REPORT ON REVISIONS TO
5TH EDITION AP-42
Section 1.3
Fuel Oil Combustion
Prepared for:
Contract No. EPA 68-D7-0068, WA-005
EPA Work Assignment Officer: Roy Huntley
Office of Air Quality Planning and Standards
Office of Air And Radiation
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Prepared by:
Eastern Research Group
Post Office Box 2010
Morrisville, North Carolina 27560
September 1998
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Table of Contents
Page
1.0 INTRODUCTION 1-1
2.0 REVISIONS 2-1
2.1 General Text Changes 2-1
2.2 Sulfur Oxides, SOX 2-1
2.3 Sulfur Trioxide, SO3 2-1
2.4 Nitrogen Oxides, Nox 2-1
2.4.1 Mid-Sized Fuel Oil Fired Boilers 2-2
2.4.2 Utility Boilers 2-4
2.5 Carbon Monoxide, CO 2-6
2.6 Filterable Particulate Matter, PM 2-6
2.7 Condensable Particulate Matter, CPM 2-8
2.7.1 Description of Documents Evaluated 2-8
2.7.2 Emission Factor Development 2-9
2.8 Total Organic Compounds (TOC) and Non-Methane TOC (NMTOC) 2-12
2.9 Particle Size Distribution 2-12
2.10 Polycyclic Organic Matter (POM) and Formaldehyde (HCOH) 2-12
2.11 Trace Elements 2-12
2.12 Greenhouse Gases 2-14
2.12.1 Carbon Dioxide, CO2 2-14
2.12.2 Methane 2-16
2.12.3 Nitrous Oxide, N2O 2-16
2.13 Speciated Organic Compounds 2-18
3.0 REFERENCES 3-1
4.0 REVISED SECTION 1.3 4-1
5.0 EMISSION FACTOR DOCUMENTATION, APRIL 1993 5-1
APPENDIX A SUPPORTING DOCUMENTATION
A Supporting Data for Supplements E
B. 1 Data Used for Average Emission Factors Development in Supplements
A and B
B.2 Source Test Report Summary Data for Supplements A and B
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1.0 INTRODUCTION
This report supplements the Emission Factor (EMF) Documentation for AP-42
Section 1.3, Fuel Oil Combustion, dated April, 1993. The EMF provides technical
documentation for updates to Section 1.3 that have been made through the 4th Edition of AP-42.
This report provides documentation for the most recent updates to the 5th edition of
AP-42 contained in Supplements A (February, 1996), B (October, 1996), and E
(September, 1998). The 5th edition of AP-42 and its supplements have greatly expanded
information concerning toxics, revised emission factors for nitrogen oxides (NOX), and added
information and emission factors for condensable particulate matter.
For Supplements A, B, and E to the 5th Edition, Section 1.3 of AP-42 was reviewed by
internal peer reviewers to identify technical inadequacies and areas where state-of-the-art
technological advances need to be incorporated. Based on these review, tables and text have
been updated or modified to address any technical inadequacies or provide clarification.
For Supplements A and B to the 5th Edition, emission factors in AP-42 were checked for
accuracy with information in the EMF Document and recent test data. New emission factors
were generated if recent test data the available test data indicated that new factors were needed.
If discrepancies were found when checking the factors, the appropriate reference materials were
then checked.
For Supplement E to the 5th Edition, emission factors for condensable particulate matter
were included. Changes were made to the text and in table headings as applicable to identify
data as either filterable or condensable particulate matter. Emission factors for nitrogen oxides
(NOX) were updated. To accommodate the NOX update, new categories are used to describe
boilers. Boiler categories were originally based on the ownership of the unit: utility, industrial
and commercial/ institutional. Evaluation of boiler data indicated that emissions from boilers are
most affected by design. Boilers with capacities less than 100 million Btu per hour are "shop
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fabricated" or "packaged" and exhibit different NOX emissions than boilers with capacities
greater than 100 million Btu per hour which are generally "field erected" boilers. Based on a
1996 EPA report, text and emission factors were added pertaining to Number 6 oil/water
emulsion mix. Emission factors for trace metals in distillate oil were updated using more current
data.
Four sections follow this introduction. Section 2 of this report documents revisions made
in Supplements A, B, and E to the 5th edition of Section 1.3 of AP-42 and the basis for the
changes. Section 3 presents the references for the changes documented in this report. Sections
4 and 5 present the web page addresses of the revised AP-42 Section 1.3 and the EMF
documentation dated April, 1993, respectively.
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2.0 REVISIONS
2.1 General Text Changes
Supplements A and B
Information in the EMF Document was used to enhance text concerning fuel oil firing
practices. Also, at the request of EPA, the metric units were removed.
Supplement E
Text was updated to describe condensate particulate matter. Additional text changes
were minimal and served to identify specific changes in emission factors.
2.2 Sulfur Oxides. S(X
Supplements A and B
The uncontrolled SOX factors were checked against information in Table 4-3 of the EMF
Document and the 10/86 version of Section 1.3 and no changes were required.
2.3 Sulfur Trioxide. SO.
Supplements A and B
The SO3 factors were checked against information in Table 4-4 of the EMF Document
and the 10/86 version of Section 1.3 and no changes were required.
2.4 Nitrogen Oxides. MX
Supplements A and B
The uncontrolled NOX factors were checked against information in Table 4-6 of the EMF
Document and the 10/86 version of Section 1.3 and no changes were required.
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2.4.1 Mid-Sized Fuel Oil Fired Boilers
Supplement E
Based on new NOX data collected, revised emission factors are presented for oil fired
boilers (>100 MMBtu/hr) equipped with Low NOX burners and flue gas recirculation.
All of the data used in this analysis originated from four sources; 1) a search of the
STIRS and STIRS II databases, 2) data compiled by EPA for use in regulatory development
activities, 3) data found in the 1990 Ozone Transport Commission (OTC) baseline NOX
emissions inventory, and 4) data reported to the EPA as part of the acid rain program. In
addition, test data collected in 1993 to update the current AP-42 emission factors have been
considered in this analysis where appropriate.
In order to provide a complete data set for use in updating AP-42, additional information
was needed to supplement the raw data contained in the individual test reports. In most cases,
this information was obtained by contacting the appropriate regulatory agency, from the source
itself, or from Energy Information Administration (EIA) publications. In particular, the
following information was sought for inclusion prior to analysis of the data:
Oil Type (No. 2 and No. 6)
• Boiler Firing Configuration; and
• Boiler size and age.
In order to convert the supplied emission factors (in most cases Ib/MMBtu) to units
consistent with those already found in AP-42 (Ib/ton for coal and lb/103 gallons for oil), the
following fuel heat contents, taken from Appendix A of AP-42, were used:
No. 6 Oil = (150,000 Btu/gal); and
No. 2 Oil = (140,000 Btu/gal).
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Once the boiler data were entered into a spreadsheet, each individual "record" (consisting
of the NOX emission rate, fuel type, and boiler firing type) was assigned (or sorted) to a unique
boiler grouping based on the following set of parameters:
• Firing Type (i.e.,. wall fired, tangentially fired);
• Control Status; and
Fuel Type (No. 2 and No. 6 Fuel Oil).
A summary of the results for each fuel type and firing configuration follows.
No. 2 Fuel Oil - For boilers over 100 (MMBtu/HR), the only change is the addition of a
NOX emission factor for No. 2 fired boilers equipped with Low-NOx burners and FOR. Two data
points were found with an average emission factor of 10 (lb/103 gallons).21'22 This compares to
the previously developed emission factor of 24 (lb/103 gallons) for No. 2 fired boilers (over
100 MMBtu/HR) with no control equipment.
For boilers under 100 (MMBtu/HR), there are no changes to the current emission factors.
Two additional data points were obtained which had an average emission factor of 13 (lb/103
gallons). However, the current AP-42 emission factor of 20 (lb/103 gallons) was obtained from
19 individual data points and is considered more appropriate.
No. 6 Fuel Oil - Three new data points were obtained for No. 6 oil fired boilers under
100 (MMBtu/HR). The average of these three data points is 58 (lb/103 gallons), which compares
favorably with the current factor of 55 (lb/103 gallons), which is based on 28 data points.
Therefore, there is no update to the emission factor for No. 6 fired boilers rated less than
100 (MMBtu/HR).
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Table 1 provides a summary of the AP-42 source category classifications and emission
factors for oil. Note that the only new emission factor in this table is for No. 2 Oil fired boilers
equipped with Low-NOx burners and FGR.
Table 1. AP-42 Revisions For Oil NOX Emission Factors
(9/98 Supplement E)
FUEL OIL BOILERS > 100 MMBTU/HR
Current AP-42
Classification
None
Current EFa
Proposed New AP-42
Classification
No. 2 oil fired, LNB/FGR
Proposed New EFa
10
Number of
Records
2
FUEL OIL - BOILERS < 100 MMBTU/HR
Current AP-42
Classification
No. 6 oil fired
Distillate oil fired
Current EFa
55
20
Proposed New AP-42
Classification
Unchanged
Unchanged
Proposed New EFa
Unchanged
Unchanged
Number of
Records
1 (lb/103 gal)
The summary and raw data used to develop the oil emission factors is also presented in
the file ICRAW.XLW (presented in Appendix A). This includes the individual records for the
No. 2 and No. 6 oil-fired boilers which were obtained for this analysis, but, as documented
above, were not used to propose new emission factors.
2.4.2 Utility Boilers
Supplement E
All of the data used in this analysis originated from EPA's Acid Rain office and is based
on third quarter 1996 continuous emissions monitoring (CEM) data collected from utility boilers
located across the country and reported to EPA. Since the acid Rain data is based on Utility
boilers, the results of this analysis applies only to larger boilers (>100 MMBtu/HR) only.
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The data provided to ERG for analysis had been quality assured internally at EPA prior
to release for use in this study.
In order to provide a complete data set for use in updating AP-42, additional information
was needed to supplement the raw data set supplied by the Acid Rain office. In particular, the
oil type and year of initial operation were obtained from other sources and included prior to
analysis of the data.
In addition, in order to convert the supplied emission factors (Ib/MMBtu) to units
consistent with those already found in AP-42 (Ib/ton for coal and lb/103 gal for oil), the
following fuel heat contents, taken from Appendix A of AP-42, were used:
No. 6 Oil = (150,000 Btu/gal)
No. 2 Oil = (140,000 Btu/gal)
Once the data set was considered complete and ready for analysis, each individual
"record" (consisting of the quarterly averaged emission rate for a single boiler unit in terms of Ib
of NOx/MMBtu) was assigned to a specific boiler grouping based on the following set of boiler
parameters:
• Firing Type (i.e., wall fired, tangentially fired);
NSPS applicability (pre-NSPS, Subpart D, Subpart Da); and
Fuel Type (No. 6 Oil, No. 2 Oil).
In addition to these parameters, boilers retrofitted with Low-NOx burners were addressed
separately. For a given boiler group the mean NOX emission factor and sample standard
deviation were calculated. The statistical values for each individual boiler grouping can be
found in the Excel file "OILRAW.XLS." A printout of this file is presented in Appendix A.
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In general, overall trends were observed which led to the final groupings. In some
instances, there were specific data recorded that could have fit into one or more groupings, but
an attempt was made to be consistent across the board with the final groupings.
For oil-fired boilers, NSPS applicability was not observed to have an impact on
emissions so the resulting proposed AP-42 emission factors are independent of boiler age. The
low-NOx burner emission factors for oil were determined using the average emission rate of
those boilers using low-NOx burners.
Table 2 (found in the file OILSUM.XLS) provides a summary of the current AP-42
source category classifications and emission factors for oil. A printout of this table is presented
in Appendix A. The proposed source classifications and emission factors, along with the number
of data records used to develop each emission factor, are also provided. The summary and raw
data used to develop the oil emission factors is presented in the file OILRAW.XLS.
Table 2. Summary Of AP-42 Revisions for Oil NOX Emission Factors
(9/98 Supplement E)
FUEL OIL - UTILITY BOILERS
Previous AP-42 Classification
No. 6 oil fired, normal firing
No. 6 oil fired, tangential firing
No. 5 oil fired, normal firingb
No. 5 oil fired, tangential firingb
No. 4 oil fired, normal firingb
No. 4 oil fired, tangential firingb
Previous
EP
67
42
67
42
67
42
Proposed AP-42 Classification
No. 6 oil fired, normal firing
No. 6 oil fired, normal firing,
low NOX burner
No. 6 oil fired, tangential firing
No. 6 oil fired, tangential firing,
Low NOx burner
No. 5 oil fired, normal firing
No. 5 oil fired, tangential firing
No. 4 oil fired, normal firing
No. 4 oil fired, tangential firing
No. 2 oil fired
Proposed
Ef
47
40
32
26
47
32
47
32
24
Number of
Records
32
17
33
2
32
33
32
33
3
; (lb/103 gal)
New data obtained for No. 6 Oil only, emission factors applied to No. 5 and No. 4 Oil for normal and tangential frred units.
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The NOX emission factors developed for No. 6 oil have also been applied to the No. 4 and
No. 5 oil.
2.5 Carbon Monoxide. CO
Supplements A and B
The CO factors were checked against information in Table 4-5 of the EMF Document
and the 10/86 version of AP-42 and no changes were required.
2.6 Filterable Particulate Matter. PM
Supplements A and B
Filterable PM emission factors were checked against information in Table 4-2 of the
EMF Documentation and the 10/86 version of AP-42. The only change required was for the PM
emission factors for residential furnaces.1'2 Several new reports were reviewed and two
contained PM emission data for new oil-fired residential furnaces. Based on these reports, it was
determined that newer furnaces (i.e., post-1970) emit significantly less PM than older furnaces
(i.e., pre-1970). The existing PM emission factor for residential furnaces in the 5th Edition of
AP-42 is based solely on pre-1970 data.
Table 3 presents the PM data for newer furnaces. The existing PM factor is 3.0 lb/1000
gal, is rated "A," and is based on 33 pre-1970 data points. The PM emission factor for newer
furnaces is 0.4 lb/1000 gal, is based on 9 post-1970 data points, and is rated "C." The PM
emission factor for new furnaces (0.4 lb/1000 gal) was added and a footnote included to qualify
it as being based on new furnaces designs and pre-1970's burner designs may emit as high as 3.0
lb/1000 gal.
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Table 3. Summary of Particulate Emission Data for New
Residential Oil-Fired Furnaces
Reference/Page
McCrillis, Page 4
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Average
Data
Rating
B
B
B
B
B
B
B
B
B
C
Furnace/Burner type
Thermo-Pride Model: M-SR
R.W. Beckett Co. Model: AF
R.W. Beckett Co. Model: AFG
R.W. Beckett Co. Model: AFG
Riello Corp. Model: Mectron 3M
Energy Kinetics Inc. Model: System 2000
Bentone Electrol Oil Model: Airtronic
Combustion Technology
Foster Miller Carlin Co.
Filterable PM
Emission Factor
0.42
0.38
0.3
0.4
0.65
0.26
0.4
0.38
0.4
2.7. Condensable Particulate Matter. CPM
Supplement E
Condensable particulate matter (CPM) as discussed in this report is defined as
condensable material measured by EPA Method 202 or an equivalent, state-approved method.
Method 202 defines condensable matter as material that condenses after passing through a filter
and as measured by the method.
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2.7.1 Description of Documents Evaluated
Supplement E
Emissions data were obtained from two sources: stack test reports provided to the U.S.
EPA by the New Jersey Department of Environmental Protection (NJDEP); and stack test reports
obtained by EPA on visits to state and local air quality agencies. The NJDEP became aware of
EPA's search for CPM emissions data and provided stack test reports from their files that
contain CPM emissions data.
Additionally, EPA gathered emissions data from permit files of state/local air pollution
agencies in Oregon, Texas, and Wisconsin. The emissions information collected consisted of
stack test reports submitted for compliance purposes. The reports were electronically scanned
into computer files to collect emissions information or information that could be used to
characterize the combustion source, operating conditions, and control devices used. A computer
file was created for each report scanned.
The reports were evaluated to identify those reports that contain CPM emissions data for
fuel oil combustion. Method 202 measures total CPM (CPM-TOT) and also measures the
organic fraction of CPM (CPM-ORG) and the inorganic fraction (CPM-IOR). If the methods
used in the test reports were EPA 202, or an equivalent method, and the data were of sufficient
quality for AP-42, the data were extracted for use in developing emission factors.
The CPM emissions data presented in the NJDEP test reports were measured using a
method equivalent to EPA Method 202 for CPM-TOT. Therefore, all of the NJDEP reports
containing CPM emissions data for fuel oil-fired boilers were used for CPM emission factor
development.
The scanned test reports used for CPM emission factor development are from the states
of Oregon and Wisconsin. None of the reports from Texas were from fuel oil-fired boilers. The
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methods used in Oregon and Wisconsin to measure CPM-TOT are very similar to EPA
Method 202 and test report data from these states were used for emission factor development
2.7.2 Emission Factor Development
Supplement E
The emissions data for CPM-IOR, CPM-ORG, and CPM-TOT plus information that
could be used to characterize the emission source were extracted to spreadsheets for emission
factor development. Where the report did not provide sufficient information to characterize the
source, the report was not used for emission factor development. Types of information used to
characterize the source include type of fuel (oil, coal), boiler firing configuration, and control
devices in use during the emissions tests. The information used to characterize the emissions
data extracted from the test reports is summarized in Table A-l.
The emissions data extracted from the test reports were in the form of concentrations and
were expressed in one of three different mathematical units: grains per dry standard cubic feet
(gr/dscf); grams per dry standard cubic feet (g/dscf); and, milligrams per dry standard cubic feet
(mg/dscf). All concentrations were converted to pounds per dry standard cubic feet (Ib/dscf).
To develop emission factors in units of pounds of pollutant emitted per million British thermal
units of heat input (Ib/MMBtu), the concentrations were adjusted from as-measured percent
oxygen to zero percent oxygen and multiplied by fuel factors (F-factors) expressed in units of
dscf/MMBtu at zero percent oxygen. Site-specific F-factors were used when available and the
default F-factor of of 9,190 dscf/MMBtu provided in EPA Method 19 for residual oil and
distillate oil was used when site-specific F-factors were not available.
The emission factors developed from each test were grouped by individual boiler and
averaged. For some boilers, there were several test reports and, for other boilers, there was only
one test report. Where there were multiple tests for a single boiler, it was verified that the boiler
was firing the same fuel and using the same control devices for all tests before grouping and
averaging the emission factors to calculate a single factor for the boiler. Using this method of
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averaging, a single boiler is not overly represented in the data set because it was tested more
frequently; each boiler carries the same weight. The individual emission factors developed for
each emissions test and the average factors developed for each boiler are presented in Table A-2.
The average factor for each boiler was then grouped with the average factors for other
boilers of the same type and operating parameters. These parameters include fuel type (e.g.,
residual oil, distillate oil) and control devices used. The factors for each boiler in a group were
averaged to arrive at an emission factor that represents that group.
Table A-2 presents the average CPM-IOR, CPM-ORG, and CPM-TOT emission factors
developed for each individual boiler and the average factors for each boiler group. Because
there are fewer data points for CPM-IOR and CPM-ORG than for CPM-TOT, average factors for
boiler groups were not developed for these two pollutants. Instead, they will be presented in
AP-42 as percentages of the CPM-TOT.
The averge factors for each group expressed in Ib/MMBtu were converted to emission
factors expressed in pounds per thousand gallons. Table 4 presents the emission factor table as it
appears in AP-42.
2.8 Total Organic Compounds (TOO and Non-Methane TOC (NMTOO
Supplements A and B
The TOC and NMTOC factors were checked against information on page 4-7 of the EMF
Document and the 10/86 version of AP-42 and no changes were necessary.
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Table 4. Condensable Particulate Matter Emission Factors For Oil Combustion3
Firing
Configuration15
(SCC)
No. 2 oil fired,
normal firing,
tangential firing
(1-01-005-01,
1-02-005-01,
1-03-005-01)
No. 6 oil fired,
normal firing,
tangential firing
(1-01-004-01/04,
1-02-004-01,
1-03 -004-01)
Controls
All controls, or
uncontrolled
All controls, or
uncontrolled
CPM - TOTb
Emission Factor
1.2
1.5d
EMISSION
FACTOR
RATING
D
D
CPM - IORb
Emission Factor
65%ofCPM-
TOT emission
factor0
85%ofCPM-
TOT emission
factor11
EMISSION
FACTOR
RATING
D
E
CPM - ORGb
EMISSION
Emission Factor FACTOR RATING
35%ofCPM-TOT D
emission factor0
15%ofCPM-TOT E
emission factord
All condensable PM is assumed to be less than 1.0 micron in diameter. To convert to Ib/MMBtu of No. 2 oil, divide by 140 MMBtu/103 gal. To convert to
Ib/MMBtu of No. 6 oil, divide by 150 MMBtu/103 gal.
CPM-TOT = total condensable paniculate matter.
CPM-IOR = inorganic condensable paniculate matter.
CPM-ORG = organic condensable paniculate matter.
References: 12-14.
References: 15-18.
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2.9 Particle Size Distribution
Supplements A and B
The particle size factors were checked against information in the EMF Document and the
10/86 version of AP-42 and no changes were required 2.10
2.10 Polvcvclic Organic Matter (POM) and Formaldehyde (HCOFD
Supplements A and B
The POM and HCOH factors in Table 1.3-7 were checked with information in
Tables 4-12 and 4-14 of the EMF Document and no changes were required.
2.11 Trace Elements
Supplements A and B
Trace element factors were checked against Table 4-12 in the EMF Document. Based on
recent test data, the factors for residual oil firing shown in Table 1.3-8 were revised (with the
exception of antimony). New factors for barium, chloride, chromium VI, copper, fluoride,
molybdenum, phosphorus, vanadium, and zinc were added. The data used to calculate the new
and revised factors are presented in Appendix A.
The spreadsheets found in Appendix A present calculated average emissions factors
based on new test data. Trace elements and speciated organic compounds are presented in
Section A. 1. Section A.2 contains the individual source test report summaries.
Data from sources tested at several EPRI, Southern California Edison, and Pacific Gas
and Electric sites were entered into the spreadsheets. The emission factor were evaluated for
patterns based on boiler type and controls. No patterns were found; therefore, the data were
averaged (arithmetic mean) together by pollutant.
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Special consideration was given to non-detected values in calculating the average factors.
If a pollutant was not detected in any sampling run, half of the detection limit (DL/2) was used in
the calculated average factor. For a given pollutant, any DL/2 factors that were greater than any
factors based on detected values were not included in the calculated averages.
Data from each source test were given a quality rating based on EPA procedures. The
ratings ranged from B-D in the tests evaluated for this report. A "B" rating was given for tests
performed by a generally sound methodology but lacking enough detail for validation. A "C"
rating was given for tests based on untested or new methodology or lacking a significant amount
of background data. When a test was based on a generally unacceptable method but provided an
order-of-magnitude value for the source, a "D" rating was assigned.
Supplement E
It was observed that some trace metals were reported in AP-42 as occurring in greater
concentration in distillate oil emissions than in residual oil emissions, even though distillate oil
has much lower metals concentration. A search was subsequently made for more current
information on metals emission from distillate oil combustion. While no emission data was
available. The following distillate fuel oil analysis was located:
Element
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Mercury
Concentration in
Distillate Oil
Number/1012 Btu
15
3
3
3
6
17
6
Former AP-42
Emission Factor
Number/1012 Btu
4.2
2.5
11
48-67
8.9
3.0
Revised AP-42
Emission Factor
Number/1012 Btu
4
O
3
O
6
9
O
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Element
Manganese
Nickel
Selenium
Zinc
Concentration in
Distillate Oil
Number/1012 Btu
6
3
15
4
Former AP-42
Emission Factor
Number/1012 Btu
14
170
Revised AP-42
Emission Factor
Number/1012 Btu
6
3
15
4
Since trace elements will appear in the flue gas in lower concentrations than in the fuel oil, the
AP-42 factors were lowered to the fuel oil concentration whenever they were higher. The
revised AP-42 distillate oil emission factors are also shown in the table above (reference 20).
2.12 Greenhouse Gases
2.12.1 Carbon Dioxide, CO2
Supplements A and B
Table 1.3-1 computes CO2 emissions through a footnote that assumes 100 percent
conversion of fuel carbon content to CO2 during combustion. This does not account for
unoxidized fuel in the exhaust stream, which is typically 1 percent for liquid fuels in external
combustion systems.3"5 The factor in note f of Table 1.3-1 was modified to reflect 99 percent
conversion instead of the current 100 percent. These new factors appear in Table 5, below.
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Table 5. Emission Factor Equations for Solid and Liquid Fuel Combustion
Emission Factor Rating: B
Fuel
No. 1
(kerosene)
No. 2
No. 6
Multiply
% carbon
% carbon
% carbon
Density
(Ib/gal)
6.88
7.05
7.88
Conversion
Factor3
250
256
286
To Obtain
IbCCyiOOOgal
IbCCyiOOOgal
IbCCyiOOOgal
a The following equation was used to develop the emission factor equation for fuel oils in Table
5-1:
44 Ib C02
12 Ib C
x 0.99 x 7.05 — x
1
gal 100%
x 1000 = 256
Ib CO,
1000 gal %C
Where: 0.99 = fraction of fuel oxidized during combustion (References 3-5), and
7.05 Ib/gal = density of No. 2 fuel oil (AP-42 Appendix A).
The factors for kerosene and No. 6 oil were computed as shown in note a to Table 5 using
the density values from AP-42 Appendix A.
Table 6 lists default emission factors for fuel oils when the carbon content is not known.
These figures are based on average carbon contents for each type of fuel and the equation shown
in note A of Table 5.
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Table 6. Default CO2 Emission Factors for Liquid Fuels
Quality Rating: B
Fuel Type
No. 1 (kerosene)
No. 2
Low Sulfur No. 6
High Sulfur No. 6
%ca
86.25
87.25
87.26
85.14
Density"
(Ib/gal)
6.88
7.05
7.88
7.88
Emission Factor (lb/1000 gal)
21,500
22,300
25,000
24,400
aAn average of the values of fuel samples in References 6-7.
References 6 and 8.
2.12.2 Methane
Supplements A and B
No new data found.
2.12.3 Nitrous Oxide, N2O
Supplements A and B
The current "E" rated N2O emission factors in Table 1.3-9 were updated with more
recent data that take into account an N2O sampling artifact discovered by Muzio and
Kramlich in 1993.4 These new emission factors in Table 7 are based on a more complete
database of source sampling than either of the references listed for the previous N2O
emission factors in AP-42.
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Table 7. N2O Emission Factors for Fuel Oil Combustion"
(Ib N2O/1000 gal)
Fuel
No. 6
No. 2
Combustion Category
Industrial/utility boilers
Industrial/utility boilers
New
B
B
NewEF
0.53
0.26
Previous
0.11
0.11
Previous
E
E
•References 10-11.
The industrial/utility boilers data for No. 6 fuel oil is based on 6 tests at 4 different
facilities collected by Nelson.10 The data for No. 2 fuel oil for industrial/utility boilers is
based on 14 source tests conducted at 6 facilities collected by Nelson.10
The data sets were converted to Ib/MMBtu according to the procedures given in
40 CFR 60, Appendix A. To obtain Ibs/MMBtu, the emissions (in ppm) were first
multiplied by 1.141 x 10"7 (lb/scf)/ppm. These values were then converted to Ib/MMBtu
using the following formula:
20.9
20.9 -
Where: Cd = N2O;
Fd = F-factor for oxygen; and
%O2 = oxygen concentration in the exhaust gas.
The following F-factors and heating values were used for the calculations:
Fuel
No. 6 (residual)
No. 2 (distillate)
F-Factor
(scf/MMBtu)
9,190
9,190
Heating Value
(Btu/gal)
150,000
140,000
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2.13 Speciated Organic Compounds
Supplements A and B
Based on new test data, a total of twenty-one new factors were developed for residual
oil fired boilers. The average factors and the data used to calculate the factors are presented
in Appendix A. The formaldehyde factor calculated with this data is based on recent tests of
utility boilers only.
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3.0 REFERENCES
1. McCrillis, R.C., and R. R. Watts, Analysis of Emissions from Residential Oil
Furnaces, U. S. Environmental Protection Agency, 92-110.06, Undated, page 4.
2. Krajewski, R. et al., Emissions Characteristics of Modern Oil Heating Equipment.
BNL-52249. Brookhaven National Laboratory. July 1990, pages 40-42.
3. Marland, G. and R.M. Rotty, "Carbon Dioxide Emissions from Fossil Fuels: A
Procedure for Estimation and Results for 1951-1981," DOE/NBB-0036 Tr-003, Carbon
Dioxide Research Division, Office of Energy Research, U.S. Department of Energy, Oak
Ridge, TN, 1983.
4. Rosland, A., Greenhouse Gas Emissions In Norway: Inventories And Estimation
Methods, Oslo: Ministry of Environment, 1993.
5. Sector-Specific Issues And Reporting Methodologies Supporting The General Guidelines
For The Voluntary Reporting Of Greenhouse Gases Under Section 1605(b) Of The
Energy Policy Act Of 1992, DOE/PO-9928, Volume 2 of 3, U.S. Department of Energy,
1994.
6. Perry, R. H. and D. Green, Perry's Chemical Engineers Handbook, Sixth ed., New York:
McGrawHill, 1984.
7. Steam: Its Generation And Use, Babcock and Wilcox, New York, 1975.
8. Compilation Of Air Pollutant Emission Factors, Volume I: Stationary Point And Area
Sources, U.S. Environmental Protection Agency, AP-42. Fifth Edition, 1995. Research
Triangle Park, NC.
9. Muzio, L.J., and J.C. Kramlic, "An Artifact in the Measurement of N2O from
Combustion Sources," Geophysical Research Letters, Volume 15, No. 12 (Nov),
pp. 1369-1372, 1988.
10. Nelson, L.P. et al., "Global Combustion Sources of Nitrous Oxide Emissions," Research
Project 233-4 Interim Report, Sacramento: Radian Corporation, 1991.
11. Peer, R. L. et al., "Characterization of Nitrous Oxide Emission Sources," Prepared for the
US EPA Contract 68-D1-0031, Research Triangle Park, NC: Radian Corporation, 1995.
12. Results of the September 14 and 15, 1994 Air Emission Compliance Tests on the No. 11
Boiler at the Appleton Paper Plant in Combined Locks, Wisconsin. Interpoll
Laboratories. October 10, 1994.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.002 (6-26-3)
5-1
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13. Compliance Emission Test Report for Lakewood Cogeneration, L.P. Lakewood
Township, New Jersey. Environmental Laboratories, Inc. December 19, 1994.
14. Compliance Test Report Air Emissions from Utility Boilers A, B, and C. Mobile Oil
Corporation. Paulsboro, New Jersey. ENSA Environmental, Inc. May 1995.
15. Boise Cascade Combined Power Boilers Title V Fuel Oil Compliance Test Report. St.
Helens, Oregon Paper Mill. Bighorn Environmental Quality Control. August 8, 1996.
16. Results of the July 13, 1993 Particulate and Sulfur Dioxide Emission Compliance Testing
at the Land O'Lakes Plant in Spencer, Wisconsin. Interpoll Laboratories, Inc.
August 16, 1993.
17. Results of the May 31, 1995 Air Emission Compliance Tests of the No. 1 Boiler at the
Land O'Lakes Plant in Spencer, Wisconsin. Interpoll Laboratories, Inc. July 12, 1995.
18. Boiler Emission Testing at KC-Neenah Paper, Whiting Mill, Stevens Point, WI. Badger
Laboratories and Engineering. February 27, 1995.
19. C.A. Miller. Hazardous Air Pollutants from the Combustion of an Emulsified Heavy Oil
in a Firetube Boiler. EPA-600/R-96-019. U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina. February 1996.
20. Emissions Inventory Testing at Long Beach Turbine. Combustion Turbine No. 3,
CARNOT, Tustin, CA. May, 1989.
21. Results of the September 14 and 15, 1994 Air Emission Compliance Tests on the No. 11
Boiler at the Appleton Paper Plant in Combined Locks, Wisconsin. Interpoll
Laboratories, Inc. October 10, 1994.
22. Emission Compliance Test Report. Merck Mfg. Division of Merck & Co. Sumneytown
Pike, West Point, PA. Industrial Technical Services, Inc.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.002 (6-26-3)
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4.0 REVISED SECTION 1.3
The electronic version of the revised Section 1.3 of AP-42, 5th Edition, can be located on
the EPA TTN at http://www.epa.gov/ttn/chief
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.002 (6-26-3)
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5.0 EMISSION FACTOR DOCUMENTATION, APRIL 1993
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.002 (6-26-3)
5-1
-------
EMISSION FACTOR DOCUMENTATION FOR
AP-42 SECTION 1.3,
FUEL OIL COMBUSTION
Prepared by:
Acurex Environmental Corporation
Research Triangle Park, NC 27709
Edward Aul & Associates, Inc.
Chapel Hill, NC 27514
E. H. Pechan & Associates, Inc.
Rancho Cordova, CA 95742
Contract No. 68-DO-0120
EPA Work Assignment Officer: Michael Hamlin
Office of Air Quality Planning and Standards
Office Of Air And Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
April 1993
-------
DISCLAIMER
This report has been reviewed by the Office of Air Quality Planning and Standards,
U. S. Environmental Protection Agency, and approved for publication. Mention of trade
names or commercial products does not constitute endorsement or recommendation for
use.
-------
TABLE OF CONTENTS
LIST OF TABLES vi
CHAPTER! INTRODUCTION 1-1
CHAPTER 2. SOURCE DESCRIPTION 2-1
2.1 CHARACTERIZATION OF FUEL OIL
APPLICATIONS 2-1
2.2 PROCESS DESCRIPTIONS 2-2
2.2.1 Watertube Boilers 2-2
2.2.2 Firetube Boilers 2-3
2.2.3 Cast Iron Boilers 2-3
2.2.4 Other Boilers 2-3
2.3 EMISSIONS 2-4
2.3.1 Participate Matter Emissions 2-5
2.3.2 Sulfur Oxide Emissions 2-5
2.3.3 Nitrogen Oxides Emissions 2-6
2.3.4 Carbon Monoxide Emissions 2-8
2.3.5 Organic Compound Emissions 2-8
2.3.6 Trace Element Emissions 2-10
2.4 CONTROL TECHNOLOGIES 2-12
2.4.1 Fuel Substitution 2-12
2.4.2 Combustion Modification 2-13
2.4.2.1 Particulate Matter Control 2-13
2.4.2.2 NOX Control 2-13
-------
2.4.3 Post Combustion Control 2-15
2.4.3.1 Particulate Control 2-15
2.4.3.2 NOX Control 2-16
2.4.3.3 S02 Control 2-16
REFERENCES 2-29
CHAPTER 3. GENERAL EMISSION DATA REVIEW AND
ANALYSIS PROCEDURES 3-1
3.1 CRITERIA POLLUTANTS 3-1
3.1.1 Literature Search 3-1
3.1.2 Literature Evaluation 3-1
3.1.3 Emission Factor Quality Rating 3-3
3.2 SPECIATED VOCs 3-4
3.2.1 Literature Search 3-4
TABLE OF CONTENTS (continued)
Page
3.2.2 Literature Evaluation 3-5
3.2.3 Data and Emission Factor
Quality Rating 3-5
3.3 AIR TOXICS 3-5
3.3.1 Literature Search 3-5
3.3.2 Literature Evaluation 3-6
3.3.3 Data and Emission Factor
Quality Rating Criteria 3-6
3.4 Nitrous Oxide 3-8
iv
-------
3.4.1 Literature Search 3-8
3.4.2 Literature Evaluation 3-8
3.4.3 Data and Emission Factor
Quality Rating 3-8
3.5 FUGITIVE EMISSIONS 3-9
3.6 PARTICLE SIZE DISTRIBUTION 3-10
3.6.1 Literature Search 3-10
3.6.2 Literature Evaluation 3-11
3.6.3 Data Quality Ranking 3-12
REFERENCES 3-16
CHAPTER 4. EMISSION FACTOR DEVELOPMENT 4-1
4.1 CRITERIA POLLUTANTS 4-1
4.1.1 Review of Previous AP-42 Data 4-1
4.1.2 Review of New Baseline Data 4-1
4.1.3 Compilation of Baseline
Em ission Factors 4-4
4.1.4 Compilation of Controlled
Em ission Factors 4-7
4.2 SPECIATED VOCs 4-8
4.3 HAZARDOUS AIR POLLUTANTS 4-8
4.3.1 Review of New Data 4-8
4.3.2 Baseline Emission Factors 4-12
4.3.3 Controlled Emission Factors 4-14
4.4 Nitrous Oxide 4-14
4.4.1 Review of Specific Data Sets 4-14
TABLE OF CONTENTS (continued)
4.5 FUGITIVE EMISSIONS 4-15
4.5.1 Review of Specific Data 4-16
4.5.2 Compilation of Emission Factors 4-16
4.6 PARTICULATE SIZE DISTRIBUTION 4-16
4.6.1 Review of 1986 Section 1.3 Data 4-16
4.6.2 Review of New Data 4-17
4.6.3 Compilation of Uncontrolled
Emission Factors 4-18
4.6.4 Control Technology Emission
-------
Factors 4-18
REFERENCES 4-51
CHAPTERS. AP-42 SECTION 1.3: FUEL OIL COMBUSTION 5-1
APPENDIXA: CONVERSION FACTORS A-1
APPENDIX B: MARKED-UP 1986 AP-42 SECTION 1.3 B-1
VI
-------
LIST OF TABLES
Table Page
2-1 U.S. Oil Consumption by Sector in 1990 2-19
2-2 Boiler Usage by Sector 2-20
2-3 Total U.S. Anthropogenic Emissions by
Category for S02, NOX, VOC, and TSP in 1989 2-21
2-4 NSPS Summary for Fossil Fuel-fired Boilers 2-22
2-5 Combustion Modification NOX Controls
Evaluated for Oil-fired Boilers 2-24
2-6 Post Combustion NOX Reduction Technologies 2-27
2-7 Commercial Post Combustion S02 Controls for
Coal Combustion Sources 2-28
3-1 Literature Search/Consultation Record 3-14
3-2 Evaluation of References 3-15
4-1 Results of 1986 Section 1.3 Data Spot Checks 4-21
4-2 PM Emission Factor Update 4-25
4-3 S02 Emission Factor Update 4-27
4-4 S03 Emission Factor Update 4-29
4-5 CO Emission Factor Update 4-31
4-6 NOX Emission Factor Update 4-32
4-7 VOC Emission Factor Update 4-34
4-8 Controlled PM Emissions 4-35
4-9 Controlled S02 Emissions 4-37
4-10 Controlled NOX Emissions 4-40
4-11 Metals Enrichment Behavior 4-44
4-12 HAP Emission Factors (Metric Units) for
Residual and Distillate Oil Combustion 4-45
4-13 HAP Emission Factors (English Units) for
Residual and Distillate Oil Combustion 4-46
4-14 Summary of N20 Emission Factors for Fuel
Oil Combustion 4-47
4-15 Comparison of Fugitive Emissions of VOCs
from Equipment Types 4-47
4-16 Oil-Fired Particulate Sizing Data for the
Current AP-42 Sections: Number of A- and B-
Rated Data Sets 4-48
4-17 Comparison of Organic and Inorganic CPM
Emissions from a 5 Million Btu/Hr Scotch
Dry-back Boiler 4-48
4-18 Comparison of Organic and Inorganic CPM
Emissions from a Type-H Stirling Boiler
Firing No. 2 Fuel Oil 4-49
VII
-------
4-19 Comparison of Organic and Inorganic CPM
Emissions from a Face-fired Supercritical
480 MW Steam Generator 4-49
LIST OF TABLES (continued)
Table Page
4-20 Comparison of Organic and Inorganic CPM
Emissions from a Face-fired, Balanced
Draft Utility Boiler 4-50
4-21 Comparison of Organic and Inorganic CPM
Emissions from an Oil-fired Boiler Equipped
with a Mechanical Collector 4-50
VIM
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1. INTRODUCTION
An emission factor is an average value which relates the quantity (weight) of a
pollutant released to the atmosphere with the activity associated with the release of that
pollutant. Emission factors for many activities are listed in the document "Compilation
of Air Pollutant Emission Factors" (AP-42) published by the U.S. Environmental
Protection Agency (EPA) since 1972. The uses for the emission factors reported in AP-
42 include:
! Estimates of area-wide emissions,
! Emission estimates for a specific facility,
! Evaluation of emissions relative to ambient air quality.
The EPA routinely updates AP-42 in order to respond to the needs of State and
local air pollution control programs, industry, as well as the Agency itself. Section 1.3 in
AP-42, the subject of this Emission Factor Documentation (EFD) report, pertains to fuel
oil combustion in stationary, external equipment.
The prior revisions of AP-42 Section 1.3 focused primarily on the criteria
pollutants, together with particle sizing. The purpose of this revision is to update the
data base for the earlier revisions and extend the section's scope to other pollutant
species. Specifically, the scope of the current update includes the following:
! Updating of emission factors for criteria pollutants during baseline,
uncontrolled operation using data that has become available since the
prior revision (i.e., 1986).
! Inclusion of several non-criteria emission species for which data are
available: organics speciation, air toxics, and greenhouse or ozone
depletion gases [e.g., nitrous oxide (N20) and carbon dioxide (C02)].
1-ix
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! Expand and update the technical discussion and control efficiency data
for boilers operating with nitrogen oxides (NOX), carbon monoxide (CO), or
particulate matter (PM) control systems.
The update of Section 1.3 of AP-42 began with a review of the existing version of
Section 1.3. Spot checks were made on the quality of existing emission factors by
selecting primary data references from the background files and recalculating emission
factors.
An extensive literature review was undertaken to improve technology
descriptions, update usage trends, and collect new test reports for criteria and non-
criteria emissions. The new test reports were subjected to data quality review as
outlined in the draft EPA document, "Technical Procedures For Developing AP-42
Emission Factors And Preparing AP-42 Sections" (March 6, 1992). The data points
obtained from test reports receiving sufficiently high quality ratings were then combined
with existing data, wherever possible, and used to produce new emission factors.
In this revision, several new emission factors pertaining to non-criteria pollutants
have been added. These new emission factors pertain to speciated volatile organic
compounds (VOCs), air toxics, N20, C02, and fugitive emissions. Additionally, in this
revision, the information on control technologies for particulate, sulfur oxides (SOX), and
NOX emissions has been updated. Finally, this revision has resulted in the addition of
several new references.
Chapter 2 of this report gives a description of the fuel oil combustion industry. It
includes a characterization of fuel oil applications, an overview of the different process
types, a description of emissions, and a description of the technology used to control
emissions resulting from fuel oil combustion. Chapter 3 is a review of emissions data
collection and analysis procedures. It describes the literature search, the screening of
emissions data reports, and the quality rating system for both emission data and
emission factors. Chapter 4 details pollutant emission factor development. It includes
reviews of specific data sets and details of emission factor compilations. Chapter 5
presents the revised AP-42 Section 1.3.
1-x
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2. SOURCE DESCRIPTION
The amount and type of oil consumed, design of combustion equipment, and
application of emission control technology have a direct bearing on emissions from oil-
fired combustion equipment. This chapter characterizes oil applications, fuel oil
combustion processes, and emission control technologies pertaining to the United
States.
2.1 CHARACTERIZATION OF FUEL OIL APPLICATIONS
Annual consumption of fuel oil in boilers in the United States totalled about 4200
kJ (4400 x 1012 Btu) in 1990.1 This consumption in boilers was divided into four sectors:
(1) utility boilers producing steam for the generation of electricity; (2) industrial boilers
generating steam or hot water for process heat, electricity generation, or space heat;
(3) boilers used for space heating of commercial facilities; and (4) residential furnaces
used for space heating purposes.
Two major categories of fuel oil are burned by combustion sources: distillate oils
and residual oils. These oils are further distinguished by grade numbers, with numbers
1 and 2 being distillate oils; numbers 5 and 6 being residual oils; and number 4 being
either distillate oil or a mixture of distillate and residual oils. Grade 6 oil is sometimes
referred to as Bunker C. Distillate oils are more volatile and less viscous than residual
oils. They have negligible nitrogen and ash contents and usually contain less than 0.5
percent sulfur (by weight). Distillate oils are used mainly in domestic and small
commercial applications.
Being more viscous and less volatile than distillate oils, the heavier residual oils
(grades 5 and 6) must be heated for ease of handling and to facilitate proper
atomization. Because residual oils are produced from the residue left over after the
lighter fractions (e.g., gasoline, kerosene, and distillate oils) have been removed from
2-xi
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the crude oil, they contain significant quantities of ash, nitrogen, and sulfur. Residual
oils are used mainly in utility, industrial, and large commercial applications.
Table 2-1 summarizes the Department of Energy data on oil use by combustion sector
in 1990.1
2.2 PROCESS DESCRIPTIONS
The three major boiler configurations for fuel oil-fired combustors (i.e., watertube,
firetube, and cast iron) are described below. Boilers are classified according to design
and orientation of heat transfer surfaces, burner configuration, and size. These factors
can all strongly influence emissions as well as the potential for controlling emissions.
2.2.1 Watertube Boilers
Watertube boilers are used in a variety of applications ranging from supplying
large amounts of process steam to providing space heat for industrial facilities. In a
watertube boiler, combustion heat is transferred to water flowing through tubes which
line the furnace walls and boiler passes. The tube surfaces in the furnace (which
houses the burner flame) absorb heat primarily by radiation from the flames. The tube
surfaces in the boiler passes (adjacent to the primary furnace) absorb heat primarily by
convective heat transfer.
Industrial watertube boilers are available as packaged or field erected units, in
capacities ranging from less than 2.9 to over 200 MW [10 to over 700 million Btu per
hour (MMBtu/hr)].1 Utility oil-fired boilers are field erected and have thermal heat input
ratings up to about 2,300 MW (8,000 MMBtu/hr). New industrial oil-fired boilers as
large as 70 MW (250 MMBtu/hr) input capacity are typically shop assembled and
shipped as packaged units. Larger oil-fired boilers are field-erected units assembled
on-site. In general, field-erected watertube boilers are much more common than
packaged units in the boiler size category above 58 MW (200 MMBtu/hr) input capacity
whereas, below this capacity, watertube boilers are usually packaged. There are,
however, packaged watertube units as large as 102 MW(350 MMBtu/hr) input capacity.
2.2.2 Firetube Boilers
Firetube boilers are used primarily for heating systems, industrial process steam
2-xii
-------
generators, and portable power boilers. In firetube boilers, the hot combustion gases
flow through the tubes while the water being heated circulates outside of the tubes. At
high pressures and when subjected to large variations in steam demand, firetube units
are more susceptible to structural failure than watertube boilers. This is because the
high pressure steam in firetube units is contained by the boiler walls rather than by
multiple small-diameter watertubes, which are inherently stronger.3 As a consequence,
firetube boilers are typically small, with heat input capacities limited to less than 15 MW
(50 MMBtu/hr) and steam pressures limited to 150 kPa (300 psig), although high-end
steam pressures of 76 kPa (150 psig) are more common.4 Firetubes are used primarily
where boiler loads are relatively constant. Nearly all firetube boilers are sold as
packaged units because of their relatively small size. Firetube boilers are generally
available as packaged units in capacities ranging from 0.1 MW(0.4 MMBtu/hr) to 15
MW (50 MMBtu/hr).
2.2.3 Cast Iron Boilers
A cast iron boiler is one in which combustion gases rise through a vertical heat
exchanger and out through an exhaust duct. Water in the heat exchanger tubes is
heated as it moves upward through the tubes. Cast iron boilers produce low pressure
steam or hot water, and generally burn oil or natural gas. They are used primarily in the
residential and commercial sectors and have input capacities up to 4 MW (14
MMBtu/hr).4
2.2.4 Other Boilers
A fourth type of heat transfer configuration used on smaller boilers is the
tubeless design. This design incorporates nested pressure vessels with water in
between the shells. Combustion gases are fired into the inner pressure vessel and are
then sometimes recirculated outside the second vessel. This type of boiler is packaged
and is available in heat input capacities ranging from 0.07 to 1.2 MW (0.25 to 4.2
MMBtu/hr).5
Boilers used in thermally enhanced oil recovery (TEOR) operations are referred
to as oil field steam generators. These units are typically packaged watertube boilers
with heat input capacities from about 5.8 to 18 MW (20 to 63 MMBtu/hr). Steam
2-xiii
-------
generators are typically cylindrical in shape and horizontally oriented, with watertubes
arranged in a coil-like design. For a given size, there is little variability in the design or
configuration of oil field steam generators.6 Table 2-2 summarizes the use of the three
major types of boilers in various sectors.7
2.3 EMISSIONS
Emissions from fuel oil combustion depend on the grade and composition of the
fuel, the type and size of the boiler, the firing practices used, and the level of equipment
maintenance. The term "baseline emissions" of criteria and non-criteria pollutants refer
to emissions from uncontrolled combustion sources. Uncontrolled sources are those
without add-on air pollution control (ARC) equipment, Iow-N0x burners, or other
modifications for emission control. Baseline emissions for sulfur dioxide (S02) and PM
can be obtained from controlled sources if measurements are taken upstream of ARC
equipment. This may not be possible with combustion modification controls for NOX,
where the controls are an intrinsic part of the boiler design.
For this update of AP-42, point source emissions of NOX, S02, PM, and CO are
being evaluated as criteria pollutants (those emissions which have established National
Primary and Secondary Ambient Air Quality Standards).34 Particulate matter emissions
are sometimes reported as total suspended particulate (TSP). The portion of inhalable
particulate matter which is less than 10 microns in aerodynamic diameter (PM-10) has
been redesignated as a criteria pollutant. In addition to the criteria pollutants, this
update includes point source emissions of some non-criteria pollutants (e.g., N20,
VOCs, and hazardous air pollutants) as well as data on particle size distribution to
support PM-10 emission inventory efforts. Emissions of C02 are also being considered
because of its possible participation in global climatic change and the corresponding
interest in including this gas in emission inventories. Most of the carbon in fossil fuels,
including fuel oil, is emitted as C02 during combustion. Minor amounts of carbon are
emitted as CO, much of which ultimately oxidizes to C02, or as carbon in the ash.
Finally, fugitive emissions associated with the use of fuel oil at the combustion source
are being included in this update of AP-42.
A general discussion of emissions of criteria and non-criteria pollutants from coal
combustion is given in the following paragraphs.
2-xiv
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2.3.1 Particulate Matter Emissions10-14'19-20'28'30-31
The PM emissions from fuel oil-firing under normal non-sooting conditions
depend primarily on the grade of oil fired. Combustion of lighter distillate oils results in
significantly lower PM formation than does combustion of heavier residual oils. Among
residual oils, firing of Nos. 4 and 5 usually produces less PM than does the firing of
heavier No. 6.
In general, PM emissions depend on the completeness of combustion as well as
the oil ash content. The PM emitted by distillate oil-fired boilers is primarily
carbonaceous particles resulting from incomplete combustion of oil and does not
correlate with the ash or sulfur content of the oil. This is because lower sulfur (distillate)
oil has substantially lower viscosity and reduced asphaltene and ash contents.
Consequently, lower sulfur oils atomize better and burn easier. The level of PM
emissions from residual oil combustion, however, is related to the oil sulfur content.
This applies regardless of whether the fuel oil is refined from naturally occurring low
sulfur crudes or is desulfurized by current refinery practice.
Boiler load can also affect particulate emissions in units firing No. 6 oil. At low
load conditions, particulate emissions may be lowered by 30 to 40 percent from utility
boilers and by as much as 60 percent from small industrial and commercial units.
However, no significant particulate emissions have been noted at low loads from boilers
firing any of the lighter oil grades. At very low load conditions, proper combustion
conditions typically cannot be maintained and particulate emissions may increase
drastically.
2.3.2 Sulfur Oxide Emissions8'12'29
Sulfur oxide emissions are generated during oil combustion from the oxidation of
sulfur contained in the fuel. The emissions of SOX from conventional combustion
systems are predominantly in the form of S02. Uncontrolled SOX emissions are almost
entirely dependent on the sulfur content of the fuel and are not affected by boiler size,
burner design, or grade of fuel being fired.13 On average, more than 95 percent of the
fuel sulfur is converted to S02; about 1 to 5 percent further oxidized to sulfur trioxide
(S03); and about 1 to 3 percent is emitted as sulfate particulate. The S03 readily reacts
with water vapor (both in air and in flue gases) to form a sulfuric acid mist.
2-xv
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2.3.3 Nitrogen Oxides Emissions 8-18.21-22.27.31
Oxides of nitrogen formed in combustion processes are due either to thermal
fixation of atmospheric nitrogen in the combustion air ("thermal NOX"), or to the
conversion of chemically-bound nitrogen in the fuel ("fuel NOX"). Although five oxides of
nitrogen exist, the term NOX is customarily used to describe the composite of nitric oxide
(NO) and nitrogen dioxide (N02). Nitrous oxide is of increasing interest as an upper
atmosphere gas, but is not included in NOX. Test data have shown that for most
stationary fossil fuel combustion systems, over 95 percent of the emitted NOX is in the
form of NO.13
On a global basis, thermal NOX formation rates in flames is exponentially
dependent on temperature and proportional to the nitrogen (N2) concentration in the
flame, the square root of the oxygen (02) concentration in the flame, and the residence
time.27 These relationships are corroborated by experimental data which show that
thermal NOX formation is most strongly dependant on three factors: (1) peak
temperature, (2) 02 concentration (or stoichiometric ratio), and (3) time of exposure at
peak temperature. The emission trends due to changes in these factors are fairly
consistent for all types of boilers: an increase in flame temperature, oxygen availability,
and/or residence time at high temperatures leads to an increase in NOX production
regardless of the boiler type.
Fuel nitrogen conversion is an important N0x-forming mechanism in residual oil-
fired boilers. It can account for 50 percent of the total NOX emissions from residual oil
firing.32 The percent conversion of fuel nitrogen to NOX, however, varies greatly.
Anywhere from 20 to 90 percent of nitrogen in oil is converted to NOX. Except in certain
large units having unusually high peak flame temperatures, or in units firing a low
nitrogen residual oil, fuel NOX will generally account for over 50 percent of the total NOX
generated. Thermal fixation, on the other hand, is the dominant NOX forming
mechanism in units firing distillate oils, primarily because of the negligible nitrogen
content in these lighter oils.
A number of variables influence how much NOX is formed by these two
mechanisms. One important variable is firing configuration. The NOX emissions from
tangentially (or corner)-fired boilers are, on the average, less than those with
2-xvi
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horizontally opposed burners. Also important are the firing practices employed during
boiler operation. Low excess air (LEA) firing, flue gas recirculation (FGR), staged
combustion (SC), or some combination thereof may result in NOX reductions of 5 to 60
percent (see Section 2.4.1 for a discussion of these techniques). Load reduction can
likewise decrease NOX production. Emissions of NOX may be reduced from 0.5 to 1
percent for each percentage reduction in load below full load operation. It should be
noted that most of these variables, with the exception of excess air, influence the NOX
emissions only of large oil-fired boilers. Low excess air firing is possible in many small
boilers, but the resulting NOX reductions may not be significant.
Nitrous oxide emissions for most oil-fired boilers are only a small fraction of the
NOX levels. Earlier data (prior to 1988) had suggested much higher levels of N20.
However, these data are thought to be erroneous due to a sampling artifiact introduced
as a result of the time lapse between sampling and analysis. New methods have been
proposed to circumvent this problem. Recent N20 emissions data, indicate that direct
N20 emissions from oil combustion units are considerably below the measurements
made prior to 1988.35 Nevertheless, the N20 formation and reaction mechanisms are
still not well understood nor well characterized. Additional sampling and research is
needed to fully characterize N20 emissions and to understand the N20 mechanism.
Emissions can vary widely from unit to unit, or even from the same unit under different
operating conditions. It has been shown in some cases that N20 increases with
decreasing boiler temperature.36 For this AP-42 update, an average emission factor
based on reported test data was developed for conventional oil combustion systems.
The nationwide inventory of PM, S02, and NOX emissions resulting from fuel oil
combustion in 1985 are summarized in Table 2-3. Table 2-4 summarizes the new
source performance standards (NSPS) pertinent to PM, S02, and NOX emissions from
fossil fuel-fired boilers.48
2.3.4 Carbon Monoxide Emissions 23'26
The rate of CO emissions from combustion sources depends on the oxidation
efficiency of the fuel. By controlling the combustion process carefully, CO emissions
can be minimized. Thus, if a unit is operated improperly or not well maintained, the
2-xvii
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resulting concentrations of CO (as well as organic compounds) may increase by several
orders of magnitude. Smaller boilers, heaters, and furnaces tend to emit more of these
pollutants than larger combustors. This is because smaller units usually have a higher
ratio of heat transfer surface area to flame volume leading to reduced flame
temperature and combustion intensity and, therefore, lower combustion efficiency than
large combustors. Larger combustors also have more complex combustion control
systems to trim 02 to a level which gives low CO emissions but high efficiency.
The presence of CO in the exhaust gases of combustion systems results
principally from incomplete fuel combustion. Several conditions can lead to incomplete
combustion. These include:
! Insufficient 02 availability;
! Extremely high levels of excess air (which leads to quenching);
! Poor fuel/air mixing;
! Cold wall flame quenching;
! Reduced combustion temperature;
! Decreased combustion gas residence time; and
! Load reduction (i.e., reduced combustion intensity).
Since various combustion modifications for NOX reduction can produce one or more of
the above conditions, the possibility of increased CO emissions is a concern for
environmental, energy efficiency, and operational reasons.
2.3.5 Organic Compound Emissions 23'26
Small amounts of organic compounds are emitted from combustion. As with CO
emissions, the rate at which organic compounds are emitted depends on the
combustion efficiency of the boiler. Therefore, any combustion modification which
reduces the combustion efficiency will most likely increase the concentrations of organic
compounds in the flue gases.
Total organic compounds (TOCs) include VOCs which remain in a gaseous state
in ambient air, semi-volatile organic compounds, and condensible organic compounds.
According to the Federal Register definition (57 FR 3945), VOC has been defined as
any organic compound excluding CO, C02, carbonic acid, metallic carbides or
carbonates, and ammonium carbonate which participates in atmospheric photochemical
2-xviii
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reactions. The following additional compounds have been deemed to be of "negligible
photochemical reactivity" and also are exempt from the definition of VOC: methane,
ethane, methyl chloroform, methylene chloride, and most chlorinated-fluorinated
compounds (commonly referred to as CFCs). Although these compounds are
considered "exempt" from most ozone control programs due to their low photochemical
reactivity rates, they are of concern when developing complete emission inventories
which are necessary for the design of effective ozone control strategies. The term TOC
will refer to all organic compounds: VOCs plus the "exempt" compounds, including
methane and ethane, toxic compounds, aldehydes, perchloroethylene, semi-volatiles,
and condensibles (as measured by EPA Reference Methods).
Emissions of VOCs are primarily characterized by the criteria pollutant class of
unburned vapor phase hydrocarbons. Unburned hydrocarbon emissions can include
essentially all vapor phase organic compounds emitted from a combustion source.
These are primarily emissions of aliphatic, oxygenated, and low molecular weight
aromatic compounds which exist in the vapor phase at flue gas temperatures. These
emissions include all alkanes, alkenes, aldehydes, carboxylic acids, and substituted
benzenes (e.g., benzene, toluene, xylene, ethyl benzene, etc.).37'38
The remaining organic emissions are composed largely of compounds emitted
from combustion sources in a condensed phase. These compounds can almost
exclusively be classed into a group known as polycyclic organic matter (POM), and a
subset of compounds called polynuclear aromatic hydrocarbons (PNA or PAH).
Information available in the literature on POM compounds generally pertains to these
PAH groups. Because of the dominance of PAH information (as opposed to other POM
categories) in the literature, many reference sources have inaccurately used the terms
POM and PAH interchangeably.
A few comments are in order concerning an extremely toxic subclass of PNA -
the polychlorinated and polybrominated biphenyls (PCBs and PBBs). A theoretical
assessment of PCB formation in combustion sources concluded that, although PCB
formation is thermodynamically possible for combustion of fuels containing some
chlorine (e.g., some coals and residual oil), it is unlikely due to low chlorine
concentrations and to short residence times at conditions favoring PCBs.39 Also, with
2-xix
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efficient mixing, 02 availability, and adequate residence time at temperatures in the
800-1000° C (1500-1800° F) range, PCBs (together with polychlorinated dibenzo-p-
dioxins and polychlorinated dibenzofurans) will be efficiently destroyed.40 Other
research has shown, however, that chlorinated PNAs can be formed via catalyzed
reactions on fly ash particles at low temperatures in equipment downstream of the
combustion device.60
Formaldehyde is formed and emitted during the combustion of hydrocarbon-
based fuels, including coal and oil. Formaldehyde is present in the vapor phase of the
flue gas. Since formaldehyde is subject to oxidation and decomposition at the high
temperatures encountered during combustion, large units with efficient combustion
resulting from closely regulated air-fuel ratios, uniformly high combustion chamber
temperatures, and relatively long residence times should have lower formaldehyde
emission rates relative to small, less efficient combustion units.41'42
2.3.6 Trace Element Emissions 23'26
Trace elements are also emitted from oil combustion with the emission rate
largely dependant on the metals concentration of the oil. For this update of AP-42,
trace metals included in the list of 189 hazardous air pollutants under Title III of the
1990 Clean Air Act Amendments (CAAA-90) are considered.43 The quantity of trace
metals emitted depends on combustion temperature, fuel feed mechanism, and the
composition of the fuel. The temperature determines the degree of volatilization of
specific compounds contained in the fuel. The fuel feed mechanism affects the
partitioning of ash into heavier material which deposits on boiler surfaces and lighter,
smaller ash which is emitted with the flue gas.
The quantity of any given metal emitted, in general, depends on:
! Its concentration in the fuel;
! The combustion conditions;
! The type of particulate control device used, and its collection efficiency as
a function of particle size; and
! The physical and chemical properties of the element affecting
transformation and fate.
2-xx
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It has become widely recognized that some trace metals concentrate in certain
waste particle streams from a combustor (e.g., bottom ash, collector ash, flue gas
particulate), while others do not.44 Various classification schemes to describe this
partitioning have been developed.45"47 The schemes have been derived for solid fuel-
firing, but are also relevant to oil-firing. The classification scheme used by Baig, et al. is
as follows:47
! Class 1: Elements which are approximately equally distributed between
fly ash and bottom ash, or show little or no small particle enrichment.
! Class 2: Elements which are enriched in fly ash relative to bottom ash, or
show increasing enrichment with decreasing particle size.
! Class 3: Elements which are intermediate between Classes 1 and 2.
! Class 4: Elements which are emitted in the gas phase.
By understanding trace metal partitioning and concentration in fine particulate, it
is possible to postulate the effects of combustion controls on incremental trace metal
emissions.44 For example, several boiler NOX control techniques reduce peak flame
temperatures (e.g., staged combustion, FGR, reduced air preheat, and load reduction).
If combustion temperatures are reduced, fewer Class 2 metals will initially volatilize, and
fewer will be available for subsequent condensation and enrichment in the fine particle
fractions. Therefore, for combustors with particulate controls, lower volatile metal
emissions should result due to improved particulate removal. Flue gas emissions of
Class 1 metals (the non-segregating trace metals) should remain relatively unchanged.
Local 02 concentration is also expected to affect metal emissions from boilers
with particulate controls. Lower 02 availability decreases the possibility of volatile metal
oxidation to less volatile oxides. Under these conditions, Class 2 metals should remain
in the vapor phase in the cooler sections of the boiler. More redistribution to small
particles should occur and emissions should increase. Again, Class 1 metals emissions
should remain unchanged.
2-xxi
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Other combustion NOX controls which decrease local 02 concentrations (such as
staged combustion and FGR) also reduce peak flame temperatures. Under these
conditions, the effect of reduced combustion temperature is expected to be stronger
than that of lower 02 concentrations.
2.4 CONTROL TECHNOLOGIES
The various control techniques and/or devices employed with oil combustion
sources depend on the source category and the pollutant being controlled. Only
controls for criteria pollutants are discussed here because controls designed specifically
for non-criteria emissions have not been demonstrated nor commercialized for oil
combustion sources.
Control techniques may be classified into three broad categories: fuel
substitution, combustion modification, and post combustion control. Fuel substitution
involves using "cleaner" fuels to reduce emissions. Combustion modification and post
combustion control are both applicable and widely commercialized for oil combustion
sources. Combustion modification is applied primarily for NOX control purposes,
although for small units, some reduction in PM emissions may be available through
improved combustion practice. Post combustion control is applied to emissions of PM,
S02, and, to some extent, N0xfrom oil combustion.
2.4.1 Fuel Substitution10'12'15'51
Fuel substitution, or the firing of "cleaner" fuel oils, can substantially reduce
emissions of a number of pollutants. Lower sulfur oils, for instance, will reduce SOX
emissions in all boilers, regardless of size or type of unit or grade of oil fired.
Particulate loading generally will be reduced when a lighter grade of oil is fired.
Nitrogen oxide emissions will be reduced by switching to either a distillate oil or a
residual oil with less nitrogen. The practice of fuel substitution, however, may be limited
by the ability of a given operation to fire a better grade of oil and by the cost and
availability of that fuel.
2.4.2 Combustion Modification8-11'15-16'20-21'27
Combustion modification includes any physical change in the boiler/burner
hardware or in boiler operation. Maintenance of the burner system, for example, is
important to assure proper atomization and subsequent minimization of any unburned
2-xxii
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combustibles. Periodic tuning is important in small units for maximum operating
efficiency and emission control, particularly of smoke and CO. Combustion
modifications, such as limited excess air firing, FGR, staged combustion and reduced
load operation, result in lowered NOX emissions in large facilities.
2.4.2.1 Particulate Matter Control.51 Control of PM emissions from residential
and commercial units is accomplished by improved burner servicing and by
incorporating appropriate equipment design changes to improve oil atomization and
combustion aerodynamics. Optimization of combustion aerodynamics using a flame
retention device, swirl, and/or recirculation is considered to be the best approach
toward achieving the triple goals of low PM, low NOX, and high thermal efficiency.
Large industrial and utility boilers are generally well-designed and well-
maintained so that soot and condensible organic compound emissions are minimized.
Particulate matter emissions are more a result of entrained fly ash in such units.
Therefore, post- combustion controls are necessary to reduce PM emissions from these
sources.
2.4.2.2 NOX Control. The formation of thermal NOX occurs in part through the
Zeldovich mechanism:
(2-1) N2 + 0 — NO + N
(2-2) N + 02 — NO + 0
(2-3) N + OH — NO + H
Reaction (2-1) is generally believed to be the rate-determining step due to its large
activation energy.44 Kinetically, thermal NOX formation is related to nitrogen (N2)
concentration, combustion temperature, and 02 concentration by the following
equation:44
(2-4) [NO] = K! exp(-k2/T) [N2] [02]1'21
where:
[ ] = mole fraction
T = temperature (°K)
t = residence time
k1; k2 = reaction rate coefficient constants
2-xxiii
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From this relationship and the Zeldovich mechanism, it can be seen that thermal
NOX formation can be controlled by four approaches: (1) reduction of peak temperature
of reaction, (2) reduction of N2 concentration, (3) reduction of 02 level, and (4) reduction
of the residence time of exposure. Typically, the N2 mole fraction in hydrocarbon-air
flames is on the order of 0.7 and is difficult to modify.44 Therefore, combustion
modification techniques to control thermal NOX in boilers have focused on reducing 02
level, peak temperature, and time of exposure at peak temperature in the primary flame
zones of the furnaces. Equation 2-4 also shows that thermal NOX formation depends
exponentially on temperature, parabolically on 02 concentration, and linearly on
residence time. Hence, temperature has a dominant effect on production of thermal
NOX.
In boilers fired on coal, crude oil, or residual oil, the control of fuel NOX is very
important in achieving the desired degree of NOX reduction since typically fuel NOX
accounts for 50 to 80 percent of the total NOX formed.52"53 Fuel nitrogen conversion to
NOX is highly dependent on the fuel-to-air ratio in the combustion zone and, in contrast
to thermal NOX formation, is relatively insensitive to small changes in combustion zone
temperature.54 In general, increased mixing of fuel and air increases nitrogen
conversion which, in turn, increases fuel NOX. Thus, to reduce fuel NOX formation, the
most common combustion modification technique is to suppress combustion air levels
below the theoretical amount required for complete combustion. The lack of 02 creates
reducing conditions that, given sufficient time at high temperatures, cause volatile fuel
nitrogen to convert to N2 rather than NO.
In the formation of both thermal and fuel NOX, all of the above reactions and
conversions do not take place at the same time, temperature, or rate. The actual
mechanisms for NOX formation in a specific situation are dependent on the quantity of
fuel bound nitrogen, if any, and the temperature and stoichiometry of the flame zone.
Although the NOX formation mechanisms are different, both thermal NOX and fuel NOX
are promoted by rapid mixing of fuel and combustion air. This rate of mixing may itself
depend on fuel characteristics such as the atomization quality of liquid fuels.55
Additionally, thermal NOX is greatly increased by increased residence time at high
2-xxiv
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temperatures, as mentioned earlier. Thus, primary combustion modification controls for
both thermal and fuel NOX typically rely on the following control approaches:
! Decrease primary flame zone 02 level:
- Decrease overall 02 level
- Control (delay) mixing of fuel and air
- Use of fuel-rich primary flame zone
! Decrease residence time at high temperatures:
- Decrease adiabatic flame temperature through dilution
- Decrease combustion intensity
- Increase flame cooling
- Decrease primary flame zone residence time
Table 2-5 shows the relationship between these control strategies and
combustion modification NOX control techniques currently in use on boilers firing fuel
oil.44
2.4.3 Post Combustion Control49'51
Post combustion control refers to removal of pollutants from combustion flue
gases. Its use is relatively rare with oil-fired boilers due to relatively high cost per mass
of pollutant removed. Some larger installations have, however, been equipped with
controls for PM, NOX, or SOX.
2.4.3.1 Particulate Control.51 Industrial and utility boilers are, generally, well-
designed and well-maintained. Hence, particulate collectors are usually needed only in
special circumstances. The use of particulate collectors with oil-firing is described
below.
Mechanical collectors, a prevalent type of control device, are primarily useful in
controlling particulates generated during soot blowing, during upset conditions, or when
a very dirty heavy oil is fired. During these situations, high efficiency cyclonic collectors
can achieve up to 85 percent control of particulate. Under normal firing conditions, or
when a clean oil is combusted, cyclonic collectors will not be nearly so effective
because of the high percentage of small particles (less than 3 micrometers in diameter)
emitted.
2-xxv
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Electrostatic precipitators (ESPs) are used in a few oil-fired power plants. Older
ESPs, usually small, remove generally 40 to 60 percent of the PM. Because of the low
ash content of the oil, greater collection efficiency may not be required. Today, new or
rebuilt ESPs have collection efficiencies of 99 percent or greater.
Scrubbing systems have been installed on oil-fired boilers, especially of late, to
control both SOX and PM. These systems can achieve S02 removal efficiencies of 90
to 95 percent and particulate control efficiencies of 50 to 60 percent.
2.4.3.2 NOX Control. The variety of flue gas treatment NOX control technologies
is nearly as great as combustion-based technologies. Although these technologies
differ greatly in cost, complexity, and effectiveness, they all involve the same basic
chemical reaction:
(2-5) NH3 + NOX — N2 + H20
In selective catalytic reduction (SCR), the reaction takes place in the presence of
a catalyst, improving performance. Non-catalytic systems rely on a direct reaction,
usually at higher temperatures, to remove NOX. Although removal efficiencies are
lower, non-catalytic systems are typically less complex and often significantly less
costly. Table 2-6 presents various catalytic and non-catalytic technologies.56
2.4.3.3 S02 Control. Commercialized post combustion flue gas desulfurization
(FGD) uses an alkaline reagent to absorb S02 in the flue gas to produce sodium or
calcium sulfate or sodium or calcium sulfite compounds. Flue gas desulfurization
technologies are categorized as wet, semi-dry, or dry depending on the state of the
reagent as it leaves the absorber vessel. These processes are either regenerable,
such that the reagent material can be treated and reused, or are nonregenerable, in
which all waste streams are de-watered and discarded. Table 2-7 summarizes
commercially available post-combustion S02 control technologies.
Wet regenerable FGD processes are attractive because they have the potential
for greater than 95 percent sulfur removal efficiency, have minimal waste-water
discharges, and produce saleable sulfur product.57 Some of the current
nonregenerable calcium-based processes can, however, produce a saleable gypsum
product.
2-xxvi
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To date, wet systems are the most commonly applied. Wet systems generally
use alkali slurries as the SOX absorbent medium and can be designed to remove
greater than 90 percent of the incoming SOX. Lime/limestone scrubbers, sodium
scrubbers, and dual alkali scrubbers are among the commercially proven wet FGD
systems. The effectiveness of these devices depends not only on control device design
but also on operating variables.
The lime and limestone scrubbing process uses a slurry of calcium oxide (CaO)
or limestone (CaC03) to absorb S02 in a wet scrubber. Control efficiencies in excess of
91 percent for lime and 94 percent for limestone over extended periods have been
demonstrated.58 The process produces a calcium sulfite and calcium sulfate mixture.
Sodium scrubbing processes generally employ a wet scrubbing solution of
sodium hydroxide (NaOH) or sodium carbonate (Na2C03) to absorb S02 from the flue
gas. Sodium scrubbers are generally applied to smaller sources because of high
reagent costs, however these systems have been installed on industrial boilers up to
125 MW (430 million Btu/hr) thermal input.1 Demonstrated S02 removal efficiencies of
up to 96.2 percent have been demonstrated.58 Because the S02 removal efficiency can
vary during load swings and process upsets, a long term mean efficiency of at least 91
percent is necessary to comply with the 90 percent NSPS reduction requirement based
on a 30-day rolling average. The operation of the scrubber is characterized by a low
liquid-to-gas ratio [1.3 to 3.4 l/m3 (10 to 25 gal/ft3)] and a sodium alkali sorbent which
has a high reactivity relative to lime or limestone sorbents. The scrubbing liquid is a
solution rather than a slurry because of the high solubility of sodium salts.
The double or dual alkali system uses a clear sodium alkali solution for S02
removal followed by a regeneration step using lime or limestone to recover the sodium
alkali and produce a calcium sulfite and sulfate sludge. Most of the effluent from the
sodium scrubber is recycled back to the scrubber, but a slipstream is withdrawn and
reacts with lime or limestone in a regeneration reactor. Performance data indicate
average S02 removal efficiencies of 90 to 96 percent.1 However, initial reports of long-
term operating histories with dual alkali scrubbing have indicated S02 control system
reliability averages of only slightly higher than 90 percent.59
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Sector
TABLE 2-1. U.S. OIL CONSUMPTION BY SECTOR IN 1990a
Oil consumption,
1012kJ(1012Btu)
Residual
Distillate13 Sum of Residual and
Distillate
Utility
Industrial
Commercial
Residential
Total for all Sectors
1201.6
(1139.4)
437.1
(414.5)
255.6
(242.4)
0.0
(0.0)
1894.4
(1796.3)
91.0
(86.3)
1245.4
(1180.9)
513.6
(487.0)
883.1
(837.4)
2733.1
(2591 .6)
1292.6
(1225.7)
1682.5
(1595.4)
769.2
(729.4)
883.1
(837.4)
4627.5
(4387.9)
"Reference 1
bFor the utility sector this value includes distillate oil (No. 2), kerosene, and jet fuel. For the other three
sectors it includes distillate oil only.
2-xxviii
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TABLE 2-2. BOILER USAGE BY SECTOR
Sector
Capacity,
MW (MMBtu/hr)
Boiler type
Application
Utility
Industrial
>29(>100)
0.29-29(10-100)
Commercial
Residential
0.1 -2.9(0.5- 10)
<0.1 (< 0.5)
Watertube
Watertube
Watertube
Watertube
Firetube
Firetube
Watertube
Firetube
Cast iron
Cast iron
Electricity generation
Electricity generation
Process steam
Space heat
Process steam
Space heat
Space heat
Space heat
Space heat
Space heat
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TABLE 2-3. TOTAL U.S. ANTHROPOGENIC EMISSIONS BY CATEGORY FOR S02,
NOX, ANDTSPIN 198933
Oil type Sector
Distillate Residential
Commercial/
Institutional
Industrial
Electric
Generation
Residual Residential
Commercial/
Institutional
Industrial
Electric
Generation
SO,
116
(128)
83
(91)
92
(101)
15
(17)
0.9
(1)
132
(146)
582
(641)
538
(593)
Emissions inventory,
MT (tons)
N0y
68
(75)
50
(55)
79
(87)
18
(20)
0
(0)
43
(47)
169
(186)
153
(169)
TSP
9
(10)
5
(5)
7
(8)
0.9
(1)
0
(0)
14
(15)
48
(53)
26
(29)
2-xxx
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TABLE 2-5. COMBUSTION MODIFICATION NOV CONTROLS EVALUATED FOR OIL-FIRED BOILERS
Control
technique
Low Excess
Air (LEA)
Staged
Combustion
(SC)
Burners Out
of Service
(BOOS)
Flue Gas
Recirculatio
n (FGR)
Description of
technique
Reduction of
combustion air
Fuel-rich firing
burners with
secondary
combustion air
ports
One or more
burners on air only.
Remainder firing
fuel rich.
Recirculation of
portion of flue gas
to burners
No. of
boilers
22 residual
oil boilers,
7 distillate
oil boilers
3 residual
oil boilers,
1 distillate
oil boiler
8 boilers
1 distillate
oil boiler,
2 residual
oil boilers
Effectiveness of control Range of application
(% NOV reduction)
Residual Distillate
oil oil
0 to 28 0 to 24 Generally excess O2
can be reduced to 2.5
% representing a 3 %
drop from baseline
20 to 50 17 to 44 70-90 % burner
stoichiometries can be
used with proper
installation of
secondary airports
10 to 30 N/A Applicable only for
boilers with minimum
of 4 burners. Best
suited for square
burner pattern with top
burner or burners out
of service. Only for
retrofit application.
1 5 to 30 58 to 73 Up to 25-30% of flue
gas recycled. Can be
implemented on all
design types.
Commercial
availability/
R&D status
Available
Technique is
applicable on
package and
field-erected
units. However,
not commercially
available for all
design types
Available.
Retrofit requires
careful selection
of BOOS pattern
and control of air
flow.
Available.
Requires
extensive
modifications to
the burner and
windbox.
Comments
Added benefits
included increase in
boiler efficiency.
Limited by increase
in CO, HC, and
smoke emissions.
Best implemented
on new units.
Retrofit is probably
not feasible for
most units,
especially
packaged ones.
Retrofit often
requires boiler de-
rating unless fuel
delivery system is
modified.
Best suited for new
units. Costly to
retrofit. Possible
flame instability at
high FGR rates.
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TABLE 2-5. COMBUSTION MODIFICATION NOV CONTROLS EVALUATED FOR OIL-FIRED BOILERS
Control
technique
Flue Gas
Recirculatio
n Plus
Staged
Combustion
Load
Reduction
(LR)
Low NOX
Burners
(LNB)
Description of
technique
Combined
techniques of FGR
and staged
combustion
Reduction of air
and fuel flow to all
burners in service
New burner
designs with
controlled air/fuel
mixing and
increased heat
dissipation
No. of
boilers
Only one
packaged
watertube
boiler
17 residual
oil-fired
boilers,
7 distillate
oil-fired
boilers
Large
number
tested in
Japan
Effectiveness of control
(% NOV reduction)
Residual
oil
25 to 53
33%
decrease
to 25%
increase
inNOx
20 to 50
Distillate
oil
73 to 77
31%
decrease
to 1 7%
increase in
NOX
20 to 50
Range of application
Max. FGR rates set at
25% for distillate oil
and 20% for residual
oil
Applicable to all boiler
types and sizes. Load
can be reduced to
25% of maximum.
New burners
described generally
applicable to all
boilers. More specific
information needed.
Commercial
availability/
R&D status
Combined
techniques are
still at
experimental
stage. Needs
more R&D.
Available now as
a retrofit
application. Better
implemented with
improved firebox
design.
Commercially
offered but not
demonstrated
Comments
Retrofit may not be
feasible. Best
implemented on
new units.
Technique not
effective when it
necessitates an
increase in excess
O2 levels. LR
possibly
implemented in new
designs as reduced
combustion
intensity (enlarged
furnace plan area).
Specific emissions
data from industrial
boilers equipped
with LNB are
lacking
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TABLE 2-5. COMBUSTION MODIFICATION NOV CONTROLS EVALUATED FOR OIL-FIRED BOILERS
Control
technique
Ammonia/
urea
Injection
Description of
technique
Injection of urea or
NH3 as a reducing
agent in the flue
gas
No. of Effectiveness of control
boilers (% NOV reduction)
Residual Distillate
oil oil
5 (4 40 to 70 40 to 70
Japanese
installations
,
1 domestic)
Range of application Commercial
availability/
R&D status
Applicable for large Commercially
package and field- offered but not
erected watertube demonstrated
boilers. May not be
feasible for fire-tube
boilers.
Comments
Elaborate NH3
injection, monitoring
and control system
required. Possible
load restrictions on
boiler and air
preheater fouling
when burning high
sulfur oil.
Reduced Air
Preheat
(RAP)
Bypass of
combustion air
preheater
2 residual 5 to 16 N/A
oil-fired
boilers
Combustion air
temperature can be
reduced to ambient
conditions (340K)
Available. Not
implemented
because of
significant loss in
thermal efficiency.
Application of this
technique on new
boilers requires
installation of
alternate heat
recovery system
(e.g., an
economizer)
-------
TABLE 2-6. POST COMBUSTION NOV REDUCTION TECHNOLOGIES56
Technique
Description
Advantages
Disadvantages
1. Urea Injection
Injection of urea into furnace
to react with NOX to form N2
and water.
- Low capital cost
- Relatively simple system
- Moderate NOX removal
(30-60%)
- Non-toxic chemical
- Typically, low energy
injection is sufficient
- Temperature dependent
- Design must consider boiler
operating conditions and
configuration
- Reduction may decline at
lower loads
2. Ammonia Injection
(Thermal-DeNOx)
Injection of ammonia into
furnace to react with NOV to
- Low operating cost
- Moderate NOX removal
(30-60%)
- Moderately high capital
costs
-Ammonia handling,
storage, vaporization, and
injection systems required
-Ammonia is a toxic
chemical
3. Air Heater SCR
(AH-SCR)
Air heater baskets replaced
with catalyst-coated baskets.
Catalyst promotes reaction of
ammonia with NOV.
- Moderate NOX removal
(40-65%)
- Moderate capital cost
- No additional ductwork or
reactor required
- Low pressure drop
- Can use urea or ammonia
- Rotating air heater assists
mixing and contact with
catalyst
- Design must address
pressure drop, maintain
heat transfer
- Due to rotation of air
heater, only 50% of catalyst
is active at any time
4. Duct SCR
A smaller version of
conventional SCR is placed in
existing ductwork.
- Moderate capital cost
- Moderate NOX removal
(30%)
- No additional ductwork
required
- Duct location unit specific
- Some pressure drop
must be accommodated
5. Activated Carbon
SCR
Activated carbon catalyst,
installed downstream of air
heater, promotes reaction of
ammonia with NOX at low
temperature.
- Active at low temperature
- High surface area reduces
reactor size
- Low cost of catalyst
- Can use urea or ammonia
- Activated carbon is a non-
hazardous material
- SOX removal as well as
NOX removal
- High pressure drop
- Not a fully commercial
technology
6. Conventional SCR
Catalyst located in flue gas
stream (usually upstream of
air heater) promotes reaction
of ammonia with NOV.
- High NOX removal (90%)
- Very high capital cost
- High operating cost
- Extensive ductwork to/from
reactor
- Large volume reactor
- Increased pressure drop
may require ID fan or larger
FDfan
- Reduced efficiency
- Ammonia sulfate removal
equipment for air heater
- Water treatment of air
heater wash
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TABLE 2-7. COMMERCIAL POST-COMBUSTION S02 CONTROLS FOR COAL
COMBUSTION SOURCES
Control
technology
Process Available
control
efficiencies
Remarks
Wet Scrubber
Spray Drying
Furnace Injection
Duct Injection
Lime/Limestone
Sodium Carbonate
Magnesium Oxide/
Hydroxide
Dual Alkali
Calcium hydroxide
slurry, vaporizes
in spray vessel
Dry calcium
carbonate/hydrate
injection in upper
furnace cavity
Dry sorbent
injection into duct,
sometimes combined
with water spray
80 - 95+% Applicable to high sulfur fuel,
Wet sludge product
80 - 98% 5 - 430 MMBtu/hr
typical application range,
High reagent costs
80 - 95+% Can be regenerated
90 - 96% Uses lime to regenerate
sodium-based scrubbing liquor
70 -90% Applicable to low and medium
sulfur fuels,
Produces dry product
25 - 50% Commercialized in Europe,
Several U.S. demonstration
projects underway
25 - 50+% Several R&D and demonstration
projects underway,
Not yet commercially available
in the U.S.
2-xxxvii
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REFERENCES FOR CHAPTER 2
1. State Energy Data Reports, Consumption Estimates, 1960-1990,,
DOE/EIA-0124(90), Energy Information Agency, May 1992.
2. Fossil Fuel Fired Industrial Boilers - Background Information Volume 1: Chapters
1-9, EPA-450/3-82-006a, U.S. Environmental Protection Agency, March 1982.
3. Emissions Assessment of Conventional Stationary Combustion Systems:
Volume IV Commercial/Institutional Combustion Sources, EPA-600/7-81-003b,
U.S. Environmental Protection Agency, January 1981.
4. Population and Characteristics of Industrial/Commercial Boilers in the U.S., EPA-
600/7-79-178a, U.S. Environmental Protection Agency, August 1979.
5. Industrial Boiler Co., Inc., Bulletin No. F2050 990-3.0.
6. NOX Emission Control for Boilers and Process Heaters - Training Manual,
Southern California Edison, 1991.
7. Spaite, P.W. and T.W. Devitt, Overview of Pollution from Combustion of Fossil
Fuels in Boilers of the United States, EPA-600/7-79-233, October 1979.
8. Smith, W.S., Atmospheric Emissions from Fuel Oil Combustion: An Inventory
Guide, 999-AP-2, U.S. Environmental Protection Agency, Washington, DC,
November 1962.
9. Danielson, J.A. (ed.), Air Pollution Engineering Manual, Second Edition, AP-40,
U.S. Environmental Protection Agency, Research Triangle Park, NC, 1973. Out
of Print.
10. Lew, A., et al., A Field Investigation of Emissions from Fuel Oil Combustion for
Space Heating, API Bulletin 4099, Battelle Columbus Laboratories, Columbia,
OH, November 1971.
11. Barrett, R.E., et al., Field Investigation of Emissions from Combustion Equipment
for Space Heating, EPA-R2-73-084a, U.S. Environmental Protection Agency,
Research Triangle Park, NC, June 1973.
12. Cato, G.A., et al., Field Testing: Application of Combustion Modifications To
Control Pollutant Emissions from Industrial Boilers - Phase I,
EPA-650/2-74-078a, U.S. Environmental Protection Agency, Washington, DC,
October 1974.
2-xxxviii
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13. Cato, G.A., et al.. Field Testing: Application of Combustion Modifications To
Control Pollutant Emissions from Industrial Boilers - Phase II, EPA-600/
2-76-086a, U.S. Environmental Protection Agency, Washington, DC, April 1976.
14. Particulate Emission Control Systems for Oil Fired Boilers, EPA-450/3-74- 063,
U.S. Environmental Protection Agency, Research Triangle Park, NC, December
1974.'
15. Bartok, W., et al., Systematic Field Study of NOx Emission Control Methods for
Utility Boilers, APTD-1163, U.S. Environmental Protection Agency, Research
Triangle Park, NC, December 1971.
16. Crawford, A.R., et al., Field Testing: Application of Combustion Modifications To
Control NOx Emissions from Utility Boilers, EPA-650/2-74-066, U.S.
Environmental Protection Agency, Washington, DC, June 1974.
17. Deffner, J.F., et al., Evaluation of Gulf Econojet Equipment with Respect to Air
Conservation, Report No. 731RC044, Gulf Research and Development
Company, Pittsburgh, PA, December 18, 1972.
18. Blakeslee, C.E. and H. E. Burbach, "Controlling NOx Emissions from Steam
Generators", Journal of the Air Pollution Control Association, 23:37-42, January
1973.
19. Siegmund, C.W., "Will Desulfurized Fuel Oils Help?", American Society of
Heating, Refrigerating and Air Conditioning Engineers Journal, 11:29-33, April
1969.
20. Govan, F.A., et al., "Relationships of Particulate Emissions Versus Partial to Full
Load Operations for Utility-sized Boilers", Proceedings of Third Annual Industrial
Air Pollution Control Conference, Knoxville, TN, March 29-30, 1973.
21. Hall, R.E., et al., A Study of Air Pollutant Emissions from Residential Heating
Systems, EPA-650/2-74-003, U.S. Environmental Protection Agency,
Washington, DC, January 1974.
22. Milligan, R.J., et al.. Review of. NOx Emission Factors- for Stationary Fossil Fuel
Combustion Sources, EPA-450/4-79-021, U.S. Environmental Protection
Agency, Research Triangle Park, NC, September 1979.
23. Suprenant, N.F., et al., Emissions Assessment of Conventional Stationary
Combustion Systems, Volume I: Gas and Oil Fired Residential Heating Sources,
EPA-600/7-79-029b, U.S. Environmental Protection Agency, Washington, DC,
May 1979.
2-xxxix
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24. Shih, C.C., et al.. Emissions Assessment of Conventional Stationary Combustion
Systems, Volume III: External Combustion Sources for Electricity Generation,
EPA Contract No. 68-02-2197, TRW, Inc., Redondo Beach, CA, November
1980.
25. Suprenant, N.F., et al., Emissions Assessment of Conventional Stationary
Combustion System, Volume IV: Commercial Institutional Combustion Sources,
EPA Contract No. 68-02-2197, GCA Corporation, Bedford, MA, October 1980.
26. Suprenant, N.F., et al., Emissions Assessment of Conventional Stationary
Combustion Systems, Volume V: Industrial Combustion Sources, EPA Contract
No. 68-02-2197, GCA Corporation, Bedford, MA, October 1980.
27. Lim, K.J., et al., Technology Assessment Report for Industrial Boiler
Applications: NOx Combustion Modification, EPA-600/7-79-178f, U.S.
Environmental Protection Agency, Washington, DC, December 1979.
28. Emission Test Reports, Docket No. OAQPS-78-1, Category II-I-257 through 265,
Office Of Air Quality Planning And Standards, U.S. Environmental Protection
Agency, Research Triangle Park, NC, 1972 through 1974.
29. Primary Sulfate Emissions from Coal and Oil Combustion, EPA Contract No.
68-02-3138, TRW, Inc., Redondo Beach, CA, February 1980.
30. Leavitt, C., et al., Environmental Assessment of an Oil Fired Controlled Utility
Boiler, EPA-600/7-80-087, U.S. Environmental Protection Agency, Washington,
DC, April 1980.
31. Carter, W.A. and R. J. Tidona, Thirty-day Field Tests of Industrial Boilers: Site 2
- Residual-oil-fired Boiler, EPA-600/7-80-085b, U.S. Environmental Protection
Agency, Washington, DC, April 1980.
32. Pershing, D.W., et al., Influence of Design Variables on the Production of
Thermal and Fuel NO from Residual Oil and Coal Combustion, Air:
Control of NOX and SOx Emissions, New York, American Institute of
Chemical Engineers, 1975.
33. The 1985 NAPAP Emissions Inventory (Version 2): Development of the
Annual Data and Modelers' Tapes, EPA-600/7-89-012a, U.S.
Environmental Protection Agency, November 1989.
34. National Primary and Secondary Ambient Air Quality Standards, U.S.
Environmental Protecion Agency, Code of Federal Regulations, Title 40, Part 50,
U.S. Government Printing Office, Washington, DC, 1991.
2-xl
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35. Clayton, R., et al., N20 Field Study. EPA-600/2-89-006, U.S. Environmental
Protection Agency, Research Triangle Park, NC, February 1989.
36. Evaluation of Fuel-Based Additives for N20 and Air Toxic Control in Fluidized
Bed Combustion Boilers, EPRI Contract No. RP3197-02, Acurex Report No. FR-
91-101-/ESD, (Draft Report) Acurex Environmental, Mountain View, CA, June
17, 1991.
37. Particulate Polycyclic Organic Matter, Nation Academy of Sciences, Washington,
DC, 1972.
38. Vapor Phase Organic Pollutants -- Volatile Hydrocarbons and Oxidation
Products, National Academy of Sciences, Washington, DC, 1976.
39. Knierien, H., A Theoretical Study of PCB Emissions from Stationary Sources,
EPA-600/7-76-028, U.S. Environmental Protection Agency, Research Triangle
Park, NC, September 1976.
40. Estimating Air Toxics Emissions From Coal and Oil Combustion Sources, EPA-
450/2-89-001, U.S. U.S. Environmental Protection Agency, Research Triangle
Park, NC, April 1989.
41. Hagebrauck, R.P., D.J. Von Lehmden, and J.E. Meeker, "Emissions of
Polynuclear Hydrocarbons and Other Pollutants from Heat-Generation and
Incineration Process", J. Air Pollution Control Assoc, 14: 267-278, 1964.
42. Rogozen, M.B., et al., Formaldehyde: A Survey of Airborne Concentration and
Sources, California Air Resources Board, ARB report no. ARB/R-84-231, 1984.
43. Clean Air Act Amendments of 1990, Conference Report To Accompany S. 1603,
Report 101-952, U.S. Government Printing Office, Washington, DC, October 26,
1990.
44. Lim, K.J., et al., Industrial Boiler Combustion Modification NOx Controls - Volume
I Environmental Assessment, EPA-600/7-81-126a, U.S. EPA, July 1981.
45. Klein, D.H., et al., "Pathways of Thirty-Seven Trace Elements Through Coal-
Fired Power Plants", Environ. Sci. Technol., 9: 973-979, 1975.
46. Coles, D.G., et al., "Chemical Studies of Stack Fly Ash From a Coal-Fired Power
Plant", Environ. Sci. Technol., 13: 455-459, 1979.
47. Baig, S., etal.. Conventional Combustion Environmental Assessment, EPA
Contract No. 68-02-3138, U.S. Environmental Protection Agency, Research
Triangle Park, NC, 1981.
2-xli
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48. CFR 40, Part 60, Subparts Da, Db, DC, July 1, 1991.
49. Flue Gas Desulfuhzation: Installations and Operations, PB 257721, National
Technical Information Service, Springfield, VA, September 1974.
50. Proceedings: Flue Gas Desulfuhzation Symposium -1973, EPA-650/2-73-038,
U.S. Environmental Protection Agency, Washington, DC, December 1973.
51. Offen, G.R., et al.. Control of Particulate Matter from Oil Burners and Boilers,
EPA-450/3-76-005, U.S. Environmental Protection Agency, Research Triangle
Park, NC, April 1976.
52. Pohl, J.H. and A.F. Sarofim, Devolatilization and Oxidation of Coal Nitrogen
(presented at the 16th International Symposium on Combustion), August 1976.
53. Pershing, D.W. and J. Wendt, Relative Contribution of Volatile and Char Nitrogen
to NOx Emissions From Pulverized Coal Flames, Industrial Engineering
Chemical Proceedings, Design and Development, 1979.
54. Pershing, D.W., Nitrogen Oxide Formation in Pulverized Coal Flames, Ph.D.
Dissertation, University of Arizona, 1976.
55. Nutcher, P.B., High Technology Low NOx Burner Systems for Fired Heaters and
Steam Generators, Process Combustion Corp., Pittsburgh, PA. Presented at the
Pacific Coast Oil Show and Conference, Los Angeles, CA, November 1982.
56. Mansour. M.N.. et al.. Integrated NOx Reduction Plan to Meet Staged SCAQMD
Requirements for Steam Electric Power Plants, Proceedings of the 53rd
American Power Conference, 1991.
57. South, D.W., et al., Technologies and Other Measures For Controlling
Emissions: Performance, Costs, and Applicability, Acidic Deposition: State of
Science and Technology, Volume IV, Report 25, National Acid Precipitation
Assessment Program, U.S. Government Printing Office, Washington, DC,
December 1990.
58. Pohl, J.H. and A.F. Sarofim, Devolatilization and Oxidation of Coal Nitrogen
(presented at the 16th International Symposium on Combustion), August 1976.
59. EPA Industrial Boiler FGD Survey: First Quarter 1979. EPA-600/7-79-067b, U.S.
Environmental Protection Agency, April 1979.
60. Seeker, W.R., et al., Municipal Waste Combustion Study: Comustion
Control of MSW Combustors to Minimize Emissions of Trace Organics,
EPA-543-SW-87-021c, U.S. Environmental Protection Agency,
Washington, DC, May 1987.
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3. GENERAL EMISSION DATA REVIEW AND ANALYSIS PROCEDURES
3.1 CRITERIA POLLUTANTS
3.1.1 Literature Search
An extensive literature search was conducted during this revision to identify
sources of criteria and non-criteria pollutant emission data associated with fuel oil-fired
boilers. This search included a broad range of relevant EPA reports as well as the
archive files from prior AP-42 revisions, and numerous additional reports and contacts
with testing groups, regulatory agencies, and trade groups. On-line computerized
databases were also accessed to gather information on sources of emissions data.
The details of the literature search are summarized in Table 3-1.
3.1.2 Literature Evaluation
A large number of references were identified and compiled through the literature
search. Subsequently, each item in this large body of literature was screened for data
on criteria pollutant emissions and/or information on control technology pertaining to
NOX, S02, and PM emissions. Checklists were developed to document this scanning
procedure. These checklists can be found in the background files for this update to AP-
42. Thereafter, references with data on criteria pollutants were subjected to a rigorous
data evaluation to determine if they contained candidate data for use in developing
uncontrolled emission factors. References relating only to control technology
information were used in characterizing control efficiencies and, as such, were not
subjected to any data evaluation procedure.
The following general criteria were used in evaluating literature with criteria
pollutant data:
1. Emissions data must be from a well-documented reference; and
3-28
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2. The report must contain sufficient data to evaluate the testing procedures
and source operating conditions.
These criteria were used in a thorough review of the reports, documents, and
information to produce a final set of reference materials. The data contained in this
final set of references were then subjected to a thorough quality and quantity evaluation
to determine their suitability for use for developing emission factors. Checklists were
employed to facilitate and document this evaluation. The completed checklists were
placed in the background files for this update to AP-42.
Data with the following characteristics were always excluded from further
consideration:
1. Test series averages reported in units that cannot be converted to the
selected reporting units;
2. Test series representing incompatible test methods (e.g., comparison of
EPA Method 5 front-half with EPA Method 5 front- and back-half);
3. Test series of controlled emissions for which the control device was not
specified;
4. Test series in which the source process was not clearly identified and
described; and
5. Test series in which it is not clear whether the emissions were measured
before or after the control device.
Data sets that were not excluded were assigned a quality rating. The rating
system used was that specified in "Technical Procedures for Developing AP-42
Emission Factors and Preparing AP-42 Sections".8 The data were rated as follows:
A - Multiple tests performed on the same source using sound methodology
and reported in enough detail for adequate validation. These tests are not
necessarily EPA reference method tests, although such reference
methods are preferred and are certainly to be used as a guide.
B - Tests that were performed by a generally sound methodology but lacked
enough detail for adequate validation.
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C - Tests that were based on an untested or new methodology or that lacked
a significant amount of background data.
D - Tests that were based on a generally unacceptable method but may
provide an order-of-magnitude value for the source.
The following criteria were used to evaluate source test reports for sound
methodology and adequate detail:
1. Source operation. The manner in which the source was operated is well
documented in the report. The source was operating within typical
parameters during the test.
2. Sampling procedures. The sampling procedures conformed to generally
acceptable methodology. If actual procedures deviated from accepted
methods, the deviations are well documented. When this occurred, an
evaluation was made of the extent such alternative procedures could
influence the test results.
3. Sampling and process data. Adequate sampling and process data are
documented in the report. Many variations can occur unnoticed and
without warning during testing. Such variations can induce wide
deviations in sampling results. If a large spread between test results
could not be explained by information contained in the test report, the
data were considered suspect and were given a lower rating.
4. Analysis and calculations. The test reports contain original raw data
sheets. The nomenclature and equations used were compared to those
(if any) specified by EPA to establish equivalency. The depth of review of
the calculations was dictated by the reviewer's confidence in the ability
and conscientiousness of the tester, which in turn was based on factors
such as consistency of results and completeness of other areas of the test
report.
3.1.3 Emission Factor Quality Rating
In each AP-42 section, tables of emission factors are presented for each
pollutant emitted from each of the emission points associated with the source. The
reliability or quality of each of these emission factors is indicated in the tables by an
overall Emission Factor Quality Rating ranging from A (excellent) to E (poor). These
ratings incorporate the results of the above quality and quantity evaluations on the data
3-30
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sets used to calculate the final emission factors. The overall Emission Factor Quality
Ratings are described as follows:
A--Excellent: Developed only from A-rated test data taken from many randomly
chosen facilities in the industry population. The source category is specific
enough so that variability within the source category population may be
minimized.
IB-Above average: Developed only from A-rated test data from a reasonable
number of facilities. Although no specific bias is evident, it is not clear if the
facilities tested represent a random sample of the industries. As in the A-rating,
the source category is specific enough so that variability within the source
category population may be minimized.
C-Average: Developed only from A- and B-rated test data from a reasonable
number of facilities. Although no specific bias is evident, it is not clear if the
facilities tested represent a random sample of the industry. As in the A-rating,
the source category is specific enough so that variability within the source
category population may be minimized.
D--Below average: The emission factor was developed only from A- and B-rated
test data from a small number of facilities, and there is reason to suspect that
these facilities do not represent a random sample of the industry. There also
may be evidence of variability within the source category population. Any
limitations on the use of the emission factor are footnoted in the emissions factor
table.
E--Poor: The emission factor was developed from C- and D-rated test data, and
there is reason to suspect that the facilities tested do not represent a random
sample of the industry.. There also may be evidence of variability within the
source category population. Any limitations on the use of these factors are
always clearly noted.
The use of these criteria is somewhat subjective and depends to an extent on
the individual reviewer. Details of the rating of each candidate emission factor are
provided in Chapter 4 of this report.
3.2 SPECIATED VOCs
3.2.1 Literature Search
An extensive literature search was conducted during this revision to identify
sources of speciated VOC emissions data associated with fuel oil-fired boilers. Some
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specific areas of search include Tennessee Valley Authority, Electric Power Research
Institute (EPRI)/PISCES, EPA/Air and Waste Management (A&WMA) Air Toxic
Symposiums, and Toxic Air Pollutants: State and Local Regulatory Strategies 1989.
3.2.2 Literature Evaluation
Until recently, little concern existed for VOC speciation on stationary external
combustion sources. Therefore, available data for VOC speciation were very sparse
and inadequate, limiting this data evaluation to EPA's Office of Air Quality Planning and
Standards (OAQPS) databases: the VOC/PM Speciation Data System (SPECIATE)
and the Crosswalk Air Toxic Emission Factor Database (XATEF), and their references.
3.2.3 Data and Emission Factor Quality Rating
The ratings of emission factors in SPECIATE and XATEF should not be used
without first reviewing primary sources of numerical data against the criteria presented
in Chapter 3.1. The quality of the data is insufficient to satisfy the requirements for
assignment of an emission factor; therefore, the data is unratable or, at best, E-rated.
3.3 AIR TOXICS
3.3.1 Literature Search
A separate literature search was conducted for hazardous air pollutants (HAPs)
since this category was not included in prior AP-42 revisions. The HAPs data base is
expanding rapidly as a result of recent regulations. The prior data base is very sparse
and largely based on obsolete protocols. Many of the data identified and evaluated
were not of suitable quality for developing emission factors and were, therefore,
eliminated for use in this update following the criteria outlined in Section 3.1.
A literature search was conducted using the Dialog Information Retrieval
Service. This is a broad-based data retrieval system that has access to over 400 data
bases. Specifically for the air toxics search, six data bases were queried by key words
relating to the processes and chemicals of concern. The data bases accessed were:
National Technical Information Service (NTIS), COMPENDEX PLUS, POLLUTION
ABSTRACT, CONFERENCE PAPERS, ENERGY SCIENCE & TECHNOLOGY, and
EPRI. The list of literature generated from the search was evaluated for applicability
and the relevant documents were obtained.
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Searches of the EPA's air toxics data bases were also performed. These data
bases include the XATEF and the SPECIATE databases, and the Air Clearing House
for Inventory and Emission Factors (CHIEF) CD ROM which contains additional data in
conjunction with XATEF and SPECIATE. The computer searches were performed by
source classification code (SCC) for all boiler sizes and types that combust oil. The
reference numbers were recorded for each of the "hits" and these references were
obtained for review.
Various air pollution control districts (APCDs) located in California were
contacted to obtain air toxics data collected under the California Assembly Bill 2588, the
Air Toxics "Hot Spots" Information and Assessment Act of 1987. This bill requires
reporting of emissions of a specified list of air toxic compounds. The following APCDs
were contacted by phone and with a written information request: Bay Area, South
Coast, Fresno County, North Coast Unified, Sacramento Metropolitan, San Joaquin
County, Ventura County, Calaveras County, Lake County, Lassen County, Santa
Barbara, San Diego, Kern County, and the California Air Resources Board.
Several industry and non-agency sources were also contacted in order to obtain
source test data for development of emission factors. These include the Western
States Petroleum Association (WSPA), the Canadian Electrical Association (CEA), and
the Ontario Ministry of the Environment.
3.3.2 Literature Evaluation
The references obtained from the literature search were evaluated for their
applicability for generating emission factors. Table 3-2 summarizes the data sources
and indicates which sources were used in generating the emission factors. The table
contains a reference number which corresponds to the list of references provided at the
end of this section. The references are evaluated and discussed in greater detail in
Section 4.3.1. The criteria used to perform this evaluation are discussed in detail in
Section 3.3.3.
3.3.3 Data and Emission Factor Quality Rating Criteria
Emissions data used to calculate emission factors were obtained from many
sources, such as published technical papers and reports, documented emissions test
results, and regulatory agencies (such as local APCDs). The quality of these data must
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be evaluated in order to determine how well the calculated emission factors represent
the emissions of an entire source category. Data sources may vary from single source
test runs to ranges of minimum and maximum values for a particular source. Some
data must be eliminated all together due to their format or lack of documentation.
Factors such as the precision and accuracy of the sampling and analytical methods and
the operating and design specifications of the unit being tested are key in the evaluation
of data viability. The key factors for data evaluation and rating were essentially the
same as detailed for criteria pollutants in Section 3.1.
The first step in evaluating a data report was to determine whether the source is
a primary or secondary source. A primary source is that which reports the actual
source test results while a secondary source is one that references a data report. Many
of the sources referenced by XATEF, SPECIATE, and the CD ROM are secondary,
tertiary, etc. sources. Preferably, only primary sources are used in the development of
emission factors.
The primary source reports are evaluated to determine if sufficient information is
included on the device of interest and on any abatement equipment associated with the
device. General design parameters such as boiler size, firing configuration, atypical
design parameters, fuel type, operating parameters during the test, (e.g., load), are all
required in order to evaluate the quality of the data. Data on the type and number of
samples, sampling and analytical methods used, sampling locations, quality control
samples and procedures, modifications to methods, fuel composition and feed rates,
etc. are also needed. Sufficient documentation to determine how the data were
reduced and how emissions estimates were made are required. This documentation
should include sample calculations, assumptions, correction factors, etc. Equivalent
information for the emission control device(s) must also be included.
When primary data could not be obtained in the time frame of this initial update,
secondary sources were evaluated to determine the representativeness of the emission
factors to a source category. A judgement of the quality of the primary data analysis
was made in this case, which automatically warrants a lower quality rating for the
emission factor. The secondary sources can potentially provide at least an order of
magnitude estimate of emissions.
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3.4 N20
3.4.1 Literature Search
An extensive literature search was conducted during this revision to identify
sources of N20 emissions data associated with fuel oil-fired boilers. Some specific
resources searched included the European N20 Workshop, EPA/Air and Energy
Engineering Research Laboratory, AWMA, and the journals Combustion and Flame
and Journal of Geophysical Research.
3.4.2 Literature Evaluation
The literature evaluation criteria were lowered for N20 to allow the inclusion of
sufficient data to calculate emission factors. Data were evaluated even if they failed
one or more questions on the test report exclusion criteria checklist described in
Section 3.1.2. This treatment was necessitated by the sparseness of the data base
resulting from the development of a protocol only since 1988.
3.4.3 Data and Emission Factor Quality Rating
Data obtained through the literature search, except that derived from on-line N20
analysis with gas chromatography/electron capture detection (GC/ECD), were rated C
or poorer because the data were based on untested or new methodology that lacked
sufficient background data. A problem has been identified with previous grab sampling
techniques to measure N20 emissions from fuel oil combustion. Storing combustion
products in grab samples containing S02, NOX, and water for periods as short as one
hour can lead to the formation of several hundred parts per million of N20 where none
originally existed. Some improved methodologies for N20 sampling and analysis and
their relative effects on data quality ratings are as follows:
1. On-line N20 analysis with GC/ECD (the preferred method);
2. Grab samples;
a. Removing H20: drying the sample reduces the most
important reactant, but may not entirely eliminate N20
formation;
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b. Removing S02: scrubbing the sample through NaOH
solution;
c. A combination of a and b above (the second method
preference).
The N20 emission data for residual oil-fired utility boilers came from full-scale
facilities and were rated B quality. The data obtained for distillate oil-fired boilers came
from two small pilot-scale systems and were assigned a B quality rating. These data
were obtained with on-line GC/ECD N20 analysis. The emission factors for residual
and distillate oil were assigned a D rating, because the data were taken from small pilot
scale systems or because the test data were from a small number of facilities and do
not represent a cross-section of the industry.
3.5 FUGITIVE EMISSIONS
Fugitive emissions have not historically been covered in Chapter 1 of AP-42.
Chapter 4 of AP-42 contains emission factors for evaporative losses from petroleum
storage facilities and will continue to be the source of such data. Fugitive particulate
emissions are very low from oil-fired boilers and only result from ash liberated during
maintenance activities. These ash deposits are usually removed during a boiler wash
(in which most of the deposits are removed in a liquid stream). Therefore, fugitive
particulate emissions from these facilities are minimal. Particulate matter fugitive
emission factors from these operations can be developed using the procedures in AP-
42 Chapter 11.
A literature search was conducted to quantify fugitive emissions from leaking
seals and fittings that would be present in the fuel feed system for oil-fired boilers.
These sources include valves, pumps, flanges, sampling connections, and open-end
lines. The literature evaluation verified the conclusions of previous attempts at
determining emission factors for VOCs in the Synthetic Organic Chemical
Manufacturing Industry (SOCMI). During the establishment of proposed standards for
fugitive VOC emissions from SOCMI, EPA determined that (1) the only quality emission
factor data were generated during a study of 13 petroleum refineries for EPA and (2)
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the best data for percent leaking of each equipment type resulted from an EPA study of
leak frequency in the SOCMI.
Data from the primary reference above were subjectively rated B quality per the
general guidelines previously described. Because of the complexity of calculating new
emission factors for fugitive emissions, the remainder of the references were not used.
3.6 PARTICLE SIZE DISTRIBUTION
3.6.1 Literature Search8
The literature search emphasized filling the perceived gaps in the previous
updates. Future updates to AP-42 are expected to report PM-10 emissions as the sum
of the in-stack filterable particulate and the organic and inorganic condensible
particulate matter (CPM). Upon review of the previous AP-42 update of particulate
sizing emission data, the largest gap appeared to be the lack of CPM data.
The background files for the previous AP-42 update were reviewed. A Dialog
Information Retreival System search was conducted, focussing on reports since 1980.
Based on the results of the Dialog search, NTIS documents, EPA reports, and
conference proceedings were ordered and journal articles were collected. Conference
symposia that were searched included the Eighth and Ninth Particulate Control
Symposia and the AWMA annual conferences for 1988 through 1991.
The following PM-10 "gap filling" documents were examined:
"PM-10 Emission Factor Listing Developed by Technology Transfer"
(EPA-450/4-89-022): The factors applicable to sections 1.1, 1.3, and 1.7
all came from AP-42. The factor for a bituminous coal commercial facility
assumes that 52% of particulate is < 10 um.
"Gap Filling PM-10 Emission Factors for Selected Open Area Dust
Sources" (EPA-450/88-003): Not applicable to stationary source
combustion.
"Generalized Particle Size Distributions for Use in Preparing Size Specific
Particulate Emission Inventories" (EPA-450/4-86-013): Lists the average
collection efficiencies of various particulate control devices for different
size fractions. This was the source of the overall collection efficiency
estimates for the 1986 PM-10 update of AP-42 Chapter 1.
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The following regional EPA offices and State and regional air pollution control
boards were contacted:
! EPA Region 2
! EPA Region 3
! EPA Region 4
! EPA Region 5
! California Air Resources Board: Stationary Sources Division, Monitoring
and Laboratory Division, and the Compliance Division
! Illinois Air Pollution Control
! New York Air Pollution Control
! New Jersey Air Pollution Control
! Bay Area Air Quality Management District (CA)
! Kern County Air Pollution Control District (CA)
! Stanislaus County Air Pollution Control District (CA)
! San Joaquin County Air Pollution Control District (CA)
The primary source of the particulate size distribution data for the 1986 AP-42
update was the Fine Particulate Emissions Information System (FPEIS). The FPEIS
has not been updated since the printouts obtained during the 1986 AP-42 update. The
printouts used for the previous update were available in the background files.
The EPA/OAQPS Emissions Monitoring Branch was contacted for test data from
method development studies for EPA Method 202.
Contacts were also made with EPRI, Wheelabrator Air Pollution Control,
Southern Research Institute, and Entropy Environmentalists, Inc.
3.6.2 Literature Evaluation
The previous update was reviewed and evaluated. The size distribution data
were evaluated by spot-checking the tabulated results against the original FPEIS
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printouts. If, during the literature search, the original test report was obtained that
corresponded to a particular FPEIS printout, the data were compared. The objective of
the review was to ensure that the data collected in the 1986 update were ranked and
used appropriately.
The 1986 update was also evaluated with respect to the development of
emission factors from the particle size distribution data.
The original FPEIS printouts were also examined. There were two objectives in
the reevaluation of the FPEIS printouts:
(1) To ensure that only filterable particulate matter was included in the
cumulative percent mass results; and
(2) To search for impinger results to provide CPM emission data.
New literature was evaluated based on the use of appropriate sampling methods
and documentation of sufficient process information.
3.6.3 Data Quality Ranking
Data were reviewed and ranked according to the criteria described in Section 3.1
and the data evaluation criteria presented for the previous update. Data quality was
assessed based on the particle sizing and/or PM-10 measurement method used and
the availability of sampling and process data.
For particulate sizing and filterable PM-10 data, the following criteria were used:
A - Particle sizing tests performed by cascade impactors or PM-10
measurements performed via Method 201 or 201 A. The test information
must provide enough detail for adequate validation and the isokinetics
must fall between 90 and 110 percent.
B - Particle sizing tests performed via SASS trains if the sampling flow rate
isokinetic value was reported and sufficient operating data was used.
Cascade impactor data or Method 201 or 201A data if isokinetics not
reported or if isokinetics not within the 90 to 110 percent range.
C - SASS train data if the isokinetics were not reported or if the isokinetics did
not fall within the 90 to 110 percent range.
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D - Test results based on a generally unaccepted particulate sizing method,
such as polarized light microscopy.
Although cascade impactors are generally considered the best available method
for measuring particulate size distributions, errors in segregating specific sizes of
combustion particles arise from the following:
! Particle bounce and re-entrainment
! Diffusive deposition of fine particles
! Deposition of condensible/adsorbable gases
! Losses to the impactor walls
The effects of such errors are described in Reference 10.
The ranking of data for CPM was based primarily on the methodology employed
in the testing. Most CPM source tests have been conducted using the back-half of an
EPA Method 5, EPA Method 17 or South Coast Methods 5.2 or 5.3 trains. However,
these test methods do not require an N2 purge of the impingers. Without the N2 purge,
dissolved S02 remains in the impingers and is included in the inorganic CPM results.
This type of CPM data is considered very low-quality.9 In contrast, Method 202 includes
a one-hour N2 purge of the impingers immediately after sampling to remove dissolved
S02. Therefore, Method 202 CPM data should be ranked higher than Method 5 or
Method 17 CPM data, even though Method 202 is a relatively new method. The
following rankings were selected for CPM data:
A - CPM tests performed via Method 202. The test information must provide
enough detail for adequate validation and the isokinetics must fall
between 90 and 110 percent.
B - CPM tests performed via Method 202 but isokinetics not reported or
isokinetics not within the 90 to 110 percent range. CPM tests performed
via Method 5 or Method 17 or another acceptable EPA Method that does
not include an impinger N2 purge, if the isokinetics were within the 90 to
110 percent range.
C - CPM tests performed via Method 5 or Method 17 or another acceptable
EPA method that does not include an impinger N2 purge, if the isokinetics
were not reported or not within the 90 to 110 percent range.
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D - Test results based on a generally unaccepted CPM method.
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TABLE 3-1. LITERATURE SEARCH/CONSULTATION RECORD
Literature type
New baseline
data
NOX control
information
Particulate
control
information
SOX control
information
(A) "Minimum" list given in the task order
1. AP-42 files /
2. ESD Files/NSPS /
Background Information
Documents
3. CTC publications none
4. ORD reports /
5. NTIS /
none
none
(B) Other sources
1.EPRI
2. Contractor in-house
documents
3. American Petroleum
Institute
none
none
none
none
none
none
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TABLE 3-2. EVALUATION OF REFERENCES
Reference
1
2
3
4
5
6
7
Evaluation
Not a primary reference; however, data quality is sufficient to determine emission
estimates.
Emission factors presented are of sufficient quality.
Not a primary reference, however, data of sufficient quality.
Not a primary reference, however, data of sufficient quality.
Not a primary reference; however, data are of sufficient quality.
Not a primary reference; however, some data presented of sufficient quality.
Not a primary reference; however, data of sufficient quality.
Parameter of Interest
POM
Metals
Cr
HCOH
Metals, POM, HCOH
Metals
Mn
-------
CHAPTER 3 REFERENCES
1. Brooks, G.W., M.B. Stockton, K. Kuhn, and G.D. Rives, Radian Corporation,
Locating and Estimating Air Emission from Source of Polvcvclic Organic Matter
(POM), EPA-450/4-84-007p, U.S. Environmental Protection Agency, Research
Triangle Park, NC, May 1988.
2. Leavitt, C., K. Arledge, C. Shih, R. Orsini, W. Hamersma, R. Maddalone, R.
Beimer, G. Richard, M. Yamada, Environmental Assessment of Coal- and Oil-
Firing in a Controlled Industrial Boiler: Volume I, II, III. Comprehensive
Assessment and Appendices, EPA-600/7-78-164abc, U.S. Environmental
Protection Agency, Research Triangle Park, NC, August 1978.
3. Locating and Estimating Air Emissions from Sources of Chromium, EPA-450/4-
84-007g, U.S. Environmental Protection Agency, Research Triangle Park, NC,
July 1984.
4. Locating and Estimating Air Emissions From Sources of Formaldehyde
(Revised), EPA-450/4-91-012, Emission Inventory Branch Technical Support
Division, U.S. Environmental Protection Agency, Research Triangle Park, NC,
1991.
5. Estimating Air Toxic Emissions from Coal and Oil Combustion Sources, EPA-
450/2-89-001, U.S. Environmental Protection Agency, Research Triangle Park,
NC, April 1989.
6. Surprenant, N.F., et. al., Emissions Assessment of conventional Stationary
Combustion Systems: Volume V: Industrial Combustion Sources, EPA-600/7-
81-003c, U.S. Environmental Protection Agency, Research Triangle Park, NC,
1981.
7. Locating and Estimating Air Emissions from Sources of Manganese, EPA-450/4-
84-007h, U.S. Environmental Protection Agency, Research Triangle Park, NC,
September 1985.
8. Technical Procedures for Developing AP-42 Emission Factors and
Preparing AP-42 Sections, Draft Report, U.S. Environmental Protection
Agency, Research Triangle Park, NC, March 1992.
9. Private communication with Ron Meyers, U.S. Environmental Protection
Agency, March 24, 1992.
10. Ondov, John M., "Cascade Impactors in the Chemical and Physical
Characterization of Coal-Combustion Aerosol Particles", Chapter 25 of
Fossil Fuels Utilization: Environmental Concerns, 1986.
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4. EMISSION FACTOR DEVELOPMENT
This chapter describes the test data and methodology used to develop pollutant
emission factors for the fuel oil combustion category.
4.1 CRITERIA POLLUTANTS
4.1.1 Review of Previous AP-42 Data
A review of the 1986 version of Section 1.3 was conducted by spot checking the
quality of existing emission factors. This was done by selecting primary data references
from the section Background File and recalculating emission factors. The results of
these spot checks are summarized in Table 4-1.
In almost all cases, the results of spot checks indicated that existing emission
factors were accurate. Spot checks also revealed that, in general, ample A-rated data
were available for the criteria pollutants. However, the S03 emission factor in the 1986
Section 1.3 was found to be incorrect and was changed as described in Section 4.1.3.
4.1.2 Review of New Baseline Data
A total of 60 references were documented and reviewed during the literature
search. These references are listed in the checklists added to the Background File for
this update to AP-42. The original group of 60 documents was reduced to a set of
rated references utilizing the criteria outlined in Chapter 3. The following is a discussion
of the data contained in each of the rated references.
References 1 -3
These references document the multi-media emission tests conducted on Boiler No. 4
of the Firestone Tire and Rubber Co. plant located in Pottstown, Pennsylvania. Flue
gas sampling was conducted before and after a pilot flue gas desulfurization unit to
establish which pollutants were removed, modified, or produced by the control device.
In these tests, continuous monitors were used to measure CO, NOX, S02, and total
hydrocarbons (THC) while a Source Assessment Sampling System (SASS) was used
to collect gaseous and particulate samples. Adequate source descriptions were
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provided in the reports. A rating of A was assigned to criteria pollutant data in these
reports.
References 4-5
These reports describe tests performed on two industrial watertube boilers to
characterize the effects of combustion modifications and operating variable changes on
thermal efficiency and pollutant emissions. In these tests, gaseous emissions were
measured by standard gas analyzer methods while EPA Method 5 was used to
measure PM emissions. Adequate source descriptions were provided in the reports. A
rating of A was assigned to criteria pollutant data in these reports.
Reference 6
This report details results of a comprehensive emissions assessment performed on the
Haynes No. 5 utility boiler in Long Beach, California. Adequate details on tests
including source operation and sampling and analysis of pollutants are provided in the
report. A rating of A was assigned to criteria pollutant data in this report. This report
was cited as Reference 26 in the 1986 AP-42 Section 1.3 but data contained in it had
not been used. Hence, these data have been included in current emission factor
calculations.
Reference 7
This report describes results of tests conducted on a 26.4 MW residual oil-fired boiler
using SC and LEA as the NOX emission control technology. Tests were conducted to
determine whether combustion modification techniques which demonstrated reductions
in air pollutant emissions during short-term tests are feasible for longer periods.
Adequate details on tests including source operation and sampling and analysis of
pollutants are provided in the report. A rating of A was assigned to criteria pollutant
data in this report. This report was cited as Reference 27 in the 1986 AP-42 Section
1.3 but data contained in it had not been used. Hence these data have been included
in current emission factor calculations.
Reference 8
This report describes the results of tests conducted on Boiler No. 7 at the Boston
Edison Company's Mystic River Station located at Everett, Massachusetts. The
purpose of the sampling program was to determine the effect of raising the temperature
of the filter and probe of an EPA Method 5 train from 120°C to 160°C and of baking the
filter at 160°C on the amounts of particulate, sulfate, and sulfuric acid emissions.
However, baseline data were obtained using EPA Method 5 procedures, including a
filter termperature of 120°C. A data rating of A was assigned to PM emissions data.
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Reference 9
This report describes the second phase of an investigation into ways to improve the air
pollutant emission and thermal efficiency characteristics of residential oil furnaces.
Detailed description of source operation and sampling methodology are provided in the
report. The data were assigned a rating of A.
Reference 10
This report presents the results of a field testing effort to characterize particulate
emissions from refinery combustion sources. The major objective of this program was
to determine emission factors, size distribution, and chemical composition of
particulates from refinery combustion sources. EPA Method 5 was used for PM
emissions measurements. Adequate details on source operation are provided in this
report. The data were assigned a rating of A.
Reference 11
This symposium paper describes a series of tests conducted on a 100 horsepower (HP)
firetube boiler. In these tests, shale oil and two types of residual oil - No. 6 oil and a
coal-oil mixture were fired. The paper does not provide enough details on emission
measurement methodology and, hence, data in this paper are rated B.
Reference 12
This report provides an overview of the regulatory baseline, technical basis, and
alternative control levels available for developing NSPS for S02 emissions from small
steam generating units (i.e., boilers). The report includes data from various sources but
does not provide details of source operation and emission sampling. Hence, the data in
this report are rated B.
Reference 13
This report provides an overview of the emissions data and technical basis for NOX
NSPS for small boilers. The report includes data from various sources but does not
provide details of source operation and emission sampling. Hence, the data in this
report are rated B.
Reference 14
This report provides an overview of the regulatory baseline, technical basis, and
alternative control levels available for developing NSPS limiting PM emissions from
small steam generating units (i.e., boilers). The report includes data from various
sources but does not provide details of source operation and emission sampling.
Hence, the data in this report are rated B.
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4.1.3 Compilation of Baseline Emission Factors
The references described above were used in updating the uncontrolled
(baseline) emission factors for criteria pollutants. A computer spreadsheet was created
to calculate emission factors from the data contained in the above references. The
formulae and conversion factors used in this spreadsheet are shown in Appendix A.
Relevant parts of this spreadsheet, pertaining to specific pollutants, are discussed in
the corresponding sections below.
As previously mentioned, spot check results revealed that criteria pollutant
emission factors are supported by ample A- rated data points. Hence, only new A-rated
data points were used in the emission factor determinations described below.
PM Emission Factors
The PM emission factors for various sources are summarized in Table 4-2. As
seen in this table, the following new data points have been added to the PM emission
factors database:
! Utility boilers firing No. 6 oil: 5 points
! Industrial boilers firing No. 6 oil: 4 points
! Industrial boilers firing No. 2 oil: 1 point
No new data points were found for commercial boilers or residential furnaces. Also, no
new data were found for No. 4 and No. 5 oil firing. Spot checks revealed that PM data
from References 26 and 27 in the 1986 AP-42 Section 1.3 were not included in
previous PM emission factor determinations. These data have been included in this
effort.
For No. 6 oil-firing, PM emissions can be correlated with the percent sulfur
content of the fuel (designated as S). This correlation, published in the 1986 AP-42
Section 1.3, has been updated in this effort. The steps involved in updating this
correlation are detailed in Table 4-2. The proposed new correlation has a correlation
coefficient, or r-value, of 0.96 as opposed to the previously published correlation with r-
value of 0.65.
S02 Emission Factors
The S02 emission factors for various sources are summarized in Table 4-3. As
seen in this table, the following new data points have been added to the S02 emission
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factors database:
! Utility boilers firing No. 6 oil: 1 point
! Industrial boilers firing No. 6 oil: 3 points
! Industrial boilers firing No. 2 oil: 1 point
No new A-rated data points were found for commercial boilers or residential furnaces.
Also, no new data could be found for No. 4 and No. 5 oil-firing. Spot checks revealed
that S02 data from Reference 26 in the 1986 AP-42 Section 1.3 were not included in
previous S02 emission factor determinations. These data have been included in this
effort.
As discussed in Section 2.3.2, S02 emissions are almost entirely dependent on
the sulfur content of the fuel. Hence, correlations between fuel sulfur content and S02
emission factors are derived in Table 4.1-3. These correlations are then compared with
emission factors developed from measured emissions. Sulfur dioxide emission factor
updates are based on such comparisons; results are shown in Table 4-3.
S0? Emission Factors
The S03 emission factors for various sources are summarized in Table 4-4. As
seen in this table, the following new data points have been added to the S03 emission
factors database:
! Industrial boilers firing No. 6 oil: 2 points
! Industrial boilers firing No. 2 oil: 1 point
No new A-rated data points were found for utility and commercial boilers or residential
furnaces. Also, no new data could be found for No. 4 and No. 5 oil-firing.
For utility boilers firing No. 6 oil, the previous emission factor was based on
information provided in Reference 25 as cited in the 1986 section. Spot checks
revealed this emission factor to be incorrect. The development of a new emission
factor is shown in Table 4-4. This table also contains new data for industrial boilers;
new calculations have been made for the S03 emission factors for residual and distillate
oil.4-5
Because of the limited amount of test data available, engineering estimates were
considered based on published conversion factors of fuel sulfur to S03. Uncontrolled
SOX emissions are almost entirely dependent on the sulfur content of the fuel. About 1
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to 5 percent of the sulfur is oxidized to S03. The 1986 Section 1.3 used a factor of 2.86
percent for conversion of fuel sulfur to S03. This factor agrees well with the median
value of the published range of 1 to 5 percent.
CO Emission Factors
The CO emission factors for various sources are summarized in Table 4.1-5. As
seen in this table, the following new data points have been added to the CO emission
factors database:
! Utility boilers firing No. 6 oil: 1 point
! Industrial boilers firing No. 6 oil: 3 points
! Industrial boilers firing No. 2 oil: 1 point
! Residential furnace firing No. 2 oil: 1 point
No new A-rated data points were found for commercial boilers. Also, no new data were
found for No. 4 and No. 5 oil-firing. Spot checks revealed that CO data from Reference
26 in the 1986 AP-42 Section 1.3 were not included in previous CO emission factor
determinations. These data have been included in this effort.
As per spot checks, CO emissions typically range between 0.1 to 120 kg/103
liters of oil (1 to 10 lb/103 gal oil). Based on this information, an emission factor of 0.6
kg/103 liters of oil (5 lb/103 gal) was adopted in 1986, along with a qualifying footnote
about the sensitivity of CO emission to combustion conditions. This emission factor has
been retained as explained in Table 4-5.
NOX Emission Factors
The NOX emission factors for various sources are summarized in Table 4.1-6. As
seen in this table, the following new data points have been added to the NOX emission
factors database:
! Utility boilers firing No. 6 oil: 2 points
! Industrial boilers firing No. 6 oil: 4 points
! Industrial boilers firing No. 2 oil: 1 point
! Residential furnace firing No. 2 oil: 1 point
No new A-rated data points were found for commercial boilers. Also, no new data were
found for No. 4 and No. 5 oil firing. Spot checks revealed that NOX data from Reference
27 in the 1986 AP-42 Section 1.3 were not included in previous NOX emission factor
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determinations. These data have been included in this effort.
Results regarding NOX emission factors are shown in Table 4-6. The correlation
between the NOX (as N02) emission factor and the fuel nitrogen content, for
industrial/commercial boilers firing residual oil, was based on 36 points as indicated in
the 1986 Emission Factor Documentation (EFD).19 However, these points were not
documented adequately in the previous. Hence, well-documented data points, given in
Reference 15, were used to develop a new correlation and to compare this correlation
with the 1986 correlation. This new correlation is based on least squares fitting of data.
A comparison of means and standard deviations of error sets pertaining to the new
correlation and the 1986 correlation indicates that the new correlation is more accurate
in the data range covered. Hence, this new correlation has been adopted in place of
the previously published one.
It is generally known that NOX emissions depend on boiler heat release rate
(HRR), where HRR is a function of boiler size and design.16 Using data from Reference
15, efforts were made to correlate NOX emissions with capacity and then with load-to-
capacity ratio. However, these efforts did not meet with success as correlation
coefficients were near 0 for the correlations developed. This is probably because the
effects of boiler design and excess air could not be excluded from the data under
consideration.
VOC Emission Factors
Only one data point providing a TOC emission factor was found in this update.
This data point is shown in Table 4-7. As seen in spot checks, 1986 emission factors
were based on multiple data points and, therefore, have been retained. The results of
the emission factor development efforts, described above, are summarized in Tables
1.3-1 through 1.3-4 in Chapters.
4.1.4 Compilation of Controlled Emission Factors
A compilation of controlled emissions and control efficiencies, attained on
application of some of the control technologies discussed in Section 2.4, is given in
Tables 4-8 through 4-10.
4.2 SPECIATED VOCs
As discussed in Section 3.2, there were insufficient data to develop emission
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factors for speciated VOC. Some isolated data were identified in the general air toxics
literature search summarized in Section 4.3.
4.3 HAZARDOUS AIR POLLUTANTS
4.3.1 Review of New Data
The screening of identified HAP data sources discussed in Section 3.3 yielded a
smaller data base which was evaluated in more detail. These data were subjected to
the quality ranking criteria discussed in sections 3.1 and 3.3. The overall evaluation of
the key references follows. In general, the data base is very sparse, with older data
taken with questionable protocols, and generally insufficient sensitivity to the
importance of equipment operation and control system operation on emission rates.
The data that are available indicate a high degree of variability of HAP emission with
fuel content, combustion conditions, and control system settings. To adequately
characterize such variability will require a comprehensive testing data base, much more
comprehensive than was developed for criteria species.
Reference 20
This article summarizes the emissions of certain trace metals and hazardous pollutants
from oil combustion. The data presented are a summary of a literature review.
Emission factors are presented in the units of mass emitted per heat unit combusted
and are presented for boilers of different sizes and configurations. The emission
factors are the same for all oil-fired boilers. The article references several primary
references which were evaluated and determined to be of insufficient quality.
Reference 21
This document is a compilation of the available information on sources and emission of
POM and is not a primary reference. The document cautions against the use of these
data for development of an exact assessment of emissions from any particular facility;
however, the data are useful for comparing with other sources to verify the validity of
calculated emission factors. The data are based primarily on utility boiler test data.
Reference 22
The emission factors for oil combustion are of sufficient quality for one of the tests
presented in the report.
4-24
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Metals: Metals emission factors for an oil test were used.
Organics: It was stated in the report that the organics recovered were not
combustion products but were components in the sample collection media
and in the analytical laboratory.
POM: POM data were below the detection limit. Malfunctioning multicyclones
would also impact the quality of these data.
Reference 23
The data quality and documentation in this report are of unacceptable quality to
generate emission factors.
Metals: Level I sampling and analysis program which is
semiquantiative (a factor of + 3) data quality. A SASS train
and spark source mass spectroscopy (SSMS) analyses
were used. These data are not suited for calculation of
enrichment factors or mass balances, as stated in the
reference.
No analytical data are presented for fuels used for the testing nor for
measured control efficiencies on the abatement devices.
The emission factors presented are calculated using average
concentrations obtained from reference sources.
The raw emissions data (in units of //g/m3) are never presented. Only
pg/J units are presented for the results and there is no documentation on
how these were calculated.
POM: The sampling and analytical methods are also of lower quality, e.g. SASS
and GC/MS.
The documentation for the analytical results is not clear as to why only
portions of the samples were analyzed; therefore, one cannot determine if
the entire sample was accounted for.
Reference 24
The purpose of this document is to provide a preliminary emission assessment of
conventional stationary combustion sources. The data presented deal with national
averages or ranges based on the best available information. Emission factors in mass
emitted per heat unit input are not provided.
Reference 25
4-25
-------
The emission factors for oil combustion that were summarized in this document came
from Reference 23. These data were eliminated from use in this update due to their
poor quality.
Reference 26
This report summarizes a study that was performed to determine organic compounds
emitted from stationary sources which contribute to the formation of smog in the
atmosphere. The report provides a summary of organic concentrations from the
exhaust from a utility boiler and provides data on families of organics but does not
clearly indicate emissions of specific compounds.
Reference 27
This report summarizes testing performed on several sizes and types of boilers;
however, only criteria pollutant testing was performed.
Reference 28
Measured and calculated emission factors for distillate and residual oil are presented in
this document. The emission factors are rated with a low quality because the document
is not a primary source and the quality of the data cannot be verified.
Reference 29
This document presents a summary of emission factors for different types of processes
which emit formaldehyde. The emission factors are presented in mass per heat unit
input. A factor is provided for residual and for distillate oil; however, the factors are
based on one test only. The emission factor is, therefore, rated with a low rating.
Reference 30
This document provides a summary of the emissions factors for metals, POM, and
formaldehyde for oil-fired boilers. The emission factors for metals were based on the
contents of typical residual and distillate oil compositions with the assumption that all
metals in the oil are emitted. The existing source test data are used to demonstrate
that the metal emission factors are within reason. The emission factors for oil-fired
boilers do not differentiate between residual and distillate oils nor by boiler configuration
or size because the number of data points is not high enough to do so.
The document cautions that relatively limited data are available on toxic air pollutants
resulting from these types of processes and that emissions data in the document
should not be used to develop an exact assessment of emissions from any particular
facility. Emission factors for the processes outlined in the document are summarized
and provided for use in determining order of magnitude emissions. The emission
factors are rated with a lower quality because this document is not a primary source of
information and, therefore, data acquisition and manipulation could not be verified.
4-26
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Reference 31
Source testing was performed on three utility boilers in southern California. Testing
was performed for the following parameters: PAH with California Air Resources Board
(GARB) Method 429; benzene, toluene, xylenes with GARB Method 410; formaldehyde,
acetaldehyde, and acrolein with GARB Method 430; metals with GARB draft multiple
metals. The QA/QC data, sampling points, number of test runs, etc. were reviewed by
the South Coast Air Quality Management District (SCAQMD) for conformance with the
applicable GARB test methods. These data were used by the SCAQMD to generate
emission factors and are considered to be of sufficient quality for this update. It is not
clear from the data, however, whether the samples were taken prior to or after the
control device. Therefore, these data will not be used in this update until the request for
clarification is received.
Reference 32
This report summarizes the results of the source testing of three distillate oil-fired
boilers, and five residual oil-fired boilers. The samples were taken using a SASS train.
The metals were analyzed using SSMS which is a semiquantitative method for
determining metals. The report does present an average fuel analysis of metals for
residual oil. These data are used in the presentation of emission factors for residual oil
emissions.
Reference 33
This document presents emission factors for sources of chromium. A literature survey
was used to compile emission estimates from residual oil-fired boilers. The emission
factor for utility boilers is used for generating the emission factor.
Reference 52
This article focused on mechanisms which control the emissions of trace metals from
waste combustion systems. A model was developed based on phenomena including
particle entrainment, chemical interactions, vaporization, condensation, particle
coagulation, and particle collection by gas cleaning system. The model was tested
against the results from metals spiking in a pilot scale rotary kiln incinerator. The
emissions data collected were not considered to be applicable for development of trace
metal emission factors for oil-fired boilers.
Reference 53
In this article thermodynamic methods were used to calculate the volatility of chromium
in the offgas for a decontamination and waste treatment facility incinerator and molten
4-27
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salt processor. The results were not considered to be applicable for development of
trace metal emission factors for oil-fired boilers.
4.3.2 Baseline Emission Factors
Emission factors for metals, or trace elements, are quite often presented in the
units of mass emitted per unit thermal heat input and are not specific to a particular
boiler configuration. Ideally, emission factors for metals should be developed as a
function of the boiler firing configuration, boiler size, trace element content in the fuel,
fuel heating value, enrichment factor, and the collection efficiency of the control device.
The concepts of partitioning and enrichment are often used to characterize the
behavior of trace metals in the combustion process. These concepts are used to
describe the distribution of trace elements among the boiler outlet streams and particle
sizes. Outlet streams for oil-firing include soot deposits, and particulate or vapor in the
flue gas. Enrichment refers to the preferential concentration of trace metals in a
specific particle size fraction or outlet stream. The process of enrichment is usually
facilitated by the action of a control device.
The physical and chemical properties of a trace metal govern how that metal will
distribute in the outlet streams. For example, mercury is a highly volatile metal and,
therefore, the majority of the mass of mercury in the fuel oil tends to be emitted from the
boiler in the flue gas and not deposited as bottom ash or convective section deposits.
A method for describing partitioning behavior is to report the fraction of the total
elemental mass input that has left the boiler in an outlet stream. Another method for
quantifying the distribution of a metal is to calculate an enrichment factor by comparing
the trace element concentration of an outlet stream to the trace element concentration
in the inlet fuel stream. The enrichment ratio calculation that is outlined in Reference 1
is performed using the following equation:
ER, = (C/C^CyCRj
where:
ERy = enrichment ratio for element i in stream j
Cy = concentration of element i in stream j
CRj = concentration of reference element R in stream j
Cic = concentration of element i in fuel
4-28
-------
'Re
= concentration of reference element R in fuel
Enrichment ratios greater than 1 indicate that an element is enriched in a given
stream, (e.g. stream j), or that it partitions to a given stream. A reference element is
used because its partitioning and enrichment behavior is often comparable to that for
the total mass. In other words, the reference element partitions with consistent
concentrations in all streams and normalizes the calculation. Typical reference
elements are aluminum (Al), iron (Fe), scandium (Sc), and titanium (Ti). The
enrichment behavior of elements is somewhat consistent in different types of boilers
and can be explained by a volatilization-condensation or adsorption mechanism. A
summary of the enrichment behavior for the HAPs metals and the reference metals is
presented in Table 4-11.
Insufficient data were available to develop enrichment ratios for different sizes
and configurations of oil-fired boilers. As stated in Reference 33, it is reasonable to
estimate metals emissions based on the assumption that the entire metal content in the
fuel is emitted. This approach results in an emission factor that is theoretically the
maximum for the fuel under analysis. The only means by which actual emissions could
be greater than the calculated value is if a metal is added to the emission stream from
metal erosion in the boiler or control device, or if the metal is present in combustion air
at a significant level. The most significant factor influencing the uncontrolled emission
is the content of the metal in the fuel. The metals content in the fuel were used in
conjunction with source test data to develop uncontrolled emission factors.
As stated in Reference 28, residual oils appear to have higher chromium
contents than crude oils as a result of the refining process. A heavy metal such as
chromium has a very low vapor pressure and exists distillation operations as a low
pressure organo-metallic complex along with the higher molecular weight hydrocarbons
in the crude oil. The metal concentrates in the residual part of the crude oil as it is
distilled. This concentration phenomenon explains why the chromium content of
distillate oils is generally lower than that of residual and crude oils. This phenomenon
holds true for similar metals.
4-29
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Unlike metals emissions, POM emissions are a direct product of inefficiency in
the combustion process as described in Reference 6. The primary constituents of the
POM emissions are naphthalene, biphenyl, phenanthrene, anthracene, and
fluoranthene. Based on very limited data, POM emissions from distillate oil combustion
appear to be slightly higher than emissions from residual oil combustion. This trend
may be due to the fact that smaller distillate oil boilers have less efficient combustion
systems than larger residual oil boilers.
Tables 4-12 and 4-13 present emission factors for metals, POM, and
formaldehyde in metric and English units, respectively. Limited data are available on
other HAPs compounds and could not be obtained for this update. The metals data
were more abundant while data for formaldehyde were very limited. The POM data
were also relatively limited. The data are presented in the units of mass emitted per
unit thermal heat input as reported in most of the references. Insufficient
documentation was available to convert the factors to mass emitted per volume of fuel
combusted.
4.3.4 Controlled Emission Factors
Insufficient data were available to generate emission factors for controlled HAPs
emissions. It is clear that control devices for criteria pollutants will impact emissions of
HAPs. For example, PM control devices will control nonvolatile metals and some
semivolatile organic compounds that are associated with PM. Additional testing of
these sources for HAPs and further data acquisition from agencies and industries which
have performed these tests will need to occur for future updates of AP-42. 4.4
Nitrous Oxide
4.4.1 Review of Specific Data Sets
A total of 29 references were identified and reviewed during the literature search.
Of these, 27 references proved to be unusable for developing N20 emission factors.
The primary reasons for rejection were:
! Data were taken with a pre-1988 protocol which has subsequently proven
to give erroneously high measurements due to artifacts resulting from
reactions in the sampling container;
4-30
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! Insufficient documentation of source or sampling/analysis methods;
! Pilot scale data.
The screening results showed two of the 29 reports to be useable. The treatment in the
current update is summarized below.
Reference 36
This reference contained N20 emissions data from eight full-scale utility boilers. All test
reports were rejected except for the test report from the Italian power plant. The Italian
power plant had two sources: one source ran on fuel oil and the other source ran on
bituminous coal. The data from the fuel oil source were used in this update. The report
provided adequate detail for validation and the sampling and analysis methodology
appeared sound. A B quality rating was assigned to the data.
Reference 37
This test report contained data for N20 emissions from two sub-scale boilers. Both of
the boiler units were run with natural gas, No. 2 fuel oil, and No. 5 fuel oil. The N20
data were measured with an on-line GC/ECD N20 analysis. Because the test report
was from a small pilot scale system, a rating of D was assigned to the data for both
boilers.
For the useable data contained in these reports, emission factor calculations
were made in terms of mass of pollutant per mass of fuel. It should be noted that the
terms "controlled" and "uncontrolled" in this discussion are indicative only of the location
at which the measurements were made.
A summary of the N20 emission data is contained in Table 4-14.
4.5 FUGITIVE EMISSIONS
There were no previous data on fugitive emissions in Chapter 1 of AP-42 and
therefore, no existing data were available for validation. Most fugitive emissions from
fuel oil handling or ash handling can be estimated from AP-42 Chapters 4 and 11. The
data added to Section 1-3 for this update were for fugitive emissions from valves and
flanges.
4.5.1 Review of Specific Data
A total of 10 references were documented and reviewed during the literature
search. Nine of the ten were rejected using the criteria summarized in Chapter 3.1.
The most common reason for rejection was lack of quantified process conditions.
4-31
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4.5.2 Compilation of Emission Factors
Emission factors for fuel and fly ash handling and storage are found in Chapters
4 and 11 of AP-42, respectively. The VOC emission factors for the fuel feed system
selected for inclusion in AP-42 were taken directly from the Petroleum Refineries study
and the 24-unit SOCMI study.38 The factors specified for fuel oil-fired boilers are the
EPA-approved values for valves, pumps, flanges, and open-ended lines handling heavy
liquids, which are defined as liquids with a vapor pressure less than kerosene. These
values were derived through a well-described emission factor development approach
derived as part of the SOCMI fugitive emissions standards proposed by EPA in January
1981. The procedure called for a determination of leaking and non-leaking source
emission factors from the refinery data set and applying these factors to the leak
frequencies found in the SOCMI 24-unit screening study to yield emission factors for
average SOCMI units. The resultant "average" SOCMI factors evolved from a
comprehensive and thorough study and were considered valid for this update. Table 4-
15 presents the developed VOC emission factors for fuel oil feed systems.
4.6 PARTICULATE SIZE DISTRIBUTION
The revised AP-42 scope is intended to include particulate size distribution
emission factors as well as filterable and condensible PM-10 emission factors. The
1986 AP-42 Section 1.3 includes detailed analysis of particulate size distribution data.
Filterable PM-10 data are included in this analysis by default, because they are among
the cumulative size fractions considered. Condensible PM-10 data are not in the 1986
Section 1.3; they should be added to future revisions of the section.
4.6.1 Review of 1986 Section 1.3 Data
The 1986 database was evaluated with respect to sources of data, data analysis,
and calculations. Only filterable particulate data were retrieved and analyzed for that
update.
Table 4-16 lists the sets of A-and B-rated data used to develop the current AP-
42 emission factors for oil-fired particulate. The FPEIS printouts were the primary
sources of emission data for the 1986 update. The original printouts were spot-
checked to ensure that the data were used appropriately in the 1986 update. The spot-
checking did not uncover any inaccuracies in the previous analysis. During the FPEIS
4-32
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evaluation, several FPEIS printouts were obtained that contained inorganic and organic
impinger data. The data were evaluated for development of condensible PM-10
emission factors. The results of this analysis are discussed below.
4.6.2 Review of New Data
A search for additional data was conducted. Of primary interest were CPM data
collected via EPA Method 202, because this particulate fraction has not been
addressed in previous AP-42 updates. Unfortunately, only method-development quality
source test data were found.
Although a variety of sources were contacted regarding particulate sizing and
PM-10 data, very little additional data were obtained. State and district offices that
were contacted either had no PM-10 data available or were unable to process such a
request in a timely fashion due to other staff commitments. Several divisions within the
GARB were contacted because GARB considers condensible particulate as a portion of
total particulate. However, the personnel contacted did not have any reportable data.
An official at the Stanislaus County Air Pollution Control District in California stated that
they assume that all particulate from fuel-oil-fired boilers is PM-10, therefore, they do
not require specific PM-10 testing.
Thirty source tests were performed on five boilers fueled with fuel oil.41
Condensible particulate matter was one of the parameters measured during this test
phase. None of the boilers was equipped with an abatement device for particulate
emissions. Two different test trains were employed in the program: an EPA SASS and
a modified EPA Method 5 train. Both trains consisted of a heated probe; three
calibrated cyclones with nominal cut sizes of 10, 3, and 1 um contained in an oven
capable of being heated to 400°F; a millipore filter also in the oven; two impingers
containing distilled water; one dry impinger; one impinger containing desiccant; vacuum
pump; and a dry gas meter. The primary difference in the two trains was size. The
SASS was the larger of the two trains. It had a sampling rate of 4.0 standard dry cubic
feet per minute (SDCFM) whereas the Method 5 sampling train had a sampling rate of
1.0 SDCFM. Condensible particulate matter data from this report are shown in Table 4-
17 to 4-20.
4-33
-------
One Method 202 test report was obtained that contained CPM emission data for
an oil-fired boiler equipped with a mechanical collector.42 The test objectives were to
document the precision and sampling train collection efficiency of Draft Method 202, as
well as to assess the general performance of the method at a source category expected
to have significant CPM emissions. The boiler was fired on moderately high-sulfur oil
and was expected to emit significant quantities of inorganic CPM.
The data are presented as mg emitted/m3. The test matrix included the
volumetric flow rates in the stacks but the process data, such as the size of the boiler or
the oil-firing rate, were not recovered. Therefore, it is not possible to prepare emission
factors from the results. However, conclusions may be drawn regarding the relative
size of the organic and inorganic portions of the CPM. These results are presented in
Table 4-21. The results indicate that CPM originating from high-sulfur oil-fired boilers
are at least 90 percent inorganic matter.
4.6.3 Compilation of Uncontrolled Emission Factors
The previous update was reviewed with respect to the procedure used to
develop emission factors from the particle size distribution data. The uncontrolled
emission factors were calculated for each size fraction by multiplying the total
particulate emission factor by the cumulative percent mass for the given size interval.
Therefore, all uncontrolled emission factors will change simply by updating the overall
particulate emission factors.
It is apparent that the level of uncertainty increases as one moves from the
cumulative percent mass to the uncontrolled emission factors. The uncontrolled
emission factors are functions of two numbers estimated generally from different sets of
data: the cumulative percent mass, and the total particulate emission factor.
4.6.4 Control Technology Emission Factors
There were two calculation steps in the development of controlled emission
factors in the previous AP-42 particulate sizing update. First, a controlled emission
factor was developed for total particulate by multiplying the uncontrolled total particulate
emission factor from the criteria pollutant table by one of the following control efficiency
factors:
• Multiple cyclone - 80 percent,
4-34
-------
• Baghouse - 99.8 percent,
ESP - 99.2 percent, and
• Scrubber - 94 percent.
Nest, a controlled emission factor was developed for each of the cumulative size ranges
by multiplying the controlled emission factor for total particulate by the cumulative
percent mass for the size range. Thus, the quality of the right-hand side of each size
distribution table in the 1986 Section 1.3 is directly related to the quality of three other
numbers: (1) the control efficiency factors, (2) the total particulate emission factor
(taken from the criteria pollutant table), and (3) the cumulative percent mass data. This,
in part, explains the low ratings generally listed the section for the controlled emission
factors for the particulate size fractions.
The disadvantage of this procedure is the loss of emission factor quality. The
advantage of the procedure is that it allows the determination of process-specific
controlled emission factors rather than using generalized control efficiency results.
Process-specific controlled emission factors are better than generalized control
efficiencies results because control efficiency is dependent on particulate parameters,
such as the resistivity, not just the particle size distribution.
It is useful to note that the procedure does not assume a single control efficiency
for each particle size. Rather, it assumes a single overall efficiency and applies this to
the total particulate emission factor. The size-based emission factors depend on the
total controlled emission factor and the percent of the total mass within a particular size
range.
Although different methods could be used to develop controlled emission
estimates, the procedure used in the 1986 document is logical. The process appears to
generate conservatively high values for the controlled emission factors, as there are
occasionally controlled emission factors in the tables that are larger than the
uncontrolled factors.
With respect to the appropriateness of the four particulate control efficiencies
used throughout the previous update, the values for the ESP and scrubbers appear to
be high. The text of the 1986 AP-42 Section 1.3 indicates that the particulate removal
efficiency of older ESPs is only 40 to 60 percent and that new or rebuilt ESPs remove
4-35
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up to 80 percent. This varies significantly from the efficiency of 99.2 percent assumed
for the calculation of the controlled emission factors. The NSPS for small steam
generating units confirms the discussion in AP-42. It lists source test data from two
different oil-fired boilers that shows particulate control efficiencies ranging from 40 to 83
percent, with an average value of 64 percent. The boiler sizes were 28 MW (94
MMBtu/hr) and 1610 MW(5500 MMBtu/hr).
The 1986 AP-42 controlled emission factor calculations assume a scrubber
efficiency of 94 percent. However, the AP-42 text notes that scrubbers remove only 50
to 60 percent of the particulate generated from oil-fired boilers. The NSPS document
lists design particulate removal efficiencies for several wet scrubbers applied to oil-fired
boilers. The efficiencies range from 40 to 92 percent with an average of 72 percent.
It is suggested that the control efficiencies used in the fuel oil tables be changed
to 50 percent for old ESPs, 80 percent for new or rebuilt ESPs, and 80 percent for
scrubbers.
4-36
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TABLE 4-1. RESULTS OF 1986 SECTION 1.3 DATA SPOT CHECKS
Pollutant Boiler Fuel
Particulate3 Utility #6
Industrial/ #6
Commercial
Industrial/ #5
Commercial
Industrial/ #4
Commercial
Industrial/ #2
Commercial
Residential #2
SO2b Utility Residual
1986
Section 1 .3
reference
7, pp. 68-74
24, printouts
3, Table VI-4
4, Table F-3
5, Table 4-1
3, Table VI-4
4, Table F-3
5, Table 4-1
3, Table VI-4
4, Table F-3
3, Table VI-4
4, Table F-3
5, Table 4-1
4, Table I-3
5, pp. 16-17
Total
data
points
53
10
21
9
3
15
33
_
Spot checked
data
points
2
2
1
1
1
1
1
1
1
-
_
Observations
A data point from a controlled facility;
Average emission factor (10 lb/1000 gal)
adopted in footnote g.
Average emission factor (7 lb/1000 gal)
adopted in footnote g.
Average emission factor (2 lb/1000 gal)
adopted in footnote g.
Emission factor suggested in the table
has been adopjed.
States that SOx emissions are
Industrial
Residual
5, pp. 16-17
proportional to fuel S% and are not
affected by boiler size, burner design, or
fuel.
States that SOx emissions are
proportional to fuel S% and are not
affected by boiler size, burner design, or
fuel.
Commercial Residual 3, pp. 1-14, 16 5
4, p. I-20, 21 1 1
Industrial Distillate 5, pp. 16-17
Generally agrees with the EPA value
(159Svs. 157S).
Suggest using a range (1 54S - 1 62S: #4
-#6).
States that SOx emissions are
proportional to fuel S% and are not
affected by boiler size, burner design, or
fuel.
4-21
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TABLE 4-1. RESULTS OF 1986 SECTION 1.3 DATA SPOT CHECKS
Pollutant Boiler
Commercial
Residential
SO3C Utility
Industrial/
Commercial
Industrial/
Commercial/
Residential
COd Utility
Industrial
Commercial
Industrial
Commercial
Residential
Fuel
Distillate
Distillate
Residual
Residual
Distillate
Residual
Residual
Residual
Distillate
Distillate
Distillate
1986
Section 1 .3
reference
3, pp. 1-14, 16
4, p. I-20, 21
3, pp. 1-13, 15
25, p. 20
_
-
8, Table 2-1 3
9, pp. 114-142
5, p. 73
3, pp. 1-14, 16
4, p. I-20, 21
5, p. 73
3, pp. 1-14, 16
4, p. I-20, 21
3, pp. 1-13
Total Spot checked Observations
data data
points points
1 - Generally agrees with the EPA value
(140Svs. 142S).
8 - Suggest using the EPA value of 142S.
18 - Lower than the EPA value (127S vs.
142S)_
Calculations based on Ref. 25 do not
yield the EPA value.
Emission factor seems to be based on a
simple mass balance indicated in ref. 1 .
Appears that the result for
Industrial/Commercial-Residualhas been
used.
9 - CO ranged in 1 -8 lb/1 000 gal oil for all
utility boilers.
5 - CO for all utility boilers, under normal
baseline conditions, was in the range
5-10 lb/1 000 gal oil.
CO, typically, was less than 1 00 ppm
(12.5 lb/1 000 gal).
5 - Average CO emission factor was 3.8
lb/1 000 gal oil.
1 1 - Suggest using a range (0.9 - 1 .2 lb/1 000
gal oil: #4- #6).
CO, typically, was less than 1 00 ppm
(12.5 lb/1 000 gal).
2 - Average CO emission factor was 2.7
lb/1 000 gal oil.
8 - Suggest using 0.5 lb/1 000 gal oil.
18 - Average CO emission factor was 5.1
lb/1 000 gal oil.
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TABLE 4-1. RESULTS OF 1986 SECTION 1.3 DATA SPOT CHECKS
Pollutant Boiler
N0xe Utility
Industrial/
Industrial/
Commercial
Residential
1986 Footnote j_
VOCf Utility
Industrial
Commercial
Residential
Fuel
Residual/
tangential
Residual/
vertical
Residual/other
Residual
Distillate
Distillate
Residual
Residual
Distillate
Residual
Distillate
Distillate
1986
Section 1 .3
reference
10, p. 25
17, Table 2-1
17, Tables 3-1
&4-1
17, Tables 3-1
&4-1
3, p. I-8;
4, p. I-9, 11;
&10, p. 25
3,4,5
19, pp. 201 &207
21, pp. 102& 106
21, pp. 102&106
20, pp. 75 & 79
20, pp. 75 & 79
18, pp. 58 & 62
Total
data
points
38
2
-
49
28
19
19
33
38
36
10
4
4
4
3
5
Spot checked Observations
data
points
Average CO emission factor was 0.1 2
lb/1000lboil
(.86lb/1000g_aloilX
New (16% lower) emission factor
adopted.
Old emission factor retained.
New (lower) emission factor adopted.
Average emission factor adopted
EPA.
Average emission factor adopted
EPA.
Verified the notes in EFD.
-
-
-
1 Verified the details in EFD.
-
-
-
-
-
by
by
Insufficient number of data points for #5 firing. Hence, emission factors for these cases should be rated B.
Adequate number of data points for #6 and #2 firing. Hence, a rating of A for corresponding emission factors.
""General comments for SO2:
1. EFD does not provide sufficient information.
2. Emission factor for residual oil seems to be based on a simple mass balance indicated in Ref. 1 (see Table 4.1-3).
3. Emission factor for distillate oil (#2), calculated as per the simple mass balance indicated in Ref. 1, seems to be somehwat lower than the EPA value (137S vs. 142
S, where S = % sulfur - see Table 4.1 .-3).
4. Ref. 2 is quite non-specific and probably should be purged.
4-23
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5. Ref. 27 does not apply.
6. Emission factor rating:
Since emission factor estimates based on a mass balance assuming -98% conversion of fuel S to SO2, are very close to AP-42 values, emission factor
ratings of A are assigned.
comments for SO3:
1. EFD does not provide enough information.
2. Ref. 2 is quite non-specific and probably should be purged.
3. Ref. 27 does not apply.
4. Utility emission factor, based on Ref. 25, seems to be incorrect (see Section 4.1.3).
5. Emission factor rating:
For rating boiler firing residual oil, Ref. 25 does not provide adequate information. Hence, emission factors for this case should be rated C.
For cases other than utility boiers firing residual oil, emission factor estimates based on 1% fuel S to SO3, are very close to AP-42 value of 2S. Hence, a rating of A
was assigned.
dGeneral comments for CO:
1. EFD does no provide adequate information.
2. An emission factor of 5 lb/1000gal seems to have been adopted for all cases and published with a qualifying footnote.
3. Emission factor rating:
In general, as shown above, CO emission factors are between 1-10lb/1000 gal. Hence, a median valuee of 5 lb/1000 gal, with a qualifying footnote about CO
emissions on combustion conditions, should be rated A.
eGeneral comments for NOX:
1. EFD is reasonably explicit but does not address footnote j adequately. No information available on specific pages in references used in connection with footnote j.
2. Emission factor rating:
Since NOX emission factors are based on ample A-rated data points, corresponding emission factor rating of A is assigned.
'General comments for VOC:
1. EFD is quite explicit and, therefore, only utility/residual case was spot checked.
2. Emission factor rating: Since emission factors are based on ample A-rated data points, ratings of A are assigned.
4-24
-------
TABLE 4-2. PM EMISSION FACTOR UPDATE
Ref. Boiler Fuel Data Site
quality
Fuel
HHV,
Btu/lb
S,
%
Ash,
%
Density,
Ib/gal
Load/ Sample O2,
capacity
PM,
Ib/MBtu
PM,
Ib/Kgal
Utility
Utility
Low S
Oil
10 Utility 6
Utility 6
1-3 Industrial 6
Haynes #5
Boiler No. 7
Refinery B,
Source 2
Refinery C,
Source 1
18958
18477
18451
18466
18477
18451
18466
18750
18750
18610
18610
17515
0.18
0.01
1.99 0.08
1.9 0.09
1.91 0.1
1.99 0.08
1.9 0.09
1.91 0.1
0.73 0.03
0.73 0.03
1.19 0.02
1.19 0.02
1.96 0.02
7.59
8.14
8.17
8.16
8.14
8.17
8.16
7.951
7.951
8.027
8.027
7.88
0.92
0.97
0.98
1.02
0.775
0.7-1
3-4
5
6.1
5.5
4.9
6.6
7.3
9.6
0.0153
Average
Average
0.035
0.035
Average
0.054
0.088
Average
0.14
2.202
16.690
22.606
23.600
20.965
29.5
15.2
15.823
20.178
5.218
5.218
5.218
8.067
13.146
10.606
19.323
4,5
Industrial
Location 19
19680
19680
0.16
0.16
0.00
0.00
6.97
6.97
0.8
3.2
2.95
0.0564
Average
7.736
0.000
7.736
Industrial
Location 19
19000
19000
0.54
0.54
0.01
0.01
7.75
7.75
0.8
3
3.1
0.084
Average
12.369
0.000
12.369
4-25
-------
TABLE 4-2. PM EMISSION FACTOR UPDATE
Ref. Boiler Fuel Data Site
quality
Industrial 6 A Location 38
7 Industrial 6 A Site 2
Results:
1 . Industrial boilers firing distillate oil:
The average emission factor from one data point,
shown above, is 7.74 lb/1 000 gal.
AP-42 emission factor, based on 1 5 points, is 2 lb/1 000 gal.
AP-42 factor is retained.
2. Utility/lndustrial/Commercial boilers firing No. 6 oil:
A. Original 71 points reduced to 3 average points in the
sulfur brackets shown below
S range # of S% PM,
(%) points lb/1 000 gal
1.5-2.5 19 2.063 23
0.625-1.25 33 0.937 13
0.10-0.625 19 0.5 8.6
B. 1 0 Additional points (added in last EFD from reference
24):
Point S% PM, HHV, PM,
Ib/MMB Btu/gal lb/1 000 gal
1 0.41 0.05 145551 7.27755
2 0.46 0.06 143156 8.58936
3 0.33 0.03 147184 4.41552
4 0.34 0.019 153192 2.94112864
5 0.39 0.106 149152 15.914518
6 0.37 0.09 142540 12.28286
7 0.44 0.006 142700 0.8562
8 0.34 0.05 142790 7.3645
9 0.37 0.03 147700 4.431
10 0.45 0.03 149289 4.47867
Fuel Density,
Ib/gal
HHV, S, Ash,
Btu/lb % %
18467 1.88 0.05 8.04
18950 0.97 0.02 7.71
19020 0.88 0.02 7.69
Points from B reduced to 1 average point:
—Average—
S range, # of S% PM,
% points lb/1 000 gal
0.25-0.625 8 0.38 6.7
Note that points 1 and 2 have not been
averaged in as these
were taken after an ESP
C. 9 additional points added in this effort:
Point S % PM,
lb/1 000 gal
1 0.18 2.2
2 1.93 21
3 1 .93 20
4 0.73 5.2
5 1.19 11
6 1.96 19
7 0.54 12.37
8 1 .88 23
9 0.925 9
Above 9 points are reduced to 3 average
points shown below
— Average
S range, # of S, PM,
% points % lb/1 000 gal
1.5-2.5 4 1.9 21
0.625-1.25 3 0.9 8.3
0.10-0.625 2 0.4 7.29
Load/ Sample O2, PM,
capacity Ib/MBtu
%
0.89 2.9 0.1543
1 8.9 0.0475
1.02 7.6 0.0757
Average
D. Linear regression using average
points from A, B, and C.
Avsrsos
PM
S, lb/1 000 gal
2.1 23
0.94 13
0.5 8.6
0.38 6.7
1.9 21
0.95 8.3
0.36 7.3
Regression Output:
Constant 3.22
StdErrofYEst 2.109
R Squared 0.94
No. Of Observations 7
Degrees of Freedom 5
X Coefficient(s) 9.19
In view of above, the algorithm given in previous AP-42
changed to:
PM, lb/1 000 gal = 9.19*5% + 3.22
This has a correlation coefficient of r = 0.97
PM,
Ib/Kgal
22.910
6.940
1 1 .077
9.008
is
4-26
-------
TABLE 4-3. S07 EMISSION FACTOR UPDATE
Ref. Boiler Fuel Data Site
quality
6 Utility Low S oil B Haynes
#5
1-3 Industrial 6 B
4,5 Industrial 2 B Location
19
Industrial 6 B Location
19
Industrial 6 B Location
38
Run
143
202-3
&4
19-5
19-7
19-97
19-99
200-24
Fuel Fuel
HHV, S,
Btu/lb %
18958 0.18
17515 1.96
19680 0.16
19680 0.16
19000 0.54
19000 0.54
18467 1.88
Density
Ib/gal
7.59
7.88
6.97
6.97
7.75
7.75
8.04
Load/ O2, SO2,
capacity % Ib/MMBtu
0.92 3-4 0.209
0.7-1 2.28
0.8 3.2 0.146
2.95 0.223
0.8 3 0.596
3.1 0.644
0.89 2.9 1.713
SO2, SO2/S%
Ib/Kgal. Residual
30.07 167.07
314.68 160.55
20.03
30.59
25.31
87.76
94.83
91.30 169.06
254.34 135.29
Average 157.99
SO2/S%
Distillate
158.17
158.17
4-27
-------
TABLE 4-3. S07 EMISSION FACTOR UPDATE
Ref.
Boiler
Fuel
Data
quality
Site
Run
Fuel
HHV,
Btu/lb
Fuel Density
S,
% Ib/gal
Load/ O2, SO2, SO2, SO2/S% SO2/S%
capacity % Ib/MMBtu Ib/Kgal. Residual Distillate
Results:
1. Residual Oil Firing:
SO2 emission factor based on fuel oil S weight percent can be estimated as follows:
0.98 x 64/32 x %S/100 x 8 x 1000 = 156.8S
assuming 98% conversion of S to SO2 and oil density of 8 Ib/gal.
1986 AP-42 emission factor is identical to the above estimated value.
The average emission factor, shown above, is also very close to the AP-42 value.
Hence, 1986 emission factor is retained.
2. Distillate Oil Firing:
SO2 emission factor based on fuel oil S weight percent can be estimated as follows:
0.98 x 64/32 x %S/100 x 7 x 1000 = 137.2S
assuming 98% conversion of S to SO2 and oil density of 7 Ib/gal.
1986 AP-42 emission factor is very close to the above estimated value.
The average emission factor, based on one data point, is higher than the above
estimated value.
In light of paucity of new data and above estimate, 1986 emission factor is retained.
3. No. 4 Oil firing:
No. 4 oil properties can be approximated by averaging residual & distillate oils properties.
Hence, emission factor is also an average.
4-2!
-------
TABLE 4-4. SO, EMISSION FACTOR UPDATE
Ref. Boiler Fuel
Data Site Run Fuel Fuel Fuel
quality HHV, S, density, capacity %
Btu/lb % Ib/gal
S03,
Ib/MMBtu
S03,
Ib/Kgal
4,5 Industrial
Industrial
Industrial
Location 19-5
19
19680 0.16
Location 19-97 19000 0.54
19
Location 200-24 18467 1.88
38
6.97
7.75
8.04
0.8
0.8
0.89
3.2
2.9
0.0023
0.0093
0.0509
0.315
1.369
7.557
2.0
2.5
4.0
4-29
-------
TABLE 4-4. SO, EMISSION FACTOR UPDATE
Ref.
Boiler
Fuel
Data
quality
Site
Run
Fuel
HHV,
Btu/lb
Fuel Fuel
S, density,
% Ib/gal
Load/
capacity
SO3,
Ib/MMBtu
SO3,
Ib/Kgal
SO3/S%
Results:
1. Utility boilers firing No. 6 oil:
An emission factor for utility boilers firing No. 6 oil, based on information in 1986 Section
1.3 Reference 25, can be estimated as follows:
0.0286 x 80/32 x S%/100 x 8 x 1000 = 5.72S
assuming a mean conversion of 2.86% for S to SO3 and oil density of 8 Ib/gal.
Above estimate suggests that for utility boilers firing No. 6 oil the 1986 AP-42 value of
2.9S Ib/Kgal is incorrect.
The above estimated value is accepted as the emission factor for this case, with a C
rating as data in 1986 Reference 25 are rated B due to lack of adequate information.
2. Other hardware/fuel combinations:
An emission factor, for residual oil firing, can be estimated as follow:
0.01 x 80/32 x S%/100 x 8 x 1000 = 2S
assuming a mean conversion of 1% for S to SO3 (as per Ref.1) and oil density of 8 Ib/gal.
Since there is a wide variability in conversion of S to SO3, the emission factor of 2S (Ib
SO3/103gal oil) is also valid for distillate oil firing.
The averaged emission factor for industrial boilers is close to the 1986 AP-42 value of 2S.
In view of paucity of new data, and above result, 1986 AP-42 value is retained.
4-30
-------
TABLE 4-5. CO EMISSION FACTOR UPDATE
Ref. Boiler Fuel Data Site Run Fuel Fuel Fuel Load/
quality HHV, S, density, capacity
Btu/lb % Ib/gal
6 Utility LowS A Haynes#5 143 18958 0.18 7.59 0.92
oil
1-3 Industrial 6 A 202-3 & 4 17515 1.96 7.88 0.7-1
17515 1.96 7.88 0.7-1
4,5 Industrial 2 A Location 19 19-5 19680 0.16 6.97 0.8
19-7 19680 0.16 6.97
Industrial 6 A Location 19 19-97 19000 0.54 7.75 0.8
19-99 19000 0.54 7.75
Industrial 6 A Location 38 200-24 18467 1.88 8.04 0.89
9 Residential 2 A 43
44
O2 CO,
Ib/MBtu
3-4 0.013
0.01
0.01
3.2 0.003
2.95 0.01
3 0.003
3.1 0.003
2.9 0.017
8.5 0.37 g/kg
8.5 0.33 g/kg
Average
CO,
Ib/Kgal.
1.87
1.38
1.38
1.38
0.45
1.30
0.88
0.49
0.49
0.49
2.58
2.59
2.31
2.45
1.61
Results:
As shown above, the average emission factor for CO is less than the 1986 AP-42 value of 5 lb/1000 gal.
However, the 1986 AP-42 value is based on many more observations; therefor it is retained.
4-31
-------
TABLE 4-6. NOV EMISSION FACTOR UPDATE
Ref. Boiler Fuel
10 Utility 6
(Horizontal
fired)
Utility 6
(Horizonal
fired)
1-3 Industrial 6
4,5 Industrial 2
Industrial 6
Industrial 6
7 Industrial 6
9 Residential 2
Data Site Run Fuel
quality HHV,
Btu/lb
A Refinery B, 10,11,12 18750
Source 2 7,8,9 18750
A Refinery C, 1,2,3 18610
Source 1 4,5,6 18610
A 202-3 & 4 17515
17515
A Location 19 19-5 19680
19-7 19680
A Location 19 19-97 19000
1 9-99 1 9000
A Location 38 200-24 18467
A Site 2 1-1 & 1-2 18950
1-3 19020
A 43
44
Fuel
N,
%
0.22
0.22
0.18
0.18
0.36
0.36
0.00
1
0.00
1
0.2
0.2
0.31
0.27
0.24
Fuel Load/ Sample
density, capacity O2,
Ib/gal %
7.951 0.97 4.9
7.951 0.98 6.6
8.027 1.02 7.3
8.027 0.775 9.6
7.88 0.7-1
7.88 0.7-1
6.97 0.8 3.2
6.97 2.95
7.75 0.8 3
7.75 3.1
8.04 0.89 2.9
7.71 1 8.9
7.69 1.02 7.6
8.5
8.5
NO2,
Ib/MMBtu
0.22
0.23
0.27
0.34
0.38
0.365
0.241
0.2301
0.428
0.438
0.52
0.506
0.4487
2.602 g/kg
2.577 g/kg
NO2,
Ib/Kgal
32.80
34.29
33.54
40.33
50.79
45.56
52.45
50.38
51.41
33.06
31.56
32.31
63.02
64.50
63.76
77.21
73.93
65.65
69.79
27.92
27.66
27.79
4-32
-------
TABLE 4-6. NOV EMISSION FACTOR UPDATE
Ref. Boiler Fuel Data Site Run Fuel
quality HHV,
Btu/lb
Results:
1 . Utility boilers firinq No. 6 oil:
Since no new data was uncovered fortangentially fired and vertical fired boilers,
old emission factors are retained for these cases. However two data points,
uncovered above, are used in determining emission factor for other firing configurations.
Average
(Ib/Kgal) n n x average
67 49 3283 1986 data described in EFD and 1986 Ref. 17
33.54 1 34 New data point
51 3362
New emission factor (EF) = 65.92 (lb/1000 gal)
% change in EF = -1.49
Since % change in EF is small, 1986 EF (67 Ib/Kgal) is retained.
2. Industrial/Commercial boilers firinq residual oil:
Average
(Ib/Kgal) n n x average
53 20 1060 1986 data described in EFD and 1986 Ref. 17
60 8 480 1986 data described in EFD and 1986 Ref. 17
51 .41 1 51 New data point
63.76 1 64 New data point
77.21 1 77 New data point
69.79 1 70 New data point
32 1802
Fuel Fuel Load/ Sample NO2, NO2,
N, density, capacity O2, Ib/MMBtu Ib/Kgal
% Ib/gal %
New emission factor (EF) = 56.32 lb/1 000 gal
% change in EF = -2.4
Since % change in EF is small, 1986 EF (55 Ib/Kgal) is retained.
3. Industrial/Commercial boilers firinq distillate oil
Average
(Ib/Kgal) n n x average
20 1 2 240 1 986 data was described in EFD and Ref. 1 7
19 7 133 1986 data was described in EFD and Ref. 17
32.31 1 32.31 New data point
20 405.3
New emission factor (EF) = 20.27 lb/1000 gal
% change in EF = 1.35
Since % change in EF is small, 1986 EF (20 Ib/Kgal) is retained.
4. Residential units firinq distillate oil:
Since only one data point was obtained for this case, 1 986 emission factor of
18lb/1000 gal, based on multiple data points, has been retained.
4-33
-------
TABLE 4-7. VOC EMISSION FACTOR UPDATE
Ref. Boiler Fuel Data Run Sample
quality O2,
%
9 Residential 2 A 43 8.5
44 8.5
TOO,
g/kg
0.04
0.04
TOO,
Ib/Kgal
0.28
0.28
0.28
Results:
The average emission factor for TOC is less than the 1986 AP-42 value of 2.49 lb/1000 gal.
The 1986 value is retained as it is derived from multiple data points.
4-34
-------
TABLE 4-8. CONTROLLED PM EMISSIONS
Boiler load,
actual/design
NR/15MW
(NR/52 MMBtu/h)
14.5MW/17MW
(49 MMBtu/h/57 MMBtu/h)
13MW/17MW
(59.3 MMBtu/h/57 MMBtu/h)
13.7MW/15MW
(52.4 MMBtu/h/50 MMBtu/h)
6.4 MW/7 MW
(22.8 MMBtu/h/25 MMBtu/h)
12.9MW/15MW
(42.5 MMBtu/h/50MMBtu/h)
13.7MW/15MW
(45.5 MMBtu/h/50 MMBtu/h)
13.5MW/15MW
(45.0 MMBtu/h/50 MMBtu/h)
NR/28 MW
(NR/94 MMBtu/h)
1630MW/1610MW
(5580 MMBtu/h 5500 MMBtu/h)
1640MW/1610MW
(5590 MMBtu/h/5500 MMBtu/h)
1610MW/1610MW
(5490 MMBtu/h/5500 MMBtu/h)
NR/10MW
NR/10MW
NR/48 MW
NR/48 MW
Boiler type
Residual oil
Residual oil
Residual oil
Residual oil
Residual oil
Residual oil
Residual oil
Residual oil
Oil fired
Oil fired
Oil fired
Oil fired
Oil fired
Oil fired
Oil fired
Oil fired
Fuel
S,
%
1.10
1.10
2.80
1.65
1.46
1.46
1.34
1.14
0.7
2
2
2
0.7
0.7
2.4
2.4
Fuel Control technology
HHV,
Btu/lb
Venturi scrubber
Steam Venturi/
spray tower
Steam Venturi/
spray tower
Heat. Tech.
caustic scrubber
Koch caustic scrubber
And. 2000 caustic
scrubber
Heat. Tech.
caustic scrubber
Koch caustic scrubber
ESP
0.08 ESP
0.09 ESP
0.10 ESP
NR ESP
NR ESP
NR ESP
NR ESP
Emissions uncontrolled/
controlled,
Ib/MMBtu
0.94a/0.03
0.94a/0.052
2.08a/0.095
1.31a/0.08
1.18a/0.07
1.18a/0.08
1.10a/0.09
0.96a/0.06
0.063/0.035
0.041/0.007
0.045/0.012
0.049/0.01 1
0.092/0.056a
0.14/0.07a
0.18/0.113a
0.35/0.1 5a
Removal
efficiency,
%
96.8a
94.5a
95.4a
93.9a
94. 1a
93.2a
91 .8a
93.8a
45
83
69
78
40
51
38.0
57.0
Ref.
14
14
14
14
14
14
14
14
14
14
14
14
18
18
18
18
4-35
-------
TABLE 4-8. CONTROLLED PM EMISSIONS
Boiler load,
actual/design
NR/48 MW
NR/593 MW
NR/595 MW
NR/589 MW
NR/119MW
NR/600 MW
NR/350 MW
5.3 MW/6.4 MW
(17.6MMBtu/h/22MMBtu/h)
5.4 MW/6.5 MW
(17.6 MMBtu/h/22 MMBtu/h)
5.4 MW/6.5 MW
(17.6 MMBtu/h/22 MMBtu/h)
5.2 MW/6.5 MW
(17.6 MMBtu/h/22 MMBtu/h)
13.6MW/16MW
(47.6 MMBtu/h 56 MMBtu/h)
NR/6.5 MW
Boiler type
Oil fired
Oil fired
Oil fired
Oil fired
Oil fired
Oil fired
Oil fired
Distillate oil/
WT packaged
Distillate oil/
WT packaged
Distillate oil/
WT packaged
Residual oil/
WT packaged
Residual oil/
WT packaged
Residual oil/
WT packaged
Fuel
S,
%
2.4
2.2
2.2
2.2
1.95
0.3
0.37
NR
NR
NR
NR
Fuel Control technology
HHV,
Btu/lb
NR ESP
NR ESP
NR ESP
NR ESP
0.09 ESP
0.02 ESP
NR ESP
LEA
LEA
OFA
LEA
LEA
OFA
Emissions uncontrolled/
controlled,
Ib/MMBtu
0.11/0.033a
0.38/0.065a
0.33/0.1 02a
0.32/0.07a
NR/0.07
0.02/0.01 7a
0.026/0.01 2a
0.06/0.04
0.06/0.01
0.06/0.03
0.08/0.07
0.15/0.11
0.08/0.07
Removal
efficiency,
%
71.0
83.0
69.0
78.0
NR
16
54
33.3
83.3
50.0
12.5
26.7
12.5
Ref.
18
18
18
18
18
18
18
13
13
13
13
13
13
Calculated value.
ESP = Electrostatic precipitator.
LEA = Low excess air.
OFA = Overfired air.
NR = Not reported.
WT = Watertube.
4-36
-------
TABLE 4-9. CONTROLLED S07 EMISSIONS
Boiler load,
actual/design
6.2 MW/6.7 MW
(21 .2 MMBtu/h/23 MMBtu/h)
6.1 MW/8.1 MW
(20.6 MMBtu/h/27.5 MMBtu/h)
13.5MW/14.7MW
(46 MMBtu/h/50 MMBtu/h)
14.1 MW/14.7MW
(48 MMBtu/h/50 MMBtu/h)
11.8MW/16.2MW
(40.3 MMBtu/h/55.2 MMBtu/h)
6.9 MW/7.3 MW
(23.8 MMBtu/h/25 MMBtu/h)
12.9MW/14.7MW
(44 MMBtu/h/50 MMBtu/h)
4.5 MW/6.4 MW
(1 5.6 MMBtu/h/22 MMBtu/h)
4.3 MW/6.4 MW
(14.7 MMBtu/h/22 MMBtu/h)
15.4MW/14.7MW
(52.5 MMBtu/h/50 MMBtu/h)
14.8MW/14.7MW
(50.5 MMBtu/h/50 MMBtu/h)
15.7MW/18.3MW
(53.8 MMBtu/h/62.5 MMBtu/h)
16.6MW/18.3MW
(56.9 MMBtu/h/62.5 MMBtu/h)
15.4MW/18.3MW
(52.5 MMBtu/h/62.5 MMBtu/h)
15.0MW/18.3MW
(51 .3 MMBtu/h/62.5 MMBtu/h)
Boiler type
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Fuel
S,
%
1.0
1.0
1.65
1.34
.60
1.00
1.46
1.56
1.61
1.58
1.66
.85
1.15
1.00
1.10
Control technology
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Emissions,
uncontrolled/
controlled
425 ng/J/38 ng/J
390 ng/J/43.0 ng/J
700 ng/J/21 .5 ng/J
700 ng/J/25.8 ng/J
345 ng/J/1 7.2 ng/J
350 ng/J/1 .7 ng/J
700 ng/J/1 2.9 ng/J
825 ng/J/1 03 ng/J
690 ng/J/38.7 ng/J
750 ng/J/77.4 ng/J
825 ng/J/34.4 ng/J
575 ng/J/1 7.2 ng/J
500 ng/J/1 2.9 ng/J
545 ng/J/21 .5 ng/J
425 ng/J/1 7.2 ng/J
Removal
efficiency,
%
91
89
96.9
96.3
95.0
99.5
98.1
87.5
94.4
89.7
95.8
97.0
97.4
96.0
96.0
Ref.
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
4-37
-------
TABLE 4-9. CONTROLLED S07 EMISSIONS
Boiler load,
actual/design
6.2 MW/6.7 MW
(21 .2 MMBtu/h/23 MMBtu/h)
15.0MW/18.3MW
(51 .3 MMBtu/h/62.5 MMBtu/h)
19.8MW/18.3MW
(67.5 MMBtu/h/62.5 MMBtu/h)
17.2MW/18.3MW
(58.8 MMBtu/h/62.5 MMBtu/h)
6.7 MW/8.8 MW
(22.8 MMBtu/h/30 MMBtu/h)
6.7 MW/7.3 MW
(23 MMBtu/h/25 MMBtu/h)
15MW/15MW
(52 MMBtu/h/52 MMBtu/h)
14.5MW/17MW
(473 MMBtu/h/57 MMBtu/h)
13MW/17MW
(40 MMBtu/h/57 MMBtu/h)
13.7MW/15MW
(40 MMBtu/h/50 MMBtu/h)
6.4 MW/7 MW
(22.8 MMBtu/h/25 MMBtu/h)
12.9MW/15MW
(42.5 MMBtu/h/50 MMBtu/h)
13.7MW/15MW
(45.5 MMBtu/h/50 MMBtu/h)
13.5MW/15MW
(45 MMBtu/h/50 MMBtu/h)
89 MW
(310 MMBtu/h)
Boiler type
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Oil-fired units
Residual oil fired
Residual oil fired
Residual oil fired
Residual oil fired
Residual oil fired
Residual oil fired
Residual oil fired
Residual oil fired
Oil
Fuel
S,
%
1.0
1.10
1.01
.80
1.20
1.46
1.10
1.10
2.80
1.65
1.46
1.46
1.34
1.14
1.5
Control technology
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Sodium scrubbing
Venturi scrubber
Steam venturi/spray
tower
Steam venturi/spray
tower
Heater tech, Caustic
scrubber
Koch Caustic scrubber
And. 2000 Caustic
scrubber
Heater tech scrubber
Koch Caustic scrubber
Dual alkali scrubber
Emissions,
uncontrolled/
controlled
425 ng/J/38 ng/J
530ng/J/215ng/J
975 ng/J/1 9.2 ng/J
550 ng/J/4.3 ng/J
465ng/J/30.1 ng/J
695 ng/J/1 2.9 ng/J
NR
NR
NR
NR
NR
NR
NR
NR
1.1 lb/MMBtu/0.091
Ib/MMBtu
Removal
efficiency,
%
91
96.0
98.0
99.2
93.5
98.1
92
99
99.9
95.0
98
96.0
92.0
99.0
91.7
Ref.
12
12
12
12
12
12
14
14
14
14
14
14
14
14
12
4-3!
-------
TABLE 4-9. CONTROLLED S07 EMISSIONS
Boiler load,
actual/design
Boiler type
Fuel
S,
Control technology
Emissions,
uncontrolled/
controlled
Removal
efficiency,
Ref.
6.2 MW/6.7 MW
(21.2 MMBtu/h/23 MMBtu/h)
70,000 SCFM
Oil-fired units
Industrial oil
1.0 Sodium scrubbing
1.5 Double Alkali System
425 ng/J/38 ng/J
17,750/710 ppm
91
96
12
4-39
-------
TABLE 4-10. CONTROLLED NOV EMISSIONS
Boiler load,
actual/design
2.5 MW/2.6 MW
(8.6 MMBtu/h/9 MMBtu/h)
4.0 MW/3.8 MW
(1 3.5 MMBtu/h/1 3 MMBtu/h)
6.3 MW/6.7 MW
(21 .6 MMBtu/h/23 MMBtu/h)
19.2MW/24MW
(65 MMBtu/h/81 MMBtu/h)
20 MW/24 MW
(67 MMBtu/h/81 MMBtu/h)
5.2 MW/6.5 MW
(1 7.6 MMBtu/h/22 MMBtu/h)
5.4 MW/6.5 MW
(17.6 MMBtu/h/22 MMBtu/h)
5.4 MW/6.5 MW
(17.6 MMBtu/h/22 MMBtu/h)
18.6MW/29MW
(64 MMBtu/h/1 00 MMBtu/h)
5.3 MW/6.5 MW
(17.6 MMBtu/h/22 MMBtu/h)
7.1 MW/9.1 MW
(24.2 MMBtu/h/31 MMBtu/h)
10.7MW/26MW
(36.1 MMBtu/h/88 MMBtu/h)
12.2MW/15MW
40.5 MMBtu/h/50 MMBtu/h)
13.6MW/16MW
(47 MMBtu/h/56 MMBtu/h)
Boiler type
Firetube/residual oil
Firetube/residual oil
Firetube/residual oil
Field erected water tube/
residual oil
Packaged water tube/residual oil
Packaged water tube/residual oil
Packaged water tube/residual oil
Packaged water tube/residual oil
Packaged water tube/residual oil
Packaged water tube/residual oil
Packaged water tube/residual oil
Packaged water tube/residual oil
Packaged water tube/residual oil
Packaged water tube/residual oil
Fuel
N,
%
0.27
1.30
0.03
0.38
0.29
0.25
0.44
0.44
0.37
0.14
0.19
NR
0.30
0.14
Control
technology
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
Emissions,
uncontrolled/
controlled,
Ib/MMBtu
(0.389/0.328)
(0.239/0.227)
(0.213/0.201)
(0.641/0.572)
(0.256/0.236)
(0.278/0.193)
(0.459/0.438)
(0.436/0.368)
(0.398/0.356)
(0.217/0.159)
(0.200/0.145)
(0.263/0.231 )
(0.251/0.230)
(0.386/0.305)
Removal
efficiency,
%
16
5
6
11
8
31
5
16
11
27
28
12
8
21
Ref.
13
13
13
13
13
13
13
13
13
13
13
13
13
13
4-40
-------
TABLE 4-10. CONTROLLED NOV EMISSIONS
Boiler load,
actual/design
13.0MW/16MW
(45.4 MMBtu/h/56 MMBtu/h)
1 .9 MW/3.8 MW
(65MMBtu/h/13MMBtu/h)
3.4 MW/7.3 MW
(1 1 .8 MMBtu/h/25 MMBtu/h)
5.5 MW/1 1 MW
(18 MM Btu/h/36 MMBtu/h)
5.1 MW/6.4MW
(17.6 MMBtu/h/22 MMBtu/h)
5.1 MW/6.4MW
(17.6 MMBtu/h/22 MMBtu/h)
4.2 MW/6.4 MW
(14.5 MMBtu/h/22 MMBtu/h)
5.3 MW/6.4 MW
(18.3 MMBtu/h/22 MMBtu/h)
8.7 MW/1 1 MW
(28.4 MMBtu/h/36 MMBtu/h)
16 MW/1 6 MW
(56 MMBtu/h/56 MMBtu/h)
5.4 MW/6.5 MW
(18.3 MMBtu/h/22 MMBtu/h)
5.4 MW/6.5 MW
(18.3 MMBtu/h/22 MMBtu/h)
18.5MW/22MW
(63 MMBtu/h/75 MMBtu/h)
6.1 MW/9.1 MW
(20.8 MMBtu/h/31 MMBtu/h)
Boiler type
Packaged water tube/residual oil
Firetube/distillate oil
Firetube/distillate oil
Packaged water tube/distillate oil
Packaged water tube/distillate oil
Packaged water tube/distillate oil
Packaged water tube/distillate oil
Packaged water tube/distillate oil
Packaged water tube/distillate oil
Packaged water tube/distillate oil
Packaged water tube/distillate oil
Packaged water tube/distillate oil
Packaged water tube/distillate oil
Packaged water tube/distillate oil
Fuel
N,
%
0.49
NR
NR
0.045
0.006
0.006
0.006
0.004
0.045
NR
0.004
0.004
NR
0.19
Control
technology
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
FGR-1 0 %
FGR-28 %
OFA
SCB
FGR-7 %
Emissions,
uncontrolled/
controlled,
Ib/MMBtu
(0.419/0.312)
(0.221/0.197)
(0.224/0.186)
(0.136/0.118)
(0.096/0.088)
(0.134/0.125)
(0.107/0.105
(0.154/0.125)
(0.158/0.134)
(0.185/0.152)
(0.154/0.041)
(0.154/0.125)
(NR/0.110)
(0.161/0.157)
Removal
efficiency,
%
26
11
17
13
10
7
2
19
15
18
73
19
NR
3
Ref.
13
13
13
13
13
13
13
13
13
13
13
13
13
13
4-41
-------
TABLE 4-10. CONTROLLED NOV EMISSIONS
Boiler load,
actual/design
6.1 MW/9.1 MW
(20.8 MMBtu/h/31 MMBtu/h)
5.3 MW/6.5 MW
(1 7.8 MMBtu/h/22 MMBtu/h)
5.2 MW/6.5 MW
(17.6 MMBtu/h/22 MMBtu/h)
5.2 MW/6.5 MW
(17.6 MMBtu/h/22 MMBtu/h)
5.1 MW/6.5 MW
(17.4 MMBtu/h/22 MMBtu/h)
12.8MW/16MW
(44.8 MMBtu/h/56 MMBtu/h)
13.6MW/16MW
(47.6 MMBtu/h/56 MMBtu/h)
40-80%-1 70 MW
40-80%-1 70 MW
40-80%-1 70 MW
40-80%-! 70 MW
40-80%-! 70 MW
40-80%-! 70 MW
40-80%-! 70 MW
40-80%-! 70 MW
60-123MW/150MW
60-123MW/150MW
60-123MW/150MW
Boiler type
Packaged water tube/distillate oil
Packaged water tube/distillate oil
Residual oil packaged watertube
Residual oil packaged watertube
Residual oil packaged watertube
Residual oil packaged watertube
Residual oil packaged watertube
O/G wall fired
O/G wall fired
O/G wall fired
O/G wall fired
O/G wall fired
O/G wall fired
O/G tangentially fired
O/G tangentially fired
Oil/wall fired
Oil/wall fired
Oil/wall fired
Fuel Control
N, technology
%
0.19 FGR-19%
0.25 FGR-25 %
0.14 OFA
0.44 OFA
0.44 OFA
0.49 OFA
0.31 OFA
BOOS
FGR
LNB + OFA
LNB + OFA +
FGR
SNCR
NCR
SNCR
NCR
BOOS
FGR
LNB + OFA
Emissions,
uncontrolled/
controlled,
Ib/MMBtu
(0.161/0.112)
(0.278/0.193)
(0.217/0.166)
(0.217/0.141)
(0.278/0.194)
(0.419/0.222)
(0.386/0.245)
(0.42/0.25)
(0.42/0.20)
(0.42/0.20)
(0.42/0.12)
(0.15/0.08)
(0.15/0.04)
(0.37/0.18)
(0.37/0.07)
(O.42/0.25)
(O.42/0.20)
(0.42/0.20)
Removal
efficiency,
%
30
31
24
35
30
47
37
40
52
52
71
47
73
51
81
40
52
52
Ref.
13
13
13
13
13
13
13
17
17
17
17
17
17
17
17
17
17
17
4-42
-------
TABLE 4-10. CONTROLLED NOV EMISSIONS
Boiler load,
actual/design
60-123MW/150MWO
60-123MW/150MW
60-123MW/150MW
60-123MW/150MW
60-123MW/150MW
60-123MW/150MW
60-123MW/150MW
Boiler type
Oil/wall fired
Oil/tangential
Oil/tangential
Oil/wall tangential
Oil/wall tangential
Oil/wall tangential
Oil/wall tangential
Fuel Control
N, technology
%
LNB + OFA +
FGR
FGR
LNB + OFA
SCR
SCR
SNCR
SNCR
Emissions,
uncontrolled/
controlled,
Ib/MMBtu
(O.42/0.12)
(0.32/0.15)
(0.32/0.12)
(O.1 5/0.04)
(O.37/0.07)
(0.15/0.08)
(0.37/0.18)
Removal
efficiency,
%
71
71
78
73
81
47
51
Ref.
17
17
17
17
17
17
17
LEA = Low excess air.
NR = Not reported.
FGR = Flue gas recirculation.
OFA = Overtired air ports.
O/G = Oil/gas.
BOOS = Burners out of service.
LNB = Low NOX burner.
SCR = Selective catalytic reduction.
SNCR = Selective non-catalytic reduction.
4-43
-------
TABLE 4-11. METALS ENRICHMENT BEHAVIOR
Class Description Reference 30 Reference 22 Reference 34
I Equal distribution
between fly ash and Al, Co, Fe, Mn, Sc, Al, Co, Cr, Fe Mn,
soot Ti Sc, Ti
II Enriched in fly ash
relative to soot As, Cd As, Cd, Pb, Sb As, Cd, Pb, Sb
III Somewhere in between
Class I and II, multiple Be, Cr, Ni, Mn Cr, Ni Ni
behavior
IV Emitted in gas phase Hg Hg Hg
4-44
-------
TABLE 4-12. HAP EMISSION FACTORS (METRIC UNITS) FOR RESIDUAL AND
DISTILLATE OIL COMBUSTION3
Firing configuration
(SCO)
Residual, Grade 6,
Normal Firing
(10100401)
Residual, Grade 6,
Normal Firing
(10100404)
Residual, Grade 6,
Normal Firing
(10200401)
Residual, Grade 6,
Normal Firing
(10300401)
Distillate, Grade 2,
(10100501)
Distillate, Grade 2,
(10200501)
Distillate, Grade 2,
(10300501)
Sb As Be Cd Cr Co Pb Mn Hg Ni Se POM HCOHb
10-20 8.2-49 1.8 6.8-91 9.0-55 33-50 12-80 10-30 0.6-14 360-964 16 3.2-3.6° 69-174
10-20 8.2-49 1.8 6.8-91 9.0-55 33-50 12-80 10-30 0.6-14 360-964 16 3.2-3.6° 69-174
10-20 8.2-49 1.8 6.8-91 9.0-55 33-50 12-80 10-30 0.6-14 360-964 16 3.2-3.6° 69-174
10-20 8.2-49 1.8 6.8 9.0-55 33-50 12-80 10-30 0.6-14 360-964 16 3.2-3.6° 69-174
1.8 1.1 4.5 21-29 - 3.8 6.0 1.3 7.3 - 9.7d 100-174
1.8 1.1 4.5 21-29 - 3.8 6.0 1.3 7.3 - 9.7d 100-174
1.8 1.1 4.5 21-29 - 3.8 6.0 1.3 7.3 - 9.7d 100-174
aAII emission factors in pg/J. All emission factors rated as E quality.
bBased on 1964 data, only four data points.
°Particulate and gaseous POM.
dParticulate POM only.
4-45
-------
TABLE 4-13. HAP EMISSION FACTORS (ENGLISH UNITS) FOR RESIDUAL AND
DISTILLATE OIL COMBUSTION3
Firing configuration
(SCO)
Residual, Grade 6,
Normal Firing
(10100401)
Residual, Grade 6,
Normal Firing
(10100404)
Residual, Grade 6,
Normal Firing
(10200401)
Residual, Grade 6,
Normal Firing
(10300401)
Distillate, Grade 2,
(10100501)
Distillate, Grade 2,
(10200501)
Distillate, Grade 2,
(10300501)
Sb As Be
24-46 19-114 4.2-
4.4
24-46 19-114 4.2-
4.4
24-46 19-114 4.2-
4.4
24-46 19-114 4.2-
4.4
4.2 2.5
4.2 2.5
4.2 2.5
Cd Cr Co Pb Mn Hg Ni Se
16- 21-128 77-121 28-194 23-74 1.4-32 837-2333 37-39
211
16- 21-128 77-121 28-194 23-74 1.4-32 837-2333 37-39
211
16- 21-128 77-121 28-194 23-74 1.4-32 837-2333 37-39
211
16- 21-128 77-121 28-194 23-74 1.4-32 837-2333 37-39
211
11 48-67 - 8.9 14 3.0 170
11 48-67 - 8.9 14 3.0 170
11 48-67 - 8.9 14 3.0 170
POM HCOHb
7.4-8.4° 161-405
7.4-8.4° 161-405
7.4-8.4° 161-405
7.4-8.4° 161-405
22d 233-405
22d 233-405
22d 233-405
aAII emission factors in lb/1012 Btu. All emission factors rated as E quality.
bBased on 1986 and limited new data.
°Particulate and gaseous POM.
dParticulate POM only.
4-46
-------
TABLE 4-14. SUMMARY OF N20 EMISSION FACTORS FOR
FUEL OIL COMBUSTION
Boiler type
Emission
factor
rating
Nitrous oxide emissions,
lb/103gal
kg/1 03I
Utility boilers
Residual oil-fired D 0.11 0.013
Industrial boilers
Residual oil-fired
Distillate oil-fired
Commercial boilers
Residual oil-fired
Distillate oil-fired
Residential furnaces
Distillate oil-fired
E
E
E
E
D
0.11a
0.11a
0.11a
0.11a
0.05
0.013a
0.01 3a
0.013a
0.013a
0.006
aNo data were available, therefore the value for utility boilers was extrapolated.
TABLE 4-15. COMPARISON OF FUGITIVE EMISSIONS OF VOCs FROM
EQUIPMENT TYPES
Equipment type
Valve - light liquid
Valve - heavy liquid
Pump - light liquid
Pump - heavy liquid
Compressor
Sampling connections
Open-ended line
Flange
Emission factor,
kg/h/sourcea
0.0071
0.00023
0.0494
0.0214
0.2280
0.0150
0.0017
0.00083
Sources leaking,
%
11. 5b
0.2b
24.0b
3.8b
58.4M
2.8C
11. 9d
7.2M
"Reference 38.
"Reference 38: Table 2-2 through Table 2-6.
Reference 39.
Reference 38: Table 2-25.
4-47
-------
TABLE 4-16. OIL-FIRED PARTICULATE SIZING DATA FOR THE CURRENT AP-42
SECTIONS: NUMBER OF A- AND B-RATED DATA SETS3
Source category
Emission control device
None
Fuel oil
- utility boilers, residual 16
- industrial boiler, residual 14
- industrial boiler, distillate 0
- commercial, residual 15
- commercial, distillate 3
- residential furn., distillate 0
Multiple
cyclones
0
0
0
0
0
NA
Scrubber
4
0
0
0
0
NA
ESP
0
0
0
0
0
NA
Baghouse
0
0
0
0
0
NA
NA = Not applicable.
aData from Reference 40.
TABLE 4-17. COMPARISON OF ORGANIC AND INORGANIC CPM EMISSIONS
FROM A 5 MILLION BTU/HR SCOTCH DRY-BACK BOILER3
Run
numberb'c
1S
U
2S
2J
3S
3J
Organic CPM
mg/m3
9.6
23.0
5.4
6.0
1.9
3.1
Ib/hr
.02
.04
.01
.01
.003
.006
% of CPM n
Inorganic CPM
ig/m3 Ib/hr
16.1 50.1 .10
32.1 48.8 .08
26.2
26.2
15.0 .03
17.1 .03
3.0 62.8 .11
15.1
17.4 .03
% of CPM
83.9
67.9
73.8
73.8
97.0
84.9
"Reference 41.
bTests 1 and 3 were run using Wilmington crude oil with a sulfur content of 1.35% sulfur and an ash
content of 0.017%. Test 2 was run with No. 6 fuel oil with a sulfur content of 0.28% and an ash content
of 0.016%.
cThe letters shown immediately after the run number denotes the use of the SASS train; the letter J
denotes the use of the EPA Method 5 train.
4-48
-------
TABLE 4-18. COMPARISON OF ORGANIC AND INORGANIC CPM EMISSIONS
FROM A TYPE-H STIRLING BOILER FIRING NO. 2 FUEL OIL3
Run
number13
Organic CPM
mg/m3
16J .2
Ib/hr
.005
% of CPM
Inorganic CPM
mg/m3
1.0 13.4
Ib/hr
.41
% of CPM
99.0
"Reference 41.
bFuel analysis results showed the sulfur content at 0.38% and the ash content at 0.001%.
TABLE 4-19. COMPARISON OF ORGANIC AND INORGANIC CPM EMISSIONS
FROM A FACE-FIRED SUPERCRITICAL 480 MW STEAM GENERATOR3
Run
numberb'c
11S
11J
12S
12J
13J
24S
24J
32S
32J
33S
33J
Organic CPM
mg/m3
1.9
4.7
.7
1.6
1.2
.6
6.8
2.8
1.6
2.4
8.5
Ib/hr
5.9
14.6
2.5
5.6
4.1
1.2
12.3
8.5
4.7
7.7
27.3
% of CPM rr
Inorganic CPM
ig/m3 Ib/hr
13.4 12.2 38.1
53.1
8.3
28.8
4.1 12.9
8.3 28.0
4.1 13.8
7.7 14.4 49.2
3.4 18.5 33.3
27.7 17.7 32.0
13.3 18.6 55.6
14.9
8.9 26.5
12.3 17.1 54.7
47.7
9.3 29.9
% of CPM
86.6
46.9
91.7
71.2
92.2
96.6
72.3
86.7
85.1
87.7
52.3
"Reference 41
bAII tests were run with No. 6 fuel oil with an average sulfur content of 0.21 % and an ash content of
0.011%.
cThe letters shown immediately after the run number denotes the use of the SASS train; the letter J
denotes the use of the EPA Method 5 train.
4-49
-------
TABLE 4-20. COMPARISON OF ORGANIC AND INORGANIC CPM EMISSIONS
FROM A FACE-FIRED, BALANCED DRAFT UTILITY BOILER3
Run
numberb'c
Organic CPM
mg/m3
21S 3.0
21J .1
22S 1.1
Ib/hr
4.3
.1
.9
% of CPM
Inorganic CPM
mg/m3
19.7 12.4
.9 10.3
5.2 19.2
Ib/hr
17.6
14.6
15.5
% of CPM
80.3
99.1
94.8
"Reference 41.
bFuel analysis results showed the sulfur content at 0.20% and the ash content at 0.012%
cThe letters shown immediately after the run number denotes the use of the SASS train; the letter J
denotes the use of the EPA Method 5 train.
TABLE 4-21. COMPARISON OF ORGANIC AND INORGANIC CPM EMISSIONS
FROM AN OIL-FIRED BOILER EQUIPPED WITH A MECHANICAL COLLECTOR3
Run
number13
Organic CPM
mg/m3
1 2.3
2 0.69
3 0.72
Ib/hr
5.6
1.6
1.4
% of CPM
Inorganic CPMC
mg/m3
7.7 27.6
3.4 19.7
2.1 33.0
Ib/hr
67.5
44.3
62.1
% of CPM
92.3
96.6
97.9
"Reference 42.
bResults for runs 1 and 2 are an average of 4 simultaneous trains purged with N2; run 3 is an average of
3 simultaneous trains.
Corrected for chlorides.
4-50
-------
CHAPTER 4 REFERENCES
1. Environmental Assessment of Coal and Oil Firing in a Controlled Industrial
Boiler, Volume I, PB 289942, U.S. Environmental Protection Agency, Research
Triangle Park, NC, August 1978.
2. Environmental Assessment of Coal and Oil Firing in a Controlled Industrial
Boiler, Volume II, EPA-600/7-78-164b, U.S. Environmental Protection Agency,
Research Triangle Park, NC, August 1978.
3. Environmental Assessment of Coal and Oil Firing in a Controlled Industrial
Boiler, Volume III, EPA-600/7-78-164c, U.S. Environmental Protection Agency,
Research Triangle Park, NC, August 1978.
4. Emission Reduction on Two Industrial Boilers with Major Combustion
Modifications, EPA-600/7-78-099a, U.S. Environmental Protection Agency,
Research Triangle Park, NC, August 1978.
5. Emission Reduction on Two Industrial Boilers with Major Combustion
Modifications, Data Supplement, EPA-600/7-78-099b, U.S. Environmental
Protection Agency, Research Triangle Park, NC, August 1978.
6. Environmental Assessment of an Oil-fired Controlled Utility Boiler, EPA-600/7-
80-087, U.S. Environmental Protection Agency, Research Triangle Park, NC,
April 1980.
7. Thirty-day Field Tests of Industrial Boilers: Site 2 - Residual Oil-fired Boiler, EPA-
600/7-80-085b, U.S. Environmental Protection Agency, Research Triangle Park,
NC, April 1980.
8. Industrial Boilers Emission Test Report, Boston Edison Company, Everett,
Massachusetts, EMB Report 81-IBR-15, U.S. Environmental Protection Agency,
Research Triangle Park, NC, October 1981.
9. Residential Oil Furnace System Optimization, phase II. EPA-600/2-77-028, U.S.
Environmental Protection Agency, Research Triangle Park, NC, January 1977.
10. Characterization of Particulate Emissions from Refinery Process Heaters and
Boilers, API Publication No. 4365, June 1983.
11. Ekmann, James, et al.. Comparison of Shale Oil and Residual Fuel Combustion
in Symposium Papers New Fuels and Advances in Combustion Technologies
Sponsored by Institute of Gas Technology, March 1979.
12. Overview of the Regulatory Baseline, Technical Basis, and Alternative Control
Levels for S02 Emission Standards for Small Steam Generating Units, EPA-
4-51
-------
450/3-89-012, (PB89-203673), U.S. Environmental Protection Agency, Research
Triangle Park, NC, May 1989.
13. Overview of the Regulatory Baseline, Technical Basis, and Alternative Control
Levels for NOx Emission Standards for Small Steam Generating Units, EPA-
450/3-89-013, (PB89-203699), U.S. Environmental Protection Agency, Research
Triangle Park, NC, May 1989.
14. Overview of the Regulatory Baseline, Technical Basis, and Alternative Control
Levels for PM Emission Standards for Small Steam Generating Units, EPA-
450/3-89-011, (PB89-203715), U.S. Environmental Protection Agency, Research
Triangle Park, NC, May 1989.
15. Industrial Boiler Combustion Modification NOx Controls, Volume I. Environmental
Assessment, EPA-600/7-81-126a, U.S. Environmental Protection Agency,
Research Triangle Park, NC, July 1981.
16. Field Testing: Application of Combustion Modifications to Control Pollutant
Emissions from Industrial Boilers - Phase II, EPA-600/2-76-086a, U.S.
Environmental Protection Agency, Research Triangle Park, NC, April 1976.
17. Evaluation and Costing of NOx Controls for Existing Utility Boilers in the
NESCAUM Region, Acurex Report (Draft), September 23, 1991.
18. Fossil Fuel Fired Industrial Boilers - Background Information: Volume 1, EPA-
450/3-82-006a, U.S. Environmental Protection Agency, Research Triangle Park,
NC, March 1982.
19. AP-42 Section 1.3, Supplement A, October, 1986.
20. Krishnan, R.E. and G.V. Helwig, "Trace Emissions from Coal and Oil
Combustion", Environmental Progress, 1(4): 290-295, 1982.
21. Brooks, G.W., M.B. Stockton, K. Kuhn, and G.D. Rives, Locating and
Estimating Air Emission from Source of Polvcvclic Organic Matter (POM),
EPA-450/4-84-007p. U.S. Environmental Protection Agency, Research
Triangle Park, NC, May 1988.
22. Leavitt, Arledge, and Shih, et. al., Environmental Assessment of Coal- and
Oil-firing in a Controlled Industrial Boiler, Volume I, II and III, August 1978.
23. Shih, C.C., R.A. Arisini, D.G. Ackerman, R. Moreno, E.L. Moon, L.L.
Scinto, and C. Yu, Emissions Assessment of Conventional Stationary
Combustion Systems: Volume III: External Combustion Sources for
Electricity Generation, EPA-600/7-81-003a, November 1980.
4-52
-------
24. Suprenant, N., R. Hall,, S. Slater, T. Susa, M. Sussman, and C. Young,
Preliminary Emissions Assessment of Conventional Stationary
Combustion Systems, Volume II - Final Report, EPA-600/2-76-046b,
March 1976.
25. Johnson, N.D. and M.T. Schultz, MOE Toxic Chemical Emissions
Inventory for Ontario and Eastern North America, Draft Report, P89-50-
5429/OG, March 15, 1990.
26. Taback, H.J., et al., Control of Hydrocarbon Emissions from Stationary
Sources in the California South Coast Air Basin, Volume II, KVB, Inc.,
Tustin, CA, June 1978.
27. Regional Air Pollution Study - Point Source Emission Inventory, EPA-
600/4-77-014 (NTIS No. PB 269567), March 1977.
28. Locating and Estimating Air Emissions from Sources of Chromium, EPA-
450/4-84-007g, U.S. Environmental Protection Agency, Research Triangle
Park, NC, July 1984.
29. Locating and Estimating Sources of Formaldehyde (Revised), EPA-450/4-
91-012, U.S. Environmental Protection Agency, Research Triangle Park,
NC, March 1991.
30. Estimating Air Toxics Emissions from Coal and Oil Combustion Sources,
EPA-450/2-89-001, April 1989.
31. Ventura County Air Pollution Control District, Ventura County, CA, source
test data for three utility boilers.
32. Suprenant, N.F., et al., Emissions Assessment of Conventional Stationary
Combustion Systems, Volume V: Industrial Combustion Sources, EPA-
600/7-81-003c, 1981.
33. Locating and Estimating Air Emissions from Sources of Manganese, EPA-
450/4-84-007h, September 1985.
34. Lyon, W.S., Trace Element Measurements at the Coal-Fired Steam Plant, CRC
Press, 1977.
35. Locating and Estimating Air Emissions from Sources of Polycyclic Organic Matter
(POM), EPA-450/4-84-007p, U.S. Environmental Protection Agency, Research
Triangle Park, NC, May 1988.
4-53
-------
36. EPA/IFP European Workshop on the Emission of Nitrous Oxide for Fuel
Combustion, EPA Contract No. 68-02-4701, Ruiel-Malmaison, France, June 1-2,
1988.
37. Linak, W.P., et al., "Nitrous Oxide Emission from Fossil Fuel," Journal of
Geophysical Research, June 1989, Prepared for Submission.
38. Fugitive Emission Sources of Organic Compounds - Additional Information on
Emissions, Emission Reductions, and Costs, EPA-450/3-82-010, U.S.
Environmental Protection Agency, Research Triangle Park, NC, April 1982.
39. Eaton, W.S., et al., "Fugitive Hydrocarbon Emissions from Petroleum Production
Operations," Vols. 1-2, API Publication No. 4322, American Petroleum Institute,
March 1980.
40. Van Buren, D., D. Barbe, and A.W. Wyss, External Combustion Particulate
Emissions: Source Category Report, November 1986, EPA-600/7-86-043.
41. Taback, H.J., A.R. Brienza, J. Macko, and N. Brunetz, "Fine Particulate
Emissions from Stationary and Miscellaneous Sources in the South Coast Air
Basin", prepared for the California Air Resources Board by KVB Inc., report
#KVB 5806-783, February 1979.
42. Segall, R. and P. Royals, "Field Evaluation of Draft Method 202 for Measurement
of Condensible Particulate Matter", prepared under U. S. Environmental
Protection Agency Contract No. 68D90055, Work Assignment No. 46, January
1991.
43. Miller, S.J. and D.L. Laudal, Particulate Characterization, DOE/FE/60181-2089,
June 1986
44. Lane, William and Anup Khosla, "Comparison of Baghouse and Electrostatic
Precipitator Fine Particulate, Trace Element, and Total Emissions", presented at
ASME-IEEE Joint Power Generation Conference, September 27, 1983.
45. EPRI CS-5040, "Precipitator Performance Estimation Procedure", prepared by
Southern Research Institute, February 1987
46. PM-10 Emission Factor Listing Developed by Technology Transfer, EPA-450/4-
89-022.
47. Gap Filling PM10 Emission Factors for Selected Open Area Dust Sources, EPA-
450/88-003.
48. Generalized Particle Size Distributions for Use in Preparing Size Specific
Particulate Emission Inventories, EPA-450/4-86-013.
4-54
-------
49. Belba, V. H., et al., "A Survey of the Performance of Pulse-Jet Baghouses for
Application to Coal-Fired Boilers Worldwide", presented at the Eighth Particulate
Control Symposium, November 1990.
50. Gushing, K., V. Belba, and R. Chang, "Fabric Filtration Experience Downstream
from Atmospheric Fluidized Bed Combustion Boilers", presented at the Ninth
Particulate Control Symposium, October 1991.
51. Mcllvaine, R. W., "Particulate Forecast: Markets and Technology", presented at
the Ninth Particulate Control Symposium, Sessions 1B-3B, October 1991.
52. Barton, R.G., W.D. Clark, and W.R. Seeker, "Fate of Metals in Waste
Combustion Systems", Combustion Science and Technology, Volume 74, 1990.
53. Ebbinghaus, B.B., Analysis of Chromium Volatility in the DWTF Incinerator and
in the Molten Salt Processor, DOE Contract No. W-7405-ENG-48, Livermore,
CA, 1992.
4-55
-------
5. AP-42 SECTION 1.3: FUEL OIL COMBUSTION
The revision to Section 1.3 of AP-42 is presented in the following pages as it
would appear in the document. A marked-up copy of the 1986 version of this section is
included in Appendix B.
4-56
-------
TABLE A-1. CONVERSION FACTORS
To obtain:
Ib pollutant/103 gal
kg pollutant/1 03C
Oil HHV in Btu/gal
Oil density in Ib/gal
From:
Ib pollutant/MMBtu
Ib pollutant/103 gal
Oil HHV in Btu/lb
°API
Multiply by:
1Q-3xOil HHV in
Btu/gala
0.1195
Oil density in
lb/galb
Use:
141.57(131.5 +
°API)x8.34
alf oil higher heating value (HHV) is not available, use:
Residual oil HHV = 150,000 Btu/gal.
Distillate oil HHV = 140,000 Btu/gal.
blf oil density is not available, use:
Residual oil density = 8 Ib/gal.
Distillate oil density = 7 Ib/gal.
A-58
-------
APPENDIX B
MARKED-UP 1986 AP-42 SECTION 1.3
B-59
-------
REPORT ON REVISIONS TO
5TH EDITION AP-42
Section 1.3
Fuel Oil Combustion
Prepared for:
Contract No. EPA 68-D2-0160, WA-50
EPA Work Assignment Officer: Roy Huntley
Office of Air Quality Planning and Standards
Office of Air And Radiation
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Prepared by:
Eastern Research Group
Post Office Box 2010
Morrisville, North Carolina 27560
December 1996
B-60
-------
Table of Contents
Page
1.0 INTRODUCTION 1-1
2.0 REVISIONS 2-1
2.1 General Text Changes 2-1
2.2 Sulfur Oxides, SOX 2-1
2.3 Sulfur Trioxide, SO3 2-1
2.4 Nitrogen Oxides, NOX 2-1
2.5 Carbon Monoxide, CO 2-1
2.6 Filterable Paniculate Matter, PM 2-2
2.7 Total Organic Compounds (TOC) and Non-Methane TOC (NMTOC) 2-3
2.8 Particle Size Distribution 2-3
2.9 Polycyclic Organic Matter (POM) and Formaldehyde (HCOH) 2-4
2.10 Trace Elements 2-4
2.11 Greenhouse Gases 2-4
2.11.1 Carbon Dioxide, CO2 2-4
2.11.2 Methane 2-6
2.11.3 Nitrous Oxide 2-6
2.12 Speciated Organic Compounds 2-7
3.0 REFERENCES 3-1
4.0 REVISED SECTION 1.3 4-1
5.0 EMISSION FACTOR DOCUMENTATION, APRIL 1993 5-1
APPENDIX A SUPPORTING DOCUMENTATION
A.I Data Used for Average Emission Factors Development
A.2 Source Test Report Summary Data
B-iii
-------
1.0 INTRODUCTION
This report supplements the Emission Factor (EMF) Documentation for AP-42 Section
1.3, Fuel Oil Combustion, dated April, 1993. The EMF describes the source and rationale for the
material in the most recent updates to the 4th Edition, while this report provides documentation
for the updates written in both Supplements A and B to the 5th Edition.
Section 1.3 of AP-42 was reviewed by internal peer reviewers to identify technical
inadequacies and areas where state-of-the-art technological advances need to be incorporated.
Based on this review, text has been updated or modified to address any technical inadequacies or
provide clarification. Additionally, emission factors were checked for accuracy with information
in the EMF Document and new emission factors generated if recent test data were available.
If discrepancies were found when checking the factors with the information in the EMF
Document, the appropriate reference materials were then checked. In some cases, the factors
could not be verified with the information in the EMF Document or from the reference materials,
in which case the factors were not changed.
Four sections follow this introduction. Section 2 of this report documents the revisions
and the basis for the changes. Section 3 presents the references for the changes documented in
this report. Section 4 presents the revised AP-42 Section 1.3, and Section 5 contains the EMF
documentation dated April, 1993.
1-1
-------
2.0 REVISIONS
2.1 General Text Changes
Information in the EMF Document was used to enhance text concerning fuel oil firing
practices. Also, at the request of EPA, the metric units were removed.
2.2 Sulfur Oxides. SO,
The uncontrolled SOX factors were checked against information in Table 4-3 of the EMF
Document and the 10/86 version of Section 1.3 and no changes were required.
2.3 Sulfur Trioxide. SO.
The SO3 factors were checked against information in Table 4-4 of the EMF Document
and the 10/86 version of Section 1.3 and no changes were required.
2.4 Nitrogen Oxides. MX
The uncontrolled NOX factors were checked against information in Table 4-6 of the EMF
Document and the 10/86 version of Section 1.3 and no changes were required.
2.5 Carbon Monoxide. CO
The CO factors were checked against information in Table 4-5 of the EMF Document and
the 10/86 version of AP-42 and no changes were required.
2-1
-------
2.6 Filterable Particulate Matter. PM
Filterable PM emission factors were checked against information in Table 4-2 of the EMF
Documentation and the 10/86 version of AP-42. The only change required was for the PM
emission factors for residential furnaces.1'2 Several new reports were reviewed and two
contained PM emission data for new oil-fired residential furnaces. Based on these reports, it was
determined that newer furnaces (i.e., pre-1970) emit significantly less PM than older furnaces
(i.e., pre-1970). The existing PM emission factor for residential furnaces in the 5th Edition of
AP-42 is based solely on pre-1970 data.
Table 1 presents the PM data for newer furnaces. The existing PM factor is 3.0 lb/1000
gal, is rated "A", and is based on 33 pre-1970 data points. The PM emission factor for newer
furnaces is 0.4 lb/1000 gal, is based on 9 post-1970 data points, and is rated "C". The PM
emission factor for new furnaces (0.4 lb/1000 gal) was added and a footnote included to qualify it
as being based on new furnaces designs and pre-1970's burner designs may emit as high as 3.0
lb/1000 gal.
2-2
-------
Table 1. Summary of Particulate Emission Data for New
Residential Oil-Fired Furnaces
Reference/Page
McCrillis, Page 4
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Krajewski, Page 40-42
Average
Data
Rating
B
B
B
B
B
B
B
B
B
C
Furnace/Burner type
Thermo-Pride Model: M-SR
R.W. Beckett Co. Model: AF
R.W. Beckett Co. Model: AFG
R.W. Beckett Co. Model: AFG
Riello Corp. Model: Mectron 3M
Energy Kinetics Inc. Model: System 2000
Bentone Electrol Oil Model: Airtronic
Combustion Technology
No model number
Foster Miller Carlin Co.
No model number
Filterable PM
Emission Factor
(lb/1000 gal)
0.42
0.38
0.3
0.4
0.65
0.26
0.35
0.4
0.24
0.38
0.35
No data
0.4
2.7 Total Organic Compounds (TOO and Non-Methane TOC (NMTOO
The TOC and NMTOC factors were checked against information on page 4-7 of the EMF
Document and the 10/86 version of AP-42 and no changes were necessary.
2.8 Particle Size Distribution
The particle size factors were checked against information in the EMF Document and the
10/86 version of AP-42 and no changes were required.
2-3
-------
2.9 Polvcvclic Organic Matter (POM} and Formaldehyde (HCOID
The POM and HCOH factors in Table 1.3-7 were checked with information in Tables 4-
12 and 4-14 of the EMF Document and no changes were required.
2.10 Trace Elements
Trace element factors were checked against Table 4-12 in the EMF Document. Based on
recent test data, the factors for residual oil firing shown in Table 1.3-8 were revised (with the
exception of antimony). New factors for barium, chloride, chromium VI, copper, fluoride,
molybdenum, phosphorus, vanadium, and zinc were added. The data used to calculate the new
and revised factors are presented in Appendix A.
The spreadsheets found in Appendix A present calculated average emissions factors
based on new test data. Trace elements and speciated organic compounds are presented in
Section A. 1. Section A.2 contains the individual source test report summaries.
Data from sources tested at several EPRI, Southern California Edison, and Pacific Gas
and Electric sites were entered into the spreadsheets. The emission factor were evaluated for
patterns based on boiler type and controls. No patterns were found; therefore, the data were
averaged (arithmetic mean) together by pollutant.
Special consideration was given to non-detected values in calculating the average factors.
If a pollutant was not detected in any sampling run, half of the detection limit (DL/2) was used in
the calculated average factor. For a given pollutant, any DL/2 factors that were greater than any
factors based on detected values were not included in the calculated averages.
Data from each source test were given a quality rating based on EPA procedures. The
ratings ranged from B-D in the tests evaluated for this report. A "B" rating was given for tests
2-4
-------
performed by a generally sound methodology but lacking enough detail for validation. A "C"
rating was given for tests based on untested or new methodology or lacking a significant amount
of background data. When a test was based on a generally unacceptable method but provided an
order-of-magnitude value for the source, a "D" rating was assigned.
2.11 Greenhouse Gases
2.11.1 Carbon Dioxide, CO2
Table 1.3-1 computes CO2 emissions through a footnote that assumes 100 percent
conversion of fuel carbon content to CO2 during combustion. This does not account for
unoxidized fuel in the exhaust stream, which is typically 1 percent for liquid fuels in external
combustion systems.3"5 The factor in note f of Table 1.3-1 was modified to reflect 99 percent
conversion instead of the current 100 percent. These new factors appear in Table 2, below.
2-5
-------
Table 2. Emission Factor Equations for Solid and Liquid Fuel Combustion
Emission Factor Rating: B
Fuel
No. 1
(kerosene)
No. 2
No. 6
Multiply
% carbon
% carbon
% carbon
Density
(Ib/gal)
6.88
7.05
7.88
Conversion
Factor3
250
256
286
To Obtain
IbCCyiOOOgal
IbCCyiOOOgal
IbCCyiOOOgal
The following equation was used to develop the emission factor equation for fuel oils in
Table 3-1:
44 Ib C02
12 Ib C
x 0. 99 x 1 .05
Ib
x
1
gal 100%
x 1000 = 256
Ib CO,
1000 gal %C
Where: 0.99 = fraction of fuel oxidized during combustion (References 3-5), and
7.05 Ib/gal = density of No. 2 fuel oil (AP-42 Appendix A).
The factors for kerosene and No. 6 oil were computed as shown in note a to Table 2 using
the density values from AP-42 Appendix A.
Table 3 lists default emission factors for fuel oils when the carbon content is not known.
These figures are based on average carbon contents for each type of fuel and the equation shown
in note A of Table 2.
2-6
-------
Table 3. Default CO2 Emission Factors for Liquid Fuels
Quality Rating: B
Fuel Type
No. 1 (kerosene)
No. 2
Low Sulfur No. 6
High Sulfur No. 6
%ca
86.25
87.25
87.26
85.14
Density"
(Ib/gal)
6.88
7.05
7.88
7.88
Emission Factor (lb/1000 gal)
21,500
22,300
25,000
24,400
aAn average of the values of fuel samples in References 6-7.
References 6 and 8.
2.11.2 Methane
No new data found.
2.11.3 Nitrous Oxide, N2O
The current "E" rated N2O emission factors in Table 1.3-9 were updated with more recent
data that take into account an N2O sampling artifact discovered by Muzio and Kramlich in 1998.4
These new emission factors in Table 4 are based on a more complete database of source
sampling than either of the references listed for the previous N2O emission factors in AP-42.
Table 4. N2O Emission Factors for Fuel Oil Combustion"
(Ib N2O/1000 gal)
Fuel
No. 6
No. 2
Combustion Category
Industrial/utility boilers
Industrial/utility boilers
New
B
B
NewEF
0.53
0.26
Previous
0.11
0.11
Previous
E
E
'References 10-11.
2-7
-------
The industrial/utility boilers data for No. 6 fuel oil is based on 6 tests at 4 different
facilities collected by Nelson.10 The data for No. 2 fuel oil for industrial/utility boilers is based
on 14 source tests conducted at 6 facilities collected by Nelson.10
The data sets were converted to Ib/MMBtu according to the procedures given in 40 CFR
60, Appendix A. To obtain Ibs/MMBtu, the emissions (in ppm) were first multiplied by 1.141 x
10"7 (lb/scf)/ppm. These values were then converted to Ib/MMBtu using the following formula:
E =
20.9
20.9 - %00
Where: Cd =N2O;
Fd = F-factor for oxygen; and
%O2 = oxygen concentration in the exhaust gas.
The following F-factors and heating values were used for the calculations:
Fuel
No. 6 (residual)
No. 2 (distillate)
F-Factor
(scf/MMBtu)
9,190
9,190
Heating Value
(Btu/gal)
150,000
140,000
2.12 Speciated Organic Compounds
Based on new test data, a total of twenty-one new factors were developed for residual oil
fired boilers. The average factors and the data used to calculate the factors are presented in
Appendix A. The formaldehyde factor calculated with this data is based on recent tests of utility
boilers only.
2-8
-------
3.0 REFERENCES
1. McCrillis, R.C., and R. R. Watts, Analysis of Emissions from Residential Oil
Furnaces, U. S. Environmental Protection Agency, 92-110.06, Undated, page 4.
2. Krajewski, R. et al., Emissions Characteristics of Modern Oil Heating Equipment.
BNL-52249. Brookhaven National Laboratory. July 1990, pages 40-42.
3. Marland, G. and R.M. Rotty, "Carbon Dioxide Emissions from Fossil Fuels: A
Procedure for Estimation and Results for 1951-1981," DOE/NBB-0036 Tr-003, Carbon
Dioxide Research Division, Office of Energy Research, U.S. Department of Energy, Oak
Ridge, TN, 1983.
4. Rosland, A., Greenhouse Gas Emissions In Norway: Inventories And Estimation
Methods, Oslo: Ministry of Environment, 1993.
5. Sector-Specific Issues And Reporting Methodologies Supporting The General Guidelines
For The Voluntary Reporting Of Greenhouse Gases Under Section 1605(b) Of The
Energy Policy Act Of 1992, DOE/PO-9928, Volume 2 of 3, U.S. Department of Energy,
1994.
6. Perry, R. H. and D. Green, Perry's Chemical Engineers Handbook, Sixth ed., New York:
McGrawHill, 1984.
7. Steam: Its Generation And Use, Babcock and Wilcox, New York, 1975.
8. Compilation Of Air Pollutant Emission Factors, Volume I: Stationary Point And Area
Sources, U.S. Environmental Protection Agency, AP-42. Fifth Edition, 1995. Research
Triangle Park, NC.
9. Muzio, L.J., and J.C. Kramlic, "An Artifact in the Measurement of N2O from
Combustion Sources," Geophysical Research Letters, Volume 15, No. 12 (Nov),
pp. 1369-1372, 1988.
10. Nelson, L.P. etal., "Global Combustion Sources of Nitrous Oxide Emissions," Research
Project 233-4 Interim Report, Sacramento: Radian Corporation, 1991.
11. Peer, R. L. et al., "Characterization of Nitrous Oxide Emission Sources," Prepared for the
US EPA Contract 68-D1-0031, Research Triangle Park, NC: Radian Corporation, 1995.
5-1
-------
4.0 RE VISED SECTION 1.3
This section contains the revised Section 1.3 of AP-42, 5th Edition. The electronic
version can be located on the EPA TTN at http://134.67.104.12/html/chief/fsnpub.htm.
4-1
-------
5.0 EMIS SIGN FACTOR DOCUMENTATION, APRIL 1993
This section contains the Emission Factor Documentation for Section 1.3 dated
April 1993. The electronic version can be located on the EPA TTN at
http://134.67.104.12/html/chief/fbgdocs.htm. The zipped file on the TTN contains this (1996)
background report as well as the 1993 Emission Factor Documentation.
4-1
-------
APPENDIX A
SUPPORTING DOCUMENTATION
-------
-------
A. 1 Data Used for Average Emission Factors Development
-------
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION
Entry
No.
1
2
3
4
5
7
9
11
12
14
20
21
23
Ref
No.
1
2
2
3
3
3
3
3
3
3
6
7
7
Facility
EPRI SITE 13
EPRI SITE 112
EPRI SITE 112
EPRI SITE 103
EPRI SITE 104
EPRI SITE 105
EPRI SITE 106
EPRI SITE 107
EPRI SITE 108
EPRI SITE 109
Southern California
Edison Company,
Alamitos Unit 5
Pacific Gas and
Electric Company,
Morro Bay Unit 3
Pacific Gas and
Electric Company,
Morro Bay Unit 3
Fuel
Type
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual
Residual
Residual
Boiler
Type
Wall-Fired
(Normal)
Tangentially-Fired
Tangentially-Fired
Wall-Fired
(Normal)
Assumed Normal
Assumed Normal
Assumed Normal
Assumed Normal
Opposed (Normal)
Opposed (Normal)
Assumed Normal
Radiant Heat
Radiant Heat
sec
10100401
10100404
10100404
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
Control
Device la
Uncontrolled
ESP
ESP
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
FOR
FOR
None
None
Control
Device T
None
None
None
None
None
None
None
None
None
None
None
None
None
Data
Quality
B
C
C
B
B
B
B
B
B
B
C
C
C
No. Of
Test
Runs
3
3
4
3
3
3
3
3
3
3
3
3
3
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry
No.
24
26
16
17
Ref
No.
8
8
4
5
Facility
Southern California
Edison Company,
El Segundo
Station 1
Southern California
Edison Company,
El Segundo
Station 1
EPRI SITE 118
Southern California
Edison Company
Long Beach
Auxiliary Boiler
Fuel
Type
Residual
Residual
Residual (No. 6)
Distillate Oil
Boiler
Type
Assumed Normal
Assumed Normal
Front-fired
(normal)
Assumed Normal
sec
10100401
10100401
10100401
10100501
Control
Device la
None
None
OFA/FGR
None
Control
Device 2a
None
None
ESP
None
Data
Quality
C
C
Dd
C
No. Of
Test
Runs
3
3
3
3
I
I
3
>
3 UNC = Uncontrolled; FGR = Flue Gas Recirculation; OFA = Over-fire Air; ESP = Electrostatic Precipitator.
b>c At least one test run was "non detect" and the emission factor is based on detection limit values, (b = one "non detect", c = more than one "non
detect").
d Data quality ratings of "D" were not used for averaging with "B" and "C" quality data.
f Pollutant was Not Detected in any of the sampling runs. Half of the detection limit value (DL/2) used to develop factor.
B For a given pollutant, any factors based solely on "non detect" values that were greater than any factors based on detected values were not
included in the calculated average factor.
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
Benzene
2.10e-04
3.51e-04
4.90e-04f
1.85e-04f
1.87e-04f
2.25e-04f
3.02e-04f
2.02e-04f
7.20e-04f
1.80e-04f
1.85e-04f
2.27e-04f
2.14e-04
7.83e-05
9.00e-08f
1,3 -Butadiene
1.18e-05f
Carbon
Tetrachloride
6.95e-05f
Chloro-benzene
5.10e-05f
Chloroform
8.05e-05f
Ethyl-benzene
6.36e-05
Ethylene
Dichloride
1.56e-04f
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
Formaldehyde
1.26e-03c
1.96e-03
1.50e-03f
2.50e-02b
9.26e-02
1.50e-03f
9.05e-02
1.44e-03f
5.96e-02
8.25e-04f
2.44e-02c
1.12e-03f
3.30e-02
7.98e-04
3.20e-06f
Methyl Bromide
1.29e-04f
Naphthalene
4.53e-07f
6.36e-04
1.94e-03b
5.55e-04
9.05e-04c
7.50e-05b
4.91e-03
4.00e-04
6.18e-04
1.27e-03
1.13e-03
4.58e-05
7.00e-llf
Perchloro-
ethylene
3.73e-05f
Propylene
Dichloride
1.78e-04f
1,1,1-TCA
2.36e-04
Toluene
7.94e-04
1.16e-02
6.20e-03
1.12e-03
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
Trichloroethane
8.85e-05f
Vinyl Chloride
1.06e-04f
o-Xylene
1.09e-04
Acenaphthene
4.53e-07f
1.48e-05b
5.25e-07f
9.90e-05
7.55e-07f
5.75e-07f
8.04e-06
6.82e-05
1.51e-05
3.20e-06
2.11e-05
7.00e-llf
Acenaphthylene
4.53e-07f
7.40e-07f
5.25e-07f
7.50e-07f
7.55e-07f
5.75e-07f
2.53e-07
6.11e-07f
6.82e-07f
5.23e-07f
2.53e-07
7.00e-llf
Anthracene
4.53e-07f
7.40e-07f
5.25e-07f
7.50e-07f
1.51e-06c
5.75e-07f
2.83e-06
1.31e-06c
1.36e-06c
2.16e-06c
1.22e-06
7.00e-llf
Benz(a)an-
thracene
4.53e-07f
7.40e-07f
4.48e-06c
7.50e-07f
1.51e-05b
5.75e-07f
1.31e-06
6.11e-07f
6.82e-07f
1.54e-05c
4.01e-06
7.00e-llf
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
Benzo(a)pyrene
4.53e-07f
7.40e-07f
5.25e-07f
7.50e-07f
7.55e-07f
5.75e-07f
6.11e-07f
6.82e-07f
2.76e-06f
7.00e-llf
Benzo(b,k)
fluoranthene
4.53e-07f
7.40e-07f
2.39e-06c
7.50e-07f
6.04e-06c
5.75e-07f
6.11e-07f
6.82e-07f
1.05e-06c
1.48e-06
7.00e-llf
Benzo(g,h,i)
perylene
4.53e-07f
7.40e-07f
1.49e-06c
7.50e-07f
4.53e-06c
5.75e-07f
6.11e-07f
6.82e-07f
1.05e-05c
2.26e-06
7.00e-llf
Chrysene
4.53e-07f
7.40e-07f
8.96e-07c
7.50e-07f
9.05e-06b
5.75e-07f
3.13e-06
6.11e-07f
6.82e-07f
6.87e-06c
2.38e-06
7.00e-llf
Dibenzo(a,h)-
anthracene
6.11e-07f
6.82e-07f
3.73e-06c
1.67e-06
7.00e-llf
Fluoranthene
4.53e-07f
7.40e-07f
5.98e-06
1.35e-06c
1.36e-05b
5.75e-07f
1.12e-05
1.41e-06c
1.36e-06c
1.17e-05c
4.84e-06
7.00e-llf
Fluorene
2.93e-06
4.53e-07f
2.07e-06
2.99e-06c
5.55e-06
6.04e-07c
5.75e-07f
2.38e-05
3.82e-06
4.66e-06c
1.69e-06c
4.47e-06
7.00e-llf
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
Indeno( 1,2,3 -
cd)pyrene
4.53e-07f
7.40e-07f
1.49e-06c
7.50e-07f
4.53e-06c
5.75e-07f
6.11e-07f
6.82e-07f
9.44e-06c
2.14e-06
7.00e-llf
Phenanthrene
2.93e-06
4.53e-07f
1.63e-06b
1.34e-05
5.40e-06
1.81e-05b
2.88e-06c
4.91e-05
3.67e-06
1.63e-06c
1.63e-05c
1.05e-05
1.77e-06
7.00e-llf
Pyrene
4.53e-07f
1.48e-06c
3.44e-06c
7.50e-07f
1.21e-05b
1.15e-06b
9.83e-06
1.26e-06c
1.40e-06c
1.07e-05c
4.25e-06
7.00e-llf
2.3.7.8-TCDD
3.18e-10f
TCDD
3.18e-10f
PeCDD
3.40e-10f
HxCDD
5.05e-10f
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
HpCDD
1.85e-09f
OCDD
3.10e-09b
2.3.7.8-TCDF
1.33e-10f
PeCDF
1.92e-10f
HxCDF
3.70e-10f
HpCDF
2.52e-09f
OCDF
1.18e-09f
£
w
t
a
to
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - METALS - DL/2
FUEL OIL COMBUSTION
Entry
No.
1
2
4
5
6
7
8
9
10
11
12
13
14
15
18
Ref
No.
1
2
3
3
3
3
3
3
3
3
3
3
3
3
6
Facility
EPRI SITE 13
EPRI SITE 112
EPRI SITE 103
EPRI SITE 104
EPRI SITE 104
EPRI SITE 105
EPRI SITE 106
EPRI SITE 106
EPRI SITE 106
EPRI SITE 107
EPRI SITE 108
EPRI SITE 108
EPRI SITE 109
EPRI SITE 109
Southern California
Edison Company,
Alamitos Unit 5
Fuel Type
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual
Boiler Type
Wall-Fired
(Normal)
Tangentially-Fired
Wall-Fired
(Normal)
Assumed Normal
Assumed Normal
Assumed Normal
Assumed Normal
Assumed Normal
Assumed Normal
Assumed Normal
Opposed (Normal)
Opposed (Normal)
Opposed (Normal)
Opposed (Normal)
Assumed Normal
sec
10100401
10100404
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
Control
Device la
Uncontrolled
ESP
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
FOR
FOR
FOR
Control
Device T
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
Data
Quality
B
C
B
B
B
B
B
B
B
B
B
B
B
B
B
No.
of
Test
Runs
3
3
3
3
2
3
6
3
4
3
3
2
3
2
6
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - METALS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry
No.
19
22
23
25
16
Ref
No.
6
7
7
8
4
Facility
Southern California
Edison Company,
Alamitos Unit 5
Pacific Gas and
Electric Company,
Morro Bay Unit 3
Pacific Gas and
Electric Company,
Morro Bay Unit 3
Southern California
Edison Company, El
Segundo Station 1
EPRI SITE 118
Fuel Type
Residual
Residual
Residual
Residual
Residual (No. 6)
Boiler Type
Assumed Normal
Radiant Heat
Radiant Heat
Assumed Normal
Front-fired
(normal)
sec
10100401
10100401
10100401
10100401
10100401
Control
Device la
FOR
None
None
None
OFA/FGR
Control
Device 2a
None
None
None
None
ESP
Data
Quality
C
C
C
C
Dd
No.
of
Test
Runs
3
3
3
3
3
£
w
t
a
to
3 UNC = Uncontrolled; FGR = Flue Gas Recirculation; OFA = Over-fire Air; ESP = Electrostatic Precipitator.
b>c At least one test run was "non detect" and the emission factor is based on detection limit values, (b = one "non detect", c = more than one
"non detect")
d Data quality ratings of "D" were not used for averaging with "B" and "C" quality data.
f Pollutant was Not Detected in any of the sampling runs. Half of the detection limit value (DL/2) used to develop factor.
B For a given pollutant, any factors based solely on "non detect" values that were greater than any factors based on detected values were not
included in the calculated average factor.
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - METALS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
4
5
6
7
8
9
10
11
12
13
14
15
18
19
22
23
25
Average8
16
Arsenic
1.08e-03
1.76e-04f
5.43e-04
9.61e-04
6.13e-04
3.90e-03
1.96e-03
9.81e-04
8.20e-05f
3.00e-03b
9.95e-04
1.56e-03
1.32e-03
8.13e-05
Barium
3.59e-03
1.54e-03
9.60e-03f
2.57e-03
1.06e-03
Beryllium
1.95e-05f
8.49e-05
3.62e-05b
2.51e-05b
2.69e-05f
2.25e-05b
7.55e-06f
2.17e-06f
3.73e-05f
2.25e-05c
3.16e-05c
2.58e-05c
2.78e-05
2.22e-06f
Cadmium
2.10e-03
4.83e-05
4.83e-04
9.17e-05
1.03e-04
1.80e-04b
2.41e-04
5.77e-04
4.62e-04
2.10e-04c
1.06e-04
1.75e-04
3.98e-04
6.65e-06f
Chloride
1.68e-01
5.26e-01
3.47e-01
5.31e-01
Chromium
1.36e-03
5.42e-04
5.28e-04
4.44e-04
3.14e-04
1.50e-03
1.21e-03
8.65e-05f
1.64e-03
9.60e-04
5.97e-04
9.53e-04
8.45e-04
4.88e-04
Chromium VI
1.36e-04b
4.44e-06f
6.28e-05c
5.70e-04
2.57e-04
4.33e-04
1.42e-04f
4.50e-04
1.24e-04c
1.98e-04
2.48e-04
Cobalt
1.51e-02
1.43e-03
1.52e-03
6.02e-03
2.87e-04
Copper
2.40e-03
9.37e-04
2.71e-04
l.Ole-03
1.49e-03
2.10e-03
3.02e-03
2.16e-03
2.38e-03
1.80e-03
1.03e-03
2.49e-03
1.76e-03
4.12e-04
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - METALS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry
No.
1
2
4
5
6
7
8
9
10
11
12
13
14
15
18
19
22
23
25
Average8
16
Fluoride
6.59e-03
6.81e-02
3.73e-02
Lead
1.23e-03
3.81e-04
5.58e-04
2.37e-04c
1.34e-03
4.20e-03
1.51e-04f
1.44e-03
2.53e-03
3.30e-03
2.37e-03
3.79e-04c
1.51e-03
2.63e-04b
Manganese
1.20e-03
2.14e-03
2.31e-03
3.25e-03
5.98e-04
6.45e-03
1.51e-03
2.16e-03
8.64e-03
3.90e-03
2.57e-03
1.22e-03
3.00e-03
2.73e-03
Mercury
3.44e-05
3.51e-05b
2.72e-04f
8.85e-04f
3.51e-04f
3.75e-04f
2.79e-03f
2.31e-03f
2.68e-04c
3.00e-04f
2.57e-03f
2.33e-03f
1.13e-04
7.39e-05
Molybdenum
4.87e-04f
8.64e-04
1.01e-03c
7.87e-04
5.91e-05
Nickel
2.78e-01
4.44e-02
5.25e-02
5.38e-02
7.62e-02
5.70e-02
6.34e-02
2.02e-01
3.57e-02
4.50e-02
5.47e-02
5.13e-02
8.45e-02
6.80e-03
Phosphorous
2.92e-03f
1.60e-02
9.46e-03
3.99e-04b
Selenium
4.87e-05f
3.52e-04f
4.07e-05
2.59e-04f
4.18e-04
6.15e-04
1.51e-04f
2.16e-03
5.51e-04c
5.10e-04c
5.59e-04c
6.09e-04c
6.83e-04
1.85e-04
Vanadium
5.29e-02
3.51e-02
7.43e-03
3.18e-02
6.24e-03
Zinc
6.75e-02
1.57e-02c
4.24e-03
2.91e-02
-------
A.2 Source Test Report Summary Data
-------
-------
OIL EF DATABASE REFERENCE NO.
1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 13
EMISSIONS MONITORING. RADIAN CORPORATION, AUSTIN,
TEXAS. FEBRUARY, 1993.
FILENAME
FACILITY:
SITE13.tbl
EPRI SITE 13
PROCESS DATA
Oil Type3
Boiler configuration3
sec
Control device I3
Control device 2
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Fuel Heating Value (Btu/lb)d
Oil density (lb/gal)e
Fuel Heating Value (Btu/gal)
Fuel Heating Value (Btu/1000 gal)
Fuel Heating Value (MMBtu/1000 gal)
No. 6
Wall-fired (normal)
10100401
none
B
350 MW
EPA, or EPA-approved, test methods
3
19,000
7.88
149,720
149,720,000
149.72
3Page 2-1
bAppendix A, Table A-l
cPage 3-9
dPage 3-6
eAppendix A of Ap-42, residual oil density.
EMISSION FACTORS
Pollutant
Arsenic
Barium
Benzene
Berylliumb
Cadmium
Emission Factor Emission Factor
(lb/ 1 0 A 1 2 Btu)3 (Ib/MMBtu)
7.2 7.20e-06
24 2.40e-05
1.4 1.40e-06
0.26 2.60e-07
14 1.40e-05
Emission Factor
(lb/ 1000 gal)
1.08e-03
3.59e-03
2.10e-04
3.89e-05
2.10e-03
A-19
-------
OIL EF DATABASE REFERENCE NO.
EMISSION FACTORS
Pollutant
Chloride
Chromium
Cobalt
Copper
Fluoride
Formaldehyde0
Lead
Manganese
Mercury
Molybdenumb
Nickel
Phosphorousb
Selenium*3
Toluene
Vanadium
"Page 3-17, Boiler Outlet - Baseline data.
bFactor based on detection limit value only.
°Detection limit values for two runs used in
PM, FILTERABLE EMISSION FACTORS
Emission Factor
(lb/MMBtu)a
0.049
Emission Factor
(lb/10A12 Btu)a
1,120
9.1
101
16
44
8.4
8.2
8.0
0.23
6.5
1,860
39
0.65
5.3
353
See page 3-9.
developing EF. See
Emission Factor
(lb/1000 gal)
7.34e+00
Emission Factor
(Ib/MMBtu)
1.12e-03
9.10e-06
l.Ole-04
1.60e-05
4.40e-05
8.40e-06
8.20e-06
8.00e-06
2.30e-07
6.50e-06
1.86e-03
3.90e-05
6.50e-07
5.30e-06
3.53e-04
page 3-9.
Emission Factor
(lb/1000 gal)
1.68e-01
1.36e-03
1.51e-02
2.40e-03
6.59e-03
1.26e-03
1.23e-03
1.20e-03
3.44e-05
9.73e-04
2.78e-01
5.84e-03
9.73e-05
7.94e-04
5.29e-02
"Page 3-17, Boiler Outlet - Baseline data.
A-20
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
EMISSIONS REPORT FOR SITES 103 - 109. PRELIMINARY
DRAFT REPORT. RADIAN CORPORATION, AUSTIN, TEXAS.
MARCH, 1993.
FILENAME SITE103.tbl
FACILITY: EPRI SITE 103
PROCESS DATA
Oil Type3
Boiler configuration3
SCCs
Control device I3
Control device 2
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Fuel Oil Heating Value (Btu/lb)d
Fuel Oil density (lb/gal)e
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Fuel Oil Flow rate (lb/hr)d
Fuel Oil Flow rate (gal/hr)
Fuel Oil Flow rate (1000 gal/hr)
Natural Gas (NG) Heating Value (Btu/Scf)3
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Residual (assume No. 6)
Wall-fired (Normal)
OIL: 10100401 NG: 10100601
None
B
150 MW
EPA, or EPA-approved, test methods
3
19,137
7.88
150,800
150,799,560
150.80
73,333
9,306
9.31
1,030
1,030,000,000
0.00103
A-21
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
Tart I: Site 103, page 2-1.
bPartI: Site 103, page 3-1.
Tart I: Site 103, page 3-6, 3-7.
Tart I: Site 103, page 3-4, Mean value.
eAppendix A of Ap-42, residual oil density.
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Arsenic
Bariumd
Berylliumb
Cadmium
Chromium
Chrome VIb
Cobalt
Copper
Lead
Manganese
Mercuryd
Molybdenum0
Nickel
Selenium
Vanadium
Acenaphthened
Acenaphthylened
Anthracened
Benz(a)anthracened
Benzo(a)pyrened
Benzo(b,k)fluoranthened
Benzo(g,h,i)perylened
Chrysened
10100401)
Emission
Factor
(lb/1012Btu)a
3.6
127
0.24
3.2
3.5
0.9
10.1
1.8
3.7
15.3
3.6
6.7
348
0.27
49.3
0.006
0.006
0.006
0.006
0.006
0.006
0.006
0.006
Emission
Factor
(Ib/MMBtu)
3.60e-06
1.27e-04
2.40e-07
3.20e-06
3.50e-06
9.00e-07
l.Ole-05
1.80e-06
3.70e-06
1.53e-05
3.60e-06
6.70e-06
3.48e-04
2.70e-07
4.93e-05
6.00e-09
6.00e-09
6.00e-09
6.00e-09
6.00e-09
6.00e-09
6.00e-09
6.00e-09
Emission
Factor
(lb/1000 gal)
5.43e-04
1.92e-02
3.62e-05
4.83e-04
5.28e-04
1.36e-04
1.52e-03
2.71e-04
5.58e-04
2.31e-03
5.43e-04
l.Ole-03
5.25e-02
4.07e-05
7.43e-03
9.05e-07
9.05e-07
9.05e-07
9.05e-07
9.05e-07
9.05e-07
9.05e-07
9.05e-07
A-22
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Dibenz(a,h)anthracened
Fluoranthened
Fluorened
Indeno(l,2,3-c,d)pyrened
Naphthalened
Phenanthrened
Pyrened
Formaldehyded
Benzened
10100401)
Emission
Factor
(lb/1012Btu)a
0.006
0.006
0.006
0.006
0.006
0.006
0.006
19.9
6.5
Emission Emission
Factor Factor
(Ib/MMBtu) (lb/1000 gal)
6.00e-09 9.05e-07
6.00e-09 9.05e-07
6.00e-09 9.05e-07
6.00e-09 9.05e-07
6.00e-09 9.05e-07
6.00e-09 9.05e-07
6.00e-09 9.05e-07
1.99e-05 3.00e-03
6.50e-06 9.80e-04
Tart I; Site 103, pages 3-9, 3-10. See 3-6, 3-7, 3-8 for individual run data.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
PM, FILTERABLE EMISSION FACTORS
10100401)
Stack gas flow rate
(Nm3/hr)a
472,400
(SCC
PM
concentration
(ug/Nm3)a
17,199
PM PM
Emission Emission
Rate Rate
(ug/hr) (Ib/hr)
8.12e+09 17.92
PM
Emission
Factor
(lb/1000
gal)
1.93
Tart I: Site 103, page 3-6, Mean value.
EMISSION FACTORS FIRING NATURAL GAS
Pollutant
Formaldehyded
Benzened
aPage 3-10. Individual run data on page 3-8
dPollutant not detected in any sampling runs
Emission
Factor
(lb/1012Btu)a
17.7
4.4
, emission factor
Emission Factor
(Ib/MM Cu Ft)
1.82e-02
4.53e-03
developed from detection limits
A-23
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REF NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
EMISSIONS REPORT FOR SITES 103 - 109. PRELIMINARY
DRAFT REPORT. RADIAN CORPORATION, AUSTIN, TEXAS.
MARCH, 1993.
FILENAME
FACILITY:
SITE104.tbl
EPRI SITE 104
PROCESS DATA
Fuel Oil Type3
Boiler configuration
SCCs
Control device la
Control device 2
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Fuel Oil Heating Value (Btu/lb)d
Oil Density (lb/gal)e
Oil Heating Value (Btu/gal)
Oil Heating Value (Btu/1000 gal)
Oil Heating Value (MMBtu/1000 gal)
NG Heating Value (Btu/cu ft) f
NG Heating Value (Btu/MM cu ft)
NG Heating Value (EA12 Btu/MM cu ft)
Residual (assume No. 6)
Assumed Normal
OIL: 10100401 NG: 10100601
None
B
350 MW
EPA, or EPA-approved, test methods
SCC 10100401: 2 for manganese, 3 for all others
SCC 10100601: 3
18,770
7.88
147,908
147,907,600
147.91
1,036.0
1,036,000,000
0.00104
Tart II: Site 104, page 2-1.
bPartII: Site 104, page 3-1.
Tart II: Site 104, pages 3-7, 3-8, 3-9, 3-10, 3-12.
dPart II: Site 104, page 3-6, mean value.
eAppendix A of Ap-42, residual oil density.
fPart II: Site 104, Appendix D, page D-3.
A-24
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REF NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Arsenic
Berylliumb
Cadmium
Chromium
Chrome VId
Copper
Leadc
Manganese6
Mercuryd
Nickel
Seleniumd
Acenaphtheneb
Acenaphthylened
Anthracened
Benz(a)anthracened
Benzo(a)pyrened
Benzo(b,k)fluoranthened
Benzo(g,h,i)perylened
Chrysened
Dibenz(a,h)anthracened
Fluoranthened
Fluorene
Indeno(l,2,3-c,d)pyrened
Naphthalene
Phenanthreneb
Pyrene0
Benzened
Formaldehydeb
10100401)
Emission Factor
(lb/10A12 Btu)a
6.5
0.17
0.62
3
0.06
6.8
1.6
22
12
364
3.5
0.1
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.014
0.01
4.3
0.011
0.01
2.5
169
Emission Factor
(Ib/MMBtu)
6.50e-06
1.70e-07
6.20e-07
3.00e-06
6.00e-08
6.80e-06
1.60e-06
2.20e-05
1.20e-05
3.64e-04
3.50e-06
l.OOe-07
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
1.40e-08
l.OOe-08
4.30e-06
1.10e-08
l.OOe-08
2.50e-06
1.69e-04
Emission Factor
(Ib/lOOOgal)
9.61e-04
2.51e-05
9.17e-05
4.44e-04
8.87e-06
l.Ole-03
2.37e-04
3.25e-03
1.77e-03
5.38e-02
5.18e-04
1.48e-05
1.48e-06
1.48e-06
1.48e-06
1.48e-06
1.48e-06
1.48e-06
1.48e-06
1.48e-06
1.48e-06
2.07e-06
1.48e-06
6.36e-04
1.63e-06
1.48e-06
3.70e-04
2.50e-02
A-25
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REF NO. 1
Tart II: Site 104, pages 3-13. See pages 3-7 through 3-12 for individual run data.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
eEmission factor based on 2 test runs.
EMISSION FACTORS NATURAL GAS (SCC 10100601)
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Benzened 2.3 2.38e-03
Formaldehyde0 25 2.59e-02
3Page 3-13. Individual run data on page 3-12.
bDetection limit value (1/2) for one run used in developing EF.
°Detection limit value (1/2) for two runs used in developing EF.
dFactor based on detection limit value only.
A-26
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
EMISSIONS REPORT FOR SITES 103 - 109. PRELIMINARY
DRAFT REPORT. RADIAN CORPORATION, AUSTIN, TEXAS.
MARCH, 1993.
FILENAME
FACILITY:
SITElOS.tbl
EPRI SITE 105
PROCESS DATA
Oil Type3
Boiler configuration
SCCs
Control device lb
Control device 2
Data Quality
Process Parameters'3
Test methods0
Number of test runsd
Fuel Oil Heating Value (Btu/lb)e
Fuel Oil density (lb/gal)f
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Natural Gas (NG) Heating Value (Btu/Scf)8
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Residual (assume No. 6)
Assumed Normal
OIL: 10100401 NG: 10100601
None
B
750 MW
EPA, or EPA-approved, test methods
3
18,960
7.88
149,405
149,404,800
149.40
1,042.5
1,042,500,000
0.0010425
Tart III: Site 105. Page 3-7, title of Table 3-2a.
bPartIII: Site 105. Page 2-1.
Tart III: Site 105. Appendix A, various pages.
Tart III: Site 105. Pages 3-7, 3-8 and 3-12.
Tart III: Site 105. Page 3-6.
fAppendix A of Ap-42, residual oil density.
Tart III: Site 105. Appendix D. Page D-4.
A-27
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Arsenic
Berylliumd
Cadmium
Chromium
Chrome VF
Copper
Lead
Manganese
Mercuryd
Nickel
Selenium
Acenaphthened
Acenaphthylened
Anthracened
Benz(a)anthracene°
Benzo(a)pyrened
Benzo(b,k)fluoranthene°
Benzo(g,h,i)perylene°
Chrysene0
Dibenz(a,h)anthracene°
Fluoranthene
Fluorene0
Indeno(l,2,3-c,d)pyrene°
Naphthalene13
Phenanthrene
Pyrene0
Benzened
Formaldehyde
10100401)
Emission Factor
(lb/10A12 Btu)a
4.1
0.36
0.69
2.1
0.42
10
9
4.0
4.7
510
2.8
0.007
0.007
0.007
0.03
0.007
0.016
0.010
0.006
0.006
0.04
0.020
0.010
13
0.09
0.023
2.5
620
Emission Factor
(Ib/MMBtu)
4.10e-06
3.60e-07
6.90e-07
2.10e-06
4.20e-07
l.OOe-05
9.00e-06
4.00e-06
4.70e-06
5.10e-04
2.80e-06
7.00e-09
7.00e-09
7.00e-09
3.00e-08
7.00e-09
1.60e-08
l.OOe-08
6.00e-09
6.00e-09
4.00e-08
2.00e-08
l.OOe-08
1.30e-05
9.00e-08
2.30e-08
2.50e-06
6.20e-04
Emission Factor
(lb/1000 gal)
6.13e-04
5.38e-05
1.03e-04
3.14e-04
6.28e-05
1.49e-03
1.34e-03
5.98e-04
7.02e-04
7.62e-02
4.18e-04
1.05e-06
1.05e-06
1.05e-06
4.48e-06
1.05e-06
2.39e-06
1.49e-06
8.96e-07
8.96e-07
5.98e-06
2.99e-06
1.49e-06
1.94e-03
1.34e-05
3.44e-06
3.74e-04
9.26e-02
A-28
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
Tartlll: Site 105. Page 3-13. Individual run data on pages 3-7, 3-8, 3-9, 3-10, 3-11 and 3-12.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
EMISSION FACTORS FIRING NATURAL GAS
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Benzened 1.0 1.04e-03
Formaldehyde 600 6.26e-01
Tart III: Site 105. Page 3-13. Individual run data on page 3-13.
dFactor based on detection limit value only.
A-29
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
EMISSIONS REPORT FOR SITES 103 - 109. PRELIMINARY
DRAFT REPORT. RADIAN CORPORATION, AUSTIN, TEXAS.
MARCH, 1993.
FILENAME
FACILITY:
SITE106.tbl
EPRI SITE 106
PROCESS DATA
Oil Type3
Boiler configuration
SCCs
Control device la
Control device 2
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Residual (assume No. 6)
NG: 10100601
Fuel Oil Heating Value (Btu/lb)d
Fuel Oil density (lb/gal)e
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Natural Gas (NG) Heating Value (Btu/Scf)f
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Assumed
Normal
OIL: 10100401
None
B
480 MW
EPA, or EPA-approved, test methods
6 for all metals except chrome, chrome VI and
manganese. 4 for manganese, 3 for chrome, chrome
VI, PAHs, benzene, formaldehyde. 2 for anthracene
19,035
7.88
149,996
149,995,800
150.00
947
947,000,000
0.000947
Tart IV: Site 106. Page 2-1.
bPartIV: Site 106. Page 3-1.
TartIV: Site 106. Page 3-7, 3-8, 3-9, 3-10, 3-11.
dPartIV: Site 106. Page 3-6.
eAppendix A of AP-42, residual oil density.
fPartIV: Site 106. Appendix D. Page D-3.
A-30
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Arsenic
Berylliumb
Cadmiumb
Chromium
Chrome VI
Copper
Lead
Manganese
Mercuryd
Nickel
Selenium
Acenaphthene
Acenaphthylened
Anthracened
Benz(a)anthracened
Benzo(a)pyrened
Benzo(b,k)fluoranthened
Benzo(g,h,i)perylened
Chrysened
Dibenz(a,h)anthracened
Fluoranthene0
Fluorene
Indeno(l,2,3-c,d)pyrened
Napththalene
Phenanthrene
Pyrened
Benzened
Formaldehyded
10100401)
Emission Factor
(lb/10A12 Btu)a
26
0.15
1.2
10
3.8
14
28
43
5
380
4.1
0.66
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.009
0.037
0.01
3.7
0.036
0.01
3
20
Emission Factor
(Ib/MMBtu)
2.60e-05
1.50e-07
1.20e-06
l.OOe-05
3.80e-06
1.40e-05
2.80e-05
4.30e-05
5.00e-06
3.80e-04
4.10e-06
6.60e-07
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
9.00e-09
3.70e-08
l.OOe-08
3.70e-06
3.60e-08
l.OOe-08
3.00e-06
2.00e-05
Emission Factor
(Ib/lOOOgal)
3.90e-03
2.25e-05
1.80e-04
1.50e-03
5.70e-04
2.10e-03
4.20e-03
6.45e-03
7.50e-04
5.70e-02
6.15e-04
9.90e-05
1.50e-06
1.50e-06
1.50e-06
1.50e-06
1.50e-06
1.50e-06
1.50e-06
1.50e-06
1.35e-06
5.55e-06
1.50e-06
5.55e-04
5.40e-06
1.50e-06
4.50e-04
3.00e-03
A-31
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
Tart VI: Site 106. Page 3-13. Individual run data on pages 3-7, 3-8, 3-9, 3-10, 3-11.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
EMISSION FACTORS FIRING NATURAL GAS
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Benzened 4 3.79e-03
Formaldehyde 82 7.77e-02
Tart VI: Site 106. Page 3-13. Individual run data on page 3-11.
dFactor based on detection limit value only.
A-32
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
EMISSIONS REPORT FOR SITES 103 - 109. PRELIMINARY
DRAFT REPORT. RADIAN CORPORATION, AUSTIN, TEXAS.
MARCH, 1993.
FILENAME
FACILITY:
SITElOV.tbl
EPRI SITE 107
PROCESS DATA
Oil Type3
Boiler configuration
SCCs
Control device la
Control device 2
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Fuel Oil Heating Value (Btu/lb)d
Fuel Oil density (lb/gal)e
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Natural Gas (NG) Heating Value (Btu/Scf)f
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Residual (assume No. 6)
Assumed
Normal
OIL: 10100401
None
NG: 10100601
B
175 MW
EPA, or EPA-approved, test methods
3 for all
19,150
7.88
150,902
150,902,000
150.90
957
957,000,000
0.000957
TartV: Site 107. Page 2-1.
bPartV: Site 107. Page 3-1.
TartV: Site 107. Page 3-7, 3-8, 3-9, 3-10, 3-11.
dPartV: Site 107. Page 3-6.
eAppendix A of Ap-42, residual oil density.
fPartV: Site 107. Appendix D. Page D-3.
A-33
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Arsenic
Berylliumd
Cadmium
Chromium
Chrome VI
Copper
Leadd
Manganese
Mercuryd
Nickel
Seleniumd
Acenaphthened
Acenaphthylened
Anthracene0
Benz(a)anthraceneb
Benzo(a)pyrened
Benzo(b,k)fluoranthene°
Benzo(g,h,i)perylene°
Chryseneb
Dibenz(a,h)anthracene°
Fluorantheneb
Fluorene0
Indeno(l,2,3-c,d)pyrene°
Naphthalene0
Phenanthreneb
Pyreneb
Benzened
Formaldehyde
10100401)
Emission Factor
(lb/10A12 Btu)a
13
0.1
1.6
8
1.7
20
2
10
37
420
2
0.01
0.01
0.010
0.1
0.01
0.04
0.03
0.06
0.010
0.09
0.004
0.03
6
0.12
0.08
4
600
Emission Factor
(Ib/MMBtu)
1.30e-05
l.OOe-07
1.60e-06
8.00e-06
1.70e-06
2.00e-05
2.00e-06
l.OOe-05
3.70e-05
4.20e-04
2.00e-06
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-07
l.OOe-08
4.00e-08
3.00e-08
6.00e-08
l.OOe-08
9.00e-08
4.00e-09
3.00e-08
6.00e-06
1.20e-07
8.00e-08
4.00e-06
6.00e-04
Emission Factor
(Ib/lOOOgal)
1.96e-03
1.51e-05
2.41e-04
1.21e-03
2.57e-04
3.02e-03
3.02e-04
1.51e-03
5.58e-03
6.34e-02
3.02e-04
1.51e-06
1.51e-06
1.51e-06
1.51e-05
1.51e-06
6.04e-06
4.53e-06
9.05e-06
1.51e-06
1.36e-05
6.04e-07
4.53e-06
9.05e-04
1.81e-05
1.21e-05
6.04e-04
9.05e-02
A-34
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
Tart V: Site 107. Pages 3-13, 3-14. Individual run data on pages 3-7 through 3-11.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
EMISSION FACTORS FIRING NATURAL GAS
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Benzened 4 3.83e-03
Formaldehyde 800 7.66e-01
"Part V: Site 107. Page 3-14. Individual run data on page 3-11.
dFactor based on detection limit value only.
A-35
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
EMISSIONS REPORT FOR SITES 103 - 109. PRELIMINARY
DRAFT REPORT. RADIAN CORPORATION, AUSTIN, TEXAS.
MARCH, 1993.
FILENAME
FACILITY:
SITE108.tbl
EPRI SITE 108
PROCESS DATA
Oil Type3
Boiler configuration
SCCs
Control device la
Control device 2
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Fuel Oil Heating Value (Btu/lb)d
Fuel Oil density (lb/gal)e
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Natural Gas (NG) Heating Value (Btu/lb)3
NG Density (lb/scf)f
NG Heating Value (Btu/Scf)
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Residual (assume No. 6)
Opposed fired (Assumed Normal)
OIL: 10100401 NG: 10100601
None
B
50 MW
EPA, or EPA-approved, test methods
2 for manganese, 3 for all others
18,300
7.88
144,204
144,204,000
144.20
23500
0.042
987
987,000,000
9.87e-04
Tart VI: Site 108. Page 2-1.
bPartVI: Site 108. Page 3-1.
Tart VI: Site 108. Page 3-7, 3-8, 3-10, 3-12.
TartVI: Site 108. Page 3-6.
eAppendix A of AP-42, residual oil density.
fAppendix A of AP-42, density of natural gas - 1 lb/23.8 ft3.
A-36
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Arsenic
Berylliumd
Cadmium
Chromiumd
Chrome VI
Copper
Lead
Manganese
Mercuryd
Nickel
Selenium
Acenaphthened
Acenaphthylened
Anthracened
Benz(a)anthracened
Benzo(a)pyrened
Benzo(b,k)fluoranthened
Benzo(g,h,i)perylened
Chrysened
Fluoranthened
Fluorened
Indeno(l,2,3-c,d)pyrened
Naphthaleneb
Phenanthrene0
Pyreneb
Benzened
Formaldehyded
10100401)
Emission Factor
(lb/10A12 Btu)a
6.8
0.03
4.0
1.2
3.0
15
10
15
32
1,400
15
0.008
0.008
0.008
0.008
0.008
0.008
0.008
0.008
0.008
0.008
0.008
0.52
0.02
0.008
2.8
20
Emission Factor
(Ib/MMBtu)
6.80e-06
3.00e-08
4.00e-06
1.20e-06
3.00e-06
1.50e-05
l.OOe-05
1.50e-05
3.20e-05
1.40e-03
1.50e-05
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
5.20e-07
2.00e-08
8.00e-09
2.80e-06
2.00e-05
Emission Factor
(lb/1000 gal)
9.81e-04
4.33e-06
5.77e-04
1.73e-04
4.33e-04
2.16e-03
1.44e-03
2.16e-03
4.61e-03
2.02e-01
2.16e-03
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
7.50e-05
2.88e-06
1.15e-06
4.04e-04
2.88e-03
A-37
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
Tart VI: Site 108. Page 3-13. Individual run data on pages 3-7, 3-8, 3-10, 3-12.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
EMISSION FACTORS FIRING NATURAL GAS
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Benzened 2.2 2.17e-03
Formaldehyde0 12 1.18e-02
Tart VI: Site 108. Page 3-13. Individual run data on page 3-12.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
A-38
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
EMISSIONS REPORT FOR SITES 103 - 109. PRELIMINARY
DRAFT REPORT. RADIAN CORPORATION, AUSTIN, TEXAS.
MARCH, 1993.
FILENAME
FACILITY:
SITE109.tbl
EPRI SITE 109
PROCESS DATA
Oil Type3
Boiler configuration3
SCCs
Control device I3
Control device 2
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Fuel Oil Heating Value (Btu/lb)d
Fuel Oil density (lb/gal)e
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Natural Gas (NG) Heating Value (Btu/Scf)3
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Residual (assume No. 6)
Opposed fired (Assumed Normal)
OIL: 10100401 NG: 10100601
Flue Gas Recirculation (FGR)
B
230 MW
EPA, or EPA-approved, test methods
Oil firing: 2 for manganese, 3 for all others.
NG firing: 6 for all (formaldehyde)
18,900
7.88
148,932
148,932,000
148.93
1,000
1,000,000,000
l.OOe-03
Tart VII: Site 109. Page 2-1.
bPartVII: Site 109. Page 3-1.
Tart VII: Site 109. Page 3-6, 3-7, 3-10.
TartVII: Site 109. Page 3-4.
eAppendix A of Ap-42, residual oil density.
A-39
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL
Pollutant
Arsenicd
Berylliumd
Cadmium
Chromium
Copper
Lead
Manganese
Mercury0
Nickel
Selenium0
Chrome VId
Acenaphthene
Acenaphthylene
Anthracene
Benz(a)anthracene
Chrysene
Fluoranthene
Fluorene
Naphthalene
Phenanthrene
Pyrene
Benzened
Formaldehyde
(SCC 10100401)
Emission Factor
(lb/10A12 Btu)a
1.1
0.5
3.1
11
16
17
58
1.8
240
3.7
1.9
0.054
0.0017
0.019
0.0088
0.021
0.075
0.16
33
0.33
0.066
9.7
400
Tart VII: Site 109. Page 3-13, 3-14, 100% load. Individual run
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
Emission Factor
(Ib/MMBtu)
1.10e-06
5.00e-07
3.10e-06
1.10e-05
1.60e-05
1.70e-05
5.80e-05
1.80e-06
2.40e-04
3.70e-06
1.90e-06
5.40e-08
1.70e-09
1.90e-08
8.80e-09
2.10e-08
7.50e-08
1.60e-07
3.30e-05
3.30e-07
6.60e-08
9.70e-06
4.00e-04
data 3-6, 3-7, 3-10.
Emission Factor
(lb/1000 gal)
1.64e-04
7.45e-05
4.62e-04
1.64e-03
2.38e-03
2.53e-03
8.64e-03
2.68e-04
3.57e-02
5.51e-04
2.83e-04
8.04e-06
2.53e-07
2.83e-06
1.31e-06
3.13e-06
1.12e-05
2.38e-05
4.91e-03
4.91e-05
9.83e-06
1.44e-03
5.96e-02
A-40
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING NATURAL GAS
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Formaldehyde 46 4.60e-02
Tart VII: Site 109. Page 3-15, 100% load. Individual run data on page 3-10.
A-41
-------
OIL EF DATABASE REFERENCE NO. 2
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
SITE 112 EMISSIONS REPORT. CARNOT, Tustin, California.
February 24, 1994.
FILENAME
FACILITY:
SITE112.tbl
EPRI SITE 112
PROCESS DATA
Oil Type3
Boiler configuration3
sec
Control device I3
Control device 2
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Fuel Heating Value (Btu/lb)d
Oil density (lb/gal)e
Fuel Heating Value (Btu/gal)
Fuel Heating Value (Btu/1000 gal)
Fuel Heating Value (MMBtu/1000 gal)
Residual (assume No. 6)
Tangentially-Fired
10100404
ESP
C (They did not measure stack gas flow rate, but used an
F-factor instead. See page 38.)
387 MW
EPA, or EPA-approved, test methods
4 for benzene and toluene; 3 for all others
18,582
7.88
146,426
146,426,160
146.43
3Page 6
bPage 12
cPage 23
dPage 19
eAppendix A of AP-42, residual oil density.
EMISSION FACTORS
Pollutant
Arsenicb
Barium
Beryllium
Cadmium
Emission Factor Emission Factor
(lb/10A12 Btu)3 (Ib/MMBtu)
2.4 2.40e-06
10.5 1.05e-05
0.58 5.80e-07
0.33 3.30e-07
Emission Factor
(lb/1000 gal)
3.51e-04
1.54e-03
8.49e-05
4.83e-05
A-42
-------
OIL EF DATABASE REFERENCE NO. 2
EMISSION FACTORS
Pollutant
Chromium
Cobalt
Copper
Lead
Manganese
Mercury0
Molybdenum
Nickel
Phosphorous
Seleniumb
Vanadium
Chloride
Fluoride
Fluorene
Phenanthrene
2-Methylnaphthalene
Benzene
Toluene
Formaldehyde
Emission Factor
(lb/10A12 Btu)a
3.7
9.8
6.4
2.6
14.6
0.24
5.9
303
109
4.8
240
3,590
465
0.020
0.020
0.015
2.4
79.5
13.4
Emission Factor
(Ib/MMBtu)
3.70e-06
9.80e-06
6.40e-06
2.60e-06
1.46e-05
2.40e-07
5.90e-06
3.03e-04
1.09e-04
4.80e-06
2.40e-04
3.59e-03
4.65e-04
2.00e-08
2.00e-08
1.50e-08
2.40e-06
7.95e-05
1.34e-05
Emission Factor
(lb/1000 gal)
5.42e-04
1.43e-03
9.37e-04
3.81e-04
2.14e-03
3.51e-05
8.64e-04
4.44e-02
1.60e-02
7.03e-04
3.51e-02
5.26e-01
6.81e-02
2.93e-06
2.93e-06
2.20e-06
3.51e-04
1.16e-02
1.96e-03
aPages 26 & 27.
bPollutant not detected in all sampling runs. See page 23.
°Detection limit value for one run used in developing EF.
PM, FILTERABLE EMISSION FACTORS
Emission Factor
(lb/MMBtu)a
0.0177
Emission Factor
(lb/1000 gal)
2.59e+00
aPage 26
A-43
-------
OIL EF DATABASE REFERENCE NO. 4
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
SITE 118 EMISSIONS REPORT. CARNOT, Tustin, California.
January 20, 1994.
FILENAME
FACILITY:
SITE118.tbl
EPRI SITE 118
PROCESS DATA
Oil Type3
Boiler configuration3
sec
Control device I3
Control device 23
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Fuel Heating Value (Btu/lb)d
Oil density (lb/gal)e
Fuel Heating Value (Btu/gal)
Fuel Heating Value (Btu/1000 gal)
Fuel Heating Value (MMBtu/1000 gal)
Residual (assume No. 6)
Front-fired (normal)
10100401
Over-fire Air, Flue Gas Recirculation
ESP
D (high blank values)
850 MW
EPA, or EPA-approved, test methods
3
18,756
7.88
147,797
147,797,280
147.80
3Page 7
bPage 15
cPage 25, 26, 27, 28
dPage 18, mean value
eAppendix A of AP-42, residual oil density.
EMISSION FACTORS
Pollutant
Filterable PM3
Emission Factor
(lb/10A12 Btu)
Emission Factor
(Ib/MMBtu)
0.0041
Emission Factor
(lb/1000 gal)
6.06e-01
A-44
-------
OIL EF DATABASE REFERENCE NO. 4
EMISSION FACTORS
Pollutant
METALS, ANIONS3
Arsenic
Barium
Berylliumd
Cadmiumd
Chromium
Cobalt
Copper
Leadb
Manganese
Mercury
Molybdenum
Nickel
Phosphorousb
Selenium
Vanadium
Chloride
PAHse
Naphthalene
Phenanthrene
2-Methylnaphthalene
PCDD/PCDFf
2,3,7,8-TCDDd
Total TCDDd
Total PeCDDd
Total HxCDDd
Total HpCDDd
OCDDb
Emission Factor
(lb/10A12 Btu)
0.55
7.16
0.06
0.18
3.30
1.94
2.79
1.78
18.5
0.50
0.40
46.0
2.70
1.25
42.2
3,590
0.31
0.012
0.027
4.3e-06
4.3e-06
4.6e-06
6.8e-06
2.5e-05
2.1e-05
Emission Factor
(Ib/MMBtu)
5.50e-07
7.16e-06
6.00e-08
1.80e-07
3.30e-06
1.94e-06
2.79e-06
1.78e-06
1.85e-05
5.00e-07
4.00e-07
4.60e-05
2.70e-06
1.25e-06
4.22e-05
3.59e-03
3.10e-07
1.20e-08
2.70e-08
4.30e-12
4.30e-12
4.60e-12
6.80e-12
2.50e-ll
2.10e-ll
Emission Factor
(lb/1000 gal)
8.13e-05
1.06e-03
8.87e-06
2.66e-05
4.88e-04
2.87e-04
4.12e-04
2.63e-04
2.73e-03
7.39e-05
5.91e-05
6.80e-03
3.99e-04
1.85e-04
6.24e-03
5.31e-01
4.58e-05
1.77e-06
3.99e-06
6.36e-10
6.36e-10
6.80e-10
l.Ole-09
3.69e-09
3.10e-09
A-45
-------
OIL EF DATABASE REFERENCE NO. 4
EMISSION FACTORS
Pollutant
2,3,7,8-TCDFd
Total TCDFd
Total PeCDFd
Total HxCDFd
Total HpCDFd
OCDFd
Emission Factor Emission Factor
(lb/10A12 Btu)
1.8e-06
1.8e-06
2.6e-06
5.0e-06
3.4e-05
1.6e-05
(Ib/MMBtu)
1.80e-12
1.80e-12
2.60e-12
5.00e-12
3.40e-ll
1.60e-ll
Emission Factor
(lb/1000 gal)
2.66e-10
2.66e-10
3.84e-10
7.39e-10
5.03e-09
2.36e-09
PCBsd
VOCs8
Benzene
Toluene
Vinyl Chlorided
l,3-Butadiened
Methyl Bromided
Chloroformd
1,2-Dichloroethane (Ethylene
Dichloride)d
1,1,1 -Trichloroethane
Carbon Tetrachlorided
1,2-Dichloropropane (Propylene
Dichloride)d
Trichloroethaned
Perchloroethylened
Chlorobenzened
Ethylbenzene
o-Xylene
Formaldehyde
0.53
7.6
1.43
0.16
1.74
1.09
2.11
1.6
0.94
2.41
1.20
1.01
0.69
0.43
0.74
5.4
5.30e-07
7.60e-06
1.43e-06
1.60e-07
1.74e-06
1.09e-06
2.11e-06
1.60e-06
9.40e-07
2.41e-06
1.20e-06
l.Ole-06
6.90e-07
4.30e-07
7.40e-07
5.40e-06
7.83e-05
1.12e-03
2.11e-04
2.36e-05
2.57e-04
1.61e-04
3.12e-04
2.36e-04
1.39e-04
3.56e-04
1.77e-04
1.49e-04
1.02e-04
6.36e-05
1.09e-04
7.98e-04
3Page 29. Individual run data on page 25.
bDetection limit value for one run used in developing EF.
°Detection limit values for two runs used in developing EF.
dFactor based on detection limit value only.
ePage 30. Individual run data on page 26
fPage 30. Individual run data on page 27
8Page 3 1 . Individual run data on page 26
(formaldehyde) and page
28.
A-46
-------
§
H ^^
l.OA
0.9A
0.8A
0.7A
0.6A
0.5A
0.4A
0.3A
0.2A
0.1A
0
ESP
Uncontrolled
Scrubber
I
0.1 OA
0.09A
0.08A
0.07A
0.06A
0.05A
0.04A
0.03A
0.02A
0.01A
0
d
.2
05
in
O
O
1
o
0.01A
0.006A
0.004A g
0.002A g
0.001A £ 2
0.0006A | £,
0.0004A 8
OH
0.0002A W
0.0001A
.1
.2
.61
4 6 10 20 40 60 100
Particle diameter ( m)
-------
M-H
-------
0.25
3 0.20
I
O
'I j" 0.15
S o
-------
o
13
T3
l.OOA
0.90A
0.80A
| 0.70A
Ji CT0.60A
0.50A
i
'0.40A
0.30A
u
| 0.20A
o
S 0.10A
0
.1
.2
Distillate oil
Residual oil
i i i i 11
J I
i i i i
0.25
0.20 £
£
0.15
.6 1
6 10 20 40 60 100
o
g -s
o.io I I
"o '-^
* ^
c ' o
0.05 |
0
Particle diameter ( m)
-------
APPENDIX A
SUPPORTING DOCUMENTATION
SUPPLEMENT E
SEPTEMBER 1998
-------
TABLE A-l. DESCRIPTION OF CONDENSABLE PARTICULATE MATTER EMISSION SOURCES (a)
REFERENCE
NUMBER
12
13
14
15
16 (e)
17 (e)
18
DATA
QUALITY
RATING
(b)
A
A
A
A
A
A
A
BOILER
NUMBER
(c)
#11
ND
Boiler B
# 6, # 7,
#8(d)
#l(e)
#l(e)
#2
BOILER
DESCRIPTION &
FIRING
CONFIGURATION
Industrial boiler;
Configuration not
reported.
Utility boiler;
Configuration not
reported.
Utility boiler; Front
wall-fired.
Industrial Boiler;
Configuration not
reported.
Industrial fire-tube
boiler; Configuration
not reported.
Industrial fire-tube
boiler; Configuration
not reported.
Industrial package
boiler; Configuration
not reported.
BOILER
CAPACITY
200,000
Ib/hr steam
131
MMBtu/hr
475
MMBtu/hr
ND
25,575 Ib/hr
steam
25,575 Ib/hr
steam
75,000 Ib/hr
steam
FUEL
TYPE
Distillate
oil (No. 2)
Distillate
oil (No. 2)
Distillate
oil (No. 2)
Residual
oil (No. 6)
Residual
oil (No. 6)
Residual
oil (No. 6)
Residual
oil (No. 6)
EMISSION
CONTROLS
Low NOx
burners; flue gas
recirculation
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
TEST
DATE
9/15/94
10/29/94
2/22/95
8/8/96
7/13/93
5/31/95
1/31/95
TEST
METHOD
Wisconsin
Method 5
EPA
Method 202
EPA
Method 202
Oregon
Method 5
Wisconsin
Method 5
Wisconsin
Method 5
Wisconsin
Method 5
FUEL
SULFUR
CONTENT
(% weight)
0.36
0.12
0.23
1.65
1.00
0.76
0.30
(a) ND = no data.
(b) Procedures presented in Procedures For Preparing Emission Factor Documents, EPA-454-95-015 Revised, were used to assign data quality ratings.
(c) Idenfitication number assigned by the facility to the boiler.
(d) Three identical boilers operating simultaneously and sharing a common stack.
(e) Data are for same facility, same boiler.
-------
TABLE A-2. CONDENSABLE PARTICULATE MATTER EMISSION FACTORS FOR OIL-FIRED BOILERS (Ib/MMBtu)
REFERENCE
NUMBER
12
13
14
BOILER
NUMBER (a)
#11
ND
Boiler B
SCC (b)
1-02-005-01
1-01-005-01
1-01-005-01
15
16(e)
17(e)
18
#6, #7, #8
(d)
#1(e)
#1(e)
#2
1-02-004-01
1-02-004-01
1-02-004-01
1-02-004-01
AVERAGE FACTORS FOR DISTILLATE-
INORGANIC. ORGANIC % OF TOTAL:
EMISSION FACTOR (Ib/ton):
Boiler average
CPM-IOR (c)
0.0075
0.0017
0.0078
0.0057
66%
0.0155
0.0073
0.0114
0.0095
AVERAGE FACTORS FOR RESIDUAL OIL:
INORGANIC ORGANIC % OF TOTAL:
EMISSION FACTOR db/torT):
0.0104
85%
CPM-ORG
(c)
0.0006
0.0033
0.0049
0.0030
34%
0.0019
0.0013
0.0016
0.0020
0.0018
15%
CPM-TOT
(c)
0.0081
0.0051
0.0127
0.0086
1.21
0.0070
0.0174
0.0086
0.0130
0.0115
0.0105
1.47
STD; REL
STD
0.004: 0.443
0.003: 0.297
to
o
ca
o
>
(a) Identification number assigned by the facility to the boiler. ND = No data.
(b) Source Classification Codes were assigned according to information presented in the test report.
(c) CPM-IOR = Condensible paniculate matter, inorganic;
CPM-ORG = Condensible paniculate matter, organic
CPM-TOT = Condensible paniculate matter, total (inorganic + organic)
(d) Data represent three identical boilers operating simultaneously and sharing a common stack.
(e) Data represent a single boiler (same boiler at same facility).
-------
The following memo describes the contents and development of the NOX database used in
the Supplement E update to Section 1.3 of AP-42. The memo is followed by tables that
summarize the NCL data.
X
Refer to oilraw.xls to review the complete set of data.
A-3
-------
May 16, 1997
SUMMARY OF THE ACID RAIN DIVISION'S SHORT-TERM NOx RATE
DATABASE: CONTENTS AND DEVELOPMENT
I Introduction
Under contract 68D20158, the Acid Rain Division (ARD), U.S. EPA asked Perrin Quarles
Associates (PQA) to develop and quality assure a database of utility boilers affected by the NOX
emission limits under Title IV of the Clean Air Act. This effort was part of an ongoing effort by
ARD to promulgate NOX regulations under section 407 of the Clean Air Act Amendments of
1990. The primary task was to ensure the accuracy and completeness of the database to support
the rulemaking and data analyses related to the emission standards under consideration and to
identify a short-term baseline (pre-control) emission rate for each affected unit. This report
documents these aspects of the project.
The quality assurance effort involved the following sources of information:
• Existing utility industry databases available to EPA and to the regulated community in
general;
• EPA's monitoring plan database, which is maintained by PQA, and contains information
on boiler types, NOX controls, stack configurations and emission points required under 40
CFRPart75;
• NOX Cost Form Data required under 40 CFR Part 76 to be submitted by utilities for units
at which the utility installed low NOX burners.
• Short-term NOX emission rate data derived from CREV processing. CREV is a software
application designed to assess certification test results, including relative accuracy tests,
required under 40 CFR Part 75.
• Emissions data analysis to identify potential anomalies or errors in data requiring unit-
specific follow-up;
• Data and information provided to EPA by interested parties, for example the Utility Air
Regulatory Group (UARG);
• Ozone attainment status data provided by OAQPS; and
• Telephone communication and written correspondence with sources to resolve questions
about inconsistent information, to verify burner, bottom, and control types and to obtain
control installation dates.
A-4
-------
Summary
May 16, 1997
Page 2
II Methodology
A Development of Initial Database
The initial database was assembled from a file provided to PQA by the Acid Rain
division, called NOXNAD2.DBF. This file was derived from the NADB V2.1 file used
for allowance allocations under Title IV.
B. Boiler Type Verification
PQA verified boiler types for all coal-fired units subject to Title IV NOX requirements as
follows:
1. Pechan Verification
The initial databases included 258 units for which E.H. Pechan & Associates had
verified the boiler and burner type for units in a database called
BFNUM270.DBF. Unless a specific question arose from other activities or by
ARD staff, these units were not reverified.
2. Automatic Verification through Currently Available Data
A software routine was created to assess current database information
automatically and "verify" those units for which the information is both redundant
and internally consistent. Data from the following sources were compared:
FGNTYPE fields and FNUM and BNUM fields in the database provided
by EPA
• Monitoring plan data in EPA's Program Tracking System (PTS). The PTS
data was entered from hardcopy monitoring plan submissions to ARD
required under 40 CFR Part 75.
• UDI Power Plant Inventory (1994)
• Edison Electric Institute Environmental Directory of US Powerplants
(September 1994).
A-5
-------
Summary
May 16, 1997
Page 3
Data for any unit for which there were at least two sources of information and no
conflicting information were considered to be quality assured. This result was
recorded in the database.
3. Source Verification of Remaining Units
For any unit which was not quality assured through steps II.B. 1 and II.B.2 (see
above), the utility was contacted for information on the unit's firing and bottom
type. Records of these phone calls are maintained in ARD's monitoring plan
files.
4. Recording the Boiler Type Verification Results
The database contains a data field, "QASTAT," used to record the basis on which
the boiler type was verified. This field contains the following values:
PECHAN: Data verified by E.H. Pechan for ARD.
ARD Data: Data provided to PQA by ARD
EEL Data verified based on consistency with EEI data.
PQA-A: Data verified with computer approach stated above.
PQA-P: Data verified by phone contact with utility.
5. New Firing and Bottom Type Fields
As a final step, new fields for bottom type and firing type were created based on
the quality assured data. This allows for the preservation of the underlying data
used for verification. The underlying data is currently archived.
6 Reconciliation of NOXBLR Boiler Types and 1994 EIA 767 Data
In the later stages of the project, PQA provided boiler type information to E.H.
Pechan who compared the data to the information submitted by utilities for boiler
and bottom type on Form EIA 767 for 1994. Based on this comparison and
further follow-up with the utilities by a DOE contractor, boiler type information
was further corrected. Based on this process many utilities also agreed to correct
erroneous information previously submitted to DOE.
A-6
-------
Summary
May 16, 1997
Page 4
IV Criteria to Define Contents of NOXBLR4
The NOXBLR4 database contains coal-fired operational utility units subject to Part 76
requirements.
A Retired Units
Any unit which is no longer operational and formally "retired" from the Acid Rain
Program was excluded from the database. Approximately 31 units which were part of the
original NADB Version 2.1 as coal-fired units were excluded from NOXBLR4 for this
reason.
B Deferred Units
Any unit which was not operational on the initial compliance date (November 15, 1993
for Phase I units and January 1, 1995 for Phase II units) and remained in long term
shutdown through September 1996 was excluded from NOXBLR4. Approximately 40
units which were part of the original NADB Version 2.1 were excluded from NOXBLR4
for this reason.
C. Definition of Coal-fired Units
Under Part 76, a coal-fired affected utility unit is defined in Section 76.2 as "a utility unit
in which the combustion of coal (or any coal-derived fuel) on a Btu basis exceeds 50.0
percent of its annual heat input, for Phase I units in calendar year 1990 and, for Phase II
units in the calendar year 1995). For this reason, any unit for which the primary fuel in
1990 in NADB Version 2.1 was indicated as coal was included in the database. This
includes approximately six units which are combusting gas only in 1996. For Part 75
monitoring requirements, it should be noted that a unit which combusts any coal is
classified as a coal-fired unit. For Phase II units, the database does not attempt to
identify or verify any Phase II unit's 1995 fuel consumption for purposes of determining
Part 76 applicability.
V Field-by-Field Descriptions
The database contains the following fields:
A-7
-------
Summary
May 16, 1997
Page 5
Identifying Information: Each boiler in the database is identified by the following
fields: State name (STATNAM), State abbreviation (STAT_ABB), EPA Region
(EPARGN), ORIS Code (ORISPL), plant name (PNAME), name of operating utility
(UTILNAME), holding company name (HOLDCO) (if applicable), and operating utility
code (UCODE).
Stack Identifier (STACK_ID1). Based on Part 75 monitoring plan data, one stack
identifier is provided to indicate common stack configuration. A unit may, however, be
associated with more than one stack.
Designated Representative (DR) (DESIGREP). The name of the current designated
representative is included. Note that the DR may be changed at any time.
Phase I or II Indicator (PHASE). This field indicates whether a unit is a Phase I or
Phase II unit for Acid Rain Program purposes.
NOX Group (NOXGRP). This field indicates whether the unit is a Group 1 or Group 2
boiler based on boiler type, as defined in 40 CFR Part 76.
Phase I Substitution Unit (PHI SUB). This field indicates whether a unit was an SO2
substitution unit through 1995 and thereby affected for Phase I under 40 CFR Part 76.
This information was obtained from EPA's Allowance Tracking System (ATS).
Phase I Reduced Utilization Unit (PH1RU). This field indicates whether a unit was an
SO2 compensating unit in 1995. This information was obtained from EPA's Allowance
Tracking System (ATS).
Phase I Extension Plan Unit (PH1EXT). This field indicates whether a unit was part of
a Phase I Extension Plan for SO2 reduction. A " 1" indicates a transfer unit; "2", a
control unit.
NOX Control Equipment (CNTLTABA). This field identifies the type of NOX controls
installed at the unit. This information was obtained from Part 75 monitoring plans and
verified by the utility, either through phone calls or other information (such as NOX Cost
Forms) submitted to EPA.
A-8
-------
Summary
May 16, 1997
Page 6
NOX Control Equipment Installation Date (NOX INDATE) This information was
obtained either directly from the utility through phone conversations, provided to EPA on
Cost Forms, or from the Part 76 rulemaking docket (EPA air docket numbers A-92-15
and A-95-28).
Indicator of Original Controls (ORIG_INST). This flag indicates units for which NOX
controls were installed as part of the original boiler installation. (It frequently applies to
NSPS units.) This flag enables an analyst to separate these units if desired.
Boiler Firing Type (VER_FIRG). This field identifies the verified firing type for the
boiler.
Boiler Bottom Type (VER_BURN). This field identifies the bottom type (wet or dry)
for the boiler.
Attainment Status (ATTAIN). The field ATTAIN contains the ozone non-attainment
status for each unit in the database. The non-attainment information used was obtained
from EPA's Office of Air Quality Planning and Standards (OAQPS) and is consistent
with formal designations through August 1995. Where specific units were located in
counties identified as "partial" the responsible State air pollution agency or the utility was
contacted to determine whether the facility is located in the nonattainment area of the
county.
NSPS Status (NSPS). PQA initiated an effort to identify the NSPS status of each unit in
the database. A list of units was sent to each EPA Regional Office. The lists contained
NSPS information on some units based on information submitted to EPA by utilities.
Acid Rain contacts were asked to identify each unit as pre-NSPS units or by the relevant
NSPS subpart. If Regions failed to or where unable to respond, a similar request was
made to the appropriate State agency. The resulting information was entered manually
into the database.
Short-term Baseline NOX Emission Rate (PRE_RATE). The field PRE_RATE
contains the short term baseline NOX emission rate used for analysis purposes in support
of the Part 76 rulemaking. For a description of how this information was obtained, see
Section VI below.
A-9
-------
Summary
May 16, 1997
Page 7
Source of Data for Short-term Baseline Rate (PRE_SRC). This field contains a code
to describe the source of data used for baseline purposes. See the explanation of codes
and priority in Section VI below.
Sum of Generating Capacity Associated with Unit (SUM_NPC). This field contains
the sum of the generating capacity of each generator serving a unit in NOXBLR. It does
not accurately reflect multi-header boilers that may be associated with more than one
generator also serving other boilers. Utilities requested corrections of specific unit values
for: FJ Gannon GB03 and GB04; Bonanza 1-1; and SA Carlson 9, 10, 11, and 12.
Boiler Year on Line (BLRYRONL). This field contains the year in which the unit
became operational. For units on line prior to 1995 this data was taken directly from
NADB Version 2.1. For new units this information was obtained from ARD's Program
Tracking System.
Generator Heat Input for Unit (BLRSUMBS). This field contains the summed total of
the 1985 - 1987 boiler generator average heat input from NADB Version 2.1.
60% Capacity Heat Input For Unit (BLRH60SHR). This field contains the summed
total of the boiler generator share of generator heat input at 60 percent capacity from field
#24 of NADB Version 2.1.
1990 Capacity Factor (CAP_90_FAC). This field contains 1990 Capacity Factors for
each unit.
1990 Heat Input (HT_90_INPT). This field contains 1990 heat input for each unit
provided to DOE/EIA, through Form 767, by utilities and quality assured by the Acid
Rain Division.
Test Date Associated with Short Term Data (CREV_ DATE). This is the date on
which the relative accuracy test used to establish a short-term baseline NOX emission rate
was performed. This was used to assess whether the test preceded the installation of NOX
controls at a unit.
Indicator for Mixed Boilers in Common Stacks (MPPROB) A logical flag of" Y"
was used in the field MBPROB to indicate potential data analysis problems due to
emission rates derived from units of mixed boiler types in a common stack. The purpose
of the flag was to allow an analyst to exclude these units from an analysis, if desired.
A-10
-------
Summary
May 16, 1997
PageS
However, no attempt was made to identify boiler-specific rates for these units and it
should be noted that the common stack rate is used as the baseline rate for every unit in
the common stack.
• Phase INOX Indicator for 1996 (LEVIIT96). A logical flag of" Y" was used to indicate
units subject to Phase INOX compliance limits in calendar 1996. The indicator includes
units for which a compliance extension has been granted and 1995 substitution units
meeting the January applicability cutoff. The list of units was reviewed and is consistent
with the list of Phase INOX units maintained by the Acid Rain Division.
VI. Baseline Emission Rate Methodology
The following codes are used to identify the source of data for baseline NOX emission
rates included in the data. These codes are listed in the order of priority assigned to their
use.
A. CREV. This code identifies short-term data taken from the mean CEMS value
from relative accuracy tests performed to certify NOX monitoring systems under
Part 75 which were processed by "CREV", EPA's certification test data software
tool used to evaluate certification test results.
B. PTS-CREV. This code identifies short-term data taken from the mean reference
value from relative accuracy tests performed to certify NOX monitoring systems
under Part 75 which were processed by EPA's Program Tracking System (PTS).
C. QA. This code identifies short-term data taken from the mean reference value
from relative accuracy tests performed to meet Part 75 quality assurance
requirements for certified monitoring systems. This data was obtained from
quarterly report data processed by EPA's Program Tracking System (PTS).
D. CF: This code identifies baseline rates reported to EPA on NOX Cost Forms
required under Part 76.
E. DOCKET. This code identifies data found in docket information for the Part 76
rulemaking. In most cases baseline information was provided as part of a study or
demonstration project submitted to support a specific rule proposal or concern.
A-ll
-------
Summary
May 16, 1997
Page 9
F. UTILITY. If a utility installed controls prior to the period in which Acid Rain
Program testing and reporting began and no short-term measured data was
available, PQA contacted the utility to request unit-specific baseline data. Most
utilities provided CEMS data for representative pre-control periods or
performance test data used to demonstrate compliance with State or federal limits.
Others submitted baseline data to demonstrate control performance. Where
necessary, selected a baseline rate associated with normal or high load or
averaged the set of data provided.
G. UARG. This code identifies rates provided by to EPA by the Utility Air
Regulatory Group (UARG). Where no other short term emission rate data was
available, this data was used. The source of the data or time period represented
by the data are unknown.
I. NADB. This code identifies rates included by EPA in the National Allowance
Database (NADB VI.2).
J. NURF. This code identifies rates taken from the 1985 National Utility Reference
File (NURF) data, included in NADB VI.2.
K. NO DATA. This code indicates units for which no pre-controlled rates were
found. In most of these cases, the utility was contacted and indicated that no pre-
control data are available.
VII Additional Data on 1990 -1994 NOX Emission Rates
In March 1997, EPA used the information in NOXBLR4 to establish year-specific NOX emission
rates for 1990 through 1994.
A. Additional Data Collection
Where data relevant to these years were not available, PQA researched related databases
or contacted utilities. For example, for units for which NOX control installation dates
were not available or for which the emission rates appeared to be inconsistent with
known emission rate values during the period, utilities were contacted for additional
information. Part 76 rulemaking docket and monitoring plan information was also used
to obtain additional information in some cases.
Summary
A-12
-------
May 16, 1997
Page 10
B Post Control Rates
For post-control NOX emission rates, the following data was used in the order of priority
listed below. The source of the data for post-control data is recorded in the field
POSTSRC.
• QA (Short-term Test Data). These data were taken from the mean reference
values from relative accuracy tests reported to ARD in quarterly emission reports
for the specific year. Where more than one test was reported the earliest test was
used. However, all available data was reviewed to ensure that the rate was
representative of the overall unit experience for that year. For two units, an EPA
Regional Office provided short-term test data from certification test results.
• CF. This code indicates that the rates were taken from Step 6 of the NOX Cost
Form submitted to EPA under Part 76.
• DOCKET. This code identifies data found in docket information for the Part 76
rulemaking. In most cases post control data were provided as part of a study or
demonstration project submitted to support a specific rule proposal or concern.
• UTILITY. These data were provided by the utility directly.
C. Criteria for Assigning Annual Values
The following criteria were used to assign annual rates:
• Uncontrolled Units: For all uncontrolled units during the period, the baseline
NOX emission rate (PRE_RATE) was used to populate each annual rate (RATE90,
RATE91, RATE92, RATE93 and RATE94).
• Units Controlled Prior to 1990. For units with controls installed as part of the
original boiler installation or prior to 1990, the controlled emission rate (based on
relative accuracy tests performed for Part 75) was used to populate each annual
rate.
A-13
-------
Summary
May 16, 1997
Page 11
Units Controlled During the Period. For units which installed controls during the
period 1990-1994, baseline NOX emission rates were assigned to each year prior
to and including the year in which the control equipment was installed. Post
control rates were used for each year following the year of control equipment
installation. PQA used data on NOX installation dates in the field NOX_INDATE
to make the determination for each year.
A-14
-------
to
o
ffl
Table A-3. FUEL OIL DATA
No. 6 FUEL OIL, UNCONTROLLED: WALL FIRED (< 100 MMBtu/hr)
Site Name
Mallinkrodt
Chemical, Inc
Masland Industnes
Masland Industries
Location
South
Whitehall
Township,
PA
Carlisle, PA
Carlisle, PA
COMBUSTOR
DESCRIPOTION
Wickes Series 600;
End
Wall-Fired Boiler #
3
RileyUmt#3
Erie City Unit No. 4
FUEL
No. 6
No. 6
No. 6
NOX
CONTROLS (a)
UNC
UNC
UNC
CAPACITY
RATING
76
96
60.6
CAPACITY
UNITS
MMBtu/hr
MMBtu/hr
MMBtu/hr
Date Installed
or Startup
SCC CODE
sec
Description
End
Wall-Fired
NOX
Value
0.39
0.361
0.405
NOX Units
Ib/MMBtu
Ib/MMBtu
Ib/MMBtu
Average
Calculated AP-42
Nox Value
58.50
54.15
60.75
57.80
AP-42 Units
lb/1038"1
lb/103gal
lb/103gal
lb/103 gal
No. 2 FUEL OIL, UNCONTROLLED: WALL FIRED (< 100 MMBtu/hr)
Site Name
Wheelmg- Pittsburgh
Southern Methodist
University
Location
Allenport, PA
Dallas, Tx
COMBUSTOR
DESCRIPTION
Boiler
Boiler No. 1
FUEL
No. 2
No. 2
NOX CONTROLS (a)
im
CAPACITY RATING
60.5
72
CAPACITY UNITS
MMBtu/hr
MMBtu/hr
Date Installed or
Startup
SCC CODE
SCC Description
NOX
Value
5.1
7.65
NOX Units
Ib/hr
Ib/hr
Average
Calculated AP-42 Nox
Value
11.80
14.88
13.34
AP-42 Units
lb/103 gal
lb/103 gal
lb/103 gal
>
(Jl
No. 2 FUEL OIL, LNB & FOR: WALL FIRED (> 100 MMBtu/hr)
Site Name
Merk & Co.
Appleton Paper
Location
West Point, PA
Combined Locks,
WI
COMBUSTOR
DESCRIPTION
B&W Model FM 120-971:
Boiler # 7
Combustion Engineering
40-A-16 Boiler Unit No 11
FUEL
No. 2
No. 2
NOX CONTROLS (a)
LNB/FGR
LNB/FGR
CAPACITY RATING
152
200,000
CAPACITY UNITS
MMBtu/hr
Ib/hr steam
Date Installed or
Startup
1995
SCC CODE
1-02-005-01
SCC Description
Grade 1 & 2 Oil
NOX
Value
0.078
8.34
NOX Units
Ib/hr
Ib/MMBtu
Average
Calculated AP-42 Nox
Value
7.6816
11.7
9.69
AP-42 Units
lb/103 gal
lb/103 gal
lb/103 gal
A-15
-------
APPENDIX B
SUPPORTING DOCUMENTATION
SUPPLEMENTS A and B
A-16
-------
B.I Data Used for Average Emission Factors Development
A-17
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION
Entry
No.
1
2
3
4
5
7
9
11
12
14
20
21
23
Ref
No.
1
2
2
3
3
3
3
3
3
3
6
7
7
Facility
EPRI SITE 13
EPRI SITE 112
EPRI SITE 112
EPRI SITE 103
EPRI SITE 104
EPRI SITE 105
EPRI SITE 106
EPRI SITE 107
EPRI SITE 108
EPRI SITE 109
Southern California
Edison Company,
Alamitos Unit 5
Pacific Gas and
Electric Company,
Morro Bay Unit 3
Pacific Gas and
Electric Company,
Morro Bay Unit 3
Fuel
Type
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual
Residual
Residual
Boiler
Type
Wall-Fired
(Normal)
Tangentially-Fired
Tangentially-Fired
Wall-Fired
(Normal)
Assumed Normal
Assumed Normal
Assumed Normal
Assumed Normal
Opposed (Normal)
Opposed (Normal)
Assumed Normal
Radiant Heat
Radiant Heat
sec
10100401
10100404
10100404
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
Control
Device la
Uncontrolled
ESP
ESP
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
FOR
FOR
None
None
Control
Device T
None
None
None
None
None
None
None
None
None
None
None
None
None
Data
Quality
B
C
C
B
B
B
B
B
B
B
C
C
C
No. Of
Test
Runs
3
3
4
3
3
3
3
3
3
3
3
3
3
B-0
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry
No.
24
26
16
17
Ref
No.
8
8
4
5
Facility
Southern California
Edison Company,
El Segundo
Station 1
Southern California
Edison Company,
El Segundo
Station 1
EPRI SITE 118
Southern California
Edison Company
Long Beach
Auxiliary Boiler
Fuel
Type
Residual
Residual
Residual (No. 6)
Distillate Oil
Boiler
Type
Assumed Normal
Assumed Normal
Front-fired
(normal)
Assumed Normal
sec
10100401
10100401
10100401
10100501
Control
Device P
None
None
OFA/FGR
None
Control
Device T
None
None
ESP
None
Data
Quality
C
C
Dd
C
No. Of
Test
Runs
3
3
3
3
3 UNC = Uncontrolled; FGR = Flue Gas Recirculation; OFA = Over-fire Air; ESP = Electrostatic Precipitator.
b>c At least one test run was "non detect" and the emission factor is based on detection limit values, (b = one "non detect", c = more than one "non
detect").
d Data quality ratings of "D" were not used for averaging with "B" and "C" quality data.
f Pollutant was Not Detected in any of the sampling runs. Half of the detection limit value (DL/2) used to develop factor.
s For a given pollutant, any factors based solely on "non detect" values that were greater than any factors based on detected values were not included in
the calculated average factor.
B-l
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
Benzene
2.10e-04
3.51e-04
4.90e-04f
1.85e-04f
1.87e-04f
2.25e-04f
3.02e-04f
2.02e-04f
7.20e-04f
1.80e-04f
1.85e-04f
2.27e-04f
2.14e-04
7.83e-05
9.00e-08f
1,3 -Butadiene
1.18e-05f
Carbon
Tetrachloride
6.95e-05f
Chloro-benzene
5.10e-05f
Chloroform
8.05e-05f
Ethyl-benzene
6.36e-05
Ethylene
Dichloride
1.56e-04f
B-2
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
Formaldehyde
1.26e-03c
1.96e-03
1.50e-03f
2.50e-02b
9.26e-02
1.50e-03f
9.05e-02
1.44e-03f
5.96e-02
8.25e-04f
2.44e-02c
1.12e-03f
3.30e-02
7.98e-04
3.20e-06f
Methyl Bromide
1.29e-04f
Naphthalene
4.53e-07f
6.36e-04
1.94e-03b
5.55e-04
9.05e-04c
7.50e-05b
4.91e-03
4.00e-04
6.18e-04
1.27e-03
1.13e-03
4.58e-05
7.00e-llf
Perchloro-
ethylene
3.73e-05f
Propylene
Dichloride
1.78e-04f
1,1,1-TCA
2.36e-04
Toluene
7.94e-04
1.16e-02
6.20e-03
1.12e-03
B-3
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
Trichloroethane
8.85e-05f
Vinyl Chloride
1.06e-04f
o-Xylene
1.09e-04
Acenaphthene
4.53e-07f
1.48e-05b
5.25e-07f
9.90e-05
7.55e-07f
5.75e-07f
8.04e-06
6.82e-05
1.51e-05
3.20e-06
2.11e-05
7.00e-llf
Acenaphthylene
4.53e-07f
7.40e-07f
5.25e-07f
7.50e-07f
7.55e-07f
5.75e-07f
2.53e-07
6.11e-07f
6.82e-07f
5.23e-07f
2.53e-07
7.00e-llf
Anthracene
4.53e-07f
7.40e-07f
5.25e-07f
7.50e-07f
1.51e-06c
5.75e-07f
2.83e-06
1.31e-06c
1.36e-06c
2.16e-06c
1.22e-06
7.00e-llf
Benz(a)an-
thracene
4.53e-07f
7.40e-07f
4.48e-06c
7.50e-07f
1.51e-05b
5.75e-07f
1.31e-06
6.11e-07f
6.82e-07f
1.54e-05c
4.01e-06
7.00e-llf
B-4
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
Benzo(a)pyrene
4.53e-07f
7.40e-07f
5.25e-07f
7.50e-07f
7.55e-07f
5.75e-07f
6.11e-07f
6.82e-07f
2.76e-06f
7.00e-llf
Benzo(b,k)
fluoranthene
4.53e-07f
7.40e-07f
2.39e-06c
7.50e-07f
6.04e-06c
5.75e-07f
6.11e-07f
6.82e-07f
1.05e-06c
1.48e-06
7.00e-llf
Benzo(g,h,i)
perylene
4.53e-07f
7.40e-07f
1.49e-06c
7.50e-07f
4.53e-06c
5.75e-07f
6.11e-07f
6.82e-07f
1.05e-05c
2.26e-06
7.00e-llf
Chrysene
4.53e-07f
7.40e-07f
8.96e-07c
7.50e-07f
9.05e-06b
5.75e-07f
3.13e-06
6.11e-07f
6.82e-07f
6.87e-06c
2.38e-06
7.00e-llf
Dibenzo(a,h)-
anthracene
6.11e-07f
6.82e-07f
3.73e-06c
1.67e-06
7.00e-llf
Fluoranthene
4.53e-07f
7.40e-07f
5.98e-06
1.35e-06c
1.36e-05b
5.75e-07f
1.12e-05
1.41e-06c
1.36e-06c
1.17e-05c
4.84e-06
7.00e-llf
Fluorene
2.93e-06
4.53e-07f
2.07e-06
2.99e-06c
5.55e-06
6.04e-07c
5.75e-07f
2.38e-05
3.82e-06
4.66e-06c
1.69e-06c
4.47e-06
7.00e-llf
B-5
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
Indeno(l,2,3-
cd)pyrene
4.53e-07f
7.40e-07f
1.49e-06c
7.50e-07f
4.53e-06c
5.75e-07f
6.11e-07f
6.82e-07f
9.44e-06c
2.14e-06
7.00e-llf
Phenanthrene
2.93e-06
4.53e-07f
1.63e-06b
1.34e-05
5.40e-06
1.81e-05b
2.88e-06c
4.91e-05
3.67e-06
1.63e-06c
1.63e-05c
1.05e-05
1.77e-06
7.00e-llf
Pyrene
4.53e-07f
1.48e-06c
3.44e-06c
7.50e-07f
1.21e-05b
1.15e-06b
9.83e-06
1.26e-06c
1.40e-06c
1.07e-05c
4.25e-06
7.00e-llf
2.3.7.8-TCDD
3.18e-10f
TCDD
3.18e-10f
PeCDD
3.40e-10f
HxCDD
5.05e-10f
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - ORGANICS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
3
4
5
7
9
11
12
14
20
21
23
24
26
Average8
16
17
HpCDD
1.85e-09f
OCDD
3.10e-09b
2.3.7.8-TCDF
1.33e-10f
PeCDF
1.92e-10f
HxCDF
3.70e-10f
HpCDF
2.52e-09f
OCDF
1.18e-09f
Cd
B-7
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - METALS - DL/2
FUEL OIL COMBUSTION
Entry
No.
1
2
4
5
6
7
8
9
10
11
12
13
14
15
18
Ref
No.
1
2
3
3
3
3
3
3
3
3
3
3
3
3
6
Facility
EPRI SITE 13
EPRI SITE 112
EPRI SITE 103
EPRI SITE 104
EPRI SITE 104
EPRI SITE 105
EPRI SITE 106
EPRI SITE 106
EPRI SITE 106
EPRI SITE 107
EPRI SITE 108
EPRI SITE 108
EPRI SITE 109
EPRI SITE 109
Southern California
Edison Company,
Alamitos Unit 5
Fuel Type
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual (No. 6)
Residual
Boiler Type
Wall-Fired
(Normal)
Tangentially-Fired
Wall-Fired
(Normal)
Assumed Normal
Assumed Normal
Assumed Normal
Assumed Normal
Assumed Normal
Assumed Normal
Assumed Normal
Opposed (Normal)
Opposed (Normal)
Opposed (Normal)
Opposed (Normal)
Assumed Normal
sec
10100401
10100404
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
10100401
Control
Device la
Uncontrolled
ESP
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
FOR
FOR
FOR
Control
Device T
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
Data
Quality
B
C
B
B
B
B
B
B
B
B
B
B
B
B
B
No.
of
Test
Runs
3
3
3
3
2
3
6
3
4
3
3
2
3
2
6
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - METALS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry
No.
19
22
23
25
16
Ref
No.
6
7
7
8
4
Facility
Southern California
Edison Company,
Alamitos Unit 5
Pacific Gas and
Electric Company,
Morro Bay Unit 3
Pacific Gas and
Electric Company,
Morro Bay Unit 3
Southern California
Edison Company, El
Segundo Station 1
EPRI SITE 118
Fuel Type
Residual
Residual
Residual
Residual
Residual (No. 6)
Boiler Type
Assumed Normal
Radiant Heat
Radiant Heat
Assumed Normal
Front-fired
(normal)
sec
10100401
10100401
10100401
10100401
10100401
Control
Device la
FOR
None
None
None
OFA/FGR
Control
Device T
None
None
None
None
ESP
Data
Quality
C
C
C
C
Dd
No.
of
Test
Runs
3
3
3
3
3
3 UNC = Uncontrolled; FGR = Flue Gas Recirculation; OFA = Over-fire Air; ESP = Electrostatic Precipitator.
b>c At least one test run was "non detect" and the emission factor is based on detection limit values, (b = one "non detect", c = more than one "non
detect")
d Data quality ratings of "D" were not used for averaging with "B" and "C" quality data.
f Pollutant was Not Detected in any of the sampling runs. Half of the detection limit value (DL/2) used to develop factor.
B For a given pollutant, any factors based solely on "non detect" values that were greater than any factors based on detected values were not included in
the calculated average factor.
B-9
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - METALS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry No.
1
2
4
5
6
7
8
9
10
11
12
13
14
15
18
19
22
23
25
Average8
16
Arsenic
1.08e-03
1.76e-04f
5.43e-04
9.61e-04
6.13e-04
3.90e-03
1.96e-03
9.81e-04
8.20e-05f
3.00e-03b
9.95e-04
1.56e-03
1.32e-03
8.13e-05
Barium
3.59e-03
1.54e-03
9.60e-03f
2.57e-03
1.06e-03
Beryllium
1.95e-05f
8.49e-05
3.62e-05b
2.51e-05b
2.69e-05f
2.25e-05b
7.55e-06f
2.17e-06f
3.73e-05f
2.25e-05c
3.16e-05c
2.58e-05c
2.78e-05
2.22e-06f
Cadmium
2.10e-03
4.83e-05
4.83e-04
9.17e-05
1.03e-04
1.80e-04b
2.41e-04
5.77e-04
4.62e-04
2.10e-04c
1.06e-04
1.75e-04
3.98e-04
6.65e-06f
Chloride
1.68e-01
5.26e-01
3.47e-01
5.31e-01
Chromium
1.36e-03
5.42e-04
5.28e-04
4.44e-04
3.14e-04
1.50e-03
1.21e-03
8.65e-05f
1.64e-03
9.60e-04
5.97e-04
9.53e-04
8.45e-04
4.88e-04
Chromium VI
1.36e-04b
4.44e-06f
6.28e-05c
5.70e-04
2.57e-04
4.33e-04
1.42e-04f
4.50e-04
1.24e-04c
1.98e-04
2.48e-04
Cobalt
1.51e-02
1.43e-03
1.52e-03
6.02e-03
2.87e-04
Copper
2.40e-03
9.37e-04
2.71e-04
l.Ole-03
1.49e-03
2.10e-03
3.02e-03
2.16e-03
2.38e-03
1.80e-03
1.03e-03
2.49e-03
1.76e-03
4.12e-04
B-10
(continued)
-------
DATA USED FOR EMISSION FACTOR DEVELOPMENT (LB/1000 GALLONS) - METALS - DL/2
FUEL OIL COMBUSTION (CONTINUED)
Entry
No.
1
2
4
5
6
7
8
9
10
11
12
13
14
15
18
19
22
23
25
Average8
16
Fluoride
6.59e-03
6.81e-02
3.73e-02
Lead
1.23e-03
3.81e-04
5.58e-04
2.37e-04c
1.34e-03
4.20e-03
1.51e-04f
1.44e-03
2.53e-03
3.30e-03
2.37e-03
3.79e-04c
1.51e-03
2.63e-04b
Manganese
1.20e-03
2.14e-03
2.31e-03
3.25e-03
5.98e-04
6.45e-03
1.51e-03
2.16e-03
8.64e-03
3.90e-03
2.57e-03
1.22e-03
3.00e-03
2.73e-03
Mercury
3.44e-05
3.51e-05b
2.72e-04f
8.85e-04f
3.51e-04f
3.75e-04f
2.79e-03f
2.31e-03f
2.68e-04c
3.00e-04f
2.57e-03f
2.33e-03f
1.13e-04
7.39e-05
Molybdenum
4.87e-04f
8.64e-04
1.01e-03c
7.87e-04
5.91e-05
Nickel
2.78e-01
4.44e-02
5.25e-02
5.38e-02
7.62e-02
5.70e-02
6.34e-02
2.02e-01
3.57e-02
4.50e-02
5.47e-02
5.13e-02
8.45e-02
6.80e-03
Phosphorous
2.92e-03f
1.60e-02
9.46e-03
3.99e-04b
Selenium
4.87e-05f
3.52e-04f
4.07e-05
2.59e-04f
4.18e-04
6.15e-04
1.51e-04f
2.16e-03
5.51e-04c
5.10e-04c
5.59e-04c
6.09e-04c
6.83e-04
1.85e-04
Vanadium
5.29e-02
3.51e-02
7.43e-03
3.18e-02
6.24e-03
Zinc
6.75e-02
1.57e-02c
4.24e-03
2.91e-02
B-ll
-------
B.2 Source Test Report Summary Data
B-13
-------
B-14
-------
OIL EF DATABASE REFERENCE NO.
1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 13
EMISSIONS MONITORING. RADIAN CORPORATION, AUSTIN,
TEXAS. FEBRUARY, 1993.
FILENAME
FACILITY:
SITE13.tbl
EPRI SITE 13
PROCESS DATA
Oil Type3
Boiler configuration3
sec
Control device I3
Control device 2
Data Quality
Process Parameters3
Test methods'3
Number of test runs0
Fuel Heating Value (Btu/lb)d
Oil density (lb/gal)e
Fuel Heating Value (Btu/gal)
Fuel Heating Value (Btu/1000 gal)
Fuel Heating Value (MMBtu/1000
3Page 2-1
bAppendix A, Table A-l
cPage 3-9
dPage 3-6
eAppendix A of Ap-42, residual oil
EMISSION FACTORS
Pollutant
Arsenic
Barium
Benzene
Berylliumb
Cadmium
No. 6
Wall-fired (normal)
10100401
none
B
350 MW
EPA, or EPA-approved, test methods
3
19,000
7.88
149,720
149,720,000
gal) 149.72
density.
Emission Factor Emission Factor
(lb/ 1 0 A 1 2 Btu)3 (Ib/MMBtu)
7.2 7.20e-06
24 2.40e-05
1.4 1.40e-06
0.26 2.60e-07
14 1.40e-05
Emission Factor
(lb/1000 gal)
1.08e-03
3.59e-03
2.10e-04
3.89e-05
2.10e-03
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-15
-------
OIL EF DATABASE REFERENCE NO.
EMISSION FACTORS
Pollutant
Chloride
Chromium
Cobalt
Copper
Fluoride
Formaldehyde0
Lead
Manganese
Mercury
Molybdenumb
Nickel
Phosphorous13
Seleniumb
Toluene
Vanadium
"Page 3-17, Boiler Outlet - Baseline data.
bFactor based on detection limit value only.
°Detection limit values for two runs used in
Emission Factor
(lb/10A12 Btu)a
1,120
9.1
101
16
44
8.4
8.2
8.0
0.23
6.5
1,860
39
0.65
5.3
353
See page 3-9.
developing EF. See
Emission Factor
(Ib/MMBtu)
1.12e-03
9.10e-06
l.Ole-04
1.60e-05
4.40e-05
8.40e-06
8.20e-06
8.00e-06
2.30e-07
6.50e-06
1.86e-03
3.90e-05
6.50e-07
5.30e-06
3.53e-04
page 3-9.
Emission Factor
(lb/1000 gal)
1.68e-01
1.36e-03
1.51e-02
2.40e-03
6.59e-03
1.26e-03
1.23e-03
1.20e-03
3.44e-05
9.73e-04
2.78e-01
5.84e-03
9.73e-05
7.94e-04
5.29e-02
PM, FILTERABLE EMISSION FACTORS
Emission Factor
(lb/MMBtu)a
0.049
Emission Factor
(lb/1000 gal)
7.34e+00
"Page 3-17, Boiler Outlet - Baseline data.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-16
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: EMISSIONS
REPORT FOR SITES 103-109. PRELIMINARY DRAFT REPORT.
RADIAN CORPORATION, AUSTIN, TEXAS. MARCH, 1993.
FILENAME
FACILITY:
SITE103.tbl
EPRI SITE 103
PROCESS DATA
Oil Type3
Boiler configuration3
SCCs
Control device I3
Control device 2
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Fuel Oil Heating Value (Btu/lb)d
Fuel Oil density (lb/gal)e
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Fuel Oil Flow rate (lb/hr)d
Fuel Oil Flow rate (gal/hr)
Fuel Oil Flow rate (1000 gal/hr)
Natural Gas (NG) Heating Value (Btu/Scf)3
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Residual (assume No. 6)
Wall-fired (Normal)
OIL: 10100401
None
B
150 MW
EPA, or EPA-approved, test methods
3
19,137
7.88
150,800
150,799,560
150.80
73,333
9,306
9.31
NG: 10100601
1,030
1,030,000,000
0.00103
Tart I: Site 103, page 2-1.
TartI: Site 103, page 3-1.
Tart I: Site 103, page 3-6, 3-7.
Tart I: Site 103, page 3-4, Mean value.
eAppendix A of Ap-42, residual oil density.
EMISSION FACTORS FIRING OIL (SCC 10100401)
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-17
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
Pollutant
Arsenic
Bariumd
Berylliumb
Cadmium
Chromium
Chrome VIb
Cobalt
Copper
Lead
Manganese
Mercuryd
Molybdenum0
Nickel
Selenium
Vanadium
Acenaphthened
Acenaphthylened
Anthracened
Benz(a)anthracened
Benzo(a)pyrened
Benzo(b,k)fluoranthened
Benzo(g,h,i)perylened
Chrysened
Emission
Factor
(lb/1012Btu)a
3.6
127
0.24
3.2
3.5
0.9
10.1
1.8
3.7
15.3
3.6
6.7
348
0.27
49.3
0.006
0.006
0.006
0.006
0.006
0.006
0.006
0.006
Emission
Factor
(Ib/MMBtu
3.60e-06
1.27e-04
2.40e-07
3.20e-06
3.50e-06
9.00e-07
l.Ole-05
1.80e-06
3.70e-06
1.53e-05
3.60e-06
6.70e-06
3.48e-04
2.70e-07
4.93e-05
6.00e-09
6.00e-09
6.00e-09
6.00e-09
6.00e-09
6.00e-09
6.00e-09
6.00e-09
Emission
Factor
(Ib/lOOOgal)
5.43e-04
1.92e-02
3.62e-05
4.83e-04
5.28e-04
1.36e-04
1.52e-03
2.71e-04
5.58e-04
2.31e-03
5.43e-04
l.Ole-03
5.25e-02
4.07e-05
7.43e-03
9.05e-07
9.05e-07
9.05e-07
9.05e-07
9.05e-07
9.05e-07
9.05e-07
9.05e-07
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-18
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Dibenz(a,h)anthracened
Fluoranthened
Fluorened
Indeno(l,2,3-c,d)pyrened
Naphthalened
Phenanthrened
Pyrened
Formaldehyded
Benzened
10100401)
Emission
Factor
(lb/1012Btu)a
0.006
0.006
0.006
0.006
0.006
0.006
0.006
19.9
6.5
Emission Emission
Factor Factor
(Ib/MMBtu (lb/ 1000 gal)
6.00e-09 9.05e-07
6.00e-09 9.05e-07
6.00e-09 9.05e-07
6.00e-09 9.05e-07
6.00e-09 9.05e-07
6.00e-09 9.05e-07
6.00e-09 9.05e-07
1.99e-05 3.00e-03
6.50e-06 9.80e-04
Tart I; Site 103, pages 3-9, 3-10. See 3-6, 3-7, 3-8 for individual run data.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
PM, FILTERABLE EMISSION FACTORS
10100401)
Stack gas flow rate
(Nm3/hr)a
472,400
(SCC
PM
concentratio
n
(ug/Nm3)a
17,199
PM PM
Emission Emission
Rate Rate
(ug/hr) (Ib/hr)
8.12e+09 17.92
PM
Emission
Factor
(lb/1000
gal)
1.93
Tart I: Site 103, page 3-6, Mean value.
EMISSION FACTORS FIRING NATURAL GAS
Pollutant
Formaldehyded
Benzened
Tage 3-10. Individual run data on page 3-8
dPollutant not detected in any sampling runs
Emission
Factor
(lb/1012 Btu)a
17.7
4.4
Emission Factor
(Ib/MM Cu Ft)
1.82e-02
4.53e-03
, emission factor developed from detection limits.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-19
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REF NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: EMISSIONS
REPORT FOR SITES 103-109. PRELIMINARY DRAFT REPORT.
RADIAN CORPORATION, AUSTIN, TEXAS. MARCH, 1993.
FILENAME
FACILITY:
SITE104.tbl
EPRI SITE 104
PROCESS DATA
Fuel Oil Type3
Boiler configuration
SCCs
Control device la
Control device 2
Data Quality
Process Parameters3
Test methods'3
Number of test runs0
Fuel Oil Heating Value (Btu/lb)d
Oil Density (lb/gal)e
Oil Heating Value (Btu/gal)
Oil Heating Value (Btu/1000 gal)
Oil Heating Value (MMBtu/1000 gal)
NG Heating Value (Btu/cu ft) f
NG Heating Value (Btu/MM cu ft)
NG Heating Value (EA12 Btu/MM cu ft)
Residual (assume No. 6)
Assumed Normal
OIL: 10100401 NG: 10100601
None
B
350 MW
EPA, or EPA-approved, test methods
SCC 10100401: 2 for manganese, 3 for all others
SCC 10100601: 3
18,770
7.88
147,908
147,907,600
147.91
1,036.0
1,036,000,000
0.00104
Tart II: Site 104, page 2-1.
bPartII: Site 104, page 3-1.
Tart II: Site 104, pages 3-7, 3-8, 3-9, 3-10, 3-12.
dPart II: Site 104, page 3-6, mean value.
eAppendix A of Ap-42, residual oil density.
fPart II: Site 104. Appendix D. page D-3.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-20
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REF NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Arsenic
Berylliumb
Cadmium
Chromium
Chrome VId
Copper
Leadc
Manganese6
Mercuryd
Nickel
Seleniumd
Acenaphtheneb
Acenaphthylened
Anthracened
Benz(a)anthracened
Benzo(a)pyrened
Benzo(b,k)fluoranthened
Benzo(g,h,i)perylened
Chrysened
Dibenz(a,h)anthracened
Fluoranthened
Fluorene
Indeno(l,2,3-c,d)pyrened
Naphthalene
Phenanthreneb
Pyrene0
Benzened
Formaldehydeb
10100401)
Emission Factor
(lb/10A12 Btu)a
6.5
0.17
0.62
3
0.06
6.8
1.6
22
12
364
3.5
0.1
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.014
0.01
4.3
0.011
0.01
2.5
169
Emission Factor
(Ib/MMBtu)
6.50e-06
1.70e-07
6.20e-07
3.00e-06
6.00e-08
6.80e-06
1.60e-06
2.20e-05
1.20e-05
3.64e-04
3.50e-06
l.OOe-07
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
1.40e-08
l.OOe-08
4.30e-06
1.10e-08
l.OOe-08
2.50e-06
1.69e-04
Emission Factor
(lb/1000 gal)
9.61e-04
2.51e-05
9.17e-05
4.44e-04
8.87e-06
l.Ole-03
2.37e-04
3.25e-03
1.77e-03
5.38e-02
5.18e-04
1.48e-05
1.48e-06
1.48e-06
1.48e-06
1.48e-06
1.48e-06
1.48e-06
1.48e-06
1.48e-06
1.48e-06
2.07e-06
1.48e-06
6.36e-04
1.63e-06
1.48e-06
3.70e-04
2.50e-02
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-21
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REF NO. 1
Tart II: Site 104, pages 3-13. See pages 3-7 through 3-12 for individual run data.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
eEmission factor based on 2 test runs.
EMISSION FACTORS NATURAL GAS (SCC 10100601)
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Benzened 2.3 2.38e-03
Formaldehyde0 25 2.59e-02
Tage 3-13. Individual run data on page 3-12.
bDetection limit value (1/2) for one run used in developing EF.
°Detection limit value (1/2) for two runs used in developing EF.
dFactor based on detection limit value only.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-22
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: EMISSIONS
REPORT FOR SITES 103-109. PRELIMINARY DRAFT REPORT.
RADIAN CORPORATION, AUSTIN, TEXAS. MARCH, 1993.
FILENAME
FACILITY:
SITElOS.tbl
EPRI SITE 105
PROCESS DATA
Oil Type3
Boiler configuration
SCCs
Control device lb
Control device 2
Data Quality
Process Parameters13
Test methods0
Number of test runsd
Fuel Oil Heating Value (Btu/lb)e
Fuel Oil density (lb/gal)f
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Natural Gas (NG) Heating Value (Btu/Scf)8
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Residual (assume No. 6)
Assumed Normal
OIL: 10100401 NG: 10100601
None
B
750 MW
EPA, or EPA-approved, test methods
3
18,960
7.88
149,405
149,404,800
149.40
1,042.5
1,042,500,000
0.0010425
Tart III: Site 105. Page 3-7, title of Table 3-2a.
Tart III: Site 105. Page 2-1.
Tart III: Site 105. Appendix A, various pages.
Tart III: Site 105. Pages 3-7, 3-8 and 3-12.
Tart III: Site 105. Page 3-6.
fAppendix A of Ap-42, residual oil density.
Tart III: Site 105. Appendix D. Page D-4.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-23
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Arsenic
Berylliumd
Cadmium
Chromium
Chrome VF
Copper
Lead
Manganese
Mercuryd
Nickel
Selenium
Acenaphthened
Acenaphthylened
Anthracened
Benz(a)anthracene°
Benzo(a)pyrened
Benzo(b,k)fluoranthene°
Benzo(g,h,i)perylene°
Chrysene0
Dibenz(a,h)anthracene°
Fluoranthene
Fluorene0
Indeno(l,2,3-c,d)pyrene°
Naphthalene13
Phenanthrene
Pyrene0
Benzened
Formaldehyde
10100401)
Emission Factor
(lb/10A12 Btu)a
4.1
0.36
0.69
2.1
0.42
10
9
4.0
4.7
510
2.8
0.007
0.007
0.007
0.03
0.007
0.016
0.010
0.006
0.006
0.04
0.020
0.010
13
0.09
0.023
2.5
620
Emission Factor
(Ib/MMBtu)
4.10e-06
3.60e-07
6.90e-07
2.10e-06
4.20e-07
l.OOe-05
9.00e-06
4.00e-06
4.70e-06
5.10e-04
2.80e-06
7.00e-09
7.00e-09
7.00e-09
3.00e-08
7.00e-09
1.60e-08
l.OOe-08
6.00e-09
6.00e-09
4.00e-08
2.00e-08
l.OOe-08
1.30e-05
9.00e-08
2.30e-08
2.50e-06
6.20e-04
Emission Factor
(lb/ 1000 gal)
6.13e-04
5.38e-05
1.03e-04
3.14e-04
6.28e-05
1.49e-03
1.34e-03
5.98e-04
7.02e-04
7.62e-02
4.18e-04
1.05e-06
1.05e-06
1.05e-06
4.48e-06
1.05e-06
2.39e-06
1.49e-06
8.96e-07
8.96e-07
5.98e-06
2.99e-06
1.49e-06
1.94e-03
1.34e-05
3.44e-06
3.74e-04
9.26e-02
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-24
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
Tart III: Site 105. Page 3-13. Individual run data on pages 3-7, 3-8, 3-9, 3-10, 3-11 and 3-12.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
EMISSION FACTORS FIRING NATURAL GAS
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Benzened 1.0 1.04e-03
Formaldehyde 600 6.26e-01
Tart III: Site 105. Page 3-13. Individual run data on page 3-13.
dFactor based on detection limit value only.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-25
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: EMISSIONS
REPORT FOR SITES 103-109. PRELIMINARY DRAFT REPORT.
RADIAN CORPORATION, AUSTIN, TEXAS. MARCH, 1993.
FILENAME
FACILITY:
SITE106.tbl
EPRI SITE 106
PROCESS DATA
Oil Type3
Boiler configuration
SCCs
Control device la
Control device 2
Data Quality
Process Parameters3
Test methods'3
Number of test runs0
Fuel Oil Heating Value (Btu/lb)d
Fuel Oil density (lb/gal)e
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Natural Gas (NG) Heating Value (Btu/Scf)f
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Residual (assume No. 6)
Assumed Normal
OIL: 10100401 NG: 10100601
None
B
480 MW
EPA, or EPA-approved, test methods
6 for all metals except chrome, chrome VI and manganese.
4 for manganese, 3 for chrome, chrome VI, PAHs,
benzene, formaldehyde. 2 for anthracene
19,035
7.88
149,996
149,995,800
150.00
947
947,000,000
0.000947
Tart IV: Site 106. Page 2-1.
bPartIV: Site 106. Page 3-1.
Tart IV: Site 106. Page 3-7, 3-8, 3-9, 3-10, 3-11.
Tart IV: Site 106. Page 3-6.
eAppendix A of AP-42, residual oil density.
Tart IV: Site 106. Appendix D. Page D-3.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-26
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Arsenic
Berylliumb
Cadmiumb
Chromium
Chrome VI
Copper
Lead
Manganese
Mercuryd
Nickel
Selenium
Acenaphthene
Acenaphthylened
Anthracened
Benz(a)anthracened
Benzo(a)pyrened
Benzo(b,k)fluoranthened
Benzo(g,h,i)perylened
Chrysened
Dibenz(a,h)anthracened
Fluoranthene0
Fluorene
Indeno(l,2,3-c,d)pyrened
Napththalene
Phenanthrene
Pyrened
Benzened
Formaldehyded
10100401)
Emission Factor
(lb/10A12 Btu)a
26
0.15
1.2
10
3.8
14
28
43
5
380
4.1
0.66
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.009
0.037
0.01
3.7
0.036
0.01
3
20
Emission Factor
(Ib/MMBtu)
2.60e-05
1.50e-07
1.20e-06
l.OOe-05
3.80e-06
1.40e-05
2.80e-05
4.30e-05
5.00e-06
3.80e-04
4.10e-06
6.60e-07
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-08
9.00e-09
3.70e-08
l.OOe-08
3.70e-06
3.60e-08
l.OOe-08
3.00e-06
2.00e-05
Emission Factor
(lb/1000 gal)
3.90e-03
2.25e-05
1.80e-04
1.50e-03
5.70e-04
2.10e-03
4.20e-03
6.45e-03
7.50e-04
5.70e-02
6.15e-04
9.90e-05
1.50e-06
1.50e-06
1.50e-06
1.50e-06
1.50e-06
1.50e-06
1.50e-06
1.50e-06
1.35e-06
5.55e-06
1.50e-06
5.55e-04
5.40e-06
1.50e-06
4.50e-04
3.00e-03
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-27
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
Tart VI: Site 106. Page 3-13. Individual run data on pages 3-7, 3-8, 3-9, 3-10, 3-11.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
EMISSION FACTORS FIRING NATURAL GAS
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Benzened 4 3.79e-03
Formaldehyde 82 7.77e-02
Tart VI: Site 106. Page 3-13. Individual run data on page 3-11.
dFactor based on detection limit value only.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-28
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: EMISSIONS
REPORT FOR SITES 103-109. PRELIMINARY DRAFT REPORT.
RADIAN CORPORATION, AUSTIN, TEXAS. MARCH, 1993.
FILENAME
FACILITY:
SITE107.tbl
EPRI SITE 107
PROCESS DATA
Oil Type3
Boiler configuration
SCCs
Control device I3
Control device 2
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Fuel Oil Heating Value (Btu/lb)d
Fuel Oil density (lb/gal)e
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Natural Gas (NG) Heating Value (Btu/Scf)f
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Residual (assume No. 6)
Assumed
Normal
OIL: 10100401
None
NG: 10100601
B
175 MW
EPA, or EPA-approved, test methods
3 for all
19,150
7.88
150,902
150,902,000
150.90
957
957,000,000
0.000957
3PartV: Site 107. Page 2-1.
bPartV: Site 107. Page 3-1.
Tart V: Site 107. Page 3-7, 3-8, 3-9, 3-10, 3-11.
dPartV: Site 107. Page 3-6.
eAppendix A of Ap-42, residual oil density.
fPartV: Site 107. Appendix D. Page D-3.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-29
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Arsenic
Berylliumd
Cadmium
Chromium
Chrome VI
Copper
Leadd
Manganese
Mercuryd
Nickel
Seleniumd
Acenaphthened
Acenaphthylened
Anthracene0
Benz(a)anthraceneb
Benzo(a)pyrened
Benzo(b,k)fluoranthene°
Benzo(g,h,i)perylene°
Chryseneb
Dibenz(a,h)anthracene°
Fluorantheneb
Fluorene0
Indeno(l,2,3-c,d)pyrene°
Naphthalene0
Phenanthreneb
Pyreneb
Benzened
Formaldehyde
10100401)
Emission Factor
(lb/10A12 Btu)a
13
0.1
1.6
8
1.7
20
2
10
37
420
2
0.01
0.01
0.010
0.1
0.01
0.04
0.03
0.06
0.010
0.09
0.004
0.03
6
0.12
0.08
4
600
Emission Factor
(Ib/MMBtu)
1.30e-05
l.OOe-07
1.60e-06
8.00e-06
1.70e-06
2.00e-05
2.00e-06
l.OOe-05
3.70e-05
4.20e-04
2.00e-06
l.OOe-08
l.OOe-08
l.OOe-08
l.OOe-07
l.OOe-08
4.00e-08
3.00e-08
6.00e-08
l.OOe-08
9.00e-08
4.00e-09
3.00e-08
6.00e-06
1.20e-07
8.00e-08
4.00e-06
6.00e-04
Emission Factor
(lb/ 1000 gal)
1.96e-03
1.51e-05
2.41e-04
1.21e-03
2.57e-04
3.02e-03
3.02e-04
1.51e-03
5.58e-03
6.34e-02
3.02e-04
1.51e-06
1.51e-06
1.51e-06
1.51e-05
1.51e-06
6.04e-06
4.53e-06
9.05e-06
1.51e-06
1.36e-05
6.04e-07
4.53e-06
9.05e-04
1.81e-05
1.21e-05
6.04e-04
9.05e-02
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-30
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
3PartV: Site 107. Pages 3-13, 3-14. Individual run data on pages 3-7 through 3-11.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
EMISSION FACTORS FIRING NATURAL GAS
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Benzened 4 3.83e-03
Formaldehyde 800 7.66e-01
Tart V: Site 107. Page 3-14. Individual run data on page 3-11.
dFactor based on detection limit value only.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-31
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: EMISSIONS
REPORT FOR SITES 103-109. PRELIMINARY DRAFT REPORT.
RADIAN CORPORATION, AUSTIN, TEXAS. MARCH, 1993.
FILENAME
FACILITY:
SITE108.tbl
EPRI SITE 108
PROCESS DATA
Oil Type3
Boiler configuration
SCCs
Control device la
Control device 2
Data Quality
Process Parameters3
Test methods'3
Number of test runs0
Fuel Oil Heating Value (Btu/lb)d
Fuel Oil density (lb/gal)e
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Natural Gas (NG) Heating Value (Btu/lb)a
NG Density (lb/scf)f
NG Heating Value (Btu/Scf)
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Residual (assume No. 6)
Opposed fired (Assumed Normal)
OIL: 10100401 NG: 10100601
None
B
50 MW
EPA, or EPA-approved, test methods
2 for manganese, 3 for all others
18,300
7.88
144,204
144,204,000
144.20
23500
0.042
987
987,000,000
9.87e-04
Tart VI: Site 108. Page 2-1.
bPartVI: Site 108. Page 3-1.
Tart VI: Site 108. Page 3-7, 3-8, 3-10, 3-12.
Tart VI: Site 108. Page 3-6.
eAppendix A of AP-42, residual oil density.
fAppendix A of AP-42. density of natural gas - 1 lb/23.8 ft3.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-32
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL (SCC
Pollutant
Arsenic
Berylliumd
Cadmium
Chromiumd
Chrome VI
Copper
Lead
Manganese
Mercuryd
Nickel
Selenium
Acenaphthened
Acenaphthylened
Anthracened
Benz(a)anthracened
Benzo(a)pyrened
Benzo(b,k)fluoranthened
Benzo(g,h,i)perylened
Chrysened
Fluoranthened
Fluorened
Indeno(l,2,3-c,d)pyrened
Naphthaleneb
Phenanthrene0
Pyreneb
Benzened
Formaldehvded
10100401)
Emission Factor
(lb/10A12 Btu)a
6.8
0.03
4.0
1.2
3.0
15
10
15
32
1,400
15
0.008
0.008
0.008
0.008
0.008
0.008
0.008
0.008
0.008
0.008
0.008
0.52
0.02
0.008
2.8
20
Emission Factor
(Ib/MMBtu)
6.80e-06
3.00e-08
4.00e-06
1.20e-06
3.00e-06
1.50e-05
l.OOe-05
1.50e-05
3.20e-05
1.40e-03
1.50e-05
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
8.00e-09
5.20e-07
2.00e-08
8.00e-09
2.80e-06
2.00e-05
Emission Factor
(lb/ 1000 gal)
9.81e-04
4.33e-06
5.77e-04
1.73e-04
4.33e-04
2.16e-03
1.44e-03
2.16e-03
4.61e-03
2.02e-01
2.16e-03
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
1.15e-06
7.50e-05
2.88e-06
1.15e-06
4.04e-04
2.88e-03
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-33
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
Tart VI: Site 108. Page 3-13. Individual run data on pages 3-7, 3-8, 3-10, 3-12.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
EMISSION FACTORS FIRING NATURAL GAS
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Benzened 2.2 2.17e-03
Formaldehyde0 12 1.18e-02
Tart VI: Site 108. Page 3-13. Individual run data on page 3-12.
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value only.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-34
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: EMISSIONS
REPORT FOR SITES 103-109. PRELIMINARY DRAFT REPORT.
RADIAN CORPORATION, AUSTIN, TEXAS. MARCH, 1993.
FILENAME
FACILITY:
SITE109.tbl
EPRI SITE 109
PROCESS DATA
Oil Type3
Boiler configuration3
SCCs
Control device I3
Control device 2
Data Quality
Process Parameters3
Test methods'3
Number of test runs0
Fuel Oil Heating Value (Btu/lb)d
Fuel Oil density (lb/gal)e
Fuel Oil Heating Value (Btu/gal)
Fuel Oil Heating Value (Btu/1000 gal)
Fuel Oil Heating Value (MMBtu/1000 gal)
Natural Gas (NG) Heating Value (Btu/Scf)3
NG Heating Value (Btu/MM Cu Ft)
NG Heating Value (EA12 Btu/MM Cu Ft)
Residual (assume No. 6)
Opposed fired (Assumed Normal)
OIL: 10100401 NG: 10100601
Flue Gas Recirculation (FGR)
B
230 MW
EPA, or EPA-approved, test methods
Oil firing: 2 for manganese, 3 for all others.
NG firing: 6 for all (formaldehyde)
18,900
7.88
148,932
148,932,000
148.93
1,000
1,000,000,000
l.OOe-03
Tart VII: Site 109. Page 2-1.
bPartVII: Site 109. Page 3-1.
Tart VII: Site 109. Page 3-6, 3-7, 3-10.
TartVII: Site 109. Page 3-4.
eAppendix A of Ap-42, residual oil density.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-35
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING OIL
Pollutant
Arsenicd
Berylliumd
Cadmium
Chromium
Copper
Lead
Manganese
Mercury0
Nickel
Selenium0
Chrome VId
Acenaphthene
Acenaphthylene
Anthracene
Benz(a)anthracene
Chrysene
Fluoranthene
Fluorene
Naphthalene
Phenanthrene
Pyrene
Benzened
Formaldehyde
(SCC 10100401)
Emission Factor
(lb/10A12 Btu)a
1.1
0.5
3.1
11
16
17
58
1.8
240
3.7
1.9
0.054
0.0017
0.019
0.0088
0.021
0.075
0.16
33
0.33
0.066
9.7
400
Tart VII: Site 109. Page 3-13, 3-14, 100% load. Individual run
bDetection limit value for one run used in developing EF.
°Detection limit value for two runs used in developing EF.
dFactor based on detection limit value onlv.
Emission Factor
(Ib/MMBtu)
1.10e-06
5.00e-07
3.10e-06
1.10e-05
1.60e-05
1.70e-05
5.80e-05
1.80e-06
2.40e-04
3.70e-06
1.90e-06
5.40e-08
1.70e-09
1.90e-08
8.80e-09
2.10e-08
7.50e-08
1.60e-07
3.30e-05
3.30e-07
6.60e-08
9.70e-06
4.00e-04
data 3-6, 3-7, 3-10.
Emission Factor
(lb/ 1000 gal)
1.64e-04
7.45e-05
4.62e-04
1.64e-03
2.38e-03
2.53e-03
8.64e-03
2.68e-04
3.57e-02
5.51e-04
2.83e-04
8.04e-06
2.53e-07
2.83e-06
1.31e-06
3.13e-06
1.12e-05
2.38e-05
4.91e-03
4.91e-05
9.83e-06
1.44e-03
5.96e-02
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-36
-------
OIL EF DATABASE REFERENCE NO. 3
NATURAL GAS EF DATABASE REFERENCE NO. 1
EMISSION FACTORS FIRING NATURAL GAS
Emission Factor Emission Factor
Pollutant (lb/10A12 Btu)a (Ib/MM Cu Ft)
Formaldehyde 46 4.60e-02
"Part VII: Site 109. Page 3-15, 100% load. Individual run data on page 3-10.
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-37
-------
OIL EF DATABASE REFERENCE NO. 2
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 112
EMISSIONS REPORT. CARNOT, Tustin, California. February 24, 1994.
FILENAME
FACILITY:
SITE112.tbl
EPRI SITE 112
PROCESS DATA
Oil Type3
Boiler configuration3
sec
Control device I3
Control device 2
Data Quality
Process Parameters3
Test methods'3
Number of test runs0
Fuel Heating Value (Btu/lb)d
Oil density (lb/gal)e
Fuel Heating Value (Btu/gal)
Fuel Heating Value (Btu/1000 gal)
Fuel Heating Value (MMBtu/1000 gal)
Residual (assume No. 6)
Tangentially-Fired
10100404
ESP
C (They did not measure stack gas flow rate,
F-factor instead. See page 38.)
387 MW
EPA, or EPA-approved, test methods
4 for benzene and toluene; 3 for all others
18,582
7.88
146,426
146,426,160
146.43
but used an
3Page 6
bPage 12
cPage 23
dPage 19
eAppendix A of AP-42, residual oil density.
EMISSION FACTORS
Pollutant
Arsenicb
Barium
Beryllium
Cadmium
Emission Factor Emission Factor
(lb/ 1 0 A 1 2 Btu)3 (Ib/MMBtu)
2.4 2.40e-06
10.5 1.05e-05
0.58 5.80e-07
0.33 3.30e-07
Emission Factor
(lb/1000 gal)
3.51e-04
1.54e-03
8.49e-05
4.83e-05
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-38
-------
OIL EF DATABASE REFERENCE NO. 2
EMISSION FACTORS
Emission Factor
Pollutant (lb/10A
Chromium
Cobalt
Copper
Lead
Manganese
Mercury0
Molybdenum
Nickel
Phosphorous
Selenium*3
Vanadium
Chloride
Fluoride
Fluorene
Phenanthrene
2-Methylnaphthalene
Benzene
Toluene
Formaldehyde
12 Btu)a
3.7
9.8
6.4
2.6
14.6
0.24
5.9
303
109
4.8
240
3,590
465
0.020
0.020
0.015
2.4
79.5
13.4
Emission Factor
(Ib/MMBtu)
3.70e-06
9.80e-06
6.40e-06
2.60e-06
1.46e-05
2.40e-07
5.90e-06
3.03e-04
1.09e-04
4.80e-06
2.40e-04
3.59e-03
4.65e-04
2.00e-08
2.00e-08
1.50e-08
2.40e-06
7.95e-05
1.34e-05
Emission Factor
(lb/1000 gal)
5.42e-04
1.43e-03
9.37e-04
3.81e-04
2.14e-03
3.51e-05
8.64e-04
4.44e-02
1.60e-02
7.03e-04
3.51e-02
5.26e-01
6.81e-02
2.93e-06
2.93e-06
2.20e-06
3.51e-04
1.16e-02
1.96e-03
aPages 26 & 27.
bPollutant not detected in all sampling runs. See page 23.
°Detection limit value for one run used in developing EF.
PM, FILTERABLE EMISSION FACTORS
Emission Factor Emission Factor
(lb/MMBtu)a (lb/1000
0.0177 2.
gal)
59e+00
aPage 26
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-39
-------
OIL EF DATABASE REFERENCE NO. 4
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 118
EMISSIONS REPORT. CARNOT, Tustin, California. January 20, 1994.
FILENAME
FACILITY:
SITE118.tbl
EPRI SITE 118
PROCESS DATA
Oil Type3
Boiler configuration3
sec
Control device I3
Control device 23
Data Quality
Process Parameters3
Test methods'3
Number of test runs0
Fuel Heating Value (Btu/lb)d
Oil density (lb/gal)e
Fuel Heating Value (Btu/gal)
Fuel Heating Value (Btu/1000 gal)
Fuel Heating Value (MMBtu/1000 gal)
Residual (assume No. 6)
Front-fired (normal)
10100401
Over-fire Air, Flue Gas Recirculation
ESP
D (high blank values)
850 MW
EPA, or EPA-approved, test methods
3
18,756
7.88
147,797
147,797,280
147.80
3Page 7
bPage 15
Tage 25, 26, 27, 28
dPage 18, mean value
eAppendix A of AP-42, residual oil density.
EMISSION FACTORS
Pollutant
Filterable PM3
Emission Factor
(lb/10A12 Btu)
Emission Factor
(Ib/MMBtu)
0.0041
Emission Factor
(Ib/lOOOgal)
6.06e-01
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-40
-------
OIL EF DATABASE REFERENCE NO. 4
EMISSION FACTORS
Pollutant
METALS, ANIONS3
Arsenic
Barium
Berylliumd
Cadmiumd
Chromium
Cobalt
Copper
Leadb
Manganese
Mercury
Molybdenum
Nickel
Phosphorous13
Selenium
Vanadium
Chloride
PAHse
Naphthalene
Phenanthrene
2-Methylnaphthalene
PCDD/PCDFf
2,3,7,8-TCDDd
Total TCDDd
Total PeCDDd
Total HxCDDd
Total HpCDDd
OCDDb
Emission Factor
(lb/10A12 Btu)
0.55
7.16
0.06
0.18
3.30
1.94
2.79
1.78
18.5
0.50
0.40
46.0
2.70
1.25
42.2
3,590
0.31
0.012
0.027
4.3e-06
4.3e-06
4.6e-06
6.8e-06
2.5e-05
2.1e-05
Emission Factor
(Ib/MMBtu)
5.50e-07
7.16e-06
6.00e-08
1.80e-07
3.30e-06
1.94e-06
2.79e-06
1.78e-06
1.85e-05
5.00e-07
4.00e-07
4.60e-05
2.70e-06
1.25e-06
4.22e-05
3.59e-03
3.10e-07
1.20e-08
2.70e-08
4.30e-12
4.30e-12
4.60e-12
6.80e-12
2.50e-ll
2.10e-ll
Emission Factor
(lb/ 1000 gal)
8.13e-05
1.06e-03
8.87e-06
2.66e-05
4.88e-04
2.87e-04
4.12e-04
2.63e-04
2.73e-03
7.39e-05
5.91e-05
6.80e-03
3.99e-04
1.85e-04
6.24e-03
5.31e-01
4.58e-05
1.77e-06
3.99e-06
6.36e-10
6.36e-10
6.80e-10
l.Ole-09
3.69e-09
3.10e-09
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-41
-------
OIL EF DATABASE REFERENCE NO. 4
EMISSION FACTORS
Pollutant
2,3,7,8-TCDFd
Total TCDFd
Total PeCDFd
Total HxCDFd
Total HpCDFd
OCDFd
Emission Factor Emission Factor
(lb/10A12 Btu)
1.8e-06
1.8e-06
2.6e-06
5.0e-06
3.4e-05
1.6e-05
(Ib/MMBtu)
1.80e-12
1.80e-12
2.60e-12
5.00e-12
3.40e-ll
1.60e-ll
Emission Factor
(lb/ 1000 gal)
2.66e-10
2.66e-10
3.84e-10
7.39e-10
5.03e-09
2.36e-09
PCBsd
VOCs8
Benzene
Toluene
Vinyl Chlorided
l,3-Butadiened
Methyl Bromided
Chloroformd
1,2-Dichloroethane (Ethylene
Dichloride)d
1,1,1 -Trichloroethane
Carbon Tetrachlorided
1,2-Dichloropropane (Propylene
Dichloride)d
Trichloroethaned
Perchloroethylened
Chlorobenzened
Ethylbenzene
o-Xylene
Formaldehyde
0.53
7.6
1.43
0.16
1.74
1.09
2.11
1.6
0.94
2.41
1.20
1.01
0.69
0.43
0.74
5.4
5.30e-07
7.60e-06
1.43e-06
1.60e-07
1.74e-06
1.09e-06
2.11e-06
1.60e-06
9.40e-07
2.41e-06
1.20e-06
l.Ole-06
6.90e-07
4.30e-07
7.40e-07
5.40e-06
7.83e-05
1.12e-03
2.11e-04
2.36e-05
2.57e-04
1.61e-04
3.12e-04
2.36e-04
1.39e-04
3.56e-04
1.77e-04
1.49e-04
1.02e-04
6.36e-05
1.09e-04
7.98e-04
3Page 29. Individual run data on page 25.
bDetection limit value for one run used in developing EF.
°Detection limit values for two runs used in developing EF.
dFactor based on detection limit value only.
ePage 30. Individual run data on page 26
fPage 30. Individual run data on page 27
8Page 3 1 . Individual run data on page 26
(formaldehyde) and page 28
7997\92\04\Suplemnt.B\Reports\Chptr01\01-03.001 (6-26-3)
B-42
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