EMISSIONS
FUEL OIL CO
An Inventory Guide
U. S. DEPARTMENT OF HEALTH, EDUCATION, AND WELFARE
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ATMOSPHERIC
EMISSIONS FROM
FUEL OIL COMBUSTION
An Inventory Guide
Walter S. Smith
Technical Assistance Branch
Robert A. Taft Sanitary Engineering Center
U. S. DEPARTMENT OF HEALTH, EDUCATION, AND WELFARE
Public Health Service
Division of Air Pollution
Cincinnati 26, Ohio
, November 1962
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The ENVIRONMENTAL HEALTH SERIES ol reports was estab-
lished to report the results of scientific and engineering studies of man's
environment: The community, whether urban, suburban, or rural,
where he lives, works, and plays; the air, water and earth he uses and
reuses; and the wastes he produces and must dispose of in a way that pre-
serves these natural resources. This SERIES of reports provides for
professional users a central source of information on the intramural
research activities of the Centers in the Bureau of Disease Prevention and
Environmental Control, and on their cooperative activities with State
and local agencies, research institutions, and industrial organizations.
The general subject area of each report is indicated by the letters that
appear in the publication number; the indicators are
AP Air Pollution
RH Radiological Health
UIH Urban and Industrial Health
Reports in the SERIES will be distributed to requesters, as supplies
permit. Requests should be directed to the Air Pollution Technical
Information Center, National Center for Air Pollution Control, Public
Health Service, U.S. Department of Health, Education, and Welfare,
Washington, D.C. 20201.
Public Health Service Publication No. 999-AP-2
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PREFACE
The total inventory of pollution emitted to the atmosphere
from all types of sources in a community will provide part of the
basis for consideration of the possible need for control of air
pollution. This review was prepared to provide a guide for in-
ventorying and controlling emissions arising from combustion of
fuel oil. Information was collected from the literature. Addi-
tional data were provided, upon request, by several power com-
panies. This review is limited to information on oil used as a
source of heat or power (exclusive of process heaters). The data
were abstracted, assembled, and converted to common units of
expression to facilitate understanding.
Although much has been done to increase the accuracy of
sampling methods, stack sampling is not an exact science and is
subject, in some cases, to significant errors. Because of this
limitation and the many design and operating variables, there is a
wide range of values for emission of any given pollutant. In a
literature review of this nature, where all the published values
are impartially reported, it is appropriate to recommend those
values reported most frequently. In most cases, this has been
done. When the most frequently reported value was not compat-
ible, however, with theoretical possibility, the value recommend-
ed was selected in the light of good judgment.
Emission values are subject to continual change as data are
made available. It is expected that current investigations on the
air pollution arising from the combustion of fuel oil will give
more complete information on this subject. Investigations now
being conducted include: (1) a survey of emissions, including
polynuclear hydrocarbons, by the Division of Air Pollution,
Public Health Service, at the Robert A. Taft Sanitary Engineering
Center in Cincinnati, Ohio; (2) a literature search, by the Bureau
of Mines at Laramie, Wyoming, for fuel oil deteulfurization
processes; (3) a study of means for removal of sulfur dioxide
from flue gases, by the Bureau of Mines at the Bruceton Station,
Pittsburgh, Pa.; and (4) a survey of emissions from the com-
bustion of fuel oil in residential and light industrial furnaces,
sponsored by the American Petroleum Institute.
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ACKNOWLEDGMENT
Grateful acknowledgment is extended to Jean
J. Schueneman, Donald F. Walters, and William
J. Schick, Jr., of the Technical Assistance Branch,
Division of Air Pollution, Public Health Service;
and to Arthur A. Orning of the U. S. Bureau of
Mines for the time and effort they spent reviewing
and editing this report.
IT
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CONTENTS
Page
Summary , 1
Introduction 1
Fuels 4
Aspects of Oil Combustion 15
Oil Preparation " 15
Oil Combustion 16
Smoke Formation . . . 16
Acidic Smut Formation 16
c
Emissions from Large Installations 17
Oxides of Nitrogen (NOX) 17
Theoretical Considerations 17
Emission Rates 19
Tangentially Fired Units 19
Horizontally Fired Units 19
Variables Affecting Emissions 21
Firing Rate 21
Two-Stage Combustion 22
Load Factor 22
Excess Air 22
Windbox Pressure 23
Flue Gas Recirculation 23
Fuel Pressure and Temperature 23
Other Variables 25
Sulfur Dioxide (SO2) 25
Theoretical Considerations 25
Emission Rates 26
i
Sulfur Trioxide (803) 26
Theoretical Considerations 26
Emission Rates 28
Variables Affecting Emissions 31
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Page
Other Gaseous Emissions 32
Particulate Emissions 32
Emission Rates 32
Particle Size 34
Chemical Composition and Description 35
Variables Affecting Emissions 36
Efficiency of Combustion 36
Atomization 38
Windbox Air Admittance 38
Burner Tilt 39
Excess Air 39
Flue Gas Recirculation 39
Sootblowing 39
Emissions from Small Installations 40
Oxides of Nitrogen (NOX) 40
Sulfur Dioxide (SO2) 41
Sulfur Trioxide (SO3) 42
Other Gaseous Emissions 43
Particulate Emissions 44
Control of Emissions 45
Oxides of Nitrogen (NOX) 45
Sulfur Dioxide (SO2> 45
Sulfur Trioxide (SO3) 45
Smoke and Organic Gases 46
Acidic Smuts 46
Participates 46
References 49
Appendixes 55
Appendix A: Detailed Data on Large Source Emissions.
Appendix B: Detailed Data on Small Source Emissions.
Appendix C: Method of Reporting the Data.
VI
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ABSTRACT
This review provides a guide for the inventorying and control
of emissions arising from the combustion of fuel oil. Information
was collected from the published literature and other sources.
The report is limited to information on oil used as a source of
heat or power (exclusive of process heaters). The data were
abstracted, assembled, and converted to common units of ex-
pression to facilitate understanding. From these data, emission
factors were established that can be applied to fuel oil combustion
to determine the magnitude of air-contaminating emissions.
Also discussed are the compositions of fuel oils; the preparation
and combustion of fuel oil; and the rates of emission, their
variables, and their control.
Vll
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ATMOSPHERIC EMISSIONS
FROM FUEL OIL COMBUSTION
An Inventory Guide
SUMMARY
The kinds and amounts of atmospheric emissions arising
from the combustion of fuel oil are summarized in Table 1. The
data in this table are divided into two groups, one for large
sources (1,000 hp or larger) and the other for small sources
(smaller than 1,000 hp).
In general, large sources produce more nitrogen oxides (NOX)
but less soot than the small sources. This is because of the
higher flame and boiler temperatures characteristic of large
sources. Small sources emit relatively larger amounts of
hydrocarbons because of the small flame volume, the large pro-
portion of relatively cool gases near the furnace walls, and,
frequently, because of improper operating practices.
Table 1 contains values that may be used in making an
inventory of emissions from combustion of fuel oil. After the
surveyor has ascertained the amount of fuel used and the sulfur
content of the fuel, he can estimate the quantities of stack emis-
sions by the application of data in Table 1 and by judgment based
on pertinent information in this report. It must be remembered
that these values are general averages and can only provide rough
estimates for the total emissions from a number of sources.
Emissions from any one installation may vary considerably from
those estimated by use of data in the table.
INTRODUCTION
Twenty years ago oil was considered to be a "clean" power
source. Compared to coal, its use results in emission of approx-
imately 90 percent less particulate matter. Oil combustion units
do, however, emit many pollutants into the air: nitrogen oxides,
sulfur oxides, and particulate matter are those most commonly
of interest at this time. Other emissions are carbon monoxide,
aldehydes, carbon, organic acids, and unburned and partially
burned hydrocarbons, which are usually emitted in relatively
larger amounts either from small sources or from inefficiently
operated large sources. *
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Table t. SUMMARY OP EMISSIONS FROM FUEL OIL COMBUSTION a> b>c
Gaseous and
particulate
emissions
NOxasNO2d
horizontal
tangential
so,"
so,'
oof
Aldehydes'
Hydrocarbons and
other organics*
H2S'
HCNf
HCl'
NHjf
V
Parttculates
Large source emissions (1, 000 hp or more)
Extreme range,
ppm In the lb/1, 000
stack gas Ib oil
0-1, 020 0-26
160-400 4. 4-11
(52-520)3 (2. 0-20)S
0-76 (0. 063-
2.9)S
0->100 0->1>7
0-67 0-1.2
0-5
<50
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Steam generation plants operate over a wide range of con-
ditions, and designs of larger plants vary widely. The rates of
emissions from these units are affected by variable operating
conditions and by nature of the fuel used. An indication of how
emissions are affected by operating variables is given in Table 2.
Table 2. EFFECTS ON EMISSIONS OF INCREASING
OPERATING VARIABLES a
Increasing
operating variables
Percent load
Fuel temperature
Fuel pressure
Excess air
Percent CO2 in stack
Dirt in firebox
Flue gas recirculation
Flame temperature
Stack temperature
Percent sulfur in oil
Percent ash in oil
NO SO2
X
I
D
D
I
D
I
D
I
-
I
-
so3
I
I
I
I
D
I
-
I
I
I
D
Particulates
-
D
D
D
I
I
I
D
D
I
I
a I means increase; D means decrease; -
means no change.
Information was collected from the published literature and
from other sources on stationary equipment for combustion of
oil, mainly furnaces, boilers, and power plants (exclusive of
process heaters). All data obtained have been included in this
report, even though some are very probably inaccurate. The
pollution sources are divided into two categories, large (1,000
hp or larger) and small (smaller than 1,000 hp). Unless other-
wise stated, the emissions are reported in parts per million
(ppm), by volume, or grains per standard cubic foot (gr/scf),
corrected to 12 percent CO2, or in pounds of pollutant per 1,000
pounds of oil fired. One standard cubic foot (scf) is taken as one
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ATMOSPHERIC EMISSIONS
at 32°F and 1 atmosphere of pressure, on a dry basis. In oil
combustion, 12 percent CO2 in the stack gas corresponds to
approximately 25 percent excess air or 5. 5 percent O2 in the
stack gas. The newer boilers normally operate with about
14 percent CO2 in the stack. When a boiler is referred to as
operating at "normal load," it is usually operating at about 85
percent of its maximum continuous capacity.
Detailed emission data are given in appendixes A and B.
Appendix A contains data for large sources, and Appendix B, data
for small sources. Appendix C illustrates the method used in
this report for graphically presenting the data.
Several factors were used to convert values found in the lit-
erature to uniform terms for this report, when necessary. These
factors were as follows:
1-bbl oil = 42 gal
1-lb oil fired = 215 scf of stack gas at 12 percent CO2 (dry)
1, 000 hp = 34, 500-lb steam/hr = 2, 500-lb oil/hr (assuming
75 percent efficiency)
Percent (X>2 = 16. 2 - 0. 775 X (where X = percent Og in the
stack)
When data on composition of residual oil were not given in material
reviewed, the following fuel analysis was assumed:
86 percent carbon, 10 percent hydrogen, and the balance
H2O, O2, N2, sulfur, and ash; 18,300 Btu/lb; 12° API* or
8. 2 Ib/gal.
FUELS
Crude oil used as raw material in petroleum refining consists
of a whole series of hydrocarbons varying from dissolved, fixed
gases to heavy, nearly solid compounds. Certain fractions of
crude petroleum, which may be separated by simple distillation,
have the necessary properties for use as a fuel oil. Some hydro-
carbons suitable for fuel oil are also produced by thermal or
catalytic cracking. Except in unusual and relatively unimportant
circumstances, the only commercial liquid fuels sufficiently
cheap for power generation and for industrial heating are certain
fractions of petroleum oil. 2
*API: American Petroleum Institute.
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FROM FUEL OIL COMBUSTION
The fuel oils used in small installations (smaller than 1,000
hp, or 34, 500-lb steam/hr, or 2, 500-lb oil/hr) are generally
kerosene, diesel fuel, and grades 1 through 6 fuel oils. The
kind of fuel oil used depends upon the size of the unit. The most
common fuel for domestic units is grade 2. Larger units, up to
200 hp, generally take grade 4; up to 1,000 hp, grades 4 to 6;
above 1,000 hp, grade 6 exclusively, or residual oils. Use of
kerosene and diesel oil is usually confined to units smaller
than 200 hp.
Typical properties of the light petroleum fuels are shown in
Table 3. Tables 4 and 5 show the NBS* Commercial Standards
Specifications for fuel oils and general classifications of fuel
oils, respectively. Table 6 shows the maximum, minimum, and
average gravity (in ° API) and sulfur content for fuel oils used in
five regions of the United States. The regions are shown in
Figure 1. Table 7 shows the sales of distillate fuel oils (grades 1
through 4 and kerosene) and residual fuel oils (grades 5 and 6
and some crude oil) in each state for 1960. 6
The fuel oil used most in boilers producing steam at a rate
of 34, 500 Ib/hr or greater (1,000 hp or more) is called Bunker
C. Other names for Bunker C and similar oils are: residual,
high-viscosity, heavy, grade 6, or Pacific Standard 400.2, 4
The range of properties for this fuel, as used in the United States
in 1961, is listed in Table 8.
Grade 6 fuel oil is residual oil a residue left after the
lighter fractions, fuel-oil distillates, kerosene, and gasoline
have been removed from the crude oil by distillation. During this
process the ash-forming constituents and sulfur-bearing com-
pounds originally present in the crude oil are concentrated in the
residual portion. With the development of improved refining
processes, larger proportions of the charged crude are removed
as distillate and motor fuel stock, leaving less residual oil, which
may contain higher concentrations of sulfur and ash than residual
oils of a few years ago. 7
Bulk fuel oil is sold in the United States in multiples of the
42-gallon barrel, at 60°F. The heat content ranges from 18,000
to 19,000 Btu/lb, the average being 18, 300. 2> 4» ' Residual fuel
oil is approximately 86 percent carbon, 10 percent hydrogen,
1.0 percent water, 0. 5 percent nitrogen, and the remainder sulfur
and ash. 2> 4 The suifur content of residual oils is usually about
1.6 percent. 5 in 1961, however, the sulfur concentration varied
in The United States from 0.34 to 4 percent, by weight (Table 8).
*NBS: National Bureau of Standards.
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ATMOSPHERIC EMISSIONS
Table 3. TYPICAL PROPERTIES OF LIGHT PETROLEUM
PRODUCTS (Reference 3)
Fuel properties
Gravity, API, 60<>F
Initial boiling point, °F
Distillation:
10% recovered at °F
50% recovered at °F
90% recovered at °F
End point, °F
Flash point (P-M)a, °F
Viscosity, Saybolt sec, 100°F
Diesel index
Sulfur, %
Cetane No. , ASTM0
Conradson carbon residue,
10% bottoms
Kerosene
41.9
336
370
437
510
546
130(TCC)b
* *
*
0.037
0.01
Premium
diesel oil
37.1
360
426
502
585
646
164
35.1
55.8
0.41
52
0.07
a (P-M) - Pensky-Martens closed tester (ASTM D93-42).
b (TCC) - Tag closed-cup tester (ASTM D56-36)!
c ASTM - American Society for Testing Materials.
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FROM FUEL OIL COMBUSTION
The composition of the ash in fuel oils varies greatly; the
presence of a large number of elements has been detected.
Normally, sulfur, aluminum, calcium, iron, nickel, silicon,
sodium, and vanadium are found in complex organic forms in the
oil. Other elements have also been found in the ash in very small
quantities: barium, chlorine, chromium, copper, gold, lead,
molybdenum, silver, strontium, thallium, tin, uranium, and
zinc. ^ > 8 A general analysis of the ash from oils (after burning
under laboratory conditions) from different areas is shown in
Table 9.
Figure 1. Geographical areas of the national survey of burner fuel oils.
Bureau of Mines regions, 1961 (Reference 5).
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Table 4. NBS COMMERCIAL STANDARDS SPECIFICATIONS FOR FUEL OILS* CS12-48 (EFFECTIVE SEPT. 25, 1948. REPLACING STANDARD CS12-40), (Reference 4)
Grade
of Description
fuel
oilb
1 A distillate oil intended
for vaporizing pot-type
burners and other burn-
ers requiring this grade
of fuel
2 A distillate oil for
general-purpose domes-
tic heating, for use in
burners not requiring
Nn 1 fuel nil
3*
4 An oil for burner instal-
lations not equipped with
preheating facilities
5 A residual-type oil for
burner installations
equipped with preheat-
ing facilities
6 An oil-tor .use in burners
equipped with preheaters
permitting use of high-
viscosity fuel
Max
water Max
Flash Pour and carbon Max
point, point, sedi- residue ash,
min °F max °F ment, on 10% %
% by bottoms, wt
volume %
100
or
legal 0 Trace 0.15
100
legal 20d 0.10 0.35
130
or 20 0.50 ... 0.10
legal
130
or ... 1. 00 ... 0. 10
legal
150 2 00f
Max distribution
temp, °F
10% 90% End
point, point, point,
420 ... 625
e 6. 75
Saybolt viscosity, sec,
Universal, Furol,
at 100°F at 122°F
Max Min Max Min
40
125 45
150 40
300 45
Kinematic viscosity,
centistokes,
At 100°F
Max Min
2.2 1.4
(4.3) ...
(26.4) (5.8)
... (32.1)
At 122°F
Max Min
(81) _
(638) (92)
Grav-
ity,
min
OAPI
35
26
Corro-
sion
(copper
strip),
3 hr at
122°FC
Pass
...
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3 Low-sulfur fuel oils used in connection with heat treatment, nonferrous metal, glass and ceramic furnaces, and other special uses may be specified in accordance with
the following:
Distillate fuel, grade Sulfur (max), % Residual fuel, grade Sulfur (max), %
1 0.05 5 No limit
2 1.0 6 No limit
4 No limit
Other sulfur limits may be specified only by mutual agreement between the purchaser and the seller.
b It is the intent of these classifications that failure to meet any requirement of a given grade does not automatically place an oil in the next lower grade unless, in fact,
it meets all requirements of the lower grade.
c The exposed copper strip shall show no gray or black deposit.
d Lower or higher pour points may be specified whenever required by conditions of storage or use; these specifications shall not require a pour point lower than O°F
under any conditions.
e The 10% point may be specified at 440°F maximum for use in other than atomizing burners.
' The amount of water by distillation plus the sediment by extraction shall not exceed 2%. The amount of sediment by extraction shall not exceed 0. 50%. A reduction in
quantity shall be made for all water and sediment in excess of 1%.
e Formerly, a distillate oil for use in burners requiring a low-viscosity fuel. Now incorporated as part of No. 2 oil. Not now part of NBS std.
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Table 5. GENERAL CLASSIFICATION OF FUEL OILS a (with range of gravities, heat values, and comparison of old
specifications, CS12-40, with those of Sept. 25, 1948, CS12-48). (Reference 4)
Grade Description
1 A distillate oil intended for
vaporizing pot -type burners
and other uses requiring a
volatile fuel
2 A distillate oil for general
purpose domestic heating,
for use in burners not re-
quiring No. 1. Moderately
volatile
3 Formerly, a distillate oil
for use in burners requiring
a low-viscosity fuel. Now
incorporated as part of new
No, 2 oil standards
Present specifications, CS12-48
Gravity,
°API
35-40
26-34
Lb/gal
6.879-7.085
7. 128-7. 490
Btu/gal
135,800-138,800
139,400-144,300
Former specifications, CS12-40
Gravity,
°API
38-40
34-36
28-32
Lb/gal
6.879-6.960
7. 043-7. 128
7.215-7.396
Btu/gal
135, 800-137, 000
138, 200-139, 400
140, 600-143, 100
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4 An oil for burner installa-
tions not equipped with pre-
heating facilities
5 A residual-type oil for
burners equipped with pre-
heating facilities. Sold as
Bunker B. Preheat sug-
gested: 170° to 220°F
6 An oil for use in burners
equipped with preheaters
permitting use of high-
viscosity fuel. Bunker C.
Preheat suggested: 220° to
260°F.
24-25
18-22
14-16
7. 538-7. 587
7. 686-7. 891
7.998-8.108
145,000-145,600
146, 800-149, 400
150,700-152,000
24-26
18-22
14-16
7. 490-7. 587
7.686-7.891
7. 998-8. 108
144, 300-145, 600
146, 800-149, 400
150,700-152,000
a Since gravities are not included in commercial standards (excepting minimum gravities of 35 for No. 1 oil and 26 for No. 2
oil), this table is unofficial, based on trade practices under code CS12-40.
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Table 6. PROPERTIES OF FUEL OILS USED IN THE U. S. - 1961 (Reference 5)
Fuel
oil
grade
1
2
4
5
6
Fuel
oil
grade
1
2
4
5
6
Property
°API, 60°F
sulfur, wt/%
°API, 60°F
sulfur, wt/%
°API, 60°F
sulfur, wt/%
°API, 60°F
sulfur, wt/%
°API, 60°F
sulfur, wt/%
Property
°AP1, 60°F
sulfur, wt/%
"API, 60°F
sulfur, wt/%
"API, 60°F
sulfur, wt/%
°API, 60°F
sulfur, wt/%
°API, 60°F
sulfur, wt/%
Eastern region
Min Avg Max
39. 5 42. 9 46. 2
0. 007 0. 069 0. 17
26. 6 35. 3 45. 8
0. 04 0. 228 0. 65
9.0 21.4 31.6
0. 18 0. 84 2. 12
7.1 17.2 21.9
0. 28 1. 17 2. 50
-3.33 12.7 19.2
0. 53 1. 34 3. 40
Rocky Mountain region
Min Avg Max
39.5 41.8 45.7
0. 006 0. 113 0. 41
27.1 35.7 40.7
0.029 0.324 1.06
10. 0 19. 6 31. 0
1.32 1.43 1.5
1. 9 12. 7 20. 8
0. 28 1. 84 3. 5
1.5 9.3 19.1
0. 516 2. 02 4. 0
Southern region
Min Avg Max
39. 8 42. 7 44. 7
0. 01 0. 068 0. 21
31. 1 35. 5 47. 7
0. 04 0. 249 0. 72
16. 9 a 27. 9
0. 27 a 1. 92
12. 5 15. 2 17. 6
0.28 1.77 3.10
5.4 11.3 14.3
0. 34 1. 58 3. 36
Western region
Min Avg Max
35. 6 40. 7 46. 7
<0.001 0.131 0.31
27. 1 34. 9 43. 0
0. 029 0. 419 0. 93
10.0 18.4 31.0
1.32 a 1.5
2.7 12.6 17.6
0. 90 1. 83 3. 5
1. 5 7. 6 13. 4
0. 80 1. 91 4. 0
Central region
Min Avg Max
39. 5 42. 5 46. 1
0.005 0.107 0.48
26. 6 35. 1 39. 3
0. 071 0. 299 0. 81
14. 1 20. 5 27. 9
0. 27 0. 90 2. 12
12. 4 16. 5 20. 1
0. 57 1. 52 3. 5
-3. 33 10. 1 23. 0
0. 42 1. 47 4. 0
ASTM Combined
standards total
Number
Min Max of Avg
samples
35 163 42.3
0.5 163 0.094
26 -- 186 35.3
1.0 186 0.286
31 20.7
31 0.99
64 15.0
44 1.58
144 10.5
144 1.60
a No averages were computed since only two samples were represented for this test.
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Table 7. SALES OF FUEL OILS IN 1960, thousand barrels
(Reference 6)
States
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
U. S. total
Distillate fuel oils
(Grades 1 to 4 and kerosene)
1,007
1,723
546
307
4, 977
1,137
21, 643
2,476
2,544
3,126
1,673
145
2,625
32, 490
20,415
8,445
1,039
1,476
1,484
6,539
10, 660
48, 594
26, 739
11,339
89
7,202
1,205
2,064
589
4,240
40, 799
764
71,488
9,665
2,376
13, 833
617
6,093
36, 627
7,619
3,375
2,294
926
5,340
1,112
2,614
9,312
13,226
487
19, 322
1,015
477, 402
Residual fuel oils
(Grades 5 and 6 and crude
oil used as fuels)
4,202
695
95
474
78, 660
1,785
14, 450
6,081
2,387
28, 978
6,413
5,613
201
25, 676
12, 856
1,021
2,246
314
8,596
5,742
16, 490
38, 942
11,242
6,363
338
2,970
1,950
377
202
2,324
42, 705
166
76, 586
4,537
655
11,382
1,108
5,453
42, 643
9,' 502
4,634
58
184
21, 463
5,552
498
17, 448
9,179
1,451
4,275
1,710
548, 872
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Table 8. PROPERTIES OF GRADE 6 FUEL OIL, 1961 a
(Reference 5)
Property
Gravity, °API
Flash point, Pensky- Mar tens closed
tester, 6F
Viscosity, Furol, at 122°F, sec
Sulfur content, wt %
Ramsbottom carbon residue on
100% sample,
Ash, wt %
Water and sediment, vol %
Pour point, °F
Min
-3.33
15.2
13.7
0.34
4.9
0.002
0.0
-10
Max
23.0
365
415
4.00
23.6
0.3
1.0
90
a The extreme ranges of various properties of fuel oil
found in the United States in 1961.
Table 9. ANALYSIS OF ASH IN VARIOUS OILS, a>b as wt %
(Reference 9)
Reported
as
Si02
1£
CaO
MgO
MnO
V205
NiO
Na20
K20
SOg
Chloride
Calif.
38.8
17.3
8.7
1.8
0.3
5.1
4.4
9.5
15.0
Mid
Conb
31.7
31.8
12.6
4.2
0.4
Trace
0.5
6.9
10.8
Tex.
1.6
8.9
5.3
2.5
0.3
1.4
1.5
30.8
1.0
42.1
4.6
Pa.
0.8
97.5
0.7
0.2
0.2
--
--
0.1
0.9
~
Kan.
10.0
19.1
4.8
1.3
Trace
0.4
0.6
23.6
0.9
36.4
0.1
Iran
52.8
13.1
6.1
9.1
Trace
14.0
1.4
2.6
--
Iran
12.1
18.1
12.7
0.2
Trace
38.5
10.7
"" 1
7.0
a After burning under laboratory condition.
b 1938 data.
-------
ASPECTS OF OIL COMBUSTION
Oil Preparation
Fuel oils must be vaporized before they can be burned.
There are two different ways of doing this. The oil may be
vaporized by heating within the burner unit or the oil may be
atomized mechanically, producing fine oil droplets that may be
vaporized. Burners in the first group, usually called vaporizing
burners, are fired only with light oils. They are sometimes
used in smaller space heaters with pot-type burners. They have
very little application in the power field. 2, 10, 11
If oil is to burn in the short time it is in the combustion
chamber of a furnace, it must be in the form of small particles
that expose as much surface per unit of volume of oil as possible
to the heat in the chamber. The necessary atomization of the oil
may be effected in three basic ways: by forcing oil under pressure
through a nozzle, as in the "gun-type" burner; by use of centri-
fugal force, as in the "rotary-cup" burner; and by use of steam
or air under pressure to inject the oil into the combustion cham-
ber, as in "steam-atomization. " Mechanical means that effect
the atomization of oil in "rotary-cup" burners consist essentially
of an oil cup, which is driven by a motor or air turbine, and an
air nozzle or ring. The cup spins at speeds from 3, 500 to
10, 000 rpm. This motion tears the oil into droplets by centri-
fugal action. The steam- or air-atomizing burners use pressures
ranging from 100 to 1, 000 psi, as do the "gun-type" burners. 10, 12
Besides atomizing the oil to achieve rapid vaporization, the
burner must also disperse the particles of oil in such a manner
that they mix with air, stripping off layers of oil from the drop-
lets as they move through the air. This requires a high degree of
turbulence. The great relative motion between the oil and the air
also produces a uniform mixture in the combustion zone. 10
Before the oil reaches the burner it is passed through a
strainer or filter to remove sludge. This filtering process pro-
longs pump life, reduces burner wear, and increases the com-
bustion efficiency.10
Grades 5 and 6 oil must be heated before they can be pumped
to the burner efficiently. For good atomization, viscosity of
these oils must be maintained in the range of 130 to 150 Say bolt
Universal. This requires heating the oil to temperatures of 170
to 260°F. 2» 10> U
15
-------
16
Oil Combustion
There are two kinds of hydrocarbon combustion: hydroxyla-
tion and decomposition. Hydroxylation or blue-flame burning
takes place when the hydrocarbon molecules combine with oxygen
and produce alcohols or peroxides that split into aldehydes,
mainly formaldehyde, and water. The aldehydes burn to form
CO2 and H2O. Decomposition or yellow-flame burning takes
place when the hydrocarbons "crack" or decompose into lighter
compounds. The lighter compounds then "crack" into carbon
and hydrogen, which burn to form CC>2 and I^O. 2, 4, 10, 12
A mixture of yellow- and blue-flame burning is ideal. This
type of burning is indicated when CO2 in the dry stack gas is 12
to 14 percent. This stack gas composition corresponds to pro-
vision of approximately 15 to 30 percent excess air, depending
on properties of the oil. 2> 4, 10, 12
Smoke Formation
Smoke from oil-burning units is the result of incomplete
combustion. An efficiently operated furnace should not smoke,
since smoke is a sign that unburned and partially burned hydro-
carbons are being emitted to the atmosphere. Incomplete atomi-
zation of the oil caused by improper fuel temperature; dirty,
worn, or damaged burner tips; or improper fuel or steam pres-
sure may cause the furnace to smoke. A poor draft or improper
fuel-to-air ratio may also cause a furnace to smoke. Other
factors that may cause a smoking fire are: poor mixing and
insufficient turbulence of the air and oil mixture, low furnace
temperatures, and insufficient time for fuel to burn completely
in the combustion chamber. 10, 12
Acidic Smut Formation
"Acidic smuts" are generally large particles, approximately
one-fourth inch in diameter, containing metallic sulfates (usually
iron sulfate) and carbonaceous material. Smut formation is a
result of the condensation of water vapor and 803 on cold metal
surfaces. The metal surface is defined as cold when its tempera-
ture is below the flue-gas dew point, which is approximately '300°F.
The metal is corroded, forming the metallic sulfate. The metallic
sulfate in turn absorbs carbonaceous particulates from the flue
gas. The smut eventually flakes off and is carried out of the stack
by the flue gas. ^
-------
EMISSIONS FROM LARGE INSTALLATIONS
Oxides of Nitrogen (NOX)
THEORETICAL CONSIDERATIONS
Air contains approximately 21 percent oxygen (02) and 79
percent nitrogen (N2) by volume. When oil is oxidized with air
at high temperatures, the composition of the main combustion
products is essentially 12 percent CO2, 5 percent 03, and 83
percent N2, by volume. Other compounds, however, are also
formed in small concentrations, some of which are air pollutants.
One class of pollutants is referred to as NOx a general term
that includes the oxides of nitrogen, such as NO, NO2, ^04,
and N2Os. During combustion, oxygen and nitrogen gas combine
to form NO as follows:
N2 + 02 ^ 2NO (1)
If time permits, this reaction will continue to equilibrium, but
it does not go to completion as does the carbon to carbon dioxide
reaction. The NO will, however, react with more oxygen and
form NO£ and other NOX products. The N2 to NO equilibrium
may shift in either direction, depending upon many variables. If
the concentration of one of the gases is increased, the equilibrium
will shift to the opposite side. There is an abundance of nitrogen
but very little oxygen present for this reaction. If the amount of
oxygen (excess air) is increased (without reducing the flame
temperature), the NO concentration will increase also, and the
reverse is true. As the NO reacts with oxygen to produce NO2,
there is a reduction in the concentration of NO, which removes
it from the equilibrium in reaction (1) above. The NO is replaced
by reaction (1) returning to equilibrium.
Another variable that complicates this equilibrium is the
motion of the gases through zones of different temperatures,
pressures, and concentrations. Most of the NO is formed in the
flame where very high temperatures are present. The residence
time of the gases at this temperature is relatively short, however,
and thus the NO reaction is prevented from reaching equilibrium.
Figure 2 shows the theoretical concentration of NO, assuming
typical fuel analysis, typical excess air, and a residence time of
0. 5 second at various flame temperatures. ^
17
-------
18
ATMOSPHERIC EMISSIONS
The main factors in NOX production are: the flame temper-
ature (usually between 2,400 and 3,600°F), the length of time that
combustion gases are maintained at the flame temperature, and
the amount of excess air present in the flame. Distinctly different
NOX concentrations have been reported for two different basic
designs of furnace, however. These designs are referred to as
tangentially and horizontally fired fireboxes. The tangentially
fired unit is built in such a manner that the flame is propagated
in a cylindrical form. The unit is constructed to produce a
spiral upward motion of the flame and combustion products around
the walls of the cylindrical firebox. It is a relatively new and
infrequently used design.
i
1000
900
800
700
600
500
400
300
200
100
2800
3OOO
3200
3400
FLAME TEMPERATURE. °F
Figure 2. Theoretical formation of nitric oxide vs flame temperature
(Reference 14).
-------
FROM FUEL OIL COMBUSTION 19
Units fired other than tangentially are classified as horizon-
tally fired units. These units are usually fired at right angles to
the walls of the firebox but they may be fired at various angles.
They may be fired on one or more sides, or from the bottom of
the firebox. The firebox may be square, rectangular, or
cylindrical. Horizontal firing tends to concentrate the hot gases
in the center of the firebox.
EMISSION RATES
Tangentially Fired Units
NOX emissions from tangentially fired units appear to be
about one-half as great as those normally reported for horizon-
tally fired units. Only a few authors have reported on emissions
from tangentially fired units. Sensenbaugh reported a range of
200- to 400-ppm NOX in the stack for this type of unit. 15
Sensenbaugh and Jonakin compiled many literature values for tan-
gentially and horizontally fired units. These values ranged from
160- to 362-ppm NOX in stacks from tangentially fired units. 14
All the data, including the experimental values, found in the
literature for tangentially fired units are shown in Figure 3. The
numeral 2 designates two-stage combustion, which will be dis-
cussed later. Figure 3 shows an extreme NOX concentration
range of 160 to 400 ppm in stack gas from tangentially fired units.
The most common range is 180 to 280 ppm. The most common
values reported in the literature are between 200 and 220 ppm,
which may be lower than normal; the few references available,
however, permit no better representation.
Horizontally Fired Units
All emission data, exclusive of that relating to tangentially
fired units, are grouped under the classification "Horizontally
fired units. " Many general ranges for emissions from horizon-
tally fired boilers have been reported, as follows:
Range NOX as NO2, ppm References
330 to 915 1
500 to 700 15
100 to 900 15, 16
310 to 915 17, 18
275 to 600* 19*
400 to 600 20
*At stack conditions.
-------
20
ATMOSPHERIC EMISSIONS
20
15
111
13
10
o
d 5
It) 1 1 1 I II
-
-
2
«
i i i 1 i i i i 1 i i i i
1 | Individual values reported
|2| Two-stage combustion
\ffA R°n9es reported
-
T
I MI
S//\ , , , , '
100 200 300
NOX IN STACK GAS, ppm
400 500
i i i i
-i
. i i i i i i i
01 2 3 4 5 6 7 8 9 10 II 12 13 14
NO^ AS NO2, lb/1,000 Ib OF OIL FIRED
Figure 3. NO emissions from large, tangentially fired units.
The most extensive NOX study was done in Los Angeles
County in a joint district, federal, state, and industry project. 19
In this study, the effects of many variables were studied. Results
from this project showed a normal range of 275- to 600-ppm NOX
at stack conditions on 63 large sources. (This included 130 tests
comprising 554 stack samples.) The average emission rate was
0. 78 pound of NOX per 10° Btu, or 14. 2 pounds of NOX per 1, 000
pounds of oil fired, calculated on the basis of 18, 300 Btu per
pound of oil fired. Other studies showed similar results.
All the data collected for NOX emissions for units, other,
than tangentially fired, are shown in Figure 4. These data show
an extreme range of 0 to 1, 020 ppm. The normal range is 300 to
700 ppm, and the most commonly reported values are between
460- and 480-ppm NOX.
-------
FROM FUEL OIL COMBUSTION
21
Q Individual values reported
Two » stage combustion
B Typical values reported
fa^/i Ranges reported
^Represents 130 tests and
554 samples on power
Represents many tests
on power plants^
IOO 200 300 4OO 500 600 700 800 900 1000 1100 1200
NO IN STACK GAS, ppm
Z 4 6 8 10 12 14 16 18 2O 22 24 26 28 3O 32
NOX AS N02, lb/1,000 Ib OF OIL FIRED
Figure 4. NOX emissions from large, horizontally fired units.
VARIABLES AFFECTING EMISSIONS
Firing Rate
One author 22 showed that the NOX emissions varied with the
firing rate. His equation may be written as:
Ib NOx/hr
= X(C)
[213 J
1.18
(2)
where X is the firing rate in pounds of oil per hour, C is the
percent of carbon in the oil, and NOX is nitrogen oxides as NO£.
Since oil usually contains about 86 percent carbon, the equation
could read:
Ib NOx/hr = X
L.248J
1.18
(3)
Data for horizontally fired units conformed to this equation
rather closely.
-------
22 ATMOSPHERIC EMISSIONS
Two-Stage Combustion
Two-stage combustion reduces NOX emissions. In two-stage
combustion, as in other types of combustion, normally 115 to
130 percent of the theoretical air is necessary for good combustion,
but only 90 to 95 percent is introduced through the burners with
the fuel. The remainder of the necessary combustion air is
introduced through auxiliary air ports in the walls of the fire-
box. I"7* 19> 23 one author found that this method of combustion
reduced the NOX concentration by 27 to 47 percent in a horizon-
tally fired unit. 24 other studies showed that, under normal
conditions, in a horizontally fired unit, the average NOX concen-
tration was reduced by 45 percent. 19, 23 One author who
reported data for two-stage combustion in a tangentially fired unit
indicated a reduction of 22 percent in NOX concentrations. 23
In two-stage combustion, the limited oxygen supply near the burn-
er probably inhibits the formation of NOX.
Load Factor
Large boilers often have a power demand fluctuation. They
normally run at about 85 percent of their designed load, which
provides a reserve for peak power demand. Several studies
indicated an average NOx decrease from 0.6 to 0.9 percent per
1 percent load decrease below a 70 percent load; and an average
NOX increase from 0.6 to 1.1 percent per 1 percent load increase
above a 70 percent load. 19, 25 The increase in NOx concentra-
tion is caused by the increased flame temperature at the higher
firing rate.
Excess Air
In electric power plants, the amount of excess air used in the
combustion of oil may vary from 8 to 30 percent, in a given plant.
The amount of excess air used in large modern plants is about
16 to 20 percent, equivalent to approximately 14 percent CO2
concentration in the stack gas. This concentration varies with
fuel composition and burner design. One author reported on a
tangentially fired unit that emitted 13 percent CO£ and 258-ppm
NOX (corrected_to 12 percent CO2>. A linear relationship was
established indicating that, as the CO2 concentration was in-
creased by 1.6 percent (decrease in excess air), the NOX con-
centration was reduced by 29 percent. This is equivalent to an
18 percent decrease in NOX per 1 percent increase in CO2- ^
The same author reported on a horizontally fired unit that
emitted 13. 6 -percent CO2 and 700-ppm NOX (corrected to 12
percent CO2). An approximate linear relationship was established
-------
FROM FUEL OIL COMBUSTION 23
indicating that, as the CO2 concentration was increased by 0. 9
percent, the NOX concentration was reduced by 32 percent. This
is equivalent to a 35 percent decrease in NOX per 1 percent in-
crease in CO2. I4
The joint project conducted in Los Angeles County investi-
gated the relationship of excess air to NOX formation. This
relationship is shown, on the basis of CO2 concentration, in
Figure 5. 19 The NOX concentration increases with a decrease
in CO2 concentration* because NOx formation is promoted by
surplus oxygen.
Windbox Pressure
The plenum chamber, through which the supply of combustion
air is provided to all burners, is the "windbox. " Air pressure
in the windbox is controlled by opening or closing the air registers.
The air registers regulate the flow of air in the windbox in much
the same manner as an air damper regulates the flow of hot air
in domestic heating units. In one study it was found that the NOX
concentration in the stack gas was decreased considerably when
the windbox pressure was increased by 1 inch of water. 19
Flue Gas Recirculation
Some plants permit a portion of the flue gas to be recycled
through the firebox. One author found an average NOX reduction
of 1.3 percent per 1 percent flue gas recycled in a tangentially
fired unit. 14 In another study it was found that NOx was reduced
approximately 2. 5 percent per 1 percent increase in the opening
of the recirculating fan damper. 19 Since recirculating the flue
gas reduced the oxygen concentration and flame temperature in
the firebox, the amount of NOX formed was also reduced.
Fuel Pressure and Temperature
One study revealed that, when the fuel feed rate was kept
constant and the pressure of the fuel oil was increased, either by
decreasing the size of the burner orifices or by decreasing the
number of burners for the same fuel rate, NOjj concentration was
decreased. The study showed an average decrease of 0.17 per-
cent NOX per one-psi increase in fuel pressure, when smaller
orifice tips were used, 19 but these' tips do not last or stay clean
as well as larger tips. 14 The study also showed that, when the
number of burners in a firebox was increased from the normal 12
to 14, resulting in a 50-psi decrease in fuel pressure, NOX
* Increase in excess air.
-------
24
ATMOSPHERIC EMISSIONS
900
800
o
o
6?
-------
FROM FUEL OIL COMBUSTION 25
concentration increased 15 percent. When the number of burners
was decreased from 12 to 10, resulting in a 100-psi increase in
fuel pressure, NOX concentration decreased 4 percent. 19
One author found that oil temperature had a small effect on
NOX concentration. His data showed an average of 0. 3 percent
decrease in NOX per °F increase in oil temperature in the range
of 207 to 277°F. 14
Other Variables
NOX production increases if deposits on boiler tubes are not
removed frequently by lancing or by other means. 14, 19 Clean-
ing the tubes increases heat transfer rates, which might be
followed by a reduction in the flame temperature and in NOX
emissions for a given load.
Approach-cone vanes dir'ect the air flow either through or
around the burner to the flame to promote efficient combustion.
One author found that, by removing the approach-cone vanes
from the burners and operating with the air registers wide open,
NOX concentration was reduced 16 percent. 24 This may have
been a peculiarity of a specific firebox design.
Sulfur Dioxide (SO.)
THEORETICAL CONSIDERATIONS
Oil contains many complex organic forms of sulfur, in con-
centrations ranging from a trace to more than 5 percent by
weight. During the combustion of oil, the sulfur in the oil is ox-
idized to sulfur dioxide (SO2) in much the same way as carbon is
oxidized to carbon dioxide (CO2). In other words, the oxidation is
virtually complete. The SO2 may react with more oxygen, how-
ever, forming sulfur trioxide (803) or sulfate radicals in a com-
plex equilibrium similar to those of the NOX compounds. This
means that not all the sulfur in the oil is emitted as SO2- The
variables controlling the SO2 emissions are those controlling the
formation of 803 and metallic sulfates. 7> 26> 2?
The amount of sulfur emitted as 803 may be inferred from a
material balance. Fly ash contains around 10 percent sulfur,
and oil contains around 0.1 percent ash. Thus, about 1 percent
of the sulfur in the oil ends up in the fly ash. Sulfur emitted as
SOg is probably about 1 percent of the sulfur in the oil. Thus, 98
percent of the sulfur in the oil is probably emitted as SO2.
-------
26 ATMOSPHERIC EMISSIONS
EMISSION RATES
The data collected on sulfur emissions are presented in
Figure 6. The extreme range is from 12 to more than 100 percent
of the sulfur in the fuel emitted as 803. The normal range is 85
to 100 percent. The most common value is 100 percent. The
100 percent value is questionable as are those values above 100
percent. One of the values plotted at 100 percent or greater
represents a calculated value of approximately 120 percent; this
impossibility indicates inaccurate sampling and analyzing prac-
tices. It would appear from the data and the material balance
that the SO2 emitted in the flue gas represents about 98 percent
of the sulfur in the oil.
Sulfur Trioxide (SO3)
THEORETICAL CONSIDERATIONS
Theoretical equilibrium considerations for the reaction
2 S02 + 02 2 S03 (4)
indicate a tendency toward 803 formation as the temperature of
the combustion gas stream becomes increasingly lower than the
flame temperature. Catalytic surfaces consisting of iron oxides
from the boiler tubes and the vanadium- and iron-bearing ash
deposits are present to accelerate the reaction. This reaction
is similar to that used in producing 803 in a contact sulfuric acid
plant; in a combustion chamber, however, there is less catalyst
and contact time. ?> 26
As the products of combustion travel toward the stack exit,
and as heat is transferred to the boiler, preheater, and
economizer, the temperature of the gases is reduced. If the SOg
comes in contact with surfaces below the dew point of the gas,
the SOg combines with water vapor to produce sulfuric acid.
The sulfuric acid reacts in turn to produce metallic sulfates on
the surface that it contacts, which reduces the 803 concentration.
The 803 markedly increases the dew point of the flue gases to
about 300°F. This high dew point of the exhaust gases may result
in corrosion of the boiler and stack, and in formation of acidic
smuts, as discussed in a previous section, 26» 28> 29> 30> 31> 32»33
-------
FROM FUEL OIL COMBUSTION
27
50
45
1 1 1 T
^
20
o
a.
O
z
10
II Individual values reported
Typical values reported
nfl
0 10 20 30 40 50 60 70 80 90 100
(OR GREATER)
SULFUR IN THE OIL EMITTED AS S02, %
Figure 6. Percent of sulfur in the oil emitted as SC>2 from large units.
-------
28 ATMOSPHERIC EMISSIONS
EMISSION RATES
The emission of 803 to the atmosphere does not appear to be
a function of the percent sulfur in the oil only, as does SO£
emission. To illustrate this, the concentration of 803 in the
stack gas is plotted against the sulfur content of oil (Figure 7).
Lines are arbitrarily drawn to represent 0. 4, 1. 2, and 2. 5 per-
cent of the sulfur in the oil emitted as 803. These lines show
the wide range of the part of the sulfur in the oil emitted as 803.
The majority of the data indicate that there is more than 6-ppm
and less than 25-ppm 803 in the stack gas. For this reason, the
803 emission data are represented by two histograms. Figure 8
shows the percent sulfur in the oil emitted as 803 and Figure 9
shows the concentration of 803 in the stack. Values in Figure 9
are not correlated with the sulfur content of the oil. The ranges
found in the literature are as follows (S is the percent sulfur in
the oil, by weight):
Range Reference
90% 8 converted to 803 and
1 to 5% SO2 converted to 803 15
100% S converted to SO2 and
1 to 2% SO2 converted to 803 16
1 to 5% S converted to SO3 18
1 to 2. 5 Ib SO3/1, 000 Ib oil, for
oil with S of 1. 5% 20
Figure 8 shows an extreme range of 0. 25 to 11. 5 percent of
the sulfur in the oil emitted as SOs. The normal range varies
from 0.25 to 2.75 percent, and the most common value is be-
tween 1.0 and 1.25 percent of the sulfur in the oil emitted as 803.
Figure 9 shows that stack concentration varies from 0 to 76 ppm.
The normal range varies between 6 and 24 ppm. The most com-
mon are between 14- and 22-ppm 803.
When the gases leave the stack, they are cooled below the
dew point, causing much of the SOs to combine with water vapor
in the surrounding gas stream, sometimes producing a visible
plume. One author reported a visible plume at 3-ppm and a
conspicuous plume at 15-ppm 803. ^> ^ The particle size of
sulfuric acid mist varies from 0. 5 to 6 microns, depending upon
the amount of water vapor present. 34
-------
FROM FUEL OIL COMBUSTION
29
<
o
u
<
80
70
60
50
40
30
20
10
Note: The lines represent calculated values
of the portion of the sulfur in oil
converted to and emitted as
sf
0-L
234
SULFUR IN THE OIL, % BY WT
Figure 7. Relationship between SOj emission and sulfur in oil
(or large units.
-------
30
ATMOSPHERIC EMISSIONS
SULFUR IN THE OIL EMITTED AS S03,55
Figure 8. Percent of sulfur in the oil emitted as $03 from large units.
20
15 -
£ «o 1-
o
a.
UJ
a.
u.
O 5 \-
6
1
A
xj
0
0
X
nl
x
x
0
It Individual values reported
1X1 Typica values reported
.
Note: $03 values not correlated
with sulfur content of oil.
_.
r"i
r n
MI 1 1 ^ i
xlllll.nMii....i.n.
30 40 50 60 70 8
S03 IN STACK GAS, ppm
Z 3
SOj, lb/1,000 Ib OF OIL FIRED
Figure 9. Concentration of $03 in stack gases of large units.
-------
FROM FUEL OIL COMBUSTION
31
VARIABLES AFFECTING EMISSIONS
One author found that variation of name temperature affected
803 concentrations in the stack gas. The experiment was done in
a pilot plant study and not with actual large furnaces or power
plants. A plot of 803 content (ppm) versus the flame temperature
is shown in Figure 10. 35 This author also indicated that the per-
cent sulfur in the fuel converted to 803 decreased with an increase
in the percent CO2 in the stack gas. These data do not agree,
however, with other data collected for this report.
70
60
- 50
O
(J
(-
t/>
Z 40
z
O
O
z
O
u
20
10
0
2800
290O 3000 3100 3200 33OO
FLAME TEMPERATURE, °F
3400
3500
Figure 10. Effect of flame temperature on $03 emission (Reference 35).
-------
32
Other factors that may have a small effect on 803 emission
are boiler load, fuel pressure, excess air, and percent ash in the
fuel. 7,26,29, 30,31,32,33,35,36,37 These variables seem to
have little significance in the formation of 803, however.
Other Gaseous Emissions
Large power plants are usually efficient operations, and
therefore, should not emit unburned or partially burned hydro-
carbons in significant quantities. Several references, however,
have given values for emission of various organic compounds or
groups of organic compounds. Since investigators have not re-
ported the organic compounds in a consistent manner, e. g.,
hydrocarbons measured as hexane, no comparison of the results
is possible. Table 10 lists organic compounds found in emissions
from large units, as reported by several investigators. Table
10 also shows some values for inorganic gases.
Particulate Emissions
EMISSION RATES
The particulate loading of stack gases depends primarily
upon the efficiency of combustion and the rate of build-up of
boiler deposits. The data do not follow any trend when the per-
cent ash in the oil is plotted against stack loadings. When oil
containing one pound of ash is introduced into a large boiler, as
little as one-half pound or as much as 10 pounds of particulates
could be emitted. This emission may result from a build-up or
detachment of boiler deposits, carbon in the fly ash, H£SO4
reacting with the boiler or stack, or from a combination of
these factors.
Particulate loading ranges cited in the literature are 0.02 to
0.04 grains per cubic foot 15 and 1 to 5 pounds per 1,000 pounds of
oil fired (0.0325 to 0.1625 gr/scf, calculated). The latter value
is for low-pressure atomization. The loading was reduced by
two-thirds when high-pressure atomizing was used. 20 All the
literature values for particulate matter are represented in Figure
11. This figure shows an extreme range between 0.005 and 0.205
gr/scf. The normal range is between 0.025 and 0.060 gr/scf.
The most commonly reported values are between 0.030 and
0. 035 gr/scf.
-------
Table 10. MISCELLANEOUS GASEOUS EMISSIONS FROM LARGE SOURCES
(Reported in lb/1,000 Ib oil fired, unless otherwise stated)
O
O
..a
0. 0051
0
100 ppm or
greater for
poor com-
bustion d> e
100 ppm or
less for poor
combustion^) e
.2 *
M
I3
..
»-
..
--
~
0.095
o u>
£ rt a>
l=|
P*
..
__
13 ppm
c,d
...
"~
St "a
8§
r
0.097
*_
.-
"
^
5b
__
__
rh
"
S *? o 5
O * -5 js
..
0.326
-
..
rt 2
^i a
s rt
!y
15b
..
15b
_-
"
0.41
5,2
I?
5l
i
..
"
0.65
£
1
..
"
d
s
w c
||
s
..
..
--
"
t
0
0.03
o>
t
.
0
CQ
SB1
<1
g
-------
34
ATMOSPHERIC EMISSIONS
20
15
O
UJ
O
0-
IU
O
z
-
:
XI
XI
X
y
-
X
//
1 ' ' i ' ' ' i ' ' ' i ' ' ' i ' i i ' i ' i ' ' i ' i ' i ' i i"
1 1 Individual values reported
13 Typical values reported
KX//I Ranges reported
IQI Represents many tests
on power plants^' _
j-
-~--G
T1
~ Y\ pr
y 1 1 i ixi fol
_
i i i t~i n n
Y////sjf///s/s//s///4//////j(/sA///tf////////////jfA . . n . . n . .
O.O2
O.O6 0.08 0.10 0.12 O.I4 0.16
PARTICULATE CONCENTRATION, gr/scf
0.20
2345
PARTICULATE, lb/1,000 Ib OF OIL FIRED
Figure 11. Particulate loading in stocks of large units.
PARTICLE SIZE
The size distribution depends upon the degree of atomization
of the oil, the efficiency of mixing, the number of collisions be-
tween fly ash particles, the flame temperature, the design of the
firebox, and the flue gas path through the boiler to the stack. 7
The lighter particles usually contain less carbon and are smaller
in size. The literature shows an assortment of sizes (Table 11).
The larger particles are skeletons of burned-out fuel parti-
cles, called cenospheres, which are hollow, black, coke-like
spherical particles. 46 The smaller particles formed by the
condensation of vapors are of regular shape and usually have a
maximum dimension of about 0.01 micron. ' Good atomization
usually reduces the number of cenospheres.
-------
FROM FUEL OIL COMBUSTION
Table 11. SIZE OF PARTICULATES EMITTED FROM LARGE UNITS
35
Size and weight percent, as reported
0.4,,
0. 4W (estimate)
or 90% less than 0. 5u
95% less than 0. 5p
In or less
less than lu to 40 u
47% less than 3 »
53%, 3 to 4u
53% greater than 4U a
95%, 10tol,000ua
Method
of collection
Millipore
Millipore
Millipore
Glass cloth
Percent bv
0-lu
48.4
64.2
93.5
94.8
1-2M
28.8
18.8
3.2
2.2
number
2-5u
16.7
10.0
2.0
1.5
5+u
6.1
7.0
1.3
1.0
Largest
size Remarks
15ii Most particles
black in color;
a few 80n in
15u size
20u Most particles
light in color
20M
Reference
42
1
43
44 & 7
16
45
46
20
47
a Carbon particles only.
CHEMICAL COMPOSITION AND DESCRIPTION
No general statement can be made on the highly variable
composition of fly ash from oil combustion. The probable
constituents of fly ash that may be found in flue gas are as follows:
A1203, A12(S04)3, CaO, CaSO4, Fe2O3, Fe2(SO4)3, MgO,
MgSO4, NiO, NiSO4, SiO2, Na2SO4, NaHSO4, Na2S2O7, V2O3,
V2O4, V205, ZnO, ZnSO4, Na2O-V2O5, 2Na2O-V2O5, 3Na2O-V2O5,
2NiO-V205, 3NiO-V205, Fe2O3- V2O5, Fe2O3-2V2O5,
Na2O- V2O4- 5V2Os and, 5Na2O- V2O4- 11V2O5.48 The average
compositions of ash found in various oils before firing are given
in Table 9.
The composition of the fly ash changes as the gas leaves the
firebox and travels through the boiler and the internal parts of
the power plant. As the gas cools, some of the fly ash condenses
and solidifies, some reacts with the boiler and stack, and some is
deposited within the unit. The fly ash composition varies from
plant to plant and from oil to oil. Table 12 shows analyses of fly
ash from a plant using residual oil. 46 Vanadium is usually
present in the fly ash and has been considered for use an an indi-
cator of the presence of fly ash from oil-fired units. Ranges
-------
36
reported for percent combustibles in the fly ash are 50 to 75
percent; 20 30 to 40 percent (but up to 94 percent); 46 and, in 31
tests in one plant, a variation from 61.1 to 95.2 percent. 23 The
amount of combustibles in fly ash decreases with increased
atomization pressure and flame temperature. ^9 A decrease in
the percent combustibles in fly ash should accompany a decrease
in stack loading; not enough data are available, however, to make
a definite statement.
Recently, much attention has been focused on the emission
of potentially carcinogenic substances from various operations.
These substances are usually polynuclear hydrocarbons, of which
3,4-benzpyrene is the most studied example. Only one author
has reported information on emission of these materials from oil-
burning units. Gurinov, a Russian investigator, found 3, 4-benz-
pyrene in concentrations of 0.01 percent of the soot emitted from
the combustion of petroleum introduced in a furnace through a
spray burner. '" Some as yet unpublished sampling data indicate
that about 0. 004 percent of the soot is 3, 4-benzpyrene when oil
is burned by means of an air-atomized oil burner. 45 These
limited data indicate that about 0.04 to 0.10 pounds of 3,4-benz-
pyrene is emitted per million pounds of oil burned.
Other properties of the fly ash given in the literature are an
initial pH of 3; 20 17 to 25 percent 803 (which includes 1^804
droplets); 46 ancj a specific gravity of 2. 5. 20 The amount of
soluble solids reported in one reference ranged from 30 to 60
percent. 19 This range of soluble solids and other values from
references (50) and (42) are represented in Figure 12. The values
range between 1. 3 and 68 percent soluble solids.
VARIABLES AFFECTING EMISSIONS
Efficiency of Combustion
Poor mixing, turbulence of the air and oil, low flame tem-
peratures, and short residence time in the combustion zone cause
larger particles, higher combustible content, and higher particu-
late loadings. *2
-------
Table 12. ELEMENTAL ANALYSES OF TOTAL PARTICULATES (Reference 46)
(Data in percent)
Elements
Carbon
Ether, soluble
Hydrogen
Ash (900°C)
Sulfates as 803
(incl H2S04)
Chlorides as Cl
Nitrogen as NOs
Iron as F62O3
Chromium as CrO2
Nickel as NiO
Vanadium as V2Oo
Cobalt as 0203
Silicon as SiO2
Aluminum as A^Og
Barium as BaO
Magnesium as MgO
Lead as PbO
Calcium as CaO
Sodium as Na2O
Copper as CuO-
Titanium as TiO2
Molybdenum as MoO2
Boron as 8203
Manganese as Mnd2
Zinc as ZnO
Phosphorus as ?2Os
Strontium as SrO
Titanium as TiO
Test A
Total solids from burning
PSa 400 oil (collected in
a laboratory electrical
precipitator at 230°F)
58. lb
2.3
17.4
17.5
3.1
.06
1.8
2.5
.08
.6
1.6
.4
.2
.1
.2
.9
.01
.02
.01
.04
.9
.04
.03
Test B
Total solids from burning
4° API oil (collected in a
glass filter sock at 300°F)
18. lb
4.4
51.2
25.0
.5
.3
3.7
.3
13.2
4.7
.3
9.7
14.9
.1
.7
.2
.4
3.0
.25
.004
.03
.1
.04
.06
a Pacific Standard.
Value probably includes minor amount of hydrogen.
-------
38
ATMOSPHERIC EMISSIONS
10
a
UJ
Individual values reported
Ranges reported
10
20 30 40 50
SOLUBLE SOLIDS, % BY WT
Figure 12. Percent soluble solids in fly ash from large units.
Atomization
The degree of atomization has an important effect on particu*-
late emissions. Low-pressure atomization produces larger fly
ash particles and a higher particulate loading. 49 High-pressure
atomization (400 psig or greater) produces smaller particles,
fewer cenospheres, and lower particulate loadings. 20
Oil viscosity has a major effect on atomization. Oil viscosity
is a function of temperature, for a given oil. In two experiments
on a 186-megawatt plant, seven tests showed that increasing the
oil temperature (which was normally between 230 and 240°F) by
approximately 35°F halved the fly ash emission and reduced the
combustible portion by 15 to 17 percent. 23
The size of the burner orifice affects atomization, and thus
the particle size and loading. Also, clean burners promote good
atomization.
12
Windbox Air Admittance
Varying the settings on the main and auxiliary air dampers
caused pronounced effects on ash emissions in two series of tests
on a 186-megawatt plant. In the first series of tests (3 tests),
the main dampers were not completely opened, but the auxiliary
dampers were opened quickly. This produced large increases in
the fly ash loading and combustible content. 23 in the second
series of tests (5 tests), a much wider range of damper settings
was used. The fly ash loadings did not rise as sharply as under
conditions of the first series of tests. The combustible content
stayed essentially constant in the second series of tests. 23
-------
FROM FUEL OIL COMBUSTION 39
Burner Tilt
One investigator conducted several series of tests involving
change in burner tilt, with and without flue gas recirculation.
There was very little effect on either the fly ash loading or com-
bustible content of the fly ash when flue gas was not recirculated.
When some flue gas was recirculated, however, the combustible
content and loading of fly ash tended to reach a maximum with the
burner tilted zero degrees from the horizontal. This would in-
dicate that best operation, from the air pollution standpoint,
would result with burners inclined either up or down. No con-
clusion has been reached on the combined effect of burner tilt
and flue gas recirculation. 23
Excess Air
Increasing the amount of excess air usually decreases the
fly ash loading and combustible content of the fly ash since more
complete combustion results. In a series of four tests it was
found that, as the oxygen concentration in the stack gas increased
from 2 to 4 percent, the particulate loading decreased from 0.140
to 0. 020 gr/scf, respectively. Or stated another way, an
increase in the CO2 content in the stack gas from 13.1 to 14.7
percent resulted in a 7-fold increase in particulate loading. 23
Flue Gas Recirculation
Fly ash emission increases as more flue gas is recirculated
into the firebox. This is owing to a cooling of the flame and of
combustion gases. One author found that, when the burners of a
186-megawatt plant were at a zero tilt from the horizontal, and
when flue gas recirculation was increased from 0 to 15 percent,
the fly ash loading increased 100 percent. The combustible
content of the fly ash stayed essentially constant. 23
Sootblowing
Sootblowing increases the particulate loading in stack gases.
One author reported a 1.7-fold increase in particulate loading
during sootblowing in one operation and a 3. 3-fold increase in
another, above normal emissions of 0.11 and 0.039 gr/scf,
respectively. ^6 Another author found an increase 2. 3 times the
normal emission of 0.028 gr/scf during sootblowing. 23
-------
40 ATMOSPHERIC EMISSIONS
EMISSIONS FROM SMALL INSTALLATIONS
The term "small sources" refers to sources of less than
1,000 hp (equivalent to 34, 500-pounds steam production per hour
or 2, 500 pounds of oil fired per hour). These units are used in
domestic heating, commercial heating, and in supplying heat and
power to small industrial processes. Because of the smaller
sizes of the units, flame temperature is usually lower than in
larger sources. In many cases, less attention is given to treat-
ment of fuel and regulation of combustion air for small units than
is usually the case for large units. This often results in less
efficient combustion in smaller units.
Small units, in general, produce less NOX and more fly ash
and unburned hydrocarbons than the large sources, because of
the reduction in flame temperature and in combustion efficiency.
Since there is a wide variation in fuels used in the small sources,
emissions are reported in pounds per 1, 000 pounds of oil fired.
Descriptions of emissions and variables affecting emission rates
are similar to those for large sources and are covered there.
Oxides of Nitrogen (NOV)
A
The literature values for NOX emitted from small units are
considerably less than those for large units. In a joint district,
federal, state, and industry project involving measurement of
emissions from 530 units producing 500 horsepower or less, an
emission factor was established. This factor was 0.49-pounds
NOX per 10^ Btu, or 9-pounds NOX per 1, 000 pounds of oil fired
(calculated on the basis of 18, 300-Btu/lb oil). 51 In another
program, which included many tests on both large and small
sources, a general value of 7.2-pounds NOX per 1, 000 pounds of
oil fired was established for small sources. 21 other general
values found in the literature are 13- ^4 an(j 7_pounds NOX ^8
per 1, 000 pounds of oil fired. The values reported in the literature
range from 0 to 18 pounds per 1,000 pounds of oil fired, and these
are shown in Figure 13. The data presentation method used in
the figure indicates that the most common value is between 0 arid
4. A more reliable average value, however, would be about
9-pounds NOX per 1,000-pounds oil fired, based on the joint project
conducted in Los Angeles County. ^1
-------
FROM FUEL OIL COMBUSTION
41
o
o*
[ ] Individual values reported
Typical values reported
Value represents 519 rests "
n Represents many tests on
small sources
02468 10 12 14 16 18 20
NO^, lb/1,000 Ib OF OIL FIRED
Figure 13. NOX emissions from small units.
Sulfur Dioxide (SC>2)
Sulfur dioxide emission data for small units are shown in
Figure 14. This distribution of values is similar to that for large
sources. The extreme range is 0 to 100 percent (of the sulfur in
the fuel oil emitted as SOg. Values up to 254 percent were re-
ported. This is impossible, however, and such values are as-
sumed to be 100 percent. (The error is probably owing to
inaccuracies in sampling and analyzing practices. ) The normal
range is from 70 to 100 percent, and the most common value is
100 percent of the sulfur emitted as SC>2, as it was for the large
sources. For reasons discussed previously under large source
emissions, 98 percent of the sulfur emitted as SC>2 is considered
a more reasonable figure.
-------
42
ATMOSPHERIC EMISSIONS
Q
UJ
1-
o 10
5 _
o
z
1 1 1 1 1 1
r J Individual values reported
JJ^^J Typical values reported
1 , , , 1 1
X
0 10 20 30 40 50 60 70 80 9O 100
(OR GREATER)
SULFUR IN THE OIL EMITTED AS S02, %
Figure 14. Sulfur dioxide emissions from small units.
Sulfur Trioxide (SO3)
Values found in the literature for sulfur trioxide emissions
are shown in Figure 15. This figure shows an extreme range of
0 to 13. 75 percent of sulfur in the fuel oil emitted as 803. The
normal range is between 0 and 1.25 percent and the most common
value is between 0 and 0. 25 percent of the sulfur emitted as 803.
Figure 15 indicates, however, that there are sufficient values
reported to support the conclusion that about 1 percent of the sul-
fur in the oil is emitted as 803. This conclusion would be in more
general agreement with the 803 emission from large sources.
UJ
13
o
f^ Individual values reported
DO Typical values reported
Efi
LXL
.1
n
I Z 8 9 13
SULFUR IN THE OIL EMITTED AS 803, %
14
Figure 15. Sulfur trioxide emissions from small units.
-------
FROM FUEL OIL COMBUSTION
43
Other Gaseous Emissions
Smaller sources tend to emit more organic compounds than
larger sources. This is owing to lower flame temperature and
lower combustion efficiency in smaller units. Literature values
for carbon monoxide are shown in Figure 16 and for aldehydes,
as formaldehyde, in Figure 17. The extreme range for CO
emissions is 0 to 194 pounds per 1,000 pounds of oil fired. The
normal range is between 0 and 1, and the most common values
are between 0- and 0. 5-pound CO emitted per 1,000-pounds oil
fired. The extreme range for the aldehydes, as formaldehyde,
is 0 to 3. 3 pounds per 1, 000 pounds of oil fired. The normal
range is 0 to 0.6 pound, and the most common values are between
0.2 and 0. 3 pound per 1,000 pounds of oil fired.
ID
UJ
|
IU
H
ce
o
0.
IU .
a S
u.
o
d
0
""
V
^H Individual values reported
M Typical values reported
T
-^
1 1 i i i n . . . . n ..
0246 8 10
n . . n
n n
30 40 60 80 100 120 140 160 180 200
CO, Ib/I,000 Ib OF OIL FIRED
Figure 16. Carbon monoxide emissions from small units.
10
a
ui
t-
"<
u. >
o
o"
z
1MB
MM
-
D
El
--P
1 1
Individual values reported
Typical values reported
153 can i .
n
0.5 10 1.5 3.0 3.5
ALDEHYDES (AS FORMALDEHYDE), lb/1,000 Ib OF OIL FIRED
Figure 17. Aldehydes (as formaldehyde) emitted from small sources.
-------
44
One author reported a variation of hydrogen (H2) from 0. 58
to 0. Oil percent in the stack gas when the CO2 varied from 12.4
to 10. 8 percent, respectively. The H2 increased to 0. 215 percent
when the CO2 was reduced to 8. 3 percent. The highest H2 content
of 0. 58 percent corresponded to a Number 9 Shell smoke number, *
which is equivalent to Ringelmann Number 1. Number 8 Shell
smoke number has been reported as the beginning of the visible
range. 52 Data for other pollutants are listed in Table 10. In
addition to these data, another program that included many tests
on commercial and domestic sources established the following
emissions in pounds per 1,000 pounds of oil fired: hydrocarbons,
0.080; aldehydes and ketones, 0.063; and other organic gases,
0.177. These figures are believed to be the most nearly correct
for small sources.
Paniculate Emissions
The fly ash loadings-tor small sources are slightly higher
than those for large sources. The data are presented in Figure
18. The extreme range is between 0 and 10 pounds of particulate
per 1,000 pounds of oil fired. The normal range is between 1 and
4 pounds of particulate per 1,000 pounds of oil fired, and the most
common values are between 1 and 2 pounds of particulate per
1,000 pounds of oil fired.
5 -
o
z
jx;
c^ *)
l><^
^
1 Individual values reported
CTT)I Represents many tests
1 1 i i 1
2345 6789 10
PARTICULATES, lb/1,000 Ib OF OIL FIRED
Figure 18. Particulate emissions from small sources.
*The Shell smoke number is determined by drawing a saniple of Clue gas through a filter paper and
comparing the stain on the paper to nine (9) standards of approximately equal steps of reflectivity.
The shades range from light to dark, the daikest being Number 9, which corresponds to Number 1
Ringelmann. 52
-------
CONTROL OF EMISSIONS
Oxides of Nitrogen (NOX)
The formation of nitrogen oxides increases with the flame
temperature, the length of time the gases remain in the flame,
and the amount of oxygen available. The flame temperature is
influenced by many variables; available oxygen is related to the
amount of excess air present. The most important factor in
reducing NOX formation is furnace design. Tangential firing and
two-stage combustion either one alone or both in combination
reportedly produce significantly less NOX than other procedures.
By decreasing the flame temperature or available oxygen, the
NOX concentration may be decreased. This decrease may be
achieved by reducing the amount of excess air, recirculating
combustion gases, or changing burner conditions. These
measures may, however, increase particulate loading because
of less efficient combustion.
Sulfur Dioxide (SO,,)
Emission of sulfur dioxide is a direct function of the sulfur in
the fuel. Emission of sulfur dioxide may be reduced either by
using low-sulfur crude oils or by removing the sulfur.
Sulfur Trioxide (SO3)
Sulfur trioxide formation is initially a function of the SC>2
concentration and temperature (provided there is a catalyst
present). As a result of reactions of the 803 with other com-
bustion products and with the combustion and heat transfer equip-
ment, however, the 803 actually emitted to the atmosphere shows
no direct correlation with the sulfur content of the oil. Effective
ways of controlling emissions of 863 include the use of additives
and the use of an electrostatic precipitator in the exit gas stream.
The basic objective of using additives is to reduce boiler
deposits and corrosion. The additives are usually added with the
fuel or added to the flue gases directly after combustion. These
compounds usually react with the 803 and tie it up in the form of
neutral salts. Some of the more common additives are oxides,
carbonates, soaps, and naphthenates of calcium, zinc, magnesium,
sodium, and other metals. The additives, by forming sulfate
45
-------
46 ATMOSPHERIC EMISSIONS
salts, usually reduce the SOs concentration, sometimes up to 50
percent, but increase the particulate loading to 1. 5 to 7 times the
normal loading. Carbon, pulverized coal, and fly ash from
pulverized coal have also been used as additives. 1> 7,26,29,30,
31,32,33,53,54,55,56,57,58
Smoke and Organic Gases
Emission of smoke and organic gases is the result of in-
complete or inefficient combustion of the oil. Some of the more
common causes of poor combustion are listed in Table 13. By
proper adjustment and operation, smoke emission can be
eliminated. 12
Acidic Smuts
Acidic smuts are caused by the flue gas coming in contact
with a surface whose temperature is below the dew point of the
flue gas. By maintaining surface temperatures and flue gas
temperatures above the dew point of the flue gas, these smuts
may be prevented. One author insulated the stack of an installa-
tion and prevented formation of smuts. ^
Particulates
Particulate emissions decrease as combustion efficiency
increases. Good combustion efficiency is obtained by high flame
and firebox temperature, high-pressure atomization, high excess
air, and low flue gas recirculation. These measures may,
however, increase the NOX formation. When the particulate
emission is decreased by adjustment of some of these variables,
the NOX emission may increase.
Use of collectors, such as multiple cyclones, on oil-fired
units is usually limited to periods when sootblowing operations
are in progress. Cyclones collect particles of around 10 microns
and larger, but they do not efficiently collect particles of 5
microns or less.
The use of electrostatic precipitators is, at present,
limited. They are found only in those areas where restrictive
legislation requires low particulate loadings and low opacity of
stack effluents. Electrostatic precipitators are generally used
continuously. They collect nearly all the particulates, including
-------
FROM FUEL OIL COMBUSTION
47
liquid droplets, such as 112804. The particulate loading may be
decreased 90 percent or more and the 803 emission may be
decreased by as much as 50 percent of the original concentration
when electrostatic precipitators are used. 1> ?» 42, 43, 59, 60, 61, 62
Table 13. COMMON CAUSES AND RESULTS OF POOR COMBUSTION
(Reference 12)
Cause
Insufficient air or too
much oil (improper air-
fuel ratio)
Poor draft
Excess air (causing white
smoke)
Dirty or carbonized burner
tip (caused by improper
location, insufficient
cleaning at regular inter-
vals)
Carbonized or damaged
atomizing cup (rotary CUD)
Worn or damaged orifice
hole
Improper burner adjustment
(diffuser plate protruding
improper distance)
Oil pressure to burner too
hieh or too low
Oil viscosity too high
Oil viscosity too low (too
high fuel oil temperature)
Forcing burner (especially
after initial light-off or
when combustion space is
relatively cold)
Insufficient atomizing steam
Water in fuel oil
Dirty fuel oil
Fluctuating oil pressure
Incorrect furnace con-
struction causing flame
and oil impingement
Carbon clinker on furnace
floor or walls
Incorrect atomizer tip size
Condensate in atomizing
steam
Atomizing steam pressure
too high
Furnace cone angle too
wide
Furnace cone angle too
narrow (making it neces-
sary to have atomizer in
mnv^mum position)
Atomizer not immediately
removed from burner
being secured
Result
Smoking
fire
X
X
Carbon formation
in the boiler
X
Sometimes
Pulsating
fire
X
X
X
X
X
X
X
X
X
X
X
X
Intermittent
X
X
X
X
X
Sometimes
X
X
X
X
X
Sometimes
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
-------
REFERENCES
1. Chadwick, W. L., and Haagen-Smit, A. J. Proc. National
Conference on Air Pollution, U. S. Dept. of HEW, PHS,
Washington, D. C., Nov. 1958. PHS Pub. 654. pp. 146-
155.
2. Perry, J. H. Chemical Engineers Handbook. 3rd ed.
McGraw-Hill, N. Y. 1950.
3. Diesel Fuel Oils: Production, Characteristics and Com-
bustion. 19th ASME Natl. Oil and Gas Power Conference,
May 20, 1947. ASME, New York. 1948. pp. 21-23.
4. Johnson, A. J., and Auth, G. H. Fuels and Combustion
Handbook. McGraw-Hill, N. Y. 1951.
5. Blade, O. C. Burner Fuel Oils, 1961. Mineral Industry
Surveys. U. S. Bureau of Mines. 1961.
6. American Petroleum Institute. Petroleum Facts and Fig-
ures, 1961.
7. Battelle Memorial Institute. A Review of Available Informa-
tion on Corrosion and Deposits in Coal and Oil-Fired Boilers
and Gas Turbines. ASME, N. Y. 1959.
8. Buckland, B. O., Gardiner, C. M., and Sanders, D. G.
Residual fuel-oil ash corrosion. ASME Paper 52-A-161.
1952.
9. Thomas, W. H. Science of Petroleum. Vol. E. Oxford
Press, London. 1938. pp. 1053-1056.
10. Rowley, L. N., McCabe, J. C., and Skrotzki, B. G. A.
Fuel and firing. Power, 92(12):735-782. Dec. 1948.
11. Roberts, E. G. Fundamentals of fuel oil combustion.
Power Plant Engineering, 42:111-114. 1938.
12. Parmelee, W. H. Operation of oil burners on steam boilers.
Los Angeles County Air Pollution Control District, Los
Angeles, Calif. 18 pp. Mimeo.
13. Blum, H. A., Lees, B., and Rendle, L. K. Prevention of
steel stack corrosion and smut emission with oil-fired
boilers. Inst. FuelJ., 32(217):165-171. Feb. 1959.
49
-------
50
14. Sensenbaugh, J. D., and Jonakin, J. Effect of combustion
conditions on nitrogen oxide formation in boiler furnaces.
ASME Paper 60-WA-334. 1960.
15. Sensenbaugh, J. D. Air pollution problems of public utili-
ties. Presented at 5th Annual Meeting New England Section,
APCA, Bloomfield, Conn. May 10, 1961.
16. Austin, H. C. Atmospheric pollution problems of the public
utility industry. JAPCA, 10(4):292-294. Aug. 1960.
17. Austin, H. C., and Chadwick, W. L. Control of air pollu-
tion from oil burning power plants. Mech. Engr., 82(4) :63-
66. Apr. 1960.
18. Gould, G. Formation of air pollutants. Power, 104:86-88.
Aug. 1960.
19. Mills, J. L., Leudtke, K. D., Woolrich, P. F., and Perry,
L. B. Emissions of oxides of nitrogen from stationary
sources in Los Angeles. Report 3: Oxides of nitrogen
emitted by medium and large sources. Los Angeles County
Air Pollution Control District, Los Angeles, Calif. July
1961.
20. Chaney, A. L. Significance of contaminants from central
power plants. Proc. First Technical Meeting, West Coast
Section, APCA. Mar. 25-26, 1957. pp. 33-35.
21. Chass, R. L., Lunche, R. G., Schaffer, N. R., and Tow,
P. S. Total air pollution emissions in Los Angeles County.
JAPCA, 10(5):351-366. Oct. 1960.
22. Woolrich, P. F. Methods for estimating oxides of nitrogen
emissions from combustion processes. Amer. Ind. Hyg.
Assoc. J., 22:481-484. 1961.
23. Jefferis, G. C., and Sensenbaugh, J. D. Effect of operat-
ing variables on the stack emission from a modern power
station boiler. ASME. Oct. 22, 1959.
24. Barnhart, D. H., and Diehl, E. K. Control of nitrogen
oxides in boiler flue gases by two-stage combustion. JAPCA,
10(5):397-406. Oct. 1960.
25. Private communication with Pacific Gas and Electric Com-
pany. Mar. 6, 1961.
-------
51
26. Huge, E. C., and Plotter, E. C. The use of additives for
the prevention of low temperature corrosion in oil-fired
steam-generating units. Trans. ASME, 77:267. 1955.
27. Grohse, E. S., and Saline, L. E. Atmospheric pollution:
the role played by combustion processes. JAPCA, 8:255-
267. Nov. 1958.
28. Yeau, J. S., and Schnidman, L. Flue products of industrial
fuels. Ind. Eng. Chem., 28:999-1004. 1936.
29. Wilkinson, T. J., and Clarke, D. G. Problems encounter-
ed with the use of high sulphur content fuel oils at March-
wood generation station and experience with chemical
additives. Inst. FuelJ., 32:61-72. 1959.
30. Jarvis, W. D. Selection and use of additives in oil-fired
boilers. Inst. FuelJ., 31(214):480-49l. Nov. 1958.
31. Rendle, L. K., and Wilsdon, R. D. The prevention of acid
condensation in oil-fired boilers. Inst. Fuel J., 29:372-380.
1956.
32. Flint, D., Lindsay, A. W., and Littlejohn, R. F. The
effect of metal oxide smokes on the SO, content of combus-
tion gases from fuel oils. Inst. FuelJ;, 26:122-127. Sept.
1953.
33. Alexander, P. A., Fielder, R. S., Jackson, P. J., Raask,
E., and Williams, T. B. Acid deposition in oil-fired
boilers. Inst. FuelJ., 34:53-72. Feb. 1961.
34. Nelson, H. W., and Lyons, C. J. Sources and control of
sulfur-bearing pollutants. JAPCA, 7:187-193. Nov. 1957.
35. Crumley, P. H., and Fletcher, A. W. The formation of
sulfur trioxide in flue gases. Inst. Fuel J., 29:322-327.
Aug. 1956.
36. Whittingham, G. The influence of carbon smokes on the
dew-point and sulphur trioxide content of flame gases. J.
Applied Chem., 1:382-399. 1951.
37. Corbett, P. F. The determination of SC>2 and 803 in flue
gases. Inst. FuelJ., 24:247-251. 1951.
-------
52
38. Wohlers, H. C., and Bell, G. B. Literature review of
metropolitan air pollutant concentrations: Preparation,
sampling and assay of synthetic atmospheres. Stanford
Research Institute Project No. SU-1816. Menlo Park,
Calf., Nov. 30, 1956.
39. Feldstein, M., Coons, J. D., Johnson, H. C., and Yocum,
J. E. The collection and infrared analysis of low molecular
weight hydrocarbons from combustion effluents. Amer.
Ind. Hyg. Assoc. J., 20:374-378. Oct. 1959.
40. Magill, P. L., and Benoliel, R. W. Air pollution in Los
Angeles County: contribution of combustion products. Ind.
Eng. Chem., 44:1347-1351. 1952.
41. Kanter, C. V., Lunche, R. G., and Fudurich, A. P.
Techniques of testing for air contaminants from combustion
sources. JAPCA, 6:191-198. Feb. 1957.
42. Haagen-Smit, A. J. Studies of air pollution control by
Southern Calif. Edison Co. ASME Paper 57-SA-59. 1957.
43. Private communication with Apra Precipitator Corp. June
1, 1961.
44. The Louisville Air Pollution Study, SEC Tech. Report,
A61-4. USDHEW, Public Health Service, Cincinnati, Ohio.
1961.
45. Unpublished data from private communications.
46. MacPhee, R. D., Taylor, J. R., and Chaney, A. L. Some
data on particles from fuel oil burning. Los Angeles County
Air Pollution Control District, Air Analysis Division.
Analysis Paper No. 7. Nov. 18, 1957.
47. Private Communication with Florida Power and Light Co.
June 28, 1961.
48. Bowden, A. T., Draper, P., and Rowling, H. The problem
of fuel oil deposition in open-cycle gas turbines. Proc. (A)
Inst. Mech. Engr., 167:291-300. 1953.
49. Clarke, J. S., and Hudson, G. J. Heavy oil burning. Inst.
Marine Engrs. Trans., 71(5):135-157. Mar. 1959.
50. Private communication with Southern California Edison Co.
Feb. 7, 1961.
-------
53
51. Emissions of Oxides of Nitrogen from Stationary Sources in
Los Angeles County. Report 2: Oxides of nitrogen emitted
by small sources. Los Angeles County Air Pollution Control
District, Los Angeles, Calif. Sept. 1960.
52. Hurley, T. F., and Flaws, L. J. The prevention of smoke
from heating boilers. J. Inst. Heating & Vent. Engrs.,
23:1-32. Apr. 1955.
53. Mcllroy, J. B., Holler, E. J., and Lee, R. B. Super-
heater slag bows to additives. Power, 97:86-88. Mar.
1953.
54. Jacklin, C., Anderson, D. R., and Thompson, H. Fireside
deposits in oil-fired boilers. Ind. and Engr. Chem.,
48(10): 1931-1934. Oct. 1956.
55. Wivstad, I. Pulverized coal additives in oil firing. Teknisk
Tidskrift, Stockh., 84:509. 1954.
56. Keck, J. W. Slurry spray cuts cost of cleaning boilers.
Electrical World, p. 130. Apr. 25, 1960.
57. Report of Informal Conference on Corrosion Problems As-
sociated with Oil Firing. Central Electricity Generating
Board, London. Nov. 20, 1957. 52 pp.
58. Fisher, G. Problem of sulfur in residual fuels. Proc.
First Technical Meeting, West Coast Section, APCA, Los
Angeles, Calif. Mar. 25-26, 1957. pp. 114-117.
59. Haagen-Smit, A. J. Removal of particulate and gaseous
contaminants from power plant flue gases. Proc. First
Technical Meeting, West Coast Section, APCA, Los Angeles,
Calif. 1957. pp. 102-110.
60. Pilpel, N. Industrial gas cleaning. Brit. Chem. Eng.,
5:542-550. Aug. 1960.
61. Austin, H. C., and Sproul, W. T. The Cottrell precipitator
for oil-fired power plants. Paper 59-55. Proc. APCA,
1959.
62. Cyclone Dust Collectors. Engineering Report Prepared for
American Petroleum Institute, Division of Refining, N. Y.,
N. Y. Feb. 1, 1955.
-------
54
63. Grossman, P. R. Developments in solid fuel burning equip-
ment in air pollution control. JAPCA, 7(3):222-226. Nov.
1957.
64. Corbett, P. F., and Fereday, F. The sulphur trioxide
content of the combustion gases from an oil-fired water tube
boiler. Inst. FuelJ., 26(151):92-106. Aug. 1953.
65. Faith, W. L. Nitrogen oxides: a challenge to chemical
engineers. Chem. Engr. Progress, 52:342-344. Aug. 1956.
66. McCabe, L. C. News of the industry. Air Engineering,
2(5) :60. May 1960.
67. Matty, R. E., and Diehl, E. K. Measuring flue-gas SC>2
and SOs. Power, 101:94-97. Nov. 1957.
68. Chass, R. L. and George, R. E. Contaminant emissions
from the combustion of fuels. Paper 59-52. Proc. APCA,
1959.
69. Sambrook, K. H. The efficient and smokeless combustion of
fuel oils. Proc. 20th Annual Conference, Glasgow, Sept. 30
to Oct. 2, 1953. National Smoke Abatement Society, London.
pp. 83-99.
70. Guvinov, B. P. Effect of the method of combustion and type
of fuel on the content of 3, 4-benzpyrene in smoke gases.
Gigiena i Sanitaria, Moscow. 23(12):6-9. Dec. 1958.
-------
APPENDIXES
APPENDIX A. DETAILED DATA ON
LARGE SOURCE EMISSIONS
APPENDIX B. DETAILED DATA
ON SMALL SOURCE EMISSIONS
APPENDIX C. METHOD OF
REPORTING THE DATA
55
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS
Refer-
ence
la
14
-
Original
work
__b
Nominal
turbine
load,
mw
175
Steam
rate,
1,000
Ib/hr
Boiler
Firing
rate,
1,000
Ib/hr
Type
of
firing
Horizontal
M
t
Tangential
Horizontal
Tangential
Horizontal
11
Tangential
Volume,
1,000
scfm
Flue g
Temp,
OF
as
Or sat (%)
CO, C02, 02
3. 5% 02
3.1% 02
2. 3% 02
4. 2% O2
3.0% 02
2. 9% 02
2. 2% 02
Emissions
Particulates and gases
75 Ib/hr solids
13. 1 ppm SOs
330 - 915 ppm NOX
> 100 ppm CO
(For poor combustion)
ppm NOX Plant:
685 El Segundo
567 A
505 B
482 C
362 E
309 F
209 G
385 El Segundo
276 B
160 G
681 & 699 C
637 & 681 C
456 & 508 C
258 G
202 G
219 G
184 G
Notes and miscellaneous
Dust 0.4^,(about)
indicates
90% <0.5H
Normal full load
Two-stage combustion
Excess air variation
-------
15a
16a
17a
18
General
--
General
No,
general
Typical
175
"
--
--
"
..
"
"
Horizontal
Tangential
~~
"
--
--
"
*" ~
"
--
239 G
210 G
202 G
222 G
219 G
202 G
202 G
184 G
90% sulfur to SOX
1-5% SO2 to SO3
0. 02-0. 04 gr/ set
100-900 ppm NOX
500-700 ppm NOX
200-400 ppm NQx
600 ppm SC>2/1% sulfur
in fuel
1-2% SOa to 803
100-900 ppm NOx
120 Ib/hr dust
13. 1 ppm (average) 803
310-915 ppm NOX
Two-stage combustion
reduced from 685 to
350 ppm NOX
CO, 100 ppm or less in
inefficient boiler
310-915 ppm NOX
Dust, 0. 14 lb/ 1,000 Ib
oil
1-5% sulfur to S03
SO2, 2,200 ppm § 14%
COa
0% gas recirculation
7. 9% gas recirculation
15. 4% gas recirculation
207°F oil temperature
238°F "
242°F '
243°F "
277°F "
--
--
Ash, < 1 to 40 M
Dust, 0. 4U
4% sulfur in oil
\
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
19
Original
work
Yes"
Nominal
turbine
load,
mw
Steam
rate,
1,000
Ib/hr
Boiler
Firing
rate,
1,000
Ib/hr
Type
of
firing
__
Volume,
1,000
sctm
__
Flue g
Temp,
OF
__
as
Orsat (%)
CO, CO2, O2
%O2
2.4
2.4
3.3
3.3
3.3
3.5
3.5
3.5
2.5
2.5
3.3
3.3
4.0
4.0
4.2
4.2
5.7
5.7
2.4
2.6
2.6
3. 1
Emissions
Particulates and gases
ppm NOX:
642
634
634
659
668
694
711
745
437
531
557
600
582
604
583
600
660
677
420
420
394
446
Notes and miscellaneous
100% load,
16, burners
85% load,
16 burners
70% load,
16 burners
-------
70
..
__
3.1
3.1
3.1
3.1
4.5
4.5
4.5
5.2
5.2
5.2
5.3
2.7
2.7
2.8
2.8
4.3
4.3
4.3
2.4
2.4
2.4
3.3
3.3
3.3
4.1
4.1
4.1
4.1
5.2
5.2
5.3
5.3
3.0
454
471
480
488
557
578
596
638
626
604
591
338
345
386
369
531
523
497
300
266
240
381
369
347
420
411
394
377
540
531
548
557
381
300
55% load
12 burners
55% load
16 burners
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
19
(cont'd)
Original
work
Nominal
turbine
load,
raw
95
120
150
175
156
Steam
rate,
1,000
Ib/hr
__
_.
_.
Boiler
Firing
rate,
1,000
Ib/hr
__
__
_.
Type
of
firing
__
__
..
Volume,
1,000
scfm
_
_
__
Flue g.
Temp,
op
__
__
IS
Orsat (%)
CO, C02, 02
"«5Jf '
3.0
3.0
3.0
3.0
Emissions
Particulates and gases
ppm NOX:
471
450
394
342
325.
492
471
462
428
407
385
377
540
531
514
432
578
557
514
445
514
492
450
445
Notes and miscellaneous
Air register, % open:
15
-------
--
--
.
--
2.5
2.8
3.2
3.4
3.5
4.0
4.5
4.6
4.7
5.4
2.0
2.2
2.8
488
462
428
420
471
462
450
437
471
432
411
402
407
394
385
364
454
471
497
471
497
535
548
540
557
561
325
342
377
30
45
60
75
Oil pressure at burner
tip, 390 psig
Oil pressure at burner
tip, 480 psig
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
19
(cont'd)
Original
work
Nominal
turbine
load,
mw
150
126
Steam
rate,
1,000
Ib/hr
__
Boiler
Firing
rate,
1,000
Ib/hr
-_
Type
of
firing
__
__
Volume,
1,000
scfm
_
Flue g
Temp,
OF
as
Orsat (%)
CO, C02, 02
%02:
3.2
3.4
3.5
3.6
4.1
5.0
3
3
Emissions
Particulates and gases
ppm NOx:
372
381
377
450
480
514
475
462
411
420
407
402
411
471
497
505
535
364
372
411
428
437
Notes and miscellaneous
14 burners, oil pressure
at burner tip, 345 psig
12 burners, oil pressure
at burner tip, 405 psig
10 burners, oil pressure
at burner tip, 505 psig
16 burners
Air register, % open:
65
70
80
90
100
65
70
80
90
100
-------
20
Yes
(general
average)
General
150
-.
100
or
greater
--
74
about
50
._
250
to
300
..
_-
2.0
2.3
2.7
2.9
3.4
3.5
3.8
3.8
4.5
4.5
2.5
2.8
3.1
3.3
3.3
3.8
4.4
4.5
4.7
5.3
_-
--
552
514
561
561
600
608
638
621
651
664
454
471
492
475
505
535
548
539
557
557
0. 78 Ib NOX/106 Btu
or 14.2 lbNOx/l,000 Ib
oil fired, calculated
using 18, 300
Btu/lb oil
Dust, 1-5 lb/1,000 Ib oil
at low pressure
atomization
2/3 reduced with good
atomization
SO2.30 lb/1,000 Iboil
S03, l-2.51b/l,0001b
oil
NOx, 400-600 ppm
Dirty boiler
Clean boiler
Based on 130 tests and
554 individual samples
1.5% sulfur in oil
Particles are both solid
and liquid. Liquid part
is H2SO4
Typical size distribution
for carbon particles,
95% is 10-1, OOOM
Specific gravity, 2. 5 of
particulates.
50-75% carbon, rest ash
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
20
(cont'd)
21
23
Original
work
General
Yes
Nominal
turbine
load,
mw
Normal,
110
Boiler
Steam
rate,
1,000
Ib/hr
_
..
Firing
rate,
1,000
Ib/hr
__
Type
of
firing
__
Tangential
Flue gas
Volume,
1,000
scfm
__
--
Temp,
op
__
--
Orsat (%)
CO, CO2, O2
-.
Emissions
Particulates and gases
lb/1,000
Iboil
fired:
NO* as NO2 17. 6
SO2 31. 4
CO 0. 0051
Aerosol 2. 5
Hydrocarbons 0. 097
Aldehydes &
Ke tones 0. 071
Other organics 0. 326
Notes and miscellaneous
Ash is light brown, In,
30 to 60% soluble, initial
pH 3, size 0. 5 to lw
Visible plume due to
particles IM or less in
size
Good power plant oper-
ation
(Converted from lb/103
bbl, using 10 API oil. )
Based on many samples,
all stationary sources
Fuel analysis: 10. 6 API,
18,210 Btu/lb, 86. 3% C,
10.28%H2, 2. 3% sulfur,
0. 06% ash, and 1. 03%
N2 + 02 (by difference)
Steam, 1, 050/1, 000°F
-------
Actual:
186
185
183
185
185
185
181
173
163
159
185
177
173
178
176
169
183
186
184
180
184
184
Dust, gr/scf: NOX, ppm
0. 068 219
0. 101 207
0. 035 201
0. 033 202
0. 105 222
0. 032 184
0. 033 212
0. 029 248
0. 026 239
0. 023 240
0. 028 245
0. 029 281
0. 028 258
0. 142 184
0. 060 202
0.030 210
0. 028 283
0. 027 193
0. 033 188
0. 049 196
0.028
0.064
Oil temp, Combustible,
°F: % in dust:
238 87.98
238 95. 24
242 79. 49
242 78. 63
207 88. 03
277 73. 15
276 72. 75
241 79. 59
241 88.37
242 73.75
241 74.36
241 77. 48
243 75. 02
242 90. 62
243 86. 07
242 83. 87
242 66. 23
242 65. 72
242
242 71.49
240
240 soot blowing
Fuel analysis: 9. 1 API,
18, 050 Btu/lb, 86. 9% C,
10. 55% H2, 2. 05% sulfur
0. 50% N2 + O2 (by dif-
ference), 0.01% ash
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
23
(cont'd)
24
Original
work
Yes
Nominal
turbine
load,
mw
Actual:
174
174
171
174
172
172
172
174
173
174
172
172
170
169
162
182
182
183
182
182
182
Boiler
Steam
rate,
1,000
Ib/hr
1,140
Firing
rate,
1,000
Ib/hr
Type
of
firing
Flue gas
Volume,
1,000
scfm
Temp,
OF
Orsat (%)
CO, C02, O2
--
Emissions
Particulates and gases
Dust, gr/scf: NOj^ppm.
220
232
252
0. 033 227
0. 047 226
0. 059 203
0. 089 198
192
226
0. 091 172
196
212
0. 055 308
0. 049 238
0. 031 277
0. 037 267
0. 076 269
0. 043 277
0. 048 206
0. 046 242
0. 026 246
685 ppm NOx normal
575 ppm NOx removed
approach-cone vanes
305 ppm NOX two-stage
combustion and no
approach-cone vanes
Notes and miscellaneous
Oil temp, Combustible,
°F: % in dust:
232
232
232
228 74. 15
234 73. 85
230 74. 61
228 76. 65
232
230
228 75. 17
234
234
208 75. 49
238 76. 27
277 64. 72
232 61. 10
232 73. 08
230
232 68. 22
239 65. 45
231 69.24
Steam, 1,860 psi 1,000°F
-------
25a
26
27
29a
Typical
Yes
Yes
General
__
__
1,170
450
..
86
30
Mechanical
atomizing
__
..
__
__
_.
__
-_
__
_.
15. 4% C02
0. 7% 02
0. 033% CO
450 ppm NOX as NO2
55 ppm 803
0. 022 gr/scf dust
loading
325 ppm, NOX as NO2 \
35 ppm, 803 j
740 ppm SO2 (calculated
38 ppm 803, air heater
inlet
28 ppm 803, air heater
outlet
37 ppm SO3, air heater
inlet
29 ppm SOs, air heater
outlet
100% sulfur in oil out
stack
SOs, PPm, SOs, PPm,
without with
additives: additives:
40 18
15 3-5
15 8-10
44 10
38 18
2% of the sulfur to SOs
Fuel analysis:
Full 6. 2 AH, 610 sec
load Furol at 122°F,
1. 3% sulfur,
0. 06% ash,
18, 040 Btu/lb
VSload "ght plume
from stack
Boiler pressure,
all loads 850 psi, temp,
1, 000°F
full load 2-4;3'3$
sulfur in oil
1/2 load
_
4. 2% sulfur in the oil
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
31a
Original
work
Yes
Nominal
turbine
load,
mw
Boiler
Steam
rate,
1,000
Ib/hr
Firing
rate,
1,000
Ib/hr
Type
of
firing
..
Flue gas
Volume,
1,000
scfm
..
Temp,
op
..
Orsat (%)
CO, C02, 02
_>
Emissions
Particulates and gases
SO3, ppm: % sulfur
in oil:
10 0.2
12 0.2
14 0.5
17 0.5
8 1.2
18 1.2
10 1.7
17 1.7
21 1.75
23 1.75
18 1.8
20 1.8
15 1. 9
22 2.2
31 2.3
18 2.7
20 2.7
22 2.7
30 2.7
18 3.2
25 3.2
32 3.2
Notes and miscellaneous
Added sulfur to some of
the oils. Data was
taken from a curve
-------
35
Yes
375
328
350
341
352
380
353
380
350
360
-.
%C02:
10.1
10.6
10.6
10.7
10.9
11.9
11.5
10.1
12.2
12.3
17 3. 25
16 3.5
27 3.5
15 4.1
21 4.1
30 4.1
31 4. 1
38 4.4
40 4.4
15 4.5
23 4.5
22 5.0
30 5.0
36 5.0
40 5.0
29 5.1
33 5.2
SOs, ppm:
38
22.6
19.3
22.4
50.6
56.5
45
75
27.5 '
50.8
Steam 925°F.
and 950 psi.
Residual fuel
Measured contains 3. 6-
in 3. 7% sulfur
primary
super Maximum
heater rating 375, 000
Ib/hr steam
Secondary
super heater
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
38
39a
Original
work
General
estimates
Nominal
turbine
load,
mw
Boiler
Steam
rate,
1,000
Ib/hr
--
Firing
rate,
1,000
Ib/hr
Type
of
firing
--
Flue gas
Volume,
1,000
scfm
--
--
Temp,
OF
Orsat (%)
CO, CO2, 02
Emissions
Particulates and gases
lb/1, 000
Ib oil:
NOX as NO2 7
SO2 20
S03 1
H2S < 1
HCN <1
NH3 1
HC1 <1
CH20 1
Organics 5
Acids
(as CH3COOH) 15
Solids 1
ppm:
0 Methane
0 Acetylene
0 Ethylene
13 Other hydro-
carbons (as
propane)
0 CO
0 NO2
0 NO
Notes and miscellaneous
Literature research for
all oils.
Data are general aver-
ages reported to be
applicable to all
sources in a major
community.
Infrared measurement
techniques
-------
40
41
42
43a
Typical
Yes
General
No,
typical
estimates
Yes
1,140
850
1,140
82.5
61
__
415
250
340
"~
688
280
9.9 CO2
8.6 CO2
0. 0% CO,
14. 6% C02,
3. 0% 02,
82. 4% N2
lb/1, 000
Ib oil:
13 NOx
0.25 Solids
30 SOX
1. 2 Aldehydes
15 Acids
(as HOAC)
5 Organics
0. 0515 gr/scf dust
0. 0325 gr/scf dust
lb/1, 000 Ib oil:
S02 28. 82 & 39
80s 0. 037 & 0. 07
NOx 5. 0 & 28. 05
Organic acid (as acetic)
0.235 &0. 41
Aldehydes (as formal-
dehyde) nil & 0. 65
Hydrocarbons (as
hexane) 0. 28 & 0. 095
Acetylene nil & 0. 03
575 ppm NOX
810 ppm SO2
18. 3 ppm SO3
0. 072 gr/scf solids
(total)
0. 049 gr/scf soluble
solids
0. 033 gr/scf dust enter
collector
0. 0033 gr/scf dust leave
collector
Fuel analysis: 4° API,
1. 6% sulfur,
8. 5% moisture in stack
Fuel analysis: 8. 7° API,
1. 4% sulfur,
7. 8% moisture in stack
Results of 2 tests
Author states that an
electrostatic precipitator
will reduce the SOs con-
centration by about 50%
Bunker C oil
Electrostatic precipitator
Dust 95% less than 0. 5u
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
44
45a
Original
work
General
Yes
-
Nominal
turbine
load,
mw
--
Boiler
Steam
rate,
1,000
Ib/hr
--
Firing
rate,
1,000
Ib/hr
--
Type
of
firing
Flue gas
Volume,
1,000
scfm
182
Temp,
OF
325
Orsat (%)
CO, CO2, O2
--
._
Emissions
Participates and gases
lb/1,000
Ib oil:
NOx as NO2 13
SO2 18 times
% sulfur
in oil
SOa 2 times
% sulfur
in oil
Solids 0. 25
Ammonia 0. 006
Organic Acids
(as acetic) 15
Aldehydes (as
formaldehyde)!. 23
Total hydro-
carbons 5
Particles collected in
cyclone, 0.0580 gr/scf
Particles collected in
precipitator, 0. 1083
gr/scf
Notes and miscellaneous
Solids lu indiam or less.
Literature research for
all oils
Particle size,
above 3-4n = 53%
under 3U = 47%
Particle analysis:
Free carbon 63. 2%
Vol combustible (ether
soluble) 2. 3%
Acid soluble volatile
noncombustible 18. 9%
Loss on ignition 84. 4%
Ash 15. 6%
100. 0%
-------
46*
50
Yes
Yes
175
1,150
85
--
Horizontal
mechanica
atomizing
--
283
--
300
12. 9 CO2
3.402
83. 7 N2
gr/scf dust: Plant:
0.11 A
0.16 A
0.18 A
0.20 A
0.03 B
0.09 B
0.05 C
0.05 C
0.04 C
gr/scf: ppra:
599 NOX
703 SO2
12. 5 SOa
0. 0316 Total dust
loading
0. 0075 Soluble
solids
Fuel, type:
PS400 During lancing
PS400
PS400
PS400
PS400
PS400 During lancing
4<> API
4<> API
4° API
Plant B had collection
device called a Multi-
clone that removed
nearly all the ceno-
spheres. A plume was
still visible
53% greater 4n. 30-40%
combustible (general),
but has found 94%
combustible. 0. 09 to
0. 29 ash in fuel/total
loading 17 to 25% SO3
in ash (include H2SC>4
droplets)
Fuel analysis: 87. 13% C,
9.64% H2, 1.35%S,
1.10%N2, 0.01% ash
Steamc: 1,000/1, 000°F
and 2, 000 psig
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
50
(cont'd)
Original
work
Nominal
turbine
load,
mw
173
30
41
220
Steam
rate,
1,000
Ib/hr
1,150
275
400
1,410
Boiler
Firing
rate,
1,000
Ib/hr
86
18.5
21.7
102
Type
of
firing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Volume,
1,000
scfm
303
69
91.2
334
Flue g
Temp,
op
300
310
320
280
a.a
Orsat (%)
CO, C02, 02
12. 9 CO2
4.202
82. 9 N2
11.6 CO2
6.602
81.8 N2
12. 2 CO2
5. 502
82. 3 N2
13. 5 C02
2.902
83. 6 N2
Emissions
Particulates and gases
gr/scf: ppm:
317 NOX
732 SO2
20. 6 803
0. 0428 Total dust
loading
0. 0079 Soluble
solids
0. 0140 Total dust
loading
0. 00235 Soluble
solids
0. 0178 Total dust
loading
0. 0012 Soluble
solids
464 NOX
812 S02
10. 4 SO3
0. 0358 Total dust
loading
0. 098 Soluble
solids
Notes and miscellaneous
Fuel analysis: 87. 36% C,
9. 53% H2, 1. 50% S,
1.14%N2, 0.07% ash
Steamc: 1,000/1, 000°F
and 2, 000 psig
Fuel analysis: 88. 66% C,
8. 83%H2) 0.86%S,
1. 04% N2, 0. 01% Ash
Steam: 900°F and 950
psig
Fuel analysis: 85. 84% C,
10.76%H2, 1.34%S,
0. 78% N2, 0. 068% Ash
Steam: 950OF and 1, 500
psig
Fuel analysis: 87. 24% C,
9. 52% H2, 1.52%S,
1. 06% N2, 0. 08% Ash
Steamc: 1, 050/1, 000°F
and 2, 500 psig
-------
20
175
Common
steam
heater
to
turbine
215
215
1,150
410
1,400
12.5
82.5
29.6
105
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
47.3
281
116
309
300
300
330
280
12. 2 CO2
5. 4 02
82. 4 N2
12.9 CO2
4.002
83. 1 N2
11.4 CO2
6.5 02
82. 1 N2
14. 6 C02
2.402
83. 0 N2
0. 0446 Total dust
loading
0. 00057 Soluble
solids
374 NOx as
N02
796 SO2
8. 7 SO3
0. 0354 Total dust
loading
0. 0026 Soluble
solids
551 NOx as
N02
709 S02
9. 5 SO3
0. 0855 Total dust
loading
0. 0074 Soluble
solids
508 NOx as
NO2
763 SO2
14. 0 SO3
0. 0294 Total dust
loading
0. 0141 Soluble
solids
Fuel analysis: 87. 13% C,
9. 95% H2, 1.58%S,
1. 08% N2( 0. 06% Ash
Steam: 900°F and 1, 150
psig
Fuel analysis: 87. 33% C,
9. 37% H2, 1.53%S,
1.18%N2) 0.12% Ash
Steam0: 1, 000/1, 000°F
and 2, 000 psig
Fuel analysis: 87. 33% C,
9. 37% H2, 1.53%S,
1. 18% N2, 0. 12% Ash
Steam: 900°F and 850
psig
Fuel analysis: 86. 9% C,
9. 6%H2, 1.4%S, 0.9%
N2) 0. 08% Ash
SteamC; 1, 050/1, 000°F
and 2, 500 psig
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
50
(cont'd)
Original
work
Nominal
turbine
load,
mw
215
215
215
Steam
rate,
1,000
Ib/hr
1,400
1,390
1,400
Boiler
Firing
rate,
1,000
Ib/hr
107
105
104
Type
of
firing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Volume,
1,000
scfm
314
309
309
Flue g
Temp,
op
280
280
280
as
Orsat (%)
CO, C02, 02
14. 3 CO2
2.802
82.9 N2
14. 9 C02
2.302
82. 8 N2
14. 6 CO2
2.5 02
82. 9 N2
Emissions
Particulates and gases
gr/scf: ppm:
451 NO* as
NO2
765 SO2
28. 2 S03
0. 0326 Total dust
loading
0. 0155 Soluble
solids
438 NOX as
NO,
790 SO2
17. 7 SO3
0. 0330 Total dust
loading
0. 0064 Soluble
solids
385 NOx as
N02
758 SO2
15. 8 SO3
0. 0347 Total dust
loading
0.0116 Soluble
solids
Notes and miscellaneous
Fuel analysis: 86. 9% C,
9. 6% H2, 1. 4% S, 0. 9%
N2, 0. 08% Ash
Steam0: 1, 050/1, 000°F
and 2, 500 psig
Fuel analysis: 86. 9% C,
9. 6% H2, 1. 4% S, 0. 9%
N2, 0. 08% Ash
Steamc: 1, 050/1, 000°F
and 2, 500 psig
Fuel analysis: 86. 9% C,
9.6%H2, 1.4%S, 0.9%
N2, 0. 08% Ash
Steamc: 1,050/1, 000°F
and 2, 500 psig
-------
215
215
215
215
1,390
1,420
1,400
1,400
105
107
104
105
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
315
320
351
315
280
280
280
280
14. 6 CO,
2.302
83. 1 N2
13. 8 COa
3.202
83. 0 N2
14. 1 CO2
2.202
83. 7 N2
15.4C02
1.902
82. 7 N2
476 NOX as
N02
812 SO2
9.0 803
421 NOX as
NO2
774 SO2
15. 4 SO3
,0. 0210 Total dust
loading
0. 0092 Soluble
solids
279 NOjj as
N02
118 SO2
5.3 803
0. 0128 Total dust
loading
0. 00217 Soluble
solids
479 NOx as
N02
786 SO2
17. 0 803
0. 0334 Total dust
loading
0. 0137 Soluble
solids
Fuel analysis: 86. 9% C,
9.6%H2, 1.4%S, 0.9%
N2, 0.08% Ash
Steam6: 1, 050/1, 000°F
and Z, 500 psig
Fuel analysis: 86. 9% C,
9. 6%H2, 1.4%S, 0.9%
N2, 0.08% Ash
Steam0: 1, 050/1, 000°F
and 2, 500 psig
Fuel analysis: 86. 7% C,
12.2%H2, 0.2%S, 0. 3%
N2) 0.01% Ash
Steam0: 1, 050/1, 000°F
and 2, 500 psig
Fuel analysis: 86. 9% C,
9. 6% H2, 1. 4% S, 0. 9%
N2, 0. 08% Ash
Steamc: 1, 050/1, 000°F
and 2, 500 psig
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
50
(cont'd)
Original
work
Nominal
turbine
load,
mw
75
173
173
173
90
Steam
rate,
1,000
Ib/hr
430
1,150
1,200
1,200
550
Boiler
Firing
rate,
1,000
Ib/hr
37
87
90
90
45
'
Type
of
firing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Volume,
1,000
scfm
141
330
387
287
150.5
Flue g
Temp,
OF
200
300
300
300
280
as
Orsat (%)
CO, C02, 02
11.7 COo
5.902
82. 4 N2
12. 3 COg
4.002
83. 7 N2
14. 1 C02
3.102
82. 8 N2
14. 2 CO2
3.1 O2
82. 7 N2
12. 1 CO2
4.4 O2
83. 5 N2
Emissions
Particulates and gases
gr/scf: ppm:
315 NOV as
N02
332 NOX as
N02
128 SO2
7.5S03
0. 0159 Total dust
loading
524 NOX as
N02
725 SOg
12. 5 SO3
370 NOx as
N02
733 SOa
11. 2 SO3
441 NOx as
N02
639 S02
10. 8 SO3
Notes and miscellaneous
Fuel analysis: 86. 9% C,
9. 6% H2, 1. 4% S, 0. 9%
N2, 0. 08% Ash
Steamc: 1, 050/1, 000°F
and 2, 000 psig
Fuel analysis: 87. 42% C,
12. 58% H2, 0. 38% S,
0.32%N2, 0.04% Ash
Steam0: 1, 000/1, 000°F
amd 2, 000 psig
Fuel analysis: 87. 53% C,
9.77%H2, 1. 57% S,
1. 17% H2, 0.14% Ash
Steamc: 1, 000/1, 000°F
and 2, 000 psig
Fuel analysis: 87. 53% C,
9.77%H2) 1.57%S,
1. 17% N2, 0.14% Ash
Steamc: 1, 000/1, 000°F
and 2, 000 psig
Fuel analysis: 87. 53% C,
9.77%H2) 1. 57% S,
1. 17% N2, 0.14% Ash
Steamc: 1, 000/1, 000°F
and 2, 000 psig
-------
90
175
175
132
132
173
530
1,200
1,200
950
950
1,150
46
89
89
66
65
87
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Horizontal
mechanical
atomizing
Tangential
mechanical
atomizing
Tangential
mechanical
atomizing
Horizontal
mechanical
atomizing
155
268
289
216
206
322
280
300
300
270
270
300
12. 7 CO2
4.7 O2
82. 6 N2
13. 8 CO2
3.502
82. 7 N2
13. 8 CO2
3.402
82. 8 N2
10. 8 CO2
6. 8 O2
82. 4 N2
11. 1 CO2
6.6 O2
82. 3 N2
12. 6 C02
4.0 O2
83. 4 N2
328 NO* as
NO2
651 SO2
7. 4SO3
561 NOx as
NO2
701 SO2
4. 6 S03
301 NOX as
N02
685 SO2
2. 8 SO3
357 NOx as
NO2
279 NOx as
NO2
431 NOx as
N02
216 S02
6. 2 803
0. 0194 Total dust
loading
0. 0107 Soluble
solids
Fuel analysis: 87. 53% C,
9.77%H2, 1.57%S,
1. 17% N2, 0. 14% Ash
Steamc: 1, 000/1, 000° F
and 2, 000 psig
Fuel analysis: 87. 53% C,
9.77%H2, 1.57%S,
1. 17% H2, 0. 14% Ash
Steamc: 1, 000/1, 000°F
and 2, 000 psig
Fuel analysis: 87. 53% C,
9.77%H2, 1.57%S,
1. 17% N2, 0. 14% Ash
SteamC: 1, 000/1, 000°F
and 2, 000 psig
Fuel analysis: 87. 15% C,
9. 78% H2, 1. 35% S,
1. 25% N2, 0. 07% Ash
SteamC: 1, 000/1, 000°F
and 1,950 psig
Fuel analysis: 87. 15% C,
9. 78% H2, 1. 35% S,
1. 25% N2, 0. 07% Ash
SteamC; 1, 000/1, 000°F
1,950 psig
Fuel analysis: 87. 03% C,
11.84%H2, 0. 47% S,
0.48%N2,.0. 039% Ash
Steam0: 1, 000/1, 000°F
and 2, 000 psig
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
50
(cont'd)
59
63
Original
work
General
Yes
Nominal
turbine
load,
mw
173
175
--
Steam
rate,
1,000
Ib/hr
1,150
..
--
Boiler
Firing
rate,
1,000
Ib/hr
85
167
Type
of
firing
Horizontal
mechanical
atomizing
_.
Volume,
1,000
scfm
306
600
Flue g
Temp,
OF ,
300
._
as
Orsat (%)
CO, COa, 02
12. 7 COa
3. 8 O2
83. 5 N2
Emissions
Farticulates and gases
gr/scf: ppm:
393 NQx as
N02
269 SO2
7.1 80s
11 Ib NQx/1,000 Ib oil
1,000 ppm SOg (approx-
imate)
0.5 Ib dust/ 1,000 Ib oil
30 Ibs SO2/l,0001boil
Without additives,
S°3, ppm: % sulfur
in oil:
2 1.5
13 1.5
17 1.5
22 2.2
23 2.2
33 2.2
35 2.2
18 2.4
20 2.4
Notes and miscellaneous
Fuel analysis: 86. 78% C,
11. 99% H2, 0. 68% S,
0. 59% N2, 0. 028% Ash
Steam": 1. 000/1, 000°F
and 2, 000 psig
Residual oil with 1. 5%
sulfur in oil
Data were read from a
graph
-------
64
No.
Reports
other
work
Actual
steam
rate:
20.3
30.7
30.0
29.5
30.1
30.1
--
--
~~
..
--
--
--
--
--
% COa: % 02:
7. 0 13. 2
8.4
11.4 5.2
10.7
10.6
10.6
21 3.1
31 3.1
20 3.2
15 3.3
17 3.3
18 3.3
14 3.5
With additives,
803, ppm: % sulfur
in oil:
3 3.2
2 3.2
3 3.4
6 3.4
5 3.7
8 3.8
3 3.8
2 3.8
SOa, ppm: SO3, ppm:
1, 530 23. 8
1, 530 23. 8
1, 430 17
1, 430 20
1, 360 17
1, 120 18
1, 120 17
7&0 21.5
680 18
710 12
595 10. 5
Normal steam
rate, 1000
Ib/hr: Plant:
20 A
30 B
30 C
30 D
30 E
30 F
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
64
(cont'd)
Original
work
No;
reports
other
work
Nominal
turbine
load,
mw
Steam
rate,
1,000
Ib/hr
Actual
steam
rate:
31.8
37.6
40.6
50.6
20.2
30.5
30.3
30.7
31.3
31.0
30.7
Boiler
Firing
rate,
1,000
Ib/hr
._
--
..
__
Type
of
firing
--
.._
Volume,
1,000
scfm
__
--
__
__
Flue g
Temp,
op
__
as
Orsat (%)
CO, C02, 02
, 12.8 3.4
10.8
i 14. 0 4. 6
13.7
8.0 9.8
8.8 8.0
11.0
11.1 5.0
10. 6 6. 5
11.2
12. 8 4. 3
Emissions
Particulates and gases
SO2, ppm: 803, ppm:
1, 600 16
1, 310 19
1, 450 23. 5
1,110 26.5
21.5
1, 400 20
750 22. 5
750 24
950 20. 5
1, 100 19
1, 200 13
1, 200 18. 5
1, 080 10
800 8
900 9
320 10. 7
440 10. 7
940 12
940 12
Notes and miscellaneous
Normal steam
rate, 1000
Ib/hr: Plant:
30 G
40 H
40 I
Maximum J
Fuel analysis: 2. 6% S,
0. 08% Ash, 85% C,
11.17%H2, 0.39%N2,
14. 3° API
Marine fuel oil from
asphaltic crude
20 A
30 B
30 C
30 D
30 E
30 F
30 G
-------
39.3
39.7
50.5
21.0
30.0
30.7
30.5
30.9
38.9
39.9
49.3
--
..
--
--
..
-_
10. 8 6. 0
13.5 --
13.3 --
7.6 10.6
8. 6 8. 8
10. 8 6. 4
11.5 5.6
12. 8 4. 4
11.0 5.8
14. 0 2. 2
13. 5 2. 1
1, 340 16. 5
1,150 11.5
1, 150 14
1,350 24.5
1, 260 22
1,260 25
1, 400 24
1^ 120 10
1,110 12
1,330 11
1, 150 10. 5
1L150 7.3
1, 030 5. 5
1,038 7.5
1,310 13
lj 090 14
1,030 8.5
^200 8.5
1,070 9
40 H
40 I
Maximum J
Fuel analysis: 22. 1° API
85. 6% C, 11.92%H2,
2. 00% S, 0.22%N2,
0. 03% Ash
Low viscosity fuel oil
from asghaltic crude
20 A
30 B
30 C
30 D
30 G
40 H
40 I
Maximum J
Fuel analysis: 21° API
86.3% C, 11.92% H2,
2. 10% S, 0.23%N2,
0. 03% Ash
Medium viscosity fuel
from mixed base crude
-------
APPENDIX A. DETAILED DATA ON LARGE SOURCE EMISSIONS (continued)
Refer-
ence
64
(cont'd)
Original
work
Nominal
turbine
load,
mw
Steam
rate,
1,000
Ib/hr
Actual
steam
rate:
19.5
30.5
30.4
30.8
31.1
31.0
31.0
41.3
41.9
48.3
Boiler
Firing
rate,
1,000
Ib/hr
._
__
__
Type
of
firing
_.
..
Volume,
1,000
scfm
__
..
_.
Flue g
Temp,
op
..
..
__
18
Orsat (%)
CO, C02, 02
% COa: % 02:
7.9 --
8.7
10. 6 6. 3
P 10. 8 4. 8
11.3 5.1
10. 5
13.0 2.7
11.2 5.5
13.0 3.3
13.6
Emissions
Particulates and gases
SO2, ppm: 303, ppm:
1, 220 14
1^370 23
1, 240 16. 5
lj 240 18
1, 580 16
1, 470 12. 5
"^ 330 14. 5
1, 170 10. 5
1, 060 15
230 5.5
230 7
1,110 7.5
1, 290 9
1, 500 10. 5
lj 500 12
1, 570 7. 5
12 570 8. 5
1, 590 12. 5
1, 590 9
Notes and miscellaneous
Normal steam
rate, 1000
Ib/hr: Plant:
20 A
30 B
30 C
30 D
30 E
30 F
30 G
40 H
40 I
Maximum J
-------
65
66
67a
No,
general
General
Yes
__
__
..
__
--
--
13. 5 Ib NOX/1,000 Iboil
or
17 IbKOx/ 1,000 Iboil
or
10 Ib NOx/1,000 Ib oil
30 Ib SO2/1.000 Ib oil
13. 5 Ib NOX as NO2/
1, 000 Ib oil
2. 5 Ib solids/1,000 Ib
oil
SO2, SO3, Theoretical
ppm: ppm: sulfur:
1, 140 33 1, 260
1, 280 23 1, 260
1, 230 32 1, 260
1,930 20 1,900
1, 890 19 1, 900
870 20 860
890 14 860
890 17 860
Fuel analysis: 85. 20% C,
11. 6%H2, 3.55%S,
0. 15% N2, 0.02% Ash
Heavy fuel oil from mixec
base crude of higher
sulfur content
Author reports that these
values have been estab-
lished for fuel oil
Fuel analysis: 1. 5%
sulfur
Test
1
1
1
2
2
3
3
3
a 12% CO2 correction not known.
b No data.
c Super heat temperature/reheat temperature.
d Data read from a graph and corrected from 3% O2 to 12% CO2.
-------
APPENDIX B. DETAILED DATA ON SMALL SOURCE EMISSIONS
Refer-
ence
21
46
51
52
Original
work
Yes
Yes
Yes
(519
tests),
general
Yes
Nominal
turbine
load,
mw
f
"
Steam
rate
150 hp
or
5,160
Ib/hr
steam
500 hp
or
less
380, 000
Btu/hr
Boiler
Firing
rate,
Ib/hr
--
"
Type
of
firing
Steam
atomizing
"
Volume,
scfm
"
Flue g
Temp,
OF
--
"
550
620
as
Orsat (%)
CO, C02, 02
"
%COa: %CO:
12.4 1.16
11.5 0.156
Emissions
Participates and gases
lb/1,000 Ib
oil fired:
NOX as NO2 7. 2
SO2 21. 2
CO nil
Aerosol 1. 7
Hydrocarbons 0. 080
Aldehydes and
ketones 0. 063
Other organics 0. 177
0. 06 gr/scf dust
0. 49 Ib, NOx/106 Btu
or
9 Ib NOx/1,000 Ib oila
%H2:
0.58
0.104
Notes and miscellaneous
Domestic and commercial
sources
Horizontal return tube
boiler, PS400 oil
"
Thermal Shell
efficiency, %: smoke no:
65.5 9
70 6
-------
68
b
c
d
e
Yes
2,070
Ib/hr
3,450
Ib/hr
4,140
Ib/hr
65.2
44.7
288
Pressure
atomizing
Pressure
atomizing
Steam
atomizing
368
480
1,700
620
680
700
250
290
710
10.8 0.011
9. 5 0. 025
8. 3 0. 725
0. 01 CO
7.0 CO2
7.902
0. 000 CO
3. 9 CO2
15.702
0. 003 CO
7.0 CO2
7.802
0.011
0.025
0.217
lb/1,000 gases In ppm,
Ib oil: particles in gr/scf:
21. 5 355 SO2
0. 123 1. 6 SO3
0. 261 9 Aldehydes
1. 98 47 NQx as N02,
2. 15 0. 065 Particles
11.4 98.2 SOj
0. 206 1. 4 $03
0. 292 5 Aldehydes
2. 92 35. 8 NOx as NOj
2. 24 0. 067 Particles
26. 13 414 SOg
0. 348 4. 7 SOa
0. 173 7 Aldehydes
16. 7 368 NOx as NO2
2. 29 0. 070 Particles
69 3
66 1
63 0
Domestic fuel
Fuel analysis: PS 200,
31. 07° API, 1.05%S,
0. 02% Ash
Excess air, 65%
Moisture in stack gas-,
9. 8% vol
Oil temp, 700F
Steam, 70 psig
Cyclotherm steam gener-
ator boiler, fire tube,
60 hp
Fuel analysis: PS 200,
28. 71° API, 0. 71% S,
0%Ash
Excess air, 290%
Moisture in stack gas,
4. 7% vol
Oil temp, 70°F
Brayan No. 315 -- 100 h|
water tube (hot water)
Fuel analysis: PS 300,
16. 51° API, 1. 0% S,
0% Ash
Excess air, 68%
Moisture in stack gas,
12. 7% vol
Oil temp, 160°F
Steam, 100 psig
Locomotive type boiler
120 hp, single pass
fire tube
-------
APPENDIX B. DETAILED DATA ON SMALL SOURCE EMISSIONS (continued)
Refer-
ence
68
(cont'd)
Original
work
Nominal
turbine
load,
mw
Steam
rate
4,310
Ib/hr
5,170
Ib/hr
6,900
Ib/hr
Boiler
Firing
rate,
Ib/hr
190.5
105
150
Type
of
firing
Pressure
atomizing
Centrifugal
atomizing
Centrifugal
atomizing
Volume,
scfm
1,700
1,600
1,890
Flue g
Temp,
OF
330
240
360
as
Orsat (%)
CO, C02, 02
0. 000 CO
5. 0 CO2
13. 3 O2
0. 001 CO
2.7 C02
16. 2 O2
0. 02 CO
4.3 CO2
13.802
Emissions
Particulates and gases
lb/1,000 gases In ppm,
Ib oil: particles In gr/scf:
26.2 2«4 SO*
0.399 3.2 SOa
0. 420 9 Aldehydes
8.82 128 NOxasNOz
3. 58 0. 104 Particles
4. 57 28 802
0. 343 1. 7 SOa
0. 380 5 Aldehydes
2. 38 20 NO, as NO*
1. 14 0. 036 Particles
15.3 11.2 S02
0.0004 5.6 803
3. 33 52 Aldehydes
2. 07 21 NOx as NOa
5. 67 0. 132 Particles
Notes and miscellaneous
Fuel analysis: PS 300,
11. 39° API, 1.78%S,
0. 18% Ash
Excess air, 180%
Moisture in stack gas,
4. 8% vol
Oil temp, 70°F
Steam, 90 psig
Pioneer boiler 125 hp,
Scotch Marine
Fuel analysis: 40. 10° API
0.09%S, 0%Ash
Excess air, 150%
Moisture in stack gas,
4. 4% vol
Oil temp, 70°F
Steam, 10 psig
Diesel fuel, Gabrial
boiler 150 hp, Scotch
Marine
Fuel analysis: 33. 82<> API
0.97%S, 0%Ash
Excess air, 210%
Moisture in stack gas,
5. 6% vol
Oil temp, 70°F
Steam, 90 psig
Diesel fuel, Johnson
boiler No. 18 200 hp,
Scotch Marine
-------
6,900
Ib/hr
8,450
Ib/hr
10, 350
Ib/hr
68.5
820
165
Pressure
atomizing
MCL 7-23
Centrifugal
1,200
4,070
1,230
370
540
390
0. 002 CO
2.8 CO2
16.3 03
0. 00 CO
7. 9 COg
6.002
0. 0024 CO
5.5 CO2
10.9 O2
0. 039 0. 2 SO?
0 0 803
0. 586 8 Aldehydes
7. 45 54. 9 NO* as NO2
3.80 0.0945 Particles
21. 1 397 SO2
0.0244 0.37 303
0. 244 8 Aldehydes
14. 75 387 NOX as NOj
1.89 0.0605 Particles
8. 20 102 SO2
0.0485 0.5 SOs
0. 242 7 Aldehydes
1. 88 32. 8 NOX as NO2
1.33 0.0388 Particles
Fuel analysis: 35. 09° API
0. 55% S, 0%Ash
Excess air, 370%
Moisture in stack gas,
3. 0% vol
Oil temp, 70°F
Steam, 120 psig
Diesel fuel, B&W boiler,
model FM-27 -- 200 hp,
water tube
Fuel analysis: PS 400,
11. 10° API, 0.94%S,
0. 13% Ash
Excess air, 43%
Moisture in stack gas,
10. 7% vol
Oil temp, 205°F
Steam, 120 psig
Erie City boiler, model
46-14 245 hp water
tube, 3 drum
Fuel analysis: PS 200,
33. 01° API, 0. 21% S,
0. 07% Ash
Excess air, 115%
Moisture in stack gas,
6. 9% vol
Oil temp, 70°F
Steam, 600 psig
B&W boiler type FM-1
-- 300 hp, water tube
-------
APPENDIX B. DETAILED DATA ON SMALL SOURCE EMISSIONS (continued)
Refer-
ence
68
(cont'd)
Original
work
Nominal
turbine
load,
mw
Steam
rate
10, 350
Ib/hr
12,750
Ib/hr
14, 700
Ib/hr
Boiler
Firing
rate,
Ib/hr
280
612
1,350
Type
of
firing
Steam
atomizing
Centrifugal
atomizing
Steam
atomizing
Volume,
scfm
2,930
3,970
10, 000
Flueg
Temp,
op
320
500
630
as
Orsat (%)
CO, CO2, O2
0.0 CO
4. 0 CO2
13. 9 O2
0. 000 CO
6.3 CO2
9.8 O2
0. 001 CO
6. 3 COa
10.3 O2
Emissions
Particulates and gases
lb/ 1,000 gases in ppm,
particles in gr/scf:
8. 00 7. 1 S02
0 0. 0 SOj
0. 285 6 Aldehydes
1. 18 14. 7 NOx as NOj
4. 47 0. 134 Particles
11.75 17 SO2
0 0 SOs
0. 098 3 Aldehydes
3. 60 72 NOx as NOj
0.425 0.0132 Particles
55. 6 700 SOj
0. 89 6. 7 SOs
0. 148 4 Aldehydes
14.7 274.9 NOx as NO;
9. 94 0. 265 Particles
Notes and miscellaneous
Fuel analysis: PS 200,
34. 87° API, 0. 29% S,
0. 01% Ash
Excess air, 220%
Moisture in stack gas
6. 3% vol
Oil temp, 60°F
Steam, 100 psig
Kewanee boiler, model
590 300 hp, 2 pass
fire tube
Fuel analysis: PS 200,
32. 9° API, 0. 42% S,
0% Ash
Excess air, 94%
Moisture in stack gas,
8. 2% vol
Oil temp, 70°F
Steam, 150 psig
Dixon wet back boiler
350 hp, Scotch Marine
Fuel analysis: PS 400,
8. 0° API, 3. 06% S,
0% Ash
Excess air, 110%
Moisture in stack gas,
10. 6% vol
Oil temp, 210°F
Steam, 160 psig
Collins boiler 425 hp,
water tube
-------
15,750
lb/hr
17, 250
lb/hr
20, 000
lb/hr
660
1,975
467
Pressure
atomizing
Steam
atomizing
Steam
atomizing
4,560
12, 400
3,030
220
560
580
0.0 CO
5. 9 C02
10.7 O2
0. 000 CO
6. 7 CO2
9.502
0.0 CO
6. 4 COa
9. 602
26. 7 362 SO2
0. 197 2. 2 S03
0. 303 7 Aldehydes
10. 5 199 NOx as NO2
1.20 0.0366 Particles
40. 0 594 SOg
0. 304 3. 6 SOs
0. S06 17 Aldehydes
12. 4 256 .NOx as NOj
1.42 0.0420 Particles
45. 0 640 S02
0. 195 2. 2 SO3
0. 257 8. 5 Aldehydes
9. 22 205. 9 NOx as NO2
1. 86 0. 057 Particles
Fuel analysis: PS 300,
12. 11° API, 0.78% S,
0. 12% Ash
Excess air, 107%
Moisture in stack gas,
6. 6% vol
Oil temp, 190° F
Steam, 275 psig
Springfield boiler -- 460
hp, water tube
Fuel analysis: PS 300,
15.09° API, 1.39%S,
0. 04% Ash
Excess air, 92%
Moisture in stack gas,
9. 1% vol
Oil temp, 160°F
Steam, 145 psig
Sterling boiler, model
477-31 (modified) --
500 hp, water tube
4 drum
Fuel analysis: PS 300,
13. 33° API, 1. 30% S,
0. 03% Ash
Excess air, 95%
Moisture in stack gas,
9. 8% vol
Oil temp, 160°F
Steam, 15 psig
Collins boiler -- 580 hp,
water tube
-------
APPENDIX B. DETAILED DATA ON SMALL SOURCE EMISSIONS (continued)
Refer-
ence
68
(cont'd)
69
Original
work
Yes
Nominal
turbine
load,
mw
__
Steam
rate
30, 000
Ib/hr
__
4,800
Ib/hr
Boiler
Firing
rate,
Ib/hr
1,372
37.1
_
Type
of
firing
Steam
atomizing
Pressure
atomizing
Pressure
atomizing
Volume,
scfm
7,400
274
_
Flue g
Temp,
OF
530
__
__
18
Orsat (%)
CO, C02, 02
0. 000 CO
8. 2 CO2
8.5 O2
0. 002 CO
5. 4 CO2
11. 1 O2
OCO
9.7C02
8.0 O2
0 CO
12. 4 C02
4. 502
Emissions
Particulates and gases
lb/1,000 gases in ppm,
Ib oil: particles in gr/scf:
19. 8 344 SO2
D. 875 1. 2 SCh
1.31 48 Aldehydes
10. 65 256 NO,, as NO,
3. 21 0. 091 Particles
11. 05 138 SO2
0. 081 2. 8 SOj
0. 405 11 Aldehydes
1. 75 33. 7 NO* as NO2
2. 18 0. 089 Particles
gr/scf particles:
0. 0615
0. 0775
Notes and miscellaneous
Fuel analysis: PS 400,
9. 30° API, 1.94%S,
0. 03% Ash
Excess air, 73%
Moisture in stack gas,
7. 9% vol
Oil temp, 220°F
Steam, 275 psig
B & W boiler, model FM
-9 870 hp, water
tube
Fuel analysis: PS 200,
33. 6° API, 0. 80% S.
0% Ash
Excess air, 120%
Moisture in stack gas,
7. 8% vol
Oil temp, 70°F
Childers oil heater,
model D-100, oil cir-
culating heat exchanger
Excess Shell
air: smoke no:
59% 3
26% 4
-------
oco
13. 4 CO2
2.702
1.0 CO
14. 2 CO2
1.302
0. 0945
0.2175
General value for
particulates, 0.06
gr/scf
12% 5
3% 7
Normal steam rate,
8, 000 Ib/hr
Double furnace
Fuel analysis: PS 400,
15.9° API, 3. 5%S,
0.05% Ash 18, 700 Btu
a Calculated using a 18,300 Btu/lb oil.
b 12% C<>2 correction is not known.
c Steam rate was calculated from the horsepower.
d Orsat analysis is on a wet basis.
e Aldehydes are calculated as formaldehydes.
f Dashes (--) indicate "no data". -
Note: Also see references 38 and 44 in Large Sources (Appendix A)
-------
94
ATMOSPHERIC EMISSIONS
APPENDIX C. METHOD OF REPORTING THE DATA
Emission data for this report fit into three categories: (1)
individual test values, (2) typical or general values, or (3) ranges
of emissions. For example, if the data for a given pollutant were
as follows (values in ppm):
Individual
values
1C
21
22
28
30
31
32
37
Hypothetical
references
1
2
3
4
5
6
7
8
Typical
values
29
33a
34
39
Hypothetical
references
10
11
12
13
Ranges
20-50
5-45
20-40
Hypothetical
references
14
15
16
Represents 200 samples.
The histogram presenting these data would be constructed as
shown in the following figure:
10
AMPLES
j\
in
ti.
O
1
F
L../I /£ ^
0 10 2
3
2
*
0
4
X
2
/ ,
/"
3
7
6
5
^5
^
5
///
"
D
1 1 1 1 1 1
D Individual test
values reported
JS^I Typical values
8 P° C
W K§] Represents 200
^"
/'^ _4 */^ Ranees reported
/^.»,Xryfl 1 l 1 1 1
r j^1 y*i 1 I 1 1 1
40 50 60 70 80 90 100
POLLUTANT CONCENTRATION, ppm
-------
FPOM FUEL OIL COMBUSTION 95
"Ranges" reported were plotted first. The range 20 to 50
from hypothetical reference 14 occupies a row extending from 20
to 50. The range 5 to 45 from hypothetical reference 15 was
then plotted in two rows extending from 5 to 45. The range 20 to
40 from reference 16 was plotted in a third row. Next, "typical
values" we-re plotted in squares appropriate to their magnitude.
The value 29 from hypothetical reference 10 is shown as a square
extending from 25 to 30. The value 34 from hypothetical reference
12 is shown as a square extending from 30 to 35 and the value 39
from hypothetical reference 13 as a square extending from 35 to
40. The typical value of 33 from hypothetical reference 11 was
given a special notation because it is based on 200 samples.
"Individual" values from references 1 through 8 were then
plotted in a fashion similar to the typical values. For this
histogram, the extreme range would be 5 to 50 ppm, the most
common range 20 to 40 ppm, and the most common values
between 30 and 35 ppm. The emission value would be chosen as
32. 5 or 33 ppm. In this histogram the hypothetical references
are represented inside each square for better understanding of
this method of representation. In the text, however, the
references are not represented, for the sake of simplicity.
* U. S. GOVERNMENT PRINTING OFFICE : 1968 O - 308-057
------- |