PB88-23419 0
Cost of Controlling Directly Emitted Acidic
Emissions from Major Industrial Sources
Radian Corp., Research Triangle Park, NC
Prepared for
Environmental Protection Agency
Research Triangle Park, NC
Jul 88
zass
as
0.& Etepsrtrrtsnt ef Conrcrce
Bstksssl Tcchnral Information Service
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PB8d-2J4iyG
EPA/600/7-88/012
July 1988
COST OF CONTROLLING DIRECTLY EMITTED
ACIDIC EMISSIONS FROM MAJOR INDUSTRIAL SOURCES
Prepared by:
T. E. Emmel, J. T. Waddell, and R. C. Adams
Radian Corporation
3200 Progress Center
Post Office Box 13000
Research Triangle Park, North Carolina 27709
EPA Contract Number:
68-02-3994
Task Assignments 13, 42, and 68
EPA Project Officer:
Julian W. Jones
U. S. Environmental Protection Agency
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
This study was conducted in cooperation with the
National Acid Precipitation Assessment Program
AIR AND ENERGY ENGINEERING RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK, NC 27711
REPRODUCED 8Y
U.S. DEPARTMENT OF COMMERCE
National Technical Information Service
SPRINGFIELD, VA. 221 SI
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TECHNICAL REPORT DATA
(Plane read Inunictivnt on the reverie before completing)
I. REPORT NO. 2.
EPA/600/7-88/012
3' &&CJPI1NT'S ACCESSIOttNO.
PBB8 -23 4 1907K
4. TITLE AND SUBTITLE
Cost of Controlling Directly Emitted Acidic Emis-
sions from Major Industrial Sources
6. REPORT DATE
July 1988
6. PERFORMING ORGANIZATION COOE
7. AUTHORISI
T. E. Emmel, J. T. Waddell, and R. C. Adams
8. PERFORMING ORGANIZATION REPORT NO.
DNC 86-203-023-13-18
9. PERFORMING ORGANIZATION NAME ANO ADDRESS
Radian Corporation
P. O. Box 13000
Research Triangle Park, North Carolina 27709
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3994, Tasks 13 and 40
12. SPONSORING AGENCY NAME AND AOORESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT ANO PERIOD COVEREO
Task Final; 2/85-8/86
14. SPONSORING AGENCY CODE
EPA/600/13
is.supplementary notes AEERL project officer is Julian W. Jones, Mail Drop 62, 919/541-
2489.
i6. abstractT^e rep0rt gives results of estimates, using a model plant approach, of
costs for retrofitting selected acidic emission control systems to utility and industrial
boilers, Claus sulfur recovery plants, catalytic cracking units, primary copper smel-
ters, coke oven plants, primary aluminum smelters, and municipal solid waste incin-
erators. Cost-effectiveness (defined as the unit annual cost for removing acidic ma-
terials) of each control system was calculated based on the anticipated performance
of the system. If S02 is simultaneously emitted with the acidic materials, controls
were selected which removed both S02 and the acidic materials. Cost-effectiveness
was considerably better for the combined (S02 plus acidic material) removal sys-
tems. Because of a need for performance data on acidic emissions control systems,
it would be desirable if research could be conducted on removing acid sulfates and
nitrates by existing gaseous and particulate control systems.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Croup
Pollution Catalytic Cracking
Emission Smelters
Acidification Copper Converters
Sulfur Dioxide Aluminum Industry
Sulfates Coking
Boilers Incinerators
Pollution Control
Stationary Sources
Acid emissions
Nitrates
Claus Plants
13 B 13H, 07A
14G 11F
07B.07C
05C
13 A
13. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
169
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
bog 19-9S
EPA Form 2220-1 (9*73)
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BIBLIOGRAPHIC INFORMATION
PB88-234190
Report Nos: DCN-86-203-023-13-18
Title: Cost of Controlling Directly Emitted Acidic Emissions from Major Industrial
Sources.
Date: Jul 88
Authors: T. E. Emmel, J. T. Waddell, and R. C. Adams.
Performing Organization: Radian Corp., Research Triangle Park, NC. A,vNational Acid
Precipitation Assessment Program, Washington, DC.
Performing Organization Report Nos: EPA/600/7-88/012
Sponsoring Organization: ^Environmental Protection Agency, Research Triangle Park,
NC. Air and Energy Engineering Research Lab.
Contract Nos: EPA-68-02-3994
Type of Report and Period Covered: Final rept. Feb 85-Aug 86,
Supplementary Notes: Prepared in cooperation with National Acid Precipitation
Assessment Program, Washington, DC. Sponsored by Environmental Protection Agency,
Research Triangle Park, NC. Air and Energy Engineering Research Lab.
NTIS Field/Group Codes: 68A, 99B
Price: PC A08/MF A01
Availability: Available from the National Technical Information Service,
Springfield, VA. 22161
Number of Pages: 169p
Keywords: *Air pollution control equipment, *Boilers, *Cost analysis, '"'Industrial
wastes, Performance evaluation, Mathematical models, Sulfur dioxide, Catalytic
cracking, Particles, Sulfates, Aluminum industry, Smelters, Incinerators, Coking,
Inorganic nitrates, *Acid gases, Claus process, Stationary sources, Copper
industry, Solid waste disposal.
Abstract: The report gives results of estimates, using a model plant approach, of
costs for retrofitting selected acidic emission control systems to utility and
industrial boilers, Claus sulfur recovery plants, catalytic cracking units,
primary copper smelters, coke oven plants, primary aluminum smelters, and municipal
solid waste incinerators. Cost-effectiveness (defined as the unit annual cost for
removing acidic materials) of each control system was calculated based on the
anticipated performance of the system. If S02 is simultaneously emitted with the
acidic materials, controls were selected which removed both S02 and the acidic
materials. Cost-effectiveness was considerably better for the combined (S02 plus
Continued on next page
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BIBLIOGRAPHIC INFORMATION
Continued... PB88-234190
acidic material) removal systems. Because of a need for performance data on acidic"
emissions control systems, it would be desirable if research could be conducted on
removing acid sulfates and nitrates by existing gaseous and particulate control
systems.
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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
The objectives of this study were: 1) to identify and characterize
stationary combustion and Industrial sources of directly emitted acidic
materials in the United States; 2) to evaluate the technical feasibility of
control techniques for these sources; and 3) to estimate the costs of
applying these control technologies. Sources of directly emitted acidic
materials were identified via a literature search. For most source
categories, emissions were estimated using emission factors and combustion
and process capacities found 1n the literature. To focus project funding on
source categories with the greatest emissions, model units were developed
for those sources which emit 4,500 Mg (5,000 tons) or more of acidic
material per year. These model units were then used as bases to establish
control technique? and determine control costs. Utility and industrial
boilers are the largest U. S. sources, emitting approximately 760,000 Hg
(830,000 tons) and 180,000-250,000 Hg (200,000-275,000 tons) of acidic
material per year, respectively. Total direct emissions of acidic materials
represent an estimated two percent of annual acid precipitation precursor
(SOg, N0X, and V0C) emissions from stationary sources. The greatest
obstacle in this study was the lack of available performance data for acidic
emissions control systems. Thus, the control systems chosen for model
development and cost estimation are generally those which are commercially
demonstrated for control of SOg and N0X and provide the greatest potential
for tjntrol of acidic material emissions. Promising research and
development activities relevant to acidic materials control were also
examined.
iii
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TABLE OF CONTENTS (Continued)
Section Page
5.3 Fluid Catalytic Cracking 5-17
5.4 Primary Copper 5-25
5.5 Coke Ovens 5-34
5.6 Primary Aluminum 5-40
5.7 Municipal Solid Waste Incinerators 5-44
5.8 References 5-47
6.0 Research and Development 6-1
6.1 Research and Development in Particulate Control 6-1
6.1.1 Electrostatic Precipitators 6-2
6.1.2 Fabric Filtration 6-4
6.1.3 Impact of Particulate R&D on Acidic Materials... 6-6
6.2 Electron-Beam Irradiation 6-7
6.3 Granular Bed Filter 6-9
6.4 References 6-11
APPENDICES
Appendix
A Derivation of Acidic Emissions Estimates A-i
B IBCOST and RCUCM Sample Tables B-i
v
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LIST OF FIGURES
Figure Page
6-1 Cold-Pipe Precharger 6-3
6-2 Reverse-Air "RIGID" Cage 6-5
6-3 E-Beam/Ammonia Process Flow Diagram 6-8
vi
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TABLE OF CONTENTS
Section Page
Abstract iii
List of Figures V1
List of Tables vii
Abbreviations and Symbols xi
1.0 Introduction 1-1
2.0 Results and Recommendations 2-1
2.1 References . 2-9
3.0 Summary of Acidic Emissions Estimates 3-1
4.0 Development of Model Units 4-1
4.1 Industrial and Utility Boilers 4-1
4.1.1 Model Boilers 4-1
4.1.2 Control of Acidic Emissions From Boilers 4-4
4.1.2.1 Sulfates, HC1, and HF 4-5
4.1.2.2 Nitrates 4-6
4.1.3 Model Control Systems 4-7
4.2 Claus Plants 4-7
4.3 Fluid Catalytic Cracking 4-12
4.4 Primary Copper 4-15
4.5 Coke Ovens 4-20
4.6 Primary Aluminum 4-25
4.7 Municipal Solid Waste Incinerators 4-30
4.8 References 4-33
5.0 Cost Analysis 5-1
5.1 Industrial and Utility Boilers 5-1
5.2 Claus Plants 5-13
iv
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LIST OF TABLES
Table Page
2-1 National Emissions Estimates for Identified Source
Categories 2-2
2-2 Summary of Controls Analyzed and Cost-Effectiveness 2-4
2-3 Performance Data for Acidic Materials Control 2-7
3-1 Summary of National Acidic Emissions Estimates 3-2
4.1-1 Model Units for Industrial and Utility Boilers 4-2
4.1-2 Model Control Systems for Boilers 4-8
4.2-1 Claus Plant Tail Gas Control Processes Constructed
Before 1983 4-9
4.2-2 Claus Process Model Plants 4-11
4.2-3 Tail Gas Control Processes Constructed in 1981 and 1982 4-13
4.3-1 Sulfate Emissions Data for FCC Unit Regenerators 4-14
4.3-2 Model Plants for Fluid Catalytic Cracking Units 4-16
4.4-1 Domestic Primary Copper Smelters 4-18
4.4-2 Model Plant for Primary Copper Smelters 4-21
4.4-3 Domestic Primary Copper Smelter Closures 4-22
4.5-1 Design Bases for Model Coke Plants 4-24
4.6-1 Extent of Potroom Control at Primary Aluminum Smelters,
1975 4-26
4.6-2 Model Control Modules for Installing Best Available Control
Technology for Primary Aluminum Smelters 4-28
4.6-3 Model Control Modules for Removal of Inadequate Existing
Control Equipment for Primary Aluminum Smelters 4-29
vi i
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LIST OF TABLES (Continued)
Table Page
4.7-1 Typical Municipal Solid Waste (MSW) Analysis 4-31
4.7-2 Model Municipal Solid Waste Incinerators 4-32
5.1-1 Analysis of Fuels Used for Model Cost Calculations 5-3
5.1-2 Performance Data for Selected FGD Systems 5-4
5.1-3 Costs of Flue Gas Desulfurization Systems for Industrial
Boiler Models 5-7
5.1-4 Costs of Flue Gas Desulfurization Systems for Utility
Boiler Models 5-7
5.1-5 Cost-Effectiveness Data for Industrial FGD Model Units:
Sulfate 5-8
5.1-6 Cost-Effectiveness Data for Utility FGD Model Units:
Sulfate 5-9
5.1-7 FGD Cost-Effectiveness for Coal-Fired Model Units:
HC1 and HF Control 5-10
5.1-8 Cost-Effectiveness for Removal of Acidic Materials by
Model FGD Systems 5-11
5.1-9 Total Cost-Effectiveness for Removal of S0? and Acidic
Materials by Model FGD Systems 5-14
5.1-10 N0X Control Costs for Model Boiler Units 5-16
5.2-1 Assumptions and Bases for Annual Costs 5-18
5.2-2 Costs for Model Claus Plants 5-19
5.2-3 Cost-Effectiveness for Control of Model Claus Plants -
Sulfate 5-20
5.2-4 Cost-Effectiveness for Control of Model Claus Plants -
S02 5-21
5.3-1 Performance Data for Sodium-Based Scrubbers on FCC Unit
Regenerators 5-23
viii
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LIST OF TABLES (Continued)
Table Page
5.3-2 Capital Costs for Sodium Scrubbing Systems Applied to
Fluid Catalytic Cracking Units 5-24
5.3-3 Bases and Assumptions for Determining Annual Costs of
Sodium-Based Scrubbing Systems Applied to Fluid Catalytic
Cracking Units 5-26
5.3-4 Annual Costs for High Energy Venturi Sodium-Based Scrubbing
Systems Applied to Fluid Catalytic Cracking Units 5-27
5.3-5 Annual Costs for Jet Ejector Venturi Sodium-Based Scrubbing
Systems 5-28
5.3-6 Cost-Effectiveness of SO Removal by Sodium-Based Scrubbing
Systems Applied to Fluid Catalytic Cracking Units 5-29
5.3-7 Cost-Effectiveness of Sulfate Removal by Sodium-Based Scrubbing
Systems Applied to Fluid Catalytic Cracking Units 5-30
5.4-1 Costs of Acid Plants Employed on Model Copper Smelter 5-31
5.4-2 Cost-Effectiveness Data for Acid Plants 5-32
5.4-3 Cost-Effectiveness Data for Acid Plants - SOg 5-33
5.5-1 Bases and Assumptions for Vacuum Carbonate Costs3 5-35
5.5-2 Capital Costs for a Vacuum Carbonate System Applied to
Model Coke Ovens 5-36
5.5-3 Annual Costs for a Vacuum Carbonate Systems Applied to
Model Coke Ovens (Retrofit) 5-37
5.5-4 Cost-Effectiveness Data for Vacuum Carbonate Systems
Applied to Model Coke Ovens - Sulfate 5-38
5.5-5 Cost-Effectiveness Data for Vacuum Carbonate Systems
Applied to Model Coke Ovens - SO2 5-39
5.6-1 Control Modules for Installing Best Available Control
Technology for Primary Aluminum Smelters 5-41
5.6-2 Control Modules for Removal of Inadequate, Existing
Control Equipment for Primary Aluminum Smelters 5-42
ix
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LIST OF TABLES (Continued)
Table Page
5.6-3 Example Retrofit Control Cost Scenarios for Primary
Aluminum Smelters 5-43
5.7-1 Assumptions and Bases Used in Cost Analysis for Sodium-Based
Scrubbers Applied to Model MSW Incinerators 5-45
5.7-2 Cost Results for Sodium-Based Scrubbers on Model MSW
Incinerators 5-46
6-1 Emissions Test Data for a Granular Bed Filter Applied
to a Copper Smelter 6-10
x
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ABBREVIATIONS AND SYMBOLS
actual cubic feet per minute
barrel
British thermal unit
Celclus
centimeter
Department of Energy
Fahrenheit
flue gas desulfurlzatlon
feet
glgajoule
hydrogen chloride
hydrogen fluoride
hour
hydrogen sulfide
kilogram
kilojoule
kilopascal
pound
long ton (equal to one megagram)
metal
megagram
milligram
minute
million Btu
nitrogen oxides
pulverized coal
parts per million (by volume)
pounds per square Inch
second
standard cubic feet per day
stream day
sulfur oxides
sulfur dioxide
tons per day
volatile organic compounds
xi
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1.0 INTRODUCTION
The Acid Precipitation Act of 1980 established an Interagency Task
Force to develop a comprehensive research program for investigation of acid
precipitation issues. The National Acid Precipitation Assessment Program
(NAPAP) was subsequently established to develop the necessary data and
provide a framework for policy recommendations in regard to acid
precipitations. One aspect of the overall acid deposition issue is to
understand the role and significance of direct emissions of acidic
materials. As such, it is necessary to identify the major industrial
sources of direct emissions of acidic material (e.g., sulfates, chlorides)
and to evaluate the control of these materials. In addition, it is
important to know if the most cost-effective methods for reducing acidic
emissions differ from those for controlling acid deposition precursors (S02,
N0X, and VOC).
Accordingly, the objectives of this study were: 1) to identify and
characterize stationary combustion and industrial sources of directly
emitted acidic materials in the United States; 2) to evaluate the technical
feasibility of control techniques for these sources; and 3) to estimate the
costs of applying these control technologies. This assessment was conducted
via review and analysis of existing data including the preliminary control
strategies evaluated by the Interagency Task Force. The potential for
emissions from transportation sources was not examined in this study.
Results of the study can be used to evaluate the merits of controlling
directly emitted acidic materials as part of a policy evaluation of overall
acid deposition control strategies. For example, if it were determined that
for a region local emissions of directly emitted acid materials were more
significant than long range precursor emissions, the information in this
report could be used to evaluate the cost effectiveness of controlling local
sources of directly emitted acidic materials versus sources of long range
precursor emissions.
1-1
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The results of the study are summarized 1n Section 2. To identify and
characterize sources of directly emitted acidic materials, national acidic
materials emissions of all combustion and industrial sources were identified
by means of a literature search (Section 3 and Appendix A). Model units
were then developed for those sources which emit 4,500 Mg (5,000 tons) or
more of acidic material per year (Section 4). The model units were used as
bases for establishing control techniques and for determining the technical
feasibility of candidate conventional control techniques. The cost of
control retrofits for the model units were estimated and cost-effectiveness
values were determined (Section 5). The cost-effectiveness of acidic
materials control was compared with the cost-effectiveness where applicable
of S02 which is co-emitted with acidic materials. Promising research and
development activities relevant to acid materials control were also examined
(Section 6).
1-2
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2.0 RESULTS AND RECOMMENDATIONS
The major combustion and industrial sources of directly emitted acidic
materials that were identified during this study are presented in Table 2-1.
For most source categories, emissions were estimated using emissions factors
and combustion and process capacities found in the literature. Utility and
industrial boilers are by far the largest acidic emissions sources in the
U.S., producing approximately 760,000 Mg (830,000 tons) and 180,000-
250,000 Mg (200,000-275,000 tons) of acidic material emissions per year,
respectively. The bases for all emissions data given in Table 2-1 are
discussed and referenced in both Section 3 and Appendix A. It was also
found that emissions of directly emitted acidic materials represent only
2 percent of the annual emissions of SOg, N0X and VOC (which are acid
precipitation precursors) from stationary sources.
Based on information obtained in the literature, model plants,
including the most applicable acidic material controls, were developed for
sources that emit over 4,500 Mg (5,000 tons) of acidic material per year.
This cut off point allowed the project funding to be focused on those source
categories with the greatest emissions. The major sources considered
include utility and industrial boilers, Claus sulfur recovery plants,
catalytic cracking units, primary copper smelters, coke oven plants, primary
aluminum smelters, and municipal solid waste incinerators. Although Kraft
pulp mills, gypsum plants, and cement plants are large sulfate emissions
sources, they were not selected for further analysis because the compounds
emitted are alkaline or pH neutral. In addition, gypsum ponds were
identified as a source category emitting large amounts of HF. However, HF
emissions from gypsum ponds are reduced by water treatment methods, whereas
this study focused primarily on controls which treat acidic gases. Thus, no
further analysis was attempted.
Little performance data is available concerning the control of acidic
emissions by currently operating control systems. Therefore, the systems
.2-1
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TABLE 2-1. NATIONAL EMISSIONS ESTIMATES FOR IDENTIFIED SOURCE CATEGORIES
Acid Sulfite Emissions Nltrato Emissions HC1 Emissions HF Emissions Total,Emissions Yoar
103 Mg/yr 103 Hg/yr) <10 Hg/yr) (ljT Hg/yr) (IT Hg/yr) Data
Source Catogory (10 tons/yr) (10^ tons/yr) (10 tons/yr) (10 tons/yr) (ltr tons/yr) Roportod
(1) Utility Bollors
Coal
Residual Oil
Olstlllato Oil
107 (117)
25 (28)
3.6 (4)
64 (70)
496 (546)
60 (66)
756 (031)
1980/1982
(2) Industrial Boilers
Coal
Rosldual Oil
Olstlllato Oil
20-81 (25-89)
5-10.4 (5.5-11.5)
27 (30)
32 (35)
88
(96)
10.6
(11.5)
182-248
(203-273)
1980/19
(3)
Municipal Solid Waste
20
(22)
20
(22)
—
(4)
Catalytic Cracking
11.3 (12.5)
11.3
(12.5)
1983
(5)
Primary Copper
8.6-10.4 (9.5-11.5)
8.6-10.4
(9.5-11.5)
1984
(6)
Primary Aluminum
0.18-0.41 (0.2-0.45)
5.9
(6.5)
6.1-6.3
(6.7-7)
1983
(7)
Gypsum Ponds
5.9
(6.5)
5.9
(6.5)
1980
(8)
Claus Plants
5.4 (6)
5.4
(6)
1980
(9)
Cofco Ovons
5 (5.5)
5
(5.5)
1983
(10)
Propyleno Oxldo
Manufacturing
2.7-4.1
(3-4.5)
2.7-4.1
(3-4.5)
1980
(11)
Residential Boilers
2.7
(3)
0.2
(0.25)
2.9
(3.25)
1974
(12)
Sulfuric Acid Plants
1.8 (2)
1.8
(2)
1982
(13)
Phosphoric Acid Plants
0.14
(0.15)
0.14
(0.15)
1980
(14)
Trlplo Super Phosphate
Manufacturing
0.18
(0.2)
0.18
(0.2)
1980
(15)
Primary Zinc
0.2 (0.25)
0.2
(0.25)
1983
(16)
(17)
D1 amnion 1 um Phosphate
Manufacturing
HF Manufacturing
0.2
0.01-1.2
(0.25)
(0.01-1.35)
0.2
0.01-1.2
(0.25)
(0.01-1.35)
1980
1980
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chosen for model unit development are generally those which are demonstrated
for control of SO^ and N0X and provide the greatest potential for control of
acidic material emissions.
Cost analyses w The combined cost-effectiveness values are included in
Table 2-2. The bases for data presented in Table 2-2 are discussed and
referenced in Section 5.
The greatest obstacle in this study was the lack of available
performance data for acidic emissions control systems. All test data that
could be readily obtained is summarized in Table 2-3. No information was
available concerning the control of acid nitrates. All test data for
removal of acid sulfates are presented in terms of H2S04 mist control and
show a wide range of removal efficiencies. Therefore, it would be desirable
if research efforts were directed toward quantitating the acid sulfate and
acid nitrate control performances of existing applicable gaseous and
particulate controls. While data for HC1 and HF removal are also lacking,
the need for research in this area is not urgent. This is because HC1 and
HF have high affinities to the alkaline solutions commonly used by FGD
systems and, as indicated by the limited test data, removal is expected to
be high.
The technologies identified as being most applicable to reducing
directly emitted acidic materials are wet/dry scrubbing techniques.
Conventional electrostatic precipitators and fabric filters are not as
effective because the acidic materials may still be in a gaseous state at
the operating conditions where these devices are typically located. As
such, it was concluded that the most cost effective control devices for,
2-3
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TARE J-2. SUM4ART Of CONTROLS ANALYZED AND COST-CFftCl I VEfcCSS
Cost-Cffflctlvoncss of RbmmI
Source Catogory/ fuol Acidic Spoclos Acidic Materia) Acidic Material • SO-,
Procoss Capacity Typo Control ControMod S/Hg (l/ton) S/Mg (l/ton)
Industrial Boilers6
JO.5 GJ/hr (30 WOtu/hr)
MSC
Sodlua-Gased Scrubber
Sulfates* HC1* \f
39*300
(35*700)
810
(740)
use
24*400
(22*200)
2.640
(2*400)
00
Sulfates
3S9.000
(327*000)
4*890
(4*440)
RO
492*800
(446*000)
1*110
(1.010)
use
Dual Alkali Scrubber
Sulfates* HCI. IF
66*100
(78*300)
1*770
(1.610)
LSC
66*000
(60*000)
7*130
(6*480)
00
Sulfates
999.000
(908*000)
13*600
(12*360)
RO
1*200*000
(1*090*000)
2*720
(2*470)
HSC
Llwo Spray Dryor
Sulfates. HCI* HF
72.600
(66*000)
1*910
(1*730)
LSC
59*900
(54*400)
7*930
(7*210)
DO
SuUatos
626*000
(569*000)
15.400
(14*000)
RO
704.000
(640.000)
2*920
(2*660)
406 GJ/hr (400 WBtu/hr)
HSC
Sodlust-Dased Scrubbor
Sulfatos. IC1* itf"
16*900
(17*200)
390
(350)
LSC
7.000
(6*300)
750
(680)
00
Sulfates
69*000
(81*000)
1*160
(1*070)
RO
200*000
(182*000)
450
(410)
HSC
Dual Alkali Scrubbor
Sulfates. HCI* If
20,600
(18*700)
420
(380)
LSC
11*400
(10*300)
1,220
(1*110)
00
Sulfates
1S6*000
(142*000)
2*060
(1*870)
RO
249*000
(276*000)
560
(510)
HSC
L1*e Spray Dryer
Sulfates. HCI* HF
21*700
(19*600)
560
(510)
LSC
14*300
(13*000)
1*810
(1*650)
00
Sulfates
119*000
(108*000)
2* 670
(2*610)
RO
172*000
(1S6*000)
710
(640)
lisc
Low Excoss Air
MO c
132
(170)
LSC
X
9
(8)
Coal
Ovorflro Air
NO C
X
112
(102)
lit 11 Itv Roll«irb
2.031 GJ/hr (7*000 WOtu/hr)
HSC
Llmestono Net Scrubbor
Sulfatus* HCI* If
64*700
(58*800)
1*130
(1,030)
LSC
52*600
(47*600)
4.960
(4*510)
RO
Sulfatos
291*000
(264*600)
2,350
(2* 140)
-------
TARE 2-2. 5UWAJ(Y 01 CUUlIHXS ANALY/IP AW) COST-tffLCTIVLHCSS (Continued)
Source Catogory/
Process Capacity
Fuel
Typ#
Control
Acidic Spoctos
Controllod
Cost-Effficttvonoss of Rooovat
Acidic Materia)
S/Mg (S/ton)
Acidic Material ~ SO
S/Hg (S/ton) 1
ro
I
cn
S.070 GJ/hr (5.000 HHQtu/hr)
CUus Plants
10 Mg/day (11 tons/day)
100 Mg/day (110 tons/day)
2S0 Mg/day (275 tons/day)
HSC
NollMn-lord Systeti
Sulfates* IC1, if
94*600
(66,000)
1*660
(1,510)
LSC
62*800
(57*100)
5*930
(5*390)
HSC
Lit* Spray Oryor
Sulfatos. ICl* W
62.100
(56*500)
1.140
(1,040)
LSC
47*300
(43*000)
4,650
(4*230)
Coal
Low NO Bornors
X
M0C
X
123
(112)
—
Coal
Low Excoss Air
NO C
7
(6)
__
on
X
2
(2)
Coal
Overflro Air
NO C
96
(87)
on
X
131
(119)
—
HSC
LlMstono Wot Scrubber
Sulfatos. HC1, \f
45*700
(41*600)
600
(730)
LSC
37.600
(34*200)
3*550
(3*230)
RO
Sulfatos
229*000(200*000)
1*850
(1*680)
HSC
Vollaan-Lord Systoa
Sulfates* HC1* If
74*300
(67,600)
1*300
(1*190)
LSC
49*400
(44*900)
4*670
(4,240)
HSC
11m Spray Dryer
Sulfatos. IC1. if
48*000 (43*600)
880
(800)
LSC
35*300 (32*000)
3,460
(3,150)
Coal
Low NO Burners
X
NO c
X
71
(64)
Coal
Low Excess Air
NO C
3
(3)
Oil
X
1
(1)
Coal
Overftre Air
NO C
56
(51)
on
X
83
(75)
Amino Tall Gas
Sulfatos
242*800(220*300)
2*420
(2.200)
Treatment
77*200 (70*000)
770
(700)
54,900 (49*000)
550 (500)
-------
TAKE 2-2. SUWARY Of CONTROLS ANALYZED AW COST-tH [CIIVCNESS (ContlnuoJ)
Sourco Category/
Procoss Capacity
Fuol
Typo
Control
Acidic Spoclcs
Controllod
CoH-Effftctlvonflis of Ramoval
Acidic HitorUl
t/Hg (t/ton)
Acidic Material « SO.
J/Hg (1/ton) 1
ro
I
CTl
Fluid Catalvt1r
Cr«cKlna Units
7.500 a3/sd (15.72S bbt/sd)'
Prlmrv Cooper Sxltori
115.000 Mg/yr (127.000 tons/yr)
Ceha Own Plants
2000 Mg/day (2200 tons/day)
6000 Mg/day (6600 tons/day)
HjnUlBil Solid Mflsta
IHSW)
360 Mg/day (420 tons/day)
730 Mg/day (600 tons/day)
ISF"
ISf*
HSF
kSV
HSW
SodluwOased Scrubber
Sulfuric Acid Plant
Vacuus Carbonato Systoa
Sodlue-Gased Scrubber®
Sulfates
Sulfatos
Sulfates
HC1
93.640 (64.950)
63,450 (S7.S60)
62*560 (56.770)
47.830 (43.390)
9.800 (6.900)
11.700 (10.600)
6.900 (6.300)
1*900 (1.730)
1.460 (1.340)
1.090 (990)
740 (670)
730 (660)
560 (510)
130 (120)
950 (870)
570 (S20)
1.020 (1.120)
970 (660)
are given In
wt. S S).
HSC • high-sulfur coal; ISC ¦ low-sulfur coali DO • dtstlllato oil) RO • residual oil,
^Boiler capacities presented In tems of heat Input.
CNo emissions data, specifically In tems of acid nitrate Missions, were available. Thus, all cost effectiveness results
tems of controlling K>x emissions.
^Catalytic cracking unit feed rather than fuel. ISF - Intemedtate-sulfur feed (1.5 «t. % S); HSF ¦ high-sulfur feed (3.5
*H1gh energy venturl scrubber using soda ash-based scrubbing liquor.
^Single stage acid plant.
deploys caustic soda-basod scrubbing liquor.
^Excludes benefits of concurrent SO, reductions.
I 3
¦ /sdi cubic aeter per streaa day
bbl/sdt barrel per streaa day.
-------
TABLE 2-3. PERFORMANCE DATA FOR ACIDIC MATERIALS CONTROL3
Acidic
Concentration
(DDmv)
Percent
Material
Inlet
Outlet
Removal
Source
H2S04b
20 - 30
4 - 10
33 - 80
Reference 1
h2so4c
2.6
1
61
Reference 1
h2so4c
3 - 9
1 - 5
44 - 67
Reference 1
h2so4c
4 - 19
1 - 8
39 - 78
Reference 2
HC1c
---
---
94 - 100
Reference 2
HFC
...
...
93 - 99
Reference 2
aAll data apply to utility wet FGD systems. Presented as ranges of test
data for particular systems.
^FGD employed on oil-fired boiler.
CFGD employed on coal-fired boiler.
2-7
-------
sulfates, fluorides and chlorides are the same controls that would be em-
ployed for SO^. Conventional combustion modification techniques, used to
control N0X emissions from boilers, were identified as the best commercially
available methods for reducing nitrate emissions.
2-8
-------
2.1 REFERENCES
1. Telecon. Balfour, D. W., Radian Corporation, Austin, Texas with
Waddell, J. T., Radian Corporation, Research Triangle Park, North
Carolina. 27 August 1985.
2. Smith. E. 0., et al_. (Black & Veatch Consulting Engineers), Full-Scale
Characterization of Conesville Unit 5, prepared for Electric Pov/er
Research Institute, Palo Alto, California, EPRI CS-2525, August 1982.
\
2-9
-------
3.0 SUMMARY OF ACIDIC EMISSIONS ESTIMATES
Identification and characterization of acidic material emissions from
industrial and combustion sources in the U.S. were accomplished through a
literature search. The specific compounds examined include sulfates, HC1,
HF, and nitrates. Sulfate emissions were further examined to identify
acidic content. Acid sulfate emissions, for the purpose of this study, can
be defined as that portion of total sulfate emissions which would readily
become acid deposition. If determined by the controlled condensation system
(CCS) test method, for example, this would include free HgSO^ and S03.
Similarly, acid nitrate emissions can be defined as that portion of total
nitrate emissions which would readily become acid deposition, (e.g., HN03).
Table 3-1 presents the acidic emissions estimates for each source
category identified, as well as the information sources used. A ,.iore
detailed discussion of how the estimates were derived can be found in
Appendix A.
Table 3-1 identifies the sources of emissions data. Work Group 3B
(WG3B) emissions estimates and the NAPAP emissions inventory were used if
possible. Otherwise, most emission factors came from EPA sources. Total
emissions were derived by multiplying the emissions factors by industry
capacities taken from EPA, DOE, Bureau of Mines or industry sources. An
emission factor for nitrates from coal-fired utility boilers was reported in
one reference and was assumed to apply for coal-fired industrial boilers
also. Emission data for N0X was available for several industrial processes
(HN03, adipic acid, organic nitrogen, nitrocellulose) but nitrate emissions
data was not available.
The national total of acidic material emissions from stationary sources
is approximately 1.0 to 1.1 million Mg (1.1 to 1.2 million tons) per year.
This equals about 2 percent of the annual national emissions of the acid
precipitator precursors, SOg, N0X, and volatile organic compounds (VOC) from
sources other than transportation. In the U. S.-Canadian Memorandum of
3-1
-------
TAat 3-1. simwr or
NATIONAL
ttlOlC EMISSIONS ESTINA1ES
Sourco Category
Acidic
Speclos Eatttod
Ealsslons Estlaato
thousand Mg/yr
(thousand tons/yr)
Derivation of Est1nate'*b
Utility Dollar*
Coal-fired
4Cld Sulfite
107
(117)
Ealsston factors derived froa Referonces 2$ 5# 6 and
WG-3B (Reforence 1) Multiplied by coeftustlon capacity
reported In Reference 7.
HC1
496
(546)
Ealsston factor given In Reference 33 njltlplled by
coebustlon capacity reported In Referonce 7.
60
(66)
Enlssfon factor reported In Roference 33 aulttplled
by coobustlon capacity reported In Reference 7.
nitrate
64
(70)
Ealsston estimate presented In Roference 44.
Residual oil-fired
acid sulfat*
25
(28)
Ealiston factor given In Reference 2$ ealsston factor
derived fro* ealsslons data (Reference 2), and
cotftustlon capacity reported In Reference 0.
Distillate oll-fIred
acid sulfate
3.6
(4)
Ealsston factor derived fro* Reference 2 and VG-3B
(Reference 1) and cortustlon capacity reported In
Reference 8.
Industrial Boilers
Coal-fIred
acid sulfate
20-61
(25-89)
Ealsston factor presented tn Reference 2 and
Mission factor derived froa oalsstons data
(Reference 2) aulttplled by coetustlon capacity
presented tn Reference 7.
HC1
88
(96)
Ealsston factor presented In Reference 33
aulttplled by coebustton capacity reported In
Reference 7.
10.4
(11.5)
Ealsston factor given In Reference 33 aulttplled
by coafcustton capacity presented In Reference 7.
nitrate
32
(35)
Ealsslons estlaate presented In Reference 44.
-------
TABLE 3-1. SlWAfiT Of
NATIONAL ACIDIC EMISSIONS ESTIMATES (Continued)
Source Catogory
Acidic
Spocles Eattted
Eatsstons Estlaate
thousand Mg/yr
(thousand tons/yr)
Dortvatton of Estimate4'**
Rosldual oll-ftrod
add sulfate
5-10.4
(5.5-11.5)
Emission factor prasentad (n Rofaranca 2 and
oalssfon factor dorlved froa omissions data
(Rofaranca 2) Multiplied by covtustlon capacity
reported tn Raforonca 6.
Distillate oll-flrod
*cld sulfate
77
(30)
Emission factor derived froa Reference 2 and WG38
(Reference 1) Multiplied by coaoustlon capacity
reported In Reference 6.
fejnlcloal Solid Waste
HC1
20
(22)
Ealsslon factor given In Reference 33 Multiplied by
combustion capacity reportod In Reforence 30.
CiUlvtlc CriChlDa
•cfd sulfate
11.3
(12.5)
HG3B (Reforence 1) ealsslon factor Multiplied by
process capacity reported In Referonce 19.
Primarv Coooer
acid sulfate
0.6-10.4
(9.5-11.5)
Ealsslon factor presented tn Reference 24 and
ealsslon factor derived froa MG3B (Reference 1)
estfaates aulttplled by process capacity reportd
1n Reference 23.
Prfnarv Alualnua
*c1d sulfate
0.16-0*41
(0.2-0.45)
Ealsston factors derived froa HOB (Refererce 1)
and Reference 4 Multiplied by procass capacity
reported 1n Reference 20.
5.9
(6.5)
Ealsslon factors presented in Reference 33
aultlplled by process capacity reported 1n
Reference 43.
frraaum Panda
acid sulfate
5.9
(6.5)
Ealsston factor given In Reference 40 Multiplied by
process capacity presented In Reference 41.
Clau* Plants
acid sulfate
5.4
(6)
Ealsslon factor given In Reference 2 aultlplled
by process capacity reported 1n Reference 29.
CcfcB Ovens
actd sal fata
S
(S.5)
Ealsslon factor given In Reference 2 aultlplled
by process capacity reported tn Reforence 9.
Proovlsne Oxlda HAnufacturlnn
HC1
2.7-4.1
(3-4.5)
Ealsslon factor derived froa Reference 36
Multiplied by process capacity presented In
Reference 37.
-------
TAlir 3-1. SUWART OF NATIONAL ACIDIC EMISSIONS ESTIMATES (Contfnuod)
Soure• Category
. Acidic
Spocles Emitted
Cnls&fons Estimate
thousand Mg/yr
(thousand toos/yr)
Dortvatlon of Estimate*'1*
Sulfuric Acid Plants.
acid sulfate
1.6 (?)
KG3B (Reference 1) emission factor multiplied by
process capacity reported In Reference 12.
Phnsjihnrlc Acltf Plant*
If
0.14 (0.1S)
Emission factor given In Reference 40 multiplied
by process capacity reported In Reference 41.
Level of control of txlstlng plants unavatlabloj
range represonts assumptions of S0-100 porcent of
plant capacity controlled.
PrtaiTY Zinc
acfd sulfate
0.2 (0*25)
Emission factor given In Reference 2 mltlplled by
process capacity reported in Reference 25 and
estimates of existing control (Reference 2*
Reference 26).
Trlplfi.Supflr Phasohitfl
Manufacture
t€
0.18 (0.2)
Emission factor glvon In Reference 42 njltlplled by
process capacity given In Reference 41.
Cluaonlua Phouhato
Manufacturfna
if
0.2 (0.25)
Emission factor presented In Referonce 42 multiplied
by assumed procoss capacities (basod on Information
presented In Roference 41).
VT Manufacturlnn
HF
0.01-1.2 (0.01-1.35)
Emission factors given In Reference 33 ultlplled by
process capacity reported In Reference 33. Level of
control on existing plants unavailable; range
represents assumptions of 50*100 percent of plant
capacity controlled.
*AU references art presented it the end of Appendix A.
^NG3B - forking Group 3B (Reference 1),
-------
Intent on Transboundary Air Pollution, Working Group 3B reported that the
national emissions of SOg, N0X> and VOC in 1980 were 23.3, 10.8, and
16.9 million Hg (25.6, 11.9, and 18.6 million tons), respectively, for
sources other than transportation. This totals 51.0 million Hg
(56.1 million tons) of acid precipitation precursors as compared to 1.0 to
1.1 million Hg (1.1 to 1.2 million tons) of directly emitted acidic
materials.
3-5
-------
4.0 DEVELOPMENT OF MODEL UNITS
Model units were developed for the combustion and industrial source
categories with estimated acidic material emissions greater than 10 million
pounds per year. A literature search was done to identify representative
sizes, process components, operational parameters, and demonstrated
emissions control equipment for each source category selected. The model
units are based on this information.
Sources chosen include industrial and utility boilers, Claus plants,
fluid catalytic cracking units, primary copper smelters, coke ovens, primary
aluminum smelters, and municipal solid waste incinerators. These categories
are discussed in Sections 4.1 through 4.7.
4.1 INDUSTRIAL AND UTILITY BOILERS
4.1.1 Model Boilers
Utility and industrial boilers are the largest emitters of sulfates,
nitrates, chlorides, and fluorides. An extensive amount of boiler control
technology cost data have been developed by EPA under standards development
and research programs. Costing models for commercial and developmental
technologies are available for a wide range of sizes and types. For this
study the model plant sizes and types selected are consistent with those
used in the development of the utility and industrial boiler New Source
Performance Standards. Therefore, the cost data for control technology
for this program is well documented.
Table 4.1-1 show- the characteristics of the model plants used for
industrial and utility boilers. These characteristics cover most of the
differences in boilers found at various sites. The principal boiler fuels
are coal, residual oil, distillate oil and natural gas. Significant amounts
of acidic emissions are not produced by natural gas-fired boilers;
therefore, model boilers were chosen to represent the other three commonly
used fuels. Since coal properties such as sulfur and ash content can vary
4-1
-------
TABLE 4.1-1. MODEL UNITS FOR INDUSTRIAL AND UTILITY BOILERS
Heat Input
Capacity
Fuel GJ/hr (106 Btu/hr) Boiler Configuration
High-Sulfur Coal
30.5
(30)
Package, watertube, underfeed
stoker
Low-Sulfur Coal
30.5
(30)
Package, watertube, underfeed
stoker
Distillate Oil
30.5
(30)
Package, firetube
Residual Oil
30.5
(30)
Package, firetube
High-Sulfur Coal
406
(400)
Field erected, watertube, PC
Low-Sulfur Coal
406
(400)
Field erected, watertube, PC
Distillate Oil
406
(400)
Field erected, watertube
Residual Oil
406
(400)
Field erected, watertube
High-Sulfur Coal
2,031
(2,000)
Field erected, watertube, PC
Low-Sulfur Coal
2,031
(2,000)
Field erected, watertube, PC
Residual Oil
2,031
(2,000)
Field erected, watertube
High-Sulfur Coal
5,078
(5,000)
Field erected, watertube, PC
Low-Sulfur Coal
5,078
(5,000)
Field erected, watertube, PC
Residual Oil
5,078
(5,000)
Field erected, watertube
4-2
-------
considerably, model boilers were selected for both low sulfur coal (LSC) and
high sulfur coal (HSC) applications. Representative boiler design
capacities within each fuel type were then selected to cover the range of
expected capacities for the utility and industrial boiler populations.
Four size categories were chosen for model boilers. These were 30.5,
406, 2,031, and 5,078 GJ/hr (30, 400, 2,000 and 5,000 million Btu/hr) of
thermal input. Capacities of industrial boilers range from less than
1.52 GJ/hr (1.5 million Btu/hr) to greater than 508 GJ/hr (500 million
Btu/hr).* The majority of boilers at the lower end of the capacity range
are used for space heating whereas the boilers at the upper end of the
capacity range are generally used for process steam and, in some cases,
electric power generation. The 30.5 and 406 GJ/hr (30 and 400 million
Btu/hr) size ranges were chosen as representative of small and large
industrial boilers. Utility boilers tend to be much larger than industrial
boilers and can have thermal inputs as large as 15,230 GJ/hr (15 billion
Btu/hr). The 2,031 and 5,078 GJ/hr (2,000 and 5,000 million Btu/hr)
categories were chosen as representative of utility boilers.
In addition to fuel type and capacity, boilers also vary according to
heat transfer configuration. The three basic heat transfer configurations
are cast iron, firetube, and watertube. Cast iron boilers are usually small
and so contribute very little to national emissions. Therefore, a model
plant representing cast iron boilers was not included.
In firetube boilers, the products of combustion flow through tubes that
are surrounded by water. These units range in size from 3.05 to
20.3 GJ/hr (3.0 to 20 x 106 Btu/hr) thermal input and are used primarily for
heating systems, to produce industrial process steam, and as portable power
2
boilers. Firetube boilers are generally used where steam/hot water demand
can be maintained relatively constant because they are susceptible to
structural failure when subjected to large variations in steam demand.
Over 90 percent of the installed capacity of firetube boilers is oil- or
gas-fired.3
A watertube boiler is one in which the hot combustion gases contact the
outside of the heat transfer tubes, while the boiling water and steam are
contained within the tubes. Usually, the tubes are connected to an
4-3
-------
overhead drum with sufficient space provided for separation of the steam
from the boiler water.
Watertube boilers can generate high-pressure, high-temperature steam,
up to 12,000 kPa (1740 psi) and 530°C (1000°F), and are available in many
sizes. The tubes are of relatively small diameter, 5 cm (2.0 inch),
providing rapid heat transfer, good response to steam demands, and high
2
efficiency.
There are two main types of coal-fired watertube boilers: pulverized
coal and stoker-fired. In pulverized coal-fired boilers the fuel is
pulverized to the consistency of light powder and pneumatically injected
through the burners into the furnace. Combustion begins at the burners and
continues into the furnace. A stoker is a conveying system that serves both
to feed the coal into the furnace and to provide a grate upon which the coal
is burned. Since feed rates by stoker units are limited, stokers are
generally used on units rated at less than 406 GJ/hr (400 x 106 Btu/hr) heat
3
input. Therefore, only model boilers in the smallest size category
(30.5 GJ/hr) were the only boilers considered for stoker firing. Boilers in
the other two size categories were represented by pulverized coal model
boilers.
Only small boilers can be assembled at the factory and then shipped to
the site. Larger boilers must be field erected. For this reason the model
boilers representing boilers in the 30.5 GJ/hr (30 million Btu/hr) category
were packaged, while the remaining model boilers were assumed to be field
erected.
4.1.2 Control Of Acidic Emissions From Boilers
A variety of demonstrated devices for controlling emissions of S02,
N0X, and particulate matter (PH) from industrial and utility boilers are
commercially available. Methods of controlling acidic material emissions,
however, are not as well defined or established. For the purpose of
developing model units, demonstrated SOg, N0x, and PM controls were selected
which provide the highest level of concurrent acidic materials control.
Flue gas desulfurization (FGD) systems for SOg control were chosen for
control of sulfates, HC1, and HF. Combustion modification techniques used
for N0X control were selected for nitrate control.
4-4
-------
4.1.2.1 Sulfates. HC1. and HF. Flue gas desulfurization (FGD) systems
use processes which contact flue gas with an alkaline "scrubbing" liquor to
absorb S0X and acid gases (HC1 and HF). These systems are typically
classified as "wet" or "dry" depending on the physical state in which the
absorption products leave the scrubbing unit. FGD processes can also be
described as regenerable or non-regenerable. Regenerable systems recover
the sulfur compounds removed from the flue gas as a salable by-product such
as sulfuric acid, liquid SOg, or elemental sulfur. Non-regenerable systems
yield solid or sludge wastes which require environmentally sound disposal
methods.
While wet FGD systems achieve SOg removal efficiencies on the order of
90 percent, they are not as efficient in removing acid sulfates.
Reference 4 estimates a sulfate removal efficiency of 35 percent. Although
wet FGD systems do not optimize acid sulfate control, they usually achieve
good overall acid gas removal. In fact, HC1 and HF are removed with at
5 6
least the same efficiency as S02. '
For industrial boilers, the most prevalent wet FGD system is the
sodium-based scrubber. Sodium scrubbers employ a sodium based solution as
the scrubbing medium. These systems comprise about 98 percent of all
industrial wet FGD installations.'' Host sodium-based scrubbers currently in
use on industrial boilers are employed on oil field steam generators.
However, even after eliminating applications such as oil field steam
generators, paper mills, soda ash, and textile plants, sodium-based
scrubbers represented at least 70 percent of the total wet FGD systems
operating in 1984.^ The second most prevalent industrial wet FGD technology
is the dual alkali process. Dual alkali scrubbers comprise about 1 percent
of the industrial wet FGD population.'' This process also involves the
absorption of S02 (and acidic materials) in a sodium based solution.
However, the absorbent is regenerated via reaction with a calcium based
slurry to produce a sludge waste that must be disposed of.
The most common wet FGD systems employed on utility boilers are
lime/limestone wet scrubbers. These devices use a calcium carbonate
solution to scrub flue gases. By September 1980, limestone wet scrubbers
4-5
-------
comprised 46.1 percent of all FGD systems on utility boilers with lime wet
O
scrubbers following at 39.5 percent. The predominant regenerable FGD
process, commercially proven for utility boiler applications, is the
Wellman-Lord Sulfite Scrubbing Process. Wellman-Lord systems account for
about 4 percent of the total U.S. operating and planned utility FGD
g
capacity.
The most prevalent dry FGD system for industrial and utility boilers is
the spray dryer. Spray drying involves contacting the flue gas with an
atomized lime slurry or sodium carbonate solution. The hot flue gas dries
the droplets to form a dry waste product, while the absorbent reacts with
SOg and acidic materials. The dry waste product, unreacted absorbent, and
boiler fly ash can then be collected in a baghouse or an electrostatic
precipitator.
Acid sulfate removal efficiencies should be higher for spray dryers
which use a baghouse for collection of solids than for wet FGD systems.
This is because the potential for HgSO^ mist is minimized, and the acid
sulfates have additional time to react with absorbent captured on the fabric
filter. Combining the Reference 4 estimates for sulfate removal in FGD
systems and fabric filters yields a 65 percent removal efficiency. While
this estimate may be overly optimistic, it should clearly be higher than for
wet systems.
HC1 and HF removal efficiencies for spray drying systems are about 90
percent. These are equivalent to the efficiencies achieved by wet systems.
4.1.2.2 Nitrates. Nitrogen oxides (N0X) are formed during the
combustion process by two mechanisms. One involves the thermal fixation of
oxygen and nitrogen present in the combustion air. The predominant
mechanism is the reaction of oxygen in the combustion air with nitrogen in
the fuel. No data could be found specifically for the control of nitrates.
Thus, for the purpose of this study, it is assumed that reduction of N0X
emissions will proportionally decrease the potential for nitrate formation.
As a result, N0X controls are chosen for analysis.
Control of N0X emissions is generally accomplished by modifying the
combustion process. One method is the low excess air (LEA) operation. This
simply reduces the primary combustion air flow to decrease the local flame
zone concentration of oxygen. N0X emissions can be reduced by about
4-6
-------
15 percent in this manner.*0'** Off-stoichiometric, or staged, combustion
is another modification technique. In this process, overfire air (OFA)
ports can be used to decrease oxygen availability in the primary flame zone
while providing sufficient air downstream for complete combustion. OFA can
reduce N0X emissions by about 30 percent.** A technique yielding higher N0X
reductions is the low-NOx burner. These burners are specifically designed
to minimize flame turbulence, delay mixing of fuel and air, and create
oxygen deficient zones in the initial combustion area. Reduction efficiency
for low-NOx burners is about 50 percent.**
4.1.3 Model Control Systems
Table 4.1-2 presents the acidic material control systems chosen for
analysis with model boilers. Limestone wet scrubbers were the only FGD
systems selected for oil-fired utility boilers. This is because no cost
data were found for other systems applied on oil-fired boilers of comparable
size. NO controls were not chosen for boilers under 406 GJ/hr
C
(400 x 10 Btu/hr) capacity. Uncontrolled emission factors from
Reference 10 indicate that the 30.5 GJ/hr (30 x 106 Btu/hr), packaged
boilers would meet the current new source performance standard (NSPS) for
N0X emissions without additional control.
4.2 CLAUS PLANTS
Claus sulfur recovery plants in the U.S. produce an estimated
5,400 Mg (12,000 tons) of acid sulfate per year. In addition to a
significant national production, two individual plants were indicated to
produce large amounts of local acid sulfate emissions. Each of these two
plants produced in excess of 550 tons of acid sulfate per year. Also, a
larjti number of smaller plants are located in Texas, Mississippi, and
Wyoming which may cause local problems.
Five types of control systems are presently being used in the U.S. to
control emissions from Claus plants. These are ARC0, Beavon, IFP-1, SCOT,
and Wellman-Lord Systems. Table 4.2-1 shows the extent to which each type
of system is used. The IFP-1 process is merely an extension of the Claus
4-7
\
-------
TABLE 4.1-2. MODEL CONTROL SYSTEMS FOR BOILERS
Boiler
Heat Input
Capacity
GJ/hr (MMBtu/hr) Fuel Sulfate, HC1, HF Control NO Control
30.5 (30)b
HSC, LSC, DO,
RO
Sodium-based scrubber
Dual alkali scrubber
Lime spray dryer
Low excess air
Overfire air
406 (400)b
HSC, LSC, DO,
RO
Sodium-based scrubber
Dual alkali scrubber
Lime spray dryer
Low excess air
Overfire air
2,031 (2,000)C
HSC, LSC
. Limestone wet scrubber
Wellman-Lord systems
Lime spray dryer
Low excess air
Overfire air
Low-NOx burners
RO
Limestone wet scrubber
Low excess air
Overfire air
5,078 (5,000)C
HSC, LSC
Limestone wet scrubber
Wellman-Lord systems
Lime spray dryer.
Low excess air
Overfire air
Low-NOx burners
RO
Limestone wet scrubber
Low excess air
Overfire air
aHSC = high-sulfur coal, LSC = low-sulfur coal, DO = distillate oil,
RO = residual oil.
^Industrial boiler
cUtility boiler
4-8
\
-------
TABLE 4.2-1. CLAUS PLANT TAIL GAS CONTROL PROCESSES CONSTRUCTED BEFORE 19834
Process
Type of Process
Number of Units
Percent of Total
IFP-1
Extended Claus
6
8
Wellman-Lord
Oxidation/Absorber
5
7
ARCO
Reducti on/Absorber
4
5
Beavon
Reduction/Absorber
30
39
SCOT
Reducti on/Absorber
31
41
4-9
-------
process. The other four processes are tail gas scrubbing systems. The
Wellman-Lord system uses an oxidation reaction, while the other three
scrubbers use a reduction reaction. All three of these reduction processes
reduce all sulfur species in the tail gas to H2S. They differ in the steps
taken to convert the HgS to elemental sulfur. IFP-1 processes represent
roughly 99.0 percent control while tail gas scrubbers can achieve up to
99.9 percent control.
Reference 12 gave the total production from Claus plants in the U.S
that were using some form of tail gas control in 1980. This total
production was 3.2 million Mg (3.5 million tons). Total production from all
Claus plants in that year was 3.9 million Mg (4.3 million tons). Therefore,
81 percent of all Claus plant production in 1980 used tail gas controls.
Assuming that uncontrolled plants collect 96 percent of the sulfur and
controlled plants collect 99.9 percent of the sulfur, uncontrolled plants
would emit 40 times more acid sulfate than a controlled plant of the same
size. Using this factor with the percentages of plants controlled and
uncontrolled gives a factor for the percentage of emissions coming from
uncontrolled plants. This percentage is 90 percent. Therefore,
4,900 Hg (5,400 tons) of acid sulfate were produced by uncontrolled plants
in 1980. If controlled, emissions reduction from these plants would be
4,800 Hg (5,250 tons).
It is important to note that all Claus plants on which construction or
modification began after October 4, 1976 and have capacities greater than
20 Mg/day (22 tons/day) are subject to a New Source Performance Standard
(NSPS) limiting S02 emissions. Since 1980, a large number of Claus plants
have begun operation (e.g., 816,000 Mg [900,000 tons] production capacity in
1981 and 1982). Practically all new units are large enough to fall under
15
the NSPS and employ tail gas controls. Assuming a plant life of 15 years,
all plants constructed prior to NSPS control will have to be replaced before
1995. Nevertheless, the high degree of control that can be achieved before
then has prompted the development of model plants for this study.
Table 4.2-2 gives the model Claus plants that will be used. Of the
17 Claus plants that became operational in 1981 and 1982, 7 were less than
100 Mg/D (110 TPD), 5 were between 100 and 199 Mg/D (110 and 219 TPD),
4-10
-------
TABLE 4.2-2. CLAUS PROCESS MODEL PLANTS*
Sulfur
Intake
Efficiency
Number of
Heat
Mg/D
(TPD)
(X)
Catalytic Stages
Recovery
1
10
(11)
95.10
1
No
2
100
(110)
96.64
2
No
3
250
(276)
96.64
2
Yes
All model plants assume one Claus furnace and 350 days/year operation.
4-11
-------
4 were between 200 and 299 Mg/D (221 and 330 TPD), and only 1 was above
300 Hg/D (331 TPD). All plants had either one or two catalytic stages.
As was shown in Table 4.2-1, 85 percent of all tail gas control systems
constructed before 1983 were reduction processes. As shown in Table 4.2-3,
95 percent of those processes beginning operation in 1981 and 1982 were
reduction processes. Since the reduction processes appear to be the
predominant choice for Claus plant control, only these systems will be
considered in the cost estimating. All three types of reduction processes
have similar costs. Therefore, only the Scot process will be used in cost
calculations.
4.3 FLUID CATALYTIC CRACKING
In Table 3-1, it was indicated that catalytic cracking units in the
U.S. emit approximately 11,000 Mg (12,500 tons) of acid sulfate per year.
Ninety-seven percent of these units are fluid catalytic cracking (FCC)
13
units, representing about 9,300 Mg (10,200 tons) of acid sulfate emissions
per year. Since FCC units dominate the catalytic cracking population and
are phasing out other methods of catalytic cracking,*4 FCC will be the only
technology of this type considered for model plant development. High local
emissions of sulfates are reported for areas of Texas and Louisiana where
petroleum refineries are concentrated. It is assumed that there are also
high local emissions from FCC units located in these states (Appendix A).
Acid sulfates are produced in an FCC unit during the catalyst
regeneration step, where coke deposits are burned off the catalyst surface.
For this reason, emission control devices are applied to FCC regenerators.
The only type of control device which has been demonstrated on FCC
regenerators is the wet sodium-based scrubber. Sodium-based scrubbers are
flue gas desulfurization (FGD) devices that employ a sodium-based liquor to
absorb sulfur dioxide from the flue gas. These scrubbers have been applied
to seven FCC units at five refineries, representing 11 percent of the U.S.
14
fresh feed capacity.
By January 1979, 31 refineries employed hydrotreating to part or all of
their feed stocks, representing about 18 percent of U.S. fresh feed
capacity.14 Hydrotreating involves heating the feed stream in the presence
4-12
-------
TABLE 4.2-3. TAIL GAS CONTROL PROCESSES CONSTRUCTED IN 1981 AND 19824
Process
Type of Process
Number of Units
Percent of Total
IFP-1
Extended Claus
0
0
Wellman-Lord
Oxidation/Absorber
1
5
ARCO
Reducti on/Absorber
1
5
Beavon
Reducti on/Absorber
7
37
SCOT
Reducti on/Absorber
10
53
4-13
-------
TABLE 4.3-1. SULFATE EMISSIONS DATA FOR FCC UNIT REGENERATORS
Control Type
U.S. Fresh1
Feed.Capaclty
Treated m /sd (bbl/sd)
Percent of
U.S. Fresh Foed
Capacity Treated
Current
Sulfate Emissions
Mg/yr (tons/yr)
Sulfate Emissions with
35 Percent Control
Mg/yr (tons/yr)
Sodium scrubbing
87.800 (552,000)
11
785
(865)a
785 (865)
Hydrotreatlng
145,000 (912.000)
18
599
(660)b
599 (660)c
None
573,000 (3,605.000)
71
7.892
(8,700)
5,126 (5,650)
TOTAL
805,800 (5,069,000)
100
9,276
(10.22S)
6,510 (7,125)
'Based on an average acid sulfate removal efficiency of 35 percent. Reference 4.
Assumes that acid sulfate removal efficiency Is equal to S0_ removal efficiency at 70 percent.
°Added control unnecessary If acid sulfate removal by hydrotreatlng Is greater than 35 percent.
-------
of hydrogen gas to reduce sulfur content. However, this process is site
specific and is applied for economic and process reasons rather than to
comply with limits on sulfur oxides emissions. Hydrotreating gives an
14
estimated 70 percent SOg reduction efficiency.
Table 4.3-1 presents the amounts of annual acid sulfate emissions for
both controlled and uncontrolled FCC units. These were calculated using the
WG3B emissions factor (43 kg/m3 [15 lbs sulfate/1000 bbl] fresh feed
capacity) presented in Section 3.1.7. Uncontrolled FCC regenerators emit
approximately 7,900 Mg (8,700 tons) of acid sulfate per year, accounting for
85 percent of total annual acid sulfate emissions.
Reference 4 estimates a sulfate removal efficiency of 35 percent by wet
FGD systems. Applying this level of control to uncontrolled FCC units would
reduce national sulfate emissions by 30 percent, to a level of about
6,400 Hg (7,000 tons) per year. The amount of sulfate emission reductions
realized by hydrotreating is not clear from available data. For the purpose
of this study, it is assumed that a reduction of at least 35 percent is
achieved and additional control is unnecessary.
Since the majority of FCC units are uncontrolled and a significant
reduction in acid sulfates emissions could be achieved, model plants were
developed for further analysis. These plants are presented in Table 4.3-2.
The two fresh feed capacities selected are representative of FCC units
14
constructed since 1975. The two values of feed sulfur content reflect
14
intermediate and high feed sulfur levels normally seen by FCC units.
A New Source Performance Standard (NSPS) was proposed in January 1984,
limiting sulfur oxides emissions from FCC unit regenerators. Under this
standard, add-on control devices (such as sodium scrubbers) must control
90 percent of S0V emissions from units using feed streams with sulfur
15
contents greater than 0.3 percent. Cost analysis will be performed for
retrofitting sodium-based scrubbers on model units to meet this NSPS. A
sulfate removal efficiency of 35 percent will be assumed.
4.4 PRIMARY COPPER
Acid sulfate emissions from primary copper smelters in the U.S. are
estimated to be 9,000 to 10,000 Hg (9,500 to 11,500 tons) per year
(Table 3-1). Emission rates vary from plant to plant, depending on smelter
4-15
-------
TABLE 4.3-2. MODEL PLANTS FOR FLUID CATALYTIC CRACKING UNITS3
Fresh Feed
Capacity m3/sd (bbl/sd)
Feed Sulfur
Content (wt. %)
Sulfate Control
Efficiency %
2500 (15,725)
1.5
35
3.5
35
8000 (50,320)
1.5
35
3.5
35
Based on a proposed New Source Performance Standard of 90 percent SO
control for add-on devices with 0.3 percent sulfur feed cut-off
(Reference 15).
4-16
-------
size, type of process equipment, and the presence or absence of S02 control.
Table 4.4-1 presents a list of domestic smelters currently operating and
their basic equipment inventories.
The only type of control system that has been demonstrated for U.S.
copper smelters is the sulfuric acid plant. Acid plants produce sulfuric
acid by catalytically oxidizing S02, which is captured from smelter
off-gases, to SO^. Two types of acid plants are currently available and in
use. One is the single contact, single absorption (SCSA) plant which
utilizes one absorption unit. An improved version, available since about
1972, is the double contact, double absorption (DCDA) plant which employs
two absorbers. SCSA units achieve about 96 percent SO, control while DCDA
16
units achieve 99.7 percent control. Eight of the ten ope.;ting domestic
copper smelters use acid plants to control part or all of their off-gases.
Two smelters remain uncontrolled. A Dimethylaniline (DMA) scrubbing system
is used by the Tennessee Chemical Company smelter in Copperhill, Tennessee
to supplement their acid plants.^ However, this smelter is the smallest in
the United States and serves primarily as a sulfuric acid producer. Thus,
DMA scrubbers will not be considered further.
Primary S02 emissions from any roaster, smelting furnace, or converter
at new copper smelters and modified existing smelters are limited by a new
source performance standard (NSPS) to 650 ppm.^ However, existing
reverberatory furnaces which process high impurity charges are exempt from
the NSPS. Sulfur dioxide emissions from reverberatory furnaces may increase
because of modifications as long as total emissions from the smelter do not
increase. This is because reverberatory furnaces produce "weak" S02 off-gas
streams, and no cost-effective control method has been found. As a result,
smelters that employ reverberatory furnaces treat only roaster and converter
off-gases. The two uncontrolled domestic copper smelters use reverberatory
furnaces but do not control any portion of roaster or converter off-gases.
Although the Copper Range smelter at White Pine, Michigan, is uncontrolled,
18
it processes a non-sulfide copper ore; thus, sulfate emissions are low.
Emissions of S02 at the remaining uncontrolled smelter (Phelps Dodge,
Douglas, Arizona) are estimated by WG3B to be about 258,000 Mg/yr
(284,000 tons/year).16 This results in approximately 3,500 Mg (3,850 tons)
4-17
-------
TAOU 4.4-1. OOMtSUC PRIMARY OOPP1R SMllURS16'"
Coapany
location
Capacity Mg/yr (tons/yr)
Process Equlpaont
SO^ Control Cqulfaent
ASAflCO
El Paso, Texas
90,700
(100,000)
4
Mltlhearth Roasters
Acid Plants (Du«l Stago)
1
3
Haydtn, Arltona
161.000
(200,000)
12
Multlhearth Roaster
Acid Plants
2
Reverberatory Furnacos
S
Converters
Tennessee Otaelcal Company
Copperfctll, Tennessee
13.600
(1S,000)
1
Fluid Bed Roaster
Acid Plants (Dual Stage)
1
Electric Furnace
DMA*
1
Converter
Inspiration Consolidated Copper Coapany
Hl«1, Artxona
136,000
(150,000)
1
Rotary Dryer
Acid Plants (Dual Stage)
1
Electric Furnace
S
Magma Copper Company
San Manuel, Arltona
18US00
(700,000)
3
Reverberatory Furnaces
Acid Plants
S
Kenneoott Copper Corporation
Haydon# Arizona
70,800
(76,000)
1
Fluid Bad Roaster
Acid Plants
1
Reverberatory Furnace
3
Converters
Hurley* Now Mexico
72*S00
(60,000)
1
Rotary Dryer
Acid Plants
1
Reverberatory Furnace
4
-------
T«U 4.4-1. DOMESTIC PRIHAAT COPflR SMUTER:.'5" " (Continued)
Coaptny
Location
C*p*ctty Mg/yr (tons/yr)
Process Equipment
SO2 Control CqutpMnt
Copper Rjnge Cotpiny
HMte Pino* Hlch1g4n
51,700 <57,000)
1 RoUry Dryir
2 Reverberttory furnaces
2 Converter*
Hone
ftielps Dodge Corporation
OougUi# AtIioha
115,200 (127.000)
24 Multlhearth Rotiter*
3 Reverberatory Furnaces
Mone
• \
Hld*lgo, Him Hextco
162.500 (179.000)
1 ftoUry Dryer
1 SUg Furntce
Acid Plant4 (Dual 5t«ge)
*DHA • DtsathyUnll In* Scrubbing Syitg*
\
-------
of acid sulfate emissions per year. If this smelter was controlled by acid
plants, acid sulfate emissions from copper smelters in the United States
would fall to between 7,000 and 9,000 Mg/yr (8,000 and 10,000 tons/year),
realizing a 16 percent reduction.
Since reduction of sulfate emissions could be achieved by controlling
the Phelps Dodge smelter mentioned above, it was specifically chosen as a
model plant for cost analysis. Acid plants will be the only control method
considered in cost analysis. Table 4.4-2 presents a description of the
plant.
However, plant closures before 1988 are projected that may obviate the
need for any additional controls. Although non-ferrous smelters were
regulated under the 1977 Clean Air Act, some copper smelters qualified for a
19
provisional waiver of the compliance date. The ten year waiver expires
January 1, 1988. Two smelters are projected to close before 1988--the
Tennessee Chemical Company smelter in Copperhill, Tennessee and the Phelps
20 21
Dodge smelter in Douglas, Arizona. ' The latter is the model unit.
Six domestic smelters have closed since 1980, and three of these closed
in 1985 alone. Table 4.4-3 presents a list of these closures. Smelter
closures have reduced domestic capacity by 36 percent from the 1984 level.
Future facilities have no impact because only one new smelter has been built
ig
since 1960 and no new construction is planned.
If all previously mentioned smelter closures are realized, acid sulfate
emissions would fall to about 1,800 to 3,600 Mg (2,000 to 4,000 tons) per
year in 1988. This estimate is based on a 60 percent capacity factor and
WG3B emission estimates.
4.5 COKE OVENS
Acid sulfate emissions from domestic coke ovens are reported to be
5,000 Mg (5,500 tons) per year (Table 3-1). Reference 22 indicates that
these emissions originate almost exclusively from underfiring the ovens. A
portion of coke oven off-gas, containing a high concentration of h^S, is
recycled to the coke oven battery as combustion fuel. This results in S0x
... emissions.
4-20
-------
TABLE 4.4-2. MODEL PLANT FOR PRIMARY COPPER SMELTERS
Capacity Number Operating/
Mg/yr (tons/yr) Process Equipment Stand-By Control Device
115,200 (127,000) Multihearth Roasters 17/7 Acid Plant
Reverberatory Furnaces 3/0
Converters 3/2
4-21
-------
TABLE 4.4-3. DOMESTIC PRIMARY COPPER SMELTER CLOSURES
Company
Location
Capacity
Mg/yr (tons/yr-)
Date of Closure
Anaconda
Anaconda, Montana
127,000 (140,000)
1980
Kennecott
McGill, Nevada
45,500 (50,000)
1983
Garfield, Utah
254,000 (280,000)
June 1985
Phelps Dodge
Morenci, Arizona
190,500 (210,000)
December 1984
Ajo, Arizona
63,500 (70,000)
April 1985
ASARCO
Tacoma, Washington
90,500 (100,000)
March 1985
4-22
-------
By-product coke plants account for about 98 percent of coke production
22
in the U.S. Many of these plants employ a desulfurization process to
remove HgS from coke oven off-gas before it is recycled. A demonstrated
example of this process is the vacuum carbonate system. The vacuum
carbonate system consists of a sodium carbonate absorption unit and an
22
actifier. The absorber removes about 90 percent of the oven gas HjS. A
portion of the desulfurized gas is then recycled to the coking battery for
combustion. The ^S-rich absorbent stream goes to the actifier where it is
stripped to produce a concentrated HgS stream. Claus plants are then used
to recover sulfur from the "sweetened" HgS stream. Material balances
reported in Reference 22 indicate that desulfurization by the vacuum
carbonate process can reduce S02 (and thus sulfate) emissions from
underfiring by about 82 percent.
It is unclear from present information, whether the emissions estimate
of 11 million pounds of acid sulfate per year takes into account existing
desulfurization processes. Reference 22 presents an AP-42, uncontrolled
emissions factor of 2 kg S02/Mg (4 lbs S02/ton) of coal charged for coke
ovens underfired with untreated oven off-gas. Combining this with the WG3B
(Reference 16) estimate that sulfate emissions equal 8.2 percent of S02
emissions yields 0.17 kg/Mg (0.33 lbs sulfate/ton coal) charged. This
agrees closely with the emissions factor presented in Section A.1.3 of
Appendix A. It could be inferred from these factors that emissions
reductions realized from existing desulfurization processes are not included
in the estimate. This would put actual acid sulfate emissions from domestic
coke ovens well below 4,500 Mg (5,000 tons) per year. However, since this
remains uncertain and the extent of existing desulfurization employed in the
coking industry could not be clearly estimated, model units were developed.
The vacuum carbonate desulfurization process was chosen for control
cost analysis because it is an established process and provides a high level
of S0X emissions reduction. The model vacuum carbonate systems are
identical to those developed in Reference 22. Capacities, in terms of gas
3
flow rate, are 0.57 million and 1.70 million std. m /day (20 million and
60 million SCFD). Model coke plants were sized proportionally with these
systems using the bases presented in Table 4.5-1. Coke plant capacities, in
terms of coal charged, are 2000 and 6000 Mg/day (2200 and 6600 tons/day).
4-23
-------
TABLE 4.5-1. DESIGN BASES FOR MODEL COKE PLANTS22
1. Coal charged is a bituminous mixture of one weight percent sulfur.
2. Coking cycle is 17 hours.
3. Plant operates 365 days per year.
4. 3.2 kilograms (6.5 lbs) of H„S are generated per Mg (ton) of coal
charged.
3
5. Vacuum carbonate system inlet H,S concentration is 9.2 mg/m
(500 grains/100 SCF). c
6. Coke oven operates at 900°C (1652°F) with 6 percent underfire
excess air.
4-24
-------
4.6 PRIMARY ALUMINUM
In Section 3 it was estimated that primary aluminum smelters in the
U.S. emit approximately 5,900 Mg (6,500 tons) of HF per year. It was also
indicated that acid sulfate emissions total 200 to 400 Mg (220 to 440 tons)
per year. However, since the amount of sulfate emissions is not significant
and HF emissions alone make primary aluminum smelters a significant source
category, only the control of fluoride emissions is discussed further.
Total fluoride emissions from new, modified, or reconstructed aluminum
smelters are limited by a standard of performance for new stationary sources
(SPNSS) to the following levels:^
1 kg (2 lbs) of fluorides per ton of aluminum produced for plants
using vertical (VSS) and horizontal stud Soderberg (HSS) cells;
0.9 kg (1.9 lbs) of fluorides per ton of aluminum produced for
plants using center-worked (CWPB) and side-worked prebake (SWPB)
cells;
0.05 kg (0.1 lb) of fluorides per ton of aluminum produced for
anode bake plants.
Existing primary smelters are regulated by the Clean Air Act, which requires
application of the best, adequately demonstrated control technology. In a
study published by the U. S. Environmental Protection Agency (EPA) in 1979,
the best control was determined to be an effective hooding system (which
minimizes secondary emissions) in combination with wet or dry scrubbing of
23
primary gases.
Two types of dry scrubbers that have been demonstrated on aluminum
smelter off-gases are fluid bed and injected alumina dry scrubbers. Both
systems employ a suspended, or "fluidized," bed of alumina particles to
absorb HF from the flue gas stream. Secondary (fugitive) emissions can be
controlled with spray screen scrubbers. These devices are installed in roof
ventilation systems and use a liquor spray to remove fluorides.
Table 4.6-1 presents the level of control existing on smelter potrooms
in 1975. If the best demonstrated controls were applied, total fluoride
23
emissions would be reduced by about 78 percent. Assuming HF is controlled
4-25
-------
TABLE 4.6-1. EXTENT OF POTROOM CONTROL AT PRIMARY ALUMINUM SMELTERS, 197523
t-
Percentage of Capacity Having:
Best
Primary
At Least Control
At Least Best +
Cell Annual Capacity Primary Primary Secondary
Type Mg A1 (10 tons Al) Control Control Control
CWPB
2.5
(2.7)
95
61
0
SWPB
0.6
(0.7)
81
79
59
HSS
0.9
(1.0)
100
83
0
VSS
0.5
(0.6)
100
100
33
All Cell Types
4.5
(5.0)
95
73
11
aCWPB = center-worked prebake cells, SWPB = side-worked prebake cells,
HSS = horizontal stud Soderberg cells, VSS = vertical stud Soderberg cells
^Based on total fluorides (gaseous + particulate) emissions.
c0r, secondary control with equivalent overall control efficiency.
4-26
-------
proportionally with total fluorides, national emissions would fall to
approximately 1,400 Hg (1,500 tons) of HF per year.
Development of model plants for the domestic primary aluminum industry
is not feasible. This is because plant type and configuration vary greatly
among existing smelters, making actual control applications site specific.
In lieu of model plants, control modules were taken from Reference 1
(Tables 4.6-2 and 4.6-3). These modules represent options for upgrading
existing smelters, including removal of inadequate equipment and
installation of the best demonstrated controls. Cost differences between
alternatives for upgrading a specific smelter can be determined by
evaluating various control scenarios. These are developed by choosing
applicable control modules and summing their costs. The following
23
approximations and assumptions were made in deriving the cost modules:
they are based on typical values of gas volumes to primary and
secondary controls;
it is assumed that the control costs per unit of production
resulting from the modules will not vary significantly with plant
size.
While this procedure is valid for specific plants, it can not be
generically applied to the primary aluminum industry. To estimate a
national retrofit cost would require access to control equipment inventories
for all existing primary aluminum smelters. Appropriate control scenarios
could then be applied and a total cost determined. In Section 5.6, an
example retrofit control case is presented for each reduction cell type, and
respective costs are updated to 1985 dollars. Cost effectiveness data,
however, will only be valid for the specific smelters chosen and will not be
representative of the industry as a whole.
4-27
-------
TABLE 4.6-2. MODEL CONTROL MODULES FOR INSTALLING BEST AVAILABLE
CONTROL TECHNOLOGY FOR PRIMARY ALUMINUM SMELTERS.
CAPITAL COSTS23 (MARCH 1985 DOLLARS)
* Capital Cost
Control Module $/Mg ($/ton) of annual capacity
VSS
1. Install spray screen-secondary 166.94 (151.45)
CWPB and SWPB
2.
Lime treatment of cryolite bleed stream
4.17
(3.78)
3.
Improve hooding
31.79
(28.84)
4.
Install primary collection system
72.93
(66.16)
5.
Install injected alumina dry scrubber-primary
112.93
(102.45)
6.
Install spray screen secondary
119.24
(108.17)
7.
Install fluidized bed dry scrubber-primary
129.55
(117.53)
8.
Install anode bake plant controls
34.39
(31.20)
HSS
9.
Lime treatment of cryolite bleed stream
4.17
(3.78)
10.
Improve hooding
31.79
(28.84)
11.
Install spray screen-secondary
166.94
(151.45)
VSS = vertical stud Soderberg cells; CWPB = center-worked prebake cells;
SWPB = side-worked prebake cells; HSS = horizontal stud Soderberg cells
4-28
-------
TABLE 4.6-3. MODEL CONTROL MODULES FOR REMOVAL OF INADEQUATE
EXISTING CONTROL EQUIPMENT FOR PRIMARY
ALUMINUM SMELTERS. CAPITAL COSTS23
(MARCH 1985 DOLLARS)
* Capital Cost
Control Module $/Mg ($/ton) of annual capacity
CWPB and SWPB
1. Remove dry ESP-primary 13.17 (11.95)
2. Remove floating bed wet scrubber-primary 12.84 (11.65)
3. Remove coated bag filters-primary 24.11 (21.87)
4. Remove fluidized bed dry scrubber-primary 34.39 (31.20)
5. Remove multiple cyclone-secondary 14.04 (12.74)
6. Remove spry tower-primary 5.95 (5.40)
HSS
7. Remove spray tower-primary 10.46 (9.49)
8. Remove floating bed scrubber-secondary 128.89 (116.93)
"k
CWPB = center-worked prebake cells; SWPB = side-worked prebake cells;
HSS = horizontal stud Soderberg ceils
4-29
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4.7 MUNICIPAL SOLID WASTE INCINERATORS
HCL emissions from municipal solid waste (MSW) incinerators are
generated by the combustion of chlorine-containing substances in the feed.
These include chlorinated hydrocarbons and plastics, such as polyvinyl
chloride. A typical analysis of MSW is presented in Table 4.7-1.
HSW incinerators generally fall into one of two categories—conventional
or modular. The categories are identified mainly on the basis of waste
throughput capacity. Conventional incinerators are large units with waste
throughput capacities greater than 45 Hg/day (50 tons/day). Capacities of
conventional units currently in operation can range up to 1800 Hg/day
25
(2000 tons/day). Modular, or packaged, incinerators are smaller units
with less than 45 Mg/day (50 tons/day) capacity. In fact, most of these
25
incinerators have MSW throughput capacities under 27 Mg/day (30 tons/day).
Reference 25 indicates that conventional units account for over 94 percent
of annual MSW incineration in the U.S. As a result, only conventional units
were considered for model development.
Incinerators can also be categorized with respect to heat recovery
capability. Conventional units with heat recovery handle approximately
48 percent of domestic MSW throughput, while conventional units without heat
25
recovery process about 46 percent. Model incinerators, presented in
Table 4.7-2, were developed using characteristics of both these types of
units. The average capacity for conventional incinerators without heat
recovery, presently operating in the U.S., is 381 Mg/day (420 tons/day).
Units with heat recovery average about 800 tons/day in capacity.
No particular system or device can be identified as a demonstrated HCL
control for use on domestic incinerators at the present time. Reference 5
suggests, however, that wet or dry scrubbing systems can achieve HCL removal
efficiencies of at least 90 percent. The HCL control chosen for cost
analysis is a wet scrubber employing a caustic soda (NaOH) based scrubbing
liquor. A removal efficiency of 90 percent will be assumed.
4-30
-------
TABLE 4.7-1. TYPICAL MUNICIPAL SOLID WASTE (MSW) ANALYSIS
Analysis
(% by weight)
25.1
25.2
3.2
18.8
0.4
0.3
0.1
8.7
12.2
6.0
100.0
10,230 kJ/kg (4,400 Btu/lb)
Component
Moisture
Carbon
Hydrogen
Oxygen
Nitrogen
Chlorine
Sulfur
Metal
Glass, Ceramics
Ash
TOTAL
Higher Heating Value
Source: Reference 24.
4-31
-------
TABLE 4.7-2. MODEL MUNICIPAL SOLID WASTE INCINERATORS
Type
Conventional
Conventional
Heat Recovery
No
Yes
Capacity:
Waste Rate Mg/day
(tons/day)
Heat Input GJ/hr K
(MMBtu/hr)
381
(420)
152
(150)
726
(800)
298
(293)
Capacity Factor
0.77
0.86
Operating Parameters:
Percent Excess Airc
Flue Gas Flow Rate m3/s (ACFM)d
HCL Control Device
Percent HCL removal
150
29 (61,450)
Sodium Scrubber
(caustic based)
90
80
40 (84,770)
Sodium Scrubber
(caustic based)
90
Based on data from Reference 27.
'Based on MSW heating value of 1288 kJ/kg (4400 Btu/lb). Reference 24.
"Reference 5.
Based on F-factor calculations.
4-32
-------
4.8
REFERENCES
1. Fossil Fuel Fired Industrial Boilers: Background Information, Volume
1, prepared for U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina. EPA-450/3-82-006a, 25 March 1982.
2. Devitt, T. (PEDCo Environmental, Inc.) Population and Characteristics
of Industrial/Commercial Boilers in the U.S., prepared for U.S.
Environmental Protection Agency, Research Triangle Park, North
Carolina. Publication No. EPA-600/7-79-178a. (NTIS PB 80-150881).
August 1979. pp. 32-33.
3. Steam, Its Generation and Use, 38th Edition. Babcock and Wilcox, New
York, 1975. p. 25-1.
4. Sellars, F.M., et al.. (GCA Corporation). National Acid Precipitation
Assessment Program Emission Inventory Allocation Factors, prepared for
U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina, EPA-600/7-85-035, (NTIS PB 86-104247), September 1985.
p. 75.
5. California Air Resources Board, Air Pollution Control at Resource
Recovery Facilities, Sacramento, California. 24 May 1984. pp. 30-142.
6. Smith, E.O., et al.. (Black and Veatch Consulting Engineers),
Full-Scale Scrubber Characterization of Conesville Unit 5, prepared for
Electric Power Research Institute, Palo Alto, California, EPRI C5-2525,
August 1982. pp. s-10, 5-133, 5-135.
7. Radian Corporation, Industrial Boiler SOp Technology Update Report,
prepared for U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, EPA-450/3-85-009, 30 July 1984. pp. 2-1 through
2-79.
8. Smith, M., et al.. (PEDCo Environmental, Inc.), EPA Utility FGD Survey:
July-September 1980, prepared for U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina, EPA-600/7-80-029d, (NTIS PB
81-142655), October 1980. p. xviii.
9. Dickerman, J.C. and K.L. Johnson (Radian Corporation), Technology
Assessment Report for Industrial Boiler Applications: Flue Gas
Desulfurization, prepared for U.S. Environmental Protection Agency,
Washington, D.C., EPA-600/7-79-178i, (NTIS PB 80-150873),
November 1979, p. 2-118.
10. Acurex Corporation, Control Techniques for Nitrogen Oxide Emissions
from Stationary Sources - Second Edition, prepared for U.S.
Environmental Protection Agency, Research Triangle park, North
Carolina, EPA-450/1-78-001, (NTIS PB 280034), January 1978.
4-33
-------
11. Huang, H.S. (Argonne National Laboratory), Control of NO from
Coal-F1red Boilers: Combustion Modification Techniques, prepared for
U.S. Department of Energy, October 1981, pp. xvi-47.
12. Review of New Source Performance Standards for Petroleum Refinery Claus
Sulfur Recovery Plants, prepared for U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, EPA-450/3-83-014,
August 1983.
13. "Annual Refining Survey." Oil and Gas Journal. 21 March 1983.
pp. 128-150.
14. U.S. Environmental Protection Agency. Sulfur Oxides Emissions from
Fluid Catalytic Cracking Unit Regenerators - Background Information for
Proposed Standards. EPA-450/3-82-013a, (NTIS PB 84-143254),
January 1984. pp. 3-2 through 6-3.
15. Telecon. Lacey, G., U.S. Environmental Protection Agency (Research
Triangle Park, North Carolina), with Waddell, J.T., Radian Corporation.
8 July 1985.
16. Rivers, M.E. and K.W. Riegel, Work Group Co-Chairman. Work Group 3B -
Emissions, Costs and Engineering Assessment. U. S.-Canadian Memorandum
of Intent on Transboundary Air Pollution. 15 June 1982.
17. U.S. Environmental Protection Agency. Background Information for
New Source Performance Standards: Primary Copper, Zinc, and Lead
Smelters. Volume 1. EPA-450/2-74-002a, (NTIS PB 237832),
October 1974. pp. 1-2, 5-3, 5-4.
18. U.S. Environmental Protection Agency. Background Information - f
-------
23. Primary Aluminum: Draft Guidelines for Control of Fluoride Emissions
from Existing Primary Aluminum Plants, U.S. Environmental Protection
Agency, Office of Air, Noise and Radiation, Research Triangle Park,
North Carolina, EPA-450/2-78-049a, (NTIS PB 294938), February 1979.
24. Wilson, E.M., et a].. (The Ralph M. Parsons Company), Engineering and
Economic Analysis of Waste to Energy Systems, prepared for
U. S. Environmental Protection Agency, Cincinnati, Ohio,
EPA-600/7-78-086, Hay 1978. p. A-14.
25. Radian Corporation, Background Information Document for Cadmium
Emission Sources, Final Report, prepared for U. S. Environmental
Protection Agency, Research Triangle Park, North Carolina, EPA Contract
No. 68-02-3818, January 16, 1985. pp. 107-116.
4-35
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5.0 COST ANALYSIS
The model units developed in Section 4.0 were analyzed to determine the
costs associated with retrofitting acidic material controls. Results of
these analyses, including capital and annual costs, emissions reduction, and .
cost-effectiveness, are presented in this section. Most cost information
was obtained through a literature search. Cost data for model industrial
and utility boilers, however, were predominantly determined using computer
modeling programs developed by Radian Corporation. Any applicable
performance data that could be found is also presented.
Cost-effectiveness is determined as the annual cost of the retrofitted
control system for removing a weight unit (Mg or ton) of acidic material.
However, this cost-effectiveness calculation excludes the benefits of
removing pollutants that are co-emitted with the acidic materials. The
primary example is the removal of SOj by the control systems for acid
sulfates, HC1, and HF. To gain a perspective of how SOg impacts the
cost-effectiveness of shared control systems, the cost-effectiveness for SO2
is also reported. Since S0£ is emitted in substantially greater volume than
the acidic materials, the cost-effectiveness of SO^ is considerably lower.
Cost analyses of controls on industrial and utility boilers, Cla-is
plants, fluid catalytic cracking units, primary copper smelters, coke ovens,
primary aluminum smelters, and municipal solid waste incinerators are
reported in the rest of this section.
5.1 INDUSTRIAL AND UTILITY BOILERS
Costs for emission controls on the model boilers were calculated using
two computer cost models developed by Radian Corporation. Industrial
control system costs were calculated by IBCOST, a program developed
specifically for industrial boilers and controls for EPA's new source
performance standards development.* To develop coal-fired utility emissions
control costs, Radian Coal Use Cost Model (RCUCM) was employed. This model
5-1
-------
is based on work conducted for EPA's Air and Environmental Engineering
Research Laboratory and is described in "Emission Controls for Coal-Fired
Boilers: Design Cost Manual" [Radian Coporation, Research Triangle Park,
North Carolina, February 14, 1984]. Algorithms in both programs determine
costs from inputs such as economic factors, cost rates, boiler
characteristics (e.g., heat input capacity, efficiency, capacity factor),
and fuel analysis. Table 5.1-1 presents brief analyses of the fuels used in
cost calculations. Sample output tables for IBCOST and RCUCM are presented
in Appendix B. Economic bases and computer nomenclature are also provided
where appropriate. Update factors were included as input in each computer
run to bring costs to March 1985 dollars. These are based on Chemical
Engineering (CE) plant cost indices for capital costs and Bureau of Labor
Statistics (BLS) producer price indices for annual operating and maintenance
costs. Oil-fired utility emissions control costs were taken from Refer-
ence 5 and updated to March 1985 dollars.
Costs for flue gas desulfurization (FGD) systems on industrial boilers
and coal-fired utility boilers are based on input values for SOj removal
efficiency, in addition to the inputs mentioned above. For the purpose of
comparing cost-effectiveness, an SOg removal efficiency of 90 percent was
chosen as an average value for all FGD systems. This value is based on test
data found in literature, which is summarized in Table 5.1.2. Removal of
HCL and HF is assumed to be 90 percent also, since concurrent control is
O Q
expected. ' Acid sulfate removal is assumed to be 35 percent for "wet"
systems and 65 percent for lime spray dryers with fabric filters.10 The
capital cost for retrofitting control systems varies from about 1.1 to 2.0
times the cost of new systems, depending on site specific considerations.
For this study, a retrofit factor of 1.3 times the capital cost for new
control units was used. Limestone wet scrubber costs for oil-fired utility
boilers were taken from Reference 11 and updated to March 1985 dollars.
Capital and annual costs for industrial and utility FGD systems are listed
in Tables 5.1-3 and 5.1-4.
Cost-effectiveness data for sulfate removal by industrial and utility
FGD systems are presented in Tables 5-1.5 and 5.1-6. Table 5.1-7 shows the
cost-effectiveness of controlling HCL and HF for all selected FGD systems.
Cost-effectiveness for removal of acid sulfates, HCL, and HF is presented in
Table 5.1-8. The total cost-effectiveness for removing S02, acid sulfates,
5-2
-------
TABLE 5.1-1. ANALYSIS OF FUELS USED FOR MODEL COST CALCULATIONS
Fuel
Sulfur
Content
(wt. %)
Ash
Content
(wt. %)
Heating
Value
kJ/kg (Btu/lb)
H1gh-sulfur coal
Low-sulfur coal''
Distillate oi1c
Residual oil (Industrial)(
Residual oil (Utility)**
3.23
0.59
0.50
3.00
1.00
12.0
11.0
trace
0.1
27,200 (11,700)
29,100 (12,500)
45,350 (19,500)
43,000 (18,500)
Based on typical values for EPA Region 5, Type H-bituminous coal.
Reference 1.
'Based on typical values for EPA Region 5, Type B-bituminous coal.
Reference 1.
"Based on average values seen by industrial boilers. Reference 2.
Average value seen by utility boilers. Reference 3.
5-3
-------
TABLE 5.1-2. PERFORMANCE DATA FOR SELECTED FGD SYSTEMS
FGD
Fuel
No. of
Tests
Average
S02 Removal (%)
Source
Sodium-Based Scrubber
Coal
8a
92
Reference 5
Oil
12a
97
Reference 5
Dual Alkali Scrubber
Coal
5a
91
Reference 5
Oil
la
92
Reference 5
Limestone Wet Scrubber
Coal
---
65-90b
Reference 6
Wellman-Lord System
Coal
3
90
Reference 7
Lime Spray Dryerc
Coal
10
83
Reference 5
aVerified as EPA approved test methods.
^Range of values for performance data rather than mean value.
cData for industrial spray dryers without fabric filters. Total removal
expected to increase 9 to 15 percent with fabric filter. Reference 5.
5-4
-------
TABLE 5.1-3. COSTS OF FLUE GAS DESULFURIZATION SYSTEMS FOR INDUSTRIAL BOILER MODELS3
Control Device
Boiler
Capacity
GJ/hr (MHBtu/hr)
Fuelb
Total
Capital
Investment
($1000)
Total
Operating
and
Maintenance
(SlOOO/yr)
Total
Annual
Costs
($1000/yr)
Sodium-Based Scrubber
30.5 (30)
HSC
491
212
293
LSC
340
123
180
DO
293
112
160
RO
406
166
233
406 (400)
HSC
2097
1543
1875
LSC
1371
450
677
DO
1196
333
532
RO
1691
985
1257
Dual Alkali Scrubber
30.5 (30)
HSC
1650
371
642
LSC
1102
306
486
DO
959
295
445
RO
1405
338
568
406 (400)
HSC
4982
1231
2044
LSC
3351
553
1105
DO
2895
474
929
RO
4200
076
1564
-------
TABLE 5.1-3. COSTS OF FLUE GAS DESULFURIZATION SYSTEMS FOR INDUSTRIAL BOILER MODELS® (Continued)
Control Device
Boiler
Capacity
GJ/hr (MMBtu/hr)
Fuel
Total
Capital
Investment
($1000)
Total
Operating
and
Maintenance
(SlOOO/yr)
Total
Annual
Costs
(JlOOO/yr)
Lime Spray Dryer0
30.5 (30)
HSC
1798
399
693
LSC
1338
337
555
DO
1183
326
518
R0
1531
364
614
406 (400)
HSC
7732
1495
2760
LSC
5733
737
1682
DO
4584
556
1312
RO
6084
999
1998
aCosts In March 1985 dollars produced by IBCOST Computer Model.
^HSC " high-sulfur coal; LSC ¦ low-sulfur coal; DO = distillate oil; RO * rosldual oil.
cIncludes cost for particulate matter control.
-------
TABLE 5.1-4. COSTS OF FLUE GAS OESULFURIZATION SYSTEMS FOR UTILITY BOILER XDELS4
Bollor
Hoat
Input
Capacity
Control Dovlco GJ/hr (WBtu/hr)
Fuel
Total
Capital
Investmont
(S1000)
Total
Oporattng
and
Maintenance
(SlOOO/yr)
Total
Annual
Costs
(tlOOO/yr)
Llmostono Mot Scrubtor
2.031
(2.000)
HSC
69.094
7.660
26.016
LSC
55.548
6.258
21.067
RO
32.592
KA
11/935
5,078
(5,000)
HSC
125.780
13.027
45.979
LSC
105.678
10.341
37.719
R0
62.926
HA
23.448
Mollman-Lord Scrubbing System
2,031
(2,000)
HSC
105.460
10.604
38.070
LSC
68.492
7,178
25.164
5.078
(5.000)
HSC
202.258
21.500
74.767
LSC
133.276
14,344
49.534
Lima Spray Dryor
2.031
(2.000)
HSC
67.790
7.696
26.217
(with fabric flltor)
LSC
56.212
5.342
19.825
5.078
(5.000)
HSC
134.137
14.940
50.613
LSC
108.822
9.387
36.940
aCosts for systems ootployod on coal-flrod boilers calculated using RCUCH. Costs for limestone wot scrubbors
on oll-rirod bollors takon from Roforonce 11 and updatod to March 1985 dollars.
^NA » Hot available.
cCosts for systems on coal-flrod units are lovollzod costs ovor 20 yoar oqulpment life.
-------
TABLE 5.1-5. COST-EFFECTIVENESS DATA FOR INDUSTRIAL FGD MODEL UNITS: SULFATE
Boiler Heat Controlled Total Cost
Input Capacity Sulfate Annual Effectiveness
GJ/hr Control Emissions Cost $/Hg ($/ton)
(MMBtu/hr) Fuel3 Device'3 Mg/yr (tons/yr)c (SlOOO/yr)'' Sulfate Removed
HSC
SS
2.41
(2.65)
293
122,000
(110,000)
DA
642
266,000
(242,000)
LSD
4.48
(4.93)
693
155,000
(141,000)
LSC
SS
2.26
(2.48)
180
80,000
(73,000)
DA
486
216,000
(196,000)
LSD
4.19
(4.61)
555
132,000
(120,000)
DO
SS
0.45
(0.49)
160
359,000
(327,000)
DA
445
999,000
(908,000)
LSD
0.83
(0.91)
518
626,000
(569,000)
RO
SS
0.47
(0.52)
233
493,000
(448,000)
DA
568
1,202,000 1
(1,092,000)
LSD
0.87
(0.96)
614
704,000
(640,000)
HSC
SS
32.16
(35.38)
1,875
58,000
(53,000)
DA
2,044
64,000
(58,000)
LSD
59.72
(65.70)
2,760
46,000
(42,000)
LSC
SS
30.10
(33.11)
677
22,000
(20,000)
DA
1,105
37,000
(33,000)
LSD
50.82
(55.90)
1,682
33,000
(30,000)
DO
SS
5.95
(6.55)
532
89,000
(81,000)
DA
929
156,000
(142,000)
LSD
11.06
(12.16)
1,312
119,000
(108,000)
RO
SS
6.28
(6.91)
1,257
200,000
(182,000)
DA
1,565
249,000
(226,000)
LSD
11.65
(12.81)
1,998
172,000
(156,000)
30.5 (30)
406 (400)
HSC = high-sulfur coal/LSC = Low-sulfur coal; DO = distillate oil;
. RO = residual oil.
SS = sodium-based scrubber; DA = dual alkali scrubber; LSD = lime spray dryer
(with fabric filter)
Based on 35 percent SOT removal for SS and DA; 65 percent removal for
.LSD (Reference 10) and emission factors from Reference 12.
All costs in March 1985 dollars, calculated by IBCOST model.
5-8
-------
TABLE 5.1-6. COST-EFFECTIVENESS DATA FOR UTILITY FGD MODEL UNITS: SULFATE
Boiler Heat Controlled Total Cost
Input Capacity Sulfate Annual Effectiveness
GJ/hr Control Emissions Cost $/Mg ($/ton)
(MMBtu/hr) Fuela Device^ Mg (tons/yr)c (SlOOO/yr)^ Sulfate Removed
2,031 (2000)
HSC
LWS
22.9
(25.2)
26,016
1,135,000
(1,032,000)
WL
38,070
1,662,000
(1,511,000)
LSD
42.5
(46.8)
26,217
616,000
(560,000)
LSC
LWS
21.5
(23.5)
21,067
982,000
(893,000)
WL
25,164
1,173,000
(1,066,000)
LSD
39.8
(43.8)
19,825
498,000
(453,000)
RO
LWS
41.0
(45.1)
11,935
292,000
(265,000)
5,078 (5000)
HSC
LWS
57.3
(63.0)
45,979
802,000
(729,000)
WL
74,767
1,305,000
(1,187,000)
LSD
106.4
(117.0)
50,613
476,000
(337,000)
LSC
LWS
53.6
(59.0)
37,719
703,000
(639,000)
WL
49,534
924,000
(840,000)
LSD
99.5
(109.5)
36,940
371,000
(337,000)
RO
LWS
102.5
(112.7)
23,448
229,000
(208,000)
HSC = high-sulfur coal/LSC = Low-sulfur coal; DO = distillate oil;
b RO = residual oil.
LWS = limestone wet scrubber; WL = Wellman-Lord System; LSD = lime spray
dryer (with fabric filter)
Based on 35 percent SOT removal for LWS and WL; 65 percent removal for
.LSD (Reference 10) and emission factors from Reference 12.
Costs in March 1985 dollars. Coal-fired unit costs calculated by RCUCM
Model; oil-fired costs taken from Reference 11.
5-9
-------
TABLE 5.1-7. FGD COST-EFFECTIVENESS FOR COAL-FIRED MODEL UNITSi Ha AND HF COKTROl
Bollor Hoat
Input Capacity
GJ/hr (WBtu/hr)
Fuol4
FGDb
Total
Annual Cost
(SlOOO/yr)
Controllod
HCL Emissions
Mg/yr (tons/yr)
Cost
Effoctlvones:.
J/Mg (S/ton HCL romovod)
Control lad
HF Emissions
Hg/yr (tons/yr)
Cost
Effoctlvonoss
S/Hg (J/ton HF roaovod)
30.5 (30)
HSC
SS
LSD
DA
293
693
642
5.1 (5.6)
57,600
136,100
126,100
(52,300)
(123,700)
(114,600)
1.0 (1.1)
293,700 (266,400)
694,400 (630.000)
643.300 (583.600)
LSC
SS
LSD
OA
160
555
486
35,400
109,000
95,500
(32,100)
(99,100)
(87.800)
180,300 (163,600)
556,100 (504,500)
487,000 (441.800)
406 (400)
HSC
SS
LSD
DA
1.875
2.760
2.044
67.2 (73.9)
27,900
41,100
30,400
(25.400)
(37.300)
(27.700)
8.4 (9.2)
224.200 (203.800)
330.000 (300.000)
244.400 (222.200)
LSC
SS
LSD
DA
677
1.682
1,105
10,100
25,000
16,400
(9.200)
(22.800)
(15.000)
80.900 (73.600)
201.100 (182.800)
132.100 (120.100)
2.031 (2,000)
HSC
LWS
LSD
WL
26.016
26,217
38.070
338.9 (372.8)
76,800
77,400
112,300
(69.800)
(70.300)
(102,100)
40.5 (44.5)
643.100 (584.600)
648.100 (589,100)
941,100 (855,500)
LSC
LMS
LSD
WL
21.067
19,825
25,164
62,200
58,500
74,200
(56,500)
(53,200)
(67,500)
520,000 (473,400)
490,100 (445.500)
622.000 (565,500)
5,078 (5.000)
HSC
LWS
LSD
WL
45,979
50,613
.74,767
847.3 (932.0)
54,300
59,700
88,200
(49,300)
(54.300)
(80.200)
101.1 (111.2)
454,800 (413,500)
500,700 (455,200)
739,600 (672,400)
LSC
LWS
LSD
WL
37,719
36,940
49,534
44,500
43.600
58,500
(40.500)
(39,600)
(53,100)
373,100 (339,200)
365,400 (332,200)
400,000 (445,400)
'HSC ¦ high-sulfur coali LSC « loo-sulfur coal.
b SS " sodium scrubber) LSD ¦ ltmo spray dryorj OA - dual alkali scrubbor; LWS « llmestono wot scrubbor) ML - Wollnan-Lord System.
cBasod on 90 porcont control and omission factors from Roforence 13.
-------
TABLE 5.1-8. COST-EFFECTIVENESS FOR REMOVAL OF ACIDIC MATERIALS
BY MODEL FGD SYSTEMS
Total
Boiler Heat Controlled Total
Input Capacity Acidic Cost-Effectiveness
GJ/hr Control Materials $/Mg (S/ton)
(MMBtu/hr) Fuela Device'5 Mg/yr (tons/yr)c (acidic material removed)
30.5 (30)
HSC
SS
7.5 (8.2)
39,300
(35,700)
DA
86,100
(78,300)
LSD
9.6 (10.5)
72,600
(66,000)
LSC
SS
7.4 (8.1)
24,400
(22,200)
DA
66,000
(60,000)
LSD
9.3 (10.2)
59,900
(54,400)
DO
SS
0.4 (0.5)
359,000
(327,000)
DA
999,000
(908,000)
LSD
0.8 (0.9)
626,000
(569,000)
RO
SS
0.5 (0.5)
492,800
(448,000)
DA
1,200,000
(1,090,000)
LSD
0.9 (1.0)
704,000
(640,000)
406 (400)
HSC
SS
99.4(109.3)
18,900
(17,200)
DA
20,600
(18,700)
LSD
126.9(139.6)
21,700
(19,800)
LSC
SS
97.3(107.0)
7,000
(6,300)
DA
11,400
(10,300)
LSD
118.0(129.8)
14,300
(13,000)
DO
SS
5.9 (6.5)
89,000
(81,000)
DA
156,000
(142,000)
LSD
11.1 (12.2)
119,000
(108,000)
RO
SS
6.3 (6.9)
200,000
(182,000)
DA
249,000
(226,000)
LSD
11.6 (12.8)
172,000
(156,000)
5-11
-------
TABLE 5.1-8. COST-EFFECTIVENESS FOR REMOVAL OF ACIDIC MATERIALS
BY MODEL FGD SYSTEMS
(Continued)
Total
Boiler Heat Controlled Total
Input Capacity Acidic Cost-Effectiveness
GJ/hr Control Materials $/Mg ($/ton)
(MMBtu/hr) Fuel3 Deviceb Mg/yr (tons/yr)c (acidic material removed)
2,031 (2,000) HSC
HSC
LWS
402.3
(442.5)
64,700
(58,800)
WL
94,600
(86,000)
LSD
421.9
(464.1)
62,100
(56,500)
LSC
LWS
400.8
(440.9)
52,600
(47,800)
WL
62,800
(57,100)
LSD
419.2
(461.1)
47,300
(43,000)
R0
LWS
41.0
(45.1)
291,100
(264,600)
5,078 (5,000) HSC
HSC
LWS
1,005.7
(1,106.2)
45,700
(41,600)
WL
74,300
(67,600)
LSD
1,054.8
(1,160.2)
48,000
(43,600)
LSC
LWS
1,002.0
(1,102.2)
37,600
(34,200)
WL
49,400
(44,900)
LSD
1,048.0
(1,152.7)
35,300
(32,000)
RO
LWS
102.5
(112.7)
229,000
(208,000)
HSC = high-sulfur coal; LSC = Low-sulfur coal; DO = distillate oil;
. RO = residual oil.
SS = sodium scrubber; DA = dual alkali scrubber; LSD = lime spray
dryer (with fabric filter); LWS = limestone wet scrubber;
WL = Wellman-Lord system.
Includes acid sulfates and acid gases (HCL and HF) for coal-fired units;
.only acid sulfates are included for oil-fired units.
Costs in March 1985 dollars. Coal-fired unit costs calculated by RCUCM
Model; oil-fired costs taken from Reference 11.
5-12
-------
HC1, and HF is given in Table 5-1.9. Sodium-based scrubbers applied to
406 GJ/hr (400 x 10® Btu/hr) industrial boilers firing low-sulfur coal
exhibit the greatest cost-effectiveness at $7000/Mg ($6300/ton) of acidic
material removed. Dual alkali scrubbers applied to 30.5 GJ/hr
(30 x 10® Btu/hr) residual oil-fired boilers are the least cost-effective,
since sulfates are the only material controlled. These units cost
$1.20 million/Mg ($1.09 million/ton) of sulfate removed.
Costs for N0X controls on industrial boilers were calculated using
IBCOST. Since no nitrate er.iission data were available, the cost of controls
is based on the reduction of N0X. Proportionate reduction of nitrates is
expected; however, since nitrate emissions make up only a portion of total
N0X emissions, the actual cost-effectiveness of nitrate emissions reduction
is higher than the calculated N0X reduction cost-effectiveness. Utility N0X
control costs for coal and oil-fired boilers were taken from References 13
and 14, respectively, and updated to March 1985 dollars. Table 5.1-10
presents total capital and annual costs, N0g emissions reductions, and
cost-effectiveness for each control method. It was determined from emission
factors in Reference 13 that the 30 x 10® Btu/hr boilers and the
400 x 10® Btu/hr oil-fired boilers would not require additional N0X control
to meet the current New Source Performance Standard (NSPS) for N0X
emissions. Therefore, they are not included in the N0X control cost
analysis.
The most cost-effective N0V control technique is low excess air (LEA)
6
applied to the 5000 x 10 Btu/hr oil-fired boiler. This method requires
only $1 per ton of reduced N0V emissions. Overfire air (OFA) ports employed
e X
on the 2000 x 10 Btu/hr oil-fired boiler and LEA applied to the
400 x 10® Btu/hr boiler firing high-sulfur coal are the least cost-effective.
These techniques cost approximately $132/Mg ($120/ton) of reduced NO
6
emissions. The wide range of LEA costs for the 400 x 10 Btu/hr boiler can
be accounted for by the difference in fuel costs. LEA generates fuel
savings, thus, the lower priced, high-sulfur coal will produce less savings.
5.2 CLAUS PLANTS
The model Claus plants developed in Section 4.2 were analyzed with
respect to capital investment, net annual cost, and cost-effectiveness of
5-13
-------
TABLE 5.1-9. TOTAL COST-EFFECTIVENESS FOR REMOVAL OF S02 AND
ACIDIC MATERIALS BY MODEL FGD SYSTEMS
Total
Boiler Heat Controlled SOg
Input Capacity and Acidic
GJ/hr Control Materials
(MMBtu/hr) Fuel3 Device*5 Mg/yr (tons/yr)c
Total
Cost-Effectiveness
$/Mg ($/ton)
(removed)
30.5 (30)
HSC
SS
362
(398)
810
(740)
DA
1,770
(1,610)
LSD
363
(400)
1,910
(1,730)
LSC
SS
68
(75)
2,640
(2,400)
DA
7,130
(6,480)
LSD
70
(77)
7,930
(7,210)
DO
SS
33
(36)
4,890
(4,440)
DA
13,600(12,360)
LSD
34
(37)
15,400(14,000)
RO
SS
210
(230)
1,110
(1,010)
DA
2,720
(2,470)
LSD
211
(231)
2,920
(2,660)
406 (400)
HSC
SS
4,863
(5,349)
390
(350)
DA
420
(380)
LSD
4,891
(5,380)
560
(510)
LSC
SS
906
(997)
750
(680)
DA
1,220
(1,110)
LSD
927
(1,020)
1,810
(1,650)
DO
SS
451
(496)
1,180
(1,070)
DA
2,060
(1,870)
LSD
457
(502)
2,870
(2,610)
RO
SS
2,797
(3,077)
450
(410)
DA
560
(510)
LSD
2,803
(3,083)
710
(640)
5-14
-------
TABLE 5.1-9. TOTAL COST-EFFECTIVENESS FOR REMOVAL OF S02 AND
ACIDIC MATERIALS BY MODEL FGD SYSTEMS
(Continued)
Boiler Heat
Input Capacity
GJ/hr
Control
Total
Controlled SOj
and Acidic
Materials
(MMBtu/hr) Fuela Device*5 Mg/yr (tons/yr)c
Total
Cost-Effectiveness
$/Mg (S/ton)
(removed)
2,031 (2,000)
HSC
LWS
22,920
(25,212)
1,130
(1,030)
WL
1,660
(1,510)
LSD
22,940
(25,234)
1,140
(1,040)
LSC
LWS
4,246
(4,671)
4,960
(4,510)
WL
5,930
(5,3C0)
LSD
4,264
(4,691)
4,650
(4,230)
RO
LWS
5,065
(5,572)
2,350
(2,140)
5,078 (5,000)
HSC
LWS
57,300
(63,030)
800
(730)
WL
1,300
(1,190)
LSD
57,350
(63,085)
880
(800)
LSC
LWS
10,616
(11,677)
3,550
(3,230)
WL
4,670
(4,240)
LSD
10,661
(11,727)
3,460
(3,150)
RO
LWS
12,664
(13,930)
1,850
(1,680)
HSC = high-sulfur coal; LSC = Low-sulfur coal; DO = distillate oil;
RO = residual oil.
SS = sodium scrubber; DA = dual alkali scrubber; LSD = lime spray
dryer (with fabric filter); LWS = limestone wet scrubber;
WL = Wellman-Lord system.
"Includes acid sulfates and acid gases (HCL and HF) for coal-fired units;
only acid sulfates are included for oil-fired units.
.LSD. Reference 10.
Costs in March 1985 dollars. Coal-fired unit costs calculated by RCUCM
Model; oil-fired costs taken from Reference 11.
5-15
-------
TKJLE 5.1-10. N0x CONTRX COSTS fOft KOOEl C01LER UNITS
Qcllor Typo
HojI
Input Capacity
GJ/hr (MMHu/hr)
"°x
Controlc
Fuol
Tctal
Capital
lnvostmant
(S)
Total
Annual Costs
($)
IIO2 Emissions
Roductions
Mg/yr (tons/yr)*1
Cost-Effuctlvoncss
J/llg (J/ton)
(K02 controlled)
Industrial /
406 (400)
LEA
IISC
163.000
17,COO
129
(142)
132
(120)
wall ft rod
LSC
162,000
1,000
120
(132)
9
(6)
OFA
Coal
146,000
29.000
258
(284)
112
(102)
2.031 (2,000)
LIU
Coal
1,480,000
264.000
2146
(2365)
124
(112)
LEA
Coal
350,000
4,000
644
(710)
7
(6)
011
143,000
1,000
536
(591)
2
(2)
OFA
Coal
412,000
124,000
1288
(1420)
96
(87)
011
314,000
94,000
715
(788)
131
(119)
5,078 (5,000)
LIC
Coal
2.135,000
360,000
5364
(5913)
8
(7)
LEA
Coal
505,000
5.000
1609
(1774)
3
(3)
011
206,000
2,000
1341
(1478)
1
(1)
OFA
Coal
595,000
160,000
3219
(3548)
56
(51)
Oil
491,000
147,000
1788
(1971)
83
(75)
aCosts produced by IDCOST Computor Modal.
bData for coal-ftrod bollors takon from Roferonco 13* Data for oil-fired boilers taken from Rofbiooco 14. All costs updatod to Maixh 19C5
dollars using C£ Plant Cost 1nd1co».
JjLEA « low oxcoss air; OFA • ovorftro air; UO ° low NO burnoru.
Based on omission factors and estimated roductlon offlclonclos# Rofcroncos 13 and 14.
I
-------
reducing sulfate emissions. All costs for the 10 and 100 Mg/day
(11 and 110 tons/day) model plants were taken from Reference 15 and updated
to March 1985 dollars using CE plant cost indices (capital costs) and
BLS producer price indices (annual costs). Costs for the 250 LT/D plant
were derived using the procedure outlined in Reference 15, Appendix A.
Capital cost estimates are derived from an analysis of data furnished
by equipment vendors and operating plants. Annual costs are based on the
assumptions and design parameters listed in Table 5.2-1. Both capital and
annual costs are presented in Table 5.2-2. Credits are given for sulfur and
steam produced by the Claus plants and control systems. The difference
between total credits and total annual cost is the net annual cost for the
model plant. For the two larger units, this becomes an annual profit for
the Claus plant.
The control system selected for each controlled model plant is an amine
tail-gas treatment system. Sulfur recovery (and, thus, SOg control) is
increased from about 96 percent to 99.9 percent with the addition of such
systems. Since this process operates under reducing conditions, as
mentioned in Section 4.2, control of sulfates is assumed proportional to SOj
control. Cost-effectiveness data presented in Table 5.2-3 reflect this
assumption. Results indicate that cost-effectiveness improves with
increasing plant size. This could be due to increased sulfur recovery with
larger amine control units. Cost-effectiveness for the 10, 100, and
250 Mg/day (11, 110, and 276 tons/day) model plants are $220,000, $72,000,
and $50,000 per ton sulfate removed, respectively. Cost-effectiveness for
SOg removal is only 1 percent of the sulfate cost-effectiveness values as
shown in Table 5.2-4.
5.3 FLUID CATALYTIC CRACKING
It was estimated in Section 4.3 that total acid sulfate emissions from
fluid catalytic cracking (FCC) units in the U.S. could be reduced by about
32 percent if sodium scrubbers were applied to existing units. This section
presents the results of a cost analysis performed to evaluate the cost-
effectiveness of retrofitting sodium-based scrubbers to TCC model units.
The analysis was based on the NSPS mentioned in Section 4.3.
5-17
-------
TABLE 5.2-1. ASSUMPTIONS AND BASES FOR ANNUAL COSTS3
1. All plants handle acid gas consisting of 80 percent ^S, 10 percent C02,
4.5 percent NHj, 0.5 percent hydrocarbons, and 5 percent moisture. Acid
gas streams are saturated at 109°F and 24.7 psia.
2. Claus plants use high efficiency alumina catalysts for maximum sulfur
recovery.
3. Claus plants consume 4100 kPa (600 psig) steam and generate 1700 kPa
(250 psig) and 100 kPa (15 psig) steam, with 3-stage plants also
generating 350 kPa (50 psig) steam.
4. With waste heat recovery, 600 psig steam is also generated, while
tail-gas treaters are net consumers of 50 psig steam.
5. Capital recovery costs are based on 15 year equipment life at 10 percent
interest. Capital recovery factor = 0.1315.
6. Plants operate 350 days per year.
7. Unit prices:
Item
Cost
b
4100 kPa
1700 kPa
350 kPa
100 kPa
(600 psig) steam
(250 psig) steam
(50 psig) steam
(15 psig) steam
$0.016/kg ($7.25/1000 lb)
$0.015/kg ($6.75/1000 lb)
$0.013/kg ($5.75/1000 lb)
$0.010/kg ($4.50/1000 lb)
Sulfur
$120/Mg ($109/ton)
aSource: Reference 15.
^Given as presented in Reference 15. All annual costs updated in actual
calculations using BLS producer price indices.
5-18
-------
TABLE 5.2-2. COSTS FOR MODEL CLAUS PLANTS3
Model Size (LT/m
10 100b 250b
Uncontrolled
Total Capital Investment 2,630,000 6,470,000 10,550,000
($)
Total Annual Cost 737,400 2,113,700 3,894,900
(S/yr)
Total Credits0 519,400 5,830,300 14,577,200
(S/yr)
Net Annual Cost 218,000 (3,716,600) (10,682,300)
($/yr)
Controlled^
Total Capital Investment 5,130,000 10,960,000 17,830,000
(S)
Total Annual Cost 1,569,500 3,798,400 6,938,800
(S/yr)
Total Credits0 569,500 5,870,100 14,697,200
(S/yr)
Net Annual Cost 967,000 (2,071,700) (7,758,400)
(S/yr)
aCosts taken from Reference 15 and updated to March 1985 dollars.
bParentheses ( ) indicate profits.
cIncludes credits for sulfur and steam produced.
^Control in all cases is amine tail-gas treatment.
5-19
-------
TABLE 5.2-3. COST-EFFECTIVENESS FOR CONTROL OF
MODEL CLAUS PLANTS - SULFATE
Model Size
Mg/D (TPD)
Annual Cost
(s/yr)a
Annual Acid Sulfate
Emissions Reduction
Mg/yr (tons/yr)')
Cost-Effectiveness
$/Mg (S/ton)
(acid sulfate removed)
10 (11)
749,000
3.1 (3.4)
242,800 (220,300)
100 (110)
1,644,900
21.3 (23.5)
77,200 (70,000)
250 (276)
2,923,900
53.3 (58.7)
54,900 (49,800)
Cost of amine tail-gas treatment. Calculated as the difference between
controlled and uncontrolled plant costs. March 1985 dollars. Reflects
profit/loss for 100 and 250 Mg/D (110 and 276 TPD) units.
''Based on S0? removal data from Reference 15 and the V/G3B estimate that
acid sulfate emissions equal one percent of SOg emissions.
5-20
-------
TABLE 5.2-4. COST-EFFECTIVENESS FOR CONTROL OF
MODEL CLAUS PLANTS - S02
Model Size
Mg/D (TPD)
Annual Cost
($/yr)a
Annual S02
Emissions Reduction
Mg/yr (tons/yr)*5
Cost-Effectiveness
5/Mg (S/ton)
(S02 removed)
10 (11)
749,000
310 (340)
2420 (2200)
100 (110)
1,644,900
2130 (2350)
770 (700)
250 (276)
2,923,900
5330 (5870)
550 (500)
Cost of amine tail-gas treatment. Calculated as the difference between
controlled and uncontrolled plant costs. March 1985 dollars. Reflects
profit/loss for 100 and 250 Mg/D (110 and 276 TPD) units.
''Based on S0~ removal data from Reference 15 and the WG3B estimate that
acid sulfate emissions equal one percent of SOg emissions.
5-21
-------
Table 5.3-1 presents a list of sodium-based scrubbers currently
operating on FCC units with their locations and performance data. Two types
of sodium-based scrubbers which are presently in use on domestic FCC unit
regenerators are jet ejector Venturis (JEV) and high energy Venturis (HEV).
Jet ejector Venturis are generally used on FCC units equipped with carbon
monoxide boilers. High energy Venturis are used on FCC units that utilize
high temperature regeneration or conventional promoted regeneration.^ JEV
scrubbers are currently employed on five FCC units at three refineries,
representing 8.5 percent of U.S. fresh feed capacity. HEV scrubbers have
been applied to two FCC units at two refineries, accounting for 2.5 percent
of domestic fresh feed capacity.
Acid sulfate removal efficiency data for sodium-based scrubbers were
not available. Reference 12 estimates 35 percent sulfate control for flue
gas desulfurization systems. Sulfur dioxide removal efficiencies, however,
were reported for two jet ejector Venturis and two high energy Venturis.
Both types of scrubbers achieve an average SO2 removal efficiency of
94 percent.
Sodium-based venturi scrubbers applied to FCC units are also effective
in controlling particulate matter (PM) emissions. Removal of PM is
accomplished via inertial impaction of scrubbing liquor with entrained
particulates. In two separate EPA Method 5 testing series at one refinery,
average PM removal efficiencies of 83 and 95 percent were achieved.^®
Capital costs for the sodium-based scrubbing systems chosen for
analysis are presented in Table 5.3-2. These costs are based on the
regenerator flue gas flow rate. The inlet SO concentration has no impact.
3
The total capital costs of the JEV systems for the 2,500 and 8,000 m /sd
(15,725 and 50,320 bbl/sd) model units are $8.4 million and $14.8 million,
respectively. The HEV systems require respective total capital investments
of $6.1 million and $10.7 million for the same model units. JEV scrubber
costs are higher than those for HEV scrubbers because JEV systems require
additional piping, pumps, and spray nozzles. All costs were taken from
Reference 16 and updated to March 1985 dollars using Chemical Engineering
(CE) plant cost indices. A retrofit factor of 1.3 times the sum of total
direct and indirect costs plus contingency was also applied.^
5-22
-------
TABLE 5.3-1. PERFORMANCE DATA FOR SOOIUH-BASED SCRUBBERS OH FCC UNIT REGENERATORS16
RofInory/Locatlon
Scrubber Typo
FCC Frgsh Food®
Capacity n /sd (bbl/sd)
SO. Romoval''
Efficiency
Exxon. Bayway. Nov Jorsoy
Too Jot ojoctor vonturls for
tho FCC unit
19,100 (120,000)
NA
Exxon. Baton Rougo, Louisiana
(2 FCC units)
Ono Jot ojoctor vonturl system
for both FCC units
24,600 (1SS,000)
NA
Exxon. Baytown, Texas
(2 FCC units)
Ono Jet ejector vonturl for
oach FCC unit
24,600 (155,000)
94
94
Marathon* Garyvlllo,
Louisiana
High onorgy vonturl
11,900 (75,000)
93
Southuostorn, Corpus Chr(stl>
Toxas
High onorgy vonturl
7,500 (47,000)
95
abbl/sd • barrols per stroan day
''For the purpoia of this study.
Reference 12.
It Is assumod that tho acid sulfatos romoval offlcloncy Is 3S porcont.
-------
TABLE 5.3-2. CAPITAL COSTS FOR S00IUH-6ASED SCRUBBING SYSTEMS APPLIED TO FLUIO CATALYTIC CRACKING UNITS®
2500 m3/sd
(15.725 bbl/sd) 8000 «i3/sd
(50,320 bbl/sd)
2500 n3/sd (15,725 bbl/sd) 8000 n3
sd (50,320 bbl/sd)
Hodol Unit
Hodol Unit
Hodol Unit
Hodol Unit
Total Direct Costsb
2.7
4.8
3.9
6.7
Indlroct Costs
1.2
2.0
1.5
2.9
Total Dlroct and Indlroct
3.9
6.8
5.4
9.5
Costs
Contingency0
0.8
1.4
1.1
1.9
Rotroftt Costd
1.4
2.5
1.9
3.4
Total Capital Cost
6.1
10.7
8.4
14.8
tn Costs In nllllons of dollars) adjusted to the 1st quarter, 1985. Reference 16.
rs> bHatortals and labor.
^wonty porcent of total dlroct and Indlroct costs.
''Assumod to bo 30 porcont of (Total Dlroct and Indlroct Cost + Contingency).
-------
The annual costs associated with these systems were also taken from
Reference 16 and updated to March 1985 dollars using BLS producer price
indices. Some of the assumptions and bases used to derive the annual costs
are listed in Table 5.3-3. Tables 5.3-4 and 5.3-5 present the annual costs
of the HEV and JEV scrubbers, respectively. Total annual cost increases
with increasing unit size and increasing feed stream sulfur content. This
results from greater requirements of sorbent at higher sulfur loadings.
Annual costs for JEV scrubbers are also higher than those for HEV scrubbers.
This is due primarily to the greater eleclrifel demand of JEV systems.16
Cost-effectiveness data are presented in Tables 5-3.6 and 5-3.7. When
caustic soda is used as the sorbent, cost-effectiveness ranges from
$47,000/.Mg ($43,000/ton) sulfate removed for the large HEV-equipped unit
using a higher sulfur feed to $123,000/Mg ($112,000/ton) sulfate removed for
the small JEV-equipped unit employing a medium sulfur feed.
5.4 PRIMARY COPPER
The model smelter chosen for cost analysis is based on the plant size
and configuration of the Phelps Dodge smelter in Douglas, Arizona. It
employs two stacks. One handles converter off-gases, while the other vents
19
roaster and reverberatory furnace off-gases. Only the control of
converter off-gases was analyzed to determine cost-effectiveness. The acid
3
plant size is based on the converter flue gas flow rate of 125 m /s
(264,000 scfm).
It should be noted that some sulfuric acid mist is emitted from acid
plants. However, electrostatic precipitators are generally used to remove
acid mist at the plant inlet, and mist eliminators are employed after each
absorption stage. For this reason, cost-effectiveness calculations assume
that sulfate removal is proportional to S02 removal.
Table 5.4-1 presents the capital and annual costs of both single-stage
(SCSA) and dual-stage (DCDA) acid plants. Total capital investments for the
SCSA and DCDA units are $48.7 million and $55.6 million, respectively.
Total annual costs are $12.3 million and $14.0 million, respectively.
Cost-effectiveness data is given in Table 5.4-2 and 5.4-3. The SCSA plant
costs $9,800/Mg ($8,900/ton) sulfate removed while the DCDA plant requires
5-25
-------
TABLE 5.3-3. BASES AND ASSUMPTIONS FOR DETERMINING ANNUAL COSTS
OF SODIUM-BASED SCRUBBING SYSTEMS APPLIED TO FLUID
CATALYTIC CRACKING UNITS16
1. Maintenap.ee includes material, labor, and overhead and equals
1.5 percent of the total capital cost.
2. Indirect operating costs include taxes, insurance, and administration
and equal 4 percent of the total capital cost.
3. The capital recovery factor (CRF) is based on an interest rate of
10 percent and a service life of 15 years (CRF = 0.1315).
4. The amount of caustic soda or soda ash consumed is proportional to the
amount of S0X removed.
5. The system operates 357 days per year.
6. Costs for treating the scrubber purge stream are included in waste
disposal costs. The purge treatment unit consists of below-ground
ponding for sedimentation of suspended solids and surface aerators to
reduce chemical oxygen demand.
5-26
-------
TABLE 5.3-4. ANNUAL COSTS FOR HIGH ENERGY VENTURI SOOIUH-BASED SCRUBBING SYSTEHS
APPLIED TO FLUID CATALYTIC CRACKING UNITS
2500 in3/ad US.725 Ml/sdl Hodol Unit booo n3/^ (sn.3?o hhi/sd) H»mi Unit
1.5 (vt.D Sulfur 3.5 (vt.S) sulfur 1.5 <«rt.S) Sulfur 3.5 (irt.X) Sulfur
Food Contont Food Content Food Content Food Contont
DIroct Oporattng Cost
52.4
52.4
.52.4
52.4
Halntonanco
91.5
91.5
160.5
160.5
Electricity
21.9
21.9
70.0
70.0
Wator
10.0
10.0
29.9
29.9
Comprossed Air
0.4
0.4
0.4
0.4
Caustic Soda
(Soda Ash)
569.7
(349.2)
1065.6
(653.2)
1823.6
(1117.9)
3397.0
(2082.4)
cn
i
Steam
1.1
1.1
3.1
3.1
no
—i
Polyeloctrolyto
4.8
4.8
14.3
14.3
Masto Disposal
6.9
6.9
22.2
22.2
Indlroct Oporatlng Costs
244.0
244.0
428.0
428.0
Capital Rocovor/ Cost
815.0
815.0
1385.6
1385.6
Total Annual Cost olth
Caustic Soda
(Soda Ash)
1817.7
(1597.2)
2313.6
(1901.2)
3990.0
(3 284.3)
5563.4
(4248.8)
aCosts In thousands of dollars; adjustod to 1st quarter. 19B5. Refironce 16.
''Basod on 90 porcont SO^ control.
-------
TABLE 5.3-5. ANNUAL COSTS FOR JET EJECTOR. VENTURI
SODIUM-BASED SCRUBBING SYSTEMS3'0
15,725 (bbl/sd) 50,320 (bbl/sd)
Model Unit Model Unit
Direct Operating Cost
52.4
52.4
Maintenance
126.0
222.0
Electricity
280.1
898.7
Water
10.0
29.9
Compressed Air
0.4
0.4
Caustic Soda
(Soda Ash)
454.1
(278.9)
1454.2
(899.9)
Steam
1.1
3.1
Polyelectrolyte
4.8
14.3
Waste Disposal
6.9
22.2
Indirect Operating Costs
336.0
592.0
Total Recovery Cost with
Caustic Soda
(Soda Ash)
2392.5
(2217.3)
5245.3
(4691.0)
aCosts in thousands of dollars; adjusted to 1st quarter, 1985. Reference 16.
''Based on feed stream sulfur content of 1.5 wt. percent and 90 percent
S0X control.
5-28
-------
TABLE 5.3-6. COST EFFECTIVENESS OF SOOIUH-BASED SCRUBBING SYSTEMS
Hodol Unit
Frosh Food
Capacity (bbl/sd)
Food Stroam
Sulfur Contont
(wt.X)
Scrubbor Typo
Total Annual Cost*
vlth Caustic Soda
(Soda Ash)
Roductlon In'1
SO Emissions
(?ons/year)
Roductlon 1nc
SO. Emissions
(tons/yoar)
Cost Effoftlvonoss
(J/ton SOj ronovod)
15.725
1.5
High Enorgy Vonturl
1818
(1597)
1640
21.4
84,950
(74,630)
Jot EJoctor Vonturl
2392
(2217)
1840
21.4
111.780
(103.600)
3.5
High Enorgy Vonturl
2314
(1901)
3440
40.2
57,560
(47,290)
50.320
1.5
High Enorgy Vonturl
3900
(3264)
5885
68.7
56,770
(47,800)
Jot EJoctor Vonturl
5245
(4691)
5885
68.7
76,350
(68,280)
3.5
High Enorgy Vonturl
5563
(4245)
10.990
128.2
43,390
(33,110)
sCosts 1n thousands of dollars* adjustod to first quartor 1985.
''Based on 90 porcont SOx control.
cBasod on a factor of 0.03 (tons acid sulfatos/ton SO^) dorlvod from Roforoncos 16 and 17 and 3S porcont sulfato removal efflcloncy.
-------
TABLE 5.3-7. COST EFFECTIVENESS OF SULFATE REMOVAL BY SOOIUH-BASED SCRUBBING SYSTEMS APPLIED
TO FLUID CATALYTIC CRACKING UNITS
Model Unit
Fre|h Feed Capacity
m /sd (bbl/sd)
Feed Stream
Sulfur Content
(wt. X)
Scrubber Type
a
rotal Annual Cost
with Caustic Soda
[Soda Ash]
b
Reduction in
Sulfate Emissions
Mg/yr (tons/yr)
Cost Effectiveness
t/Mg (S/ton Sulfate Removed)
2500 (15,725)
1.5
High Evergy Venturi
1818
19.4
(21.4)
93,640
(84,950)
CI 5971
[82,270]
(74,630)
Jet Ejector Venturi
2392
19.4
(21.4)
123,220
(111,780)
[2217]
[114,200
(103,600)]
3.5
High Energy Venturi
2341
36.5
(40.2)
63,450
(57,560)
[19011
[52,130
(47,290)]
8000 (50,320)
1.5
High Energy Venturi
3900
62.3
(68.7)
62,580
(56,770)
[3284]
[52,690
(47,800)
Jet Ejector Venturi
5245
62.3
(68.7)
84,160
(76,350)
[4691]
[75,270
(68,280)
3.5
High Energy Venturi
5563
116.3
(128.2)
47,830
(43,390)
[4245]
[36,500
(33,110)]
a
Costs in thousands of dollars, adjusted to first quarter 1985.
Based on a factor of 0.03 (Hg acid sulfates/Hg SO ) delivered from Reference 16 and 18 and 35 percent sulfate removal
x
efficiency.
-------
TABLE 5.4-1 COSTS FOR ACID PLANTS EMPLOYED ON MODEL COPPER SMELTER3
Single-Stage Dual-Stage
Acid Plant Acid Plant
Capital Costs
Capitalb 37,400 42,800
Retrofit Cost0 11,300 12,800
Total Capital Investment 48,700 55,600
Annual Costs
Operating Labor 328 328
Maintenance 2,244 2,568
Electricity 878 1,048
Process Water 546 546
Total Direct Costs 3,996 4,490
Indirect Costsd 3,996 2,224
Total Direct and Indirect Costs 5,944 6,714
Capital Recovery Coste 6,400 7,300
Total Annual Cost 12,344 14,014
?Costs in thousands of dollars (March 1985). Reference 19.
Battery limits costs, including site clearance and hook-up of available
off-site facilities. Reference 19.
.Assumed to be 30 percent of capital.
Assumed to be 4 percent of total capital investment.
Based on 10 percent interest rate and 15 year plant life. Capital recovery
factor equals 0.1315.
5-31
-------
TABLE 5.4-2. COST-EFFECTIVENESS DATA FOR ACID PLANTS3
Total Annual
Cost ($1000)
c d
Sulfate Emissions '
Reduction
Cost-Effectiveness
S/Hg ($/ton)
(Sulfate Removed)
Mg/yr (tons/yr)
SCSA
12,344
1,260 (1,390)
9,800 (8,900)
DCDA
14,014
1,320 (1,450)
10,600 (9,700)
aCosts in March 1985 dollars.
^SCSA = Single contact, single absorption acid plant;
DCDA = Double contact, double absorption acid plant
c
Based on 96 percent S02 control efficiency for SCSA plants and
99.7 percent control efficiency for DCDA plants. Reference 18.
d
Total emission based on SOg emissions data from Reference 18.
5-32
-------
TABLE 5.4-3. COST-EFFECTIVENESS DATA FOR ACID PLANTS - S02a
Plant
Type
Total Annual
Cost ($1000)
S02 Emissions '
Reduction
Hg/yr (tons/yr)
Cost-Effectiveness
5/Mg (S/ton)
(S02 Removed)
SCSA
12,344
93,300 (10,300)
130 (120)
DCDA
14,014
97,800 (107,400)
140 (130)
aCosts in March 1985 dollars.
^SCSA = Single contact, single absorption acid plant;
DCDA = Double contact, double absorption acid plant
Based on 96 percent S02 control efficiency for SCSA plants and
99.7 percent control efficiency for DCDA plants. Reference 18.
d
Total emission based on S02 emissions data from Reference 18.
5-33
-------
$1,070/Mg ($9,700/ton) sulfate removed. The incremental cost-effectiveness
is $30,900 per additional Mg ($28,000 per additional ton) of sulfate removed
by the DCDA plant over the SCSA plant. All costs were taken from
Reference 19 and updated to March 1985 dollars using CE plant cost indices.
5.5 COKE OVENS
All costs presented in this section are those associated with the
vacuum carbonate desulfurization system discussed in Section 4.5. This
process removes HgS from coke oven off-gas before it is recycled to the oven
battery as combustion fuel for underfiring. Single-stage vacuum carbonate
systems achieve H,S removal efficiencies of 80 to 93 percent, while
20
two-stage systems reach efficiencies of 98 percent. The amount of sulfur
available for SOx production during combustion is proportionally reduced.
Mass balances reported in Reference 20, based on 90 percent ^S removal,
indicate that S02 emissions are reduced by about 82 percent. For the
purpose of this analysis, vacuum carbonate systems are also assumed to
reduce sulfate emissions by 82 percent.
The assumptions and bases used to derive costs for the model plants are
presented in Table 5.5-1. Capital costs, presented in Table 5.5-2, were
taken from Reference 21 and updated to March 1985 dollars using CE plant
cost indices. A retrofit cost equalling 30 percent of the total capital
investment (TCI) required for a new unit was applied to obtain the retrofit
TCI. Annual costs were derived from information in References 15 and 20.
Credit was given for sulfur produced by the Claus sulfur recovery unit
incorporated into the desulfurization plant. The net annual cost,
therefore, is the difference between total annual cost and sulfur credit.
It should also be noted that steam is both generated and consumed by the
total process. The annual steam cost is a net charge for the difference
between steam generation and consumption. Annual costs are listed in
Table 5.5-3.
Cost-effectiveness data are presented in Table 5.5-4 and 5.5-5. The
cost-effectiveness of retrofitting vacuum carbonate systems on 2,000 and
6,000 Mg/day (2,200 and 5,600 tons/day) coke plants are $11,700 and $7,000
($10,600 and $6,300) per ton of sulfate removal, respectively.
5-34
-------
TABLE 5.5-1. BASES AND ASSUMPTIONS FOR VACUUM CARBONATE COSTS3
1. Coke ovens operate on a 17 hour cycle, 365 days per year.
2. Operating labor assumed as 6205 hrs/yr at $15.70 per hour.
Supervision assumed as 1/4 of time required for operating
labor at $17.04 per hour.
3. Maintenance and repair taken as 3 percent of total capital
investment (TCI).
4. Indirect annual costs include taxes, insurance, and
administration and equal 4 percent of TCI.
5. Capital costs updated to March 1985 dollars using CE Plant Cost
indices. Annual costs updated to March 1985 dollars using BLS
producer price indices where applicable.
6. Unit cost assumptions:
Item
Costa
Steam .
Soda Af!r
Power
Cooling Water
$5.75/1000 lbs
$120/ton
$ .05/KWH
$ .05/1000 gal
^Assumptions derived from References 15 and 20.
Chemical Market Reporter. March 11, 1985.
5-35
-------
TABLE 5.5-2. CAPITAL COSTS FOR AVACUUM CARBONATE SYSTEM APPLIED
TO MODEL COKE OVENS3
2000 Mg/D (2200 TPD)b'c 6000 Mg/D (6500 TPD)b,C
Desulfurization 2.71 5.03
Claus Sulfur Recovery 1.04 1.43
Total Capital Investment 3.75 6.46
(New Coke Plant)
Retrofit Costd 1.12 1.94
Total Capital Investment 4.87 8.40
(Existing Coke Plant)
installed costs in millions of dollars taken from Reference 20 and updated
.to March 1985 dollars.
TPD = tons of coal charged per day.
2000 and 6000 Mg/D (2200 and 6600 TPD) correspond to 20 million and 60
million SCFD, respectively. Inlet gas concentration based on 500 grains
.H?S/100 SCF. Reference 20.
Retrofit cost assumed to be 30 percent of total capital investment (new
plant).
5-36
-------
TABLE 5.5-3. ANNUAL COSTS FOR A VACUUM CARBONATE SYSTEMS
APPLIED TO MODEL COKE OVENS (RETROFIT)3
2000 Mg/D (2200 TPD)
6000 Mg/D (6600 TPD)
Labor
171,000
171,000
Maintenance and Repair
146,000
252,000
Steam
232,600
789,200
Power
33,500
99,300
Cooling Water
21,600
64,800
Soda Ash
6,700
20,000
Indirect Annual Costs
195,000
336,000
Total Operating & Maintenance
764,000
1,732,000
Capital Cost
640,000
1,105,000
Total Annual Cost
1,404,000
2,837,000
Sulfur Credit
258,000
774,000
Net Annual Cost
1,146,000
2,063,000
aAll costs in dollars per year (March 1985) calculated using data from
Reference 20 and assumptions in Table 5.5-1.
5-37
-------
TABLE 5.5-4. COST-EFFECTIVENESS DATA FOR VACUUM CARBONATE
SYSTEMS APPLIED TO MODEL COKE OVENS - SULFATE
Parent Coke
Plant Size
Net Annual Cost
(S/yr)
Sulfate
Emissions Reduction
Mg/yr (tons/yr)
Cost-Effectiveness
$/Mg (S/ton)
(Sulfate removed)
New
2200
963,000
98.3 (108.4)
9,800 (8,900)
6600
1,672,000
295.0 (325.2)
5,600 (5,100)
Retrofit
2200
1,146,000
98.3 (108.4)
11,700 (10,600)
6600
2,063,000
295.0 (325.2)
6,900 (6,300)
aBased on SOp mass balance data for model in Reference 20 and WG3B acid
sulfate emissions factor.
5-38
-------
TABLE 5.5-5. COST-EFFECTIVENESS DATA FOR VACUUM CARBONATE
SYSTEMS APPLIED TO MODEL COKE OVENS - S02
SO, Emissions Cost-Effectiveness
Parent Coke Net Annual Cost Reduction $/Mg ($/ton)
Plant Size (S/yr) Mg/yr (tons/yr) (S02 removed)
New
2200
963,000
1,200
(1,320)
800
(730)
6600
1,672,000
3,600
(3,970)
460
(420)
Retrofit
2200
1,146,000
1,200
(1,320)
955
(870)
6600
2,063,000
3,600
(3,970)
570
(520)
aBased on SO? mass balance data for model in Reference 19 and W63B acid
sulfate emissions factor.-
5-39
-------
5.6 PRIMARY ALUMINUM
In Section 4.6 it was estimated that total emissions of HF from
domestic primary aluminum smelters could be reduced from 5,900 to 1,400 Mg
(6,500 to 1,500 tons) per year by applying the best demonstrated controls.
These controls consist of effective hooding systems (which minimize
secondary emissions) in combination with wet or dry scrubbing of primary
21
gases. Section 4.6 also mentioned the great variability of plant type and
configuration existing among primary aluminum smelters in the U. S. Since
this makes control applications site specific, model plants could not be
developed.
Tables 5.6-1 and 5.6-2 present control modules taken from Reference 21,
which are used in cost analysis. The modules represent options for
upgrading
existing primary smelters, including removal of inadequate control equipment
and installation of the best demonstrated controls. Costs were updated to
March 1985 dollars using CE plant cost indices.
To determine capital and annual costs for a specific smelter, control
modules should be selected to make a complete retrofit scenario. Module
costs are then summed to give a total retrofit cost. An example retrofit
case for smelters using each reduction cell type is presented in
Table 5.6-3. The cost-effectiveness results are determined on the
cumulative costs obtained by adding the annual costs of selected control
modules and on the corresponding incremental decrease in fluoride emissions.
For the center-worked prebake cell, anode bake plant controls (Module 8-1)
was selected as the baseline control at annual costs of $10.15/Mg A1
produced and fluoride emissions of 6.2 kg/Mg A1. When control is increased
by:
Installing a fluidized bed dry scrubber, primary (Module 7-1),
Removing a dry ESP (Module 1-R),
Removing a spray tower - primary (Module 6-R), and
Installing a spray screen - secondary (6-1);
the cumulative annual cost increases to $67.04/Mg A1 produced to achieve an
incremental reduction in emissions of 3.9 kg/Mg A1 (6.2 kg F~/Mg A1 -
5-40
-------
TABLE 5.6-1. CONTROL MODULES FOR INSTALLING BEST AVAILABLE CONTROL
TECHNOLOGY FOR PRIMARY ALUMINUM SMELTERS
Capital
Annual
Control
Module3
Costb
Costb
VSS
1-1.
Install spray screen-secondary
166.94 (151.45)
55.62 (50.46)
CWPB AND SWPB
2-1.
Lime treatment of cryolite bleed
stream
4.17 (3.78)
1.83 (1.66)
3-1.
Improve hooding
31.79 (28.84)
8.13 (7.38)
4-1.
Install primary collection system
72.93 (66.16)
20.24 (18.40)
5-1.
Install injected alumina dry
scrubber - primary
112.93 (102.45)
-3.09 (-2.80)
6-1.
Install spray screen -
secondary
119.24 (108.17)
39.98 (36.35)
7-1.
Install fluidized bed dry
scrubber - primary
129.55 (117.53)
5.54 (5.03)
8-1.
Install anode bake plant controls
34.39 (31.20)
10.15 (9.21)
HSS
9-1.
Lime treatment of cryolite bleed
stream
4.17 (3J8)
1.83 (1.66)
10-1.
Improve hooding
31.79 (28.84)
8.13 (7.38)
11-1.
Install spray screen - secondary
166.94 (151.45)
55.61 (50.45)
VSS = vertical-stud Soderberg cell, CWPB = center-worked prebake cell,
.SWPB = side-worked prebake cell, HSS = horizontal-stud Soderberg cell.
Costs in $/Mg ($/ton) annual capacity updated to March 1985 dollars.
Reference 21.
Credit.
5-41
-------
TABLE 5.6-2. CONTROL MODULES FOR REMOVAL OF INADEQUATE, EXISTING CONTROL
EQUIPMENT FOR PRIMARY ALUMINUM SMELTERS
Control Module
Capital Cost3
$/Mg ($/ton)
Annual Costa,l)
S/Mg (S/ton)
CWAB AND SWPB
1-R. Removal dry ESP - primary
13.7 (11.95)
2.97 (2.69)
2-R. Removal floating bed wet scrubber -
primary
12.84 (11.65)
-13.93(-12.64)
3-R. Remove coated bag filters - primary
24.11 (21.87)
2.00 (1.81)
4-R. Remove fluidized bed dry scrubber -
primary
34.39 (31.20)
-5.54 (-5.03)
5-R. Remove multiple cyclone - secondary
14.04 (12.74)
-10.14(-9.20)
6-R. Remove spray tower - primary
5.95 (5.40)
-7.23 (-6.56)
HSS
7-R. Remove spray tower - primary
10.46 (9.49)
-11.36(-10.31)
8-R. Remove floating bed scrubber - primary
128.89(116.93)
136.45(123.74)
aCosts in $/Mg annual capacity ($/ton annual capacity), taken from
Reference 21 and updated to March 1985 dollars.
^Negative numbers indicate a credit given for the module.
5-42
-------
TABLE 5.6-3. EXAMPLE RETROFIT CONTROL COST SCENARIOS FOR PRIHARY ALUMINUM SHELTERS
CO
Cell Type^ Control Copttal Cost Annual Cost Average F Emissions emulative Cost-Effectiveness
Plant Code Module9 S/Mg (S/ton) J/Hg (S/ton) leg F /Kg Al (lb F /ton Al) S/Ng F Removed (S/ton F Removed)
VSS/5Ab --- 2.1 (4.2)
11-1 166.94 (151.45) 55.61 (50.45) 0.6 (1.2) 37,080 (33,640)
CVPB/4AC 8-1 34.39 (31.20) 10.15 (9.21) 6.2 (12.5)
7-1, 1-R, 6R 182.69 (166.08) 11.43 (10.37) 2.3 (4.7) 2,930 (2,660)
6-1 301.67 (274.25) 67.04 (60.82) 0.9 (1.9) 12,650 (11,480
SUPB/24d 8-1 34.39 (31.20) 10.15 (9.21) 24.0 (48.0)
4-1, 5-1 220.25 (199.81) 27.30 (24.81) 5.1 (10.2) 1,430 (1,300)
6-1 339.49 (307.98) 67.28 (61.16) 1.5 (3.0) 2,980 (2,700)
HSS/26® 9-1 4.17 (3.78) 1.83 (1.66) 17.2 (34.5)
10-1 35.96 (32.62) 9.96 (9.04) 9.2 (18.4) 1,230 (1,120)
11-1 202.90 (184.07) 65.58 (59.49) 3.7 (7.4) 4,850 (4,400)
°Costs in f/Hg annual capacity (S/ton annual capacity) updated to March 1985 dollars. Reference 21.
b
Presently operating with best primary control.
C6aseUne controls consist of o dry ESP and a spray tower,
d
No primary or secondary baseline control.
CSpray tower Is the only baseline control.
^VSS = vertical-stack Soderberg cell, CUPB = center-worked prcbakc cell, SUPB = side-worked prcbake cell, HSS * horizontal*stud Sodcrbcrg
cell.
9
For control module description, see Tables 5.6*1 nnd 5.6*2.
-------
0.9 kg F"/Mg Al). The cost effectiveness for this scenario is
$12,650/Hg F". To determine the cost-effectiveness of adding Module 6-R to
already installed Modules 7-1, 1-R, and 6-R incremental cost increase
($67.04/Mg Al - $11.43/Mg Al) is used and the incremental emissions
reduction (2.3 kg F~/Mg Al - 0.9 kg F~/Mg Al) is used. The result is
$39,680/Mg F~. Plant codes are given as listed in Reference 21. Cost
effectiveness data is valid only for each specific plant shown and is not
representative of the industry as a whole. In addition, a national retrofit
cost can not be calculated unless present control equipment inventories for
all existing primary aluminum smelters are available.
5.7 MUNICIPAL SOLID WASTE INCINERATORS
This section presents the costs associated with retrofitting caustic
soda (NaOH)- based wet scrubbers to the model municipal solid waste (MSW).
incinerators developed in Section 4.7. The assumptions and bases used to
derive these costs are listed in Table 5.7-1.
It should be noted that scrubber costs are based on stainless steel
construction material. In reality, stainless steel units could experience
corrosion problems due to high chloride concentrations in incinerator flue
gas. Alternative materials can be applied when this occurs. Wet scrubbers
employed on utility boilers which operate in high chloride environments are
often constructed of organic-lined or glass flake/polyester-lined carbon
23
steel. Costs for these materials, however, are less than those for
stainless steel. Thus, the costs presented in this section should be
conservative.
Caustic soda requirements take into account reagent utilization for S02
absorption, as well as HC1 control. Ninety percent removal of both
compounds is assumed. Cost-effectiveness is given in terms of HC1 removal
only, since it is the acidic material of concern for the purpose of this
study.
Results of the cost analysis are presented in Table 5.7-2.
Cost-effectiveness for scrubbing HC1 from the flue gas of the 381 Mg/day
(42C tons/day) MSW incinerator is $1,903/Mg ($l,726/ton) HC1 removed. The
scrubber on the 726 Mg/day (800 tons/day) unit requires $1,481/Mg
($1,344/ton) HC1 removed.
5-44
-------
TABLE 5.7-1. ASSUMPTIONS AND BASES USED IN COST ANALYSIS FOR
SODIUM-BASED SCRUBBERS APPLIED TO MODEL MSW
INCINERATORS
1. A retrofit factor of 1.3 was applied to capital costs.
2. Caustic soda requirements were obtained via S02 and HCL emissions
factors and stoichiometric mass balances.
3. Capital costs for material handling systems are based on information in
Reference 22.
4. Scrubber costs are based on algorithms and cost data from References 1
and 23.
5. Capital recovery charges are based on a 15 year equipment life and
10 percent interest rate.
6. Capital costs and annual costs were updated to March 1985 dollars using
CE plant cost indices and BLS producer price indices, respectively.
7. The price for caustic soda (50% NaOH) is S176/Mg (5160/ton). 1983
dollars, Reference 22.
8. The absorber is the spray baffle type.
9. The scrubber construction material is 316 stainless steel.
5-45
-------
TABLE 5.7-2. COST RESULTS FOR SODIUM-BASED SCRUBBERS ON MODEL MSW
INCINERATORS
Incinerator Capacity
726 Mg/D (800 TPD)
381 Mg/D (420 TPD)
Total Capital Investment
(S)
1,161,400
826,300
Total Operating & Maintenance
(S/yr)
576,400
315,900
Total Annual Cost
(S/yr)
760,700
448,700
*
HCL Emissions Reduction
(tons/yr)
514 (566)
236 (260)
S02 Emissions Reduction
Mg/yr (ton/yr)
271 (299)
127 (140)
Cost-Effectiveness
$/Mg ($/ton) (SOg removed)
2,800 (2,540)
3,530 (3,200)
Cost-Effectiveness
($/ton HCL removed)
1,482 (1,344)
1,903 (1,726)
"k
Based on emission factor (Reference 12) and 90 percent HCL removal
efficiency.
5-46
-------
5.8 REFERENCES
1. Laughlin, J. H., et al. (Radian Corporation), Industrial Boiler SO,
Cost Report, prepared for U. S. Environmental Protection Agency, Office
of Air Quality Planning and Standards, Research Triangle Park,
North Carolina, EPA-450/3-85-011, November 28, 1984. pp. 2-1 - 4-2.
2. PEDCo Environmental, Inc., Capital and Operating Costs for Industrial
Boilers, prepared for U. S. Environmental Protection Agency,
Cincinnati, Ohio, EPA-450/5-80-007, June 1979. p. 25.
3. Kocur, C. and P. Budzik (National Coal Association), Steam Electric
Plant Factors, Washington, D.C., 1982.
4. Anderson, R. T., Power. 127(5):54-59 (1983).
5. Smith, M., et al. (PEDCo Environmental, Inc.), EPA Utility FGD Survey:
July-September 1980, prepared for U. S. Environmental Protection
Agency, Research Triangle Park, North Carolina, EPA-600/7-80-029d,
(NTIS PB 81-142655) October 1980.
6. Radian Corporation, Industrial Boiler SO, Technology Update Report,
prepared for U. S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Research Triangle Park, North Carolina,
EPA-450/3-85-009, July 30, 1984. pp. 2-13 - 2-80.
7. Dickerman, J. C. and K. L. Johnson (Radian Corporation), Technology
Assessment Report for Industrial Boiler Applications: Flue Gas
Desulfurization, prepared for U. S. Environmental Protection Agency,
Research Triangle Park, North Carolina, EPA-600/7-79-178i,
(NTIS PB 80-150873), November 1979. p. 2-119.
8. California Air Resources Board, Air Pollution Control at Resource
Recovery Facilities, Sacramento, California, Hay 24, 1984. pp. 30-143.
9. Smith, E. 0., et al. (Black & Veatch Consulting Engineers), Full Scale
Scrubber Characterization of Conesville Unit 5, prepared for Electric
Power Research Institute, Palo Alto, California, EPRI CS2525,
August 1982. pp. iii, 10-4.
10. Sellars, F. M., et al. (GCA Corporation), National Acid Precipitation
Assessment Program Emission Inventory Allocation Factors, prepared for
U. S. Environmental Protection Agency, Research Triangle Park, North
Carolina, EPA-600/7-85-035, (NTIS PB86-104247), September 1985. p. 75.
11. Noll, K. E. and W. T. Davis, Power Generation: Air Pollution
Monitoring and Control, Ann Arbor Science Publishers, Inc., Ann Arbor,
Michigan, 1976. pp. 338-351.
5-47
-------
12. Misenheimer, D., et al.. (GCA Corporation), Hydrogen Chloride and
Hydrogen Fluoride Emission Factors for the NAPAP Emission Inventory,
prepared for U. S. Environmental Protection Agency, Research Triangle
Park, North Carolina, EPA-600/7-85-041, (NTIS PB 86-134020),
October 1985.
13. Huang, H. S. (Argonne National Laboratory), Control of NO from
Coal-Fired Boilers: Combustion Modification Techniques, prepared for
U. S. Department of Energy, October 1981. pp. xv-xx.
14. Acurex Corporation, Control Techniques for Nitrogen Oxides Emissions
from Stationary Sources, prepared for U. S. Environmental Protection
Agency, Research Triangle Park, North Carolina, EPA-450/1-78-001,
(NTIS PB 280034), January 1978. pp. 4-24 - 4-31.
15. U. S. Environmental Protection Agency, Research Triangle Park, North
Carolina, Review of New Source Performance Standards for Petroleum
Refinery Claus Sulfur Recovery Plants, EPA-450/3-83-014, August 1983.
16. U. S. Environmental Protection Agency. Sulfur Oxides Emissions from
Fluid Catalytic Cracking Unit Regenerators - Background Information for
Proposed Standards. EPA-450/3-82-013a, (NTIS PB 84-143254),
January 1984.
17. Uhl, V. W. (U. S. Environmental Protection Agency, Research Triangle
Park, North Carolina), A Standard Procedure for Cost Analysis of
Pollution Control Operation, Vol. I, EPA-600/8-79-018a,
(NTIS PB 80-108038), June 1979.
18. Rivers, M. E. and K. W. Riegel, Work Group Co-Chairmen. Work Group 3B
- Emissions, Costs and Engineering Assessment. U. S.-Canadian
Memorandum of Intent on Transboundary Air Pollution, June 15, 1982.
19. U. S. Environmental Protection Agency. Background Information - Review
of New Source Performance Standards: Primary Copper, Zinc, and Lead
Smelters. Volume 1. EPA-450/2-74-002a, (NTIS PB 237832),
October 1974.
20. Hossain, S. M., et al. (Catalytic, Inc.), Applicability of Coke Plant
Control Technologies to Coal Conversion, prepared for
U. S. Environmental Protection Agency, Research Triangle Park, North
Carolina, EPA-600/7-79-184 (NTIS PB 80-108954), August 1979.
pp. 40-104.
21. Primary Aluminum: Draft Guidelines for Control of Fluoride Emissions
from Existing Primary Aluminum Plants, U. S. Environmental Protection
Agency, Office of Air, Noise, and Radiation, Research Triangle Park,
North Carolina, EPA-450/2-78-049a, (NTIS PB 294938), February 1979.
5-48
-------
22. Andersen 2000 Inc., Sulfur Dioxide Removal Systems for Industrial
Boilers and Steam Generators and Chemical Feed Systems for these
Scrubbing Units, Peachtree City, Georgia, June 1983.
23. Berry, R. S. and G. S. Shareef (Radian Corporation), Sodium Scrubbing
Cost Algorithm Development, prepared for U. S. Environmental Protection
Agency, Office of Air Quality Planning and Standards, Research Triangle
Park, North Carolina, February 7, 1984. (EPA Docket No. A-83-27).
5-49
-------
6.0 RESEARCH AND DEVELOPMENT
With the focus on developing control technologies for removal of high
volume pollutants (SOg, N0X, PM), little research and development (R & D)
activity was uncovered in the acidic materials control area. Granular bed
filters have been tested for SOg and acid mist control on a primary copper
smelter (Section 6.3). Otherwise, acidic materials control can probably
benefit from work being done to improve existing controls or to develop new
technologies for control of the aforementioned high volume pollutants.
Recent development work in particulate collection include potential
improvements in costs and performance of electrostatic precipitators (ESP)
and fabric filters (Section 6.1), including better acid mist controls on wet
scrubbing systems. Electron-beam irradiation is a S0x/N0x control process
in early stages of development that converts S02 and N0X to sulfuric acid
and nitric acid (Section 6.2) and ultimately to ammonium or calcium salts.
Successful acidic materials control will depend on particulate control
performance for removal of these salts as well as reaction kinetics for the
ensuing reactions. This further highlights the need for developing improved
particulate controls.
6.1 RESEARCH AND DEVELOPMENT IN PARTICULATE CONTROL
Several technologies available for the control of acidic materials
involve the injection of sorbents into flue gas followed by particulate
collection in a fabric filter or an electrostatic precipitator. Examples of
these technologies include lime spray drying and sodium dry injection for
coal-fired boilers and alumina dry injection for primary aluminum smelters.
Application of sorbent injection technologies may result in the need
for 1) modification of existing particulate control equipment or
2) installation of new equipment to meet particulate emission requirements.
The choice between modifying existing equipment (if present) and installing
6-1
-------
new equipment will generally be based on economics. However, another
consideration is the effect that this choice may have on the acidic material
removal capability of the sorbent injection technology. Many of the
injection technologies rely on the intimate flue gas/sorbent contacting that
occurs on the surface of fabric filters to achieve effective acidic
materials control.
Recent R&D activities in the area of particulate control offer
potential improvements in 1) the costs and particulate removal performance
of ESP's and 2) the costs of fabric filters. These R&D activities are
summarized briefly in the following sections. Discussions in the following
sections are based on readily available information.
6.1.1 Electrostatic Precipitators
Recent ESP research is largely directed toward the improvement of
removal performance with high resistivity dusts. Results of this work will
also be applicable to situations where improved ESP performance is needed to
allow acidic materials control. Areas of on-going research involve the use
of large diameter electrodes and particle precharging techniques.
Pilot- and laboratory-scale studies conducted under EPA funding have
shown that the use of large diameter, smooth-surface electrodes can provide
a significant improvement in ESP performance, especially when high
resistivity dust is collected. Recent test results indicate that large
diameter wires can reduce the penetration of the ESP for high resistivity
12
dust (> 2 x 10 ohm-cm) by a factor of 4 and the penetration for moderate
resistivity dust (8 x 1010 ohm-cm) by a factor of 1.25.1 Performance of the
ESP is improved because the large diameter electrodes allow operation at
high field strengths and useful current densities. Cost analyses indicate
that the large diameter wire technology should be economical for dust
resistivities greater than about 8 x 10*° ohm-cm.
One promising precharger technique currently under investigation is the
cold-pipe precharger. The cold-pipe precharger, shown in Figure 6-1,
consists of discharge wires interspersed with grounded pipes through which
cooling water flows. The purpose of the cooling water is to cool the dust
6-2
-------
High Nfottaga Insulator
Water
tntet
Figure 6-1. Cold-pipe precharger.
6-3
-------
layer that forms on the pipes and thus lower the dust resistivity. Based on
3
EPA pilot tests (28 actual m /min) with high resistivity dusts, the use of
cold-pipe precharging in combination with large diameter electrodes can
reduce the collection plate area required for a given collection efficiency
to 20 or 25 percent of that needed for a conventional ESP.
6.1.2 Fabric Filtration
Recent R&D activities in the fabric filtration area involve
electrostatically augmented fabric filtration (ESFF). The ESFF technology
uses an electric field parallel to the fabric surface to reduce the flow
resistance of the collected dust. This reduced resistance results in lower
fabric filter pressure drops and thus may allow operation at increased
operating face velocities.
For pulse-jet FSFF operation, the electric field is generated using a
special filter bag cage in which alternate cage rods are electrically
connected. A typical cage-type electrode is illustrated in Figure 6-2.
Electrodes for reverse-air units consist of filter bags with stainless steel
yarns, each containing 90 filaments, woven into the fabric.
Changes in the pattern of dust deposition on the filter that may
2
account for the reduced pressure drop include:
- an increased fraction of dust collecting on or near
the upstream surface of the filter (instead of penetrating
deep within the filter),
- changes in the pattern of particle collection, such as
more dendritic collection and bridging, and
- formation of a highly non-uniform dust deposit on the
filter surface.
Pilot-scale testing of ESFF on both pulse-jet and reverse-air cleaned
baghouses has shown about a 50 percent reduction in pressure drop when
compared to a conventional baghouse. These tests were conducted on a 7.1
actual m /hr (15,000 acfm) pilot unit treating flue gas from an industrial
coal-fired boiler. The pilot unit consisted of two baghouses, one ESFF unit
6-4
-------
Wo Wad 8f Points
of Contact
Top Cap
High Voftago
Boctrodos
Ceramic Insulators
Bag
Qioundod
Boctrodos
Approximate) Top
of Thimble
Figure 6-2. Reverse-air "RIGID" cage.
6-5
-------
and one conventional unit, operated in a parallel arrangement. During the
testing, no significant reduction in particulate removal performance was
observed for ESFF operation.
Economic analyses indicate that the power savings associated with the
reduced pressure drop of ESFF do not justify installation on existing
baghouses or on new baghouses that will operate at conventional face
velocities (i.e., the velocity through the bag). However, operation of an
ESFF baghouse at an increased face velocity appears to be an attractive
alternative and the pilot data indicate that such operation, may be
possible.
For new units, an ESFF reverse-air system operated at 2 cm/s (4 ft/min)
using bags costing 3 times conventional bags would have an 11-percent
economic advantage over a conventional system at 1 cm/sec (2 ft/min).
Similarly, an ESFF pulse-jet system would have a 30-percent advantage at
3 cm/s (6 ft/min) compared to a conventional system at 2 cm/s (4 ft/min).
Costs for ESFF appear to be most sensitive to face velocity with bag
costs also being an important factor.
6.1.3 Impact of Particulate R&D on Acidic Materials
Research and development in the area of particulate matter control will
affect the control of acidic emissions by enhancing particulate control
performance. As discussed in the previous sections, improved particulate
removal can be achieved by modification of existing ESPs with large diameter
electrodes and particle precharging techniques. This type of modification
would reduce the emissions of sulfates under the following two retrofit
scenarios:
1) Upgrading the performance of an existing ESP, and
2) Upgrading the performance of an existing ESP in combination with a
sorbent injection technology which would reduce sulfate emissions
by neutralizing SOg and acid sulfates with the sorbent.
6-6
-------
Additionally, improved acidic material removal would be achieved by
modifying an existing fabric filter system combined with sorbent injection
such that the sorbent could be injected without increasing the system
pressure drop.
Improved particulate control after wet scrubbing would also reduce
emissions of acid mist. Currently, almost all wet scrubbing systems control
aerosol emissions from the absorber with mist eliminators. However, if a
high-efficiency ESP was placed downstream of the scrubber, instead of a
conventional mist eliminator, acid sulfate removal would improve.
In fact, a petroleum coke-fired cogeneration plant now under
construction, with a heat input of approximately 15,230 GJ/hr
(15,000 million Btu/hr), will use a wet ESP for SO, and acid mist control
3
following a wet limestone scrubber. Wet ESPs use water to wash material
away from the collection plates rather than rapping, which is used by dry
ESPs.
6.2 ELECTRON-BEAM IRRADIATION
An area of non-particulate R&D which could affect acidic material
control is electron-beam (E-beam) irradiation. E-beam processes involve the
irradiation of flue gas containing a reactant, such as ammonia or lime. The
process removes both SOg and N0X from the flue gas and produces a dry waste
product that must be subsequently removed in a particulate collector.
A schematic diagram of the E-beam/ammonia process is shown in
Figure 6-3. In this process, incoming flue gas is cooled and humidified in
a water quench tower, resulting in a gas moisture content of about
10 percent. Ammonia is injected into the cooled gas and the gas is passed
through an E-beam reactor. In the reactor, oxygen and water are ionized to
form the radicals [HO], [0], and [HOg] by the application of electrons at a
dose of 1 to 3 Mrads (1 Hrad is equivalent to 10 joules/g of flue gas).
These radicals react with S0£ and N0X to form sulfuric acid (HgSO^) and
nitric acid (HN03). The acids are neutralized by ammonia and water in the
flue gas to form solid ammonium sulfate ((NH^SO^) and ammonium sulfate
nitrate ((NH4)2S04 2 NH^NOj). The reaction time for formation of the
6-7
-------
Additionally, improved acidic material removal would be achieved by
modifying an existing fabric filter system combined with sorbent injection
such that the sorbent could be injected without increasing the system
pressure drop.
Improved particulate control after wet scrubbing would also reduce
emissions of acid mist. Currently, almost all wet scrubbing systems control
aerosol emissions from the absorber with mist eliminators. However, if a
high-efficiency ESP was placed downstream of the scrubber, instead of a
conventional mist eliminator, acid sulfate removal would improve.
In fact, a petroleum coke-fired cogeneration plant now under
construction, with a heat input of approximately 15,230 GJ/hr
(15,000 million Btu/hr), will use a wet ESP for SO, and acid mist control
3
following a wet limestone scrubber. Wet ESPs use water to wash material
away from the collection plates rather than rapping, which is used by dry
ESPs.
6.2 ELECTRON-BEAM IRRADIATION
An area of non-particulate R&D which could affect acidic material
control is electron-beam (E-beam) irradiation. E-beam processes involve the
irradiation of flue gas containing a reactant, such as ammonia or lime. The
process removes both S02 and N0X from the flue gas and produces a dry waste
product that must be subsequently removed in a particulate collector.
A schematic diagram of the E-beam/ammonia process is shown in
Figure 6-3. In this process, incoming flue gas is cooled and humidified in
a water quench tower, resulting in a gas moisture content of about
10 percent. Ammonia is injected into the cooled gas and the gas is passed
through an E-beam reactor. In the reactor, oxygen and water are ionized to
form the radicals [HO], [0], and [HOg] by the application of electrons at a
dose of 1 to 3 Hrads (1 Hrad is equivalent to 10 joules/g of flue gas).
These radicals react with SOg and N0X to form sulfuric acid (HgSO^) and
nitric acid (HNOj). The acids are neutralized by ammonia and water in the
flue gas to form solid ammonium sulfate ((NH^SO^) and ammonium sulfate
nitrate ((NH^SO^ 2 NH^NOg). The reaction time for formation of the
6-7
-------
Asaonia
Stack
E-gun
ID
Booatrr
Kan
Particu-
late
Collector
E-beaa
Reactor
Quench
. Tower
Flue
Gaa
¦^"Product Sollda
Drain
Figure 6-3. E-beam/ammonia process flow diagram.
-------
sulfate and nitrate salts is less than one second. Product solids are
collected in a hopper below the E-beam reactor or in a downstream
particulate collector.
In another version of the E-beam process, the water quench tower is
replaced with a lime-based spray dryer (see Section 2.2.1). Reactions in
the E-beam reactor occur in the same manner as above except that the
products formed are calcium salts (CaSO^, Ca(N03)2, and CaS03) instead of
ammonium salts.4
6.3 GRANULAR BED FILTER
A system which has been tested for S03 and acid mist control on a
primary copper smelter is the sorbent injection/granular bed filter
5
process. This process uses an electrostatically charged sorbent in
combination with moving granular bed filters for dual acid gas/particulate
control. A dry sorbent (e.g., hydrated lime, soda ash) is electrostatically
charged and injected into the hot flue gas. The gas stream then enters a
collection chamber where it passes through a series of moving granular bed
filters. The particulate matter and reaction products are collected in the
filters. As the granular bed of each filter moves through the chamber and
is discharged, the filter media are screened to remove collected material.
Table 6-1 presents the results of a pilot test conducted at a primary
copper smelter's reverberatory furnace. The off-gas first passed through an
ESP operated to achieve 95 percent particulate removal and then through the
sorbent/filter system.
6-9
-------
TABLE 6-1. EMISSIONS TEST DATA FOR A GRANULAR BED FILTER
APPLIED TO A COPPER SHELTER3'b
Inlet
Outlet
Removal
g/m3 (gr/dscf)
g/m3 (gr/dscf)
%
0.5991 (0.2618)
0.0098 (0.0043)
98.3
0.2883 (0.1260)
0.0178 (0.0078)
93.8
0.4661 (0.2037)
0.1638 (0.0716)
64.8
Average 0.4513 (0.1972)
0.0638 (0.0279)
85.6
?Emissions data given in terms of S03/H2S0.
Source: Reference 5.
mist.
6-10
-------
6.4 REFERENCES
1. Plaks, N. (U.S. Environmental Protection Agency), An Overview of the
EPA Particulate Technology R&D Program, JAPCA 35:4, pp. 400-405,
April 1985.
2. Van Osdell, D. W. (Research Triangle Institute) and D. A. Furlong
(ETS, Inc.), Electrostatic Augmentation of Fabric Filtration:
Reverse-Air Pilot Unit Experience, prepared vor U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
EPA-600/7-84-085, (NTIS PB 84-230002), August 1984.
3. Shroff, G. H., A. F. Papa, and J. M. Whalen, Chem. Ena. Proa..
81(10):51-56 (1985).
4. Radian Corporation, Industrial Boiler S02 Technology Update Report,
prepared for U. S. Environmental Protection Agency, Research Triangle
Park, North Carolina, EPA-450/3-85-009, July 30, 1984.
5. Letter from Hudnall, K. A. (NEXCO Corporation) to Carlton, D. H.
(Radian Corporation). August 30, 1985.
6-11
-------
APPENDIX A
DERIVATION OF ACIDIC EMISSIONS ESTIMATES
A-i
-------
TABLE OF CONTENTS
Section Page
A.l Sulfate Emission Sources A-l
A.2 Chloride Emission Sources A-19
A.3 Fluoride Emission Sources A-24
A.4 Nitrate Emission Sources A-32
A. 5 References A-34
LIST OF FIGURES
Figure
A-l Estimated Residential Coal Consumption in 1974
by State A-23
. A-2 Location of Alumina Plants and Aluminum Smelters
in the United States A-30
LIST OF TABLES
Table
A-l National Sulfate Emissions A-3
A-2 Acid Sulfate Emissions from Coal-fired Utility Boilers A-4
A-3 Sulfate Emissions from Residual Oil-fired Utility Boilers A-6
A-4 Acid Sulfate Emissions from Coal-fired Industrial
Boilers A-8
A-5 Acid Sulfate Emissions from Residual Oil-fired
Industrial Boilers A-10
A-6 Domestic Primary Copper Smelters A-15
A-7 Domestic Primary Zinc Smelters A-17
A-8 HC1 Emissions A-20
A-9 HF Emissions A-25
A-10 Summary of N02 and Nitrate Emissions Estimates A-31
A-i i
-------
APPENDIX A - ACIDIC EMISSIONS ESTIMATES
A literature search was done to identify domestic combustion and
industrial sources of acidic emissions. Based on the information found for
each source category, emissions estimates were made. Generally, this v/as
accomplished via emission factors and national process capacities found in
the literature.
This section presents the estimates for each category and the methods
by which they were derived. The acidic materials discussed are sulfates,
HC1, HF, and nitrates. Section A.l discusses sulfate emission sources.
Sections A.2 and A.3 cover sources of HC1 and HF emissions, respectively.
Sources of nitrate emissions are discussed in Section A.4.
Emissions are discussed in terms of national emissions and local
emissions. National emissions refer to the total emissions of a given
substance in the U.S. by a specific combustion or industrial source. Local
emissions deal with the possibility of high emission levels in a specified
area of the U.S. This could result when a large plant or a concentration of
plants, representing a single source category, exists in the area of
concern.
A.l SULFATE EMISSION SOURCES
This section contains an analysis of available information on sulfate
emissions from industrial sources and electric utilities. The approach used
was to use the best existing data; no new information was generated.
The work that Working Group 3B (WG3B) did on estimating sulfate
emissions was used as a starting point (Reference 1). That information was
augmented with Background Information Documents for air standards,
U.S. Mineral Industry Surveys, and other references. National Emissions
Data System (NEDS) data were used in some cases. These data were used only
as a last resort, however, because obvious frequent omissions were evident.
A-l
-------
The overall results of the study of sulfate emissions are shown in
Table Al. As the table shows, highest national emissions were estimated
for utility boilers, industrial boilers, Kraft pulp mills, and cement
plants. Possible high local sulfate ambient air concentrations were
indicated for coke plants, primary copper smelters, and Claus plants.
Two additional sources not included in this study were included in
WG3B's estimates: iron and steel sintering and sulfite pulp mills.
Insufficient data were found to estimate sulfate emissions from those
sources.
The basis for the sulfate emissions data in Table A-l and the sources
of information are given in the remainder of Section A.l.
A.1.1 Electric Utilities
A. 1.1.1 National Emissions—Coal-Fired Boilers. Reference 2 presented
primary sulfate emission factors for coal-fired utilities. The factors were
0.175 kg (0.385 lbs) and 0.89 kg (1.95 lbs) sulfate emitted per ton of
bituminous and lignite coal burned, respectively. WG3B estimated sulfate
emissions to be about 1.2 percent of SOg emissions from coal-fired
utilities.
An estimate of the coal-fired utility capacity controlled with FGD
systems was made. A report entitled "Typical Sulfur Dioxide Emissions from
Subpart D Power Plants Firing Compliance Coal" [PEDCo Environmental, Inc.,
March 1984] contains a list of 62 utilities subject to the new source
performance standard. The capacity represented by the list represented
about 20 percent of the total coal-fired utility capacity (Reference 5).
Taking the average emission rate (controlled condensation system tests only)
for FGD-controlled sulfate emissions and the average emission rate for
ESP-controlled sulfate emissions and weighting them to reflect 20 percent
FGD control, results in an emission rates of 0.14 kg (0.30 lbs) sulfate/ton
bituminous coal burned and 0.69 kg (1.52 lbs) sulfate/ton lignite coal
burned.
A summary of data for sulfate emissions from utility boilers
(Reference 2) included the test results shown in Table A-2. This table
shows that for a limited number of test sites the range in sulfate emissions
A-2
-------
TABLE A-l. NATIONAL SULFATE EMISSIONS
Source Category
Total Sulfate,Emissions
10J Hg/yr (10J tons/yr)
Comments
(1) Utility Boilers
Coal 107
Residual 011 39
Distillate Oil 7.3
(2) Industrial Boilers
Coal 24-95
Residual 011 10-21
Distillate Oil 52
(3) Kraft Pulp Hills
Recovery Boiler 204
(4) Cement Plants 159
(5) Gypsum Plants 73
(6) Catalytic Cracking 11.3
(7) Primary Copper 8.6-10.5
(8) Claus Plants 5.4
(9) Coking 5
(10) Sulfuric Acid Plants 1.8
(11) Primary Zinc 0.45
(12) Primary Aluminum 0.18-0.41
(117)
(43)
(8)
(26-105)
(11-23)
(57)
(225)
(175)
(80)
(12.5)
(9.5-11.5)
(6)
(5.5)
(2)
(0.5)
(0.2-0.45)
TOTAL
708-792 (778-873)
100% acid sulfate
67% acid sulfate
50% acid sulfate
85% acid sulfate
50% acid sulfate
55% acid sulfate
Sulfate is mostly NajSO^ (neutral)
Particulates (probably refractory)
CaS04 (neutral)
All acid sulfate
*AZ, NH; all acid sulfate
*HS, HY; all add sulfate
•PA, IN, OH; all acid sulfate
HjSOj mist
All acid sulfate
36% acid sulfate
54% non-acidic sulfate
10% undetermined sulfate
"Possible high local ambient air concentrations.
A-3
-------
TABLE A-2. ACID SULFATE EH1SS10NS FROM COAL-FIRED UTILITY BOILERS3
Fuel Sulfur
Boiler Size Content Emission . Sulfate Emission
Coal Type
(MW)
(Weight X)
Control
Test Method
kg/Mg (lb/ton)
Bituminous
125
0.9
ESP
CCS
0.146 (0.293)
Bituminous
163
0.9
ESP
CCS
0.148 (0.296)
Bituminous
156
3.3
ESP
CCS
0.190 (0.381)
Bituminous
156
3.3
ESP & FGD
CCS
0.134 (0.269)
Bituminous
560
1.0
ESP
. CCS
0.081 (0.162)
Bituminous
411
3.5
ESP & FGD
CCS
0.139 (0.279)
Lignite
440
1.3B
ESP
Method 6
0.975 (1.951)
Bituminous
700
1.10
None
Method 6
0.813 (1.627)
Bituminous
700
1.10
FGD
Method 6
0.380 (0.761)
Bituminous
468
1.67
ESP
Method 6
0.645 (1.290)
Bituminous
411
4.7
ESP
CCS
0.396 (0.793)
Bituminous
411
4.7
ESP & FGD
CCS
0.240 (0.480)
aSource: Reference 2.
bCCS 3 controlled condensation system.
-------
is 0.146 to 0.975 kg (0.293 to 1.951 lbs) per ton of coal. It can be
inferred from the limited data set that acid sulfate emission factors in the
0.14 to 0.19 kg (0.3 to 1.5 lbs) per ton range are representative. The data
also indicate that FGD systems reduce the amount of sulfates emitted.
The coal-fired utility emissions were extrapolated to a national total
using the quantity of coal burned in the utility sector. Reference 6
reports 495 million Mg (545 million tons) of bituminous coal and 43 million
Mg (47 million tons) of lignite coal burned in the utility sector in 1982.
Applying the bituminous and lignite emission factors results in total
national acid sulfate emissions of 107,000 Mg (117,500 tons) per year.
Oil-Fired Boilers. WG3B (Reference 1) estimated sulfate emissions from
distillate oil-fired boilers were estimated to be 8.2 percent of S02
emissions. Reference 2 normalized those estimates to production rates
included in NEDS and estimated (12 lb/1,000 gal) distillate burned. A
review of emission data (Reference 2) included tests of 3 oil-fired units.
The data are summarized in Table A-3. These data indicate that an emission
factor of 1.4 kg/m3 (12 lb/1,000 gal) may be high by a factor of 2.
Reference 2 presents a primary sulfate emission factor for residual
oil-fired utility boilers of 0.63 kg/m3 (5.44 lbs/1,000 gal).
3
Reference 7 reports 62 million m (390 million barrels) of residual oil
3
fired in the utility sector in 1980. Applying the 0.63 kg/m
(5.44 lb/1,000 gal) emission factor to the quantity consumed results in an
estimate of national sulfate emissions of 39,000 Mg (43,000 tons) from
residual oil-fired utilities.
No sulfate emissions numbers for distillate oil-fired boilers other
than the WG3B estimate were found. Reference 2 derived an emission factor
of 1.4 kg/m3 (12 lb/1,000 gal) burned from WG3B's estimate and the
production rate data in NEDS. Applying the factor to the total amount of
distillate fired in the utility industry (5 million m (32 million barrels))
(Reference 7 results in national sulfate emission estimate of 7,300 Mg
(8,000 tons) from distillate oil-fired utility boilers.
WG3B estimated that 65 percent of the total sulfate produced in
residual-fired utilities is acid sulfate, while 50 percent of the total
sulfate produced in distillate-fired utilities is acid sulfate
A-5
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TABLE A-3. SULFATE EMISSIONS FROM RESIOUAL OIL-FIRED UTILITY BOILERS
Unit Size3
(MW)
Fuel Sulfur
Content
(Weight %)
Emission
Controls
Sulfate Emissions
kg/1000 m3 (lb/1,000 Gal)
100
1.88
Fuel Additive
0.61 (5.089)
100
1.72
Fuel Additive
0.67 (5.589)
100
1.45
Fuel Additive
0.68 (5.640)
Source: Reference 2.
aThree units at one plant.
A-6
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(Reference 1). Applying their acid sulfate estimates would indicate that
acid sulfate emissions from residual-fired utilities would be about
12,500 Mg (28,000 tons) per year. Similarly, acid sulfate emissions from
distillate-fired utility boilers would be about 4 million kg (8 million lbs)
per year.
A.1.1.2 Local Emissions. Utility combustion sources appear to be
dispersed widely throughout the U.S. However, electric utilities are large
sources and high local sulfate ambient air concentrations could result in
their vicinity.
A.1.2 Industrial Boilers
A.1.2.1 National Emissions. In the industrial boiler category WG3B
estimated sulfate emissions to be 1.6 percent of SO^ emissions. Reference 2
normalized this estimate to 0.304 kg/Mg (0.608 lb/ton) for anthracite and
bituminous coals and 0.240 kg/Mg (0.480 lb/ton) for lignite. Arbitrarily
multiplying 0.25 kg/Mg (0.5 lb/ton) by 95 million Mg (105 million tons) of
coal used in the industrial sector (Reference 6) results in a national
sulfate emissions estimate of 23,600 Mg (26,000 tons) per year.
A review of sulfate emissions data (Reference 2) included 3 test
results from coal-fired industrial boilers. (See Table A-4.) The two data
points obtained with the CCS method indicate that the actual emission factor
may be higher by a factor of 4, considering that FGO systems are not common
among industrial boilers. Using a factor of 0.9 kg/Mg (2 lb/ton) coal
burned results in an estimate of 95,300 Mg (105,000 tons) sulfate per year.
WG3B estimated that 85 percent of the sulfate emissions from non-utility
combustion of coal are acid sulfate emissions. Applying this factor would
indicate that acid sulfate emissions from industrial coal-fired boilers are
about 20,000 to 81,000 Mg/yr (22,000 to 89,000 tons/year).
WG3B estimated emissions of sulfate from oil-fired industrial boilers
to be 8.2 percent of SOg emissions. Reference 2 presented an emission
factor based on WG3B's estimate and combustion rates in NEDS of 1.4 kg
3
sulfate/m (12 lb sulfate/1,000 gal) for distillate oil fired in industrial
boilers. No other sulfate emission data were found for distillate oil-fired
industrial boilers. Multiplying the 1.4 kg sulfate/m (12 lb
A-7
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TABLE A-4. ACID SULFATE EMISSIONS FROM COAL-FIREO INDUSTRIAL BOILERS
Fuel Sulfur
Acid
Boiler
Content
Emission
Sulfate Emissions
Size
(Weight %)
Control Test Method
kg/Mg (lb/ton)
10 MW
1.64
Multiclone CCS
1.323 (2.646)
10 MW
1.64
Multiclone & CCS
0.230 (0.462)
FGD
100,000 lb
0.91
ESP Method 8
0.099 (0.199)
steam/hr
A-8
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sulfate/1,000 gal) by the amount of distillate fired in the industrial
sector results in an estimate of 52 million kg (114 million lbs) of sulfate
from distillate oil-fired industrial boilers. WG3B estimated 50 percent of
the sulfate emissions from industrial oil combustion to be acid sulfates.
This would indicate that about 27,200 Mg (30,000 tons) of the potential
sulfate emissions are acid sulfates.
Results of two tests of one residual-fired industrial boiler were
reported (Reference 2) as shown in Table A-5. The primary sulfate emission
3
factors resulting from these tests were 0.63 kg/m (5,30 lbs/1,000 gal) and
3
0.31 kg/m (2.62 lbs/1,000 gal) for uncontrolled and controlled boilers,
respectively. Multiplying these factors by the quantity of residual oil
burned in the industrial sector (Reference 7) results in primary sulfate
emissions of 10,000 to 21,300 Hg (11,000 to 23,500 tons) per year. Using
WG3B's estimate that 50 percent of sulfates produced in industrial oil
combustion are acid sulfates, acid sulfates would be about 5,000 to
10,400 Hg (5,500 to 11,500 tons) per year.
A.1.2.2 Local Emissions. Industrial combustion sources appear to be
widely dispersed throughout the U.S. No high local sulfate concentrations
are expected, but industrialized areas may contribute significant quantities
of sulfate emissions from combustion.
A.1.3 Coke Production
A.1.3.1 National Emissions. The WG3B sulfate emissions estimate for
coke production is 8.2 percent of the SOg emissions. Reference 2 normalized
that estimate to the production rate in NEDS and came up with 0.15 kg/Mg
(0.3 lb/ton) coal charged. No other sulfate emission data were found.
Reference 8 reports 34 million Hg (37 million tons) of coal charged to coke
ovens in 1983. Using this quantity as a multiplier, national annual
emissions of sulfate from coking are estimated to be 5,000 Hg
(5,500 tons). All of the sulfate emissions are thought to be acid sulfate
(Reference 1).
A-9
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TABLE A-5. ACID SULFATE EMISSIONS FROM RESIDUAL OIL-FIRED INDUSTRIAL BOILERS
Boiler
Size
Fuel Sulfur
Content
(Weight X)
Emission
Control
Test
Method
Primary
Sulfate Emissions
kg/m (lb/1,000 Gal)
10 HW
1.96
Multiclone
CCS
0.63 (5.296)
10 HW
1.96
Multiclone &
FGD
CCS
0.31 (2.616)
A-10
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A.1.3.2 Local Emissions. As of 1980, Pennsylvania, Indiana, and Ohio
accounted for 23, 19, and 16 percent of total U.S. capacity, respectively.
However, it is not clear from this information whether local concentrations
of sulfate can be expected to be high because of sulfate emissions from coke
plants.
A.1.4 Sulfuric Acid Plants
A.1.4.1 National Emissions. WG3B used a sulfate emission factor of
0.05 kg/Mg (0.1 lb/ton) acid produced. Reference 9 reported uncontrolled
emissions of 0.18 to 1.8 kg (0.4 to 4 lbs) HgSO^ mist per ton of acid
produced. The same reference reported that about 5 percent of the acid
plants in the U.S. have no controls for acid mist. Reference 10 reported
NSPS compliance test data for 29 sulfuric acid plants, representing about
30 percent of the U.S. capacity (References 10,11). The average acid mist
emission rate reported was 0.04 kg/Mg (0.08 lb/ton) of acid produced. This
value agrees well with the WG3B factor of 0.05 kg/Mg (0.1 lb/ton) which was
used in this study.
Extrapolating to the national production rate of 1982 (Reference 11)
yields total national sulfate emissions of 1,800 Mg (2,000 tons) per year.
A.1.4.2 Local Emissions. Based on data listed in NEDS, Florida
accounts for 55 percent of the domestic sulfuric acid production. If these
data are correct, local sulfate concentrations could be high in that region.
However, major omissions noted in NEDS data for other industries makes it
difficult to judge the reliability of the data.
A.1.5 Gypsum Plants
A.1.5.1 National Emissions. Reference 12 estimates 73,000 Mg/yr
(80,000 tons/yr) of particulate emissions from the gypsum industry. If one
assumes the particulate matter to be calcium sulfate (neutral in water), one
can assume about 55 percent to be sulfate. Using these assumptions results
in a national emissions estimate of about 40,000 Mg (44,000 tons) sulfate
from gypsum production. This approach is similar to the one used by WG3B.
A-11
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These data are based on 1973 emissions estimates. However, since sulfate
emissions from gypsum plants are assumed to be non-acidic (calcium sulfate),
more recent emissions data were not pursued.
A.1.5.2 Local Emissions. Gypsum plants appear to be broadly
distributed throughout the U.S. and, thus, significant localized sulfate
emissions are not anticipated.
A.1.6 Kraft Pulp Hills
A.1.6.1 National Emissions. WG3B derived a sulfate emission factor of
85 percent of total particulate emissions for Kraft pulp mills. Based on
this factor sulfate emissions are estimated to be 29,200 Mg (32,200 tons)
per year. WG3B estimated no SOg emissions. However, other sources have
given estimates for SOg emissions. Reference 3 presents SOg emission rates
from recovery boilers as 0 to 6 kg/Mg (0 to 13 lb/ton) air dried pulp.
Using the mid-point of the range and production rates from Reference 13,
national emissions of 109,000 Mg SOg (120,000 tons SOg) are estimated.
However, to maintain consistency with this and other work in the National
Acid Precipitation Assessment Program (NAPAP), WG3B's estimate of no SOg
emission will be used. Controlled particulate emissions estimates of 0.5
to 25 kg/Mg (1 to 50 lb/ton) are presented in Reference 3. The major
constituent is reported to be Na2S0^ (neutral in water). Assuming all the
particulate emissions from the recovery boiler to be Na2S0^, using the
production rate of air dried pulp from Reference 12, and using the high side
of the range results in a national emissions estimate of 404,000 Mg
(445,000 tons) of particulate sulfate. Using a mid-point results in a
national emissions estimate of 204,000 Mg (225,000 tons) of sulfate. One
other estimate of particulate emissions was found. Reference 13 presents
uncontrolled particulate emission rates from the recovery furnace of 22
to 283 kg/Mg (44 to 565 lb/ton) of air dried pulp. It was assumed for
purposes of this study that most recovery boilers would be controlled to
some degree. Therefore, the controlled emission rate presented in
Reference 3 was thought to be more applicable.
A-12
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A.1.6.2 Local Emissions. NEDS production rate data totals about
27 million Hg (30,000,000 tons) of Kraft pulp. States with the largest
production rates and, therefore, the largest estimated sulfate emission
potential are (according to NEDS) Alabama, Georgia, and Florida. Alabama
accounts for 17 percent of the Kraft Pulping capacity. It is not clear from
these numbers whether local concentrations of sulfate can be expected to be
high because of sulfate emissions from Kraft pulp mills.
A.1.7 Catalytic Cracking
A.1.7.1 National Emissions. The WG3B sulfate emission factor for
catalytic cracking is 0.04 kg/m3 (15 lb/1,000 bbl) fresh feed. Sulfate
emissions data for catalytic cracking units were found in four other sources
(References 14, 15, 16, 17). Emissions test data for uncontrolled emissions
gave 0.08 and 0.05 kg/m3 (29 and 16 lb/1,000 bbl) for combined SOg and
sulfate (Reference 16). Controlled emission rates were about 2 orders of
magnitude lower (References 14, 15, 16, 17). The WG3B number agrees closely
with the uncontrolled emission rates. Applying the emission factor to the
nameplate capacity of 831,540 m3/sd (5,230,400 bbl/sd) for catalytic
cracking in 1983 (Reference 18) gives a national potential emissions
estimate of 11,300 Hg (12,500 tons) of sulfate emissions per year. The test
data provided in References 14 through 17 indicate that all of the sulfate
emissions are acid sulfate.
A.1.7.2 Local Emissions. Catalytic cracking capacity and estimated
potential sulfate emissions are highest in Texas which accounts for
30 percent of U.S. capacity. Louisiana accounts for 15 percent. These
figures do not indicate any clearly defined areas of high local sulfate
concentrations. However, sulfate emissions will be high in areas of Te::as
and Louisiana where petroleum refineries are concentrated.
A.1.8 Primary Aluminum
A.1.8.1 National Emissions. WG3B estimated that sulfate emissions
from primary aluminum smelters were about 0.5 percent of the SOg emissions.
No other sulfate emissions data were found. Reference 4 estimated that SO^
A-13
-------
emissions would amount to 6 to 13 Hg/day (7 to 14 tons/day) for a 545 Mg/day
(600 ton/day) plant. Combining the WG3B factor with the estimate in
Reference 4, the sulfate emissions would amount to 0.060 to 0.120 kg/Mg
(0.120 to 0.240 lb/ton) aluminum. In 1983, 3,310,000 Mg (3,640,000 tons) of
primary aluminum were produced (Reference 19). Based on that production
rate, national sulfate emissions from primary aluminum production would then
be 180 to 410 Mg (200 to 450 tons) per year. WG3B indicated that the
sulfates emitted from aluminum smelters are acid sulfates (Reference 1).
A.1.8.2 Local Emissions. Sulfate emissions from individual aluminum
smelters appear to be low, and high local sulfate concentration would not be
expected.
A.1.9 Primary Copper
A.1.9.1 National Emissions. WG3B estimated that two tons of SO2 are
generated per ton of copper produced in primary copper smelters. They also
estimated that acid sulfates emissions equal 1.35 percent of SOg emissions.
Combining these factors yields an emissions estimate of 25 kg (54 lbs) of
acid sulfate per ton of copper smelted. Sulfuric acid emissions data were
found in two test reports for copper smelters. Both were tests of scrubbers
on electric slag cleaning furnaces. Sulfuric acid levels for both scrubbers
were 0.14 kg/hr (0.03 lb/hr) at the scrubber inlet and 0.03 kg/hr
(0.07 lb/hr) at the scrubber outlet (References 20, 21). It was unclear
from the test reports how these values could be related to the copper
production rate at the smelter.
Reference 22 reported 1.16 million tons of copper smelted in the U.S.
in 1984. Reference 23 estimated 70 percent control of SOg at copper
smelters. Applying these estimates to the WG3B emissions factor of
27 kg acid sulfate/Mg (54 lbs acid sulfate/ton) copper smelted yields
8,600 Mg (9,500 tons) of acid sulfates. Reference 23 also estimated
2,177 kg (4,800 lbs) S02 generated/ton copper smelted. Combining this with
the WG3B estimate of 0.0061 kg (0.0135 lbs) acid sulfate/lb SOg and assuming
A-14
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TABLE A-6. DOMESTIC PRIMARY COPPER SMELTERS
Annual
Capacity
Company
Location
Mg
Tons
ASARCO, Incorporated
El Paso, Texas
Hayden, Arizona
91,000
182,000
100,000
200,000
Tennessee Chemical Company
Copperhill, Tennessee
13,600
15,000
Copper Range Company
White Pine, Michigan
52,000
57,000
Inspiration Consolidated
Copper Company
Miami, Arizona
136,000
150,000
Kennecott Minerals Company
(SOHIO)
Hayden, Arizona
Hurley, New Mexico
71,000
73,000
78,000
80,000
Magma Copper Company
San Manuel, Arizona
181,000
200,000
Phelps Dodge Corporation
Douglas, Arizona
Hidalgo, New Mexico
115,000
163,000
127,000
179,000
Source: Reference 23, p. 3-2.
A-15
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70 percent control yields 10,400 Mg (11,500 tons) of acid sulfate. Thus,
total domestic acid sulfates emissions from primary copper smelters are
8,600 to 10,400 Mg (9,500 to 11,500 tons) per year.
A.1.9.2 Local Emissions. Table A-6 shows locations and capacities
for primary domestic copper smelters. The vast majority are located in the
Western U.S. In fact, Arizona and New Mexico account for 80 percent of
domestic capacity. This area may see high concentrations of sulfate
from copper smelters.
A.1.10 Primary Zinc
A.1.10.1 National Emissions. Reference 2 reported a sulfate emission
factor for primary zinc smelting of 27.7 kg/Mg (55.5 lb/ton) processed.
This emission factor was derived from WG3B's estimate of 5 percent of S02
emissions and the production rate data in NEDS. No other sulfate emissions
estimates were found for zinc smelters. Reference 24 reported 261,750 Mg
(288,525 tons) of slab zinc smelted in 1983. These figures would indicate
that uncontrolled emissions of sulfate from domestic primary zinc smelters
would be about 16 million pounds per year. Controlled sulfate emissions
from zinc smelters are expected to be much lower. All currently operating
primary zinc smelters in the U.S. employ contact sulfuric acid plants for
S0g control (Reference 25). These acid plants achieve a 96 percent S02
removal efficiency (Reference 1). Since the process involves high
efficiency acid mist elimination and S03 absorption, concurrent sulfate
control is assumed. This yields controlled sulfate emissions of
450 Mg (500 tons) per year. It is unclear whether the smelter related acid
plants are included in the sulfuric acid plant category (Section A.1.4) or
are a separate source category.
A.1.10.2 Local Emissions. Table A-7 shows primary zinc smelters in
the U.S. Using WG3B's estimate of 5 percent of the S02 emissions, the
following emissions estimates were derived (Reference 26) for some of the
zinc smelter acid plants:
- Jersey Miniere Zinc/Clarksville, TN: about 435 Mg/yr (478
tons/yr) S02; about 21.3 Mg sulfate/yr (23.5 tons sulfate/yr).
A-16
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TABLE A-7. DOMESTIC PRIMARY ZINC SMELTERS
Plant
Location
Capacity8
Mg/yr (tons/yr)
Sulfate Emissions
Mg/yr (tons/yr)
ASARCO/Corpus Chrlstl
Corpus Chrlstl, Texas *
100,000 (110,000)
15.5 (17.0)
AMAX/Saugot
Sauget, Illinois
72,700 (80,000)
16.2 (20.0)
Jersey Mlnlere Z1nc
National Zinc
Clarksvllle, Tennessee
61,600 (90,000)
21.4 (23.5)
Bartlesvllle, Oklahoma
50,900 (56,000)
—
St. Joe/Monaca
Monaca» Pennsylvania
90,900 (100,000)b
~
aZ1nc production capacity.
bTh1s Includes 60,000 tons/yr of zinc and 20*000 tons/yr zinc equivalent of zinc oxide.
\
-------
- AMAX/Sauget, IL: about 360 Mg/yr (400 tons/yr) SO^; 18
Mg sulfate/yr (20 tons sulfate/yr).
- ASARCO/Corpus Christi, TX: about 305 Mg/yr (335 tons/yr) S02;
about 15.5 Mg sulfate/yr (17 tons sulfate/yr).
A.1.11 Cement Plants
A.1.11.1 National Emissions. WG3B's uncontrolled sulfate emission
factor is 2.8 kg sulfate/Mg (5.6 lb sulfate/ton) cement (Reference 2).
Reference 27 reports finished cement capacity of 95 million Mg
(104 million tons) and a capacity utilization of about 0.6 for 1983.
Combining these numbers to get a production rate and applying the 2.8 kg/Mg
(5.6 lb/ton) emission factor results in a national sulfate emissions
estimate of 160,000 Mg (175,000 tons) from cement production. The
particulate emissions from cement manufacture are expected to be of a
refractory nature and, therefore, not very soluble in water. Thus, they
would not readily form acid deposition.
A.1.11.2 Local Emissions. Based on data from NEDS, no one state has
more than 10 percent of tl.d U.S. cement plant capacity. Thus, no high local
sulfate concentrations are anticipated.
A.1.12 Claus Plants
A.1.12.1 National Emissions. The sulfate emission factor derived by
WG3B for Claus plants is 1 percent of the S02- Reference 2 presented an
emission factor normalized to the NEDS production rate data of 1.4 kg/Mg
(2.8 lb/ton) of sulfur processed (Reference 2). No other sulfate emissions
data were found. Reference 28 reports that sulfur recovered from petroleum
refineries and natural gas plants amounted to 39,000 Mg (4.3 million tons)
in 1980. Combining the two factors, national sulfate emissions from Claus
plants would be about 5,400 Mg/yr (6,000 tons/yr). All of the sulfate
emissions from Claus plants are thought to be acid sulfate (Reference 1).
A.1.12.2 Local Emissions. Reference 28 reports that 49 Claus plants
are located in Texas, 10 in New Mexico, 13 in Mississippi-Alabama-Florida,
and 8 in Wyoming. Neither production rate nor capacity are presented by
A-18
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state, however, except for companies with only one plant. Two of these are
very large, each accounting for 10 percent of the U.S. capacity. It is
possible that high sulfate levels could occur in the vicinity of Claus
plants as large as those. Also, if the Claus plants in Texas and New Mexico
are concentrated in local area*,, local sulfate concentrations could be high.
A. 2 CHLORIDE EMISSION SOURCES
This section contains an analysis of available information on HC1
emissions from industrial sources and electric utilities. The approach used
was to use the best existing data; no new information was generated. The
sources of this information include Source Assessment Documents, Control
Technology Guidelines, and other references.
The overall results of the study of HC1 emissions are shown in
Table A-8. As the table shows, the highest national emissions were
estimated for utility and industrial boilers. Possible high local HCl
levels were also suggested in the vicinity of propylene oxide plants.
Incinerators also have high HCl emissions. Emission factors were
available for municipal solid waste, industrial waste, and liquid waste.
However, the basis for the factors for industrial or liquid waste were not
explained adequately, so emissions estimates for these wastes could not be
made.
The basis for the HCL emissions data in Table A-8 and the sources of
information are given in the remainder of Section A.2.
A.2.1 Coal-Fired Utility Boilers
A.2.1.1 National Emissions. Reference 31 gives HCl emissions from
46 sites across the country. These measurements were obtained using an EPA
source assessment sampling system (SASS) train. From these tests an HCl
g
emission factor of 33.9 ng/J (78.8 lb/10 Btu) was obtained. This factor
was based on the use of bituminous coal. Assuming a heating value of
30
30,200 kJ/kg (13,000 Btu/lb), the emission factor becomes 1.0 kg/Mg
(2.0 lb/ton) of bituminous coal burned. Emission factors for lignite and
anthracite coal were obtained in the same manner yielding 0.01 kg/Mg
(0.02 lb/ton) lignite and 0.5 kg/Mg (1.0 lb/ton) anthracite burned.
A-19
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TABLE A-8. HC1 EMISSIONS
National HC1 Emissions
Source Category 103 Kg (103 tons)
(1)
Utility Boilers
496 (546)
(2)
Industrial Boilers
88 (96)
(3)
Incineration
Industrial Waste
Municipal Solid Waste
Liquid Waste
a
20 (22)
a
(4)
Propylene Oxide''
Manufacturing
1.9 (2.1)
(5)
Residential Boilers
Anthracite Coal
Bituminous Coal
Lignite Coal
1.3 (1.48)
1.4 (1.5)
0.004 (0.005)
aSpecific data lacking.
^Possible high local emissions In TX/LA area.
A-20
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Reference 6 reports 495 million Hg (545 million tons) bituminous,
43 million Hg (47 million tons) lignite, and 0.9 million Hg (1.0 million
tons) anthracite coal burned in the utility sector in 1982. Hultiplying the
emission factors by the national combustion rates results in total HC1
emissions of 496,000 Hg (546,000 tons) per year.
A.2.1.2 Local Emissions. Utility combustion sources appear to be
dispersed widely throughout the U.S. However, electric utilities are large
sources and could result in high local HC1 levels.
A.2.2 Coal-Fired Industrial Boilers
A.2.2.1 National Emissions. Reference 31 gives HC1 emissions from
32 sites across the country. These measurements were obtained using an EPA
SASS train. From these tests an HC1 emission factor of 33.9 ng/J
g
(78.8 lb/10 Btu) was obtained. This factor was based on the use of
bituminous coal. Assuming a heating value of 30,000 kJ/kg (13,000 Btu/lb),
the emission factor becomes 1.0 kg/Hg (2.0 lb/ton) of bituminous coal
burned. Factors of 0.01 kg/Hg (0.02 lb/ton) lignite and 0.5 kg/Hg
(1.0 lb/ton) anthracite burned were obtained in the same manner.
Reference 6 reports 87 million Hg (96 million tons) bituminous,
7 million Hg (8 million tons) lignite, and 0.5 million Hg (0.6 million tons)
anthracite burned in the industrial sector in 1982. Hultiplying the
emission factors by these national combustion rates results in total HC1
emissions of 88,000 Hg (96,500 tons) per year.
A.2.2.2 Local Emissions. Industrial combustion sources appear to be
widely dispersed throughout the U.S.; thus, no high local HC1 levels are
anticipated.
A.2.3 Coal-Fired Residential Boilers
A.2.3.1 National Emissions. Reference 32 gives HC1 emissions for
anthracite, bituminous, and lignite coal. These emission factors are
52 ng/J (120 lb/109 Btu), 26 ng/J (60.5 lb/109 Btu), and 15 ng/J
g
(35.1 lb/10 Btu). Little information was given concerning the basis for
these emission factors. Heating values of 31,400 kJ/kg (13,500 Btu/lb) for
anthracite, 30,000 kJ/kg (13,000 Btu/lb) for bituminous, and 16,800 kJ/kg
A-21
-------
I
Reference 6 reports 495 million Mg (545 million tons) bituminous,
43 million Mg (47 million tons) lignite, and 0.9 million Mg (1.0 million
tons) anthracite coal burned in the utility sector in 1982. Multiplying the
emission factors by the national combustion rates results in total HC1
emissions of 496,000 Mg (546,000 tons) per year.
A.2.1.2 Local Emissions. Utility combustion sources appear to be
dispersed widely throughout the U.S. However, electric utilities are large
sources and could result in high local HC1 levels.
A.2.2 Coal-Fired Industrial Boilers
A.2.2.1 National Emissions. Reference 31 gives HC1 emissions from
32 sites across the country. These measurements were obtained using an EPA
SASS train. From these tests an HC1 emission factor of 33.9 ng/J
g
(78.8 lb/10 Btu) was obtained. This factor was based on the use of
bituminous coal. Assuming a heating value of 30,000 kJ/kg (13,000 Btu/lb),
the emission factor becomes 1.0 kg/Mg (2.0 lb/ton) of bituminous coal
burned. Factors of 0.01 kg/Mg (0.02 lb/ton) lignite and 0.5 kg/Mg
(1.0 lb/ton) anthracite burned were obtained in the same manner.
Reference 6 reports 87 million Mg (96 million tons) bituminous,
7 million Mg (8 million tons) lignite, and 0.5 million Mg (0.6 million tons)
anthracite burned in the industrial sector in 1982. Multiplying the
emission factors by these national combustion rates results in total HC1
emissions of 88,000 Mg (96,500 tons) per year.
A.2.2.2 Local Emissions. Industrial combustion sources appear to be
widely dispersed throughout the U.S.; thus, no high local HC1 levels are
anticipated.
A.2.3 Coal-Fired Residential Boilers
A.2.3.1 National Emissions. Reference 32 gives HC1 emissions for
anthracite, bituminous, and lignite coal. These emission factors are
52 ng/J (120 lb/109 Btu), 26 ng/J (60.5 lb/109 Btu), and 15 ng/J
g
(35.1 lb/10 Btu). Little information was given concerning the basis for
these emission factors. Heating values of 31,400 kJ/kg (13,500 Btu/lb) for
anthracite, 30,000 kJ/kg (13,000 Btu/lb) for bituminous, and 16,800 kJ/kg
A-21
-------
(7,200 Btu/lb) for lignite were assumed. This gives emission factors of
1.6 kg/Mg (3.2 lb/ton) for anthracite, 0.8 kg/Mg (1.6 lb/ton) for
bituminous, and 0.25 kg/Mg (0.5 lb/ton) for lignite burned.
Reference 32 reports that 850,000 Mg (937,000 tons) of anthracite,
1.74 million Mg (1.92 million tons) of bituminous, and 20,000 Mg
(22,000 tons) of lignite coal were burned in 1974. Based on the emission
factors given above, annual estimates of HC1 production are 1,400 Mg
(1,500 tons) for anthracite coal, 1,400 tons (1,500 tons) for bituminous
coal and 4.5 Mg (5 tons) for lignite.
A.2.3.2 Local Emissions. As shown in Figure A-l the majority of coal
that is burned in residential boilers is consumed in the northeastern U.S.
Because of the relatively low amount of coal burned nationwide by
residential boilers, high local HC1 levels are not expected.
A.2.4 Propylene Oxide Manufacturing
A.2.4.1 National Emissions. Reference 34 gives an emission factor of
7.46 HC1 per ton of propylene oxide produced. Reference 35 gives total
production from propylene oxide plants in 1980 as 0.52 million Mg
(0.57 million tons). Using the emission factor of 3.7 kg HCl/Mg
(7.46 lb HCl/ton) gives national emissions of 1,930 Mg/yr
(2,120 tons/yr).
A.2.4.2 Local Emissions. Three propylene oxide plants are located in
the Texas/Louisiana area and produce 0.42 Mg/yr (0.64 tons/yr) or 80 percent
of the national production. Emissions from these three plants are
1,500 Mg (1,700 tons) of HC1 per year. HC1 could contribute to local
problems in these two states.
A.2.5 Incineration
A.2.5.1 Industrial Waste. Reference 31 gives an emission factor of
2.43 kg (5.35 lb) HC1 per ton of waste burned. However, the reference does
not provide details concerning how this emission factor was derived. No
other information could be found to support or refute this factor.
A-22
-------
I
ro
CO
Figure A-l. Estimated residential coa]
KM > Utl 000 aaUic fans/yr
isssi 14000 to 1001000 metric tons/yr
I 1 < l&OODtttrictons/yr
consumption in 1974 by state. 35
-------
A.2.5.2 Municipal Solid Waste (HSW). Reference 31 gives an emission
factor of 2.3 kg (5.0 lbs) HC1 per ton of HSW burned. This factor is based
on the results from three municipal incinerators that were tested for
uncontrolled emissions. No information was available concerning the
accuracy of the emission test that was done. Reference 36 indicates that
8 million Hg (8.8 million tons) of HSW are incinerated per year. Based on
this amount, 20,000 Hg (22,000 tons) of HC1 are produced per year from the
combustion of HSW.
A.2.5.3 Liquid Wastes. Liquid wastes such as polychlorinated waste,
waste oil, and various other hydrocarbon liquids produce HC1 when
incinerated. Reference 31 gives an emission factor of 0.59 kg of HC1 per Mg
(1.19 lbs of HC1 per ton) of liquid waste burned. This factor is based on
the results from "several" uncontrolled sites. However, no information was
available concerning these sites or the type of test done.
A.3 FLUORIDE EMISSION SOURCES
This section contains an analysis of available information on HF
emissions from industrial sources and electric utilities. The approach used
was to use the best existing data; no new information was generated. The
sources of this information include Source Assessment Documents, Control
Technology Guidelines, and other references.
The overall results of the study of HF emissions are shown in
Table A-9. As the table shows, highest national emissions were estimated
for utility and industrial boilers. Possible high local HF levels were
indicated in the vicinity of primary aluminum smelters.
Clay and glass plants also have HF emissions. However, not enough
information was available on which to make an emissions estimate.
The basis for the HF emissions data in Table A-9 and the sources of
information are given in the remainder of Section A.3.
A.3.1 Coal-Fired Utility Boilers
A.3.1.1 National Emissions. Reference 31 gives HF emissions from
46 sites across the country. These measurements were obtained using an EPA
A-24
-------
TABLE A-9. HF EMISSIONS
National HF Emissions
3 3
Source Category 10 Mg/yr (10 tons/yr)
(1)
Utility Boilers
60
(66)
(2)
Industrial Boilers
10.6
(11-6)
(3)
Gypsum Ponds
5.9
(6.5)
(4)
Primary Aluminum Industry*
Anode Baking Furnace
Prebake Reduction Cell
Verticle Sodderberg Cell
Horizontal Soderberg Cell
2.6
1.5
1.95
(2.9)
(1.65)
(2.15)
(5)
Phosphoric Acid Production
0.14
(0.15)
(6)
Triple Super-Phosphate
Manufacturing
0.18
(0-2)
(7)
Diammonium Phosphate
Manufacturing
0.23
(0.25)
(8)
Residential Boilers
Anthracite Coal
Bituminous Coal
Lignite Coal
0.05
0.15
0.001
(0.06)
(0.17)
(0.001)
(9)
HF Manufacturing
0.02-1.3
(0.02-1.4)
~Possible high local concentrations in KY and WA areas.
A-25
-------
SASS train. From these tests an HF emission factor of 4.0 ng/0
g
(9.4 lb/10 Btu) was obtained. This factor was based on the use of
bituminous coal. Assuming a heating value of 30,200 kJ/kg
(13,000 Btu/lb)^®, the emission factor becomes 0.12 kg/Mg (0.24 lb/ton) of
bituminous coal burned. Emission factors of 0.01 kg/Mg (0.02 lb/ton)
lignite and 0.1 kg/Mg (0.2 lb/ton) anthracite coal burned were obtained in
the same manner.
Reference 6 reports 495 million Mg (545 million tons) bituminous, 43
million Mg (47 million tons) lignite, and 0.9 million Mg (1.0 million tons)
anthracite burned in the utility sector in 1982. Multiplying the emission
factors by the national combustion rates results in total HF emissions of
60,000 Mg (66,000 tons) per year.
A.3.1.2 Local Emissions. Utility combustion sources appear to be
dispersed widely throughout the U.S. However, electric utilities are large
sources, so high local HF concentrations could result in their vicinity.
A.3.2 Coal-Fired Industrial Boilers
A.3.2.1 National Emissions. Reference 31 gives HF emissions from
32 sites across the country. These measurements were obtained using an EPA
g
SASS train. From these tests an HF emission factor of 4.0 ng/J (9.4 lb/10
Btu) was obtained. This factor was based on the use of bituminous coal.
•3Q
Assuming a heating value of 30,200 kJ/kg (13,000 Btu/lb) , the emission
factor becomes 0.12 kg/Mg (0.24 lb/ton) of bituminous coal burned. Emission
factors of 0.01 kg/Mg (0.02 lb/ton) lignite and 0.1 kg/Mg (0.2 lb/ton)
anthracite burned were obtained in the same manner.
Reference 6 reports 87 million Mg (96 million tons) bituminous, 7
million Mg (8 million tons) lignite, and 0.5 million Mg (0.6 million tons)
anthracite burned in the industrial sector in 1982. Multiplying the
emission factors by the national combustion rates results in 10,600 Mg
(11,650 tons) of HF emissions per year.
A.3.2.2 Local Emissions. Industrial combustion sources appear to be
widely dispersed throughout the U.S.; thus no high local HF levels are
anticipated.
A-26
-------
A.3.3 Coal-Fired Residential Boilers
Reference 31 gives HF emissions for anthracite, bituminous, and lignite
coal as 2.1 ng/J (4.95 lb/10^ Btu), 3.0 ng/J (6.87 lb/105* Btu), and 2.7 ng/J
g
(6.34 lb/10 Btu), respectively. Little information was given concerning
the basis for these emission factors. Heating values of 31,400 kJ/kg
(13,500 Btu/lb) for anthracite, 30,200 kJ/kg (13,000 Btu/lb) for bituminous,
30
and 16,700 kJ/kg (7,200 Btu/lb) for lignite were assumed. This gives
emission factors of 0.06 kg/Mg (0.13 lb/ton) of anthracite, 0.09 kg/Mg
(0.18 lb/ton) of bituminous, and 0.05 kg/Mg (0.09 lb/ton) of lignite burned.
Reference 32 reports that 850,000 Mg (937,000 tons) of anthracite,
1.74 million Mg (1.92 million tons) of bituminous, and 20,000 Mg
(22,000 tons) of lignite coal were burned in 1974. Based on the emission
factors given above, annual estimates of HF emissions are 54 Mg (60 tons)
for anthracite coal, 150 Mg (170 tons) for bituminous coal, and 907 kg
(2,000 lbs) for lignite.
A.3.4 HF Manufacturing
Reference 31 gives HF emission factors of 12.5 kg/Mg (25.0 lb/ton) of
product for uncontrolled plants and 0.1 kg/Mg (0.2 lb/ton) of product for
controlled plants. These emission factors were based on a study of four
manufacturing plants. However, very little is known about the accuracy of
these tests. In 1980, 193 x 103 Mg (213 x 103 tons) of HF was produced.3^
Assuming 100 percent control, this production yields 19.3 Mg (21.3 tons) HF
emissions per year. Assuming 50 percent control yields 1,220 Mg
(1,340 tons) HF emissions per year.
A.3.5 Phosphoric Acid Production
Reference 31 gives an uncontrolled HF emission factor of 0.21 kg/Mg
(0.42 lb/ton) of phosphate rock processed. As a result of control by
scrubbers, it is estimated that a typical emission factor of approximately
0.015 kg HF/Mg (0.030 lb HF/ton) of P205 or 0.005 kg HF/Mg (0.010 lb HF/ton)
A-27
-------
of phosphate rock processed can be used to represent HF emissions from
phosphoric acid production. This estimate is based on the fact that all
wet-process plants located in Florida are required to achieve an emission
limit of 0.01 i;g total fluoride/Mg (0.02 lb total fluoride/ton) of P2°5- It
is estimated that 74 percent of production is in attainment with the 0.02
level. The remaining 26 percent ranges from 0.010 to 0.035 kg total
fluroide/Hg (0.020 to 0.070 lb total fluoride/ton) P205- Also, all wet-
process plants built since 1967 are assumed to have installed spray-
crossflow packed bed scrubbers. With a 1980 wet-process phosphoric acid
production of about 9 million Mg (10 million tons) per year, total HF
emissions would be 140 Mg (150 tons) per year.
A.3.6 Gypsum Ponds In Phosphoric Acid Plants
Reference 38 gives an emission factor based on measurements of gypsum
ponds at two different phosphate fertilizer plants in Florida. This factor
is 0.64 kg/Mg (1.28 lb/ton) of phosphoric acid. Based on a national
production of phosphoric acid of 9.3 million Mg (10.2 million tons) given in
"Review of New Source Performance Standards for Phosphate Fertilizer
Industry - Revised" [U.S. Environmental Prtoection Agency, Research Triangle
Park, NC, November 1980], 5,900 Mg (6,500 tons) of HF are emitted yearly
from gypsum ponds in the U.S.
A.3.7 Triple Super-Phosphate Manufacturing fTSPl
The major sources of fluoride emissions from a granular TSP plant are
the reactors, den, granulator, dryer and cooler. Uncontrolled emissions
from these sources have been estimated at a rate of 10.5 kg F/Mg (21.0 lbs
F/ton) PgO,- input.31 A controlled emission factor of 0.12 kg F/Mg (0.24 lbs
F/ton) P20g input from granulator plants is reported. Assuming that most of
the fluorides are emitted in the form of hydrogen fluoride results in
uncontrolled and controlled emission factors of 10.5 and 0.12 kg HF/Mg (21.0
and 0.24 lbs HF/ton) P205 input, respectively. Reference 39 reports the
A-28
-------
national production of TSP in 1980 was 1.54 million Mg (1.69 million tons).
Based on the controlled factor, annual HF emissions are estimated to be
180 Mg (205 tons).
A.3.8 Diammonium Phosphate Manufacturing
Reference 31 reports a controlled emission factor of 0.04 kg F/Mg
(0.08 lb F/ton) of diammonium phosphate fertilizer produced. Reference 39
gives the 1980 national production of diammonium phosphate as 5.6 million Mg
(6.1 million tons). Assuming that most of the fluorides are emitted as HF
results in annual HF emissions of 210 Mg (250 tons).
A.3.9 Primary Aluminum Industry
Reference 40 breaks down the HF emission factors for the primary
aluminum industry by the type of process used. These emission factors are
0.26 kg/Mg (0.52 lb/ton) for anode baking furnaces, 0.86 kg/Mg (1.72 lb/ton)
for prebake reduction cells, 2.7 kg/Mg (5.5 lb/ton) for vertical Soderberg
(VS) cells and 2.0 kg/Mg (4.1 lb/ton) for horizontal Soderberg (HS) cells.
No information was provided by this reference concerning the basis on which
emission factors were derived.
Reference 40 also gives the annual production capacity of aluminum in
1975. Anode baking furnaces are not included in these production estimates.
However, the capacity of prebake reduction cells was estimated as
3.1 million Mg (3.4 million tons). The capacity of HS cells was estimated
at 0.91 million Mg (1.0 million tons) and VS cells at 0.54 million Mg
(0.6 million tons). Based on these capacities, HF emissions are estimated
at 2,600 Mg (2,900 tons) from prebake reduction cells, 1,500 Mg (1,650 tons)
from VS cells and 1,950 Mg (2,150 tons) from HS cells.
Figure A-2 shows the geographical distribution of U.S. aluminum
smelters. As can be seen in this figure smelters are spread across the
eastern U.S. and in the northwestern corner of the country. Concentration
of smelters occurs in the northwestern corner of the U.S. and in the western
Kentucky area. Significant local problems could occur in these two areas.
A-29
-------
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WASHINGTON
MONTANA NORTH DAKOTA 1 MINNESOTA
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ORECON
IDAHO
SOUTH DAKOTA
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NEBRASKA
IOWA
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UTAH
CAUFORNIA
ARIZONA
COLORADO
NEW MEXICO
ILLINOIS
IN
OHIO
L«g«nd:
¦ Aluminum Sm«lt«ra
• Alumina Plants
Sourcaa: Authur D. LlttU, Inc.
KANSAS
MISSOURI V
1 OKLAHOMA
ARKANSAS i
/
¦ /
^ (
TEXAS
¦
¦
• rt
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) •
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. VW
-DE
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1KENTUCKY
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'VIRGINIA
"NO. CAROLINA,
SO.
(.CAROLINA/
ALABAMA)
GEORGIA'
SAINT CHOIX
U. S. VIRCIN ISLANDS
Figure A—2. Location of alumina plants and aluminum smelters in the United States.
-------
TABLE A-10. SUMMARY OF N02 AND NITRATE EMISSIONS ESTIMATES
3 ^23
10J Mg (l6J tons)
, Nitrate
10J Mg (10J tons)
Utility Boilers
318 (350)
64 (70)
Industrial Boilers
136 (150)
32 (35)
Industrial Processes
HN03 Production
64 (70)
--
Adipic Acid
14 (15)
Not Available
Organic Nitration
1.4 (1.5)
Not Available
Nitrocellulose
15 kg/Mg (30 lb/ton)
9.5 kg/Mg (19 lb/ton)
A-31
-------
A.4 NITRATE EMISSION SOURCES
National annual estimates of nitrate and N02 emissions from electric
utilities and industrial sources are shown in Table A-10. In many cases
nitrate emissions data were unavailable, but N02 data were available. Since
N02 is soluble in water, some fraction of the N02 will be emitted as HNOj.
As shown by Table A-10, the combustion sources are the largest potential
emitters of N02 and nitrates.
A.4.1 Utility and Industrial Boilers
Host references consulted agreed that N02 directly emitted from boilers
ranges up to about 5 percent of the total N0X emissions. Since N02 is
soluble in water (1.26 g/1) a portion will be emitted in the form of HNOj.
However, no information estimating the portion emitted as HNOg was
available.
One value for nitrate emissions from utility boilers was found
(Reference 41). That value was about 0.04 kg/Mg (0.08 lb/ton) coal
combusted. Applying this factor to the total coal combusted in the utility
sector, emissions would be estimated to be less than 1 percent of the total
N0X emissions. Because no other information was available, nitrate
emissions were estimated to be 1 percent of the total N0X emissions from
utility boilers. This results in about 64,000 Mg (70,000 tons) of nitrate
emissions per year. The same factor was used for estimating emissions from
industrial boilers, yielding 32,000 Mg (35,000 tons) of nitrate emissions
per year.
A.4.2 Industrial Processes
Sources in the literature used for this study mentioned adipic acid,
nitration reactions, explosives, and nitric acid production processes as
potential sources of nitrate emissions.
Information in Reference 41 resulted in estimates of 6,00 to 14,000 Mg
(7,000 to 15,000 tons) N02 emissions from adipic acid production. There was
no indication that any of this was HNOj, however.
A-32
-------
Total N0X emissions from organic nitrations were estimated to be
1,400 Mg (1,500 tons) (Reference 41). There was no indication of what
quantity of these emissions could be expected to be HNOj.
Manufacture of nitrocellulose was estimated (Reference 41) to emit
9.5 kg (19 lb) HN03 mist per ton of product and 15 kg (30 lb) N02 per ton
product. No national production levels were found to extrapolate these
factors to national emission levels.
A-33
-------
A. 5 REFERENCES
1. Rivers, Martin E. and Kurt W. Riegel, Work Group Co. - Chairmen. Work
Group 3B - Emissions, Costs and Engineering Assessment. U.S.-Canadian
Memorandum of Intent on Transboundary Air Pollution. June 15, 1982.
2. Homolya, James B. (Radian Corporation) Primary Sulfate Emission
Factors for the National Acid Precipitation Assessment Program
Emissions Inventory. Prepared for U.S. Environmental Protection
Agency, Research Triangle Park, NC, EPA-600/7-85-037, (NTIS
PB 86-108263), September 1985.
3. U.S. EPA. Environmental Pollution Control, Pulp and Paper Industry,
Part I, Air. EPA-625/7-76-001. October 1976. pp. 1-7, 1-9.
4. U.S. EPA. Background Information for Standards of Performance:
Primary Aluminum Industry, Volume 1: Proposed Standards.
EPA-450/2-74-020a, (NTIS PB 237612), October 1974. p. 12.
5. U.S. Department of Energy, Energy Information Administration.
Thermal-Electric Plant Construction Cost and Annual Production
Expenses - 1981. DOE/EIA0323(81).
6. National Coal Association, Coal Data 1981/82, Washington, D.C., 1983.
7. U.S. Department of Energy, Energy Information Administration. State
Energy Data Report, 1960 through 1980. D0E/EIA-0214(80). July 1982.
8. U.S. Department of Energy, Energy Information Administration.
Quarterly Coal Report. D0E/EIA-0118(81).
9. U.S. EPA. Final Guideline Document: Control of Sulfuric Acid Mist
Emissions from Existing Sulfuric Acid Production Units.
EPA-450/2-77-019, (NTIS PB 274085), September 1977. p. 4-8, 6-48.
10. U.S. EPA. A Review of Standards of Performance for New Stationary
Sources - Sulfuric Acid Plants. EPA-450/3-79-003, (NTIS PB 292278),
January 1979. pp. 5-1, 5-2.
11. "Sulfuric Acid" in Chemical Profile. Chemical Marketing Reporter.
July 26, 1982. p. 50.
12. Processes Research, Inc., Screening Study for Background Information
and Significant Emissions from Gypsum Product Manufacturing, prepared
for U.S. Environmental Protection Agency, Research Triangle Park, N.C.,
EPA-R2-73-286, (NTIS PB 222736). May 1973.
A-34
-------
13. U.S. EPA. Review of New Source Performance Standards for Kraft Pulp
Mills. EPA-450/3-83-017. September 1983. p. 2-21.
14. U.S. EPA. Petroleum Refineries - Fluid Catalytic Cracking Regenerators
- Particulate Test Method Evaluation - Emission Test Report - Arco
Petroleum Products Company - Philadelphia, PA. EMB 82-CAT09.
August 1983.
15. U.S. EPA. Petroleum Refineries - Fluid Catalytic Cracking Regenerators
- Particulate Test Method Evaluation - Emission Test Report - Phillips
Petroleum Company - Sweeny, Texas. EMB 83-CAT-ll. August 1983.
16. U.S. EPA. Petroleum Refineries - Fluid Catalytic Cracking Regenerators
- Particulate Test Method Evaluation - Emission Test Report - Exxon
Company, USA - Baton Rouge, LA. EMB 83-CAT-12. August 1983.
17. U.S. EPA. Sulfur Oxides Emissions from Fluid Catalytic Cracking Unit
Regenerators - Background Information for Proposed Standards.
EPA-450/3-82-013a, (NTIS PB 84-143254), January 1984.
18. "Annual Refining Survey." Oil and Gas Journal. March 21, 1983.
pp. 128-150.
19. U.S. Department of the Interior, Bureau of Mines. Mineral Industry
Surveys. Aluminum and Bauxite in 1983. December 30, 1983.
20. U.S. EPA. Review of New Source Performance Standards for Primary
Copper Smelters-Appendices. EPA-450/3-83-018b. March 1984. p. C13.
21. U.S. EPA. NSPS Revision - Nonferrous Smelter Flash Furnace and
Electric Slag Cleaning Furnace - Emission Test Report - Phelps - Dodge
Hidalgo Smelter, Playas, New Mexico. EMB 81-CUS18. September 1982.
pp. 45-46.
22. U.S. Department of the Interior, Bureau of Mines. Mineral Industry
Surveys. Copper in the United States, March 1985. June 3, 1985.
23. U.S. EPA Review of New Source Performance Standards for Primary Copper
Smelters - Chapters 1 through 9. EPA-450/3-83-018a. March 1984.
24. U.S. Department of the Interior, Bureau of Mines. Mineral Industry
Surveys. Zinc Industry in December 1983 and Smelter Production in
January 1984. March 7, 1984.
25. U.S. EPA. Preliminary Study of Sources of Inorganic Arsenic.
EPA-450/5-82-005. August 1982. p. 71.
26. Personal Communication. Keller, L., Radian Corporation, with
Wilkins, G. E., Radian Corporation.
27. U.S. Department of Commerce, Bureau of Industrial Economics. 1984
U.S. Industrial Outlook. January 1984. p. 2-8.
A-35
-------
28. U.S. EPA. SO, Emissions in Natural Gas Production Industry -
Background Information for Proposed Standards. EPA-450/3-82-023a.
November 1983. p. 9-34.
29. Shih, C. C. et al., "Emissions Assessment of Conventional Stationary
Combustion Systems (TRW, Inc.); Volume III. External Combustion
Sources for Electricity Generation, Prepared for U.S. Environmental
Protection Agency, Research Triangle Park, N.C., EPA-600/7-81-003a,
(NTIS PB 81-145195), January 1981.
30. Perry, John H. et al., Perry's Chemical Engineers Handbook, Fourth
Edition, McGraw-Hill, New York, 1963.
31. David Misenheimer, et al., (GCA Corporation), Hydrogen Chloride and
Hydrogen Fluoride Emission Factors for the NAPAP Emission Inventory,
prepared for U.S. Environmental Protection Agency, Industrial
Environmental Research Laboratory, EPA-600/7-85-041, (NTIS
PB 86-134020), October 1985.
32. Surprenant, N. F. et al., "Emissions Assessment of Conventional
Stationary Combustion Systems; Volume V. Industrial Combustion
Sources, prepared by GCA/Technology Division, Bedford, HA for U.S.
Environmental Protection Agency, Research Triangle Park, N.C.,
EPA-600/7-81-003C, (NTIS PB 81-225559), July 1981.
33. De Angel is, D. G. and R. B. Renzik, Source Assessments: Residential
Combustion of Coal. Prepared by Monsanto Research Corporation, Dayton,
OH for U.S. Environmental Protection Agency, Research Triangle
Park, N.C., EPA-600/2-79-019a, (NTIS PB 295649), January 1979.
34. Khan, Z. S. and T. W. Hughes (Monsanto Research Corporation), Source
Assessment: Chlorinated Hydrocarbons Manufacture, prepared for
U.S. Environmental Protection Agency, Research Triangle Park, NC
EPA-600/2-79-019g, (NTIS PB 80-138209), August 1979.
35. U.S. International Trade Commissions. Preliminary Report on
U.S. Production of Selected Synthetic Organic Chemicals (Including
Synthetic Plastics and Resin Materials) November, December and
Cumulative Totals, 1980. U.S. Government. Printing Office,
Washington, D.C. February 1981.
36. Radian Corporation, Background Information Document for Cadmium
Emission Sources, Final Report, prepared for U. S. Environmental
Protection Agency, Research Triangle Park, N.C., EPA Contract No.
68-02-3818, January 16, 1985. pp. 109-116.
37. Chlorine and Hydrogen Chloride, U.S. Environmental Protection Agency,
Research Triangle Park, N.C., April 1976. EPA-600/1-76-020,(NTIS
PB 253196). p. 278.
A-36
-------
38. Control of Fluoride Emissions from Existing Phosphate Fertilizer
Plants, EPA-450/2-77-005, (NTIS PB 265062), U.S. Environmental
Protection Agency, Office of Air and Waste Management, Research
Triangle Park, N.C., March 1977.
39. Fertilizer Outlook and Situation, U.S. Department of Agriculture,
Washington, D.C., December 1982.
40. Primary Aluminum: Guidelines for Control of Fluoride Emissions from
Existing Primary Aluminum Plants, U.S. Environmental Protection Agency,
Office of Air, Noise, and Radiation, Research Triangle Park, N.C.,
EPA-450/2-78-049b, (NTIS PB 80-153935), 1979.
41. Acurex Corporation, Control Techniques for Nitrogen Oxide Emissions
from Stationary Sources, prepared for U.S. Environmental Protection
Agency, Research Triangle Park, N.C., EPA-450/1-78-001, (NTIS
PB 280034), January 1978.
A-37
-------
APPENDIX B
IBCOST AND RCUCM SAMPLE TABLES
TABLE B-l. NOMENCLATURE USED IN IBCOST ALGORITHMS
I. Capital Costs
EQUP
Equipment
INST
Installation
TO
Total Direct
IND
Indirect (Engineering, Field, Construction, Start-up, and
other miscellaneous costs)
TDI
Total Direct and Indirect
CONT
Contingencies
TK
Turnkey
LAND
Land
WC
Working Capital
TOTL
Total Capital
ODeratlon and Maintenance Costs4
DL
Direct Labor
SPRV
Supervision Labor
MANT
Malntenace Labor
SP
Spare Parts
ELEC
Electricity
UC
Utilities and Chemicals
WTR
Water
SW
Solid Waste Disposal
SLG
Sludge Waste Disposal
LW
Liquid Waste Disposal
SC
Sodium Carbonate
LMS
Limestone
LIME
Lime
FUEL
Fuel
TDOM
Total Direct Operation and Maintenance
OH
Overhead
TOTL
Total Operation and Maintenance
3. Annualized Costs
CR - Capital Recovery
WCC - Working Capital Charges
MISC - Miscellaneous (G & A, Taxes, Insurance)
TCC - Total Capital Charges
TOTL - Total Annualized Charges
B-l
-------
TABLE B-l. NOMENCLATURE USED IN IBCOST ALGORITHMS (Continued)
4. Boiler Specifications
0 - Thermal Input (106 Btu/hr) MW)b.
fi«- - Flue Gas Flowrate (acfm) (m /s)
CF - Capacity Factor (-)
BCRF » Capital Recovery Factor for Boiler System
5. Fuel Specifications
FC - Fuel Cost (S/106 Btu) (SMJ)b .
H - Heating Value (Btu/lb) (KJ/kg)
S » Sulfur Content (percent by uelght)
A - Ash Content (percent by weight)
N - Fuel Nitrogen Content (percent by weight)
6. SO, Control Specifications
UNCS02 - Uncontrolled SO, Emissions (lb/106 Btu) (ng/J)b
CTRS02 - Controlled SO, Emissions (lb/10 Btu) (ng/J)
EFFS02 - SO, Removal Efficiency (percent)
CRFS02 - Capital Recovery Factor for SOg Control System
7. PH Control Specifications
UNCPM ¦ Uncontrolled PM Emissions (lb/106 Btu) (ng/J)b
CTRPM ¦ Controlled PH Emissions (lb/10 Btu) (ng/J)
EFFPM » PM Removal Efficiency (percent)
CRFPM » Capital Recovery Factor for PM Control System
8. Cost Rates
ELEC - Electricity Rate,($/kw-hr) , h
WTR - Water Rate (S/IO"9 gal) «/nT)D
ALIME - Lime Rate (S/ton) S/kg)D h
ALS - Limestone Rate (S/ton) (S/kg) h
SASH - Sodium Carbonate Rate (S/ton) (S/kgJ
SLDG - Sludge Disposal Rate ($/ton) (S/kg) h
SWD - Solid Waste Disposal Rate (S/toni (Skg) , .
LWD « Liquid Waste Disposal Rate (S/10 gal) (S/m )
DLR - Direct Labor Rate (S/man-hr)
SLR - Supervision Labor Rate ($/man-hr)
AMLR - Maintenance Labor Rate (S/ican-hr)
-------
TABLE B-l. NOMENCLATURE USED IN IBCOST ALGORITHMS (Continued)
9. NO^ Control Specification;
FFAC - F-Factor (dscf/106 Btu)
UNCC* » Uncontrolled Excess Air (X)
CTREA « Controlled Excess Air (X)
DELT - Change 1n the flue gas exit temperature due to the
elimination of the air preheater or a reduction 1n Its
effectiveness.
CRFNO - Capital Recovery Factor for NO Control System
Cost categories are not mutually exclusive. For example, some costing
routines Include electricity and waste cost 1n the utilities category
while others calculate these costs separately.
bFGD algorithms use metric units.
c(-) factor presented as fraction, not as percent.
-------
TABLE B-2. calculations common to ibcost algorithms
1. Capital Costs
EQUP + INST - TDah
IND - 0.333 * TD
TDI - TD + INO
CONT - 0.20 * TDI
LAND - S4000 pulverized coal boilers
- S2000 all other boilers A
WC - 0.25 * (TDOM - Fuel) + 0.0833 (Fuel)0
TOTL - TK + LAND + WC
2. Operation and Maintenance Costs
FUEL - CF * Q ~ FC * 8760
TDOM - Sum of all O&M Costs other than OH
OH - 0.30 * DL + 0.26 * (DL + SPRV + MANT + SP)
TOTL - TDOH + OH
3. Annualized Costs
CR - CRF * TK
WCC - 0.10 * WC
MISC - 0.04 * TK
TCC - CR + WCC + MISC
TOTL - TCC + TOTL O&M Costs
aFGD system cost algorithms compute TD without prior computation of EQUP and
INST.
^Some algorithms compute IND explicitly as a function of boiler and/or
control device specifications.
cOnly boilers have costs assumed for land.
dFor boilers, assume a 3-month supply of all working capital components
except fuel which will have a 1-month supply. For control devices, working
capital is 25 percent of total direct operating and maintenance costs.
B-4
-------
TABLE B-3. SAMPLE OUTPUT: IBCOST
STAR (METRIC)*
OSTAR (METRIC)-
BOILER ROUTINE*
PM ROUTINE*
HALF-* YES
1.072
452.296
PLVR S02 ROUTINE*
NOX ROUTINE* LEA
MONT* YES
MAXFUEL* NO
80ILER SPECIFICATIONS
Q* 400.0 FLW* U1399.
FUEL SPECIFICATIONS
FC* 2.24 H* 11660.
FN- .00 REG* REG V
PM SPECIFICATIONS
UNCPH* 4.374 CTRPH* 4.374
S02 SPECIFICATIONS
UNCS02* 5.540 CTRS02* .554
NOX SPECIFICATIONS
FFAC* 9620. UNCEA* 50.0
F8C SPECIFICATIONS
FCS* .000
COST RATES
DLR* 18.15 SLR- 23.60
ALIME* 53.00 ALS- 12.00
ALWO* .600
ECONOMIC SPECIFICATIONS
BCRF« .1315 CRFS02* .1315
CAPCM* 1.030 AOHCM* 1.030
S» 3.23 A*
FTYP* H-BIT
EFFPM*
.600
12.00
• 00
EFFS02* 90.00REL* 95.00
3.77
CTREA* 35.0
AMLR* 22.09
SASH* 136.00
CELT*
ELEC-
SLDG-
• 0390
23.00
«TR-
SVO-
• 230
23.00
COST TABLE - RUN NO.
ITEM BOILER
1 (S1000)
NOX
CRFPM-
FUELM-
S02
1315
1.000
CRFNOX*
AYEAR"
• 1315
MAR 85
TOTAL
EQU°
10855.
37, •
0.
0.
10892.
INST
5808.
14.
0.
0.
5622.
TC
16663.
51.
2021.
0.
18735.
in:
5211.
0.
0.
0.
5211.
TOI
21874.
SI.
0.
0.
21925.
CONT
4375.
10.
0.
0.
4385.
TK
26249.
62.
3184.
0.
29494.
land
6.
0.
0.
0.
6.
wc
94S.
-3.
271.
0.
1213.
UONT
113.
59.
1.
0.
173.
IOC
3150.
7.
436.
0.
3593.
TOTL
30463.
125.
3892.
0.
34480.
OL
633.
0.
123.
0.
756.
SPRV
172.
0.
24.
0.
196.
MANT
335.
0.
127.
0.
462.
SP
409.
3.
0.
0.
412.
ELEC
540.
0.
41.
0.
581.
UC
0.
0.
0.
0.
0.
WTF
79,
0.
4.
0.
84.
SM
44.
0.
0.
0.
44.
SLOG
0.
0.
479.
0.
479.
L*
0.
0.
0.
0.
0.
SC
0.
0.
55.
0.
55.
LMS
0.
0.
0.
0.
0.
L IWE
0.
0.
23 0.
0.
230.
fuel
4709.
•44.
P.
0.
4666.
TSO*>
6921.
-40.
1083.
p.
7964.
OH
592.
1.
108.
0.
701.
MOST
54.
37.
40.
0.
131.
TOTL
7567.
-2.
1231.
0.
8796.
CR
3866.
9.
476»
0.
435 1.
*cc
95.
0.
27.
0.
121.
MISC
1050.
2.
127.
0.
1160.
TCC
5CI0.
11.
630.
0.
5652.
MOhT
68.
45.
4C •
c.
154.
TOTL
11592.
17.
1362.
0.
14471.
T r - A •_
:rc: :?z~i
•».:iuciss
COSTS 14632.
B-5
-------
TABLE B-4. SAiMPLE OUTPUT: RCUCM
Input Data Summary, Run No. 1, Algorithm LWSU 00-00-00
Data Block RATE COST RATES
DLR
2
DIRECT LABOR RATE (*/M-HR)
IB.ISO
ELEC
2
ELEC RATE (*/KU-HR)
.039
8TM
2
STEAM RATE U/1000 LB)
3.000
ALS
2
LIMEBTONE RATE («/TON)
12.000
FOIL
0
FUEL OIL RATE («/GAL)
.000
Data
Block BLRS BLR SPECIFICATIONS
BTYP
2
BOILER TYPE (1.-PC,2.-SB,3.-MF)
1.000
OUMW
2
UTILITY CAPACITY (MM)
200.000
a
2
HEAT INP CAPACITY (MMBTU/HR)
200u.000
FLU
1
FLUE GAS FLOWRATE (ACFM)
700723.000
EFF
2
BOILER EFFICIENCY (PERCENT)
.830
HROV
1
UTIL OVERALL HEAT RATE (BTU/KWH)
932881.390
ELEV
1
UTIL SITE ELEVATION (FT MSL)
.000
CF
2
CAPACITY FACTOR (-)
.600
HR9T
I
UTIL STM CYCLE HEAT RATE (BTU/KWH)
7924.000
Data Block FUEL FUEL SPECIFICATIONS
H 2 HEATING VALUE (BTU/LB) 11660.000
S 2 SULFUR CONTENT (PERCENT) 3.230
FTYP 2 FUEL TYPE (1.-EB.2.-WB.3.-LGN,4.-ANTH) 1.000
Data Block S02 S02 EMISSION DATA
UNCS 2 UNCONTROLLED S02 EMISSIONS (LB/MMBTU> 5.263
CTRS 2 CONTROLLED S02 EMISSIONS (LB/MMBTU) .326
EFFS 2 S02 CONTROL EFFICIENCY (PERCENT) 90.000
BYPS 2 BYPASS SYSTEM (I.-NO,2.»YES>? 1.000
RHTS 2 REHEAT SYSTEM (1.-NO,2.-YES)? 1.000
Data Block ECON ECONOMIC FACTORS
RFER
2
REAL FUEL ESCALATION RATE (PRCT/YR)
.000
ROER
0
REAL OM ESCALATION RATE (PRCT/YR)
.000
INFR
1
INFLATION RATE (PRCT/YR)
3.000
DISC
2
DISCOUNT RATE/COST OF MONEY (PRCT/YR)
10.000
ROE
2
RETURN ON EQUITY (PRCT/YR)
13.000
ROD
2
RETURN ON DEBT (PRCT/YR)
13.000
DEBT
2
AMOUNT DEBT FINANCED (PERCENT)
30.000
ANPE
2
ANALYSIS PERIOD/EQUIPMENT LIFE (YRS)
20.000
ACRS
2
TAX EQUIP LIFE (1.-3,2.-3,3.-tO,4.-13)
4.000
AITR
2
COMBINED (8T/FED) TAX RATE (PRCT/YR)
30.000
CPER
2
CONSTRUCTION PERIOD (MONTHS)
24.000
UF
2
UPDATE FACTOR (USE 1.0 FOR NO UPDATE)
1.343
Algorithm Laval Coat Ramulta, Run No. 1, Algorithm LWSU 00-00-00
Capital Coats
TOTAL PLANT COST - SS206B20.
INTR DURING CONSTR - 9033137.
START UP AND MODIF - 2760341.
B-F.
-------
TABLE B-4. SAMPLE OUTPUT: RCUCM (Continued)
total oeprec tNvsr • 67uoo30o.
*0**1*0 CAPITAL - 2093664*
TOTAc CAPITAL INVST - 69093960.
Operation «na risintsnancs Costs
DIRECT LABOR
t -
918173.
SUPERVISION
labor •
137726.
MAINTENANCE
LABOR •
1309973.
SPARE
PARTS
•
1309973.
ELECTRICITY
m
684068.
LintsTONE
m
601129.
total
DIRECT
QUI -
5357847.
OVERHEAD
¦
2301099.
total
OiH
m
7639744.
• 1
J
Cycls
Analysis o# Algorithm Lsvsl Casts* Run No.
1« Algorithm LWSU
O
o
o
o
-00
rr
0 *nd
n
Capital Cftargss
tsar Tota
Fu.l
Otnsr
ROE
ROD
Ospr
Inc Tax
Ins/PT
1
0.
8042733.
3102047.
5182047.
3330013.
-6200003*
2410209.
I79t>7i:t.
2
0.
8444869.
4930796.
4930796.
3330013.
1580701*
2410289.
25&°S54is
3
0.
8867112.
4679543.
4679343.
3330013.
1999533*
2410289.
259940;i>.
4
0.
9310468.
4428294.
4420294.
3330015.
2410285*
2418289.
26l3364g.
S
0.
9775990.
4177042.
4177042.
3350013.
2837037*
2418289.
26733410,
6
0.
10264790.
3925791.
3923791.
3330015.
3233780*
2410289.
27140460.
7
0.
10778030.
3674340.
3674540.
3350013.
3004337.
2418289.
26899930.
8
0.
11316930.
3423289.
3423289*
3350013.
2753286.
2418209.
26683^90.
9
0.
11882780.
3172030.
3172030*
3330015.
2302033.
2418289.
26497190.
to
0,
12476910.
2920786.
2920706*
3350013.
2920786.
2410289.
2700737ft.
u
0.
13100760.
2669535*
2669333.
3350015.
2669335.
2410289.
26877o60.
12
0.
13733800.
2418284*
2418284*
3350015;
2410284.
2410209.
26776930.
13
0.
14443590.
2167033.
2167033.
3350015.
2167033.
2410209.
26712990.
14
0.
13163760.
1915702.
1913782.
3350015.
1915782.
2410289.
2oo814lO.
ts
0.
13924050*
1664531*
1664331*
3350015.
1664531.
2410289.
26683940.
16
0.
16720230.
1413280.
1413280*
3350013.
4763295.
2418289*
30078410.
17
0.
17556260.
1162029*
1162029*
3330015.
4512044.
2418289*
36?0.
18
0*
18434080.
910770.
910778*
3350013.
4260792.
2418289.
30284730.
19
0.
19355780.
659526.
639526.
3330013*
4009541.
2418289.
3043:c8«'».
20
0.
20323370.
408275*
400275.
3330015*
3738290.
2410289.
3066O710.
Total®
Ao«
0.
265940300.
33903220.
35903220.
67000300*
49203180.
48365760.
5423162'^u.
PW
0.
97414200.
30196640.
30196640.
28520560*
14376360.
20588250.
22l492a^.
usv
0.
11442240.
3346886.
3546886.
3350014*
1712134.
2410288.
;a'H64«".
------- |