EPA-450/3-77-050b
December 1977
ENERGY REQUIREMENTS
FOR CONTROLLING
SO2 EMISSIONS
FROM COAL-FIRED
STEAM/ELECTRIC
GENERATORS -
EXECUTIVE SUMMARY
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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EPA-450/3-77-050b
ENERGY REQUIREMENTS
FOR CONTROLLING SO2 EMISSIONS
FROM COAL-FIRED
STEAM/ELECTRIC GENERATORS -
EXECUTIVE SUMMARY
by
W.C Thomas
Radian Corporation
P.O. Box 9948
Austin, Texas 78766
Contract No. 68-02-2608
Project No. 8
EPA Project Officer: K.R. Durkee
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
December 1977
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This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - in limited quantities - from the
Library Services Office (MD-35) , Research Triangle Park, North Carolina
27711; or, for a fee, from the National Technical Information Service,
5285 Port Royal Road, Springfield, Virginia 22161.
This report was furnished to the Environmental Protection Agency by
Radian Corporation, P.O. Box 9948, Austin, Texas 78766, in fulfillment
of Contract No. 68-02-2608, Project No. 8. The contents of this report
are reproduced herein as received from Radian Corporation. The opinions,
findings, and conclusions expressed are those of the author and not
necessarily those of the Environmental Protection Agency • Mention of
company or product names is not to be considered as an endorsement
by the Environmental Protection Agency.
Publication No. EPA-450/3-77-050b
11
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TABLE OF CONTENTS
Page
1. 0 BACKGROUND AND PURPOSE 1
2. 0 APPROACH 2
3.0 SUMMARY OF RESULTS 4
3.1 Design Assumptions 4
3.2 Comparison by S02 Control Methods 4
3.3 Comparison by S02 Control Level 11
3.4 Energy Penalty Projections 13
iii
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1.0 BACKGROUND AND PURPOSE
The existing New Source Performance Standard (NSPS) for
S02 emissions from coal-fired steam generators is 0.52 g S02/MJ
(1.2 Ib S02/106 Btu) of heat input. Depending on coal sulfur
content and heating value, compliance with this standard can be
achieved by means of flue gas desulfurization (FGD), coal desul-
furization, the use of low sulfur coal, or a combination of these
approaches. Since the promulgation of the S02 NSPS in 1971, im-
provements have been made in the performance and reliability of
FGD processes. Because of these improvements, public interest
groups have requested that the EPA promulgate more stringent S02
emission standards. Therefore, the EPA's Office of Air Quality
Planning and Standards (OAQPS) has undertaken a program to review
the existing NSPS. The study described in this report was done
to assist OAQPS in the review by providing information on the en-
ergy requirements of S02 control systems. The report answers the
following questions.
What are the amounts and types of energy required to
operate various S02 emission control systems?
How do these energy requirements compare to those of
steam generators without emission control systems?
How do projected energy requirements for emission con-
trol compare with projected national energy demands in 1987 and
1997?
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2.0 APPROACH
The study was based on an EPA model including 102 sys-
tems which are combinations of power plants and S02 control meth-
ods. The variables considered in the model are level of S02 con-
trol, method of S02 control, power plant size, and coal composi-
tion. The levels of each variable considered in this study and
the combinations of variables were defined by EPA as shown in
Table 1. Three levels of S02 control were considered. They in-
clude the existing NSPS (0.52 g S02/MJ heat input), 90 percent SO2
removal, and 0.22 g S02/MJ. Control methods considered include
regenerable FGD processes, nonregenerable FGD processes, trans-
portation of low sulfur coal to the Midwest, and a combination
of coal cleaning and nonregenerable FGD processes.
Energy requirements for the 102 model systems were cal-
culated by extrapolating "base case energy requirements. Base
case energy requirements for each S02 control method were calcu-
lated from material and energy balances. The base case was 90
percent S02 removal from the flue gas of a 500 MW power plant
burning 3.5 percent sulfur coal. Extrapolation factors which de-
scribe energy requirements in terms of flue gas rate and S02 re-
moved were defined. The extrapolation factors were used to cal-
culate energy requirements for all the power plant/S02 control
system combinations included in the model.
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TABLE 1. MODEL S02 EMISSION CONTROL SYSTEMS STUDIED
SO2 Control Level
Plant Sizes Considered, Mf FGD Processes Considered*
Coal
0.52 g SOj/KJ (1.2 Ib S02/10' Btu)
25, 100, 500, 1000
25, 100, 500, 1000
25, 500
25, 500
500
LS, L, MgO. W-L/A, D-A
LS, L
LS, L
3.5Z sulfur; 27.9 MJ/kg
7.0Z sulfur; 27.9 MJ/kg
0.6Z sulfur; 20.9 MJ/kg western coal
transported to a Midwest power plant
0.8Z sulfur; 25.6 MJ/kg western coal
transported to a Midwest power plant
2.3Z sulfur; 29.2 MJ/kg**
I
lo
I
90Z S02 Reaoval by FGD
0.22 g S02/MJ (0.5 Ib S02/10( Btu)
25,
25,
25,
25,
25,
25.
25,
25,
100, 500, 1000
100, 500, 1000
100, 500
100, 500
500
500
500
500
LS,
LS,
LS,
LS,
LS,
LS,
LS,
LS,
L, MgO, W-L/A, D-A
L, MgO, W-L/A, D-A
L
L
L
L
L
L
3
7
0
0
0
0
2
4
.5Z
.01
.8Z
.8Z
.81
.81
.3Z
.61
sulfur;
sulfur;
sulfur;
sulfur;
sulfur,
sulfur;
sulfur;
sulfur;
27.
27.
20.
25.
20.
25.
29.
29.
9
9
9
6
9
6
2
2
MJ/kg
MJ/kg
MJ/kg
MJ/kg
MJ/kg
MJ/kg
MJ/kg**
MJ/kg***
*LS - Linestone
L - Line
MgO - Magnesia Slurry
W-L/A - Wellnan-Lord/Allled
D-A - Double-Alkali
**Physlcally cleaned 3.5Z sulfur; 27.9 MJ/kg coal (40Z sulfur removal)
***Physically cleaned 7.0Z sulfur; 27.9 MJ/kg coal (40Z sulfur removal)
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3.0 SUMMARY OF RESULTS
The results of the study show how energy requirements
depend on SOa control method, level of control, and coal sulfur
content. It was found that energy requirements for S02 control
systems (expressed as energy required per unit of electrical
generating capacity) depend only slightly on plant size.
3.1 Design Assumptions
The energy requirements for operating flue gas
desulfurization systems were calculated based on the process
designs summarized in Table 2. The design assumptions for coal
cleaning processes are shown in Table 3. A unit train con-
sisting of 100 coal cars and five locomotives was the design
basis for coal transportation. Fuel consumption rates, transport
distance, train speeds at full and reduced power, and coal dust
blow-off losses were specified.
Table 4 shows calculated energy requirements for the
six processing operations in FGD systems. Particulate/chloride
removal, reheaters, and fans account for 65 to 90 percent ot
total energy requirements for nonregenerable FGD processes.
Sulfur recovery operations account for the majority of energy
requirements for regenerable FGD processes.
3.2 Comparison by SOa Control Methods
Figure 1 shows the energy required to meet the existing
NSPS of 0.52g S02/MJ using different S02 control methods for
several coal compositions. The total energy requirements are
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TABLE 2. PROCESS DESIGN BASES FOR FGD PROCESSES
i
Ul
i
FGD Process
Process Step Limestone
Particulate/Chlorlde Removal Venturi
SO 2 Scrubbing Mobile Bed
Reheat Indirect Stem
Re heater
Fans Induced Draft Fans
Sulfur Disposal/Recovery Lined Settling
Pond
Line
Venturi
Mobile Bed
Indirect Steaa
Reheater
Induced Draft Fan*
Lined Settling
Pond
MgO
Venturi
Venturi
Indirect Steaa
Reheater
Induced Draft Fans
Production of
Sulfuric Acid
Uellman- Lord/Allied
Venturi
Valve Tray
Indirect Steam
Reheater
Induced Draft Fans
Production of
Elemental Sulfur
Double-Alkali
Venturi
Mobile Bed
Indirect Steam
Reheater
Induced Draft Fans
Lined Settling
Pond
•Selection of processing techniques was baaed on data from the open literature which were representative of
commercially available systems.
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separated into the types of energy required, i.e., steam, fuel
oil, natural gas, electricity, and coal losses. Nonregenerable
FGD processes impose the lowest energy requirements. The combi-
nation of coal cleaning and nonregenerable FGD systems requires
three times the energy required by the FGD process alone. Trans-
portation of low sulfur western coal to the Midwest requires
25 to 100 percent more energy than combusting a high sulfur
eastern coal and using a nonregenerable FGD process.
TABLE 3. DESIGN ASSUMPTIONS FOR PHYSICAL COAL CLEANING FACILITY
40% sulfur removal
95% energy recovery efficiency
The electric power requirements for a
278 kg/s (500 ton/hr) cleaning plant
are 2980 kW.
The heat duty of a thermal dryer is
534 kJ/kg (230 Btu/lb) of coal dried.
One half of the clean coal product (the coal
fines) is thermally dried.
Heat for the thermal dryers is supplied by
burning a portion of the clean coal
product.
507o of the ash content of the coal is removed.
The average heating value of the clean coal is
29.2 MJ/kg (12,500 Btu/lb).
Figure 2 shows the energy required to meet a standard of 90%
S02 removal using different S02 control methods for several coal
compositions. Figure 3 shows energy requirements for meeting a
standard of 0.22 g S02/MJ. The energy requirements for different
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TABLE 4. ENERGY REQUIREMENTS FOR THE PROCESSING OPERATIONS IN FGD SYSTEMS
Energy Requirements for Flue Gas Desulfurization, MJ/s
FGD Process
Limestone
Lime
Magnesia Slurry
Wellman-Lord/Allled
Double- Alkali
Coal Sulfur
Content
3. 51
7. 01
3. 5*
7.0Z
3.5Z
7. OX
3. 51
7.0Z
3.5Z
7.0*
Raw Material
Handling and
Preparation
2.2
4.4
0.2
0.4
0.5
0.9
0.2
0.3
0.3
0.5
Partlculate/
Chloride
Removal
9.0*
9.0*
9.0*
9.0*
3.0
3.0
3.0
3.1
3.0
3.0
S02
Scrubbing
6.8
13.5
6.3
9.4
2.5
5.0
0.9
0.9
2.4
2.4
Reheat
18.3
18.5
18.3
18.3
15.3
IS. 4
16.8
17.3
18.2
18.2
Fans
10.4*
11.1*
10.2*
10.4*
14.7
16.1
18.3
18.8
14.9
14.9
Sulfur
Recovery/
Disposal
0.3
0.6
0.3
0.5
41.1
82.8
136
281
0.7
1.3
Total System
Energy
Requirements**
49.2
57.3
44.3
48.2
77.5
124
176
321
39.8
40.7
*Energy required by fans to overcome pressure drop associated with partlculate removal Is included In the particulate removal operation.
"Utilities and Services for the FGD processes account for the discrepancies In system totals.
Assumptions
500 MW power plant (net generating capacity)
901 SO: removal
Uncontrolled power plant net heat rate - 2640 J/kW-s
-
Uncontrolled power plant net heat rate - 2640 J/kW-s
Steam produced in Magnesia Slurry and Wellman-Lord/Allled process is used within the process.
Magnesia Slurry process produces sulfurlc acid as a by-product.
Wellman-Lord/Allied process produces sulfur as a by-product.
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I OIL ON «AS
I COAL CLIANINO ANO TNAIN WIMOAM 1.OSHS
I STIAM AND ILICTNICITV
) OIIStL FUIL OIL
O.ttlULFUN.
20.IMJIX
COAL
0.§» SULFUH.
tf.t MJ/k«
COAL
Figure 1. Energy requirements for S02 and particulate control
0.52g S02/MJ control level, 500 MW plant.
-8-
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LtQCNO:
| OIL OR «Ai
I ITIAM AW ILICTMCITV
O
i!
3.5% SULFUR
ar.auj/kg COAL
7* SULFUR O.t* SULFUR O.t* SULFUR
I7.9MJ/k| COAL t0.tMJ/kv COAL tl.VMJ/hf COAL
Figure 2. Energy penalties for S02 and particulate control
907o S02 removal control level, 500 MW plant.
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*.•% SULFU
tT.t UJ/h
COAL
T.0« SULFUR.
>?.«MJ/kt
COAL
Figure 3. Energy requirements for S02 and particulate
control - 0.22 g/S02/MJ control level, 500 MW
plant.
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control methods have the same relative variations for the more
stringent standards as those for meeting the existing standard.
Table 5 summarizes the energy requirements shown in Figures 1
through 3 for combusting a 3.5 percent sulfur coal.
TABLE 5. ENERGY PENALTIES ASSOCIATED WITH DIFFERENT
METHODS OF CONTROLLING S02 EMISSIONS - 500 MW
PLANT, 3.5% SULFUR COAL
S02 Control
Process
Nonregenerable FGD
Limestone
Lime
Double- Alkali
Regenerable FGD
Magnesia Slurry
Wellman-Lord/Allied
Coal Cleaning Plus
Lime/Limestone FGD
Energy Penalty (% Energy Input To
Equivalent Uncontrolled Power Plant)
Level
0.52g S02/MJ
(NSPS)
3.4
3.0
3.0
5.3
11.7
9.8
of SOz Control
90%
Removal 0
3.8
3.4
3.0
6.1
13.2
NE
.22g S02/MJ
NE
NE
NE
NE
NE
9.8/10.2
NE = Not Examined
3.3 Comparison by SO; Control Level
Figure 4 shows how energy penalties depend on the level
of S02 control. Two levels of control are shown, the existing
standard and 90 percent SO2 removal. Ninety percent removal is
a more stringent level of control than the existing standard.
Figure 4 shows that for most control methods the energy penalty
for achieving 90 percent removal is about 10-15 percent higher
than that required to meet the existing NSPS.
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09
I
cd
c
0)
PH
bO
fc
0)
360 -
340 -
320-
300-
280 -
260 .
*
!
180 -
160-
140-
120 -
100-
80-
Physical Coal Cleaning and
Limestone or Lime FGD
©
Transporting Low Sulfur Western
Coal to Midwest-No FGD
Basis:
500 MW plant;
2640 J/kW-s net heat rate;
3.5Z sulfur,
27.9 MJ/kg coal
Double-Alkali FGD
0.52 g S02/MJ
(NSPS)
90% SO2
Removal
Level of Control of SO: Emissions
Figure 4. Energy penalties for S02 control
of effects of S02 control level.
- summary
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The results of the study also show that for combustion
of low sulfur western coal, 90 percent S02 removal requires up to
10 percent more energy than controlling emissions to 0.22 g S02/MJ
(0.5 Ib S02/106 Btu) of heat input. For low sulfur coals, 0.22 g
S02/MJ is more stringent than the existing NSPS but less stringent
than 90 percent removal.
For a "bare bones" S02 control system, the energy re-
quired for flue gas reheat and particulate/chloride removal is
excluded from the limestone and lime systems. This reduces the
energy requirements of these systems by 50 to 60 percent. For
the double-alkali, magnesia slurry and Wellman-Lord/Allied pro-
cesses, the particulate/chloride removal operation is required
to prevent buildup of chlorides in the S02 scrubbing liquor.
However, excluding flue gas reheat requirements would reduce the
energy required by the MgO system by 15 to 25 percent, the W-L/A
by about 10 percent and the double-alkali by about 50 percent.
3.4 Energy Penalty Projections
The energy penalties associated with S02 controls were
compared with projected total U.S. energy consumption for 1987
/
and 1997. Depending on control level, method of control, and
sulfur content of coal, the energy required to control S02 emis-
sions from new coal-fired power plants installed in 1983 through
1987 will be from 0.1 to 0.4 percent of total energy consumption
in 1987. For the new capacity installed in 1983 through 1997, the
energy penalty ranges from 0.4 to 1.7 percent of projected U.S.
energy consumption in 1997. These ranges are based on combusting
0.8 to 3.5 percent sulfur coal and controlling S02 emission to
the existing NSPS or effecting 90 percent S02 removal. Assuming
the majority of future S02 controls are limestone or lime FGD
systems, as is presently true, estimates for 1987 and 1997 would
be 0.1 percent and 0.4 percent, respectively.
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-450/3-77-0506b
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
The Energy Requirements for Controlling S02 Emissions
from Coal-Fired Steam/Electric Generators
5. REPORT DATE
January, 1978
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
W. C. Thomas
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
Radian Corporation
P. 0. Box 9948
Austin, Texas 78766
11. CONTRACT/GRANT NO.
68-02-2608
12. SPONSORING AGENCY NAME AND ADDRESS
Environmental Protection Agency
Office of Air Quality Planning and Standards (MD-13)
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The report is an executive summary of the main report (EPA-450/3-
77-050a). The main report is an analysis of the energy required by
various methods of reducing sulfur dioxide emissions from coal-fired
boilers. The energy required for limestone, lime, double alkali, mag-
nesium slurry and Wellman-Lord/Allied flue gas scrubbing systems is
presented. The variation of energy requirements with coal sulfur
content, emission level achieved and plant size is presented. The
energy required to transport low sulfur coal to the mid-west or to
physically clean sulfur from the coal is presented also.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
18. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (ThisReportI
Unclassified
21. NO. OF ?
18
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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