throat
with Studded Tubes
Water Cooled
Furnace Wall
Figure 2. Circular register burner with water-cooled throat for
oil firing
13
-------
Gas Manifold
Gas Element
Gas Supply
Ignitor
Register Door
Control Linkag<
Spud Support Ring
Regulating Rod
Flame Retainer
Register
Assembly
and Frame
Water-Cooled
Furnace Wall
Figure 3. Cell burner showing location of C-B type natural-gas-
firing elements
14
-------
Natural gas requires no initial preparation before firing. Oils of grades
heavier than No. 2 have viscosities that inhibit the atomization of the
fuel. Steam or electric heaters are used to lower the viscosity of the
heavy oils to 135 to 150 SUS. To achieve this viscosity level No. 4 oil
must reach 57°C (135°F); No. 5 oil, 85°C (185°F); and No. 6 oil, 93° to
105°C (200 to 221°F).
Atomization is accomplished using either steam or air as the pressure
agent. Steam atomizers, Figure 4, spray an emulsion of dry steam and oil
into the furnace. A wide dispersion pattern of microscopic droplets is
produced when the pressurized steam undergoes rapid expansion upon entry
into the combustion area. Compressed air can be utilized in the same
manner, although the cost of pressurizing and drying the air are prohib-
itive. Steam atomization requires approximately 0.1 Ib of steam per Ib of
fuel oil. This can lead to a serious efficiency loss in utility-sized
units where high energy conversion efficiency is a necessity. Therefore,
in the large capacity units, mechanical dispersion accomplished by the
rapid expansion of the highly pressurized oil flow is used. Pressures are
maintained at 40 to 68 atm (600 to 1000 psi), whereas steam atomization
requires oil pressures less than 7 atm (100 psi). Dispersion and mixing
are increased at the burner throat by the spinning impeller and tangen-
tially introduced secondary air. Figures 4 and 5 present schematic repre-
sentations of these designs.
Combustion air is preheated to maintain stable ignition and ensure more
efficient combustion. Excess air of 5 to 10 percent will produce the
desired combustion efficiency over load ranges varying between 10 to 1
and 3 to 1, depending on the operating parameters of the specific unit:
maximum oil pressure, furnace configuration, feed air temperature, and
burner throat velocity. Gas firing will remain stable with an air feed
up to 25 percent excess stoichiometric.
15
-------
Slip Joint
Ox
-Steom or Air Tube
-Fuel Barrel
Oil Inlet
Steam or Air Inlet
Regulating Rod
Sealing
Surfaces
Sprayer
Plate
Sprayer
Head
Figure 4. Steam (or air) oil atomizer assembly
-------
Supply Fuel Barrel
Return Fuel Barrel
Oil Inlet
Oil Return
Regulating Rod
Sprayer Head -1
Intermediate Plate-
Sprayer Plate -
Figure 5. Mechanical return-flow oil atomizer assembly
-------
Natural gas is typically burned in a central battery gas element located
within the burner throat (Figure 3). Several of these spuds are posi-
tioned around an impeller. The fuel composition for stable ignition re-
quires at least 70 percent methane, 70 percent propane, or 25 percent
hydrogen by volume. The maximum output for a burner utilizing central
battery gas elements is 44 x 10 Kcal/hr (175 x 10 Btu/hr).
BOILER DESIGN
Two types of heat exchangers are used in the size range of 2.5 to
63 x 10 Kcal/hr (10 to 250 Btu/hr). Combustion gases are either passed
through tubes surrounded by water, designated fire tube boilers, or they
are passed between banks of tubes containing water, called water tube
boilers. A third boiler design, shell-and-tube, is also widely used but
is applicable only to capacities below 2.
and is therefore not under consideration.
is applicable only to capacities below 2.5 x 10 Kcal/hr (10 x 10 Btu/hr)
The water tube design is selected for most modern boiler construction.
This arrangement provides safe and dependable heat exchange between all
portions of the system, eliminating the large indeterminate stresses to
which fire-tube boilers are subjected. Water tube designs are used ex-
clusively in industrial boilers with capacities above 17.6 x 10 Kcal/hr
(70 x 10 Btu/hr). This design is inherently safer than fire-tube units
due to the ability of the components to accommodate higher pressures.
These units attain operating efficiencies of approximately 80 percent
without heat recovery. Straight tube design was initially used for steam
production (Figure 6). Bent tube designs provide better mass flow
variations and pipe positioning for maximum heat exchange. It has,
therefore, supplanted straight tube systems in most large capacity units.
Water-tube boilers are constructed either as packaged units or are
field erected. The field-erected units have capacities ranging from
18
-------
Figure 6. Horizontal straight tube boilers-*-
(courtesy, the Babcock & Wilcox Co.)
12.6 x 106 to 126 x 106 Kcal/hr (50 x 106 to 500 x 106 Btu/hr).
Packaged
systems have been limited to 2.5 x 10 Kcal/hr (10 x 10 Btu/hr) in the
past, but larger units are currently being designed. Only oil and gas can
be used to fire these units because coal combustion requires larger furnace
volumes.
The boiler configuration chosen for water-tube heat exchangers is dependent
on the operating characteristics and unit size limitations. Straight tube
boilers provided easy maintenance access but have a tendency to leak, re-
quiring considerable labor for constant inspections. Also, water cir-
culation rates are low and its distribution throughout the tube banks is
poor. The bent-tube design is supplanting the straight tube boiler due
to its design flexibility, making them readily adaptable to units with
space limitations. Horizontal bent-tube boilers are classified by the
number of drums, head room, and tube configuration. The tubes enter a
19
-------
drum radially and are designed to allow for the anticipated expansion.
The furnace is the waterwall type backed by refractory material. Steam
and water are separated by separators and cyclones within the steam drum.
Figure 7 shows the various configurations of A, D, and 0 type bent-tube
heat exchangers. Water flowing from one reservoir is heated to form the
pressurized steam collected in the other reservoir. The package units
using this configuration are oil, gas, or combination-fired with coal
used in a small number of packaged unit boilers. The larger, field-
erected units, greater than 6.3 x 10 Kcal/hr (25 x 10 Btu/hr), are
identical to utility boiler constructions, utilizing multiple burners in
both tangential and wall-fired designs. However, packaged systems are
projected to account for 90 percent of the industrial units by 1990. Also,
dual-fuel design is the future trend.
Fire-tube units direct the combustion products through tubes submerged in
water. The straight tubes, set in tube sheets at either end, may be
horizontal, inclined, or vertical; most units are horizontal. The large
water storage capacity of this design effectively dampens any wide fluc-
tuations in steam demand. These units are used where steam demand is
relatively small. The steam pressures of the design are limited to between
1 and 17 atmospheres (15 and 250 psi) and depend on the process demands.
Various fire-tube boilers are now commercially available. Horizontal re-
turn tubular (HRT) suitable for capacities up to 5.5 x 10 Kcal/hr
(22 x 10 Btu/hr) have a two-pass combustion gas flow. Approximately 10
percent of all commercial units are HRT. The major disadvantage of HRT
is an efficiency rating of approximately 70 percent due to the sluggish
water circulation.
Firebox boilers are short and compact, employing two or three passes.
They are constructed with an internal, steel encased, water-jacketed
firebox. They can attain efficiencies to 80 percent and require a minimum
of floor space for installation. However, the limited furnace size re-
quires proper matching of the burner flame length and combustion volume.
20
-------
A-type has two small lower drums
or headers. Upper drum is larger
to permit separation of water and
steam. Most steam production
occurs in center furnace-wall
tubes entering drum.
D-type allows much flexibility.
Here the more active steaming
risers enter drum near water line.
Burners may be located in end
walls or between tubes in buckle
of the D, right angles to drum.
0-type is also a compact
steamer. Transportation
limits height of furnace so,
for equal capacity, longer
boiler is often required.
Floors of D and 0 types are
generally tile-covered.
Figure 7. Types of bent tube packaged water-tube boilers
21
-------
Scoth designs can produce up to 6.3 x 10 Kcal/hr (25 x 10 Btu/hr) at
efficiencies of approximately 80 percent (Figure 8). They are designed
for a minimum amount of heating surface, typically 5 square feet for one
boiler horsepower. The combustion gases are passed two, three, or four
times, with the burner flame contained in an elongated, water-cooled
combustion chamber that acts as the first pass. The compact design and
multiple tube passes have caused the trend toward the use of Scotch units
even though cleaning is more difficult than other fire-tube designs.
Figure 8 presents an schematic representation of a full-size industrial
boiler.
FACTORS AFFECTING EMISSIONS FROM OIL AND NATURAL GAS COMBUSTION
Pollutants from gas and oil firing consist of NO , SO , particulates,
X X
hydrocarbons (HC), and CO along with many trace elements, notably Ni, V,
and Na in oil. Gas combustion is very clean, with no appreciable emis-
sions of SO or particulates. However, NO is produced in large quan-
X X
tities during gas firing due to the high peak flame temperature present
in the incandescent gas flame. All the NO formed in gas combustion is
X
the result of thermal fixation; the N_ content of the fuel feed stream is
negligible. Oil combustion, however, has a significant contribution of
fuel-N conversion to NO . Once again, the high temperatures lead to a
X
large quantity of thermal fixation of NO , but the low excess 00 present
x 2.
at each burner causes the total rates of release to be lower than for gas
firing. Tangential firing is an effective means of reducing NO emissions
because of the lower temperatures found in these units. It is estimated
that 16 percent of oil-fired and 10 percent of gas-fired industrial boilers
2
use tangential firing patterns. Particulate emissions from oil-fired
units are low, but the particulates produced have very small diameters and
therefore are very difficult to capture.
Significant emissions of SO occur only in oil firing, because the
X
volatile sulfur compounds present in natural gas are removed at the
drill site. The amount of SO^ emitted is a function of the sulfur
22
-------
Atternperatori
——• -i '[ i y\ la!
^nrrjr—:jbk ^zrair
Reheat, /
ilSuperheater
Secondary
Superheater
Figure 8. Universal-pressure boiler for natural-gas firing
23
-------
content of the oil. The sulfur content of No. 2 distillate oil may be as
high as 0.7 percent, by ASTM standards, or, at times, be higher by mutual
agreement between the buyer and the seller of the oil. One range of
analyses of fuel oils indicated the sulfur content varying between 0.05
and 1.0 percent. The strictest state regulation, that of New Jersey,
limits emissions from boilers in this size range to 0.54 kg/10 Kcal
(0.3 lb/10 Btu) . Using a typical heating value for No. 2 fuel oil of
10,800 Kcal/kg (19,460 Btu/lb) the 0.54 kg/10 Kcal (0.3 lb/10 Btu) emis-
sion standard effectively calls for fuel with a sulfur content of less
than 0.29 percent sulfur content. Therefore it is possible that certain
boilers utilizing No. 2 fuel oil would exceed allowable emissions.
Residual oil is of higher sulfur content and therefore more likely to ex-
ceed regulatory limits. There are four types of residual oil which are
fired in boilers; No. 4 and No. 5 light, No. 5 heavy, and No. 6. There is
no ASTM limit on sulfur content of residual oils, however, there is a gen-
eral tendency for sulfur content to increase in going from No. 4 to No. 6
residual oil as noted below.
Fuel oil grade Minimum sulfur Maximum sulfur (wt %)
No. 4 0.2 2.0
No. 5 0.5 3.0
No. 6 0.7 3.5
Utilizing a heating value of 10,456 Kcal/kg (18,840 Btu/lb) for No. 4 oil,
the maximum S02 emissions would be 3.84 kg/Kcal (2.13 lb/10 Btu), well
in excess of the state standards of New Jersey. The use of the cleanest
No. 6 fuel would also exceed standards and sulfur reduction by pretreatment
of the fuel, flue gas cleaning or fuel switching would be indicated.
NEDS emission factors for oil and natural gas combustion are provided in
Table 6. These emission factors have been extensively studied in recent
work aimed primarily at modifications of boilers to achieve NO emission
X
reductions. The most extensive recent program has been conducted by KVB
24
-------
Engineering, Inc. They have completed a 1-year EPA sponsored emission
characterization field test of packaged and field erected industrial
boilers in the size range 4,500 to 225,000 kg (10,000 to 500,000 Ib)
steam/hr. Forty-seven boilers encompassing 75 combinations of boilers/
burners/fuels were tested to yield a representative sample of the in-
dustrial boiler field population. All major fuels - gas, distillate
and residual oil, and pulverized or stoker coal - were tested. Limited
study was made of the degree of control achievable from fine tuning of
excess air level, unit load, burner adjustment, and, where possible,
biased burner firing, burner swirl, and overfire air. In comparison to
utility boilers, industrial boilers were found to have limited flexibility
for NO control through minor modification of operating conditions.
X
Table 6. NEDS EMISSION FACTORS
Combustion system
Residual oil,
lb/103 gal
Residual oil,
lb/103 gal
Residual oil,
lb/103 gal
Distillate oil,
lb/103 gal
Natural gas,
lb/106 ft3
Emission factor
Particulate
No. 6 = 10(S) + 3
No. 5 = 10
No. 4 r 7
2
10
SOX
159Sa
159Sa
159Sa
144S
0.6
NOX
60
60
60
22
120-600b
HC
1
1
1
3
3
CO
5
5
5
5
17
S = sulfur content of fuel.
Emission factor dependent upon size.
In the NO control tests, low excess air (LEA) firing was shown most ef-
2£
fective for coal-fired stokers and oil-fired watertube boilers. The fire-
tube boilers and gas-fired watertube units generally showed less response
to LEA firing. For multiburner units, off-stoichiometric combustion was
achieved by biasing burner stoichiometry or by taking burners out of
25
-------
service. This yielded NO reductions up to 40 percent. For stokers, off-
X
stoichiometric combustion was achieved by modification of existing over-
fire air ports. This resulted in NO reductions up to 25 percent.
2C
Results from a second phase of the KVB survey are in preparation. The
Phase II effort applied more extensive control techniques to a smaller
3
number of units.
The emissions of hydrocarbons result from the incomplete combustion of
carbonaceous fuels. Poor mixing of the combustion gases produces
localized fuel rich areas with insufficient oxygen for complete combustion.
CO is formed as an intermediate product of reactions between carbonaceous
fuels and oxygen. When less than the stoichiometric amount of oxygen
required for complete combustion is supplied, CO is a final product of
the reaction. CO may also be formed by the dissociation of C0? at high
temperatures.
C02 ~ CO + 0
The equilibrium concentrated of CO increases with increasing temperature.
Rapid quenching of the combustion products then "freezes" the concentra-
tion of CO.
To minimize CO emissions, combustion equipment is designed for rapid
reaction rates and long cooling times. Rapid reaction rates are promoted
by: providing intimate contact between fuel and air; furnishing suf-
ficient but not excessive air for complete combustion; increasing the
combustion temperature by preheating the fuel and air; and minimizing
the heat loss during combustion of the fuel. After complete combustion,
slow cooling of the gases promotes complete oxidation of CO to CO .
26
-------
Control of CO emissions is attained by proper adjustment of the air-fuel
ratio. Insufficient air for complete combustion will produce high con-
centrations of CO. Insufficient mixing of the gases in the combustion
units will produce localized fuel rich areas which promote the formation
of CO.
EMISSION ESTIMATES
Estimates of emissions of criteria pollutants from the major combustion
source types and fuels were presented in Table 5. These emissions are
based on: NEDS emission factors; the amount of fuel burned by combustion
source type and load factor, as shown in Table 7; the critical fuel pro-
perties (heating value, ash content and sulfur content); and the appli-
cation of control as determined in this study. The extent of control
applied was based on the assumption that state regulations were being met
in thos states for which regulations have been promulgated.
Table 7. FUEL CONSUMPTION AND LOAD FACTORS
FOR OIL- AND NATURAL GAS-FIRED
INDUSTRIAL BOILERS (2.5 - 63 x 10
Kcal/hr INPUT), 1975
6
Combustion
system
Residual oil
Distillate oil
Natural gas
Fuel
consumption
13,657 x 106 gal
4,100 x 106 gal
3,534 x 109 cf
Load
factor3
0.27
0.38
0.54
Ratio of Btu input to installed capacity,
-27
-------
REFERENCES
1. Steam/Its Generation and Use. Babcock and Wilcox, New York, N.Y.,
1972, 38th Edition.
2. Preliminary Emissions Assessment of Conventional Stationary Combustion
Systems. GCA/Technology Division, EPA 600-2-76-046b, March 1976.
3. Field Testing: Application of Combustion Modifications to Control
Emissions From Industrial Boilers - Phase I and II. (KVB Engineering,
Tustin, California, Project Officer - Robert E. Hall, IERL/RTP.)
EPA Contract No. 68-02-1415.
28
-------
SECTION III
APPLICABLE BEST SYSTEMS OF EMISSION REDUCTION
CONTROL OF NO EMISSIONS
X
NO (the combination of NO and N0«) results from two reactions occuring
X ^
within the furnace volume:
Fuel bound N + 1/2 0 £ NO = Fuel-N conversion
and
Atmospheric N» + 0 J 2NO = Thermal fixation
*- £t
Both reactions require a high temperature environment. Fuel-N conversion
occurs concurrently with the oxidation of the other chemical components in
the fuel matrix. This reaction proceeds at normal combustion temperatures
and is less temperature dependent than thermal fixation. Figure 9 in-
dicates the possible mechanisms of fuel-N conversion to NO.
High temperature in the reaction zone result in a very fast forward reac-
tion for thermal fixation of NO. At sufficiently high temperatures the
reverse reaction exceeds that of the forward reaction rate. However, the
reverse reaction is impeded by quenching of NO as it leaves the flame zone.
The mechanism of N0_ formation is purely theoretical. Experimental analy-
sis has placed the location of maximum N02 concentration just beyond the
visible flame. The formation and decay of NO is attributed to the
3
reactions:
29
-------
OIL DROPLET
( OR 1
COAL PARTICLE
VOLATILE FRACTIONS
(HYDROCARBONS,RN ETC.)
ASH
VIRTUALLY
NITROGEN
FREE
Figure 9. The possible fate of fuel-nitrogen contained in
oil droplets during combustion^
30
-------
NO + H02 = N02 + OH
NO, + 0 - NO + 0
£. £
The formation reaction is therefore dependent on the concentration of the
H0~ radical formed in the ionized gases present within the flame. However,
the post-flame reactions reduce the N0? to NO, producing very low concen-
trations of NO. in the final combustion products.
The rate of NO emission is therefore dependent on all furnace operating
X
and design characteristics which will affect the reaction zone environ-
ment. These include:
• Excess air
• Two-stage combustion
• Burner design and setting
• Feed air temperature
• Flue gas recirculation
• Firing rate
• Fuel utilized
• For oil, the entering viscosity and atomization method and pressure
• Boiler design - fire tube or water tube
• Steam or water injection into furnace
• Mixing rate of feed components
Tests on full size units have shown fuel-N conversion efficiency is:
• Inversely proportional to (N) in fuel
• Directly proportional to local fuel/air ratio
• A weak function of local temperature
Fuel-N conversion efficiency is dependent on the availability of single
oxygen atoms. For low fuel-N concentrations within the fuel, low concen-
trations of free oxygen atoms will provide high conversion efficiency of
the resulting free N atoms to NO. As the fuel-N concentration increases,
31
-------
the avilability of free 0 atoms will decrease as they are combined with
the N atoms. The free N atoms will then tend to form NZ and the percent
conversion of fuel-N to NO will decrease. However, the overall contri-
bution to N0x emissions will be greater for a high fuel-N concentration
fuel due to higher concentration of N atoms and the more complete com-
bination of free 0 atoms within the local combustion environments.
Thermal fixation occurs in appreciable quantities only above 1600 C
(2900°F). The total quantity of NO produced in any given gas stream
X
is therefore dependent on the temperature and concentration-time history
of each individual gas pocket. The time-temperature curve for a typical
boiler is shown in Figure 10. Tests have shown the residence times
for the flue gases in the high temperature (above 1600 C (2900 F) environ-
ment to be less than 50 millseconds. Therefore, the total NO resulting
from thermal fixation is critically dependent on the peak flame tempera-
ture and the concentration of oxygen atoms.
Initial studies of NO formation and emissions control were based on the
x
results of computer simulations of the combustion area. Theoretical
reaction parameters were varied and the total NO output was calculated.
X
More recently, the production of reliable NO detection equipment has made
X
possible the accumulation of production data for actual unit operation
with various NO control technologies. Each method will be discussed
x
separately and the best design will be suggested in the conclusions.
Boiler Modifications
Excess Air Reduction - All boilers utilize an excess air feed rate to in-
crease the quantity of oxygen present in the reaction zone. Lowering this
excess can reduce the total amount of NO produced in the combustion zone.
x
Also, the overall system enjoys an increase in the thermal efficiency as
the total volume of excess air is decreased. Tests on utility boilers
have shown an average decrease in NO of 0.014 kg as N09/10 Kcal (0.0078
fi ^ (\
lb/10 Btu) for each 1 percent decrease in excess air in the feed stream.
32
-------
Ul
a:
CL
5
UJ
2800
2400
2000
1600
1200
800
400
, 350F
SUPERHEATER/REHEATER/
1 ECONOMIZER/
FURNACE AIR HEATER
l TO2
SEC
2 TO 5
SEC
STACK
TIME
5 TO 6
SEC
Figure 10. Time-temperature profile in a typical large boiler furnace^
33
-------
Figures lla and lib show test data for two small boilers firing residual
oil. These data indicates that the maximum reduction possible with
these units was 12 percent of the uncontrolled NO output. A second
A.
study determined that NO reduction resulting from variation of excess air
ft
is also fuel-dependent. Further discussion of these data will be pre-
sented in the fuel switching effects on N0x output. Figure 12 indicates
the effects of excess air reduction on oils with various fuel-N concen-
trations. From these data, it can be determined that the decrease in con-
centration of 0 atoms affects both the thermal and the fuel-N production
of NO . Reduced fuel-N concentration resulted in lower NO reductions for
9 X
equal losses in excess air percentages.
These data indicate that reducing the excess air will result in significant
NO reductions. This technique is easy to implement by simply increasing
X
the fuel feed rate while maintaining the same air feed rate. The reduc-
tion of excess 09 is limited by the occurrence of incomplete combustion
at very low levels. In addition, CO, smoke, and HC release rates become
unacceptable. Also, boiler operation is negatively affected at very low
excess air levels; vibrations occur, slag forms within the unit, and fire-
side corrosion rates can increase. The implementation of this modifica-
tion must, therefore, take into consideration the individual unit operat-
ing characteristics, furnace dimensions, and construction materials.
Two-Staged Combustion - A portion of the combustion air is diverted from
the initial combustion zone and injected downstream from the burner. This
modification has two principal effects on NO production: the combustion
X
process is slowed down and the delayed release of the heat results in
lower bulk gas temperature and, consequently, the thermal fixation re-
action will be suppressed; and the lower 0 atom concentration in the ini-
tial flame zone lowers the rate of fuel-N conversion to NO . The loca-
x
tion for introduction of the secondary air feed is best situated at the
end of the visible flame. At this point, the residence time of the unoxi-
dized fuel-N is sufficient to allow its reduction to N . Hydrocarbon
34
-------
0.50
0.45
a 0.40
(0
2 0.35
^
o
z 0-30
M
00.25
JS
of 0.20
z
§0-15
S
iu _ ,_
xO.IO
z
O.O5
Q
_
N0.6 OIL
— ^ — +
-i-^--*^-^^
^>^ +
"*
_ _ .
_ UK UIL __x__
^.x — — ~x
'x
-
^ GAS
-T3 O ^^^^^
NO. 2 OIL "o-x
^ T~ —
-
i i i i i i i i
0-60
0.55
-, 0.50
_
CD
(g
^5 *
>^
Tvi 0-40
0
z
« 0.35
o
i 0.30
£i
of 0.25
z
o
w 0.20
S 0.15
x
o
•z. o-io
0-05
0 10 20 30 40 50 60 70 80 90 0
EXCESS AIR, percent ^
-
_
N0.6 OIL
4-— —
•«• -~ —
^.+
+•
CR OIL x-
jt^^"
X
-
NO. 2 OIL
- jr-*^ GAS
II 1J ft ^~~<3
^
~"^
-
1 1 1 1 1 1 r 1
) 10 20 30 40 50 60 70 80 9<
EXCESS AIR, percent
Figure lla. NOX versus excess air for Scotch
fire tube boiler, 2.52 x 106
Kcal/hr7
Figure lib. NOX versus excess air for water
tube boiler, 5.04 x 10& Kcal/hr7
-------
600
20
30 40 50
EXCESS AIR (%)
60
70
80
90
Figure 12. NO (ppm) corrected to 12 percent CO versus excess air (%)9
-------
oxidation proceeds more slowly in the fuel rich primary stage thus re-
ducing the peak flame temperature and slowing the rate of NO thermal
X
fixation.
Figure 13 presents data from tests on an oil-fired unit utilizing various
positions for secondary air introduction. These data indicate that
the injection position significantly affects the potential control pos-
sible for the specific unit. These values were obtained without exceed-
ing a test control value of 100 ppm of CO for any NOX control modification.
Shaded symbols on Figure 6 represent uncontrolled NOX emission rates, open
symbols for staged air introduction. Numbers inside circles indicate dis-
tance from the burner face at which the secondary air was introduced.
Cm distances from burner throat are beside the symbols. Unit capacity
was 4.28 x 106 Kcal/hr (17 x 106 Btu/hr) operated at a test load of 82
percent of capacity: Fuel = No. 6 oil, steam atomized.
The installation of this modification can be carried out in many different
ways. In multiple burner arrays, reduction of fuel feed rate to the upper
burners and introduction of higher fuel injection to the remaining units
will form an effective secondary combustion zone. The maximum reduction
possible was found to be approximately 50 percent of the uncontrolled NO
X
emission rate for a primary air feed at 90 percent stoichiometric.
Figure 14 presents reduction experienced with a two-stage combustion
operation.
However, many of the units utilizing these methods require an increase in
total excess air to maintain the combustion efficiency; CO and particulate
rates tend to increase above the acceptable limits due to incomplete oxi-
dation of carbonaceous material. The total NO reduction is thus less
X
than operating with this modification alone. The total volume of air
injected into the second stage should equal approximately 15 percent of
the total air feed, with the nozzle and duct velocities equal to the wind
box values. This will provide the needed heat release reduction while
not deleteriously affecting the flame characteristics.
37
-------
u>
oo
C\J
O
c/j 100-
90-
z
o
CO
52 80
ui
CO
x 70
Z
UJ
60-
190
180
170
E
°- 160
-------
700
600
500
£400
2
Q.
Q.
300
200
100
1 kXXXO
OvXXXX
\X\X\X
/
/
/
A
\\X\\N
NXXXXX
-
/
/
/
XXXNXX
XXXXXX
\\XX\N
(
—
OPERATION
NORMAL 0
TWO- STAGE Q]
'
/; n
^
FIRING
DESIGN
HORIZONTAL HORIZONTAL TANGENTIAL
Figure 14. Two-stage combustion, oil fuel
39
8
-------
The minimum cost of installation of an overfire air system on an exist-
ing unit was estimated to be $100,000 for a 21.7 x 10 Kcal/hr
(86 x 106 Btu/hr) plant in 1975. This corresponds to approximately
$0.005 Kcal/hr ($0.0013 Btu/hr) capacity. However, this cost can be
as high as $0.0185 Kcal/hr ($0.0047 Btu/hr) capacity. These costs
10
make its installation prohibitive except on new units.
Flue Gas Recirculation - This modification requires the recirculation
of the combustion products into the combustion air feed stream. The
thermal fixation reaction is inhibited by the reduction of the peak
flame temperature. The high concentrations of CO^, CO, and H20 cause
the reaction to be slowed and the heat release to be lowered. Fuel-N
oxidation may also be reduced of the 0 atom concentration in the primary
combustion zone. The reduction of NO realized is very dependent on the
X
mixing efficiency of the flue gases and combustion air prior to entry
into the flame zone. Locally, high 0~ concentrations will cause an in-
crease in the heat release rate and thus the NO emissions rate.
x
Figure 15 presents data from the KVB emissions study indicating the
variation of the effect of flue gas recirculation (FGR) on the NO per-
X
centage decrease from the base line operating values. This modification
is more effective when burning natural gas than oil-firing. This process
has shown little effect on the combustion efficiency of the boilers
tested thus far. ' However, for high rates of FGR (greater than 50
Q
percent), flame stability is adversely affected and particulate loading
increases. Also, the cost and increased space requirement of FGR equip-
ment are very high due to the large volumes of high temperature gas which
must be recirculated. This method should be considered as a last resort
•I f)
for the solution of an existing emissions control problem. New burner
designs may incorporate FGR without the added expense of extra fans and
duct work. These designs will be discussed in the burner design modi-
fication section.
40
-------
100
80 -
Ld
>
LU
CD
U.
O
2«o
O
ID
O
LD
CC
X
O
20
NO. 6 FUEL OIL, AIR ATOMIZED
NO. 6 FUEL OIL, STEAM ATOMIZED
NATURAL GAS FUEL
NATURAL GAS FUEL a NO. 6 FUEL
OIL, AIR ATOMIZED
10 20 30
% FLUE GAS RECIRCULATION
40
Figure 15. Effect of flue gas recirculation on total
nitrogen oxides emission
41
-------
Boiler Design - The major affects of boiler design on N0% production are
the result of the furnace heat release volume and burner spacing which
combine to influence the time/temperature history of the combustion gases.
Wider burner spacing allows the combustion gases to experience more
cooling before the mixing affects of flame interactions can cause higher
thermal fixation rates. The effect of heat release volume is fuel de-
pendent. Gas-firing exhibits no significant dependence, probably because
of the short-time periods required for complete combustion. Other fac-
tors previously discussed in the firing methods section add to the NOX
production for various designs, but the heat release volume is a signi-
ficant factor due to its effects on the average flame temperature.
Finally, tests performed on fire tube and water tube units with equal
capacities and fuel requirements have demonstrated no consistent effects
of heat exchanger design on NO production rates.
X
Water or Steam Injection - This measure directly reduces the flame tem-
perature and, thus, the NO thermal fixation. The maximum feasible in-
x 6 6
jection rate would be 43.7 kg water/10 Kcal fuel fired (24.2 lb/10 Btu).
This would result in an efficiency penalty of at least 5 percent.
Although the installation cost of this modification is low, the operating
cost penalty is very high due to the increased gas flow rate and the
latent heat losses through the stack. It is, therefore, not suitable
for full scale NO emissions control, but may be useful as a trimming
X
technique when meteorological conditions require very low emissions
levels.
Burner Modifications
The combustion environment generated by the burner flame can be modified
by redesign or adjustment of the burner itself or its feed streams. NO
emission rates for a particular burner are a function of the degree of
mixing, the addition of recirculated gases, and the atomization of the fuel.
42
x
-------
The rate of heat dissipation from the flame can also affect the charac-
teristic emission rates of a burner. Burner design paramaters affecting
these flame characteristics are: the baffle setting which produces the
swirl of the combustion gases; the ignition-point location with respect
to the burner throat; and the direction of the air feed to the combustion
zone. Modifications of these burner characteristics cause variations of
the flame produced, resulting in different rates of NO production.
X
Burner Register Adjustment - Burner registers control local air distribu-
tion patterns and the degree of swirl imparted to the combustion gases.
Figure 16 presents the typical effects of variations in the secondary air
register position. The reduction of NO realized was between 6 and 22
X
percent of the baseline value with efficiency dropping no more than 1
percent. A fully-opened damper decreased the amount of primary air re-
sulting in decreased fuel/air mixing near the burner and maximum NO
X
reduction. However, this reduction was obtained with a large increase of
particulate concentrations.
For single register burners, the major effect is the increased swirl
that accompanies closing of the secondary air register. The cooling
experience by the hot combustion zone gases when mixed with the cooler
air feed gases causes the reduction of NO thermal fixation. Dual-register
X
burners vary both the secondary and tertiary air flow rates, thereby
increasing or decreasing the total excess air. Any increase in excess
air would cause any NO reduction resulting from swirl variation to be
10 x
overshadowed. Further R&D is necessary to determine the optimum
setting or air distribution patterns that are most beneficial for NO
X
control.
Burner Tune-Up - Manufacturer specifications suggest specific settings
for fuel and air feed rates, register settings, etc. When burners were
tuned to these settings, NO emission rates tended to increase for gas
X
firing and had no effect on oil burners. However, the efficiency of
43
-------
in
LJ
a
x
o
60--
50--
O
z
Is
40--
30--
20--
120
10
10/90
I-
20 40 60 80
SECONDARY AIR REGISTER,% OPEN
20/80 30/70 40/60
100
SO/50 60/40
APPROXIMATE RATJO, SECONDARY AIR/PRIMARY AIR
1 0
o
x
o
QL 4
20 40 60 80
SECONDARY AIR REGISTER ,% OPEN
Figure 16. Effect of secondary air register position on total
nitrogen oxides emissions and smoke level, No. 2
oil fuel10
44
-------
combustion did increase up to 1 percent with reduced CO for both oil and
gas. Particulate emission showed no variation. Therefore, with existing
units, no NO reduction can occur with readjustment of burners to design
X
specifications.
Fuel Atomization Method - Oils are atomized using four different techniques:
steam, air, pressure-mechanical, and rotary cup. The latter system is
used only for units below this study's capacity limitations. KVB data in-
dicate that the rate of NO emission is independent of this atomization
method.
Fuel Atomization Pressure - Only a small amount of data has been collected
on the effect of variations of atomization pressure. From these tests, it
has been postulated that increasing the pressure causes the resulting fuel
cone to be tighter, delaying contact with the combustion air and therefore
causing NO production by slowing the overall rate of oxidation. For units
X
operating at low load percentages, the increased pressure would enhance
the burning rate of a lazy flame and therefore cause an NO increase.
X
Further study of the cone pattern effects on NO production is again neces-
X
sary to determine the optimum design pressures.
Delayed Mixing - Mixing patterns dominate N0x production in turbulent
diffusion flames. A high swirl rate in a short flame will produce large
13
quantities of NO ; low swirl in long flame lowers NO . A delay in the
X "
mixing and combustion of the feed materials allows the entrainment of bulk
furnace gases which lower the overall flame temperature and therefore the
thermal NO production. A slowly mixed flame is characterized by a yellow
luminescence, the product of inefficient combustion. This type of flame
was found to emit NO at 0.89 kg/10 Kcal (350 ppm). A highly turbulent
x /-
flame can produce NO at rates of between 1.28 to 3.83 kg/10 Kcal.
X
(500 to 1500 ppm). This significant reduction suggests that further
analytical work must be done to produce a system which achieves complete
combustion, but at the slow rates characteristic of a poorly mixed flame.
45
-------
Japanese Low NO Burners - Three types of low N0x burners are now in use
or under study in Japanese industries:
• TRW burner
• Self-recirculating gasification burner
• IHI divided flame burner18
The TRW burner provides good fuel-air mixing with rapid combustion. Air
is injected in a continuous cylindrical stream around a single fuel
element through which fuel is injected radially through shaped ports.
The intermixing of the fuel and air produces a thin, conical flame pat-
tern. This provides the maximum possible radiating surface, allowing
rapid dissipation of heat. Also, a short residence time is assured and
combustion products are recirculated within the flue. Eleven boilers in
Japan and a few in the U.S. with output ranges of 4.56 x 10 to 24.1 x 10
Kcal/hr are now in operation utilizing the TRW design. This burner is
characterized by low soot formation and requires no furnace redesign to
accommodate the flame shape. Its inherent disadvantages is a high pres-
sure drop at the burner.
The SRG burner provides a high rate of recirculation of the combustion
products back into the flame. The flame is very stable over large load
variations. However, the candle shape of the flame cannot be altered and
may require larger furnace volumes than may be desirable. Over 1000 units
are now operating in Japan.
The IHI burner (Ishikawajima-Harima Henvy Industries) produces a divided
flame by installation of a specially designed burner tip. Field test
results have indicated that fifty percent NO reduction is possible for
X
new units incorporating this nozzle tip according to field test results.
This burner may see expanded usage when data become available for com-
mercial installations.
46
-------
Burner redesing is thus one viable alternative to NO control. However,
X
the technology requires further research and field testing for reliability
and applicability to all boiler designs.
Effect of Fuel on NO Emissions
x
Coal-fired boilers emit larger quantities of NO than oil- pr gas-fired
X
units. Table 8 presents the average and range of NO emissions rates
X
from the tests run on 47 operational boilers.
Table 8. RANGE AND AVERAGE EMISSIONS OF TOTAL NITROGEN
OXIDES AT BASELINE AND LOW-NOX OPERATION10
Fuel type
Coal
No. 2 oil
No. 5 oil
No. 6 oil
Natural gas
Range
Baseline
NOX
g/GJ*
(ppm)
100-562
(164-922)
36-101
(65-180)
112-347
(200-619)
107-196
(190-350)
26-191
(50-375)
Average
Baseline operation
NOX
g/GJ
(ppm)
290
(475)
67
(120)
164
(293)
151
(269)
71
(139)
Excess
02
%
8.7
5.5
5.8
5.3
4.8
Low-NOx operation
NOX
g/GJ
(ppm)
225
(369)
59
(105)
142
(254)
121
(216)
57
(111)
Excess
02
%
6.7
4.0
4.9
4.9
5.0
*4.19 x 103 g/GJ = kg/106 Kcal.
The larger excess air requirement for efficient combustion is the most
aignificant factor responsible for this trend. Fuel conversion is depen-
dent on excess 02 concentrations.
47
-------
Fuel-N conversion is the major contributor to the large NC>x emission
rates for coal combustion. A 1 percent N (by weight) composition in
coal will result in a NO emission rate of 1200 g/GJ (1900 ppm), assuming
X
complete conversion. The maximum fuel-N conversion rate for oil is lower,
730 g/GJ (1300 ppm), due to tis higher heating value per pound of fuel.
The actual conversion efficiency of fuel-N to NO is much lower than 100
X
percent. It is dependent on the initial fuel-N content and the avail-
ability of oxygen in the combustion zone. KVB data indicate that the
percentage conversion decreases with increasing fuel-N content. The
average percentage of the conversion for all oils tested was 46 percent.
The thermal fixation of nitrogen in the combustion air resulted in NO
X
emission rates of 34 to 100 g/GJ (60 to 200 ppm) for all the oil furnaces
tested. Gas firing, although carried out with higher peak flame temperature
has a low rate of NO production, due to the low excess air requirements.
X
The control of these emissions cannot be carried out utilizing the same
modifications for each type of fuel. The varying furnace, burner, and
combustion environment characteristics result in wide differences in con-
trol efficiencies for different combustion equipment modifications.
Fuel switching could be considered as a possible NO control measure;
x '
however, the cost of furnace conversion and the requirements for higher
grade fuels make this method unfeasible.
Natural Gas Combustion and NO Control - Gas firing has already been shown
X
to have a low NO emission rate in tests done on existing furnaces. Excess
X
air reduction has shown a 13 to 25 percent reduction in NO for a reduction
of 10 to 5 percent excess air. '
This is true only for systems utilizing preheated feed air. The NO pro-
X
duced by gas firing is a function of the rate .of thermal fixation. The
excess air levels are already low, requiring high flame temperatures for
NO production. Boilers without preheat, typically fire tube designs,
48
-------
have a relatively constant NO production rate due to the air-fuel pre-
mixing characteristics of the individual burners, the heat absorbing cha-
racteristics of the furnace, and the differences in burner design.
Preheated air boilers experience a 5 to 40 ppm NO decrease for each 1 per-
cent excess 09 decrease. Accompanying this .NO reduction, the furnace
^ X
combustion efficiency increased 0.5 percent for each 1 percent excess 0
reduction. The actual percentage of excess air reduction possible for a
given unit will depend on the specific operating characteristics.
Staged combustion for natural gas firing has been shown to reduce NO
25 to 50 percent below the base line operation emission rates. The
initial fuel-air feed can be reduced to 70 to 85 percent of the stoichio-
metric air requirements without increasing smoke output. The pressurized
gas flame provides sufficient mixing to allow the maintenance of a low
peak flame temperature and burner stability at fuel rich feed concentra-
tions. The second stage, introduced when the combustion gases have
cooled to the point where second stage oxidation will not cause the bulk
gas temperature to exceed the peak flame temperature, should be added
to maintain the lowest possible excess air concentrations. Figure 17
shows the data points for second stage NO reductions from the KVB
X
testing program.
Flue gas recirculation was found to be the most effective for natural
gas firing. Gas firing generates NO only by the thermal fixation
X
mechanism. FGR lowers the high temperature of the characteristically
intense gas flame. This flame undergoes no self-cooling by natural
recirculation of the combustion products. The gaseous flow patterns
drive all the product gases away from the combustion area. The addition
of C00 and H00 slows the reaction rate and effectively lowers the NO
22 x
emission rates.
Preheated air systems also can experience significant NO reduction by
X
reducing the operating load. The combination of lower air preheat and
49
-------
TESTLOAD: 42 GJ/HT (40xi63ib/hr)
FUEL: NATURAL GAS
TEST Nos. 180 a 183
IZD
z
o
co 100
co
LJ
LU
Q
— —3
X /o
0 ^
LL)
O
cr
i_
i 75
50 J
240
OT<~\
£JVj
220
o \r\
C.\\J
or\r\
C\j(j
~ 2z
°- 100
Q. 190
CO
0 mn
loU
^ I7O
f- ' U
<
>• icn
2 lbU
Q
150
I4O
Rn
120
i in
inn
9
FUEL RICH
COMBUSTION
BASELINE NOx
0 /
>
/oP V
A/vT
n /
/
/v
/
0 1C
AIR RICH
COMBUSTION
A
ft
%
/
/
y/lH/
/v
V
O II
p
a
/„
0
SYM PORT OPEN
O NONE
/\ 00-7
Q 6 a 7
0 8 as
D 10 a 1 1
A 12813
v 14 a 15
® ISonly
II I4oniy
n ior
THEORETICAL AIR AT BURNER, %
Figure 17. Effect of staged air on total nitrogen oxides
emissions, natural gas fuel ^
50
-------
poorer mixing characteristics resulted in lower temperatures for the
Q
combustion products and therefore lower NO . Figure 18 presents
X
data for NO reduction with gas-fired load reductions.
X
Variations of burner air register had little effect on the NO emission
X
rates because the change of the swirl pattern does not significantly
alter the mixing efficiency of the burners. The flame intensity and
temperatures are therefore not altered.
Feed air preheat temperature was shown to be a significant factor for
NO emission rate variations. With preheat, firing rate and excess air
X
changes caused moderate differences in NO emissions; fire tube and small
X
water tube units without preheat showed little or no effects for these
changes. The effects of preheated air on NO are dependent on the out-
X 6
put capacity of the individual boiler. Units less than 7.56 x 10 Kcal/hr
(30 x 10^ Btu/hr) showed a 15 ppm increase in NOX for each 55.5°C
(100°F) increase in preheat temperature; 10.1 x 106 to 15.1 x 106
Kcal/hr (40 to 60 x 106 Btu/hr) units a 56 ppm NOX increase per
55.5°C (100°F) increase; and 27.7 x 106 to 40.3 x 106 Kcal/hr (110 to
160 x 10 Btu/hr) units demonstrated a 125 ppm NO increase for each
8 x
55.5°C (100°F) preheat temperature increase.
Fuel Oil Combustion and NO Control - The most important factor in NOX
emission rates from residual oil was found to be the fuel-N content.
The average percentage of the conversion to NO for all the KVB test
X
data was 46 percent of the N fixed in the fuel matrix. The control
measures that will be effective therefore have to reduce both the ex-
cess oxygen availability and the temperature of the combustion products.
During the distillation of No. 2 oil, most of the fuel bound nitrogen
is removed, causing the effects of modifications to be similar to the
natural gas results. Excess air has little effect on the NOX production
rates, in this case independent of the preheating done to the combustion
51
-------
Ul
NUMERAL WITHIN
SYMBOL INDICATE
TEST NUMBER
FUEL NATURAL GAS
50 75
PERCENTAGE OF BOILER CAPACITY %
Figure 18. Effect of firing rate on total nitrogen oxides emissions, gas-fired water tube boilers
17
-------
air. The residual grade fuels (higher fuel-N) do experience significant
NO reduction for lower excess air inputs. Typical emission rates are
X
30 ppm for distillate fuels and 100 to 200 ppm for residuals with fuel-N
concentration of 0.1 to 0.4 weight percent. Excess air variation was
found to reduce NO by 7 percent for each 1 percent reduction in excess
0- for No. 5 and 6 fuels. ' No. 2 fuel oil experienced less than one-
half this rate of emission control with lower excess air. The efficiency
of combustion was found to increase by 0.6 percent of the base line value
with each 1 percent decrease in excess air.
Staged combustion was also demonstrated to be an effective NO control
X
technique for oil firing. No. 5 fuel experienced 6 to 25 percent re-
duction in NO when staging was carried out by air introduction through
X
the upper burners of an array. No. 6 reductions of NO using this method
Q 2C
were 12 to 29 percent. However, the particulate counts also increased
with the staged combustion modification; the 12 to 75 percent increase
in particulate loading resulted from an increase in the unburned carbon
output. Also, high-sulfur fuel oils using staged combustion cause large
increases in furnace slagging and pressure part corrosion due to the re-
13
ducing atmosphere of the fuel rich flame emitted from the burner.
Staging, therefore, does not show the promise for fuel oil NO control
X
that it does for natural gas, even though the possible reduction is greater
without consideration of the other effects.
Flue gas recirculation has shown great potential for oil NO control.
X
A 10 to 90 percent reduction occurred when firing No. 6 oil with FGR in
the KVB testing. Other tests have shown a 30 percent reduction for N
14
containing oils with FGR. Previous testing by ESSO demonstrated an
80 percent reduction in NO for a 30 percent recycle rate for all types
of fuel oils. Also, other emissions were not increased until more FGR
9
caused the flame to become unstable. FGR thus seems to be a promising
NO control technique for new boiler constructions.
53
-------
Firing rate reduction (percentage of capacity) has little or no effect
Q
on the rates of NO emissions when firing oil.
X
The effects of boiler design on the efficiency of N0x control depend on
the burner heat release rates and volume. The larger the heat release
volume, the lower the bulk gas temperature resulting in lower N0x>
Fire tube and water tube units were sensitive to the same control measures,
Q
Adjusting the burner air registers has little effect.
Fuel oil viscosity was tested for No. 6 oil over a temperature range of
68.3° to 121. 1°C (155° to 250°F) . No consistent relationship appeared
in the KVB data for NO production.
X
Scrubbing Technology for NO Control
'
An alternative to combustion and furnace design modifications is the use
of stack gas clean-up. These scrubber systems would be useful in special-
ized situations where high rates of NO emission exist or in the case that
X
very low levels are required. Four scrubbing systems have been considered
for the removal of N0x from an effluent gas stream:
® H2SO^ scrubbing
9 Alkaline scrubbing
® Molecular sieve absorption
• Catalytic reduction
H2S04 Process* by Tyco Lab of Waltham, Massachusetts, recycles N02 to
oxidize S02 to t^SO^. Equimolar concentrations of NO and NOo are re-
quired for efficient operation. This ratio is hard to maintain in most
effluent gas streams. The H2S04 process operates with very slow transfer
rates which require large contacting equipment. The resulting cost and
chemical concentration requirements cause this process to be unacceptable.
54
-------
The alkaline process by ESSO Research utilizes reaction of Mg(OH)2 with
N02 to remove N0x from effluent gases. This process also operates with
slow mass transfer rates between the flue gas and the sorbent. The ini-
tial capital cost will thus be high for the large equipment installation
required. However, the by-products are saleable, making the overall operat-
ing costs run in the black. The initial capital investment, however,
makes this process unfeasible.
Molecular sieve absorption is also unfeasible because the materials now
in use preferentially absorb H20, one of the main combustion products
in the flue gases.
Catalytic reduction processes seem to hold the most promise for flue
gas treatment of NO as a supplement of combustion modifications. Selec-
X
tive reduction with NH, and nonselective reduction by CO or H~ are under
consideration. The major question that researchers have not yet doc-
umented concerns the effect of the combustion effluents on the cata-
lyst lifetime. A 2 x 105 m3/hr (7 x 106 ft3/hr) plant is now in oper-
ation in Japan. The initial capital investment was $5 million with operating
costs of $2,382 per year. These figures, when extrapolated to utility
plant sizes, show a capital cost of $130/kW at a differential operating
cost of 7.9 mills/kWh. Flue gas desulfurization costs are $30 to $100/kW
and 1 to 4 mills/kWh while combustion modifications are typically $1 to
14
$10/kW and 0.1 to 0.4 mills/kWh. Despite the costs, the use of cata-
lytic reduction may see industrial installation in the 1980's.
Thus, all the possible flue gas treatment systems have significant problems
which make their immediate use impossible. Development of a larger data
base on catalyst performance and long-term operating efficiencies will
delay the use of this control technique until the 1980's.
55
-------
NO Scrubbing Technology in Japan
'X
Strict regulation of NO emission rates for all Japanese industries has
X
resulted in widespread installation of NO scrubbers. Tables 9 and 10
X
indicate the current status of the commercial installation of these
units in Japan. These flue gas treatment facilities utilize either dry
or wet scrubbing. The dry units depend on selective catalytic reduction
(SCR). Ten boilers are now operating with SCR in Japan. The Sumitomo
Chemical design has shown good reliability and has maintained an NO
X
removal efficiency of 90 percent without catalyst destruction. The sim-
plicity of operation, combined with the resistance of the catalyst to
poisoning by SO , indicate the high potential this design has for wider
application. The absence of any water treatment facilities also adds
to the attractiveness of this design. The costs of application are high,
however. The catalyst is broken down and lost when contracted with a dust
laden feed stream. The system thus requires initial electrostatic preci-
pitation of dirty flue gases, more than doubling the total cost of installa-
tion. The total cost is comparable to SO particulate scrubber systems,
X
and with implementation of more stringent NO controls in the U.S., their
X
system may see extensive use in combination with combustion modifications
of industrial boilers. The utilization of this design in the U.S. will
occur only after extensive commercial operation provides reliable data for
analysis of the systems cost effective control possibilities.
Comparison of the wet versus dry systems does not provide any basis for a
final conclusion as to which design might prove to be the best choice.
The wet scrubber has the following advantages:
o Simultaneous SO and NO removal
X X
® No high temperature requirements for the feed stream
* No particulate concentration requirements
e By-produces nitrate and sulfate fertilizers.
56
-------
Table 9. MAJOR PLANTS FOR DENITRIFICATION BY SELECTIVE CATALYTIC REDUCTION
19
Process
[developer
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Tokyo Electric-
Mitsubishi H.I.
Kurabo
Plant owner
Sumitomo Chiba
Chem.
Higashi Nihon
Methanol
Nihon Ammonia
Sumitomo Chem.
Sumitomo Chem.
Sumitomo Chem.
Sumitomo Chem.
Sumitomo Chem.
Tokyo Electric
Kurabo
Plant site
Sodegaura
Sodegaura
Sodegaura
Anegasaki
Anegasaki
Niihama
Sodegaura
Sodegaura
Minamiyokohama
Hirakata
Capacity,
Nm3/hr
30,000
200,000a
250,000a
100,000a
200,000a
200,000a
250,000
300,000
10,000a
30,000
Source of gas
Oil-fired boiler
Heating furnace
Heating furnace
Gas-fired boiler
Gas-fired boiler
Heating furnace
Oil-fired boiler
Oil-fired boiler
Gas-fired boiler
Oil-fired boiler
Completion
July 1973
May 1974
Mar. 1975
Feb. 1975
Feb. 1975
Mar. 1975
May 1976
May 1976
Jan. 1974
Aug. 1975
-------
Table 10, MAJOR PLANTS FOR NO REMOVAL FROM FLUE GAS BY WET PROCESS
X
19
Process
developer
Sumitomo Metal
Fuji Kasui
Sumitomo Metal
Fuji Kasui
Sumitomo Metal
Fuji Kasui
Tokyo Electric
Mitsubishi H.I.
Type
of
process
Redox
Redox
Redox
Oxidation
absorption
Plant owner
Sumitomo
Metal
Toshin
Steel
Toshin
Steel
Tokyo
Electric
Plant site
Amagasaki
Fuji
Osaka
Minami-
Yokohama
Capacity,
Nm3/hr
62,000
100,000
39,000
100,000
Source
of
gas
Boiler3
d
Furnace
Boilera
Boilerb
Completion
December ' 74
December '74
December ' 74
October ' 74
By-product
NaN03, NaCl
Na2S04
NaNO NaCl
Na2S04
NaN03, NaCl
Na2S04
HNO_
00
Oil-fired boiler.
Gas-fired boiler.
"Coal-fired boiler.
Metal heating furnace.
'Iron ore sintering furnace.
-------
However, the disadvantages are:
• Most designs require an expensive oxidizing agent,
• A large absorber is required to accommodate the slow
reaction rates,
• The by-products are produced in a very dilute liquor
requiring a large energy input for recovery,
• The demand for these by-products is limited.
Dry systems have the following advantages:
• Consumes much less reducing gas than nonselective
catalytic reduction,
• Simpler operation and requires less plant space than
wet processes,
• No troublesome by-products,
• No gas reheating is required,
• Best for clean flue gas treatment (gas-fired boilers).
The disadvantages of the dry system are:
• Dirty gas treatment requires a base metal catalyst,
which have characteristically lower reaction rates.
Less than one-tenth the volumetric flow rate is possible.
• The catalyst is poisoned by S0_, SO., and dust.
• Disposal of spent heavy metal catalyst could be a problem.
Wet absorption systems are operating on four industrial-sized boilers in
Japan. Once again, Sumitomo, in combination with Fuji Kasui, has developed
the most promising design. This wet system provides simultaneous removal
of SO and NO . The high removal efficiencies, 90 percent for NO and
X " X
98 percent for S02, are offset by high costs of installation and opera-
tion. Also, the resulting water treatment problem, a low concentration
of nitrate and sulfate in large quantities of water, is a major drawback.
59
-------
This design is superior to the other Japanese designs due to its demonstrated
commercial applicability, simplicity, and lack of gypsum sludge production.
It also utilizes a less expensive oxidizing agent, CIO™, rather than the
ozone required by many of the other systems. This oxidation step is
required by these units because the NO- form of NOX reacts more quickly
with the basic solution within the scrubber.
Conclusions - NO Control Technology
Table 11 summarizes the NO reductions that have been demonstrated with
x
the indicated control measures without significant increases in CO or par-
ticulate emissions. Staged combustion also can be used for oil-fired burn-
ers to obtain average NOX reduction of 27 percent SOX residual oil and
10 percent for distillate fuels. Baseline NOX emissions for distillate
and residual fuels are 36 - 101 g/GJ (0.084 - 0.23 lb/106 Btu) and
107 - 196 g/GJ (0.25 - 0.46 lb/106 Btu) for the tests results found in
Table 8. Finally, gas-fired boilers can obtain a 70 percent reduction
of NO by means of flue gas recirculation. The baseline rate of 26
x ft
26 - 101 g/GJ (0.06 - 0.23 lb/10 Btu) can thus reach a level of 7.8 to
57.3 g/GJ (0.02 - 0.13 lb/10 Btu) well below the requirements for new
sources greater than 63 x 10 Kcal/hr (250 x 106 Btu/hr).
Burner redesign has high potential for lowering the emissions of industrial
and commercial units. However, the low-NO burner technology is still in
X
its infancy as far as application to commercial units is concerned. Wide
scale application could reduce N0x emissions by 50 percent or more, but ••.
further research and design is necessary.
NO scrubber systems provide excellent removal efficiencies but the cost
is prohibitive in all cases. If future advances can bring the initial
investments to reasonable levels, such as packaged units utilizing cheap,
regenerable catalysts while producing directly useful by-products, these
systems could see wide application. Also, for plants operating in areas
60
-------
Table 11.. NO REDUCTIONS BY CONTROL HOBtFXCATIONS
A.
on
No. 2
No. 6
Tang.
Front
Tang.
Front
Gas
Comments
1. Excess combustion
air
15%
21.451
8.4%
Easiest, least costly for all
units.
2. Staged combustion
10%
27%
26.52
Useful In many cases, but
will cause partlcuate In-
crease In oil firing.
3. Burner register
ad j ustment
Effects caused by air distribution to individual burners, not swirl.
4. Combustion air
temp reduction
No data
13.5%
40.5%
Can cause major efficiency
losses in boilers. Heat
lost through stack.
5. Flue gas
recirculation
Low fuel-N cone makes
application inef-
fective in that loss
of flue stability.
17%
702
Ten percent particulate
loading Increase with oil
44 p. 159 at 17% FGR.
6. Firing rate
reduction
Except in preheat air gas. Dependent on excess variation with <10% load changes.
7. Fuel oil
viscosity
variation
No general trend. ±10% for various
temperatures.
Particulate loading
decreases with Increasing
temperature of oil feed.
8. Burner tune—up
Only slight reductions possible, dependent on
unit. No general trend.
Increased NO,
Particulate loading in-
creased. Most effective
timing, decrease except
air and accept resulting CO
increases.
9. Fuel atomlzation
method change
Rotary
Cup
Ste
Air
Pressure
See attached table and comments
No significant variation
between atomizers.
10. Fuel atomizatlon
pressure
variation
Increased pressure (air, steam, or oil) = 6% in-
crease in NOX.
.'. Use lowest pressure
prescribed by burner
manufacturer which still
produces acceptable flue.
11. Wet scrubbing
60-90% removal efficient-see tables for process descriptions & characteristics
No data obtained—values
from EPA summary of
Japanese process efficiency.
12. Dry scrubbing
(catalytic
reduction)
80-852
See tables for process descriptions and
characteristics
90%
No data except summary-cost
make use of those units
unacceptable to date.
13. Fuel nitrogen
content
No. 6 •* No. 2 » 70 percent
No fuel-N, only entrained
Nj in gas.
Coal-to-oil switches will de-
pend on excess air require-
ments, furnace geometry, etc.
with fuel-S drop not as
significant.
Note
New Units =
Existing Unit!
| ] (Best possible efficiency.
-------
requiring negligible NO concentrations, this may be a viable alternative
X
when the simultaneous removal of SO is also realized. Its use on small
X
boilers will be limited at best in 1985.
The most cost effective technique for NO reduction in 1985 will be the
X
incorporation of all the boiler modifications suggested previously,
staged combustion, flue gas recirculation, excess air control. Installa-
tion of low NO burner designs must also be incorporated into new boiler
X
units. Scrubber costs will be prohibitively expensive well into the
future, but more restrictive emission regulations and further improve-
ments in operation may require their installation eventually.
62
-------
CONTROL OF SOV EMISSIONS
X
Two alternatives are available to control SOX emissions from combustion
of high sulfur fuel oil.
• Precombustion desulfurization of feedstock
• Flue gas desulfurization (FGD).
A number of flue gas desulfurization schemes presently exist which are
applicable to both coal-fired and oil-fired boilers. Residual oil
desulfurization techniques produce a variety of solid, liquid and gaseous
fuels.
Feedstock Desulfurization
Several feedstock desulfurization techniques exist which produce low sulfur
solid, liquid and gaseous fuels from high sulfur feedstocks. For example:
coking produces solid, liquid and gaseous fuels; hydrodesulfurization
(HDS) produces a liquid fuel; and a procedure called partial oxidation
produces a low Btu gas. Although the specific reaction steps vary, most
feedstock desulfurization techniques are based on the reaction of hydrogen
with oil in the presence of a catalyst, as is shown in the general reaction.
rj +H
catalyst
fuel sulfur | + H >
clean fuel
ELS is evolved in the desulfurization process. Consequently, residual
desulfurization is a two step process: (1) desulfurization of the resid-
ual oil with the resulting formation of t^S; and (2) the disposal or
recovery of the lUS process stream in an environmentally acceptable manner.
The metals content of the feed is the most significant variable influencing
processing cost and desulfurization efficiency. High molecular-weight
organometallic compounds of vanadium and nickel are found in most crude-oil
residues. Under the reaction conditions necessary for desulfurization,
63
-------
some of these complex molecules decompose resulting in the deposition of
vanadium and nickel on the surface of the desulf urization catalyst. Over
months of continuous operation, metal accumulation causes a reduction in
catalytic desulfurization activity. High metals feedstock (metals in
excess of 150 to 220 ppm) will, in most cases, require some form of feed
demetalization.
In general, residual oils of low to moderate metals content (Ni plus V
content less than 100 ppm) and sulfur content as high as 6 percent can be
directly desulfurized to yield heavy oil products containing as little as
0.5 wt percent sulfur. For higher metal content feeds and lower sulfur
product fuel oil levels, modified techniques, such as Flexicoking or
demetalization/desulf urization, will be required.
Only three systems (L.C. Fining, demetalization/desulf urization and
Flexicoking in conjunction with an HDS unit) have been designed to effect-
ively handle high metal content feedstocks. L.C. Fining and demetalization/
desulfurization are both hydrodesulf urization techniques. The Flexicoking
process is an extension of the fluid coking process. Other systems are
capable of desulfurizing high metal feeds, but at a higher operating cost.
Removal - Because feedstock desulfurization generates I^S as a process
stream, it is necessary to dispose of or convert this gas to a useful
product. The most commonly practiced method is the conversion of HoS
19
to elemental sulfur by means of a Glaus Plant. A flow diagram of a
typical two stage Glaus sulfur plant is shown in Figure 19.
The most common method of concentrating and collecting H»S involves wash-
ing the product gas with a water solution containing an amine. The rich
solution is then steam stripped, driving off the H s, and regenerating the
absorbing solution. A typical composition of the gas taken from an amine
regenerator is :
64
-------
H2S 90 -
C02 2 -
HC 0.5 -
H-O vapor 5
THERMAL STAGE
HgS •+• ~ 02— »S02-f HgC
S02+ 2H2S<=^3S-I-2H20
I^IAH, I » ^_ - L_L.J
V ./ i-- u — •" r '
' ' »• r 1 r 1
A'K J J
H20 ' H20 '
\
S
CATALY
STAG
t- A S02 + 2
H20-J
!
93%
10%
2%
10%
TIC INCINERATOR STACK
ES
so2--
H-Sv^aS-* 2H-Q + A 10.000 ppm TO
*• *• 30,000 ppm
Fun
1 AIR ^
iHgO—1 1
S
APPROXIMATE SULFUR 60% 25% 7%
YIELD
Figure 19. Typical two-stage Glaus sulfur plant
The tUS present in the gas may then be converted to elemental sulfur by
the following reaction scheme:
H2S
S0_ + H« (thermal combustion)
2 H S + S0n
3 S + 2 HO (thermal and catalytic)
(overall) 3 H S + 0
2H20+3 S+H2
The overall efficiency of a Claus plant is 90 to 97 percent.
fur conversion in a Claus plant is limited because:
• The Claus reaction is reversible and is limited by
chemical equilibrium;
Maximum sul-
65
-------
• A very significant portion (25 percent) of the sulfur
passes through the system in relatively unreduced
form - carbonyl sulfide and carbon disulfide.
Glaus Tail Gas Cleanup - The tail gas from a typical sulfur plant contains
about one-third water vapor, 5 to 15 percent C02, 2 to 4 percent sulfur com-
pounds (H?S, S02, COS and CS2), and the balance nitrogen. The S02 concen-
tration in the tail gas is 10,000 to 30,000 ppm. In order to produce a
stack gas with less than 250 ppm SC>2 content, the overall sulfur plant
must be at least 99.9 percent efficient. This efficiency is not possible
with present technology unless a tail gas cleanup plant is also used.
Several systems are available for tail gas cleanup: the Beavon Sulfur
Removal Process, the Cleanair Sulfur Process, and the IFF process. The
investment and operating costs for the Beavon and Cleanair Process are
approximately equal to the original cost of the sulfur removal plant. The
IFP process is approximately one half the cost of the original sulfur
plant but is not as efficient as the first two (99.0 percent versus 99.9
percent).
Beavon Sulfur Removal Process - The Beavon Sulfur Removal Process, de-
veloped by Ralph M. Parsons Company and Union Oil Company of California,
is capable of limiting SO,, emissions to 40 to 80 ppm depending on the
efficiency of the preceding Glaus Plant. In this process the Glaus plant
tail gas is mixed with hot combustion gas produced by burning fuel gas
with air. The resulting reducing mixture is passed through a catalytic
reactor similar to that in a Glaus plant. The sulfur is hydrogenated to
I^S on a cobalt/molybdate catalyst. Water is condensed from the gas in
a heat exchanger. The cooled gas stream is passed to a Stretford section
in which H,,S is removed from the gas and converted to elemental sulfur.
The cost of this system is approximately equal to the original cost of
the Glaus plant.
Stretford Process - The Stretford Process consists of a gas washing system
wherein the gas is contacted countercurrently with an alkaline washing
66
-------
solution (sodium carbonate). Hydrogen sulfide is removed from the gas
stream and is oxidized to elemental sulfur. The sulfur is formed as a
finely dispersed solid in the circulating solution. The reduced solution
is then oxidized by air blowing which simultaneously removes the sulfur
by froth flotation. The oxidized solution is returned to the gas wash
system to repeat the cycle. The sulfur slurry is fed to an autoclave
where heat is applied to dry and melt the sulfur. Liquid sulfur of
greater than 99.5 percent purity is obtained.
Cleanair Sulfur Process - The Cleanair Sulfur Process developed by
J.F. Pritchard and Co. and Texas Gulf Sulfur Co. is capable of producing
a gas effluent containing less than 250 ppm of SCL. This system is com-
posed of three process stages, two of which are proprietary and are not
fully explained in the literature:
• Stage 1 converts essentially all of the SC>2 to elemental
sulfur with some additional conversion of I^S to elemental
sulfur;
• Stage 2, which is the Stretford process (the same process
used in the Beavon process) converts the remaining H2S to
elemental sulfur;
• Stage 3 is an important step in controlling COS and CSo
emissions from the Glaus tail gas. Concentrations of
these two compounds are reduced to less than 250 ppm
equivalent S02« Carbon disulfide and carbonyl sulfide
are the prime precursors of high S02 concentrations in
Glaus tail gas treating systems.
The cost of this system is similar to the Beavon process and is approx-
imately equal to the original cost of the Glaus plant.
IFP Process - The third Glaus tail gas treatment process is the Institute
Francais du Petrole (IFP) system. Glaus tail gas at about 127°C (260°F)
is injected into the lower section of a packed tower, where a solvent
containing catalyst is circulated countercurrently, resulting in maximum
liquid-gas contact. Product sulfur accumulates at the bottom of the
67
-------
tower and is continuously removed. Some solvent is 1'ost by evaporation
through the top of the column and therefore must be replaced. Catalyst
is also pumped to the tower to maintain a constant concentration. Due
to this system's inability to handle COS and CS2j emissions are approx-
imately 1500 ppm S02', however, the original investment is only one-half
of that required for the Beavon or Cleanair Sulfur Process.
Environmental Impacts of Residual HDS - Possible environmental problem
areas from HDS are:
• Catalyst disposal (including vanadium and nickel deposits)
• Vanadium, nickel and other trace constitutents in
desulfurized fuel
• Various wastewater streams
• Glaus and tail gas cleanup emissions
• NH_ from amine scrubber
• Catalyst disposal from Glaus and tail gas cleanup process
• COS emissions
• CS2 emissions
Economics of Feedstock Desulfurization Processes - Table 12 summarizes
the feed types, desulfurization efficiencies and hydrogen and water re-
quirements of the three feedstock desulfurization techniques capable of
handling high metal feedstock. Table 13 presents the same data for
other processes.
Cost data are taken directly from literature published by system developers,
It is difficult to accurately compare process costs for the following
reasons:
68
-------
Table 12. PROCESS PARAMETERS OF HIGH METALS FEEDSTOCK DESULFURIZATION TECHNIQUES
20
Process
Flexicoking
Demetalization/
Desulfurization
L. C. Fining
Feed
type
Iranium
heavy
Bachaquero
% S
feed
3.43
3.66
% S
product
7. S
removal
0.2 equiv. 947. equiv.
0.2 equiv. 95% equiv.
W. Texas ! 4.6
Venezuelan
high metals
crude
Venezuelan
medium metals
atm res id
Kuwait
atm resid
Gach
Saran
atm resid
5.6
2.8
4.05
4.05
2.6
2.6
0.2 equiv. 96% equiv.
1.27
0.64
1.0
0.5
1.0
0.5
77
77
75
88
62
81
Metals
feed,
ppm
525
Metals
product,
ppm
5
1040 j 10
137 1
Hi - 85
V - 1100
Ni - 57
V - 398
Ni - 15
V - 49
Ni - 15
V - 49
Ni - 45
V - 165
Ni - 45
V - 165
H2
consump-
tion,
scf/bbl
-
-
•
!
-
_
.
.
1140
680
910
1030
540
630
Water usage
20-30 gal/bbl cooling
12-16 gal/bbl boiler feed
20-30 gal/bbl cooling
12-16 gal/bbl boiler feed
20-30 gal/bbl cooling
12-16 gal/bbl boiler feed
-
-
4590 gal/min A25°F cooling
4860 gal/min A25°F cooling
5410 gal/min A25°F cooling
5830 gal/min A25°F cooling
-------
Table 13. PROCESS PARAMETERS OF RESIDUAL OIL FEEDSTOCK DESULFURIZATION TECHNIQUES
20
Process
HDS-Gulf
RCD Isomax
Universal Oil
Products Co.
Residue
Desulfurization
BP
Residue
Hydroprocessing
Standard
Oil Co.
Residue
Ultrafining
Amoco
Feed
type
Kuwait
Kuwait
Direct I
Direct II
Modified
Direct III
Kuwait
Kuwait
Khafyi
W. Texas
Sour
% s
feed
3.8
3.8
3.8
3.92
4.1
3.9
3.9
3.9
4.0
4.0
4.0
4.02
4.02
4.47
3.85
3.85
•1. s
product
1.0
0.3
0.1
1.0
0.3
1.0
0.5
0.32
1.0
0.5
0.3
1.0
0.5
1.0
1.0
0.3
7. S
removal
75
92
97
74
93
74
87
92
75
88
93
75
88
78
74
92
Metals
feed,
ppm
60
60
60
Ni - 15
V - 47
Ni - 15
V - 47
Ni - 15
V - 45
Ni - 15
V - 45
Ni - 15
V - 45
Ni - 13
V - 49
Ni - 13
V - 49
Ni - 13
V - 49
69
69
Ni - 93
V - 32
Ni - 25
V - 16
Ni - 25
V - 16
Metals
product,
ppm
0.2
<0.1
<0.1
-
-
-
-
-
-
-
-
-
-
Ni - 6
V - 18
Ni - 4
V - 13
Hi - 3
V - 12
16
5
-
H2
consump-
tion,
scf/bbl
515
740
900
600
750
550
770
850
625
835
1050
560-620
560-620
580
420
600
Water usage
214 gal/bbl cooling A20°F
288 gal/bbl cooling A20°F
355 gal/bbl cooling A20°F
-
-
-
-
-
-
-
-
160 gal/bbl cooling 4.2 gal/bbl process
160 gal/bbl cooling 4.2 gal/bbl process
-
_
_
1
-------
Table 13 (continued). PROCESS PARAMETERS OF RESIDUAL OIL FEEDSTOCK
DESULFURIZATION TECHNIQUES 20
Process
Go-fining
Feed
type
Arab
Heavy
Exxon Athabasca
Res id fining
Exxon
Residue
HDS
Badische
Anilin-und
Soda-Fabrik
A.G.
HDS - Trickle
Flow
IFF .Residue
and VGO HDS
Institute
Francais du
Petrole
sands
Gach
% S
feed
2.96
3.97
Saran 2.5
Arab
Heavy
Kuwait
Thermal
cracker gas
Iranian
Light
Atmospheirc
4.19
4.1
1.33
2.5
7. S
product
0.1
0.11
0.3
0.3
0.95
0.16
0.3
7. S
removal
97
97
88
93
77
88
88
Metals
feed,
ppm
-
-
Metals
product,
PPm
-
-
220 !
1
1
120
-
-
-
-
-
H2
consump-
tion,
scf/bbl
410
975
625
915
650
232
Water usage
30-50 gal/bbl cooling
30-50 gal/bbl cooling
150-300 gal/bbl cooling
150-300 gal/bbl cooling
-
260 gal/bbl cooling A30°F
37.7 gal/bbl cooling
-------
• Differences in feedstock
— Source
— Sulfur content
— Metals content
• Differences in amortization rates
• Differences in assumed costs of hydrogen and other materials
— For example, the reported price of hydrogen varies
between 25c and $1.00 per 28.5 Nm3 (thousand standard
cubic feet) of gas
• Differences in plant sizes
• Unpublished assumptions regarding labor costs,
transportation costs, etc.
With these caveats in mind Table 14 presents a summary of the economics
of these processes. The column labeled "GCA estimated operating costs"
represents an attempt to report process costs on a common basis in 1975
dollars. The figures in this column were calculated based upon estimated
operating costs of 75
-------
Table 14. ECONOMICS OF RESIDUAL OIL DESULFURIZATION TECHNIQUES
20
U)
Process
Feed
type
Cost
basis,
bpsd
% S
feed
Of c
In 3
product
HDS-Gulf : Kuwait ; '
Type II
Type III
Type IV
RCD-Isomax ; Kuwait
Direct I
Direct II
; Modified
Direct III
Residue Desulf.
Bp process |
Investment
% S Total
removal MM, S
50,000 3.8 : 1.0 74 !
50,000
3.8 ! 0.3 92
Per bbl,
capac ity ,
?
1.58
2.10
50,000 3.8 0.1 97 2.43
, j
50,000 ! 3.92 : 1.0
50,000
40,000
40,000
40,000
50,000
4.1 0.3
3.9 1.0
3.9
3.9
'
4.0
4.0
i
Resid Hydro- j Kuwait
20,000-
processing ; j 40,000
Standard
Oil Co.
Go-fining ! Arab Heavy
i
Athabasca
tar sand
I
Resid-
Gach
fining ! Saran
Residue HDS
Arab
Heavy
Kuwait
18,000-
95,000
4.0
4.02
0.5
0.32
74 28.1 1.69
93 . 41.5
74 21.80
87 29.32
92 35.31
1.0 75
0.5 | 88
0.3 93
28.6-
31.6
1.0 75 i
i
i
2.96
2.49
1.63
2.21
2.65
1.36
1.57
-
2.14
2.37
Operating cost
Total
MM, S
Per bbl,
capacity,
$
-
-
-
GCA estimated
operating cost,
$/bbl
0.85
1.20
1.58
i
1.30 1.41
0.1 97 $80-150/bpsd
; capacity
3.97
55,000 : 2.5
(Avg.)
, 4.19
45,000
4.1
0.11 97 1
0.3 | 88 $300-750/bpsd
j capacity
0.3
93 :
|
0.95
77
1.38
1.73a
0.71a
0.98
1.10
1.49
1.95
2.47
t
I
|
1
1.91
1.15
1.59
1.78
_
-
-
1.08
-
-
-
-
0.90
References
1, 2, 3, 4, 5
6, 7, 4, 8, 9
10, 11
12, 13
14, 15, 4, 16
15, 4, 14
17
difference in operating cost is price of hydrogen 60
-------
Table 14 (continued). ECONOMICS OF RESIDUAL OIL DESULFURIZATION TECHNIQUES
20
Process
HDS-Trickle
flow
IFP Re sid
and VGO HDS
Resid ultra-
fining
Amoco
Shell
Feed
type
! Khafyi
Cost
basis,
bpsd
13,000
(Avg.)
40,000
40,000
i
W. Texas
Sour
W. Texas
Sour
Gasification |
process
Delayed coking
VGO/VRDS Isomax
Flexicoking
Demetalization/
Desulfurization
Vene-
zuelan
metals
| crude
L.C. Fining
Vene-
zuelan
metals
atm
re sid
Kuwait
atm
re sid
Gach
Saran
40,000
10,000
conversion
of vacuum
Resid at
$2/bbl
No econo-
mic data
20,000
20,000
20,000
25,000
25,000
40,000
7. S
feed
1.33
2.5
4.47
3.85
7. S
product
0.16
0.3
1.0
1.0
3.85
0.3
5.0
3.43
3.66
4.6
5.6
2.8
4.05
4.05
2.6
2.6
% S
removal
88
88
78
74
92
0.2 equiv.
947. equiv.
0.2 equiv.
957. equiv.
0.2 equiv.
967. equiv.
1.27
0.64
1.0
0.5
1.0
0.5
77
77
75
88
62
81
Investment
Total
MM
26.8
19.8
26.8
24.4
17.9
20.4
23.7
23.9
25.2
33.4
34.3
29.8
38.9
Per bbl,
capacity,
$
2.01
2.01
1.49
2.01
2.73
Operating cost
Total
MM
Per bbl,
capacity,
$
0.99
1.16
0.84
1.17
$0.79/MM
Btu of gas
or
$3. 57 /bbl
1.51
3.09
3.60
2.89
3.05
2.53
2.22
3.23
2.60
2.26
2.95
0.24
0.34
0.48
1.17
0.95
GCA estimated
operating cost,
$/bbl
_
1.28
1.60
1.17
1.63
.
-
-
-
-
1.32
1.11
1.21
1.35
1.04
1.28
References
18
4
19, 4
20, 21
22, 23, 24, 25, 9
26, 27, 4, 28
29
1
30, 4, 31
-------
Table 15. SUMMARY DESCRIPTION OF FLUE GAS DESULFURIZATION PROCESSES
21
Ul
Process
Lime/limestone
scrubbing
Double alkali
process
scrubbing
Vellum-Lord
Classification/
operating principles
Throwaway process /wet
absorption In scrubber
by slurry; Insoluble
sulfltes and sulfates
disposed of as waste.
absorption in scrubber;
products soluble; reac-
tion products precipi-
tated and removed from
recycled react ant solu-
tion outside of scrubber;
most coimion react ant
sodium sulfite.
absorption by magnesium
oxide slurry; fly asb
removed prior to or after
scrubbing; magnesium
oxide regenerated by
calcining vitb carbon;
SQ2 byproduct can be con-
or sulfur.
Regenerative process/
•odium base scrubbing
with sulfite to prodace
bisulfite; regeneration in
an evaporative crystalli-
zer; sulfate formed
either purged or removed
by selective crystalliza-
tion.
S02 participate
efficiency
Up to 90 percent S02
removal /99 percent fly
ash removal by most
scrubbers.
cent S02 removal /high
particulate removal
part iculate removal as
required by prescrubber.
>90 percent S02 removal
particulate removal by
prescrubber.
Development status
primarily to scaling;
16 full scale units in
stare-up by 1977.
scale demonstration as
yet; G.H. installed a
boiler in Feb. 1974;
several sulfate removal
schemes under study.
test at Boston Edison
150 HW oil-fired unit
Reliably operated
(>9000 hours) in
Japan. Full scale dem-
onstration scheduled
at Northern Indiana
Public Service coal-
fired 115 KH boiler;
sulfate removal vital
to success.
Application
Old bue prefer-
plants; coal- or
oil-fired.
potentially
lower cost and
operation favor-
ing some inroads
into smaller
plants.
limestone but
oil-fired boil-
ers will not
require partic-
ulate control
upstream of
scrubber.
As above.
Implementation
installation by 1977;
new plants; 3 years
for retrofit of old
plants.
estimates $600 mil-
lion a year market
generation lime/
limestone system;
lead times as above
for power plants.
immediate implemen-
tation; lead times
as for lime/lime-
stone systems.
As above.
Advantages
Cheapest of ex-
cesses; ellmin-
ment.
cheaper, sim-
pler and more
lime /limes tone
system.
reliable than
lime /limes tone
process; no
known waste
disposal prob-
lems; regen-
eration facil-
ity need not
be located at
utility.
More reliable
than lime/
limestone sys-
tem based on
Japanese ex-
perience; sim-
plicity of
unit opera -
t ions in re -
generator;
waste disposal
problems re-
duced.
Disadvantages
Techr.ical reliability
water pollution prob-
supply and handling of
large volumes of reac-
tant may be problems.
all throwaway systems.
marketing of sulfur
product s ; reheat .
Some bleed of solution
to remove undesirable
reaction products a
source of water pollu-
tion, otherwise as above.
-------
Table 15 (continued). SUMMARY DESCRIPTION OF FLUE GAS DESULFURIZATION PROCESSES
21
Process
Citrate system
Catalytic
Classification/
operat ng pr nc p es
Regenerative process/flue
and absorbed In sodium
t on in packed tower;
s lution then reacted
u th hydrogen sulfide to
Regenerative process/
convert S02 to S03 fol-
lowed by condensation to
forro 70-80 percent
H2S04- Variation of con-
tact process applied to
dilute gases.
S02 participate
e c ency
>95 percent SO2 removal/
plugging and fouling
of catalyst.
New development by Bureau
1000 cfm pilot plant;
also 2000 cfm unit in
High potential.
on 100 HW boiler of
Illinois Power Company;
reliability not demon-
strated.
As above.
New plants, oil
^
As above.
As above .
g s
High efficiency;
economic ; no
intermediate
SO2 regenera-
1 lability; poten-
tially most at-
tractive of
viable pro-
cesses.
Relatively sin-
technology;
minimal mechan-
ical operations;
no relevant re-
heat require-
ments.
n g
Marketing of sulfur;
reheat.
Expensive; poor qual-
poor reliability with
apprec iable downtime ;
extra ducting to avoid
problems associated
with ESP failures and
high temperature gases.
-------
Table 16. OIL-FIRED UTILITY BOILERS IN THE UNITED STATES EMPLOYING FLUE GAS DESULFURIZATION20
Utility & plant
City of Key West3
Stock Island
Boston Edison
Mystic 6b
Capacity,
MW
42
155
Process type
Tail-end limestone
scrubbing
Magnesia scrubbing
Startup
date
8/73
4/72
Availability,
7,
Low
57
Par tic -
ulate
control
Mech
-
No
ESP
-
Yes
System efficiency
Particulate
removal, "k
90
—
S02
removal, "1,
85
90
Longes t
continuous
run, days
5
7
Comments
Very little scrubber operation since .
startup; high liquid level in scrubber
causes high pressure drop, which kicks
system off-line.
Scrubber availability improved from
March through June 1974; during this
period, the inability to demonstrate
runs longer than 7 days was due
primarily to boiler problems and not
related to scrubber operation; scrub-
ber was shut down at the end of June
at the conclusion of the 2-year test
program.
Only oil-fired boilers using flue gas desulfurization.
bOil-fired boiler.
SOURCE: EPRI 209, Status of Stack Gas Control Technology. Prepared by Battelle Columbus Laboratories.
July 1975.
-------
Environmental Impacts of Flue Gas Desulfurization Techniques - The en-
vironmental impacts of five flue gas desulfurization techniques are dis-
22
cussed below. These techniques are:
1. Limestone slurry scrubbing;
2. Lime slurry scrubbing;
3. Magnesia slurry scrubbing;
4. Sodium solution - SC>2 reduction;
5. Catalytic oxidation
Emissions and effluent data are based on a 500 MW power plant. The fuel
is coal containing 3.5 percent sulfur with the FGD system assumed to have
a 90 percent efficiency. Coal is used in this comparison instead of resid-
ual oil because it is the only fuel with sufficient environmental data for
FGD. The solid waste and particulate matter generated when firing residual
oil will be less than for coal firing. Table 17 lists the pollutants
which are incompletely converted or generated as byproducts from each
22
system.
Table 17- FGD ENVIRONMENTAL IMPACT3, TONS/YR
Limestone slurry
scrubbing
Lime slurry
scrubbing
Magnesia slurry
Sodium solution
scrubbing
Catalytic oxidation
Particulate
1,280
4,276
1,968
3,077
96
so2
1,921
1,847
2,884
4,225
144
NO
X
448
431
673
1,089
34
Solid waste
156,444
156,442
386
35,002
(32,700-sul£ur)b
55
Water
soluble
-
-
110,400b
(H2S04)
1,300
(Na2S04)b
109,900 b
'Capacity 500 MW; fuel, coal; SO. removal, 901; sulfur In fuel 3.5%.
t . _
Salable by-product.
78
-------
Limestone Slurry Process - A considerable quantity of CaSO«/CaSO solid
waste is generated approaching as much as 4 times the weight of the sulfur
removed. Wastes discharged to settling ponds are reported to have poor
settling properties and may lead to difficulty when reclaiming the land for
future use. Potential runoff from the ponding site could lead to addi-
tional water pollution problems.
Lime Slurry Process - Characteristics and problems associated with the
lime slurry process are similar in nature to the limestone slurry process.
The only difference is that an additional 2.73 x 10 kg (3000 tons) of
particulates are produced from the production of lime, which may, however,
be generated offsite.
Magnesia Slurry Process - This process is also similar to the two preced-
ing FGD methods with the exception that the by-products (MgSO»/MgSO,) are
regenerated, thus eliminating the large quantities of solid waste. The
regeneration step requires additional process water and fuel thus producing
additional emissions.
Sodium Solution Process - Although this process is considered to be a
regenerative process, a great amount of Na_SO, by-product is produced.
This process requires a large amount of steam and water resulting in the
largest quantity of airborne pollutants among the five processes.
Catalytic Oxidation Process - This process is the cleanest and least
energy intensive of all five processes with no by-products generated
other than marketable sulfuric acid. Catalyst life appears to be a signif-
icant problem area.
The only recent data for the environmental impacts of a residual oil-fired
23
boiler using a FGD system is that from the Boston Edison Mystic 6 Station.
This demonstration plant was for a 150 MW magnesia-wet scrubbing system
firing 2.5 percent sulfur fuel. Spent material is sent to an off-site MgO
regeneration plant capable of producing 4.55 x 10 kg (50 tons) per day of
79
-------
sulfuric acid. The system recovers 91.7 percent of the inlet S02 and re-
duced particulate emissions by 57 percent.
Sources of emissions from this demonstration plant include:
MgO losses (total average loss of 336 kg (0.37 tons)/day over
13 day test program)
• Stack
• Centrifuge washing
• Centrifuge case leaks
• Pump packing gland leaks
• Absorber overflow
• MgO slurry tank blow-down
• MgO slurry tank overflow
• Centrate tank overflow
• Solids loss at dryer feed end
• Dust losses at dryer I.D. fan
• Dust loss at expansion joints
• Spillage at MgO feeder
• Spillage at MgSO., belt galley
• Spillage at truck loading point
Waste water
• Process water
• Cooling water
Solids buildup in regenerated MgO
• Vanadium
• Nickel
• Ash
Flue Gas Desulfurization Economics - In the generation of operating costs
for FGD two factors must be considered; the internal costs (i.e., the
cost of running the equipment at the plant), and the external costs
(i.e., the costs associated with operations away from the site). The
80
-------
external costs represent the charge for disposing of transformed pollu-
tants, undesirably by-products, and the indirect pollutants generated
from the production of raw materials. These values are not available
for oil-fired boilers using FGD since the two existing units on an
oil-fired boiler have not reached stable conditions. However, they
are available for coal-fired boilers using FGD and are given in
Table 18. As can be seen from this table, the use of catalytic
oxidation is cheaper and generates fewer pollutants than the other sys-
tems, but the limestone scrubbing process is cheaper to operate.
Table 18. ANNUAL CONTROL COSTS - EXTERNAL AND OPERATING COSTS
a,20
Pollutants /wastes,
tons /year
Particulate
S02
NOx
Solid
Water soluble
Cost
External cost
1,000 dollars/
year
Particulate
S02
NOx
Solid
Total
Operating cost
1,000 dollars/
year
Total cost
1,000 dollars/
year
Limestone
1,280
1,921
448
156,444
b
288
565
132
469
1,454
7,703
9,157
Lime
4,276
1,847
431
156,442
b
962
543
127
313
1,945
8,102
10,047
Magnesia
1,968
2,844
673
386
—
443
848
198
1
1,490
9,211
10,701
Sodium
3,077
4,225
1,089
2,302
b
692
1,242
320
7
2,261
11,602
13,863
Catalytic
oxidation
96
144
34
55
b
22
42
9
—
73
8,874
8,947
Capacity, 500 MW; fuel, coal; SO removal, 90%; sulfur content of
the fuel, 3.5%.
Data not available.
81
-------
The small difference in total cost is negligible because it depends on
many variables. The catalytic oxidation process is the most energy effi-
cient, requiring only 5 percent of the input energy. The soidum system
is the most wasteful, requiring up to 35 percent of the input energy.
Disposal alternatives can also affect the total operating cost. An onsite
unlined pond with a clarified liquid recycle system contributes approxim-
ately 7 percent of the total operating cost. An impervious liner increases
this cost to 12 percent of the total; offsite disposal adds another 10 per-
cent and chemical fixation with offsite disposal is approximately 25 per-
cent higher than onsite ponding.
There are at present no actual cost figures available for FGD using lime-
stone scrubbers on oil-fired boilers. The only economic data available
for oil-fired boilers using FGD is for the Boston Edison Plant with a
magnesia scrubber. The results show that in order for this system to be
economically competitive, a $3/bbl difference must exist between the cost
24
of high sulfur and low sulfur fuel oil. Since low sulfur oil can be
prepared from high sulfur feedstock by HDS for under $3/bbl, it appears
that FGD using a magnesia scrubber is a costly way of meeting air pollu-
tion standards for SO- emissions.
Economic Comparison of SO Control Measures - Existing economics data on
X .-.-..-• i
the application of SO reduction control to oil-fired boilers are in-
adequate to allow generalizations to be made regarding the best system
25
of control. Westinghouse has developed cost comparisons for FGD and
HDS for utility-size, oil-fired boilers which indicate that FGD is consi-
derably less expensive than HDS. However, the capital costs involved in
constructing FGD units for boilers in the size range considered in this
report may well offset the price advantage found for utility boilers.
CONTROL OF PARTICULATE EMISSIONS
Mechanical collectors such as cyclones and settling chambers have pre-
viously been the only cost-effective particulate control method used for
small boilers. Recently, changes in state and New Source Performance
82
-------
Standards, (NSPS), have necessitated the installation of other more effi-
cient designs: wet scrubbers, fabric filters, and electrostatic precipita-
tors. Cyclones have maintained their usefulness as primary collectors to
remove large particulates which would clog the more efficient devices;
however, the cyclone's inability to remove particulates with diameters
less than 10 ym (3.94 x 10 in.) requires secondary treatment of the flue
gases to meet the local regulations.
Cyclones
Cyclones, both single and multiple units, can efficiently remove large
diameter particulates. The centrifugal force generated by the device
drives large diameter particles to the walls of the cyclone, thus removing
them from the gas stream. This design operates at efficiencies of 65 per-
cent for single units and up to 70 to 90 percent for multiple cyclone
systems depending on particulate diameters. However, due to the small
size of oil particulate matter, the efficiency of cyclone collectors is
much lower, reaching levels ranging from 40 to 60 percent efficient.
7 ft
Types of centrifugal collectors are:
• Centrifugal reverse flow, either tangential or axial inlet,
high efficiency or high throughput is dependent on the
cyclone diameter.
• Straight through flow cyclones; typically used as a pre-
cleaner for other collection equipment, characterized by
a low pressure drop and a high gas flow rate.
• Impeller collector; its compact size is offset by problems
involving solids buildup on blades and temperature limi-
tations due to bearings and seals.
Wet Scrubbers
Scrubbers remove particulate matter by two mechanisms: by increasing the
effective size of the particle by interaction with water molecules; or
83
-------
by trapping particles in larger water droplets which can be washed away
without reentrainment. For these mechanisms to operate, the particles
r\ r
must contact the water droplets. This occurs by:
• Interception or impingement; actual contact.
• Gravitation to droplet or droplet to particle.
• Diffusion (for submicron particles only).
• Electrostatic forces caused by charges induced
by flame ionization, friction, or presence of
charged matter.
• Thermal gradients; particles move from hot to
cold areas because more molecular collision
occur on the hot side.
Four types of wet scrubbers have been applied to boilers:
• Spray chamber,
• Centrifugal spray scrubbers,
• Impingement plate scrubbers,
• Venturi scrubbers.
Scrubbers have high removal efficiencies, approaching 99.5 percent for
large diameter particulates. However, their operation is characterized
by the following problems:
• High corrosion rates caused by acidic SO solution
which develops in the wash water, x
• High or fluctuating pressure drops,
• Adverse effects on stack gas dispersion,
• Wastewater treatment requirements.
• Poor efficiency for particles less than 1 micron diameter.
Although the initial investment for scrubbers is lower than other high
efficiency design collectors, the operating costs due to pressure drop
84
-------
and due to maintenance and water treatment are far greater than other
units removing particulates in a dry form.
Electrostatic Precipitation (ESP)
96
ESP is a three-stage process:
• Charge supplied to particle by passage through a high
voltage, direct current corona.
• Negatively charged particles move to grounded surface;
the electrostatic attraction is resisted by inertial
and drag forces.
• Vibrate collection plate or wash with liquid.
ESP's operate in the following flue gas environments:
r «
• Gas volumes of 85,400 to 3.42 x 10 Nm /hr
(3 x 106 - 1.2 x 108 ft3/hr)
• Gas pressures of 1 to 10 atmospheres.
• Temperatures of ambient to 400°C (750°F)
• Peak voltages between 30 to 100 kilovolts.
Use of the ESP is limited by:
• Economic considerations; the units have a high cost for a
narrow specificity of small particles. ESP use on small
gas flows is therefore not cost effective.
• Pretreatment cooling is required in some cases, again
increasing the cost and operating complexity.
• Fuel composition affects efficiency; reduction of fuel-S
will cause the collection efficiency to decrease, requiring
a larger plate area for the same removal rates. Decreasing
the concentration of 803 increases the resistivity of the
particulates formed, causing collection from plates to be
extremely difficult.
85
-------
Fabric Filtration
Fabric filtration, also called bag filtering, operates at very high filtra-
tion efficiencies, (approximately 100 percent) of particles greater than
0.5 micros (1.97 x 10~ in.) in diameter, and accounts for substantial re-
moval of particles greater than 0.01 microns (3.94 x 10 in.) in diameter.
Previously, fabric filters had been unsuitable for boiler application due
to an unpredictable and usually short service life. Coatings of flame-
proofing, weldproofing, shrinkage reducing and/or dust releasing materials
all continued to increase the lifetime of the individual bags but did not
solve the requirement of 12 months of continuous operation with low main-
tenance. New fabrics have accomplished what coating of cotton, wool,
Dacron, Nylon, Orion, and propylene could not. Teflon-coated fiberglass,
Teflon, Nomex, and Goretex were found to resist high temperatures for ex-
tended time periods while maintaining their flexibility and continuity.
In addition, the bag filter must withstand occasional excursions beyond the
usual filtering environment conditions, frequent load changes, and periodic
shutdowns typical of small and medium sized boiler operation. This
variable operation causes the temperature of the system to pass through
the acid dew point (~ 135°C (275°F)) repeatedly. Although some fabrics
can withstand these dewpoint excursions, bypass systems and auxiliary
heating are usually employed to achieve reliable operation.
The other major disadvantage of the fabric filtration system is the high
filtration resistance of the baghouse. As the filter cake increases in
thickness, the pressure drop across the baghouse also increases (reaching
5 to 7 in. H20). This requires a more powerful fan system to provide
sufficient pressure to drive the air through the cake and fabric. Also,
the fabrics slowly become blinded, that is the small pores through the
material are filled with particulate matter, preventing the flow of air.
Cleaning systems cannot remove all this material, effectively reducing
86
-------
the total surface area available for filtration. This problem has been
partially solved by the use of different cleaning systems. They are:
• Reverse air
• Pulsed jet
• Sonic waves
• Greater mechanical stressing
27
Advantages of fabric filtration are the following:
• Highly efficient dust collection
• High fractional efficiency for fine dust particles.
• Low sensitivity to physical or chemical changes in the dust.
• Size distribution of particles in inlet not critical.
• Simple design and operation.
• Reliable operation.
• Flexible sizing; units are now being developed for
boilers down to 0.05 x 106 Kcal/hr (2 x Ifl5 Btu/hr).28
Bag filtration is normally applied to coal-fired furnaces. Full scale
operation on an oil-fired boiler was accomplished in Alamitos, California.
However, the ash formed during oil firing is consistently smaller than
coal particulate matter and is surrounded by a sticky outside coating.
The small particles therefore tend to be trapped in the fabric, increasing
the tendency for blinding to occur. The problem has been partially solved
by introduction of pulverized dolomitic limestone as a precoat for the
fabric. This material forms the initial filter cake to prevent the oil
particulate matter from contacting the fabric and also inhibits the forma-
tion of sulfuric acid on the filter bags.
Electrostatic precipitators operation also is hindered by the charac-
teristics of oil-fired particulates. The low resistivity of the high
carbon content ash results in inefficient removal rates for systems
87
-------
utilizing electrostatic forces. The low total rate of emission from oil-
fired units also makes the high investment costs of ESP unattractive.
The clogging problems experienced by wet scrubbers when firing coal will
be reduced by the lower loading factor of the lower ash residual oils.
Sludge treatment is still a problem in this design, however. The total
quantity of solids to be removed is relatively small, but the quantity of
water necessary for removal of these small diameter particulates is still
large. Wastewater treatment requirements therefore cause this technique
to be rejected for industrial oil-fired boilers.
Mechanical separators will remove a portion of the particulates generated
in oil flames, but at very inefficient removal rates. Efficiencies rang-
ing from 40 to 60 percent are typical for multiclones operating down-
stream from oil-fired industrial boilers. This removal rate does not
allow many units to meet the state regulations on particulate release
rates or opacity ratings from stacks. More efficient designs must there-
fore be used.
For oil-fired boilers with capacities greater than 16 x 10 Kcal/hr
(63 x 106 Btu/hr), ESP may be the best design for particulate control.
These units would operate at removal efficiencies of approximately 98
percent. However, this design, which is most cost effective for these
larger industrial boilers today still is limited by the particulate
resistivity. The units installed must be much larger than those utilized
for the same flow rates from coal-fired furnaces. Only minor improvements
can be expected in the future.
Bag filtration is the most cost effective system available for units less
than 16 x 10 Kcal/hr (63 x 10 Btu/hr) today. Efficiencies of 85 to 90
percent can be achieved consistently when the fabrics are pretreated with
inert powders or pulverized dolomitic limestone. Further improvements in
fabric filtration characteristics will result in a wider range of applica-
bility. By 1985, the fabric filters may see use as the major control
88
-------
method for all sizes of industrial boilers, resulting in an overall
particulate removal efficiency of at least 85 percent for oil-fired
boilers.
Effects of N0y Control Combustion Modifications
on Particulate Emission Rates
KVB's testing of combustion modifications on industrial boilers included an
analysis of the particulate loading of the resultant flue gas streams.
Summarizing their results:
• Reduction of excess O^ concentrations reduced particulate
emissions (by as much as 30 percent) in two-thirds of the
tests run.
• Staged combustion caused increases in particulate loading
in all measured runs, ranging between 20 and 48 percent
of the baseline levels.
• Adjustment of the burner registers caused no significant
change.
• No overall trend in the effect of combustion-air temperature
reductions could be discerned with the limited testing that
was carried out.
• Flue gas recirculation was found to significantly increase
particulate emissions from industrial boilers firing coal
and oil, limiting its utility to gas-fired furnaces.
• Reducing the firing rate of the boiler furnace caused large
reductions in the particulate emission rate in one test.
• Burner tune-ups were found to have no effect on particulate
emissions if the resulting flame did not impinge on the walls
of the furnace, thus quenching the oxidation reaction and
causing a drastic increase in unburned carbon emissions.
• Fuel oil preheat temperature was found to decrease
solid concentrations in the flue gas with increas-
ing temperature.
• The oil atomization method effects each burner-fuel-
boiler combination differently. No trends were identified.
• Increasing the atomization pressure can;reduce particulate
emission rates.
89
-------
Summary
Control of particulates from oil-fired boilers must deal with many signif-
icant problems not faced by coal-fired control systems. Industrial applica-
tion of particulate collectors has not been widespread to date. Bag
filtration systems, precoated with dusts to form the initial filter cake,
may be the best design, operating at removal efficiencies of 85 percent or
more.
As more testing of emissions from industrial boilers operating in the low
NO mode become available, the variation of the particulate size distribu-
X
tion and the total emission rates may be incorporated into the final designs
of the bag filtration units.
CONTROL OF CO AND HYDROCARBON EMISSIONS
CO and HC emissions are the result of incomplete combustion of carbonaceous
fuels. The presence of these materials in the effluent gas stream indicates
that the unit is operating with either excess 02 or a burner malfunction.
In all cases, CO and HC result from a lack of available 02 for complete
oxidation in the local fuel/air pockets.
KVB tests have shown CO and HC emission rates to be low in most cases,
generally less than 200 ppm for all fuels. Individual units were found
to have high CO release rates. The less efficient combustion occuring in
stoker units cause higher emission rates than pulverized or cyclone firing.
Oil flames had very low emission rates due to the elimination of CO by
increased excess air concentrations typically used to control smoke emis-
sions. Instances of significant CO product were caused by poor flame cha-
racteristics. In cases where the flame contacted the water walls of the
boiler, the oxidation reactions were either quenched or the fuel/air mixing
was disturbed, resulting in increased CO.
90
-------
Gas combustion utilizes low excess air concentrations and therefore has
the potential for high CO emission rates if the burner is untuned. How-
ever, these near stochiometric C^ concentrations result in lower CO release
rates. Higher air/fuel ratios result in a reduction of the flame tempera-
ture and lower the residence time for the combustion gases in the high
temperature environment. The faster reaction C + 1/2 02 -»• CO reaction has
sufficient time to proceed while the slower reaction of CO + 1/2 02 -> 02 +
does not have sufficient time to reach completion.
Control of CO and HC emissions is performed by adjustment of the burner to
ensure the proper distribution of feed air to combustion zone. Tuning a
burner to the manufacturer's specification reduced the CO emission levels
to near zero while increasing the overall efficiency of the unit and not
affecting the particulate loading of the flue gases. This tuning involves:
• Examining the burner tips for wear,
• Adjusting the spray angle and flame length to make
sure the unburned fuel does not strike the sides
or walls of the furnace.
Table 19 presents data for CO reductions accomplished by this adjust-
ment carried out by varying the amount and swirl of the combustion air.
Table 19. CONTROL OF CO BY BURNER ADJUSTMENT
Test no.
108
112
CO before
407 ppm
116 ppm
CO after
110 ppm
0 ppm
Capacity
29 x 106 Btu/hr
100 x 106 Btu/hr
Excess air increase
2.7 - 3.8%
Control of CO can successfully be controlled by ensuring the combustion
environment has:
• High turbulence to increase fuel/air mixing and thereby
lower the diffusion control of the combustion rate.
• Sufficient residence time for combustion.
• High temperatures.
29
• A near stoichiometric A/F ratio.
91
-------
EMISSIONS FROM THE STORAGE OF OIL AND NATURAL GAS
Emissions from the delivery, storage, and transfer of petroleum and natural
gas are negligible for industrial and commercial boiler systems. The
only pollutants emitted from petroleum and natural gas handling operations
are hydrocarbons. These fugitive evaporative losses are dependent on
several factors:
• Vapor pressure of the liquid
• Temperature variations within the tank
• Height of vapor space
• Tank diameter
• Filling and emptying frequency
• Condition and type of tank
For fixed roof storage tanks the largest emissions result from emptying
and filling operations (working losses) and to a lesser degree from
breathing losses associated with thermal expansion pressure fluctuations
and continuous vaporization. Emission factors for oil and natural gas
storage can be found in AP-42.
92
-------
REFERENCES
1. Surprenant, N. et al. Preliminary Emissions Assessment of Con-
ventional Stationary Combustion Systems. EPA Contract No.
68-02-1316. January 1976.
2. Heap, M.P., et al. The Optimization of Burner Design Parameters
to Control NO Formation in Pulverized Coal and Heavy Oil Flames.
Presented at Symposium in Stationary Source Combustion. September
1975. Atlanta, p. 11-193.
3. Axeworthy, A.E., et al. Chemistry of Fuel Nitrogen Conversion to
Nitrogen Oxides in Combustion. EPA 600/2-76-039, February 1976.
4. Battelle Memorial Institute. The Federal R&D Plan for Air Pollu-
tion Control by Combustion-Process Modification. Contract CPA
22-69-147. January 1971.
5. Reducing NOX Emissions. Chemical Engineering, p. 82-84. October
18, 1970.
6. Blakeslee, C.E. and A.P. Selker. Program for Reduction of NOX
From Tangential Coal-Fired Boilers, Phases 1, 2, and 2a. EPA
650/2-73-005. 1975.
7. Barrett, R.E., S.E. Miller, and D.W. Locklin. Field Investigation
of Emissions From Combustion Equipment for Space Heating.
EPA-R2-73-084a (API Pub. 4180). June 1973.
8. Cato, G.A., et al. Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions From Industrial
Boilers - Phase I. EPA 650/2-74-078a. October 1974.
9. Muzio, L.J., R.P. Wilson, Jr., and C. McConis. Packaged Boiler
Flame Modifications for Reducing Nitric Oxide Emissions. Phase
II of III. EPA-R2-73-292b. June 1974.
10. Cato, G.A., L.J. Muzio, and R.E. Hall. Influence of Combustion
Modifications on Pollutant Emissions From Industrial Boilers.
Presented at EPA Symposium for Stationary Source Combustion.
September 1975.
11. Armento, W.J. Effects of Design and Operating Variables on NOX
From Coal-Fired Furnaces - Phase I. EPA 650/2-74-002a.
January 1974.
93
-------
12. Turner, D.W., R.L. Andrews, and C.W. Siegmond. Influence of
Combustion Modifications and Fuel Nitrogen Content on Nitrogen
Oxides From Fuel Oil Combustion. Combustion, p. 21-30.
August 1972.
13. Krippena, B.C. Burner and Boiler Alterations for N0x Control.
Presented at the Combustion Institute, Madison, Wisconsin.
March 1974.
14. Hall, R.E. and J.S. Boiven. Stationary Source Combustion: An
R&D Update. J of the Air Pollut Contr Assoc. 26(2). February
1976.
15. EPA Industrial Environmental Research Lab. NOX Control Review.
1(1). March 1976.
16. Cato, G.A., L.J. Muzio, and D.E. Shore. Field Testing: Applica-
tion of Combustion Modification to Control Pollutant Emissions
From Industrial Boilers - Phase II. EPA 600/2-76-086a.
April 1976.
17. Shafstall, D.R. and D.H. Larson. Aerodynamic Control of NO and
Other Pollutants From Fossil Fuel Combustion. Vol. 1 Data
Analysis and Summary of Conclusions. EPA 650/2-73-033a.
18. Audo, J., H. Tohato, and G.A. Issacs. NO Abatement for Sta-
tionary Sources in Japan. EPA 600/2-76-OI3b. January 1976.
19. Beers, W.D. Characterization of Glaus Plant Emissions. Process
Research, Inc., Cincinnati, Ohio. U.S. Environmental Protection
Agency. Report Number EPA-R2-73-188. April 1973. 173 p.
20. Werner, A.S. et al. Preliminary Environmental Assessment of the
CAFB. EPA Contract No. 68-02-1316, Task Order No. 4. June 1976.
21. Surprenant, N.S., R. Hall, S. Slater, T. Suza, M. Sussman, and
C. Young. Preliminary Emissions Assessment of Conventional Sta-
tionary Combustion Systems. Volume II - Final Report. GCA Corpora-
tion, GCA/Technology Division, Bedford, Mass. U.S. Environmental
Protection Agency, Research Triangle Park, N.C. Report Number
EPA 600/2-76-046b. March 1976. 531 p.
22. Yan, C.J. Evaluating Environmental Impacts of Stack Gas Desulfuriza-
tion Processes. Environ Sci Technol. 10:54-58. January 1976.
23. Koehler, G. and J.A. Burns. The Magnesia Scrubbing Process as Applied
to an Oil-Fired Power Plant. Chemical Construction Company, New
York, N.Y. U.S. Environmental Protection Agency. Report Number
EPA-600/2-75-057. October 1975.
94
-------
24. Yan, C.J. Evaluating Environmental Impacts of Stack Gas Desulfuriza-
tion Processes. Environ Sci Technol. 10:54-58. January 1976.
25. Keairns, D.L., R.A. Newby, E.J. Vidt, E.P. O'Neill, G.A. Peterson,
C.C. Sun, C.D. Buscaglia, and D.H. Archer. Fluidized Bed Combustion
Process Evaluation. Phase I - Residual Oil Gasification/Desulfurization
Demonstration at Atmospheric Pressure. Volume I — Summary. Westing-
house Research Laboratories, Pittsburgh, Pa. U.S. Environmental Protec-
tion Agency, Research Triangle Park, N.C. Report Number EPA-650/2-75-027a.
March 1975. 137 p.
26. Control Techniques for Particulate Air Pollutants. AP-9, U.S. Department
of HEW, January 1969.
27. Koscianowski, J.R., and L. Koscianowska. Effect of Filtration Parameters
on Dust Cleaning Fabrics. EPA 600/2-76-074.
28. Fabric News Letter. Vol. 1, No. 1. November 10, 1975.
29. Air Quality Criteria for CO. AP-62, U.S. Department of HEW. March 1970.
95
-------
SECTION IV
STATE AND LOCAL AIR POLLUTION CONTROL REGULATIONS
All state and local regulations pertaining to emissions of particulate
matter, sulfur dioxide, and nitrogen dioxide are listed in Tables 20
through 28 and on Figures 20 through 26. Nationally averaged uncon-
trolled particulate emissions from burning of natural gas, distillate
oil, and residual oil, are lower than required by state regulations.
In fact, particulate emissions from natural gas and distillate oil are
sufficiently low that these emissions are normally not controlled.
Uncontrolled particulate emissions from residual oil-firing average out
to 0.283 kg/106 Kcal (0.157 Ib/MM Btu) compared with the nationally
weighted average state regulation limit of 0.5 kg/106 Kcal (0.278 lb/
MM Btu). Particulate emissions from residual oil-fired boilers may be
controlled with fabric filters up to 85 percent, reducing the emissions
to 8.4 percent of the average amount currently allowed.
Similarly, uncontrolled emissions of sulfur dioxide from combustion of
natural gas, distillate, and residual oil are less than those allowed
by state regulations. Again, natural gas and distillate are sufficiently
low in sulfur content so as not to require any controls. Uncontrolled
sulfur dioxide emissions from residual oil-fired boilers are 81.1 percent
of that allowed by state regulations and may be reduced by 90 percent
with hydrodesulfurization of the feed. Emissions from residual oil-fired
boilers may be reduced to 8.1 percent of the level currently allowed by
state regulations.
96
-------
Very few states currently have standards for NCL.. However, the nationally
X
averaged NOX emission rate exceeds the requirements of most state regula-
tions. The best available control technology for NOX relies upon modifi-
cation of excess air rates, burner design and flue gas recirculation rates.
Only one state, Illinois, had a regulation pertaining to emissions of
CO, which is, no emissions greater than 200 ppm at 50 percent excess air.
The effect of this one state's regulation upon the U.S. total is negli-
gible, therefore, we assumed that no controls exist for CO.
97
-------
Table 20. STATE PARTICULATE REGULATIONS, Ib/MM Btu
State
Existing
New
Conn.
Maine
Maai.
N.H.
R.I.
Vt.
N.J.
N.Y.
Pa.
111.
Ind.
Mich.
Ohio
W18.
Iowa
Kans.
Minn.
Mo. .
Nabr.
N. Dak.
S. Dak
Del.
D.C.
Fla.
Oa.
Md.
N.C.
S.C.
Va.
W. Va.
Ala.
Ky.
Miss.
Term.
Ark.
Lu.
Okla.
Tex.
Ariz.
Colo.
Idaho
Mont.
Nev.
N. Mex.
Utah
Wyo.
Calif.
Oreg.
Wash.
Alaska
Hawaii
0.2 Ib/MM Btu
See attached aheet
0.15 Ib/MM Btu
See attached aheet
0.2 Ib/MM Btu
See attached aheet
See attached sheet
E • 1.02H-0-219
0.4 <50 and >50 MM Btu/hr
E - 3.6H-°-56
E - 5.18H-0-715
E - 0.87H-0-1-6
See attached page
E - 51.27H-0-30
E - 0.87H-0-1-6
0.8 max
E - 1.026H"0-233
0.4
logE —0,23299 logH
+ 2.1454
E • 1.026H-0-233
E • 0.811H-°'131
0.3
0.3
E - 0.17455H-°-23522
Beat available tech-
nology or
See attached aheet
E - 1.09H-0.2594
0.6
E - 0.8425H-0-2314
See attached aheet
E - 3.109H-°-sa9 Claaa 2
E • 3.109H-0-589 Clae».2
E - 0.963H-°-"56
See attached sheet
E - 1.09H-°-2594
Ambient concentrations
may not exceed
75 ug/m3 above
background
0.6
See attached aheet
0.3
E - 1.02H-0.769
E - 0,5H-°-2&
logE - 0.23 logH -2.0111
See attached sheet
E « 1.02H-0.2131
E - 0.96135H-°-23471 .
Minimum 857. control
See attached sheet
10 Ib/hr or 0.1 grain/ecf
generally, however each
county has separate
regulations
0.2 grain/act
0.2 grain/scf
0.1 grain/scf
Nona for coal and oil
0.1 Ib/MM Btu
See attached aheet
0.1 Ib/MM Btu
See attached sheet
0.2 Ib/MM Btu
See attached aheet
See attached aheet
E • 1.02H-0.219
0.4 <50 and >50 MM Btu/hr
E - 3.6H-0.56
E - 5.18/H°-715
E - 0.87H-0-"
See attached page
E - 51.27H-0.30
E - 0.87H-0.16
0.6 max
E - 1.026H-°-233
0.4
logE - -0.3382 logH
+ 2.1454
E - 1.026H-°-233
E - O.BllH"0-"!
0.3
0.3
E - 0.17455H-0.23522
Best available tech-
nology or
0.1 Ib/MM Btu
E • 1.584H-0.5
See attached aheet
E - 1.09H-5-"9«
0.6
E - 0.8425H-0-2314
Sea attached aheet
E - 1.38H-0.44 Claas 1
E - 3.109H-°-589 ciaaa 2
E - 0.963H-0-2356
See attached aheet
E • 2.16H-0.5566
Ambient concentration*
may not exceed
75 Mg/m3 above
background
0.6
See attached aheet
0.3
E - 1.02H-0-769
E - 0.5H-0.26
logE » 0.23 logH -2.0111
See attached sheet
E - 1.02H-0.2131
E - 0.96135H-°'23"1
Minimum 857. control
See attached sheet
10 Ib/hr or 0.1 grain/scf
generally, however each
county has separate
regulations
0.1 grain/scf
0.1 grain/scf
0.1 grain/scf
None for coal and oil
Nots
E • Ib/MM Btu.
H - MM Btu/hr haat input.
98
-------
Table 21. STATE S09 REGULATIONS, Ih/MM Btu FOR COAL-FIRED BOILERS
State
Conn.
Maine
Mas*.
N.H.
R.I.
Vt.
N.J.
N.Y.
Fa.
111.
Ind.
Mich.
Ohio
Ula.
Iowa
Kane.
Minn.
Mo.
Nebr.
N. Dak.
S. Oak.
Del.
D.C.
Fla.
Ga.
Md.
N.C.
S.C.
Va.
W. Va.
Ala.
Ky.
Miss.
Tenn.
Ark.
La.
Okla.
Tex.
Ariz.
Colo.
Iddho
Mont .
Nev.
N. Hex.
Utah
Wyo.
Calif.
Oreg.
WJ3h.
Alaska
Hawaii
Existing
0.55
< 2.5% S
0.55
1.5
< 0.55
2% S
2.0
2.8
3.0 for below 50 MM Btu/hr
and E - S.llT0-!* for
> 50 MM Btu/hr
6.0
See attached sheet
8.2
3.2
1.5% S
6.0
No regulation below
. 250 MM Btu/hr
2% S
2000 ppm S02
2.51 S
3.0
3.0
1% S
0.57. S
Latest available control
technology or 6.17 for
solid fuel
2.57. S below 200 MM Btu/hr
and 37. for greater than
200 MM Btu/hr
Low aulfur
2.3
3.5
2.64
3.2
4.0
E - 9.464JT0-37*0
2.4
4.0
< 0.2 ppm ambient (assuming
no control)
Meet ambient regulations
(assuming no control)
Meet ambient regulation*
3.0
1.0
< 500 ppm S02
< 1.07. S
< 1
0.7
No regulations
17. S
No regulations
200 Ib hr or 0.2% by volume,
or 1000 ppm, or 0.57. S
17. 3 below 150 MM Btu/hr,
1.6 above 150 MM Btu/hr
2000 ppra
500 ppm
< 2% S
New
0.55
< 2.5Z S
0.28
1.5
i 0.55
27. S
1.5
2.8
1.0 and E - 1.7H"0'1*
respectively
1.8
See attached sheet
2.4
1.0
1.53! S
5.0
No regulation below
250 MM Btu/hr
1.5% S
500 ppm SOj
2.5% S
3.0
3.0
1% S
0.57. S
Latest available control
technology or 6.17 for
solid fuel
1.2Z S
Low sulfur
1.6
2.3
1.06
1.6
1.8
E - 9.46H"0-3740
2.4
1.6
< 0.2 ppm ambient (assuming
no control)
Meet ambient regulations
(assuming no control)
0.2
3.0
0.8
< 500 ppm 502
< 1.07. S
< 1
0.7
No regulations
17. S
No regulations
200 Ib/hr or 0.27. by volume
or 1000 ppm, or 0.57. S
17. S below 150 MM Btu/hr,
1.6 above 150 MM Btu/hr
1000 ppm
500 ppm
< 27. S
Mule: L - Ib/MM BLu.
11 - MM Bcu/hr heat Input.
99
-------
Table 22. STATE SO REGULATIONS, Ib/MM Btu FOR OIL- AND GAS-FIRED BOILERS
2
State
Cotm.
Maine
Mass.
N.H.
R.I.
Vt.
N.J.
N.Y.
Pa.
111.
Ind.
Mich.
Ohio
Wl8.
Iowa
leans.
Minn.
Mo.
Nebr.
N. Oak.
S. Dak.
Del.
D.C.
Fla.
Go.
Md.
N.C.
S.C.
Va.
W. Va.
Ala.
Ky.
Mies.
Term.
Ark.
La.
Okla.
Tex.
Ariz.
Colo.
Idaho
Mont.
Nev.
N. Hex.
Utah
Wyo.
Calif.
Oreg.
Wdsh.
Alaska
Hawaii
Existing
0.55
< 2.5% S
0.55
1.5
< 0.55
2% S
2.0
2.8
3.0 for below 50 MM Btu/hr
and E - 5.1H-0-14 for
> 50 MM btu/hr
1.0 for residual oil and
0.3 for distillate oil
See attached sheet
2.2
3.2
1.0% for realdual oil and
0.7% for distillate oil
2.5
No regulations
1.75
2000 ppm S02
2.5
3.0
3.0
1.0% S
0.5% S
Latest technology or 2.75
2.5% below 100 MM Btu/hr
and 3.0% for greater than
100 MM Btu/hr
Low sulfur
2.3
3.5
2.64
3.1
4.0
E - 5.6484H"0-354
2.4
4.0
< 0.2 ppm SC>2 ambient
(assume no control)
2000 ppm S02
0.8 for oil and 0.2 for gas
2.2
500 ppm SC>2
1.75% S for residual oil and
0.5% S for distillate oil
1.0 for oil and
5 grains/100 ft3 for gas
0.7
0.34
1.5% S
200 Ib/hr or 0.2% by volume
or 1000 ppm, or 0.5% S
1.75% S for realdual oil and
0.5% S for distillate oil
2000 ppm S02
500 ppm S02
No regulations
New
0.55
< 2.5% S
0.28
1.5
< 0.55
2% S
1.5
2.8 Q ,,
1.0 and E - 1.7H u>1*
respectively
1.0 for residual oil and
0.3 for distillate oil
See attached sheet
1.7
1.0
1.0% for residual oil and
0.7% for distillate oil
2.5
No regulations
1.75
500 ppm S02
2.5
3.0
3.0
0.3% S
0.5% S
Latest technology or 2.75
2.5% below 100 MM Btu/hr
and 3.0% for greater than
100 MM Btu/hr
Low sulfur
1.6
2.3
1.06
1.6
1.8
E - 5.6484H-0-354
2.4
1.6
< 0.2 ppm S02 ambient
(assume no control)
2000 ppm S02
0.8 for oil and 0.2 for gas
0.8
500 ppm SO,
1.75% S for residual oil and
0.5% S for distillate oil
1.0 for oil and
5 grains/100 ft3 for gas
0.7
0.34
1.5% S
200 Ib/hr or 0.2% by volume
or 1000 ppm, or 0.5% S
1.75% S for residual oil and
0.5% S for distillate oil
1000 ppm S02
500 ppm SO,
No regulations
Note : L - 11) /MM Btu.
H - MM Btu/hr heat input.
100
-------
Table 23. STATE NO (AS N0?) REGULATIONS, Ib/MM Btu
FOR COAL-FIRED BOILERS
State
Existing
New
Conn.
Maine
Ma a 8.
N.H.
R.I.
Vt.
N.J.
N.Y.
Pa.
111.
Ind.
Mich.
Ohio
Wla
Via.
Iowa
Kans.
Minn.
Mo.
Nebr.
N. Oak.
S. Dak.
Del.
D.C.
Fla.
Ga.
Md.
N.C.
S.C.
Va.
W. Va.
Ala.
Ky.
Miss.
Term.
Ark.
La.
Okla.
Tex.
Ariz.
Colo.
Idaho
Mont.
Nev.
N. Mex.
Utah
Wyo.
Cdllf.
Oreg.
Wash.
Alaska
Hawaii
0.9
No regulations
250 ppm maximum atack
concentration
No regulations
No regulation*
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
Best current technology
(assuming no control)
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations'
No regulations
0.7 for units greater than
100 MM Btu/hr
Latest control technology
(assuming no control)
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
140 pounds per hour
maximum
No regulations
No regulations
Requires permit If greater
than 100 tons/year
(assuming no control)
No regulations
0.7
No regulations
250 ppm maximum stack
concentration
No regulations
No regulations
0.3
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
Best current technology
(assuming no control)
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
0.7 for unltu greater than
100 MM Btu/hr
Latest control technology
(assuming no control)
0.7
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
0.7 for units greater than 50 MM Btu/hr
No regulations
0.7
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
140 pounds per hour
maximum
No regulations
No regulations
Requires permit If greater
than 100 tons/year
(assuming no control)
No regulations
NlllL
Ib/MJl Btu.
MM Btu/hr heat Input.
101
-------
Table 24. STATE NO (AS N02) REGULATIONS, Ib/MM Btu
FOR OIL-XAND GAS-FIRED BOILERS
State
Conn.
Maine
Mass.
N.H.
R.I.
Vc.
N.J.
N.Y.
Pa.
111.
Ind.
Mich.
Ohio
Wla.
Iowa
Kanti.
Minn.
Mo.
Nebr.
N. Dak.
S. Dak.
Del.
D.C.
Fla.
Ga.
Md.
N.C.
S.C.
Va.
W. Va.
Ala.
Ky.
Mlsa.
Term.
Ark.
La.
Okla.
Ttfx.
Ariz.
Colo.
Uaho
Mont.
Nev.
N. Mex.
Utah
Wyo.
Oillf .
Orcg.
Wjsh.
Aid ukd
ll.lW.lll
Existing
0.2 for gas and 0.3 for
oil
No regulations
No regulations
No regulations
0.2 for gas and 0.3 for
oil for units greater
than 100 MM Btu/hr
No regulations
0.2 for gas and 0.3 for
oil
No regulations
No regulations
No regulations
No regulations
No regulations
0.2 for gas and 0.3 for
oil
No regulations
No regulu tlons
No regulations
No regulations
No regulations
No regulations
No regulations
0.2 for gas and 0.3 for
oil
No regulations
0.2 for gas and 0.3 for
oil
Latest control technology
(assuming no control)
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
0.3
No regulations
0.23 for gas and 0.6 for
oil
140 Ib/hr maximum
No regulations
No regulations
No regulat Ions
No regulations
New
0.2 for gas and 0.3 for
oil
No regulations
No regulations
No regulations
0.2 for gas and 0.3 for
oil for units greater
than 100 MM Btu/hr
No regulations
0.2 for gas and 0.3 for
oil
No regulations
No regulations
No regulations
No regulations
No regulations
0.2 for gas and 0.3 for
oil
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
0.2 for gas and 0.3 for
oil
No regulations
0.2 for gas and 0.3 for
oil
Latest control technology
(assuming no control)
0.2 for gas and 0.3 for oil
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
No regulations
0.2 for gas and 0.3 for oil for units » 50 MM BTU/lir
0.5
0.2 for gas and 0.3 for oil
No regulations
No regulations
No regulations
No regulations
0.2 for gas
No regulations
0.2 for gas and 0.3 for
oil
140 Ib/hr maximum
No regulations
No regulations
No regulations
No regulations
Note: L - Ib/MM Liu.
H - MM liLu/hr lieut Input.
102
-------
Q.
- 10 r-
3
£
oc
u
Q.
Ul
o
K
(0
CO
I
UJ
bJ
O.I
a:
S!
0.01
to
OR LESS
i i i i 11
i i i
100
1000
EQUIPMENT CAPACITY RATING, !06Btu/hr INPUT
10,000
OR MORE
Figure 20. Particulate regulations for Maine
103
-------
Table 25. PARTICULATE REGULATIONS FOR MARYLAND
Emission Standards and Dust Collector
Performance Standards for Fuel Burning Installations
Installation description
Residual oil burning; all
installations up to 200
million BTU per hour heat
input
Residual oil burning ;
existing and modified
installations
Residual oil burning;
new fuel burning
equipment
Distillate oil burning;
all installations
Solid fuel burning; all
installations
Max. rated heat Effective
input in million date of
BTU per hour Standard
per furnace
Less than 10 (d)
Less than 10
10-50
10-50
51 - 200
51 - 200
Greater than
200
Greater than
200
All sizes
200 or less
Greater than
200
Jan. 4, 1971
Oct. 1, 1973
Jan. 4, 1971
Oct. 1, 1972
Jan. 4, 1971
Oct. 1, 1972
Jan. 4, 1971
Jan. 4, 1971
Oct. 1, 1971
Oct. 1, 1972
Oct. 1, 1972
Oct. 1, 1972
Maximum allow- Maximum allow-
able emission able emission ;
of particulate Shell-Bacharach
matter smoke spot test
gr/SCFD number (b)
No reqm't
0.03
No reqm't.
0.025
No reqm't.
0.02
0.02
0.01
No reqm't
No reqm't.
0.05
0.03
6
4
6
4
6
4
4
4
3
2
No reqm't
No reqm't
(a) Relates to subsection .03B.
(b) The method used for measurement of both residual and distillate oil burning equipment shall
with method D-2156 published by the American Society for Testing and Materials.
(c) Collection efficiencies for residual oil burning units determined assuming a minimum inlet
0.06 gr/SCFD.
(d) Construction of Residual oil fired units of less than 5 million BTU/hr. prohibited after Jan.
Required collec-
tion efficiency
of dust
collector (c)
No reqm't.
50% or more
No reqm't
60% or more
No reqm't
70% or more
70% or more
80% or more
No reqm't
No reqm't
90% or more
99% or more
be in accordance
grain loading of
4, 1971 (See par.
-------
T—I I I III I | 1 1 II III I | 1 1 III III | 1 1 I I MM | 1 I II III I
o
Ul
<
til
c
o
\
i
-------
Z
1-0
0.8
H ° 6
2 0.5
x
3 0.4
m
O c
0.3
5 | 0.25
^
s £ 0.20
I
x 0.15
0.10
-i—r i run]—i—i i 11 n r| 1 i i i iui| 1—rrrrn
MAXIMUM EMISSION OF PARTICULATE MATTER
FROM EXISTING FUEL BURNING INSTALLATIONS
I 1 I I I I I 111 I 1 I I I Illl I I I I I I 1111
10 100 1000 10,000
TOTAL INPUT, millions OF Btu/hr
i 1—i i 11II l| 1—i I I ini|
MAXIMUM EMISSION OF PARTICULATE MATTER
FROM NEW FUEL BURNING INSTALLATIONS ~l
0.10
10 100 1000 10,000
TOTAL INPUT, millions OF Btu/hr
Figure 22. Particulate regulations for Montana
106
-------
Table 26. PARTICULATE REGULATIONS FOR NEW HAMPSHIRE
Maximum allowable emissions of
particulate matter in pounds per
million British thermal units
neat input in million
British thermal units,
per hour
Up to and including 10
50
100
500
1000
2500
5000
7500
10,000 and above
Existing fuel
burning equipment
0.60
0.46
0.40
0.31
0.28
0.24
0.22
0.20
0.19
New fuel
burning equipment
0.60
0.40
0.35
0.10
0.10
0.10
0.10
0.10
0.10
Table 27. PARTICULATE REGULATIONS FOR NEW JERSEY
Heat input rate,
millions of
British thermal
units per hour
1
10
20
30
40
50
60
70
80
90
100
120
140
160
180
Max imum
allowable
emission rate,
pounds per hour
00.6
06
08
09
10
11
12
13
14
14.5
15
16.5
17.5
18.5
19.3
Heat input rate,
millions of
British thermal
units per hour
200
400
600
800
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
10,000
Max imum
allowable
emission rate,
pounds per hour
20
40
60
80
100
200
300
400
500
600
700
800
1,000
NOTE; Heating input rate shall be the sum of the heat input rates of all
fuel burning equipment discharging through a single stack or chimney
107
-------
D
EH
VD
O
3
1.0
0.8
0.6
0.5
0.4
0.3
to
w
w
l-q
1
s
.2
0.1
0.08
0.07
0.06
0.05
10
10'
10-
10'
EQUIPMENT CAPACITY RATING, 106 BTU/HR
Figure 23. Particulate regulations for Oklahoma
108
-------
I I I I I IT
3
*•
OD
Z
o
0.5
I I I I I 1111
I II I I I I I l_
0.2
-------
Table 28. PARTICULATE REGULATIONS FOR WEST VIRGINIA
Table for Type 'e1 Units
Total
Type
Design Heat Input for all
'e1 Fuel Burning Units
Located at One Plant in Millions
of B.
T . U . ' s Per Hour
10
20
40
60
80
100
200
400
600
3,333
Total Allowable Particulate
Matter Emission Rate for
All Type 'e' Fuel Burning
Units Located on One Plant
in Pounds Per Hour
3.4
5.6
9.0
11.7
14.4
16.6
26.4
42.2
54.0
300.0
'• I"—II "I III I . ,1 I .,11
TOTAL INPUT, millions OF Btu/hr
10,000
100,000
Figure 25. Particulate regulations for Wyoming
110
-------
I
to" ~
Is
to ui
to T
UJ ^
m
UJ -,•
o =
< K
UJ
^ O
x. to
2
UJ
O.I
1
1 1 — 1 Mil
1
1 1 1 1
1
| 1 |
1
1 - 1 1
I M
ALLOWABLE SULFUR DIOXIDE FOR FUEL BURNING OPERATIONS
INCLUDES DIRECT FIRED PROCESS OPERATIONS
1 1 1 II L
1 1 1 M
| _ I I I I I 1
I 1 1 1 1 1 1 l
M='-2QM
1 1 1 1 1 1
1 _ 1 1 1 1
10,000
to
to
to
UJ
1000 uj
I
< to
_ j*
a.
UJ
10
I 10 100 IOOO 10,000 100,000
QM, TOTAL PLANT EQUIPMENT CAPACITY RATING, MILLIONS OF Btu FUEL INPUT/hr
Figure 26. Sulfur dioxide regulations for Indiana
-------
SECTION V
ESTIMATED EMISSION REDUCTIONS
INTRODUCTION
The purpose of this screening study is to determine the effect of New
Source Performance Standards which could be applied to emissions of
particulates, sulfur dioxide, nitrogen oxides, hydrocarbons and carbon
monoxide upon boilers between 2.5 and 63 million Kcal/hr (10 and 250
million Btu/hr) input. The appraisal of these proposed standards is to
be determined by the use of a model developed by TRC, called Model IV.
In order to use Model IV it is necessary to determine parameters con-
cerning three major areas: (1) installed capacity of boilers and their
utilization rate by state; (2) the annual production of boilers including
the portion representing replacement and additional capacity; (3) the
emission rates of these boilers under existing state regulations. These
emission rates are expressed in two ways, those with no controls, and
those which are based on utilizing the best available control technology
in the year 1985.
Utilizing parameters derived from the above-mentioned information, Model
IV calculations may be performed to determine four emissions estimates
for each pollutant of interest. In this specific case of boilers between
2.5 and 63 million Kcal/hr (10 to 250 million Btu/hr) input, emissions
estimates have been derived for three categories of boilers representing
various fuels and firing mechanisms. This more detailed analysis was
necessary because there exists a considerable diversity in types of
boilers and the emission rates can vary significantly depending on
the type of boiler and the fuel it uses.
112
-------
MODEL IV - BACKGROUND INFORMATION
The additional control potential of new or revised standards of per-
formance stems from the application of emission standards that are more
stringent than those presently applied to construction and modification.
This potential, for a specified time period, is expressed as:
-------
B = production capacity from construction and modification to
replace obsolete facilities (production units/yr)
C = production capacity from construction and modification to
increase output above baseline year capacity (production
units/yr)
p = construction and modification rate to replace obsolete capacity
(decimal fraction of baseline capacity/yr)
P = construction and modification rate to increase industry capa-
city (decimal fraction of baseline capacity/yr)
E = allowable emissions under existing regulations (mass/unit
capacity)
EN = allowable emissions under standards of performance (mass/unit
capacity)
£„ = emissions with no control (mass/unit capacity)
For the purpose of this study, the i year is defined as 1985 and the
jth year, 1975.
Assuming that capacity lost due to obsolescence is replaced by construc-
tion and modification, then:
Ts = Es K (A - B) + Eg K (B + C) (1)
and
TN = Es K (A - B) + Ej, K (B + C) (2)
Ts - TN = K (B + C) (Eg - EN) (3)
If simple growth is assumed, values of B and C are determined as follows:
114
-------
B = AiPB (4)
C = AiPc (5)
where i = elapsed time, years
In addition, the following values may be calculated:
TA = ESKA (6)
Tn = EjjK (A - B) + EyK (B + C) (7)
Further refinement of the Model may be realized for cases where Ec for
O
new and existing plants differ. In this case,
Tg = KEg (A - B) + KEg (B + C) (8)
where E = Eg for existing plants
E = E for new plants.
On O
Therefore,
Tg - TN = K (B + C) (Eg - EN) (9)
In this report, all data concerning the installed capacity of boilers and
fuel consumption is for 1974 and the data for annual sales is for 1975.
To determine the value of A for 1975, it was only necessary to add the
annual production capacity of 1975 (B + C), to the 1974 installed
capacity.
115
-------
The data and emission factors related to the heat content of the fuel
2
were calculated utilizing the following conversion factors:
Fuel Conversion factor
Residual oil - 147,000 Btu/gal, 7.88 Ib/gal
Distillate oil - 140,000 Btu/gal, 7.05 Ib/gal
3
Natural gas - 1,022 Btu/ft
INSTALLED BOILER CAPACITY AND FUEL CONSUMPTION
To determine the total installed boiler capacity and annual firing rate
for the U.S. and for each individual state of boilers between 2.5 and
63 MM Kcal/hr (10 and 250 MM Btu/hr) input, we relied primarily on two
data sources.
First, for total installed capacity by boiler type for the U.S. the
report by Battelle-Columbus Laboratories titled, "Evaluation of National
Boiler Inventory"^ was utilized. Data from this source indicated the
total installed U.S. boiler population for three use categories, 15 size
ranges, and three fuel types. A plot of boiler capacity versus size on
log-probability paper displayed the size distribution of boilers for
the various fuel and use categories for which the data are available.
In every case the distribution is essentially a straight line, indicating
a log-normal distribution. From these curves (Figures 27 through 35),
one can determine the percentage of boilers between 2.5 and 63 MM Kcal/hr
(10 and 250 MM Btu/hr) input for each fuel and use category.
Tables 29 through 31 summarize the installed capacity of utility, in-
dustrial and commercial/institutional boilers using oil and gas in the
size range.
116
-------
10
10
ffi
t" ,o<
O
O.
O
(T
UJ
_J
O
o
10'
10
0.01 O.I I 10 50 90 95
PERCENT LESS THAN STATED SIZE
99.9
Figure 27. Residual oil, (utility) design firing rate versus
% < stated size
117
-------
0.01 O.I I 10 50 90 95
PERCENT LESS THAN STATED SIZE
99.9
Figure 28. Distillate oil, (utility) design firing rate versus
% < stated size
118
-------
10
10
CD
£ 10"
o
Q.
O
IE
UJ
_J
O
m
10'
10
i I
0.01 O.I I 10 50 90 95
PERCENT LESS THAN STATED SIZE
99.9
Figure 29. Natural gas, (utility) design firing rate versus
% < stated size
119
-------
10
10
m
t" ,0
O
<
Q.
<
0
-------
10
10
10'
t ,0°
u
<
a.
<
u
5
ae
ui
_j
o
CD
10'
10
94- 50s 44%
J L
_L
_L
J_
J_
0.01 O.I I 10 50 90 95
PERCENT LESS THAN STATED SIZE
99.9
Figure 31. Distillate oil, (industrial) design firing rate versus
% < stated size
121
-------
10
10
m
>
i-
o
0.
ac.
UJ
_i
5
CD
10'
20%
70°/c
10
70 - 20 r 50 %
0.01 O.I I 10 50 90 95
PERCENT LESS THAN STATED SIZE
99.9
Figure 32. Natural gas, (industrial) design firing rate versus
% < stated size
122
-------
10
10
ffi
>-
o
0.
o
Ul
O
m
10'
10
I I
97%
64°/<
97-64i 33%
0.01 O.I I 10 50 90 95
PERCENT LESS THAN STATED SIZE
99.9
Figure 33. Distillate oil, (commercial) design firing rate versus
% < stated size
123
-------
10
10
10'
t 10"
o
8
a
<
o
UJ
_l
5
0
28%
95%
10'
95-28 = 67%
10
0.01 O.I I 10 50 90 95
PERCENT LESS THAN STATED SIZE
99.9
Figure 34. Residual oil, (commercial) design firing rate versus
% < stated size
124
-------
10
10.
CD
>-
o
a.
o
ae
o
m
10'
77- 38*39%
10
0.01 O.I I 10 50 90 95
PERCENT LESS THAN STATED SIZE
99.9
Figure 35. Natural gas, (commercial) design firing rate versus
% < stated size
125
-------
Table 29. INSTALLED CAPACITY OF OIL AND GAS UTILITY BOILERS BETWEEN
10 AND 250 MILLION Btu/hr INPUT IN THE U.S.
Fuel and boiler
type
Distillate oil
Residual oil
Natural gas
Percentage of installed
capacity
6.9
39.3
53.8
Installed capacity,
x 1012 Btu/hr
83
470
643
Table 30. INSTALLED CAPACITY OF OIL AND GAS INDUSTRIAL BOILERS BETWEEN
10 AND 250 MILLION Btu/hr INPUT IN THE U.S.
Fuel and boiler
type
Distillate oil
Residual oil
Natural gas
Percentage of installed
capacity
8.0
46.5
45.5
Installed capacity,
x 1012 Btu/yr
961
5,610
5,483
Table 31. INSTALLED CAPACITY OF COMMERCIAL/INSTITUTIONAL BOILERS
BETWEEN 10 AND 250 MILLION Btu/hr INPUT IN THE U.S.
Fuel and boiler
type
Distillate oil
Residual oil
Natural gas
Percentage of installed
capacity
17.8
58.9
23.3
Installed capacity,
x 1012 Btu/yr
467
1,542
610
126
-------
The second step in the determination of the annual firing rate of the
aforementioned boilers was to determine the fuel consumption of these
boilers. This was accomplished by utilizing data from a GCA report
titled "Preliminary Emissions Assessment of Conventional Stationary
2
Combustion Systems," Volume II, Final Report. The data found in
Tables 152, 153, and 154 of that report (with minor modifications to
delete any nonboiler fuel consumption) indicate the fuel consumed by all
commercial, industrial, and utility boilers in the U.S. by state, and
fuel type for 1974. Assuming that the boilers between 2.5 and 63 MM
Kcal/hr (10 to 250 MM Btu/hr) capacity consume fuel proportional to
their percentage of capacity, we determined the amount of fuel utilized
by each by taking the percentage of capacity from the boiler distribu-
tion curves times the state fraction of annual U.S. fuel consumption
given in Tables D-10, D-ll, and D-12 of Appendix D.
To calculate the boiler capacity by state, we assumed that the annual
average load factor and the boiler size distribution are the same for
each state as for the U.S. This assumption is necessary to keep the
calculations from becoming too unwieldy. Utilizing this approach we
derived Tables D-13, D-14, and D-15 of Appendix D which indicate the
installed capacity, fuel firing rate, and the fuel consumption for each
boiler and fuel type by state. The type of firing utilized for these
boilers was assumed to be the same as indicated in Tables 12, 88, and
115 of the GCA report
duced in Appendix D.)
2
115 of the GCA report previously mentioned. (These tables are repro-
The data in Tables D-13, D-14, and D-15 of Appendix D were consolidated
in Table D-16 of Appendix D to indicate the installed capacity; firing
rate, and fuel consumption by state for all boilers between 2.5 and 63
MM Kcal/hr (10 million and 250 million Btu/hr) input capacity.
The approach for estimating boiler capacity and firing rate by combining
the Battelle data and Bureau of Mines data results in a more reliable
estimate of installed boiler capacity in our size range than had only
127
-------
only the Battelle data been used. We consider the Bureau of Mines data
a reliable source of fuel consumption, and as boiler sizes tend to follow
a log-normal distribution, the combination of the fuel consumption and
size distribution is easily managed. This is the lower size range which
appears in the NEDS data. Battelle relied heavily on NEDS data to get
their boiler capacity data, but the size range of interest here is the
least reliable NEDS data because it includes the lower limit of NEDS
coverage and it involves many more individual boilers than with the
larger units. NEDS data for smaller boilers is dubious because records
of small boiler operation tend to be less complete than for larger
boilers for a number of reasons, some of which include less stringent
government reporting requirements and a lack of adequate technical per-
sonnel in the small companies to operate these small units.
EMISSION FACTORS
The data utilized to draw the boiler size distribution curves for the
utility, industrial, and commercial sectors were consolidated and new
boiler size distribution curves were drawn. These new curves (Figures
D-l, D-2, and D-3 of Appendix D) are approximately log-normal distri-
butions, and were used to determine weighted average emission factors
for states with emission regulations which take into account boiler
capacity. For example, the State of Colorado's particulate emission
limitation for boilers below 63 million Kcal/hr (250 million Btu/hr)
input is determined using the equation:
E = 0.5 Q-°'26 (10)
where E = allowable emissions in pounds per million Btu input.
Q = rated capacity of the boiler in million Btu per hour.
From the boiler size distribution for residual oil-fired boilers in
Figure D-l of Appendix D, we used the median boiler size, 25 MM Kcal/hr
128
-------
(100 million Btu/hr) as representing the average of the 2.5 to 63 MM Kcal/
hr (10 million to 250 million Btu/hr) size range. Solving the equation:
E = 0.5 Q-°'26 (11)
= 0.5 (100)-°'26
= 0.5 (0.302)
E = 0.151 lb/106 Btu
For residual oil of 8.25 x 106 Kcal/103 kg (36.0 x 106 Btu/ton), the
emission rate E', in Ib/tons, meeting the calculated allowable emission
factor, is simply the product of the emission factor in lb/10 Btu and
the heat content of the coal in Btu/tons or:
E1 = (0.151 lb/106 Btu) (36.0 x 106 Btu/ton) (12)
E1 = 5.44 Ib/tons
All of the emission factors for each state were calculated in this
manner, unless their state regulation did not account for boiler size.
State emission regulations which were given in units of concentration
limits, such as 500 ppm S02 at 12 percent C02 or 0.229 g/NM3 grain per
dry standard cubic foot) at 12 percent C02, were converted utilizing
conventional fuel stoichiometry to an emission factor in pounds per unit
of fuel consumption. Similar conversions were performed on all state
regulations where necessary to make them compatible with the emission
factors given in AP-42. For example, state regulations for S02 given
in pounds per million Btu were converted to their equivalent percentage
of sulfur content for each fuel, and then used in conjunction with the
AP-42 emission factor to yield an emission factor in pounds per unit of
fuel consumption.
129
-------
Uncontrolled emissions were taken from the NEDS emission factors given
in AP-42.4 Sulfur contents of the oils for determining uncontrolled
emissions were taken from a survey report done by the Bureau of Mines.
For the oil- and gas-fired boilers we used a weighted average factor for
nitrogen oxides (NCL) emissions from the Industrial Sources section of
AP-42, assuming that the firing patterns are distributed as in Table 88
of Reference 2. The overall emission factors for the U.S. were determined
by utilizing both a weighted average of the individual state emission
factors and a weighting factor of each state's fuel consumption.
These exercises are provided in Tables D-17 through D-19 of Appendix D,
which contain the annual fuel consumption, uncontrolled emission factors,
and emission factors representing compliance with state regulations, and
the weighted average of these factors for the U.S. total. The emission
factor representing the use of best available control technology will be
simply the uncontrolled emission factor multiplied by Vnri
Table D-19 of Appendix D for natural gas does not contain any factors for
emissions meeting state regulations for particulate and sulfur dioxide
since the uncontrolled emissions are low enough so as not to require
regulation; consequently, the uncontrolled emissions are substantially
less than state regulations. A similar situation occurs with distillate
oils, where the uncontrolled emissions are often less than the state
regulation allows. For distillate oils, however, we did use the higher
state regulations limits because it is conceivable that lower grade oils
could be substituted for distillate oils currently in use; thus, in-
creasing emissions to the limit allowed by state regulations.
All of the preceding discussion has been aimed at obtaining the first
parameters required to do the Model IV calculations - the emission
factors. The first emission factor, Eg, "allowable emissions under
existing regulations," is the weighted average appearing in the "meeting
state regulations" columns of Tables D-17 through D-19 of Appendix D. E ,
"allowable emissions under standards of performance," is simply E
130
-------
multiplied by the efficiency of the best available control technique.
E-j, "emissions with no control," is the weighted average appearing in
the "Uncontrolled" column of Tables D-17 through D-19 of Appendix D.
(It should be noted that these were changed to appropriate units in
order to fit the Model IV format.)
1975 BOILER SALES
3
The capacity of boilers between 4.5 and 114 x 10 kg (10 and 250 thousand
pounds) of steam per hour, approximately 2.5 to 63 x 10 Kcal/hr (10 to
250 x 10 Btu/hr) which were sold in the U.S. was derived from data pro-
vided by the American Boiler Manufacturers Association. The data were
for both water-tube and fire-tube boilers and were estimated to represent
96 percent and 85 percent, respectively, of the U.S. total of these
boilers.
ABMA data indicate that, of the total boiler capacity sold in the U.S.
9 10
in our size range of interest, 8.57 x 10 Kcal/hr (3.4 x 10 Btu/hr)
9 10
are water-tube boilers and 4.05 x 10 Kcal/hr (1.6 x 10 Btu/hr) are
fire-tube boilers. Approximately 39.3 percent of the water-tube boilers
were primarily fired by oil, with 29.4 percent by gas, and 31.3 percent
by solid fuels. The fire-tube boilers were fired 67.3 percent by oil
and 32.7 percent by gas.
Water-tube boilers have an annual replacement rate of about 20 percent.
Fire-tube boilers have a replacement rate of 1/3 of annual capacity.
The oil- and gas-fired boilers replacement rate can be determined by
using a weighted average of the two replacement rates using the capacity
of each boiler type as the weighting factor. Using this approach we
find that 25.45 percent of oil- and gas-fired boilers sold in 1975
represent replacement units.
131
-------
MODEL IV CALCULATIONS
Input Parameters
Because Model IV is not set up specifically for the situation concerning
boilers, their manufacture and emissions, it is necessary to use some lati-
tude in the interpretation of the Model IV input definitions. Model IV
is best suited to a process type of industry where there is a limited num-
ber of plants in the U.S., and where the emissions are directly related
to annual production of the product, and come directly from these manu-
facturing plants themselves. The situation with boilers is quite differ-
ent. Annual production of boilers is only marginally related to annual
emissions from boilers, and the emissions from these boilers are not at
all related to the place where they are produced. Having made this dis-
tinction we can now determine the methodology for determining the values
of the Model IV input parameters.
The factor "K", defined as "normal fractional utilization rate of exist-
ing capacity, assumed constant during time interval" was determined for
each of the three boiler/fuel categories corresponding to Tables D-17
through D-19 of Appendix D. The total fuel consumption (annual firing
rate) was divided by the total installed capacity. For example, for
residual oil-fired boilers, we get the total annual firing rate by
adding the total U.S. annual firing rates for the three categories of
utility, industrial, and commercial/institutional boilers and dividing by
the total U.S. installed capacity for these same three categories, as
follows in Table 32. Firing rates are found by converting the total U.S.
fuel consumption in each category from tons/yr to Btu/yr.
132
-------
Table 32. SAMPLE DATA FOR DETERMINING K FACTOR
Firing rate,
(Btu/yr) x 10
Installed capacity,
(Btu/yr) x 1012
K
Utility
23
105
Industrial
376
2,577
Commercial/
institutional
47
481
Total
446
3,163
0.141
To calculate A, "baseline year production capacity" for each category
of boilers we assumed that new boiler capacity was distributed between
fuel and firing types in the same way that existing capacity is dis-
tributed. Therefore, A is equal to the fractional capacity of installed
residual oil-fired boilers multiplied by the 1975 production of all
oil-fired boiler capacity plus the installed capacity:
. _ /Residual-Oil Installed Capacity \ /
\Total Oil-Fired Installed Capacity) I
+(Residual-Oil Installed Capacity)
1975 Oil-Fired Production\ (13)
Capacity /
= /7.622 x 1015 Btu/yr \ (2.121 x 1014 Btu/yrJ + /7.622 x 1015 Btu/yrJ
X9.113 x 1015 Btu/yr/
.113 x 10
7.799 x 1015 Btu/yr
For the baseline year the value of B, "production capacity from construc-
tion and modification to increase output above baseline year capacity,"
is simply the percentage of 1975 oil-fired production capacity (25.45 per-
cent) which represents replacement units times the portion of 1975 oil-
fired production capacity which represents residual oil-fired capacity:
133
-------
_ . iv^oj-^ui-ij- \jj-j. .1.1.11? i.u..i..i-<-vi vju^tiv-j-t. \ i _ .-. .
\Total Oil-Fired Installed Capacity) j x 0.2545 J
/Residual Oil Installed Capacity \ ,1975 Oil-Fired Productionx
x 0.2545 J
Capacity /
B./7.622 xlO Btu/yr V / m ^ 1Q14 Btu/yr x Q>2545
\ 9.133 x 1015 Btu/yr / \
B = 4.51 x 1013 Btu/yr
The value for the baseline year of C, "production capacity from construc-
tion and modification to increase output above baseline year capacity,"
is 74.55 percent of the 1975 bituminous-stoker production capacity.
Therefore:
C = 0.7455 (1.77 x 1014 Btu/yr) (15)
C = 1.32 x 1014 Btu/yr
The value of PB, "construction and modification rate to replace obsolete
facilities," is simply B during the baseline year divided by A or:
PB = B/A (16)
= 4.51 x 1013 Btu/yr/7.799 x 1015
PB = 0.00578
D
The value of PC, "construction and modification rate to increase industry
capacity," is simply C during the baseline year divided by A or:
PC = P/A (17)
= 1.32 x 1014 Btu/yr/7.799 x 1015 Btu/yr
Pn = 0.01692
134
-------
RESULTS OF MODEL IV CALCULATIONS
Model IV calculations were performed for the three categories of boilers
and fuel-types comprising U.S. boilers between 2.5 and 63 x 10 Kcal/hr
(10 million and 250 million Btu/hr). Values for T. , T , T , T. , and
f\ JN U «.
T., and T - T have been determined for the four pollutants of interest
A o N
(SO , NO , particulates, and CO), for each of the three categories as
X 2£
well as for the sum of these three categories. These results are tabu-
lated in Tables 33 through 36. In order to determine the relative sig-
nificance of the annual emissions calculated from Model IV for each
boiler/fuel category, the percentage annual fuel consumption for each
boiler is tabulated along with the percentage of the total annual emis-
sions from Model IV. In this manner, we can determine the significance
of application of NSPS to each boiler/fuel category. For example, natural
gas-fired boilers account for 49.1 percent of the total annual fuel con-
sumption; yet the imposition of NSPS in this category would have no impact
on particulate, CO, or SO emissions. The application of NSPS for NO ,
x x
however, could result in a significant emission reduction. Residual
oil-fired boilers comprise 27.5 percent of fuel consumption and 61.1
percent of the potential reduction in particulate matter by the use of
fuel consumption and 61.1 percent of the potential reduction in particu-
late matter by the use of NSPS.
The total (T0 - T._) for particulate represents 16.5 percent of Tc; in
o N s
other words, the potential reduction in emissions by application of
NSPS represents 16.5 percent of the total emissions that would result
in 1985 under current state regulations. For S0? and N0» NSPS would
mean a 18.6 percent and 7.6 percent reduction in emissions, respectively.
There is no CO reduction. The S0? reduction calculated using Model IV
is large due to the assumption that many boilers which are currently,
and will in the future be utilizing lower sulfur fuels (e.g., distillate
oil) than is currently required by state regulations, are just meeting
statfe regulations. If we assume that the boilers currently utilizing
lower sulfur oil than required by state regulations will continue to do
135
-------
Table 33. RELATIVE RESULTS OF MODEL IV CALCULATIONS FOR PARTICIPATES
Boiler and fuel type
Residual oil
Distillate oil
Natural gas
Total (2 of columns)
1975 fuel
consumption
percentage
32.58
9.24
58.18
100
1
Ts, 1000
tons/yr
341.3
88.91
20.81
451.02
7. of
total
TS
75.67
19.71
4.62
100
TN, 1000
tons/yr
277.3
78.34
20.81
376.45
7. of
total
73.66
20.81
5.53
100
TA, 1000
tons/yr
288.6
75.2
18.01
381.81
7. of
total
TA
75.59
19.70
4.71
100
TU, 1000
tons/yr
192.0
37.20
20.81
250.01
7. of
total
TU
76.8
14.88
8.32
100
TS-TN
tons/yr
64.0
7. of
total
TS-%
85.83
10.57 ! 14.17
0
74.57
0
100
Table 34. RELATIVE RESULTS OF MODEL IV CALCULATIONS FOR SULFUR DIOXIDE
Boiler and fuel type
Residual oil
Distillate oil
Natural gas
Total (Z of columns)
1975 fuel
consumption
percentage
32.58
9.24
58.18
100
Ts, 1000
tons/yr
2467
598.1
1.256
3066.36
7. of
total
TS
80.45
19.51
0.04
100
TN, 1000
tons/yr
2003
491.2
1.256
2495.46
7. of
total
TN
80.27
19.68
0.050
100
TA, 1000
tons/yr
2086
505.8
1.087
2592.89
7o of
total
TA
80.45
19.51
0.04
100
TU, 1000
tons/yr
2001
75.38
1.256
2077.64
7. of
total
TU
96.31
3.63
0.006
100
TS-TN
tons/yr
464
106.9
0
570.9
7, of
total
VTN
81.28
18.72
0
100
-------
Table 35. RELATIVE RESULTS OF MODEL IV CALCULATIONS FOR NITROGEN DIOXIDE
Boiler and fuel type
Residual oil
Distillate oil
Natural gas
Total (Z of columns)
1975 fuel
consumption
percentage
32.58
9.24
58.18
100
TS, 1000
tons/yr
577.0
173.0
559.7
1309.7
'/, of
total
TS
44.03
13.26
42.71
100
TN, 1000
tons/yr
-550.8
170.0
490.4
1211.2
% of
total
TN
45.48
14.03
40.49
100
TA, 1000
tons/yr
487.8
147.0
484.4
1119.2
7. of
total
TA
43.58
13.14
43.28
100
TU, 1000
tons/yr
615.1
182.4
570.4
1367.9
7, of
total
TU
44.97
3.80
69.3
99.3
TS-TN
tons/yr
26.2
3.80
69.3
99.3
7. of
total
TS-%
26.38
3.83
69.79'
100
Table 36. RELATIVE RESULTS OF MODEL IV CALCULATIONS FOR CARBON MONOXIDE
Boiler and fuel type
Residual oil
Distillate oil
Natural gas
Total (2 of columns)
1975 fuel
consumption
"percentage
32.58
9.24
58.18
100
Ts, 1000
tons/yr
33.83
9.923
35.39
78.693
% of
total
TS
42.42
12.61
44.97
100
TN, 1000
tons/yr
33.83
9.923
35.39
78.693
% of
total
TN
42.42
12.61
44.97
100
TA, 1000
tons/yr
28.22
8.392
30.63
67.242
% of
total
TA
41.97
12.48
45.55
100
Ty, 1000
tons/yr
33.38
9.923
35.39
78.693
7, of
total
TU
42.42
12.61
44.97
100
VTN
tons/yr
0
0
0
0
7= of
total
TS-TN
0
0
0
0
-------
g
so in the future, then the value of T would be 1.83 x 10 kg/yr
(2.017 x 106 tons/yr) instead of 2.79 x 109 kg/yr (3.07 x 106 tons/yr).
8 5
Also, (T -T ) would be reduced to 3.35 x 10 kg/yr (3.685 x 10 tons/yr)
R 5
from 5.19 x 10 kg/yr (5.71 x 10 tons/yr). With current regulations,
however, there are no guarantees that this will be the case.
Table 37 contains the total annual emissions for all of the boilers,
determined by summing the data in Tables 33 through 36. Tables 38
through 41 present an overall summary of the input/output variables of
Model IV for each of the pollutants (particulates, S0_, N09, and CO).
138
-------
Table 37. MODEL IV RESULTS FOR TOTAL OF ALL GAS- AND OIL-FIRED BOILERS
Pollutant
Particulate
Sulfur dioxide
Nitrogen dioxide
Carbon monoxide
Total
Ts
1000 tons/yr
451.02
3066.36
1309.7
78.69
4905.77
T
XN
1000 tons/yr
376.45
2495.46
1211.2
78.69
4161.81
TA
1000 tons/yr
381.81
2592.89
1119.2
67.24
4161.14
T
U
1000 tons/yr
250.01
2077.64
1367.9
78.69
3774.24
T - T
XS N
1000 tons/yr
74.57
570.9
99.3
0
744.77
-------
Table 38. SUMMARY OF INPUT/OUTPUT VARIABLES FOR MODEL IV PARTICIPATE
Boiler/
fuel type
Residual oil
Distillate oil
Natural gas
K
0.266
0.380
0.536
Units
Ib/MM Btu
Ib/MM Btu
Ib/MM Btu
EU
0.1565
0.1071
0.00978
ES
0.2782
0.2560
0.00978
EN
0.0235
0.1071
0.00978
PC PB
0.0169 0.00578
0.0169 0.00578
0.0145 • 0.00496
Industrial capacity
Units/yr
Btu
Btu
Btu
A
1975
7.799xl015
1.546xl015
6.870xl015
B
1985
4.627xl014
9.172xl013
3.485xl014
C
1985
1.425xl015
2.824xl014
1.067xl015
Emissions
TN
277.30
78.34
20.81
TS
341.30 .
88.91
20.81
TA
288.60
75.20
18.01
Impact
1000
TS-TH
1985
64.0
10.57
0
-P-
o
Table 39. SUMMARY OF INPUT/OUTPUT VARIABLES FOR MODEL IV S02
fuel type
Residual oil
Distillate oil
Natural gas
K
0.266
0,380
0.536
Units
Ib/MM Btu
Ib/MM Btu
Ib/MM Btu
EU
1.631
0.2171
0.00059
ES
2.631
1.722
0.00059
EN
0.1631
0.2171
0.00059
PC PB
0.0169 0.00578
0.0169 0.00578
0.0145 . 0.00496
Industrial capacity
Units /yr
Btu
Btu
Btu
1975
7.799xl015
1.546xl015
6.870xl015
1985
4.627xl014
9.172xl013
3.485xl014
1985
1.425xl015
2.824xl014
1.067xl015
Emissions
TN
2003
491.2
1.3
TS
2467
598.1
1.3
TA
2086
505.8
1.1
• Inpact
1000
T
1985
464
106.9
0
-------
Table 40. SUMMARY OF INPUT/OUTPUT VARIABLES FOR MODEL IV N00
fuel type
Residual oil
Distillate oil
Natural gas
K
0.266
0.380
O.S36
Units
Ib/MM Btu
Ib/MM Btu
Ib/MM Btu
%
0.5014
0.525
0.268
KS
0.4703
0,5005
0.2630
%
0.3660
0.4464
0.0804
pc
0.0169
0.0169
0.0145
PB
0.00578
0.00578
0.00496
Industrial capacity
Units/yr
Btu
Btu
Btu
1975
7. 799x1 O15
1.546xl015
6.870xl015
1985
4.627xl014
9.172xl013
3.485X1014
1985
1.425X1015
2.824xl014
1.067xl015
Emissions
TN
550.80
170.0
490.4
TS
577.0
173.8
559.7
TA
487.8
147.0
484.4
Ivp act
1000
tons/yr
TQ-TH
1985
26.2
3.8
69.3
Table 41. SUMMARY OF INPUT/OUTPUT VARIABLES FOR MODEL IV CO
Boiler/
fuel type
Residual oil
Distillate oil
Natural gas
K
0.266
0.380
0.536
Units
Ib/MM Btu
Ib/MM Btu
Ib/MM Btu
BO
0.0272
0.0286
0.01663
ES
0.0272
0.0286
0.01663
%
0.0272
0.0286
0.01663
PC
0.0169
0.0169
0.0145
PB
0.00578
0.00578
0.00496
Onits/yr
Btu
Btu
Btu
Industrial capacity
A
1975
7.799xl015
1.546xl015
6.870xl015
B
1985
4.627xl014
9.172xl013
3.485xl014
c
1985
1.425xl015
2.824xl014
1.067xl015
Eaiiaalons
TN
33.38
9.923
35.39
TS
33.38
9.923
35.39
TA
28.22
8.392
30.63
Impact
1000
tons/yr
Ts-T
1985
0
0
0
-------
REFERENCES
1. Hopper, T.G. and W.A. Marrone. Impact of New Source Performance
Standards on 1985 National Emissions From Stationary Sources.
Prepared by TRC, The Research Corporation of New England,
Wethersfield, Connecticut, for The Emission Standards and Engin-
eering Division, Office of Air Quality Planning and Standards.
Environmental Protection Agency, Research Triangle Park, N.C.
Publication Number TRC Project No. 32391. October 24, 1975.
2. Surprenant, N., R. Hall, S. Slater, T. Susa, M. Sussman, and
C. Young. Preliminary Emissions Assessment of Conventional
Stationary Combustion Systems. Vol. II. Prepared by GCA/
Technology Division, Bedford, Massachusetts, for the U.S. Environ-
mental Protection Agency. Publication Number EPA-600/2-76-046b.
March 1976.
3. Putnam, A.A., E.L. Kropp, and R.E. Barrett. Evaluation of
National Boiler Inventory. Prepared by Battelle-Columbus
Laboratories, Columbus, Ohio, for the U.S. Environmental Protec-
tion Agency, Washington, D.C. Publication No. EPA-600/2-75-067.
October 1975.
4. U.S. Environmental Protection Agency, Research Triangle Park,
N.C. Compilation of Air Pollutant Emission Factors. March 1975.
5. U.S. Department of the Interior, Bureau of Mines, Washington, D.C.
Burner Fuel Oils, 1974. Petroleum Products Survey No. 86.
August 1974.
6. Federal Power Commission, Washington, D.C. Steam-Electric Plant
Air and Water Quality Control Data for the Year Ended December 31,
1972. March 1975.
7. Hamilton, P.A., D.H. White, Jr., and T.K. Matson. The Reserve
Base of U.S. Coals by Sulfur Content. United States Department
of the Interior, Bureau of Mines, Intermountain Field Operation
Center, Denver, Colorado. Information Circular 8693.
142
-------
SECTION VI
MODIFICATION AND RECONSTRUCTION
Modification of existing boilers to increase capacity is extremely rare.*
The capacity of a boiler is determined to a large degree by the amount of
heating surface, which cannot be easily changed, therefore it is not
usually considered feasible to boost the steam generating capacity of
existing boilers. It is possible, however, to increase the amount of hot
gases contacting the heating surface by increasing the boiler's forced
draft fan power and corresponding fuel consumption by changing the burner.
This technique is not generally considered, however, since it causes a
decrease in overall boiler fuel to steam efficiency meaning higher than
otherwise necessary fuel costs. By utilizing this approach, it is pos-
sible to increase the boiler's steam output by as much as 20 percent to
50 percent, depending upon the specific boiler.
The resulting loss in combustion efficiency from such modifications will
result in an overall increase in emissions on a per Btu basis. Generally,
efficient fuel combustion and operating efficiency result in lower emis-
sions. Nitrogen oxides do not necessarily follow this trend, however,
because increased fuel utilization at higher efficiencies results in
high temperatures which lead to increased nitrogen oxide formation.
We were unable to obtain any specific case histories for boilers which
have been modified to increase output.
Modifications of boilers to convert the type of fuel utilized are much
more common than those to increase capacity. Many boilers were converted
143
-------
from coal to oil and gas firing following World War II because of the in-
creased availability of these fuels. Conversion from coal to oil or
natural gas has been widely practiced and the change in emissions from
these boilers is primarily a function of the new fuel rather than the type
of modifications necessary. Existing particulate control equipment designed
for coal fly ash will not be nearly as efficient on the oil fly ash; however
the overall emission rate will almost always be substantially decreased.
Emissions will be governed by the fuel and firing methods, and will be
changed in a straightforward manner.
Conversion from oil- or gas-firing to coal requires major engineering
effort and equipment purchases or modification. Boiler capacity is de-
o
creased by as much as 50 percent because coal requires a larger volume
combustion zone to compensate for its slower burning characteristics. For
these reasons it is unlikely that many changes would occur from oil or gas
to coal. However, the many existing units which were originally designed
to burn coal and have been since converted to gas or oil may be re-
converted to coal-firing without as much effort because they were originally
designed for coal-firing. In these cases, conversion to coal would mean
increased particulate emissions, unless best available control technology
is utilized. Other emissions will depend upon fuel properties and firing
method.
144
-------
REFERENCE
1. Personal Communication with Roy M. Rulseh, Cleaver-Brooks
Division of Aqua-Chem, Milwaukee, Wisconsin. 24 June 1976.
2. Bogot, A. and R. C. Sherrill. Principal Aspects of Converting
Steam Generators Back to Coal Firing. Combustion, p. 10,
March 1976.
145
-------
APPENDIX A
EMISSION DATA
The test data which are most relevant to the emission data discussed in
Sections II and III are presented in those respective chapters. Much of
this data was extracted from the reports listed below. For additional
data on boiler field tests, the reader should obtain these reports.
1. Cato, G. A., L. J. Muzio, and R. E. Hall. Influence of Combustion
Modification on Pollutant Emissions From Industrial Boilers. (Presented
at Symposium on Stationary Source Combustion. Atlanta. September
1975.)
2. Barrett, R. E., S. E. Miller, and D. W. Locklin. Field Investigation
of Emissions From Combustion Equipment for Space Heating. U.S. En-
vironmental Protection Agency. Publication Number EPA-R2-084a (API
Publication Number 4180). June 1973.
3. Cato, G. A., et al. Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions From Industrial Boilers -
Phase I. U.S. Environmental Protection Agency. Publication Number
EPA 650/2-74-078a. October 1974.
4. Combustion Evaluation - Sources and Control Devices. EPA Institute
for Air Pollution Training Manual.
5. Cato, G. A., L. J. Muzio, and D. E. Shore. Field Testing: Application
of Combustion Modifications to Control Pollutant Emissions From
Industrial Boilers - Phase II. U.S. Environmental Protection Agency.
Publication Number EPA 600/2-76-086a. April 1976.
•
6. Choi, P. S. K., et al. S02 Reduction in Non-Utility Combustion
Sources - Technical and Economic Comparison of Alternatives. U.S.
Environmental Protection Agency. Publication Number EPA 600/2-75-073.
October 1975.
7. Weast, T. E., et al. Fine Particulate Emission Inventory and Control
Survey. U.S. Environmental Protection Agency. Publication Number EPA
450/3-74-036. January 1974.
A-l
-------
APPENDIX B
LIST OF CONTACTS
This section contains a list of all individuals or organizations that were
contacted during this study.
B-l
-------
Table B-l. LIST OF CONTACTS
ABCO Industries
633 Walnut St.
Abilene, Texas
(915)677-2011
Mr. Axtman
ABMA
1500 Wilson Blvd.
Rosslyn. N.Y.
(703) 522-7298
Ace Glass, Inc.
1430 N.W. Blvd.
Vineland, N.J. 08360
(609) 642-3333
Mr. Joe Orcino
Ace Tank & Heater Co.
Santa Fe Springs, Calif.
(213) 941-0221
Mr. Bryan Phelan
Air Collection Div, UOP
Tokeneka Road
Darien, Conn. 06820
(203) 655-8711
Mr. I.Ghklany
Air Pollution Control Div.
Michigan Dept. of Natural Res.
Lansing, Michigan
(517) 373-8630
Mr. Louis Mason
Air Pollution Industries, Inc.
95 Cedar Lane
Englewood, N.J. 07631
(201) 871-3855
Mr. Elliot Mabee
American Air Filter Co., Inc.
215 Central Ave.
Louisville, Ken. 40208
(502) 637-0011
Mr. W.B. Hoyt
American Soc, of Mech. Engineers
345 E 47th St.
New York, N.Y
(212) 644-7500
American Standard
Air Quality Div.
Detroit, Mich. 48232
(313) 931-4000
American Van Tongeren Corp.
3435 Livingston Ave.
Columbus, Ohio 43227
(614) 236-5197
AVCO
Lycoma Div.
Williamsport, Penna.
(717) 323-6181
Mr. N.W. Eft
Babcock and Wilson
20 S. Van Buren Ave.
Barberton, Ohio
(216) 753-4511
Mr. David Locklin
Battelle, Inc.
Columbus, Ohio
(614) 424-6424
Mr. Daniel Lislecki
Bellco Pollution Control Co.
P. 0. Box 412
570 W. Mt. Pleasant Ave.
Livingston, N.J. 07039
Mr. Walter Rykowski
Bethlehem Corp.
25th and Lennox Sts.
Easton, Penna.
(215) 258-7111
Mr. D.F. Penning
The Bigelow Co.
New Haven, Conn.
(203) 772-3150
Mr. Bushnell
Boiler Engineering & Supply Co,
Phoenixville, Penna.
(215) 93305832
B-2
-------
Table B-l (continued). LIST OF CONTACTS
Mr. Robert Ellery
Brenton & Hart, Inc.
Cambridge, Mass.
(617) 868-1720
Mr. Don Robinson
Bryan Steam Corp.
P. 0. Box 27
State Road, No. 19 North
Peru, Indiana
(317) 473-6651
Mr. Terry Beckly
Burnham Corp.
Commercial Steel Div.
Lancaster, Penna.
(717) 397-4704
Carborundum Co.
Pollution Control Div.
P. 0. Box 1269
Knoxville, Tenn.
(615) 588-2461
Mr. Millard Prowler
CEA Combustion
P. 0. Box 2039
Stamford, Conn.
(203) 359-1320
C-E Air Preheater
Sub. of Comb. Eng. Inc.
Wellesville,N.Y. 14895
(716) 593-2700
Mr. Robert Muir
Centri-Spray Corp.
Boston, Mass.
(617) 246-1410
Mr. E.L. Weaver
Cleaver Brooks Div.
Aqua-Chem. Corp.
Milwaukee, Wisconsin
(414) 962-0100
Mr. Audolensky
Combustion Eng. and Indus. Boiler Div.
Windsor, Conn.
(203) 688-1911
Mr. Larry Milo
Combustion Engineering, Inc.
75 Federal St.
Boston, Mass.
(617) 426-6650
Continental Air Products, Inc.
1390 Valley Road
Stirling, N.J. 07980
(201) 647-4433
Mr. Don Lythe
Cyclotherm Div.
Oswego Packaged Boiler Co.
Oswego, N.Y.
(315) 343-0660
Dollinger Corp.
Rochester, N.Y. 14603
Ducon Co.
147 E Second St.
Mincola, L.I., NY 11501
(516) 741-6100
Mr. Robert Reese
Dunham-Bush Co.
Harrisonburg, Va.
(703) 434-0711
Dr. Helfritsch
Dustex Div.
Amer. Precision Indus.
2777 Walden Ave.
Buffalo, N.Y. 14225
(716) 685-1200
Mr. Kenneth Freelane
FEA - Industrial Programs
Washington, D.C.
(202) 254-9700
B-3
-------
Table B-l (continued). LIST OF CONTACTS
Mr. Pete Sender
Flex-Kleen Corp.
222 S. Riverside Plaza
Chicago, 111. 60606
(312) 648-5333
Mr. Tom Schroppe
Foster-Wheeler Energy Corp.
Peach Tree Hill Road
Livingston, N.J. 07039
(201) 533-3216
Fuller Co., Dracco Prod.
124 Bridge St.
Catasauque, Penna. 18032
(215) 264-6011
Mr. James Richards
Industrial Combustion, Inc.
Milwaukee, Wis.
(414) 332-4100
Mr. Ed Mordt
International Boiler Works Co.
E. Stroudsberg, Penna.
(717) 421-5100
Mr. T.D. Francis,
Eng. of Combustion Products
Iron Fireman, Dunham Bush
Harrisonburg Div., Va.
(703) 434-0711
Mr. Brook Marstiller
Johnston Boiler Co.
Ferrysburg, Mi.
(616) 842-5050
Mr. G.L. Kasperian, Vice Pres.
Kewanee Boiler Corp.
101 Franklin St.
Kewanee, 111. 61443
(309) 853-3541
Koppers Co., Inc.
Metals Prod. D.iv.
200 Scott St., P. 0. Box 298
Baltimore, Md. 21203
(301) 368-6800
Mr. Glen Cato
KVB, Calif.
(714) 832-9020
A.D. Little, Inc.
Publications Dept.
Cambridge, Mass.
(617) 864-5770
Mahon Industrial Corp.
Sub. of Pullman, Inc.
6045 Dixie Highway
P. 0. Box 611
Saginaw, Mich. 48606
(517) 777-2521
Mr. Redcay
Mass. Bureau of Air Quality Control
Boston, Mass.
(617) 727-2700
Mr. C.F« Onasch
McGraw-Hill
607 Boylston St.
Boston, Mass. 02115
(617) 262-1160
Mr. Robert Frey, Vice Pres.
Nanset Corp.
969-5604
Mr. Harry Kumpula
Nebraska Boiler Mfg. Co., Inc.
Lincoln, Nebraska
(402) 464-7411
Mr. Harold B. Infield,
Chief Boiler Design Engineer
North American Mfg. Co.
4455 E 71st St.
Cleveland, Ohio
(216) 271-6000
Peabody Engineering Corp.
835 Hope St.
Stamford, Conn. 06907
(203) 327-7000
B-4
-------
Table B-l (continued). LIST OF CONTACTS
Pollution Control
Walther, Inc.
1833 S. 27th Ave.
Birmingham, Ala. 35209
(205) 870-8818
Prox Co., Inc.
Terre Haute, Indiana
(812) 232-4324
Reichhold Chem.
Pensacola, Fla.
Mr. Bob Bomp
Research-Cottrell, Inc.
Box 750
Boundbrook, N.J.
(201) 885-7262
Rohm and Haas
Louisville, Ky.
(502) 448-2531
Mr. Horace Rounds
Frank I. Rounds, Inc.
112 Needham St.
Newton Highlands, Mass.
(617) 332-4200
St. Regis Paper Co.
Pensacola, Fla.
Sly Mfg. Co.
4700 Train Ave.,P.O.Box 5939
Cleveland, Ohio
(216) 631-1160
Mr. Doyle
Standard Havens Systems
Air Pollution Control Div.
7219 E. 17th St.
K.C., Miss. 64126
(816) 737-0400
Tailor and Co., Inc.
P. 0. Box 587
Davenport, Iowa 52805
(319) 355-2621
Mr. R. Hanson
Tongren
Mr. Finnigan
Torit Corp.
1133 Rankin St.
St. Paul, Minn. 55116
(612) 698-0391
Mr. John Copeland
U.S. Environmental Protection Agency
Durham, N.C.
(919) 688-8146
U.S. Gypsum Co.
Pittsburg, Penna.
Mr. Billig
Henry Vogt Machine Co.
Louisville, Ky.
(502) 634-9411
Mr. Heridan
U.S. Bureau of Mines
Washington, B.C.
(202) 634-1026
Mr. Wayne Nolan
Weil-McLean Co., Inc.
Michigan City, Ind.
(219) 879-6561
Western Precipitation Div.
Joy Mfg. Co.
P. 0. Box 2744
Terminal Annex
Los Angeles, Calif. 90054
(213) 627-4771
Young Industries, Inc.
Muncy, Penna. 17756
(717) 546-3165
B-5
-------
Table B-l (continued). LIST OF CONTACTS
E. Keeler Co.
238 West St.
Williamsport, Penna.
Riley Stoker
Dover, Delaware
Utah State University
Logan, Utah
Jones and Laughlin Steel Corp.
3 Gateway Center
Pittsburgh, Penna.
Pennsylvania Refining Co.
Karns City, Penna.
Old Fort Paper Co.
Old Fort, N.C.
Howes Leather Co.
Curwensville, Penna.
Hanley Co.
Lewis Run, Penna.
Union Carbide
South Charleston, W.Va.
Municipal Power Plant
Celina, Ohio
Amalgamated Sugar Co.
Paul, Idaho
Firestone Tire & Rubber Co.
Quincy, 111.
01in Chemical Co.
Brandenburg, Kentucky
Air Reduction Co.
Airco Industrial Gases Div.
Mead Co.
Chillicothe, Ohio
International Paper Co.
Mobile, Ala.
Alco
Rockdale, Texas
Mr. Bryan Phelan
Hamilton Paper Co.
Erie, Penna.
General Electric
Appliance Park
Louisville, Kentucky
N.Y. State Electric & Gas Co.
New York, N.Y.
Alton Box Board Co.
Alton, 111.
Mead Paper Co.
Lynchburg, Va.
(804) 847-5521
Union Camp Corp.
Franklin, Va.
(703)562-4111
Mr. Robert R. French, Manager
Air Resources Section
Department of Natural Resources
and Environmental Control
State of Delaware
Dover, Delaware 19901
Mr. James W. Dills
Division of Air Pollution Control
Department for Natural Resources
and Environmental Quality
Commonwealth of Kentucky
Frankfort, Kentucky 40601
Mr. Indur M. Goklany, Engineer
Air Pollution Control Division
Michigan Department of Natural
Resources
Lansing, Michigan 48926
(517) 373-8630
B-6
-------
Table B-l (continued). LIST OF CONTACTS
Mr. Tom C. Allen
North Carolina Department of
Natural & Economic Resources
Box 27687
Raleigh, N.C. 27611
(919) 829-4740
Mr. Douglas L. Lesher, Chief
Permit Section
Division of Abatement &
Compliance
Commonwealth of Pennsylvania
P. 0. Box 2063
Harrisburg, Penna. 17120
Mr. James W. Haynes
Chief Engineering Program
Division of Air Pollution
State of Tennessee
256 Capitol Hill Bldg.
Nashville, Tenn. 37219
Ms. Maggie Carvan
FEA
Boston, Mass.
Mr. Dan Doyle
Field Sales Manager
Standard Havens, Inc.
8800 E. 63rd St.
Kansas City, Missouri 64133
(816) 737-0400
Ms. Abbie Page
Office of Energy Resources
Augusta Maine
(207) 289-2195
Mr. T.C. Schuyler
Marketing Manager
Riley Stoker Corp.
Worcester, Mass. 01613
B-7
-------
APPENDIX C
REPORTS AND CORRESPONDENCE
This section includes copies of all letters written, responses received,
meeting or trip reports and telephone summaries that resulted from this
study.
C-l
-------
SUMMARY OF TELEPHONE CONTACTS WITH BOILER MANUFACTURERS
The following table summarizes our telephone conversations with various
manufacturers concerning possible changes in fuel usage, boiler design,
and boiler sales.
C-2
-------
SUMMARY OF TELEPHONE CONTACTS WITH BOILER MANUFACTURERS
Company
n
I
1. Ace Tank and Heater Co.
Santa Fe Springs, Cal.
213-941-0221
2.
3.
Bethlehem Corporation
Easton, Fa.
215-258-7111
The Bigelow Company
New Haven, Conn.
203-772-3150
4.
5.
6.
7.
Boiler Engineering and
Supply Co.
Phoenixville, Pa.
215-933-5822
Burnham Corporation
Commercial Steel Division
Lancaster, Pa.
717-397-4704
Bryan Steam Corporation
Peru, Indiana
317-473-6651
Cleaver Brooks Division
Aqua Chemical Corp.
Milwaukee, Wisconsin
414-962-0100
Person contacted
Joe Orcino
Sales/Applications
Engineer
Walter Rykowski
Sales Manager
D.E. Penning
Sales/Applications
Engineer
Mr. Bushnell
Sales Engineer
Terry Beckly/
Louis Stanke
Sales Engineers
Jesse McVay
Sales Engineer
Don Robinson
Mfg. Engineer
E.L. Weaver
Date
4/21/76
4/21/76
4/14/76
4/20/76
4/15/76
4/16/76
4/20/76
Comments
Produces three or four 10-25 x 10 Btu/hr
boilers distillate petroleum (mostly), gaa,
or combination; all back and front fired.
Produces 250-300 10-35 x 106 Btu/hr fire-
tube front-back firing boilers. Residual
petroleum, distillate petroleum, gas, or
oil and gas fired.
Produces 10-50 x 10 Btu/hr fire-tube and
10-250 x 10 Btu/hr water tube front-back
fired units. All firing types, including
wood, wet pulverized, and dry pulverized
coal fired 75-250 x 106 Btu/hr units;
Stoker fired overfeed, spreader, and under-
feed 10-250 x 106 Btu/hr. Up to 125 x 10
Btu/hr gas/oil fired or 75 x 10 Btu/hr
coal/solid fired is packaged. Air-fuel
ratio contributes to design to control
emissions. Steam atomized for large units,
pressure for small.
Produces 10-120 x 10 Btu/hr water tube
front-back fired units. Burns all fuel
types and combination. One of the largest
manufacturers of forced flow high tempera-
ture water boilers (up to 250°F) for heat-
ing applications.
Produces 10-30 x 10 Btu/hr fire-tube
front-back boilers. Burns all fuel types.
Burner pressure or air atomized.
Produced 12 combination fueled front-back
fired water tube units in the range
10.6 to 15 x 10 Btu/hr. Can produce gas-
and oil-fired units only.
Produces 10-100 x 106 Btu/hr residual
petroleum, distillate petroleum, gas, and
oil- and gas-fired units. Fire tube 10-30
x 10 Btu/hr. Water, tube 10-100 x 106
Btu/hr. All front-back fired.
-------
SUMMARY OF TELEPHONE CONTACTS WITH BOILER MANUFACTURERS
Company
9.
ID.
r>
11.
12.
13.
Combustion Engineering
Industrial Boilers Division
Windsor, Conn.
203-688-1911
Cyclotherm Division
Oswego Package Boiler Co. Inc.
Oswego, New York
315-343-0660
Sunham-Bush Co.
Harrisburg, Va.
703-434-0711
Babcock and Wilcox, Inc.
Barberton, Ohio/Boston, Mass.
215-258-7111/617-542-6823
Elipse Fuel Engineering Co.
Boiler Division
Chattanooga, Tenn.
615-365-3441
Trane Company
608-782-8000
Person contacted
Mr. Audolensky
Sales Engineer
Don Lytle
Sales Coordinator
Robert Reese
Applications
Engineer
N.W. Eft/Bill
Fidurko
Sales Engineers
Mr. Stevens
Ass't. Chief Engr.
Carl Adams
Sales Engineer
Date
4/20/76
4/20/76
4/21/76
4/27/76
4/21/76
6/15/76
Comments
All fuel types, 10-250 x 10 Btu/hr.
100-250 Btu/hr water tube type, horizontal
front-back fired. Steam atomization.
Liquid and gas packaged; coal and other
solid fuel field erected.
Produces 10-30 x 106 Btu/hr fire-tube type,
residual petroleum, distillate petroleum,
or combination oil and gas fired.
Produces residual petroleum, distillate
petroleum, gas, and combination fueled
10-25 x 106 Btu/hr fire-tube units, front-
back fired. Pressure and air used for
atomization in burner. Also produces fire-
box boilers up to 22 x 10° Btu/hr and
Scotch boilers up to 25 x 106 Btu/hr.
Residual petroleum, distillate petroleum,
gas, and combination water-tube type,
front-back fired 20-250 x 106 Btu/hr units.
Coal water-tube type front-back fired
70-250 x 106 Btu/hr. Wet pulverized, dry
pulverized 150-250 x 106 Btu/hr. Overfeed,
spreader and underfeed stoker fired 70-
250 x 106 Btu/hr. Steam or air atomized.
Coal units field erected. Oil and gas up
to 125-150 x 10 Btu/hr packaged.
Production of 10-28 x 10 Btu/hr units.
12.5 percent each residual and distillate
petroleum and gas fuel; 75 percent gas and
oil. All fire-tube front-back fired.
10-150 x 106 Btu/hr. 98% burn residual
petroleum, distillate petroleum, gas.
Fire-tube range 4 to 25 x 106 Btu/hr; 12
MBtu/hr average. Water-tube range 14 to
250 x 106 Btu/hr; average is 80 x 106
Btu/hr. 2 percent hogged wood. Combina-
tion - 50 percent gas and oil. All front-
back fired. Steam atomization or water
tube. Air or some fire tube. 1974 -
900 water tube units.
-------
SUMMARY OF TELEPHONE CONTACTS WITH BOILER MANUFACTURERS
Company
14. York-Shipley, Inc.
York, Pa.
717-755-1081
15. Zurn Industries
Erie, Pa.
814-452-6421
D
Or
16. H. B. Smith Co., Inc.
Westfield, Mass.
413-562-9631
17. Superior Boilerworks Inc.
Hutchinson, Kansas
316-662-6693
18. Sellers Engineering Co.
Chicago, Illinois
312-561-6900
19. Seattle Boiler Works
Seattle, Washington
206-762-0737
20. E. Keeler Co.
Williamsport, Pa.
717-326-3361
Person contacted
Rob Williams/ Mr.
Petrie
Technical Dept./
Design Engineering
Robert Esser
Production Sales
Mgr.
Stanley Smith
Vice President
Mr. Johnson/
Don Carlson
W.C. Pellaurer
Boiler Sales
Bill Browning
Sales Manager
Robert Lantz
Chief Sales Engr.
Date
4/14/76
4/21/76
4/15/76
4/15/76
4/15/76
it/15/76
4/15/76
4/19/76
Comments
Produces 10-35 x 106 Btu/hr units. 50 per-
cent residual or distillate petroleum, 15
percent gas, 35 percent combination. All
fire-tube front-back fired.
Few 10-75 x 106 Btu/hr. Mostly 75-250 x 106
Btu/hr - 80 percent oil and gas burning.
Water-tube residual/distillate petroleum.
Fire tube for combination. All front-back
fired. Solid fuel - coal, bark, refuse,
bagasse. Some wet pulverized; all types
of stoker. Steam atomization burner. De-
sign features that contribute to emission
control: coal - dust collector, scrubber,
ESP baghouse. Oil - dust collectors.
Gas - nothing.
50 to 100 units. 10-15 x 106 Btu/hr.
Residual petroleum, distillate petroleum,
gas fueled, or combination, cast iron,
front-back fired. Air atomizing burner.
350 10-31 x 10° Btu/hr units. 60 percent
combination fired, 25 percent gas, 15 per-
cent residual or petroleum distillate.
Alt fire-tube, front-back fired.
100 10-20 x 10 Btu/hr fire-tube, front-
back fired units. 40 percent residual or
distillate petroleum; 60 percent gas.
50 (domestic sales) 10-40 x 10 Btu/hr
fire-tube and water-tube, front-back
fired units. 25 percent burns hog fuel,
sawdust; 10 percent gas; 15 percent re-
sidual and distillate petroleum.
125 10-15 x 10 Btu/hr water-tube, front-
back fired units. 70 percent residual
petroleum, distillate petroleum, gas;
25 percent coal; 5 percent wood; 90 per-
cent coal field erected. Some combina-
tion. 75 percent of wood have gas and
oil capability
-------
SUMMARY OF TELEPHONE CONTACTS WITH BOILER MANUFACTURERS
Company
1. North American Mfg. Co.
Cleveland, Ohio
216-271-6000
2. Kewanee Boiler Corp.
Kewanee, Illinois
309-853-3541
Person contacted
Harold B. Infield
G.M. Halley
Ass't. Chief Engr.
Date
4/13/76
4/12/76
Comments
10-75 x 10 Btu/hr. Residual distillate
petroleum, gas, or combination fired.
Fire tube and water tube. All front-back
fired.
56 10-30 x 10 Btu/hr residual petroleum,
distillate petroleum, gas, or combination
fired. Fire tube front -back fired. 98
percent packaged.
n
j
-------
AMERICAN BOILER MANUFACTURERS ASSOCIATION ACTIVE MEMBER COMPANIES
AND PLANTS
ABCO Industries, Inc.
633 Walnut Street
P.O. Box 268
Abilene, Texas 79604
(915) 677-2011
D. J. Nash, President
Babcock and Wileox Company
20 South Van Buren Avenue
Barberton, Ohio 44203
(216) 753-4511
W. H. Jackson, Vice President
Group Marketing
161 East 42nd Street*
New York, New vork 10017
(212) 687.6700
R. S. Chase, Jr.
P.O.Box 1478
Brunswick, Georgia 31520
(912) 265-0510
E.J.O'Breza
1501 Raff S.W,
Canton, Ohio 44700
(216) 478-1441
T, E. Murray
P.O. Box 2423
North Canton, Ohio 44720
(216) 4947610
T. M. Campbell, Jr.
P.O. Box 507
Lynchburg, Virginia 24500
(703) 384-5111
E. J. Silk
Highway 69 West
Mt Vernon, Indians 47620
(812) 838-6071
A. L. MacKinney
P. O. Box 490
Paris, Texas 75460
(214) 784-2571
S. L. Abbett
1725 K Street, N.W. *
Washington, D. C. 20006
(202) 296-0390
J. Taylor, Jr.
P.O. Box 677
West Point, Mississippi 39973
(601) 494-1323
N. R. Johanson
P.O.Box 1730
Wilmington, North Carolina 2E401
(919) 791-9010
J. D. Coleman
Bethlehem Corporation
25th and Lennox Streets
Easton, Pennsylvania 18042
(215) 258-7111
R. D. Pennstrom, Sales Manager
225 West Second Street*
Bethlehem, Pennsylvania 13018
(215) 867-4605
W. Bittler
The Bigelow Company
P.O. Box 706
New Haven, Connecticut 06503
(203) 772-3150
E. C. Grotty, President
Bryan Steam Boiler Company
P.O. Box 27
Peru, Indiana 46970
(317) 4736651
'Office
C-7
H. V. Koch, President
-------
Burnham Corporation
P.O.Box 1079
Lancaster, Pennsylvania 17604
(717)397-4701
L. G. Shenk, Jr., Vice President & Manager,
Hydronics Division
CEA Combustion, Incorporated
P.O. Box 2039
Stamford, Connecticut 06906
(203)359-1320
R. K. Ennis, Sales Manager
555 Madison Avenue
New York, New York 10022
(212) 980-3700
F. Margolick
Power Flame Division
2001 South 21st Street
Parsons, Kansas 67357
(316)421-0480
W. Wiener
C-E Air Preheater Corporation
P.O Box 372
Wellsville, New York 14895
(716) 593-2700
T. L. Woolard, President
P.O. Box 790
Marion, North Carolina 28752
(704) 7244171
W. Kehler
Cleaver Brooks Division
P.O. Box 421
Milwaukee, Wisconsin 53201
(414)962-0100
R.J Kendro, President
P.O. Box 150
Lebanon, Pennsylvania 17042
(717)2733773
C. Powell Adams
P.O.Box 1357
Greenville, Mississippi 38702
(601)335-3501
W. C. Crawford
P.O. Box 458
Stratford, Ontario, Canada
(519)271-9220
A. Urich
The Coen Company
1510 Rollins Road
Burlingame, California 94010
(415)697-0440
T. S. Voorheis, President
35 Montesano Road
Fairfield, New Jersey 07006
(201)625-4830
C. Binasik
Combustion Engineering, Incorporated
1000 Prospect Hill Road
Windsor, Connecticut 06095
(203) 688-1911
T. E. McMahon, Vice President
900 Long Ridge Road*
Stamford, Connecticut 06902
(203) 329-8771
A. J. Santry
911 West Main Street
Chattanooga, Tennessee 37401
(615)265-4631
H. F. McQueen
C-E/Avery Company
P.O, Box 630
Portsmouth, New Hampshire 0308I
(603) 421-8100
D. Packaid
425 West 151 Street
East Chicago, Indiana 46312
(219) 397-6460
H. A. Keightley
•Office
C-8
-------
Monongahela Plant
Monongahela, Pennsylvania 15063
(412) 2584600
E. Ricketts
1101 15th Street N.W.*
Washington, D. C. 20005
(202) 296-8966
J. Bennett
601 North Washington Avenue
Saginaw, Michigan 48607
(517)755-1101
E. Duckett, Jr.
5319 Shreve Avenue
St. Louis, Missouri 63115
(314) 381-1600
G.F. Gross
Detroit Stoker Company
P.O. Box 732
Monroe, Michigan 48161
(313) 241-9500
H. L. Knox, President
Eclipse Lookout Company
P.O. Box 4756
Chattanooga, Tennessee 37405
(615) 265-3441
E. E. Msgnuson, Consultant and Director
of Training
The Engineer Company
P.O. Box 39
South Plainfield, New Jersey 07080
(201)755-2500
R. W. Carry, President
Foster Wheeler Energy Corporation
110 South Orange Avenue
Livingston, New Jersey 07039
(201) 533-1100
H. B. Wallace, Jr., Assistant Vice President
"Office
P.O. Box 290
Dansville, New York 14437
(716) 335-3131
N. Freeman
Forney Engineering
P.O. Box 189
Addison, Texas 75001
(214)233-1871
A. Svien
Crestwood Industrial Park
Mountaintop, Pennsylvania 18707
(717)474-6366
W. York
Nuclear Power Product Company
P.O. Box 700
Panama City, Florida 32401
(904) 769-3201
J. K.Tannehill
1701 Pennsylvania Avenue*
Washington, D. C. 20006
(202) 298-7750
R. Reilly
Hoffman Combustion Engineering
1780Southfield Road
Lincoln Park, Michigan 48146
(313) 383-8400
W. B. Hoffman, President
A. F. Holman Boiler Works, Incorporated
1956 Singleton Boulevard
Dallas, Texas 75212
(214) 637-0020
C. G. Stokes, Vice President
Industrial Boiler Company
221 Law Street
Thomesville, Georgia 31792
(912) 226-3024
P.W. Goggins, President
C-9
-------
Industrial Combustion, Incorporated
4465 North Oakland Avenue
Milwaukee, Wisconsin 53211
(414) 332-4100
J. Fletcher, President
351-21st Street
Monroe, Wisconsin 53566
(608) 325-3141
D. Wyttenbach
International Boiler Works Company
P. 0. Box 498
East Stroudsburg, Pennsylvania 18301
(717) 421-5100
R. Imbt, Jr., Vice Present
Iron Fireman, Dunham-Bush,
Harrisonburg Division
101 Burgess Road
Harrisonburg, Virginia 22801
(703) 434-0711
A. J. Jenkins, Director-Sales & Marketing
Combustion Products
Johnston Brothers, Incorporated
Pine Street
Ferrysburg, Michigan 49409
(616) 842-5050
R. R. Whitehouse, President
E. Keeler Company
238 West Street
WiHiamsport, Pennsylvania 17701
(717) 326-3361
R. J. Engler, President and General Manager
Kewanee Boiler Corporation
101 North Franklin Street
Kewanee, Illinois 61443
(309) 853-3541
Lasker Boiler & Engineering Corporation
3201 South Wolcott Avenue
Chicago, Illinois 60608
(312) 523-3700
F. A. Lasker, President
McBurney Stoker & Equipment Company
P. O. Drawer 47848
Atlanta, Georgia 30340
(404) 448-8144
W. B. McBurney, President
Mid-Continent Metal Products
2717 North Greenview
Chicago, Illinois 60614
(312) 549-3900
E. W. Haedike, Executive Vice President
National Combustion Company, Incorpora
45-03 Junction Boulevard
Corona, New York 11368
(212) 592-2600
W. Blank, Vice President
Nebraska Boiler Company, Incorporated
P. O. Box 82287
Lincoln, Nebraska 68501
(402) 464-7441
D. T. Scully, President
Oswego Package Boiler Company
157 East First Street
Oswego, New York 13126
(315) 343-0660
A. J. Drechsler, President
9 Boulder Road
Norwalk, Connecticut OG854
(203) 838-9000
E. J. Zisek
D. W. Stoner, Chairman of the Board
C-10
-------
Peabody Engineering Corporation
835 Hope Street
Stamford, Connecticut 06907
(203) 327-7000
F. E. Lammers, Executive Vice President
39 Maple Tree Avenue
Stamford, Connecticut OC906
(203) 327-7000
R. Frolke
Peabody Gordon-Piatt, Incorporated
P. 0. Box 650
Winfield, Kansas 67156
(316) 221-4770
M. K. Gordon, President
2720 Des Plaines Avenue
Des Plaines, Illinois 60018
(312) 297-2640
T. Judson
Preferred Utilities Manufacturing Corporation
11 South Street
Danbury, Connecticut 06810
(203) 743-6741
R. G. Bohn, President
W. N. Best Combustion Equipment Company
11 South Street
Danbury, Connecticut 06810
(203) 743-6741
J. S. Akin
Ray Burner Company
1301 San Jose Avenue
San Francisco, California 94112
(415) 333-5800
R. C. Westover, Jr., President
Riley Stoker Corporation
P. 0. Box 547
Worcester, Massachusetts 01613
(617) 852-7100
J. J. Farrell, President
P. O. Box 6260
Erie, Pennsylvania 16512
(814) 454-8164
K. O. Nelson
Riley Southwest Corporation
P. 0. Box 1328
Sapulpa (Tulsa), Oklahoma 74066
(918) 224-7074
W. Sommers
Riley-Beaird, Incorporated
P. O. Box 1115
Shreveport, Louisiana 71130
(318) 868-4441
W. M. Bradshaw
Superior Boiler Works, Incorporated
3524 East 4th Street
Hutchinson, Kansas 67501
(316) 662-6693
C. C. Anderson, President
Superior Oorr'r-ustion Industries
801 Broad Street
Emmaus, Pennsylvania 18049
(215) 965-9051
R. W. Vollmer, President
Thermo-Pak Boilers, Incorporated
P. 0. Box 13223
Memphis, Tennessee 38113
(901) 942-4684
R. W. Butcher, Vice President
C-ll
-------
Trane Company
3600 Pamme! Creek Road
La Crosse, Wisconsin 54G01
(608) 782-8000
H. J. Michaels, Sales Manager, Boiler
and Combustion Products
Williams and Davis Boiler and Welding
Company, Incorporated
P.O. Box "AF"
Hutchins, Texas 75141
(214) 225-2356
J. E. Davis, General Manager
P. O. Box 967
Burlington, Iowa 52601
(319) 754-6541
Vic Pufahl
2020 North 14th Street
Suite 408
Arlington, Virginia 22201
(703) 525-4015
J. Wolf
Vapor Corporation, VA Power Division
6420 West Howard Street
Chicago, Illinois 60648
(312) 631-9200
A Lemos, Jr., Vice President and General
Manager
Henry Vogt Machine Company
P.O. Box 1918
Louisville, Kentucky 40201
(502) 634-9411
y York -Shipley, Incorporated
P. O. Box 349
York, Pennsylvania 17405
(717) 755-1081
C. H. Neiman, Jr., Technical Vice President
Zurn Industries, Incorporated
2214 West 8th Street
Erie, Pennsylvania 16512
(814) 455-0921
M. O. Funk, Executive Vice President
Erie City Energy Division
1422 East Avenue
Erie, Pennsylvania 16503
(814) 452-6421
C. L. Hedrick
R. W. Precious, General Manager, Boiler
Division
C-12
-------
RECORDS OF TELEPHONE CONVERSATIONS
The following section contains the records of the individual telephone
conversations which were part of our survey on boiler manufacturing trends.
C-13
-------
PERSON CALLED
ORGANIZATION
Address:
TEL. NO.
GCA PERSONNEL
SUBJECT MATTER:
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS Y
SOLID FUEL '*
DATE: 4/15/76
Aftm Tn/fnef-*.-;
633 Walnut St.
Abilene, Texas
(915) 677-2011
TPM
Boiler data - Firm does not produce systemswithin the
10 million to 250 million Btu/hr size range.
C-14
-------
REPORT OF TELEPHONE CONVERSATION
X
RSON CALLED_
GANIZATION:_
Address:
L. NO.
RE: OIL AND GAS
SOLID FUEL
Mr. A.xtman
ABMA
703-522-7298
X
DATE: 4/28/76
A .PERSONNEL MAC
EJECT MATTER:
Mr. Axtman called in the morning to suggest we set up a meeting
with him to discuss our boiler survey. Mr. Schyler of Riley-Stoker
had called him regarding the information requested in my letter. Mr.
Axtman said that ABMA had all of that data and he would be willing
to set up a meeting.
After talking with Paul & Art, I returned Mr. Axtman's call to -suggest
we plan to set up our meeting after Paul and Art meet with Ken Durkee
on Friday (4/30/76).
I will 3et up an appointment for sometime next week and call
him Monday.
C-15
-------
PERSON CALLED.
ORGANIZATION:_
Address:
TEL. NO.
GCA PERSONNEL
SUBJECT MATTER:
REPORT OF TELEPHONE CONVERSATION
X
RE: OIL AND GAS
SOLID FUEL
JOE ORCINO
ACE TANK & HEATER CO.
SANTA FE SPLINGS. CALIF.
213-941-0221
TPM
X
DATE: 4/21/76
Boiler data. Afte producers only 3 or 4 units per year in the
10 million to 25 million BTU/hr. category. All are light oil
and/or gas fired. The design is different from other manufacturers -
sounds like a finned fire box design. See questionnaire.
C-16
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X _
SOLID FUEL X _
DATE: 4/15/76
.SON CALLED _ Mr. Axtman _
ANIZATION: American Boiler Manufacturers
,ddress: Ste 317 1500 Wilson Blvd
Arlington, Va. 22209
J% NO. 7Q3-522-72QK
PERSONNEL M. REI
EJECT MATTER:
Mr. Axtman prepared a list of boiler manufacturers which he had previously
sent to -me. I asked him if the list could be revised since we no longer
were looking for manufacturers below 10 MM Btu/Hr. He went over the list
with me and indicated which manufacturers are currently in business and
produce boilers in the new size range. He assured me that the list was
complete and as up to date as could be gathered.
C-17
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND CAS
SOLID FUEL X
DATE: 23 April 1976
PERSON CALLED Mr. Axtman
ORGANIZATION; American Boiler Manufacturers Association
Address: Arlington, Virginia
TEL. NO. (703) 522-7298
GCA .PERSONNEL T. P. Midurski
SUBJECT MATTER: I spoke with Mr. Axtman of the American Boiler Manufacturers
Association (ABMA) regarding the possibility of obtaining boiler production fig-
ures from him. He-indicated that sales figures are available and could possibly
be obtained from him. However, he also indicated that sales tabulations are
currently being submitted to EPA (IERL) as well as Batte11-Columbus Labs. From
his point of view it would be desireable for us to obtain whatever summeries we
wanted through either IERL or Battell. Further, he indicated that either Bob Hall
or Stan Cuffe at EPA (IERL) or Dave Locklin at Battell would be appropriate contacts
for this data.
Axtman also remarked that he has been reluctant to supply consultants such as
GCA with data because he seldom receives any acknowledgement for his effort - acknow-
ledgement meaning letter of thanks, 'courtesy copy of reports for which data were
used, etc. Perhaps we should make it a point to formally thank him for his assis-
tance with a letter and/or a copy of the report.
C-18
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS x
SOLID FUEL X
' DATE: 4/12/76
.SON CALLED MR. W.B. HOYT
ANIZATION: AMERICAN SOCIETY OF MECHANICAL ENGINEERS
,ddress: 345 East 47th St.
New York, NY
N0 (212) 644-7500
PERSONNEL TPM
EJECT MATTER:
Discussed the availability of general data regarding boiler design,
fuels, manufacturers, design standards. Apparently all pressure vessels
manufactured in the U'.S. must be constructed IAW ASME design codes. These
codes do not pertain to emission rates - only to the adequacy of the design
to ensure safety and standardization of fittings, etc. List of man-
ufacturers is provided in ASME publication Companies Holding ASME Certifi-
cation of Authorization (copies of this are available at MIT).
C-19
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS x
SOLID FUEL x
DATE: 4/16/76
PERSON CALLED
ORGANIZATION; AVCO- Lycoma Division fPreviously Spencer Div.)
Address: Williamsport. Penna.
TEL. NO. (7171 323-filBI
TPM
GCA PERSONNEL
SUBJECT MATTER: Boiler
Firm sold its boiler operations to Burnham Corp. about 3 years ago.
C-20
-------
DN CALLED_
SIZATION:_
dress:
NO.
PERSONNEL
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
OIL AND GAS
SOLID FUEL
MR. N.W. EFT
Babcock and Wilcox
20 South Van Buren Ave.
Barberton, Ohio
(216) 753-4511
TPM
X
DATE: 4/21/76
JECT MATTER:
Boiler data . Couldn't get much information - he will send
literature on product line for us to review and then we can call
back to discuss data required.
C-21
-------
PERSON CALLED_
ORGAN1ZATION:_
Address:
REPORT OF TELEPHONE CONVERSATION
X
RE: OIL AND GAS
SOLID FUEL
DAVE LOCKLIN
BATTELLE. INC.
COLUMBUS. OHIO
X
DATE: 4/26/76
TEL. NO. (614^) 424-6424
GCA PERSONNEL TPM
SUBJECT MATTER:
Talked to Mr. Locklin at the suggestion of Mr. Axtman, of ABMA, regarding
Battelle's work in boiler inventories. Apparently, Battelle has an exceptionally
comprehensive inventory - they obtain a file on almost every watertube boiler
unit sold (as reported to AMBA) which they enter in their computer file. The
type of data is described in^he EPA report Design Trends and Operating Problems
/ ^?
in Combustion Modification of Industrial Boilers, by Battelle. Locklin indicated
that special summaries could be run for us - if we did want these, however,
they would have to charge us for them. Again, the summaries are industry wide.
C-22
-------
RSON CALLED_
GANIZATION:_
Address:
;L, NO.
!A PERSONNEL
JBJECT MATTER:
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
OIL AND GAS
SOLID FUEL
X
DATE: 4/21/76
WLLTER RYKOWSKI
BETHLEHEM CORP.
25th and LENNOX STS.
EASTON,PENNA.
(215) 258-7111
TPM
Boiler data - Bethlehem produces boiler systems up to about 35 x 10
BTU's/hr. for oil and gas. Recently obtained license to build coal fired
equipment but will be some time before actual production begins. Se-e
questionnaire.
C-23
-------
PERSON CALLED,
ORGANIZATION:,
Address:
TEL. NO.
GCA PERSONNEL
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS
SOLID FUEL
MR. P.P. PENNTNa
THE BIGELOW COMPANY
NEW HAVEN, CONN.
(203") 772-^1 sn
DATE: April 14, 1976
TPM
SUBJECT MATTER:
Obtain data on boilers produced. Bigelow does produce boilers in all sizes
through 250 million BTU's/hr. Mr. penning isn't sure about releasing sales
figures - he'll check with the director or vice president of manufacturing
to see if sales data can be made available to us. Call back Tuesday or
Thursday of next week.
C-24
-------
SON CALLED_
ANIZATION:_
.ddress:
,. NO.
PERSONNEL
BJECT MATTER:
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X_
OIL AND GAS
SOLID FUEL
MR. D.E. PENNING
BIGELOW CO.
NEW HAVEN, CONN.
(203) 772-31 SO
TPM
X
DATE: 4/22/76
Boiler data: additional data on boiler system
See questionnaire
C-25
-------
PERSON CALLED,
ORGANIZATION:,
Address:
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS y
SOLID FUEL v
DATE: 4/2/?6
MR. BUSHNELL
BOILER ENGINEERING & SUPPLY CO.
PHOENIXVILLE, PENNSYLVANIA
TEL. NO. (215') 933-5832
GCA PERSONNEL TPM
SUBJECT MATTER:
Boiler data. Produce systems up to about 120 x 1Q6 BTU's/hr to burn
any type(s) of fuel. They do not manufacture the stackers' or burners
used in the systems, however, The firm is not willing to disclose
production figures - possibly try a vice president of manufacturing
for this information. See questionnaire.
C-26
-------
ISDN CALLED_
;ANIZATION:_
Address:
L. NO.
b. PERSONNEL
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS
SOLID FUEL
BOB ELLERY
BRENTON & HART.INO.
CAMBRIDGE. MASS.
(617) 868-1720
TPM
x
X
DATE:
4/21/76
EJECT MATTER:
Boiler data. Brenton & Hart are manufacturers-reps for the
Burham Corp. They will send literature on system.
C-27
-------
TEL. NO.
GCA PERSONNEL
SUBJECT MATTER:
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS x
SOLID FUEL v
DATE: 4/16/76
PERSON CALLED DON RORTNSDN/.TRggp? MCVAY
ORGANIZATION: BRYAN STEAM CORP.
Address: P.O. Box 27 - STATE ROAD. N». 19 NORTH
PERU, INDIANA
(317U73-66S1
TPM
Boiler data. This 'firm produces up. to 15 x 106 BTU/hr.
Covv^iAocruv* F>rcc/.
systems - light oil, gas, or coBibuefci.ui.iJUi.-l. Produced
about 12 units in the 10 million to L5 millionBtu/hr
size range during 1975. See questionnaire for particulars.
C-28
-------
. NO.
PERSONNEL
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS x
SOLID FUEL ' x
DATE: 4/15/76
;ON CALLED TERRY BECKLY/LOUIS STANKE
iNIZATION; BUliNHAM CORP. - COMMERCIAL STEEL DIV.
Idress: LANCASTER. PENNA.
(717) 337-4704
TPM
UECT MATTER:
Interview regarding boilers produced in the 10 million to 250 million
BTU/hr size range. Interview obtained; could not obtain data on the
number of units produced. It was suggested that a letter be sent to
Mr. Louis Shenk, Division Manager, in Lancaster explaining our request.
See interview sheet for data obtained.
C-29
-------
PERSON CALLED_
ORGANIZATION:.
Address:
TEL. NO.
GCA PERSONNEL
SUBJECT MATTER:
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
SOLID FUEL X
DATE: 4/21/76
MB, MTT.TABD PKCMT.F.K
CEA COMBUSTION
P.O. Box 2039
Stamford. Conn.
(203) 3S9-1320
TPM
Boiler data - Boiler systems in the 10 million to 250 million
Btu/hr size range are manufactured by a separate division of
CEA - International Boiler Works in East Straudsburg, Penna.
C-30
-------
REPORT OF TELEPHONE CONVERSATION
RE:
OIL AND GAS
SOLID FUEL
x
X
DATE: 4/2/76
3N CALLED MR. E.L. WEAVER
KIZATION: CLEAVER BROOKS DIV. OF AQUA-CHEM CORP.
dress: MILWAUKEE, WISCONSIN _
NO.
PERSONNEL TPM
JECT MATTER:
Boiler data. Firm produces systems up to about 100 x 106 BTU's/hr.
to bur* oil and/or "gas. Production figures not available without
written request stating why we need it and how it will be used.-
send to E.L.Weaver at address above.
See questionnaire
C-31
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS Y
SOLID FUEL K
DATE:4/20/76
PERSON CALLED MR. AUDOLENSKY
ORGANIZATION; COMBUSTION ENGINEERING AND TNDTTSTKTAT. BOILER DIV.
Address: WINDSOR.CONN.
TEL. NO.
GCA PERSONNEL
(203) 688-1911
TPM
SUBJECT MATTER:
Boiler data. Within the range that we're concerned with
C - E produces sytems "in the 100 million to 250 million Btu/hr size
range. Systems accommodate any fuel type. Production figures shofold
be available from American Boilers Mfrs. Assoc.
See questionnaire
C-32
-------
SON CALLED_
\NIZATION:_
ddress:
.. NO.
, PERSONNEL
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
OIL AND GAS
SOLID FUEL
'X
MR. LARRY MILO
COMBUSTION ENGINEERING. INC.
75 Federal St.
Boston, Mass.
(617) 426-6650
TPM
DATE: 4/21/76
3JECT MATTER:
Boiler data. Called to obtain data on C.E. boiler systems.
C-33
-------
REPORT OF TELEPHONE CONVERSATION
RE:
OIL AND GAS
SOLID FUEL
x
DATE: 4/20/76
PERSON CALLED Mr. Dpn Lythe
ORGANIZATION; Cyclotherm Div. of Oswego Packaged Boiler Co.
Address : Oswego, New York
TEL. NO. (315) 343-0660
GCA PERSONNEL TPM
SUBJECT MATTER:
Boiler data. Firm produces sytems up to about 30 x 10 BTU's/hr to
burn oil and/pr gas. Produce mainly smaller systems, however (less
than 107 BTU's/hr).
Production figures can't be disclosed without a written request to
the general manager.
See questionnaire.
C-34
-------
3N CALLED_
SIZATION:_
dress:
NO.
PERSONNEL
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS v
SOLID FUEL 'v
DATE: 4/21/76
MR. ROBERT REESE
7)UMHAM-
DUfriglAM-BUSH CO.
OK)
HARRISJ3URG, VA.
TPM
JECT MATTER:
Boiler data. Company purchases boiler assemblies from
Superior Boiler Works and installs their own burners to produce their product line,
See questionnaire.
C-35
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
SOLID FUEL X
DATE: 4/14/76
PERSON CALLED _ Kenneth Freelane
ORGAN IZATION : _ FJ.A -
Address: __
TEL. NO. 202-254-9700
GCA PERSONNEL MAC
SUBJECT MATTER:
Follow-up on "Federal Energy News" of 1/22/75 which described an FEA contract
to .KVB to study energy conservation in industrial boilers.
KVB - behind schedule - can''t expect any outputs in time for use in this study
Other FEA contracts:
Battelle - Final due in 1 month: fuel additives for oil-fired boilers
(an add-on from EPA work) call back in 1 month to get report.
Auburn University, Alabama - Due in 1 month - results of state wide
boiler efficiency tests, stack samples for C02 and HC content
(as measure of efficiency). This is a micro study, more of a
"how you can improve your boiler's efficiency."
C-36
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
OIL AND GAS
SOLID FUEL
X
ON CALLED_
,KIZATION:_
Idress:
, NO.
ELLEN RUSSELL
FEA - Office nf
ITU n*at j_?n
202-961-8.S91
PERSONNEL MAC
DATE: 4/14/76
JECT MATTER:
Inventory of industrial boilers £ 100 x 106 Btu/hr
Final report due in 6 weeks -now in Office of General Council for review
is complete
covers fuel use, firing methods, size, but not individual
identification - i.e. a summary
Will be sent to me when released
C-37
-------
PERSON CALLED_
ORGANIZATION:_
Address:
TEL. NO.
GCA PERSONNEL
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
OIL AND GAS
SOLID FUEL
X
DATE: April 13, 1976
MR. TOM SCHROPPE
FOSTER-WHEELER ENERGY CORPORATE ON
PEACH TREE HILL ROAD
LIVINGSTON. N.J. 07039
201-533-3216
A.S. WERNER
SUBJECT MATTER:
F-W manufactures very few stationary-package boilers in the 10-250 Btu/hr
range. Those that are made are manufactured at their facility at St. Catherine,
Ontario, Canada. Mr. Schroppe guessed they make 5-10 year but suggested that
I call Mr. Al Downham in their general sales division for that information. The
oil and natural gas boilers are all 2 pass water tubetypes. The solid fueled
boilers are all top supported, horizontal firing with vertical gas exit from
the furnace. Solid fueled boilers can be used for oil and gas but not vice-
versa because the former do not have ash removal devices. Mr. Schroppe
estimated that boilers in this range have emission rates 2-3 times higher than
NSPS for large boilers. Additional control would require complete redesign
and physically much larger units. He mentioned the following companies not on
our other lists: B&W, Erie City,Seattle Boiler Works and Wickes.
C-38
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
SOLID FUEL
DATE:4/l5/76
SON CALLED_
ANIZATION:_
.ddress:
,. NO.
JIM RICHARDS
INDUSTRIAL COMBUSTION. INC.
MILWAUKEE. WIS.
414 332-4100
PERSONNEL
M. REI
EJECT MATTER: Boiler survey
Mr. Richards indicated that "his company does not manufacture boilers, but that
it does sell some boilers under their own name. They are a burner manufacturer;
however, they do have boiler shells make for them to which they add their burners,
and sell in their name. He indicated that the type of information requested is
proprietary, but a written request from GCA fully explaining our intentions, in-
cluding an assurance of confidentiality of the data gathered, could result in
the release of the data over the telephone or written responses to specific
questions. The company only handles oil and gas fired boilers up to 700 HP
(22.75 MM Btu/hr).
C-39
-------
REPORT OF TELEPHONE CONVERSATION
X
OIL AND GAS
SOLID FUEL
X
DATE:
PERSON CALLED
ORGANIZATION:
Address:
TEL. NO.
GCA PERSONNEL
Ed Mordt
International B<
E. Stroudsberg,
liler Works Co
Penna.
717 421-5100
M. Rei
SUBJECT MATTER:
Mr.Mordt indicated that the primary production data can be given
to GCA if we send him a questionnaire. They produce oil, gas, and
JU
various solid fueled (coal, peanut and mae<4gniian nut shells, etc.)
boilers from 10 - 150 MM Btu/hr capacity. They specialize in hot
water rather than steam generating boilers. I indicated that we
would likely be sending him a questionnaire of some sort in the
next month.
C-40
-------
SON CALLED_
\NIZATION:_
ddress:
NO.
PERSONNEL
3JECT MATTER:
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
OIL AND GAS
SOLID FUEL
X
DATE: 4/15/76
Brook Marstiller
.TfVhnot-nn 'Rrci
616 842-SDSn
M. RET
Boiler survey
Mr. Marstiller indicated that the official response to our' questions
is negative. He suggested that the information is proprietary and they
would not release it. However, he said that if we get an overall industry
response that (if the data is kept confidential) is positive, that they
would reconsider their position. The information would have to be kept
confidential in any event.
C-41
-------
Company: North American Mfg. Co.
Contact Person; Harold B. Infield
Telephone No. : (2l6) 271-6000
Location; 4455 E. 71st St.;
Title; Chief Boiler Design Engineer
Date; May 13, 19?6 _
I. Current Production (in the Size Range 10-250 x 10 Btu/hr, domestic sales
only) :
A. Size Distribution: Total numbers or percentages:
Size
category
(MBtu's hr)
10-15
15-20
20-30
30-50
50-75
75-100
100-150
150-250
Residual
petroleum-
Qf0
40$
Qo%
90%
100%
Annual production of fuel type
Distillate
petroleum
72%
55%
15%
5%
0%
Gas
20%
5%
5%
0%
0%
Coal
0
0
0
0
0
Other
solid fuel
Combination
fired
50%
±5%
12%
10%
0%
Total
units
B. Type Distribution:
Size
category
(MBtu's hr)
10-15
15-20
20-30
30-50
50-75
75-100
100-150
150-250
Residual petroleum
Fire
tube
20
20
10
10
Water
tube
50
50
50
50
Other
30
30
40
40
100
Distillate petroleum
Fire
tube
50
50
50
30
0
Water
tube
20
20
20
30
0
Other
30
30
30
40
0
Gas
Fire
tube
30
30
30
20
0
Water
tube
30
30
30
40
0
Other
40
40
40
40
0
C-42
-------
B. Type Distribution (continued)
Size
category
(MBtu's hr"1)
10-15
15-20
20-30
30-50
50-75
100-150
150-250
Coal-fired
Fire
tube
Water
tube
0$
Other
Other solid fuel
Fire
tube
Water
tube
0$
Other
Combination fuel
Fire
tube
Water
tube
0$
Other
C. Distribution by firing type:
Size
category
(MBtu's hr"1)
10-15
15T20
20-30
30-50
50-75
75-100
100-150
150-250
Residual petroleum
Front-back
fired
100$
Opposed
fired
Tangentially
fired
Distillate petroleum
Back-front
fired
100$
Opposed
fired
Tangenttally
fired
Gas
Back-front
fired
100$
Opposed
fired
Tangentally
fired
C-43
-------
C. Distribution by firing type (continued)
Size
category
(MBtu's-hr"1)
10-15
15-20
20-30
30-50
50-75
75-100
100-150
150-250
Coal
Wet
pulverized
Dry
pulverized
09£
Cyclone
Stoker-fired
Overfeed
Spreader
0^
Underfeed
Other fuels:
C-44
-------
D. Burner configuration:
What type of atomization is used? (indicate size ranges)
1 to 5 Million BTU Mech. - 5'to 60 Million - Air or Steam
E. General discussion:
1. What proportion of product line is packaged and field erected?
(Indicate size ranges and fuels)
100$ packaged
2. Is equipment of a standard design or custom built?
Standard
3. If custom built, what factors are most critical in determining
the design configuration (e.g., customer preferences, variations
in fuel to be used, etc.)?
4. General statements regarding future production - consider fuels,
product demand as it relates to the overall economic posture,
new designs to be introduced, etc; by boiler size,and type.
Future production will be distillate and residual
fuels entirely with provision to fire both pulverized
and slury coal. The only gas fired units will be
replacement units.
C-45
-------
II. Emissions Characteristics:
1. Have you analyzed emissions for particulates, S02, N0x> CO and hydro-
carbons? Yes
results: (please indicate boiler size, fuel-fired, firing design)
#6 Oil
Particulates,-.013 gr/SCR
NOV - 2 x 10° Ibs/SCR
CO - 0$
2. Are you conducting research programs on design features to reduce
pollution emissions? Yes
please indicate general areas of research and problems in the
trade-offs between emissions control and efficiency, safety, etc.
1. Attempting to reduce particulate through reduction
of hydrocarbon through better mixing and atomizing.
2. Forget NO in effort to achieve higher efficiency.
Is equipment certified to meet emission performance criteria - if
so by whom (ASME, Manufactures guarantee, etc)? Yes
Independent testing agency for Dept. of Environmental
Protection State of Connecticut.
Is pollution control equipment available/necessary to meet specified
emissions criteria? What types of pollution control equipment do
you recommend with your boilers?
None
C-46
-------
REPORT OF TELEPHONE CONVERSATION
X
RE: OIL AND GAS
SOLID FUEL
X
DATE: 4/15/76
SON CALLED_
GLEN CATO
KVB
idress :
, NO.
PERSONNEL
714-832-9020
MAC
JJECT MATTER:
Called about paper presented at Combustion Conference, Atlanta, Ga.,
October 1975: report on Emissions from Industrial Boilers
i
This report was based on Phase I and Phase II documents.
Phase #1: NTIS PB 238 920/AS, October 1974
Phase #2: EPA - 600/2-76=086A April 1976
Also asked about FEA contract on boiler efficiency - he is not working
on that project, but expects it to be finished in about a month.
C-47
-------
REPORT OF TELEPHONE CONVERSATION
PERSON CALLED
RE: OIL AND GAS
SOLID FUEL
:* REDCAY^
x
x
DATE: 4/27/76
ORGANIZATION: MASSACHUSETTS BUREAU OF ATR QUALITY CONTROL (BAQC)
Address: Boston. Mass.
TEL. NO.
GCA PERSONNEL
(611) 727-2700
TPM
SUBJECT MATTER:
BAQC compiles data on emission characteristics of boiler systems installed
in the state as these, systems must comply with state emission standards.
Reday indicated that he would be willing to meet with us after the 14th of
May to determine whether or not the data that they have would be of value
for oar project. I told him that we would be in touch with him within the
next .two weeks to arrange a meeting.
C-48
-------
RSON CALLED_
GANIZATION:_
Address:
L. NO.
!A PERSONNEL
IBJECT MATTER:
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS _x
SOLID FUEL
DATE
C.F. ONASCH
MCGRAW-HILL PjflUBLISHER/POWER MAGAZINE
607 ECYLSTON STREET
BOSTON, MASS. 02115
262-1160
TPM
General discussion on boilers - who manufacturers systems, data sources,
data/literature available, etc.
C-49
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS *~
S<:
SOLID FUEL
DATE:
PERSON CALLED_ A-eW^r f-ret/ . !/• "
ORGANIZATION:_
Address:
TEL. NO.
GCA PERSONNEL
SUBJECT MATTER:
Modular baghouses 0 to 15,000 CFM
99.75% effort or > ly
Pulse jet
Cleaning T . .
Intermittent pneumatic-air blast
system
Intermittent mechanical-shaker
Many operating units but would not release names of companies.
Mike McShenry - individual cyclones used for units from 13 to
14,000 CFM to 200 to 300 CFM. Have high velocity and removal
efficiency characteristics.
C-50
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
SOLID FUEL
DATE: 4/15/76
IRSON CALLED Harry Kumpula
IGANIZATION: Nebraska Boiler Mfg. Co.r Inc.
Address: Lincoln, Nebraska
El. NO. 402-464-7411
CA PERSONNEL M. Rei
OBJECT MATTER:
Boiler Survey
Mr. Kumpala told me that they make approximately 60 boilers •
per year all type D or A watertube design. He indicated that nearly
all of their units were residual oil-fired, but an occasional gas
fired unit was manufactured. He said that they are working on a
package coal-fired(stoker) boiler, but that it is only in the preliminary
stages and that its size and other pertinent details have not been
determined. He said that the demand for gas fired units has dwindled
steadily to nearly zero today.
C-51
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS
SOLID FUEL x
DATE: 4/15/76
PERSON CALLED
ORGANIZATION; PROX CO., INC.
Address: Terra Haute, Indiana
TEL. NO.
GCA PERSONNEL
SUBJECT MATTER:
They no longer manufacture new boilers - only repairs
C-52
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS
SOLID FUEL
DATE:
IRSON CALLED_
IGANIZATION:_
Address:
ft. NO.
CA PERSONNEL
UBJECT MATTER:
'hree units controlled by electrostatic precipitator.
Imallest, 50,000 ACFM at 97 percent efficienty (guaranteed)
tO percent of particulates less than
C-53
-------
PERSON CALLED_
ORGANIZATION:_
Address:
TEL. NO.
GCA PERSONNEL
SUBJECT MATTER:
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS x
SOLID FUEL X
DATE: 4/20/76
HORACE ROUNDS
FRANK I. ROUNDS. TNfl.
112 Needham St.
Newton Highlands. Mass.
332-4200
TPM
Data on Cleaver-Brooks Boilers
I requested literature on Cleaver-Brooks.boiler system from Mr.
Rounds -area sales agent for Cleaver-Brooks. Also asked about
emissions data for thesame. He indicated that such data was available
but since he had been "bothered" so many times in the past by the
State (Massachusetts) for the data, he d.idn't feel that he would want
to comply with our request - he "suggested" that we obtain it from
the State.
C-54
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
OIL AND GAS
SOLID FUEL
X
DATE:
PERSON CALLED
ORGANIZATION:
Address:
A/.G.
TEL. NO.
GCA PERSONNEL
SUBJECT MATTER:
NOX control technology summary for large boilers.
His work consists of a summarizing of report info previously
reported. In his opinion, burner and furnace designs are
the feasible alternatives, with flue gas cleanup not a feasible
method due to the lack of complete analysis.
Hall & Lachapelle studies are his main sources of info.
C-55
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS x
SOLID FUEL „
DATE: 4/21/76
PERSON CALLED Mr- Bi-Hig
ORGANIZATION; Henry Vogt Machine Co.
Address: Louisville. Kv.
TEL. NO. (502) 634-9411
GCA PERSONNEL MAC
SUBJECT MATTER:
Most of their boilers are heat recovery. They only manufacture about
2 waste wood boilers per year.
C-56
-------
JRSON CALLED.
8GANIZATION:_
Address:
EL. NO.
CA PERSONNEL
ABJECT MATTER:
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
OIL AND GAS
SOLID FUEL
X
DATE: 4/14/76
MR. SHERIDAN
U.S. BUREAU OF MINES, FUEL USE SECTION
WASHINGTON, D.C.
(202) 634-1026
TPM
General .discussion regarding availability of data on fuel
• <\J\, i Trk*!
used for irliiii lniiiiiiuL applications. Doesn't appear to be a lot.
C-57
-------
REPORT OF TELEPHONE CONVERSATION
RE: OIL AND GAS X
SOLID FUEL X
PERSON CALLED_
ORGANIZATION:_
Address:
WAYNE NOLAN
Wei 1-MrT.pan C.n .
Michigan Ci'rv. Tnrl
TEL. NO. 219-879-6561
GCA PERSONNEL MAC
SUBJECT MATTER:
DATE: 4/15/76
They do not manufacture any boilers larger than 8.4 x 10? Btu/hi
C-58
-------
CORRESPONDENCE
The following pages contain copies of all correspondence related to this
project.
C-59
-------
KE.WANEE, B°ILER
101 FRANKLIN STREET . KEWANEE, ILLINOIS . 61443 . (309) 853-3541
May 13, 1976
Ms Mary Anne Chi 11ingworth
GCA/Technology Division
Burlington Road
Bedford, MA 01730
Dear Ms Chi 11ingworth:
In response to your letter of April 21, 1976 seeking information
for EPA, we are returning the completed questionnaire.
If you have any further questions, please let me know.
)urs ve£y truly,
ffi.
"{,,
/G. M. Halley
Assistant Chief Engineer
Is
encs
C-60
-------
Company ;
Contact Person;
Telephone No. :
Location : (of
Title;
IL (
. ^5*3. 3$ 4t
Date; A//? y
/? ?6.
I. Current Production (in the Size Range 10-250 x 10 Btu/hr, domestic sales
only) :
A. Size Distribution: Total numbers or percentages:
Size
category
(MBtu's hr)
10-15
15-20
20-30
30-50
50-75
75-100
100-150
150-250
Residual
petroleum'
j
J
/$
&
3
\
J>o*J
Annual production of fuel type
Distillate
petroleum
i%
8
lo
>T ?k&i>a<
Gas
ts
S
II
'J2 i
Coal
—
—
—
/A//7
Other
solid fuel
— .
—
—
S /V Tf/£$
Combination
fired
/S
^ g
If
. **«
Total
units
3o
*3
&
B. Type Distribution:
Size
category
(MBtu's hr)
10-15
15-20
20-30
30-50
50-75
75-100
100-150
150-250
Residual petroleum
Fire
tube
IB
s
3
"i
Do
J
Water
tube
—
—
4r,
Other
_
—
tfAlLE
Distillate petroleum
Fire
tube
12
8
to
U»n
Water
tube
_
—
T /V
Other
.
—
TH&>
Gas
Fire
tube
fc
a
n
r &
Water
tube
*™^
—
lyqe
Other
—
— '
s.
C-61
-------
B. Type Distribution (continued)
Size
category
(MBtu's hr
Coal-fired
Fire
tube
Water
tube
Other
Other solid fuel
Fire
tube
Water
tube
Other
Combination fuel
Fire
tube
Water
tube
Other
10-15
15-20
20-30
30-50
50-75
100-150
150-250
\
7
C. Distribution by firing type:
Size
category
(MBtu's hr"1)
Residual petroleum
Fron
fired
Opposed
fired
Tangentlally
fired
Distillate petroleum
•in.*1 front
fired
Opposed
fired
Tangentially
fired
Gas
front
fired
Opposed
fired
Tangentally
fired
10-15
15-20
20-30
30-50
50-75
75-100
100-150
150-250
/2
9
to
C-62
-------
\Vf~
D. Burner configuration:
What type of atomization is used? (indicate size ranges)
' /yt;
o/c5
E. General discussion:
1. What proportion of product line is packaged and field erected?
(Indicate size ranges and fuels)
/s
2. Is equipment of a standard design or custom built?
If custom built, what factors are most critical in determining
the design configuration (e.g., customer preferences, variations
in fuel to be used, etc.)? iJ /JL
General statements regarding future production - consider fuels,
product demand as it relates to the overall economic posture,
new designs to be introduced, etc; by boiler size and type.
^&'
IS $Tfl£T/*fCi To fiAze A Co/yet/tOC £(J€" /A/
Sties dp &&ft-££ THAT t*>& Ska ov(£
&*/ 5tiw*/ lu '
fitt) DUCTS fa Fv€C
ere).
, )t
C-63
-------
II. Emissions Characteristics:
1. Have you analyzed emissions for particulates , SO^, NO , CO and hydro-
carbons? ye^ ~ $M&/&lr/c/£>Ar£^^$$G(is e-#A. &b»fofrj>
results: (please^naicat'e/'bo'iler*'size, fuel-fired, firing design)
? EPfl-&$o/2 - 74 -07? -a.
Ace, fotL£& Pig&To&e &MIPT f^a^r Ft&&t SCOTCH Dewpt -
2. Are you conducting research programs on design features to reduce
pollution emissions?
please indicate general areas of research and problems in the
trade-offs between emissions control and efficiency,1 safety, etc.
QF
®
HOST iMPweH£*tf" /A/
G/t, Jtob
'Cot?.
3. Is equipment certified to meet emission performance criteria - if
so by whom (ASME, Manufactures guarantee, etc)?
4. Is pollution control equipment available/necessary to meet specified
emissions criteria? What types of pollution control equipment do
you recommend with your boilers?
o
C-64
-------
5. Comments:
E.?A
C-65
-------
G^CA/TECHNOLOGY DIVISION
May 27, 1976
Delaware Department of Natural Resources
and Environmental Control
Tatnall Building, Capitol Complex
Dover, Delaware 19901
Dear Sir:
For the successful completion of two projects under EPA Contract No.
68-02-1316, T.O. No. 22, "Screening Study to Obtain Information Necessary
for the Development of Standards of the Performance for Oil-Fired and
Natural Gas-Fired Boilers" and T.O. No. 19 (under the same contract num-
ber), "Screening Study to Obtain Information Necessary for the Development
of Standards of the Performance for Solid Fuel-Fired Boilers," we need
basic data about boilers in the range 10 x 10^ - 250 x 106 Btu/hour heat
input and with controlled emissions.
According to our information, this data may be obtained from applica-
tions for boiler permits which may include control equipment data and
stack and other egress data. We would greatly appreciate your sending us
copies of these above-mentioned forms covering the following boilers:
NAME OF COMPANY CONTROL DEVICE
City of Dover Cyclone A V^
Dover, Delaware 300,000 ACFM "^
We would also appreciate your sending us copies of the same form for
one or two boilers, arbitrarily chosen by you, with uncontrolled emissions,
operating in your state.
If you have any questions, please contact me at tel. no. 617-275-9000,
ext. 372, for more information.
Thank you for your kind cooperation.
Sincerely yours,
V.Hampl
C-66
BURLINGTON ROAD. Bf DFORD. MASSACHUSETTS 01730 / PHONE 617-275-9000
-------
STATE OF DELAWARE
DEPARTMENT OF NATURAL RESOURCES AND ENVIRONMENTAL CONTROL
Dover, Delaware 19901
J hn C Bryson Division of Environmental Control
Secretary ' N-c- Vasuki, Director
June 4, 1976
Mr. V. Hampl
GCA Technology Division
Burlington Road
Bedford, Massachusetts 01730
Dear Mr. Hampl:
In accordance with your letter dated May 27, 1976 and your telephone
conversation with Herman Hastings on June 3, 1976, we are pleased to furnish
you the attached information relative to the City of Dover Power Plant.
If we can assist you further please let us know.
Sincerely yours,
Robert R. French, P.E.
Manager
Air Resources Section
RRF:HHH:Kek
Enclosure
C-67
-------
CITY OF DOVER POWER STATION
23
Unit Boiler Mfg.
I3 B & W
B & W
Fuel
#6 oil
#6 oil
Boiler Capacity
BTU/Hr. Input1'
200 x 106
200 x 106
Flue Gas
Flow Rate, ACFM
53.7501
53.7501
Partlculate
Emissions, Ib/MM BTU
0.1282
0.128'
Stack Data
Particulate
Device Eff., Percent El. Dia.
85
85
175'
175'
8.0'
8.0'
Stack Gas
Temp.°F
310
310
n
oo
Riley Stoker #6 oil 1,125 x 106
325,OOO1
0.04"
85
175'
10.5'
300
1. Computed full load (20% excess air & 300°F)
2. After cyclones, verified by stack test
3. Units 1 & 2 have common stack
4. Not verified by stack test
-------
3CA/TECHNOL6GY DIVISION
May 27, 1976
Division of Air Pollution
Kentucky Department for Natural Resources
and Environmental Protection
Capital Plaza Tower
Frankfurt, Ky. 40601
Dear Sir:
For the successful completion of two projects under EPA Contract No.
68-02-1316, T.O. No. 22, "Screening Study to Obtain Information Necessary
for the Development of Standards of the Performance for Oil-Fired and
Natural Gas-Fired Boilers" and T.O. No. 19 (under the same contract num-
ber), "Screening Study to Obtain Information Necessary for the Development
of Standards of the Performance for Solid Fuel-Fired Boilers," we need
basic data about boilers in the range 10 x 106 --250 x 106 Btu/hour heat
input and with controlled emissions.
According to our information, this data may be obtained from applica-
tions for boiler permits which may include control equipment data and
stack and other egress data. We would greatly appreciate your sending us
copies of these above-mentioned forms covering the following boilers:
NAME OF COMPANY CONTROL DEVICE
Olin Chemicals Co. Cyclone
Brandenburg, Ky. 85,000 ACFM
Air Reduction Co. Cyclone
Calvert City, Ky. 100,000 ACFM
We would also appreciate your sending us copies of the same form for
one or two boilers, arbitrarily chosen by you, with uncontrolled emissions,
operating in your state.
If you have any questions, please contact me at tel. no. 617-275-9000,
ext. 372, for more information.
Thank you for your kind cooperation.
Sincerely yours,
V.Hampl
C-69
BURLINGTON ROAD, BEDFORD, MASSACHUSETTS 01730 / PHONE, 617-275-9000
-------
SECRETARY
r, L j- n D~II H* ffm "H JULIAN M.CARROLL
RohertD. Bell Wt If v» 6QVEBM0.
COMMONWEALTH OF KENTUCKY
DEPARTMENT FOR NATURAL RESOURCES AND ENVIRONMENTAL PROTECTION
BUREAU OF ENVIRONMENTAL QUALITY
Frank L. Stanonis
COMMISSIONER
FRANKFORT, KENTUCKY tosoi
June 3, 1976
GCA/Technology Division
Burlington Road
Bedford, Massachussetts 01730
Attention: Vladimir Hampl
Dear Sir:
As you requested in your letter dated May 27, 1976, I have
enclosed copies of the information you requested on the 01 in Chemicals
Company at Brandenburg, Kentucky and the Air Reduction Company at
Calvert City. Specifically, the copies of the Registration Forms
submitted by the 01 in Chemicals Company reflect the installation of
electrostatic precipitators on their boilers and their most recent
schedule of operation. Likewise, the attached copy of a letter dated
April 2, 1971 reflects a change in ownership of the Air Reduction Company.
Secondly, as you requested, I have enclosed copies of boiler application
forms submitted by the Kentucky State Penitentiary at Eddyville and the
Western Kentucky University at Bowling Green. When in use, these boilers
operate uncontrolled.
If you have any questions or if I may be of further assistance, please
feel free to contact me.
Sincerely,
James W. Dills
Engineering and Permits Program
Division of Air Pollution Control
JWD:cbo
Enclosures
C-70
-------
CALVERT. ClY-PLANT
\ P. O. Box 97, Calvert City, Kentucky 42029 • Telephone 502 395-4181
April 2, 1971
Mr. Clyde P. Baldwin, P.E.
Principal Sanitary Engineer
Water Pollution Control Commission
275 East Main Street
Frankfort, Kentucky 40601
Dear Mr. Baldwin:
The chemical facilities at Calvert City previously owned by
Air Reduction Co., Inc., and operated as part of their Chemicals
and Plastics Division has been purchased by Air Products and
Chemicals, Inc., Allentown, Pennsylvania, and is being operated
as a segment of their Chemicals Group.
In accordance with the information you so kindly supplied to
me with your letter of January 25 regarding our need to file
a "Permit Application for Air Contaminant Source," we herewith
submit the required information in the name of Air Products
and Chemicals, Inc., Chemicals Group, Calvert City Plant. A
list of attachments follows this letter.
May I ask you to forward this packet to the proper person in
Frankfort to whom this application should be submitted. Our
application has been executed by Mr. T. L. Carey, a Vice Presi-
dent of Air Products and Chemicals, Inc.
I trust all of the attached is properly prepared. It is accurate
to the best of our knowledge and capabilities of deducing. Should
there be any further information required, you may reach me at
this location.
Again, many thanks for your help.
Very truly yours,
AIR PRODUCT AND CHEMICALS, INC.
Howard L. Watson
Works Manager
HLW:al
Attachments C-71
-------
KENTUCKY AIR POLLUTION CONTROL COMMISSION
275 East Main Street
Frankfort, Kentucky 40601
PERMIT APPLICATION FOR AIR CONTAMINANT SOURCE
ADMINISTRATIVE INFORMATION
The completion and return of this form is required under Regulation No. AP - 1, Section 5, Permit to Construct and Operate
an Air Contaminant Source, pursuant to the Kentucky Air Pollution Control Law. Applications are incomplete unless ac-
companied by copies of all plans, specifications and drawings. Failure to supply information required or deemed necessary
by the Commission to enable it to act upon the Permit Application shall result in denial of the permit.
1. Name of Firm or Institution: Air Products and Chemicals, Inc,
Street
City
Calvert City
City
Calvert City
County
County
Zip
42029
Marshall
Zip
42029
2. Mailing Address:
Number
P.O. Box 97
3. Facility Location:
Number Street
Off State Highway 95
4. Previous Registration or Identification Number:
5: General Nature of Business: SIC 281
6. Type of Permit Required:
Pursuant to the provisions of Regulation No. AP—1, Section 5 of the Kentucky Air Pollution Control Commission,
and
application is hereby made for authority to construct -JL__ W operate X an air contaminant source.
7. Estimated cost of equipment or of alteration.
Total Facility ^6irtjt^i^NaM^«ria^yKV^p^^qy^^vytp'^^^'^»ytftqi«ffy^f ^ 3, 500,000
Air Pollution Control Equipment existing as of date of application
New Air Pollution Control Equipment to be installed.
Modification to existing Air Pollution Control Equipment
3. Present status of equipment: (Check and complete applicable items)
(a) Construction started (Date)
(b) Equipment to be njtcbfted constructed
Basic Equipment fyl
Air Pollution Control Equipment f^]
$ New installation
95/000
C-72
APC 110 (Rev. 10/72)
-------
AIR POLLUTION CONTROL COMMISSIC
275 Eost Main Street
Frankfort, Kentucky 40601
INDIRECT HEAT EXCHANGER
Point of Emission Number
1. A completed form (No. APC 110A) shall be submitted for each individual unit. The following types of units are exempted
from this portion of the application:
. A. Indirect heat exchangers used solely for heating residential buildings not exceeding a total pf six
apartment units;
_ B. New installations with a capacity of less than 1 million BTU per hour input;
. C. New installations using natural or liquified petroleum gas, including those having distillate fuel oil
as standby fuel with a capacity of less than 50 million BTU per hour input;
D. Marine installations and locomotives;
E. Internal combustion engines and vehicles used for transportation of passengers or freight.
If your indirect heat exchanger is in one of the above categories'please check that category and disregard the remaining
portions of APC-110A.
New installations are those for which construction commenced after April 9, 1972.
2. Type of Unit Coal-fired steam boiler A. Manufacturer's Name Babcock and Wilcox Co.
Two-drum Stirling-S-55
B. Manufocturer's Model Number Kn, Tfi^-lR'-n" C. Date Installed 1959
3. Rated Capactiy-lnput (BTU/Hr.) 213,405,000 _
4. Type of Combustion Unit (Coal) With fly ash reinjection _ Without fly ash reinjection — X after revision
A. Pulverized C. Stoker-fired
Dry Bottom _ Spreader Stoker x
Wet Bottom _ Other Stoker _
B. Cyclone _ D. Hand-fired
E. Other (Specify)
5. Type of Combustion Unit (oil)
A. Tangentially-fired
B. Horizontally—fired
Type of Combustion Unit (Wood)
With fly ash reinjection Without fly ash reinjection
A. Pile
B. Thin Bed
C. Cyclonic
C-73 APC 110A (Rev. 10/72)
-------
IN ECT HEAT EXCHANGER (CONT'D)
10. Purpose (If multipurpose, describe percent in each use category)
Space Heat < 5%
Process Heat > 95%
Power 0
11. Type of Control Equipment Control Efficiency Basis of Estimate
Participates S02 Other (Specify)
12. Stack
.Electrostatic Precipitator
_Cyclone
-Multiple Cyclone
.Wet Scrubber
.Settling Chamber '
_Other (Specify) 93% Manufacturer Warranty
Dust Collector
A. Outlet temperature _45Q °F
B. Outlet velocity 2fi ft/sec maximum
C. Height 100 feet
D. Inside diameter (outlet) ^__1QJ?_ inches
E. Number of sampling ports provided 4 below induced draft fan
F. Nearest distance from sampling port downstream to stack outlet, bend or obstruction feet
G. Nearest distance from sampling port upstream to bend or obstruction feet
H. List other sources vented to this stack
13. Combustion air: Natural draft Inrlueefl
Forced pressure ___2JJS__ tasx&septax in. HO
Excess air (total air supplied in excess of theoretical air required) 28 %
14. Describe fuel transport, storage methods and related dust control measures.
Unloaded from bottom of rail car to belt conveyor to bucket elevator to silo over stoker.
15. Describe fly ash (or other collected air contaminants) disposal, transportation methods and related dust control measures.
Air conveyed to separators and scrubber over storage silo. Loaded wet into trucks and
transported to industrial landfill.
16. Attach manufacturer's literature and guaranteed performance data for the indirect heat exchanger and air pollution control
equipment. Include information concerning fuel input, burners and combustion chamber dimensions.
Refer to operating permit issued January 14, 1972.
C-74 APC 110A(Rev. 10/72)
-------
"H
7. Type "and Quantity of Fuel (List both primary and standby):
i u;
BTU per Unit** Lb.
Percent Ash* Percent Sulfur* (specify units)
Type of Fuel
Coal
Fuel Oil
1,2,4,5,6,
(Circle One)
Natural Gas
Propane
Butane
Wood
Other
Min.
6.0
Max.
7.5
Avg.
6.7
Min.
2.5
Max.
3.5
Avg.
3.0
Min.
12,000
Max.
13,OOC
Avg.
12,30C
Type of Fuel
Units
Qty.
Per 1972 CONSUMPTION
Yr. Jon. Feb. Mor. Apr. May June July Aug. Sept. Oct. Nov. Dec.
Coal Tons 33
Fuel Oil
1,2,4,5,6 Gallons
(circle one)
Natural Gas MCF
(103CU. ft.)
Propane Gallons
Butane Gallons
Wood Tons
OtUr
,100
3500
2700
3000
1500
•
0
3500
5000
2500
2500
2700
3000
3200
8 FIIA! <^urrp Peabody Coal Company, Island Creek Coal Company
Normal Operating Schedule:
48-50 Weeks per year, 7_
. Days per week, 24
Hours per day
* As received basis. (Proximate analysis for ash, ultimate analysis for sulfur)
Higher heating value.
C-75
APC 110A (Rev. 10/72)
-------
NATURAL RESOURCES AND ENVlKUNMtWAL
Division of Air Pollution
REGISTRATION OF AIR CONTAMINANT SOURCE
Section I - General Information
PLEASE READ INSTRUCTIONS ON REVERSE SIDE BEFORE FILLING OUT FORMS
1, SOURCE NAME Olln Corporation, Doe Run Plant
2,
3,
MAILING ADDRESS
P. 0. Box 547
(street or box number)
LOCATION Three miles east of Brandenburg on Highway 933
Brandenburg, Ky. 40108
(city) -(state) (zip)
I], CONTACT Jerry R. Perrich
Telephone (502J .422-J101
5, UTM Coordinates: Zone 16
(county)
Title Environmental Engineer
or Latitude
Horizontal Cbn) _77 _ *
_ Longtitude
Vertical 65
or(accurate directions)
"The making of this report Is done under
governmental ooiapulcion and doea not
6,
7,
8,
NUMBER OF EMPLOYEES 500
LAND AREA AT SOURCE LOCATION 1642.7
PRINCIPAL PRODUCTS Organic Chemicals
constitute any waiver of a legal privilege
against self-incriminatlon; and the report-
ing corporation and the individual signing
this report each reserves the right to objeciw
to ji-<- use or admissibility in whole or In
*,j\ any subssouent proceeding against
the rc-^ortir.g corporation and/or tb»
individual signing this report".
9, The information contained in this report is representative of calendar year 1976
Signed CT\ . £?. (J^v^-A^t^; Title Plant Manager
OFICE USE ONLY
DATE RECEIVED
LOG NO. R
ID NUMBER
NUMBER OF EMISSION POINTS
COMPLIANCE STATUS:
EMISSIONS
PART
POTENTIAL
ACTUAL
[ALLOWABLE
S02
C-76
HC
CO
OTHER
-------
KENTUCKY DEPARTMENT FOR NATURAL RESOURCES
AMI ENVIRONMENTAL PKOUCTION
Division of Air Pollution
REGISTRATION OF AIR CO'IWINANT SOURCE
SECTJOV II - Fuel Combustion for Heat, Steam and Power Generation
24
gnu) operating schedule for fuel use:
gtes of annually occurring shutdowns of operations:
IOTA
Hours per day
Varies
Days per week 52 Hecks per year 8760 Hours per year
. Additional operating Information enclosed
Source a
' Code
01-02
03
04
! 05
Number of
Combustion
Sources °
(Boilers)
3'
1
1
1
Sire of
Unit (Input) c
10* BTU/hr.
112 ea
217
217
217
Type of Unit rf
Gas fired
Each; pulverized
Coal, dry bottom
Without flv ash reject!
Installation
Date «
1950
1960
1962
m 1968
Percent Excess
Air Used In
Combustion
(Design)
20%
22%
22%
22%
Power Output
Megawatts 5
—
_
_
WTB
•I
(Source
r*
.1?
02 J
03
04
05
Type
of 9
Fuel
Gas l
•
Coal3
Total ANNUAL CONSUMPTION h
quantity *•
2
51,000
200,000
Percent Distribution by Season
SPRING
March/
May
25
25
SUMMER
June/
Aug.
25
25
FhLL
Sept./
Nov.
25
25
WINTER
Dec./
Febr.
25
25
HOURLY CONSUMPTION *•
Maximum
-
-
Average
187
21,7
Percent
Used for
Space Heat
2%
2%
Heat
Content .
BTU/Quan. 1
21
1000/cuf
12,400/tf
Percent
Ash (Solid .
Fuel Only) fe
t
6-10%
Delivered
Cost of
Fuel
S/Quantity
-
-
Future
Use *
Same
Same
Residue gas, infrequently supplemented w
"The leaking of this r»port Is done under
i^H/efftftWil-conipulslon and does not
. 2. Nominal values. constitute any waiver of a legal privilege
's*t reverse side for footnote explanation. against self -incrimination ; and the report -
Number 11 seam, Western Ky. coal, washed.1?* Corporation and the individual signing
, j » ^hls report caoh regerveB the rlght to obje<
3.
o/0
o
%
£1
C-77
report caoh regerveB the rlght
to its use or admlsslbility in whole or in
part, In any subsequent proceeding against
't^e roporting corporation and/or the
individual signing -this report".
-------
-constitute-any _
against self-incrlmlnatl-onr: and the report
ing corporation and the individual signing
each reserves the right to
SECT ,OH V.-A.R CLEAN
the reporting corporation and/or the
Individual signing this report11-
Source
Code3
03
04
05
03
04
05
Type of Air
Cleaning Equipment
-------
DEPARTMENT FOR
NATURAL RESOURCES AND ' Log # X
ENVIRONMENTAL PROTECTION
DIVISION OF AIR POLLUTION
FRANKFORT, KENTUCKY 40601
INDIRECT HEAT EXCHANGER . .
/
Point of Emission Number '
1. A completed form (No. ARC 110A) shall be submitted for each individual unit. The following types of units are exempted
from this portion of the application:
A. Indirect heat exchangers used solely for heating residential buildings not exceeding a total of six
apartment units;
B. New installations with a capacity of less than 1 million BTU per hour input;
C- New installations using natural or liquified petroleum gas, including those having distillate fuel oil
as standby fuel with a capacity of less than 50 million cVTU per hour input;
D. Marine installations and locomotives;
r E. Internal combustion engines and vehicles used for transportation of passengers or freight.
If your indirect heat exchanger is in one of the above categories please check that category
and complete only items 7, 8, 9.
New installations are those for which construction commenced after April 9, 1972.
'2. Type of UnityfTZra^ £UT- Jt-r**** &*//** A. Manufacturer's Name &&/£' &" £•* S?S7$~
' n U/,«..f«r*..w'.U.^«l N..mk«, VZ. Z£-7.o-/£ CL Dote Inttalled
3. Rated Capactiy-lnput (BTU/Hr.) //fZfMSTU. W4*»** Z*>*2. & * ¥%%**.&?,
<. Type of Combustion Unit (Cocl) With fly ash reinjection Without fly ash reinjection
A. Pulverized C. Stoker-fired
Dry Bottom Spreader Stoker
Wet Bottom Other Stoker _
_. ^ Hand-fired -
E. Other (Specify)
I. Typo-of Combustion Unit (oil)
A. Tcngentially-fired _____
3. Horirontclly-fir«>d - ,
& Type of Combustion Unit (Wood) •> _, .-.^ I//
F^l€,ftAife \'Qf
Y/ith fly osh reinjection . Without fly ash reinfection ^
i, Pile
C-79
APC '.I'j/^i'^v. 'iOr
-------
DEPARTMENT FOR
NATURAL RESOURCES AND Log # '
ENVIRONMENTAL PROTECTION
DIVISION OF AIR POLLUTION
FRANKFORT, KENTUCKY 40601
INDIRECT HEAT EXCHANGER
Point ol Emission Number
1. A completed form (No. APC 110A) shall be submitted for each individual unit* The following typos of units ore exempted
.•from this portion of the application:
A, Indirect heat exchangers used solely for heating residential buildings not exceeding a total of six
apartment units;
__________ B. New installations with a capacity of less than 1 million BTU per hour input;
C. New installations using natural or liquified petroleum ga#, including those having distillate fuel oil
as standby fuel with a capacity of less than 50 million BTU per hour input;
D. Marine installations and locomotives;
r E. Internal combustion engines ond vehicles used for transportation of passengers or freight.
If your indirect heat exchanger is in one of the above categories please check that categc
and complete only items 7, 8, 9.
New installations are those for which construction commenced after April 9, 1972.
2, Type of Unit ^Tf^/ OsT J^Vfiw gy
-------
DEPARTMENT HOR
NATURAL. RESOURCES AND Log #
ENVIRONMENTAL PROTECTION '
DIVISION OF AIR POLLUTION
FRANKFORT, KENTUCKY 40601
INDIRECT HEAT EXCHANGER
Point of Emission Number
|. A completed form (No. ARC 110A) shall be submitted for ecch individual unit. The following types of units or« exempted
from this portion of the application:
,_ - - A. Indirect heat exchangers used solely for heating residential buildings not exceeding a total of six
apartment units;
B. New installations with a capacity of less than 1 million BTU per hour input;
C. New installations using natural or liquified petroleum gas, including those having distillate fuel oil
as standby fuel with a capacity of less than 50 million BTU per hour input;
D. Marine installations and locomotives;
L E. Internal combustion engines and vehicles used for transportation of passengers or freight.
If your indirect heat exchanger is in one of the above categories please check that category
and complete only items 7, 8, 9.
New installations are those for which construction commenced after April 9, 197Z
2. Type of Unit JM.ICfc &T 3 DRUM fVT SrtrHftf' ^ Manufacturer's Name tf**/A M>
' B. Manufacturer's Model Number \ll- **(.(. C Dote Installed
7
3. Rated Capactiy-lnput (BTU/Hr.) Z.^1^Z WETU //»* #tl +-
4. Type of Combustion Unit (Cocl) With fly ash reinfection Without fly ash roinjection *^
A. Pulverized C. Stoker-fired ^x-l
Dry Bottom Spreader Stoker «*xX^ 3 4S*tff >
Wet Bottom Oth«»r Stoker
B. Cyclone D. Hand-fired
E. Other (Specify)
5. Type of Combustion Unit (oil)
A. Tongentially-firod _ _
B. Horiiontollv-fired -
6. Type of Combustion Unit (Wood) T ^ J«7 fj P V / - *>$4 UP X ?4.5*
A. PH. __
B. Thin B«d - Z f 7fZ Kt BTtj
C. Cyclor.ic -
C-81
ARC 1 IDA (Rov. 10/72)
-------
INDIRECT HEAT EXCHANGER (CONT'D)
Log #
7. Type and Quantity of Fuel (List both primary and standby):
Percent Sulfur*
_ Type of Fuel
BTU per Unit**
(specify units)
Percent Ash*
Min. Max. Avg. Min. Max. Avg. Min. Max. Avg.
1,2,4,5,6,
(Circle One)
Natural Gas
Propone
Butane
Wood
f
/o
7-r
'*•
<
3
I7ooo
•»
**•
r 4(100,000
T&OA/O
err:
Type of Fuel Units
Fuel Oil
1 ") A •> A ftnllnn«
(circle one)
•Natural Gas UCF
(103 cu. ft.)
Propane Gallons
Butane Gallons
Wood Tens
Ottier
8. Fu-l Sftnrr. /Sldli
*. \\ nfcl Opercting Schedule:
V C. . WMfc« nmr vaar
Qty.
Per
Yr.
ta
*/ft
Jan.
tec
fa
~?
Feb.
*/
^STC
3ays pe
Mar.
\*
^^
^
r week.
Apr.
*ff
2
May
/~
4
June
/CO
Hours c
July
/~
t(Q
er day
Aug.
„•
Sept.
/CO
Oct.
*
Nov.
ZOO
De.
v!
•
- * 3
*>*/+# &rp.
;>.t receiveJ basis, (Prcx'tfat* analysis for ajh, ultimate analysis for sulfur)
** Uiiiher heeting voluo.
C-82
-------
INDIRECT HEAT EXCHANGER (COMT'D)
Log #
I. Purpose (If multipurpose, describe percent in each us* category)
Space Heal
Process Heat
Power
I. Type of Control Equipment Control Efficiency Bosit of Estimate
Pcrticulotes SOj Other (Specify)
Electrostatic Procipitator
Cyclone
.Multiple Cyclone
Wet Scrubber
Settling Chamber
Other (Specify)
2. Stock
• A. Outlet temperature *l *** _ *F
B. Outlet velocity^ _ ft/sec
C. Height _/5_0_ feet /
D. Inside diameter (outlet) —£&. _ inches
E. Number of sampling ports provided
F. Nearest distance from sampling port downstream to stack outlet, bend or obstruction _ feet
G. Nearest distance from sampling port upstream to bend or obstruction - feet
H. Lir- other sources vented to this stack
3,. Combustion air: Natural draft ***<^ Induced
Forced pressure / M)£ lk«Vgg. in. -,
Excess air (total air supplied in excess of theoretical air required) ^ ^
Describe fuel transport, storage methods and related dust control measures.
r£jp
>•• Describe fly ash (or other collected air contaminant*) disposal, transportation methods and related dust control measures.
Attach monufacturw's literature and guaranteed performance data for the indirect heat exchanger and air pollution control
equipment. Include information concerning fuel input, burners and combustion chamber dimensions.
C-83
(K»V. 10/72}
-------
275 East Main Street
Frankfort, Kentucky 40601
INDIRECT HEAT EXCHANGER
OOt*)l> W
I
/^7
. . M ,
Point of Emission Number
Boiler #1
Coal Onlv
1. A completed form (No. ARC 110A) shall be submitted for each individual unit. The following types of units are exempted
from this portion of the application:
_ A. Indirect heat exchangers used solely for heating residential buildings not exceeding a total of six
apartment units;
_ B. New installations with a capacity of less than 1 million BTU per hour input;
_ C. New installations using natural or liquified petroleum gas, including those having distillate fuel oil
as standby fuel with a capacity of less than 50 million BTU per hour input;
_ D. Marine installations and locomotives;
_ E. Internal combustion engines and vehicles used for transportation of passengers or freight.
If your indirect heat exchanger is in oneof the above categories please check that category and disregard the remaining
portions of APC-110A.
New installations are those for which construction commenced after April 9, 1972.
2. Type of Unit Hater tube (two drum) _ A. Manufacturer's Name Unknown _
B. Manufacturer' s Model Number JJnknQWn
3. Rated Capactiy-lnput (BTU/Hr.)
404- BAA, p
C. Date Installed
1 927
4. Type of Combustion Unit (Coal) With fly ash reinjection
A. Pulverized
Dry Bottom
Wet Bottom
Without fly ash reinjection
' B, (/
~~^ (
B. Cyclone
C. Stoker-fired
Spreader Stoker __
Other Stoker JLChain grate
D. Hand-fired _
E. Other (Specify)
5. Type of Combustion Unit (oil)
A. Tangentially—fired
B. Horizontally-fired X
6. Type of Combustion Unit (Wood)
V/ith fly ash reinjection
Without fly ash reinjection "
A. Pile
B. Thin Bed JL
C. Cyclonic
C-64
APC 110 A (Rev. 10/72)
-------
7. Type and Quantity of Fuel (List both primary and standby):
Percent Ash*
Percent Sulfur*
BTU per Unit*
(specify units)
ype of rue]
Coal
Fuel Oil
1,2,4,5,6,
(Circle One)
Natural Gas
Propane
Butane
Wood
Otn^r
Min.
Max.
Avg.
6.50
Min.
Max.
Avg.
3.50
Min.
Max.
Avg.
12.648
Qty.
Per
Type of Fuel Units Yr. .Ion. Feb. Mar. Apr. May June July Aug. Sept. Oct. Nov. Dec.
Coal Tons
Fuel Oil
1,2,4,5,6 Gallons
(circle one)
Natural Gas MCF
(K)3cu. ft.)
Propane Gallons
Butane Gallons
Wood Tons
Oth ^r
Eme»
oil
gency
suppl
opera
V.
tion
anly;
fuel
burne
1 con
:inger
t on r
atura
1 gas
and
8. Fuel Source
Coal
9. Normal Operating Schedule: Emergency Only
Weeks per year, Days per week,
.Hours per day
* As received basis. (Proximate analysis for ash, ultimate analysis for sulfur)
** Higher heating value.
C-85
APC 110A(Rev. 10/72)
-------
10. Purpose (If multipurpose, describe percent in each use category)
Space HOOT 100%
Process Heat
Power ——
11. Type of Control Equipment Control Efficiency Basis of Estimate
Particulates SC>2 Other (Specify)
12. Stock
_ Electrostatic Precipitator
_ Cyclone
_Multiple Cyclone
.V/et Scrubber
_ Settling Chamber
_Other (Specify)
A. Outlet temperature ' °F
B. Outlet velocity O/3. ft/sec
C. Height 130 feet
D. Inside diameter (outlet) 60_jnches
E. Number of sampling ports provided n/3
F. Nearest distance from sampling port downstream to stack outlet, bend or obstruction
G. Nearest distance from sampling port upstream to bend or obstruction feet
H. List other sources vented to this stack Boiler #2 and #3
13. Combustion air: Natural draft Induced
Forced pressure Ibs./sq.in.
Excess air (total air supplied in excess of theoretical air required)
14. Describe fuel transport, storage methods and related dust control measures.
Truck to coal hopper with elevators to bunkers (oil treated coal)
15. Describe fly ash (or other collected air contaminants) disposal, transportation methods and related dust control measures,
Ash collector, steam inspection/no dust control
16. Attach manufacturer's literature and guaranteed performance data for the indirect heat exchanger and air pollution control
equipment. Include information concerning fuel input, burners and combustion chamber dimensions.
n/a
C 86 APC 110A(Rev. 10/72)
-------
Boiler #2
Coal and Natural Gas
275 East Wair, Sircci
Frankfort, Kentucky 40601
INDIRECT HEAT EXCHANGER
Point of Emission Number
1. A completed form (No. APC 110A) shall be submitted for each individual unit. The following types of units ore exempted
from this portion of the application'
.A. Indirect heat exchangers used solely for heating residential buildings not exceeding a total of six
apartment units;
I
.3. New installations with a capacity of less than 1 million BTU per hour input;
. C. New installations using natural or liquified petroleum gas, including those having distillate fuel oil
as standby fuel with a capacity of less than 50 million BTU per hour input;
. D. Marine installations and locomotives;
. E. Internal combustion engines and vehicles used for transportation of passengers or freight.
if your indirect heat exchanger is in oneof the above categories please check that category and disregard the remaining
portions of APC- 110A.
New installations are those for which construction commenced after April 9, 1972.
2. Type of Unit water tube (two drum)
B. Manufacturer's Model Number EP-18 #32
A. Manufacturer's Name
B & W
C. D0finStoii«J948 (Gas sidewall burners, 1971)
3. Rated Capactiy-lnput (BTU/Hr.) 73,611.100
4. Type of Combustion Unit (Coal) With fly ash reinjection
A. Pulverized
Dry Bottom
Wet Bottom
B. Cyclone
5. Type of Combustion Unit (oil)
A. Tangentially— fired
B. Horizontally-fired
Without fly ash reinjection
C. Stoker-fired
Spreader Stoker 4 -
Other StokerXJfifTn grate
D. Hand-fired
E. Other (Specify)
6. Type of Combustion Unit (Wood)
With fly ash reinjection -
A. Pile _
B. Thin Bed _X - .
C. Cyclonic _ - .
Without fly ash reinjection
C-87
APC 110A(Rov. 10/72)
-------
7. Type and Quantity of Fuel (List both primary and standby):
Percent Ash* .
Percent Sulfur*
BTU per Unit*
(specify units)
"y?e of Fuel
Cool
Fuel Oil
1,2,4,5,6,
(Circle One)
Natural Gas
Propone
Butane
V/ood
Otnir
Min.
Max.
Avg.
6.50
Min.
Max.
Avg.
3.50
Min.
Max.
Avg.
2.648
Qty.
Per
Type of Fuel Units Yr. Jan. Feb. Mar. Apr. May June July Aug. Sept. Oct. Nov.
Coal Tons
Fuel Oil
1,2,4,5,6 Gallons
(circle one)
Natural Gas MCF
(103 cu. ft.)
Propane Gallons
Butane Gallons
V/ood Tons
Eme
gas
rgenc
and <
' oper
111 SU
Jtion
-
K. Fno| Coal with auxiliary nas side wal
only
— .fu
1 burners
el bur
ned c
Installpfi 1
ontingent o
cm
i nati
ral
9. Normal Operating Schedule: Emergency Only
ri/3 Y/eeks per year, n/9 Days per week, H/fl Hours per day
* As received basis. (Proximate analysis for ash, ultimate analysis for sulfur)
** Higher heating valuo.
C-88
ADr~ 11n A /o
'0/72)
-------
10. Purpose (If multipurpose, describe percent in each use category)
Space Heat __A
Process Heat ^_
Power
il« Type of Control Equipment Control Efficiency Basis of Estimate
Particulates SC Other (Specify)
.Electrostatic Precipitator
.Cyclone
.Multiple Cyclone
.Vi'et Scrubber
_ Settling Chamber
.Other (Specify)
12. Stack
A. Outlet temperature n/d ,°F
B. Outlet velocity n/3 ft/sec
C. Height 130 feet
D. Inside diameter (outlet) 60 inches
E; Number of sampling ports provided lyfl
F. Nearest distance from sampling port downstream to stack outlet, bend or obstruction feet
G. Nearest distance from sampling port upstream to bend or obstruction feet
H. List other sources vented to this stack
13. Combustion air: Natural draft Induced X_
Forced pressure Ibs./sq.in.
Excess air (total air supplied in excess of theoretical air required)
14. Describe fuel transport, storage methods and related dust control measures.
Truck to coal hoppers with elevators to bunker/oil treated
15. Describe fly ash (or other collected air contaminants) disposal, transportation methods and related dust control measures.
Ash collector/steam inspection/no dust control
16. Attach manufacturer's literature and guaranteed performance data for the indirect heat exchanger and air pollution control
equipment. Include information concerning fuel input, burners ana' combustion chamber dimensions.
n/a
C-89
APC 110A(Rev. 10/72)
-------
275 East Main Street
Frankfort, Kentucky 40601
Boiler #3
Coal and Natural Gas INDIRECT HEAT EXCHANGER
Point of Emission Number .
1. A completed form (No. APC 110A) shall be submitted for each individual unit. The following types of units are exomptf
from this portion of the application;
__ A. Indirect heat exchangers used solely for heating residential buildings not exceeding a total of six
apartment units;
B. New installations with a capacity of less than 1 million BTU per hour input;
_ C. New instoiiations using nctural or liquified petroleum gas, including those having distillate fuel oil
as standby fuel with a capacity of less than 50 miilipn B I U per hour input;
D. Marine installations and locomotives;
E. Internal combustion engines and vehicles used for transportation of passengers or freight.
If your indirect heat exchanger is in oneof the above categories please check that cotegory and disregard the remaining
portions of APC-110A.
New installations are those for which construction commenced after April 9, 1972.
2. Type of Unit Water tube (two drum) A. Manufacturer's Name Keeler ^_
B. Manufacturer's Model Number _I^J}£_JU£B _ C. Dote Instolledl 963 (gas sidpwall burners 1971)
3. Roted Copactiy-input (BTU/Hr.) 8
4. Type of Combustion Unit (Coal) With fly ash reinjection _ Without fly ash reinjection
A. Pulverized C. Stoker-fired
Dry Bottom _ Spreader Stoker
Wet Bottom Other Stoker X Chain grate
B. Cyclone D. Hand—fired
E. Other (Specify)
5. Type of Combustion Unit (oil)
A. Tongentially—fired
3. Horizontally-fired X
6. Type of Combustion Unit (Wood)
With fly ash reinjection Without fly ash reinjection
A. Pile
S. Thin Bed JL
C. Cyclonic
C-90
'- 72)
-------
7. Type and Quantity of Fuel (List both primary and standby):
Percent Ash* .
Percent Sulfur*
BTU per Unit*
(specify units)
Type of Fuel Min. Ma*. Ava. Min. Max. Ava. Min. Max. Ava.
?•**•
Coal
Fuel Oil
1,2,4,5,6,
(Circle One)
Natural Gas
Propane
Butane
Wood
Other _.
6.50
3.50
12.648
Qty.
Per
Type of Fuel Units Yr. Jan. Feb. Mar.
Coal Ton s
Fuel Oil
1,2,4,5,6 Gallons
(circle one)
Natural Gas MCF
(103Cu. ft.)
Propane Gallons
Butane Gallons
V/ood Tons
Other
En
ergen
s and
:y ope
oil s
ratiot
upply
only/fuel consimpticn con;ingen; on ratura
8. Fuel Source Coal with auxiliary gas si
hurnprt: i
197]
9. Normal Operating Schedule: Emergency Only
V/eeks per year, Days per week,
.Hours per day
* As received basis. (Proximate analysis for ash, ultimate analysis for sulfur)
* Higher heating value.
C-91
APC nOA(Rev. 10/72)
-------
10. Purpose (If multipurpose, describe percent in each use category)
Space Heat . <> ,
Process Heat
Power
11. Type of Control Equipment ' Control Efficiency Basis of Estimate
Particulates S02 Other (Specify)
.Electrostatic Precipitator
.Cyclone
.Multiple Cyclone
\*o- _V/et Scrubber
.Settling Chamber
12. Stack
_Other (Specify)
A. Outlet temperature M/a °F
3. Outlet velocity n/fl ft/sec
C. Height ___13£L_ feet
D. Insia'e a'iometer (outlet) 60— inches
Number of sampling ports provided
F. Nearest distance from sampling port downstream to stack outlet, bend or obstruction feet
G. Nearest distance from sampling port upstream to bend or obstruction feet
H. List other sources vented to this stack
13. Combustion air: Natural draft Induced A :
Forced pressure , Ibs./sq.in.
Excess air (total air supplied in excess of theoretical air required)
14. Describe fuel transport, storage methods and related dust control measures.
Truck to coal hopper with e-levators to bunkers, oil treated
15. Describe fly ash (or other collected air contaminants) disposal, transportation methods and related dust control measim
Ash collector/steam inspection/no dust control
16. Attach manufacturer's literature and guaranteed performance data for the indirect heat exchanger and air pollution contr
equipment. Include information concerning fuel input, burners and combustion chamber dimensions.
n/a
C-92
APC NOAfRov. 10/72)
-------
iCVTECHNOLOGY DIVISION ~ OA
May 27, 1976
Department of Natural and Economic Resources
Division of Environmental Management
P.O. Box 27687
Raleigh, N.C. 27611
Dear Sir:
For the successful completion of two projects under EPA Contract No.
68-02-1316, T.O. No. 22, "Screening Study to Obtain Information Necessary
for the Development of Standards of the Performance for Oil-Fired and
Natural Gas-Fired Boilers" and T.O. No. 19 (under-the same contract num-
ber), "Screening Study to Obtain Information Necessary for the Development
of Standards of the Performance for Solid Fuel-Fired Boilers," we need
basic data about boilers in the range 10 x 106 - 250 x 106 Btu/hour heat
input and with controlled emissions.
According to our information, this data may be obtained from applica-
tions for boiler permits which may include control equipment data and
stack and other egress data. We would greatly appreciate your sending us
copies of these above-mentioned forms covering the following boilers:
NAME OF COMPANY CONTROL DEVICE
Old Fort, N.C. 26,000 ACFM
Old Fort Paper Co. Cyclone / ^ ' ^ \f\
A/- ,^ \^x
V
V tof •£
American Enka Precipitator
Enka, N.C. 80,000 ACFM
We would also appreciate your sending us copies of the same form for
one or two boilers, arbitrarily chosen by you, with uncontrolled emissions,
operating in your state.
If you have any questions, please contact me at tel. no. 617-275-9000,
ext. 372, for more information.
Thank you for your kind cooperation.
Sincerely yours,
V.Hampl
C-93
IGTON POAD, BEDFORD MASSACHUSETTS 01730 / PHONF. A17-275.9000
-------
NER
North Carolina Department of
Natural & Economic Resources
JAMES E. HOLSHOUSER, JR , GOVERNOR • GEORGE W. LITTLE, SECRETARY
DIVISION OF
ENVIRONMENTAL
MANAGEMENT
W. E. Knight
Acting Director
BOX 27687, RALEIGH 27611
TELEPHONE 919 829-4740
June 7, 1976
Mr. Vladimir Hampl, Senler Engineer
Control Systems Development Section
Environmental Engineering Department
GCA/Technology Division
Burlington Road
Bedford, Massachusetts 01730
Dear Mr. Hampl:
Reference 1s made to your letter of May 27, 1976, requesting Information
on several coal-fired and oil-fired boilers 1n North Carolina.
Old Fort Finishing Plant, Old Fort. This company had three coal-fired
boilers which were converted to bum residual oil. Data for coal usage 1n 1971
are presented. Boiler II and 12 are Identical; each 1s rated at 50,000 1b. of
steam/hr.; each burns 9,400 T/yr. using 16,600 gal/yr. of distillate oil for
ignition. The stack height for these two boilers Is 77'6". Boiler #3 Is rated
at 60,000 Ib. of steam/hr., burns 12,200 T/yr., and uses 16,800 gal/yr. of
distillate oil for Ignition. Its stack height 1s 86'9". All three units are
pulverized coal boilers and each has a multiple cyclone to control particulate
matter. The coal has an ash content of 8.6% and sulfur content of 1.6%.
Marine Corps A1r Station, Cherry Point. The following data are for residual
oil-fired boilers for 1974. The sulfur content of the oil 1s 1.95%.
Boiler
Capacity
mm BTU/hr.
50
50
35
35
35
40
Firing Rate
gal/hr. m Gal/yr.
333
333
233
233
233
267
1674
1674
1171
1171
1171
1339
Stk.
Ht.
ft.
77
77
77
77
77
77
Stk.
D1a.
ft.
5.5
5.5
6.5
6.5
6.5
6.5
Stk.
Temp.
515
587
540
525
500
Flow
Rate
Cfm
60,000
60,000
40,000
40,000
40,000
C-94
-------
Mr. Vladimir Hampl
Page Two
Marine Corps Air Station, Camp Lejeune. The following data are for residual
on-fired boilers for 1974. The oil has a sulfur content of 2.16* and a heat
content of 150,000 BTU/gal.
Boiler
Capad ty
Firing Rate
mm BTU/hr. gal/hr. m gal/yr.
13
13
114
114
12
13
17
12
13
21
17
53
53
26
38
20
21
114
88.6
88.6
763
763
80.5
88.6
112
80.5
88.6
138
113
352
352
173
253
133
140
763
200
200
2000
2000
180
180
180
180
180
400
400
750
750
750
686
600
600
2000
Stk.
Ht.
ft.
60
50
100
100
60
70
24
27
33
46
46
42
42
42
40
40
40
100
Stk.
Dla.
ft.
3.0
2.5
6.5
6.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
3.5
3.5
3.5
2.5
2.5
2.5
6.5
Stk.
Temp.
300
400
350
330
450
340
320
450
450
300
500
730
650
500
500
450
500
330
J. P. Stevens, Rosemary Plant, Roanoke Rapids. This plant has a 135 million
BTU/hr. spreader stoker coal-fired boiler. In 1971 the boiler burned 20,000
tons of coal with an ash content of 6.9* and a sulfur content of 1.1*. The maximum
hourly firing rate was 10,000 pounds of coal. A multiple cyclone with a collection
efficiency of 85* was used to control part1culate emissions. The flue gas flow
rate was 90,830 cfm at 605°F. The stack height was 103 ft. with a Inside diameter
of 7 ft. The boiler was later modified so that 1t would bum No. 4 oil 1n comb1nat1<
with coal. Also the multiple cyclone 1s still being used. In 1975 the flue gas
flow rate was determined to be 52,504 cfm at 479°F. It was also determined that the
optimum firing rates for the control of visible emission would be that 100* of the
heat Input should be provided by oil when the boiler was operating at less than
30* of Its capacity and that 10 to 20* of the heat Input should be provided by oil
and 80 to 90* should be provided by coal when the boiler was operating above 30*
of Its capacity. At 71 million BTU/hr., this meant that 60,350,000 BTU/hr. or
85* of the heat Input was provided by coal, which was burned at the rate of 4700
Ib/hr., and 10,650,000 BTU/hr. or 15* of the heat Input was provided by oil, which
was burned at the rate of 74 gal/hr. In 1975 the sulfur content of the oil was
1.7*, and the sulfur content of the coal was 0.78*. The ash content of the coal
was 7.9*.
Cone Mills, Greensboro. Four pulverized coal/natural gas-fired boilers have
been converted to No. 6 oil/natural gas-fired boilers. The following data are
for the coal/natural gas-fired boilers in 1971.
C-95
-------
Mr. viacnmir nampi
Page Three
Boiler
1
2
3
4
Max.
Rating
Ib. steam/hr.
90,000
90,000
85,000
150,000
Max. Heat Max.
Input Coal
mm BTU/hr. T/hr.
124 4.5
124 4.5
117 4.25
207 7.5
Avg.
Coal
T/hr.
3.6
3.6
3.4
6.0
Coal
T/yr.
4,438
5,900
3,289
12,479
Natural
Gas
mm cu.ft,
153
167
234
501
The following table presents the company's estimation of emissions 1n 1971.
The emissions are for average operating conditions and for coal with an ash content
of 6.0% and a sulfur content of 1.0%. The flue gas flow rates are at 320°F and
29.9 1n Hg.
Boiler
1
2
3
4
Particulate Emissions
No. eye. w/cyc.
Ib/hr. Ib/hr.
360
360
340
600
72
72
68
120
so2
Ib/hr.
137
137
129
228
Flue Gas
Flow Rate
Cfm
31,320
31,320
29,600
52,200
After conversion the boilers have these parameters:
Furn. Max.
Vol. Rating
Boiler cu.ft. Ib. steam/hr.
1 5500 80,000
2 5500 80,000
3 5500 80,000
4 8600 150,000
Max. Heat
Input
mm BTU/hr.
No. 6 011
Max. Avg
gph gph
124
124
117
207
827
827
780
1380
660
660
520
920
Natural Gas
Max. Avg.
mcf/hr. mcf/hr.
124
124
117
207
99
99
93.6
165.6
Boilers No. 1 and 2 use the same stack, and boilers No. 3 and 4 use the same
stack. Each stack 1s 175' 1n height and has an Inside stack area at the top of
113 sq.ft.
C-96
-------
Mr. viacnmir nampi
Page Four
American Enka, Enka. The following table presents boiler and stack
parameters.
Boiler
1
3
5
6
7
8
9
10
11
12
Steam
Load
Ib/hr.
25,000
25,000
60,000
60,000
60,000
80,000
105,000
150,000
175,000
200,000
Heat
Input
mm BTU/hr.
35.
35.
83,
83.
83.
112.0
146.0
203.0
2*0:0'
268.0
.3
.3
.5
.5
.5
Max.
Firing
Rate
250 gph #2 oil
250 gph 12 oil
6,250 Ib/hr coal
6,250 Ib/hr coal
6,250 Ib/hr coal
8,350 Ib/hr coal
10,950 Ib/hr coal
1,350 gph 16 oil
18,000 Ib/hr coal
1,790 gph #6 oil
Flue Gas
Flow Rate
cfm
18,000
18,000
37,467
37,467
37,467
69,694
73,664
81,561
84,873
*
Stk. Gas
Temp.
°F
400
400
419
419
419
367
370
325
353
325
*254,000 Ib/hr
Boilers 1, 3, 5, 6, 7, 8, and 11 use the same stack. This stack has a height of
250 ft. and an Inside diameter at the top of 13.5 ft. Boilers 9, 10, and 12 use
the same stack, and this stack has a height of 250 ft. and an Inside diameter of
11 ft. at the top. Part1culate emissions from boilers 8, 9, and 10 are controlled
by electrostatic predpltators, one per boiler, which have a collection efficiency
of approximately 99%. Particulate emissions from boilers 5, 6, and 7 are con-
trolled by mechanical collectors with 85% efficiency. Boilers 5, 6, and 7 are
used only 1n emergencies. Company calculated maximum particulate emissions are
as follows:
Boiler
1
3
5
6
7
8
9
10
11
12
Uncontrolled
Emissions
Ib/hr
Trace
Trace
437.0
437.0
437.0
585.0
767.0
5.4
1260.0
7.1
'Controlled
Emissions
Ib/hr
Trace
Trace
65.6
65.6
65.6
5.
7.
.85
.67
5.4
12.60
7.1
The coal has a heat content of 13,350 BTU/lb., an ash content of 10% and a sulfur
content of 1% with a range of 0.5 to 1.5%. The residual oil has a sulfur content
of 2.1%, an ash content 0.05%, and a heat content of 152,000 BTU/gal.
If you have any questions or need any further assistance, please call me at
919-829-4740 extension 235.
Sincerely,
Tom C. Allen
C-97
-------
GGA/TECHNOLOGY DIVISION
May 28, 1976
Bureau of Air Quality and Noise Control
Dept. of Environmental Resources
200 N. Third Street
Harrisburg, Pennsylvania 17120
Dear Sir:
For the successful completion of two projects under EPA Contract No.
68-02-1316, T.O. No. 22, "Screening Study to Obtain Information Necessary
for the Development of Standards of the Performance for Oil-Fired and
Natural Gas-Fired Boilers" and T.O. No. 19 (under the same contract num-
ber), "Screening Study to Obtain Information Necessary for the Development
of Standards of the Performance for Solid Fuel-Fired Boilers," we need
basic data about boilers in the range 10 x 10^ - 250 x 106 Btu/hour heat
input and with controlled emissions.
According to our information, this data may be obtained from applica-
tions for boiler permits which may include control equipment data and
stack and other egress data. We would greatly appreciate your sending us
copies of these above-mentioned forms covering the following boilers:
vNAME OF COMPANY CONTROL DEVICE
E. Keeler Co., Williamsport, Penna. Cyclone, 67,000 ACFM
Jones and Laughlin Steel Corp, Pittsburgh, Pa. Cyclone, 120,000 ACFM
Pennsylvania Refining Co., Karns City, Penna. Cyclone, 31,000 ACFM
Howes Leather Co., Curwensville, Penna. Cyclone, 22,000 ACFM
Hanley Co., Lewis Run, Penna. Cyclone, 18,000 ACFM
Monsanto Chemical Co., Portland, Penna. Precipitator, 66,000 ACFM
We would also appreciate your sending us copies of the same form for
Dire or two boilers, arbitrarily chosen --by- you, with uncontrolled emissions,
operating in your state.
If you have any questions, please contact me at tel. no. 617-275-9000,
ekt. 372, for more information.
Thank you for your kind cooperation.
Sincerely yours,
V.Hampl
C-98
6UBJNOTON 8QAD. BEDfOBD. MASSACHUSETTS 0)730 / PHONE. 617-275-9000
-------
DEPARTMENT OF ENVIRONMENTAL RESOURCES
POST OFFICE BOX 2063
HARRISBURG, PENNSYLVANIA 171ZO
June 9, 1976
Mr. V. Hampl
GCA/Technology Division
Burlington Road
Bedford, Massachusetts 01730
Dear Mr. Hampl:
This is in response to your May 28, 1976 letter.
Copies of the application forms for Pennsylvania Refining Company
and Howes Leather Company, Inc. are enclosed. We do not have application
forms for E. Keller Company, Hanley Company or the Monsanto Chemical Com-
pany. Permits would not be needed for these facilities unless they were
constructed, modified or reactivated, since the adoption of our regulations.
Allegheny County operates its own autonomous air pollution con-
trol program. For information on the Jones and Laughlin Steel Corporation
you may contact Mr. J. 0. Graham, Engineer, Plan Review Section, Allegheny
County Health Department, Bureau of Air Pollution Control, 301 - 39th
Street, Pittsburgh, PA 15201.
In addition to those requested I have chosen at random and enclosed
an application for a boiler at the Bloomsburg State College and an emission
inventory printout for boiler facility at the FMC Corporation in Lewistown,
Pennsylvania.
If I can be of any further assistance, please do not hesitate to
contact me. My phone number should you need it is (717) 787-4324.
Sincerely yours,
Douglas L. Lesher
Chief, Permit Section
Division of Abatement § Compliance
Bureau of Air Quality § Noise Control
Enclosures
C-99
-------
S < L
1
FI«M CODE PLANT sic LOf.urio
44-0479804 02 2nUT
li" i.";ALtTY <-^Lj NOISE CONTROL DISTRICT
" NAME
RESOURCES
06/08/76
hit, CORP CHtM FIBER DIV
1000 ELlZAb AVE LEWISTOWN
LEWISTOWN 717 248 7881
ALERT PLAN
OR PERMIT REGION
CORE COMPANY PERMIT 4
17044
17044
SHIFTS HOURS DAYS DAYS PEAK i'.Pt-RA T 1 M':> UON OPERATING COMbU^tlON IiMCIN- fETHOO OF COMB TYPES COMB REFUSE AMOUNT OK NON COMd MET_
UAY SHIFT WEEK YEAR MROLtSs 4ulLtk PKuCtSS rtOILtR tijUI^MENT LRATOK REFUSE DISPOSAL GEN IN TONS/YR' REFUSE IN TONS YR' DIS
08
01-12
11-UJ
YtS
NO
LANDFILL
"MIXED REFUSE
500
200
FILL
BOILER NO. A-p DATE INPUT FIRING RATE OTY/hR UNITS-
IDENT UNITS INSTALLED BTU NORMAL REAK
"31 01 N N 1V29 11720UOOU 2.5 4.9 TONS COAL
032 01 N N 1^29 117200000 2.5 4.9 TONS COAL
METHOD OF FLY ASH TYPE OF FUEL * % 8.T.U. E'XHAUST
FIRING REINJECT SULF ASH PER VOL SCFM
UNDERFEED 'R«t.«-t NO BITUMINOUS 1.7 11.4 012640 29400
UNDERFEED NO BITUMINOUS 1.7 11.4_ 012640 26000
REF M CODE DATE TYPE AIR OPE" LtlS/F
O CODE C INSTAL CLEANING EQUIPMENT EFF TYPE EMISSIONS ."NORMAL
O °31 • HYDROCARBON ' ""0.5
O
031 . CARBON MONOXIDE ' 1.2
031 . SULFUR DIOXIDE " " 161.0
031 " '. OXIDES OF NITROGEN ~
031 . OUST
032" ' . GUIDES' OF NITROt-EN
032 . SULFUR DIOXIDE
032 . HYDROCARBON
032 . CAkdON MONO/ IDE
032 . iMjsT
TOTAL HYC^OCirtbtn
TOTAL O.xKiES UF -UTwObtN
TuT-aL SULFu^ UlLUlLt
50".0
51.7
"50 . 0
161.0
0.5
1 .2
51.7
1.0
100.0
322.0
iQUR STACK INSIDE
PEAK BASIS"OF" ESTIMATE HEIGHT "DIAM'
1.0 EM'IS FACTOR EST" """206 12~
2.5 EMIS FACTOR" EST 208 12
316.0 EMIS FACTOR EST 208 12
98.0 E"Mi"S" EACTOR'EST ~20"8~ 12
91.0 STACK TEST D.E.R. 208 12
98.0 EMIS FACTOR EST 208 12
316.0 EMIS FACTOR EST 208" 12
1.0 EMIS FACTOR EST 206 12'"'
2.5 EMIS FA'CTOR EST ' 208 "12
VI. 0 STACK TEST O.E.R. 20b 12
2.0 "•;
)9b.O
^32.0
TEMP EXHAUST SEQ
"FAHR "VOLUME MCC NUM
"4i2 29"466 nor
412 294"60 1 002
412 29400 1 003
' 412 29400 1 004
412 29400 1 005
412 29400 1 001
"412 29400 1 002
412" ~29"400 Y'0"03
4"l2 29400 "1 005
412 29400 1 006
MuivOxIuE
5.0
-------
DEPARTMENT OF HEALTH
AIR POLLUTION CONTROL
.
APPLICATION FOR PLAN APPROVAL. PSICS \\;. "-,2 COKSTRUCTICU
OR MODIFICATION OF CCMBUSTiGU UNITS OTHER "MAN INCINERATORS
[Xj CO«3USTION UNIT |X FLUE GAS CLEANING DEVICE [Xj NEW j_j MODIFICATION
I. OWNER OF UNIT
Pennsylvania Refining Co.
DIVISION'S USE ONLY
APPROVAL ""
EXAMINED PY
• DATE.
2A. NAME OF RESPONSIBLE PERSON SIGNING APPLICATION
George A. Beck
8. TITLE
Vice President
C. SIGNATURE
t MAILING ADDRESS
Karns City, Pennsylvania
«. NAME OF INSTALLATION
Pennsylvania Refining Co. - Plant No. 1
5. STREET ADDRESS OF INSTALLATION
None
6. MUNICIPALITY
Karns City
7. NAI.5I- Or EQUIPMENT
Hoffman Combustion Engineerir
Co.
8. RATED INPUT (BTU/HR.)
65,475,880
9. FUEL
Bituminous Coal 1-V x 0
TOWNSHIP
MODEL NO.
g Type 3A-P.A.D.
ANNUAL FUEL CONSUMPTION
15,000 to 20,000 tons
FIRING RATE (MAXIMUM)
5450 Ibs./hr.
COUNTY
Butler
USE
Process
% SULFUR % ASH
1.75 12
METHOD OF FIRING
Spreader Stoker
FLUE GAS CLEANING DEVICES
IDA. MANUFACTURER
Western Precipitation Group
- Joy Manufacturing Co.
8. TYPE
Multi-Tube Centrifugal
C. PRESSURE DROP
2.7" VWC
0. INLET GAS TEMP. °F
580
MODEL OR CATALOGUE NO.
9VGR10 with Spirocones
VOLUME OF GAS HANDLt.0 (CFM)
31,100
COST OF THE DEVICE (ESTIMATED)
5,500.00
E. CONTAMINANTS TO BE CONTROLLED
Fly Ash
F. INLET EMISSION RATE LB/HR
665.43 maximum
LS/CU. KT.
3„6 x 10 maximum
G. EXPECTED COLLECTION EFFICIENCY
• 94.5% (minimum)
COMBUSTION AIDS AND/OR CONTROLS
1!
i Lfl A. OVERFIRE JETS
L JU B. DRAFT CONTROLS
.Ljc. OIL PREHEAT
_ KJ D. SOOT CLEANING
TYPE
Air
NUMBER HEIGHT ABOVE GHATE
7-frcv-t 14" -from:
U-ypa-r l.fi"-' -,-,•>•>
' YVPE
Pneumatic
TEMPERATURE <°F)
METHOD
Periodic
FREQUENCY
Once/ 8 hrs. shift
l min./blov;
D,.
STAC;< SPRAYS
". SvX/. .. .DNITORING DEVICES
COiv.. ,.iTiON EFFICIENCY
G. MOJM;TORING DEVICSS
TYPE
TYPE
Steam Flow/Air Flow Indicating Recorder
ATOMIZATION INTERLOCKING DEVICE
C-101
-------
COLLECTED FLYASH RE-ENTRAINMENT
1X1 1. PREVENTATIVE DEVICE
TYPE
Slide
[j3 J. MODULATING CONTROLS | | STEP
Gate Valve on Collector Hopper
0 AUTOMATIC from pressure
12.
D
FLYASH REINJECTION
DESCRIBE OPERATION
13. DESCRIBE METHOD OF SUPPLYING MAKE-UP AIR TO THE FURNACE ROOM
Outside Air Louver in Wall
STACKS
UA.
B.
C.
HEIGHT OF STACK ABOVE GRADE
64 ft.
DISTANCE TO NEAREST OBSTRUCTION
INSIDE DIAMETER
48"
HEIGHT OF NEAREST OBSTRUCTION
MATERIALS OF CONSTRUCTION OF STACK
1/4" steel plate
[X] SAMPLING PORTS
NUMBER OF PORTS
2
IS. BRIEFLY DESCRIBE GENERAL NATURE OF THE AREA IN WHICH UNIT IS TO BE LOCATED
KarnsCipr Pa,, Population approximately 400 - IJLANT IN INDUSTRIAL ZONE AT ELEVATION OF
AFPROXIMAiELY 1200 - Boiler House Approx. 300 ft. from property line - Hills 1/2 to 3/4
mile distant N, E, SW and W of plant at 1400 to 1475' elevation. No structures in
immediate area higher than stack except existing stacks.
16. MODIFICATIONS - DESCRIBE IN DETAIL ON AN ATTACHED SHEET.
17. EXPECTED DATE OK COMPLETION
March 1968
REG „.
1 . NOVl61967
C-102
-------
\
PRESSURE DROP '
INCHES VWC T
o/ f.TATE:;;',:. y.. .;-;i i© M
NOTE: *OR CONCENTRATIOiSS LESS THAN 0.8 GRAINS PER-
CO. FT., THE INIET CONCENTRATION SHALL BE TAKEN
TO M 0.8 GRAINS PEK CU. FT. AT STACK CONDITIONS.
PARTICIE SHE ANALYSIS BY BAHCO CLASSIFIER
-------
&j*>~
^^SOI^X^^A/XJOISr :^d: 10-1-61
Cancels: **-10-60
DIVISION OF JOY MANUFACTURING CO.
MULTICLONE PERFORMANCE DATA
Type
9VGR10
9VGR12
9VGR1*
9VGR MULTICLONE
Parti cle
0 - 10
10-20
20 - V*
+ kk
0-10
10 - 20
20 - ttk
+ M»
0 - 10
10-20
20 - kk
* W
Fractional Efficiency Data*
-Fly Ash
Tnllpction Efficiencies
Size Range 1" P.O.
Microns 62.5
95.8
98.6
99-3
55.0
9^.2
97.8
99.0.
1.6
92
96.3
98.6
2"- P.O.
67
97.8
99.1
99.5
62.5'
96.5
98.2
99. ^
52
96.0
98.3
99.3
3" P.P.
70.0
98.0
99.3
99.6
6k. 0
97.8
99.3
99.6
56.0
96.0
99.0
99.**
*For Spi rocone des.ign corresponding to efficiency curves
shown on Serials M3-009-1., M3-009-2, and M3-009-1*.
Micron - U. S. Sieve Size Comparison*
Microns 37 & 53 62 7k 88 105 125 1**9 177
U.S. Sieve Size kOO 325 270 230 200 170 1^0 120 100 80
Microns 210 250 297 350 *»20 500 590 710 8^0 1000
U.S. Sieve Size 70 60 50 ^5 kO 35 30 25 20 18
*Courtesy of The W. S. Tyler Company
XL
C-104
-------
DEPARTMENT OF HEALTH
AIR POLLUTION CONTROL
APPLICATION FOR PLAN APPROVAL PRIOR TO THE CONSTRUCTION
OR MODIFICATION OF COMBUSTION UNITS OTHER THAN INCINERATORS
J i
••' i»i i — i r
!;W COMBUSTION UNIT | | FLUE GAS CLEANING DEVICE [
£ NEW Q MODIFICATION
^NER OF UNIT
Hcwrats Leather Co.t inc.
DIVISION'S USE ONLY
APPBOUAI ^o ss-jvi-eooef
DATF 9-/9-0*
(. NAME OF RESPONSIBLE PERSON SIGNING APPLICATION
G. £. Mevenor
8. TITLE
Engineer
C. SIGNATURE (\ ^ ^^ 1 i
-------
FLYASH RE-ENTRAIWMEN1
Q J. HOOUUmMO CONTROLS
w. n
LJ FkVASH HelMJtCTION
TYPE
_ Q STEP
DESCRIBE OPERATION
(yi AUTOMATIC •Pressure
NONE
It. DOC*IM METHOD OF SUPPLYING MAKE-UP AIR TO THE FURNACE ROOM
Mr taken through duct to outside source.
STACKS
14A. HEIGHT OF STACK ABOVE GRADE
60'
B. DISTANCE TO NEAREST OBSTRUCTION
lUft* t.o 11* hlcrh obstruction
C. INSIDE DIAMETER
42"
HEIGHT OF NEAREST OBSTRUCTION
Dearest tall obstruction 31*
MATERIALS pF CONSTRUCTION OF STACK
steel
Q SAMPLING PORTS
KiUH'B^R OF PORTS
15. BRIEFLY DESCRIBE GENERAL NATURE OF THE AREA IN WHICH UNIT IS TO BE LOCATED
Along Susquehanna river on outskirts of a town with a population of 3200,
In the Industrial zone. The boiler plant will b» located approximately
210* from V. property lln« 2UO* from 2. property line, ^75* to W. property
line which la the south bank of the Suaquehanna river and 1020 from the
2. property line. The elevation Is about 1150* above sea level.
16. MODIFICATIONS DESCRIBE IN DETAIL ON AN ATTACHED SHEET.
17. EXPECTED DATE OF COMPLETION
g - 1969
.-•*
<.*>**'
C-106
-------
HOWES LEATHER COMPANY, INC.
TANNERS OF
SOLE LEATHER
CURWENSVILLE, PA. 16833
*»v , .^ _,.. .,., ^ , „»»» '
238 West Street, Williamsport, Pa. 17701. Mr. Pysher is O*
handling our contract with Keeler Boiler Company.
Yours very truly,
HOWES LEATHER COMPANY, INC.
G. S. Hevenor
QSHrleg
co: Mr. Max S. Malre - Boston
NOTHING TAKES THE PLACE OF LEATHER
C-107
-------
AIR POLLUTION CONTROL
APPLICATION FOR PLAN APPROVAL PRIOR TO THE CONSTRUCTION
OR MODIFICATION OF COMBUSTION UNITS OTHER THAN INCINERATORS
•.•"••*
fl
COMBUSTION UNIT
TR OF UNIT
General State
Q FLUE GAS CLEANING DEVICE f^J NEW j |
Authority
MODIFICATION
DIVISION
APPROVAL NO.
EXAMINED BY
DATF
S USE ONLY
2A. NAME OF RESPONSIBLE PERSON SIGNING APPLICATION
S. K. Wilson
B.
Director of. Eng/Arch
c. sic
3. MAILING ADDRESS
The General State Authority, 1 8th & Herr Streets, Harrisburg, Pa., 17120
4. NAME OF INSTALLATION
Bloomsburg State College Boiler Plant
5. STREET ADDRESS OF INSTALLATION
Corner of Light Street Road & Penn Street
6.
7.
B.
hr.
9.
MUNICIPALITY
NAME OF EQUIPMENT
Boiler
RATED INPUT (BTU/HR.) & ^ , OGG# j
23,625,000
FUEL
Coal
TOWNSHIP
MODEL NO.
CP 300 HP
ANNUAL FUEL CONSUMPTION
2500 tons (max.)
FIRING RATE (MAXIMUM)
25#/Hr./S.T.» grate
Columbia
USE Campus Central
Steam System
% SULFUR by % ASH
0.45 (w£t.) 14.64
METHOD OF FIRING
traveling grate stoker
FLUE GAS CLEANING DEVICES
10A. MANUFACTURER
Fly ash arrestor Corp. (or approved equal)
B. TYPE
Mechanical
C. PRESSURE DROP
2. 5 w.g.
D. 'NLET GAS TEMP, °F
580 ma-xr.
MODEL OR CATALOGUE NO.
MTSA-18-9 CYT
VOLUME OF GAS HANDLED (CFM)
14,500
COST OF THE DEVICE (ESTIMATED)
$3,000
E. CONTAMINANTS TO BE CONTROLLED
Flv ash
F. IKLET EMISSION RATE LB/HR
70
LB/CU. FT.
0.0398
G. EXPECTED COLLECTION EFFICIENCY
90%
COMBUSTION AIDS AND/OR CONTROLS
11
LJ A. OVERFIRE JETS
1 1 B. DRAFT CONTROLS
LJ C, OIL PREHEAT
1 — 1
LJ D. SOOT CLEANING
TYPE
NUMBER HEIGHT ABOVE GRATE
TYPE
TEMPERATURE (°F)
METHOD
FREQUENCY
GE.
STACK SPRAYS
CK,
MOKE MONITORING DEVICES
r—, COMBUSTION EFFICIENCY
•_.• C. .'OM'-OFINO DEVICES
TYPE
TYPE
_J H. ".TD^i.'ATION INTERLOCKING DEVICE
C-108
(OVER)
-------
COLLECTED FLYASH RE-ENTRAINMENT
pREVENTATIVE DEVICE
TYPE
[i-
0
MODULATING CONTROLS
FLYASH REINJECTION
a
STtP
AUTOMATIC
DESCRIBE OPERATION
DESCRIBE METHOD OF SUPPLYING MAKE-UP AIR TO THE FURNACE ROOM
Large fixed wall louver (288 S. F. )
STACKS
f. HEIGHT OF STACK ABOVE GRADE
1 150 ft.
f DISTANCE TO NEAREST OBSTRUCTION
! 750ft.
i
f. INSIDE DIAMETER
8'-0"
HEIGHT OF NEAREST OBSTRUCTION
Columbia Hall - Girl's Dormitory
MATERIALS OF CONSTRUCTION OF STACK
brick
Q SAMPLING PORTS NONE
NUMBER OF PORTS
BRIEFLY DESCRIBE GENERAL NATURE OF THE AREA IN WHICH UNIT IS TO BE LOCATED
Unit shall be located in an existing boiler house located at the edge of a College
Campus and with some residential area on the east side not facing the Campus.
MODIFICATIONS - DESCRIBE IN DETAIL ON AN ATTACHED SHEET.
EXPECTED DATE OF COMPLETION
June 1974
C*109
-------
APPLICATION FOR PLAN APPROVAL
TO CONSTRUCT, MODIFY OR REACTIVATE
AN AIR CONTAMINATION SOURCE AND/OR AIR CLEANING DEVICE
OR FOR A PERMIT TO OPERATE
Read the instructions carefully before completing this form. Submit duplicate copies.
Section A - Identity and Location of Air Contamination Source
1A. Application is being made for:
•Q Construction of New Source
D Reactivation of a Source
D„ Modification of Existing Source
D Installation of Air Cleaning Device
n Extension of Plan Approval
D Amendment to a Previous Application
D Extension of Plan Approval
D Operating Permit
D Extension of Operating Permit
IB. Type of source
Stoker-fired Boiler #6
1C. Plant in which source is located
D New H Existing
ID. Expected date of completion
June 1974
IE. If source is new, does it replace another source (describe source replaced) d Yes & No
2 A. Owner of source
General State Authority
2C. Name of company official signing application
(See instructions)
S. K. Wilson
''•^^N^LXx^JI^^— ___
. 2G. Mailing address (Street or P.O. Box, City, State, Zip Code)
18th & Herr Streets
Harrisburg, Pa., 17120
2B. Employer l.D. No. (Federal)
2D. Title
Director of Eng/Arch
2F. Date
February 7, 1973
2H. Telephone
717-787-3377
3A. Owners designation of source and/or plant if any
Bloomsburg State College Boiler Plant
3B. Location of source (Street address or Route No.)
Corner of Light Street Road
and Penn Street
City or Municipality
Bloomsburg
County
Columbia
3C. Mailing address, if different from 2G. , ,
(Street or P.O. BOX, City, Zip Code) Bloomsburg State College
Bloomsburg, Pennsylvania 17815
3D. Telephone
717/389-2211
4A. Person to contact regarding this Application (name and title)
Joseph M. Gatelli, P.E., Partner
4B. Mailing address (Street or P.O. Box, City, Slate, Zip Code) if different from 2C,.
Smith., Miller & Associates
189 Market Street, Kingston, Pennsylvania 18704
4C. Telephone
717/288-4567
Name and address of person who is to receive Plan Approval and Operating Permit if different from 2G
C-110
-------
Section If /'rotrxs Information
PageZ of 6
FKOO-SS EQUIPMENT
A Manufacturer ol Source
E. Keeler Co. ,
or
approv*
•el
equal
H.
GP
Model
300
No.
HP
C. No.
One
of
units
D. Rated Capacity
15,000 #/Hr.
E. Kate under normal operation (Describe variations)
15,000#/Hr. continuous
20,000 #/Hr. @ 200% of rating (4 hrs. max. )
F. Describe the process equipment (Give type, use, product, etc. on attached sheet)
300 HP high-pressure boiler to generate steam for Campus use - heating, domestic
hot water, etc.
G. Sketch flow diagram of process giving aJI (gaseous, liquid, and solid) flow rates (attach separate sheet). Also list all raw
materials charged to process equipment and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum
and average of both normal and occasional charges).
to
to
to
Coal + air "" stoker "" steam to main header College Campus
distribution for heating - hot water - etc.
2. OPERATING SCHEDULE
hours/day
days/week
weeks/year
3, SEASONAL PERIODS (MONTHS) Two (2) weeks for maintenance.
Operating
to
Non-Operating
to
4. Describe fully the facilities provided to monitor and record all operating conditions that may affect the emission ot air contaminants.
Provide detailed information to show that the facilities provided are adequate.
NONE
5. Describe modifications to process equipment in detail
NONE
6. Type and method of disposal of all waste materials generated by this process
(Is a Solid Waste Disposal Permit Needed? D Yes H No )
Ash to ash storage silo to trucks which haul to Township winter cinder storage
for roads.
'• Briefly describe the method of handling the waste water from this process and its associated air pollution control equipment
(Is a Water Quality Management Permit needed? D Yes D No )
NONE
A'ta'.h aav rv.d al' additional information necessary to perform a thorough evaluation ot the extent and nature of emissions from
'his process.
NONE
C-lll
-------
OT
Section (' Control k
, Continued
«>. ADSORPTION AND ABSORPTION EQUIPMENT ( IF APPLICABLE)
NONE
A. Manutacturer
B. Type
D. Volume of gases handled (ACTM)
V. Design inlet volume (ACTM)
C. Model No.
E. Inlet temperature (°F)
G. Pressure drop (water gage)
H. Absorbent or adsorbent I. Retention time (set)
i. Inlet concentration
K. Outlet concentration
L. Overall efficiency (%)
M. Method and frequency of regeneration
N. Describe absorption or adsorption equipment fully
10. OTHER CONTROL EQUIPMENT (IF APPLICABLE)
Fly Ash Arrester
A. Manufacturer
Fly Ash Arrestor Corporation
(or approved equal)
D. Volume of gases handled (ACFM)
14,500
G. Inlet concentration
(Ibs/hr or gr/SCF Dry)
70 #/Hr.
B. Type
Mechanical
E. Design inlet volume (ACFM)
14,500
H. Outlet concentration
(Ibs/hr or gr/SCF Dry)
7 #/Hr.
C. Model No.
MTSA-18-9 CYT
F. Jnlet temperature ( ° F )
580 maximum
1. Overall efficiency (%)
90
Attached
K. Describe fully giving important parameters and method of operation
This mechanical type collector employs a multiplicity of centrifugal precipitating
tubes operating in parallel.
C-112
-------
Page of
Section D - HMC And Air Contaminant Emission Information
"7"sTACK AND EXHAUSTER
~~ A. Exhauster (attach fan curves)
Induced draft fan
B. Stack height (ft)
150
ZO HP <•>•• 900 RPM
C'. Stack diameter (ft)
8 (inside diameter)
I). Weather cap
D Yes C3 No
E. Indicate on an attached sheet the location of sampling ports with respect to exhaust fans, breeching, etc. Give all
necessary dimensions.
NONE
F. Can the control equipment be bypassed? (If Yes, explain)
D Yes
No
2. ATMOSPHERIC EMISSIONS
A. Particulate matter emissions (Ibs/hr or gi/SCI- Dry)
B. Gaseous contaminant emissions
Contaminants
Concentration
(1)
(2)
(3)
pplT) (Vol.)
ppm (Vol.)
ppm (Vol.)
Ibs/hr
Ibs/hr
Ibs/hr
IN
-------
Ot «
Section I', Miscellaneous Information
T~[)escnbe I'ully facilities to monitor and record the emission of air contaminants. I'm vide detmlod information to sliow that the
facilities provided arc adequate. Include cost and maintenance inclination. Periodic maintenance reports arc to be submitted to
the Department.
NONE
2. Attach Air Pollution Episode Strategy (if applicable)
NONE
3. Briefly describe the general nature of the area in which the source is located.
Unit shall be located in an existing boiler house located at the edge of a
College Campus and with some residential area on the side not facing
the Campus.
4. Attach calculations and any additional intonn.ition neiessary to thorough!) evaluate compliance with all the applicable- requiremonU
ot Article III of the Rules and Regulations of liic Department of l-.nviro'imeni.iJ Resources and those requirements promulgated b>
the Administrator of the United States bnviionmental Protection Agency pursuant 10 the provisions of the Clean Air Act.
5. List all attachments made to this Application.
(a) Fly Ash Arrestor - Curve showing collection efficiency versus particle size.
(b) Report of Test & Inspection - Coal Analysis - Laboratory No. 119
(c) Fly Ash Collector - Specification
C-114
-------
CA/TECHNOLOGY DIVISION
May 28, 1976
Division of Air Pollution Control
Tennessee Dept. of Public Health
301 Seventh Avenue, Room 256
Capitol Hill Building
Nashville, Tennessee 37219
Dear Sir:
For the successful completion of two projects under EPA Contract No.
68-02-1316, T.O. No. 22, "Screening Study to Obtain Information Necessary
for the Development of Standards of the Performance for Oil-Fired and
Natural Gas-Fired Boilers" and T.O. No. 19 (under the same contract num-
ber), "Screening Study to Obtain Information Necessary for the Development
of Standards of the Performance for Solid Fuel-Fired Boilers," we need
basic data about boilers in the range 10 x 106 - 250 x 106 Btu/hour heat
input and with controlled emissions.
According to our information, this data may be obtained from applica-
tions for boiler permits which may include control equipment data and
stack and other egress data. We would greatly appreciate your sending us
copies of these above-mentioned forms covering the following boilers:
NAME OF COMPANY
E.I. DuPont de Nemours Co.
New Johnsonville, Tenn.
American Enka
Lowland, Tenn.
CONTROL DEVICE
Baghouse filter
(in construction)
Precipitator
83,000 ACFM
We would also appreciate your sending us copies of the same form for
one or two boilers, arbitrarily chosen by you, with uncontrolled emissions,
operating in your state.
If you have any questions, please contact me at tel. no. 617-275-9000,
ejct;. 372, for more information.
Thank you for your kind cooperation.
Sincerely yours,
V.Hampi
3TON HOAR BEDfORD. MASSACHUSETTS 0«730 f fHONfc 61747S400Q
C- 1 1 5
-------
RAY BLANTON
GOVERNOR
Eugene W. Fowinkle, M.D., M.P.H.
Commissioner
June 9, 1976
STATE OF TENNESSEE
DEPARTMENT OF PUBLIC HEALTH
NASHVILLE 37219
256 Capitol Hill Building
Vladimir Hamtl
Senior Engineer
Environmental Engineering Department
GAG/Technology Division
Earlington Road
Bedford, Massachusetts 01730
Dear Mr. Hamtl:
Your letter of May 28, 1976, requesting information from this Division's
files has been received. You are welcome to visit this Division's offices
and personally review the company files in regard to the information you
need to fulfill your EPA contract. Should you be unable to make such a
visit, the source registration forms and other pertinent information requested
by you will be reproduced and forwarded to you at a cost of $.50 per page.
Please contact this Division to indicate what your preference is.
Sincerely,
o
ies W. Haynes, P.E.
faef Engineering Program
Division of Air Pollution Control
JWH/psb 2/3
C-116
-------
Daniel Doyle
Field Sales Manager
Standard Havens. Inc.
August 20, 1975 oooo C. o:iu( s,10tM
Kansas City, Missouri 64133 (816) 737.04QQ
GSA Technical Division
Burlington Road
Bedford, Massachusetts 01730
ATTN: Mr. V. Hampl , Engineer
Dear Mr. Hampl:
TM
Enclosed is a feature sheet describing the Standard Havens Dry Reactor
and a brochure on our complete line of air pollution control equipment.
The Dry Reactor is specially designed for continuous control of process
gas stream emissions on coal-fired boilers and other difficult applications.
Essentially, it is a highly efficient baghouse with the added capability
of utilizing a fluidized bed chemical reaction to absorb gaseous pollutants.
Only dry chemicals are used—there is no liquid effluent to create
secondary water pollution and sludge processing expenses.
The Dry Reactor can be installed to operate as a standard baghouse for
solid particulate; then, if and when federal regulations on gaseous
pollutants control become effective, it can be converted to a Dry Reactor.
If we can provide you with more specific information, please do not
hesitate to contact me. I will be glad to discuss your air pollution
control requirements with you, in person, at your convenience.
Sincerely,
STANDARD HAVENS INC.
*"•""""^"v. V»^"""""^y
-------
Research Cottrell
Air Pollution uontroi uroup
Box 750, Bound Brook, New Jersey 08805
Telephone 201 885-7000
5
PARTIAL INSTALLATION LIST
PRECIPITATORS ON INDUSTRIAL
PULVERIZED COAL FIRED BOILER GASES
Company and Location
V American Cyanamid, Bound Brook, NJ
St. Joe Lead (Kaiser), Josephtown, PA
Luzerne El. Div., United Gas Improvement, Hunlock, PA
University of Washington, Seattle, WA
E. 1. DuPont de Nemours & Co., Louisville, KY
Shell Chemical (Riley Stoker), Marietta, OH
Eastman Kodak Co., Rochester, NY
Jones & Laughlin, Aliquippa, PA
Container Corp. of America, Manayunk, PA
Garden State Paper Co. (Carlson & Sweatt), Garfield, NJ
Allied Chem. Corp., Syracuse, NY
Celanese Fibers, Narrows, VA
Purdue University, Lafayette, IN
Monsanto Chemical Co., Portland, PA
Eastman Kodak Co., Kodak Park Works, Rochester, NY
Babcock & Wilcox, University of Notre Dame, Notre Dame, IN -
West Virginia Pulp & Paper Co., Luke, MD ftVt( u
Eastman Kodak Co., Rochester, NY
Union Carbide, Institute, WV
Eastman Kodak Co., Rochester, NY
City of New York, South Shore Incinerator, New York, NY
Babcock & Wilcox for Fort Howard Paper Co., Green Bay, Wl
FMC Corp., South Charleston, WV
The Dow Chemical Co., Ludington, Ml > >' • ri <•---
Union Carbide Corp., Institute, WV
Union Carbide Corp., South Charleston, WV
General Electric (B&W), Erie, PA
Tennessee Eastman Co., (UE&C), Kingsport, TN
Union Carbide, Institute, WV
Union Carbide Corp., Chem. & Plastics Div., Institute, WV
Celanese Fibers Co., Rome, GA
FMC Corp., Inorganic ^617)7157^., South Charleston, WV
FAS, Philadelphia, PA
Union Carbide Corp., Chem. & Plastics Div., South Charleston, WV
FMC Corp., Lewistown, PA
Celanese Fibers Co., Rock Hill, SC
Eastman Kodak Co., Rochester, NY
FMC Corp., American Viscose Div., Meadville, PA
FMC Corp., American Viscose Div., Nitro, WV
Celanese Fibers Co., Chatillon Rd., Rome, GA
FMC Corp., Inorganic Chem. Div., South Charleston, WV
U.S. Plywood-Champion Papers Inc., Canton, NC
U.S. Plywood-Champion Papers Inc., Canton, NC
E. 1. DuPont de Nemours & Co., Clinton, 1 A
, ,- ' <*'
• V '
Gas Volume
CFM
90,500
-------
PARTIAL INSTALLATION LIST
PRECIPITATORS ON INDUSTRIAL
PULVERIZED COAL FIRED BOILER GASES
Company and Location
FMC Corp., South Charleston, WV
Olin Corp., Pisgah Forest, NC
Michigan State University (Erie City, IN), City of Lansing, Ml
Georgia Kraft, Rome, GA
United Illuminating, Cokes Works # 1, New Haven, CT
St. Joe Minerals (Bechtel), Monaca, PA
Tennessee Eastman, Kingsport, TN
Goodyear Co., Akron, OH
Goodyear Co., Akron, OH
Nekoosa-Edwards, Nekoosa. Wl ', ••' '-*'
American Enka, Enka, NC
Spring Mills, Inc., Ft. Mill,SC
Spring Mills, Inc., Ft. Mill, SC
B&W for FMC, Green River, WY
B&Wfor H. K. Ferguson, So., Minnesota Beet Sugar, Olivia, MN
American Enka, Lowland, TN '• '
E. I. DuPont de Nemours £ Co., Aiken, SC
Riegel Textile Corp., Ware Shoals, SC
P. H. Glatfelter Paper Co., Spring Grove, PA
Monsanto Chemical Co., Decatur, AL
Mead Corporation, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Carolina Eastman, Columbia, SC
Monsanto Chemical Co., Decatur, AL
National Starch, Indianapolis, IN ii^ -,
FMC, Front Royal, VA
FMC, Front Royal, VA
Monsanto Chemical Co., Decatur, AL
Quaker State Oil, Farmers Valley, PA
Quaker State Oil, Emlenton, PA
Quaker State Oil, St. Mary's, WV
Allied Chemical Co., Solvay, NY
Tennessee Eastman, Batesville, AR ,
Gas Volume
CFM
1 80,000
120,000
294,000
550,000
749,000 ea.
250,000 ea.
135,000 (#20)
1 18,000 (Bal.)
1 70,000 ea.
100,000
89,000
80,000 ea.
80,000
95,400
84,500
655,000
270,000
83,000 ea.
744,000
131,000
325,000
325,151
190,000
161,000
183,900
198,200
108,900
157,000
120,000
97,000
126,715
122,615 ea.
100,000
138,000
109,800
100,000
125,700
30,187
Temperature
Degrees
Fahrenheit
500
340
740
330
-
300
340
450
700
740
375-460
400-460
340
340
800
450
300-400
367
422
285-485
785
325
400
400
400
420
325
480
410
365 ± 30°
460 ± 30°
450-630
553
608
606
350-425
465
Sulfur
Percent
0.9
.5
.6
1.25-1.5
-
1.65
0.6-2.0
0.6-2.0
0.5-1.0
0.5-1.0
2.4
.9
.9
.9
.6
.3
.6
.6
.85
1.5-4.0
0.7-3.7
0.7-3.0
0.6-2.0
0.6-2.0
0.6-2.0
0.6-2.0
.7
0.7-3.7
.6
.7
.7
0.7-3.7
2.46
2.23
1.25
1.0
.7
Efficiency
Percent
99.5
99.5
99.8
99.5
95
98.0 ASME
95.46 EPA
98.9
—
99.0
99.9
97.0 ASME
99.5 EPA
99.875 ASME
97
97
99.1
99.3 EPA
99.6 ASME
99.35 EPA
99.675 ASME
95.6
98.0
90.0
99 EPA-dry
98.25 EPA
91. 43 EPA
91.43 EPA
91.43 EPA
91.43 EPA
99.5 EPA
98 EPA
95 EPA
99.2 EPA-dry
99.2 EPA-dry
96 EPA
98. 138 EPA
96.267 EPA
97.575 EPA
97.34 EPA
97.7 EPA-dry
C-119
-------
Research Cottrell
Air Pollution control uroup
Box 750, Bound Brook, New Jersey 08805
Telephone 201 885-7000
PARTIAL INSTALLATION LIST
PRECIPITATORS ON INDUSTRIAL
PULVERIZED COAL FIRED BOILER GASES
Company and Location
American Cyanamid, Bound Brook, NJ
St. Joe Lead (Kaiser), Josephtown, PA
Luzerne El. Div., United Gas Improvement, Hunlock, PA
University of Washington, Seattle, WA
E. I. DuPont de Nemours & Co., Louisville, KY
Shell Chemical (Riley Stoker), Marietta, OH
Eastman Kodak Co., Rochester, NY
Jones & Laughlin, Aliquippa, PA
Container Corp. of America, Manayunk, PA
Garden State Paper Co. (Carlson & Sweatt), Garfield, NJ
Allied Chem. Corp., Syracuse, NY
Celanese Fibers, Narrows, VA
Purdue University, Lafayette, IN
Monsanto Chemical Co., Portland, PA
Eastman Kodak Co., Kodak Park Works, Rochester, NY
Babcock £ Wilcox, University of Notre Dame, Notre Dame, IN
West Virginia Pulp & Paper Co., Luke, MD
Eastman Kodak Co., Rochester, NY
Union Carbide, Institute, WV
Eastman Kodak Co., Rochester, NY
City of New York, South Shore Incinerator, New York, NY
Babcock & Wilcox for Fort Howard Paper Co., Green Bay, Wl
FMC Corp., South Charleston, WV
The Dow Chemical Co., Ludington, Ml
Union Carbide Corp., Institute, WV
Union Carbide Corp., South Charleston, WV
General Electric (B&W), Erie, PA
Tennessee Eastman Co., (UE&C), Kingsport, TN
Union Carbide, Institute, WV
Union Carbide Corp., Chem. & Plastics Div., Institute, WV
Celanese Fibers Co., Rome, GA
FMC Corp., Inorganic Chem. Div., South Charleston, WV
FAS, Philadelphia, PA
Union Carbide Corp., Chem. & Plastics Div., South Charleston, WV
FMC Corp., Lewistown, PA
Celanese Fibers Co., Rock Hill, SC
Eastman Kodak Co., Rochester, NY
FMC Corp., American Viscose Div., Meadville, PA
FMC Corp., American Viscose Div., Nitro, WV
Celanese Fibers Co., Chatillon Rd., Rome, GA
FMC Corp., Inorganic Chem. Div., South Charleston, WV
U.S. Plywood-Champion Papers Inc., Canton, NC
U.S. Plywood-Champion Papers Inc., Canton, NC
E. I. DuPont de Nemours & Co., Clinton, I A
Gas Volume
CFM
90,500
338,000
220,000
50,000
110,000
79,000
152,000
1 ,000,000
191,000
65,700
109,000
130,000
116,000
66,000
152,000
76,000
350,000
181,000
120,000
204,000
136,000
191,500
70,000
90,600
120,000
120,000
133,000
200,000
120,000/Pptr.
120,000
30,000
103,000
216,000
155,000
100,000
135,000
162,000
120,000
50,000
60,000
150,000
187,000 (ACFM)
236,000
75,000
Temperature
Degrees
Fahrenheit
270
273
-
344
430
391
330
630
450
333
400
336
345
900
300
340
350
450
500
325
580-620
290
390
320
500
550
345
280
500
500
335
360
320-420
340
330
410
410
335
505
425
425
480
Sulfur
Percent
3.6
2.2
-
.6
3.5
5.0
2.2
2.8
1.2
1.4
-
.75
1.9
3.3
2.2
3.0
1.5
3.5
.5
2.2
—
—
.9
1.1
.68
.8
3.0
0.9
.68
_
1.0
.9
.5
1.25
1.25
.7.
.75
.9
.7
.7
.75
Efficiency
Percent
80
98
95
90
90
98
95
96.8
84
97
94
99
98.5
99.5
95
98
90
95
97.0
98.3
95
97
99
96.0
97.0
99
98.73
96.0
97.0
97.0
95
99
93.75
99
99.0
95.0
90
99
99
96.5
99
99.35
99.35
99
C-120
-------
PARTIAL INSTALLATION LIST
PRECIPITATORS ON INDUSTRIAL
PULVERIZED COAL FIRED BOILER GASES
Company and Location
FMC Corp., South Charleston, WV
Olin Corp., Pisgah Forest, NC
Michigan State University (Erie City, IN), City of Lansing, Ml
Georgia Kraft, Rome, GA
United Illuminating, Cokes Works #1, New Haven, CT
St. Joe Minerals (Bechtel), Monaca, PA
Tennessee Eastman, Kingsport, TN
Goodyear Co., Akron, OH
Goodyear Co., Akron, OH
Nekoosa-Edwards, Nekoosa, Wl
American Enka, Enka, NC
Spring Mills, Inc., Ft. Mill,SC
Spring Mills, Inc., Ft. Mill.SC
B&W for FMC, Green River, WY
B&Wfor H. K. Ferguson, So., Minnesota Beet Sugar, Olivia, MN
American Enka, Lowland, TN
E. I. DuPont de Nemours £ Co., Aiken, SC
Riegel Textile Corp., Ware Shoals, SC
P. H. Glatfelter Paper Co., Spring Grove, PA
Monsanto Chemical Co., Decatur, AL
Mead Corporation, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Carolina Eastman, Columbia, SC
Monsanto Chemical Co., Decatur, AL
National Starch, Indianapolis, IN
FMC, Front Royal, VA
FMC, Front Royal, VA
Monsanto Chemical Co., Decatur, AL
Quaker State Oil, Farmers Valley, PA
Quaker State Oil, Emlenton, PA
Quaker State Oil, St. Mary's, WV
Allied Chemical Co., Solvay, NY
Tennessee Eastman, Batesville, AR
Gas Volume
CFM
80,000
120,000
294,000
550,000
749,000 ea.
250,000 ea.
135,000 (#20)
1 18,000 (Bal.)
1 70,000 ea.
100,000
89,000
80,000 ea.
80,000
95,400
84,500
655,000
270,000
83,000 ea.
744,000
131,000
325,000
325,151
190,000
161,000
183,900
198,200
108,900
157,000
120,000
97,000
126,715
122,615 ea.
100,000
138,000
109,800
100,000
125,700
30,187
Temperature
Degrees
Fahrenheit
500
340
740
330
-
300
340
450
700
740
375-460
400-460
340
340
800
450
300-400
367
422
285-485
785
325
400
400
400
420
325
480
410
365 ± 30°
460 ± 30°
450-630
553
608
606
350-425
465
Sulfur
Percent
0.9
.5
.6
1.25-1.5
—
1.65
0.6-2.0
0.6-2.0
0.5-1.0
0.5-1.0
2.4
.9
.9 ,
.9
.6
.3
.6
.6
.85
1.5-4.0
0.7-3.7
0.7-3.0
0.6-2.0
0.6-2.0
0.6-2.0
0.6-2.0
.7
0.7-3.7
.6
.7
.7
0.7-3.7
2.46
2.23
1.25
1.0
.7
Efficiency
Percent
99.5
99.5
99.8
99.5
95
98.0ASME
95.46 EPA
98.9
—
99.0
99.9
97.0ASME
99.5 EPA
99.875 ASME
97
97
99.1
99.3 EPA
99.6 ASME
99.35 EPA
99.675 ASME
95.6
98.0
90.0
99 EPA-dry
98.25 EPA
91. 43 EPA
91.43 EPA
91. 43 EPA
91.43 EPA
99.5 EPA
98 EPA
95 EPA
99.2 EPA-dry
99.2 EPA-dry
96 EPA
98.138 EPA
96.267 EPA
97.575 EPA
97.34 EPA
97.7 EPA-dry
C-121
-------
Research Co tt re 11
Air Pollution oontroi uroup
Box 750, Bound Brook, New Jersey 08805
Telephone 201 885-7000
PARTIAL INSTALLATION LIST
PRECIPITATORS ON INDUSTRIAL
PULVERIZED COAL FIRED BOILER GASES
Company and Location
American Cyanamid, Bound Brook, NJ
St. Joe Lead (Kaiser), Josephtown, PA
Luzerne El. Div., United Gas Improvement, Hunlock, PA
University of Washington, Seattle, WA
E. I. DuPont de Nemours & Co., Louisville, KY
Shell Chemical (Riley Stoker), Marietta, OH
Eastman Kodak Co., Rochester, NY
Jones & Laughlin, Aliquippa, PA
Container Corp. of America, Manayunk, PA
Garden State Paper Co. (Carlson & Sweatt), Garfield, NJ
Allied Chem. Corp., Syracuse, NY
Celanese Fibers, Narrows, VA
Purdue University, Lafayette, IN
Monsanto Chemical Co., Portland, PA
Eastman Kodak Co., Kodak Park Works, Rochester, NY
Babcock & Wilcox, University of Notre Dame, Notre Dame, IN
West Virginia Pulp & Paper Co., Luke, MD
Eastman Kodak Co., Rochester, NY
Union Carbide, Institute, WV
Eastman Kodak Co., Rochester, NY
City of New York, South Shore Incinerator, New York, NY
Babcock & Wilcox for Fort Howard Paper Co., Green Bay, Wl
FMC Corp., South Charleston, WV
The Dow Chemical Co., Ludington, Ml
Union Carbide Corp., Institute, WV
Union Carbide Corp., South Charleston, WV
General Electric (B&W), Erie, PA
Tennessee Eastman Co., (UE&C), Kingsport, TN
Union Carbide, Institute, WV
Union Carbide Corp., Chem. & Plastics Div., Institute, WV
Celanese Fibers Co., Rome, GA
FMC Corp., Inorganic Chem. Div., South Charleston, WV
FAS, Philadelphia, PA
Union Carbide Corp., Chem. & Plastics Div., South Charleston, WV
FMC Corp., Lewistown, PA
Celanese Fibers Co., Rock Hill, SC
Eastman Kodak Co., Rochester, NY
FMC Corp., American Viscose Div., Meadville, PA
FMC Corp., American Viscose Div., Nitro, WV
Celanese Fibers Co., Chatillon Rd., Rome, GA
FMC Corp., Inorganic Chem. Div., South Charleston, WV
U.S. Plywood-Champion Papers Inc., Canton, NC
U.S. Plywood-Champion Papers Inc., Canton, NC
E. I. DuPont de Nemours & Co., Clinton, I A
Gas Volume
CFM
90,500
338,000
220,000
50,000
110,000
79,000
152,000
1 ,000,000
191,000
65,700
109,000
130,000
116,000
66,000
152,000
76,000
350,000
181,000
120,000
204,000
136,000
191,500
70,000
90,600
120,000
120,000
133,000
200,000
120,000/Pptr.
120,000
30,000
103,000
216,000
155,000
100,000
135,000
162,000
120,000
50,000
60,000
150,000
187,000 (ACFM)
236,000
75,000
Temperature
Degrees
Fahrenheit
270
273
-
344
430
391
330
630
450
333
400
336
345
900
300
340
350
450
500
325
580-620
290
390
320
500
550
345
280
500
500
335
360
320-420
340
330
410
410
335
505
425
425
480
Sulfur
Percent
3.6
2.2
-
.6
3.5
5.0
2.2
2.8
1.2
1.4
—
.75
1.9
3.3
2.2
3.0
1.5
3.5
.5
2.2
_
—
.9
1.1
.68
.8
3.0
0.9
.68
_
1.0
.9
,
.5
1.25
1.25
.7.
.75
.9
.7
.7
.75
Efficiency
Percent
80
98
95
90
90
98
95
96.8
84
97
94
99
98.5
99.5
95
98
90
95
97.0
98.3
95
97
99
96.0
97.0
99
98.73
96.0
97.0
97.0
95
99
93.75
99
99.0
95.0
90
99
99
96.5
99
99.35
99.35
99
,'75
C-122
-------
PARTIAL INSTALLATION LIST
PRECIPITATORS ON INDUSTRIAL
PULVERIZED COAL FIRED BOILER GASES
Company and Location
FMC Corp., South Charleston, WV
Olin Corp., Pisgah Forest, NC
Michigan State University (Erie City, IN), City of Lansing, Ml
Georgia Kraft, Rome, GA
United Illuminating, Cokes Works # 1, New Haven, CT
St. Joe Minerals (Bechtel), Monaca, PA
Tennessee Eastman, Kingsport, TN
Goodyear Co., Akron, OH
Goodyear Co., Akron, OH
Nekoosa-Edwards, Nekoosa, Wl
American Enka, Enka, NC
Spring Mills, Inc., Ft. Mill.SC
Spring Mills, Inc., Ft. Mill,SC
B&W for FMC, Green River, WY
B&W for H. K. Ferguson, So., Minnesota Beet Sugar, Olivia, MN
American Enka, Lowland, TN
E. I. DuPont de Nemours £ Co., Aiken, SC
Riegel Textile Corp., Ware Shoals, SC
P. H. Glatfelter Paper Co., Spring Grove, PA
Monsanto Chemical Co., Decatur, AL
Mead Corporation, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Tennessee Eastman, Kingsport, TN
Carolina Eastman, Columbia, SC
Monsanto Chemical Co., Decatur, AL
National Starch, Indianapolis, IN
FMC, Front Royal, VA
FMC, Front Royal, VA
Monsanto Chemical Co., Decatur, AL
Quaker State Oil, Farmers Valley, PA
Quaker State Oil, Emlenton, PA
Quaker State Oil, St. Mary's, WV
Allied Chemical Co., Solvay, NY
Tennessee Eastman, Batesville, AR
Gas Volume
CFM
80,000
120,000
294,000
550,000
749,000 ea.
250,000 ea.
135,000 (#20)
1 18,000 (Bal.)
1 70,000 ea.
100,000
89,000
80,000 ea.
80,000
95,400
84,500
655,000
270,000
83,000 ea.
744,000
131,000
325,000
325,151
190,000
161,000
183,900
198,200
108,900
157,000
120,000
97,000
126,715
122,615 ea.
100,000
138,000
109,800
100,000
125,700
30,187
Temperature
Degrees
Fahrenheit
500
340
740
330
-
300
340
450
700
740
375-460
400-460
340
340
800
450
300-400
367
422
285-485
785
325
400
400
400
420
325
480
410
365 ± 30°
460 ± 30°
450-630
553
608
606
350-425
465
Sulfur
Percent
0.9
.5
.6
1.25-1.5
-
1.65
0.6-2.0
0.6-2.0
0.5-1.0
0.5-1.0
2.4
.9
.9
.9
.6
.3
.6
.6
.85
1.5-4.0
0.7-3.7
0.7-3.0
0.6-2.0
0.6-2.0
0.6-2.0
0.6-2.0
.7
0.7-3.7
.6
.7
.7
0.7-3.7
2.46
2.23
1.25
1.0
.7
Efficiency
Percent
99.5
99.5
99.8
99.5
95
98.0 ASME
95.46 EPA
98.9
—
99.0
99.9
97.0 ASME
99.5 EPA
99.875 ASME
97
97
99.1
99.3 EPA
99.6 ASME
99.35 EPA
99.675 ASME
95.6
98.0
90.0
99 EPA-dry
98.25 EPA
91. 43 EPA
91.43 EPA
91.43 EPA
91.43 EPA
99.5 EPA
98 EPA
95 EPA
99.2 EPA-dry
99.2 EPA-dry
96 EPA
98.138 EPA
96.267 EPA
97.575 EPA
97.34 EPA
97.7 EPA-dry
C-123
-------
APPENDIX D
BACKGROUND DATA ON BOILER SIZE DISTRIBUTIONS
CAPACITIES, FUEL CONSUMPTION AND EMISSIONS
CUMULATIVE SIZE DISTRIBUTIONS OF VARIOUS
CLASSES OF BOILERS
The following figures illustrate the size distributions of various types
of boiler/fuel pairings. Most of this data has come from the Battelle
National Boiler Inventory. The capacity percentage of boilers in our
size range of interest, 10 to 250 x 10 Btu/hr, is marked on each graph. ,
This information provides the starting point for the capacity parameters
needed for the Model IV calculations. (See Section V for a further dis-
cussion) . Also provided here are Tables 1 through 15 which indicate both
the cumulative capacity and cumulative number as a function of size.
D-l
-------
Table D-l. SIZE DISTRIBUTION DATA FOR RESIDUAL OIL,
UTILITY BOILERS
&
97
M
il
'. 03
-------
Table D-3. SIZE DISTRIBUTION DATA FOR NATURAL GAS,
UTILITY BOILERS
6^7
7>/
6f>.~7
. 7
Table D-4. SIZE DISTRIBUTION DATA FOR RESIDUAL OIL,
INDUSTRIAL UTILITY BOILERS
c>
J/Z,^8
\ *
J^
6'/S,
5\3j€;
t?^
W.
of.*
/OO
£*,
cT7/
D-3
-------
Table D-5. SIZE DISTRIBUTION DATA FOR DISTILLATE OIL,
INDUSTRIAL UTILITY BOILERS
I
Me.
n
V
—"-'- /
\
x/o
crcTO
£U
Table D-6.
X
SIZE DISTRIBUTION DATA FOR NATURAL GAS,
INDUSTRIAL UTILITY BOILERS
X
o —
/ CrO
437
D-4
-------
Table D-7-
SIZE DISTRIBUTION DATA FOR RESIDUAL OIL,
COMMERCIAL UTILITY BOILERS
•0
A
/t
Table D-8. SIZE DISTRIBUTION DATA FOR DISTILLATE OIL,
COMMERCIAL UTILITY BOILERS
O
j
«.*!-
iti&j&i
~s~
D-5
-------
Table D-9. SIZE DISTRIBUTION DATA FOR NATURAL GAS,
COMMERCIAL UTILITY BOILERS
(
2Z
SOX JO
H
o
/OX./C
D-6
-------
FUEL CONSUMPTION DATA
The following tables provide data on fuel consumption by state for various
boiler types. This data is used in conjunction with boiler size distribu-
tion data to apportion the boiler population on a state by state basis.
The key assumption in apportioning boiler capacity on a state by state
basis is that the cumulative capacity distribution of boilers based on
national totals applies evenly across all states. (See Section V for
further discussion.)
D-7
-------
Table D-lOa.
ELECTRIC
BY STATE
UTILITY OIL AND GAS CONSUMPTION
1
D.S. total
NCM England
Connecticut
Maine
Ma ssachuse tts
New Hn^rpshtre
Rhode Island
Vermont
Middle Atl.lntlc
Nvw Jersey
New York
Pennsylvania
East North Central
Illinois
Indiana
Michigan
Onto
Wisconsin
West North Central
leva
Kansas
Minnesota
Hi ssuuri
N-jhraska
North Dokota
South Dakota
South Atlantic
DC lauarc
Die trice of Columbia
Florida
Georgia
XcslJu.il oil
103 Kol/yr
19.55'.. 050
3.231,415
1.138,103
189, son
1,733,534
77,823
92,000
155
5.430,934
1,552,979
3.199,897
678,058
732,741
252,296
21,950
362,078
59,229
37,183
120,047
9,723
42,53'.
37,769
19,059
4,571
77
6,314
5,630,587
229,131
210,654
2.663,335
135,155
Distillate oil
103 gal/yr
1.117,817
5,232
4,826
0
0
0
406
0
0
0
0
0
140.871
48,561
16,310
51,815
11,568
12,617
75,567
14,667
12,524
27,398
11.048
6,314
440
676
45.833
3,202
0
0
7.590
Cas
106 fc/yr
3,124,690
9,940
C
0
6,600
0
1.900
1,440
25,800"
7,700
12,700
5,400
103,400
26,700
9.1CO
33,000
13,200
21,400
330,700
53,800
158,200
31,200
41,700
42,700
0
3,100
186,820
640
0
132,000
37,400
D-8
-------
Table D-lOb (continued)
ELECTRIC UTILITY OIL AND GAS
CONSUMPTION BY STATE
1
South Atlantic
Maryland
fiorth Carolina
South Carotin*
Virginia
West Virginia
East South Central
A J ob.i'na
Kentucky
Mississippi
Tennessee
West South Central
/rknnsas
Loulu iana
Oklahoma
Texas
Mount nln
Arizona
Colorado
I8
3.261.02/,
542
2. 092
232
333,158
IHjtlll.-.tc oil
103 Ral/yt
0
14,643
17.524
2,774
0
169,851
0
909
168,942
0
410,146
13,850
172. 3SO
3,399
220,517
230,868
195,770
1,890
0
5,808
5,656
21,320
424
0
39.449
22,491
0
16,958
0
0
Gas
106 ft/yr
3,500
350
12,200
320
370
44.690
4,900
4,990
34,800
0
1.960,800
38,800
33'. ,000
283,000
1.305,000
185,540
25,600
63,300
3
0
28,200
64,600
3.100
730
277,000
277,000
0
0
0
0
D-9
-------
Table D-ll. INDUSTRIAL BOILER FUEL CONSUMPTION BY STATE
O
K-1
o
\ 5uV»«.\»*F Slturdnpuj Antiiraclta
\ »o>"W/Yr 103 tonsTyr^ 10 J toii«/yr
Oe fi-itfll '• ^***11— «- sfjO r f • 6 , J 364
t d * LOCfli ^^^ ' *X/tl ' «*M^
New F. -island ffi £ SZlfe) '•'
- i— J
Connecticut 3'.,/O ^ S7»© i
Pennsylvania JW3.5"?'^'^^ 220
East Horth Central ' (o%J7.fr?1 8.778
Illinois J41/?, /^/VQ5 °
Indlana 3jfe3.^ ,t*7.S-<5) °
Michigan 3£?£7 «k3-fr.3&S
Ohio » .fat' - i 7.000
Wisconsin /Ap^x' ff^./O 1>778
West North Central 3^6.?. ao/6 .-Jfii 1.222
Iowa T»t'i , -ffl. 7& \ o
Kansas *>"?-* « »«, 6 ® ,' 0
LlRiitto
103 tons/yr
2.866
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
800
0
0
Uln.iesota AM.t 569. Vp 1.222 0
Missouri ifV.t •:f3^,'tf''. \ 0
Nebraska is?* 'ft-SW) 0
North Dakota if?, •/ /*/,£ : 0
South Dakota /Tf'/' / it, I, \ 0
0
0
800
0
RcsJ.lu.il oil
10-* Rn'/yr
8.443,281
1.090,110
/
/ 305,718
317,310
336,672
60,942
52,453
17,010
1,847,832
638 ,400
427,476
781,956
1.336.440
506,478
467,124
136,962
184,963
40.9C8
356,076
5,250
62,022
20i,D/.4
51,492
4,074
24,733
2,«56
DUtlUato oil* C.is*
lol gal/yr W6 ft3/^r i
3,024,e'iO i^OflJwW '
119,196 -'??'/*
/ a
41.538 9Kk"
15,960 >;•&:-
46,993 ,"/y<3
5,166 C'Olo
6,132 pO;'-'/
3;402 ? PC
369,936 ^5'/b
240,324 A tO 33"
23,100 9S-OVC?
173,166 ^iJj^C''}
36,073 8>/^S&
17,553 IQIC'>3
36,498 fe T i i.3
54,432 602
-------
Table D-ll (coi
\ $,V~V~i»J
\ sw?
V
South Atlantic
Delaware
District of Colunbla
Florida
Ccorr.la
Maryland
North Carolina
South Carolina
Virginia
West Virginia
bet South Central
Al.ib.lM
Kentucky
Mississippi
Tennessee
Vest So'ith Central
Arkansas
Louisiana
Oklahoma
Tcxa«
Mountain
Arizona
Colorado
Idaho
Montana
Nevada
New Mexico
Utah
Wycntng
Pacific
California
Oregon
Washington
Al«sU«
Hawaii
itinued). INDUSTRIAL BOILER FUEL CONSUMPTION BY STATE
lltiuJLogua Aathraclce
103 tSSffvr 103 tons/yr
s>^ \
nZt/r>, 9)
<3&} y*.> • 5-co°
^yroV*) 30QO
ikc.i |v.s-.A0 o
*>'/.e ! />/?'-; 0
y/r.o i '*'**•> 0
ytrf. fcj ys°. f(i 0
>9V&! 5VJi5- 1.1 11
(n> \ .//*?&> 0>889
i£63. i ?*'3. O °
^^ i ,4ri 0
/ |
jv. y { &2& °
ii-/fe i M'/iij: 0
i i ft ! j J> /A^i
|1, f j i*. f(5j) 0
95, J- \ ye-i^ii
I50>,/ ] f/5,7 i o
Vfrs,v ; ai/.cei o
o'z.y ' -
7r?,z" ?j.:cd 1>333
S-/ , */ ^(?i 0
» ,' 0
,1,4.1 \ f7.f& 1.333
\ \
Jbl.C IVS.fSj °
. 0\ 6 1 0
Lignite
103 ton«/yr
0
- 0
0
0
0
0
0
0
0
0
0
0
0
0
0
2,000
0
0
0
2,000
66
0
0
66
0
0
0
0
0
0
0
0
0
0
0
toaUual oil
103 gal/yr
1,941,954
154,132
2. 940
359,352
305, 17J!
305,298
292.C68
165,144
341,628
16.170
196,812
92.9S8
31,878
58,968
12,976
473,038
79,254
99,582
53,508
240,744
290,157 .
106,302
19,57?
1,365
37,800
18,774
34,432
47,418
24,444
839,412
502,362
115,453
221.592
22,764
48.636
DlatlUate oil
103 gal/yr
477.834
1C, 584
1,134
65,436
. 67.244
69,334
103,152
50,442
BO.C84
29,734
205,086
60,060
42,924
30,492
VI. 610
363.678
28,644
. c«»
10* ftj/yr ;
J'^tri'U
S'f/l
I •>«'••!
5i '•'(.
I
30>i>Z.
<^0^01
v/oi/
•76 t>"}J
VOO 3 7
/f9^frt
^WA
102,312 : (,4?01t
55,440 ! qoSll
177,282
313,698
10,122
38,724
30,996
56,910
1,680 i
//V0r?D
J? 3 7^-7
^77^
*/>0>^
_ /•
/"r^ofo
Z/5'Tf
!&'*<{
21,924 ! 39V'^'7
113,862 ^]rtOl
39,480 i J'ioSg
I
398,454 V?3,?/^
246,582 • 3* 3 $01.
72,618 J3$>2?
79.254 tmf,
11.970
10.962
?sC7
0
-------
Table D-12. COMMERCIAL/INSTITUTIONAL BOILER FUEL CONSUMPTION BY STATE
Bltumlnoui Anthracite
10^ tons/yr 10^ cons/yr
U.S. total < 7 o'l!
New Fpolnnd 1^.3
New llanpshire ./i
Rliot'e Island • ''•>
Vermont ' ',
Middle Atlantic /CC
.y? c
3.3,7 0.6
.5? 0
•; L o
'& 2.3
f;?^)' 2,088
N'-w Jersey /2./J */i,(, ' ' 111
New York jy '/
Pennsylvania )«
Enst North Central ti?^ {
Illinois r, (
Indlon.i v'.u I
Michigan <7 ^. 3 '
Ohio m."J
Wisconsin T^.te
Wost North Central ^ j
Iowa "O /
Kansas /• ?
Minnesota V/. £j
Missouri //.?(
Nebraska /> 0 '
North Dakota ^,2. |
"South Dakota ifJ
A" . £^*' *^'
15^'^; >>748
j/^'.^5 0
/
;-/3<; ' o
33:i'J: 0
^7.S,7(i.\ 0
£^0,3 o
39?V 0
a7/ : o
"/' T"' ! °
^l ^ ': o
'V5 ' -. i °
V ' / i n
f-e ' o
;/•? 0
/t,^ 0
R«il
-------
Table D-12 (continued). COMMERCIAL/INSTITUTIONAL BOILER FUEL CONSUMPTION BY STATE
Bltu
103
^oiitli Atlantic "t
Delaware •' -'
District of Columbia .Jy'
Florida ^, v
Georgia ^^
Maryland , ',
North Carolina .'Jji*
South Carolina JJ'-j
Virginia ^<: ?
West Virginia <>
t«st South Central /??..?
Alabama *'
Kentucky fr-i'
Mississippi
Tennessee /p7'*
West South Central ,»-.
Arknnsas C
Louisiana £
Oklahoma Q
TCXHS C
Hountnln 5 ^7-' $
Arizona »'-i
Colorado -i.5
Idaho r- -y
Montana ^ i
Nevada -— . ._. > ,c7i
Ncv Mexico 0
Utah Q
Wyoming £>
mlnoAu Anthracite
on»/yr 10^ tons/yr
/•^?;.^ 21
v' '•' n
3'. -' °
/o. ? °
. • 0
_pn < 10
/K"'' 0
*' ^V"~ • " 0
<5--:/£ o
0 0 '
*&-2'-.'v Q
'o " ' ' 0
^x'i o
. - . f' 0
lC*,l O Q
0
0
0
0
0.
''••i.-i® o
. V 7 0
J i . i 0
.'' f ~ ! 0
^-;,7 i 0
.2:1 o
r o
r o
o c
\
toiiis. 0] c, ,
California ^ 0 ®
Oregon j i? \ ^ ; 0
Washington ! ^ ' c "
Alaska | O 'i 0 °
1 ;
Hawaii O| £, 0
kslduitl oil
103 R.il/yr
872,046
44,772
213,234
106. B90
104,664
221,676
83,874
8,400
71,442
17,094
60,984
40,866
8,862
2,772
8,484
73,122
19,614
630
4.410
48,468
84,336
0
25.662
6,930
8,736
3,402
2,814
23,436
13,356
399,966
133,098
138,852
128,016
546
3,528
DliCUlatc oil
867,636
51,282
35,028
125,496
84,420
138,432
204,246
38,976
18'1,440
8,316
484,428
128.604
83,938
109,158
162,708
807,744
80,724
99.540
86,352
541.128
347.508
34,230
70,938
27,426
17,472
8,104
66.360
80,388
41,790
414,162
408,114
6.048
0
0
0
106 ft3/yr
170,300
2,400
3,200
26,800
35.800
26,500
18,500
13,103
26.600
17,400
119,100
28.300
34.700
21,400
34,700
221,300
31,000
4] .500
32.900
116,400-
139,600
22,300
51.000
7,400
13,900
9,500
18,800
6,300
10,000
190,400
157,800
10,000
"vwoo
8,400
0
x\ \ i • ' :
-------
Table D-13. CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF ELECTRIC UTILITY BOILERS BY STATE
F.e\ lUi (Or %oA«f
T1?«- . _ _ -
{?.»„
ut\ 6
F.r'. .
;-• «,,.;-=/ „.-,<-.{
.4,0.. ie S<-ot<-
77.6
/.*?
iJJ:r, fr ni
o
V,
6 '
.^i
/e.c
-------
Table D-13 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF ELECTRIC UTILITY BOILERS BY STATE
/Or
-yy .=-.:O
-------
Table D-13 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF ELECTRIC UTILITY BOILERS BY STATE
/Or
^ • •• -~ . -•*: r«'-f*,
'-':.,.,!<• p..' •, '?<*
F.f..,
I
F.e\ fcvl /Or
^Hf-
S-i^. -.,.. -P/.,~.t-E
.'[ n, I
at\ B
76.
-------
Table D-13 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF ELECTRIC UTILITY BOILERS BY STATE
/Or V.W
. ,
Ckfkl.l^ ft At ClMMfk*.
tci *>.»:..j », ft* i 6
//yy c.
./AT
//>/
/• */ o, A
F.t\ k*\ /Or
/* i
'•^^—i-
a.&to <3./t/*»_ ____ <
£>. <$*$.$ £>,jf& 7,
0.S4.I 0.&3&, /•/?
J )e>v
-------
Table D-13 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF ELECTRIC UTILITY BOILERS BY STATE
F-*\ fcv.i/0^
g^- .,.t-B..'.^._.
C.C/7
C-60/
o
M
oo
0,066 "
F-e\ AV.& /Or V.V«
i » R»-.»
0*886- t*.
&.>&& 993 /
-------
Table D-13 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF ELECTRIC UTILITY BOILERS BY STATE
F»t\ fc.i /Or VA«
a
vo i—£_
8- , Coc-
; oj /o
4 jj*s _ jfl'
i1 «.L/>
'flv/
ryr-,
/'
.| J J_
-------
Table D-14. CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF INDUSTRIAL BOILERS BY STATE
Oer^. Me , Ma . TI , H,
W /Or
i* fo>.tu__ _
M __5L.
us,
<7,33
O o
6
_0__
O
70? ? ,
c '
.., * F-«l
.//J
:?/*/
N5
O
C\
6 O
3/6
-123 .Q-/?
C- 0
ut\ 8
fO-
^^. , y, i<
-30C
/C.+
•3o>>>-*'-
J&.0 52.
/.'f yyg
;;-i
-------
Table D-14 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF INDUSTRIAL BOILERS BY STATE
'Ly. *•{. £W:U;
F»e\ fcwi /Or %o\\
o
0
0
v , 0
I c ,
Clfkl'.Vf
ut\ B
0 0 O
-Sr_
O
<•: c
-£L
.130
2,1. S
15."}
,7__
35C.S
L/_
23_
_ax_
f/t 'j,
7,73
*"*
,2$
V-5.C-
>« .SO,/
NJ
,.U^>A
F-e\ fe-i /Or ^'
0
o , o
U
/, 7
c, o
0
5 1 3
$.97 t.tf
-4
0 0
±rj
-------
Table D-14 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF INDUSTRIAL BOILERS BY STATE
J1L . &*
F-£\ *,»>. /Or %oA«t
f-lf'-
6
<0
R-l
?.Wi- »- '5
*!L4_
gu ^>V C.\
50.
/u, 7 /?/
-•?/
Si.rV-A\vU OA
-------
Table D-14 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF INDUSTRIAL BOILERS BY STATE
AI \c A> -,
n ' *ZL l^y I"' ijj-p» I -ev\ A ,
/Or
Cif kt'Ax^
I o o
0
0 0
C< 0
*'F.HU
;?i.c
G
N)
/Or
-------
Table D-14 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF INDUSTRIAL BOILERS BY STATE
Tl
,?t£> 'I?.
n <>»+*«.
o
H
M.n,
C' c--. C-
ft.
O : C) O
JAL
3t.?77
0 O
< 7. /of
O
,32
.to1? •
t/,001- oee
OA
. /71/
G.X.,
a
N3
3L&A.
^
0
0 ' C?
0 0
/?A^
£L.
c.
.,iY ._?>**._.
O O
o
^ ' t t 1
,2-32- ,
0
O
-O-
S;-V.'Avl<. O.V
"*9e>'
7 7
o o
.. OA
-------
Table D-15. CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF COMMERCIAL BOILERS BY STATE
F-e\ hv-i, /Or Ww J^J
o.&so c, c<~--
£>./
0, 0/0 0,
o.s/8
CA
3-57 *l
N5
Ui
F.t\ fcvi /Or
PA.
.06 S"*/
-------
Table D-15 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF COMMERCIAL BOILERS BY STATE
F.«\ IWi /Or lo.W
vt\ B
30.3
OA
<&> 4*1
0
N3
- •
/Or %o,
63 A
/v, 0.
?.L»-'.»«1
s&.y
D \-V.V\vW.
-------
Table D-15 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF COMMERCIAL BOILERS BY STATE
F«t\ fcv^ /Or lo
*****
F-«A
* F^-J * F.41
SU^tt
?.Li*.»«l tt.u
/i /Or
A/- <^^
?•.'-«..
•0.3?8\/f,6
0 <=> O
V/.y ':
<*?
-------
Table D-15 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF COMMERCIAL BOILERS BY STATE
K»V«._ ^O-j-^
&.*//& /j,o
9. At
0
C5 0 O
SV- X-A Ci\
OA
\/3,J53
o F.*\
i
K> •
03
%e,W
; 0
Mj£~
/&'<£" /6s/Xs*
37, y i
7//7
-------
Table D-15 (continued). CAPACITY, FIRING RATE AND FUEL CONSUMPTION OF COMMERCIAL BOILERS BY STATE
O O
fi? C?
_2A_
7.
N3
ut| B
<£> 0 0
o o o
066
^- 6V- /^r g, - CaiA \o3
! DA . «?
-------
Table D-16. TOTALS ON CAPACITY, FIRING RATE AND FUEL CONSUMPTION FOR ALL BOILERS
(UTILITY, INDUSTRIAL, COMMERCIAL) IN THE SIZE RANGE 10-250x10° BTU/HR BY STATE
< £.
O ' O
.U*o ,'//o '/.
//./
LU.
0 ' 0
O
'• O o
e) • '• O
f"1
.I5(o
1L2^
_£227J
!>^ 33.? 33/97 M
1, 0.8:
1,37
F-e\ A«!i /Or %o,\
' o
' '"•
?2./ agy
3JC
»5/ :;a?
7/1
-------
Table D-16 (continued)
F-e\ A.«i
JLi.
TOTALS ON CAPACITY, FIRING RATE AND FUEL CONSUMPTION FOR ALL BOILERS (UTILITY,
INDUSTRIAL, COMMERCIAL) IN THE SI£E RANGE 10-250xl06 BTU/HR BY STATE
• F.«.\
'->
^J', 7
;?«"#.
0 C
C'
0
£2,3 ,?. 3
/r-J_,
O O
6-
(9
u .
0
S
8
/7,3
ZZ3&S9
u>
3^7 /
F.t\ A.A /Or %c,\«f
a.
i/ 57,
N £££*<> ICH
33. G ! /5.5T! 704.
3.3V
o.
tf,
i. lo
37, 3
0/^3 0, OTI 3,^2
IS.7-
97. /
i-'^^f ?.i
O ,
2,62. I.3S
0:0
0
0:0
0
O
0
$31.
0
O
0
0 i O
O
o
n 3,,* 7,4 ; sv;«,
/S.5
ze.o i /A4/
a. 1
7?
«?7. 2 i
-------
Table D-16 (continued). TOTALS ON CAPACITY, FIRING RATE AND FUEL CONSUMPTION FOR ALL BOILERS (UTILITY,
INDUSTRIAL, COMMERCIAL) IN THE SIZE RANGE 10-250x10 BTU/HR BY STATE
F.e\ A»k /Or
SD
ilL. ..U&L-
DC
q-.T-g \ I.It?
/, Lc '' 73, -
•>, 3 -5". '-'if'
it'll ' -;:,io /io,
£
M
1/4.
/.-J3
577 1
//.? t.ol %>$
.2.60 ,
* F...U, <^
i /?.i '
/^3
j^L
47
L ,. J.
.//5" i .0/7 i .^ttO
/IS.
H.S
;4.7
.» 7/U/8
Jt.Vitt.*
i 38,0
3 'So r.*C»
-------
Table D-16 (continued). TOTALS ON CAPACITY, FIRING RATE AND
INDUSTRIAL, COMMERCIAL) IN THE SIZE
FUEL CONSUMPTION FOR ALL BOILERS (UTILITY,
RANGE 10-250xl06 BTU/HR BY STATE
F-«A fcv-fc /Or V,W
A
7^5"
/44
JLL
44.1
943
\
*'
/4.4 i 13. i
J.bl i-l<>
l£L
lAJ
o.oS?
O
t
. 0
67,0
/o.a
F.e\
-y--.,^ ,.
7-ex,
9,67
V/25-?
/,/3 '^y
•R4-^-. -.,..• '-,-\ =
o i a
77,
es
o o
o
/,
cs
1 CD
«D
o
cs ! O
O
e>
^9,7
36-6
/7V
A V i
&2.
^630
-------
Table D-16 (continued). TOTALS ON CAPACITY, FIRING RATE AND FUEL CONSUMPTION FOR ALL BOILERS (UTILITY,
INDUSTRIAL, COMMERCIAL) IN THE SIZE RANGE 10-250xl06 BTU/HR BY STATE
F.t\ fc.l /Or
lot,
3,98
/*•!•
tl.t
; O.03I
0.07k-
0.3.10
/,
//,(»
1- o - •• r f_ ' t* f
o
0.0/7
a
G
U)
/y.g
3.
'/.to
31,
23. 1
2-7,8
F.e\ fc.i /Or V
T.,?«.
S-i .,--.,.,,. TV,.-. i
, /
zo,osi.
3V, 7 /8,8
J3. 4 v f t - w_- ^^'
O
' O
o
0
o
3. Yd-
O
0.3$)' 0, /6V
.e&Y /.off
o
o
o
o
o
cs
c;
0
0 ! C? 0
0 • 0
er o
'"if ^'
/t_r__B*.i«/yn I
1 B- \.
.10* *•-/»"
•h-
-------
SIZE DISTRIBUTION DATA FOR BOILERS SUMMED OVER ALL USE
CATEGORIES (UTILITY, INDUSTRIAL, COMMERCIAL)
The following figures indicate the size distributions of the various
boiler/fuel combinations when the state totals are summed over each of
the categories — electric utility, industrial and commercial.
D-35
-------
Figure D-l. Residual oil, three categories design firing rate versus
percent < stated size
D-36
-------
Figure D-2. Distillate oil, three categories design firing rate versus
percent < stated size
D-37
-------
Figure D-3. Natural gas, three categories design firing rate versus
percent < stated size
D-33
-------
WEIGHTED AVERAGE EMISSION FACTORS
The following tables provide the weighted average emission factors by
state which were used in our Model IV calculations.
D-39
-------
Table D-17. RESIDUAL OIL WEIGHTED AVERAGE EMISSION FACTORS
CGUU
He
M*
N. H.
R.H.
\|T
u,T.
Kl.Y.
PK
ru
ovi
VMI
10
Kk
MO
NE
•S/fc.
1>E
T>,C.
FL
GA
hl>
K),C.
S..C.
^k
wj.•>•*(.
V-h"!
$?, W J
•Ho.?'?
., s.-..
PwrtU,WV«.
I
J3
(U.-Xu.
J~7.V
S./,7
j'j.y
/'/•?
//?.&
yy. /
'A?, y
Jcl.i
/PJC.A
37?
3o3
dig
3oj
So,
(TO
3/4
44
4-7 /
4*1
i4t
nt
3k e
-------
Table D-18. DISTILLATE OIL WEIGHTED AVERAGE EMISSION FACTORS
COUtt
N. H.
R.t.
MT
M,T.
U.Y.
PK
IL
tK)
H>4V»
OW
\A)1
10
WE
Nib
-S.fc.
FL
i.C.
AU
MoUT
OT
CA
0«.
«•>*'
v/3
V8M
•f&.O
Je.if
AT
S"S,0
U*u*«
&'
3
3|
i
»
3
I
|
, J
>.
>
»
S
9
J
3
i
J
*
3
2
J
3
£
3
.4
^
4
1. *
Utul
I.
7
f
7
f
S
J
i
3
f
3
3
J . .
j
•a
P
^
3
3
7
3
7
4
3
3
n
V)
ti
23
*»
^
41
n
]f
41
So,.^.^*)
AV>V 9,;J
7f
jrr
7J
/If
ISS
314
43
4»b
?? /
Jfl /
43
V « »
*'J
3/0
4f*
37
A ^*3
Ji^«
37
?47
<*Aft
5*to
3^2-
413
413
/4t
?/
^3
M/
/4t
7t4
4«
111
1 7«*
437
^i>4
3.03
338
«t
37
a-48
37
o7
?•*
3/0
&r
11
933
oa
70
4f
9/J
4/
71
71
-s'49
I3t
*.<•
M»i0.fc
Uv>|.^
.M
7J
«
-»u«i
cv
.5-
OOv'*
Jfck..!f
44.
1
M
13
4>
•>:
',
v
4'
7-
,
>
M
•M
V
V
7;
^
.Tfc
D-41
-------
Table D-19. NATURAL GAS WEIGHTED AVERAGE EMISSION FACTOR
COklkJ
N. H-
R.T:.
\JT
M,T.
U.Y.
Pfc
XL
tK)
lo
MO
ME
FL
CA
MI)
Ki.C.
AL
KY
VA\*i
i «*>^
A»s»
COLO
XT)
HoiJT
OT
C.A
Oft.
UJX
AUJ-
743
/j ;.--r/
'Cf,Ul
IS),
-------
APPENDIX E
CONVERSION TABLES
E-l
-------
Flow rates: ^- = 1.71 x SCFM
hr
Emission rate: S = 4.19 x 10~3 -&=
106 cal GJ
J GJ
Boiler capacity: 1 Boiler Horsepower = 2.99 x 10~5
nr
1 MW = 3.4483 x 106
hr
Pressure: 1 atmosphere = 14.7 psi
Temperature: °C = 0.5555 x (°p - 32)
E-2
-------
EMISSIONS UNITS CONVERSION FACTORS
I
LO
~^^«uiu.i.jJiy oy
To Obtain ^^^^-^.^
% Weight
In Fuel
Ibs
10& Btu
grains
10b Cal
(ppm) Vol.
Dry Basis
grains
SCF of flue gas
% Weight
In Fuel
1
10, 000 (M)
(A) (HV)
18, 000 (M)
(A) (HV)
10,000
(A) (N)
95. 9 (M)
(A) (N) (TR)
Ibs
106 Btu
(A) (HV)
10, 000 (M)
1
1.8
HV
(M) (N)
. 00959 (HV)
(N) (TR)
grams
10b Cal
(A) (HV)
18, 000 (M)
1
1.8
1
HV
1.8(M) (N)
. 00533 (HV)
(N) (TR)
(ppm) Vol .
Dry Basis
(A) (N)
10,000
(M) (N)
HV
1.8(M) (N)
HV
1
. 00959 (M)
(TR)
grains
SCF of Flue Gas
(A) (N) (TR)
95.9(M)
(N) (TR)
. 00959 (HV)
(N) (TR)
, 00533 (HV)
(TR)
. 00959 (M)
1
A = Atomic Weight of basic element considered: A = 14(Nitrogen) , A = 32(Sulfur)
HV = Fuel higher heating value: Btu/lb of fuel
M = 30 (NO) , M
o
N — Moles of dry flue gas per pound of fuel. Typical values are:
M = Molecular weight of oxide emitted from stack: M = 64(SO ), M = 80(SO )
46(N02)
Fuel
Natural Gas
Fuel Oil
Coal
N
3% 02
0.618
0.554
0.369
N
o% o2
0.530
0.474
0.316
N
15% 02
1.85
1.66
1.11
N
12% C02
0.539
0.626
0.481
HV
(btu/lb)
23,440
19,100
12,280
T = Standard Temperature in degrees Rankine used for defining SCF of flue gas: EPA T
R R
County APCD's T_ = 520°R.
530°R,
-------
CONVERSION FACTORS - EMISSION RATES
Desired
units
Given
units
gms/sec
gms/min
kg/hr
kg /day
Ibs/min
Ibs/hr
Ibs/day
tons/hr
tons /day
tons/yr
gms /sec
1. 0
1.6667
X lO"2
2. 7778
x icr1
1.1574
x io-2
7. 5598
1. 2600
x io-1
5. 2499
x io-3
2.5199
X IO2
1. 0500
X 10
2.8766
x io-2
gms/min
60. 0
1.0
16.667
6. 9444
X 10-1
4. 5359
X IO2
7. 5598
3.1499
X lO'1
1. 5120
X IO4
6.2999
X IO2
1. 7260
kg/hr
3.6
6.0
X IO-2
1.0
4.1667
x io-2
2. 7215
X 10
4. 5359
X ID"1
1. 8900
x io-2
9.0718
X IO2
3, 7799
X 10
1.0356
x io-1
kg /day
8. 640
X 10
1.4400
2.4000
X 10
1.0
6. 5317
X IO2
1. 0886
X 10
4. 5359
x io-1
2.1772
X104
9. 0718
X IO2
2.4854
Ibs/min
1. 3228
x io-1
2. 2046
X ID"3
3.6744
X ID'2
1.5310
X 10'3
1.0
1.6667
x io-2
6. 9444
X IO-4
3. 3333
X 10
1. 3889
3.8052.
x io-3
Ibs/hr
7. 9367
1. 3228
x io-1
2. 2046
9.1860
x io-2
60.0
1. 0
4.1667
x io-2
2. 0
X IO3
8. 3333
X 10
2.2831
x io-1
Ibs/day
1.9048
X IO2
3.1747
5. 2911
X 10
2.2046
1.44
X IO3
24.0
1.0
4. 8000
X IO4
2. 0
X IO3
5.4795
tons/hr
3. 9683
X IO-3
6. 6139
X IO-5
1. 1023
X 10'3
4. 5930
x io-5
3. 000
x io-2
5.0000
x io-4
2. 0833
X IO-5
1. 0
4.1667
x io-2
1.1416
XIO'4
tons /day
9. 5240
X 10~2
1. 5873
x io-3
2.6456
x io-2
1.1023
x io-3
7. 2000
x io-1
1.2000
x io-2
5.0000
xio-4
24. 0
1.0
2. 7397
X lO'3
tons/yr
3.4763
X 10
5. 7938
x io-1
9. 6563
4. 0235
x io-1
2. 6280
X IO2
4. 3800
1. 8250
X ID"1
8. 7600
X IO3
365.0
1.0
To convert a value from a given unit to a
and beneath the desired units.
desired unit, multiply the given value by the factor opposite the given units
------- |