PB86-108263
I
Primary Sulfate Balsaion Factors for the
NAPAP (National Acid Precipitation
Assessment Program) Emissions Inventory
Radian Corp., Research Triangle Park? NC
Prepared for
Environmental Protection Agency
Research Triangle Park, NC
Sep 85
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EPA/600/7-85/037
September 1985
PRIMARY SULFATE EMISSION FACTORS
FOR THE NAPAP EMISSIONS INVENTORY
by
James B. Homolya
Radian Corporation
3200 East Chapel Hill Road/Progress Center
Research Triangle Park, North Carolina 27709
Contract No. 68-02-3994
Work Assignment 5
Project Officer
J. David Mobley
A1r and Energy Engineering Research Laborato-y
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
AIR AND ENERGY ENGINEERING RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK, NC 27711
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TECHNICAL REPORT DATA
(Htat ntd Inunctions on iht rtreru btfon compttMt)
• REPORT NO
EPA/600/7-85/037
2.
3 RECIPIENT'S ACCESSION1 WO.
4 TITLE AND SUBTITLE
Primary Sulfate Emission Factors for the NAPAP
Emissions Inventory
I. REPORT DATS
September 1985
I. PERFORMING ORGANIZATION COOi
7 AUTHORISI
James B. Homolya
I. PERFORMING OROANIIATION REPORT NO
• PERFORMING ORGANIZATION NAME AND AOORE SB
Radian Corporation
P. O. Box 13000
Research Triangle Park. North Carolina 27709
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3994, Task 5
12 SPONSORING AOf NCV NAMI AND ADORES*
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13. TYPE Of REPORT AND PERIOD COVERED
Task Final; 9/83 - 7/85
14. SPONSORING AGENCY COOS
EPA/600/13
is SUPPLEMENTARY NOTIS AEERL project officer is J. David Mobley. Mail Drop 6TT9T9/
541-2612.
is. ABSTRACT jne report gives results of an estimation of primary sulfate emission fac-
tors for use in the 1980 and 1985 National Acid Precipitation Assessment Program
(NAPAP) emissions inventories. The estimates were developed from an assessment
of existing measurements data for source categories including external combustion.
chemical manufacturing, primary metals, wood products, mineral products, and
petroleum refining. Initial elements of the assessment summarized primary sulfate
formation mechanisms prevalent in combustion processes and reviewed the state-
of-the-art methodology for primary sulfate sampling and analysis of source emis-
sions, The Controlled Condensation System (CCS) was evaluated as the best primary
sulfate emission measurement approach. CCS-derived measurement data were ab-
stracted from an inventory of reports consisting of a variety of environmental asses-
sment studies, field measurement evaluation experiments, and the U.S. /Canadian
Work Group 3B inventory. The measurement data were then used to estimate primary
sulfate emission factors for the corresponding source categories. Uncertainty esti-
mates are given for each emission factor, and source catego* ies are identified where
data are either lacking or incomplete to permit the assignment of an emission
factor.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b IDENTIPlSRS/OPEN ENDED TERMS
C. COSATl f KM/Croup
Pollution
Sulfates
Emission
Precipitation
Acidity
Measurement
Combustion
Chemical Industry
Metals
Wood Products
Minerals
Petroleum Refining
Pollution Control
Stationary Sources
AcH Rain
NAPAP
13B
D7B
14G
04B
07 D
21B
07A
11F
11L
08G
13H
t DISTRIBUTION STATEMENT
Release to Public
IS SECURITY CLASS
Unclassified
21 NO or PAOIS
I 56
20 SECURITY
Unclassified
13 PRICE
EPA Perm 1110-1 IS-73)
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NOTICE
This document has been reviewed in accordance with
U.S. Environmental Protection Agency policy and
approved for publication. Mention of trade names
or commercial products does not constitute endorse-
ment or recommendation for use.
ii
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ABSTRACT
Primary sulfate emission factors were estimated for Task Group B, Man-Mada
Sources, of the National Add Precipitation Assessment Program (HAPAP), for
use In the 1980 and 1985 NAPAP Emissions Inventories. The estimates were
developed from an assessment of existing measurements data for source
categories Including external combustion, chemical manufacturing, primary
metals, wood products, mineral products, and petroleum refining. Initial
elements of the assessment summarized primary sulfate formation mechanisms
prevalent In combustion processes and reviewed the state-of-the-art methodology
for primary sulfate sampling and analyses of source emissions. The controlled
condensation system (CCS) method was evaluated as the best primary sulfate
emission measurement approach. CCS-deHved measurement data were abstracted
from an Inventory of reports consisting of a variety of environmental
assessment studies, field measurement evaluation experiments, and the
U. S./Canadian Work Group 3B Inventory. The measurement data were then used
to estimate primary sulfate emission factors for the corresponding source
categories. Uncertainty estimates are given for each emission factor ard
source categories are Identified where data Is either lacking or Incomplete to
permit the assignment of an emission factor.
ill
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CONTENTS
Abstract . . . . , ill
Tables vi
Abbreviations Vii
1. Project SuMMry 1
Introduction 1
Approach f . . 2
Recommended Primary Sulfate Emission! Factors for the
NAPAP Inventories 4
2. Formation of Primary Sulfates In Combustion Sources 9
Fuel Characteristics 9
Combustion Processes 11
3. Review of Primary Sulfate Emission Measurement Methodology ... 16
Absorption Systems 17
Condensation Systems . . 17
4. Review of Available Primary Sulfate Emission Factor Data Bases . . 19
Primary Sulfate Emission Factors from the
SURE Emissions Inventory 19
Primary Sulfate Emission Factors Utilized by
working Group 38 21
Emission Characterization of Major Fossil Fuel
Power Plants In the Ohio River Valley 21
Primary Sulfate Emissions from a Lignite and a
Western Bituminous Coal-Fired Utility Source 25
Measurement of Sulfate Emissions at KCP&L
Hawthorne Station, Kansas City, Missouri 27
CCEA — Sulfates Sampling and Analysis on a
Utility FGO Unit 30
Primary Sulfate Emissions from Residual 011-Flred Boilers . . 30
Primary Sulfate Emissions from a Coal- and
Oil-Fired Industrial Boiler with FGO Controls 32
Primary Sulfate Emissions from a Dry Bottom Industrial
Boiler Firing Pulverized Bituminous Coal 34
Primary Sulfate Emissions from Low-Sulfur Residual
011-Flred Commercial and Institutional Boilers 37
Primary Sulfate Emissions from a Bark/Coal-Fired Boiler ... 39
Primary Sulfate Emissions from 011-Flred
Residential Heating Sources 39
Primary Sulfate Emissions at a Scrubber-Equipped
Coal-Fired Boiler 41
References 43
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TABLES
Number Page
1 Primary Sulfate Emission Factors for NAPAP Emissions Inventory . . 5
2 CompjHson of Fuel Characteristics 10
3 Effects of Fuel Oil Characteristics on PSE 11
4 Primary Sulfate Emission Factors Utilized for
Working Group 38 Emissions Estimate 22
5 Primary Sulfate Emission Factors for Bituminous
Coal-Fired Utility Sources 26
6 Primary Sulfate Emission Factors for a Lignite and a
Western Bituminous Coal-Fired Utility Source 28
7 Primary Sulfate Emission Factors for a Nixed Bituminous
Coal-Fired Utility Bailer 29
8 Primary Sulfate Emission Factor for a 31luminous
Coal-Fired Utility Source 31
9 Primary Sulfate Emission Factors for Residual
Oil-Fired Utility Boilers 33
10 Primary Sulfate Emission Factors for a Bituminous Coal or
Residual Oil-Fired Industrial Boiler with FGO 35
11 Primary Sulfate Emission Factor for a Coal-Fired
Dry Bottom Industrial Boiler 36
12 Primary Sulfate Emissions from Residential/Institutional
Boilers Burning Low-Sulfur Residual 011 38
13 Primary Sulfate Emission Factor for a Wood Bark-
and Coal-Fired Boiler 40
14 Primary Sulfate Emission Factors for Distillate 011-Fired
Residential Heating Sources 42
15 Primary Sulfate Emission Factors for a Scrubber-Equipped
Coal-Fired Boiler 43
vi
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LIST OF ABBREVIATIONS AND SYMBOLS
ABBREVIATIONS
Ib — pound (0.45359 Mlogran)
ton — short ton (906.18 kilograms)
gal — U. S. gallon (3.7853 liters)
bbl . — barrel (42 U. S. gallons)
MW — megawatt (1.02 x 10* kilograms-meters/second)
vii
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SECTION 1
PROJECT SUMMARY
INTRODUCTION
The National Add Precipitation Assessment Program (NAPAP) was established
by the United States Congress In 1980 to coordinate and expand research relevant
to the problems posed by acid deposition In and around the United States.
NAPAP 1s organized and Managed through the Interagency Task Force on Add
Precipitation (ITFAP) and ten subordinate task groups coordinating specific
technical areas of research. Task Group B: Man-Hade Sources has the basic
two-fold objectives of:
1. Providing an accurate and complete Inventory of emissions from
man-made sources beloved to be Important 1n acid deposition
processes. The Inventories are to be provided with adequate
geographic, temporal, and sectoral resolution.
2. Providing models which predict how acidic and acld-presursor emissions
may be altered by factors such as economic growth, fuel supply,
emissions regulation, and control techniques. The models are to
have the capability to permit the calculation of alternative control
strategies.
Task Group B has prepared a NAPAP Emissions Inventory Implementation
Plan which 1s designed to address the needs of the NAPAP research programs
being conducted by the other nine task groups within ITFAP. In general, the
emissions Inventory needs of these various task groups can be summarized 1n
two categories:
1. Detailed, multlcomponent point and area source disaggregated Inventory
for defined annual base years to support the development and testing
of atmospheric transport and transformation models to predict add
deposition.
2. Retrospective Inventory summaries of addle and acld-presursor
emissions over the past eighty years to support historical analyses
of materials damage and to aid In developing policy assessments.
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Tht modeling activities presently envisioned by NAPAP Include the
utilization of both Eulerian and Lagranglan Acid Deposition Models. Eulerlan
nodel development Is being directed by the EPA/ORO Environmental Sciences
Research Laboratory which 1s supporting the development of a modeling approach
similar to the Northeast Regional 0x1dent Study (NEROS) Model. Lagranglan
•odeling Involves the use of existing models developed by EPA and others.
Given the general emissions Inventory requirements of each modeling approach
and the needs of those task groups dealing with assessments and historical
analyses, the NAPAP Emissions Inventory Implementation Plan Identified that
the level of temporal, spatial, and sectoral resolution to be contained 1n the
NAPAP Emissions Inventory. The highest level of detail 1n the NAPAP Inventory
must be directed to the requirements of the Eulerlan Model.
Emissions Inventory development 1s geared to provide data for both the
1980 and 1985 base years which have been targeted for modeling studies. The
1980 Inventory contains emissions for S02, NO , VOC, primary sulfate, NH3, CO,
and partlculate matter.
APPROACH
This report summarizes an analysis of existing data on primary sulfate
emissions from a variety of source categories and presents a tabulation of
primary sulfate emission factors appropriate for use with the NAPAP Emissions
Inventory. This analysis also Identified areas where data are either lacking
or Incomplete to permit the assignment of an emission factor. The study does
not address the relative Importance or abundance of primary sulfates 1n the
atmosphere compared to "secondary" sulfate derived from the atmospheric
transformation of sulfur dioxide. These types of assessments require extensive
emissions and air quality measurements which must be evaluated through the use
of complex transport and transformation models.
Prior to the current need for NAPAP Task Group B to Inventory primary
sulfate emissions, two different environmental program activities have Included
assessments of primary sulfate emission factors for use In emission Inventory
development. The EPRI-sponsored sulfate regional experiment (SURE) program
summarized existing experimental measurements data on primary sulfates and
recommended generalized emission factors for a large number of source
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categories. For the most part, many of the factors were based upon an
extrapolation of a United data set for uncontrolled fossil fuel combustion
sources along with data contained In the EPA Emission Factor Guidelines (AP-42)
for sulfurlc acid manufacturing to Inventory the range of source classification
coded point and area sources 1n the mldwestern and northeastern United States
and southeastern Canada. At that time, primary sulfate field measurement
methodology was under development by EPA. Consequently, much of the existing
data In the literature were qualified by the uncertainty of the sampling and
analysis procedures. In fact many of the available field measurement data
were obtained for the purpose of method development with the attendant problem
that few critical supporting measurements were taken to permit the proper
calculation of emission factors.
More recently, the United States/Canada Work Group 3B (WG 3B) prepared an
emissions measurement report 1n accordance with the Memorandum of Intent on
Transboundary A1r Pollution of August 1980. The report Included an estimate
of United States and Canadian primary sulfate emissions using emission factors
obtained from a study of available data conducted by the Ontario Research
Foundation. Those emission factors were abstracted fro* similar open
literature sources used for preparation of the SURE Inventory along with
unpublished emissions data from Canadian measurements. Emission factors were
reported for uncontrolled fossil fuel combustion sources as well as for primary
metal smelters. Measurements data for smelters were acquired from tests in
Canada using a variety of sampling and analysis methods.
Since the preparation of the SURE and WG 3B inventories, several
developments have occurred regarding primary sulfate emission measurements.
The first major development has been the acceptance of a standard sampling and
analysis procedure for sulfate emission assessment. The source emission
measurement technical community now agree that the controlled condensation
sampling (CCS) procedure is the best approach for the determination of H2S04,
and particulate sulfate emissions from stationary sources. Although this
acceptance does not invalidate previous source measurements using methodology
available at the time, the Integration of CCS into field measurement programs
conducted by EPA and other has afforded the opportunity to assess the general
consistency of sulfate emission measurements conducted at various point sources
within given source categories.
3
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As a result of a series ot environmental assessment studies conducted by
the EPA's Industrial and Environmental Research and Environmental Sciences
Research Laboratories, several field programs Included detailed primary sulfate
emission measurements taken at both uncontrolled and S02-controlled utility
and Industrial sources utilizing a variety of fuels. The Importance of sulfate
emission measurements for scrubber-equipped sources became apparent after
researchers discovered that scrubbers removed proportionately less sulfate
than S02 from flue gases.
Therefore, the objective of this report 1s to summarize the current body
of sulfate emissions data. This Investigation consisted of four major
activities Including:
1. a summary discussion of primary sulfate formation mechanisms thought
to be prevalent In combustion processes;
2. assessment of the state-'of-the-art met'iodology for primary sulfate
sampling and analysis of source emissions;
3. review of the SURE and WG 3B primary sulfate emission Inventories;
and
4. collection, review, and calculdtion of primary sulfate emission
factors derived from additional field studies not Included 1n the
SURE and WG 3B Inventories.
RECOMMENDED PRIMARY SULFATE EMISSION FACTORS FOR THE NAPAP INVENTORIES
Primary sulfate emission factors recommended for use In the NAPAP
Emissions Inventories are given 1n Table 1. The factors are reported for a
number of source classification codes (SCCs) based on an analysis of available
data. Most of the current data set 1s for fossil fuel combustion 1n the
Industrial and utility sectors. The emission factors have been calculated to
a normalized Emissions Information System (EIS) format as:
Sulfate emissions per SCC unit = (Emission factor x percent sulfur
content of fuel)
The emission factors given 1n Table 1 reflect sulfate emitted as SO}2
based upon chemical analyses of source test samples. The source descriptions
and fuel sulfur contents for fossil fuel combustion are given in Section 4.
Emission factors for fuel sulfur contents other than those given 1n Section 4
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TABLE 1. PRIMARY SULFATE EMISSION FACTORS FOR NAPAP EMISSIONS INVENTORY
Source category
ilectrlc Utmtle* - Uternal Conbmttor
(astern bltuBtnow coal
Western bltuBtnou* coal
Lignite
•ettduel ell (>tt sulfur contmt)
Industrial - Uternal Coabustlon
fastern bttuBlnous coal
Residual otl
CoMMrcUI/lnstltutlonaV - CaUriMl Co^uttlon
•Mlducl oil <
Industrial trocttt - PrlMry Httalt
rrlatry copper taclurt
NEDS Source
cUstlflcetlon
coot (SCC) Control d»«tc»
1-01-002 IS*
iv tnt tea
1-01-002 1ST
isr and rco
1-01-003 csr
1-01-004 ruol oil «ddltl««
1-02-002 Nulttcloiw*
Nulttclonot and FCO
1-02-004 Nultlclonn
NulttclonM *nd FCO
l-OJ-004 Fuel oil aditUiw
1-05-001-05 Horn
3-Q1-OJ3 OnliUr
3-03fOOS-l
3-03-005-2
J-OJ-OOS-3
3-QJ-OOS-4
•rUMry iulf«U *
••tttton lector
0.385 ID/ton
0 2SOt
-1.290
0 Til .
• l.»l
5 43* lb*/1.000
.. gellom
2.M6 Ibt/ton
0.4*2
S.2W lb*/1.000
gelloi*
2 »16
25 07 Ibt/l.OOOi
0*1 Ion*
».U lbs/1.000
gel Ion*
0.100 Ib/toa
ectd produced
22 S lb*/ton
concentrated ore
1 01
57*
IS 6t
Uncertainty
Reference . range* '
». »
n. M
.26. 37
M
29
M. 31
30
30
30
32
14
• 4
4
4
4
4
*
C
•
C
C
•
• .
. C
0
0
C
C
t
C
C
0
0
(continued)
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TABLE 1. (continued)
Source category
Industrial Process - Prlaery Metals (Cont'd) '
Prlaary tine saelters . -
Priaary aluainua saolter
Iron production
Cote
Industrial Process - Mood Produc tt
Kraft pulp aill
Sulfite pulp Bill - '
Mood/bark waste
Industrial Process - Mineral Products
Ceaent aanufacturing
Cypsua aanufacturing
Industi lal Process - Petreleua Industry
fluid crackers
Sulfur recovery Claws plants
MfOS Source
classification
code (SCO . Control device
3-03-030
3-0«-001
3-03-008
3-03-003
3-07-001
3-07-002
1-02-009 Nultlc tenet
-
3-05-006 and
3-05-007
3-OV01S
3-06-002 ESP
3-01-032
Prlaary sulfate
eaission factor Reference
5$ 5 Ibs/ton
processed
0 &X of SO,
2 OX of SO,
0 320 ID/ton
coal charged
-•
••
3.6 Ibs/ton '
bark
tt
M.
-
15 0 lbs/1.000
barrels ell
2 • Ibs/ton
produced
4
4
4
4
4
4
33
'
4
4
4.
4
Uncertainty
range*
0
0
0
0
C
c
0
0
0
c
. c
* CstiMted ••Isiian factor uncertainty Attunes that 90S of the values for an Individual source II* within Uie e»an
uncertainty ettleutes. Corresponding values are: A > *10»; • » t2SS; C • iSOB; 0 - S7SX, and [ > 100X. -
» [Billion factor based en average sulfete scrubbing efficiency of 3SX. - .
I t«l»»io« factor applicable only U low sulfur content (0.3* i, residual fuel oil
• Total sulfate ea'issions fe" kraft pulp Blllt estiMted us 8SS of NCOS total earticulate enlsslens froB kraft recovery
boilers (see Reference 3t). . - -
•* Tout sulfate ealsslons froB MdluB-tase sulfite Bills estimated at 70» of NEOS SO, eaisslons; for ctlclua-base sulfite Bills
estimated as 2Sk of MCOS SO, eaisslont (tee Reference 3s>).
tt total sulfate Missions I ram ceeent kilns estlBtted as 5.6 Ibs/ton of ceaent on an uncontrolled basis Average partlcuVate
control efficiency froa MfOS'data-assuBed to apply in order to ca'cvlate actual eBlssions (see Reference 3i).
ii Total sulfate froa gypsue plants estlaated as MX as NEDS actual partlculate eaisstons (>ee Reference 36)
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can only be estimated since the dependence of primary sulfate emissions on
fuel sulfur content had not been studied 1n detail. In fact, the limited data
available suggest that sulfate emissions can be markedly affected by other
parameters such as furnace oxygen levels and trace element content of the
fuel. For source categories oJter than fossil fuel combustion, sulfate
emission factors are reported In standard SCC units or as percentages of mass
part1cu1ate emissions.
The calculation of specific primary sulfate emission factors were based
on the following heirarchical Selection process.
1. Where available, all field measurements using the CCS procedure were
considered as the prime data set.
2. Sulfate emission assessments were aggregated for different point
sources within the same source category only If fuel composition and
emission controls were similar.
3. Emissions data acquired through the use of methods other thnn CCS
were Included only If multiple measurements yielded data with minimal
scatter.
Therefore, the primary sulfate emission factors summarized In Table 1 are
representative of the current emissions data base and reflect the WG 3B
emission factors calculated for source categories other than fuel combustion.
There are a number of source categories for which no experimental field
data exist. At present,-the only alternative to an emission factor for the
NAPAP Emission Inventory 1s the assignment of an "assumed11 factor already
contained within the source allocation codes Tor the Regional Model Data
Handling System (RMDHS). However, most of the regional mass emissions of
primary sulfates should occur from those source categories for which emission
factors have already been substantiated (utility and Industrial fossil fuel
burning). The best approach to Improving the NAPAP Emissions Inventory sulfate
component may be an expanded field measurement activity which focuses on those
source categories which have not been sufficiently characterized but are
potentially significant contributors to regional emissions. Improvements are
needed In the data base for low sulfur residual oil-fired Industrial and
commercial boilers. Field measurements using the CCS procedure are
recommended for this source type which 1s a significant source of sulfur
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Missions In Major Metropolitan areas In the eastern United States. In
addition, sulfate emissions from the pulp and paper Industry need further
characterization given the large preliminary emission factors reported by
WG 3B. Pulp Mill operations a:e concentrated In the add deposition sensitive
Northeast and represent a major S0a and particulate source contributor 1n the
southeastern United States.
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SECTION 2
FORMATION OF PRIMARY SULFATES IN COMBUSTION SOURCES
Sulfur present In fossil fuels 1s emitted to the atmosphere mainly as
sulfur dioxide (S0a). However, some of the sulfur Is oxidized further In the
combustion process and Is emitted In a variety of forms, collectively known as
"primary sulfates". These forms Include gaseous sulfur trloxlde (S03) and
sulfurlc acid (H2S04), sulfurlc add mist, and metallic sulfates (MS04, where
M may be metal or ammonium Ions). Secondary sulfates are formed In the
atmosphere by the oxidation of some of the emitted S0a. Some S02 and sulfates,
both primary and secondary, are returned to the earth by wet or dry deposition.
Others remain 1n the atmosphere and may be transported far from the emission
source. These atmospheric sulfates form ambient aerosols - stable mixtures of
gases, liquid droplets, and particles.
The largest source of primary sulfate emissions (PSE) appears to be from
the combustion of coal and oil. The amount of primary sulfates emitted from a
particular combustion source 1s dependent on a great number of factors. Among
these are fuel type and composition, equipment type and design, operating
parameters, and emission controls.
FUEL CHARACTERISTICS
A significantly higher conversion of fuel sulfur to primary sulfates
occurs during oil firing as compared to coal firing. In general, the fraction
of fuel sulfur emitted as primary sulfates has been found to be related to the
metals content of the fuel as well as the amount of excess air used for
combustion. It 1s believed that, among other factors, the relatively higher
vanadium and nickel content of residual fuel oil contributes to the higher
conversion of fuel sulfur to sulfate.
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Several other fuel characteristics have an effect on PSE. Table 2 shows
some of the properties of coal and oil which are Important In assessfng the
potential of the fuel to form primary sulfates when burned.
TABLE 2. COMPARISON OF FUEL CHARACTERISTICS
Coal Fuel oil
Burn rate Relatively slow Relatively fast
Ash content 5 to 15** 0.01 to 0.20%
Principal metals S1, Al, Fe, Ca Mg, Na, V, N1
Minor netals Mg, Na, K Ca, Fe, Al
Sulfur content 0.2 to TV 0.1 to 4%
* Weight percent, dry basis.
Characteristics of Coal
Coal Is a slow-burning fuel, which results In a lower flame temperature
than Is achieved with oil firing. Relatively low flame temperatures lessen
production of S03 formed In the flame zone by the combination of S02 with
atomic oxygen.
The principal metals which typically constitute coal ash are silicon,
aluminum, Iron, and calcium, which are usually present In the oxide form.
Magnesium, sodium, and potassium are usually present, but 1n much smaller
amounts. Certain coal ashes such as those formed from lignite combustion are
basic, so some of the acid formed during coal combustion Is neutralized 1n the
flue gases by the large quantity of ash produced. The high ash content and
slow burning properties of the fuel tend to make coal-fired boilers emit less
of the fuel sulfur as S03 and H2S04 than oil-fired boilers of comparable size.
Although the sulfur content of coal 1s In many cases higher than fuel
oil, some of the sulfur present In coal 1s trapped In bottom ash which 1s not
emitted to the atmosphere. In any case, the sulfate content of bituminous
coal ash emitted to the atmosphere 1s less than 1.5 percent as SOJ.
10
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Properties of Fuel Oil
The low ash, fast burning properties of fuel oil favor formation of
pr1 >ary sulfates during oil firing. In particular, the ability of some of the
principal metals 1n oil ash to catalyze the formation of SOA 1n the combustion
process contributes to Increased sulfate emissions. Table 3 summarizes the
effects on PSE of different fuel oil characteristics.
\
TABLE 3. EFFECTS OF FUEL OIL CHARACTERISTICS ON PSE
Increasing. . . Causes. . .
Percent V In oil Increased S03, H2S04 and MS04 emissions
Other metals In oil Increased MS04 emissions
Percent S In oil Increased S03, H2S04 and MS04 emissions
COMBUSTION PROCESSES
Specifics of the combustion process, such as equipment type and design,
operating parameters, and emission controls, can affect the quantity of PSE.
There are several possible mechanisms by which primary sulfates are believed
to form 1n combustion processes.
Primary Sulfate .Formation Mechanisms
r~!
Sulfates are formed In combustion processes 1n both the flame region and
downstream In the heat transfer section. The proportions of total PSE formed
In each region are not known, and probably vary from process to process.
Primary sulfates are formed by oxidation of S02 to S03, hydratIon of S03 to
H2S04, corrosion of boiler Internals by H2S04, and conversion of metallic
oxides 1n ash to partlculate sulfates.
11
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In combustion flames, the predominant sulfate formation mechanism 1s
reaction of S0a with molecular oxygen to form S03. In the adlabatlc flame
region, peaks of SQ3 can occur which coincide with peaks of 0 atom concen-
tration resulting from Co combustion. However, as combustion reactions reach
equilibrium, SO* concentrations drop to less than 1 ppmv, thus only a small
portion of emitted S0a 1s formed 1n the flame region.
Ai combustion products are cooled by radiative and conductive heat
transfer 1n the post-flame region, 0 atom concentrations exceed 0-02
equilibrium. This causes an Increase 1n S03 concentration above S02-S03
equilibrium levels at the flame temperature. With further cooling, production
of 0 atoms ceases. Oxygen molecules form from 0 atoms, which are rapidly
depleted by this reaction. This depletion prevents formation of more S03, the
concentration of which remains at a superequlHbrlum level above that normally
expected at the flame temperature.
The final S03 concentration depends on 02 concentration, cooling rate,
and the location and rate of mixing of excess air. Only fuel-rich combustion
(zero percent excess 02) can prevent S03 formation by flame processes. For
fuel-lean combustion, S03 concentration Increases nearly linearly with 02
concentration 1n the range zero to 3 percent excess 02. In excess of 3 percent
Oa above stolchlometrlc, only slight Increases 1n S03 concentration are noted.
Decreasing the level of excess 02 In the combustion process has been shown to
decrease sulfate emissions, but this practice Is not feasible for all systems.
The rate of cooling of combustion gases in the temperature range 1,650°C
to 820°C 1s another parameter affecting Sti3 formation 1n the post-flame region.
An Increase 1n S03 concentration occurs when combustion products are rapidly
cooled In the heat transfer section of the boiler. Rapid cooling rates result
In superequlllbrlum 0 atom concentrations and the production of more S03, the
concentration of which Increases with Increasing rates of cooling. Altering
the cooling rate of combustion gases 1n existing equipment would Involve majo'-
modifications. New sources designed for slower cooling rates would probably
be less energy efficient overall than current designs.
Proper staging of excess air addition after fuel-rich combust1on can
minimize S03 formation. This technique has been used to reduce NO emissions
n
from combustion sources. However, staged-a1r mixing to high excess Oa levels
12
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In tht rang* 1,090°C to 1,650°C must bt avoided, since In this range excess 02
causes high 0 atom concentrations and results In higher S03 levels than occur
with normal unstaged combustion. Further modeling and experimental work Is
needed to determine whether staged air addition can be effectively used to
Unit S03 formation.
Tht importance of catalysis In the oxidation of S0a to S03 has been
studied by many Investigators. Many different substances have been shown to
have a catalytic effect on the reaction, and have thus been Implicated as
contributing to Increased PSE. Hedley and Cull1s7 and Mulcahy8 have discussed
the homogeneous catalysis of S0a oxidation by N02, and Levy and Merryman9
demonstrated an Increase 1n S03 when the oxldant In combustion was switched
from Q2-Ar to 02-N2.
Heterogeneous catalytic oxidation of S02 by metals, metal oxides, and
soot suspended In the stream of combustion gases or deposited on boiler
Internal surfaces can occur to substantially Increase PSE. One of the best
catalysts for conversion of S02 to S03 Is V20S. Residual fuel oils from
Venezuela and the Middle East contain significant amounts of vanadium, which
Is liberated as V209 during combustion. Vanadium catalysis has been noted
often 1n the literature.10'1*'1*'13 At high relative humidities,
Fea0314*15'16 and Mn0215'17 are also strong catalysts. The major constituents
of coal fly ash, S102 and A1203, are only weak catalysts. Soot (carbon) has
18
been reported to catalyze S02 oxidation but data are mainly qualitative, and
little Is known of the Importance of particle characteristics or temperature
on the catalytic action.
Sulfurlc add Is formed by reaction of S03 with water vapor 1n combustion
product gases. This H2S04 can adsorb on ash or soot particles, condense on
cooler parts of the combustion equipment, or be emitted to the atmosphere as a
mist. The S03-to-H2S04 conversion Is temperature- and moisture-dependent.
For example, at a flue gas moisture level of eight volume percent, the
following observations can be made: (1) above 370°C essentially all the S03
Is In the vapor ph:se; (2) from 370°C to 20S°C S03 reacts with water vapor to
form H2S04 vapor; and (3) below 205°C, H2SQ4 condensation occurs and the gas
stream consists of an equilibrium mixture of H2S04 liquid aerosol and H2S04
vapor. Because of this Integral relationship between S03 and H2S04, the two
13
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are often referred to collectively as S03/H2S04. As the temperature of the
flue gas decreases, It approaches the add dewpolnt, which Is a function of
S03/HaS04 concentration. When flue gas temperature reaches the acid dewpolnt
(at a given S03/H2S04 concentration), concentrated H2S04 condenses on air
heaters, ductwork, fly ash collectors, and stacks. The resulting corrosion
cycle can pose a serious problem and can exacerbate primary sulfate emissions
as described below.
The formation mechanism for metallic sulfates (NS04) Is subject to some
debate. Some HS04 1s probably formed by conversion of metal oxides In ash to
sulfates by the action of adsorbed H2S04. Additionally, sulfurlc acid
condensed on boiler Internals can react with the Iron (and possibly with other
constituents of metallic alloys such as N1, Cr, Mo) In the system to form
corrosion products. Ferrous sulfate (FeS04-7H20), a corrosion product, can
further react with S02 and oxygen 1n the flue gas to yield highly corrosive
ferric sulfate (Fe2(S04)3). Below pH 3, the latter will attack boiler metal,
producing more ferrous sulfate, and beginning the corrosion cycle again.
Another suggested mechanism, of which little Is known, 1s direct gas-to-
partlcle conversion of S02 and atomic or molecular oxygen to particulate
sulfates.
Process Differences
The amount of PSE from combustion sources can be affected by several
system design parameters, Including fuel type* source type, and equipment
configuration. With few exceptions, oil-fired sources are not equipped with
emission control systems. In the late 1960's, many existing sources converted
to oil from coal to comply with emissions regulations for S02 and partlculates.
The mechanical collectors used for part1cu1ate control at these sources are
Ineffective for removing significant quantities of ash from oil firing, and
thus fall to substantially mitigate PSE. Recently, large p1l-f1red sources
have successfully used MgO-based fuel additives, which decrease PSE from these
systems.
In contrast to oil-fired sources, coal-fired sources often employ both
participate and S02 control. Electrostatic predpltators have been shown
capable of removing In excess of 50 percent of the primary sulfates generated
14
-------
18
fro* coal combustion. Flue gas desulfurination systems not only remove S02
from stack gases, but also trap some of the primary sulfates from coal firing.
Among coal-fired sources, burner type can affect the characteristics of PSE.
For example, pulverized coal firing emits particles which are, on average,
smaller than those emitted from stoker-fired units.
15
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SECTION 3
REVIEW OF PRIMARY SULFATE EMISSION MEASUREMENT METHODOLOGY
The accuracy of primary sulfate emission factors depends on the ability
to accurately measure and characterize sulfate emissions. This discussion
Includes descriptions and evaluations of the various method used to
characterize PSE from combustion sources.
The measurement of primary sulfate emissions In combustion sources has
been conducted on an extractive basis. The two most commonly known methods
for measuring S03/H2S04 are the collection of the acid by absorption and by
selectively condensing the add 1n a temperature-controlled condenser. Both
of these methods, which Involve the extraction of the sample, have critical
parameters which affect the accuracy of the emission measurement. The first
element, whlcn Is common to all such extractive sampling of flue gases. Is the
separation of the part1cu1ate matter from the gaseous portion of the sample
gas. If one Is to speak of acid as a separate species from participate
sulfste, this separation must be achieved prior to the collection and
measurement method. This separation 1s ordinarily attempted by placing some
type of filter on or In the sample entrance end of the probe. The potential
difficulty with the probe filter not only Involves the efficiency with which
the separation can be achieved, but may well Involve the oxidation of S02
either on the filter material Itself or on the participates which accumulate
on the filter surface during sampling. For the acid collection after this
separation, problems have also been proposed both with respect to the oxidation
of S02 In the absorption medium as well as acid mist collection efficiency for
both methods.
Extractive sampling of flue gases for the purpose of measuring S03 and
H2S04 can be summarized by stating that the accuracy of the measurement Is
contingent on how well the separation can be achieved as well as how
efficiently the add can be collected.
16
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ABSORPTION SYSTEMS
A number of Investigators have developed some form of the selective
absorption procedure. In selective absorption, the gas stream enters an 1ce
cooled bubbler containing a solution of 80 percent Isopropyl alcohol (IPA),
which absorbs the H2S04 and passes most of the S02. The S02 Is absorbed
downstream 1n H202 bubblers and oxidized to sulfate. There 1s evidence that
IPA prevents the oxidation of S02, so that tneoretlcally absorbed S02 can be
purged later from the IPA bubbler using S02-free air (normally ambient air).
This procedure Is the basis for the standard EPA Method 6.
Several Investigators, recognizing the need to collect both metallic
sulfates (NS04) and H2S04, have extended the M6 system by the addition of a
glass wool plug In the probe. This modified Method 6 (MM6) procedure 1s
capable of partially separating MS04 from the gaseous H2S04 (Including S03),
and has been used extensively to measure PSE. However, a laboratory study has
shown that the alkaline nature of the glass plug actually favors capture of a
major portion of the sulfurlc acid In the emission stream. This results 1n an
Incomplete separation of H2S04 and MS04.
The operation of the MM6 train 1s similar to EPA Method 6. At the end of
the test, the probe 1s removed from the stack and any S02 dissolved 1n the IPA
Implnger Is purged with clean ambient air. The probe plug and probe are
either washed with H20 or rinsed directly with 80 percent IPA and titrated.
The IPA bubbler, plug, and H202 Implngers are treated In the same fashion as
the EPA M6 procedure.19
The primary purpose In the design and operation of the MM6 train was to
efficiently trap sulfates (sulfurlc acid and metallic sulfates) and S02. Data
reported from this train 1s typically divided In water soluble sulfate (H2S04,
MS04) and S02. Other selective absorption methods Include the standard EPA
Method 820 and the Shell-Emeryville method.2
CONDENSATION SYSTEMS
Development of the controlled condensation system (CCS) 1s generally
22
attributed to the work of Goksoyr and Ross. In the controlled condensation
approach, H2S04 Is separated from the gas stream by cooling the flue gas in a
17
-------
coll below the dew paint for H2S04 but above the dew point of H20. The
resulting H2S04 aerosol Is either collected on the walls of the cooling coll
or on a back-up frit. The H20 and S02 passes from the controlled condensation
coll (CCC) to an 1mp1nger system where the S02 1s trapped and oxidized 1n
Implngers containing dilute H202. Laboratory studies have found the precision
and accuracy of controlled condensation to be ±6 percent In synthetic gas
streams. Recognizing the need to Improve the participate removal capability
of the controlled condensation approach, an Improved filtration system was
99 9*1 9A
designed, and extensive field testing "»"«^» was conducted to determine the
effect of operating parameters. The use of the controlled condensation system
1s considered to be the best state-of-the-art approach for conducting primary
sulfate emission measurements at fossil fuel combustion sources.
18
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SECTION 4
REVIEW OF AVAILABLE PRIMARY SULFATE EMISSION FACTOR DATA BASES
A United number of previous emissions Inventory development programs
have considered Inclusion of primary sulfates as a non-criteria pollutant to
be Inventoried. Two separate activities which were Identified are:
1, Emissions Inventory for the SURE Region; and
2. Work Group 3B Emissions Inventory.
In this section, the sulfate components of each Inventory are reviewed for
applicability of emission factors to the NAPAP Emission Inventory.
Several recent test reports were Identified which either describe
t
specific primary sulfate emission assessments or Included a limited number of
primary sulfate measurements as part of a comprehensive environmental emissions
assessment study. Each test report has been reviewed and 1s summarized. A
primary sulfate emission factor has been calculated and 'listed for each
source/fuel/em1ss1ons control element discussed 1n the test reports. Although
each emission factor presented Is based on multiple measurements at each
source, the data sets still require more Intensive study to assess the
uncertainties of the source-categorized factors.
PRIMARY SULFATE EMISSION FACTORS FROM THE SURE EMISSIONS INVENTORY3
The Electric Power Research Institute sponsored an extensive study which
was aimed at defining the mechanisms that link emissions td ambient concen-
trations of sulfur dioxide and sulfates and at the development of an air
quality model that could relate emissions to ambient concentrations. The
monitoring and modeling study (the Sulfate Regional Experiment - SURE) Involved
the development of a detailed emissions Inventory for all man-made stationary
sources of emissions and surface transportation emissions focused on the
eastern United States and parts of southern Canada.
19
-------
Included 1n the inventory are emission estimates for S02 and primary
sulfates. Major problems were encountered In acquiring valid and reasonably
accurate data for sulfate because of the limited amount of available test
data. Those data which were available for major sulfate source emissions such
as fossil fuel combustion were acquired by a variety of sampling and analysis
methods which had not been validated. Based on available data, the following
emission rates were applied to sulfur emissions from boilers.
• Coal-fired boilers. SO equivalent to 95"percent of fuel sulfur,
S04 equivalent to 1.0 percent of SO , and SC2 equivalent to
99.C percent of SOX. *
• Oil-fired boilers. SO equivalent to 94 percent of fuel sulfur, S04
equivalent to 6.0 percent of SO emissions, and S02 equivalent to
94.0 percent of SOX- *
Sulfate emissions from sulfuHc acid plants were estimated at 20 percent
of the SO emissions based on EPA estimates contained In AP-42. For mobile
source gasoline combustion the limited data available on sulfate emissions
from catalyst-equipped vehicles reported levels which are Insignificant. The
sulfate emissions from overall gasoline combustion was estimated to be about
4 percent of the SOX.
Sulfate emissions data for other sources were unavailable. Therefore,
the following general assumptions were made.
• For those source categories using fossil fuel combustion for process
heat or steam, the sulfate emission factors for boilers were used.
f Sulfate emission estimates for sulfuMc acid production were used
for those source categories which used sulfuric acid in various
product manufacturing schemes according to the consumption of
sulfuHc add in the process.
• For those source categories which could not be Included in the two
previous general classifications discussed above, it was arbitrarily
assumed that S04 emissions were equivalent to 0.5 percent of the SO
emissions.
Primary sulfate allocation factors were then assigned to the entire array
of NEDS Source Classification Codes (SCC), as appropriate. As a result of the
extensive extrapolation of a limited number of source measurement data sets to
a wide rtinge of SCCs, there is some question regarding the uncertainties of
sulfate emission estimates for a specific SCC.
20
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PRIMARY SULFATE EMISSION FACTORS UTILIZED BY WORKING GROUP 3B4
An missions measurement report was prepared by the U.S./Canada Work
Group 38 on emissions, costs and engineering assessment 1n accordance with the
Memorandum of Intent on Transboundary A1r Pollution concluded between Canada
and tht United States on August 5, 1980. As part of this activity, preliminary
estimates of primary sulfate emissions for tht U.S. were developed for the
calendar year 1930. The work group concluded that the draft report
Anthropogenic Sources and Emissions of Primary Sulfates In Canada, prepared
for Environment Canada by the Ontario Research Foundation, contained the most
complete collection of Information on primary sulfate emission factors. The
emission factors contained In this report were based upon Information obtained
from Canadian sources, open technical literature, EPA reports, and EPA data
bases. Many of the references cited for the emission factor development were
Identical with those used for the preparation of the EPRI-sponsored Emissions
Inventory for the SURE Region. Table 4 summarizes the emission factors used
to prepare the WG 3B primary sulfate emissions estimates. For consistency and
IntercompaHson with similar data, the factors have been recalculated and
expressed In units appropriate for NAPAP Inventory development.
EMISSION CHARACTERIZATION OF MAJOR FOSSIL FUEL POWER PLANTS IN THE OHIO RIVER
VALLEY25
The purpose of the study was to characterize the atmospheric emissions
from five major coal-fired power plant units 1n the Ohio River Valley between
Portsmouth, Ohio, and Louisville, Kentucky. This characterization provided
data that are representative of the boiler fuel emission control combinations
of the current power plant population scheduled to go on line before the end
of 1983. The selection criteria for the units to undergo testing Included the
following:
• size of unit;
• age and condition of unit;
• furnace type and burner arrangement;
• load pattern;
21
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TABLE 4. PRIMARY SULFATE EMISSION FACTORS UTILIZED FOR WG 38 EMISSIONS ESTIMATES
Source category
NEDS source
classification codes
(SCO
Normalized primary sulfate
emission factors
IS}
Electric Utilities
Coal (1.7-2.64% S content)
Residual oil (1.75-2.25X S content)
Distillate oil (0.3X S content)
Non-Utility Coal (2.2X S content)
Industrial Oil (0.3X S content)
Commercial 011 (0.3X S content)
Residential 011 (0.3% S content)
Primary Copper Smelters
Primary Zinc Smelters
1-01-001 through 1-01-003
1-01-004
1-01-005
1-02-001 through 1-02-002
1-02-003
1-03-001 through 1-03-002
1-03-003
1-02-005
1-03-005
1-05-002
3-03-005-1
3-03-005-2
3-03-005-3
3-03-005-4
3-03-030
0.456 Ibs/ton
9.143 lbs/1,000 gallons
11.808 lbs/1.000 gallons
0.608 Ibs/ton
0.480 Ibs/ton
0.608 Ibs/ton
0.480 Ibs/ton
11.808 lbs/1.000 gallons
12.960 lbs/1,000 gallons
15.552 lbs/1,000 gallons
22.500 Ibs/ton concentrated ore
1.080 Ibs/ton concentrated ore
5.760 Ibs/ton concentrated ore
15.660 Ibs/ton concentrated ore
55.500 Ibs/ton processed
(continued)
-------
TABLE 4. (continued)
Source category
NEOS source
classification codes
(SCO
Nomailzed primary sulfate
emission factors
ro
OJ
Primary Aluminum Smelters
Iron/Steel Sintering
Coke
Sulfurlc Acid
Kraft Pulp Mill
Sulfite Pulp Nils
Cement Plants
Gypsum Plants
Sulfur Recovery Claus Plants
Catalytic Cracking Units
3-04-001
3-03-008
3-03-003
3-01-023
3-07-001
3-0/-002
3-05-006 through 3-05-007
3-05-015
3-01-032
3-06-002
0.5% of S0a
2% of S0a
0.328 Ibs/ton coal charged
0.100 Ibs/ton acid produced
*
t
§
*
2.8 Ibs/ton produced
15.0 lbs/1,000 barrels fuel
* Total sulfate emissions for kraft pulp mills estimated as 85 percent of NEDS total partlculate
emissions from kraft recovery boilers.
t Total sulfate emissions from sodium-base sulflte mills estimated as 70 percent of NEOS S0a
emissions; for calcium-base sulflte mills estimated as 25 percent of NEDS S02 emissions.
§ Total sulfate emissions from cement kilns estimated as 5.6 Ib/ton of cement on an uncontrolled
basis. Average partlculate control efficiency from NEOS data assumed to apply In order to
calculate actual emissions.
f Total sulfate from gypsum plants estimated as 56 percent of NEDS actual partlculate emissions.
-------
• emission control system;
• operating status (e.g., retirement, emergency only); and
• fuel characteristics.
The units selected for testing were grouped according to the following age
categories:
Group 1: 25 years Or older;
Group II: 10 to 25 years old; and
Group III: less than 10 years old.
The relative size of the units In these age categories was similar. Group I
ranged from 69 to 215 MW (113 MW average); Group II from 150 to 225 MW (192 MW
average); and Group III from 227 to 610 MW (469 MW average). For the purposes
of the test program, one unit was selected from Group I and two units each
were selected from Groups II and III. One unit from Group II and one from
Group III are equipped with control devices for controlling partlculate
emissions only. The other two units 1n Groups II and III are equipped with
full partlculate and S02 control devices.
The unit tested from Plant A has a rated nameplate generating capacity of
560 MW and was placed Into service In 1970. This Babcock and Wllcox unit has
an opposed-fired burner configuration and 1s equipped with a Buell weighted
wire electrostatic predpltator to control partlculate emissions.
The unit for Plant fl which was selected from Group I has a rated nameplate
generating capacity of 125 MW and was placed Into service In 1954. This
Babcock and Wllcox unit has a front-fired burner configuration and Is equipped
with a retrofit Research Cottrell CSP Installed In 1973 to control partlculate
emissions.
The Plant C unit, which was selected from Group II, has a rated nameplate
generating capacity of 163 MW and was placed Into service In 1958. This
Combustion Engineering unit has a tangential-fired burner configuration. The
partlculate emission control system consists of two ESP's In series. The
newer retrofit Research Cottrell ESP was Installed 1n 1975.
24
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A unit was selected at Plant D to represent Group III. The unit tested
has a rated nameplate generating capacity of 411 MW and was placed Into service
In .1978. This Sabcock and W11cox unit has an opposed-fired burner
configuration. The air pollution control equipment consists of an American
Air Filter (AAF) rigid frame ESP that was Installed In 1978. After passing
through the ESP, the flue gas enters a carbide Hme mobile bed flue gas
d«sulfur1zat1on (F6D) system which was also Installed 1n 1978 by AAF.
The unit at Plant E from Group II has a rated nameplate generating
capacity of 156 MW and was placed Into service In 1962. This Combustion
Engineering unit has a horizontal-fired burner configuration. The air
pollution control equipment consists of a Research Cottrell weighted wire ESP
Installed In 1962. After passing through the ESP, the flue gas enters an AAF
11* slurry FGD system which was Installed In 1976.
During onslte testing, the units were operated 1n a normal manner with
the loads changing according to demand. Tests were conducted over a 5-day
sampling period In an effort to obtain emission data under a number of
operating conditions. The Controlled Condensation System (CCS) was utilized
to simultaneously collect and differentiate particulate sulfate, H2S04, and S02.
Two CCS samples were collected each day over the five day testing period.
Table 5 summarizes the primary sulfate emission factors calculated from the
source measurements taken at each unit.
PRIMARY SULFATE EMISSIONS FROM A LIGNITE AND A WESTERN BITUMINOUS COAL-FIRED | i
UTILITY SOURCE26
The purpose of the study was to provide background data on the sulfur
dioxide and primary sulfate emissions from power plants burning North Dakota
lignite, and Western coal. The two plants tested were the Lei and Olds Steam
Plant of the Basin Electric Company, Stanton, North Dakota, and the Sherburne
County (Sherco) generating plant of North States Power Company, Becker,
Minnesota.
The unit tested at the Leiand Olds Station 1s sized at 440 MW and went
Into commercial operation In December 1975. The unit 1s a Babcock and Wllcox
cyclone-fired boiler with a rated steam capacity of 3,000,000 Ib/hour. A Joy
Manufacturing Company electrostatic predpltator provides a design partlculate
25
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TABLE 5. PRIMARY SULFATE EMISSION FACTORS FOR
BITUMINOUS COAL-FIRED UTILITY SOURCES
Group
I
II
III
Plant
B
C
E
E
A
0
Size
(MW)
125
163
156
156
560
411
Fuel sulfur Normalized primary
content Emissions sulfate emission
(weight X) controls factor (Ibs/ton)
j
0.9
0.9
3.3
3.3
1.0
3.5
ESP
ESP
ESP
ESP and FGD*
ESP
ESP and FGO
0.293
0.296
0.381
0.269
0.162
0.279
* FGD sulfate removal efficiency = 29.4 percent.
26
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removal efficiency of 99.5 percent. During the tests, the unit was burning a
North Dakota lignite with a dry heating value of 10,515 Btu/lb containing
1.38 weight percent sulfur. Primary sulfate emissions were determined using
EPA Modified Method 6.
The unit tested at the Sherco plant was sized at 700 MW and employed a
Combustion Engineering controlled circulation, single-reheat, balanced draft
steam generator. The emission control utilizes a Combustion Engineering
scrubber system which Is a tall-end limestone, negative pressure, two-stage
wet scrubber. A rod venturl Is used as the first stage for particulate removal
and a marble bed as the second stage for sulfur dioxide removal. The complete
scrubber consists of 12 modules, 11 of which are required for full load
operation. When tested, the unit was burning a Western bituminous coal with a
dry heating value of 11,649 Btu/lb containing 1.10 percent sulfur. Samples
were collected at both the Inlet and outlet of a representative scrubber
module. Primary sulfate emission measurements were made using EPA Modified
Method 6.
Table 6 summarizes the primary sulfate emission factors calculated for
both units tested during the program. The scrubber Inlet sulfate emissions
measured at Sherco were taken prior to any particulate removal.
MEASUREMENT OF SULFATE EMISSIONS AT KCP&L HAWTHORNE STATION, KANSAS CITY,
MISSOURI27
The objectives of the testing Included obtaining measurements data on
total water-soluble sulfates emitted from a power plant burning a mixture of
Chelrea (Oklahoma) and Wyoming coals. The unit tested was built 1n 1969 by
Combustion Engineering as a corner-fired boiler. It has six coal feeders and
the entire boiler system 1s under positive pressure. The boiler 1s rated for
468 MW and uses two Buell Engineering electrostatic predpltators 1n series
with a design load of 400 MW. During operation, two of the coal feeders use a
high-sulfur Oklahoma coal with the remaining four fed with low-sulfur Wyoming
coal. Total sulfate emission samples were collected at the breaching of the
stack after the predpltators using EPA Modified Method 6. Table 7 summarizes
the calculated primary sulfate emission factor derived from the source
27
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TABLE 6. PRIMARY SULFATE EMISSION FACTORS FOR A LIGNITE AND
A WESTERN BITUMINOUS COAL-FIRED UTILITY SOURCE
Unit size
440 MW
700 MW
700 MW
Fuel
sulfur content
1.38 weight X
(Lignite)
1.10 weight X
(Western Bituminous)
1.10 weight X
(Western Bituminous)
Emissions
controls
ESP
(None)
FGD*
Normalized primary
sulfate emission
factor (Ibs/ton)
1.951
1.627
0.761
* FGO sulfate removal efficiency = 53 percent.
28
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TABLE 7. PRIMARY SULFATE EMISSION FACTORS FCR A
MIXED BITUMINOUS COAL-FIRED UTILITY BOILER
Normalized primary
Fuel Emissions sulfate emission
Unit size sulfur content controls factor (Ibs/ton)
468 MM 1.67 weight X* ESP 1.290
* Based on "as-fired" mixture of 1.37 percent Wyoming coal and
2.19 percent Oklahoma coal.
29
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measurements. The normalized emission factor represents sulfate emissions for
the particular ratio of high and low sulfur coals that were being used during
the testing.
CCEA — SULFATES SAMPLING AND ANALYSIS ON A UTILITY FGO UNIT28
The cbntrolled-condensatlon system was used to collect reactive sulfur
species at the, Inlet and cutlet of the FGO unit on Columbus and Southern Ohio
Electric's Conesvllle Power Station. The Conesvllle Power Station 1s a
2,055 MW six-unit, coal-fired facility located on the Musklngum River near
Coshocton, Ohio. Tests were conducted on Unit 5 which Is equipped with an FGO
system. The unit Is a coal-fired, dry bottom Combustion Engineering steam
generator rated at 411 MW. The fuel 1s a blend of high-sulfur Ohio coals
containing approximately 4.7 percent sulfur and 15 percent ash. The air
pollution control system consists of a cold-side electrostatic predpltator by
Research-Cottrel1 and a Universal 011 Products/Air Correction Division sulfur
dioxide scrubber. The predpltator Is designed for 99.65 percent partlculate
removal. The turbulent contact S02 absorber module Is designed for an S02
removal efficiency of 89.6 percent.
Gas samples were taken at the Inlet and outlet of the FGO module using
the controlled-condensatlon sampling and analysis method. Table 8 summarizes
the calculated primary sulfate emission factors for the source with and without
FGO controls.
PRIMARY SULFATE EMISSIONS FROM RESIDUAL OIL-FIRED BOILERS29
A specific point source of sulfate emissions was chosen In the
Northeastern United States to assess the Impact of sulfate emissions on air
quality. A comprehensive partlculate and sulfur emission characterization was
performed at the Albany Steam Station, owned and operated by the Niagara
Mohawk Power Corporation In Glenmont, New York.
Each of four boilers at the plant Is a Combustion Engineering unit wth
tangential combustion, rated at 675,000 Ibs steam/hour and 100 MW net power
output. During the period of study, the plant was firing residual fuel oil of
Venezuelan origin with an approximate heating value of 18,600 Btu/lb. The
30
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TABLE 8. PRIMARY SULFATE EMISSION FACTOR FOR A
BITUMINOUS COAL-FIREO UTILITY SOURCE
Unit size
411 MM
Fuel
sulfur content
4.7 weight X
Emissions
controls
ESP
ESP and FGD*
Normalized primary
sulfate emission
factor (Ibs/ton)
0.793
0.480
* FGD sulfate removal efficiency = 39.5%.
31
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average sulfur content was 1.9 percent with vanadium and ash concentrations of
200~~ppm snd 0.12 percent , respectively. A fuel additive, consisting of
magnesium and magnesium oxide in a petroleum liquid, was added to the oil just
prior to combustion to inhibit corrosion caused by sulfuric acid. The additive
was injected into the fuel oil feed lines at a nominal ratio of 2,500:1 (oil,
additive by volumetric measure).
The boilers were operated at an average of 80 percent maximum generation
capacity during the measurement period. Each boiler exhaust is vented to an
individual stack Three of the four boiler exhaust stacks were sampled for
primary sulfate emissions using the controlled condensation sampling and
analysis method. The calculated primary sulfate emission factors for each of
the units is summarized in Table 9.
PRIMARY SULFATE EMISSIONS FROM A COAL AND OIL-FIRED INDUSTRIAL BOILER WITH FGO
CONTROLS30 s^
" . » ,
The study was designed to provide a comparative multimedia assessment of
coal-firing and oil-firing In an industrial boiler. The boiler 1s an Integral
furnace, once-through, Babcock and Wllcox unit which was installed in 1958.
In 1967, the unit was converted to f1>>3 either coal or oil with a 10 MW
equivalent generating capacity.
The flue gases are treated by en air pollution system which consists of
multlcone units and a pilot FGO unit- The multiclones are the primary
participate control device. All of the flue gas passes through the multiclones
after which the steam is split and two*thirds of the flue gas is ducted to the
stack. The other one-third is ducted to the pilot FGD system which removes
S02 and additional particulate matter.
The flue gas desulfurizatlon (FGO) system was designed and manufactured
by FMC Corporation. The process utilizes a sodium sulflte-sodlunf bisulfite
solution as the absorbent.
A high volatile bituminous feed coal was utilized for all coal-fired
tests. The coal contained 1.64 weight percent sulfur with a heating value of
12,683 Btu/pound. Simultaneous primary sulfate emission measurements were
made simultaneously at the inlet and outlet of the FGO unit using the
controlled condensation sampling and analysis method.
32
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TABLE 9. PRIMARY SULFATE EMISSION FACTORS FOR
RESIDUAL OIL-FIRED UTILITY BORERS
Unit
S1zt
Fuel sulfur
content
(weight %)
Emissions
controls
Normalized
primary sulfate
emission factor
(lbs/1,000 gallons)
1
2
4
100
loo
100
1.88 Magnesium fuel
oil additive
1.72 Magnesium fuel
oil additive
1.45 Magnesium fuel
oil additive
5.089
5.589
5.640
33
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Oil-fired tests were conducted with the unit fired with a No. 6 residual
fuel oil containing 1.96 weight percent sulfur and a heating value of
approximately 16,600 Btu/pound. The fuel vanadium content was approximately
36.5 ppm. During the tests, the furnace exit oxygen content averaged about
3.5 percent. Primary sulfate emission measurements were conducted
simultaneously at the inlet and outlet of the FGO using the controlled
condensation sampling and analysis method.
Table 10 summarizes the calculated primary sulfate emission factors for
the unit burning either coal or oil. Emission factors have been calculated
for the unit operating with or without the FGO system by assuming that the FGO
inlet concentrations approximate the atmospheric emissions from the boiler In
the absence of sulfur dioxide controls.
PRIMARY SULFATE EMISSIONS FROM A DRY BOTTOM INDUSTRIAL BOILER FIRING PULVERIZED
BITUMINOUS COAL31
The study Includes an assessment of the potential Impact of air emissions,
wastewater effluents, and solid wastes resulting from the operation of dry
bottom industrial boilers firing pulverized bituminous coal. Consuming
approximately '3 million metric tons of such coal per year, this source
category constitutes the primary method of firing coal in industrial boilers.
The boiler chosen for sampling and analysis was a horizontally-fired, dry
bottom unit burning pulverized Appalachian bituminous coal to produce steam
for process and space heating at an industrial site. The boiler has a rated
firing capacity of 123 MBtu/hour and an output capacity of 100,000 Ibs
steam/hour. The air emissions from the unit are controlled by a tiigh
efficiency electrostatic precipitator. The coal burned has an as received
heating value of 28.78 MJ/kg and a sulfur content of 0.91 percent.
Air emission samples were collected at the outlet duct of the ESP using a
modified EPA Method 8 procedure. Table 11 summarizes the calculated primary
sulfate emission factor for the unit.
34
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TABU 10. PRIMARY SULFATE EMISSION FACTORS FOR A BITUMINOUS COAL
OR RESIDUAL OIL-FIRED INDUSTRIAL BOILER WITH FGD
Fuel type
Fuel
sulfur content
Emissions
controls
NonMllzcd primary
sulfate Mission
factor
BUunlnous
coal
Residual
oil
1.64 weight X
1.64 weight X
1.96 weight X
1.96 weight X
Multlclone
Multlclone
and FGD
Multlclone
Multlclone
and FGD
2.646 Ibs/ton
0.462 Ibs/ton
5.296 lbs/1,000
gallons
2.616 lbs/1,000
gallons
35
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TABLE 11. PRIMARY SULFATE EMISSION FACTOR FOR A
COAL-FIRED DRY BOTTOM INDUSTRIAL BOILER
Fuel type
Fuel
sulfur content
Emissions
controls
Normalized primary
sulfate emission
factor (Ibs/ton)
Appalachian
coal
0.91 weight %
ESP
0.199
36
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PRIMARY SULFATE EMISSIONS FROM LOW-SULFUR RESIDUAL OIL-FIRED COMMERCIAL AND
INSTITUTIONAL BOILERS32
The study Involved the measurement of primary sulfate emissions from
four non-Industrial packaged boilers located In the New York, NY metropolitan
area. All units tested were burning a 0.3 percent sulfur hydrodesulfurlzed
residual fuel oil.
Boiler No. 1 was at the Starrett City residential apartment complex 1n
Brooklyn, New York which generates fts electricity, heating, and cooling
requirements by a central power complex. The power station centers around
four boilers, each rated at 110,000 Ibs/hour steam, at a firing rate of
7,850 Ibs/hour of fuel oil. The design primary fuel Is natural gas, but due
to economic and availability considerations, the units have been operated on
No. 6 fuel otT. Testing was done on the No. 4 boiler, a Combustion Engineering
Type 28-VP-12W constructed 1n 1971, rated at 110,000 Ibs/hour steam. During
the tests, a No. 6 residual fuel oil with a rated sulfur content of less than
0.3 percent was used as the sole fuel source.
Boiler No. 2 was located at Long Island University In Brooklyn, New York.
Steam requirements for the university building complex are supplied by
three Compak Water Tube Generators, Model FPL-21-600, manufactured by the
International Boiler Works Company. Each unit 1s rated at 24,000 Ibs/hour
steam. Emission tests were run on the outlet of the No. 3 boiler. The fuel
used was a No. 4 low-sulfur oil. During all test periods, the boiler was on
lead status and was to run continuously at uniform load conditions.
Testing was conducted at Boiler 3 which IS located at the Columbia
Presbyterian Hospital in New York, NY. Five boilers supply the steam needs,
two Combustion Engineering and one Babcock and Wilcox units rated at
120,000 Ibs/hour steam, and two Babcock and Wilcox units rated at
45,000 Ibs/hour steam. The units are fired with a No. 6, low sulfur oil with
Gilbert Fire-Side Additive continuously Injected to the oil. All emission
tests were run on the No. 3 Babcock and Wilcox boiler, rated at 120,000 Ibs/
hour steam at 250 psig built in 1975.
Boiler No. 4 (a confidential source 1n New York, NY) 1s rated at
125,000 Ibs/hour steam at 300 psig. The fuel burned during all tests was a
No. 6 low-sulfur residual oil.
37
-------
TABLE 12. PRIMARY SULFATE EMISSIONS FROM RESIDENTIAL/INSTITUTIONAL
BOILERS BURNING LOW-SULFUR RESIDUAL OIL
Unit
Size
(Ib/hr
steam)
Fuel sulfur
content
(weight X)
Emissions
controls
Normalized
primary sulfate
emission factor
(Ibs/1,000 gallons)
1
2
3
4
110,000
24,000
120,000
125,000
0.3
0.3
0.3
0.3
None
None
Fuel oil additive
None
21.55
19.20
35.47
24.07
38
-------
All primary sulfate emission measurements were made using the modified
EPA Method 6 sampling and analysis procedure. Table 12 summarizes the
calculated primary sulfate emission factors for the four boilers tested during
the study.
PRIMARY SULFATE EMISSIONS FROM A BARK/COAL-FIRED BOILER33
A three week monitoring study was carried out to assess the Impact of
stationary source emissions from a typical pulp and paper mill on local ambient
air quality. Primary sulfate emission measurements were taken at a coal/wood
bark-fired boiler at the mill.
The unit Is a Rlley bark boiler which Is a combination stoker coal- and
bark-fired boiler which 1s used for supplemental power generation. Typical
steam production Is about 80 tons/hour which 1s achieved by burning a steady
stream of bark from the chipping operation. Coal 1s fed by a chute as a
supplemental fuel In order to maintain load. The unit 1s equipped with primary
and secondary Corn multlclone mechanical collectors and a venturl scrubber.
During the measurements, the unit was fired with about 29 tons/hour of
bark with an average sulfur content of 0.1 percent along with about 1 ton/hour
of coal. A series of seven primary sulfate emission measurements were made
using the controlled condensation sampling and analysis method. Table 13
summarizes the normalized primary sulfate emission factor for the unit.
PRIMARY SULFATE EMISSIONS FROM OIL-FIRED RESIDENTIAL HEATING SOURCES34
During the study, emissions from gas- and oil-fired residential heating
sources were assessed through a critical examination of existing emissions
data, followed by the conduct of a phased measurement program to fill gaps In
the emissions data base. Partlculate sulfate, S02, and S03 omission data were
obtained at two of the oil-fired sites. The cho1-». of the specific sites In
the program was based on the representativeness of the sites as measured
against Important characteristics of systems within each source category such
as:
e burner type and age;
e firing rate; and
e duty cycle.
39
-------
TABLE 13. PRIMARY SULFATE EMISSION FACTOR FOR A
WOOD BARK- AND COAL-FIRED BOILER
Normalized primary
Mixed-fuel Combustion fuel Emissions sulfate emission
type sulfur content controls factor
Wood bark 0.1 weight X Dual multlclone 3.6 Ibs/ton
(96%) and venturl
Coal (4X)
40
-------
On« of the oil-fired residential combustion units tested as an Arcollner
No. W.O. 351, Series 3AS3 unit with a conventional high pressure burner using
a forced air heating medium with a rated capacity of 141,000 Btu/hour. The
unit tested was 16 years old.
The second unit tested was an Armstrong, Model L61-95 A527 device with a
conventional high pressure burner. The unit, approximately six years old, was
rated at 120,000 Btu/hour and employed a forced air heating medium.
Both units were burning a distillate fuel oil containing approximately
0.25 percent sulfur. The controlled condensation sampling and analysis method
was used to collect two samples from the emissions of each unit. Table 14
summarizes the calculated primary sulfate emission factors based on the
emission iwasurements.
PRIMARY SULFATE EMISSIONS AT A SCRUBBER-EQUIPPED COAL-FIRED BOILER35
The controlled condensation sampling and analysis method was used to
evaluate the performance of two prototype sulfurlc acid monitors at a
coal-fired boiler employing FGD. The testing was done at the Widows Creek
Steam Plant Unit No. 8 operated by the Tennessee Valley Authority at
Bridgeport, Alabama. The unit Is a 300 MW balanced draft, tangentially-flred
coal boiler burning a 4.3 percent sulfur coal. TVA retrofitted this unit with
a limestone FGD system with a designed S02 removal efficiency of 80 percent.
The emission control system consists of an electrostatic preclpUator followed
by four variable-throat ventuH scrubber/multl-grld tower absorber trains
containing oie packed tower.
SamnHng was conducted at the outlet of Module A. Table 15 contains ir->
normalized primary sulfate emission factor calculated from the measurements
data.
41
-------
TABLE 14. PRIMARY SULFATE EMISSION FACTORS FOR
DISTILLATE OIL-FIRED RESIDENTIAL HEATING SOURCES
Unit
Heating
rate
(Btu/hr)
Age
Fuel sulfur
content
(weight X)
Normalized
primary sulfate
emissions factor
(lbs/1,000 gallons)
Arcollner Series 141,000 16 years 0.25
No. W.O. 351, 3AS3
Armstrong
L61-95 A527
120,000 6 years
0.25
7.09
4.21
42
-------
TABLE 15. PRIMARY SULFATE EMISSION FACTORS FOR A
SCRUBBER EQUIPPED COAL-FIRED BOILER
Nomal 1 zed
Unit •"*• primary sulfate
slzt Fuel sulfur content •*fn1ss1ons controls emissions factor
300 MW 4.3 wt. % butunlnous
FGD
0.005 Ibs/ton
43
-------
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47
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