EPA-450/3-89-12
OVERVIEW OF THE REGULATORY BASELINE,
TECHNICAL BASIS, AND ALTERNATIVE CONTROL
LEVELS FOR SULFUR DIOXIDE (SO2) EMISSION
STANDARDS FOR SMALL STEAM GENERATING UNITS
Emission Standards Division
U.S. Environmental Protection Agency
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, N.C. 27711
May 1989
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This report has been reviewed by the Emission Standards Division of the
Office of Air Quality Planning and Standards, EPA, and approved for
publication. Mention of trade names or commercial products is not intended
to constitute endorsement or recommendation of use. Copies of the report
are available through the Library Service Office (MD-35), U.S. Environmental
Protection Agency, Research Triangle Park, N.C. 27711, or from National
Technical Information Services, 5285 Port Royal Road, Springfield,
Virginia 22161.
ii
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TABLE OF CONTENTS
Section Page
1.0 INTRODUCTION 1
2.0 SUMMARY . 2
3.0 OIL S02 EMISSIONS AND CONTROL TECHNIQUES 4
3.1 REGULATORY BASELINE EMISSION LEVELS 4
3.2 MEDIUM, LOW, AND VERY LOW SULFUR OIL 4
3.3 SODIUM SCRUBBING FGO SYSTEMS 7
3.4 DUAL ALKALI FGD SYSTEMS 12
3.5 LIME/LIMESTONE FGO SYSTEMS 14
3.5 ALTERNATIVE CONTROL LEVELS 14
4.0 COAL S02 EMISSIONS AND CONTROL TECHNIQUES 15
4.1 REGULATORY BASELINE EMISSION LEVELS . . . 15
4.2 LOW SULFUR COAL :.......... 15
4.3 SODIUM SCRUBBING FGD SYSTEMS 18
4.4 DUAL ALKALI FGD SYSTEMS 20
4.5 LIME/LIMESTONE FGD SYSTEMS . . . 22
4.6 LIME SPRAY DRYING FGD SYSTEMS 23
4.7 fLUIDIZED BED COMBUSTION (FBC) 26
4.8 ALTERNATIVE CONTROL LEVELS 32
5.0 REFERENCES . . . . . 33
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LIST OF TABLES
Table
3-1
3-2
3-3.
3-4
4-1
4-2
4-3
SO- EMISSION RATES FOR VARIOUS OIL TYPES
EMISSION DATA FROM SODIUM SCRUBBING FGO SYSTEMS APPLIED
TO OIL-FIRED SMALL STEAM GENERATORS
AVERAGE RESULTS FROM SODIUM SCRUBBING FGD SYSTEMS APPLIED
TO OIL-FIRED SMALL STEAM GENERATORS
SHORT-TERM EMISSIONS DATA FOR DUAL ALKALI SYSTEMS USING
EPA TESTING METHODS -
MAXIMUM EXPECTED EMISSION RATES FOR COAL COMBUSTION . . .
SUMMARY OF SHORT-TERM EMISSIONS DATA FOR FOUR INDUSTRIAL
LIME SPRAY DRYING FGD SYSTEMS
FLUIDIZED BED COMBUSTION EMISSION TEST DATA
Pace
5
9
11
13
17
24
27
iv
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LIST OF FIGURES
Figure Page
4-1 Daily Average SCL Removal, Boiler Load, and Slurry pH
For Coal-Fired Boiler Equipped with a Sodium Scrubber . . 19
4-2 Daily Average SO- Removal Efficiency for the FBC Boiler
at Prince Edward Island 29
4-3 Daily Average Ca/S Molar Feed Ratio for the FBC Boiler at
Prince Edward Island 30
4-4 Daily Average Boiler Load for the FBC Boiler at Prince
Edward Island 31
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1.0 INTRODUCTION
This report provides an overview of the regulatory baseline, technical
basis, and alternative control levels available for developing new source
performance standards (NSPS) limiting sulfur dioxide (SO-) emissions from
small steam generating units (i.e., boilers). Small boilers are defined as
industrial-commercial-institutional steam generating units having a heat
input capacity of 29 MW (100 million Btu/hour) or less.
Many SO- control techniques were considered for the purpose of
evaluating alternative SO- emission standards for small boilers. Detailed
discussions of the design and operating principles of each of these
techniques can be found in the report entitled "Small Steam Generating Unit
Characteristics and Emission Control Techniques" and References 2 and 3.
This report discusses the quantity of S02 emissions generated and the
technical feasibility of controlling those emissions from boilers with heat
input capacities of 29 MW (100 million Btu/hour) and less. However, this
report does not address natural gas or nonfossil fuels because they have
negligible amounts of sulfur and correspondingly low SO- emissions
potential.
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2.0 SUMMARY
The national average State implementation plan (SIP) emission limit for
small, oil-fired boilers is 1,010 ng/J (2.35 Ib/million Btu). However,
projected fuel prices are available only for fuel o.ils capable of meeting
S02 emission limits of 1,290 and 690 ng/J (3.0 and 1.6 ID/million Btu).
Consequently, for purposes of analysis, the regulatory baseline emission
level selected for oil-fired boilers is 1,290 ng/J (3.0 Ib/million Btu) heat
input.
The control techniques considered for reducing SO- emissions from
oil-fired boilers include medium sulfur oil, very low sulfur oil, sodium
scrubbing flue gas desulfurization (FGD), dual alkali FGD, and
lime/limestone FGD. The use of medium sulfur oil can reduce SO- emissions
to 690 ng/J (1.60 Ib/million Btu) heat input. Similarly, the use of very
low sulfur oil can reduce SO- emissions to 210 ng/J (0.50 ID/million Btu)
heat input. The use of FGD systems can reduce SO- emissions from oil-fired
boilers by 90 percent or more over uncontrolled levels. Emission levels of
690 ng/J (1.6 Ib/million Btu), 210 ng/J (0.50 Ib/million Btu), and
90 percent SO- reduction, therefore, are selected as Alternative Control
Levels 1, 2, and 3, respectively, to represent the SO- control performance
of medium sulfur oil, very low sulfur oil, and FGD systems.
The national average SIP emission limit for small, coal-fired boilers
is 1,460 ng/J (3.4 Ib/million Btu) heat input. However, projected fuel
prices are only available for coals capable of meeting SO- emission limits
of 1,550 and 1,120 ng/J (3.6 and 2.6 Ib/million Btu). Consequently, for
purposes of analysis, the regulatory baseline emission level selected for
coal-fired boilers is 1,550 ng/J (3.6 To/million Btu).
The control techniques considered for reducing S02 emissions from
coal-fired boilers include low sulfur coal, sodium scrubbing FGD, dual
alkali FGD, lime/limestone FGD, lime spraying drying FGD, and fluidized bed
combustion (FBC). The use of low sulfur coal can reduce SO- emissions from
small coal-fired boilers to 520 ng/J (1.2 million Btu/hour). The use of FGD
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systems or FBC units can reduce SO- emissions by 90 percent or more over
uncontrolled levels. An emission level of 520 ng/J (1.2 1 fa/million Btu)
heat input is, therefore, selected as Alternative Control Level 1 and
90 percent reduction is selected as Alternative Control Level 2 to represent
the SO- control performance of low sulfur coal and FGD or FBC systems,
respectively.
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3.0 OIL S02 EMISSIONS AND CONTROL TECHNIQUES
The control techniques considered for reducing SO- emissions from small
oil-fired boilers include medium sulfur oil, very, low sulfur oil, sodium
scrubbing FGD, dual alkali FGD, and lime/limestone F6D.
3.1 REGULATORY BASELINE EMISSION LEVELS
The regulatory baseline SO- emission level for small oil-fired boilers
is based on the national average SIP emission limit for small, oil-fired
boilers. The national average SIP SO- emission limit for small oil-fired
boilers is 1,010 ng/J (2.35 Ib/million Btu) and is essentially independent
of boiler size. However, projected fuel prices are available only for oils
capable of meeting SO- emission limits for 1,290 and 690 ng/J (3.0 and
1.6 Ib/million Btu). As a result, a regulatory baseline of 1,290 ng/J
(3.0 Ib/million Btu) is selected for purposes of analysis.
3.2 MEDIUM, LOW, AND VERY LOW SULFUR OIL
The sulfur content of fuel oil determines the SO- emission rate from an
oil-fired steam generating unit. Use of medium, low, or very low sulfur oil
limits SO- emissions by reducing the amount of sulfur available for SO-
formation. Table 3-1 presents the oil classification scheme used to
represent fuel oils fired in steam generating units. In this classification
scheme, oil is classified by its sulfur content. This classification scheme
originated from classifications used by the U.S. Department of Energy to
study fuel oil use patterns and to report refinery production data. The
classifications reflect the fact that many distillate and residual oils are
produced to meet market demands created by existing Federal, State, and
local S02 emission regulations. For example, "low sulfur" distillate and
residual fuel oils can be fired to meet the 1971 NSPS (40 CFR Part 60,
Subpart D) emission limit of 340 ng/J (0.80 Ib/million Btu) heat input for
steam generating units with a heat input capacity greater than 73 MW
(250 million Btu/hour), or more stringent standards adopted by Stats or
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TABLE 3-1. S02 EMISSION RATES FOR VARIOUS OIL TYPES
SO-
Emission Rate
Oil Type ng/J (Ib/million Btu)
Very Low Sulfur . 130 (0.3)
Low Sulfur 340 (0.8)
Medium Sulfur 690 (1.6)
High Sulfur 1,290 (3.0)
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local governments. Factors such as refinery techniques, storage and
transportation methods, and fuel handling at the steam generating unit site
serve to make a given fuel oil shipment relatively homogeneous with respect
to fuel sulfur content. Thus, there is little variability in SO- emissions
resulting from the combustion of a specific fuel oil shipment.
Fuel oils with low sulfur contents are generally produced by refining
low sulfur content crude oils, however, a number of hydrodesulfurization
(HDS) processes are available for producing low sulfur oil from high sulfur
oil. Although both distillate oils and low sulfur residual oils can be
produced from any crude oil, most low sulfur residual oils are produced from
low sulfur crude oils and/or by blending with lower sulfur oils. Low sulfur
oils can be fired in any steam generating unit designed to fire oil,
although different burners may be required to achieve good combustion and
fuel heating may be required to reduce viscosity for pumping and proper
atomization at the burner tip.
A distinction exists between the sulfur content of most residual oils
and distillate oils. Residual oils generally are higher in sulfur content
and have a wider range of sulfur contents- than distillate oil. The sulfur
content of residual oil, for example, can vary from as little as 0.3 weight
percent to over 3.0 weight percent. Although the sulfur content of
distillate oil can be as low as 0.2 weight percent, the maximum sulfur
content is limited to 0.5 weight percent by fuel oil specifications adopted .
by the American Society for Testing and Materials (ASTM).
Medium sulfur residual oil is widely available throughout the United
States. Generally speaking, low and very low sulfur residual oils are not
widely available throughout the United States. Distillate oil, however, is
widely available. The maximum sulfur content of distillate oil (0.5 weight
percent), therefore, serves as a useful benchmark for identifying the sulfur
content of those very low sulfur fuel oils that are widely available
throughout the United States. In a few areas, both distillate oil and very
low sulfur residual oils with sulfur contents of less than 210 ng/J
(0.5 Ib/million Btu) heat input will be available.
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Because of their national availability and extensive use in small steam
generating units, medium sulfur oils and very low sulfur oils (distillate
oil and very low sulfur residual oils) are considered demonstrated control
techniques for reducing SO- emissions from small steam generating units.
3.3 SODIUM SCRUBBING FGD SYSTEMS
Sodium scrubbing FGO systems employ an aqueous solution of sodium
hydroxide (NaOH) or sodium carbonate (Na-CO,) in the scrubber to absorb SO-
from the boiler flue gas. Sodium scrubbers are the most extensively used
wet FGD systems in the industrial boiler sector and have been widely applied
on small oil-fired boilers.
The vast majority of sodium scrubbing systems have been applied on
small oil field steam generating units. Sodium scrubbers used in these
applications are package systems that are skid-mounted, shipped to the site,
and installed for operation witji a minimum of on-site fabrication. One
report estimates that 89 percent of all sodium scrubbers in operation are
used on oil' field steam generating units, and 74 percent of all sodium
scrubbers in operation are used on boiler size equivalents (i.e., the heat
generating capacity serviced by the scrubber) less than 29 MW (100 million
Btu/hour).6
These boilers usually operate under constant, high-load conditions,
whereas other small industrial-commercial-institutional boilers can
experience significant load swings. However, boiler load swings can be
monitored and accommodated by the scrubber system's process control
instrumentation and, as a result, have not been shown to be deleterious to
sodium scrubber operation.
In response to changes in flue gas flow rate and/or SO- gas
concentration, changes can be made to the scrubber liquid pumping rate and
the reagent addition rate. Moreover, the buffering capacity of these
systems allows changes to be made without affecting SO- removal performance.
The popularity of sodium scrubbers can be attributed primarily to their ease
of operation (requiring minimal operator training and attention) and overall
reliability.
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Table 3-2 presents SO- emissions data for 20 oil-fired steam generating
units equipped with sodium scrubbers and operated to produce steam for
tertiary oil recovery. All SO- emission tests were short-term compliance
tests (typically over a 3-hour period). Sulfur dioxide emissions were
measured using either EPA Reference Method 8 or continuous emission monitors
(CEM). The short-term CEM tests were performed using ultraviolet
photometry. These tests are considered as alternative methods to measure
SO-. From this table, it can be seen that SO- removal efficiency ranged
from 87.5 to 99.5 percent for oils having sulfur contents ranging from 0.6
to 1.66 weight percent. Boiler operating loads ranged from 67 to 108
percent of full load.
Table 3-3 shows that SO- removal efficiency for these 20 sodium
scrubbers averaged 95.2 percent. The average SO- outlet emissions were
30 ng/J (0.07 Ifa/million Btu). The sulfur content of the oils and operating
load for the 20 boilers averaged 1.21 weight percent and 87.5 percent of
full load, respectively.
Although long-term performance data are not available for sodium
scrubbing systems operating on small oil-fired boilers, the long-term
performance of sodium scrubbing systems on oil-fired boilers can be inferred
from analyzing the long-term performance of sodium scrubbers on coal-fired
boilers. Thirty days of SO- emission data were available and were analyzed
for SO- reduction variability for one sodium scrubbing FGO system on a
coal-fired boiler. The data are discussed below in Section 4.3. Although
these data were collected for a sodium .scrubber on a larger [55 MW
(188 million Btu/hour)] boiler, the variability of a smaller sodium
scrubbing system should not be significantly different. Also, because the
sulfur content of oils is more consistent and less variable than the sulfur
content of coals, the variability results using the 30-day SO- emissions
data from a coal-fired boiler would be a conservatively high estimate of the
emission variability for sodium scrubbers on oil-fired boilers.
The variability results from the coal-fired boiler/sodium scrubber
system, when applied to oil-fired boiler/sodium scrubber systems, indicate
that sodium scrubbers on oil-fired boilers could comply with a 90 percent
SO- reduction specification using a 30-day rolling averaging period if the
8
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TABLE 3-2. EMISSION DATA FROM SODIUM SCRUBBING FGD SYSTEMS APPLIED TO
OIL-FIRED SMALL STEAM GENERATORS (8)
Boiler
1.0.
7
8
12
30
6
It
U-24
22-4
22-41
30-7
30-71
1
2
34
38
64
4
3
5
U-23
Abaorber
type (a)
LJE
LJE
LJE
LJE
SB
SB
SB
TA(b)
TA
TA(b)
TA
VS
VS
VS
VS
VS
ST
UNK (c)
UNK
UNK
Boiler
equivalent
•Ize. MW
(mUUonBlu/tv)
heal Input
6.7(23)
8.1 (27.6)
14.7 (50)
14.7(50)
16.2(55.2)
7.3 (25)
14.7 (50)
6.4 (22)
6.4 (22)
14.7 (50)
14.7(50)
18.3 (62.5)
18.3 (62.5)
18.3 (62.5)
18.3 (62.5)
18.3 (62.5)
18.3 (62.5)
18.3 (62.5)
8.8(30)
7.3 (25)
OU
autfur
content
(percent)
1.00
1.00
1.65
1.34
0.60
1.00
1.46
1.66
1.61
1.58
1.66
0.85
1.15
1.00
1.10
1.10
1.01
0.80
1.20
1.46
Percent
of
lull
load
92 (d)
75 (d)
92 (e)
96 (e)
73 (d)
95 (d)
88 (e)
71
67
105
101
66 (d)
91 (d)
84 (d)
82 (d)
82 (d)
108(d)
94 (d)
78 (d)
92 (e)
Scrubber
Inlet
pH
NA(f)
NA
NA
NA
NA
NA
NA
7.23
7.57
6.97
7.10
NA
NA
NA
NA
NA
NA
NA
NA
NA
Slowdown
PH
NA
NA
NA
NA
NA
NA
NA
6.60
6.27
6.20
5.75
NA
NA
NA
NA
NA
NA
NA
NA
NA
S02
removal
efficiency
(percent)
91.0
89.0
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
96.0
98.0
99.2
93.5
98.1
Outlet SO2
emltslons
(ng/J)
(g)
38.7
43.0
21.5
25.8
17.2
1.7
12.9
103.0
38.7
77.4
34.4
17.2
12.9
21.5
17.2
21.6
19.2
'4.3
30.1
12.9
SO2
test method
(number of rune)
(h)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
CEM (4)
CEM(1)
CEM (5)
CEM(l)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
EPA 8 (3)
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TABLE 3-2. EMISSION DATA FROM SODIUM SCRUBBING FGD SYSTEMS APPLIED TO
OIL-FIRED SMALL STEAM GENERATORS (CONTINUED) (8)
(a) LJE • Liquid Jet aductor; SB - Spray baffle; TA • Tray absorber; VS - (e) The heat Input during the test Is determined using the
Venturl scrubber; 8T • Spray tower. F-faclor. the flue gas flow rate, and the flue gas oxygen
content.
(b) Both sites use two tray absorbers. Two tray absorbers are known to have
lower SO2 removal efficiencies than three tray absorbers. The other two sites (f) NA - Not available.
(22-41 and 30-71) use three tray absorbers.
(g) DMde ng/J by 430 for conversion to Ib/mllllon Btu.
(c) UNK . Unknown.
(h) All tests were short-term.(about 1 hour per run). EPA 8 -
(d) The heat Input during the test Is determined by multiplying the oil flow EPA Reference Method 8; CtM - Continuous emission monitor.
rate to the boiler and an assumed heating value of 43.000 kJ/kg (16,500
Blu/lb). Results of fuel analysis (actual heating value) are not available.
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TABLE 3-3. AVERAGE RESULTS FROM SODIUM SCRUBBING FGD SYSTEMS APPLIED
TO OIL-FIRED SMALL STEAM GENERATORS9
SQ? Removal Efficiencies, Percent
Average Efficiency (± Standard Deviation) 95.2 ± 3.4
Outlet SO- Emissions. no/J Mb/IP6 Btu)
Average SO- Outlet Emissions
(± Standard Deviation) 30 ± 26 (0.07 ± 0.06)
Sulfur Content of Oil. Weight Percent
Average Sulfur Content of Oil Fired
(± Standard Deviation) 1.21 ± 0.31
Boiler Load. Percent of FullLoad
Average Load (± Standard Deviation) 87.5 ± 11.3
11
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mean SO- reduction is 91 percent or greater. The average SOg removal
efficiency of the short-term test data summarized above was 95.2 percent,
well above the required 91 percent reduction level. Thus, the ability of
sodium scrubbers to continuously reduce SO- emission by 90 percent on a
30-day rolling average basis is considered demonstrated.
3.4 DUAL ALKALI FGD SYSTEMS
Dual alkali FGD systems are the second most prevalent wet FGD
technology for industrial boiler applications. The dual "alkali FGD process
is similar to sodium scrubbing FGD in the absorption stage; both
technologies use a clear sodium solution for SO- removal. However, dual
alkali FGD includes a regeneration stage where lime or limestone is used to
regenerate the active sodium alkali for S02 sorption. Dual alkali
technology has been applied primarily to coal-fired units. However,
emissions data were available for one dual alkali system applied to an
oil-fired steam generating unit. As shown in Table 3-4, the SO- removal
performance of the dual alkali system applied to the oil-fired unit is
comparable to that of the coal-fired units. The data for the oil-fired unit
were obtained from a compliance test; the test duration was unavailable.
The boiler had a heat input capacity of 91 MW (310 million Btu/hour). The
sulfur content of the oil fired was 1.5 weight percent. The outlet
emissions were 0.091 Ib SO-/mi 11 ion Btu, and the SO- removal efficiency was
91.7 percent.
Long-term performance data are not available for dual alkali systems
operating on small oil-fired boilers. However, the design and operating
principles for dual alkali technology are similar for both coal- and
oil-fired boilers. Thus, the performance of these systems on oil-fired
boilers can be evaluated from analyzing their performance on large and small
coal-fired boilers. Seventeen and 24 days of SO- emission data were
available for a dual alkali system comprising two scrubbers applied on two
coal-fired boilers with a single regeneration section. These test data are
discussed below in Section 4.4. The average SO- removal efficiency of these
scrubbers was 92 percent.
12
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TABLE 3-4. SHORT-TERM EMISSIONS DATA FOR DUAL ALKALI SYSTEMS
USING EPA TESTING METHODS (11)
Boiler capacity
Company treated (a) Fuel
(location) (million Blu/hour) type
ARCO Polymer* 1,360 Coal
(Monaca, PA)
General Motors 570 Scrubber! Coal
(Parma, OH) Scrubber II Coal
Grlssom Air Force Base 140 System! Coal
(Peru, IN) System II Coal
Santa Fe Energy 310 Oil
Average
Sulfur content
of fuel
(weight percent)
2.5 - 2.8
2.5
2.5
3.0 - 3.5
3.0 • 3.5
1.5
2.61
Outlet SO2
emissions
(Ib/mlllon Btu)
0.65
0.30
0.32
0.56
0.38
0.091
0.38
SO2 removal
efficiency
(percent)
68.0 (b)
92.2 (c)
91.6(d)
88.1 (b)
94.2
91. 7 (b)
91.0
(a) Total capacity of all boilers treated.
(b) Data from short-term compliance tests.
(c) 24-day test.
(d) 17-day test.
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Thus, the ability of dual alkali scrubbers to reduce SO- emissions by
90 percent on a 30-day rolling average basis for small oil-fired steam
generating units is considered demonstrated.
3.5 LIME/LIMESTONE FGD SYSTEMS
Lime/limestone FGD systems employ a slurry of calcium oxide (CaO, lime)
or calcium carbonate (CaCO,, limestone) to remove SO- from industrial-
commercial -institutional steam generating units. Although no emission data
are available to document the performance of lime/limestone FGO systems on
oil-fired boilers, emission data are available for lime and limestone FGD
systems applied to small and large coal-fired units. These data, which are
presented and discussed below in Section 4.5, show S02 removal efficiencies
for lime and limestone FGD systems of 91.5 and 94.3 percent, respectively.
Due to the similarity in system design and operation, it can be inferred
from analyzing this performance data that the performance of a
lime/limestone FGD system as appl-ied to an oil-fired-boiler would be
comparable to the same system applied to a coal-fired boiler.
3.6 ALTERNATIVE CONTROL LEVELS
The evaluation of SO- control techniques for small oil-fired boilers
indicates that use of medium sulfur oil, very low sulfur oil, sodium
scrubbing FGD systems, dual alkali FGD systems, and lime/limestone FGO
systems are demonstrated techniques that could serve as the technical basis
for developing NSPS for small boilers. Medium sulfur oil combustion will
reduce SO- emissions to 690 ng/J (1.6 Ib/million Btu); consequently, this
level is selected as Alternative Control Level 1. Very low sulfur oil
combustion will reduce SO- emissions to 210 ng/J (0.50 Ib/million Btu) heat
input; thus, an emission level of 210 ng/J (0.50 Ib/million Btu) heat input
is selected as Alternative Control Level 2. Flue gas desulfurization
systems are capable of 90 percent SO- emission reduction and, as a result,
90 percent reduction is selected as Alternative Control Level 3.
14
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4.0 COAL S02 EMISSIONS AND CONTROL TECHNIQUES
The control techniques considered for reducing S02 .emissions from small
coal-fired boilers include low sulfur coal, sodium scrubbing FGD, dual
alkali FGD, lime/limestone FGD, lime spray drying FGD, dry alkali injection,
FBC, limestone injection multistage burner (LIMB), coal gasification, and
coal liquefaction.
Limestone injection multistage burner and dry alkali injection
technologies are still in the process development stage and, thus, are not
considered further. Despite the potential of coal gasifi-cation for
producing a low sulfur fuel, fewgasifiers have been designed specifically
for small boiler applications. Furthermore, coal gasification is unlikely
to achieve widespread application to new small boilers in the near future.
Hence, coal gasification is not examined further. Several pilot-scale coal
liquefaction plants have been built and tested. However, no commercial coal
liquefaction plants have been constructed to date, nor are any planned or
under construction. In view of the long lead time associated with the
design, construction, and start-up of coal liquefaction plants, it is
unlikely that these fuels will be available for use in small boiler
applications in the near future. As a result, coal liquefaction also is not
considered further.
4.1 REGULATORY BASELINE EMISSION LEVELS
The regulatory baseline SO- emission level for small coal-fired boilers
is based on the national average SIP emission limit for small, coal-fired
boilers. Average SO- limits for small, coal-fired boilers range from
1,400 to 1,510 ng/J (3.26 to 3.51 Ib/million Btu) for boilers of 29 and
2.9 MW (100 and 10 million Btu/hour) heat input capacity, respectively. The
overall national average SIP emission limit is 1,460 ng/J (3.4 Ib/million
Btu). However, projected fuel prices are only available for coals capable
of meeting S02 emission limits of 1,550 and 1,120 ng/J (3.6 and
2.6 Ib/million Btu) heat input. As a result, a regulatory baseline of
1,550 ng/J (3.6 Ib/million Btu) heat input is selected for purposes of
analysis.
15
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As noted in Table 4-1, the medium sulfur Type F coal which corresponds
to the regulatory baseline is characterized by a maximum expected SO-
emission rate of 1,550 ng/J (3.6 Ib/million Btu) heat input. The difference
between this value and the long-term average S02 emission rate of 1,230 ng/J
(2.86 Ib/million Btu) heat input reflects the allowance for S02 emissions
variability that applies to this coal type.
4.2 LOW SULFUR COAL
Use of low sulfur coal limits SO- emissions by reducing the amount of
sulfur available in the fuel for S02 formation. Low sulfur coal is defined
as coal that can meet an emission limit of 520 ng/J (1.2 Ib/million Btu)
heat input on a continuous basis using a 30-day rolling average without
additional SO- control.
Low sulfur coal is obtained primarily from naturally occurring low
sulfur coal deposits. Low sulfur coal may also be produced through coal
treatment to reduce the naturally occurring sulfur content. A commercially
available method for producing low sulfur coal is physical coal cleaning
(PCC). The design and operating factors and the mechanism by which PCC can
reduce SO- emissions are discussed in Reference 12. Low sulfur coal can be
burned in any small boiler designed to fire coal, so its applicability is
not limited by boiler size.
Coal markets that supply coals with low sulfur contents [520 ng/J
(1.2 Ib/million Btu) heat input or less] have developed throughout the
Nation. Because of widespread availability and extensive use of low sulfur
coal for steam generating purposes, use of low sulfur coal is considered to
be a demonstrated technique for reducing SO- emissions from small steam
generating units.
Unlike SO- emissions from oil combustion, SO- emissions from coal
combustion exhibit variability because the sulfur content of coal is not
homogeneous. Coal produced from a single coal mine will vary in sulfur
content. This variability may be further influenced by mining practices.
Whether coal is cleaned or blended with other coals also will influence its
S02 emissions variability when it is combusted.
16
-------
TABLE 4-1. MAXIMUM EXPECTED EMISSION RATES FOR COAL COMBUSTION
13
Coal
Category
Low Sulfur
Low Sulfur
Medium Sulfur0
Medium Sulfur0
High Sulfur0
High Sulfur0
Coal
Typed
Type B
Type D
Type E
Type F
Type 6
Type H
Long-Term Average
SO- Emissions
ng/J (ID/million Btu)
464 (1.08)
620 (1.45)
900 (2.10)
1,230 (2.86)
1,790 (4.15)
2,380 (5.54)
Maximum
Expected
SO- Emission Ratea
ng/J (Ib/mi
520
690
1,120
1,550
2,240
2,920
llion Btu)
(1.2)
(1-6)
(2.6)
(3.6)
(5.2) .
(6.8)
Once in 10-year maximum expected 30-day rolling average SO- emission rate.
Based on a daily average SO- emission rate relative standard deviation
of 0.10. i
°Based on a daily average SO- emission rate relative standard deviation of
0.20. '
All coals are bituminous coals.
17
-------
The SO- emissions variability associated with combustion of low sulfur
coals has been addressed in earlier reports. This variability leads to
the maximum expected emission rates shown in Table 4-1. These maximum
expected emission rates represent the SO- emission limits that could be
achieved by combustion of low sulfur coals in small boilers.
4.3 SODIUM SCRUBBING FGD SYSTEMS
Sodium scrubbing FGD technology has been directly applied on small,
coal-fired boilers and is commercially available for small, coal-fired
boiler applications. One leading manufacturer of sodium scrubbers has
designed, constructed, and started up systems to service steam generators as
small as 1.5 MW (5 million Btu/hour).
Emission test data are available to document sodium scrubber
performance for coal firing. Thirty days of certified CEM test data were
gathered from a sodium scrubber applied to a pulverized coal-fired boiler
rated at 55 MW (188 million Btu/hour) heat input.18 The FGD system tested
was a tray and quench liquid scrubber that consisted of a three-stage
impingement tower with a Chevron mist eliminator. The scrubbing medium was
a 50 percent aqueous NaOH solution. The makeup rate to the scrubber was
2.2 liters per second (1/s) (35 gal/rain). The scrubbing solution pH was
8.1. The boiler operated at loads between 40 and 60 percent of full load
and averaged 48 percent of full load for the test duration. The sulfur
content of the coal fired was 3.6 weight percent. The design SO- efficiency
of this system was 90 percent at an inlet SO- concentration of 2,000 ppmv.
Figure 4-1 shows consistently high SO- removal efficiencies for this
system, averaging 96.2 percent for the test period. The daily average
outlet S02 emissions ranged from 56 to 267 ng/J (0.13 to 0.62 To/million
Btu), averaging 86 ng/J (0.20 1 fa/mill ion Btu) for the 30-day test period.
The performance data from this 30-day test were analyzed for SO-
emission reduction variability. The results of the variability analysis
indicate that a long-term mean of 91 percent SO- reduction would be
necessary to comply with a 90 percent SO- reduction requirement based on a
30-day rolling average with no more than one exceedance every 10 years. A
relative standard deviation (RSD) of 1.2 percent and an autocorrelation
18
-------
100
«
80
70
10
*«nov«1 • 34.2:
15
20
30
90,
801
! «
I 50
* 40
8'
7'
<>
*»
10
10
Average boiler load * 4£
IS
IS
Test Otyt
20
Average slurry pH » 3.1
20
Figure 4-1.
Dally average S02 removal, boiler load, and slurry pH
for coal-fired boiler equipped with a sodium scruboer1-
19
-------
coefficient (AC) of 0.13 were determined from the SO- reduction data for
21
this boiler. If the mean SO- reduction performance of 96.2 percent
measured in the 30-day test were maintained at full load, then the sodium
scrubber would exceed the level necessary for compliance (i.e., 91 percent
SO- reduction) with a 90 percent SO- reduction specification using a 30-day
rolling average.
The SO- removal efficiency of sodium scrubbing systems can vary during
load swings. Further, changes in flue gas flow rate and SO- concentration
result in imbalances in the sodium-to-sulfur ratio and the pH of the
scrubber solution. Therefore, to maintain a constant SO- removal
efficiency, these two parameters must be adjusted during Toad swings. With
proper design and operation of the scrubber system, consistently high SO-
removal rates can be maintained during fluctuations in boiler load.
Although the sodium scrubber in this 30-day test was applied to a
boiler rated above 29 MW (100 million Btu/hour) heat input, the performance
data from this scrubber are applicable to small boilers. This application
can be made because sodium scrubber design and operating characteristics
(e.g., L/G ratio, pH, gas distribution, etc.)"do not vary signiffcantly with
size in this general size range. As a result, performance and variability
of smaller systems would be similar to those of the scrubber examined here.
Thus, achievement of a 90 percent SO- reduction by sodium scrubbing systems
on small coal-fired boilers on a 30-day rolling average basis is considered
demonstrated.
4.4 DUAL ALKALI FGD SYSTEMS
Dual alkali FGO technology has been applied primarily to large
coal-fired units, but is commercially available for units of most sizes.
Tests of dual alkali FGD systems operating on coal-fired steam generating
units have shown short-term SO- removal efficiencies of greater than
22
90 percent, with long-term efficiencies of around 92 percent.
Emission data are available from two long-term tests to document dual
alkali FGD system performance for small coal-fired steam generating units.
As discussed in Reference 23, the dual alkali system tested consisted of two
S0£ absorbers, each serving a separate steam generating unit, and a single
20
-------
regeneration section. Seventeen days of test data were gathered from one
absorber applied to a coal-fired spreader stoker steam generating unit rated
at 40 MW (135 million Btu/hour), and 24-days of test data were gathered from
the other absorber applied to a unit rated at 23 MW (77 million Btu/hour).
Data were collected using continuous SO. emission monitors on both the inlet
and outlet of the FGD system.
The sulfur content of the bituminous coal received at the plant during
these tests averaged 1,490 ng S02/J (3.47 Ib S02/million Btu). During these
tests, the steam generating units also burned oil with an average sulfur
content of 320 ng SO-/J (0.74 Ib SOg/nrillion Btu). During both tests, the
dual alkali FGD system operated at a reliability level of 100 percent.
In the 17-day test, the steam generating unit operated at an average
load of 67 percent, with the load varying between 42 and 96 percent. The
SO- removal efficiency averaged 91.6 percent. In the 24-day test, the steam
generating unit operated at an average load of 62 percent, with loads
varying between 5 and 95 percent. The S02 removal efficiency averaged
92 percent.
Results of the 24-day test show that at least 90 percent SO- removal
can be reliably and consistently achieved on a small coal-fired steam
generating unit. In addition, the results of the 17-day test indicate that
the S02 removal efficiency achieved on a large steam generating unit .[>29 MW
(>100 million Btu/hour)] is essentially the same as that achieved on a small
steam generating unit [£29 MW (<100 million Btu/hour)]. This same level of
performance can be achieved at full load conditions if vigorous gas-liquid-
contact is maintained in the absorber and the sodium-to-sulfur and
liquid-to-gas ratios are maintained at a level sufficient to provide an
adequate supply of active sodium species.
Based on these analyses of system performance, dual alkali FGD is a
demonstrated technology for reducing SO- emissions from small coal-fired
industrial-commercial-institutional steam generating units by 90 percent
on a 30-day rolling average basis.
21
-------
4.5 LIME/LIMESTONE FGD SYSTEMS
Emission data from two long-term tests are available to document
lime/limestone FGD performance on industrial steam generating units. As
discussed in Reference 24, the scrubbing system serviced six coal-fired
stoker boilers with a total heat input capacity of 62 MW (210 million
Btu/hour).
The tests were conducted using continuous SO- emission monitors at both
the inlet and outlet of the FGD system. Data were collected for a 29-day
period while the system used a lime reagent and for 30 days while the system
used a limestone reagent.
During the 29-day data collection period when lime was used as the
reagent in the wet scrubbing system, the sulfur content of the bituminous
coal fired averaged 2,150 ng SO-/J (5.0 Ib S0-/million Btu). During this
period, the steam generating unit load varied from 34 to 65 percent of full
load. The SO- removal efficiency averaged 91.5 percent, and the lime wet
scrubbing FGD system operated at a reliability level of over 91 percent.
During the 30-day test period when limestone was used as the reagent in
the wet scrubbing system, the sulfur content of the bituminous coal burned
averaged about 2,150 ng SO-/J (5.0 Ib S0-/million Btu). During this period,
the steam generating unit load varied from 30 to 67 percent of full load.
The SO- removal efficiency averaged 94.3 percent, and the system operated at
a reliability level of 94 percent.
The long-term data presented above for lime and limestone FGD systems
show SOg removal efficiencies of 91.5 and 94.3 percent, respectively, which
are near or above the long-term average required to meet consistently a once
in ten year 30-day rolling average minimum performance level of 90 percent
emission reduction. Although these results were obtained at less than
maximum load conditions, new systems could achieve this level of performance
at full load by operating at a higher liquid-to-gas ratio. In addition, new
systems would likely be equipped with a spray tower or turbulent contact
absorber to provide increased mass transfer area and gas residence time for
improved SO- absorption.
22
-------
Based on this analysis of system performance and system variability,
the lime/limestone wet scrubbing FGD technology is considered a demonstrated
technology for reducing SO- emissions from small coal-fired industrial-
commercial -institutional steam generating units by 90 percent using a 30-day
rolling average to calculate emission reductions.
4.6 LIME SPRAY DRYING FGD SYSTEMS
Lime spray drying is a dry scrubbing process that involves contacting
the flue gas with an atomized lime slurry or a solution of sodium carbonate.
The hot flue gas dries the droplets to form a dry waste product while the
absorbent reacts with SO- in the flue gas. The dry waste solids, consisting
of sulfite and sulfate salts, unreacted sorbent, and fly ash are collected
in a baghouse or ESP for disposal.
Emission test data are available in Reference 25 to document lime spray
drying performance for coal firing. As shown in Table 4-2, a series of four
short-term tests were conducted to demonstrate lime spray drying
performance. The first short-term test was a compliance test conducted over
approximately 2 hours, where the lime spray drying system treated flue gas
from a pulverized coal-fired steam generating unit with a heat input
capacity of 82 MW (280 million Btu/hour). This unit burned bituminous coal
with an average sulfur content of 1,430 ng SO-/J (3.33 Ib S0-/million Btu)
and operated at 100 percent of full load. The SO- removal efficiency
averaged 74.5 percent.26
The second short-term test was also conducted over approximately 2
hours, where the system treated flue gas from a pulverized coal-fired unit
with a heat input capacity of 34 MW (115 million Btu/hour). This unit,
which fired a mixture of bituminous coal with an average sulfur content of
410 ng S02/J (0.96 Ib S02/million Btu), operated at about 75 percent of full
load. Of the total heat input to the unit, 94.2 percent was derived from
coal and the remainder from oil. Sulfur dioxide removal efficiencies
averaged 92.4 percent during this test period.
A series of three short-term tests was conducted over 8 hours at a
third site. The coal-fired spreader stoker unit for these tests operated
23
-------
TABLE 4-2. SUMMARY OF SHORT-TERM EMISSION DATA FOR FOUR INDUSTRIAL
LIME SPRAY DRYING FQD SYSTEMS (25)
ro
Number
of
Location runs
1 6
2 6
3 1
3 1
3 1
3 1
3 1
3 1
3 1
3 1
3 1
3 1
3 1
4 3
Test
duration
(hours)
2
2
8
8
8
4
4
4
4
4
4
4
4
1
Average SO2
removal (%)
74.5
02.4
79.7
89.9
95.6
64.0
78.0
74.0
80.8
83.0
87.0
90.0
96.0
96.6
Boiler
load
(%)
100
75
35
70
82
50-74
50-74
50-74
50-74
50-74
50-74
50-74
50-74
100
Reagent
ratio
NA(b)
NA
0.6
1.4
1.9
1.1
1.2
1.3
1.0
1.1
1.2
1.3
1.6
3.3
Coal average
sulfur content
(ng S02/J)
(«)
1.430
2.530 (c)
2,190
2,190
2.190
2,840
2,840
2.840
2.840
2.840
2,840
2,840
2.840
410
Approach
temperature,
degrees C
(degrees F)
19(35)
14 (25)
13 (23)
13 (23)
13 (23)
17 (30)
17 (30)
17 (30)
17 (30)
17 (30)
17(30)
17(30)
17(30)
28-39 (50-70)
Unit
heat Input
capacity. MW
(million Btu/hr)
82 (280)
34(115)
69 (235)
69(235)
69 (235)
69 (235)
69 (235)
69 (235)
69 (235)
69 (235)
69 (235)
69 (235)
69 (235)
69 (235)
(a) Divide ng/J by 430 for conversion to Ib/mllllon Btu.
(b) NA - Not available.
(c) Coat/oil mixture with 94.2% coal heat Input.
-------
with a heat input capacity of 69 MW (235 million Btu/hour) and fired
bituminous coal with an average sulfur content of 2,190 ng SO-/J (5.09 Ib
S0-/million Btu). During these three tests, unit load was maintained at 35,
70, and 82 percent of full load. The reagent ratio was varied during each
testing period to obtain the following results: 79.7 percent SO- removal at
0.6 reagent ratio; 89.9 percent SO- removal at 1.4 reagent ratio; and
95.6 percent SO- removal at 1.9 reagent ratio.
A second series of short-term tests was also conducted at this same
site over a 4-hour period. For this test series, the unit fired bituminous
coal with an average sulfur content of 2,840 ng SO-/J (6..60 Ib SO-Xmillion
Btu) and operated at loads that varied between 50 and 74 percent of full
load. Both the reagent ratio and approach to saturation temperature were
varied during the testing. At a 17°C (30°F) approach to saturation
temperature, SO- removal efficiencies of 64, 78, and 74 percent were
achieved with reagent ratios of 1.1, 1.2, and 1.3, respectively. Lowering
the approach to saturation temperature to 12°C (2?°F) resulted in
80.8 percent S02 removal at a reagent ratio of 1.0. At a 11°C (20°F)
approach to saturation temperature, SO- removal efficiencies of 83, 87, 90,
and 96 percent were achieved with reagent ratios of 1.1, 1.2, 1.3, and 1.6,
respectively.
The fourth short-term test, which was conducted over three 1-hour
periods, involved a lime spray drying system treating flue gas from a
pulverized coal-fired steam generating unit with a heat input capacity of
69 MW (235 million Btu/hour). This unit burned bituminous coal with an
average sulfur content of 410 ng S02/J (0.96 Ib S02/million Btu) and
operated at 100 percent of full load. The SO- removal efficiency averaged
96.6 percent.
The short-term performance data from these tests indicate that lime
spray drying systems are capable of achieving at least 93 percent reduction
in S02 emissions from industrial-commercial-institutional steam generating
units. Few long-term data are available, but long-term removal rates as low
as 70 percent have been reported. This, however, reflects the fact that
many large commercial systems have not been required to achieve high removal
levels, rather than any inherent limitation of the technology. One spray
drying vendor believes that high reliability can be achieved at high
25
-------
performance levels and is prepared to offer a 95 percent reliability
guarantee on lime spray drying systems, irrespective of coal sulfur content
and SO- removal guarantees. Such a guarantee, however, would require that
owners/operators follow proper maintenance and operating procedures.
As a result, there appear to be no technical barriers to achieving
greater than 90 percent SO- removal with a lime spray drying system on a
sustained basis at high (90 percent) reliabilities. Furthermore, due to
similarities in design and operation between large and small systems, it
has been concluded that lime spray dryers would also be capable of meeting
the 90 percent SO- reduction levels on small industrial-commercial-
institutional units. Therefore, this control technique is considered
demonstrated for purposes of establishing performance standards for small
coal-fired steam generating units.
4.7 FLUIDIZED BED COMBUSTION (FBC)
Fluidized bed combustion is a boiler design option which, because of
its ability to incorporate limestone addition, can achieve significant SO-
emission reductions. This technology offers a variety of advantages over
conventional boiler designs, including SO- emission reduction without the
use of FGD systems as well as greater flexibility in fuel use.
Atmospheric fluidized bed combustion (AFBC) boilers have developed
rapidly over the past five years and are now being applied to small boiler
sizes. Two AFBC design alternatives that are currently available are the
conventional bubbling fluidized bed (with or without solids recycle) and the
circulating fluidized bed. Pressurized FBC technology has been under
development for over a decade, but has not yet been used in commercial
practice and is unlikely to be applied to small boiler applications.
Table 4-3 presents S02 emission data for one circulating bed FBC and
four bubbling bed boilers, ranging in size from 15 to 61 MW (50 to 208
million Btu/hour). Certified CEM or EPA Reference Methods were used to
measure S02 emissions. Tests using EPA Reference Methods were short-term
tests (approximately three-hour tests) unless otherwise stated in Table 4-3,
while tests using CEM's were long-term tests. The results from this table
26
-------
TABLE 4-3. FLUIDIZED BED COMBUSTION EMISSION TEST DATA (28)
Plant owner
(location)
Iowa Beef Processors
(Amarillo.TX)
Idaho National
Engineering Labs
(Scoville.lD)
Sohio Oil Corp.
(Lima, OH)
Summerside CFB
(Prince Edward
Island, Canada)
Summerside CFB
(Prince Edward
Island, Canada)
Summerside CFB
(Prince Edward
Island, Canada)
California Portland
Cement (Colion. CA)
Type of
unit (a)
PSB
PBB
PBB
PBB
PBB
PBB
FEC
Boiler
capacity. MW
(million Blu/hr)
heal input
26.4 (90)
24.0(82)
28.4 (97)
14.7 (50)
14.7(60)
14.7 (50)
60.9 (208)
SO2 Emissions Data
Percent
sulfur
in coal
4.2
0.85
3.6
6.0
6.5
5.7
0.43
• VIWVIH
of
lul
load
59
56
72
72
66
56
too
Ca/S
ratio
3.1
ND(e)
NA
3.7
45
72
NA
Sorbent
type
Dolomite
Limestone
Limestone
Limestone
Limestone
Limestone
Limestone
Sorbenl
size
(millimeters)
16x21.7
3.2 x 0.8
6.3x0
2.4 x 0.8
6.3x0
2.4 x 0.8
0.125x0.039
Bed
temperature Recycle
(degrees C) ratio
878 (763) (c) 0
NA(f) 0
NA 0
837 ND(fl)
838 ND (g)
799 ND(g)
NA by design
SO2 removal Outlet SO2
efficiency
(percent)
91
86
90
94
91
99
82
emissions
(ng/J) (b)
258
69
267
258
430
26
56
Emission
test method
(test duration)
(«0
CEM (1 day)
CEM (67 days)
EPA-6 (3 hours)
CEM (7.5 days)
CEM (15 hours)
CEM (5 hours)
EPA-8 (3 hours)
(a) PSB - Packaged staged bubbling bed; PBB - Packaged bubbling bed;
FEC . Field-erecied circulating bed.
(b) Divide ng/J by 430 for conversion to to/million Blu.
jc) Number In parentheses is the desuMurization bed temperature. Number not
in parentheses is the combustion bed temperature.
fd) CEM - certified continuous emission monitor; EPA-6 - EPA Reference Method 6
EPA-8 - EPA Reference Method 8.
(e) ND > not determined; the Ca/S ration could not be determined at this site
because the coal and limestone feed rates were inaccurate.
(0 NA - Not available.
(g) ND - Not determined; at this site, solids were recycled to the boiler, but
the rale of solids recycled was not determined for the above tests. However,
the recycle ratio was estimated as 4.0 at lest conditions similar to those for
the 7.5-day lest as reported in this table.
-------
show that S02 removal efficiencies ranged from 86 to 99 percent for tests on
the four bubbling bed boilers. The outlet SO- emissions for a 15 MW
(50 million Btu/hour) bubbling bed boiler at Prince Edward Island,
Nova Scotia, ranged from 69 ng/J (0.16 ID/million Btu) when firing a
5.7 weight percent sulfur coal and operating at a calciura-to-sulfur (Ca/S)
ratio of 7.2:1 to 420 ng/J (0.98 Ib/million Btu) when firing a 6.5 weight
percent sulfur coal and operating at a Ca/S ratio of 3.1:1. This
77
corresponds to 99 and 91 percent SO- removal efficiency, respectively.i/
In addition to the three test results reported in Table 4-3 for the
15 MW (50 million Btu/hour) boiler at Prince Edward Island, emission data
were collected for the entire test period of 30 days. Figures 4-2 to 4-4
show the trends in SO- removal efficiency, Ca/S molar ratio, and boiler
load, respectively, for the entire test period. The results shown in these
figures are based on daily average data. The daily average SOg removal
efficiency ranged from 73 to 97 percent, averaging 93.5 percent. The lower
daily average SO- removal efficiency of 73 percent on day 10 was attributed
to operating the boiler at a low Ca/S ratio of 2.5:1.
Emission data for the first 7.5 days of continuous operation from the
FBC boiler at Prince Edward Island were analyzed for SO- emission reduction
variability.^^ This time period represented the longest continuous
operating period for which emission and operating data were collected.
During this period, the FBC unit operated at 94 percent mean SO- reduction
efficiency. The results of variability analyses applied to the SO-
reduction data of this period indicate that a long-term mean of at least
91.3 percent SO- reduction would be required to comply with a 90 percent SO-
reduction limit based on a 30-day rolling average with no more than one
exceedance every 10 years. If the mean SO- reduction performance of
93.5 percent measured in the 7.5 day test were maintained at full load, then
the FBC unit would exceed the level (i.e., 91.3 percent S02 reduction)
required for compliance with a 90 percent SO- reduction specification using
a 30-day rolling average.
Although these performance levels are based primarily on bubbling bed
designs, equal or better performance is expected from circulating and dual
bed systems because of more rapid carbon burnout, higher limestone particle
28
-------
*S02
Removal
100
90-
80-
70
60-
50-
40-
30 •
20
10
0
Average S02 Removal * 93.55
10 15 20 25 30
Test Days
Figure 4-2. Dally average S02 removal efficiency fop the
F3C boiler at Prince Edward Island.29
-------
Ca/S Ratio 4-
Average Ca/s ratio » 4.0
10 15 20 25 30
Test Days
Figure 4-3. Dally average Ca/S molar feed ratio for the
FBC boiler at Prince Edward Island.30
30
-------
80 -r
70-
60-
50-
Boiler Load 40-
30-
20-
10-
0--
Average boiler load * 70.6
10 15 20
Test Days
25
30
Figure 4-4. Dally average boiler load for trte FBC
boiler at Prince Edward Island.31
31
-------
densities in the freeboard area, and more uniform gas-solid contact between
SO- and limestone. These factors are discussed in more detail in
Reference 32.
The SO- removal efficiency of FBC systems can vary during load swings.
Changes in coal feed rate and coal sulfur content result in imbalances in
the calcium-to-sulfur ratio of the fluidized bed. To maintain a constant
SO- removal efficiency, this parameter must be adjusted during load swings
by adjusting the limestone feed rate. Alternatively, the fluidized bed can
be operated with a higher-than-required calcium-to-sulfur ratio to
accommodate transient increases in boiler load (i.e., coal feed rate) or
coal sulfur content. With proper design and operation of the FBC system,
consistently high SO- removal rates can be maintained during fluctuations in
boiler load.
"As a result of the above-described technical analysis of FBC units, the
ability of FBC units to continuously reduce SO- emissions by 90 percent or
more on a 30-day rolling average is considered demonstrated.
4.8 ALTERNATIVE CONTROL LEVELS
The evaluation of SO- control techniques for small coal-fired boilers
indicates that use of low sulfur coal, sodium scrubbing FGD systems, dual
alkali FGD systems, lime/limestone FGD systems, lime spray drying FGD
systems, and FBC units are demonstrated techniques which can serve as the
technical basis for developing NSPS for small boilers. Low sulfur coal
combustion will reduce SOj emissions to 520 ng/J (1.2 ID/million Btu) or
less. This, therefore, is selected as Alternative Control Level 1.
Flue gas desulfurization systems and FBC units are capable of
90 percent S02 reduction. Consequently, 90 percent SO- reduction is
selected as Alternative Control Level 2.
32
-------
5.0 REFERENCES
1. U.S. Environmental Protection Agency. Small Steam Generating Unit
Characteristics and Emission Control Techniques. Research Triangle
Park, N.C. March 31, 1989.
2. U.S. Environmental Protection Agency. Fossil Fuel Fired Industrial
Boilers - Background Information. Volume I. Research Triangle Park,
N.C. Publication No. EPA-450/3-82-006a. March 1982.
3. U.S. Environmental Protection Agency. Industrial Boiler S02 Technology
Update Report. Research Triangle Park, N.C. Publication No.
EPA-450/3-85-009. March 1985.
4. White, David and Edward Moretti (Radian Corporation). Production of
Very Low-Sulfur Residual Fuel Oils. Prepared for U.S. Environmental
Protection Agency. Research Triangle Park, N.C. April 10, 1987.
5. Energy and Environmental Analysis, Inc. Small Boiler NSPS Impacts on
Oil Markets. Prepared for U.S. Environmental Protection Agency.
Research Triangle Park, N.C. November 19887
6. Reference 3.
7. U.S. Environmental Protection Agency. Summary of Regulatory Analysis
New Source Performance Standards: Industrial-Commercial-Institutional
Steam Generating Units of Greater than 100 Million Btu/hr Heat Input.
Research Triangle Park, N.C. 1986.
8. Reference 1.
9. Reference 1.
10. Reference 3, p. 2-46.
11. Reference 3, p. 2-47.
12. Reference 2, pp. 4-163 through 4-168.
13. Reference 7.
14. Giguere, G.C., et al. (Radian Corporation). Determination of Mean S02
Emission Levels Required to Meet a 1.2 Lb SOVMillion Btu Emission
Standard for Various Averaging Times and Compliance Policies. Prepared
for U.S. Environmental Protection Agency. Research Triangle Park, N.C.
Contract No. 68-02-3816. March 1985. p. B-3.
15. Technical note from Margerum, S.C. and G. Giguere, Radian Corporation,
to J.A. Eddinger, EPA:ISB. July 1985. Variability of S0? Emissions
from Low Sulfur Coal-Fired Industrial Boilers.
33
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16. Dunbar, D.R. (PEDCo Environmental, Inc.). Typical Sulfur Dioxide
Emissions from Subpart D Power Plants Firing Compliance Coal. Prepared
for U.S. Environmental Protection Agency. Research Triangle Park, N.C.
EPA Contract No. 68-02-3152. May 1984. 88 pp.
17. Struthers-Andersen. Points to Consider in Evaluation of Sulfur Dioxide
Emission Control Systems for Steam Generators in the Oil Fields.
Atlanta, Ga. November 1980. p. 1.
18. Huckabee, D.S., S. Diamond, T. Porter, and P. McGlew. (GCA
Corporation). Continuous Emission Monitoring for Industrial Boilers,
General Motors Corporation assembly Division, St. Louis, Missouri.
Volume I: System Configuration and Results of the Operational Test
Period. Prepared for U.S. Environmental Protection Agency. Research
Triangle Park, N.C. EPA Contract No. 68-02-2687. June 1980.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
Reference
1.
DeBose, D.A., et al . (Radian Corporation). Statistical Analysis of Wet
Flue Gas Desulfurization Systems and Coal Sulfur Content, Volume I:
Statistical Analysis. Prepared for the U.S. Environmental Protection
Agency. Research Triangle Park, N.C. EPA Contract No. 68-02-3816.
August 18, 1983.
Reference
Reference
Reference
Reference
Reference
Reference
2,
7,
7,
7,
7,
7,
P
PP
PP
PP
PP
PP
. C-165
. 5-46
. 5-44
. 5-38
. 5-28
. 5-28
•
through 5-47.
through 5-47.
through 5-41.
through 5-36.
through 5-36.
U.S. Environmental Protection Agency. Statistical Analysis of Emission
Test Data from Fluidized Bed Combustion Boiler at Prince Edward Island,
Canada. EPA-450/3-86-015. December 1986.
Reference
Reference
Reference
Reference
Reference
1.
1.
1.
1.
7.
34
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
HSPORT NO.
EPA-450/3-89-12
2.
3. RECIPIENT'S ACCESSION NO.
TITLE AND SUBTITLE
Overview of the Regulatory Baseline, Technical Basis,
and Alternative Control Levels for Sulfur Dioxide (562)
Emission Standards for Small Steam Generating Units
5. REPORT DATE
May 1989
6. PERFORMING ORGANIZATION CODE
AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
PERFORMING ORGANIZATION NAME ANO ADDRESS
Emission Standards Division
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-4378
2. SPONSORING AGENCY NAME ANO ADDRESS
Office of Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT ANO PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA/200-04
5. SUPPLEMENTARY NOTES
6. ABSTRACT
This report provides a summary of the technical data used in developing proposed
new source performance standards (NSPS) for small industrial-commercial-institutional
steam generating units (small boilers). The report focuses on sulfur dioxide (S0£)
emissions from boilers firing coal and oil with heat input capacities of 100
million Btu/hour or less. Conclusions are drawn from the data regarding the per-
formance of technologies available to reduce S0£ emissions. Alternative control
levels are then chosen based on the conclusions drawn from the data.
KEY WORDS ANO DOCUMENT ANALYSIS
DESCRIPTORS
b.lOENTIFIERS/OPEN ENDED TERMS
COSATI Field/Group
Air Pollution
Pollution Control
Standards of Performance
Steam Generating Units
Industrial Boilers
Small Boilers
Air Pollution Control
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